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Oil and Gas Exploration and Production Industries Disclosures (Notes)
 12 Months Ended
Dec. 31, 2021
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. 

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, 2021.  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, 2021, 2020 and 2019 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 18 professionals, all of whom hold, at a minimum, bachelor's degrees in engineering, and three 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 35 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, processing and applicable fractionation 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 Chief Executive Officer; the President and Chief Operating Officer; the Executive Vice Presidents, Exploration and Production; and the Executive Vice President and Chief Financial Officer, for approval.

Opinions by D&M for the years ended December 31, 2021, 2020 and 2019 covered producing areas containing 78%, 83% and 82%, 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 27, 2022, 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, 2021, 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, 2021, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2021, 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 (MMBbl) (2)
Net proved reserves at December 31, 20181,532 — — 1,532 
Revisions of previous estimates(43)— — (43)
Purchases in place3 — — 3 
Extensions, discoveries and other additions370 — — 370 
Sales in place(1)— — (1)
Production(167)— — (167)
Net proved reserves at December 31, 20191,694 — — 1,694 
Revisions of previous estimates(225)— — (225)
Purchases in place2 — — 2 
Extensions, discoveries and other additions194 1 — 195 
Sales in place(3)— — (3)
Production(149)— — (149)
Net proved reserves at December 31, 20201,513 1 — 1,514 
Revisions of previous estimates(116)— — (116)
Purchases in place2 — — 2 
Extensions, discoveries and other additions311 1 — 312 
Sales in place(2)— — (2)
Production(162)— — (162)
Net proved reserves at December 31, 20211,546 2 — 1,548 
Natural Gas Liquids (MMBbl) (2)
    
Net proved reserves at December 31, 2018614 — — 614 
Revisions of previous estimates5 — — 5 
Purchases in place2 — — 2 
Extensions, discoveries and other additions168 — — 168 
Sales in place(1)— — (1)
Production(48)— — (48)
Net proved reserves at December 31, 2019740 — — 740 
Revisions of previous estimates(60)— — (60)
Purchases in place4 — — 4 
Extensions, discoveries and other additions180 — — 180 
Sales in place(1)— — (1)
Production(50)— — (50)
Net proved reserves at December 31, 2020813 — — 813 
Revisions of previous estimates(128)— — (128)
Purchases in place3 — — 3 
Extensions, discoveries and other additions194 — — 194 
Sales in place— — — — 
Production(53)— — (53)
Net proved reserves at December 31, 2021829 — — 829 
 United
States		Trinidad
Other
International (1)
Total
Natural Gas (Bcf) (3)
Net proved reserves at December 31, 20184,391 237 59 4,687 
Revisions of previous estimates(184)47 3 (134)
Purchases in place72 — — 72 
Extensions, discoveries and other additions1,176 87 10 1,273 
Sales in place(15)— — (15)
Production(405)(95)(13)(513)
Net proved reserves at December 31, 20195,035 276 59 5,370 
Revisions of previous estimates(498)5 1 (492)
Purchases in place26 — — 26 
Extensions, discoveries and other additions1,078 54 — 1,132 
Sales in place(157)— — (157)
Production(441)(66)(12)(519)
Net proved reserves at December 31, 20205,043 269 48 5,360 
Revisions of previous estimates754 26 3 783 
Purchases in place23 — — 23 
Extensions, discoveries and other additions2,574 100 — 2,674 
Sales in place(4)— (48)(52)
Production(483)(80)(3)(566)
Net proved reserves at December 31, 20217,907 315 — 8,222 
Oil Equivalents (MMBoe) (2)
    
