Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
(Mark One)
☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2025
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
☐ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report …………………………..
Commission file number: 001-34175
ECOPETROL S.A.
(Exact name of Registrant as specified in its charter)
N/A
(Translation of Registrant’s name into English)
REPUBLIC OF COLOMBIA
(Jurisdiction of incorporation or organization)
Carrera 13 No. 36 – 24
Bogotá – Colombia
Tel. (57) 310 315 8600
(Address of principal executive offices)
Maria Fernanda Moreno Rodriguez
Investor Relations Officer
investors@ecopetrol.com.co
Carrera 13 No.36 - 24
Bogotá, Colombia
(Name, Telephone, E-Mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
American Depository Shares (as evidenced by American Depository Receipts), each representing 20 common shares par value COP 609 per share
EC
New York Stock Exchange
Ecopetrol common shares par value COP 609 per share
New York Stock Exchange (for listing purposes only)
8.625% Notes due 2029
EC29
6.875% Notes due 2030
EC30
4.625% Notes due 2031
EC31
7.750% Notes due 2032
EC32
8.875% Notes due 2033
EC33
8.375% Notes due 2036
EC36
7.375% Notes due 2043
EC43
5.875% Notes due 2045
EC45
5.875% Bonds due 2051
EC51
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
41,116,694,690 Ecopetrol common shares, par value COP 609 per share
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
⌧ Yes ◻ No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
◻ Yes ⌧ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ⌧
Accelerated filer ◻
Non-accelerated filer ◻
Emerging growth company ☐
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ◻
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
◻ U.S. GAAP
⌧ International Financial Reporting Standards as issued by the International Accounting Standards Board
◻ Other
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:
◻ Item 17 ◻ Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
☐ Yes ⌧ No
1. Introduction
1
1.1 About This Annual Report
1.2 Forward-looking Statements
2
1.3 Selected Operating Data
3
2. Strategy and Market Overview
2.1 Our Corporate Strategy
4
2.1.1 2040 Strategy: Energy That Transforms
2.1.1.1 Grow with the Energy Transition
5
2.1.1.2 Generate Value through TESG
6
2.1.1.3 Cutting-edge Knowledge
7
2.1.1.4 Competitive Returns
2.1.2 2026 Investment Plan
8
3. Business Overview
9
3.1 Our History
3.2 Our Corporate Structure
11
3.3 Recent Developments
13
3.4 Our Business
16
3.5 Exploration and Production
3.5.1 Exploration Activities
3.5.1.1 Exploration Activities in Colombia
17
3.5.1.2 Exploration Activities Outside Colombia
20
3.5.2 Production Activities
22
3.5.2.1 Production Activities in Colombia
3.5.2.1.1 Ecopetrol S.A.’s Production Activities in Colombia
3.5.2.1.2 Ecopetrol S.A.’s Affiliates and Subsidiaries’ Production Activities in Colombia
29
3.5.2.2 Production Activities Outside Colombia
32
3.5.2.3 Unconventional Hydrocarbons
34
3.5.2.4 Marketing of Crude Oil and Natural Gas
35
3.5.3 Reserves
37
3.5.4 Joint Venture and Other Contractual Arrangements
46
3.6 Transport and Logistics
49
3.6.1 Transportation Activities
3.6.1.1 Pipelines
52
3.6.1.2 Export and Import Facilities
58
3.6.2 Other Transportation Facilities
3.6.3 Marketing of Transportation Services
3.7 Refining and Petrochemicals
3.7.1 Refining
3.7.1.1 Barrancabermeja Refinery
59
3.7.1.2 Cartagena Refinery
60
3.7.1.3 Esenttia S.A.
61
3.7.1.4 Invercolsa
3.7.1.5 Biofuels
3.7.2 Marketing and Supply of Refined Products
3.8 Energy Transmission and Toll Roads Concessions
3.8.1 ISA
62
3.8.2 Electricity Transmission Activities
3.8.2.1 Electricity Transmission Activities in Colombia
63
3.8.2.2 Electricity Transmission Activities Outside Colombia
3.8.3 Toll Roads Concessions Activities
64
3.8.4 Telecommunications and ICT
3.9 Research and Development; Intellectual Property
3.10 Applicable Laws and Regulations
66
3.10.1 Regulation of Exploration and Production Activities
3.10.1.1 Business Regulation
3.10.1.1.1 Environmental Licensing and Prior Consultation
72
3.10.1.1.2 Royalties
76
3.10.2 Regulation of Transportation Activities
3.10.3 Regulation of Refining and Petrochemical Activities
79
3.10.3.1 Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels
80
ii
3.10.3.2 Regulation Concerning Production and Prices
81
3.10.3.3 Regulation of Biofuels, Biogas and Related Activities
83
3.10.4 Regulation of the Natural Gas Market
84
3.10.5 Regulation of the Electric Energy Commercialization Activity
87
3.10.6 Regulation of the Electricity Self-Generation Activity
89
3.10.7 Regulatory Framework for Energy Transmission
92
3.10.8 Regulation of the Toll Roads Concessions
95
3.11 Technology, Environment, Social and Governance (TESG)
98
3.11.1 Energy Initiatives
107
3.11.2 HSE
3.11.2.1 Ecopetrol S.A.
108
3.11.2.2 Cenit
113
3.11.2.3 Cartagena Refinery
3.11.2.4 ISA
114
3.12 Related Party and Intercompany Transactions
3.13 Insurance
118
3.13.1 Exploration and Production, Refining and Petrochemicals and Transport and Logistics segments
3.13.2 Energy Transmission and Toll Roads Concessions
120
3.14 Human Resources/Labor Relations
121
3.14.1 Employees
3.14.2 Collective Bargaining Arrangements
125
4. Financial Review
126
4.1 Factors Affecting Our Operating Income
4.2 [Reserved]
130
4.3 Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results
4.3.1 Taxes
4.3.2 Exchange Rate Variation
134
4.3.3 Effects of Inflation
135
4.3.4 Effects of Crude Oil and Refined Product Prices
4.4 Accounting Policies
136
4.5 Material accounting judgments and estimates
4.6 Operating Results
4.6.1 Consolidated Results of Operations
137
4.6.1.1 Total Sales
4.6.1.2 Cost of Sales
138
4.6.1.3 Administrative, operations and project expenses, net of other income before Impairment of Non-Current Assets Effects
140
4.6.1.4 Impairment recovery (loss) of long-term non-monetary assets
4.6.1.5 Finance Results, Net
142
4.6.1.6 Income Tax
143
4.6.1.7 Net Profit Attributable to Owners of Parent
4.6.1.8 Segment Performance and Analysis
4.6.1.9 Exploration and Production Segment Results
145
4.6.1.10 Transport and logistics Segment Results
147
4.6.1.11 Refining and Petrochemicals Segment Results
148
4.6.1.12 Energy Transmission and Toll Roads Concessions Segment Results
149
4.7 Liquidity and Capital Resources
151
4.7.1 Review of Cash Flows
4.7.2 Capital Expenditures
152
4.7.3 Dividends
4.8 Summary of Differences between Internal Reporting Policies (Colombian IFRS) and IFRS
4.9 Financial Indebtedness and Other Contractual Obligations
154
4.10 Off Balance Sheet Arrangements
158
4.11 Statements of Financial Position
4.12 Trend Analysis and Sensitivity Analysis
159
5. Risk Review
160
5.1 Risk Factor Summary
5.2 Risk Factors
163
5.2.1 Risks Related to Our Business
5.2.2 Risks Related to Colombia and the Region’s Political and Regional Environment
179
5.2.3 Legal and Regulatory Risks
189
5.2.4 Risks Related to Our ADSs
194
5.2.5 Risks Related to the Controlling Shareholder
197
iii
5.3 Risk Management
5.3.1 Integrated Risk Management System and Internal Control System
5.3.2 Managing Low Carbon Economy and Climate Change Risks
198
5.3.3 Information Security and Cybersecurity Management
199
5.3.4 Managing Financial Risk
202
5.4 Legal Proceedings and Related Matters
204
6. Shareholder Information
213
6.1 Shareholders’ General Assembly
6.2 Dividend Policy
214
6.3 Market and Market Prices
215
6.4 Description of Ecopetrol Registered Debt Securities
216
6.5 Description of Ecopetrol ADRs
6.6 Taxation
217
6.6.1 Colombian Tax Considerations
6.6.2 U.S. Federal Income Tax Consequences
223
6.7 Exchange Controls and Limitations
226
6.8 Exchange Rates
227
6.9 Major Shareholders
228
6.10 Enforcement of Civil Liabilities
7. Corporate Governance
229
7.1 Bylaws
233
7.2 Code of Ethics and Conduct
236
7.3 Board of Directors
238
7.3.1 Board Practices
244
7.3.2 Board Committees
245
7.4 Compliance with NYSE Listing Rules
248
7.5 Management
249
7.6 Compensation of Directors and Management
254
7.7 Share Ownership of Directors and Executive Officers
255
7.8 Controls and Procedures
8. Financial Statements
F-1
9. Signature Page
258
10. Exhibits
259
11. Cross-reference to Form 20-F
263
iv
1.
Introduction
1.1
About This Annual Report
We file our annual report on Form 20-F and other information with the U.S. Securities and Exchange Commission.
We file reports, including annual reports on Form 20-F, and other information with the SEC pursuant to the rules and regulations of the SEC that apply to foreign private issuers. The materials included in this annual report on Form 20-F may be downloaded at the SEC’s website: http://www.sec.gov. Any filings we make are also available to the public over the Internet at the SEC’s website at www.sec.gov and at our website at www.ecopetrol.com.co. These URLs are intended to be inactive textual references only. They are not intended to be active hyperlinks to such websites. The information on our website, which might be accessible through a hyperlink resulting from such URL, is not and shall not be deemed to be incorporated into this annual report.
Unless the context otherwise requires, the terms “Ecopetrol”, “we”, “us”, “our”, “Ecopetrol Group”, “Group” or the “Company” are used in this annual report to refer to Ecopetrol S.A. and its subsidiaries on a consolidated basis.
For purposes of the section Business Overview—Exploration and Production, “we” refers to Ecopetrol S.A., its subsidiaries and the partnerships in which Ecopetrol has an interest.
References to the “Nation” or “Colombia” in this annual report relate to the Republic of Colombia, our controlling shareholder. References made to the Colombian Government or the “Government” correspond to the executive branch including the President of Colombia, the ministries, and other government agencies responsible for regulating our business.
Our consolidated financial statements for the years ended December 31, 2023, 2024, and 2025 were prepared in accordance with IFRS accounting standards as issued by IASB. References in this annual report to IFRS mean IFRS as issued by the IASB.
IFRS differs in certain significant aspects from the current reporting standards as in effect in Colombia (“Colombian IFRS”), which is the accounting standard we use for local reporting purposes. As a result, our financial information presented under IFRS is not directly comparable to our financial information presented under Colombian IFRS. For a description of the differences between Colombian IFRS and IFRS, see section Financial Review—Summary of Differences between Internal Reporting Policies (Colombian IFRS) and IFRS.
Our consolidated financial statements were consolidated line by line and all transactions and balances among subsidiaries have been eliminated. These financial statements include the financial results of all subsidiary companies controlled, directly or indirectly, by Ecopetrol S.A. See Exhibit 1 – Consolidated subsidiaries, associates, and joint ventures, to our consolidated financial statements included in this annual report.
In this annual report, references to “USD” or “U.S. dollars” are to United States dollars and references to “COP” “Colombian Peso” or “Colombian Pesos” are to Colombian Pesos, the Ecopetrol Group’s functional and presentation currency under which we prepare our consolidated financial statements. This annual report translates certain Colombian Peso amounts into U.S. dollars at specified rates solely for the convenience of the reader. Unless otherwise indicated, such Colombian Peso amounts have been translated at the rate of COP 4,052.89 per USD 1.00, which corresponds to the average Tasa Representativa del Mercado (TRM), or Representative Market Exchange Rate, for 2025. Such conversion should not be construed as a representation that the Colombian Peso amounts correspond to, or have been or could be converted into, U.S. dollars at that rate or any other rate. On March 31, 2026, the Representative Market Exchange Rate was COP 3,669.96 per USD 1.00. Certain figures shown in this annual report have been subject to rounding adjustments, and, accordingly, certain totals may therefore not precisely equal the sum of the numbers presented. In this annual report, a billion is equal to one with nine zeros.
In this annual report, we use unit measures like: “bpd” (barrels per day), “boepd” (barrels of oil equivalent per day), “mbd” (thousand barrels day), “mboed” (thousand barrels of oil equivalent day), “mboe” (thousand barrels of oil equivalent), “mmboe” (million barrels of oil equivalent), “mmbd” (million barrels per day), “mmb” (million barrels), “mmcfpd” (million cubic feet per day), “GBTud” (giga British thermal units per day) and “MMscfd” (million standard cubic feet per day).
1.2
Forward-looking Statements
This annual report on Form 20-F contains forward-looking statements within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These statements are not based on historical facts and reflect our expectations for future events and results. Most facts are uncertain because of their nature. Words such as “anticipate”, “believe”, “could”, “estimate”, “expect”, “should”, “plan”, “potential”, “predict”, “prognosticate”, “project”, “target”, “achieve” and “intend”, among other similar expressions, are understood as forward-looking statements. We have made forward-looking statements that address, among other things:
Our forward-looking statements and sensitivity analysis are not guarantees of future performance and are subject to assumptions that may prove incorrect and to risks and uncertainties that are difficult to predict. Actual results could differ materially from those expressed or forecasted in any forward-looking statements as a result of a variety of factors. These factors may include, but are not limited to, the following:
All forward-looking statements attributed to us are qualified in their entirety by this cautionary statement. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information or for any other reason. Accordingly, readers should not place undue reliance on forward-looking statements.
1.3
Selected Operating Data
The following table sets forth, for the periods and at the dates indicated, certain key operating data.
Table 1 – Selected Operating Data
Operating Information
2025
2024
2023
2022
2021
Oil and gas production (mboed)
745.3
745.8
736.6
709.5
679.0
Proved oil and gas reserves (mmboe)(1)
1,944
1,893
1,883
2,011
2,002
Exploratory wells(2)(3)
26
Refinery throughput (bpd)(4)
420,460
416,879
422,623
360,451
355,895
1P Reserves replacement ratio
%
104
48
200
Transmission Lines (km)
50,564
49,677
49,426
48,766
48,330
(1)
Include natural gas royalties and exclude crude oil royalties. As of 2025, it includes crude oil royalties paid in cash for five contracts in Colombia.
(2)
Gross exploratory wells.
(3)
The table does not include stratigraphic wells, although they are considered exploratory. These wells do not come into production and are subsequently plugged and abandoned after the relevant study is completed. The table also includes wells drilled by partners at sole risk.
(4)
Includes the Barrancabermeja, Cartagena, Apiay and Orito refineries.
2.
Strategy and Market Overview
Our consolidated financial results for 2025 reflect the cumulative impact of a crude oil price that fell short of our initial expectations. In our investment plan for 2025, we forecasted a Brent Crude oil price of USD 73.00 per barrel for the year, while the actual average price stood at USD 68.19 per barrel. Moreover, the price showed a decrease of USD 11.65 per barrel compared to 2024. This lower-than-anticipated price environment was driven by two main factors: (i) a volatile global crude market shaped by steady supply growth, particularly from OPEC and its allies (OPEC+), and (ii) a notable slowdown in the growth of oil demand across key emerging economies, especially China and India, compounded by persistent trade and geopolitical uncertainty. As a result, price movements during the year were often amplified by changes in risk perception and financial positioning.
