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Supplemental Information on Oil and Gas Producing Activities (Unaudited) | 12 Months Ended
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Dec. 31, 2019
Text block [abstract] |
Supplemental Information on Oil and Gas Producing Activities (Unaudited) |
39. | SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following information is presented in accordance with ASC No. 932 “Extractive Activities – Oil and Gas”, as amended by ASU 2010 – 03 “Oil and Gas Reserves. Estimation and Disclosures , ” issued by FASB in January 2010. Oil and gas reserves Proved oil and gas reserves are those quantities of oil and 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, and under existing economic conditions, operating methods and government regulations) prior to 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within reasonable time. In some cases, substantial investments in new wells and related facilities may be required to recover proved reserves. Information on net proved reserves as of December 31, 2019, 2018 and 2017 was calculated in accordance with the SEC rules and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 932, as amended. Accordingly, crude oil prices used to determine reserves were calculated each month for crude oils of different quality produced by the Company. Consequently, to calculate our net proved reserves as of December 31, 2019, the Company considered the realized prices for crude oil in the domestic market taking into account the effect of export taxes as in effect as of each of the corresponding years (until 2021, in accordance with Law 27,541). For the years beyond the mentioned periods, the Company considered the unweighted average price of the first-day-of-the-month for each month within the twelve-month period ended December 31, 2019, which refers to the Brent prices adjusted by each different quality produced by the Company. Additionally, since there are no benchmark market natural gas prices available in Argentina, the Company considered the domestic market realized prices 12 months average, according to the SEC rules and FASB’s ASC 932 rules. Notwithstanding the foregoing, commodity prices have fluctuated significantly since 201 6 . See “Item 3. Key Information—Risk Factors—Risks Relating to the Argentine Oil and Gas Business and Our Business—Our oil and natural gas reserves are estimates” and “Item 3. Key Information—Risk Factors—Risks Relating to the Argentine Oil and Gas Business and Our Business—Our reserves and production are likely to decline . ” Net reserves are defined as that portion of the gross reserves attributable to the interest of YPF after deducting interests owned by third parties. In determining net reserves, the Group excludes from its reported reserves royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and is able to make lifting and sales arrangements independently. By contrast, to the extent that royalty payments required to be made to a third party, whether payable in cash or in kind, are a financial obligation, or are substantially equivalent to a production or severance tax, the related reserves are not excluded from the reported reserves despite the fact that such payments are referred to as “royalties” under local rules. The same methodology is followed in reporting our production amounts. Gas reserves exclude the gaseous equivalent of liquids expected to be removed from the gas on concessions and leases, at field facilities and at gas processing plants. These liquids are included in net proved reserves of natural gas liquids. Technology used in establishing proved reserves additions in 2019 YPF’s estimated proved reserves are based on estimates generated through the integration of available and appropriate data, utilizing well-established technologies that have been demonstrated in the field to yield repeatable and consistent results. Data used in these integrated assessments include information obtained directly from the subsurface via wellbore, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also include subsurface information obtained through indirect measurements, including high quality 2-D and 3-D-seismic data, calibrated with available well control. Where applicable, geological outcrops information was also utilized. The tools used to interpret and integrate all these data included both proprietary and commercial software for reservoir modeling, simulation and data analysis. In some circumstances, where appropriate analog reservoir models are available, reservoir parameters from these analog models were used to increase the reliability of our reserves estimates. . Changes in YPF’s Estimated Net Proved Reserves The table below sets forth information regarding changes in YPF’s net proved reserves during 2019, 2018 and 2017, by hydrocarbon product.
|  | 2019 |  |  | 2018 |  |  | 2017 |
Oil and Condensate |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |
|  | (Millions of barrels) |
Consolidated entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At January 1, |  |  | 582 |  |  |  | 582 |  |  |  | — |  |  |  | 422 |  |  |  | 422 |  |  |  | — |  |  |  | 525 |  |  |  | 525 |  |  |  | — |
Developed |  |  | 339 |  |  |  | 339 |  |  |  | — |  |  |  | 286 |  |  |  | 286 |  |  |  | — |  |  |  | 380 |  |  |  | 380 |  |  |  | — |
Undeveloped |  |  | 243 |  |  |  | 243 |  |  |  | — |  |  |  | 136 |  |  |  | 136 |  |  |  | — |  |  |  | 145 |  |  |  | 145 |  |  |  | — |
Revisions of previous estimates (1) |  |  | 21 |  |  |  | 21 |  |  |  | * |  |  |  | 126 |  |  |  | 126 |  |  |  | — |  |  |  | (72 | ) |  |  | (72 | ) |  |  | — |
Extensions and discoveries |  |  | 86 |  |  |  | 86 |  |  |  | — |  |  |  | 103 |  |  |  | 103 |  |  |  | — |  |  |  | 19 |  |  |  | 19 |  |  |  | — |
Improved recovery |  |  | 8 |  |  |  | 8 |  |  |  | — |  |  |  | 15 |  |  |  | 15 |  |  |  | — |  |  |  | 33 |  |  |  | 33 |  |  |  | — |
Purchase of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Sale of minerals in place |  |  | (1 | ) |  |  | (1 | ) |  |  | — |  |  |  | (1 | ) |  |  | (1 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Production for the year (2) |  |  | (83 | ) |  |  | (83 | ) |  |  | * |  |  |  | (83 | ) |  |  | (83 | ) |  |  | — |  |  |  | (83 | ) |  |  | (83 | ) |  |  | — |
At December 31, (3) |  |  | 613 |  |  |  | 613 |  |  |  | — |  |  |  | 582 |  |  |  | 582 |  |  |  | — |  |  |  | 422 |  |  |  | 422 |  |  |  | — |
