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Oil and Gas Exploration and Production Industries Disclosures (Notes) | 12 Months Ended
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Dec. 31, 2019
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 Estimates 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 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, 2019. 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 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, 2019, 2018 and 2017 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 33 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 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, 2019, 2018 and 2017 covered producing areas containing 82%, 79% 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 24, 2020, 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, 2019, 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, 2019, and the changes in the net proved reserves for each of the three years in the period ended December 31, 2019, 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, 2016 | 1,168,491 |  |  | 839 |  |  | 8,255 |  |  | 1,177,585 |
Revisions of previous estimates | 57,935 |  |  | 80 |  |  | (179 | ) |  | 57,836 |
Purchases in place | 1,111 |  |  | — |  |  | — |  |  | 1,111 |
Extensions, discoveries and other additions | 207,137 |  |  | 301 |  |  | 119 |  |  | 207,557 |
Sales in place | (8,393 | ) |  | — |  |  | — |  |  | (8,393 | )
Production | (122,210 | ) |  | (322 | ) |  | (191 | ) |  | (122,723 | )
Net proved reserves at December 31, 2017 | 1,304,071 |  |  | 898 |  |  | 8,004 |  |  | 1,312,973 |
Revisions of previous estimates | (13,237 | ) |  | (183 | ) |  | 44 |  |  | (13,376 | )
Purchases in place | 2,743 |  |  | — |  |  | — |  |  | 2,743 |
Extensions, discoveries and other additions | 383,003 |  |  | — |  |  | 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, 2018 | 1,531,684 |  |  | 417 |  |  | 211 |  |  | 1,532,312 |
Revisions of previous estimates | (42,959 | ) |  | 85 |  |  | (8 | ) |  | (42,882 | )
Purchases in place | 2,859 |  |  | — |  |  | — |  |  | 2,859 |
Extensions, discoveries and other additions | 369,968 |  |  | — |  |  | 28 |  |  | 369,996 |
Sales in place | (1,282 | ) |  | — |  |  | — |  |  | (1,282 | )
Production | (166,310 | ) |  | (236 | ) |  | (40 | ) |  | (166,586 | )
Net proved reserves at December 31, 2019 | 1,693,960 |  |  | 266 |  |  | 191 |  |  | 1,694,417 |
Natural Gas Liquids (MBbl) (2) |  |  |  |  |  |  |  |  |  |  |
Net proved reserves at December 31, 2016 | 416,366 |  |  | — |  |  | — |  |  | 416,366 |
Revisions of previous estimates | 46,843 |  |  | — |  |  | — |  |  | 46,843 |
Purchases in place | 421 |  |  | — |  |  | — |  |  | 421 |
Extensions, discoveries and other additions | 75,003 |  |  | — |  |  | — |  |  | 75,003 |
Sales in place | (2,887 | ) |  | — |  |  | — |  |  | (2,887 | )
Production | (32,273 | ) |  | — |  |  | — |  |  | (32,273 | )
Net proved reserves at December 31, 2017 | 503,473 |  |  | — |  |  | — |  |  | 503,473 |
Revisions of previous estimates | 23,942 |  |  | — |  |  | — |  |  | 23,942 |
Purchases in place | 2,006 |  |  | — |  |  | — |  |  | 2,006 |
Extensions, discoveries and other additions | 127,409 |  |  | — |  |  | — |  |  | 127,409 |
Sales in place | (41 | ) |  | — |  |  | — |  |  | (41 | )
Production | (42,460 | ) |  | — |  |  | — |  |  | (42,460 | )
Net proved reserves at December 31, 2018 | 614,329 |  |  | — |  |  | — |  |  | 614,329 |
Revisions of previous estimates | 5,380 |  |  | — |  |  | — |  |  | 5,380 |
Purchases in place | 1,948 |  |  | — |  |  | — |  |  | 1,948 |
Extensions, discoveries and other additions | 167,782 |  |  | — |  |  | — |  |  | 167,782 |
Sales in place | (855 | ) |  | — |  |  | — |  |  | (855 | )
Production | (48,892 | ) |  | — |  |  | — |  |  | (48,892 | )
