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Oil and Gas Exploration and Production Industries Disclosures (Notes)
 12 Months Ended
Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Oil and Gas Exploration and Production Industries Disclosures
Oil and Gas Producing Activities

The following disclosures are made in accordance with Financial Accounting Standards Board Accounting Standards Update No. 2010-03 "Oil and Gas Reserve Estimation and Disclosures" and the United States Securities and Exchange Commission's (SEC) final rule on "Modernization of Oil and Gas Reporting."

Oil and Gas Reserves.  Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids (NGLs) and natural 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; crude oil and condensate, NGL and natural gas prices; and continual reassessment of the viability of production under varying economic conditions.  Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time.  Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.  For related discussion, see ITEM 1A, Risk Factors.

Proved reserves represent estimated quantities of crude oil, NGLs and natural gas, which, by analysis of geoscience and engineering data, can be estimated, with reasonable certainty, to be economically producible from a given date forward from known reservoirs under then-existing economic conditions, operating methods and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

Proved developed reserves are proved reserves expected to be recovered under operating methods being utilized at the time the estimates were made, through wells and equipment in place or if the cost of any required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves (PUDs) are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion or recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. PUDs can be recorded in respect of a particular undrilled location only if the location is scheduled, under the then-current drilling and development plan, to be drilled within five years from the date that the PUDs were recorded, unless specific factors (such as those described in interpretative guidance issued by the Staff of the SEC) justify a longer timeframe.  Likewise, absent any such specific factors, PUDs associated with a particular undeveloped drilling location shall be removed from the estimates of proved reserves if the location is scheduled, under the then-current drilling and development plan, to be drilled on a date that is beyond five years from the date that the PUDs were recorded.  EOG has formulated development plans for all drilling locations associated with its PUDs at December 31, 2020.  Under these plans, each PUD location will be drilled within five years from the date it was recorded.  Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

In making estimates of PUDs, EOG's technical staff, including engineers and geoscientists, perform detailed technical analysis of each potential drilling location within its inventory of prospects.  In making a determination as to which of these locations would penetrate undrilled portions of the formation that can be judged, with reasonable certainty, to be continuous and contain economically producible crude oil, NGLs and natural gas, studies are conducted using numerous data elements and analysis techniques.  EOG's technical staff estimates the hydrocarbons in place, by mapping the entirety of the play in question using seismic techniques, typically employing two-dimensional and three-dimensional data.  This analysis is integrated with other static data, including, but not limited to, core analysis, mechanical properties of the formation, thermal maturity indicators, and well logs of existing penetrations.  Highly specialized equipment is utilized to prepare rock samples in assessing microstructures which contribute to porosity and permeability.

Analysis of dynamic data is then incorporated to arrive at the estimated fractional recovery of hydrocarbons in place.  Data analysis techniques employed include, but are not limited to, well testing analysis, static bottom hole pressure analysis, flowing bottom hole pressure analysis, analysis of historical production trends, pressure transient analysis and rate transient analysis.  Application of proprietary rate transient analysis techniques in low permeability rocks allow for quantification of estimates of contribution to production from both fractures and rock matrix.
The impact of optimal completion techniques is a key factor in determining if the PUDs reflected in prospective locations are reasonably certain of being economically producible.  EOG's technical staff estimates the recovery improvement that might be achieved when completing horizontal wells with multi-stage fracture stimulation.  In the early stages of development of a play, EOG determines the optimal length of the horizontal lateral and multi-stage fracture stimulation using the aforementioned analysis techniques along with pilot drilling programs and gathering of microseismic data.

The process of analyzing static and dynamic data, well completion optimization data and the results of early development activities provides the appropriate level of certainty as well as support for the economic producibility of the plays in which PUDs are reflected.  EOG has found this approach to be effective based on successful application in analogous reservoirs in low permeability resource plays.

Certain of EOG's Trinidad reserves are held under production sharing contracts where EOG's interest varies with prices and production volumes.  Trinidad reserves, as presented on a net basis, assume prices in existence at the time the estimates were made and EOG's estimate of future production volumes.  Future fluctuations in prices, production rates or changes in political or regulatory environments could cause EOG's share of future production from Trinidadian reserves to be materially different from that presented.