Developed |  |  | 301 |  |  |  | 301 |  |  |  | — |  |  |  | 339 |  |  |  | 339 |  |  |  | — |  |  |  | 286 |  |  |  | 286 |  |  |  | — |
Undeveloped |  |  | 312 |  |  |  | 312 |  |  |  | — |  |  |  | 243 |  |  |  | 243 |  |  |  | — |  |  |  | 136 |  |  |  | 136 |  |  |  | — |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At January 1, |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Developed |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Undeveloped |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Revisions of previous estimates (1) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Extensions and discoveries |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Improved recovery |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Purchase of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Sale of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Production for the year (2) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
At December 31, (3) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Developed |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Undeveloped |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Consolidated and Equity-accounted entities |  |  |  |
At January 1, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed |  |  | 339 |  |  |  | 339 |  |  |  | — |  |  |  | 286 |  |  |  | 286 |  |  |  | — |  |  |  | 380 |  |  |  | 380 |  |  |  | — |
Undeveloped |  |  | 243 |  |  |  | 243 |  |  |  | — |  |  |  | 136 |  |  |  | 136 |  |  |  | — |  |  |  | 145 |  |  |  | 145 |  |  |  | — |
Total |  |  | 582 |  |  |  | 582 |  |  |  | — |  |  |  | 422 |  |  |  | 422 |  |  |  | — |  |  |  | 525 |  |  |  | 525 |  |  |  | — |
At December 31, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed |  |  | 301 |  |  |  | 301 |  |  |  | — |  |  |  | 339 |  |  |  | 339 |  |  |  | — |  |  |  | 286 |  |  |  | 286 |  |  |  | — |
Undeveloped |  |  | 312 |  |  |  | 312 |  |  |  | — |  |  |  | 243 |  |  |  | 243 |  |  |  | — |  |  |  | 136 |  |  |  | 136 |  |  |  | — |
Total |  |  | 613 |  |  |  | 613 |  |  |  | — |  |  |  | 582 |  |  |  | 582 |  |  |  | — |  |  |  | 422 |  |  |  | 422 |  |  |  | — |
* | Not material (less than 1).
(1) | Revisions in estimates of reserves are performed at least once a year. Revisions of oil and gas reserves is considered prospectively in the calculation of depreciation.
(2) | Crude oil production for the years 2019, 2018 and 2017 includes an estimated approximately 12, 12 and 12 mmbbl, respectively, in respect of royalty payments which are a financial obligation or are substantially equivalent to a production or similar tax.
(3) | Proved crude oil reserves of consolidated entities as of December 31, 2019, 2018 and 2017 include an estimated approximately 88, 83 and 61 mmbbl, respectively, in respect of royalty payments which, as described above, are a financial obligation , or are substantially equivalent to a production or similar tax.
|  | 2019 |  |  | 2018 |  |  | 2017 |
Natural Gas Liquids |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |
|  | (Millions of barrels) |
Consolidated entities |  |  |  |
At January 1, |  |  | 56 |  |  |  | 56 |  |  |  | — |  |  |  | 58 |  |  |  | 58 |  |  |  | — |  |  |  | 68 |  |  |  | 68 |  |  |  | — |
Developed |  |  | 41 |  |  |  | 41 |  |  |  | — |  |  |  | 47 |  |  |  | 47 |  |  |  | — |  |  |  | 53 |  |  |  | 53 |  |  |  | — |
Undeveloped |  |  | 15 |  |  |  | 15 |  |  |  | — |  |  |  | 11 |  |  |  | 11 |  |  |  | — |  |  |  | 15 |  |  |  | 15 |  |  |  | — |
Revisions of previous estimates (1) |  |  | 4 |  |  |  | 4 |  |  |  | — |  |  |  | (1 | ) |  |  | (1 | ) |  |  | — |  |  |  | 4 |  |  |  | 4 |  |  |  | — |
Extensions and discoveries |  |  | 14 |  |  |  | 14 |  |  |  | — |  |  |  | 13 |  |  |  | 13 |  |  |  | — |  |  |  | 5 |  |  |  | 5 |  |  |  | — |
Improved recovery |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Purchase of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Sale of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Production for the year (2) |  |  | (14 | ) |  |  | (14 | ) |  |  | — |  |  |  | (14 | ) |  |  | (14 | ) |  |  | — |  |  |  | (19 | ) |  |  | (19 | ) |  |  | — |
At December 31, (3) |  |  | 60 |  |  |  | 60 |  |  |  | — |  |  |  | 56 |  |  |  | 56 |  |  |  | — |  |  |  | 58 |  |  |  | 58 |  |  |  | — |
Developed |  |  | 38 |  |  |  | 38 |  |  |  | — |  |  |  | 41 |  |  |  | 41 |  |  |  | — |  |  |  | 47 |  |  |  | 47 |  |  |  | — |
Undeveloped |  |  | 22 |  |  |  | 22 |  |  |  | — |  |  |  | 15 |  |  |  | 15 |  |  |  | — |  |  |  | 11 |  |  |  | 11 |  |  |  | — |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At January 1, |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Developed |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Undeveloped |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Revisions of previous estimates (1) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Extensions and discoveries |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Improved recovery |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Purchase of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Sale of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Production for the year (2) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
At December 31, (3) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Developed |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Undeveloped |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Consolidated and Equity-accounted entities |  |  |  |
At January 1, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed |  |  | 41 |  |  |  | 41 |  |  |  | — |  |  |  | 47 |  |  |  | 47 |  |  |  | — |  |  |  | 53 |  |  |  | 53 |  |  |  | — |
Undeveloped |  |  | 15 |  |  |  | 15 |  |  |  | — |  |  |  | 11 |  |  |  | 11 |  |  |  | — |  |  |  | 15 |  |  |  | 15 |  |  |  | — |
Total |  |  | 56 |  |  |  | 56 |  |  |  | — |  |  |  | 58 |  |  |  | 58 |  |  |  | — |  |  |  | 68 |  |  |  | 68 |  |  |  | — |
At December 31, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed |  |  | 38 |  |  |  | 38 |  |  |  | — |  |  |  | 41 |  |  |  | 41 |  |  |  | — |  |  |  | 47 |  |  |  | 47 |  |  |  | — |
Undeveloped |  |  | 22 |  |  |  | 22 |  |  |  | — |  |  |  | 15 |  |  |  | 15 |  |  |  | — |  |  |  | 11 |  |  |  | 11 |  |  |  | — |
Total |  |  | 60 |  |  |  | 60 |  |  |  | — |  |  |  | 56 |  |  |  | 56 |  |  |  | — |  |  |  | 58 |  |  |  | 58 |  |  |  | — |
* | Not material (less than 1).