Net proved reserves at December 31, 20182,878 40 10 2,928 
Revisions of previous estimates(68)8 — (60)
Purchases in place17 — — 17 
Extensions, discoveries and other additions734 14 2 750 
Sales in place(5)— — (5)
Production(283)(16)(2)(301)
Net proved reserves at December 31, 20193,273 46 10 3,329 
Revisions of previous estimates(368)1 — (367)
Purchases in place10 — — 10 
Extensions, discoveries and other additions554 10 — 564 
Sales in place(31)— — (31)
Production(272)(11)(2)(285)
Net proved reserves at December 31, 20203,166 46 8 3,220 
Revisions of previous estimates(118)4 — (114)
Purchases in place9 — — 9 
Extensions, discoveries and other additions934 18 — 952 
Sales in place(3)— (8)(11)
Production(295)(14)— (309)
Net proved reserves at December 31, 20213,693 54 — 3,747 
(1)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.
(2)Million barrels or million 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 2021, EOG added 952 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 53% of the 2021 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 China assets and the sale or exchange of other producing assets. Revisions of previous estimates of negative 114 MMBoe for 2021 included an upward revision of 194 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2021, reserves estimation as compared to the prices used in the prior year estimate. The primary areas affected were the Permian Basin and the Rocky Mountain area. Revisions other than price of negative 308 MMBoe were primarily related to the removal from the five-year development plan of certain PUD locations. These locations were replaced with more economic locations in the Permian Basin and the Dorado gas play, and the related reserves from these locations were included as extensions, discoveries and other additions. Purchases in place of 9 MMBoe were primarily related to the Permian Basin and the purchase or exchange of other producing assets.

During 2020, EOG added 564 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 oil play 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 oil play 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.
 United
States		Trinidad
Other
International (1)
Total
NET PROVED DEVELOPED RESERVES
Crude Oil (MMBbl)
December 31, 2018713 — — 713 
December 31, 2019801 — — 801 
December 31, 2020792 1 — 793 
December 31, 2021886 — — 886 
Natural Gas Liquids (MMBbl)    
December 31, 2018341 — — 341 
December 31, 2019387 — — 387 
December 31, 2020392 — — 392 
December 31, 2021416 — — 416 
Natural Gas (Bcf)    
December 31, 20182,699 224 41 2,964 
December 31, 20192,974 178 42 3,194 
December 31, 20202,586 171 32 2,789 
December 31, 20213,743 131 — 3,874 
Oil Equivalents (MMBoe)    
December 31, 20181,503 38 7 1,548 
December 31, 20191,684 30 7 1,721 
December 31, 20201,614 30 5 1,649 
December 31, 20211,926 22 — 1,948 
NET PROVED UNDEVELOPED RESERVES    
Crude Oil (MMBbl)    
December 31, 2018819 — — 819 
December 31, 2019893 — — 893 
December 31, 2020721 — — 721 
December 31, 2021660 2 — 662 
Natural Gas Liquids (MMBbl)    
December 31, 2018273 — — 273 
December 31, 2019353 — — 353 
December 31, 2020421 — — 421 
December 31, 2021413 — — 413 
Natural Gas (Bcf)    
December 31, 20181,692 13 18 1,723 
December 31, 20192,061 98 17 2,176 
December 31, 20202,457 98 16 2,571 
December 31, 20214,164 184 — 4,348 
Oil Equivalents (MMBoe)    
December 31, 20181,375 2 3 1,380 
December 31, 20191,589 16 3 1,608 
December 31, 20201,552 16 3 1,571 
December 31, 20211,767 32 — 1,799 
(1)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.
Net Proved Undeveloped Reserves. The following table presents the changes in EOG's total PUDs during 2021, 2020 and 2019 (in MMBoe):
 202120202019
Balance at January 11,571 1,608 1,380 
Extensions and Discoveries
779 456 578 
Revisions
(305)(277)(50)
Acquisition of Reserves
— — 2 
Sale of Reserves
(3)(4)— 
Conversion to Proved Developed Reserves
(243)(212)(302)
Balance at December 311,799 1,571 1,608 

For the twelve-month period ended December 31, 2021, total PUDs increased by 228 MMBoe to 1,799 MMBoe.  EOG added approximately 40 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-39 and F-40 of this Annual Report on Form 10-K), EOG added 739 MMBoe of PUDs.  The PUD additions were primarily in the Permian Basin and 52% of the additions were crude oil and condensate and NGLs.  During 2021, EOG drilled and transferred 243 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,619 million. Revisions of previous estimates of negative 305 MMBoe of PUDs for 2021 included an upward price revision of 29 MMBoe due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2021, reserves estimation as compared to the prices used in the prior year estimate.  Revisions other than price of negative 334 MMBoe were primarily related to the removal from the five-year development plan of certain PUD locations. These locations were replaced with more economic locations in the Permian Basin and the Dorado gas play, and the related reserves from these locations were included as extensions and discoveries. 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, 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, 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 oil play and the Rocky Mountain area.