Estimates of proved reserves at December 31, 2020, 2019 and 2018 were based on studies performed by the engineering staff of EOG.  The Engineering and Acquisitions Department is directly responsible for EOG's reserve evaluation process and consists of 17 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and four of whom are Registered Professional Engineers.  The Vice President, Engineering and Acquisitions is the manager of this department and is the primary technical person responsible for this process.  The Vice President, Engineering and Acquisitions holds a Bachelor of Science degree in Petroleum Engineering, has 34 years of experience in reserve evaluations and is a Registered Professional Engineer.

EOG's reserves estimation process is a collaborative effort coordinated by the Engineering and Acquisitions Department in compliance with EOG's internal controls for such process.  Reserve information as well as models used to estimate such reserves are stored on secured databases.  Non-technical inputs used in reserve estimation models, including crude oil, NGL and natural gas prices, production costs, transportation costs, future capital expenditures and EOG's net ownership percentages, are obtained from other departments within EOG.  EOG's Internal Audit Department conducts testing with respect to such non-technical inputs.  Additionally, EOG engages DeGolyer and MacNaughton (D&M), independent petroleum consultants, to perform independent reserves evaluation of select EOG properties comprising not less than 75% of EOG's estimates of proved reserves.  EOG's Board of Directors requires that D&M's and EOG's reserve quantities for the properties evaluated by D&M vary by no more than 5% in the aggregate.  Once completed, EOG's year-end reserves are presented to senior management, including the Chairman of the Board and Chief Executive Officer; the Chief Operating Officer; the President; the Executive Vice President, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2020, 2019 and 2018 covered producing areas containing 83%, 82% and 79%, respectively, of proved reserves of EOG on a net-equivalent-barrel-of-oil basis.  D&M's opinions indicate that the estimates of proved reserves prepared by EOG's Engineering and Acquisitions Department for the properties reviewed by D&M, when compared in total on a net-equivalent-barrel-of-oil basis, do not differ materially from the estimates prepared by D&M.  Specifically, such estimates by D&M in the aggregate varied by not more than 5% from those prepared by the Engineering and Acquisitions Department of EOG.  All reports by D&M were developed utilizing geological and engineering data provided by EOG.  The report of D&M dated January 26, 2021, which contains further discussion of the reserve estimates and evaluations prepared by D&M, as well as the qualifications of D&M's technical person primarily responsible for overseeing such estimates and evaluations, is attached as Exhibit 99.1 to this Annual Report on Form 10-K and incorporated herein by reference.

No major discovery or other favorable or adverse event subsequent to December 31, 2020, is believed to have caused a material change in the estimates of net proved reserves as of that date.

The following tables set forth EOG's net proved reserves at December 31 for each of the four years in the period ended December 31, 2020, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2020, as estimated by the Engineering and Acquisitions Department of EOG:
NET PROVED RESERVE SUMMARY
 United
States		Trinidad
Other
International (1)
Total
NET PROVED RESERVES
Crude Oil (MBbl) (2)
Net proved reserves at December 31, 20171,304,071 898 8,004 1,312,973 
Revisions of previous estimates(13,237)(183)44 (13,376)
Purchases in place2,743 — — 2,743 
Extensions, discoveries and other additions383,003 — 15 383,018 
Sales in place(768)— (6,310)(7,078)
Production(144,128)(298)(1,542)(145,968)
Net proved reserves at December 31, 20181,531,684 417 211 1,532,312 
Revisions of previous estimates(42,959)85 (8)(42,882)
Purchases in place2,859 — — 2,859 
Extensions, discoveries and other additions369,968 — 28 369,996 
Sales in place(1,282)— — (1,282)
Production(166,310)(236)(40)(166,586)
Net proved reserves at December 31, 20191,693,960 266 191 1,694,417 
Revisions of previous estimates(225,375)(19)(18)(225,412)
Purchases in place2,176 — — 2,176 
Extensions, discoveries and other additions194,724 863 — 195,587 
Sales in place(3,183)— — (3,183)
Production(149,402)(355)(30)(149,787)
Net proved reserves at December 31, 20201,512,900 755 143 1,513,798 
Natural Gas Liquids (MBbl) (2)
    