(1) | Revisions in estimates of reserves are performed at least once a year. Revision of oil and gas reserves is considered prospectively in the calculation of depreciation.
(2) | Natural gas liquids production for the years 2019, 2018 and 2017 includes an estimated approximately 1, 2 and 2 mmbbl, respectively, in respect of royalty payments which are a financial obligation or are substantially equivalent to a production or similar tax.
(3) | Proved natural gas liquids reserves of consolidated entities as of December 31, 2019, 2018 and 2017 include an estimated approximately 6, 8 and 6 mmbbl, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.
|  | 2019 |  |  | 2018 |  |  | 2017 |
Natural gas |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |
|  | (Billions of standard cubic feet) |
Consolidated entities |  |  |  |
At January 1, |  |  | 2,481 |  |  |  | 2,481 |  |  |  | — |  |  |  | 2,520 |  |  |  | 2,520 |  |  |  | — |  |  |  | 2,923 |  |  |  | 2,923 |  |  |  | — |
Developed |  |  | 1,915 |  |  |  | 1,915 |  |  |  | — |  |  |  | 1,850 |  |  |  | 1,850 |  |  |  | — |  |  |  | 2,143 |  |  |  | 2,143 |  |  |  | — |
Undeveloped |  |  | 566 |  |  |  | 566 |  |  |  | — |  |  |  | 670 |  |  |  | 670 |  |  |  | — |  |  |  | 780 |  |  |  | 780 |  |  |  | — |
Revisions of previous estimates (1) |  |  | (104 | ) |  |  | (104 | ) |  |  | — |  |  |  | 178 |  |  |  | 178 |  |  |  | — |  |  |  | (161 | ) |  |  | (161 | ) |  |  | — |
Extensions and discoveries |  |  | 384 |  |  |  | 384 |  |  |  | — |  |  |  | 329 |  |  |  | 329 |  |  |  | — |  |  |  | 313 |  |  |  | 313 |  |  |  | — |
Improved recovery |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Purchase of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 12 |  |  |  | 12 |  |  |  | — |
Sale of minerals in place |  |  | (8 | ) |  |  | (8 | ) |  |  | — |  |  |  | (4 | ) |  |  | (4 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Production for the year (2) |  |  | (512 | ) |  |  | (512 | ) |  |  | — |  |  |  | (542 | ) |  |  | (542 | ) |  |  | — |  |  |  | (567 | ) |  |  | (567 | ) |  |  | — |
At December 31, (3) (4) |  |  | 2,241 |  |  |  | 2,241 |  |  |  | — |  |  |  | 2,481 |  |  |  | 2,481 |  |  |  | — |  |  |  | 2,520 |  |  |  | 2,520 |  |  |  | — |
Developed |  |  | 1,743 |  |  |  | 1,743 |  |  |  | — |  |  |  | 1,915 |  |  |  | 1,915 |  |  |  | — |  |  |  | 1,850 |  |  |  | 1,850 |  |  |  | — |
Undeveloped |  |  | 498 |  |  |  | 498 |  |  |  | — |  |  |  | 566 |  |  |  | 566 |  |  |  | — |  |  |  | 670 |  |  |  | 670 |  |  |  | — |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At January 1, |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Developed |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Undeveloped |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Revisions of previous estimates (1) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Extensions and discoveries |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Improved recovery |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Purchase of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Sale of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Production for the year (2) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
At December 31, (3) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Developed |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Undeveloped |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Consolidated and Equity-accounted entities |  |  |  |
At January 1, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed |  |  | 1,915 |  |  |  | 1,915 |  |  |  | — |  |  |  | 1,850 |  |  |  | 1,850 |  |  |  | — |  |  |  | 2,143 |  |  |  | 2,143 |  |  |  | — |
Undeveloped |  |  | 566 |  |  |  | 566 |  |  |  | — |  |  |  | 670 |  |  |  | 670 |  |  |  | — |  |  |  | 780 |  |  |  | 780 |  |  |  | — |
Total |  |  | 2,481 |  |  |  | 2,481 |  |  |  | — |  |  |  | 2,520 |  |  |  | 2,520 |  |  |  | — |  |  |  | 2,923 |  |  |  | 2,923 |  |  |  | — |
At December 31, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed |  |  | 1,743 |  |  |  | 1,743 |  |  |  | — |  |  |  | 1,915 |  |  |  | 1,915 |  |  |  | — |  |  |  | 1,850 |  |  |  | 1,850 |  |  |  | — |
Undeveloped |  |  | 498 |  |  |  | 498 |  |  |  | — |  |  |  | 566 |  |  |  | 566 |  |  |  | — |  |  |  | 670 |  |  |  | 670 |  |  |  | — |
Total |  |  | 2,241 |  |  |  | 2,241 |  |  |  | — |  |  |  | 2,481 |  |  |  | 2,481 |  |  |  | — |  |  |  | 2,520 |  |  |  | 2,520 |  |  |  | — |
* | Not material (less than 1 ).
(1) | Revisions in estimates of reserves are performed at least once a year. Revision of natural gas reserves is considered prospectively in the calculation of depreciation.