On the demand front, global oil consumption grew by 0.8 mmbd in 2025, below the trend rate of 1.3 mmbd growth expected at the beginning of the year and well under the pre-pandemic trend of 1.2 mmbd observed during 2015-2019. This underperformance was primarily driven by weaker demand growth in China and India, which each expanded by only 0.1 mmbd in 2025. While China’s growth was unchanged relative to 2024 (0.1 mmbd), India’s demand growth fell from 0.2 mmbd in 2024. In both cases, outcomes fell short of initial market expectations of 0.3 mmbd for China and 0.2 mmbd for India. Given that China alone has accounted for nearly half of global oil demand growth over the past two decades, this deceleration weighed materially on the global demand balance.
By contrast, the United States stood out with resilient oil demand growth of 0.1 mmbd. Although this represented a decline from the 0.2 mmbd increase recorded in 2024, it exceeded early-year expectations of flat demand growth, supported by a stronger-than-anticipated macroeconomic backdrop. Overall, however, strength in U.S. demand and parts of the Asia-Pacific region was insufficient to offset the broader slowdown across large emerging markets, leaving global consumption growth markedly below expectations.
On the supply side, OPEC+, including Russia, increased crude supply by 1.3 mmbd during 2025. This outcome contrasted sharply with market expectations at the beginning of the year, which projected a 0.1 mmbd reduction. The unexpected upside supply was largely the result of the group’s decision to begin unwinding previously implemented production cuts, leading to a net oil market surplus over the course of the year. In particular, the market was shaped by the gradual reincorporation of 2.5 mmbd as OPEC+ dismantled the two tranches of output cuts starting in April 2025. This process brought back volumes that had been restricted since 2023, materially altering the supply–demand balance. The pace and scale of this normalization exceeded earlier guidance and contributed decisively to lose fundamentals. The graph below sets forth the oil demand and supply balance compared against the evolution of the Brent price as of the periods indicated.
Graph 1 – Supply/Demand Balance vs ICE Brent Price Evolution
Source: S&P Global Commodity Insights, Bloomberg
At the end of 2025, with the U.S. economy stabilizing, inflation moderating in developed markets, and major economies initiating interest rate cuts, signs of demand recovery emerged. Additionally, China’s economy rebounded, boosting market sentiment. These developments prompted the International Monetary Fund (IMF) to place global economic growth of 3.3% for 2025, with advanced economies growing at 1.7% and emerging market and developing economies at 4.4%.
Although international oil prices and global demand and supply dynamics are significant factors affecting our business and financial condition, Colombia’s local economic factors have also influenced, and will continue to affect our performance, given that we conduct most of our business in this country.
The Colombian economy, as measured by real GDP, grew at a rate of 2.6% in 2025, which is aligned to the average GDP growth in the region (2.4% according to IMF estimates), and compared to a 1.5% growth rate in 2024. In 2025, GDP growth was mainly driven by (i) private consumption and government spending, with an increase in annual terms of 3.6% and 7.1%, respectively; and (ii) government spending, with an increase in annual terms of 5.2% in 2025. In contrast, the external sector contributed negatively to GDP growth, with imports increasing by 8.6% and exports growing by 1.4%, resulting in an increase in the current account deficit.
2.1
Our Corporate Strategy
2.1.1
2040 Strategy: Energy That Transforms
On February 8, 2022, the Ecopetrol Group published its long-term strategy (the “2040 Strategy”), also referred to as “Energy That Transforms.” The 2040 Strategy aims to address comprehensively current environmental, social, and governance priorities, while maintaining our focus on generating sustainable value for all our stakeholders. The objective of this long-term strategy is to consolidate an agile and dynamic organization that promptly adapts to the changes faced by the energy industry.
“Energy That Transforms” is designed to position the Ecopetrol Group as an integrated energy group, leader in Latin America in energy diversification, which participates in all segments of the hydrocarbon chain (exploration and production, refining and petrochemicals and transport and logistics) as well as energy infrastructure. Our focus is to diversify into low-emission businesses that allow us to continue reducing our carbon footprint and achieve (i) a 55% reduction in methane emissions by 2030, (ii) a 25% reduction of our CO2e emissions compared to the 2019 baseline for scopes 1 and 2 by 2030, (iii) a net-zero carbon emissions (scopes 1 and 2), and (iv) a 50% reduction in total emissions (scopes 1, 2 and 3) by 2050. This strategy comprises four strategic pillars: (i) Grow with the Energy Transition, (ii) Generate Value through Technology, Environmental, Social and Governance (“TESG”), (iii) Cutting-edge Knowledge, and (iv) Competitive Returns. The corporate strategy is based on a long-term oil price of USD 55/Bl.
In addition, on September 11, 2023, Ecopetrol announced certain adjustments to its 2040 Strategy initially presented in February 2022. Such adjustments were approved by the Board of Directors of the Company and pertain to the following aspects of the strategy: (1) the new strategic focus of the Caribbean offshore lever is to maximize gas potential in the Colombian Caribbean; (2) unconventional hydrocarbon exploration activities should not be pursued in Colombia; and (3) the previously defined strategic objective of “energy efficiency” has been replaced by optimization of the internal consumption of energy by 25 petajoules (“PJ”) for the period 2018-2030. Regarding the energy consumption optimization target of 25 PJ by 2030, by the end of 2025 a cumulative reduction of 24.8 PJ had been achieved equivalent to 99% of the 25 PJ target established for 2030.
The replacement of the strategic objective of “energy efficiency” has impacted the “Generate Value through TESG” and “Grow with the Energy Transition” pillars of the Company. All other elements of the 2040 Strategy announced to the market in February 2022 remain unchanged. The long-term strategy reaffirms our commitment to a fair and equitable energy transition, emphasizing portfolio diversification while preserving the integrity and value of our traditional business. Additionally, our focus remains on strict capital discipline to ensure profitable and sustainable growth in our business lines and value creation for all our stakeholders.
2.1.1.1
Grow with the Energy Transition
The first pillar seeks to maximize the life and value of the hydrocarbon portfolio, while advancing towards decarbonization and a more diversified strategy of low-emission businesses. This pillar aims to maintain Ecopetrol Group’s competitiveness in the integrated hydrocarbon value chain and increase gas supply, offshore exploration, and enhanced recovery, thereby strengthening our traditional businesses with the latest technology and innovations to have more sustainable processes and maximize the value of reserves and future barrels.
On average, we expect to invest between COP 20 and COP 30 trillion annually by 2040. In production, investment is expected to be focused on enhanced recovery technologies, Caribbean offshore gas developments, and protecting the base production curve by improving the natural decline of production fields. In line with international best practices, the valuation for these projects includes greenhouse gas emissions cost under the CO2 shadow price methodology, with a price curve starting at 40 USD/tCO2e today and reaching 50 USD/tCO2e by 2030.
In the exploration and production segment, we expect to maintain our production between 700 and 750 thousand barrels of oil equivalent per day (“mboed”) through 2040. In 2025, crude oil production reached 745 mboed, representing the highest national level of crude production in the last five years. Additionally, a reserves replacement ratio of 121% was achieved, the greatest level of reserves in addition to the past four years.
For gas, production is expected to increase alongside new commercialization opportunities, with long-term business growth anticipated across the gas value chain, including transportation and regasification. In December 2025, Ecopetrol and Petrobras successfully concluded the commercialization process for gas from the Sirius field, selling 100% of the available gas volume sold, equivalent to up to 249 million cubic feet per day, regardless of each partner’s equity participation in the project. The gas was commercialized through the execution of 66 binding contracts, subject to conditions, with 17 counterparties. The commercialization of Sirius gas is a key milestone toward advancing the project toward its estimated operational start date in 2030.
In the transport and logistic segment, the long-term objectives include capturing over 90% of the Colombian hydrocarbons transportation market, while enabling the Ecopetrol Group’s hydrocarbons infrastructure to secure demand and diversify into alternative businesses, thereby sustaining its value proposition.
The refining and petrochemicals segment seeks to: (i) increase the margin of existing refineries’ assets; (ii) maximize the polypropylene margin, and (iii) assess options for diversifying into petrochemicals and green fuels. In 2025, the refining and petrochemicals segment recorded one of the highest annual throughput levels in its history, benefiting from a favorable price environment. The gross refining margin increased by USD 3.2/bbl due to feedstock optimization and higher output of high-value fuels.
Additionally, the value of the various products is expected to be strengthened through commercial strategies which seek to diversify heavy crude destinations, leverage the advantage in quality and reliability of supply and integrate customer-based logistics and recipes.
The diversification towards low-emission businesses contemplates adding new businesses in low-emission electrons and molecules. Currently, through ISA, leader in the energy transmission and toll roads concessions business in terms of regional market share, the Ecopetrol Group responds competitively to the challenges of decarbonization and diversification, meeting new demands in the context of the energy transition, diversifying the portfolio and participating into new segments of the energy sector.
In the energy transmission and toll roads concessions segment, the aim is to continue the growth trajectory in both new and existing geographies, leveraging ISA’s strategic leadership position in the power transmission business in Latin America.
On March 13, 2025, ISA launched its 2040 Strategy, “Energy that brings life to the transition,” aiming to position itself as a leading energy transmission company on the continent through investments in new electric energy businesses. In this new strategic cycle, the focus is on preserving the relevance of the transmission business while capturing opportunities arising from the energy transition that complement the core business. ISA maintains a strong competitive position as one of the leading electricity transmission operators in Colombia, Peru, Chile, Brazil, and Bolivia, with market shares of 64%, 74%, 13%, 11%, and 4%, respectively. This solid regional footprint supports the business line’s strategic relevance and reinforces its role in the Group’s diversification within the electrons business.
ISA achieved significant milestones across the region, strengthening its growth and diversification strategy. In Peru, ISA was awarded the country’s two largest electricity transmission projects, comprising 1,054 km of infrastructure and expected to generate USD 83.5 million in annual revenues starting in 2029. These projects will support the energy transition, enhance system reliability, and improve electricity service for more than nine million people. Additionally, through ISA CTEEP, the Company generates approximately USD 5 million in annual revenues from Brazil’s first large-scale battery energy storage system integrated into the transmission grid. With 30 MW of power and 60 MWh of storage capacity, this initiative represents a key step in ISA’s diversification into innovative energy solutions and flexible grid infrastructure.
The energy transition business line is expected to secure the energy required by the Ecopetrol Group, ensure reductions in the Group’s energy costs, and diversify cash flows through gas commercialization and hydrogen.
The value proposition includes diversifying into low-emission businesses, for which we have invested USD 115 million since January 2023, in green hydrogen projects, CCUS and in renewables incorporation.
2.1.1.2
Generate Value through TESG
This pillar seeks to strengthen transparent and ethical relations with our stakeholders, applying high standards of corporate governance to achieve environmentally responsible, safe, and efficient operations in which innovation and technology function as catalysts to accelerate solutions for future challenges. To achieve this, the Ecopetrol Group has identified five focus areas: (i) build and generate value through an efficient, clean and safe production, (ii) decarbonized operations and energy efficiency, (iii) ensure circular water management, (iv) support local development in the places where we operate, and (v) generate trust in the social context through proactive dialogue and by improving the quality of life of people looking for mutual benefits, with a focus on inclusion, and on reactivating and diversifying local economies.
Environmentally, the long-term TESG targets include the achievement of the following targets, compared to the 2019 baseline: (i) 55% reduction in methane emissions by 2030, (ii) 25% reduction in CO2e emissions by 2030, (iii) net-zero emissions of CO2 equivalent by 2050 (scopes 1 and 2) in all our operations, (iv) zero routine gas flaring by 2030 in the exploration and production business, (v) zero treated produced and wastewater discharges by 2045 along with an expected reduction of 58% to 66% in the intake of fresh water for operations. Our TESG commitments represent long-term aspirations. Between 2020 and 2025, Ecopetrol implemented 61 methane emission reduction projects in the production segment, achieving a cumulative reduction of 46% compared to the 2019 baseline year. Of this total, around 21 ktCH₄ correspond to initiatives implemented between 2020 and 2024, reductions that are already consolidated in the emissions inventory closed in 2025. The remaining ~14 ktCH₄ correspond to projects conducted in 2025, whose results will be fully reflected in the GHG emissions inventory at the end of 2026. In 2025, we reduced 561,454 tCO2e from new projects implemented during that year, exceeding the established annual target by 165%. The accumulated reduction for the 2021-2025 period is 2.8 MtCO2e.
The Company has set specific targets towards achieving its energy matrix decarbonization and enabling the incorporation of low-emission businesses within its portfolio. The Company maintains its long-term target of incorporating more than 1,000 MW of non-conventional renewable energy by 2030 and, by 2025, strengthened its energy self-sufficiency by integrating 950.6 MW of installed renewable energy capacity. This portfolio consists of 381.3 MW in operation, 297.9 MW associated with purchases in the Wholesale Energy Market (Mercado de Energía Mayorista or “MEM” for its acronym in Spanish), 221.0 MW under execution, and 50.4 MW under construction.
During the fourth quarter of 2025, there was substantial progress in the Coral project. The Coral project involves the installation of a green hydrogen plant using PEM (proton exchange membrane) technology, the largest of this kind in Latin America, with an expected capacity of 800 tons per year of green H₂, equivalent to an estimated annual emissions reduction of approximately 7,700 tCO₂e. All equipment for the Coral project and SS-20 substation was delivered to the Cartagena Refinery.
On the social front, the long-term TESG targets focus on promoting the generation of approximately 230 thousand new non-oil related jobs by 2040 and contributing to the education of two million young Colombians.
2.1.1.3
Cutting-edge Knowledge
This pillar seeks to develop the required skills and capacities to face the challenges towards growth and TESG, through a comprehensive science, technology, and innovation strategy, as well as improving the competitiveness and resilience of current assets, contributing to diversification, increasing clean energy, decarbonizing operations and strengthening of talent through transformative practices such as training programs to optimize performance or fill new positions in order to build an agile and productive organization, with top talent contributing to society in the context of the energy transition.
In 2025, the Company’s Science, Technology and Innovation activities, together with the capabilities of the Colombian Institute of Petroleum and Energy Transition (ICPET), are fully aligned with the needs of the business, prioritizing technological focus areas that generate a direct impact on the assets of the Ecopetrol Group.
2.1.1.4
Competitive Returns
The fourth pillar ensures continuity of our strict capital discipline, the efficient use of resources, and the protection of cash, all of which have been leveraging the Ecopetrol Group’s strategy since 2015. The long-term aspiration includes, among others, maintaining the ordinary dividend policy between 40% and 60%, in line with operating results. The long-term strategy will allow transfers to the Nation between COP 13-20 trillion annually on average, through royalties, taxes, and dividends and is expected to enable a sustainable capital structure with a gross debt to EBITDA ratio below 2.5 times.
In 2025, our financial results included: a net income of COP 9.0 trillion and a total contribution to the Nation of COP 34.6 trillion among dividends, taxes, and royalties in 2025. These results were achieved thanks to our 2025 operational results, rigorous financial discipline, an efficiency plan that reached historic figures of COP 6.6 trillion in savings, and our human capital and execution capability.