Net proved reserves at December 31, 2017503,473 — — 503,473 
Revisions of previous estimates23,942 — — 23,942 
Purchases in place2,006 — — 2,006 
Extensions, discoveries and other additions127,409 — — 127,409 
Sales in place(41)— — (41)
Production(42,460)— — (42,460)
Net proved reserves at December 31, 2018614,329 — — 614,329 
Revisions of previous estimates5,380 — — 5,380 
Purchases in place1,948 — — 1,948 
Extensions, discoveries and other additions167,782 — — 167,782 
Sales in place(855)— — (855)
Production(48,892)— — (48,892)
Net proved reserves at December 31, 2019739,692 — — 739,692 
Revisions of previous estimates(59,790)— — (59,790)
Purchases in place3,831 — — 3,831 
Extensions, discoveries and other additions180,205 — — 180,205 
Sales in place(1,399)— — (1,399)
Production(49,796)— — (49,796)
Net proved reserves at December 31, 2020812,743 — — 812,743 
 United
States		Trinidad
Other
International (1)
Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 20173,898.5 313.4 51.2 4,263.1 
Revisions of previous estimates(127.2)20.7 15.0 (91.5)
Purchases in place41.3 — — 41.3 
Extensions, discoveries and other additions951.4 — 4.6 956.0 
Sales in place(22.2)— — (22.2)
Production(351.2)(97.1)(11.2)(459.5)
Net proved reserves at December 31, 20184,390.6 237.0 59.6 4,687.2 
Revisions of previous estimates(184.4)47.0 2.6 (134.8)
Purchases in place71.7 — — 71.7 
Extensions, discoveries and other additions1,175.9 87.5 9.7 1,273.1 
Sales in place(14.5)— — (14.5)
Production(404.5)(95.4)(13.1)(513.0)
Net proved reserves at December 31, 20195,034.8 276.1 58.8 5,369.7 
Revisions of previous estimates(497.7)4.8 1.6 (491.3)
Purchases in place26.3 — — 26.3 
Extensions, discoveries and other additions1,077.9 53.9 — 1,131.8 
Sales in place(157.3)— — (157.3)
Production(441.4)(65.9)(11.6)(518.9)
Net proved reserves at December 31, 20205,042.6 268.9 48.8 5,360.3 
Oil Equivalents (MBoe) (2)
    
Net proved reserves at December 31, 20172,457,302 53,142 16,526 2,526,970 
Revisions of previous estimates(10,500)3,272 2,544 (4,684)
Purchases in place11,640 — — 11,640 
Extensions, discoveries and other additions668,972 — 778 669,750 
Sales in place(4,509)— (6,310)(10,819)
Production(245,127)(16,478)(3,406)(265,011)
Net proved reserves at December 31, 20182,877,778 39,936 10,132 2,927,846 
Revisions of previous estimates(68,317)7,915 431 (59,971)
Purchases in place16,761 — — 16,761 
Extensions, discoveries and other additions733,730 14,577 1,661 749,968 
Sales in place(4,555)— — (4,555)
Production(282,619)(16,130)(2,232)(300,981)
Net proved reserves at December 31, 20193,272,778 46,298 9,992 3,329,068 
Revisions of previous estimates(368,127)773 259 (367,095)
Purchases in place10,398 — — 10,398 
Extensions, discoveries and other additions554,585 9,840 — 564,425 
Sales in place(30,802)— — (30,802)
Production(272,757)(11,347)(1,969)(286,073)
Net proved reserves at December 31, 20203,166,075 45,564 8,282 3,219,921 
(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.
(2)Thousand barrels or thousand barrels of oil equivalent, as applicable; oil equivalents include crude oil and condensate, NGLs and natural gas. Oil equivalents 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.
(3)Billion cubic feet.
During 2020, EOG added 564 million barrels of oil equivalent (MMBoe) of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin.  Approximately 67% of the 2020 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States.  Sales in place of 31 MMBoe were primarily related to the sale of the Marcellus Shale assets and the sale or exchange of other producing assets. Revisions of previous estimates of negative 367 MMBoe for 2020 included a downward revision of 278 MMBoe primarily due to decreases in the average crude oil, NGLs and natural gas prices used in the December 31, 2020, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were the Eagle Ford and the Rocky Mountain area. Purchases in place of 10 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets.