(2) | Natural gas production for the years 2019, 2018 and 2017 includes an estimated approximately 60, 61 and 64 bcf, respectively, in respect of royalty payments which are a financial obligation or are substantially equivalent to a production or similar tax.
(3) | Proved natural gas reserves of consolidated entities as of December 31, 2019, 2018 and 2017 include an estimated approximately 259, 288 and 289 bcf, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.
(4) | Proved natural gas reserves of consolidated entities and equity-accounted entities as of December 31, 2019, 2018 and 2017 include an estimated approximately 321, 349 and 364 bcf, respectively, which is consumed as fuel at the field.
|  | 2019 |  |  | 2018 |  |  | 2017 |
Oil equivalent (1) |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |
|  | (Millions of barrels of oil equivalent) |
Consolidated entities |  |  |  |
At January 1, |  |  | 1,080 |  |  |  | 1,080 |  |  |  | — |  |  |  | 929 |  |  |  | 929 |  |  |  | — |  |  |  | 1,113 |  |  |  | 1,113 |  |  |  | — |
Developed |  |  | 722 |  |  |  | 722 |  |  |  | — |  |  |  | 663 |  |  |  | 663 |  |  |  | — |  |  |  | 815 |  |  |  | 815 |  |  |  | — |
Undeveloped |  |  | 358 |  |  |  | 358 |  |  |  | — |  |  |  | 266 |  |  |  | 266 |  |  |  | — |  |  |  | 298 |  |  |  | 298 |  |  |  | — |
Revisions of previous estimates (2) |  |  | 7 |  |  |  | 7 |  |  |  | * |  |  |  | 157 |  |  |  | 157 |  |  |  | — |  |  |  | (96 | ) |  |  | (96 | ) |  |  | — |
Extensions and discoveries |  |  | 169 |  |  |  | 169 |  |  |  | — |  |  |  | 174 |  |  |  | 174 |  |  |  | — |  |  |  | 80 |  |  |  | 80 |  |  |  | — |
Improved recovery |  |  | 8 |  |  |  | 8 |  |  |  | — |  |  |  | 15 |  |  |  | 15 |  |  |  | — |  |  |  | 32 |  |  |  | 32 |  |  |  | — |
Purchase of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2 |  |  |  | 2 |  |  |  | — |
Sale of minerals in place |  |  | (3 | ) |  |  | (3 | ) |  |  | — |  |  |  | (2 | ) |  |  | (2 | ) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Production for the year (3) |  |  | (188 | ) |  |  | (188 | ) |  |  | * |  |  |  | (193 | ) |  |  | (193 | ) |  |  | — |  |  |  | (202 | ) |  |  | (202 | ) |  |  | — |
At December 31, (4) |  |  | 1,073 |  |  |  | 1,073 |  |  |  | — |  |  |  | 1,080 |  |  |  | 1,080 |  |  |  | — |  |  |  | 929 |  |  |  | 929 |  |  |  | — |
Developed |  |  | 650 |  |  |  | 650 |  |  |  | — |  |  |  | 722 |  |  |  | 722 |  |  |  | — |  |  |  | 663 |  |  |  | 663 |  |  |  | — |
Undeveloped |  |  | 423 |  |  |  | 423 |  |  |  | — |  |  |  | 358 |  |  |  | 358 |  |  |  | — |  |  |  | 266 |  |  |  | 266 |  |  |  | — |
Equity-accounted entities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
At January 1, |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Developed |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Undeveloped |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Revisions of previous estimates (2) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Extensions and discoveries |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Improved recovery |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Purchase of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Sale of minerals in place |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Production for the year (3) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
At December 31, (4) |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Developed |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Undeveloped |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Consolidated and Equity-accounted entities |  |  |  |
At January 1, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed |  |  | 722 |  |  |  | 722 |  |  |  | — |  |  |  | 663 |  |  |  | 663 |  |  |  | — |  |  |  | 815 |  |  |  | 815 |  |  |  | — |
Undeveloped |  |  | 358 |  |  |  | 358 |  |  |  | — |  |  |  | 266 |  |  |  | 266 |  |  |  | — |  |  |  | 298 |  |  |  | 298 |  |  |  | — |
Total |  |  | 1,080 |  |  |  | 1,080 |  |  |  | — |  |  |  | 929 |  |  |  | 929 |  |  |  | — |  |  |  | 1,113 |  |  |  | 1,113 |  |  |  | — |
At December 31, |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed |  |  | 650 |  |  |  | 650 |  |  |  | — |  |  |  | 722 |  |  |  | 722 |  |  |  | — |  |  |  | 663 |  |  |  | 663 |  |  |  | — |
Undeveloped |  |  | 423 |  |  |  | 423 |  |  |  | — |  |  |  | 358 |  |  |  | 358 |  |  |  | — |  |  |  | 266 |  |  |  | 266 |  |  |  | — |
Total |  |  | 1,073 |  |  |  | 1,073 |  |  |  | — |  |  |  | 1,080 |  |  |  | 1,080 |  |  |  | — |  |  |  | 929 |  |  |  | 929 |  |  |  | — |
* | Not material (less than 1) .
(1) | Volumes of natural gas have been converted to barrels of oil equivalent at 5,615 cubic feet per barrel.
(2) | Revisions in estimates of reserves are performed at least once a year. Revision of crude oil, natural gas liquids and natural gas reserves are considered prospectively in the calculation of depreciation.
(3) | Barrel of oil equivalent production of consolidated entities for the years 2019, 2018 and 2017 includes an estimated approximately 24, 24 and 25 mmboe, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.
(4) | Proved oil equivalent reserves of consolidated entities as of December 31, 2019, 2018 and 2017 include an estimated approximately 140, 143 and 119 mmboe, respectively, in respect of royalty payments which, as described above, are a financial obligation, or are substantially equivalent to a production or similar tax.
The paragraphs below explain in further detail the most significant changes in our proved reserves during 2019, 2018 and 2017.