Net proved reserves at December 31, 2019 | 739,692 |  |  | — |  |  | — |  |  | 739,692 |
| United States |  | Trinidad |  | Other International (1) |  | Total
Natural Gas (Bcf) (3) |  |  |  |  |  |  |
Net proved reserves at December 31, 2016 | 3,021.2 |  |  | 280.9 |  |  | 15.8 |  |  | 3,317.9 |
Revisions of previous estimates | 602.8 |  |  | (27.4 | ) |  | 8.6 |  |  | 584.0 |
Purchases in place | 4.8 |  |  | — |  |  | — |  |  | 4.8 |
Extensions, discoveries and other additions | 619.3 |  |  | 174.2 |  |  | 35.9 |  |  | 829.4 |
Sales in place | (56.4 | ) |  | — |  |  | — |  |  | (56.4 | )
Production | (293.2 | ) |  | (114.3 | ) |  | (9.1 | ) |  | (416.6 | )
Net proved reserves at December 31, 2017 | 3,898.5 |  |  | 313.4 |  |  | 51.2 |  |  | 4,263.1 |
Revisions of previous estimates | (127.2 | ) |  | 20.7 |  |  | 15.0 |  |  | (91.5 | )
Purchases in place | 41.3 |  |  | — |  |  | — |  |  | 41.3 |
Extensions, discoveries and other additions | 951.4 |  |  | — |  |  | 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, 2018 | 4,390.6 |  |  | 237.0 |  |  | 59.6 |  |  | 4,687.2 |
Revisions of previous estimates | (184.4 | ) |  | 47.0 |  |  | 2.6 |  |  | (134.8 | )
Purchases in place | 71.7 |  |  | — |  |  | — |  |  | 71.7 |
Extensions, discoveries and other additions | 1,175.9 |  |  | 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, 2019 | 5,034.8 |  |  | 276.1 |  |  | 58.8 |  |  | 5,369.7 |
Oil Equivalents (MBoe) (2) |  |  |  |  |  |  |  |  |  |  |
Net proved reserves at December 31, 2016 | 2,088,392 |  |  | 47,661 |  |  | 10,880 |  |  | 2,146,933 |
Revisions of previous estimates | 205,262 |  |  | (4,493 | ) |  | 1,249 |  |  | 202,018 |
Purchases in place | 2,332 |  |  | — |  |  | — |  |  | 2,332 |
Extensions, discoveries and other additions | 385,354 |  |  | 29,340 |  |  | 6,104 |  |  | 420,798 |
Sales in place | (20,687 | ) |  | — |  |  | — |  |  | (20,687 | )
Production | (203,351 | ) |  | (19,366 | ) |  | (1,707 | ) |  | (224,424 | )
Net proved reserves at December 31, 2017 | 2,457,302 |  |  | 53,142 |  |  | 16,526 |  |  | 2,526,970 |
Revisions of previous estimates | (10,500 | ) |  | 3,272 |  |  | 2,544 |  |  | (4,684 | )
Purchases in place | 11,640 |  |  | — |  |  | — |  |  | 11,640 |
Extensions, discoveries and other additions | 668,972 |  |  | — |  |  | 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, 2018 | 2,877,778 |  |  | 39,936 |  |  | 10,132 |  |  | 2,927,846 |
Revisions of previous estimates | (68,317 | ) |  | 7,915 |  |  | 431 |  |  | (59,971 | )
Purchases in place | 16,761 |  |  | — |  |  | — |  |  | 16,761 |
Extensions, discoveries and other additions | 733,730 |  |  | 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, 2019 | 3,272,778 |  |  | 46,298 |  |  | 9,992 |  |  | 3,329,068 |
(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 2019, EOG added 750 million barrels of oil equivalent (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. During 2017, EOG added 421 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 Trinidad. Approximately 67% of the 2017 reserve additions were crude oil and condensate and NGLs, and 92% were in the United States. Sales in place of 21 MMBoe were primarily related to the sale or exchange of certain producing assets. Revisions of previous estimates of 202 MMBoe for 2017 included an upward revision of 154 MMBoe primarily due to increases in the average crude oil, NGLs and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate. The primary plays affected were in the Rocky Mountain area, the Eagle Ford and the Permian Basin. Positive revisions other than price of 48 MMBoe resulted primarily from improved well performance in the Permian Basin and lower production costs. Purchases in place of 2 MMBoe were primarily related to the Permian Basin.
