Supplemental information on oil and gas producing activities (unaudited)

12 Months Ended

Dec. 31, 2025

Supplemental information on oil and gas producing activities (unaudited)

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 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, 2025, 2024 and 2023, and includes information related to the Ecopetrol Group’s consolidated subsidiaries.

Under the SEC final rule optional disclosure of possible and probable reserves is allowed but, the Ecopetrol Group opted not to do so. Ecopetrol estimated its reserves without considering non–traditional resources.

Capitalized costs relating to oil and gas exploration and production activities


		2025		2024		2023
Natural and environmental properties		113,499		109,005		96,856
Wells, equipment, and facilities – property, plant, and equipment		47,638		42,387		35,897
Exploration and production projects		20,069		19,489		17,373
Accumulated depreciation, depletion, and amortization		(105,722)		(96,990)		(84,413)
Net capitalized cost		75,484		73,891		65,713

It includes information on 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 2,473, $1,498 and $4,102 during 2025, 2024 and 2023, respectively.

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 year.


		2025		2024		2023
Acquisition of proved properties (1)		—		1,972		38
Acquisition of unproved properties (2)		—		578		—
Exploration costs		3,354		3,378		2,912
Development costs		15,839		15,965		19,976
		19,193		21,893		22,926

(1)	For 2024, it corresponds to the acquisition of 45% interest in Block CPO-09. For 2023, 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.

Results of operations for oil and gas exploration and production activities

The Ecopetrol Group’s results of operations from oil and gas exploration and production activities for the years ended December 31, 2025, 2024 and 2023 are as follows:


		2025		2024		2023
Net revenues
Sales		58,845		67,411		66,258
Transfers		12,207		13,677		15,257
		71,052		81,088		81,515
Production costs (1)		20,552		21,568		20,545
Depreciation, depletion, and amortization (2)		11,083		10,357		8,531
Other production costs (3)		22,315		22,938		22,752
Exploration expenses (4)		952		1,770		2,089
Other expenses (5)		5,329		3,636		7,508
		60,231		60,269		61,425
Income before income tax expense		10,821		20,819		20,090
Income tax expense		(2,755)		(9,627)		(9,250)
Results of operations for exploration and production activities		8,066		11,192		10,840

(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 2025, 2024 and 2023 of $570, $636, and $478, respectively.

(2)	In accordance with IAS 37, the expense related to asset retirement obligations that were recognized during 2025, 2024 and 2023 in depreciation, depletion, and amortization, were $207, $704, and $439, respectively.

(3)	Includes transportation costs and naphtha that are not part of the Ecopetrol Group’s lifting cost.

(4)	Exploration expenses include the costs of geological and geophysical activities, as well as the non–productive exploratory wells.

(5)	It corresponds to administration, marketing expenses, and impairment.

During 2025, 2024, and 2023, the Ecopetrol Group transferred approximately 17.2%, 16.9% and 18.7%, respectively, of its crude oil and gas production; (percentages based on the value sales in Colombian pesos) to intercompany business units. Those transfers were 56.0%, 55.5% and 57.0%, respectively, of crude oil and gas production volume.

The intercompany transfers were realized at market prices.

Reserve information

The Ecopetrol Group follows international standards for estimating, classifying, and reporting reserves framed under SEC definitions. Corporate Reserve Management of the 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 2026.

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 Group in 2025, 2024 and 2023, and corresponds to the official reserves statements prepared by the Ecopetrol Group:


		2025						2024						2023
		Oil		Gas		Total		Oil		Gas		Total		Oil		Gas		Total
		(Mbls)		(Gpc)		(Mbe)		(Mbls)		(Gpc)		(Mbe)		(Mbls)		(Gpc)		(Mbe)
Proved reserves:
Opening balance		1,522		2,116		1,892		1,471		2,346		1,883		1,515		2,828		2,011
Revisions of previous estimates (1)		164		(135)		141		94		(55)		84		38		(165)		9
Improved recovery		137		29		143		79		102		97		91		9		93
Purchases		12		22		16		35		5		35		—		—		—
Extensions and discoveries		—		—		—		42		40		49		17		—		17
Sales		—		—		—		(5)		(5)		(6)		—		—		—
Production		(199)		(277)		(248)		(194)		(317)		(250)		(190)		(326)		(247)
Closing balance		1,636		1,755		1,944		1,522		2,116		1,892		1,471		2,346		1,883
Proved developed reserves:
Opening balance		1,087		1,750		1,394		1,083		2,007		1,435		995		2,174		1,376
Closing balance		1,204		1,539		1,474		1,087		1,750		1,394		1,083		2,007		1,435
Proved undeveloped reserves:
Opening balance		435		366		498		388		339		448		520		654		635
Closing balance		432		216		470		435		366		498		388		339		448

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.

Standardized 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 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.


		2025		2024		2023
Future cash inflows		483,412		493,144		425,762
Future costs
Production (1)		(218,949)		(193,523)		(158,870)
Development		(40,983)		(49,299)		(40,677)
Income taxes		(72,960)		(84,245)		(80,373)
Future net cash flow		150,520		166,077		145,842
10% discount factor		(43,481)		(48,561)		(49,557)
Standardized measure of discounted net cash flows		107,039		117,516		96,285

(1)	Production future costs include the estimated costs related to assets retirement obligations in the amount of 26,287, $25,449, and $22,615, as of December 31, 2025, 2024, and 2023, respectively.

The following are the principal sources of change in the standardized measure of discounted net cash flows in 2025, 2024 and 2023:


		2025		2024		2023
Net change in sales and transfer prices and in production cost (lifting) related to future production		(16,429)		41,742		(123,240)
Changes in estimated future development costs		(6,229)		(15,349)		(10,624)
Sales and transfer of oil and gas produced net of production costs		(50,500)		(59,519)		(60,970)
Net change due to extensions, discoveries, and improved recovery		8,778		3,723		6,173
Net change due to purchase and sales of minerals in place		—		1,501		—
Net change due to revisions in quantity estimates		15,796		8,877		967
Previously estimated development costs incurred during the year		23,283		27,042		34,815
Accretion of discount		17,713		14,935		28,677
Timing and other		(10,617)		4,828		(13,215)
Net change in income taxes		7,728		(6,549)		77,093
Aggregate change in the standardized measure of discounted future net cash flows for the year		(10,477)		21,231		(60,324)