Changes in our estimated proved reserves during 2019 Extensions and Discoveries As a result of wells drilled in unproved reserves and resources areas , approximately 32 mmboe of proved developed reserves (11 mmbbl of crude oil, 2 mmbbl of NGL and 107 bcf of natural gas), and 137 mmboe of proved undeveloped reserves (76 mmbbl of crude oil, 12 mmbbl of NGL and 276 bcf of natural gas) were added mainly due to new shale oil and gas projects from Loma La Lata Norte, Bandurria Sur, La Amarga Chica and Aguada de la Arena fields. Main proved undeveloped reserves additions are related to Unconventional activities in the Neuquina basin, while proved developed reserves contributions come in most cases from the Neuquina and San Jorge basin executed projects. Improved Recovery A total of approximately 8 mmboe of proved reserves were added mainly due to new projects and positive production response. Main contributions came from Neuquina basin where addition s were 5 mmboe of proved secondary recovery reserves, 2 mmboe from Golfo San Jorge basin and 1 mmboe from Cuyana basin. Sales and Acquisitions As a net result of Sales and Acquisitions, 3 mmboe of proved reserves were reduced. The decrease in these reserves is related mainly to the sale of interests in Al Sur de la Dorsal, El Santiagueño and Bajo del Piche fields. Revisions of Previous Estimates During 2019, the Company’s proved reserves were revised upwards by 7 mmboe (21 mmbbl of crude oil, 4 mmbbl of NGL and a decrease of 103 bcf of natural gas). The main revisions to proved reserves have been due to the following: • As a result of lower average oil and gas prices jointly with lower operating costs in 2019 , its impact on incomes, and on fields economic limit, 10 mmboe of p roved r eserves were deducted. Changes occurred mainly in fields of Cuyana and Neuquina basins. • Total liquids and gas production performance from existing wells was better than expected, resulting in an addition of approximately 33 mmboe to proved developed reserves, according to new reserves estimates, mainly in the Neuquina and Golfo San Jorge basins. • Change of development strategy in certain areas which resulted in a downwards revision of 42 mmboe from previous projects, mainly from Neuquina, Austral and Golfo San Jorge basins. • Revision of Vaca Muerta development project at Loma Campana field, which resulted in an upward revision of 19 mmboe. • Some primary and improved recovery oil projects development schedules were modified or canceled, resulting in a 6 mmboe proved undeveloped reserves reduction, mainly in Golfo San Jorge and Neuquina basins Changes in our estimated proved reserves during 2018 Extensions and Discoveries As a result of wells drilled in unproved reserves and resources areas , approximately 25 mmboe of proved developed reserves (8 mmbbl of crude oil, 1 mmbbl of NGL and 92 bcf of natural gas), and 149 mmboe of proved undeveloped reserves (95 mmbbl of crude oil, 12 mmbbl of NGL and 238 bcf of natural gas) were added mainly due to new shale oil and gas projects from Loma La Lata Norte, Loma Campana, Bandurria Sur and La Amarga Chica fields. Main proved undeveloped reserves additions are related to Unconventional and Tight Gas activities in the Neuquina basin, while proved developed reserves contributions come in most cases from the Neuquina, Noroeste and San Jorge basin projects. Improved Recovery A total of approximately 15 mmboe of proved reserves were added mainly due to new projects and positive production response. Main contributions come from Golfo San Jorge basin where addition s w ere 4.4 mmboe of proved developed and 8 mmboe of proved undeveloped secondary recovery reserves and 3 mmboe from Neuquina basin. Sales and Acquisitions As a net result of Sales and Acquisitions, 1.4 mmboe of proved developed reserves were reduced. The decre ase in these reserves is related mainly to the change in participation for Cerro Bandera and Bandurria Sur fields and acquisition of participation in Llancanelo field. Revisions of Previous Estimates During 2018, the Company’s proved reserves were revised upwards by 156 mmboe (126 mmbbl of crude oil and 178 bcf of natural gas and a decrease of 1 mmbbl of NGL). The main revisions to proved reserves have been due to the following: • As a result of higher average oil and gas prices and lower operating costs in 2018 , its impact on incomes, and on fields economic limit, 143 mmboe of p roved d eveloped r eserves were added. Changes occurred mainly in fields of Neuquina Basin (56 mmboe), Golfo San Jorge basin (40 mmboe) and Austral Basin (31 mmboe). • New economic scenario also improved scheduled projects economics, resulting in a 48 mmboe Proved Undeveloped Reserves incorporation mainly from oil fields of Golfo San Jorge Basin (33 mmboe) and Neuquina basin (15 mmboe). • Total liquids and gas production performance from existing wells was better than expected, resulting in an addition of approximately 33 mmboe to proved developed reserves, according to new reserves estimates, mainly in the Neuquina and Golfo San Jorge basins. • Change of development strategy in certain areas which resulted in a downwards revision of 43 mmboe from previous projects, mainly from Neuquina, Austral and Golfo San Jorge basins. • Some primary and improved recovery oil projects development schedules were modified or canceled, resulting in a 5 mmboe proved undeveloped reserves reduction, mainly in Austral, Golfo San Jorge and Cuyana basins. • Changes in gas compression projects which resulted