| United States |  | Trinidad |  | Other International (1) |  | Total
NET PROVED DEVELOPED RESERVES |  |  |  |  |  |  |
Crude Oil (MBbl) |  |  |  |  |  |  |
December 31, 2016 | 507,531 |  |  | 839 |  |  | 8,255 |  |  | 516,625 |
December 31, 2017 | 605,405 |  |  | 898 |  |  | 7,933 |  |  | 614,236 |
December 31, 2018 | 712,218 |  |  | 417 |  |  | 150 |  |  | 712,785 |
December 31, 2019 | 801,189 |  |  | 266 |  |  | 143 |  |  | 801,598 |
Natural Gas Liquids (MBbl) |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 | 230,219 |  |  | — |  |  | — |  |  | 230,219 |
December 31, 2017 | 286,872 |  |  | — |  |  | — |  |  | 286,872 |
December 31, 2018 | 341,386 |  |  | — |  |  | — |  |  | 341,386 |
December 31, 2019 | 387,253 |  |  | — |  |  | — |  |  | 387,253 |
Natural Gas (Bcf) |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 | 1,804.4 |  |  | 262.2 |  |  | 15.8 |  |  | 2,082.4 |
December 31, 2017 | 2,450.8 |  |  | 299.2 |  |  | 29.3 |  |  | 2,779.3 |
December 31, 2018 | 2,699.0 |  |  | 223.9 |  |  | 40.9 |  |  | 2,963.8 |
December 31, 2019 | 2,974.6 |  |  | 177.7 |  |  | 41.8 |  |  | 3,194.1 |
Oil Equivalents (MBoe) |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 | 1,038,483 |  |  | 44,543 |  |  | 10,880 |  |  | 1,093,906 |
December 31, 2017 | 1,300,758 |  |  | 50,779 |  |  | 12,798 |  |  | 1,364,335 |
December 31, 2018 | 1,503,441 |  |  | 37,746 |  |  | 6,950 |  |  | 1,548,137 |
December 31, 2019 | 1,684,209 |  |  | 29,886 |  |  | 7,117 |  |  | 1,721,212 |
NET PROVED UNDEVELOPED RESERVES |  |  |  |  |  |  |  |  |  |  |
Crude Oil (MBbl) |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 | 660,690 |  |  | — |  |  | — |  |  | 660,690 |
December 31, 2017 | 698,666 |  |  | — |  |  | 71 |  |  | 698,737 |
December 31, 2018 | 819,466 |  |  | — |  |  | 61 |  |  | 819,527 |
December 31, 2019 | 892,771 |  |  | — |  |  | 48 |  |  | 892,819 |
Natural Gas Liquids (MBbl) |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 | 186,147 |  |  | — |  |  | — |  |  | 186,147 |
December 31, 2017 | 216,601 |  |  | — |  |  | — |  |  | 216,601 |
December 31, 2018 | 272,943 |  |  | — |  |  | — |  |  | 272,943 |
December 31, 2019 | 352,439 |  |  | — |  |  | — |  |  | 352,439 |
Natural Gas (Bcf) |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 | 1,216.8 |  |  | 18.7 |  |  | — |  |  | 1,235.5 |
December 31, 2017 | 1,447.7 |  |  | 14.2 |  |  | 21.9 |  |  | 1,483.8 |
December 31, 2018 | 1,691.6 |  |  | 13.1 |  |  | 18.7 |  |  | 1,723.4 |
December 31, 2019 | 2,060.2 |  |  | 98.4 |  |  | 17.0 |  |  | 2,175.6 |
Oil Equivalents (MBoe) |  |  |  |  |  |  |  |  |  |  |
December 31, 2016 | 1,049,909 |  |  | 3,118 |  |  | — |  |  | 1,053,027 |
December 31, 2017 | 1,156,544 |  |  | 2,363 |  |  | 3,728 |  |  | 1,162,635 |
December 31, 2018 | 1,374,337 |  |  | 2,190 |  |  | 3,182 |  |  | 1,379,709 |
December 31, 2019 | 1,588,569 |  |  | 16,412 |  |  | 2,875 |  |  | 1,607,856 |
(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 proved undeveloped reserves during 2019, 2018 and 2017 (in MBoe):
| 2019 |  | 2018 |  | 2017
Balance at January 1 | 1,379,709 |  |  | 1,162,635 |  |  | 1,053,027 |
Extensions and Discoveries | 578,317 |  |  | 490,725 |  |  | 237,378 |
