PART I
ITEM 1. Business
General
EOG Resources, Inc., a Delaware corporation organized in 1985, together with its subsidiaries (collectively, EOG), explores for, develops, produces and markets crude oil, natural gas liquids (NGLs) and natural gas primarily in major producing basins in the United States of America (United States or U.S.), The Republic of Trinidad and Tobago (Trinidad), The People's Republic of China (China), Canada 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, 2019,2021, EOG's total estimated net proved reserves were 3,3293,747 million barrels of oil equivalent (MMBoe), of which 1,6941,548 million barrels (MMBbl) were crude oil and condensate reserves, 740829 MMBbl were NGLs reserves and 5,3708,222 billion cubic feet (Bcf), or 8951,370 MMBoe, were natural gas reserves (see "Supplemental Information to Consolidated Financial Statements"). At such date, approximately 98%99% of EOG's net proved reserves, on a crude oil equivalent basis, were located in the United States 1% in Trinidad and 1% in other international areas.Trinidad. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet (Mcf) of natural gas.
As of December 31, 2019, EOG employed approximately 2,900 persons, including foreign national employees.
EOG's operations are all crude oil and natural gas exploration and production related. For information regarding the risks associated with EOG's domestic and foreign operations, see ITEM 1A, Risk Factors.
EOG's business strategy is to maximize the rate of return on investment of capital by controlling operating and capital costs and maximizing reserve recoveries. Pursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintainingin shareholder value and maintain a strong balance sheet. EOG is focused on innovation and cost-effective utilization of advanced technology associated with three-dimensional seismic and microseismic data, the development of reservoir simulation models 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, that is consistentcoupled with efficient and safe operations and environmentally responsible operationsrobust environmental stewardship practices and performance, is also an important goalintegral in the implementation of EOG's strategy.
With respect to information on EOG's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by EOG's working interest in the wells or acreage.
Exploration and Production
United States Operations
EOG's operations are located in most of the productive basins in the United States with a focus on crude oil and, to a lesser extent, liquids-rich natural gas plays.
At December 31, 2019,2021, on a crude oil equivalent basis, 52%42% of EOG's net proved reserves in the United States were crude oil and condensate, 23%22% were NGLs and 25%36% were natural gas. The majority of these reserves are in long-lived fields with well-established production characteristics. EOG believes that opportunities exist to increase production through continued development in and around many of these fields and through the utilization of applicable technologies. EOG also maintains an active exploration program designed to extend fields and add new trends and resource plays to its already broad portfolio.
The following is a summary of significant developments during 2019wellhead volume statistics and anticipated 2020 plansnet well completions for the year ended December 31, 2021, total net acres at December 31, 2021, and expected net well completions planned for 2022 for certain areas of EOG's United States operations.
|
| | | | | | | | | | | | | | |
2019 | | 2020 |
Area of Operation | Crude Oil & Condensate Volumes (MBbld) (1) | Natural Gas Liquids Volumes (MBbld) (1) | Natural Gas Volumes (MMcfd) (1) | Total Net Acres (2) | | Net Well Completions | | Expected Net Well Completions |
| | | | | | | | |
Eagle Ford | 187 |
| 30 |
| 146 |
| 579,000 |
| | 321 |
| | 300 |
|
Austin Chalk | 15 |
| 7 |
| 41 |
| — |
| (3) | 14 |
| | 6 |
|
Delaware Basin | 174 |
| 65 |
| 402 |
| 389,000 |
| | 276 |
| | 350 |
|
Rocky Mountain Area | 62 |
| 15 |
| 188 |
| 1,264,000 |
| | 96 |
| | 95 |
|
Upper Gulf Coast | — |
| — |
| 10 |
| 360,000 |
| | 1 |
| | — |
|
Mid-Continent | 10 |
| 2 |
| 20 |
| 120,000 |
| | 32 |
| | 20 |
|
Fort Worth Basin | 2 |
| 12 |
| 67 |
| 146,000 |
| | — |
| | — |
|
South Texas | 1 |
| 1 |
| 102 |
| 564,000 |
| | 15 |
| | 15 |
|
Marcellus Shale | — |
| — |
| 68 |
| 151,000 |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
2021 | | 2022 |
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 | 231.1 | | 84.6 | | 651 | | 395 | | | 288 | | | 375 | |
South Texas | 149.5 | | 29.3 | | 273 | | 1,131 | | | 166 | | | 125 | |
Rocky Mountain | 50.3 | | 16.9 | | 182 | | 1,037 | | | 50 | | | <50 |
Other Areas | 12.5 | | 13.7 | | 104 | | 1,130 | | | 12 | | | 20 | |
Total | 443.4 | | 144.5 | | 1,210 | | 3,693 | | | 516 | | | 520 | |
| |
(1) | Thousand barrels per day or million cubic feet per day, as applicable. Total volumes exclude 5 MBbld of crude oil and condensate, 2 MBbld of NGLs and 25 MMcfd of natural gas related to other plays. |
| |
(2) | Total net acres excludes approximately 0.7 million net acres in other areas. |
| |
(3) | The Austin Chalk play encompasses the same net acres as the Eagle Ford. |
(1)Thousand barrels per day or million cubic feet per day, as applicable.
The Eagle Ford is a world-class crude oil field which has produced in excess of 3.4 billion barrels of crude oil and condensate. With approximately 516,000 of its 579,000 total net acres in the prolific oil window, EOG continues to be the largest crude oil producer in the Eagle Ford with cumulative gross production in excess of 600 MMBbl of crude oil and condensate. In 2019, EOG completed 321 net Eagle Ford wells and 14 net Austin Chalk wells. EOG continues to evaluate the prospectivity of the Austin Chalk, which overlays EOG's Eagle Ford acreage. EOG has approximately 150 Eagle Ford net wells in its enhanced oil recovery (EOR) gas injection program. The company did not add wells to the EOR program in 2019 and does not expect to add wells in 2020. EOR is a secondary recovery process and the company continues to evaluate the primary development opportunities on its acreage before expanding the EOR program. In 2020, EOG expects to complete approximately 300 net Eagle Ford wells and 6 net Austin Chalk wells while continuing to improve well productivity and operational efficiencies. The combination of exceptional execution and continuous operational improvements have made this play one of the foundations of EOG's portfolio.
In the Delaware Basin, EOG completed 276288 net wells during 2019,2021, primarily in the Delaware Basin Wolfcamp, Bone Spring and Leonard plays. EOG also identified additional drilling locations in the Wolfcamp M and Third Bone Spring formations, expanding its inventory of future drilling locations across its approximately 389,000 total net acre position. The Delaware Basin consists of approximately 4,800 feet of oil rich stacked pay potential across multiple zones, offering EOG multiple co-development opportunities acrossthroughout its acreage395,000 net acre position.
In the Delaware Basin Wolfcamp play, where itEOG has approximately 346,000 net acres, EOG completed 201189 net wells in 2019. EOG continued its development plan with well spacing as close as 500 feet in the crude oil portion2021. Continued improvement and 880 feet in the combination crude oil and natural gas portion. Resultsexcellent results in the Delaware Basin Wolfcamp program were supported by optimized well spacing the application ofand co-development, enhanced well completions, precision drilling and continued cost reductions. TheIn 2022, the Delaware Basin Wolfcamp play will continue to be a primary area of focus in 2020.focus.
In the Third Bone Spring play, EOG completed 13 net wells in 2019 on its 200,000 net prospective acres. With multiple targetshas three main sub-plays: the First, Second and ample co-development opportunities, the Third Bone Spring. In 2021, EOG completed 79 total net Bone Spring play is expected to be a large portion of EOG’s future development program. Inwells within the three sub-plays. Of thethree sub-plays, the Second Bone Spring play,had the majority of the activity in 2021 with EOG holds approximately 289,000completing 63 net acres and completed 34 net wells in 2019. EOG also continued development in the Firstwells. The Bone Spring play where EOG has approximately 100,000 net acres and completed nine net wells in 2019. Both the First and Second Bone Spring plays continuecontinues to be an integral part of EOG’sEOG's Delaware Basin plans and portfolio.
In the Leonard play, EOG has approximately 160,000 net acres and continuedmaintained its development plan with 1920 net wells completed in 2019.2021. EOG has tested co-development of up to three 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 20202022 will continue to beremain focused inon the Delaware Basin Wolfcamp, Third Bone Spring, Second Bone Spring, First Bone Spring, and Leonard plays, where EOG expects to complete approximately 350375 net wells.
The South Texas area includes our Eagle Ford oil play and our Dorado gas play. EOG holds approximately 516,000 total net acres in the prolific oil window of the Eagle Ford oil 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 2021, EOG completed 155 net Eagle Ford oil play wells, and 11 net wells in the Dorado gas play.In 2022, EOG expects to complete approximately 95 net Eagle Ford oil play wells and 30 net Dorado wells.
Activity in the Rocky Mountain area in 2021 was consistent in 2019 with a focusfocused on the Wyoming Powder River Basin. In the Powder River Basin, EOG operated a two-rig program and completed 3245 net wells in the Niobrara, Mowry, Turner and Parkman formations. The focusIn addition, key infrastructure was added in 2019 wasorder to delineate the Mowry and Niobrara plays and to begin adding infrastructure. Drilling activity and infrastructure buildout will increase significantly in 2020 as activity shifts to development drilling. The infrastructure added will lower operating costs and increase price realizations going forward. In the Wyoming DJ Basin, EOG operated one rigdrilled and completed 44one net wellswell in 2019 in both the Codell and the Niobrara formations. Activity in the DJ Basin is expected to be moderate in 2020 as activity shifts to the Powder River Basin.formation. In the Williston Basin, EOG completed 20four net wells in the Bakken and Three Forks. On average, well performanceForks formations. Activity in both the DJ and Williston Basins is expected to be minimal in 2022 as development remains focused on the Powder River Basin greatly improved due to better targeting and completion techniques. The seasonal program of completing wells mostly in the summer while drilling throughout the year will continue in 2020, although activity will be at a slightly lower pace than 2019.where EOG currently holds approximately 1.3 million net acres in the Rocky Mountain area.
In the Mid-Continent area, EOG continued its development of the Woodford Oil Window play with 30 net wells completed during 2019. EOG holds 41,700 net acres in the play and plans to build on its results in the Woodford Oil Window with 20complete approximately 40 net well completions in 2020. In 2019, EOG completed 11 gross (two net) wells in the Western Anadarko Basin Marmaton Sand.
Net production for the Marcellus Shale in 2019 averaged approximately 68.3 MMcfd of natural gas. At December 31, 2019, EOG held approximately 151,000 net acres in the Marcellus Shale.
Fort Worth Basin Barnett Shale production averaged 1.7 MBbld of crude oil and condensate, 12.2 MBbld of NGLs and 67.4 MMcfd of natural gas in 2019.
wells.
In the South Texas area, EOG completed 15 net wells in 2019. Exploration and evaluation efforts will continue in this region in 2020,where we expect to drill and complete another 15 net wells.
At December 31, 2019, EOG held approximately 2.3 million net undeveloped acres in the United States.
During 2019, EOG continued to operate gathering and processing facilities in the Eagle Ford in South Texas, the Williston Basin Bakken and Three Forks plays in North Dakota, the Fort Worth Basin Barnett Shale and the Permian Basin in West Texas and New Mexico. At December 31, 2019, EOG-owned natural gas processing capacity in the Eagle Ford and the Fort Worth Basin Barnett Shale totaled 325 MMcfd and 180 MMcfd, respectively.
Operations Outside the United States
EOG has operations offshore Trinidad in the China Sichuan Basin and in Canada and is making preparations to drill offshore Australia, as well as evaluating additional exploration, development and exploitation opportunities in these and other select international areas.
In addition, EOG is in the process of exiting Block 36 and Block 49 in the Sultanate of Oman (Oman) and is executing an abandonment and reclamation program in Canada. EOG sold its operations in the China Sichuan Basin (China) in the second quarter of 2021.
Trinidad
Trinidad.. EOG, through several of its subsidiaries, including EOG Resources Trinidad Limited,
holds an 80% working interestinterests in (i) the exploration and production licenselicenses covering the South East Coast Consortium (SECC) Block, offshore Trinidad, except in the Deep Ibis area in which EOG's working interest decreased as a result of a third-party farm-out agreement;
holds an 80% working interest in the explorationPelican and production license covering the Pelican Field and its related facilities;
holds a 50% working interest in the exploration and production licenses covering theBanyan Fields, Sercan Area and each of their related facilities and the Ska, Mento, Reggae and deep Teak, Saaman and Poui Areas, all of which are offshore Trinidad;
holds a 100% working interest in and (ii) a production sharing contract with the Government of Trinidad and Tobago for each of the Modified U(a) Block,, Modified U(b) Block and Block 4(a); Blocks.
holds a 50% working interest in the exploration and production license covering the Banyan Field;
holds a 50% working interest in the exploration and production license covering the Ska, Mento, Reggae Area deep Teak, deep Saaman and deep Poui offshore Trinidad (collectively SMR Area);
owns a 12% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Caribbean Nitrogen Company Limited; and
owns a 10% equity interest in an anhydrous ammonia plant in Point Lisas, Trinidad, that is owned and operated by Nitrogen (2000) Unlimited.
Several fields in the SECC, Block, Modified U(a) Block,, Modified U(b) Block, Blockand 4(a), the Blocks, Banyan Field and the Sercan Area have been developed and are producing natural gas and crude oil and condensate. Natural gas from EOG's Trinidad operations currently is sold under various contracts
In March 2021, EOG signed a farmout agreement with the National Gas Company of Trinidad and Tobago Limited and its subsidiary (NGC). Crude oil and condensate from EOG's Trinidad operations currently is sold under various contracts to 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 2019,2021, EOG's net production from Trinidad averaged approximately 260217 MMcfd of natural gas and approximately 0.61.5 MBbld of crude oil and condensate. In 2019,2021, EOG drilledmade progress on the design and completed two net wells in Trinidadfabrication of a platform and wasrelated facilities for its previously announced discovery in the process of drilling anotherModified U(a) Block.
In 2022, EOG expects to drill one net exploratory well at December 31, 2019. Onein the EOG Area in addition to three development wells and one exploratory well in the Modified U(a) Block.
Australia. On April 22, 2021, a subsidiary of these wellsEOG entered into a purchase and sale agreement to acquire a 100% interest in the WA-488-P Block, located offshore Western Australia. On November 19, 2021, the petroleum exploration permit for that block was a successful developmenttransferred to that subsidiary.
In 2022, EOG will continue preparing for the drilling of an exploration well whilewhich is expected to commence in 2023.
Oman. EOG, through its subsidiaries, holds interests in Exploration and Production Sharing Agreements in Block 36 and Block 49 located in Oman.
In 2021, EOG's partner in Block 49 completed the otherdrilling and testing of one net exploratory well, which was determined to be an unsuccessful exploratory well. In addition,a dry hole. EOG notified its partner and the Ministry of Energy and Minerals of its intention to withdraw from Block 49. Additionally, EOG drilled two exploratory wells and completed one stratigraphic exploratory well in Trinidad, which discovered commercially economic reserves. At December 31, 2019,Block 36. There was a discovery of natural gas in Block 36, but the well results did not yield sufficient projected returns for EOG held approximately 115,000 net undeveloped acres in Trinidad.
to move forward with the project. In 2020,2022, EOG expects to drill and complete three net wellsexit Block 36 in Trinidad. All of the natural gas produced from EOG's Trinidad operations in 2020 is expected to be sold to NGC. All crude oil and condensate produced from EOG's Trinidad operations in 2020 is expected to be sold to Heritage.
Oman.
China. In July 2008, EOG acquired rights from ConocoPhillips in a Petroleum Contract covering the Chuan Zhong Block exploration area in the Sichuan Basin, Sichuan Province, China. In October 2008, EOG obtained the rights to shallower zones on the acquired acerage.
China.In 2019,May 2021, EOG drilled two natural gas wells to completecompleted the drilling program startedsale of all of its interest in 2018. In 2019, EOG also completed two natural gas wells that were drilled during the 2018 drilling program. All natural gas produced from the Baijaochang Field is sold under a long-term contract to PetroChina. In 2019,Resources China Limited. EOG no longer has any operations or assets in China. EOG's net production averaged approximately 3025 MMcfd of natural gas net, in China.prior to the sale.
Canada. In March 2020, EOG plans to continue to completebegan the remaining drilled uncompleted wells (DUCs)process of exiting its Canada operations in the future as pipeline capacity allows.Horn River area in Northeast British Columbia.
Marketing
In 2019,2021, 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,Coast, including Houston and Corpus Christi, Texas and Louisiana;Texas; Cushing, Oklahoma; the Permian Basin and the Midwest. In late 2019,2021, EOG also sold crude oil at the Houston Ship Channel (HSC)and the Port of Corpus Christi for export to foreign destinations. In each case, the price received was based on market prices at that specific sales point or based on the price index applicable for that location. In 2020,2022, the pricing mechanism for such production is expected to remain the same. In 2020, EOG expects to sell crude oil at the Port of Corpus Christi for export, in addition to sales at the HSC. At December 31, 2019,2021, EOG was committed to deliver to multiple parties fixed quantities of crude oil of 2816 MMBbls in 2020 and 22022, 7 MMBbls in 2021,2023, 7 MMBbls in 2024, and 1 MMBbls in 2025, all of which is expected to be deliveredsourced from future production of available reserves.
In 2019,2021, EOG processed certain of its United States wellhead natural gas production, either at EOG-owned facilities or at third-party facilities, extracting NGLs. NGLs were sold at prevailing market prices, into either local markets or downstream locations. In certain instances, EOG exchanged its NGL production for purity products received downstrean,downstream, which were sold at prevailing market prices. In 2020,2022, such pricing mechanisms are expected to remain the same. In 2021, 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 2022, the pricing mechanism for such production is expected to remain the same. At December 31, 2021, EOG was not committed to deliver fixed quantities of NGLs in 2022.
In 2019,2021, 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 2020,2022, the pricing mechanism for such production is expected to remain the same. Additionally, in 2019, EOG entered into an agreement, beginning in 2020, to sellsells natural gas to an LNGa liquefaction facility near Corpus Christi, Texas, and receivereceives pricing based on the Platts Japan Korea Marker. At December 31, 2019,2021, EOG was committed to deliver to multiple parties fixed quantities of natural gas of 159 Bcf in 2020, 108 Bcf in 2021, 82223 Bcf in 2022, 82190 Bcf in 2023, 31150 Bcf in 2024, 138 Bcf in 2025, 195 Bcf in 2026 and 1,6851,459 Bcf thereafter, all of which is expected to be deliveredsourced from future production of available reserves.
In 2019, a majority of the wellhead2021, natural gas volumes from Trinidad were sold under contracts with prices which were either wholly or partially dependent on Caribbean ammonia index prices and/or methanol prices. The remaining volumes were sold under a contract at prices partially dependent on United States Henry Hub market prices and under a fixed price contract.contract ending in 2026. The pricing mechanismsmechanism for these contractsproduction in Trinidad areis expected to remain the same in 2020; however, we anticipate the majority of volumes will be sold under a fixed price contract.2022.
In 2019,Through May 2021, all wellhead natural gas volumes from China were sold at regulated prices based on the purchaser's pipeline sales volumes to various local market segments. The pricing mechanism for production in China is expected to remain the same in 2020.
In certain instances, EOG purchases and sells third-party crude oil and natural gas in order to balance firm transportation capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities.
During 2019,2021, two purchasers each accounted for more than 10% of EOG's total wellhead crude oil and condensate, NGLs and natural gas revenues and gathering, processing and marketing revenues. The two purchasers are in the crude oil refining industry. EOG does not believe that the loss of any single purchaser would have a materialmaterially adverse effect on its financial condition or results of operations.
Wellhead Volumes and Prices
The following table sets forth certain information regarding EOG's wellhead volumes of, and average prices for, crude oil and condensate, NGLs and natural gas. The table also presents crude oil equivalent volumes which are determined using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 Mcf of natural gas for each of the years ended December 31, 2019, 20182021, 2020 and 2017.2019. 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 | 2019 | | 2018 | | 2017 | Year Ended December 31 | 2021 | | 2020 | | 2019 |
| | | | | | |
Crude Oil and Condensate Volumes (MMBbl) (1) | | | | | | Crude Oil and Condensate Volumes (MMBbl) (1) | |
United States: | | | | | | United States: | |
Eagle Ford | 68.3 |
| | 62.4 |
| | 57.4 |
| |
Eagle Ford Oil Play | | Eagle Ford Oil Play | 51.8 | | | 54.6 | | | 68.3 | |
Delaware Basin | 63.4 |
| | 46.3 |
| | 31.6 |
| Delaware Basin | 84.3 | | | 67.0 | | | 63.4 | |
Other | 34.6 |
| | 35.4 |
| | 33.2 |
| Other | 25.7 | | | 27.8 | | | 34.6 | |
United States | 166.3 |
| | 144.1 |
| | 122.2 |
| United States | 161.8 | | | 149.4 | | | 166.3 | |
Trinidad | 0.2 |
| | 0.3 |
| | 0.3 |
| Trinidad | 0.5 | | | 0.4 | | | 0.2 | |
Other International (2) | 0.1 |
| | 1.6 |
| | 0.2 |
| Other International (2) | — | | | — | | | 0.1 | |
Total | 166.6 |
| | 146.0 |
| | 122.7 |
| Total | 162.3 | | | 149.8 | | | 166.6 | |
Natural Gas Liquids Volumes (MMBbl) (1) | | | |
| | |
| Natural Gas Liquids Volumes (MMBbl) (1) | | | | | |
United States: | | | |
| | |
| United States: | | | | |
Eagle Ford | 10.7 |
| | 11.4 |
| | 9.4 |
| |
Eagle Ford Oil Play | | Eagle Ford Oil Play | 9.0 | | | 9.7 | | | 10.7 | |
Delaware Basin | 23.5 |
| | 15.8 |
| | 8.8 |
| Delaware Basin | 30.9 | | | 27.7 | | | 23.5 | |
Other | 14.7 |
| | 15.3 |
| | 14.1 |
| Other | 12.8 | | | 12.4 | | | 14.7 | |
United States | 48.9 |
| | 42.5 |
| | 32.3 |
| United States | 52.7 | | | 49.8 | | | 48.9 | |
Other International (2) | — |
| | — |
| | — |
| Other International (2) | — | | | — | | | — | |
Total | 48.9 |
| | 42.5 |
| | 32.3 |
| Total | 52.7 | | | 49.8 | | | 48.9 | |
Natural Gas Volumes (Bcf) (1) | |
| | |
| | | Natural Gas Volumes (Bcf) (1) | | | | | |
United States: | | | |
| | | United States: | | | |
Eagle Ford | 53 |
| | 58 |
| | 55 |
| |
Eagle Ford Oil Play | | Eagle Ford Oil Play | 55 | | | 53 | | | 53 | |
Delaware Basin | 147 |
| | 110 |
| | 81 |
| Delaware Basin | 238 | | | 168 | | | 147 | |
Other | 190 |
| | 169 |
| | 143 |
| Other | 149 | | | 160 | | | 190 | |
United States | 390 |
| | 337 |
| | 279 |
| United States | 442 | | | 381 | | | 390 | |
Trinidad | 95 |
| | 97 |
| | 114 |
| Trinidad | 79 | | | 66 | | | 95 | |
Other International (2) | 14 |
| | 11 |
| | 9 |
| Other International (2) | 3 | | | 11 | | | 14 | |
Total | 499 |
| | 445 |
| | 402 |
| Total | 524 | | | 458 | | | 499 | |
Crude Oil Equivalent Volumes (MMBoe) (3) | |
| | |
| | | Crude Oil Equivalent Volumes (MMBoe) (3) | | | | | |
United States: | |
| | |
| | | United States: | | | | |
Eagle Ford | 87.8 |
| | 83.5 |
| | 76.0 |
| |
Eagle Ford Oil Play | | Eagle Ford Oil Play | 70.0 | | | 73.1 | | | 87.8 | |
Delaware Basin | 111.4 |
| | 80.3 |
| | 53.9 |
| Delaware Basin | 154.9 | | | 122.7 | | | 111.4 | |
Other | 81.0 |
| | 78.8 |
| | 71.2 |
| Other | 63.3 | | | 66.9 | | | 81.0 | |
United States | 280.2 |
| | 242.6 |
| | 201.1 |
| United States | 288.2 | | | 262.7 | | | 280.2 | |
Trinidad | 16.0 |
| | 16.5 |
| | 19.4 |
| Trinidad | 13.7 | | | 11.4 | | | 16.0 | |
Other International (2) | 2.4 |
| | 3.4 |
| | 1.8 |
| Other International (2) | 0.6 | | | 1.8 | | | 2.4 | |
Total | 298.6 |
| | 262.5 |
| | 222.3 |
| Total | 302.5 | | | 275.9 | | | 298.6 | |
|
| | | | | | | | | | | |
Year Ended December 31 | 2019 | | 2018 | | 2017 |
| | | | | |
Average Crude Oil and Condensate Prices ($/Bbl) (4) | | | | | |
United States | $ | 57.74 |
| | $ | 65.16 |
| | $ | 50.91 |
|
Trinidad | 47.16 |
| | 57.26 |
| | 42.30 |
|
Other International (2) | 57.40 |
| | 71.45 |
| | 57.20 |
|
Composite | 57.72 |
| | 65.21 |
| | 50.91 |
|
Average Natural Gas Liquids Prices ($/Bbl) (4) | | | | | |
United States | $ | 16.03 |
| | $ | 26.60 |
| | $ | 22.61 |
|
Other International (2) | — |
| | — |
| | — |
|
Composite | 16.03 |
| | 26.60 |
| | 22.61 |
|
Average Natural Gas Prices ($/Mcf) (4) | | | | | |
United States | $ | 2.22 |
| | $ | 2.88 |
| | $ | 2.20 |
|
Trinidad | 2.72 |
| | 2.94 |
| | 2.38 |
|
Other International (2) | 4.44 |
| | 4.08 |
| | 3.89 |
|
Composite | 2.38 |
| | 2.92 |
| (5) | 2.29 |
|
| | | | | | | | | | | | | | | | | |
Year Ended December 31 | 2021 | | 2020 | | 2019 |
| | | | | |
Average Crude Oil and Condensate Prices ($/Bbl) (4) | | | | | |
United States | $ | 68.54 | | | $ | 38.65 | | | $ | 57.74 | |
Trinidad | 56.26 | | | 30.20 | | | 47.16 | |
Other International (2) | 42.36 | | | 43.08 | | | 57.40 | |
Composite | 68.50 | | | 38.63 | | | 57.72 | |
Average Natural Gas Liquids Prices ($/Bbl) (4) | | | | | |
United States | $ | 34.35 | | | $ | 13.41 | | | $ | 16.03 | |
Other International (2) | — | | | — | | | — | |
Composite | 34.35 | | | 13.41 | | | 16.03 | |
Average Natural Gas Prices ($/Mcf) (4) | | | | | |
United States | $ | 4.88 | | | $ | 1.61 | | | $ | 2.22 | |
Trinidad | 3.40 | | | 2.57 | | | 2.72 | |
Other International (2) | 5.67 | | | 4.66 | | | 4.44 | |
Composite | 4.66 | | | 1.83 | | | 2.38 | |
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(1) | Million barrels or billion cubic feet, as applicable. |
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(2) | Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. |
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(3) | Million barrels of oil equivalent; includes crude oil and condensate, NGLs and natural gas. |
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(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). |
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(5) | Includes a positive revenue adjustment of $0.44 per Mcf related to the adoption of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees related to certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas revenues. |
(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).