During 2019, EOG added 750 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford and the Rocky Mountain area.  Approximately 72% of the 2019 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States.  Sales in place of 5 MMBoe were primarily related to the sale of certain South Texas area operations and the sale or exchange of other producing assets. Revisions of previous estimates of negative 60 MMBoe for 2019 included a decrease in the average crude oil, NGLs and natural gas prices used in the December 31, 2019, reserves estimation as compared to the prices used in the prior year estimate. The primary area affected was the Rocky Mountain area. Purchases in place of 17 MMBoe were primarily related to the South Texas area.

During 2018, EOG added 670 MMBoe of proved reserves from drilling activities and technical evaluation of major proved areas, primarily in the Permian Basin, the Eagle Ford, the Rocky Mountain area and the Mid-Continent area.  Approximately 76% of the 2018 reserve additions were crude oil and condensate and NGLs, and substantially all were in the United States.  Sales in place of 11 MMBoe were primarily related to the sale of the United Kingdom operations and the sale or exchange of other producing assets. Revisions of previous estimates of negative 5 MMBoe for 2018 included an upward revision of 35 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2018, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Downward revisions other than price of 40 MMBoe resulted primarily from changes in production forecasts and higher production costs. Purchases in place of 12 MMBoe were primarily related to the South Texas area.
 United
States		Trinidad
Other
International (1)
Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MBbl)
December 31, 2017605,405 898 7,933 614,236 
December 31, 2018712,218 417 150 712,785 
December 31, 2019801,189 266 143 801,598 
December 31, 2020791,744 755 93 792,592 
Natural Gas Liquids (MBbl)    
December 31, 2017286,872 — — 286,872 
December 31, 2018341,386 — — 341,386 
December 31, 2019387,253 — — 387,253 
December 31, 2020391,708 — — 391,708 
Natural Gas (Bcf)    
December 31, 20172,450.8 299.2 29.3 2,779.3 
December 31, 20182,699.0 223.9 40.9 2,963.8 
December 31, 20192,974.6 177.7 41.8 3,194.1 
December 31, 20202,586.1 171.1 31.6 2,788.8 
Oil Equivalents (MBoe)    
December 31, 20171,300,758 50,779 12,798 1,364,335 
December 31, 20181,503,441 37,746 6,950 1,548,137 
December 31, 20191,684,209 29,886 7,117 1,721,212 
December 31, 20201,614,462 29,268 5,368 1,649,098 
NET PROVED UNDEVELOPED RESERVES    
Crude Oil (MBbl)    
December 31, 2017698,666 — 71 698,737 
December 31, 2018819,466 — 61 819,527 
December 31, 2019892,771 — 48 892,819 
December 31, 2020721,156 — 50 721,206 
Natural Gas Liquids (MBbl)    
December 31, 2017216,601 — — 216,601 
December 31, 2018272,943 — — 272,943 
December 31, 2019352,439 — — 352,439 
December 31, 2020421,035 — — 421,035 
Natural Gas (Bcf)    
December 31, 20171,447.7 14.2 21.9 1,483.8 
December 31, 20181,691.6 13.1 18.7 1,723.4 
December 31, 20192,060.2 98.4 17.0 2,175.6 
December 31, 20202,456.5 97.8 17.2 2,571.5 
Oil Equivalents (MBoe)    
December 31, 20171,156,544 2,363 3,728 1,162,635 
December 31, 20181,374,337 2,190 3,182 1,379,709 
December 31, 20191,588,569 16,412 2,875 1,607,856 
December 31, 20201,551,613 16,296 2,914 1,570,823 
(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.
Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total PUDs during 2020, 2019 and 2018 (in MBoe):
 202020192018
Balance at January 11,607,856 1,379,709 1,162,635 
Extensions and Discoveries
456,073 578,317 490,725 
Revisions
(277,325)(49,837)(8,244)
Acquisition of Reserves
47 1,711 311 
Sale of Reserves
(3,670)— — 
Conversion to Proved Developed Reserves
(212,158)(302,044)(265,718)
Balance at December 311,570,823 1,607,856 1,379,709 