Revisions | (49,837 | ) |  | (8,244 | ) |  | 33,127 |
Acquisition of Reserves | 1,711 |  |  | 311 |  |  | — |
Sale of Reserves | — |  |  | — |  |  | (8,253 | )
Conversion to Proved Developed Reserves | (302,044 | ) |  | (265,718 | ) |  | (152,644 | )
Balance at December 31 | 1,607,856 |  |  | 1,379,709 |  |  | 1,162,635 |
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 (see discussion of technology employed on pages F-39 and F-40 of this Annual Report on Form 10-K), 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. 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, 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. For the twelve-month period ended December 31, 2017, total PUDs increased by 110 MMBoe to 1,163 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 199 MMBoe. The PUD additions were primarily in the Permian Basin and, to a lesser extent, the Eagle Ford and the Rocky Mountain area, and 74% of the additions were crude oil and condensate and NGLs. During 2017, EOG drilled and transferred 153 MMBoe of PUDs to proved developed reserves at a total capital cost of $1,440 million. Revisions of PUDs totaled positive 33 MMBoe, primarily due to updated type curves resulting from improved performance of offsetting wells in the Permian Basin, the impact of increases in the average crude oil and natural gas prices used in the December 31, 2017, reserves estimation as compared to the prices used in the prior year estimate, and lower costs. During 2017, EOG sold or exchanged 8 MMBoe of PUDs primarily in the Permian Basin. 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, 2019 and 2018:
| 2019 |  | 2018
Proved properties | $ | 59,229,686 |  |  | $ | 53,624,809 |
Unproved properties | 3,600,729 |  |  | 3,705,207 |
Total | 62,830,415 |  |  | 57,330,016 |
Accumulated depreciation, depletion and amortization | (35,033,085 | ) |  | (31,674,085 | )
Net capitalized costs | $ | 27,797,330 |  |  | $ | 25,655,931 |
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, 2019, 2018 and 2017:
| United States |  | Trinidad |  | Other International (1) |  | Total
2019 |  |  |  |  |  |  |
Acquisition Costs of Properties |  |  |  |  |  |  |
Unproved (2) | $ | 276,092 |  |  | $ | — |  |  | $ | — |  |  | $ | 276,092 |
Proved (3) | 379,938 |  |  | — |  |  | — |  |  | 379,938 |
Subtotal | 656,030 |  |  | — |  |  | — |  |  | 656,030 |
Exploration Costs | 213,505 |  |  | 46,616 |  |  | 13,218 |  |  | 273,339 |
Development Costs (4) | 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 (5) | $ | 486,081 |  |  | $ | 1,258 |  |  | $ | — |  |  | $ | 487,339 |
Proved (6) | 123,684 |  |  | — |  |  | — |  |  | 123,684 |
Subtotal | 609,765 |  |  | 1,258 |  |  | — |  |  | 611,023 |
Exploration Costs | 157,222 |  |  | 22,511 |  |  | 13,895 |  |  | 193,628 |
Development Costs (7) | 5,605,264 |  |  | (12,863 | ) |  | 22,628 |  |  | 5,615,029 |
Total | $ | 6,372,251 |  |  | $ | 10,906 |  |  | $ | 36,523 |  |  | $ | 6,419,680 |
2017 |  |  |  |  |  |  |  |  |  |  |
Acquisition Costs of Properties |  |  |  |  |  |  |  |  |  |  |
Unproved (8) | $ | 424,118 |  |  | $ | 2,422 |  |  | $ | — |  |  | $ | 426,540 |