Human Capital Management
As of December 31, 2021, EOG employed approximately 2,800 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 environment in which to work, and by maintaining a consistent college recruiting and internship program, EOG is able to attract and retain some of the industry's best and brightest. To help assess the effectiveness of its approach to human capital management, EOG conducts an annual employee engagement survey. Based on the results of the survey, EOG has received "top workplace" recognition in various office locations.
Compensation, Benefits, Health & Wellness. EOG places a high level of importance on attracting and retaining talent, by providing competitive salaries, bonuses and a subsidized, comprehensive benefits package. EOG also offers a holistic wellness program, a matching gifts program, a flexible work schedule, paid family care leave, paid leave for illness or injury and an employee assistance program to support the mental well-being of employees and their dependents. In addition, with new-hire stock grants, an annual stock grant program and an employee stock purchase plan, every employee has the opportunity to be a participant in EOG's success.
COVID-19 Pandemic. In 2020, in response to the COVID-19 pandemic, EOG focused on keeping its employees and their families safe, including providing technology and support to employees to enable them to not only work safely and productively from the office or at home, but also to remain engaged and connected across the company. In 2021, EOG continued to provide such technology and support and remained focused on the safety of its employees, reopening its offices and worksites in a phased approach and instituting additional practices and protocols, including those related to social distancing, mask wearing and symptom screening.
Training and Development. EOG focuses on developing its employees for meaningful career opportunities, including promotion into supervisory and management positions and enhanced compensation opportunities. EOG provides training in leadership, management skills, communication, team effectiveness, technical skills and use of EOG systems and applications. EOG's leadership training 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 believes gender, racial, ethnic and cultural diversity, and diversity in background and experience, leads to diversity of thought, which is valued by EOG. As part of its effort to build and maintain a diverse and inclusive workplace, EOG focuses on creating a collaborative culture that fosters inclusion at all levels of the company and reflects the diversity of thought of its employees. EOG also takes steps to raise employee awareness, provide leadership and offer training to help advance diversity and inclusion 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 within which management can assess safety performance in a systematic way. EOG's safety performance is also considered in evaluating employee performance and compensation. EOG provides initial, periodic and refresher safety training to employees as well as to contractors and others who may work at or visit EOG's facilities. These training programs address various topics, including operating procedures, safe work practices and emergency and incident response procedures.
Competition
EOG competes with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and access to the facilities, equipment, materials, services, and employees and other contract 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 to a lesser extent, from competing energy sources, such as alternativerenewable 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 and (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies. 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, Wyoming and the Gulf of Mexico, as well as in other areas, are granted by the federal government and administered by the Bureau of Land Management (BLM) and/or the Bureau of Indian Affairs (BIA) or, in the case of offshore leases (which, for EOG, are de minimis), by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), all federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous additional statutory and regulatory restrictions and, in the case of leases relating to tribal lands, certain tribal environmental and permitting requirements and employment rights regulations. In addition, the U.S. Department of the Interior (via various of its agencies, including the BLM, the BIA and the Office of Natural Resources Revenue) has certain authority over our calculation and payment of royalties, bonuses, fines, penalties, assessments and other revenues related to our federal and tribal oil and gas leases.
BLM, BIA and BOEM leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act (which are subject to change by the BOEM or BSEE). Under certain circumstances, the BLM, BIA, BOEM or BSEE (as applicable) may require operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect EOG's interests.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 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 Fort Worth Basin Barnett Shale in North Texas, the Williston Basin Bakken and Three Forks plays in North Dakota, and the Eagle Ford in South Texas. State regulation of gathering and processing facilities generally includes various safety, environmental and, in some circumstances, nondiscrimination requirements with respect to the provision of gathering and processing services, but does not generally entail rate regulation. EOG's gathering and processing operations could be materially and adversely affected should they be subject in the future to the application of state or federal regulation of rates and services.
EOG's gathering and processing operations also may be, or become, subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. Additional rules and legislation pertaining to these matters are considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, such legislation might have on its operations and financial condition, EOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future legislative and regulatory changes.
EOG also owns crude oil rail loading facilities in North Dakota and crude oil truck unloading facilities in certain of its U.S. plays. Regulation of such facilities is conducted at the state and federal levels and generally includes various safety, environmental, permitting and packaging/labeling requirements. Additional regulation pertaining to these matters is considered and/or adopted from time to time. Although EOG cannot predict what effect, if any, any such new regulations might have on its crude-by-rail assets and the transportation of its crude oil production by truck, EOG could be required to incur additional capital expenditures and increased compliance and operating costs depending on the nature and extent of such future regulatory changes. EOG did not transport any crude oil by rail during 2019.2021.
Proposals and proceedings that might affect the oil and gas industry are considered from time to time by Congress, the state legislatures, the FERC and other federal, state and local regulatory commissions, agencies, councils and courts. EOG cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the oil and gas industry historically has been very heavily regulated; therefore, there is no assurance that the approach currently being followed by such legislative bodies and regulatory commissions, agencies, councils and courts will remain unchanged.
Environmental Regulation Generally - United States. EOG is subject to various federal, state and local laws and regulations covering the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations affect EOG's operations and costs as a result of their effect on crude oil and natural gas exploration, development and production operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements.
In addition, EOG has acquired certain oil and gas properties from third parties whose actions with respect to the management and disposal or release of hydrocarbons or other wastes were not under EOG's control. Under environmental laws and regulations, EOG could be required to remove or remediate wastes disposed of or released by prior owners or operators. EOG also could incur costs related to the clean-up of third-party sites to which it sent regulated substances for disposal or to which it sent equipment for cleaning, and for damages to natural resources or other claims related to releases of regulated substances at such third-party sites. In addition, EOG could be responsible under environmental laws and regulations for oil and gas properties in which EOG previously owned or currently owns an interest, but was or is not the operator. Moreover, EOG is subject to the U.S. Environmental Protection Agency's (U.S. EPA) rule requiring annual reporting of greenhouse gas (GHG)GHG emissions and, as discussed further below, is also subject to federal, state and local laws and regulations regarding hydraulic fracturing and other aspects of our operations.
Compliance with environmental laws and regulations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition or results of operations. In addition, it is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts (whether for environmental control facilities or otherwise) that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, given that such laws and regulations are subject to change, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding the environment and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations relating to such future laws and regulations. The direct and indirect cost of such laws and regulations (in enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.
Climate Change - United States. Local, state, federal and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. The U.S. Congress has, from time to time, proposed legislation for imposing restrictions or requiring fees or carbon taxes for GHG emissions. In addition to the U.S. EPA's rule requiring annual reporting of GHG emissions, the U.S. EPA has adopted regulations for certain large sources regulating GHG emissions as pollutants under the federal Clean Air Act. Further, the U.S. EPA, in May 2016, issued regulations that require operators to reduce methane emissions and emissions of volatile organic compounds (VOC) from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In 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.
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. However,2016 and which the U.S.United States formally rejoined in February 2021. The United States has begun the process to withdraw from the Paris Agreement.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 response,addition, many state and local officials have stated their intent to intensify efforts to uphold the commitments set forth in the international accord. Further, in November 2021, the U.S. Department of the Interior released its "Report on the Federal Oil and Gas Leasing Program," which recommended increasing royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs.
EOG believes that its strategy to reduce GHG emissions throughout its operations is both in the best interest of the environment and a prudent business practice. EOG has developed a system that is utilized in calculating GHG emissions from its operating facilities. This emissions management system calculates emissions based on recognized regulatory methodologies, where applicable, and on commonly accepted engineering practices. EOG reports GHG emissions for facilities covered under the U.S. EPA's Mandatory Reporting of Greenhouse Gases Rule published in 2009, as amended.
EOG is unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations, treaties or treatiespolicies 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, and treaties or policies (if enacted)enacted, issued or applied) could materially and adversely affect EOG's operations, financial condition and results of operations. 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.
Also, In November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in November 2016, the BLM issued a final rule that limits venting, flaringoil and leaking of natural gas from oil and gas wells and equipment on federal and Indian lands, though, in September 2018, the BLM issued a final rule rescinding certain requirements of that rule. Theresector. From time to time, there have been various other proposals to regulate hydraulic fracturing at the federal level. In addition, there have been proposals and positions taken by candidates for elected office and others regarding additional restrictions on, or the complete prohibition of, hydraulic fracturing operations.
In addition to the above-described federal regulations, some state and local governments have imposed, or have considered imposing, various conditions and restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; disclosure of the chemical additives used in hydraulic fracturing operations; restrictions on the type of chemical additives that may be used in hydraulic fracturing operations; and restrictions on drilling or injection activities on certain lands lying within wilderness wetlands, ecologically or seismically sensitive areas, and other protected areas. Such federal, state and local permitting and disclosure requirements, operating restrictions, conditions or prohibition could lead to operational delays and increased operating and compliance costs and, moreover, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing.
Compliance with laws and regulations relating to hydraulic fracturing and other aspects of our operations increases EOG's overall cost of business, but has not had, to date, a material adverse effect on EOG's operations, financial condition or results of operations. In addition, it is not anticipated, based on current laws and regulations, that EOG will be required in the near future to expend amounts that are material in relation to its total exploration and development expenditure program in order to comply with such laws and regulations. However, EOG is unable to predict (i) the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing in the United States or other aspects of our operations and (ii) the ultimate cost of compliance or the ultimate effect on EOG's operations, financial condition and results of operations relating to such future laws and regulations. The direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations.
Other International Regulation. EOG's exploration and production operations outside the United States are subject to various types of regulations, including environmental regulations, imposed by the respective governments of the countries in which EOG's operations are conducted, and may affect EOG's operations and costs of compliance within those countries. EOG currently has operations in Trinidad, China and Canada. EOG is unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect EOG's operations, financial condition and results of operations. EOG will continue to review the risks to its business and operations outside the United States associated with all environmental matters, including climate change and hydraulic fracturing regulation. In addition, EOG will continue to monitor and assess any new policies, legislation, regulations and treaties in the areas outside the United States where it operates to determine the impact on its operations and take appropriate actions, where necessary.
Other Regulation. EOG has sand mining and processing operations in Texas and Wisconsin, which support EOG's exploration and development operations. EOG's sand mining operations are subject to regulation by the federal Mine Safety and Health Administration (in respect of safety and health matters) and by state agencies (in respect of air permitting and other environmental matters). The information concerning mine safety violations and other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this report.
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 77% in 2021, decreased 33% in 2020 and decreased 11% in 2019, and increased 28% in 2018 and 22% in 2017, each as compared to the immediately preceding year. Average NGL prices received by EOG for production in the United States increased 156% in 2021, decreased 16% in 2020 and decreased 40% in 2019, and increased 18% in 2018 and 55% in 2017, each as compared to the immediately preceding year. During the last three years,Fluctuations in average United States wellhead natural gas prices have fluctuated, at times rather dramatically. These fluctuations resulted in a 23% decrease in the average wellhead natural gas price received by EOG for production in the United States resulted in 2019, a 31%203% increase (inclusive ofin 2021, a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09)27% decrease in 20182020, and a 38% increase23% decrease in 2017,2019, 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)Countries, and the duration and impact of the ongoing COVID-19 pandemic), the global supply of, and demand for, crude oil, NGLs and natural gas and the availability of other energy supplies, the relative competitive relationships of the various energy sources in the view of consumers and other factors, EOG is unable to predict what changes may occur in the prices of crude oil and condensate, NGLs and natural gas in the future. For additional discussion regarding changes in crude oil and condensate, NGLs and natural gas prices, the potential impacts on EOG and the risks that such changes may present to EOG, see ITEM 1A, Risk Factors.
BasedIncluding the impact of EOG's crude oil and NGL derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity (exclusive of basis swaps) in 20202022 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGL price, is approximately $117$107 million for net income and $152$138 million for pretax cash flows from operating activities. BasedIncluding the impact of EOG's natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 20202022 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in wellhead natural gas price is approximately $31$15 million for net income and $40$19 million for pretax cash flows from operating activities. For a summary of EOG's financial commodity derivative contracts through February 19, 2020,18, 2022, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Resources and Liquidity - Commodity Derivative Transactions. For a summary of EOG's financial commodity derivative contracts for the twelve monthsyear ended December 31, 2019,2021, 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 19, 2020,18, 2022, see ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations ‑ Capital Resources and Liquidity - Commodity Derivative Transactions.
All of EOG's crude oil, NGL and natural gas activities are subject to the risks normally incident to the exploration for, and development, production and transportation of, crude oil, NGL and natural gas, including rig and well explosions, cratering, fires, loss of well control and leaks and spills, each of which could result in damage to life, property and/or the environment. EOG's operations are also subject to certain perils, including hurricanes, flooding and other adverse weather events. Moreover, EOG's activities are subject to governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events could reduce EOG's revenues and increase costs to EOG to the extent not covered by insurance.
Insurance is maintained by EOG against some, but not all, of these risks in accordance with what EOG believes are customary industry practices and in amounts and at costs that EOG believes to be prudent and commercially practicable. Specifically, EOG maintains commercial general liability and excess liability coverage provided by third-party insurers for bodily injury or death claims resulting from an incident involving EOG's operations (subject to policy terms and conditions). Moreover, in the event anfor any incident involving EOG's operations which results in negative environmental effects, EOG maintains operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that EOG may incur from such an incident, including obligations, expenses or claims in respect of seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the event of a well control incident resulting in negative environmental effects, such operators extra expense coverage would be EOG's primary coverage, with the commercial general liability and excess liability coverage referenced above also providing certain coverage to EOG. All of EOG's drilling activities are conducted on a contractual basis with independent drilling contractors and other third-party service contractors. The indemnification and other risk allocation provisions included in such contracts are negotiated on a contract-by-contract basis and are each based on the particular circumstances of the services being provided and the anticipated operations.
In addition to the above-described risks, EOG's operations outside the United States are subject to certain risks, including the risk of increases in taxes and governmental royalties, changes in laws and policies governing the operations of foreign-based companies, expropriation of assets, unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities, currency restrictions and exchange rate fluctuations. Please refer to ITEM 1A, Risk Factors, for further discussion of the risks to which EOG is subject with respect to its operations outside the United States.
Information About Our Executive Officers
The current executive officers of EOG and their names and ages (as of February 27, 2020)24, 2022) are as follows:
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Name | | Age | | Position |
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NameEzra Y. Yacob | | Age45 | | Position |
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William R. Thomas | | 67 | | Chairman of the Board and Chief Executive Officer |
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Lloyd W. Helms, Jr. | | 6264 | | President and Chief Operating Officer |
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Kenneth W. Boedeker | | 5759 | | Executive Vice President, Exploration and Production |
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Ezra Y. YacobJeffrey R. Leitzell | | 4342 | | Executive Vice President, Exploration and Production |
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Timothy K. Driggers | | 5860 | | Executive Vice President and Chief Financial Officer |
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Michael P. Donaldson | | 5759 | | Executive Vice President, General Counsel and Corporate Secretary |
William R. ThomasEzra Y. Yacob was elected Chairman of the Board and Chief Executive Officer and appointed as a Director effective October 2021.Prior to that, he served as President from January 2014. He was elected Senior2021 through September 2021; Executive Vice President, Exploration and Production from December 2017 to January 2021; and Vice President and General Manager of EOG's Fort Worth,Midland, Texas office in June 2004, Executive Vice President and Generalfrom May 2014 to December 2017.He also previously served as Manager, ofDivision Exploration in EOG's Fort Worth, Texas, officeand Midland, Texas, offices from March 2012 to May 2014 as well as in February 2007various geoscience and Senior Executive Vice President, Exploitation in February 2011. He subsequently served as Senior Executive Vice President, Exploration from July 2011 to September 2011, as President from September 2011 to July 2013 and as President and Chief Executive Officer from July 2013 to December 2013.leadership positions. Mr. ThomasYacob joined a predecessor of EOG in January 1979. Mr. Thomas is EOG's principal executive officer.August 2005.
Lloyd W. Helms, Jr. was elected President and Chief Operating Officer ineffective 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.
Ezra Y. YacobJeffrey R. Leitzell was elected Executive Vice President, Exploration and Production in December 2017. HeMay 2021. Mr. Leitzell previously served as Vice President and General Manager of EOG's Midland, Texas office from December 2017 to May 20142021 and as Operations Manager in Midland from August 2015 to December 2017.Prior to that, he served as Manager, Division ExplorationMr. Leitzell held various engineering roles of increasing responsibility in EOG's Fort Worth, Texas,multiple offices and Midland, Texas, offices from March 2012 to May 2014 as well as in various geoscience and leadership positions. functional areas within EOG.Mr. YacobLeitzell joined EOG in August 2005.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.
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 and NGL prices are volatile, and a substantial and extended decline in commodity prices can have a material and adverse effect on us.
Prices for crude oil and natural gas (including prices for natural gas liquids (NGLs) and condensate) fluctuate widely. Among the interrelated factors that can or could cause these price fluctuations are:
•domestic and worldwide supplies of, 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;
consumer and industrial/commercial demand for crude oil, natural gas and NGLs;
•worldwide economic conditions, geopolitical factors and political conditions, including, but not limited to, the imposition of tariffs or trade or other economic sanctions, political instability or armed conflict in oil and gas producing regions;
•the duration and economic and financial impact of epidemics, pandemics or other public health issues, such as the ongoing COVID-19 pandemic;
•the availability, proximity and capacity of appropriate transportation, gathering, processing, compression, storage, refining and refiningexport facilities;
•the price and availability of, and demand for, competing energy sources, including alternative energy sources;
•the effect of worldwide energy conservation measures, alternative fuel requirements and climate change-related initiatives;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 derivatives transactions and hedging activities, tax laws and regulations and laws and regulations with respect to the import and export of crude oil, NGLs, and natural gas and related commodities;
•the level and effect of trading in commodity futures markets, including trading by commodity price speculators and others; and
•natural disasters, weather conditions and changes in weather patterns.
The above-described factors and the volatility of commodity prices make it difficult to predict future crude oil, NGLs and natural gas prices in 2022 and NGL prices.thereafter. As a result, there can be no assurance that the prices for crude oil, NGLs and/or natural gas and NGLs will sustain, or increase from, their current levels, andnor 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 other operating expenses,expenses; the terms on which we can access the credit and capital markets andmarkets; our results of operations.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 and NGLs that we can produce economically. Substantial and extended declines in the prices of these commodities can render uneconomic a portion of our exploration, development and exploitation projects, resulting in our having to make downward adjustments to our estimated proved reserves and also possibly shut in or plug and abandon certain wells. In addition, significant prolonged decreases in commodity prices may cause the expected future cash flows from our properties to fall below their respective net book values, which willwould require us to write down the value of our properties. Such reserve write-downs and asset impairments couldcan materially and adversely affect our results of operations and financial position and, in turn, the trading price of our common stock.
IfDevelopments 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 and energy conservation measures, (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 decline from current levels(including fluctuations in commodity prices) on our financial condition, cash flows and results of operations.
In addition to potentially adversely affecting the demand for, an extended periodand prices of, time,the crude oil, NGLs and natural gas that we 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 risks on our financial condition and results of operations, see the discussion in the section below 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 to us of capital. For further discussion of the potential impact of such risks on our financial condition, cash flows and results of operations, will be adversely affectedsee the discussion below in this section and in the section below entitled "Risks Related to Regulatory and Legal Matters."
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 and have other adverse effects (e.g., greater potential for governmental investigations or litigation). For further discussion regarding the risks to us of climate change-related regulations, policies and initiatives, see the discussion below in the section entitled "Risks Related to Regulatory and Legal Matters."
We have substantial capital requirements, and we may be limited inunable 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, cash on hand and sales of non-core assets and, to a lesser extent and if and as necessary, commercial paper borrowings, bank borrowings, borrowings under our revolving credit facility and public and private equity and debt offerings.
Lower crude oil, NGLs and natural gas prices, however, reduce our cash flows and could also delay or impair our ability to maintain our current levelconsummate certain planned non-core asset sales and divestitures. Further, if the condition of dividendsthe credit and capital markets materially declines, we might not be able to obtain financing on our common stock.terms we consider acceptable, if at all. In addition, weweakness and/or volatility in domestic and global financial markets or economic conditions or a depressed commodity price environment may be requiredincrease the interest rates that lenders and commercial paper investors require us to incur impairment chargespay 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 make downward adjustments to our proved reserve estimates. As a result,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 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 maycould 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 required to conduct our operations;
•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 downward revision 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 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 2022 is subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 2022 and beyond, we may be materially and adversely impacted by any declines in commodity prices, which may result in lower net cash provided by operating activities. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.
The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.
We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.
Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as (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, andNGLs and/or natural gas reserves (including "dry holes").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 marketexport 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 transporting,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 transportationexport of crude oil, NGLs and natural gas; and
•malfunctions of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil and natural gas operations.
If any of these events occur, we could incur losses, liabilities and other additional costs as a result of:
•injury or loss of life;
•damage to, or destruction of, property, facilities, equipment and crude oil and natural gas reservoirs;
•pollution or other environmental damage;
•regulatory investigations and penalties as well as cleanup and remediation responsibilities and costs;
•suspension or interruption of our operations, including due to injunction;
•repairs necessary to resume operations; and
•compliance with laws and regulations enacted as a result of such events.
We maintain insurance against many, but not all, such losses and liabilities in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. However, the occurrence of any of these events and any losses or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage, would reduce the funds available to us for our operations and could, in turn, have a material and adverse effect on our business, financial condition and results of operations. 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 and export facilities and equipment are unavailable.
The sale of our crude oil, NGLs and natural gas production depends on a number of factors beyond our control, including the availability, proximity and capacity of, and costs associated with, gathering, processing, compression, storage, transportation and export facilities and equipment owned by third parties. These facilities and equipment may be temporarily unavailable to us due to market conditions, regulatory reasons, mechanical reasons or other factors or conditions, and may not be available to us in the future on terms we consider acceptable, if at all. In particular, in certain newer plays, the capacity of gathering, processing, compression, storage, transportation and export facilities and equipment may not be sufficient to accommodate potential production from existing and new wells. In addition, lack of financing, construction and permitting delays, permitting costs and regulatory or other constraints could limit or delay the construction, manufacture or other acquisition of new gathering, processing, compression, storage, transportation and export facilities and equipment by third parties or us, and we may experience delays or increased costs in accessing the pipelines, gathering systems or rail systems necessary to transport our production to points of sale or delivery.
Any significant change in market or other conditions affecting gathering, processing, compression, storage, transportation and export facilities and equipment or the availability of these facilities and equipment, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all, could materially and adversely affect our business and, in turn, our financial condition and results of operations.
A portion of our crude oil, NGLs and natural gas production may be subject to interruptions that could have a material and adverse effect on us.
A portion of our crude oil, NGLs and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, storage, transportation, refining or export facilities or equipment or field labor issues, or intentionally as a result of market conditions such as crude oil, NGLs or natural gas prices that we deem uneconomic. If a substantial amount of our production is interrupted or shut in, our cash flows and, in turn, our financial condition and results of operations could be materially and adversely affected.
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 water districts 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 problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.
From time to time, we seek to acquire crude oil and natural gas properties. Although we perform reviews of properties to be acquired in a manner that we believe is duly diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems (such as title or environmental issues), nor may they permit us to become sufficiently familiar with the properties in order to fully assess their deficiencies and potential. Even when problems with a property are identified, we often may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.
In addition, there are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves (as discussed further above), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.
Competition in the oil and gas exploration and production industry is intense, and some of our competitors have greater resources than we have.
We compete with major integrated oil and gas companies, government-affiliated oil and gas companies and other independent oil and gas companies for the acquisition of licenses and leases, properties and reserves and access to the facilities, equipment, materials, services and employees and other personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil, NGLs and natural gas. Certain of our competitors have financial and other resources substantially greater than those we possess and have established strategic long-term positions or strong governmental relationships in countries or areas in which we may seek new or expanded entry. As a consequence, we may be at a competitive disadvantage in certain respects, such as in bidding for drilling rights or in accessing necessary services, facilities, equipment, materials and personnel. In addition, our larger competitors may have a competitive advantage when responding to factors that affect demand for crude oil, NGLs and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. We also face competition from competing energy sources, such as renewable energy sources.
Risks Related to Our International Operations
We operate in other countries and, as a result, are subject to certain political, economic and other risks.
Our operations in jurisdictions outside the U.S. are subject to various risks inherent in foreign operations. These risks include, among other risks:
•increases in taxes and governmental royalties;
•changes in laws and policies governing operations of foreign-based companies;
•loss of revenue, loss of or damage to equipment, property and other assets and interruption of operations as a result of expropriation, nationalization, acts of terrorism, war, civil unrest and other political risks;
•unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities;
•difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations; and
•currency restrictions or exchange rate fluctuations.
Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation, including tariffs or trade or other economic sanctions; modifications to, or withdrawal from, international trade treaties; and U.S. laws with respect to participation in boycotts that are not supported by the U.S. government. The realization of any of these factors could materially and adversely affect our business, financial condition and results of operations.
Unfavorable currency exchange rate fluctuations could materially and adversely affect our results of operations.
The reporting currency for our financial statements is the U.S. dollar. However, certain of our subsidiaries are located in countries other than the U.S. and have functional currencies other than the U.S. dollar. The assets, liabilities, revenues and expenses of certain of these foreign subsidiaries are denominated in currencies other than the U.S. dollar. To prepare our consolidated financial statements, we must translate those assets, liabilities, revenues and expenses into U.S. dollars at then-applicable exchange rates. Consequently, increases and decreases in the value of the U.S. dollar versus other currencies will affect the amount of these items in our consolidated financial statements, even if the amount has not changed in the original currency. These translations could result in changes to our results of operations from period to period. For the fiscal year ended December 31, 2021, 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 Regulatory and Legal Matters
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 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 (including, but not limited to, an increase in applicable royalty percentages) and (vi) U.S. federal income tax laws applicable to oil and gas exploration and production companies.
Further, such regulatory, legislative and policy changes may, among other things, result in additional permitting and disclosure requirements, additional operating restrictions and/or the imposition of various conditions and restrictions on drilling and completion operations or other aspects of our business, any of which could lead to operational delays, increased operating and compliance costs and/or other impacts on our business and operations and could materially and adversely affect our business, results of operations and financial condition.
For related discussion, see the below risk factors regarding legislative and regulatory matters impacting the oil and gas exploration and production industry 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 and financial condition.