For the twelve-month period ended December 31, 2020, total PUDs decreased by 37 MMBoe to 1,571 MMBoe.  EOG added approximately 7 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs (see discussion of technology employed on pages F-43 and F-44 of this Annual Report on Form 10-K), EOG added 449 MMBoe of PUDs.  The PUD additions were primarily in the Permian Basin and 67% of the additions were crude oil and condensate and NGLs.  During 2020, EOG drilled and transferred 212 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,674 million. Revisions of previous estimates of negative 277 MMBoe of PUDs for 2020 included a downward price revision of 77 MMBoe due to decreases in the average crude oil, NGLs and natural gas prices used in the December 31, 2020, reserves estimation as compared to the prices used in the prior year estimate.  Revisions other than price of negative 200 MMBoe were primarily related to the removal of PUD locations due to lower projected capital spending over the next five years as compared to the prior year projections. The primary areas affected were the Eagle Ford and the Rocky Mountain area. All PUDs, including drilled but uncompleted wells (DUCs), are scheduled for completion within five years of the original reserve booking.

For the twelve-month period ended December 31, 2019, total PUDs increased by 228 MMBoe to 1,608 MMBoe.  EOG added approximately 38 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs, EOG added 540 MMBoe.  The PUD additions were primarily in the Permian Basin, the Eagle Ford and, to a lesser extent, the Rocky Mountain area, and 73% of the additions were crude oil and condensate and NGLs.  During 2019, EOG drilled and transferred 302 MMBoe of PUDs to proved developed reserves at a total capital cost of $3,032 million. 

For the twelve-month period ended December 31, 2018, total PUDs increased by 217 MMBoe to 1,380 MMBoe.  EOG added approximately 31 MMBoe of PUDs through drilling activities where the wells were drilled but significant expenditures remained for completion.  Based on the technology employed by EOG to identify and record PUDs, EOG added 460 MMBoe.  The PUD additions were primarily in the Permian Basin, Anadarko Basin, the Eagle Ford and, to a lesser extent, the Rocky Mountain area, and 80% of the additions were crude oil and condensate and NGLs.  During 2018, EOG drilled and transferred 266 MMBoe of PUDs to proved developed reserves at a total capital cost of $2,745 million. 
Capitalized Costs Relating to Oil and Gas Producing Activities.  The following table sets forth the capitalized costs relating to EOG's crude oil, NGLs and natural gas producing activities at December 31, 2020 and 2019:
 20202019
Proved properties$61,724,487 $59,229,686 
Unproved properties3,068,311 3,600,729 
Total64,792,798 62,830,415 
Accumulated depreciation, depletion and amortization(38,750,852)(35,033,085)
Net capitalized costs$26,041,946 $27,797,330 

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities.  The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil and Gas Topic of the Accounting Standards Codification (ASC).

Acquisition costs include costs incurred to purchase, lease or otherwise acquire property.

Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses.

Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.
The following table sets forth costs incurred related to EOG's oil and gas activities for the years ended December 31, 2020, 2019 and 2018:
 United
States		Trinidad
Other
International (1)
Total
2020
Acquisition Costs of Properties
Unproved (2)
$264,778 $— $— $264,778 
Proved (3)
97,073 — 38,089 135,162 
Subtotal361,851 — 38,089 399,940 
Exploration Costs203,403 81,216 11,409 296,028 
Development Costs (4)
2,998,155 4,036 20,072 3,022,263 
Total$3,563,409 $85,252 $69,570 $3,718,231 
2019    
Acquisition Costs of Properties    
Unproved (5)
$276,092 $— $— $276,092 
Proved (6)
379,938 — — 379,938 
Subtotal656,030 — — 656,030 
Exploration Costs213,505 46,616 13,218 273,339 
Development Costs (7)
5,661,753 25,007 12,096 5,698,856 
Total$6,531,288 $71,623 $25,314 $6,628,225 
2018    
Acquisition Costs of Properties    
Unproved (8)
$486,081 $1,258 $— $487,339 
Proved (9)
123,684 — — 123,684 
Subtotal609,765 1,258 — 611,023 
Exploration Costs157,222 22,511 13,895 193,628 
Development Costs (10)
5,605,264 (12,863)22,628 5,615,029 
Total$6,372,251 $10,906 $36,523 $6,419,680 
(1)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.
(2)Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges.
(3)Includes non-cash proved property acquisition costs of $15 million related to property exchanges.
(4)Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment.
(5)Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.
(6)Includes non-cash proved property acquisition costs of $52 million related to property exchanges.
(7)Includes Asset Retirement Costs of $181 million, $1 million and $4 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
(8)Includes non-cash unproved leasehold acquisition costs of $291 million related to property exchanges.
(9)Includes non-cash proved property acquisition costs of $71 million related to property exchanges.
(10)Includes Asset Retirement Costs of $90 million, $(12) million and $(8) million for the United States, Trinidad and Other International, respectively.  Excludes other property, plant and equipment.
Results of Operations for Oil and Gas Producing Activities (1). The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2020, 2019 and 2018:
United
States		Trinidad
Other
International (2)
Total
2020
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$7,055,098 $179,690 $55,468 $7,290,256 
Other60,989 (35)— 60,954 
Total
7,116,087 179,655 55,468 7,351,210 
Exploration Costs136,266 1,909 7,613 145,788 
Dry Hole Costs13,055 — 28 13,083 
Transportation Costs734,071 747 171 734,989 
Gathering and Processing Costs459,211 — — 459,211 
Production Costs1,479,976 26,964 10,407 1,517,347 
Impairments2,018,283 815 80,682 2,099,780 
Depreciation, Depletion and Amortization3,192,000 60,328 15,747 3,268,075 
Income (Loss) Before Income Taxes(916,775)88,892 (59,180)(887,063)
Income Tax Provision(220,437)23,526 3,428 (193,483)
Results of Operations$(696,338)$65,366 $(62,608)$(693,580)
2019    
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$11,250,853 $269,957 $60,635 $11,581,445 
Other134,325 18 15 134,358 
Total
11,385,178 269,975 60,650 11,715,803 
Exploration Costs130,302 4,290 5,289 139,881 
Dry Hole Costs11,133 13,033 3,835 28,001 
Transportation Costs753,558 4,014 728 758,300 
Gathering and Processing Costs479,102 — — 479,102 
Production Costs2,063,078 30,539 40,369 2,133,986 
Impairments510,948 5,713 1,235 517,896 
Depreciation, Depletion and Amortization3,560,609 79,156 17,832 3,657,597 
Income (Loss) Before Income Taxes3,876,448 133,230 (8,638)4,001,040 
Income Tax Provision884,450 54,980 3,152 942,582 
Results of Operations$2,991,998 $78,250 $(11,790)$3,058,458 
2018    
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$11,488,620 $302,112 $155,755 $11,946,487 
Other89,708 (49)(24)89,635 
Total
11,578,328 302,063 155,731 12,036,122 
Exploration Costs121,572 21,402 6,025 148,999 
Dry Hole Costs4,983 — 422 5,405 
Transportation Costs742,792 3,236 848 746,876 
Gathering and Processing Costs (3)
404,471 — 32,502 436,973 
Production Costs1,924,504 33,506 70,073 2,028,083 
Impairments344,595 — 2,426 347,021 