2.1.2
2026 Investment Plan
On November 27, 2025, we announced that the Board of Directors approved the 2026 Investment Plan (the “2026 Investment Plan”) which contemplates a budget of between COP 22 trillion (USD 5.4 billion) and COP 27 trillion (USD 6.7 billion). The 2026 Investment Plan is aligned with the group’s commitment to energy security and the country’s energy transition. The 2026 Investment Plan assumes, among others, a USD 60/Bl Brent price, an exchange rate close to COP 4,050 per USD 1.00 and the collection of the accounts receivable from the Fuel Price Stabilization Fund (“FEPC”) for 2025. The 2026 Investment Plan maintains investment levels compared to 2025 under capital discipline criteria and includes the following guidelines:
·
Approximately COP 17.2 trillion, about 70% of the budget, is expected to be allocated to achieve profitable production between 730 and 740 thousand barrels of oil equivalent per day, maintain an average refinery throughput of 410 to 420 thousand barrels per day, and transport between 1,110 and 1,120 thousand barrels per day.
Around COP 7.1 trillion, approximately 30% of the budget, is expected to be invested in energy transition and power transmission projects, as well as roads and other corporate investments.
About COP 1.7 trillion is expected to be allocated to advance the goals of the sustainability strategy, mainly in climate change, sustainable territories, materials and waste, and occupational health.
The following are some excerpts from the annual investment budget approved by the Board of Directors, disaggregated by business line:
Hydrocarbons Line
For 2026, investments in the exploration and production segment are expected to be approximately 14 trillion pesos (approximately 89% of the annual budget for crude oil-related investments and around 11% for gas-related investments) and are expected to allow organic production levels in 2026 between 730,000 and 740,000 barrels of oil equivalent per day (80% crude, 15% gas, and 5% white products), seeking to implement recovery technologies to optimize the use of available resources and maintain production levels. Crude oil production in Colombia is expected to remain at similar levels of last years and compensating for the natural decline of gas fields.
In 2026, the Company has planned to drill between 380 and 430 development wells, of which 95% would be executed in Colombia and the remaining 5% in the United States. In terms of exploration, the Company has planned to drill between eight and 10 wells mainly in the Meta and Putumayo Departments and the Caribbean Offshore of Colombia. The Company also estimates gas investments of approximately 1.5 trillion pesos in 2026, mainly in the Piedemonte Llanero and Offshore, to develop Caribbean Colombia gas, contributing to a production of approximately between 105,000 and 110,000 barrels of oil equivalent per day.
Investments in the transport and logistics segment are expected to reach approximately 1.5 trillion pesos, corresponding to 6% of the total budget for 2026, mainly in integrity and reliability projects concerning the infrastructure developed by Cenit Transporte y Logística de Hidrocarburos S.A.S., Oleoducto Central S.A., Oleoducto de Colombia S.A., and Oleoducto de los Llanos S.A. Transported volumes are expected to reach between 1,110,000 and 1,120,000 barrels per day, in line with the country’s production expectations and refined product demand.
Investments in the refining and petrochemicals segment are expected to reach approximately 1.7 trillion pesos, corresponding to 7% of the total investment amount estimated for 2026, and are expected to be focused on ensuring the reliability, availability, and sustainability of the operation of the Barrancabermeja and Cartagena refineries, ensuring the development of programs that would reduce product imports, ensuring better quality fuels, and developing renewable fuel (SAF) projects. The joint load of the refineries is expected to be between 410,000 and 415,000 barrels per day.
Energies for the Transition Line
To advance energy transition, around COP 0.9 trillion (3% of the 2026 Investment Plan) is expected to be invested in non-conventional renewable energy and energy efficiency projects, among others. Approximately 750 MW of additional clean energy generation capacity is expected from projects in operation, construction, and development.
Transmission and Roads Line
ISA is expected to invest between COP 6.2 and 6.8 trillion in 2026, about 26% of the Ecopetrol Group’s annual budget, with roughly 80% allocated to the electric transmission business.
Finally, the Ecopetrol Group expects to allocate about COP 0.2 trillion (1% of the 2026 Investment Plan) to corporate areas and operational support.
Table 2 – 2026 Investment Plan
Business Segment
% Percentage
Exploration and Production
57
Refining and Petrochemicals
Transport and logistics
Energy Transmission and Toll Roads Concessions
Other
TOTAL
100
3.
Business Overview
3.1
Our History
Ecopetrol was established in 1951 by the Colombian Government as Empresa Colombiana de Petróleos and began operating the crude oil fields at La Cira-Infantas, the first oil field in Colombia where production started in 1918, as well as the pipeline that connected that field with the Barrancabermeja refinery and the port of Cartagena. In 1961, we assumed the direct operation of the Barrancabermeja refinery and continued its transformation into an industrial complex. In 1974, we acquired the Cartagena Refinery (as defined below), which had been in operation since 1957. Pursuant to Decree 0062 of 1970, we evolved into a governmental, industrial, and commercial company.
In 2003, pursuant to Decree Law 1760, as amended, the National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos or “ANH” for its acronym in Spanish) was created and Ecopetrol’s public role as administrator and regulator of the national hydrocarbons resources was transferred to the ANH. Ecopetrol modified its organic structure and became Ecopetrol S.A., a publicly held corporation, one hundred percent state-owned, and continued the development of exploration and production activities on a competitive basis with autonomy over business decisions. Since 2006, according to Law 1118, we have evolved from a wholly state-owned entity to a mixed-economy company with private capital. This process has resulted in a substantial change in the legal framework to which we are subject, and in the nature of our relationship with the Nation, as our controlling shareholder.
We conducted our initial public offering in August 2007, when our common shares were listed on the Colombian Stock Exchange. Our American Depositary Shares (ADSs) were listed on the New York Stock Exchange in September 2008. We conducted a follow-on public offering in Colombia in August 2011.
In June 2012, Cenit was incorporated as a subsidiary specialized in logistics and transportation of hydrocarbons in Colombia, whose main objective was to enhance the strategic and logistical framework of the Colombian oil industry, given the boost in hydrocarbon production and looking to increase sales of crude oil and refined products in Colombia and in the international markets.
In 2016, 34 units of the Cartagena Refinery came into operation and upgrades were made to the Barrancabermeja refinery.
In 2017, we entered for the first time into the Mexican market, where we were awarded (together with Petronas and Pemex) two blocks to explore and produce hydrocarbons in shallow waters in the southeastern basin.
In 2018, we made progress in the internationalization of offshore exploration by entering the Brazilian pre-salt oil region, one of the areas with the greatest potential for oil reserves in the world, working together with top-tier companies such as British Petroleum, China National Petroleum, China National Offshore Oil Corporation (“CNOOC”), Shell and Chevron. Additionally, we reached a milestone in our plan to transition into renewable energies with the award of a contract for the construction of the first solar farm in Meta, with an installed capacity of more than 20 MW to supply part of the energy demanded by the Castilla field.
In 2019, we began operations in the Permian Basin through a strategic alliance with Occidental Petroleum. We believe this project contributed to strengthen our position in knowledge and technology in unconventional reservoirs.
On July 1, 2021, we incorporated Ecopetrol Singapore Pte Ltd., a wholly owned subsidiary which owns 100% of the capital stock of Ecopetrol Trading Asia Pte Ltd. The latter’s main purpose is the international commercialization of crude oil and refined products of the Ecopetrol Group and of third parties throughout Asia.
On August 20, 2021, we acquired 51.4% of the outstanding shares of ISA from the Ministry of the Treasury and Public Credit (Ministerio de Hacienda y Crédito Público or “MHCP” for its acronym in Spanish), through which we expect to reposition ourselves along the energy value chain by offering services such as electricity transmission and aligning ourselves with the market trends towards decarbonization and electrification.
On November 16, 2022, we incorporated Ecopetrol US Trading LLC, a wholly owned indirect subsidiary of the Company owned through its subsidiary Ecopetrol USA Inc. Ecopetrol US Trading LLC’s main purpose is the international marketing of refined, petrochemical and industrial products as well as crude oil and natural gas from the Ecopetrol Group and third parties.
On March 17, 2023, we incorporated Econova Technology & Innovation, S.L.U. (“Econova”), a wholly owned subsidiary in Spain. Econova’s main purpose is the development of technology, innovation and science activities.
On October 1, 2024, the Company concluded the liquidation process of Ecopetrol Energía S.A.S. E.S.P.
On July 7, 2025, Ecopetrol acquired 100% of the shares of Wind Autogeneración S.A.S., from Enel S.A.S. The Windpeshi project of Wind Autogeneración S.A.S., located in La Guajira, between the municipalities of Uribia and Maicao. See details of the accounting recognition in Section 2.3 of the financial statements.
On July 22, 2025, the merger by absorption between Oleoducto Central S.A. – Ocensa (surviving entity) and Ocensa Ductos S.A.S. (absorbed entity) was registered with the Bogotá Chamber of Commerce. The merger was perfected through Public Deed No. 2157 dated July 15, 2025, executed before Notary Office No. 39 of Bogotá. As a result of this transaction, Ocensa acquired all assets, property and rights of Ocensa Ductos S.A.S., which was dissolved without liquidation, thereby streamlining the corporate structure and strengthening Ocensa’s direct ownership interest in Oleoducto de Colombia S.A., in alignment with the Ecopetrol Group’s strategy for the transport and logistics segment.
On November 13, 2025, Ecopetrol S.A. closed the transaction with Statkraft European Wind and Solar Holding AS (“Statkraft”) for the acquisition of one company engaged in the development and operation of Statkraft’s portfolio in Colombia, and other nine companies which own solar or wind projects. Through this acquisition, Ecopetrol S.A. advances its decarbonization and energy transition objectives, in alignment with its 2040 Strategy.
On November 28, 2025, Ecopetrol successfully concluded negotiations with Grenergy Renovables S.A. for the potential acquisition by Ecopetrol of seven companies within its portfolio in Colombia, located across the departments of Córdoba (three companies), Cesar (two), Magdalena (one), and Sucre (one). The transactions are still subject to certain conditions precedent, and Ecopetrol is still not the sole shareholder of those companies.
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3.2
Our Corporate Structure
Pursuant to our 2040 Strategy, we are currently organized into three corporate business lines: (A) hydrocarbons, which includes three operating segments: (i) exploration and production, (ii) transport and logistics, and (iii) refining and petrochemicals; (B) energies for the transition and (C) energy transmission and toll roads concessions. Ecopetrol Group seeks to maintain the competitiveness of the Hydrocarbons business, the development and scaling of the businesses in the energies for the transition portfolio, and the growth of the energy transmission and toll roads concession line. Following the changes to the Company as a result of the ISA acquisition and in line with our 2040 Strategy, we started a process in 2022 to align our current segments more closely to the business lines set forth in the 2040 Strategy for the Ecopetrol Group, and such process is expected to continue throughout 2026.
For this annual report, the financial information is organized into four reportable segments: (i) exploration and production, (ii) transport and logistics, (iii) refining and petrochemicals, and (iv) energy transmission and toll roads concessions. This segmentation covers all of the business lines described above, with the exception of the energies for the transition business line, which is not yet presented as a separate reportable segment. The current segment structure remains consistent with prior annual reports and is expected to be maintained until management completes the restructuring of the operating and financial reporting model to better align with the 2040 Strategy.
Although the energies for the transition business line is not yet presented as a separate reportable segment, management of this business line is supported by dedicated internal financial information. In addition to the segment information prepared for external reporting purposes, the Company prepares monthly internal management financial reports to support administrative, strategic and operational decision-making at the business line level. The financial information used to manage the energies for the transition line is primarily derived from underlying gas and power-related activities, which are currently included largely within the exploration and production segment.
Our significant subsidiaries, as such term is defined under SEC Regulation S-X, include the following:
We have several directly and indirectly held subsidiaries both in Colombia and abroad. As of December 31, 2025, we have 20 directly owned and 77 indirectly owned subsidiaries.
The table below sets forth our corporate structure as of December 31, 2025:
Graph 2 – Ecopetrol’s Corporate Structure
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The stock ownership percentage listed next to each entity refers to Ecopetrol S.A.’s direct and indirect participation therein as of December 31, 2025. Such data presents a summary of Ecopetrol S.A.’s corporate structure and does not include information about every entity directly or indirectly owned by the Company, and participation information has been rounded to the nearest integer; as such, it should not be relied upon and should be used solely for information purposes.
Exhibit 8.1 to this annual report identifies our principal operating subsidiaries, their respective countries of incorporation, and our percentage ownership in each (both directly and indirectly through other subsidiaries).
3.3
Recent Developments
Ecopetrol and Frontera Energy signed a strategic regasification agreement
On February 5, 2026, Ecopetrol and Frontera Energy announced the execution of a strategic agreement for regasification services. The agreement is intended to support the timely and reliable supply of natural gas to Colombia beginning in the third quarter of 2026. The project’s initial phase provides for early capacity of 126 mmcfpd in 2026, followed by a phased expansion to up to 370 mmcfpd by 2028. This incremental capacity is expected to strengthen Colombia’s medium‑term natural gas supply and enhance the reliability of the national energy system.
Ecopetrol and Gran Tierra Entered into an agreement to extend the development of the Tisquirama and San Roque fields
On March 17, 2026, Ecopetrol and Gran Tierra entered into an agreement to extend the development and production activities of the Tisquirama and San Roque fields, located in the department of Cesar, Colombia. The agreement contemplates total investments of approximately USD 92.4 million, to be fully funded by Gran Tierra and executed over the 40 months following the completion of the transaction. Operations will be conducted within the Tisquirama Direct Operation Area.
Ecopetrol and Petrobras confirmed offshore natural gas discovery at the Copoazú‑1 exploratory well
On March 18, 2026, Ecopetrol and Petrobras confirmed a new offshore natural gas discovery following the drilling of the Copoazú‑1 exploratory well, located in the GUA‑OFF‑0 Block in deep waters of the Colombian Caribbean. Drilling operations at the Copoazú‑1 exploratory well commenced on November 11, 2025. Gas‑bearing intervals were evaluated through well logging and fluid sampling, confirming the presence of natural gas beyond the primary exploration target. These intervals will be subject to further characterization and evaluation.
Unwinding of cross-holdings in IE Madeira and IE Maranhuns
On March 19, 2026, ISA Energía Brasil S.A., informed that it had entered into a share purchase agreement with “Centrais Elétricas Brasileiras S.A.” (“Axia Energia”) to unwind the cross-holdings in Interligação Elétrica do Madeira S.A. (“IE Madeira”) and Interligação Elétrica Garanhuns S.A., through:
Within the scope of the cross-shareholding unwinding, the Company shall pay a cash consideration of BRL $1,174 billion (December 2025 base date), subject to the price adjustment provisions set forth in the share purchase agreement.