in a 5 mmboe reduction of proved undeveloped reserves, mainly from Neuquina basin. • Net production results and forecasts from existing and new wells were lower than expected, resulting in a 13 mmboe reduction of proved reserves. Main differences were found in Neuquina basin. Changes in our estimated proved reserves during 2017 Extensions and Discoveries As a result of wells drilled in unproved reserves and resources areas , approximately 26 mmboe of proved developed reserves (7.4 mmbbl of crude oil, 1.9 mmbbl of NGL and 94 bcf of natural gas), and 54 mmboe of proved undeveloped reserves (11.7 mmbbl of crude oil, 3.4 mmbbl of NGL and 219 bcf of natural gas) were added. Main proved undeveloped reserves additions are related to Unconventional and Tight Gas activities in the Neuquina basin, while proved developed reserves contributions come in most cases from the Neuquina and San Jorge basin projects. Improved Recovery A total of approximately 32 mmboe of proved reserves were added mainly due to new projects and positive production response. Main contributions come from Neuquina basin (5.4 mmboe of proved developed and 10 mmboe of proved undeveloped reserves) while Golfo San Jorge basin addition s w ere 5.6 mmboe of proved developed and 9.6 mmboe of proved undeveloped secondary recovery reserves. Sales and Acquisitions As a net result of Sales and Acquisitions, 2.3 mmboe of proved developed reserves were added. The increase in these reserves is related to the to change in participation for Aguada de la Arena field. Revisions of Previous Estimates During 2017, the Company’s proved reserves were revised downwards by 96 mmboe (71 mmbbl of crude oil and 161 bcf of natural gas and an increase of 4 mmbbl of NGL). The main revisions to proved reserves have been due to the following: • As a result of lower average oil and gas prices and higher operating costs in 2017 , its impact on incomes, and on fields economic limit, 105 mmboe of p roved d eveloped r eserves were deducted. Changes occurred mainly in fields of Neuquina basin (-60 mmboe ) , Golfo San Jorge Basin (-25 mmboe) and Cuyana Basin (-14 mmboe). • New economic scenario also affected scheduled projects economics, resulting in a 20 mmboe Proved Undeveloped Reserves reduction mainly from oil fields of Neuquina basin (-15 mmboe) and Golfo San Jorge Basin (-3 mmboe). • Total liquids and gas production performance from existing wells was better than expected, resulting in an addition of 25 mmboe to proved developed reserves, according to new reserves estimates. Upward revisions of 48 mmboe are primarily due to better than expected well performance mainly in the Neuquina basin (31 mmboe) and Golfo San Jorge basin (14 mmboe). Downward revisions of approximately 23 mmboe are mainly related to performance updates in certain wells in the Neuquina basin. • A total volume of 5.6 mmboe of proved reserves was added due to feasibility studies performed to include new projects to field development plans, mainly in Golfo San Jorge basin (3.5 mmboe) and Neuquina basin (2.1 mmboe). • Net production results and forecasts from some new wells were lower than expected, resulting in a 7 mmboe reduction of proved reserves. Main differences were found in Neuquina and Golfo San Jorge basins. • As a better than expected WO jobs performance, 4.2 mmboe of Proved Reserves were added, mainly in Golfo San Jorge and Neuquina basins. Capitalized costs The following tables set forth capitalized costs, along with the related accumulated depreciation and allowances as of December 31, 2019, 2018 and 2017:
|  | 2019 |  |  | 2018 |  |  | 2017 |
Consolidated capitalized costs |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |
Proved oil and gas properties |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Mineral property, wells and related equipment ( 1 ) |  |  | 2,693,690 |  |  |  | 2,033 |  |  |  | 2,695,723 |  |  |  | 1,594,064 |  |  |  | — |  |  |  | 1,594,064 |  |  |  | 770,461 |  |  |  | — |  |  |  | 770,461 |
Support equipment and facilities |  |  | 80,012 |  |  |  | — |  |  |  | 80,012 |  |  |  | 47,224 |  |  |  | — |  |  |  | 47,224 |  |  |  | 22,171 |  |  |  | — |  |  |  | 22,171 |
Drilling and work in progress (2) |  |  | 142,122 |  |  |  | — |  |  |  | 142,122 |  |  |  | 80,737 |  |  |  | — |  |  |  | 80,737 |  |  |  | 40,567 |  |  |  | — |  |  |  | 40,567 |
Unproved oil and gas properties |  |  | 30,012 |  |  |  | — |  |  |  | 30,012 |  |  |  | 14,909 |  |  |  | 1,241 |  |  |  | 16,150 |  |  |  | 6,189 |  |  |  | 558 |  |  |  | 6,747 |
Total capitalized costs |  |  | 2,945,836 |  |  |  | 2,033 |  |  |  | 2,947,869 |  |  |  | 1,736,933 |  |  |  | 1,241 |  |  |  | 1,738,174 |  |  |  | 839,388 |  |  |  | 558 |  |  |  | 839,946 |
Accumulated depreciation and valuation allowances ( 3 ) |  |  | (2,239,487 | ) |  |  | (1,973 | ) |  |  | (2,241,460 | ) |  |  | (1,283,840 | ) |  |  | (489 | ) |  |  | (1,284,328 | ) |  |  | (600,086 | ) |  |  | — |  |  |  | (600,086 | )
Net capitalized costs |  |  | 706,349 |  |  |  | 60 |  |  |  | 706,409 |  |  |  | 453,093 |  |  |  | 752 |  |  |  | 453,846 |  |  |  | 239,302 |  |  |  | 558 |  |  |  | 239,860 |
(1) | Includes 24,468 corresponding to all Upstream contracts, excepted for Drilling Contracts (2) comprised in right-of-use assets (IFRS 16).
(2) | Includes 11,032 corresponding to Drilling contracts comprised in right-of-use assets (IFRS 16).
(3) | Includes (8,841) corresponding to Accumulated Depreciation of all Upstream contracts of right-of-use assets (IFRS 16).
