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Supplemental information on oil and gas producing activities (unaudited) | 12 Months Ended
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Dec. 31, 2023
Supplemental information on oil and gas producing activities (unaudited) |
Supplemental information on oil and gas producing activities (unaudited) | 33.Supplemental information on oil and gas producing activities (unaudited) The information in this note is referred to as “unaudited” as a means of clarifying that it is not covered by the audit opinion of the independent registered public accounting firm that has audited and reported on the “Consolidated Financial Statements.” In accordance with the requirements of the United States Securities and Exchange Commission (SEC), Rule 4–10(a) of Regulation S–X, Release 33–8879, Accounting Standards Codification 932 and the ASU– 2010–03 “Oil and Gas reserve Estimation and Disclosures” rule, this section provides supplemental information on oil and gas exploration and producing activities of the Ecopetrol Business Group. The information included in sections (1) to (3) provides historical cost information pertaining to costs incurred in exploration, property acquisitions and development, capitalized costs, and results of operations. The information included in sections (4) and (5) presents information on Ecopetrol’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows. The following information corresponds to Ecopetrol’s oil and gas producing activities as of December 31, 2023, 2022 and 2021, and includes information related to the Ecopetrol Business Group’s consolidated subsidiaries. Under the SEC final rule optional disclosure of possible and probable reserves is allowed but, the Ecopetrol Business Group opted not to do so. Ecopetrol estimated its reserves without considering non–traditional resources. 33.1 Capitalized costs relating to oil and gas exploration and production activities ​
​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2023 |  | 2022 |  | 2021
Natural and environmental properties |  | 96,856,236 |  | 90,284,366 |  | 79,385,151
Wells, equipment, and facilities – property, plant, and equipment |  | 35,897,318 |  | 33,568,835 |  | 31,730,001
Exploration and production projects |  | 17,372,792 |  | 16,451,284 |  | 11,474,682
Accumulated depreciation, depletion, and amortization |  | (84,413,729) |  | (79,744,788) |  | (70,739,885)
Net capitalized cost |  | 65,712,617 |  | 60,559,697 |  | 51,849,949
​ It includes information of the Exploration and Production segment subsidiaries and joint ventures. In accordance with IAS 37, costs capitalized to natural and environmental properties include provisions for asset retirement obligations of $4,101,617, $1,979,749, and $3,930,370 during 2023, 2022 and 2021, respectively. 33.2 Costs incurred in oil and gas exploration and developed activities Costs incurred are summarized below and include both amounts expensed and capitalized in the corresponding period. ​
​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2023 |  | 2022 |  | 2021
Acquisition of proved properties (1) |  | 37,419 |  | 141,928 |  | —
Acquisition of unproved properties (2) |  | — |  | 339,394 |  | —
Exploration costs |  | 2,911,974 |  | 3,322,055 |  | 1,793,549
Development costs |  | 19,976,218 |  | 16,266,222 |  | 11,264,075
​ |  | 22,925,611 |  | 20,069,599 |  | 13,057,624
(1) | For 2023 and 2022, it corresponds to 49% of participation contract in Barnett, acquired by Ecopetrol Permian.
(2) | During 2022, Ecopetrol Óleo e Gás do Brasil Ltda have acquired and capitalized seven offshore blocks in the Santos Basin. The blocks are operated by Shell, which holds a 70% of participation in the assets, with a 30% of participation held by Ecopetrol Brasil.
33.3 Results of operations for oil and gas exploration and production activities The Ecopetrol Business Group’s results of operations from oil and gas exploration and production activities for the years ended December 31, 2023, 2022 and 2021 are as follows: ​
​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2023 |  | 2022 |  | 2021
Net revenues |  |  |  |  |  |
Sales |  | 66,258,193 |  | 71,223,307 |  | 50,631,272
Transfers |  | 15,256,723 |  | 19,797,158 |  | 12,617,680
​ |  | 81,514,916 |  | 91,020,465 |  | 63,248,952
Production costs (1) |  | 20,544,682 |  | 22,152,495 |  | 12,554,338
Depreciation, depletion, and amortization (2) |  | 8,531,483 |  | 7,138,902 |  | 6,623,891
Other production costs (3) |  | 22,751,720 |  | 20,741,550 |  | 21,156,904
Exploration expenses (4) |  | 2,088,922 |  | 1,512,385 |  | 960,247
Other expenses (5) |  | 7,508,085 |  | 5,399,726 |  | 3,090,128
​ |  | 61,424,892 |  | 56,945,058 |  | 44,385,508
Income before income tax expense |  | 20,090,024 |  | 34,075,407 |  | 18,863,444
Income tax expense |  | (9,250,450) |  | (13,026,271) |  | (5,652,743)
Results of operations for exploration and production activities |  | 10,839,574 |  | 21,049,136 |  | 13,210,701
(1) | Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities including costs such as operating labor, materials, supplies, and fuel consumed in operations and the costs of operating natural gas liquids plants. In addition, they include expenses related to the asset retirement obligations that were recognized during 2023, 2022 and 2021 of $477,511, $333,683, and $292,329, respectively.