Closing of the transaction is subject to the satisfaction of customary conditions precedent for transactions of this nature, including the applicable approvals/clearances from the Brazilian Electricity Regulatory Agency (“ANEEL”), the Brazilian antitrust authority (“CADE”), and the required consents from certain creditors
Agreement with the Republic of Colombia related to the FEPC
On April 1, 2026, Ecopetrol S.A. and Refinería de Cartagena S.A.S. entered into an agreement with the Republic of Colombia regarding the settlement of the outstanding balance of the FEPC corresponding to the first quarter of 2025. Through Resolutions Nos. 00368 and 00369 dated March 31, 2026, the Hydrocarbons Directorate of the Ministry of Mines and Energy ordered the payment of the outstanding FEPC balance for the first quarter of 2025 for a total amount of approximately COP 1.6 trillion, of which approximately COP 1.2 trillion corresponds to Ecopetrol S.A. and approximately COP 0.4 trillion corresponds to Refinería de Cartagena S.A.S. Under this agreement, the Nation acknowledges in favor of Ecopetrol S.A. and Refinería de Cartagena S.A.S. the cost associated with the time elapsed between the execution of the agreement and the payment scheduled for December 2026.
Ecopetrol S.A. obtained authorization to carry out a debt management transaction of up to USD $1.25 billion
On April 1, 2026, Ecopetrol S.A., as part of its comprehensive debt management strategy, through Resolution No. 0666 dated April 1, 2026, the Ministry of Finance and Public Credit (“MHCP”) authorized the execution of a loan of up to USD $1.25 billion. The lenders participating in the loan are: Banco Bilbao Vizcaya Argentaria, S.A. New York Branch (USD $350 million), Bank of America, N.A. (USD $350 million), JP Morgan Chase Bank, N.A. (USD $350 million), and Bank of China Limited – Panama Branch (USD $200 million). The term of the loan will be five (5) years as from the execution date of the agreement, repayable in four (4) equal installments and bearing a floating interest rate indexed to the SOFR rate, under the terms previously agreed with the lenders.
This loan was authorized within the framework of a request submitted by Ecopetrol to execute an external public debt management. The transaction involves: (i) repayment of the USD $1.2 billion loan authorized by the MHCP under Resolution No. 0652 dated March 20, 2024, originally entered into for the acquisition of Ecopetrol’s ownership interest in Interconexión Eléctrica S.A. E.S.P; and (ii) repayment of USD $50 million of the outstanding balance of the USD $500 million loan authorized by the MHCP under Resolution No. 0910 dated April 25, 2025.
The MHCP reviewed and authorized the terms of the loan agreement, which includes customary borrower events of default, such as failure to pay principal or interest, potential impairment of the borrower’s payment capacity, impairment of the integrity of its financial information, and breach of covenants. If any such event occurs, the lenders may demand early repayment of the debt, following the procedure set forth in the agreement. The agreement also provides Ecopetrol with the right to seek recourse against the lenders if they fail to disburse funds as required. The agreement is governed by the laws of the State of New York.
Standard & Poor’s Global Ratings (S&P) Affirmed Ecopetrol’s Stand‑Alone Credit Profile and Revised Its Global Credit Rating
On April 8, 2026, S&P Global Ratings revised Ecopetrol’s global credit rating from BB to BB- with a stable outlook, in line with the adjustment to Colombia’s sovereign credit rating. S&P also affirmed Ecopetrol’s Stand‑Alone Credit Profile (SACP) at BB+. The agency noted that Ecopetrol’s credit rating continues to be constrained by Colombia’s sovereign rating due to the company’s strategic importance, government ownership, and significant contribution to the country’s fiscal revenues. As a result, Ecopetrol’s outlook mirrors that of the Colombian sovereign.
For more information, see section Risk Review - Risks Related to Our Business- Our ability to access credit markets may be limited by the deterioration of these markets, changes in credit ratings, and limited offering from financial institutions to participants in the oil and gas industry
Ecopetrol entered into an Agreement to acquire an equity stake in Brava Energia S.A. a company domiciled in Brazil
On April 23, 2026, Ecopetrol announced that it entered into a Share Purchase Agreement with Jive, Yellowstone and Bloco Somah Printemps Quantum, which together constitute a group of significant shareholders holding approximately 26% of the outstanding common shares of the Brazilian company Brava Energia S.A. (B3: BRAV3) (“Brava”), for the acquisition by Ecopetrol S.A., or one of its affiliates or subsidiaries within the Ecopetrol Group, of 120,813,490 shares of Brava, representing approximately 26% of Brava’s share capital.
Brava was incorporated in 2024 as a result of the merger between 3R Petroleum Óleo e Gás S.A. and Enauta Participações S.A., two oil and gas companies operating in Brazil. Brava currently conducts crude oil and natural gas production activities in offshore and onshore fields across multiple basins in Brazil and also participates in the midstream and downstream segments. As of December 2025, according to Brava’s publicly available information, Brava reported EBITDA of USD 806 million, with an EBITDA margin of 39%. Brava is positioned as the second-largest independent company listed in the Brazilian capital market in terms of reserves and production.
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The completion of this transaction is subject to certain customary conditions precedent, including, among others, approval by Brazil’s Administrative Council for Economic Defense (CADE), the receipt of certain waivers and consents under Brava’s financing instruments and relevant commercial agreements, as well as the purchase by Ecopetrol S.A., or one of its affiliates or subsidiaries within the Ecopetrol Group, of the number of shares required to achieve a 51% controlling stake of Brava’s voting share capital.
Ecopetrol S.A. or one of its affiliates or subsidiaries within the Ecopetrol Group plans to launch a Voluntary Tender Offer (Oferta Pública de Aquisição – OPA) on the B3 stock exchange in Brazil, at a price of R$23.00 per share, to acquire the additional number of Brava shares required to secure a 51% equity and voting interest in the Company. This offer price represents a premium of approximately 27.8% over the Volume-Weighted Average Price (VWAP) of the Company’s shares during the 90 trading days immediately preceding the date of this announcement. The tender offer is planned to be addressed to all of Brava’s shareholders, ensuring equal treatment and conditions, and will be subject to applicable regulatory requirements and certain conditions precedent.
Ecopetrol S.A. or one of its affiliates or subsidiaries within the Ecopetrol Group expects to secure the funding required to consummate the transaction through a bridge loan, in accordance with the expected transaction timeline and certain conditions precedent.
Upon completion of the transaction, the Ecopetrol Group would incorporate pro-rata 1P reserves based on its ownership interest from Brava’s total reported reserves of 459 million barrels of oil equivalent (MMboe) as of year-end 2025, under the Petroleum Resources Management System (PRMS) standard, through a diversified portfolio of offshore and onshore assets. In addition, the transaction would allow the immediate addition of pro-rata production from Brava’s average reported production of approximately 81 thousand barrels of oil equivalent per day (Mboed) in 2025, strengthening production sustainability and cash flow generation in a geography where the Ecopetrol Group already has an established presence. This transaction directly supports the objectives set forth in the Ecopetrol Group’s 2040 Strategy. Moreover, the transaction is aligned with the Ecopetrol Group’s capital discipline and, upon closing, is expected to contribute to metrics such as ROACE and EBITDA. Finally, this transaction would expand the Ecopetrol Group’s footprint in Brazil, diversifying its asset base in a high-growth region and strengthening its international portfolio.
Once the applicable conditions precedent and legal requirements for closing the transaction have been satisfied, Ecopetrol will disclose the relevant information in accordance with the applicable legal and regulatory framework through this same channel and/or any other required means.
Moody’s Downgraded Ecopetrol’s Global Credit Rating to Ba2 and Affirmed Its Stand - Alone Credit Profile at b1
On April 23, 2026, the credit rating agency Moody’s Ratings downgraded the Company’s global credit rating from Ba1 to Ba2 and revised the outlook from stable to negative. In contrast, the agency affirmed Ecopetrol’s Baseline Credit Assessment (BCA), or stand-alone credit profile, at b1, highlighting the Company’s intrinsic strength.
According to Moody’s, the downgrade to Ba2 with a negative outlook is mainly driven by a less favorable view on the support from the Government of Colombia, stemming from an increased perception of potential government interference and reduced clarity regarding the timeliness and predictability of support mechanisms, particularly those related to the Fuel Price Stabilization Fund (FEPC). In this context, Moody’s also included considerations related to Ecopetrol’s corporate governance and its influence on the rating.
Additionally, Moody’s incorporated the possibility of higher refinancing risk associated to a potential material merger and acquisition transaction financed with short-term debt. Nevertheless, the agency highlighted that the Company has strong sources of liquidity that support its financial profile.
Moody’s reaffirmed Ecopetrol’s stand-alone credit profile (BCA) at b1, considering the Company’s solid business profile as Colombia’s leading integrated oil and gas company, supported by the diversification of its operations, moderate leverage levels, an adequate liquidity position, and its strategic role in ensuring the country’s energy supply.
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Management
On April 6, 2026, we announced the following in relation to senior management:
1.Ricardo Roa Barragán, who has served as the Company’s Chief Executive Officer, requested to take his accrued and legally entitled vacation leave. Mr. Roa’s vacation period is scheduled to run from April 7, 2026, through May 27, 2026. In addition, the Board of Directors approved an unpaid leave of absence, in accordance with Section 3 of Article 23 of the Company’s Bylaws and the Decision‑Making and Authorities Matrix. The unpaid leave of absence will commence on May 28, 2026, and is expected to have a duration of 30 calendar days.
2.Effective April 7, 2026, Juan Carlos Hurtado Parra, the Company’s Vice President of Exploration, Development, and Production, is serving as the Company’s Acting Chief Executive Officer, in his capacity as the first alternate to the Chief Executive Officer of the Company.
See Corporate Governance – Management.
3.4
Our Business
We are the largest oil producer and major fields operator company in Colombia and one of the main integrated energy companies in the American continent. We are responsible for over 60% of the hydrocarbon production, of most transportation, logistics, and hydrocarbon refining systems in Colombia, and maintain a leading position in the petrochemicals and gas distribution segments. Through ISA, the Company participates in energy transmission, the management of real-time systems (XM), and the Barranquilla - Cartagena coastal highway concession. At the international level, Ecopetrol has a stake in strategic basins in the American continent, with drilling and exploration operations in the United States (Permian basin and the Gulf of Mexico (aka Gulf of America)), Brazil, and Mexico, and, through ISA and its subsidiaries, Ecopetrol holds leading positions in the power transmission business in Brazil, Chile, Peru, and Bolivia, road concessions in Chile, and the telecommunications sector. The Nation currently owns 88.49% of our voting capital stock. We are among the world’s largest public oil and gas companies, ranking 28 on the Forbes 2025 Global 2000 Ranking, and the largest Colombian company in this ranking.
3.5Exploration and Production
Our exploration and production business segment includes exploration, development, and production activities in Colombia and abroad. Ecopetrol began exploration activities in Colombia in 1955 and expanded to international exploration in 2006. These operations are conducted directly by Ecopetrol S.A., and through some of our subsidiaries, as well as through joint ventures with third parties. As of December 31, 2025, we were the largest operator and producer of crude oil and natural gas in Colombia, maintaining the largest exploration acreage position in Colombia.
Unless otherwise stated, all figures are given before deducting royalties.
3.5.1
Exploration Activities
In 2025, our exploration strategy was focused on three working fronts: Colombian onshore, Colombian Caribbean offshore, and overseas. By year-end, the Ecopetrol Group was a party to 68 contracts for exploratory activities, with 44 of those contracts being for Colombia, and 24 of those contracts for outside of Colombia, distributed as follows:
Our Business Plan aims at incorporating resources in high reward projects concentrated in: (i) onshore basins in Colombia (both foothills and foreland in Llanos basin, Middle and Upper Magdalena Valley, Putumayo and gas in Guajira, Sinú-San Jacinto and Lower Magdalena Valley), (ii) offshore Colombia (appraise and evaluate existing gas discoveries as well as identify new hydrocarbons accumulations), and (iii) international areas such as Gulf of Mexico (aka Gulf of America) and offshore Brazil in Santos basin.
Graph 3 – Sedimentary Basins where Ecopetrol Executes Exploration Activities
3.5.1.1
Exploration Activities in Colombia
In 2025, Ecopetrol S.A. and its subsidiaries drilled 16 exploration and appraisal wells in Colombia, out of which nine were exploratory (A3/A2) and seven were appraisal (A1) wells. As of December 31, 2025, seven wells were successful, four were dry, and five remained under technical evaluation. This drilling activity was concentrated in basins of interest around Colombia, including the Caribbean offshore, Llanos, Piedemonte, Middle Magdalena Valley and Putumayo.
The seven successful wells drilled by Ecopetrol S.A. and its partners in Colombia during 2025 were located in the following regions: Sirius-2 ST2 in the Caribe Offshore, Toritos Norte-3, Toritos Este-1, Toritos Sur-3, Currucutu-1, and Cosecha GNE-1 (association contract) in the Llanos basin and Raju-1 in the Putumayo.
In 2025, Ecopetrol and other partners executed the following agreements for exploration activities:
The following table sets forth, for the periods indicated, the number of gross and net productive, dry, and under evaluation exploratory wells drilled by Ecopetrol S.A., Hocol and by our joint venture partners, and the exploratory wells drilled by third parties pursuant to sole risk contracts with us.
18
Table 3 – Exploratory Drilling in Colombia
For the year ended December 31,
(Number of wells)
COLOMBIA
Ecopetrol S.A.
Gross exploratory wells
Owned and operated by Ecopetrol
Productive
—
Dry(1)
3.00
Under Evaluation(2)
1.00
2.00
Total
5.00
Operated by a partner in Joint Venture
Under Evaluation(2)(4)
6.00
4.00
Operated by Ecopetrol in Joint Venture
Net Exploratory Wells(3)
1.09
1.11
1.60
1.62
1.21
3.48
1.52
0.65
3.55
4.23
2.97
8.63
Sole Risk
Hocol
Gross Exploratory Wells
7.00
9.00
11.00
2.50
1.50
3.50
5.50
A dry well or hole is an exploratory well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well.
An “under evaluation” well is an exploratory well where there is not yet enough information to determine its result as successful or dry. This classification is maintained until additional well-testing operations are conducted to determine the hydrocarbon production capacity or some petrophysical parameter of the rocks or fluids in the reservoir.
Net exploratory wells were calculated according to our percentage of ownership in these wells.
Infantas 3340 well was classified as “under evaluation”. However, as of January 2026, it has been declared a dry well. Currucutú-2 well was also classified as “under evaluation”, however, as of January 2026, it has been declared a productive well.
19
Seismic
In Colombia, during 2025, Ecopetrol did not acquire any seismic information, while Hocol acquired 68.1 km2 3D of seismic information in Llanos 100 block. Moreover, 27.2 km2 of 3D seismic and 3.6 km of 2D seismic were reprocessed by Ecopetrol in the Middle (VMM) and Lower (VIM) Magdalena Valley, Putumayo, Llanos, Piedemonte and in the Colombian Caribbean. In non-seismic methods, 13.8 km2 of aerogradiometry (iFTG) data were modeled and integrated across onshore basins and seismic characterization has been done through quantitative interpretation - QI of 19.8 km2 of 3D projects and 80 km in 2D in the Middle (VMM) and Upper (VSM) and Lower (VIM) Magdalena Valley, Llanos and in the Colombian Caribbean.
Hocol, during the first quarter of 2025, completed the acquisition of the LLA 100-3D-2024 seismic program in the LLA-100 block, located in the Llanos basin, in the municipality of Puerto Gaitán, Meta department. 68.1 km² of high-quality 3D seismic data were acquired, with no reportable health and safety incidents. During 2026, studies and designs will be conducted for the acquisition of seismic programs in the Lower Magdalena Valley basin in subsequent years.