Proved (9) | 72,584 |  |  | — |  |  | — |  |  | 72,584 |
Subtotal | 496,702 |  |  | 2,422 |  |  | — |  |  | 499,124 |
Exploration Costs | 144,499 |  |  | 62,547 |  |  | 16,553 |  |  | 223,599 |
Development Costs (10) | 3,590,899 |  |  | 109,491 |  |  | 16,297 |  |  | 3,716,687 |
Total | $ | 4,232,100 |  |  | $ | 174,460 |  |  | $ | 32,850 |  |  | $ | 4,439,410 |
(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.
(2) | Includes non-cash unproved leasehold acquisition costs of $98 million related to property exchanges.
(3) | Includes non-cash proved property acquisition costs of $52 million related to property exchanges.
(4) | 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.
(5) | Includes non-cash unproved leasehold acquisition costs of $291 million related to property exchanges.
(6) | Includes non-cash proved property acquisition costs of $71 million related to property exchanges.
(7) | 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.
(8) | Includes non-cash unproved leasehold acquisition costs of $256 million related to property exchanges.
(9) | Includes non-cash proved property acquisition costs of $26 million related to property exchanges.
(10) | Includes Asset Retirement Costs of $50 million, $2 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, 2019, 2018 and 2017:
| United States |  | Trinidad |  | Other International (2) |  | Total
2019 |  |  |  |  |  |  |
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | $ | 11,250,853 |  |  | $ | 269,957 |  |  | $ | 60,635 |  |  | $ | 11,581,445 |
Other | 134,325 |  |  | 18 |  |  | 15 |  |  | 134,358 |
Total | 11,385,178 |  |  | 269,975 |  |  | 60,650 |  |  | 11,715,803 |
Exploration Costs | 130,302 |  |  | 4,290 |  |  | 5,289 |  |  | 139,881 |
Dry Hole Costs | 11,133 |  |  | 13,033 |  |  | 3,835 |  |  | 28,001 |
Transportation Costs | 753,558 |  |  | 4,014 |  |  | 728 |  |  | 758,300 |
Gathering and Processing Costs | 479,102 |  |  | — |  |  | — |  |  | 479,102 |
Production Costs | 2,063,078 |  |  | 30,539 |  |  | 40,369 |  |  | 2,133,986 |
Impairments | 510,948 |  |  | 5,713 |  |  | 1,235 |  |  | 517,896 |
Depreciation, Depletion and Amortization | 3,560,609 |  |  | 79,156 |  |  | 17,832 |  |  | 3,657,597 |
Income (Loss) Before Income Taxes | 3,876,448 |  |  | 133,230 |  |  | (8,638 | ) |  | 4,001,040 |
Income Tax Provision | 884,450 |  |  | 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 |
Other | 89,708 |  |  | (49 | ) |  | (24 | ) |  | 89,635 |
Total | 11,578,328 |  |  | 302,063 |  |  | 155,731 |  |  | 12,036,122 |
Exploration Costs | 121,572 |  |  | 21,402 |  |  | 6,025 |  |  | 148,999 |
Dry Hole Costs | 4,983 |  |  | — |  |  | 422 |  |  | 5,405 |
Transportation Costs | 742,792 |  |  | 3,236 |  |  | 848 |  |  | 746,876 |
Gathering and Processing Costs (3) | 404,471 |  |  | — |  |  | 32,502 |  |  | 436,973 |
Production Costs | 1,924,504 |  |  | 33,506 |  |  | 70,073 |  |  | 2,028,083 |
Impairments | 344,595 |  |  | — |  |  | 2,426 |  |  | 347,021 |
Depreciation, Depletion and Amortization | 3,181,801 |  |  | 91,788 |  |  | 46,687 |  |  | 3,320,276 |
Income (Loss) Before Income Taxes | 4,853,610 |  |  | 152,131 |  |  | (3,252 | ) |  | 5,002,489 |