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 oil play 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. 
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, 2021 and 2020:
 20212020
Proved properties$64,876 $61,725 
Unproved properties2,768 3,068 
Total67,644 64,793 
Accumulated depreciation, depletion and amortization(41,907)(38,751)
Net capitalized costs$25,737 $26,042 

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, 2021, 2020 and 2019:
 United
States		Trinidad
Other
International (1)
Total
2021
Acquisition Costs of Properties
Unproved (2)
$207 $— $8 $215 
Proved (3)
100 — — 100 
Subtotal307 — 8 315 
Exploration Costs296 7 51 354 
Development Costs (4)
3,206 77 17 3,300 
Total$3,809 $84 $76 $3,969 
2020    
Acquisition Costs of Properties    
Unproved (5)
$265 $— $— $265 
Proved (6)
97 — 38 135 
Subtotal362 — 38 400 
Exploration Costs203 81 12 296 
Development Costs (7)
2,998 4 20 3,022 
Total$3,563 $85 $70 $3,718 
2019    
Acquisition Costs of Properties    
Unproved (8)
$276 $— $— $276 
Proved (9)
380 — — 380 
Subtotal656 — — 656 
Exploration Costs214 47 12 273 
Development Costs (10)
5,662 25 12 5,699 
Total$6,532 $72 $24 $6,628 
(1)Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.
(2)Includes non-cash unproved leasehold acquisition costs of $45 million related to property exchanges.
(3)Includes non-cash proved property acquisition costs of $5 million related to property exchanges.
(4)Includes Asset Retirement Costs of $86 million, $24 million and $17 million for the United States, Trinidad and Other International, respectively. Excludes other property, plant and equipment.
(5)Includes non-cash unproved leasehold acquisition costs of $197 million related to property exchanges.
(6)Includes non-cash proved property acquisition costs of $15 million related to property exchanges.
(7)Includes Asset Retirement Costs of $97 million and $20 million for the United States and Other International, respectively. Excludes other property, plant and equipment.
(8)Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.
(9)Includes non-cash proved property acquisition costs of $52 million related to property exchanges.
(10)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.
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, 2021, 2020 and 2019:
United
States		Trinidad
Other
International (2)
Total
2021
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$15,062 $301 $18 $15,381 
Other108 — — 108 
Total
15,170 301 18 15,489 
Exploration Costs137 5 12 154 
Dry Hole Costs29 — 42 71 
Transportation Costs863 — — 863 
Gathering and Processing Costs559 — — 559 
Production Costs2,108 39 8 2,155 
Impairments312 3 61 376 
Depreciation, Depletion and Amortization3,411 87 6 3,504 
Income (Loss) Before Income Taxes7,751 167 (111)7,807 
Income Tax Provision1,690 73 (1)1,762 
Results of Operations$6,061 $94 $(110)$6,045 
2020    
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$7,056 $180 $55 $7,291 
Other60 — — 60 
Total
7,116 180 55 7,351 
Exploration Costs136 2 8 146 
Dry Hole Costs13 — — 13 
Transportation Costs734 1 — 735 
Gathering and Processing Costs459 — — 459 
Production Costs1,480 27 10 1,517 
Impairments2,018 1 81 2,100 
Depreciation, Depletion and Amortization3,192 60 16 3,268 
Income (Loss) Before Income Taxes(916)89 (60)(887)
Income Tax Provision(220)24 3 (193)
Results of Operations$(696)$65 $(63)$(694)
2019    
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues
$11,251 $270 $61 $11,582 
Other134 — — 134 
Total
11,385 270 61 11,716 
Exploration Costs130 4 6 140 
Dry Hole Costs11 13 4 28 
Transportation Costs753 4 1 758 
Gathering and Processing Costs479 — — 479 
Production Costs2,063 31 40 2,134 
Impairments511 6 1 518 
Depreciation, Depletion and Amortization3,561 79 18 3,658 
Income (Loss) Before Income Taxes3,877 133 (9)4,001 
Income Tax Provision884 55 3 942 
Results of Operations$2,993 $78 $(12)$3,059 
(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, 2021.
(2)Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021. EOG began exploration programs in Australia in the third quarter of 2021 and in Oman in the third quarter of 2020. The decision was reached in the fourth quarter of 2021 to exit Block 36 and Block 49 in Oman.
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, 2021, 2020 and 2019:
 United
States		Trinidad
Other
International (1)
Composite
Year Ended December 31, 2021$3.71 $2.32 $16.13 $3.67 
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 
(1)    Other International primarily consists of EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.