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 and financial condition.
The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements and, further, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations. The U.S. Environmental Protection Agency (U.S. EPA) has issued regulations relating to hydraulic fracturing and there have been various other proposals to regulate hydraulic fracturing at the federal level.
Any new requirements, restrictions, conditions or prohibition could lead to operational delays and increased operating and compliance costs and, further, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. Accordingly, our production of crude oil and natural gas could be materially and adversely affected. For additional discussion regarding hydraulic fracturing regulation, see Regulation of Hydraulic Fracturing and Other Operations - United States under ITEM 1, Business - Regulation.
We will continue to monitor and assess any proposed or new policies, legislation, regulations and treaties in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations and financial condition. See also the risk factor below regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to regulation of derivatives transactions and entities (such as EOG) that participate in such transactions.
Regulations, government policies and government and corporate initiatives relating to greenhouse gas emissions and climate change could have a significant impact on our operations and we could incur significant cost in the future to comply.
Local, state, federal and international regulatory bodies have been increasingly focused on GHG emissions and climate change issues in recent years. For example, we are subject to the U.S. EPA’s rule requiring annual reporting of GHG emissions. In addition, our oil and gas production and processing operations are subject to the U.S. EPA's new source performance standards applicable to emissions of volatile organic compounds from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations and gas processing plants.
At the international level, in December 2015, the U.S. participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. The Paris Agreement went into effect on November 4, 2016 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. Further, in November 2021, the U.S. Department of the Interior released its “Report on the Federal Oil and Gas Leasing Program”, which recommended increasing royalties associated with oil and gas resources extracted from federal lands and offshore waters to account for corresponding climate costs.
It is possible that the Paris Agreement and subsequent domestic and international regulations and government policies 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 and results of operations. 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 greenhouse gas 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. For additional discussion regarding climate change regulation, see (i) Climate Change - United States under ITEM 1, Business – Regulation and (ii) the risk factor above with respect to the new U.S. administration.
In addition, the achievement of our current or future internal initiatives relating to the reduction of GHG emissions may increase our costs, including requiring us to purchase emissions credits or offsets, the availability and price of which are outside of our control, or may impact or otherwise limit our ability to execute on our business plans. Further, such initiatives relating to the reduction of GHG emissions could be subject to business, regulatory, economic and competitive uncertainties and contingencies, and required advancements in technology.
Tax laws and regulations applicable to crude oil and natural gas exploration and production companies may change over time, and such changes could materially and adversely affect our cash flows, results of operations and financial condition.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal income tax laws applicable to crude oil and natural gas exploration and production companies, such as with respect to the intangible drilling and development costs deduction and bonus tax depreciation. While these specific changes were not included in the Tax Cuts and Jobs Act signed into law in December 2017, no accurate prediction can be made as to whether any such legislative changes or similar or other tax law changes will be proposed in the future (for example, by the new U.S. administration) and, if enacted, what the specific provisions or the effective date of any such legislation would be. The elimination of certain U.S. federal income tax deductions, as well as any other changes to, or the imposition of new, federal, state, local or non-U.S. taxes (including the imposition of, or increases in, production, severance or similar taxes), could materially and adversely affect our cash flows, results of operations and financial condition.
In addition, legislation may be proposed with respect to the enactment of a tax levied on the carbon content of fuels based on the GHG emissions associated with such fuels. A carbon tax would generally increase the prices for crude oil, 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.
Federal legislation and related regulations regarding derivatives transactions could have a material and adverse impact on our hedging activities.
As discussed in the risk factor above regarding our hedging activities, we use derivative instruments to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (CFTC), the U.S. Securities and Exchange Commission (SEC) and certain federal agencies that regulate the banking and insurance sectors (the Prudential Regulators) adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act are yet to be adopted, the CFTC, the SEC and the Prudential Regulators have issued numerous rules, including a rule establishing an “end-user” exception to mandatory clearing (End-User Exception), a rule regarding margin for uncleared swaps (Margin Rule) and a rule imposing position limits (Position Limits Rule).
We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. We also qualify as a "non-financial end user" for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe our hedging activities constitute bona fide hedging under the Position Limits Rule and are therefore not subject to limitation under such rule. However, many of our hedge counterparties and many other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and are subject to the Position Limits Rule. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which apply to our transactions with counterparties subject to such Foreign Regulations.
The Dodd-Frank Act, the rules adopted thereunder and the Foreign Regulations could increase the cost of derivative contracts, alter the terms of derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.
Risks Related to COVID-19, Cybersecurity and Other External Factors
Outbreaks of communicable diseases can adversely affect our business, financial condition and results of operations.
Global or national health concerns, including a widespread outbreak of contagious disease, can, among other impacts, negatively impact the global economy, reduce demand and pricing for crude oil, 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 current pandemic involving a highly transmissible and pathogenic coronavirus (COVID-19) and the measures being taken to address and limit the spread of the virus have adversely affected the economies and financial markets of the world, resulting in an economic downturn that 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, if the COVID-19 outbreak should worsen, we may also experience disruptions to commodities markets, equipment supply chains and the availability of our workforce, which could materially and adversely affect our ability to conduct our business and operations. In addition, if the COVID-19 outbreak were to worsen, resulting in another 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 are still too many variables and uncertainties regarding the COVID-19 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 COVID-19 pandemic; increased logistics costs; additional operating costs due to remote working arrangements, adherence to social distancing guidelines, and other COVID-19-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 are currently unknown or considered immaterial, to fully assess the potential impact on our business, financial condition and results of operations.
Our business could be materially and adversely affected by security threats, including cybersecurity threats, and other disruptions.
As an oil and gas producer, we face various security threats, including (i) cybersecurity threats to gain unauthorized access to, or control of, our sensitive information or to render our data or systems corrupted or unusable; (ii) threats to the security of our facilities and infrastructure or to the security of third-party facilities and infrastructure, such as gathering, transportation, processing, fractionation, refining and export facilities; and (iii) threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material and adverse effect on our business.
We rely extensively on information technology systems, including internally developed software, data hosting platforms, real-time data acquisition systems, third-party software, cloud services and other internally or externally hosted hardware and software platforms, to (i) estimate our oil and gas reserves, (ii) process and record financial and operating data, (iii) process and analyze all stages of our business operations, including exploration, drilling, completions, production, transportation, pipelines and other related activities and (iv) communicate with our employees and vendors, suppliers and other third parties. Further, our reliance on technology has increased due to the increased use of personal devices, remote communications and other work-from-home practices 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;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 of America (United States or U.S.).States. Moreover, external digital technologies control nearly all of the crude oil and natural gas distribution and refining systems in the U.S. and abroad, which are necessary to transport and market our production. A cybersecurity attack directed at, for example, crude oil and natural gas distribution systems could (i) damage critical distribution and storage assets or the environment; (ii) disrupt energy supplies and markets, by delaying or preventing delivery of production to markets; and (iii) make it difficult or impossible to accurately account for production and settle transactions.
Any such terrorist attack or cybersecurity attack that affects us, our customers, suppliers, or others with whom we do business and/or energy-related assets could have a material adverse effect on our business, including disruption of our operations, damage to our reputation, a loss of counterparty trust, reimbursement or other costs, increased compliance costs, significant litigation exposure and legal liability or regulatory fines, penalties or intervention. Although we have business continuity plans in place, our operations may be adversely affected by significant and widespread disruption to our systems and the infrastructure that supports our business. While we continue to evolve and modify our business continuity plans as well as our cyber threat detection and mitigation systems, there can be no assurance that they will be effective in avoiding disruption and business impacts. Further, our insurance may not be adequate to compensate us for all resulting losses, and the cost to obtain adequate coverage may increase for us in the future and some insurance coverage may become more difficult to obtain, if available at all.
While we have experienced limited cybersecurity attacksincidents in the past, we have not sufferedhad, to date, any business interruptions or material losses as a resultfrom breaches of such attacks; however,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.
Terrorist activities and deliver our crude oil, NGLsmilitary and natural gas production could be materially and adversely affected if adequate gathering, processing, compression, storage and transportation 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 and transportation facilities and equipment owned by third parties. These facilities 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 and transportation 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 and transportation facilities, export facilities and equipment by third parties or us, and we may experience delays or increased costs in accessing the pipelines, gathering systems or rail systems necessary to transport our production to points of sale or delivery.
Any significant change in market or other conditions affecting gathering, processing, compression, storage or transportation facilities, export facilities and equipment or the availability of these facilities, including due to our failure or inability to obtain access to these facilities and equipment on terms acceptable to us or at all,actions could materially and adversely affect our businessus.
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 turn, ourresponse to these acts, could cause instability in the global financial condition and resultsenergy 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 operations.terrorist organizations.
If we failAny 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, acquire or find sufficient additional reserves over time, our reservesthe disruption of energy supplies and production will decline from their current levels.
The ratemarkets, the reduction of production fromoverall demand for 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 resultingincreased volatility in additional reserves, acquire additional properties containing reserves or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our reserves will decline as they are produced. Maintaining our production of crude oil and natural gas at,prices or increasing our production from, current levels, is, therefore, highly dependent upon our levelthe possibility that the facilities and other infrastructure on which we rely could be a direct target or an indirect casualty of success in acquiring or finding additional reserves. To the extent we are unsuccessful in acquiring or finding additional reserves, our future cash flows and resultsan act of operationsterrorism, and, in turn, the trading price of our common stock could be materially and adversely affected.
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, in turn, materially and adversely affect our business, results of operations and financial condition.
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 and financial condition.
The regulation of hydraulic fracturing is primarily conducted at the state and local level through permitting and other compliance requirements and, further, some state and local governments have imposed or have considered imposing various conditions and restrictions on drilling and completion operations. In November 2016, however, the U.S. Bureau of Land Management (BLM) issued a final rule that limits venting, flaring and leaking of natural gas from oil and gas wells and equipment on federal and Indian lands (in September 2018, the BLM issued a final rule rescinding certain requirements of the rule). In addition, 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. Further, there have been proposals and positions taken by candidates for elected office and others regarding additional restrictions on, or the complete prohibition of, hydraulic fracturing operations.
Any such requirements, restrictions, conditions or prohibition could lead to operational delays and increased operating and compliance costs and, further, could delay or effectively prevent the development of crude oil and natural gas from formations which would not be economically viable without the use of hydraulic fracturing. Accordingly, our production of crude oil and natural gas could be materially and adversely affected. For additional discussion regarding hydraulic fracturing regulation, see Regulation of Hydraulic Fracturing and Other Operations - United States under ITEM 1, Business - Regulation.
We will continue to monitor and assess any proposed or new policies, legislation, regulations and treaties in the areas where we operate to determine the impact on our operations and take appropriate actions, where necessary. We are unable to predict the timing, scope and effect of any currently proposed or future laws, regulations or treaties, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations and financial condition. See also the risk factor below regarding the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act with respect to regulation of derivatives transactions and entities (such as EOG) that participate in such transactions.
Regulations 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 greenhouse gas (GHG) emissions and climate change issues in recent years. For example, we are subject to the U.S. EPA's rule requiring annual reporting of GHG emissions. In addition, in May 2016, the U.S. EPA issued regulations that require operators to reduce methane emissions and 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, gas processing plants and natural gas transmission compressor stations.
At the international level, in December 2015, the U.S. participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. The Paris Agreement went into effect on November 4, 2016. However, the U.S. has begun the process to withdraw from the Paris Agreement. In response, 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 will have adverse effects on the market for crude oil, natural gas and other fossil fuel products as well as adverse effects on the business and operations of companies engaged in the exploration for, and production of, crude oil, natural gas and other fossil fuel products. We are unable to predict the timing, scope and effect of any currently proposed or future investigations, laws, regulations or treaties regarding climate change and GHG emissions, but the direct and indirect costs of such investigations, laws, regulations and treaties (if enacted) could materially and adversely affect our operations, financial condition and results of operations. For additional discussion regarding climate change regulation, see Climate Change - United States under ITEM 1, Business - Regulation.
Further, increasing attention to global climate change risks has created the potential for a greater likelihood of governmental investigations and private and public litigation, which could increase our costs or otherwise adversely affect our business.
Tax laws and regulations applicable to crude oil and natural gas exploration and production companies may change over time, and such changes could materially and adversely affect our cash flows, results of operations and financial condition.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal income tax laws applicable to crude oil and natural gas exploration and production companies, such as with respect to the intangible drilling and development costs deduction and bonus tax depreciation. While these specific changes were not included in the Tax Cuts and Jobs Act signed into law in December 2017, no accurate prediction can be made as to whether any such legislative changes or similar or other tax law changes will be proposed in the future 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.
A portion of our crude oil, NGLs and natural gas production may be subject to interruptions that could have a material and adverse effect on us.
A portion of our crude oil, NGLs and natural gas production may be interrupted, or shut in, from time to time for various reasons, including, but not limited to, as a result of accidents, weather conditions, the unavailability of gathering, processing, compression, storage, transportation, refining or export facilities or equipment or field labor issues, or intentionally as a result of market conditions such as crude oil, NGLs or natural gas prices that we deem uneconomic. If a substantial amount of our production is interrupted or shut in, our cash flows and, in turn, our financial condition and results of operations could be materially and adversely affected.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an interest are operated by other companies and involve third-party working interest owners. As a result, we have limited ability to influence or control the operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with respect to such properties. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share of the capital expenditures of such projects. In addition, a third-party operator could also decide to shut-in or curtail production from wells, or plug and abandon marginal wells, on properties owned by that operator during periods of lower crude oil, NGLs or natural gas prices. These limitations and our dependence on the operator and third-party working interest owners for these projects could cause us to incur unexpected future costs, lower production and materially and adversely affect our financial condition and results of operations.
If we acquire crude oil, NGLs and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.
From time to time, we seek to acquire crude oil and natural gas properties - for example, our October 2016 mergers and related asset purchase transactions with Yates Petroleum Corporation and certain of its affiliated entities. Although we perform reviews of properties to be acquired in a manner that we believe is duly diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems (such as title or environmental issues), nor may they permit us to become sufficiently familiar with the properties in order to assess fully their deficiencies and potential. Even when problems with a property are identified, we often may assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.
In addition, there are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves (as discussed further below), actual future production rates and associated costs with respect to acquired properties. Actual reserves, production rates and costs may vary substantially from those assumed in our estimates. In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.
We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms, if at all.
We make, and will continue to make, substantial capital expenditures for the acquisition, exploration, development, production and transportation of crude oil, NGLs and natural gas reserves. We intend to finance our capital expenditures primarily through our cash flows from operations, commercial paper borrowings and sales of non-core assets and, to a lesser extent and if and as necessary, bank borrowings, borrowings under our revolving credit facility and public and private equity and debt offerings.
Lower crude oil, NGLs and natural gas prices, however, reduce our cash flows and could also delay or impair our ability to consummate certain planned non-core asset sales and divestitures. Further, if the condition of the credit and capital markets materially declines, we might not be able to obtain financing on terms we consider acceptable, if at all. In addition, weakness and/or volatility in domestic and global financial markets or economic conditions or a depressed commodity price environment may increase the interest rates that lenders and commercial paper investors require us to pay or adversely affect our ability to finance our capital expenditures through equity or debt offerings or other borrowings.
Similarly, a reduction in our cash flows (for example, as a result of lower crude oil, NGLs and natural gas 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.
The inability of our customers and other contractual counterparties to satisfy their obligations to us may have a material and adverse effect on us.
We have various customers for the crude oil, natural gas and related commodities that we produce as well as various other contractual counterparties, including several financial institutions and affiliates of financial institutions. Domestic and global economic conditions, including the financial condition of financial institutions generally, may adversely affect the ability of our customers and other contractual counterparties to pay amounts owed to us from time to time and to otherwise satisfy their contractual obligations to us, as well as their ability to access the credit and capital markets for such purposes.
Moreover, our customers and other contractual counterparties may be unable to satisfy their contractual obligations to us for reasons unrelated to these conditions and factors, such as the unavailability of required facilities or equipment due to mechanical failure or market conditions. Furthermore, if a customer is unable to satisfy its contractual obligation to purchase crude oil, natural gas or related commodities from us, we may be unable to sell such production to another customer on terms we consider acceptable, if at all, due to the geographic location of such production; the availability, proximity and capacity of appropriate gathering, processing, compression, storage, transportation and refining facilities; or market or other factors and conditions.
The inability of our customers and other contractual counterparties to pay amounts owed to us and to otherwise satisfy their contractual obligations to us may materially and adversely affect our business, financial condition, results of operations and cash flows.
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 contract personnel (including geologists, geophysicists, engineers and other specialists) necessary to explore for, develop, produce, market and transport crude oil 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 and natural gas, such as changing worldwide prices and levels of production and the cost and availability of alternative fuels. We also face competition, to a lesser extent, from competing energy sources, such as alternative energy sources.
Reserve estimates depend on many interpretations and assumptions that may turn out to be inaccurate. 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 and our independent petroleum consultants. 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 which 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 revisions or "write-downs" 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.
Weather and climate may have a significant and adverse impact on us.
Demand for crude oil and natural gas is, to a degree, dependent on weather and climate, which impacts, among other things, the price we receive for the commodities that we produce and, in turn, our cash flows and results of operations. For example, relatively warm temperatures during a winter season generally result in relatively lower demand for natural gas (as less natural gas is used to heat residences and businesses) and, as a result, lower prices for natural gas production during that season.
In addition, there has been public discussion that climate change may be associated with more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather events, such as winter storms, flooding and tropical storms and hurricanes in the Gulf of Mexico, which may cause a loss of production from temporary cessation of activity or damaged facilities and equipment. Such extreme weather events could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs, the installation and operation of gathering, processing, compression, storage, transportation and/or export facilities and the availability of, and our access to, necessary third-party services, such as gathering, processing, compression, storage and transportation services and export services. Such extreme weather events and changes in weather patterns may materially and adversely affect our business and, in turn, our financial condition and results of operations.
Our hedging activities may prevent us from benefiting fully from increases in crude oil, NGLs and natural gas prices and may expose us to other risks, including counterparty risk.
We use derivative instruments (primarily financial basis swap, price swap, option, swaption and collar contracts) to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. To the extent that we engage in hedging activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of increases in crude oil, NGLs and natural gas prices above the prices established by our hedging contracts. A portion of our forecasted production for 2020 is subject to fluctuating market prices. If we are ultimately unable to hedge additional production volumes for 2020 and beyond, we will be impacted by any declines in commodity prices, which may result in lower net cash provided by operating activities. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.
Federal legislation and related regulations regarding derivatives transactions could have a material and adverse impact on our hedging activities.
As discussed in the risk factor immediately above, we use derivative instruments to hedge the impact of fluctuations in crude oil, NGLs and natural gas prices on our results of operations and cash flows. In 2010, Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which, among other matters, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (CFTC), the U.S. Securities and Exchange Commission (SEC) and certain federal agencies that regulate the banking and insurance sectors (the Prudential Regulators) adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain categories of swaps and may result in certain market participants needing to curtail their derivatives activities. Although some of the rules necessary to implement the Dodd-Frank Act are yet to be adopted, the CFTC, the SEC and the Prudential Regulators have issued numerous rules, including a rule establishing an "end-user" exception to mandatory clearing (End-User Exception), a rule regarding margin for uncleared swaps (Margin Rule) and a proposed rule imposing position limits (Position Limits Rule).
We qualify as a "non-financial entity" for purposes of the End-User Exception and, as such, we are eligible for such exception. As a result, our hedging activities are not subject to mandatory clearing or the margin requirements imposed in connection with mandatory clearing. We also qualify as a "non-financial end user" for purposes of the Margin Rule; therefore, our uncleared swaps are not subject to regulatory margin requirements. Finally, we believe our hedging activities would constitute bona fide hedging under the Position Limits Rule and would not be subject to limitation under such rule if it is enacted. However, many of our hedge counterparties and many other market participants are not eligible for the End-User Exception, are subject to mandatory clearing and the Margin Rule for swaps with some or all of their other swap counterparties, and may be subject to the Position Limits Rule. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations related to derivatives (collectively, Foreign Regulations) which apply to our transactions with counterparties subject to such Foreign Regulations.
The Dodd-Frank Act, the rules adopted thereunder and the Foreign Regulations could increase the cost of derivative contracts, alter the terms of derivative contracts, reduce the availability of derivatives to protect against the price risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, lessen the number of available counterparties and, in turn, increase our exposure to less creditworthy counterparties. If our use of derivatives is reduced as a result of the Dodd-Frank Act, related regulations or the Foreign Regulations, our results of operations may become more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for, and fund, our capital expenditure requirements. Any of these consequences could have a material and adverse effect on our business, financial condition and results of operations.
Our business and prospects for future success depend to a significant extent upon the continued service and performance of our management team.
Our business and prospects for future success, including the successful implementation of our strategies and handling of issues integral to our future success, depend to a significant extent upon the continued service and performance of our management team. The loss of any member of our management team, and our inability to attract, motivate and retain substitute management personnel with comparable experience and skills, could materially and adversely affect our business, financial condition and results of operations.
We operate in other countries and, as a result, are subject to certain political, economic and other risks.
Our operations in jurisdictions outside the U.S. are subject to various risks inherent in foreign operations. These risks include, among other risks:
increases in taxes and governmental royalties;
changes in laws and policies governing operations of foreign-based companies;
loss of revenue, loss of or damage to equipment, property and other assets and interruption of operations as a result of expropriation, nationalization, acts of terrorism, war, civil unrest and other political risks;
unilateral or forced renegotiation, modification or nullification of existing contracts with governmental entities;
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations; and
currency restrictions or exchange rate fluctuations.
Our international operations may also be adversely affected by U.S. laws and policies affecting foreign trade and taxation, including tariffs or trade or other economic sanctions and modifications to, or withdrawal from, international trade treaties. 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 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, 2019, less than 1% of our net operating revenues related to operations of our foreign subsidiaries whose functional currency was not the U.S. dollar.
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 at times 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 society disruption, could materially and adversely affect us in unpredictable ways, including, but not limited to, the disruption of energy supplies and markets, the reduction of overall demand for crude oil and natural gas, increased volatility in crude oil and natural gas prices or the possibility that the facilities and other infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business, financial condition and results of operations.
ITEM 1B. Unresolved Staff Comments
Not applicable.
ITEM 2. Properties
Oil and Gas Exploration and Production - Properties and Reserves
Reserve Information. For estimates and discussions of EOG's net proved reserves of crude oil and condensate, natural gas liquids (NGLs) and natural gas, the qualifications of the preparers of EOG's reserve estimates, EOG's independent petroleum consultants and EOG's processes and controls with respect to its reserve estimates, see "Supplemental Information to Consolidated Financial Statements."
There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in "Supplemental Information to Consolidated Financial Statements" represent only estimates. Reserve engineering is a complex, subjective process of estimating underground accumulations of crude oil and condensate, NGLs and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates by different engineers normally vary. In addition, results of drilling, testing and production or fluctuations in commodity prices subsequent to the date of an estimate may justify revision of such estimate (upward or downward). Accordingly, reserve estimates are often different from the quantities ultimately recovered. Further, the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. For related discussion, see ITEM 1A, Risk Factors, and "Supplemental Information to Consolidated Financial Statements."
In general, the rate of production from crude oil and natural gas properties declines as reserves are produced. Except to the extent EOG acquires additional properties containing proved reserves, conducts successful exploration, exploitation and development activities or, through engineering studies, identifies additional behind-pipe zones or secondary recovery reserves, the proved reserves of EOG will decline as reserves are produced. The volumes to be generated from future activities of EOG areFuture production is, therefore, highly dependent upon the level of success in finding or acquiring additional reserves.of these activities. For related discussion, see ITEM 1A, Risk Factors. EOG's estimates of reserves filed with other federal agencies are consistent with the information set forth in "Supplemental Information to Consolidated Financial Statements."
Acreage. The following table summarizes EOG's gross and net developed and undeveloped acreage at December 31, 2019.2021 (in thousands). 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 | 2,329 | | | 1,829 | | | 2,852 | | | 1,864 | | | 5,181 | | | 3,693 | |
Trinidad | 80 | | | 67 | | | 216 | | | 125 | | | 296 | | | 192 | |
Oman | — | | | — | | | 4,585 | | | 4,585 | | | 4,585 | | | 4,585 | |
Australia | — | | | — | | | 1,009 | | | 1,009 | | | 1,009 | | | 1,009 | |
Total | 2,409 | | | 1,896 | | | 8,662 | | | 7,583 | | | 11,071 | | | 9,479 | |
|
| | | | | | | | | | | | | | | | | |
| Developed | | Undeveloped | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
| | | | | | | | | | | |
United States | 2,773,841 |
| | 2,034,901 |
| | 3,083,256 |
| | 2,272,783 |
| | 5,857,097 |
| | 4,307,684 |
|
Trinidad | 79,277 |
| | 67,474 |
| | 201,435 |
| | 115,274 |
| | 280,712 |
| | 182,748 |
|
China | 130,548 |
| | 130,548 |
| | — |
| | — |
| | 130,548 |
| | 130,548 |
|
Canada | 39,842 |
| | 35,613 |
| | 103,618 |
| | 96,494 |
| | 143,460 |
| | 132,107 |
|
Total | 3,023,508 |
| | 2,268,536 |
| | 3,388,309 |
| | 2,484,551 |
| | 6,411,817 |
| | 4,753,087 |
|
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 andto five years.Approximately 0.40.2 million net acres will expire in 2020, 0.32022, 0.1 million net acres will expire in 20212023 and 0.1 million net acres will expire in 20222024 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, 2021, there were no proved undeveloped reserves (PUDs) associated with such undeveloped acreage. In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future. As
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.
Acreage associated with EOG's exploration program in Oman was reduced as of December 31, 2019, there were no proved undeveloped reserves2021, due to EOG contractually agreeing with its partner in Block 49 to withdraw.Additionally, EOG does not intend to proceed with additional work commitments and therefore anticipates relinquishing its Block 36 acreage in the third quarter of 2022.
The agreement governing the acreage associated with such undeveloped acreage.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 granted a production license.
Productive Well Summary. The following table represents EOG's gross and net productive wells, including 2,4652,427 wells in which we hold a royalty interest.
|
| | | | | | | | | | | | | | | | | |
| Crude Oil | | Natural Gas | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
| | | | | | | | | | | |
United States | 9,798 |
| | 6,882 |
| | 5,133 |
| | 2,735 |
| | 14,931 |
| | 9,617 |
|
Trinidad | 2 |
| | 2 |
| | 30 |
| | 24 |
| | 32 |
| | 26 |
|
China | — |
| | — |
| | 38 |
| | 38 |
| | 38 |
| | 38 |
|
Canada | — |
| | — |
| | 24 |
| | 23 |
| | 24 |
| | 23 |
|
Total (1) | 9,800 |
| | 6,884 |
| | 5,225 |
| | 2,820 |
| | 15,025 |
| | 9,704 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Crude Oil | | Natural Gas | | Total |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
| | | | | | | | | | | |
United States | 8,999 | | | 6,402 | | | 4,756 | | | 2,850 | | | 13,755 | | | 9,252 | |
Trinidad | 2 | | | 2 | | | 33 | | | 26 | | | 35 | | | 28 | |
Total (1) | 9,001 | | | 6,404 | | | 4,789 | | | 2,876 | | | 13,790 | | | 9,280 | |
| |
(1) | EOG operated 10,641 gross and 9,297 net producing crude oil and natural gas wells at December 31, 2019. Gross crude oil and natural gas wells include 238 wells with multiple completions. |
(1) EOG operated 10,233 gross and 9,064 net producing crude oil and natural gas wells at December 31, 2021. Gross crude oil and natural gas wells include 129 wells with multiple completions.