Depreciation, Depletion and Amortization3,181,801 91,788 46,687 3,320,276 
Income (Loss) Before Income Taxes4,853,610 152,131 (3,252)5,002,489 
Income Tax Provision1,086,077 12,170 1,898 1,100,145 
Results of Operations$3,767,533 $139,961 $(5,150)$3,902,344 
(1)Excludes gains or losses on the mark-to-market of financial commodity derivative contracts, gains or losses on sales of reserves and related assets, interest charges and general corporate expenses for each of the three years in the period ended December 31, 2020.
(2)Other International primarily consists of EOG's United Kingdom, China and Canada operations. EOG began an exploration program in Oman in the third quarter of 2020. The United Kingdom operations were sold in the fourth quarter of 2018.
(3)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 or net income resulting from changes to the presentation of natural gas processing fees (see Note 1 to Consolidated Financial Statements).
The following table sets forth production costs per barrel of oil equivalent, excluding severance/production and ad valorem taxes, for the years ended December 31, 2020, 2019 and 2018:
 United
States		Trinidad
Other
International (1)
Composite
Year Ended December 31, 2020$3.75 $2.33 $6.78 $3.72 
Year Ended December 31, 2019$4.59 $1.85 $18.26 $4.54 
Year Ended December 31, 2018$4.84 $1.67 $20.19 $4.84 
(1)    Other International primarily consists of EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves.  The following information has been developed utilizing procedures prescribed by the Extractive Industries - Oil and Gas Topic of the ASC and based on crude oil, NGL and natural gas reserves and production volumes estimated by the Engineering and Acquisitions Department of EOG.  The estimates were based on a 12-month average for commodity prices for the years 2020, 2019 and 2018.  The following information may be useful for certain comparative purposes, but should not be solely relied upon in evaluating EOG or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of EOG.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections.  It is expected that material revisions to some estimates of crude oil, NGL and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions.  Such decisions are based upon a wide range of factors, including estimates of probable and possible reserves as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the standardized measure of discounted future net cash flows from projected production of EOG's oil and gas reserves for the years ended December 31, 2020, 2019 and 2018:
 United
States		Trinidad
Other
International (1)
Total
2020
Future cash inflows (2)
$73,726,893 $900,815 $281,658 $74,909,366 
Future production costs(34,618,860)(153,275)(53,933)(34,826,068)
Future development costs(15,159,373)(226,430)(18,400)(15,404,203)
Future income taxes(4,336,578)(81,368)(24,311)(4,442,257)
Future net cash flows19,612,082 439,742 185,014 20,236,838 
Discount to present value at 10% annual rate(8,410,282)(100,350)(36,194)(8,546,826)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$11,201,800 $339,392 $148,820 $11,690,012 
2019    
Future cash inflows (3)
$120,359,769 $813,102 $305,491 $121,478,362 
Future production costs(42,387,801)(166,705)(87,381)(42,641,887)
Future development costs(20,355,746)(212,303)(18,400)(20,586,449)
Future income taxes(11,459,567)(73,508)(32,423)(11,565,498)
Future net cash flows46,156,655 360,586 167,287 46,684,528 
Discount to present value at 10% annual rate(21,042,593)(86,009)(35,161)(21,163,763)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$25,114,062 $274,577 $132,126 $25,520,765 
2018    
Future cash inflows (4)
$133,066,375 $749,695 $303,620 $134,119,690 
Future production costs(42,351,174)(204,444)(99,024)(42,654,642)
Future development costs(16,577,794)(78,199)(11,900)(16,667,893)
Future income taxes(14,756,011)(174,382)(31,748)(14,962,141)
Future net cash flows59,381,396 292,670 160,948 59,835,014 
Discount to present value at 10% annual rate(27,348,744)(26,832)(33,483)(27,409,059)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$32,032,652 $265,838 $127,465 $32,425,955 
(1)Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.