There is no Group’s share in equity method investees’ capitalized costs during the years ended December 31, 2019, 2018 and 2017. Costs incurred The following tables set forth the costs incurred for oil and gas producing activities during the years ended December 31, 2019, 2018 and 2017:
|  | 2019 |  |  | 2018 |  |  | 2017 |
Consolidated costs incurred |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |
Acquisition of unproved properties |  |  | 4,171 |  |  |  | — |  |  |  | 4,171 |  |  |  | 276 |  |  |  | — |  |  |  | 276 |  |  |  | — |  |  |  | — |  |  |  | — |
Acquisition of proved properties |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 166 |  |  |  | — |  |  |  | 166 |  |  |  | 154 |  |  |  | — |  |  |  | 154 |
Exploration costs |  |  | 9,115 |  |  |  | 771 |  |  |  | 9,886 |  |  |  | 7,283 |  |  |  | 381 |  |  |  | 7,664 |  |  |  | 3,302 |  |  |  | 149 |  |  |  | 3,451 |
Development costs ( 1 ) |  |  | 132,289 |  |  |  | — |  |  |  | 132,289 |  |  |  | 53,553 |  |  |  | — |  |  |  | 53,553 |  |  |  | 39,039 |  |  |  | — |  |  |  | 39,039 |
Total costs incurred |  |  | 145,575 |  |  |  | 771 |  |  |  | 146,346 |  |  |  | 61,278 |  |  |  | 381 |  |  |  | 61,659 |  |  |  | 42,495 |  |  |  | 149 |  |  |  | 42,644 |
(1) | Includes 18,547 corresponding to additions of Upstream contracts comprised in right-of-use assets (IFRS 16).
There is no Group’s share in equity method investees ’ costs incurred during the years ended December 31, 2019, 2018 and 2017. Results of operations from oil and gas producing activities The following tables include only the revenues and expenses directly associated with oil and gas producing activities. It does not include any allocation of the interest costs or corporate overhead and, therefore, is not necessarily indicative of the contribution to net earnings of the oil and gas operations. Differences between these tables and the amounts shown in Note 5 “Segment information”, for the exploration and production business unit, relate to additional operations that do not arise from those properties held by the Group.
|  | 2019 |  |  | 2018 |  |  | 2017 |
Consolidated results of operations |  | Argentina |  |  | Other Foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |
Net sales to unaffiliated parties |  |  | 1,949 |  |  |  | 120 |  |  |  | 2,069 |  |  |  | 3,085 |  |  |  | — |  |  |  | 3,085 |  |  |  | 521 |  |  |  | — |  |  |  | 521 |
Net intersegment sales |  |  | 286,585 |  |  |  | — |  |  |  | 286,585 |  |  |  | 207,480 |  |  |  | — |  |  |  | 207,480 |  |  |  | 115,955 |  |  |  | — |  |  |  | 115,955 |
Total net revenues |  |  | 288,534 |  |  |  | 120 |  |  |  | 288,654 |  |  |  | 210,565 |  |  |  | — |  |  |  | 210,565 |  |  |  | 116,476 |  |  |  | — |  |  |  | 116,476 |
Production costs |  |  | (164,562 | ) ( 1 ) |  |  | (242 | ) |  |  | (164,804 | ) |  |  | (114,381 | ) |  |  | — |  |  |  | (114,381 | ) |  |  | (69,944 | ) |  |  | — |  |  |  | (69,944 | )
Exploration expenses |  |  | (6,045 | ) |  |  | (734 | ) |  |  | (6,779 | ) |  |  | (5,185 | ) |  |  | (224 | ) |  |  | (5,409 | ) |  |  | (2,279 | ) |  |  | (168 | ) |  |  | (2,447 | )
Depreciation of property, plant and equipment; intangible and right-of-use assets |  |  | (124,977 | ) ( 2 ) |  |  | (980 | ) |  |  | (125,957 | ) |  |  | (72,044 | ) |  |  | — |  |  |  | (72,044 | ) |  |  | (45,277 | ) |  |  | — |  |  |  | (45,277 | )
Impairment of Property, plant and equipment |  |  | (40,561 | ) |  |  | — |  |  |  | (40,561 | ) |  |  | 3,265 |  |  |  | (365 | ) |  |  | 2,900 |  |  |  | 5,032 |  |  |  | — |  |  |  | 5,032 |
Other |  |  | (6,569 | ) |  |  | (56 | ) |  |  | (6,625 | ) |  |  | (2,839 | ) |  |  | (168 | ) |  |  | (3,007 | ) |  |  | (2,706 | ) |  |  | — |  |  |  | (2,706 | )
Pre-tax income (loss) from producing activities |  |  | (54,180 | ) |  |  | (1,892 | ) |  |  | (56,072 | ) |  |  | 19,381 |  |  |  | (757 | ) |  |  | 18,624 |  |  |  | 1,302 |  |  |  | (168 | ) |  |  | 1,134 |
Income tax expense / benefit |  |  | 16,254 |  |  |  | 417 |  |  |  | 16,671 |  |  |  | (5,814 | ) |  |  | 227 |  |  |  | (5,587 | ) |  |  | (456 | ) |  |  | 59 |  |  |  | (397 | )
Results of oil and gas producing activities |  |  | (37,926 | ) |  |  | (1,475 | ) |  |  | (39,401 | ) |  |  | 13,567 |  |  |  | (530 | ) |  |  | 13,037 |  |  |  | 846 |  |  |  | (109 | ) |  |  | 737 |
(1) | Includes Ps 6,680 million corresponding to short term leases and variable lease payments related to the use of assets. For more information See Note 2.b.12) to the Audited Consolidated Financial Statements.
(2) | Includes Ps (6,060) million corresponding to depreciation of right-of-use assets (IFRS 16).
There is no Group’s share in equity method investees’ results of operations during the years ended December 31, 2019, 2018 and 2017.