3.5.1.2
Exploration Activities Outside Colombia
Our international exploration strategy is focused on high material basins, aiming at mitigating our risk exposure and ultimately increasing our reserves. This strategy is supported by efficient, business-oriented portfolio management, which involves participation in competitive bidding rounds to secure high-potential exploration blocks in the focus areas. Within this context, a key element is the formation of strong joint ventures with international and regional oil companies which can contribute with operational expertise and leading-edge technology.
Ecopetrol Óleo e Gás do Brasil Ltda. is part of a Joint Operating Agreement (JOA) with Shell as operator for 11 blocks in the Santos Sul Basin, holding a 30% interest in the exploratory blocks assigned during the 2022 round 17 of the National Agency of Petroleum, Natural Gas and Biofuels of Brazil (“ANP,” for its acronym in Portuguese). These blocks are located approximately 210 km to the west of Itajai Port. In 2025, the 3D reprocessing and seismic interpretation, was completed as part of the investment commitments for the exploratory phase. Within Ecopetrol, leads and prospects identification activities were conducted as part of the technical work supporting a potential exploratory well to be drilled in 2027.
The Orca Brasil project (formerly known as Gato do Mato), in which the Company holds a 30% interest and Shell holds a 70% interest, achieved significant progress. The project’s development plan includes the installation of a Floating Production, Storage and Offloading unit (“FPSO”) with a capacity of up to 120,000 barrels per day, the addition of significant reserves in 2026, and an estimated start of production in 2029. This operation aligns with the Company’s strategy of internationalization, capital discipline, and technical learning in high-complexity offshore projects in Latin America.
In 2025, the execution phase of project Orca Brasil began. As part of this stage, the declaration of commercial viability for Orca and Orca Sul—the official names of the two fields—was accepted. ANP approved the final evaluation report of the discovery, officially concluding the exploration phase of the contract before the agency. The FPSO construction project has reached 28.61% progress, along with advancements in the contracts for subsea production systems and the rig for the drilling campaign. Technical and economic evaluations of the field are expected to support the incorporation of 1P reserves above 50 mboe, once the development plan is approved by the ANP in 2026.
The following table sets forth information on our international exploratory drilling for the periods indicated.
Table 4 – Exploratory Drilling Outside Colombia
Ecopetrol America LLC
BRAZIL
Ecopetrol Óleo e Gás do Brasil Ltda.
Productive(5)
Net Exploratory Wells(3)(4)
0.20
An “under evaluation well” is an exploratory well where there is not yet enough information to determine its result as successful or dry. This classification is maintained until additional well testing operations are conducted to determine the hydrocarbon production capacity or some petrophysical parameter of the rocks or fluids in the reservoir.
None of our international wells were drilled pursuant to a sole risk contract.
Ecopetrol America participated in the acquisition of seismic rights in the operational area of the K2 field, using the Ocean Bottom Nodes (OBN) technique over an area of 300 km². Additionally, this seismic data was integrated and reprocessed together with previously acquired data, covering a total area of 535 km².
During 2025, Ecopetrol Óleo e Gás do Brasil Ltda., aligned with its commitment to the ANP, received the final products of the high- quality multi-client 3D seismic campaign, completing 10,816 km2 of 3D seismic data for the southern Santos basin. This dataset is currently used to assess the area’s exploration potential and to support the maturation of leads and prospects within the portfolio.
21
3.5.2
Production Activities
In 2025, our consolidated average production was 745.3 thousand barrels of oil equivalent per day (“mboed”), remaining broadly in line with 2024 levels. This result primarily reflects: (1) in Colombia, (i) higher output from Caño Sur field and the acquisition of a 45% interest in the CPO09 block, (ii) interventions in gas fields, such as Cusiana – Cupiagua and Recetor (Piedemonte Llanero) – aimed at mitigating natural decline, (iii) higher than expected water intrusion in fields such Guajira and Gibraltar, and (iv) electrical disruptions in Meta and Magdalena Medio, public order challenges, natural field decline, and extended timelines for projects and drilling activities due to blockades earlier in the year; and (2) outside of Colombia, improved performance in production at Permian and Ecopetrol America compared to 2024.
The following table summarizes the results of our oil and gas production activities for the periods indicated:
Table 5 – Ecopetrol Group’s Oil and Gas Production
Oil
Gas(1)
(mboed)
Total gross production in Colombia(2)(5)
517.3
115.9
633.1
509.4
135.1
644.5
515.7
147.6
663.3
Total international gross production(3)
64.1
48.0
112.2
60.4
40.9
101.3
44.5
28.8
73.3
Total gross production of Ecopetrol Group
581.4
163.9
569.8
176.0
560.2
176.4
Total production of Ecopetrol Group for presentation of reserves(4)
546.3
133.0
679.3
531.6
152.6
684.2
521.1
156.9
678.0
Conversion between million cubic feet per day (mcfpd) and boepd is performed at 5,700 mcfpd to 1 boepd. Includes natural gas and natural gas liquids.
Total production in Colombia corresponds to Ecopetrol S.A. and Hocol. Includes royalties.
Total International production corresponds to Ecopetrol Permian LLC and Ecopetrol America LLC. Includes royalties.
For the Company’s presentation of reserves, the Company deducts from its total gross production the 100% of crude royalties from Ecopetrol Group companies and gas royalties from non-Colombian Ecopetrol Group companies, Ecopetrol Permian LLC (United States) and Ecopetrol America LLC (United States). Gas royalties derived from Colombian production are not deducted because according to local regulation the Company is entitled to such gas royalties. Also includes self-consumption, which is only comprised of natural gas self-consumption and is immaterial. Oil production includes natural gas liquids (“NGL”) and oil self-consumption, which is immaterial.
(5)
The total gross production in Colombia, includes the production of 100% of Arauca field (0.3 mboed). Although in December 2024, Ecopetrol S.A. and Parex filed a request to transfer Ecopetrol’s 50% stake in the agreement for the Arauca field to Parex, approval from the ANH was only received through an addendum dated as of December 15, 2025.
3.5.2.1
Production Activities in Colombia
3.5.2.1.1
Ecopetrol S.A.’s Production Activities in Colombia
For the year ended December 31, 2025, Ecopetrol S.A. was the largest participant in the Colombian hydrocarbons industry, accounting for approximately 66.4% of crude oil production and 61.4% of natural gas production (calculations based on information from the Ministry of Mines and Energy (Ministerio de Minas y Energía or “MME” for its acronym in Spanish). In 2025, Ecopetrol S.A. drilled and completed 322 development wells, mainly in crude oil assets group of Andina Oriente Region and some through associated operation with partners (222 through direct operations and 100 through associated operation).
Up until February 16, 2025, Ecopetrol S.A. managed its production operations considering the regional location of the operation and whether the operation was conducted in association with partners (“associated operations”).
On February 16, 2025, the exploration and production segment changed its management structure from one defined by regions to one defined by products or asset groups (i.e. oil and gas). This change seeks to strategically redirect the segment to comply with the 2040 Strategy.
The maps below show the locations of Ecopetrol S.A.’s operations by product and by region.
Graph 4 – Ecopetrol S.A. Operations in Colombia by Product and by Region
Note: Associated operation is conducted through a countrywide management of assets with partners.
Ecopetrol S.A. manages its production operations through two product assets groups: (1) crude oil fields and (2) natural gas fields, as well as an associated organization. Together, these comprise a total of 142 fields with active production in 2025. Additionally, we operate 60 fields with active production through joint operations with various partners.
Crude Oil Production
The average daily production of crude oil in Colombia by Ecopetrol S.A. (excluding its subsidiaries), was 495.75 mbd in 2025, 4.38 mbd higher than in 2024, which represents a year-to-year increase of 0.89%.
The following chart summarizes Ecopetrol S.A.’s average daily crude oil production in Colombia by region, prior to deducting royalties, for the periods indicated.
23
Table 6 – Ecopetrol S.A.’s Average Daily Crude Oil Production in Colombia by Region
(Thousand bpd)
Central Region
La Cira – Infantas
14.48
15.10
16.35
Casabe
10.60
11.62
12.47
Yarigui
13.47
14.28
15.53
Nare
13.67
14.45
Other (1)
15.94
15.35
15.98
Total Central Region
68.16
70.80
75.12
Orinoquía Region
Castilla
95.11
98.64
100.69
Chichimene
58.49
57.72
59.03
CPO-09
26.31
12.68
11.46
Apiay
5.87
6.07
5.04
5.77
6.63
Total Orinoquía Region
191.55
181.11
182.85
Piedemonte Region
Piedemonte Campo
14.74
16.53
16.45
Cupiagua
3.57
3.75
3.73
Cusiana
0.52
0.70
Recetor
1.90
1.54
Gibraltar (2)
0.47
0.59
Total Piedemonte Region
21.20
23.11
23.76
Andina Oriente Region
Rubiales
94.38
97.98
103.29
Caño Sur
50.75
39.54
31.91
San Francisco
3.12
3.43
Huila Area
4.03
4.19
Tello
4.18
3.93
4.28
8.26
8.94
8.61
Total Andina Oriente Region
164.80
157.54
155.70
Total Crude Oil Assets by Region
445.72
432.56
437.43
Associated Operations
Quifa
11.98
13.38
Caño Limon
19.15
22.44
23.90
18.92
23.91
24.00
Total Associated Operations
50.04
58.82
61.28
Total Ecopetrol S.A. (Colombia)
495.75
491.38
498.71
The Nare fields were included in Associated Operations until November 2021, when the association contract with Mansarovar ended. Starting in November 2021, these fields are reported under the Central Region.
Since 2022, Gibraltar field is included in Table 5 as the ANH’s request to consider condensate as crude oil production and not as natural gas liquids in this field.
Note:The table contains the crude oil production fields according to the new structure of the Company. In addition, they were categorized by regions as follows: (i) Central Region: included fields located in Santander, Antioquia, Norte de Santander and Cesar; (ii) Andina Oriente Region: included fields located in Meta, Huila, and Putumayo; (iii) Piedemonte Region: includes fields located in Casanare and Norte de Santander; and (iv) Orinoquia Region: include fields located in Meta.
24
Table 7 – Ecopetrol S.A. Production per Type of Crude
Year-on-Year
(Mbd)
∆ (%)
Light
21.61
(9.36)
23.84
(1.0)
24.10
Medium
105.02
(8.99)
115.40
(5.3)
121.80
Heavy
369.12
4.82
352.13
(0.2)
352.85
0.89
(1.5)
498.75
Ecopetrol S.A.’s crude oil production in Colombia during 2025 was approximately 75% heavy crudes and 25% light and medium crudes. In 2024, approximately 72% of the crude oil production consisted of heavy crudes, and 28% of the crude oil production consisted of light and medium crudes. In 2023, approximately 71% of the crude oil production consisted of heavy crudes and 29% consisted of light and medium crudes.
Natural Gas Production
In 2025, the average daily production of natural gas by Ecopetrol S.A. (excluding its subsidiaries) reached 102.13 mboed, including natural gas liquids (NGLs), corresponding to a 14% decrease compared to 2024 production. This production was supplied from the following fields: Floreña (33%), Cupiagua (33%), Cusiana (13%), Guajira (7%), and the remaining 14% from other fields.
By the end of December 31, 2025, the Liquefied Petroleum Gas (“LPG”) plant of the Cupiagua field produced 9,189 LPG barrels per day. The plant produces LPG and other products such as natural gas liquids (NGL), and penthane (C5).
25
Table 8 – Ecopetrol S.A.’s Average Daily Natural Gas Production in Colombia
Thousand
bpd
mmcfpd
0.48
2.20
0.46
2.11
0.43
1.99
Provincia
1.13
4.16
1.17
3.67
2.73
1.12
0.24
1.39
0.37
2.13
1.74
9.34
1.84
9.55
1.72
8.90
16.81
3.71
16.72
3.52
15.75
0.13
0.12
0.14
0.29
0.40
0.61
0.41
0.54
Floreña
33.80
173.92
42.58
215.49
42.10
212.04
35.83
155.42
37.71
169.23
41.16
183.87
13.72
67.18
16.99
81.61
113.63
Gibraltar
4.77
27.16
5.70
32.48
5.68
32.41
88.11
423.69
102.98
498.81
112.78
541.95
0.31
0.17
0.33
0.28
0.90
0.69
0.06
0.32
0.07
1.24
0.30
1.35
0.64
0.51
1.89
2.65
Total Gas Assets by Region
92.91
443.00
107.61
517.42
115.36
560.35
Guajira
6.97
39.71
8.57
48.86
9.93
56.62
2.26
8.97
2.08
8.16
1.75
7.24
9.22
48.68
10.65
57.02
11.68
63.86
Total Natural Gas Production (Colombia)
102.13
491.68
118.26
574.44
129.17
624.21
Note:
(i)
Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd. Conversion was done only in respect of natural gas since natural gas liquids cannot be converted into mcfpd. Therefore, when the Company’s natural gas production is measured in boepd, it is higher as that includes natural gas and natural gas liquids. Ecopetrol S.A.’s sales of natural gas liquids represented less than 2.9% of the Ecopetrol S.A.’s consolidated production for the periods presented in this annual report.
(ii)
The table contains the natural gas production fields according to the new structure of the Company. In addition. they were categorized by regions as follows: (i) Central Region: included fields located in Santander, Antioquia, Norte de Santander and Cesar; (ii) Andina Oriente Region: included fields located in Meta, Huila, and Putumayo; (iii) Piedemonte Region: includes fields located in Casanare and Norte de Santander and (iv) Orinoquia Region: Include fields located in Meta.
Projects to Increase Recovery Factor
In 2025, Ecopetrol continued to implement recovery programs to enhance the recovery factor of the fields. By year-end 2025, the fields with secondary and tertiary recovery programs contributed 42% of the Ecopetrol Group’s production.
The recovery programs increased proven reserves by 143 mmboe with an investment of approximately USD 808.4 million distributed among 42 recovery projects, 35 of which correspond to secondary recovery and seven to tertiary recovery.
Development Wells
The following table sets forth the number of gross and net development wells drilled and completed or plugged and abandoned in Colombia, both solely by Ecopetrol S.A. and with its associates, which reached total depth for the years ended December 31, 2025, 2024 and 2023.
Table 9 – Ecopetrol S.A.’s Gross and Net Development Wells in Colombia(1)
Dry
Wells
Gross development wells owned and operated by Ecopetrol
20.0
1.0
23.0
21.0
178.0
181.0
4.0
2.0
Total gross development wells owned and operated in Colombia
222.0
198.0
205.0
6.0
Gross development wells in joint ventures
99.0
128.0
131.0
Net development wells
48.6
0.4
67.2
0.5
79.8
Total gross development wells in joint ventures Ecopetrol S.A. in Colombia (2)
Total net development wells in joint ventures Ecopetrol S.A. in Colombia (3)
Total gross development wells Ecopetrol S.A. in Colombia
321.0
326.0
3.0
336.0
Total net development wells Ecopetrol S.A. in Colombia (3)
270.6
265.2
1.5
284.8
Includes only wells that were drilled and completed or plugged and abandoned
The decrease in the number of wells under joint ventures is related to the acquisition of a 45% stake in CPO09 in 2025. As of 2025, CPO09 is included within owned and operated wells in Colombia.