(2)Estimated crude oil prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $37.19, $26.75, and $41.87, respectively. Estimated NGL price used to calculate 2020 future cash inflows for the United States was $12.47. Estimated natural gas prices used to calculate 2020 future cash inflows for the United States, Trinidad and Other International were $1.45, $3.28, and $5.65, respectively.
(3)Estimated crude oil prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $57.51, $46.77 and $57.22, respectively. Estimated NGL price used to calculate 2019 future cash inflows for the United States was $16.91. Estimated natural gas prices used to calculate 2019 future cash inflows for the United States, Trinidad and Other International were $2.07, $2.90 and $5.01, respectively.
(4)Estimated crude oil prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $68.54, $55.66 and $61.66, respectively. Estimated NGL price used to calculate 2018 future cash inflows for the United States was $27.83. Estimated natural gas prices used to calculate 2018 future cash inflows for the United States, Trinidad and Other International were $2.50, $3.06 and $4.88, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows.  The following table sets forth the changes in the standardized measure of discounted future net cash flows at December 31, for each of the three years in the period ended December 31, 2020:
 United
States		Trinidad
Other
International (1)
Total
December 31, 2017$17,756,935 $332,427 $238,298 $18,327,660 
Sales and transfers of oil and gas produced, net of production costs
(8,416,853)(265,370)(52,399)(8,734,622)
Net changes in prices and production costs12,750,466 84,353 21,610 12,856,429 
Extensions, discoveries, additions and improved recovery, net of related costs
8,418,666 — 12,287 8,430,953 
Development costs incurred2,732,560 — 12,600 2,745,160 
Revisions of estimated development cost(410,741)4,030 (3,814)(410,525)
Revisions of previous quantity estimates(173,084)39,608 31,750 (101,726)
Accretion of discount1,967,592 50,191 24,839 2,042,622 
Net change in income taxes(4,965,373)3,844 (11,529)(4,973,058)
Purchases of reserves in place116,887 — — 116,887 
Sales of reserves in place(35,874)— (82,058)(117,932)
Changes in timing and other2,291,471 16,755 (64,119)2,244,107 
December 31, 201832,032,652 265,838 127,465 32,425,955 
Sales and transfers of oil and gas produced, net of production costs
(7,955,115)(235,404)(19,919)(8,210,438)
Net changes in prices and production costs(10,973,981)65,962 27,572 (10,880,447)
Extensions, discoveries, additions and improved recovery, net of related costs
5,608,038 85,233 16,287 5,709,558 
Development costs incurred3,003,510 22,820 5,820 3,032,150 
Revisions of estimated development cost(597,869)(129,047)(11,108)(738,024)
Revisions of previous quantity estimates(812,781)116,062 1,198 (695,521)
Accretion of discount3,891,701 43,148 14,909 3,949,758 
Net change in income taxes1,454,050 93,975 682 1,548,707 
Purchases of reserves in place98,539 — — 98,539 
Sales of reserves in place(50,651)— — (50,651)
Changes in timing and other(584,031)(54,010)(30,780)(668,821)
December 31, 201925,114,062 274,577 132,126 25,520,765 
Sales and transfers of oil and gas produced, net of production costs
(4,381,840)(151,979)(45,355)(4,579,174)
Net changes in prices and production costs(18,624,768)131,859 46,916 (18,445,993)
Extensions, discoveries, additions and improved recovery, net of related costs
1,436,988 64,385 — 1,501,373 
Development costs incurred1,674,800 — — 1,674,800 
Revisions of estimated development cost4,148,768 (11,161)— 4,137,607 
Revisions of previous quantity estimates(3,307,180)11,632 (1,764)(3,297,312)
Accretion of discount3,054,437 34,624 15,307 3,104,368 
Net change in income taxes3,497,362 (12,185)3,022 3,488,199 
Purchases of reserves in place49,232 — — 49,232 
Sales of reserves in place(156,293)— — (156,293)
Changes in timing and other(1,303,768)(2,360)(1,432)(1,307,560)
December 31, 2020$11,201,800 $339,392 $148,820 $11,690,012 
(1)    Other International includes EOG's United Kingdom, China and Canada operations. The United Kingdom operations were sold in the fourth quarter of 2018.