Drilling and Acquisition Activities. During the years ended December 31, 2019, 20182021, 2020 and 2017,2019, EOG expended $6.6$4.0 billion, $6.4$3.7 billion and $4.4$6.6 billion, respectively, for exploratory and development drilling, facilities and acquisition of leases and producing properties, including asset retirement obligationscosts of $186$127 million, $70$117 million and $56$186 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, 2019, 20182021, 2020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross Development Wells Completed | | Gross Exploratory Wells Completed |
| Crude Oil | | Natural Gas | | Dry Hole | | Total | | Crude Oil | | Natural Gas | | Dry Hole | | Total |
2021 | | | | | | | | | | | | | | | |
United States | 474 | | | 72 | | | 5 | | | 551 | | | 10 | | | 1 | | | 1 | | | 12 | |
Trinidad | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Oman | — | | | — | | | — | | | — | | | — | | | — | | | 3 | | | 3 | |
Total | 474 | | | 72 | | | 5 | | | 551 | | | 10 | | | 1 | | | 4 | | | 15 | |
2020 | | | | | | | | | | | | | | | |
United States | 580 | | | 13 | | | 15 | | | 608 | | | 3 | | | — | | | 4 | | | 7 | |
Trinidad | — | | | — | | | — | | | — | | | — | | | 3 | | | — | | | 3 | |
Total | 580 | | | 13 | | | 15 | | | 608 | | | 3 | | | 3 | | | 4 | | | 10 | |
2019 | | | | | | | | | | | | | | | |
United States | 833 | | | 26 | | | 14 | | | 873 | | | 4 | | | — | | | 1 | | | 5 | |
Trinidad | — | | | 1 | | | — | | | 1 | | | — | | | — | | | 1 | | | 1 | |
China | — | | | 2 | | | — | | | 2 | | | — | | | — | | | 1 | | | 1 | |
Total | 833 | | | 29 | | | 14 | | | 876 | | | 4 | | | — | | | 3 | | | 7 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Gross Development Wells Completed | | Gross Exploratory Wells Completed |
| Crude Oil | | Natural Gas | | Dry Hole | | Total | | Crude Oil | | Natural Gas | | Dry Hole | | Total |
2019 | | | | | | | | | | | | | | | |
United States | 833 |
| | 26 |
| | 14 |
| | 873 |
| | 4 |
| | — |
| | 1 |
| | 5 |
|
Trinidad | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
|
China | — |
| | 2 |
| | — |
| | 2 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | 833 |
| | 29 |
| | 14 |
| | 876 |
| | 4 |
| | — |
| | 3 |
| | 7 |
|
2018 | | | | | | | | | | | | | | | |
United States | 834 |
| | 39 |
| | 22 |
| | 895 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Trinidad | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
China | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | 2 |
| | — |
| | 2 |
|
Total | 834 |
| | 40 |
| | 22 |
| | 896 |
| | — |
| | 2 |
| | 1 |
| | 3 |
|
2017 | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
United States | 568 |
| | 22 |
| | 13 |
| | 603 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Trinidad | — |
| | 8 |
| | — |
| | 8 |
| | — |
| | 1 |
| | — |
| | 1 |
|
China | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | 568 |
| | 33 |
| | 13 |
| | 614 |
| | — |
| | 1 |
| | 2 |
| | 3 |
|
The following tables set forth the results of the net crude oil and natural gas wells completed for the years ended December 31, 2019, 20182021, 2020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net Development Wells Completed | | Net Exploratory Wells Completed |
| Crude Oil | | Natural Gas | | Dry Hole | | Total | | Crude Oil | | Natural Gas | | Dry Hole | | Total |
2021 | | | | | | | | | | | | | | | |
United States | 434 | | | 66 | | | 4 | | | 504 | | | 10 | | | 1 | | | 1 | | | 12 | |
Trinidad | — | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Oman | — | | | — | | | — | | | — | | | — | | | — | | | 3 | | | 3 | |
Total | 434 | | | 66 | | | 4 | | | 504 | | | 10 | | | 1 | | | 4 | | | 15 | |
2020 | | | | | | | | | | | | | | | |
United States | 516 | | | 12 | | | 15 | | | 543 | | | 2 | | | — | | | 3 | | | 5 | |
Trinidad | — | | | — | | | — | | | — | | | — | | | 2 | | | — | | | 2 | |
Total | 516 | | | 12 | | | 15 | | | 543 | | | 2 | | | 2 | | | 3 | | | 7 | |
2019 | | | | | | | | | | | | | | | |
United States | 721 | | | 22 | | | 12 | | | 755 | | | 4 | | | — | | | 1 | | | 5 | |
Trinidad | — | | | 1 | | | — | | | 1 | | | — | | | — | | | 1 | | | 1 | |
China | — | | | 2 | | | — | | | 2 | | | — | | | — | | | 1 | | | 1 | |
Total | 721 | | | 25 | | | 12 | | | 758 | | | 4 | | | — | | | 3 | | | 7 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Net Development Wells Completed | | Net Exploratory Wells Completed |
| Crude Oil | | Natural Gas | | Dry Hole | | Total | | Crude Oil | | Natural Gas | | Dry Hole | | Total |
2019 | | | | | | | | | | | | | | | |
United States | 721 |
| | 22 |
| | 12 |
| | 755 |
| | 4 |
| | — |
| | 1 |
| | 5 |
|
Trinidad | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | 1 |
|
China | — |
| | 2 |
| | — |
| | 2 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | 721 |
| | 25 |
| | 12 |
| | 758 |
| | 4 |
| | — |
| | 3 |
| | 7 |
|
2018 | | | | | | | | | | | | | | | |
United States | 704 |
| | 37 |
| | 18 |
| | 759 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Trinidad | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
China | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | 2 |
| | — |
| | 2 |
|
Total | 704 |
| | 38 |
| | 18 |
| | 760 |
| | — |
| | 2 |
| | 1 |
| | 3 |
|
2017 | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
United States | 490 |
| | 21 |
| | 13 |
| | 524 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Trinidad | — |
| | 6 |
| | — |
| | 6 |
| | — |
| | 1 |
| | — |
| | 1 |
|
China | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | 1 |
| | 1 |
|
Total | 490 |
| | 30 |
| | 13 |
| | 533 |
| | — |
| | 1 |
| | 2 |
| | 3 |
|
EOG participated in the drilling of wells that were in the process of being drilled or completed at the end of the period as set out in the table below for the years ended December 31, 2019, 20182021, 2020 and 2017:2019:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Wells in Progress at End of Period |
| 2021 | | 2020 | | 2019 |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
| | | | | | | | | | | |
United States | 191 | | | 167 | | | 155 | | | 147 | | | 317 | | | 286 | |
Trinidad | 1 | | | 1 | | | 1 | | | 1 | | | 1 | | | 1 | |
China | — | | | — | | | 3 | | | 3 | | | 3 | | | 3 | |
Oman | — | | | — | | | 1 | | | 1 | | | — | | | — | |
Total | 192 | | | 168 | | | 160 | | | 152 | | | 321 | | | 290 | |
|
| | | | | | | | | | | | | | | | | |
| Wells in Progress at End of Period |
| 2019 | | 2018 | | 2017 |
| Gross | | Net | | Gross | | Net | | Gross | | Net |
| | | | | | | | | | | |
United States | 317 |
| | 286 |
| | 297 |
| | 238 |
| | 247 |
| | 208 |
|
Trinidad | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
China | 3 |
| | 3 |
| | 4 |
| | 4 |
| | 1 |
| | 1 |
|
Total | 321 |
| | 290 |
| | 301 |
| | 242 |
| | 248 |
| | 209 |
|
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, 2019,2021, there were approximately 10072 MMBoe of net proved undeveloped reserves (PUDs)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 | | Drilled Uncompleted Wells at End of Period |
| 2019 | | 2018 | | 2017 | | 2021 | | 2020 | | 2019 |
| Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net | | Gross | | Net |
| | | | | | | | | | | | | | | | | | | | | | | |
United States | 188 |
| | 165 |
| | 168 |
| | 137 |
| | 147 |
| | 121 |
| United States | 121 | | | 105 | | | 89 | | | 86 | | | 188 | | | 165 | |
China | 3 |
| | 3 |
| | 3 |
| | 3 |
| | 1 |
| | 1 |
| China | — | | | — | | | 3 | | | 3 | | | 3 | | | 3 | |
Total | 191 |
| | 168 |
| | 171 |
| | 140 |
| | 148 |
| | 122 |
| Total | 121 | | | 105 | | | 92 | | | 89 | | | 191 | | | 168 | |
EOG acquired wells as set forth in the following tables as of the end of each periodtable (excluding the acquisition of additional interests in 11, 1145, 8 and 2911 net wells in which EOG previously owned an interest for the years ended December 31, 2021, 2020 and 2019, 2018respectively) for the years ended December 31, 2021, 2020 and 2017, respectively):2019:
| | | | | | | | | | | | | | | Gross Acquired Wells | | Net Acquired Wells |
| Gross Acquired Wells | | Net Acquired Wells | | Crude Oil | | Natural Gas | | Total | | Crude Oil | | Natural Gas | | Total |
| Crude Oil | | Natural Gas | | Total | | Crude Oil | | Natural Gas | | Total | |
2021 | | 2021 | | | | | | | | | | | |
United States | | United States | 2 | | | 14 | | | 16 | | | 1 | | | 13 | | | 14 | |
Total | | Total | 2 | | | 14 | | | 16 | | | 1 | | | 13 | | | 14 | |
2020 | | 2020 | | | | | | | | | | | |
United States | | United States | 80 | | | 3 | | | 83 | | | 70 | | | 3 | | | 73 | |
Total | | Total | 80 | | | 3 | | | 83 | | | 70 | | | 3 | | | 73 | |
2019 | | | | | | | | | | | | 2019 | | | | | | | | | | | |
United States | 9 |
| | 45 |
| | 54 |
| | 9 |
| | 37 |
| | 46 |
| United States | 9 | | | 45 | | | 54 | | | 9 | | | 37 | | | 46 | |
Total | 9 |
| | 45 |
| | 54 |
| | 9 |
| | 37 |
| | 46 |
| Total | 9 | | | 45 | | | 54 | | | 9 | | | 37 | | | 46 | |
2018 | | | | | | | | | | | | |
United States | 15 |
| | 13 |
| | 28 |
| | 10 |
| | 6 |
| | 16 |
| |
Total | 15 |
| | 13 |
| | 28 |
| | 10 |
| | 6 |
| | 16 |
| |
2017 | |
| | |
| | |
| | |
| | |
| | |
| |
United States | 12 |
| | 3 |
| | 15 |
| | 6 |
| | 2 |
| | 8 |
| |
Total | 12 |
| | 3 |
| | 15 |
| | 6 |
| | 2 |
| | 8 |
| |
Other Property, Plant and Equipment. EOG's other property, plant and equipment primarily includes gathering, transportation and processing infrastructure assets buildings, crude-by-rail assets, and sand mine and sand processing assetsbuildings 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.
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, 2021.
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
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 (NYSE) under the ticker symbol "EOG."
As of February 13, 2020,11, 2022, there were approximately 2,1702,000 record holders and approximately 386,000749,000 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 Purchased as Part of Publicly Announced Plans or Programs | | (d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs (2) |
| | | | | | | | |
October 1, 2019 - October 31, 2019 | | 18,117 |
| | $ | 71.38 |
| | — | | 6,386,200 |
|
November 1, 2019 - November 30, 2019 | | 2,122 |
| | 71.27 |
| | — | | 6,386,200 |
|
December 1, 2019 - December 31, 2019 | | 18,628 |
| | 78.60 |
| | — | | 6,386,200 |
|
Total | | 38,867 |
| | $ | 74.84 |
| | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
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) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2)(3) |
| | | | | | | | |
October 1, 2021 - October 31, 2021 | | 40,557 | | | $ | 89.42 | | | — | | 6,386,200 | |
November 1, 2021 - November 30, 2021 | | 22,852 | | | 94.24 | | | — | | $ | 5,000,000,000 | |
December 1, 2021 - December 31, 2021 | | 15,351 | | | 86.38 | | | — | | $ | 5,000,000,000 | |
Total | | 78,760 | | | $ | 90.22 | | | | | |
| |
(1) | The 38,867 total shares for the quarter ended December 31, 2019, and the 309,888 total shares for the full year 2019, consist solely of shares that were withheld by or returned to EOG (i) in satisfaction of tax withholding obligations that arose upon the exercise of employee stock options or stock-settled stock appreciation rights or the vesting of restricted stock, restricted stock unit or performance unit grants or (ii) in payment of the exercise price of employee stock options. These shares do not count against the 10 million aggregate share repurchase authorization of EOG's Board discussed below. |
| |
(2) | In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock. During 2019, EOG did not repurchase any shares under the Board-authorized repurchase program. EOG last repurchased shares under this program in March 2003. |
(1)The 78,760 total shares for the quarter ended December 31, 2021, and the 503,667 total shares for the full year 2021, 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 either the September 2001 Authorization or the November 2021 Authorization (each as defined and further discussed below).
(2)In September 2001, the Board authorized the repurchase of up to 10,000,000 shares of EOG's common stock (September 2001 Authorization). The September 2001 Authorization was announced on October 2, 2001. EOG did not repurchase any shares under the September 2001 Authorization during the fourth quarter 2021 (through November 3, 2021) and last repurchased shares under the September 2001 Authorization in March 2003.
(3)Effective November 4, 2021, the Board (i) 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) and (ii) revoked and terminated the September 2001 Authorization. Under the November 2021 Authorization (which was announced November 4, 2021), 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 period from November 4, 2021 through December 31, 2021.
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, 2014 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. |
1.$100 was invested on December 31, 2016 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, 2019)2021)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
EOG | $ | 100.00 | | | $ | 107.47 | | | $ | 87.41 | | | $ | 84.96 | | | $ | 51.97 | | | $ | 95.82 | |
S&P 500 | $ | 100.00 | | | $ | 121.83 | | | $ | 116.49 | | | $ | 153.17 | | | $ | 181.36 | | | $ | 233.43 | |
S&P O&G E&P | $ | 100.00 | | | $ | 93.70 | | | $ | 75.43 | | | $ | 84.50 | | | $ | 55.41 | | | $ | 103.66 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 |
EOG | $ | 100.00 |
| | $ | 77.47 |
| | $ | 111.59 |
| | $ | 119.93 |
| | $ | 97.55 |
| | $ | 94.81 |
|
S&P 500 | $ | 100.00 |
| | $ | 101.39 |
| | $ | 113.52 |
| | $ | 138.30 |
| | $ | 132.24 |
| | $ | 173.88 |
|
S&P O&G E&P | $ | 100.00 |
| | $ | 65.85 |
| | $ | 87.47 |
| | $ | 81.96 |
| | $ | 65.98 |
| | $ | 73.91 |
|
ITEM 6. Reserved
Selected Financial Data
(In Thousands, Except Per Share Data)
The following selected consolidated financial information should be read in conjunction with ITEM 7, Management's Discussion and Analysis of Financial Condition and Results of Operations and ITEM 8, Financial Statements and Supplementary Data.
|
| | | | | | | | | | | | | | | | | | | | |
Year Ended December 31 | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | | | | | | | | | |
Statement of Income Data: | | | | | | | | | | |
Operating Revenues and Other (1) | | $ | 17,379,973 |
| | $ | 17,275,399 |
| | $ | 11,208,320 |
| | $ | 7,650,632 |
| | $ | 8,757,428 |
|
Operating Income (Loss) | | $ | 3,699,011 |
| | $ | 4,469,346 |
| | $ | 926,402 |
| | $ | (1,225,281 | ) | | $ | (6,686,079 | ) |
Net Income (Loss) | | $ | 2,734,910 |
| | $ | 3,419,040 |
| | $ | 2,582,579 |
| | $ | (1,096,686 | ) | | $ | (4,524,515 | ) |
Net Income (Loss) Per Share | | | | | | | | | | |
Basic | | $ | 4.73 |
| | $ | 5.93 |
| | $ | 4.49 |
| | $ | (1.98 | ) | | $ | (8.29 | ) |
Diluted | | $ | 4.71 |
| | $ | 5.89 |
| | $ | 4.46 |
| | $ | (1.98 | ) | | $ | (8.29 | ) |
Dividends Per Common Share | | $ | 1.0825 |
| | $ | 0.81 |
| | $ | 0.67 |
| | $ | 0.67 |
| | $ | 0.67 |
|
Average Number of Common Shares | | | | | | | | | | |
Basic | | 577,670 |
| | 576,578 |
| | 574,620 |
| | 553,384 |
| | 545,697 |
|
Diluted | | 580,777 |
| | 580,441 |
| | 578,693 |
| | 553,384 |
| | 545,697 |
|
|
| | | | | | | | | | | | | | | | | | | | |
At December 31 | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | | | | | | | | | |
Balance Sheet Data: | | | | | | | | | | |
Total Property, Plant and Equipment, Net | | $ | 30,364,595 |
| | $ | 28,075,519 |
| | $ | 25,665,037 |
| | $ | 25,707,078 |
| | $ | 24,210,721 |
|
Total Assets (2) (3) (4) | | 37,124,608 |
| | 33,934,474 |
| | 29,833,078 |
| | 29,299,201 |
| | 26,834,908 |
|
Total Debt (4) | | 5,175,443 |
| | 6,083,262 |
| | 6,387,071 |
| | 6,986,358 |
| | 6,655,490 |
|
Total Stockholders' Equity | | 21,640,716 |
| | 19,364,188 |
| | 16,283,273 |
| | 13,981,581 |
| | 12,943,035 |
|
| |
(1) | Effective January 1, 2018, EOG adopted the provisions of Accounting Standards Update (ASU) 2014-09, "Revenue From Contracts With Customers" (ASU 2014-09). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees relating to certain processing and marketing agreements within its United States segment as Gathering and Processing Costs instead of as a deduction to Natural Gas Revenues. There was no impact to operating income, net income or cash flows resulting from changes to the presentation of natural gas processing fees. EOG elected to adopt ASU 2014-09 using the modified retrospective approach with no reclassification of amounts for the years ended December 31, 2017, 2016 and 2015 (see Note 1 to Consolidated Financial Statements). |
| |
(2) | Effective January 1, 2019, EOG adopted the provisions of ASU 2016-02, "Leases (Topic 842)" (ASU 2016-02), which require that lessees recognize a right-of-use (ROU) asset and related lease liability, representing the obligation to make lease payments of certain lease transactions, on the Consolidated Balance Sheets. EOG elected to adopt ASU 2016-02 and other related ASUs using the modified retrospective approach with a cumulative-effect adjustment to the opening balance of retained earnings as of the effective date. Financial results reported in periods prior to January 1, 2019, are unchanged. There was no impact to retained earnings upon adoption of ASU 2016-02 and other related ASUs. See Notes 1 and 18 to Consolidated Financial Statements. |
| |
(3) | Effective January 1, 2017, EOG adopted the provisions of ASU 2015-17, "Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes" (ASU 2015-17), which simplifies the presentation of deferred taxes in a classified balance sheet by eliminating the requirement to separate deferred income tax liabilities and assets into current and noncurrent amounts. Instead, ASU 2015-17 requires that all deferred tax liabilities and assets be shown as noncurrent in a classified balance sheet. In connection with the adoption of ASU 2015-17, EOG restated its Consolidated Balance Sheets at December 31, 2016 and 2015 by $160 million and $136 million, respectively, from deferred tax liabilities to deferred tax assets. |
| |
(4) | Effective January 1, 2016, EOG adopted the provisions of ASU 2015-03, "Interest - Computation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs" (ASU 2015-03). ASU 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct reduction from the related debt liability rather than as an asset. In connection with the adoption of ASU 2015-03, EOG restated its Consolidated Balance Sheets at December 31, 2015 by $4.8 million of unamortized debt issuance costs from Other Assets to Long-Term Debt. |
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Overview
EOG Resources, Inc., together with its subsidiaries (collectively, EOG), is one of the largest independent (non-integrated) crude oil and natural gas companies in the United States with proved reserves in the United States Trinidad and China.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. EachPursuant to this strategy, each prospective drilling location is evaluated by its estimated rate of return. This strategy is intended to enhance the generation of cash flow and earnings from each unit of production on a cost-effective basis, allowing EOG to deliver long-term production growth while maintainingin shareholder value and maintain a strong balance sheet. EOG implements its strategy primarily by emphasizing the drilling of internally generated prospects in order to find and develop low-cost reserves. Maintaining the lowest possible operating cost structure, that is consistentcoupled with efficient and safe operations and environmentally responsible operationsrobust environmental stewardship practices and performance, is also an important goalintegral in the implementation of EOG's strategy.
EOG realized net income of $2,735$4,664 million during 20192021 as compared to a net incomeloss of $3,419$605 million for 2018.2020. At December 31, 2019,2021, EOG's total estimated net proved reserves were 3,3293,747 million barrels of oil equivalent (MMBoe), an increase of 401527 MMBoe from December 31, 2018.2020. During 2019,2021, net proved crude oil and condensate and natural gas liquids (NGLs) reserves increased by 28750 million barrels (MMBbl), and net proved natural gas reserves increased by 6832,862 billion cubic feet or 114477 MMBoe, in each case from December 31, 2018.2020.
Recent Developments
Commodity Prices. In 2020, the COVID-19 pandemic 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 beginning in early 2020 that negatively impacted global demand and prices for crude oil and condensate, NGLs and natural gas. In response, OPEC+, a consortium of OPEC (Organization of Petroleum Exporting Countries) and certain non-OPEC global producers (Russia, Kazakhstan and others), agreed to voluntarily curtail crude oil supplies beginning in April 2020 with a schedule to bring back some of these curtailments through April 2021. Certain other non-OPEC+ countries also curtailed production and/or reduced investments in existing and new crude oil projects. This response started the process of balancing supply with demand.
In 2021, the effects of global COVID-19 mitigation efforts, including extensive global fiscal stimulus and the availability of vaccines, tempered by new COVID-19 variant strains and corresponding containment measures in certain parts of the world, have resulted in overall increased demand for crude oil and condensate, NGLs and natural gas. See ITEM 1A, Risk Factors for discussion of risks related to the COVID-19 pandemic.
During 2021 and into early 2022, OPEC+ continued their schedule of gradually returning all curtailed production through 2022 in response to expected increases in demand for crude oil. The continuing rebalancing of crude oil demand and supply resulting from improving or stabilizing conditions in certain economies and financial markets of the world, combined with the continuing actions taken by OPEC+, had a positive impact on crude oil prices in 2021. Prices for crude oil and condensate and NGLs returned to prepandemic levels in the first quarter of 2021, while natural gas prices returned to pre-pandemic levels at the beginning of 2021.
As a result of the many uncertainties associated with (i) the world economic and political environment, (ii) the COVID-19 pandemic and its continuing effect on the economies and financial markets of the world and (iii) any future actions by the members of OPEC+, and the effect of these uncertainties on worldwide supplies of, and demand for, crude oil and condensate, NGLs and natural gas, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs and natural gas prices in the future. However, prices for crude oil and condensate, NGLs and natural gas have historically been volatile, and this volatility is expected to continue. For related discussion, see ITEM 1A, Risk Factors.
EOG will continue to monitor future market conditions and adjust its capital allocation strategy and production outlook accordingly in order to maximize shareholder value while maintaining its strong financial position.
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, 2019.2021.
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 liquids-richcondensate, NGLs and natural gas production. EOG has placed an emphasis on applying its horizontal drilling and completion expertise to unconventional crude oil and, to a lesser extent, liquids-rich reservoirs.natural gas plays.
During 2019,2021, EOG continued to focus on increasing drilling, completion and operating efficiencies gained in prior years. Such efficiencies resulted in lower operating, drilling and completion costs in 2021. In addition, EOG continued to evaluate certain potential crude oil and liquids-richcondensate, NGLs and natural gas exploration and development prospects and to look for opportunities to add drilling inventory through leasehold acquisitions, farm-ins, exchanges or tactical acquisitions. On a volumetric basis, as calculated using a ratio of 1.0 barrel of crude oil and condensate or NGLs to 6.0 thousand cubic feet of natural gas, crude oil and condensate and NGLs production accounted for approximately 77%75% and 76% of United States production during both 20192021 and 2018.2020, respectively. During 2019,2021, drilling and completion activities occurred primarily in the Delaware Basin play, Eagle Ford play, Delaware Basinoil play and Rocky Mountain area. EOG's major producing areas in the United States are in New Mexico, North Dakota, Texas and Wyoming.New Mexico. EOG faced interruptions to sales in certain markets due to disruptions throughout the United States from Winter Storm Uri in the first quarter of 2021. Winter Storm Uri also negatively impacted Lease and Well, Transportation and Gathering and Processing Costs in the first quarter of 2021. See ITEM 1, Business - Exploration and Production for further discussion regarding EOG's 2021 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 (SECC) 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. Limited (Heritage).
In 2019,March 2021, EOG drilledsigned 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. EOG continues to make progress on the design and completed two net wells in Trinidadfabrication of a platform and wasrelated facilities for its previously announced discovery in the process of drilling another exploratory well at December 31, 2019. One of these wells was a successful development well, while the other well was determinedModified U(a) Block.
In 2022, EOG expects to be an unsuccessful exploratory well. In addition, EOG drilleddrill one stratigraphicnet exploratory well in Trinidad, which discovered commercially economic reserves.the EOG Area in addition to three development wells and one exploratory well in the Modified U(a) Block.
Other International. In Australia, on April 22, 2021, a subsidiary of EOG entered into a purchase and sale agreement to acquire a 100% interest in the Sichuan Basin, Sichuan Province, China,WA-488-P Block, located offshore Western Australia. The transaction was closed in the fourth quarter of 2021 including the transfer of the petroleum exploration permit for that block. In 2022, EOG will continue preparing for the drilling of an exploration well which is expected to commence in 2023.
In the Sultanate of Oman (Oman), a Royal Decree was issued on March 9, 2021, and EOG became a participant in the Exploration and Production Sharing Agreement for Block 49, holding a 50% working interest. EOG's partner in Block 49 completed the drilling and testing of one net exploratory well, which was determined to be a dry hole. EOG notified its partner and the Ministry of Energy and Minerals of its intention to withdraw from Block 49. In Block 36, where EOG holds a 100% working interest, EOG drilled two net exploratory wells and completed one net exploratory well. There was a discovery of natural gas wells in 2019Block 36, but the well results did not yield sufficient projected returns for EOG to completemove forward with the drilling program startedproject. EOG recorded pretax impairment charges of $45 million and dry hole costs of $42 million in 2018.2021. In 2019,2022, EOG also completed twoexpects to exit Block 36.