Net wells correspond to the sum of wells owned and operated by us plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations.
The following tables set forth activities by geographical area, including the number of gross and net wells in the process of being drilled, completed, or waiting on completion for the year ended December 31, 2025.
Table 10 – Ecopetrol S.A.’s Gross and Net In Process Wells
For the year ended December 31, 2025
Drilled
but not
Being
completed
Mobilization
drilled
Gross in process wells owned and operated by Ecopetrol
7.0
5.0
0.0
Total gross in process wells owned and operated in Colombia
8.0
12.0
Gross in process wells in joint ventures
Net in process wells (1)
0.6
Total gross in process wells in joint ventures Ecopetrol S.A.
Total net in process wells in joint ventures Ecopetrol S.A. (1)
Total gross in process wells Ecopetrol S.A. in Colombia
11.0
14.0
Total net in process wells Ecopetrol S.A. in Colombia (1)
6.1
9.5
12.6
27
Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations.
Production Acreage
The following table sets forth Ecopetrol S.A.’s developed and undeveloped gross and net acreage of crude oil and natural gas production in Colombia for the year ended December 31, 2025.
Table 11 – Ecopetrol SA.’s Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production in Colombia
Developed
Undeveloped
Gross
Net (Acres)
435,352
376,131
3,940,804
2,992,223
28
Gross and Net Productive Wells
The following table sets forth Ecopetrol S.A.’s total gross and net productive wells by region for the year ended December 31, 2025.
Table 12 – Ecopetrol S.A.’s Gross and Net Productive Wells by Region (1)(2)
Crude Oil(3)
Natural Gas(4)
Net(5)
3,078
2,559
964
963
1,758
1,752
224
1,595
893
7,619
6,391
53
41
The table reflects the productive wells that directly contribute to hydrocarbon production and therefore excludes wells used for injection, disposal, water abstraction, or other similar activities.
Includes only wells that were drilled and completed.
We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose.
Natural gas wells are those in which operations are directed only toward the production of commercial gas.
Net productive wells are calculated by multiplying gross productive wells by our ownership percentage.
3.5.2.1.2
Ecopetrol S.A.’s Affiliates and Subsidiaries’ Production Activities in Colombia
In 2025, the subsidiaries’ production in Colombia came from Hocol, with a production of 35.3 mboed, which represents 4.7% of the Ecopetrol Group’s total production.
The following table sets forth our average daily crude oil production from Hocol, prior to deducting royalties, for the periods indicated.
Table 13 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Crude Oil Production
Joint venture operation
3.95
3.49
1.77
Direct operation
17.56
14.53
15.25
Total Hocol
21.51
18.02
17.02
Total Average Daily Crude Oil Production (Subsidiaries in Colombia)
The following table sets forth our subsidiaries’ average daily natural gas production, prior to deducting royalties, for the periods indicated.
Table 14 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Natural Gas Production
0.94
5.74
2.62
14.95
17.80
12.83
73.12
14.26
81.29
15.31
87.26
13.77
78.47
16.88
96.24
18.43
105.06
Production Tests
Total Average Daily Gas Production (Subsidiaries in Colombia)
Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd.
The following table sets forth the number of gross and net development wells drilled and completed exclusively by our subsidiaries and in their joint ventures in Colombia for the periods indicated.
Table 15 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Development Wells (1)
Gross development wells owned and operated by Hocol
Net development wells(2)
15.0
Total gross development wells in joint ventures in Colombia
Total net development wells (Subsidiaries in Colombia)(2)
There were no gross and net in process wells drilled and completed exclusively by our subsidiaries and in their joint ventures in Colombia for the year ended December 31, 2025.
30
The following table sets forth our subsidiaries developed and undeveloped gross and net acreage of crude oil and natural gas production in Colombia for the year ended December 31, 2025.
Table 16 – Ecopetrol S.A.’s Subsidiaries in Colombia Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production
Net
(Acres)
64,270.3
40,358.0
49.3
The following table sets forth the expiration dates of material concentrations of the Company’s consolidated undeveloped acreage by geographic area as of December 31, 2025.
Table 17 – Undeveloped Production Acreage as of December 31, 2025 by Expiration Year
2026
2027
2028
2029
2030 and beyond
Ecopetrol S.A.(1)
509,917
Total Colombia
UNITED STATES OF AMERICA
Ecopetrol Permian LLC(2)
2,862
Total United States of America
Inclusive of potentially material areas with an expiration date. Areas which represent more than 5% of the total net undeveloped areas are considered material. Areas that can be developed until their resources are exhausted or until they need to be reverted to their owners, are not included.
Net acres correspond to our share and only include acreage under direct operation by Occidental Petroleum. Non-operated acreage is not included because they are not considered material.
The following table sets forth our subsidiaries’ total gross and net productive wells in Colombia for the year ended December 31, 2025.
Table 18 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Productive Wells(1)(2)
374.0
339.5
46.0
28.9
Total (Subsidiaries in Colombia)
The table reflects productive wells that directly contribute to hydrocarbons production and therefore excludes wells used for injection, disposal, water abstraction or other similar activities.
Natural gas wells are those in which operations are directed only towards the production of commercial gas.
Net wells correspond to the sum of wells entirely owned by us or our subsidiaries and our ownership percentage of wells owned in joint ventures with our partners.
31
3.5.2.2
Production Activities Outside Colombia
In 2025, the subsidiaries’ production outside Colombia came from Ecopetrol America LLC and Ecopetrol Permian LLC. In 2025, the production obtained from these two companies was 112.17 mboed, which represents 15% of the Ecopetrol Group’s total production.
The following table sets forth our average daily crude oil production outside Colombia, prior to deducting royalties, for the periods indicated.
Table 19 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Crude Oil Production
8.29
6.68
5.86
Ecopetrol Permian LLC
55.85
53.69
38.61
Total average daily crude oil production (International)
64.14
60.37
44.47
The following table sets forth our average daily natural gas production outside Colombia, prior to deducting royalties, for the periods indicated.
Table 20 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Natural Gas Production
6.21
0.83
4.73
0.95
5.41
46.94
122.89
40.06
102.34
27.82
70.11
Total average daily natural gas production (International)
48.03
129.10
40.89
107.07
28.77
75.52
Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd. Conversion was done only in respect of natural gas since natural gas liquids cannot be converted into mcfpd. Therefore, when the Company’s natural gas production is measured in boepd, it is higher as that includes natural gas and natural gas liquids. The sales of natural gas liquids by Ecopetrol S.A.’s subsidiaries outside Colombia represented less than 23% of the consolidated production by Ecopetrol S.A.’s subsidiaries outside Colombia for the periods presented in this annual report.
The following table sets forth the number of gross and net development wells outside Colombia, drilled and completed exclusively by us and in joint ventures for the periods indicated.
Table 21 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Development Wells(1)
Number of wells
Gross development wells
0.2
111.0
105.0
58.3
0.9
61.0
67.5
Total gross wells (International)
106.0
113.0
Total net wells (International)(2)
61.2
68.1
Table 22 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net In Process Wells
Gross in process wells
Net in process wells(1)
4.7
Total gross in process wells (International)
Total net in process wells (International)(1)
Includes only wells under direct operation by Occidental Petroleum. Non -operated wells are not included because they are not material.
33
The following table sets forth our developed and undeveloped gross and net acreage of crude oil and natural gas production outside Colombia for the year ended December 31, 2025.
Table 23 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production
56,420
14,772
Ecopetrol Permian LLC(1)
56,983
44,193
3,021
Total (International)
113,403
58,965
Inclusive of acreage held by production.
The following table sets forth our total gross and net productive wells outside Colombia for the year ended December 31, 2025.
Table 24 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Productive Wells(1)
For the year ended
December 31, 2025
Crude Oil
10.00
5.15
531.00
288.03
541.00
293.18
3.5.2.3
Unconventional Hydrocarbons
On February 28, 2020, the Colombian Government, issued the Decree 328, providing the general guidelines for developing Integral Research Pilot Projects (PPIIs), followed by the issuance of corresponding environmental technical and social regulation by other Ministries to allow PPIIs to be performed. Furthermore, on December 24, 2020, Ecopetrol S.A. signed a Special Contract for Research Projects (Contrato Especial de Proyectos de Investigación, or “CEPI” for its acronym in Spanish) with the ANH regarding the development of a PPII, entitled Kalé. On June 4, 2021, Exxon Mobil Colombia signed a contract for the development of a PPII located near Ecopetrol S.A.’s PPII area, named Platero. On June 17, 2021, Exxon Mobil and Ecopetrol S.A. signed a consortium to jointly develop both PPIIs, in which Ecopetrol S.A. is the consortium operator.
On 2022, the Government of Colombia (Ministry of Mines and Energy and Ministry of Environment and Sustainable Development) announced a change in the energy policy of the country, according to which it seeks to prohibit activities related to the application of the technique known as “fracking”, including the prohibition of the Integral Research Pilot Projects PPII which were being executed through the referred CEPIs. In connection with said new policy, on September 9, 2022, Ecopetrol S.A and ExxonMobil requested to the ANH the suspension of the CEPIs.
On September 23, 2022, Ecopetrol S.A. filed a request for the suspension of the environmental obligations of Resolutions 00648 of March 25, 2022, and 01283 of June 10, 2022 before the National Authority of Environmental Licenses (“ANLA” for its acronym in Spanish), relating to the environmental license for the PPII Kalé. On September 29, 2022, the ANLA accepted Ecopetrol’s request and suspended such environmental obligations relating to the environmental license for PPII Kalé.
On November 4, 2022, in response to the request for suspension of the CEPIs filed on September 9, 2022, the ANH published Agreement 009, through which it was authorized to amend Clause 55 of the CEPIs, to allow for the suspension by mutual agreement of such contracts.
On December 28, 2022, the CEPI Kalé was formally amended to allow for its suspension by mutual agreement, as authorized by Agreement 009 of November 4, 2022, and was extended by Suspension Agreement No. 2 on October 4, 2023.
After failed attempt with bills proposed in 2022 and 2024, a new bill to prohibit fracking was proposed to the legislative branch in 2025. Ecopetrol is currently awaiting the outcome of the legislative process in the Colombian Congress regarding such bill.
For more information see Applicable Laws and Regulations and Risk Factors – Risks Related to Our Operations.
In addition, in connection with Ecopetrol’s unconventional resources strategy outside Colombia, in 2019 we formed a joint venture (JV) with Occidental Petroleum Corp. (“Occidental Petroleum”) for the development of approximately 97,000 acres in the Midland Basin, within the Permian Basin, Texas, by which we acquired 49% of Rodeo Midland Basin LLC (“Rodeo JV”).
See section Business Overview—Exploration and Production—Production Activities—Production Activities Outside Colombia.
As of January 1, 2022, the Rodeo JV agreement with the Company and Occidental Petroleum was amended to provide Ecopetrol access to a larger production stake (75%) and adjust the carry obligation in the Midland area of the Permian Basin. On June 17, 2022, Ecopetrol Permian LLC (a subsidiary of Ecopetrol) signed a Joint Development Agreement with certain Occidental Petroleum subsidiaries to conduct drilling and production programs from 2022 to 2027, in an area of approximately 21,000 acres located in Permian Basin. The agreement allowed Ecopetrol to expand its presence in Permian with an approximately 49% interest stake of drilling and production programs in this area. On September 11, 2023, Ecopetrol announced certain adjustments to its 2040 Strategy, including that unconventional hydrocarbon exploration activities will not be pursued in Colombia, among other updates.
See section 2040 Strategy: Energy That Transforms.
On February 3, 2025, Ecopetrol and Oxy announced they reached an agreement to extend the Midland development plan, in the Permian Basin, until June 2026. Prior to the expiration of that term, on February 13, 2026, Ecopetrol and Oxy agreed to further extend the development plan in the Midland sub-basin, in the Permian area (Texas, United States) that includes the drilling of 39 development wells that will be executed between July 2026 and July 2027, with an estimated investment of USD 235 million, under the joint venture established in July 2019. The agreement allows the partners to evaluate a potential future extension of the development plan, depending on macroeconomic conditions, industry dynamics, and the interests of the partners. The activity covered by this agreement, together with the wells currently under execution, represents an estimated investment plan for Ecopetrol Permian of approximately USD 300 million in 2026, and an average production range (before royalties) of 75 to 78 mboed for the year. Ecopetrol and Oxy expect to keep the Joint Development Agreement (JDA) for the development of the Delaware subbasin active, which is expected to remain in place until July 2027.
For more information, see section Business Overview—Applicable Laws and Regulations and section Risk Review—Risk Factors—Risks Related to Our Business.
3.5.2.4
Marketing of Crude Oil and Natural Gas
In 2025, we sold 970.5 mboed, out of which 456.8 mboed represented sales of fuels and petrochemicals (47%), 429.1 mboed represented sales of crude oil (44%), and 84.6 mboed sales of natural gas (9%).
Crude Oil Export Sales
In 2025, crude oil export sales totaled 429.1 mboed and decreased by 16.8 mboed compared to 2024, mainly due to lower purchases of crude oil from third parties (15 mboed), which reduced the volumes available for export as a greater share of own production was directed to supply the refineries’ crude diet. Our crude oil export sales are traded both in the spot and contract markets, primarily to refiners in Asia and the United States.
The Castilla blend is the main type of crude oil for export sales, with 237 mboed sold during 2025 (a 55% share of the crude oil basket) followed by the Apiay blend with 74.9 mboed (a 17% share of the crude oil basket), the Mares blend with 29.6 mboed (a 7% share of the crude oil basket) and the domestic crudes from Ecopetrol Permian LLC with 41.7 mboed (a 10% share of the crude oil basket).
We distribute our exports to markets that offer the best value for crude oil. In 2025, the Asian market was the primary destination, accounting for 50% of crude oil exports, followed by the United States market at 45%. Colombian crude oil flows to Asia were driven by above-average refining runs over the past five years, primarily in China, as well as increased crude oil demand from India. The United States maintained its appetite for our heavy crude oils to maximize margins at its complex refineries.
Moreover, volatility in the production of regional competitors has given refiners in the United States, India, and other markets an incentive to diversify their supply sources, which in turn has opened opportunities for Colombian producers. Our crude basket realization price decreased by USD 9.7/Bl year over year, due to market conditions.
Crude Oil Purchase Contracts
We have signed several crude oil purchase contracts with third parties and business partners. We also purchased the country’s crude oil royalties from the ANH. These crudes are processed in our refineries or exported. The purchase price is referenced to export parity based on international market prices, plus a commercial fee. See section Business Overview—Related Party and Intercompany Transactions.
The table below sets forth the volumes of crude oil purchased from our business partners and third parties and volumes of crude oil purchased from the ANH from royalties for the years ended on December 31, 2025, 2024 and 2023.
Table 25 – Ecopetrol Consolidated Crude Oil Purchases
(Million barrels)
Crude oil purchased from ANH royalties
31.4
35.5
32.1
Crude oil purchased from third parties
36.3
42.7
Crude oil imported from third parties
21.8
16.8
During 2025, part of our crude strategy was centered on increasing the purchase and subsequent commercialization of crude oil from third parties, which enables further optimization of the supply chain and margin capture.
Imports of Diluents
In 2025, we increased the imports of diluent by 6% (1.7 mboed) compared to 2024, due to higher crude sales. Diluent is used to transport heavy crudes through the pipeline system.