Income Tax Provision | 1,086,077 |  |  | 12,170 |  |  | 1,898 |  |  | 1,100,145 |
Results of Operations | $ | 3,767,533 |  |  | $ | 139,961 |  |  | $ | (5,150 | ) |  | $ | 3,902,344 |
2017 |  |  |  |  |  |  |  |  |  |  |
Crude Oil and Condensate, Natural Gas Liquids and Natural Gas Revenues | $ | 7,570,768 |  |  | $ | 284,673 |  |  | $ | 52,450 |  |  | $ | 7,907,891 |
Other | 81,610 |  |  | 59 |  |  | (59 | ) |  | 81,610 |
Total | 7,652,378 |  |  | 284,732 |  |  | 52,391 |  |  | 7,989,501 |
Exploration Costs | 113,334 |  |  | 26,245 |  |  | 5,763 |  |  | 145,342 |
Dry Hole Costs | 91 |  |  | — |  |  | 4,518 |  |  | 4,609 |
Transportation Costs | 737,403 |  |  | 1,885 |  |  | 1,064 |  |  | 740,352 |
Production Costs | 1,446,333 |  |  | 27,839 |  |  | 88,038 |  |  | 1,562,210 |
Impairments | 477,223 |  |  | — |  |  | 2,017 |  |  | 479,240 |
Depreciation, Depletion and Amortization | 3,157,056 |  |  | 115,174 |  |  | 24,536 |  |  | 3,296,766 |
Income (Loss) Before Income Taxes | 1,720,938 |  |  | 113,589 |  |  | (73,545 | ) |  | 1,760,982 |
Income Tax Provision (Benefit) | 625,562 |  |  | 24,882 |  |  | (1,342 | ) |  | 649,102 |
Results of Operations | $ | 1,095,376 |  |  | $ | 88,707 |  |  | $ | (72,203 | ) |  | $ | 1,111,880 |
(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, 2019.
(2) | 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.
(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, 2019, 2018 and 2017:
| United States |  | Trinidad |  | Other International (1) |  | Composite
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 |
Year Ended December 31, 2017 | $ | 4.58 |  |  | $ | 1.39 |  |  | $ | 50.86 |  |  | $ | 4.66 |
(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 2019, 2018 and 2017. 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, 2019, 2018 and 2017:
| United States |  | Trinidad |  | Other International (1) |  | Total
2019 |  |  |  |  |  |  |
Future cash inflows (2) | $ | 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 flows | 46,156,655 |  |  | 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 (3) | $ | 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 flows | 59,381,396 |  |  | 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 |
2017 |  |  |  |  |  |  |  |  |  |  |
Future cash inflows (4) | $ | 83,652,363 |  |  | $ | 904,141 |  |  | $ | 664,560 |  |  | $ | 85,221,064 |
Future production costs | (32,018,812 | ) |  | (239,213 | ) |  | (311,383 | ) |  | (32,569,408 | )
Future development costs | (13,395,873 | ) |  | (84,379 | ) |  | (58,543 | ) |  | (13,538,795 | )
Future income taxes | (5,948,453 | ) |  | (195,855 | ) |  | (16,233 | ) |  | (6,160,541 | )
Future net cash flows | 32,289,225 |  |  | 384,694 |  |  | 278,401 |  |  | 32,952,320 |
Discount to present value at 10% annual rate | (14,532,290 | ) |  | (52,267 | ) |  | (40,103 | ) |  | (14,624,660 | )
Standardized measure of discounted future net cash flows relating to proved oil and gas reserves | $ | 17,756,935 |  |  | $ | 332,427 |  |  | $ | 238,298 |  |  | $ | 18,327,660 |
(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 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.