In May 2021, EOG closed the sale of its subsidiary which held all of its assets in the China Sichuan Basin (China). Net production was approximately 25 million cubic feet per day (MMcfd) of natural gas wells that were drilled duringprior to the 2018 drilling program. All natural gas produced from the Baijaochang Field is sold under a long-term contract to PetroChina.sale. EOG no longer has any operations or assets in China.
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 19% at December 31, 20192021 and 24%22% at December 31, 2018.2020. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
On June 3, 2019,February 1, 2021, EOG repaid upon maturity the $900$750 million aggregate principal amount of its 5.625%4.100% Senior Notes due 2019.2021 (2021 Notes).
On June 27, 2019, EOG entered into a new $2.0 billion senior unsecured Revolving Credit Agreement (New Facility) with domestic and foreign lenders (Banks). The New Facility replaced EOG's $2.0 billion senior unsecured Revolving Credit Agreement, dated as of July 21, 2015, which had a scheduled maturity date of July 21, 2020. The New Facility has a scheduled maturity date of June 27, 2024, and includes an option for EOG to extend, on up to two occasions, the term for successive one-year periods subject to certain terms and conditions. The New Facility (i) commits the Banks to provide advances up to an aggregate principal amount of $2.0 billion at any one time outstanding, with an option for EOG to request increases in the aggregate commitments to an amount not to exceed $3.0 billion, subject to certain terms and conditions, and (ii) includes a swingline subfacility and a letter of credit subfacility.
Effective January 1, 2019, EOG adopted the provisions of Accounting Standards Update (ASU) 2016-02, "Leases (Topic 842)" (ASU 2016-02). ASU 2016-02 and other related ASUs resulted in the recognition of right-of-use assets and related lease liabilities representing the obligation to make lease payments for certain lease transactions and the disclosure of additional leasing information. The adoption of ASU 2016-02 and other related ASUs resulted in a significant increase to assets and liabilities related to operating leases on the Consolidated Balance Sheet at December 31, 2019. Financial results prior to January 1, 2019, are unchanged. See Note 1 "Summary of Significant Accounting Policies" and Note 18 "Leases" to EOG's Consolidated Financial Statements in this Annual Report on Form 10-K.
During 2019,2021, EOG funded $6.7$4.1 billion ($152124 million of which was non-cash) in exploration and development and other property, plant and equipment expenditures (excluding asset retirement obligations), repaid $900 million aggregate principal amount of long-term debt, paid $588$2,684 million in dividends to common stockholders and purchased $25 million of treasury stock in connection with stock compensation plans,repaid the 2021 Notes, primarily by utilizing net cash provided from its operating activities and net proceeds of $140$231 million from the sale of assets.
Total anticipated 20202022 capital expenditures are estimated to range from approximately $6.3$4.3 billion to $6.7$4.7 billion, excluding acquisitions and non-cash exchanges.transactions. The majority of 20202022 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 New Facility,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.
Dividend Declarations and Share Repurchase Authorization. On February 25, 2021, EOG's Board increased the quarterly cash dividend on the common stock from the previous $0.375 per share to $0.4125 per share, effective beginning with the dividend paid on April 30, 2021, to stockholders of record as of April 16, 2021.
On May 6, 2021, EOG's Board declared a special cash dividend on the common stock of $1.00 per share. The special cash dividend, which was in addition to the quarterly cash dividend, was paid on July 30, 2021 to stockholders of record as of July 16, 2021.
On November 4, 2021, EOG's Board (i) further increased the quarterly cash dividend on the common stock from the previous $0.4125 per share to $0.75 per share, effective beginning with the dividend paid on January 28, 2022, to stockholders of record as of January 14, 2022, (ii) declared a special cash dividend on the common stock of $2.00 per share, paid on December 30, 2021, to stockholders of record as of December 15, 2021, (iii) established a new share repurchase authorization to allow for the repurchase by EOG of up to $5 billion of the common stock and (iv) revoked and terminated the share repurchase authorization established by the Board in September 2001. See ITEM 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities for additional discussion.
On February 24, 2022, the Board declared a quarterly cash dividend on the common stock of $0.75 per share payable April 29, 2022, to stockholders of record as of April 15, 2022. The Board also declared a special dividend of $1.00 per share payable March 29, 2022, to stockholders of record as of March 15, 2022.
Results of Operations
The following review of operations for each of the three years in the period ended December 31, 2019,2021, should be read in conjunction with the consolidated financial statements of EOG and notes thereto beginning on page F-1.
Operating Revenues and Other
During 2019,2021, operating revenues increased $105$7,610 million,, or 1%69%, to $17,380$18,642 million from $17,275$11,032 million in 2018.2020. Total wellhead revenues, which are revenues generated from sales of EOG's production of crude oil and condensate, NGLs and natural gas, decreased $365increased $8,090 million, or 3%111%, to $11,581$15,381 million in 20192021 from $11,946$7,291 million in 2018.2020. Revenues from the sales of crude oil and condensate and NGLs in 20192021 were approximately 90%84% of total wellhead revenues compared to 89% in 2018.2020. During 2019,2021, EOG recognized net gainslosses on the mark-to-market of financial commodity derivative contracts of $180$1,152 million compared to net lossesgains of $166$1,145 million in 2018.2020. Gathering, processing and marketing revenues increased $130$1,705 million during 2019,2021, to $5,360$4,288 million from $5,230$2,583 million in 2018. Net gains on asset dispositions of $124 million in 2019 were primarily as a result of sales of producing properties, acreage and other assets, as well as non-cash property exchanges, in New Mexico compared to2020. EOG recognized net gains on asset dispositions of $175$17 million in 2018.2021 compared to net losses on asset dispositions of $47 million in 2020.
Wellhead volume and price statistics for the years ended December 31, 2019, 20182021, 2020 and 20172019 were as follows:
|
| | | | | | | | | | | | |
Year Ended December 31 | | 2019 | | 2018 | | 2017 |
| | | | | | |
Crude Oil and Condensate Volumes (MBbld) (1) | | | | | | |
United States | | 455.5 |
| | 394.8 |
| | 335.0 |
|
Trinidad | | 0.6 |
| | 0.8 |
| | 0.9 |
|
Other International (2) | | 0.1 |
| | 4.3 |
| | 0.8 |
|
Total | | 456.2 |
| | 399.9 |
| | 336.7 |
|
Average Crude Oil and Condensate Prices ($/Bbl) (3) | | | | |
| | |
|
United States | | $ | 57.74 |
| | $ | 65.16 |
| | $ | 50.91 |
|
Trinidad | | 47.16 |
| | 57.26 |
| | 42.30 |
|
Other International (2) | | 57.40 |
| | 71.45 |
| | 57.20 |
|
Composite | | 57.72 |
| | 65.21 |
| | 50.91 |
|
Natural Gas Liquids Volumes (MBbld) (1) | | | | | | |
United States | | 134.1 |
| | 116.1 |
| | 88.4 |
|
Other International (2) | | — |
| | — |
| | — |
|
Total | | 134.1 |
| | 116.1 |
| | 88.4 |
|
Average Natural Gas Liquids Prices ($/Bbl) (3) | | | | |
| | |
|
United States | | $ | 16.03 |
| | $ | 26.60 |
| | $ | 22.61 |
|
Other International (2) | | — |
| | — |
| | — |
|
Composite | | 16.03 |
| | 26.60 |
| | 22.61 |
|
Natural Gas Volumes (MMcfd) (1) | | | | | | |
United States | | 1,069 |
| | 923 |
| | 765 |
|
Trinidad | | 260 |
| | 266 |
| | 313 |
|
Other International (2) | | 37 |
| | 30 |
| | 25 |
|
Total | | 1,366 |
| | 1,219 |
| | 1,103 |
|
Average Natural Gas Prices ($/Mcf) (3) | | | | |
| | |
|
United States | | $ | 2.22 |
| | $ | 2.88 |
| | $ | 2.20 |
|
Trinidad | | 2.72 |
| | 2.94 |
| | 2.38 |
|
Other International (2) | | 4.44 |
| | 4.08 |
| | 3.89 |
|
Composite | | 2.38 |
| | 2.92 |
| (4) | 2.29 |
|
Crude Oil Equivalent Volumes (MBoed) (5) | | | | | | |
United States | | 767.8 |
| | 664.7 |
| | 551.0 |
|
Trinidad | | 44.0 |
| | 45.1 |
| | 53.0 |
|
Other International (2) | | 6.2 |
| | 9.4 |
| | 4.9 |
|
Total | | 818.0 |
| | 719.2 |
| | 608.9 |
|
| | | | | | |
Total MMBoe (5) | | 298.6 |
| | 262.5 |
| | 222.3 |
|
| | | | | | | | | | | | | | | | | | | | |
Year Ended December 31 | | 2021 | | 2020 | | 2019 |
| | | | | | |
Crude Oil and Condensate Volumes (MBbld) (1) | | | | | | |
United States | | 443.4 | | | 408.1 | | | 455.5 | |
Trinidad | | 1.5 | | | 1.0 | | | 0.6 | |
Other International (2) | | 0.1 | | | 0.1 | | | 0.1 | |
Total | | 445.0 | | | 409.2 | | | 456.2 | |
Average Crude Oil and Condensate Prices ($/Bbl) (3) | | | | | | |
United States | | $ | 68.54 | | | $ | 38.65 | | | $ | 57.74 | |
Trinidad | | 56.26 | | | 30.20 | | | 47.16 | |
Other International (2) | | 42.36 | | | 43.08 | | | 57.40 | |
Composite | | 68.50 | | | 38.63 | | | 57.72 | |
Natural Gas Liquids Volumes (MBbld) (1) | | | | | | |
United States | | 144.5 | | | 136.0 | | | 134.1 | |
Other International (2) | | — | | | — | | | — | |
Total | | 144.5 | | | 136.0 | | | 134.1 | |
Average Natural Gas Liquids Prices ($/Bbl) (3) | | | | | | |
United States | | $ | 34.35 | | | $ | 13.41 | | | $ | 16.03 | |
Other International (2) | | — | | | — | | | — | |
Composite | | 34.35 | | | 13.41 | | | 16.03 | |
Natural Gas Volumes (MMcfd) (1) | | | | | | |
United States | | 1,210 | | | 1,040 | | | 1,069 | |
Trinidad | | 217 | | | 180 | | | 260 | |
Other International (2) | | 9 | | | 32 | | | 37 | |
Total | | 1,436 | | | 1,252 | | | 1,366 | |
Average Natural Gas Prices ($/Mcf) (3) | | | | | | |
United States | | $ | 4.88 | | | $ | 1.61 | | | $ | 2.22 | |
Trinidad | | 3.40 | | | 2.57 | | | 2.72 | |
Other International (2) | | 5.67 | | | 4.66 | | | 4.44 | |
Composite | | 4.66 | | | 1.83 | | | 2.38 | |
Crude Oil Equivalent Volumes (MBoed) (4) | | | | | | |
United States | | 789.6 | | | 717.5 | | | 767.8 | |
Trinidad | | 37.7 | | | 30.9 | | | 44.0 | |
Other International (2) | | 1.6 | | | 5.4 | | | 6.2 | |
Total | | 828.9 | | | 753.8 | | | 818.0 | |
| | | | | | |
Total MMBoe (4) | | 302.5 | | | 275.9 | | | 298.6 | |
| |
(1) | (1) Thousand barrels per day or million cubic feet per day, as applicable. |
| |
(2) | Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018. |
| |
(3) | Dollars per barrel or per thousand cubic feet, as applicable. Excludes the impact of financial commodity derivative instruments (see Note 12 to Consolidated Financial Statements). |
| |
(4) | Includes a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09, "Revenue From Contracts with Customers" (ASU 2014-09) (see Note 1 to the Consolidated Financial Statements). In connection with the adoption of ASU 2014-09, EOG presents natural gas processing fees related to certain processing and marketing agreements as Gathering and Processing Costs, instead of as a deduction to Natural Gas revenues. |
| |
(5) | 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. |
2019(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.
2021 compared to 2018.2020. Wellhead crude oil and condensate revenues in 20192021 increased $96$5,339 million, or 1%92%, to $9,613$11,125 million from $9,517$5,786 million in 2018,2020, due primarily to an increase in production ($1,351 million), partially offset by a lowerhigher composite average wellhead crude oil and condensate price ($1,2554,852 million) and an increase in production ($487 million). EOG's composite wellhead crude oil and condensate price for 2019 decreased 11%2021 increased 77% to $57.72$68.50 per barrel compared to $65.21$38.63 per barrel in 2018.2020. Wellhead crude oil and condensate production in 20192021 increased 14%9% to 456445 MBbld as compared to 400409 MBbld in 2018.2020. The increased production was primarily in the Permian Basin, andpartially offset by decreased production in the Eagle Ford.Ford oil play.
NGLs revenues in 2019 decreased $3432021 increased $1,144 million, or 30%171%, to $784$1,812 million from $1,127$668 million in 20182020 primarily due to a lowerhigher composite average wellhead NGLs price ($5181,104 million), partially offset by and an increase in production ($17540 million). EOG's composite average wellhead NGLs price decreased 40%increased 156% to $16.03$34.35 per barrel in 20192021 compared to $26.60$13.41 per barrel in 2018.2020. NGL production in 20192021 increased 16%6% to 134145 MBbld as compared to 116136 MBbld in 2018.2020. The increased production was primarily in the Permian Basin.
Wellhead natural gas revenues in 2019 decreased $1182021 increased $1,607 million, or 9%192%, to $1,184$2,444 million from $1,302$837 million in 2018,2020, primarily due to a lowerhigher composite wellhead natural gas price ($2801,486 million), partially offset by and an increase in natural gas deliveries ($162121 million). EOG's composite average wellhead natural gas price decreased 18%increased 155% to $2.38$4.66 per Mcf in 20192021 compared to $2.92$1.83 per Mcf in 2018.2020. Natural gas deliveries in 20192021 increased 12%15% to 1,3661,436 MMcfd as compared to 1,2191,252 MMcfd in 2018.2020. The increase in production was primarily due to higher deliveries in the United States resulting from increased production of associated natural gas from the Permian Basin and higher natural gas volumes in South Texas.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 2019,2021, 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, NGL 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 $180$1,145 million, which included net cash received forfrom settlements of crude oil, NGL and natural gas financial derivative contracts of $231 million. During 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash paid for settlements of crude oil and natural gas financial derivative contracts of $259$1,071 million.
Gathering, processing and marketing revenues are revenues generated from sales of third-party crude oil, NGLs and natural gas, as well as fees associated with gathering third-party natural gas and revenues from sales of EOG-owned sand. Purchases and sales of third-party crude oil and natural gas may be utilized in order to balance firm transportation capacity at third-party facilities with production in certain areas and to utilize excess capacity at EOG-owned facilities. EOG sells sand in order to balance the timing of firm purchase agreements with completion operations and to utilize excess capacity at EOG-owned facilities.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 2019 decreased $182021 increased $230 million compared to 2018,2020, primarily due to lowerhigher margins on crude oil and condensate marketing activities, partially offset by higher margins onand 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.
2018
2020 compared to 2017.2019. Wellhead crude oil and condensate revenues in 2018 increased $3,2612020 decreased $3,827 million, or 52%40%, to $9,517$5,786 million from $6,256$9,613 million in 2017,2019, due primarily to a higherlower composite average wellhead crude oil and condensate price ($2,0882,860 million) and an increasea decrease in production ($1,173967 million). EOG's composite wellhead crude oil and condensate price for 2018 increased 28%2020 decreased 33% to $65.21$38.63 per barrel compared to $50.91$57.72 per barrel in 2017.2019. Wellhead crude oil and condensate production in 2018 increased 19%2020 decreased 10% to 400409 MBbld as compared to 337456 MBbld in 2017.2019. The decreased production was primarily in the Eagle Ford oil play and the Rocky Mountain area, partially offset by increased production in the Permian Basin.
NGLs revenues in 2020 decreased $116 million, or 15%, to $668 million from $784 million in 2019 primarily due to a lower composite average wellhead NGLs price ($130 million), partially offset by an increase in production ($13 million). EOG's composite average wellhead NGLs price decreased 16% to $13.41 per barrel in 2020 compared to $16.03 per barrel in 2019. NGL production in 2020 increased 1% to 136 MBbld as compared to 134 MBbld in 2019. The increased production was primarily in the Permian Basin, andpartially offset by decreased production of associated NGLs in the Eagle Ford.Ford oil play.
NGLs revenues in 2018 increased $398 million, or 55%, to $1,127 million from $729 million in 2017 primarily due to an increase in production ($229 million) and a higher composite average wellhead NGLs price ($169 million). EOG's composite average wellhead NGLs price increased 18% to $26.60 per barrel in 2018 compared to $22.61 per barrel in 2017. NGLs production in 2018 increased 31% to 116 MBbld as compared to 88 MBbld in 2017. The increased production was primarily in the Permian Basin and the Eagle Ford.
Wellhead natural gas revenues in 2018 increased $3802020 decreased $347 million, or 41%29%, to $1,302$837 million from $922$1,184 million in 2017,2019, primarily due to a higherlower composite wellhead natural gas price ($282251 million) and an increasea decrease in wellhead natural gas deliveries ($9896 million). EOG's composite average wellhead natural gas price increased 28%decreased 23% to $2.92$1.83 per Mcf in 20182020 compared to $2.29$2.38 per Mcf in 2017. This increase in composite wellhead natural gas prices includes a positive revenue adjustment of $0.44 per Mcf related to the adoption of ASU 2014-09.2019. Natural gas deliveries in 2018 increased 11%2020 decreased 8% to 1,2191,252 MMcfd as compared to 1,1031,366 MMcfd in 2017.2019. The increasedecrease in production was primarily due to increased productionlower natural gas volumes in Trinidad, the United States (158 MMcfd),Marcellus Shale and the Rocky Mountain area, partially offset by decreased production in Trinidad (47 MMcfd). The increased production in the United States was due primarily to increased production of associated natural gas infrom the Permian Basin and Rocky Mountain area and higher volumes in the Marcellus Shale. The decrease in Trinidad was primarily attributable to higher contractual deliveries in 2017.Basin.
During 2018, EOG recognized net losses on the mark-to-market of financial commodity derivative contracts of $166 million, which included net cash paid for settlements of crude oil and natural gas financial derivative contracts of $259 million. During 2017,2020, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $20$1,145 million, which included net cash received fromfor settlements of crude oil, NGL and natural gas financial derivative contracts of $1,071 million. During 2019, EOG recognized net gains on the mark-to-market of financial commodity derivative contracts of $180 million, which included net cash received for settlements of crude oil and natural gas financial derivative contracts of $7$231 million.
Gathering, processing and marketing revenues less marketing costs in 2018 increased $592020 decreased $124 million compared to 2017,2019, primarily due to higherlower margins on crude oil and condensate marketing activities. The margin on crude oil marketing activities in 2020 was negatively impacted by the price decline for crude oil in inventory awaiting delivery to customers and EOG's decision early in the second quarter of 2020 to reduce commodity price volatility by selling May and June 2020 deliveries under fixed price arrangements.
Operating and Other Expenses
20192021 compared to 20182020. During 2019,2021, operating expenses of $13,681$12,540 million were $875$964 million higher than the $12,806$11,576 million incurred during 2018.2020. The following table presents the costs per barrel of oil equivalent (Boe) for the years ended December 31, 20192021 and 2018:2020:
|
| | | | | | | |
| 2019 | | 2018 |
| | | |
Lease and Well | $ | 4.58 |
| | $ | 4.89 |
|
Transportation Costs | 2.54 |
| | 2.85 |
|
Depreciation, Depletion and Amortization (DD&A) - | | | |
Oil and Gas Properties | 12.25 |
| | 12.65 |
|
Other Property, Plant and Equipment | 0.31 |
| | 0.44 |
|
General and Administrative (G&A) | 1.64 |
| | 1.63 |
|
Net Interest Expense | 0.62 |
| | 0.93 |
|
Total (1) | $ | 21.94 |
| | $ | 23.39 |
|
| | | | | | | | | | | |
| 2021 | | 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 gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income. |
(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 20192021 compared to 20182020 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes.
Lease and well expenses include expenses for EOG-operated properties, as well as expenses billed to EOG from other operators where EOG is not the operator of a property. Lease and well expenses can be divided into the following categories: costs to operate and maintain crude oil and natural gas wells, the cost of workovers and lease and well administrative expenses. Operating and maintenance costs include, among other things, pumping services, salt water disposal, equipment repair and maintenance, compression expense, lease upkeep and fuel and power. Workovers are operations to restore or maintain production from existing wells.
Each of these categories of costs individually fluctuates from time to time as EOG attempts to maintain and increase production while maintaining efficient, safe and environmentally responsible operations. EOG continues to increase its operating activities by drilling new wells in existing and new areas. Operating and maintenance costs within these existing and new areas, as well as the costs of services charged to EOG by vendors, fluctuate over time.
Lease and well expenses of $1,367$1,135 million in 20192021 increased $84$72 million from $1,283$1,063 million in 20182020 primarily due to higher operating and maintenance costs in the United States ($7633 million) and in Trinidad ($5 million), higher workovers expenditures in the United States ($25 million) and higher lease and well administrative expenses ($29 million) in the United States ($12 million); partially offset by lower operating and maintenance costs in Canada ($6 million) and as a result of the United Kingdom ($15 million) due todisposition of all of the sale of operationsChina assets in the fourthsecond quarter of 2018 and in Canada2021 ($115 million). Lease and well expenses increased in the United States primarily due to increased operating activities resulting infrom 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 $758$863 million in 20192021 increased $11$128 million from $747$735 million in 20182020 primarily due to increased transportation costs in the Permian Basin ($91121 million) and South Texasthe Rocky Mountain area ($1122 million), partially offset by decreased transportation costs in the Eagle Ford oil play ($7713 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 $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 Fort WorthRocky Mountain area ($10 million), increased operating costs in the Permian Basin Barnett Shale ($1326 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 oil play ($5 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 20192021 increased $315$251 million to $3,750$3,651 million from $3,435$3,400 million in 2018.2020. DD&A expenses associated with oil and gas properties in 20192021 were $337$235 million higher than in 20182020 primarily due to an increase in production in the United States ($489307 million) and Trinidad ($12 million) and higher unit rates in Trinidad ($14 million), partially offset by lower unit rates in the United States ($119 million) and the sale of the United Kingdom operations in the fourth quarter of 2018 ($3385 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 $489$511 million in 20192021 increased $62$27 million from $427$484 million in 20182020 primarily due to increaseda net increase in costs associated with corporate support activities, including employee-related expenses ($48 million) and increased information systemssystem costs ($854 million) resulting from expanded operations.; partially offset by a decrease in idle equipment and termination fees ($46 million).
Net interest expense of $185$178 million in 20192021 was $60$27 million lower than 20182020 primarily due to repayment in February 2021 of the $900$750 million aggregate principal amount of 5.625%4.100% Senior Notes due 20192021 ($29 million), repayment in June 2019 ($30 million) and2020 of the $350$500 million aggregate principal amount of 6.875%4.40% Senior Notes due 20182020 ($9 million), repayment in October 2018April 2020 of the $500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($183 million) and an increase in capitalizedlower interest ($14 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. See Note 1 to the Consolidated Financial Statementspayments for discussion related to EOG's adoption of ASU 2014-09.
Gathering and processing costs increased $42 million to $479 million in 2019 compared to $437 million in 2018 primarily due to increased operating costs and fees in the Permian Basinlate royalty payments on Oklahoma properties ($526 million), the Rocky Mountain area ($13 million) and South Texas ($5 million); partially offset by decreased operating coststhe issuance in April 2020 of the United Kingdom$750 million aggregate principal amount of 4.950% Senior Notes due 2050 ($3311 million) and $750 million aggregate principal amount of 4.375% Senior Notes due to the sale of operations in the fourth quarter of 2018.2030 ($10 million).
Exploration costs of $140$154 million in 2019 decreased $92021 increased $8 million from $149$146 million in 20182020 primarily due to decreasedincreased geological and geophysical expenditures in Trinidad ($17 million), partially offset by increased general and administrative expenses in the United States ($7 million).States.
Impairments includeinclude: amortization of unproved oil and gas property costs as well as impairments of proved oil and gas properties; other property, plant and equipment; and other assets. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. When circumstances indicate that a proved property may be impaired, EOG compares expected undiscounted future cash flows at a DD&A group level to the unamortized capitalized cost of the asset.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, 20192021 and 20182020 (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 | |
|
| | | | | | | |
| 2019 | | 2018 |
| | | |
Proved properties | $ | 207 |
| | $ | 121 |
|
Unproved properties | 220 |
| | 173 |
|
Other assets | 91 |
| | 49 |
|
Inventories | — |
| | 4 |
|
Total | $ | 518 |
| | $ | 347 |
|
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 20192020 were primarily for the write-down to fair value of sand and 2018.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 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 20192021 increased $28$569 million to $800$1,047 million (6.9%(6.8% of wellhead revenues) from $772$478 million (6.5%(6.6% of wellhead revenues) in 2018.2020. The increase in taxes other than income was primarily due to an increase in ad valorem/property taxes ($53 million), partially offset by an increase in credits available to EOG in 2019 for state incentive severance tax rate reductions ($12 million) and a decrease inincreased severance/production taxes ($12 million) primarily as a result of decreased wellhead revenues, all in the United States.
Other income, net, was $31 millionStates ($522 million), increased severance/production taxes in 2019 compared to other income, net, of $17 million in 2018. The increase of $14 million in 2019 was primarily due to an increase in interest incomeTrinidad ($147 million) and an increase in foreign currency transaction gainsdecreased state severance tax refunds ($9 million), partially offset by an increase in deferred compensation expense ($439 million).
EOG recognized an income tax provision of $810$1,269 million in 20192021 compared to an income tax provisionbenefit of $822$134 million in 2018,2020, primarily due to decreasedincreased pretax income, partially offset by the absence of tax benefits from certain tax reform measurement-period adjustments.income. The net effective tax rate for 20192021 increased to 23%21% from 19%18% in the prior year, primarily2020. The higher effective tax rate is mostly due to taxes attributable to EOG's foreign operations and stock-based compensation tax deficiencies increasing the absence ofeffective tax benefits from certainrate on pretax income in 2021 and decreasing the effective tax reform measurement-period adjustments.
rate on pretax loss in 2020.