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 2021, 2020 and 2019.  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, 2021, 2020 and 2019:
 United
States		Trinidad
Other
International (1)
Total
2021
Future cash inflows (2)
$166,316 $1,135 $— $167,451 
Future production costs(44,905)(258)— (45,163)
Future development costs(13,885)(380)— (14,265)
Future income taxes(22,831)(84)— (22,915)
Future net cash flows84,695 413 — 85,108 
Discount to present value at 10% annual rate(38,834)(88)— (38,922)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$45,861 $325 $— $46,186 
2020    
Future cash inflows (3)
$73,727 $901 $281 $74,909 
Future production costs(34,619)(153)(54)(34,826)
Future development costs(15,159)(227)(18)(15,404)
Future income taxes(4,337)(81)(24)(4,442)
Future net cash flows19,612 440 185 20,237 
Discount to present value at 10% annual rate(8,410)(101)(36)(8,547)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$11,202 $339 $149 $11,690 
2019    
Future cash inflows (4)
$120,360 $813 $305 $121,478 
Future production costs(42,387)(166)(88)(42,641)
Future development costs(20,356)(212)(18)(20,586)
Future income taxes(11,460)(74)(32)(11,566)
Future net cash flows46,157 361 167 46,685 
Discount to present value at 10% annual rate(21,043)(86)(35)(21,164)
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves
$25,114 $275 $132 $25,521 
(1)Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.
(2)Estimated crude oil prices used to calculate 2021 future cash inflows for the United States and Trinidad were $67.79 and $58.32, respectively. Estimated NGL price used to calculate 2021 future cash inflows for the United States was $30.28. Estimated natural gas prices used to calculate 2021 future cash inflows for the United States and Trinidad were $4.61 and $3.28, respectively.
(3)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.
(4)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.
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, 2021:
 United
States		Trinidad
Other
International (1)
Total
December 31, 2018$32,033 $266 $127 $32,426 
Sales and transfers of oil and gas produced, net of production costs
(7,955)(235)(20)(8,210)
Net changes in prices and production costs(10,974)66 28 (10,880)
Extensions, discoveries, additions and improved recovery, net of related costs
5,608 85 16 5,709 
Development costs incurred3,004 23 6 3,033 
Revisions of estimated development cost(599)(129)(11)(739)
Revisions of previous quantity estimates(813)116 1 (696)
Accretion of discount3,892 43 15 3,950 
Net change in income taxes1,454 94 1 1,549 
Purchases of reserves in place99 — — 99 
Sales of reserves in place(51)— — (51)
Changes in timing and other(584)(54)(31)(669)
December 31, 2019$25,114 $275 $132 $25,521 
Sales and transfers of oil and gas produced, net of production costs
(4,382)(152)(45)(4,579)
Net changes in prices and production costs(18,625)132 47 (18,446)
Extensions, discoveries, additions and improved recovery, net of related costs
1,437 64 — 1,501 
Development costs incurred1,675 — — 1,675 
Revisions of estimated development cost4,149 (11)— 4,138 
Revisions of previous quantity estimates(3,307)12 (2)(3,297)
Accretion of discount3,055 34 15 3,104 
Net change in income taxes3,497 (12)3 3,488 
Purchases of reserves in place49 — — 49 
Sales of reserves in place(156)— — (156)
Changes in timing and other(1,304)(3)(1)(1,308)
December 31, 2020$11,202 $339 $149 $11,690 
Sales and transfers of oil and gas produced, net of production costs
(11,532)(261)(16)(11,809)
Net changes in prices and production costs37,088 133 (1)37,220 
Extensions, discoveries, additions and improved recovery, net of related costs
12,154 71 — 12,225 
Development costs incurred1,619 16 — 1,635 
Revisions of estimated development cost2,773 (133)— 2,640 
Revisions of previous quantity estimates(1,789)73 — (1,716)
Accretion of discount1,313 42 17 1,372 
Net change in income taxes(9,914)27 17 (9,870)
Purchases of reserves in place151 — — 151 
Sales of reserves in place(19)— (151)(170)
Changes in timing and other2,815 18 (15)2,818 
December 31, 2021$45,861 $325 $— $46,186 
(1)    Other International includes EOG's China and Canada operations. The China operations were sold in the second quarter of 2021.