Standardized measure of discounted future net cash flows The standardized measure is calculated as the excess of future cash inflows from proved reserves less future costs of producing and developing the reserves, future income taxes and a discount factor. Future cash inflows represent the revenues that would be received from production of year-end proved reserve quantities assuming the future production would be sold at the prices used for reserves estimates as of year-end (the “average price”). Accordingly, crude oil prices used to determine reserves were calculated each month, for crude oils of different quality produced by the Group. For the year ended December 31, 2019, the Company considered the realized prices for crude oil in the domestic market taking into account the effect of export taxes as in effect as of each of the corresponding years (until 2021, in accordance with Law 27,541). For the years beyond the mentioned periods, the Company considered the unweighted average price of the first-day-of-the-month for each month within the twelve-month period ended December 31, 2019, which refers to the Brent prices adjusted by each different quality produced by the Company. Additionally, since there are no benchmark market natural gas prices available in Argentina, the Company considered the realized prices in the domestic market according to the SEC rules and FASB’s ASC 932 rules, but also taking into account the effect of certain market regulations set forth mainly during the second half of the year for certain natural gas segments. Future production costs include the estimated expenditures related to production of the proved reserves, plus any production taxes without consideration of future inflation. Future development costs include the estimated costs of drilling development wells and installation of production facilities, plus the net costs associated with dismantling and abandonment of wells, assuming year-end costs continue without consideration of future inflation. Future income taxes were determined by applying statutory rates to future cash inflows less future production costs and less tax depreciation of the properties involved. The present value was determined by applying a discount rate of 10 % per year to the annual future net cash flows. The future cash inflows and outflows in foreign currency have been remeasured at the selling exchange rate of Argentine pesos 59.79 as of December 31, 201 9 . The standardized measure does not purport to be an estimate of the fair market value of the Group’s proved reserves. An estimate of fair value would also take into account, among other things, the expected recovery of reserves in excess of proved reserves, anticipated changes in future prices and costs and a discount factor representative of the time value of money and the risks inherent in producing oil and gas.
|  | 2019 |  |  | 2018 |  |  | 2017 |
Consolidated standardized measure of discounted future net cash flows |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |  |  | Argentina |  |  | Other foreign |  |  | Worldwide |
Future cash inflows (1) |  |  | 2,545,028 |  |  |  | — |  |  |  | 2,545,028 |  |  |  | 1,786,896 |  |  |  | — |  |  |  | 1,786,896 |  |  |  | 564,396 |  |  |  | — |  |  |  | 564,396 |
Future production costs |  |  | (1,333,468 | ) |  |  | — |  |  |  | (1,333,468 | ) |  |  | (913,980 | ) |  |  | — |  |  |  | (913,980 | ) |  |  | (349,819 | ) |  |  | — |  |  |  | (349,819 | )
Future development costs |  |  | (482,015 | ) |  |  | — |  |  |  | (482,015 | ) |  |  | (304,448 | ) |  |  | — |  |  |  | (304,448 | ) |  |  | (128,885 | ) |  |  | — |  |  |  | (128,885 | )
Future income tax expenses |  |  | (120,966 | ) |  |  | — |  |  |  | (120,966 | ) |  |  | (121,388 | ) |  |  | — |  |  |  | (121,388 | ) |  |  | (2,324 | ) |  |  | — |  |  |  | (2,324 | )
10% annual discount for estimated timing of cash flows |  |  | (227,670 | ) |  |  | — |  |  |  | (227,670 | ) |  |  | (138,847 | ) |  |  | — |  |  |  | (138,847 | ) |  |  | (16,935 | ) |  |  | — |  |  |  | (16,935 | )
Total standardized measure of discounted future net cash flows |  |  | 380,909 |  |  |  | — |  |  |  | 380,909 |  |  |  | 308,233 |  |  |  | — |  |  |  | 308,233 |  |  |  | 66,433 |  |  |  | — |  |  |  | 66,433 |
(1) | For the years ended December 31, 2019, future cash inflows are stated net of the effect of withholdings on exports until 2021 in accordance with Law No. 27,541. For the years ended December 31, 2018, future cash inflows are stated net of the effect of withholdings on exports until 2020 in accordance with Decree No. 793/2018. For the years ended December 31, 2017, future cash inflows are stated net of the effect of withholdings on exports until 2017 in accordance with Law No. 26,732.
There is no Group’s share in equity method investees’ standardized measure of discounted future net cash flows during the years ended December 31, 2019, 2018 and 2017. Changes in the standardized measure of discounted future net cash flows The following table reflects the changes in standardized measure of discounted future net cash flows for the years ended December 31, 2019, 2018 and 2017:
|  | 2019 |  |  | 2018 |  |  | 2017 |
Beginning of year |  |  | 308,233 |  |  |  | 66,433 |  |  |  | 106,411 |
Sales and transfers, net of production costs |  |  | (197,278 | ) |  |  | (62,115 | ) |  |  | (53,759 | )
Net change in sales and transfer prices, net of future production costs |  |  | (239,226 | ) |  |  | 68,651 |  |  |  | (74,046 | )
Changes in reserves and production rates (timing) |  |  | (26,496 | ) |  |  | 111,137 |  |  |  | 15,495 |
Net changes for extensions, discoveries and improved recovery |  |  | 228,354 |  |  |  | 160,784 |  |  |  | 28,489 |
Net change due to purchases and sales of minerals in place |  |  | (1,152 | ) |  |  | (730 | ) |  |  | — |
Changes in estimated future development and abandonment costs |  |  | (82,799 | ) |  |  | (71,368 | ) |  |  | (32,052 | )
Development costs incurred during the year that reduced future development costs |  |  | 102,784 |  |  |  | 39,780 |  |  |  | 22,475 |
Accretion of discount |  |  | 43,534 |  |  |  | 11,490 |  |  |  | 9,724 |
Net change in income taxes |  |  | 66,705 |  |  |  | (80,832 | ) |  |  | 25,920 |
Others ( 1 ) |  |  | 178,250 |  |  |  | 65,003 |  |  |  | 17,776 |
End of year |  |  | 380,909 |  |  |  | 308,233 |  |  |  | 66,433 |
(1) | Corresponds mainly to exchange differences arising from the translation of our cashflows in the functional currency to the presentation currency.
There is no Group’s share in equity method investees’ changes in the standardized measure of discounted future net cash flows during the years ended December 31, 2019, 2018 and 2017.

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