2018
2020 compared to 20172019. During 2018,2020, operating expenses of $12,806$11,576 million were $875$2,105 million higherlower than the $10,282$13,681 million incurred during 2017.2019. The following table presents the costs per barrel of oil equivalent (Boe)Boe for the years ended December 31, 20182020 and 2017:2019:
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Lease and Well | $ | 4.89 |
| | $ | 4.70 |
|
Transportation Costs | 2.85 |
| | 3.33 |
|
Depreciation, Depletion and Amortization (DD&A) - | | | |
Oil and Gas Properties | 12.65 |
| | 14.83 |
|
Other Property, Plant and Equipment | 0.44 |
| | 0.51 |
|
General and Administrative (G&A) | 1.63 |
| | 1.95 |
|
Net Interest Expense | 0.93 |
| | 1.23 |
|
Total (1) | $ | 23.39 |
| | $ | 26.55 |
|
| | | | | | | | | | | |
| 2020 | | 2019 |
| | | |
Lease and Well | $ | 3.85 | | | $ | 4.58 | |
Transportation Costs | 2.66 | | | 2.54 | |
Gathering and Processing Costs | 1.66 | | | 1.60 | |
Depreciation, Depletion and Amortization (DD&A) - | | | |
Oil and Gas Properties | 11.85 | | | 12.25 | |
Other Property, Plant and Equipment | 0.47 | | | 0.31 | |
General and Administrative (G&A) | 1.75 | | | 1.64 | |
Net Interest Expense | 0.74 | | | 0.62 | |
Total (1) | $ | 22.98 | | | $ | 23.54 | |
| |
(1) | Total excludes gathering and processing costs, exploration costs, dry hole costs, impairments, marketing costs and taxes other than income. |
(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 20182020 compared to 20172019 are set forth below. See "Operating Revenues and Other" above for a discussion of production volumes.
Lease and well expenses of $1,283$1,063 million in 2018 increased $2382020 decreased $304 million from $1,045$1,367 million in 20172019 primarily due to higher operating and maintenance costs ($171 million), higher workover expenditures ($44 million) and higher lease and well administrative expenses ($41 million), all in the United States, partially offset by lower operating and maintenance costs in the United KingdomStates ($18157 million) and in Canada ($25 million), lower workovers expenditures in the United States ($103 million) and lower lease and well administrative expenses in the United States ($12 million).Lease and well expenses increaseddecreased in the United States primarily due to increaseddecreased operating activities resulting in increased production.from decreased production, efficiency improvements and service cost reductions.
Transportation costs of $747$735 million in 2018 increased $72020 decreased $23 million from $740$758 million in 20172019 primarily due to increased transportation costs in the Permian Basin ($116 million), partially offset by decreased transportation costs in the Fort Worth Basin Barnett Shale ($5227 million), the Eagle Ford ($31 million) and the Rocky Mountain area ($2524 million) and the Eagle Ford oil play ($20 million), partially offset by increased transportation costs in the Permian Basin ($56 million).
Gathering and processing costs decreased $20 million to $459 million in 2020 compared to $479 million in 2019 primarily due to decreased operating costs in the Eagle Ford ($16 million) and decreased gathering and processing fees in the Eagle Ford oil play ($9 million) and the Fort Worth Basin Barnett Shale ($5 million); partially offset by increased gathering and processing fees in the Permian Basin ($15 million).
DD&A expenses in 2018 increased $262020 decreased $350 million to $3,435$3,400 million from $3,409$3,750 million in 2017.2019. DD&A expenses associated with oil and gas properties in 20182020 were $24$390 million higherlower than in 20172019 primarily due to an increasea decrease in production in the United States ($647222 million) and the United KingdomTrinidad ($2122 million), partially offset by and lower unit rates in the United States ($625150 million) and a decrease in production in Trinidad ($16 million).Unit rates in the United States decreased primarily due to upward reserve revisions and reserves added at lower costs as a result of increased efficiencies.DD&A expenses associated with other property, plant and equipment in 2020 were $40 million higher than in 2019 primarily due to an increase in expense related to gathering and storage assets and equipment.
G&A expenses of $427$484 million in 20182020 decreased $7$5 million from $434$489 million in 20172019 primarily due to decreased employee-related expenses ($43 million) and professional legal and other services ($247 million);, partially offset by increased employee-related expenses resulting from expanded operationsidle equipment and termination fees ($15 million) and increased information systems costs ($1046 million).
Net interest expense of $245$205 million in 20182020 was $29$20 million lowerhigher than 20172019 primarily due to repaymentthe issuance of the $600Notes in April 2020 ($51 million) and lower capitalized interest ($7 million), partially offset by repayment in June 2019 of the $900 million aggregate principal amount of 5.875%5.625% Senior Notes due 20172019 ($21 million), repayment in September 2017 ($25 million) andJune 2020 of the $350$500 million aggregate principal amount of 6.875%4.40% Senior Notes due 20182020 ($13 million) and repayment in October 2018April 2020 of the $500 million aggregate principal amount of 2.45% Senior Notes due 2020 ($610 million).
Exploration costs of $146 million in 2020 increased $6 million from $140 million in 2019 primarily due to increased geological and geophysical expenditures in the United States ($15 million), partially offset by a decrease in capitalized interest ($3 million).
Gathering and processing costs increased $288 million to $437 million in 2018 compared to $149 million in 2017 primarily due to the adoption of ASU 2014-09 ($204 million) and increased operating costs in the Permian Basin ($32 million), the United Kingdom ($28 million) and the Eagle Ford ($25 million).
Exploration costs of $149 million in 2018 increased $4 million from $145 million in 2017 primarily due to increaseddecreased general and administrative expenses in the United States ($7 million), partially offset by decreased geological and geophysical expenditures in Trinidad ($58 million).
The following table represents impairments for the years ended December 31, 20182020 and 20172019 (in millions):
| | | | | | | | | | | |
| 2020 | | 2019 |
| | | |
Proved properties | $ | 1,268 | | | $ | 207 | |
Unproved properties | 472 | | | 220 | |
Other assets | 300 | | | 91 | |
Firm commitment contracts | 60 | | | — | |
Total | $ | 2,100 | | | $ | 518 | |
|
| | | | | | | |
| 2018 | | 2017 |
| | | |
Proved properties | $ | 121 |
| | $ | 224 |
|
Unproved properties | 173 |
| | 211 |
|
Other assets | 49 |
| | 28 |
|
Inventories | 4 |
| | — |
|
Total | $ | 347 |
| | $ | 463 |
|
Impairments of proved properties were primarily due to the write-down to fair value of legacy and non-core natural gas and crude oil and combo plays in 2020 and legacy natural gas assets in 2018 and 2017.2019.
Taxes other than income in 2018 increased $2272020 decreased $322 million to $772$478 million (6.5%(6.6% of wellhead revenues) from $545$800 million (6.9% of wellhead revenues) in 2017. 2019.The increasedecrease in taxes other than income was primarily due to increases indecreased severance/production taxes in the United States ($190232 million) primarily as a result of increased wellhead revenues and an increase in, decreased ad valorem/property taxes ($33 million), both in the United States.States ($51 million) and a state severance tax refund ($27 million).
Other income, net, was $17$10 million in 20182020 compared to other income, net, of $9$31 million in 2017. 2019.The increasedecrease of $8$21 million in 20182020 was primarily due to a decrease in interest income.
In response to the economic impacts of the COVID-19 pandemic, the President of the United States signed the Coronavirus Aid, Relief, and Economic Security Act (the CARES Act) into law on March 27, 2020.The CARES Act provides economic support to individuals and businesses through enhanced loan programs, expanded unemployment benefits, and certain payroll and income tax relief, among other provisions. The primary tax benefit of the CARES Act for EOG was the acceleration of approximately $150 million of additional refundable alternative minimum tax (AMT) credits into tax year 2019. These credits originated from AMT paid by EOG in years prior to 2018 and were reflected as a deferred compensation expense ($12 million)tax asset and an increasea non-current receivable as of December 31, 2019 since they had been expected to either offset future current tax liabilities or be refunded on a declining balance schedule through 2021.The $150 million of additional refundable AMT credits was received in interestJuly 2020.
Further pandemic relief was contained in the Consolidated Appropriations Act of 2021 (the CA Act) which was signed into law by the President of the United States on December 27, 2020.In addition, the CA Act provided government funding and limited corporate income ($4 million), partially offset by an increase in foreign currency transaction losses ($15 million).tax relief primarily related to making permanent or extending certain tax provisions, none of which were a material benefit for EOG.
EOG recognized an income tax provisionbenefit of $822$134 million in 20182020 compared to an income tax benefitprovision of $1,921$810 million in 2017,2019, primarily due to the absence of certain 2017 tax benefits related to the Tax Cuts and Jobs Act (TCJA) and higherdecreased pretax income. The most significant impact of the TCJA on EOG was the reduction in the statutory income tax rate from 35% to 21% which required the existing net United States federal deferred income tax liability to be remeasured resulting in the recognition of an income tax benefit in 2017 of approximately $2.2 billion. The net effective tax rate for 2018 increased2020 decreased to 19%18% from (291%)23% in the prior year, primarily2019.The lower effective tax rate is mostly due to the absence of the TCJAtaxes attributable to EOG's foreign operations and increased stock-based compensation tax benefits.deficiencies.
Capital Resources and Liquidity
Cash Flow
The primary sources of cash for EOG during the three-year period ended December 31, 2019,2021, were funds generated from operations, net proceeds from the issuance of long-term debt, net cash received from settlements of commodity derivative contracts and proceeds from asset sales. The primary uses of cash were funds used in operations; exploration and development expenditures; repayments of debt; dividend payments to stockholders; repayments of debt; net cash paid for settlements of commodity derivative contracts and other property, plant and equipment expenditures; and purchases of treasury stock in connection with stock compensation plans.
expenditures.
2019
2021 compared to 2018.2020. Net cash provided by operating activities of $8,163$8,791 million in 20192021 increased $394$3,783 million from $7,769$5,008 million in 20182020 primarily reflectingdue 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 receivedpaid for settlements of commodity derivative contracts ($4901,709 million), a decrease; an increase in net cash paid for income taxes ($3671,320 million) and favorable changes; net cash used in working capital and other assets and liabilitiesin 2021 ($122817 million); partially offset compared to net cash provided by a decreaseworking capital in wellhead revenues2020 ($365193 million); and an increase in cash operating expenses ($202882 million).
Net cash used in investing activities of $6,177$3,419 million in 20192021 increased by $7$71 million from $6,170$3,348 million in 20182020 primarily due to an increase in additions to oil and gas properties ($313394 million), a decreasepartially 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 salesales of assets ($8739 million); and an increasea decrease in additions to other property, plant and equipment ($339 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).
2020 compared to 2019. Net cash provided by operating activities of $5,008 million in 2020 decreased $3,155 million from $8,163 million in 2019 primarily due to a decrease in wellhead revenues ($4,291 million); unfavorable changes in working capital and other assets and liabilities ($166 million); a decrease in gathering, processing and marketing revenues less marketing costs ($123 million) and an increase in net cash paid for income taxes ($86 million); partially offset by favorable changesan increase in working capital associated withcash received for settlements of commodity derivative contracts ($840 million) and a decrease in cash operating expenses ($641 million).
Net cash used in investing activities of $3,348 million in 2020 decreased by $2,829 million from $6,177 million in 2019 primarily due to a decrease in additions to oil and gas properties ($4162,908 million); an increase in proceeds from the sale of assets ($52 million); a decrease in additions to other property, plant and equipment ($49 million); and a decrease in other investing activities ($10 million); partially offset by an unfavorable change in working capital associated with investing activities ($190 million).
Net cash used in financing activities of $1,513$359 million in 20192020 included repayments of long-term debt ($9001,000 million), cash dividend payments ($588821 million), repayment of finance lease liabilities ($19 million) and purchases of treasury stock in connection with stock compensation plans ($2516 million).Cash provided by financing activities in 20192020 included long-term debt borrowings ($1,484 million) and proceeds from stock options exercised and employee stock purchase plan activity ($18 million).
2018 compared to 2017. Net cash provided by operating activities of $7,769 million in 2018 increased $3,504 million from $4,265 million in 2017 primarily reflecting an increase in wellhead revenues ($4,039 million), favorable changes in working capital and other assets and liabilities ($758 million) and a favorable change in the cash paid for income taxes ($113 million), partially offset by an increase in cash operating expenses ($746 million) and an unfavorable change in the net cash paid for the settlement of financial commodity derivative contracts ($26616 million).
Net cash used in investing activities of $6,170 million in 2018 increased by $2,183 million from $3,987 million in 2017 primarily due to an increase in additions to oil and gas properties ($1,888 million); unfavorable changes in working capital associated with investing activities ($211 million); and an increase in additions to other property, plant and equipment ($64 million).
Net cash used in financing activities of $839 million in 2018 included cash dividend payments ($438 million), repayments of long-term debt ($350 million) and purchases of treasury stock in connection with stock compensation plans ($63 million). Cash provided by financing activities in 2018 included proceeds from stock options exercised and employee stock purchase plan activity ($21 million).
Total Expenditures
The table below sets out components of total expenditures for the years ended December 31, 2019, 20182021, 2020 and 20172019 (in millions):
|
| | | | | | | | | | | |
| 2019 | | 2018 | | 2017 |
Expenditure Category | | | | | |
Capital | | | | | |
Exploration and Development Drilling | $ | 4,951 |
| | $ | 4,935 |
| | $ | 3,132 |
|
Facilities | 629 |
| | 625 |
| | 575 |
|
Leasehold Acquisitions (1) | 276 |
| | 488 |
| | 427 |
|
Property Acquisitions (2) | 380 |
| | 124 |
| | 73 |
|
Capitalized Interest | 38 |
| | 24 |
| | 27 |
|
Subtotal | 6,274 |
| | 6,196 |
| | 4,234 |
|
Exploration Costs | 140 |
| | 149 |
| | 145 |
|
Dry Hole Costs | 28 |
| | 5 |
| | 5 |
|
Exploration and Development Expenditures | 6,442 |
| | 6,350 |
| | 4,384 |
|
Asset Retirement Costs | 186 |
| | 70 |
| | 56 |
|
Total Exploration and Development Expenditures | 6,628 |
| | 6,420 |
| | 4,440 |
|
Other Property, Plant and Equipment (3) | 272 |
| | 286 |
| | 173 |
|
Total Expenditures | $ | 6,900 |
| | $ | 6,706 |
| | $ | 4,613 |
|
| | | | | | | | | | | | | | | | | |
| 2021 | | 2020 | | 2019 |
Expenditure Category | | | | | |
Capital | | | | | |
Exploration and Development Drilling | $ | 2,864 | | | $ | 2,664 | | | $ | 4,951 | |
Facilities | 405 | | | 347 | | | 629 | |
Leasehold Acquisitions (1) | 215 | | | 265 | | | 276 | |
Property Acquisitions (2) | 100 | | | 135 | | | 380 | |
Capitalized Interest | 33 | | | 31 | | | 38 | |
Subtotal | 3,617 | | | 3,442 | | | 6,274 | |
Exploration Costs | 154 | | | 146 | | | 140 | |
Dry Hole Costs | 71 | | | 13 | | | 28 | |
Exploration and Development Expenditures | 3,842 | | | 3,601 | | | 6,442 | |
Asset Retirement Costs | 127 | | | 117 | | | 186 | |
Total Exploration and Development Expenditures | 3,969 | | | 3,718 | | | 6,628 | |
Other Property, Plant and Equipment (3) | 286 | | | 395 | | | 272 | |
Total Expenditures | $ | 4,255 | | | $ | 4,113 | | | $ | 6,900 | |
| |
(1) | Leasehold acquisitions included $98 million, $291 million and $256 million related to non-cash property exchanges in 2019, 2018 and 2017, respectively. |
| |
(2) | Property acquisitions included $52 million, $71 million and $26 million related to non-cash property exchanges in 2019, 2018 and 2017, respectively. |
| |
(3) | Other property, plant and equipment included $49 million of non-cash additions in 2018, respectively, primarily related to a finance lease transaction in the Permian Basin. |
(1)Leasehold acquisitions included $45 million, $197 million and $98 million related to non-cash property exchanges in 2021, 2020 and 2019, respectively.
(2)Property acquisitions included $5 million, $15 million and $52 million related to non-cash property exchanges in 2021, 2020 and 2019, 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 $6,442$3,842 million for 20192021 were $92$241 million higher than the prior year. The increase was primarily due to increased property acquisitions ($256 million), increased exploration and development drilling expenditures in Trinidad ($53 million) and increased capitalized interest ($14 million), partially offset by decreased leasehold acquisitions ($212 million) and decreased exploration and development drilling expenditures in the United States ($19267 million) and Other Internationalincreased facilities expenditures ($1958 million), partially offset by decreased exploration and development drilling expenditures in Trinidad ($61 million), decreased leasehold acquisitions ($50 million) and decreased property acquisitions ($35 million). 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 2019 exploration and development expenditures of $6,442 million included $5,513 million in development drilling and facilities, $511 million in exploration, $380 million in property acquisitions and $38 million in capitalized interest. The 2018 exploration and development expenditures of $6,350 million included $5,546 million in development drilling and facilities, $656 million million in exploration, $124 million in property acquisitions and $24 million in capitalized interest. The 2017 exploration and development expenditures of $4,384 million included $3,661 million in development drilling and facilities, $623 million in exploration, $73 million in property acquisitions and $27 million in capitalized interest.
The level of exploration and development expenditures, including acquisitions, will vary in future periods depending on energy market conditions and other related economic factors. EOG believes it has significant flexibility and availability with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. While EOG has certain continuing commitments associated with expenditure plans related to its operations, such commitments are not expected to be material when considered in relation to the total financial capacity of EOG.
Commodity Derivative Transactions
Crude Oil Derivative Contracts. Prices received by EOG for its crude oil production generally vary from U.S. New York Mercantile Exchange (NYMEX) West Texas Intermediate (WTI) prices due to adjustments for delivery location (basis) and other factors. EOG has entered into crude oil basis swap contracts in order to fix the differential between pricing in Midland, Texas, and Cushing, Oklahoma (Midland Differential). Presented below is a comprehensive summary of EOG's Midland Differential basis swapfinancial commodity derivative contracts throughsettled during the year ended December 31, 2021 (closed) and remaining for 2022 and thereafter, as of February 19, 2020. The weighted average price differential expressed18, 2022. Crude oil and NGL volumes are presented in $/Bbl represents the amount of reduction to Cushing, Oklahoma,MBbld and prices for the notionalare presented in $/Bbl. Natural gas volumes expressedare presented in barrelsMMBtu per day (Bbld) covered by the basis swap contracts.(MMBtud) and prices are presented in dollars per MMBtu ($/MMBtu).
| | | | | | | | | | | | | | | | | | | | |
Crude Oil Financial Price Swap Contracts |
| | | | Contracts Sold |
Period | | Settlement Index | | Volume (MBbld) | | Weighted Average Price ($/Bbl) |
| | | | | | |
January 2021 (closed) | | NYMEX West Texas Intermediate (WTI) | | 151 | | | $ | 50.06 | |
February - March 2021 (closed) | | NYMEX WTI | | 201 | | | 51.29 | |
April - June 2021 (closed) | | NYMEX WTI | | 150 | | | 51.68 | |
July - September 2021 (closed) | | NYMEX WTI | | 150 | | | 52.71 | |
January 2022 (closed) | | NYMEX WTI | | 140 | | | 65.58 | |
February - March 2022 | | NYMEX WTI | | 140 | | | 65.58 | |
April - June 2022 | | NYMEX WTI | | 140 | | | 65.62 | |
July - September 2022 | | NYMEX WTI | | 140 | | | 65.59 | |
October - December 2022 | | NYMEX WTI | | 140 | | | 65.68 | |
January - March 2023 | | NYMEX WTI | | 150 | | | 67.92 | |
April - June 2023 | | NYMEX WTI | | 120 | | | 67.79 | |
July - September 2023 | | NYMEX WTI | | 100 | | | 70.15 | |
October - December 2023 | | NYMEX WTI | | 69 | | | 69.41 | |
|
| | | | | | | | |
| Midland Differential Basis Swap Contracts |
| | | Volume (Bbld) | | Weighted Average Price Differential ($/Bbl) |
|
|
| 2019 | | | | |
| January 1, 2019 through December 31, 2019 (closed) | | 20,000 |
| | $ | 1.075 |
|
EOG has also entered into crude oil basis swap contracts in order to fix the differential between pricing in the U.S. Gulf Coast and Cushing, Oklahoma (Gulf Coast Differential). Presented below | | | | | | | | | | | | | | | | | | | | |
Crude Oil Basis Swap Contracts |
| | | | Contracts Sold |
Period | | Settlement Index | | Volume (MBbld) | | Weighted Average Price Differential ($/Bbl) |
| | | | | | |
February 2021 (closed) | | NYMEX WTI Roll Differential (1) | | 30 | | | $ | 0.11 | |
March - December 2021 (closed) | | NYMEX WTI Roll Differential (1) | | 125 | | | 0.17 | |
January - February 2022 (closed) | | NYMEX WTI Roll Differential (1) | | 125 | | | 0.15 | |
March - December 2022 | | NYMEX WTI Roll Differential (1) | | 125 | | | 0.15 | |
(1) This settlement index is a comprehensive summary of EOG's Gulf Coast Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to Cushing, Oklahoma, prices for the notional volumes expressed in Bbld covered by the basis swap contracts.
|
| | | | | | | | |
| Gulf Coast Differential Basis Swap Contracts |
| | | Volume (Bbld) | | Weighted Average Price Differential ($/Bbl) |
|
|
| 2019 | | | | |
| January 1, 2019 through December 31, 2019 (closed) | | 13,000 |
| | $ | 5.572 |
|
EOG has also entered into crude oil swapsused to fix the differential in pricing between the NYMEX calendar month average and the physical crude oil delivery month (Roll Differential). Presented below is a comprehensive summary of EOG's Roll Differential swap contracts through February 19, 2020. The weighted average price differential expressed in $/Bbl represents the amount of addition to delivery month prices for the notional volumes expressed in Bbld covered by the swap contracts.
|
| | | | | | | | |
| Roll Differential Swap Contracts |
| | | Volume (Bbld) | | Weighted Average Price Differential ($/Bbl) |
|
|
| 2020 | | | | |
| February 2020 (closed) | | 10,000 |
| | $ | 0.70 |
|
| March 1, 2020 through December 31, 2020 | | 10,000 |
| | 0.70 |
|
Presented below is a comprehensive summary of EOG's crude oil price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
|
| | | | | | | | |
| Crude Oil Price Swap Contracts |
| | | Volume (Bbld) | | Weighted Average Price ($/Bbl) |
|
|
| 2019 | | | | |
| April 2019 (closed) | | 25,000 |
| | $ | 60.00 |
|
| May 1, 2019 through December 31, 2019 (closed) | | 150,000 |
| | 62.50 |
|
| | | | | |
| 2020 | | | | |
| January 2020 (closed) | | 200,000 |
| | $ | 59.33 |
|
| February 1, 2020 through March 31, 2020 | | 200,000 |
| | 59.33 |
|
| April 1, 2020 through June 30, 2020 | | 200,000 |
| | 59.59 |
|
| July 1, 2020 through September 30, 2020 | | 107,000 |
| | 58.94 |
|
month.
NGLs Derivative Contracts.
Presented below is a comprehensive summary of EOG's Mont Belvieu propane (non-TET) price swap contracts through February 19, 2020, with notional volumes expressed in Bbld and prices expressed in $/Bbl.
|
| | | | | | | | |
| Mont Belvieu Propane Price Swap Contracts |
| | | Volume (Bbld) | | Weighted Average Price ($/Bbl) |
|
|
| 2020 | | | | |
| January 2020 (closed) | | 4,000 |
| | $ | 21.34 |
|
| February 2020 | | 4,000 |
| | 21.34 |
|
| March 1, 2020 through December 31, 2020 | | 25,000 |
| | 17.92 |
|
| | | | | | | | | | | | | | | | | | | | |
NGL Financial Price Swap Contracts |
| | | | Contracts Sold |
Period | | Settlement Index | | Volume (MBbld) | | Weighted Average Price ($/Bbl) |
| | | | | | |
January - December 2021 (closed) | | Mont Belvieu Propane (non-Tet) | | 15 | | | $ | 29.44 | |
Natural Gas Derivative Contracts.
Presented below is a comprehensive summary
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Natural Gas Financial Price Swap Contracts |
| | | | Contracts Sold | | Contracts Purchased |
Period | | Settlement Index | | Volume (MMBtud in thousands) | | Weighted Average Price ($/MMBtu) | | Volume (MMBtud in thousands) | | Weighted Average Price ($/MMBtu) |
| | | | | | | | | | |
January - March 2021 (closed) | | NYMEX Henry Hub | | 500 | | | $ | 2.99 | | | 500 | | | $ | 2.43 | |
April - September 2021 (closed) | | NYMEX Henry Hub | | 500 | | | 2.99 | | | 570 | | | 2.81 | |
October - December 2021 (closed) | | NYMEX Henry Hub | | 500 | | | 2.99 | | | 500 | | | 2.83 | |
January - December 2022 (closed) (1) | | NYMEX Henry Hub | | 20 | | | 2.75 | | | — | | | — | |
January - February 2022 (closed) | | NYMEX Henry Hub | | 725 | | | 3.57 | | | — | | | — | |
March - December 2022 | | NYMEX Henry Hub | | 725 | | | 3.57 | | | — | | | — | |
January - December 2023 | | NYMEX Henry Hub | | 725 | | | 3.18 | | | — | | | — | |
January - December 2024 | | NYMEX Henry Hub | | 725 | | | 3.07 | | | — | | | — | |
January - December 2025 | | NYMEX Henry Hub | | 725 | | | 3.07 | | | — | | | — | |
April - September 2021 (closed) | | Japan Korea Marker (JKM) | | 70 | | | 6.65 | | | — | | | — | |
(1) In January 2021, EOG executed the early termination provision granting EOG the right to terminate all of EOG'sits 2022 natural gas price swap contracts through February 19, 2020, with notional volumes expressed inwhich were open at that time. EOG received net cash of $0.6 million British thermal units (MMBtu) per day (MMBtud) and prices expressed in dollars per MMBtu ($/MMBtu).
|
| | | | | | | | |
| Natural Gas Price Swap Contracts |
| | | Volume (MMBtud) | | Weighted Average Price ($/MMBtu) |
|
|
| 2019 | | | | |
| April 1, 2019 through October 31, 2019 (closed) | | 250,000 |
| | $ | 2.90 |
|
EOG has also entered into natural gas collar contracts, which establish ceiling and floor prices for the salesettlement of notional volumes of natural gas as specified in the collar contracts. The collars require that EOG pay the difference between the ceiling price and the NYMEX Henry Hub natural gas price for the contract month (Henry Hub Index Price) in the event the Henry Hub Index Price is above the ceiling price. The collars grant EOG the right to receive the difference between the floor price and the Henry Hub Index Price in the event the Henry Hub Index Price is below the floor price. Presented below is a comprehensive summary of EOG's natural gas collar contracts through February 19, 2020, with notional volumes expressed in MMBtud and prices expressed in $/MMBtu.
|
| | | | | | | | | | | | |
| Natural Gas Collar Contracts |
| | | | | Weighted Average Price ($/MMBtu) |
| | | Volume (MMBtud) | | Ceiling Price | | Floor Price |
|
|
| 2020 | | | | | | |
| April 1, 2020 through October 31, 2020 | | 250,000 |
| | $ | 2.50 |
| | $ | 2.00 |
|
Prices received by EOG for its natural gas production generally vary from NYMEX Henry Hub prices due to adjustments for delivery location (basis) and other factors. EOG has entered into natural gas basis swap contracts in order to fix the differential between pricing in the Rocky Mountain area and NYMEX Henry Hub prices (Rockies Differential). Presented below is a comprehensive summary of EOG's Rockies Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swapthese contracts.
|
| | | | | | | | |
| Rockies Differential Basis Swap Contracts |
| | | Volume (MMBtud) | | Weighted Average Price Differential ($/MMBtu) |
|
|
| 2020 | | | | |
| January 1, 2020 through February 29, 2020 (closed) | | 30,000 |
| | $ | 0.55 |
|
| March 1, 2020 through December 31, 2020 | | 30,000 |
| | 0.55 |
|
| | | | | | | | | | | | | | | | | | | | |
Natural Gas Basis Swap Contracts |
| | | | Contracts Sold |
Period | | Settlement Index | | Volume (MMBtud in thousands) | | Weighted Average Price ($/MMBtu) |
| | | | | | |
January - February 2022 (closed) | | NYMEX Henry Hub Houston Ship Channel (HSC) Differential (1) | | 210 | | | $ | (0.01) | |
March - December 2022 | | NYMEX Henry Hub HSC Differential (1) | | 210 | | | (0.01) | |
January - December 2023 | | NYMEX Henry Hub HSC Differential (1) | | 135 | | | (0.01) | |
January - December 2024 | | NYMEX Henry Hub HSC Differential (1) | | 10 | | | 0.00 | |
January - December 2025 | | NYMEX Henry Hub HSC Differential (1) | | 10 | | | 0.00 | |
EOG has also entered into natural gas basis swap contracts in order(1) This settlement index is used to fix the differential between pricing at the Houston Ship Channel (HSC) and NYMEX Henry Hub prices (HSC Differential). Presented below is a comprehensive summary of EOG's HSC Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.prices.
|
| | | | | | | | |
| HSC Differential Basis Swap Contracts |
| | | Volume (MMBtud) | | Weighted Average Price Differential ($/MMBtu) |
|
|
| 2020 | | | | |
| January 1, 2020 through February 29, 2020 (closed) | | 60,000 |
| | $ | 0.05 |
|
| March 1, 2020 through December 31, 2020 | | 60,000 |
| | 0.05 |
|
In connection with its financial commodity derivative contracts, EOG had $1.4 billion of collateral posted at February 18, 2022. EOG expects this collateral to be applied to the settlement of financial commodity derivative contracts if market prices remain above contract prices or returned to EOG if market prices decrease below contract prices.