Natural Gas Sales
We sell natural gas to distribution companies through firm, interruptible and conditional contracts. These distributors supply natural gas to the residential market, as compressed natural gas for vehicles market and to large industrials in Colombia. We also market and sell natural gas directly to the industrial sector and to gas-fired power plants.
Our natural gas sales and self-consumption in 2025 decreased by 12.5% (-14.82 mboed) compared to 2024, mainly due to the decrease in production from large fields and external events that affected production (-17.8 mboed), which was partially offset by the increase in the Permian and Ecopetrol America LLC sales. (+3.0 mboed).
Gas Supply
36
Ecopetrol has structured a strategy to address the decline in national gas production over the next 15 years. In a first phase (2026–2030), the focus is on short- and medium-term solutions to meet demand through imported gas via the Caribbean and Pacific coasts. Ecopetrol expects to procure LNG on the international market, in accordance with applicable regulations and internal governance policies. In this context, in August 2025, eighteen (18) firm contracts subject to conditions were executed for the commercialization of 60 GBtud of imported natural gas through Buga, located in Valle del Cauca in southwestern Colombia, following the contracting of regasification capacity in February 2025.
In a second phase (2030–2040), supply will be supported by the development of organic offshore and onshore gas production. Accordingly, in December 2025, Ecopetrol and Petrobras successfully concluded the commercialization process for gas from the Sirius field, achieving the sale of 100% of the offered volumes (up to 249 MMscfd) through the execution of 66 firm contracts subject to conditions with 17 agents, for a period of up to six years starting in 2030.
Natural Gas Delivery Commitments
The table below sets forth the commitments we have in Colombia under firm contracts with local natural gas distribution companies, local industries, gas-fired power generators and internal agreements with our refineries and fields.
Table 26 – Ecopetrol Consolidated Natural Gas Delivery Commitments
(GBtud)
Volume for sales third parties
227.52
203.40
115.10
59.05
Volume for self-consumption
142.81
154.80
154.35
150.24
Volume for intercompany sales
76.20
86.71
77.24
Total Commitments
440.44
434.40
356.16
286.53
The table above is based on current contracts of Ecopetrol S.A. and the official report made to the Ministry of Mines and Energy in 2025. Self-consumption volumes decreased over time as a result of more efficient operations in our refineries. Third party volumes do not include potential production coming from exploration projects. According to current regulations, these volumes will be committed and commercialized after declaring exploratory success.
3.5.3
Reserves
The reserves reporting process was conducted in accordance with SEC definitions and rules set forth in Rule 4-10(a) of Regulation S-X and the disclosure guidelines contained in the SEC’s Modernization of oil and gas reporting final rule dated December 31, 2008, and effective as of January 1, 2010.
The estimated reserve amounts presented in this annual report, as of December 31, 2025, are based on the average price during the 12-month period prior to the ending date of the period covered in this annual report, determined as the unweighted arithmetic averages of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. For 2025, the average ICE Brent price was USD 68.64/Bl.
Our crude oil and natural gas net proved reserves include reserves from Ecopetrol S.A. and our subsidiaries located in the United States, and from Hocol’s assets in Colombia.
Estimated Net Proved Reserves
The following table sets forth our estimated net proved developed reserves of crude oil and gas by region for the years ended December 31, 2025, 2024 and 2023.
Table 27 – Net Proved Developed Reserves
North
Colombia
America
Net Proved Developed oil reserves in million barrels oil equivalent
As of December 31, 2025
1,076.2
66.0
1,142.2
As of December 31, 2024
971.9
56.5
1,028.9
As of December 31, 2023
969.2
56.8
1,026.0
Net Proved Developed NGL reserves in million barrels oil equivalent
30.4
31.7
62.1
33.4
25.4
58.8
37.3
19.4
56.7
Net Proved Developed gas reserves in billion standard cubic feet
1,375.1
163.4
1,538.5
1,622.4
127.6
1,750
1,906.4
100.9
2,007.3
Net Proved Developed oil, NGL and gas reserves in million barrels oil equivalent
1,347.8
126.4
1,474.2
1,289.9
104.3
1,394.2
1,341.0
93.9
1,434.9
Note: Totals may not exactly equal the sum of the individual entries due to rounding.
The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
We are required, as are all oil companies undertaking exploratory and production activities in Colombia, to pay a percentage of our production to the Government as royalties, in cash or in-kind. The ANH’s Resolution 877 of 2013 as amended by Resolution 640 of 2014 and Resolution 165 of 2015 require natural gas royalties to be paid in cash. The main producing gas fields are Cupiagua, Pauto, Cusiana, Chuchupa and Cupiagua Sur. Similarly, in 2025, the ANH’s Resolution 0977 was published, requiring that oil royalties for the CP09, Caño Sur, Cubarral, Rubiales, and Magdalena Medio–Yarigui Cantagallo Contracts be paid in cash. These resolutions have the effect of determining the amount to be paid in royalties, based on property rights to the total volume of natural gas or oil produced, without deductions on account of royalties.
Ecopetrol S.A. owns 100% of Cenit, a subsidiary that operates in Colombia and is dedicated to the storage and transportation of hydrocarbons through pipelines and of refined products through multipurpose pipelines. Cenit provides transportation services for the entire Ecopetrol Group, and Cenit is fully consolidated into our consolidated results of operations. Therefore, the difference between the tariffs set by the Ministry of Mines and Energy and the real transportation costs (fixed and variable operating expenses) does not affect our consolidated income statement. Thus, in presenting our reserves information in the 2023, 2024 and 2025 annual reports, we have used our real transportation costs, rather than the regular tariffs set by the Ministry of Mines and Energy.
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 19 million barrels of fuel oil, 238.0 billion standard cubic feet of fuel gas within our natural gas results, 219.9 billion cubic feet of gas royalties, and 95.8 million barrels of oil royalties, as of December 31, 2025. Of the total of 126.4 mmboe of proved developed reserves within North America, 114.6 mmboe corresponds to unconventional reservoirs within the Permian Basin, and 11.8 mmboe correspond to Gulf of Mexico (aka Gulf of America) fields. Moreover, of the total of 56.8 mmboe of proved undeveloped reserves within North America, 55 mmboe corresponds to unconventional reservoirs within the Permian Basin, and 1.8 mmboe corresponds to Gulf of Mexico (aka Gulf of America) fields.
38
Table 28 – Proved Oil, NGL and Natural Gas Reserves for 2025
Natural
Total Oil
NGL
Gas
and Gas
Oil (mmb)
(mmb)
(bcf)
(mmboe)
PROVED DEVELOPED RESERVES
International
North America
South America
TOTAL PROVED DEVELOPED RESERVES
PROVED UNDEVELOPED RESERVES
385.7
4.4
132.0
413.3
25.1
16.9
84.2
TOTAL PROVED UNDEVELOPED RESERVES
410.8
21.3
216.2
470.1
TOTAL PROVED RESERVES
1,553.0
83.4
1,754.7
1,944.3
Note: Totals may not exactly equal the sum of the individual entries due to rounding. The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 19.96 million barrels of fuel oil, 235.5 billion standard cubic feet of fuel gas within our natural gas results and 276.8 billion cubic feet of royalties, as of December 31, 2024.
Table 29 – Proved Oil, NGL and Natural Gas Reserves for 2024
Natural Gas
Total Oil and
Gas (mmboe)
1,028.4
1,750.0
353.6
231.5
398.9
46.8
29.3
134.0
99.6
400.4
34.0
365.5
498.5
1,428.8
92.8
2,115.5
1,892.7
39
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 17.9 million barrels of fuel oil, 281.5 billion standard cubic feet of fuel gas within our natural gas results and 304.9 billion cubic feet of royalties, as of December 31, 2023.
Table 30 – Proved Oil, NGL and Natural Gas Reserves for 2023
282.7
6.4
221.7
328.0
75.4
24.0
116.8
119.9
358.1
338.6
447.9
1,384.2
87.1
2,345.9
1,882.8
Changes in Proved Reserves
Table 31 – Changes in Proved Reserves
(Mmboe)
Revisions of previous estimates
140.8
84.4
8.9
Improved Recovery
142.6
97.0
93.1
Extensions and discoveries
16.1
49.2
17.2
Purchases
35.4
Sales
(6.3)
Total reserves additions
299.5
259.6
119.3
Production
(248.0)
(249.7)
(247.5)
Net change in proved reserves
51.6
10.0
(128.2)
Reserves Replacement
The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves divided by produced volumes in any given period. The following table presents the changes in reserves in each category relating to the reserve replacement ratio for the years 2025, 2024 and 2023.
The reserves replacement ratio for 2025 was 121% compared to 104% in 2024 and 48% in 2023.
The average replacement ratio for the last three years was 91%.
40
Table 32 – Reserves Replacement Ratio (Including Purchases and Sales)
Annual
Three-year average
91
85
117
Revisions of Previous Estimates
In 2025, revisions increased reserves by 140.8 million boe, mainly as a result of:
As discussed above, beginning on January 1, 2026, the oil royalties for the CP09, Caño Sur, Cubarral, Rubiales, and Magdalena Medio–Yarigui Cantagallo Contracts are to be paid in cash, therefore they are considered a financial obligation and are no longer deducted from net reserves. As a result, reported reserves increased by 95.8 million boe in 2025.
An increase of 4.5 mmboe as a result of the agreement executed by and among ANH and Ecopetrol in 2025, by means of which it was agreed that the payments related to the E&P Campos Tello y la Jagua for the oil and gas produced from the Tello and La Jagua fields are to be paid in cash, and therefore, included in reserves pursuant to applicable legislation.
(iii)
New development projects in Caño Sur, Akacias, Rubiales, Lisama, Yarigui and Palagua fields resulted in a 32.4 million boe increase in reserves.
(iv)
An increase of 38.6 mmboe in reserves due to better performance in development activities in existing fields, including the La Cira- Infantas, Pauto, Quifa, Rubiales and Nare Area fields.
(v)
A decrease of 33.7 mmboe in reserves due to depletion of gas fields including Gibraltar, Chuchupa, Cupiagua, Recetor and Cusiana.
(vi)
A reserve growth of 3.2 mmboe, resulted from development efforts and strong well performance in other fields.
In 2024, revisions increased reserves by 84.4 mmboe, mainly as a result of:
An increase of 51.5 mmboe in reserves due to better performance in development activities in existing fields, including the Caño Sur, Chichimene, Castilla, Pauto, La Cira- Infantas, Apiay-Suria, Caño Limon, Palagua and Nare Area fields, among others.
A decrease of 36 mmboe in reserves due to depletion of gas fields including Ballena, Chuchupa, Cupiagua and Gibraltar among others.
An increase of 15.7 mmboe in reserves due to new projects mainly in the Palogrande and Cupiagua fields.
An increase 14.4 mmboe as a result of the agreement executed by and among ANH and Ecopetrol in 2024, by means of which it was agreed that the payments related to the E&P Contract CPO-9 for the oil and gas produced from the Akacias field are to be paid in cash, and therefore, included in reserves pursuant to applicable legislation.
An increase of 30.9 mmboe in reserves due to better performance in North American fields.
7.9 mmboe, increase in reserves was due to varying increases due to development activities and good well performance in other fields.
In 2023, revisions increased reserves by 9 mmboe, mainly as a result of:
An increase of 67 mmboe in reserves due to new projects and better performance in development activities in different fields; mainly in the Rubiales, Castilla Asset and Caño Sur fields.
A decrease of 58 mmboe, due to economic factors, primarily the decrease in oil prices, and the ICE Brent crude price decreasing by 15.5% in 2023 as compared to 2022, which resulted in the lowering of economic limits in some of our fields and an increase of operating costs.
In 2025, improved recovery activities boosted reserves by 142.6 million boe. This growth primarily resulted from the identification of new proved areas through water flooding in fields such as Castilla, Akacias, Chichimene, Suria, Apiay, and La Cira-Infantas, as well as from optimizing gas injection at the Pauto and Floreña fields.
In 2024, improved recovery activities increased reserves by 97 mmboe. This increase was mainly associated with new proved areas under water flooding in the Chichimene, Akacias, Castilla, Suria, Yarigui, Casabe and La Cira- Infantas fields among others, and optimization of the gas injection of the Pauto and Floreña fields.
In 2023, improved recovery activities increased reserves by 93 mmboe, mainly due to new proved areas under water flooding in the Chichimene Asset, Castilla Asset and Akacias fields.
Extensions and Discoveries
The following table sets forth the change in the Company’s proved reserves attributed to extensions and discoveries in millions of barrels of oil equivalent for the periods indicated.
Table 33 – Changes in Proved Reserves Attributed to Extensions and Discoveries
Total change
Proved Undeveloped Reserves Change
39.7
10.4
Change from unproved to proved developed reserves
12.7
9.4
6.8
The difference between the change of developed proved reserves and undeveloped proved reserves is related to the drilling of new wells on an unproved acreage that led to new proved producing reserves.
The Company’s extensions and discoveries during 2025 amounted to 16.1 mmboe, primarily due to extensions of proved acreage, which in turn were mainly from activities in newly proved areas in Ecopetrol Permian fields, which accounted for 11.6 mmboe of the increase. The remaining 3.1 mmboe corresponds to small changes in different fields and 1.41 million in newly discovered reservoirs in Loma Larga and Arauca fields and Lorito as new field.
The Company’s extensions and discoveries during 2024 amounted to 49.2 mmboe, primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales and Caño Sur fields, among others, which accounted for 34.8 mmboe of the increase. The remaining 14.4 mmboe corresponds to 6.1 million in small changes in different fields and 8.3 million in newly discovered fields (Arrecife, Saltador and Toritos fields).
The Company’s extensions and discoveries during 2023 amounted to 17.2 mmboe, primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Caño Sur y Cohembi fields, among others, which accounted for 13.5 mmboe of the increase. The remaining 3 mmboe corresponds to 1.8 million in small changes in four fields and 1.9 million in newly discovered fields and reservoirs in the Alqamari, Flamencos and Ibamaca fields.
In 2025, there were no purchases or acquisitions of reserves.
42
In 2024, Ecopetrol acquired the remaining 45% of its participation in the CPO-09 Block of Repsol Colombia Oil & Gas Limited (“Repsol”), for an amount of USD 452 million, making it the holder of 100% of the participation interest in the block, a strategic asset in the Piedemonte Llanero. This transaction is the result of the exercise of the right of first refusal by Ecopetrol, within the framework of the Joint Operation Agreement (JOA). This purchase increased Ecopetrol’s proved reserves by 31.7 mmboe.
Additionally, Ecopetrol S.A., through its wholly owned subsidiary, Ecopetrol Permian LLC, and acting within the joint venture with Occidental Midland Basin LLC, purchased additional acreage of 5,840 acres net to the joint venture that extended the South Curtis Ranch Field area in the Midland Basin. This purchase increased Ecopetrol’s proved reserves by 3.7 mmboe.
In 2023, there were no purchases or acquisitions of reserves.
In 2025, there were no sales of reserves.
In 2024, Ecopetrol S.A., through its wholly owned subsidiary, Ecopetrol Permian LLC, and acting within the joint venture with Occidental Midland Basin LLC, sold all acreage of 4,967 acres net to the joint venture that comprised the Saint Andrews field area. The result of the sale reduced Ecopetrol’s proved reserves by 6.3 mmboe.
