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Supplemental information on oil and gas producing activities (unaudited)

12 Months Ended

Dec. 31, 2024

Supplemental information on oil and gas producing activities (unaudited)

Supplemental information on oil and gas producing activities (unaudited)

34.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 proven 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, 2024, 2023 and 2022, 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.

34.1Capitalized costs relating to oil and gas exploration and production activities


	2024	2023	2022
Natural and environmental properties	109,005,280	96,856,236	90,284,366
Wells, equipment, and facilities – property, plant, and equipment	42,387,351	35,897,318	33,568,835
Exploration and production projects	19,488,784	17,372,792	16,451,284
Accumulated depreciation, depletion, and amortization	(96,990,855)	(84,413,729)	(79,744,788)
Net capitalized cost	73,890,560	65,712,617	60,559,697

It includes information of the Exploration and Production segment subsidiaries.

In accordance with IAS 37, costs capitalized to natural and environmental properties include provisions for asset retirement obligations of $1,497,834, $4,101,617, and $1,979,749 during 2024, 2023 and 2022, respectively.

34.2Costs 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.


	2024	2023	2022
Acquisition of proved properties (1)	1,972,255	37,419	141,928
Acquisition of unproved properties (2)	577,804	—	339,394
Exploration costs	3,378,446	2,911,974	3,322,055
Development costs	15,964,905	19,976,218	16,266,222
	21,893,410	22,925,611	20,069,599

(1)	For 2024, it corresponds to the acquisition of 45% interest in Block CPO-09. For 2023 and 2022, it corresponds to 49% of participation contract in Barnett, acquired by Ecopetrol Permian.

(2)

For 2024, it corresponds to the acquisition of 45% interest in Block CPO-09. 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.

34.3Results 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, 2024, 2023 and 2022 are as follows:


	2024	2023	2022
Net revenues
Sales	67,410,322	66,258,193	71,223,307
Transfers	13,677,202	15,256,723	19,797,158
	81,087,524	81,514,916	91,020,465
Production costs (1)	21,568,517	20,544,682	22,152,495
Depreciation, depletion, and amortization (2)	10,356,534	8,531,483	7,138,902
Other production costs (3)	22,937,996	22,751,720	20,741,550
Exploration expenses (4)	1,769,785	2,088,922	1,512,385
Other expenses (5)	3,635,945	7,508,085	5,399,726
	60,268,777	61,424,892	56,945,058
Income before income tax expense	20,818,747	20,090,024	34,075,407
Income tax expense	(9,627,028)	(9,250,450)	(13,026,271)
Results of operations for exploration and production activities	11,191,719	10,839,574	21,049,136

(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 2024, 2023 and 2022 of $636,308, $477,511 and $333,683, respectively.

(2)	In accordance with IAS 37, the expense related to asset retirement obligations that were recognized during 2024, 2023 and 2022 in depreciation, depletion, and amortization, were 704,084, $438,675, and $768,466, 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 2024, 2023, and 2022, the Ecopetrol Business Group transferred approximately 16.9%, 18.7%, and 21.8%, respectively, of its crude oil and gas production; (percentages based on the value sales in Colombian pesos) to intercompany business units. Those transfers were 55.5%, 57.0%, and 50.4%, respectively, of crude oil and gas production volume.

The intercompany transfers were realized at market prices.

34.4Reserve 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 2025.

The reserves were estimated at a level of 99% 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 2024, 2023 and 2022, and corresponds to the official reserves statements prepared by the Ecopetrol Business Group:


	2024			2023			2022
	Oil	Gas	Total	Oil	Gas	Total	Oil	Gas	Total
	(Mbls)	(Gpc)	(Mbe)	(Mbls)	(Gpc)	(Mbe)	(Mbls)	(Gpc)	(Mbe)
Proved reserves:
Opening balance	1,471	2,346	1,883	1,515	2,828	2,011	1,449	3,151	2,002
Revisions of previous estimates (1)	94	(55)	84	38	(165)	9	81	(104)	63
Improved recovery	79	102	97	91	9	93	77	21	81
Purchases	35	5	35	—	—	—	39	50	48
Extensions and discoveries	42	40	49	17	—	17	52	33	57
Sales	(5)	(5)	(6)	—	—	—	—	—	—
Production	(194)	(317)	(250)	(190)	(326)	(247)	(183)	(323)	(240)
Closing balance	1,522	2,116	1,892	1,471	2,346	1,883	1,515	2,828	2,011
Proved developed reserves:
Opening balance	1,083	2,007	1,435	995	2,174	1,376	921	2,561	1,370
Closing balance	1,087	1,750	1,394	1,083	2,007	1,435	995	2,174	1,376
Proved undeveloped reserves:
Opening balance	388	339	448	520	654	635	528	590	632
Closing balance	435	366	498	388	339	448	520	654	635

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.

34.5Standardized measure of discounted future net cash flows relating to proven 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.


	2024	2023	2022
Future cash inflows	493,144,459	425,761,732	685,716,359
Future costs
Production (1)	(193,522,901)	(158,870,388)	(182,522,131)
Development	(49,298,761)	(40,675,517)	(58,332,264)
Income taxes	(84,245,300)	(80,373,445)	(201,912,509)
Future net cash flow	166,077,497	145,842,382	242,949,455
10% discount factor	(48,561,554)	(49,557,596)	(86,340,334)
Standardized measure of discounted net cash flows	117,515,943	96,284,786	156,609,121

(1)	Production future costs include the estimated costs related to assets retirement obligations in the amount of $25,448,529, $22,615,261, and $23,234,408, as of December 31, 2024, 2023, and 2022, respectively.

The following are the principal sources of change in the standardized measure of discounted net cash flows in 2024, 2023 and 2022:


	2024	2023	2022
Net change in sales and transfer prices and in production cost (lifting) related to future production	41,742,427	(123,240,049)	158,798,134
Changes in estimated future development costs	(15,349,339)	(10,624,343)	(52,166,780)
Sales and transfer of oil and gas produced net of production costs	(59,519,007)	(60,970,234)	(68,867,970)
Net change due to extensions, discoveries, and improved recovery	3,723,233	6,173,144	9,993,781
Net change due to purchase and sales of minerals in place	1,501,219	—	1,767,856
Net change due to revisions in quantity estimates	8,877,125	967,150	10,807,453
Previously estimated development costs incurred during the period	27,041,713	34,815,000	69,458,458
Accretion of discount	14,934,714	28,676,517	15,360,418
Timing and other	4,828,442	(13,215,214)	(11,990,359)
Net change in income taxes	(6,549,370)	77,093,694	(84,908,732)
Aggregate change in the standardized measure of discounted future net cash flows for the year	21,231,157	(60,324,335)	48,252,259