EOG has also entered into natural gas basis swap contracts in order to fix the differential between pricing at the Waha Hub in West Texas and NYMEX Henry Hub prices (Waha Differential). Presented below is a comprehensive summary of EOG's Waha Differential basis swap contracts through February 19, 2020. The weighted average price differential expressed in $/MMBtu represents the amount of reduction to NYMEX Henry Hub prices for the notional volumes expressed in MMBtud covered by the basis swap contracts.
|
| | | | | | | | |
| Waha Differential Basis Swap Contracts |
| | | Volume (MMBtud) | | Weighted Average Price Differential ($/MMBtu) |
|
|
| 2020 | | | | |
| January 1, 2020 through February 29, 2020 (closed) | | 50,000 |
| | $ | 1.40 |
|
| March 1, 2020 through December 31, 2020 | | 50,000 |
| | 1.40 |
|
Financing
EOG's debt-to-total capitalization ratio was 19% at December 31, 2019,2021, compared to 24%22% at December 31, 2018.2020. As used in this calculation, total capitalization represents the sum of total current and long-term debt and total stockholders' equity.
At December 31, 20192021 and 2018,2020, respectively, EOG had outstanding $5,140$4,890 million and $6,040$5,640 million aggregate principal amount of senior notes which had estimated fair values of $5,452$5,577 million and $6,027$6,505 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 2019,2021, EOG funded its capital program and operations primarily by utilizing cash provided by operating activities, cash on hand and proceeds from asset sales. While EOG maintains a $2.0 billion revolving credit facility to back its commercial paper program, there were no borrowings outstanding at any time during 20192021 and the amount outstanding at year-end was zero. EOG considers the availability of its $2.0 billion senior unsecured revolving credit facility, as described in Note 2 to Consolidated Financial Statements, to be sufficient to meet its ongoing operating needs.
Contractual Obligations
The following table summarizes EOG's contractual obligations at December 31, 2019 (in millions):
|
| | | | | | | | | | | | | | | | | | | | |
Contractual Obligations (1) (2) | | Total | | 2020 | | 2021-2022 | | 2023-2024 | | 2025 & Beyond |
| | | | | | | | | | |
Current and Long-Term Debt | | $ | 5,140 |
| | $ | 1,000 |
| | $ | 750 |
| | $ | 1,250 |
| | $ | 2,140 |
|
Interest Payments on Long-Term Debt | | 1,059 |
| | 169 |
| | 258 |
| | 193 |
| | 439 |
|
Finance Leases (3) | | 64 |
| | 15 |
| | 27 |
| | 16 |
| | 6 |
|
Operating Leases (3) | | 850 |
| | 390 |
| | 335 |
| | 85 |
| | 40 |
|
Leases Effective, Not Commenced (3) | | 699 |
| | 80 |
| | 132 |
| | 134 |
| | 353 |
|
Transportation and Storage Service Commitments (4) | | 6,034 |
| | 914 |
| | 1,632 |
| | 1,130 |
| | 2,358 |
|
Purchase and Service Obligations | | 1,222 |
| | 399 |
| | 498 |
| | 152 |
| | 173 |
|
Total Contractual Obligations | | $ | 15,068 |
| | $ | 2,967 |
| | $ | 3,632 |
| | $ | 2,960 |
| | $ | 5,509 |
|
| |
(1) | This table does not include the liability for unrecognized tax benefits, EOG's pension or postretirement benefit obligations or liability for dismantlement, abandonment and asset retirement obligations (see Notes 6, 7 and 15, respectively, to Consolidated Financial Statements). These amounts are excluded because they are subject to estimates and the timing of settlement is unknown. |
| |
(2) | This table does not include the liability for commitments to purchase fixed quantities of crude oil and natural gas. The amounts are excluded because they are variable and based on future commodity prices. At December 31, 2019, EOG is committed to purchase 1.8 MMBbls of crude oil and 5.5 Bcf of natural gas in 2020 and 1.4 MMBls of crude oil in 2021. |
| |
(3) | For more information on contracts that meet the definition of a lease under ASU 2016-02, see Note 18 to Consolidated Financial Statements. |
| |
(4) | 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, 2019. Management does not believe that any future changes in these rates before the expiration dates of these commitments will have a material adverse effect on the financial condition or results of operations of EOG. |
Off-Balance Sheet Arrangements
EOG does not participate in financial transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities or partnerships, often referred to as variable interest entities (VIE) or special purpose entities (SPE), are generally established for the purpose of facilitating off-balance sheet arrangements or other limited purposes. EOG was not involved in any unconsolidated VIE or SPE financial transactions or any other "off-balance sheet arrangement" (as defined in Item 303(a)(4)(ii) of Regulation S-K) during any of the periods covered by this report and currently has no intention of participating in any such transaction or arrangement in the foreseeable future.
Foreign Currency Exchange Rate Risk
During 2019,2021, EOG was exposed to foreign currency exchange rate risk inherent in its operations in foreign countries, including Trinidad, ChinaAustralia, Oman, Canada and, Canada.through May 2021, in China. 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 worldwide energy supplies and the relative competitive relationships of the various energy sources in the view of consumers, EOG is unable to predict what changes may occur in crude oil and condensate, NGLs, natural gas, ammonia and methanol prices in the future. The market price of crude oil and condensate, NGLs and natural gas in 20202022 will impact the amount of cash generated from EOG's operating activities, which will in turn impact EOG's financial position. As of February 19, 2020,18, 2022, the average 20202022 NYMEX crude oil and natural gas prices were $53.75$84.45 per barrel and $2.12$4.61 per MMBtu, respectively, representing a decreasean increase of 6%24% for crude oil and a decreasean increase of 20% for natural gas from the average NYMEX prices in 2019.2021. See ITEM 1A, Risk Factors.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.
BasedIncluding the impact of EOG's crude oil and NGL derivative contracts (exclusive of basis swaps) and based on EOG's tax position, EOG's price sensitivity (exclusive of basis swaps) in 20202022 for each $1.00 per barrel increase or decrease in wellhead crude oil and condensate price, combined with the estimated change in NGL price, is approximately $117$107 million for net income and $152$138 million for pretax cash flows from operating activities. BasedIncluding the impact of EOG's natural gas derivative contracts and based on EOG's tax position and the portion of EOG's anticipated natural gas volumes for 20202022 for which prices have not been determined under long-term marketing contracts, EOG's price sensitivity for each $0.10 per Mcf increase or decrease in wellhead natural gas price is approximately $31$15 million for net income and $40$19 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 19, 2020,18, 2022, see "Derivative"Commodity Derivative Transactions" above.
Capital. EOG plans to continue to focus a substantial portion of its exploration and development expenditures in its major producing areas in the United States. In particular, EOG will be focused on United States crude oil drilling activity in its Delaware Basin, Eagle Ford andoil 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 lower drilling and completion costsoffset inflationary pressure through efficiency gains and lowerby locking in certain service costs.costs for drilling and completion activities. In addition, EOG expects to spend a portion of its anticipated 2022 capital expenditures on leasing acreage, evaluating new prospects, long-term transportation infrastructure and environmental projects.
The total anticipated 20202022 capital expenditures of approximately $6.3$4.3 billion to $6.7$4.7 billion, excluding acquisitions and non-cash exchanges,transactions, is structured to maintain EOG's strategy of capital discipline by funding its exploration, development and exploitation activities primarily from available internally generated cash flows and cash on hand. EOG has significant flexibility with respect to financing alternatives, including borrowings under its commercial paper program, bank borrowings, borrowings under its $2.0 billion senior unsecured revolving credit facility and equity and debt offerings.
Operations. In 2020, both total production and2022, total crude oil, NGLs and natural gas production areis expected to increase from 2019return to prepandemic levels. In 2020,2022, EOG expects to continue to focus on reducingmitigating 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 ASU 2016-02. In 2022, EOG anticipates the following cash requirements under these commitments (in millions):
| | | | | |
Finance Leases (1) | $ | 42 | |
Operating Leases (1) | 262 |
Leases Effective, Not Commenced (1) | 25 |
Transportation and Storage Service Commitments (2) (3) | 961 |
Purchase and Service Obligations (3) | 374 |
Total Cash Requirements | $ | 1,664 | |
(1) For more information on contracts that meet the definition of a lease under ASU 2016-02, 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, 2021. 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 2022, EOG has no senior notes maturing and expects to pay interest of $191 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 2022 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 the portrayal of 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.policies and estimates. Following is a discussion of EOG's most critical accounting policies: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 commercial reserves. If commercial quantities of proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether commercial quantities of proved commercial 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. CostsThe concept of sufficient progress is subject to develop proved reserves, including the costs of all development wellssignificant judgment and related equipment usedmay require further operational actions or require additional approvals from government agencies or partners in the production of crude oil and natural gas are capitalized.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 wereare revised upward or downward, earnings wouldwill increase or decrease, respectively.
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Oil and gas properties are grouped in accordance with the provisions of the Extractive Industries - Oil and Gas Topic of the ASC. The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions and/or property dispositions and impairments.
Depreciation and amortization of other property, plant and equipment is calculated on a straight-line basis over the estimated useful life of the asset.
Impairments
Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive is amortized over the remaining lease term. Unproved properties with individually significant acquisition costs are reviewed individually for impairment. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
When circumstances indicate that proved oil and gas properties may be impaired, EOG compares expected undiscounted future cash flows at a depreciation, depletion and amortization group level to the unamortized capitalized cost of the asset.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, 2019,2021, WTI crude oil spot prices have fluctuated from approximately $26.19$(36.98) per barrel to $77.41$85.64 per barrel, and Henry Hub natural gas spot prices have ranged from approximately $1.49$1.33 per MMBtu to $6.24$23.86 per MMBtu. Market prices for NGLs are influenced by the production composition ofcomponents extracted, including ethane, propane, butane and natural gasoline, among others, and the respective market pricing for each component.
EOG uses the five-year NYMEX futures strip for WTI crude oil and Henry Hub natural gas and the five-year Oil Price Information Services futures strip for NGLs components (in each case as of the applicable balance sheet date) as a basis to estimate future crude oil, NGLs and natural gas prices. EOG's proved reserves estimates, including the timing of future production, are also subject to significant assumptions and judgment, and are frequently revised (upwards and downwards) as more information becomes available. Proved reserves are estimated using a trailing 12-month average price, in accordance with SEC rules. In the future, if any combination of crude oil prices, NGLs prices, natural gas prices actual production or operating costsestimated proved reserves diverge negatively from EOG's current estimates, impairment charges and downward adjustments to our estimated proved reserves 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.
Stock-Based Compensation
In accounting for stock-based compensation, judgments and estimates are made regarding, among other things, the appropriate valuation methodology to follow in valuing stock compensation awards and the related inputs required by those valuation methodologies. Assumptions regarding expected volatility of EOG's common stock, the level of risk-free interest rates, expected dividend yields on EOG's common stock, the expected term of the awards, expected volatility in the price of shares of EOG's peer companies and other valuation inputs are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense recognized on the Consolidated Statements of Income and Comprehensive Income.
Information Regarding Forward-Looking Statements
This Annual Report on Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG's future financial position, operations, performance, business strategy, goals, returns and rates of return, budgets, reserves, levels of production, capital expenditures, costs and asset sales, statements regarding future commodity prices and statements regarding the plans and objectives of EOG's management for future operations, are forward-lookingforward‐looking statements. EOG typically uses words such as "expect," "anticipate," "estimate," "project," "strategy," "intend," "plan," "target," “aims,”"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-lookingforward‐looking statements. In particular, statements, express or implied, concerning EOG's future operating results and returns or EOG's ability to replace or increase reserves, increase production, generate returns and rates of return, replace or increase drilling locations, reduce or otherwise control operating costs and capital expenditures, generate cash flows, pay down or refinance indebtedness, 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-lookingforward‐looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, EOG's forward-looking statements may be affected by known, unknown or currently unforeseen risks, events or circumstances that may be outside EOG's control. Important factors that could cause EOG's actual results to differ materially from the expectations reflected in EOG's forward-looking statements include, among others:
•the timing, extent and duration of changes in prices for, supplies of, and demand for, crude oil and condensate, natural gas liquids (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, operating and capital costs related to, and (iv) maximize reserve recovery from, its existing and future crude oil and natural gas exploration and development projects and associated potential and existing drilling locations;
•the extent to which EOG is successful in its efforts to market its production of crude oil and condensate, NGLs and natural gas liquids, natural gas and related commodity production;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 refiningexport facilities;
•the availability, cost, terms and timing of issuance or execution of and competition for, mineral licenses and leases and governmental and other permits and rights-of-way, and EOG’sEOG'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; climate change and otherregulations (including, but not limited to, carbon tax legislation); environmental, health and safety laws and regulations relating to air emissions, disposal of produced water, drilling fluids and other wastes, hydraulic fracturing and access to and use of water; laws and regulations affecting the leasing of acreage and permitting for oil and gas drilling and the calculation of royalty payments in respect of oil and gas production; laws and regulations imposing additional permitting and disclosure requirements, additional operating restrictions and conditions or restrictions on drilling and completion operations and on the transportation of crude oil and natural gas; laws and regulations with respect to derivatives and hedging activities; and laws and regulations with respect to the import and export of crude oil, natural gas and related commodities;
•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; 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;
•EOG's ability to effectively integrate acquired crude oil and natural gas properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and drilling, completing and operating costs with respect to such properties;
•the extent to which EOG's third-party-operated crude oil and natural gas properties are operated successfully, economically and economically;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, employees and other personnel, facilities, equipment, materials and services;properties;
•the availability and cost of, and competition in the oil and gas exploration and production industry for, employees and other personnel, facilities, equipment, materials (such as water and tubulars) and services;
•the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
•weather, including its impact on crude oil and natural gas demand, and weather-related delays in drilling and in the installation and operation (by EOG or third parties) of production, gathering, processing, refining, compression, storage, transportation, and transportationexport facilities;
•the ability of EOG's customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
•EOG's ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all, and to otherwise satisfy its capital expenditure requirements;
•the extent to which EOG is successful in its completion of planned asset dispositions;
•the extent and effect of any hedging activities engaged in by EOG;
•the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
•the duration and economic and financial impact of epidemics, pandemics or other public health issues, including the COVID-19 pandemic;
•geopolitical factors and political conditions and developments around the world (such as the imposition of tariffs or trade or other economic sanctions, political instability and armed conflict), including in the areas in which EOG operates;
the use of competing energy sources and the development of alternative energy sources;
•the extent to which EOG incurs uninsured losses and liabilities or losses and liabilities in excess of its insurance coverage;
•acts of war and terrorism and responses to these acts; and
•the other factors described under ITEM 1A, Risk Factors on pages 13 through 23 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.
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 "Derivative"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."
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 F-1 and is incorporated by reference herein.
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
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, 2019.2021. 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, 2019.2021.
Management's Annual Report on Internal Control over Financial Reporting. EOG's management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act). Even an effective system of internal control over financial reporting, no matter how well designed, has inherent limitations, including the possibility of human error, circumvention of controls or overriding of controls and, therefore, can provide only reasonable assurance with respect to reliable financial reporting. Furthermore, the effectiveness of a system of internal control over financial reporting in future periods can change as conditions change.
EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2019.2021. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on this assessment and such criteria, EOG's management believes that EOG's internal control over financial reporting was effective as of December 31, 2019.2021. See also "Management's Responsibility for Financial Reporting" appearing on page F-2 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 F-3 of this report.
There were no changes in EOG's internal control over financial reporting that occurred during the quarter ended December 31, 2019,2021, that have materially affected, or are reasonably likely to materially affect, EOG's internal control over financial reporting.
ITEM 9B. Other Information
None.
ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection
None.
PART III
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 20202022 Annual Meeting of Stockholders to be filed not later than April 29, 202030, 2022 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.
ITEM 11. Executive Compensation
The information required by this Item is incorporated by reference from EOG's Definitive Proxy Statement with respect to its 20202022 Annual Meeting of Stockholders to be filed not later than April 29, 2020.30, 2022. 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.
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 20202022 Annual Meeting of Stockholders to be filed not later than April 29, 2020.30, 2022.
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 and restricted stock units 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).
EOG's stockholders approved the EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (2008 Plan) at the 2008 Annual Meeting of Stockholders in May 2008. The 2008 Plan provided for grants of stock options, SARs, restricted stock, restricted stock units, performance units and other stock-based awards to employees and non-employee members of EOG's Board. At the 2010 Annual Meeting of Stockholders in April 2010 (2010 Annual Meeting), EOG's stockholders approved an amendment to the 2008 Plan, was approved, pursuant to which the number of shares of common stock available for future grants of stock options, stock-settled stock appreciation rights (SARs), restricted stock, restricted stock units, performance units and other stock-based awards under the 2008 Plan was increased byauthorizing an additional 13.8 million shares to an aggregate maximum of 25.8 million shares plus shares underlying forfeited or canceled grantsEOG common stock for grant under the prior stock plans referenced in the 2008 Plan document.plan. At the 2013 Annual Meeting of Stockholders in May 2013, EOG's stockholders approved the Amended and Restated EOG Resources, Inc. 2008 Omnibus Equity Compensation Plan (Amended and Restated 2008 Plan). As more fully discussed in the Amended and Restated 2008 Plan, document, the Amended and Restated 2008 Plan, among other things, authorizesauthorizing an additional 31.0 million shares of EOG common stock for grant under the plan and extendsextending the expiration date of the plan to May 2023. Under the Amended and Restated 2008 Plan, grants may be made to employees and non-employee members of EOG's Board.
Also at the 2010 Annual Meeting, an amendment to the EOG Resources, Inc. Employee Stock Purchase Plan (ESPP) was approved to increase the shares available for grant by 2.0 million shares.shares and extend the term of the ESPP to December 31, 2019, unless terminated earlier by its terms or by EOG. The ESPP was originally approved by EOG's stockholders in 2001 and would have expired on July 1, 2011. The amendment also extended the term of the ESPP to December 31, 2019, unless terminated earlier by its terms or by EOG. At the 2018 Annual Meeting of Stockholders in April 2018, stockholders approved an amendment and restatement of the ESPP to (among other changes) increase the number of shares available for grant by 2.5 million shares and further extend the term of the ESPP to December 31, 2027, unless terminated earlier by its terms or by EOG.
Stock Plans Not Approved by EOG Stockholders. In December 2008, the Board approved the amendment and continuation of the 1996 Deferral Plan as the "EOG Resources, Inc. 409A Deferred Compensation Plan" (Deferral Plan). Under the Deferral Plan (as subsequently amended), payment of up to 50% of base salary and 100% of annual cash bonus, director's fees, vestings of restricted stock units granted to non-employee directors (and dividends credited thereon) under the 2008 Plan and 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, 2019, 332,2482021, 401,535 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, 2019.2021.
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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)) | |
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Equity Compensation Plans Approved by EOG Stockholders | | 10,967,766 |
| (2) | $ | 94.53 |
| | 9,116,617 |
| (3) |
Equity Compensation Plans Not Approved by EOG Stockholders | | 224,225 |
| (4) | N/A |
| | 207,752 |
| (5) |
Total | | 11,191,991 |
| | $ | 94.53 |
| | 9,324,369 |
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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)) | |
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Equity Compensation Plans Approved by EOG Stockholders | | 11,524,127 | | (2) | $ | 84.37 | | | 19,079,181 | | (3) |
Equity Compensation Plans Not Approved by EOG Stockholders | | 300,920 | | (4) | N/A | | 138,465 | | (5) |
Total | | 11,825,047 | | | $ | 84.37 | | | 19,217,646 | | |
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(1) | The weighted-average exercise price is calculated based solely on the exercise prices of the outstanding stock option and SAR grants and does not reflect shares that will be issued upon the vesting of outstanding restricted stock unit and performance unit grants, or Deferral Plan phantom shares, all of which have no exercise price. |
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(2) | Amount includes 974,484 outstanding restricted stock units, for which shares of EOG common stock will be issued, on a one-for-one basis, upon the vesting of such grants. Amount also includes 598,147 outstanding performance units and assumes, for purposes of this table, (i) the application of a 100% performance multiple upon the completion of each of the remaining performance periods in respect of such performance unit grants and (ii) accordingly, the issuance, on a one-for-one basis, of an aggregate 598,147 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 102,382 and a maximum of 1,093,912 performance units could be outstanding and (B) accordingly, a minimum of 102,382 and a maximum of 1,093,912 shares of EOG common stock could be issued upon the vesting of such grants. |
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(3) | Consists of (i) 6,844,409 shares remaining available for issuance under the Amended and Restated 2008 Plan and (ii) 2,272,208 shares remaining available for purchase under the ESPP. Pursuant to the fungible share design of the Amended and Restated 2008 Plan, each share issued as a SAR or stock option under the Amended and Restated 2008 Plan counts as 1.0 share against the aggregate plan share limit, and each share issued as a "full value award" (i.e., as restricted stock, restricted stock units or performance units) counts as 2.45 shares against the aggregate plan share limit. Thus, from the 6,844,409 shares remaining available for issuance under the Amended and Restated 2008 Plan, (i) the maximum number of shares we could issue as SAR and stock option awards is 6,844,409 (i.e., if all shares remaining available for issuance under the Amended and Restated 2008 Plan are issued as SAR and stock option awards) and (ii) the maximum number of shares we could issue as full value awards is 2,793,636 (i.e., if all shares remaining available for issuance under the Amended and Restated 2008 Plan are issued as full value awards). |
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(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 224,225 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2019). |
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(5) | Represents phantom shares that remain available for issuance under the Deferral Plan. |
(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) 9,968,540 outstanding stock option and SAR grants, (ii) 876,476 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) 679,111 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 679,111 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 1,358,222 performance units could be outstanding and (B) accordingly, a minimum of 0 and a maximum of 1,358,222 shares of EOG common stock could be issued upon the vesting of such grants. (3)Consists of (i) 17,500,011 shares remaining available for issuance under the 2021 Plan and (ii) 1,579,170 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 300,920 phantom shares issued and outstanding under the Deferral Plan as of December 31, 2021).
(5)Represents phantom shares that remain available for issuance under the Deferral Plan.
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 20202022 Annual Meeting of Stockholders to be filed not later than April 29, 2020.30, 2022.
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 20202022 Annual Meeting of Stockholders to be filed not later than April 29, 2020.30, 2022.
PART IV
ITEM 15. Exhibits, Financial Statement Schedules
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedule
See "Index to Financial Statements" set forth on page F-1.
(a)(3), (b) Exhibits
See pages E-1 through E-7E-6 for a listing of the exhibits.
ITEM 16. Form 10-K Summary
None.
EOG RESOURCES, INC.
INDEX TO FINANCIAL STATEMENTS
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Consolidated Financial Statements: | |
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Management's Responsibility for Financial Reporting | |
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Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34) | |
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Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) for Each of the Three Years in the Period Ended December 31, 20192021 | |
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Consolidated Balance Sheets - December 31, 20192021 and 20182020 | |
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Consolidated Statements of Stockholders' Equity for Each of the Three Years in the Period Ended December 31, 20192021 | |
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Consolidated Statements of Cash Flows for Each of the Three Years in the Period Ended December 31, 20192021 | |
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Notes to Consolidated Financial Statements | |
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Supplemental Information to Consolidated Financial Statements | |
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING
The following consolidated financial statements of EOG Resources, Inc., together with its subsidiaries (collectively, EOG), were prepared by management, which is responsible for the integrity, objectivity and fair presentation of such financial statements. The statements have been prepared in conformity with generally accepted accounting principles in the United States of America and, accordingly, include some amounts that are based on the best estimates and judgments of management.
EOG's management is also responsible for establishing and maintaining adequate internal control over financial reporting as well as designing and implementing programs and controls to prevent and detect fraud. The system of internal control of EOG is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. This system consists of 1) entity level controls, including written policies and guidelines relating to the ethical conduct of business affairs, 2) general computer controls and 3) process controls over initiating, authorizing, recording, processing and reporting transactions. Even an effective internal control system, 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.
The adequacy of EOG's financial controls and the accounting principles employed by EOG in its financial reporting are under the general oversight of the Audit Committee of the Board of Directors. No member of this committee is an officer or employee of EOG. Moreover, EOG's independent registered public accounting firm and internal auditors have full, free, separate and direct access to the Audit Committee and meet with the committee periodically to discuss accounting, auditing and financial reporting matters.