(2) | In accordance with IAS 37, the expense related to asset retirement obligations that were recognized during 2023, 2022 and 2021 in depreciation, depletion, and amortization, were $438,675, $768,466, and $887,725, respectively.
(3) | Includes transportation costs and naphtha that are not part of the Ecopetrol Business Group’s lifting cost.
(4) | Exploration expenses include the costs of geological and geophysical activities, as well as the non–productive exploratory wells.
(5) | Corresponds to administration, marketing expenses, and impairment.
During 2023, 2022, and 2021, the Ecopetrol Business Group transferred approximately 18.7%, 21.8%, and 19.9%, respectively, of its crude oil and gas production; (percentages based on the value sales in Colombian pesos) to intercompany business units. Those transfers were 57.0%, 50.4%, and 52.1%, respectively, of crude oil and gas production volume (including Refinería de Cartagena). The intercompany transfers were realized at market prices. 33.4 Reserve information The Ecopetrol Business Group follows international standards for estimating, classifying, and reporting reserves framed under SEC definitions. Corporate Reserve Management of Ecopetrol Business Group, Upstream Management and the Vice-Presidency of Development and Production, present the reserves balance to the Board of Directors, which approved it in February 2024. The reserves were estimated at a level of 99.8% by specialized firms: DeGolyer and MacNaughton, Ryder Scott Company, and Gaffney and Cline. According to these certifications the reserves report complies with the content and guidelines set forth in Rule 4–10 of Regulation S–X issued by the United States SEC. The following information relates to the net proven reserves owned by the Ecopetrol Business Group in 2023, 2022 and 2021, and corresponds to the official reserves statements prepared by the Ecopetrol Business Group: ​
​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​ | ​
​ | ​ | 2023 | ​ | 2022 | ​ | 2021
​ | ​ | Oil | ​ | Gas | ​ | Total | ​ | Oil | ​ | Gas | ​ | Total | ​ | Oil | ​ | Gas | ​ | Total
​ |  | (Mbls) |  | (Gpc) |  | (Mbe) |  | (Mbls) |  | (Gpc) |  | (Mbe) |  | (Mbls) |  | (Gpc) |  | (Mbe)
Proved reserves: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Opening balance |  | 1,515 |  | 2,828 |  | 2,011 |  | 1,449 |  | 3,151 |  | 2,002 |  | 1,257 |  | 2,921 |  | 1,770
Revisions of previous estimates (1) |  | 38 |  | (165) |  | 9 |  | 81 |  | (104) |  | 63 |  | 240 |  | 431 |  | 315
Improved recovery |  | 91 |  | 9 |  | 93 |  | 77 |  | 21 |  | 81 |  | 120 |  | 107 |  | 139
Purchases |  | — |  | — |  | — |  | 39 |  | 50 |  | 48 |  | — |  | — |  | —
Extensions and discoveries |  | 17 |  | — |  | 17 |  | 52 |  | 33 |  | 57 |  | 12 |  | — |  | 12
Sales | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | — | ​ | (3) | ​ | (4) | ​ | (3)
Production |  | (190) |  | (326) |  | (247) |  | (183) |  | (323) |  | (240) |  | (177) |  | (304) |  | (231)
Closing balance |  | 1,471 |  | 2,346 |  | 1,883 |  | 1,515 |  | 2,828 |  | 2,011 |  | 1,449 |  | 3,151 |  | 2,002
Proved developed reserves: |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​
Opening balance |  | 995 |  | 2,174 |  | 1,376 |  | 921 |  | 2,561 |  | 1,370 |  | 834 |  | 2,636 |  | 1,297
Closing balance |  | 1,083 |  | 2,007 |  | 1,435 |  | 995 |  | 2,174 |  | 1,376 |  | 921 |  | 2,561 |  | 1,370
Proved undeveloped reserves: |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​
Opening balance |  | 520 |  | 654 |  | 635 |  | 528 |  | 590 |  | 632 |  | 423 |  | 285 |  | 473
Closing balance |  | 388 |  | 339 |  | 448 |  | 520 |  | 654 |  | 635 |  | 528 |  | 590 |  | 632
Some values were rounded for presentation purposes. Mbls = Million barrels Gpc: Giga cubic feet Mbe = Million barrels of oil equivalent
(1) | Represents changes in previous proved reserves, upward or downward, resulting from new information (except for an increase in a proved area), usually obtained from development drilling and production history or result from changes in economic factors.