(3) | 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.
(4) | Estimated crude oil prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $49.21, $41.87 and $50.06, respectively. Estimated NGL price used to calculate 2017 future cash inflows for the United States was $23.51. Estimated natural gas prices used to calculate 2017 future cash inflows for the United States, Trinidad and Other International were $1.96, $2.76 and $5.16, 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, 2019:
| United States |  | Trinidad |  | Other International (1) |  | Total
December 31, 2016 | $ | 8,493,727 |  |  | $ | 185,750 |  |  | $ | 132,680 |  |  | $ | 8,812,157 |
Sales and transfers of oil and gas produced, net of production costs | (5,387,031 | ) |  | (254,948 | ) |  | 36,649 |  |  | (5,605,330 | )
Net changes in prices and production costs | 6,606,908 |  |  | 436,969 |  |  | 77,668 |  |  | 7,121,545 |
Extensions, discoveries, additions and improved recovery, net of related costs | 3,644,041 |  |  | 270,255 |  |  | 43,952 |  |  | 3,958,248 |
Development costs incurred | 1,435,600 |  |  | 4,700 |  |  | — |  |  | 1,440,300 |
Revisions of estimated development cost | (114,464 | ) |  | 9,683 |  |  | (20,096 | ) |  | (124,877 | )
Revisions of previous quantity estimates | 2,460,498 |  |  | (58,373 | ) |  | 36,146 |  |  | 2,438,271 |
Accretion of discount | 849,373 |  |  | 24,066 |  |  | 13,268 |  |  | 886,707 |
Net change in income taxes | (1,918,989 | ) |  | (114,575 | ) |  | (10,099 | ) |  | (2,043,663 | )
Purchases of reserves in place | 30,362 |  |  | — |  |  | — |  |  | 30,362 |
Sales of reserves in place | (76,527 | ) |  | — |  |  | — |  |  | (76,527 | )
Changes in timing and other | 1,733,437 |  |  | (171,100 | ) |  | (71,870 | ) |  | 1,490,467 |
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 costs | 12,750,466 |  |  | 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 incurred | 2,732,560 |  |  | — |  |  | 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 discount | 1,967,592 |  |  | 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 place | 116,887 |  |  | — |  |  | — |  |  | 116,887 |
Sales of reserves in place | (35,874 | ) |  | — |  |  | (82,058 | ) |  | (117,932 | )
Changes in timing and other | 2,291,471 |  |  | 16,755 |  |  | (64,119 | ) |  | 2,244,107 |
December 31, 2018 | 32,032,652 |  |  | 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 incurred | 3,003,510 |  |  | 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 discount | 3,891,701 |  |  | 43,148 |  |  | 14,909 |  |  | 3,949,758 |
Net change in income taxes | 1,454,050 |  |  | 93,975 |  |  | 682 |  |  | 1,548,707 |
Purchases of reserves in place | 98,539 |  |  | — |  |  | — |  |  | 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, 2019 | $ | 25,114,062 |  |  | $ | 274,577 |  |  | $ | 132,126 |  |  | $ | 25,520,765 |
(1) 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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