EOG's management assessed the effectiveness of EOG's internal control over financial reporting as of December 31, 2019.2021. In making this assessment, EOG used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). These criteria cover the control environment, risk assessment process, control activities, information and communication systems, and monitoring activities. Based on this assessment and those criteria, management believes that EOG maintained effective internal control over financial reporting as of December 31, 2019.2021.
Deloitte & Touche LLP, independent registered public accounting firm, was engaged to audit the consolidated financial statements of EOG and audit EOG's internal control over financial reporting and issue a report thereon. In the conduct of the audits, Deloitte & Touche LLP was given unrestricted access to all financial records and related data, including all minutes of meetings of stockholders, the Board of Directors and committees of the Board of Directors. Management believes that all representations made to Deloitte & Touche LLP during the audits were valid and appropriate. Their audits were made in accordance with the standards of the Public Company Accounting Oversight Board (United States). Their report appears on page F-3.
|
| | | | | | | |
WILLIAM R. THOMASEZRA Y. YACOB | | TIMOTHY K. DRIGGERS |
Chairman of the Board andChief Executive Officer | | Executive Vice President and Chief |
Chief Executive Officer | | Financial Officer |
| | |
Houston, Texas | | |
February 27, 202024, 2022 | | |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholdersStockholders and the Board of Directors of
EOG Resources, Inc.
Houston, Texas
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of EOG Resources, Inc. and subsidiaries (the "Company") as of December 31, 20192021 and 2018,2020, the related consolidated statements of income (loss) and comprehensive income (loss), stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2019,2021, and the related notes (collectively referred to as the “financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019,2021, based on criteria established in Internal Control -— Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2021, based on the criteria established in Internal Control -— Integrated Framework (2013) issued by COSO.
Basis for Opinions
The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.
Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements.
Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Proved Oil and Gas Properties and Depletion and Impairment -– Crude Oil and Condensate, NGLs, and Natural Gas Reserves -Refer— Refer to NotesNote 1 and 14 to the financial statementsFinancial Statements
Critical Audit Matter Description
The Company’s capitalized costs of proved oil and natural gas properties are depleted using the units of production method and are evaluated for impairment by comparison to the net cash flows of the underlyingbased on estimated proved oil and natural gas reserves. The development of the Company’s estimated proved crude oil, NGLs and natural gas reserve volumes and the related future cash flows requires management to make significant estimates and scheduling assumptions related to the five-year development plan for proved undeveloped reserves, future oil and natural gas prices, and future well costs.assumptions. The Company’s reserve engineers estimate crude oil, NGLs and natural gas quantities using these estimates and assumptions and engineering data. Changes in these assumptions could have a significant impact onmaterially affect the Company’s estimated reserve quantities and the amount of depletion and any proved oil and gas impairment.depletion. Proved oil and gas properties were $24$23 billion as of December 31, 2019,2021, net of accumulated depletion, and depletion and proved property impairment were $3.75was $3.5 billion, and $207 million, respectively, for the year then ended.
Given the significant judgments made by management, performing audit procedures to evaluate the Company’s estimated proved crude oil, NGLs and natural gas reserve quantities, and the related net cash flows including management’s estimates and assumptions related to the five-year development plan, future oil and natural gas prices and future well costs, required a high degree of auditor judgment and an increased extent of effort, including the need to involve our fair value specialists.effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to management’s significant estimates and assumptions related to crude oil, NGLs and natural gas reserve quantities and estimates of future net cash flows included the following, among others:
•We tested the operating effectiveness of controls over the Company’s estimation of proved crude oil, NGLs and natural gas reserve quantities.
•We evaluated the Company’s estimated proved crude oil, NGLs and natural gas reserve quantities by:
◦Evaluating the experience, qualifications, and related future net cash flows, including controls relating to the five-year development plan, future oil and natural gas prices and future well costs.
We evaluated the reasonablenessobjectivity of management’s five-year development plan by comparing the forecasts to:
| |
◦ | Historical conversions of proved undeveloped reserves. |
| |
◦ | Internal communications to management and the Board of Directors. |
| |
◦ | Permits and approval for expenditures. |
| |
◦ | Analyst and industry reports for the Company and certain of its peer companies. |
With the assistance of our fair value specialists, we evaluated management’s estimated future oil and natural gas prices by:
| |
◦ | Understanding the methodology used by management for development of the future prices and comparing the estimated prices to an independently determined range of prices. |
| |
◦ | Comparing management’s estimates to published forward pricing indices and third-party industry sources. |
| |
◦ | Evaluating the historical realized price differentials incorporated in the future oil and natural gas prices. |
We evaluated the reasonableness of capital expenditures (well costs) by comparing to comparable historical wells drilled and analyst and industry reports.
We evaluated the Company’s reserve engineers and the independent petroleum consultants, including the methodologies used to estimate proved crude oil, NGLs and natural gas reserve quantities.
◦Comparing the Company’s reserve volumes by:to those independently developed by the independent petroleum consultants.
| |
◦ | Comparing the Company’s reserve volumes to historical production volumes. |
| |
◦ | Comparing the Company’s reserve volumes to those independently developed by the independent petroleum consultants. |
| |
◦ | Evaluating the reasonableness of the production volume decline curves. |
| |
◦ | Understanding the experience, qualifications, and objectivity of the Company’s reserve engineers and the independent petroleum consultants. |
◦Comparing the Company’s reserve estimated future production to historical production volumes.
◦Assessing the reasonableness of the production volume decline curves by comparing to historical decline curve estimates.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 27, 202024, 2022
We have served as the Company's auditor since 2002.
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
(In Thousands,Millions, Except Per Share Data)
| | | | | | | | | | | | | | | | | |
Year Ended December 31 | 2021 | | 2020 | | 2019 |
Operating Revenues and Other | | | | | |
Crude Oil and Condensate | $ | 11,125 | | | $ | 5,786 | | | $ | 9,613 | |
Natural Gas Liquids | 1,812 | | | 668 | | | 785 | |
Natural Gas | 2,444 | | | 837 | | | 1,184 | |
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | (1,152) | | | 1,145 | | | 180 | |
Gathering, Processing and Marketing | 4,288 | | | 2,583 | | | 5,360 | |
Gains (Losses) on Asset Dispositions, Net | 17 | | | (47) | | | 124 | |
Other, Net | 108 | | | 60 | | | 134 | |
Total | 18,642 | | | 11,032 | | | 17,380 | |
Operating Expenses | | | | | |
Lease and Well | 1,135 | | | 1,063 | | | 1,367 | |
Transportation Costs | 863 | | | 735 | | | 758 | |
Gathering and Processing Costs | 559 | | | 459 | | | 479 | |
Exploration Costs | 154 | | | 146 | | | 140 | |
Dry Hole Costs | 71 | | | 13 | | | 28 | |
Impairments | 376 | | | 2,100 | | | 518 | |
Marketing Costs | 4,173 | | | 2,698 | | | 5,352 | |
Depreciation, Depletion and Amortization | 3,651 | | | 3,400 | | | 3,750 | |
General and Administrative | 511 | | | 484 | | | 489 | |
Taxes Other Than Income | 1,047 | | | 478 | | | 800 | |
Total | 12,540 | | | 11,576 | | | 13,681 | |
Operating Income (Loss) | 6,102 | | | (544) | | | 3,699 | |
Other Income, Net | 9 | | | 10 | | | 31 | |
Income (Loss) Before Interest Expense and Income Taxes | 6,111 | | | (534) | | | 3,730 | |
Interest Expense | | | | | |
Incurred | 211 | | | 236 | | | 223 | |
Capitalized | (33) | | | (31) | | | (38) | |
Net Interest Expense | 178 | | | 205 | | | 185 | |
Income (Loss) Before Income Taxes | 5,933 | | | (739) | | | 3,545 | |
Income Tax Provision (Benefit) | 1,269 | | | (134) | | | 810 | |
Net Income (Loss) | $ | 4,664 | | | $ | (605) | | | $ | 2,735 | |
Net Income (Loss) Per Share | | | | | |
Basic | $ | 8.03 | | | $ | (1.04) | | | $ | 4.73 | |
Diluted | $ | 7.99 | | | $ | (1.04) | | | $ | 4.71 | |
Average Number of Common Shares | | | | | |
Basic | 581 | | | 579 | | | 578 | |
Diluted | 584 | | | 579 | | | 581 | |
Comprehensive Income (Loss) | | | | | |
Net Income (Loss) | $ | 4,664 | | | $ | (605) | | | $ | 2,735 | |
Other Comprehensive Loss | | | | | |
Foreign Currency Translation Adjustments | (1) | | | (7) | | | (3) | |
Other, Net of Tax | 1 | | | — | | | — | |
Other Comprehensive Loss | — | | | (7) | | | (3) | |
Comprehensive Income (Loss) | $ | 4,664 | | | $ | (612) | | | $ | 2,732 | |
|
| | | | | | | | | | | |
Year Ended December 31 | 2019 | | 2018 | | 2017 |
Operating Revenues and Other | | | | | |
Crude Oil and Condensate | $ | 9,612,532 |
| | $ | 9,517,440 |
| | $ | 6,256,396 |
|
Natural Gas Liquids | 784,818 |
| | 1,127,510 |
| | 729,561 |
|
Natural Gas | 1,184,095 |
| | 1,301,537 |
| | 921,934 |
|
Gains (Losses) on Mark-to-Market Commodity Derivative Contracts | 180,275 |
| | (165,640 | ) | | 19,828 |
|
Gathering, Processing and Marketing | 5,360,282 |
| | 5,230,355 |
| | 3,298,087 |
|
Gains (Losses) on Asset Dispositions, Net | 123,613 |
| | 174,562 |
| | (99,096 | ) |
Other, Net | 134,358 |
| | 89,635 |
| | 81,610 |
|
Total | 17,379,973 |
| | 17,275,399 |
| | 11,208,320 |
|
Operating Expenses | |
| | |
| | |
|
Lease and Well | 1,366,993 |
| | 1,282,678 |
| | 1,044,847 |
|
Transportation Costs | 758,300 |
| | 746,876 |
| | 740,352 |
|
Gathering and Processing Costs | 479,102 |
| | 436,973 |
| | 148,775 |
|
Exploration Costs | 139,881 |
| | 148,999 |
| | 145,342 |
|
Dry Hole Costs | 28,001 |
| | 5,405 |
| | 4,609 |
|
Impairments | 517,896 |
| | 347,021 |
| | 479,240 |
|
Marketing Costs | 5,351,524 |
| | 5,203,243 |
| | 3,330,237 |
|
Depreciation, Depletion and Amortization | 3,749,704 |
| | 3,435,408 |
| | 3,409,387 |
|
General and Administrative | 489,397 |
| | 426,969 |
| | 434,467 |
|
Taxes Other Than Income | 800,164 |
| | 772,481 |
| | 544,662 |
|
Total | 13,680,962 |
| | 12,806,053 |
| | 10,281,918 |
|
Operating Income | 3,699,011 |
| | 4,469,346 |
| | 926,402 |
|
Other Income, Net | 31,385 |
| | 16,704 |
| | 9,152 |
|
Income Before Interest Expense and Income Taxes | 3,730,396 |
| | 4,486,050 |
| | 935,554 |
|
Interest Expense | |
| | |
| | |
|
Incurred | 223,421 |
| | 269,549 |
| | 301,801 |
|
Capitalized | (38,292 | ) | | (24,497 | ) | | (27,429 | ) |
Net Interest Expense | 185,129 |
| | 245,052 |
| | 274,372 |
|
Income Before Income Taxes | 3,545,267 |
| | 4,240,998 |
| | 661,182 |
|
Income Tax Provision (Benefit) | 810,357 |
| | 821,958 |
| | (1,921,397 | ) |
Net Income | $ | 2,734,910 |
| | $ | 3,419,040 |
| | $ | 2,582,579 |
|
Net Income Per Share | |
| | |
| | |
|
Basic | $ | 4.73 |
| | $ | 5.93 |
| | $ | 4.49 |
|
Diluted | $ | 4.71 |
| | $ | 5.89 |
| | $ | 4.46 |
|
Average Number of Common Shares | |
| | |
| | |
|
Basic | 577,670 |
| | 576,578 |
| | 574,620 |
|
Diluted | 580,777 |
| | 580,441 |
| | 578,693 |
|
Comprehensive Income | |
| | |
| | |
|
Net Income | $ | 2,734,910 |
| | $ | 3,419,040 |
| | $ | 2,582,579 |
|
Other Comprehensive Income (Loss) | |
| | |
| | |
|
Foreign Currency Translation Adjustments | (2,883 | ) | | 16,816 |
| | 2,799 |
|
Other, Net of Tax | (678 | ) | | 1,123 |
| | (3,086 | ) |
Other Comprehensive Income (Loss) | (3,561 | ) | | 17,939 |
| | (287 | ) |
Comprehensive Income | $ | 2,731,349 |
| | $ | 3,436,979 |
| | $ | 2,582,292 |
|
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED BALANCE SHEETS
(In Thousands,Millions, Except Share Data)
|
| | | | | | | |
At December 31 | 2019 | | 2018 |
ASSETS |
Current Assets | | | |
Cash and Cash Equivalents | $ | 2,027,972 |
| | $ | 1,555,634 |
|
Accounts Receivable, Net | 2,001,658 |
| | 1,915,215 |
|
Inventories | 767,297 |
| | 859,359 |
|
Assets from Price Risk Management Activities | 1,299 |
| | 23,806 |
|
Income Taxes Receivable | 151,665 |
| | 427,909 |
|
Other | 323,448 |
| | 275,467 |
|
Total | 5,273,339 |
| | 5,057,390 |
|
Property, Plant and Equipment | |
| | |
|
Oil and Gas Properties (Successful Efforts Method) | 62,830,415 |
| | 57,330,016 |
|
Other Property, Plant and Equipment | 4,472,246 |
| | 4,220,665 |
|
Total Property, Plant and Equipment | 67,302,661 |
| | 61,550,681 |
|
Less: Accumulated Depreciation, Depletion and Amortization | (36,938,066 | ) | | (33,475,162 | ) |
Total Property, Plant and Equipment, Net | 30,364,595 |
| | 28,075,519 |
|
Deferred Income Taxes | 2,363 |
| | 777 |
|
Other Assets | 1,484,311 |
| | 800,788 |
|
Total Assets | $ | 37,124,608 |
| | $ | 33,934,474 |
|
LIABILITIES AND STOCKHOLDERS' EQUITY |
Current Liabilities | |
| | |
|
Accounts Payable | $ | 2,429,127 |
| | $ | 2,239,850 |
|
Accrued Taxes Payable | 254,850 |
| | 214,726 |
|
Dividends Payable | 166,273 |
| | 126,971 |
|
Liabilities from Price Risk Management Activities | 20,194 |
| | — |
|
Current Portion of Long-Term Debt | 1,014,524 |
| | 913,093 |
|
Current Portion of Operating Lease Liabilities | 369,365 |
| | — |
|
Other | 232,655 |
| | 233,724 |
|
Total | 4,486,988 |
| | 3,728,364 |
|
Long-Term Debt | 4,160,919 |
| | 5,170,169 |
|
Other Liabilities | 1,789,884 |
| | 1,258,355 |
|
Deferred Income Taxes | 5,046,101 |
| | 4,413,398 |
|
Commitments and Contingencies (Note 8) |
|
| |
|
|
Stockholders' Equity | |
| | |
|
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 582,213,016 Shares and 580,408,117 Shares Issued at December 31, 2019 and 2018, respectively | 205,822 |
| | 205,804 |
|
Additional Paid in Capital | 5,817,475 |
| | 5,658,794 |
|
Accumulated Other Comprehensive Loss | (4,652 | ) | | (1,358 | ) |
Retained Earnings | 15,648,604 |
| | 13,543,130 |
|
Common Stock Held in Treasury, 298,820 Shares and 385,042 Shares at December 31, 2019 and 2018, respectively | (26,533 | ) | | (42,182 | ) |
Total Stockholders' Equity | 21,640,716 |
| | 19,364,188 |
|
Total Liabilities and Stockholders' Equity | $ | 37,124,608 |
| | $ | 33,934,474 |
|
| | | | | | | | | | | |
At December 31 | 2021 | | 2020 |
ASSETS |
Current Assets | | | |
Cash and Cash Equivalents | $ | 5,209 | | | $ | 3,329 | |
Accounts Receivable, Net | 2,335 | | | 1,522 | |
Inventories | 584 | | | 629 | |
Assets from Price Risk Management Activities | — | | | 65 | |
Income Taxes Receivable | — | | | 23 | |
Other | 456 | | | 294 | |
Total | 8,584 | | | 5,862 | |
Property, Plant and Equipment | | | |
Oil and Gas Properties (Successful Efforts Method) | 67,644 | | | 64,793 | |
Other Property, Plant and Equipment | 4,753 | | | 4,479 | |
Total Property, Plant and Equipment | 72,397 | | | 69,272 | |
Less: Accumulated Depreciation, Depletion and Amortization | (43,971) | | | (40,673) | |
Total Property, Plant and Equipment, Net | 28,426 | | | 28,599 | |
Deferred Income Taxes | 11 | | | 2 | |
Other Assets | 1,215 | | | 1,342 | |
Total Assets | $ | 38,236 | | | $ | 35,805 | |
LIABILITIES AND STOCKHOLDERS' EQUITY |
Current Liabilities | | | |
Accounts Payable | $ | 2,242 | | | $ | 1,681 | |
Accrued Taxes Payable | 518 | | | 206 | |
Dividends Payable | 436 | | | 217 | |
Liabilities from Price Risk Management Activities | 269 | | | — | |
Current Portion of Long-Term Debt | 37 | | | 781 | |
Current Portion of Operating Lease Liabilities | 240 | | | 295 | |
Other | 300 | | | 280 | |
Total | 4,042 | | | 3,460 | |
Long-Term Debt | 5,072 | | | 5,035 | |
Other Liabilities | 2,193 | | | 2,149 | |
Deferred Income Taxes | 4,749 | | | 4,859 | |
Commitments and Contingencies (Note 8) | 0 | | 0 |
Stockholders' Equity | | | |
Common Stock, $0.01 Par, 1,280,000,000 Shares Authorized and 585,521,512 Shares and 583,694,850 Shares Issued at December 31, 2021 and 2020, respectively | 206 | | | 206 | |
Additional Paid in Capital | 6,087 | | | 5,945 | |
Accumulated Other Comprehensive Loss | (12) | | | (12) | |
Retained Earnings | 15,919 | | | 14,170 | |
Common Stock Held in Treasury, 257,268 Shares and 124,265 Shares at December 31, 2021 and 2020, respectively | (20) | | | (7) | |
Total Stockholders' Equity | 22,180 | | | 20,302 | |
Total Liabilities and Stockholders' Equity | $ | 38,236 | | | $ | 35,805 | |
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In Thousands,Millions, Except Per Share Data) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | Additional Paid In Capital | | Accumulated Other Comprehensive Income (Loss) | | Retained Earnings | | Common Stock Held In Treasury | | Total Stockholders' Equity |
Balance at December 31, 2018 | $ | 206 | | | $ | 5,659 | | | $ | (2) | | | $ | 13,543 | | | $ | (42) | | | $ | 19,364 | |
Net Income | — | | | — | | | — | | | 2,735 | | | — | | | 2,735 | |
Common Stock Issued Under Stock Plans | — | | | — | | | — | | | — | | | — | | | — | |
Common Stock Dividends Declared, $1.0825 Per Share | — | | | — | | | — | | | (629) | | | — | | | (629) | |
Other Comprehensive Income | — | | | — | | | (3) | | | — | | | — | | | (3) | |
Change in Treasury Stock - Stock Compensation Plans, Net | — | | | (11) | | | — | | | — | | | 3 | | | (8) | |
Restricted Stock and Restricted Stock Units, Net | — | | | (5) | | | — | | | — | | | 5 | | | — | |
Stock-Based Compensation Expenses | — | | | 175 | | | — | | | — | | | — | | | 175 | |
Treasury Stock Issued as Compensation | — | | | (1) | | | — | | | — | | | 7 | | | 6 | |
Balance at December 31, 2019 | 206 | | | 5,817 | | | (5) | | | 15,649 | | | (27) | | | 21,640 | |
Net Loss | — | | | — | | | — | | | (605) | | | — | | | (605) | |
Common Stock Issued Under Stock Plans | — | | | — | | | — | | | — | | | — | | | — | |
Common Stock Dividends Declared, $1.50 Per Share | — | | | — | | | — | | | (874) | | | — | | | (874) | |
Other Comprehensive Loss | — | | | — | | | (7) | | | — | | | — | | | (7) | |
Change in Treasury Stock - Stock Compensation Plans, Net | — | | | (9) | | | — | | | — | | | 9 | | | — | |
Restricted Stock and Restricted Stock Units, Net | — | | | (9) | | | — | | | — | | | 9 | | | — | |
Stock-Based Compensation Expenses | — | | | 146 | | | — | | | — | | | — | | | 146 | |
Treasury Stock Issued as Compensation | — | | | — | | | — | | | — | | | 2 | | | 2 | |
Balance at December 31, 2020 | 206 | | | 5,945 | | | (12) | | | 14,170 | | | (7) | | | 20,302 | |
Net Income | — | | | — | | | — | | | 4,664 | | | — | | | 4,664 | |
Common Stock Issued Under Stock Plans | — | | | 17 | | | — | | | — | | | — | | | 17 | |
Common Stock Dividends Declared, $4.9875 Per Share | — | | | — | | | — | | | (2,915) | | | — | | | (2,915) | |
Other Comprehensive Loss | — | | | — | | | — | | | — | | | — | | | — | |
Change in Treasury Stock - Stock Compensation Plans, Net | — | | | (22) | | | — | | | — | | | (18) | | | (40) | |
Restricted Stock and Restricted Stock Units, Net | — | | | (5) | | | — | | | — | | | 5 | | | — | |
Stock-Based Compensation Expenses | — | | | 152 | | | — | | | — | | | — | | | 152 | |
Treasury Stock Issued as Compensation | — | | | — | | | — | | | — | | | — | | | — | |
Balance at December 31, 2021 | $ | 206 | | | $ | 6,087 | | | $ | (12) | | | $ | 15,919 | | | $ | (20) | | | $ | 22,180 | |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | Additional Paid In Capital | | Accumulated Other Comprehensive Income (Loss) | | Retained Earnings | | Common Stock Held In Treasury | | Total Stockholders' Equity |
Balance at December 31, 2016 | $ | 205,770 |
| | $ | 5,420,385 |
| | $ | (19,010 | ) | | $ | 8,398,118 |
| | $ | (23,682 | ) | | $ | 13,981,581 |
|
Net Income | — |
| | — |
| | — |
| | 2,582,579 |
| | — |
| | 2,582,579 |
|
Common Stock Issued Under Stock Plans | 7 |
| | 7,082 |
| | — |
| | — |
| | — |
| | 7,089 |
|
Common Stock Dividends Declared, $0.67 Per Share | — |
| | — |
| | — |
| | (387,164 | ) | | — |
| | (387,164 | ) |
Other Comprehensive Loss | — |
| | — |
| | (287 | ) | | — |
| | — |
| | (287 | ) |
Change in Treasury Stock - Stock Compensation Plans, Net | — |
| | (27,348 | ) | | — |
| | — |
| | (9,395 | ) | | (36,743 | ) |
Restricted Stock and Restricted Stock Units, Net | 11 |
| | 2,552 |
| | — |
| | — |
| | (2,563 | ) | | — |
|
Stock-Based Compensation Expenses | — |
| | 133,849 |
| | — |
| | — |
| | — |
| | 133,849 |
|
Treasury Stock Issued as Compensation | — |
| | 27 |
| | — |
| | — |
| | 2,342 |
| | 2,369 |
|
Balance at December 31, 2017 | 205,788 |
| | 5,536,547 |
| | (19,297 | ) | | 10,593,533 |
| | (33,298 | ) | | 16,283,273 |
|
Net Income | — |
| | — |
| | — |
| | 3,419,040 |
| | — |
| | 3,419,040 |
|
Common Stock Issued Under Stock Plans | 8 |
| | 5,612 |
| | — |
| | — |
| | — |
| | 5,620 |
|
Common Stock Dividends Declared, $0.81 Per Share | — |
| | — |
| | — |
| | (469,443 | ) | | — |
| | (469,443 | ) |
Other Comprehensive Income | — |
| | — |
| | 17,939 |
| | — |
| | — |
| | 17,939 |
|
Change in Treasury Stock - Stock Compensation Plans, Net | — |
| | (35,118 | ) | | — |
| | — |
| | (13,336 | ) | | (48,454 | ) |
Restricted Stock and Restricted Stock Units, Net | 8 |
| | (3,891 | ) | | — |
| | — |
| | 3,883 |
| | — |
|
Stock-Based Compensation Expenses | — |
| | 155,337 |
| | — |
| | — |
| | — |
| | 155,337 |
|
Treasury Stock Issued as Compensation | — |
| | 307 |
| | — |
| | — |
| | 569 |
| | 876 |
|
Balance at December 31, 2018 | 205,804 |
| | 5,658,794 |
| | (1,358 | ) | | 13,543,130 |
| | (42,182 | ) | | 19,364,188 |
|
Net Income | — |
| | — |
| | — |
| | 2,734,910 |
| | — |
| | 2,734,910 |
|
Common Stock Issued Under Stock Plans | 1 |
| | (9 | ) | | — |
| | — |
| | — |
| | (8 | ) |
Common Stock Dividends Declared, $1.0825 Per Share | — |
| | — |
| | — |
| | (629,169 | ) | | — |
| | (629,169 | ) |
Other Comprehensive Loss | — |
| | — |
| | (3,561 | ) | | — |
| | — |
| | (3,561 | ) |
Change in Treasury Stock - Stock Compensation Plans, Net | — |
| | (10,637 | ) | | — |
| | — |
| | 3,784 |
| | (6,853 | ) |
Restricted Stock and Restricted Stock Units, Net | 17 |
| | (4,566 | ) | | — |
| | — |
| | 4,549 |
| | — |
|
Stock-Based Compensation Expenses | — |
| | 174,738 |
| | — |
| | — |
| | — |
| | 174,738 |
|
Treasury Stock Issued as Compensation | — |
| | (845 | ) | | — |
| | — |
| | 7,316 |
| | 6,471 |
|
Cumulative Effect of Accounting Changes | — |
| | — |
| | 267 |
| | (267 | ) | | — |
| | — |
|
Balance at December 31, 2019 | $ | 205,822 |
| | $ | 5,817,475 |
| | $ | (4,652 | ) | | $ | 15,648,604 |
| | $ | (26,533 | ) | | $ | 21,640,716 |
|
The accompanying notes are an integral part of these consolidated financial statements.
EOG RESOURCES, INC.
The accompanying notes are an integral part of these consolidated financial statements.