For additional information about the changes in Proved Reserves and the process for estimating reserves, see section 3.1 – Oil and Gas Reserves. 33.5 Standardized measure of discounted future net cash flows relating to proved oil and gas quantities and changes therein The standardized measure of discounted future net cash flows related to the above proved crude oil and natural gas reserves is calculated in accordance with the requirements of ASU 2010–03. Estimated future cash inflows from production under SEC requirements are computed by applying unweighted arithmetic average of the first day–of–the–month for oil and gas price to year–end quantities of estimated net proved reserves, with cost factors based on those at the end of each year, currently enacted tax rates and a 10% annual discount factor. In our view, the information so calculated does not provide a reliable measure of future cash flows from proved reserves, nor does it permit a realistic comparison to be made of one entity with another because the assumptions used cannot reflect the varying circumstances within each entity. In addition, a substantial but unknown proportion of future real cash flows from oil and gas production activities is expected to derive from reserves which have already been discovered, but which cannot yet be regarded as proved. ​
​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2023 |  | 2022 |  | 2021
Future cash inflows |  | 425,761,732 |  | 685,716,359 |  | 401,980,640
Future costs |  | ​ |  | ​ |  | ​
Production (1) |  | (158,870,388) |  | (182,522,131) |  | (129,109,036)
Development |  | (40,675,517) |  | (58,332,264) |  | (38,451,863)
Income taxes |  | (80,373,445) |  | (201,912,509) |  | (69,053,224)
Future net cash flow |  | 145,842,382 |  | 242,949,455 |  | 165,366,517
10% discount factor |  | (49,557,596) |  | (86,340,334) |  | (57,009,654)
Standardized measure of discounted net cash flows |  | 96,284,786 |  | 156,609,121 |  | 108,356,863
(1) | Production future costs include the estimated costs related to assets retirement obligations in the amount of $22,615,261; $23,234,408; and $17,364,520, as of December 31, 2023, 2022, and 2021, respectively.
​ The following are the principal sources of change in the standardized measure of discounted net cash flows in 2023, 2022 and 2021: ​
​ | ​ | ​ | ​ | ​ | ​ | ​
​ |  | 2023 |  | 2022 |  | 2021
Net change in sales and transfer prices and in production cost (lifting) related to future production |  | (123,240,049) |  | 158,798,134 |  | 110,224,660
Changes in estimated future development costs |  | (10,624,343) |  | (52,166,780) |  | (22,011,659)
Sales and transfer of oil and gas produced net of production costs |  | (60,970,234) |  | (68,867,970) |  | (50,694,613)
Net change due to extensions, discoveries, and improved recovery |  | 6,173,144 |  | 9,993,781 |  | 6,741,068
Net change due to purchase and sales of minerals in place |  | — |  | 1,767,856 |  | (13,419)
Net change due to revisions in quantity estimates |  | 967,150 |  | 10,807,453 |  | 32,923,680
Previously estimated development costs incurred during the period |  | 34,815,000 |  | 69,458,458 |  | 32,941,335
Accretion of discount |  | 28,676,517 |  | 15,360,418 |  | 10,468,951
Timing and other |  | (13,215,214) |  | (11,990,359) |  | (16,636,925)
Net change in income taxes |  | 77,093,694 |  | (84,908,732) |  | (36,016,420)
Aggregate change in the standardized measure of discounted future net cash flows for the year |  | (60,324,335) |  | 48,252,259 |  | 67,926,658
​

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