In 2023, there were no sales of reserves.
Development of Reserves
As of December 31, 2025, our total proved undeveloped oil and gas reserves amounted to 470.1 mmboe, 81% of which is related to development activities at the Rubiales, Caño Sur Este, Akacias, Castilla Asset, Chichimene Asset, Pauto, Palogrande, Quifa, Floreña, La Cira, Infantas and Suria in Colombia, among others, and 12.1% of which is related to development activities in North American fields; which is broken down as follows: 96.8% corresponding to unconventional reservoirs within Permian and Delaware basins and the other 3.2% corresponding to Gulf of Mexico (aka Gulf of America) fields.
As of December 31, 2024, our total proved undeveloped oil and gas reserves amounted to 498.5 mmboe, 80% of which is related to development activities at the Rubiales, Caño Sur Este, Akacias, Castilla Asset, Chichimene Asset, Pauto, Palogrande, Quifa, Floreña and Suria in Colombia, among others, and 20% of which is related to development activities in North American fields; which is broken down as follows: 95% corresponding to unconventional reservoirs within Permian and Delaware basins and the other 5% corresponding to Gulf of Mexico (aka Gulf of America) fields.
As of December 31, 2023, our total proved undeveloped oil and gas reserves amounted to 447.9 mmboe, 73% of which was related to development activities at the Rubiales, Castilla Asset, Chichimene Asset, Caño Sur Este, Pauto, Cupiagua, Recetor, Akacias, Quifa and La Cira fields in Colombia, among others, and 27% of which was related to development activities in North American fields; which is broken down as follows: 25% corresponding to unconventional reservoirs within Permian and Delaware basins and the other 2% corresponding to Gulf of Mexico (aka Gulf of America) fields. The proved undeveloped reserves estimated for the Rubiales, and Caño Sur Este fields included locations with production start dates that extend beyond the five-year initial disclosure period and were associated with the water-handling capacities in these fields. Similarly, the development plan of La Cira and Infantas fields includes investments beyond the next five years, because the current waterflooding project requires the drilling of new injector wells and beginning the water injection before drilling of producers in the same pattern. These exemptions were reviewed and approved by an external certification agent.
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The following table reflects the developed and undeveloped proved reserves estimates through the past three fiscal years.
Table 34 – Developed and Undeveloped Proved Reserves
2025 Proved Reserves
2024 Proved Reserves
2023 Proved Reserves
Changes in Undeveloped Proved Reserves
The following table reflects the main changes in undeveloped proved reserves as of December 31, 2025, 2024, and 2023.
Table 35 – Changes in Undeveloped Proved Reserves
Consolidated companies
29.5
41.3
(91.1)
65.0
75.9
22.8
16.5
Proved undeveloped converted to proved developed
(126.2)
(116.6)
(129.0)
Net change in unproved reserves
(28.4)
50.5
(186.9)
Totals may not exactly equal the sum of the individual entries due to rounding.
Of the total amount of proved undeveloped reserves that we had at the end of 2024 (498.5 mmboe), we converted approximately 126.2 mmboe, or 25%, to proven developed reserves during 2025. Approximately 71% of the total conversion is mainly associated with the development of crude oil and gas projects in Caño Sur, Rubiales, Akacias, Castilla, Chichimene Arrecife and Pauto, among others, and 29% is associated with development execution in fields in the United States, 100% of the total volume within United States corresponds to unconventional fields within the Permian and Delaware basins. Investments made during 2025 to convert proved undeveloped reserves to proved developed reserves totaled USD 1,031 million in cash.
Of the total amount of proved undeveloped reserves that we had at the end of 2023 (447.9 mmboe), we converted approximately 116.6 mmboe, or 26%, to proven developed reserves during 2024. Approximately 73% of the total conversion is mainly associated with the development of crude oil and gas projects in Caño Sur, Rubiales, Castilla, Chichimene Cupiagua and Pauto, among others, and 27% is associated with development execution in fields in the United States, 100% of the total volume within United States corresponds to unconventional fields within the Permian and Delaware basins. Investments made during 2024 to convert proved undeveloped reserves to proved developed reserves totaled USD 1,145 million in cash.
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Of the total amount of proved undeveloped reserves that we had at the end of 2022 (635 mmboe), we converted approximately 129 mmboe, or 20%, to proven developed reserves during 2023. Approximately 73.6% of the total conversion is mainly associated with the development of crude oil and gas projects in Castilla Asset, Chichimene Asset, Rubiales, Caño Sur Este and Pauto fields, among others, and 26.4% is associated with development execution in fields in the United States, which in turn is broken down as follows: 25.9% of the total volume within United States corresponds to unconventional fields within the Permian and Delaware basins and 0.5% corresponds to Gulf of Mexico (aka Gulf of America) fields. Investments made during 2023 to convert proved undeveloped reserves to proved developed reserves totaled USD 1,498 million in cash.
All the explanations that were included in the section on Changes in Proved Reserves apply to this section.
Reserves Process
The Ecopetrol Group follows international standards for estimating, classifying, and reporting reserves, as defined in SEC regulation. Our reserves process is coordinated by Fidel Antonio Delgado Loría, the Resources and Reserves Manager. Mr. Delgado Loría is a Petroleum Engineer with over 20 years of experience in the upstream sector of production business in the Ecopetrol Group and other companies in the oil and gas industry in Colombia and Venezuela. He holds his engineering degree from Universidad Central de Venezuela and a Financial Management Specialist degree from Pontificia Universidad Javeriana. He reports to the Hydrocarbon Chief Financial Officer. In addition, our reserves team is comprised of reserves coordinators who are geologists and petroleum engineers, each of them with more than 15 years of experience in reservoir characterization, field development, estimation, and reporting of reserves by SEC guidelines. This team supports and interacts with the specialists involved in the estimation and reporting process, following an established procedure with its corresponding internal controls. As in previous years, reserves are estimated and certified by recognized external independent engineers, this year consisting of DeGolyer and MacNaughton, GaffneyCline, and Ryder Scott Company, in compliance with the definitions of the Society of Petroleum Engineers and the applicable SEC rules. According to our corporate policy, we report the values of the reserves obtained from the external engineers, even if they are lower than our expected reserves.
The reserves estimation process ends when the Resources and Reserves Manager consolidates the results and together, with the Exploration, Development and Production Vice-President, presents the outcome to the Resources and Reserves Committee, which comprises the Ecopetrol Group’s CEO, CFO, Hydrocarbons Executive Vice-president and the Exploration, Development and Production Vice-President among others. Results are later presented to the audit and risk committee of the Board of Directors and finally reviewed and approved by the Board of Directors.
The Resources and Reserves unit, and the Exploration, Development and Production Vice-presidency presented the reserves balance to the Board of Directors, who approved it in February 2026. The aforementioned external independent engineering consultants have estimated and certified our proved reserves as of December 31, 2025. These external engineers estimated 99% of our estimated net proved reserves for the year ended December 31, 2025, 2024 and 2023. In accordance with these certifications, our reserves report complies with Rule 4-10 of Regulation S-X issued by the SEC. The reserves’ reports of the external engineers are included as exhibits to this annual report.
Our reserves process uses deterministic methods which are commonly used internationally to estimate reserves. These methods whilst reliable, have some inherent uncertainty, and thus, estimates should not be interpreted as exact amounts. Most of the producing proved reserves were estimated by applying appropriate decline curves or other performance relationships. In analyzing decline curves, reserves were estimated by calculating economic limits that are based on current economic conditions. In certain cases where the methods previously employed could not be used, reserves were estimated by analogy with similar reserves for which more complete data was available.
Estimates of reserves were prepared by geological and engineering standard methods commonly used in the oil and gas industry. The method or combination of methods used in the analysis of each reserve was adopted from experience analogy reserves, including information on the stage of development, quality and completeness of basic data and production history.
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The following table reflects the estimated proved reserves of oil and gas as of December 31, 2023, 2024 and 2025, and the changes among such dates.
Table 36 – Estimated Proved Reserves of Oil and Gas
excluding
Net proved oil, NGL and gas reserves in mmboe
At December 31, 2023
1,669.0
213.8
Revisions
63.3
21.1
3.7
(221.5)
(28.3)
At December 31, 2024
1,688.7
204.0
142.2
(1.4)
4.5
11.6
(216.9)
(31.1)
At December 31, 2025
1,761.1
183.1
For more information regarding the potential impacts of oil prices on our reserve estimates, see the sections Financial Review—Trend Analysis and Sensitivity Analysis and Risk Review—Risk Factors.
3.5.4
Joint Venture and Other Contractual Arrangements
We conduct our exploration and production segment through a variety of contractual arrangements with the Colombian Government or with third parties. Below is a general description of the main types of contractual arrangements to which we were a party as of December 31, 2025. For additional information, see Section 4.3.2 – Joint Ventures of the consolidated financial statements.
Association Contracts
Association contracts were introduced by Decree 2310 of 1974, as amended, and were entered into between private companies and Ecopetrol between 1975 and 2003. Through an association contract, Ecopetrol partners with a petroleum company or a consortium to explore and, upon successful discovery, exploit the found oil and gas resources. An operator is defined among them or hired as a third party.
Every association contract has specific terms and conditions for specific issues. This section will describe the common terms and conditions agreed in the association contracts. Under association contracts, the exploratory risk is entirely assumed by Ecopetrol S.A.’s contractual partner, the associate. If there is a discovery and Ecopetrol S.A. agrees that the relevant field is commercially viable, Ecopetrol S.A. intends to participate in the field’s development. A joint account is expected to be created, and Ecopetrol S.A. and the partner plan to participate in the expenses and investments in the proportions established in the corresponding contract. Ecopetrol S.A. intends to reimburse the direct exploratory expenses incurred by the contractual partner in the proportions established by the contract.
If Ecopetrol S.A. does not believe that the relevant field is commercially viable, the partner has the right to execute on its own all activities considered necessary for the field’s exploitation as a “sole risk operation”, and to be reimbursed for a defined percentage of all investments for such sole risk operation in accordance with the corresponding contract, if specific terms and conditions are complied with by Ecopetrol.
Every association contract provides for an executive committee that makes all technical, financial, and operational decisions if Ecopetrol S.A. has agreed that a field is commercially viable. All major decisions of this committee must be made unanimously.
The maximum term of an association contract is 28 years. The first six years of the contract are for the exploratory phase, which may be extended for one or two additional years at the partner’s request. The remaining time is for the exploitation phase. This type of contract, together with E&P contracts and special contracts (La Cira-Infantas and Teca-Cocorná fields), both of which are described below, are the most significant in terms of our production and proved reserves. According to CONPES Document 3245 of 2003, Ecopetrol has the possibility to evaluate the extension of the original term of an association contract. Under this framework, Ecopetrol may pursue an extension to better serve its economic interests instead of abandoning the asset or directly operating the oil and gas asset.
Incremental Production Contracts
We enter into incremental production contracts to obtain additional hydrocarbon production beyond a base production curve that is established based on the proven reserves of a specific field or well, originating from contracts entered into by Ecopetrol with third parties or from projects undertaken by Ecopetrol. This incremental production results from new investments to increase the recovery factor of reservoirs or to add new reserves. Therefore, under this type of arrangement, Ecopetrol S.A. owns 100% of the hydrocarbons defined by the base production curve. The incremental production (i.e., the hydrocarbon volume obtained beyond the basic production as a result of investment activities), is expected to be owned by the contract parties in the proportions established by such contract.
The initial phase of an incremental production contract has a term of up to three years, in which the contractual partner executes an initial work program approved by Ecopetrol S.A. in order to gain the right (but not the obligation) to continue with the second phase. If our partner decides to continue with the project for the second phase (the complementary phase), it must inform Ecopetrol S.A. in writing no later than 90 days prior to the termination date of the initial phase and deliver a proposed development plan for each covered field. The second phase is the production phase and has a maximum term of 22 years, minus the length of the initial phase.
Incremental production contracts provide for an executive committee that is responsible for making all decisions in order to approve, control and supervise all operations that take place during the duration of the contract. These contracts also provide for a steering committee, which is responsible for the supervision of the execution of the work programs, the 2026 Investment Plan, and other items.
Special Contracts
We are party to a joint venture for exploration and exploitation of “La Cira-Infantas” Area and of “Teca-Cocorná” Area.
These contracts between Ecopetrol S.A. and SierraCol Energy, formerly known as Occidental Andina LLC, which were executed on September 6, 2005, and June 24, 2014, respectively, have as their purpose, a joint collaboration between the parties with the goal of increasing the economic value of the La Cira-Infantas and the Teca-Cocorná fields, by means of hydrocarbon exploration and production activities, including, among others, an incremental production project to improve the recovery factor, process optimization, and exploratory activities.
Ecopetrol S.A. partially assigned its exploratory and production rights in the contracted areas to SierraCol Energy. Additionally, pursuant to these contracts, Ecopetrol S.A. provides financial resources and the preferential rights of use for the existing infrastructure in that zone and SierraCol Energy provides financial resources and the technical and operative experience in mature fields redevelopment projects and enhanced recovery technologies.
Ecopetrol S.A. is the operator under both joint ventures, and, on behalf of the parties, is responsible for the conduction, execution, and control, directly or via contractors, of the operational activities.
The La Cira-Infantas joint venture is divided into three phases. The first phase lasted 180 days, the second lasted 730 days, and the third phase lasts up to the date on which the field reaches its commercial viability.
The incremental production, after deduction of the royalties, is owned 52% by Ecopetrol S.A. and 48% by SierraCol Energy. These same percentages apply to the participation in the operational and direct expenses. Adjustments to the participations for the benefit of Ecopetrol S.A. are expected to occur if there are high production levels or high prices.
The Teca-Cocorná joint venture is divided into two phases. The first phase lasted three years and was extended for an additional year until 2018; the second term is 20 years and could be reduced by the term of any extensions of the first phase.
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The basic production is 100% owned by Ecopetrol S.A. The incremental production, after deduction of the royalties, is owned 60% by Ecopetrol S.A. and 40% by SierraCol Energy. These same percentages apply to the participation in the operational and direct expenses. Adjustments to the participations for the benefit of Ecopetrol S.A. is expected to occur if there are high production levels and high prices.
The Teca- Cocorná Business Collaboration Agreement was mutually terminated by the parties on April 25, 2025, due to external circumstances that prevented the project’s completion. As of that date, Ecopetrol S.A is the sole holder of the Hydrocarbon Exploitation Convenio for the Teca- Cocorná Area.
The National Hydrocarbons Agency (ANH) and its Contracts
The ANH was created by Decree Law 1760 of 2003 and was given the authority to administer all national hydrocarbon reserves under contracts executed since January 1, 2004. Pursuant to Decree Law 1760 of 2003, Empresa Colombiana de Petróleos, Ecopetrol, was split, and its organic structure was modified, to create two new entities: the Agencia Nacional de Hidrocarburos and the Sociedad Promotora de Energía de Colombia S.A. Prior to January 1, 2004, Ecopetrol S.A. had the authority to contract with third parties for the exploration and production of new areas.
However, the creation of the ANH did not modify our rights or obligations or the rights or obligations of other parties with respect to contracts in existence before January 1, 2004, when the ANH was created. Therefore, we have retained the authority to execute agreements with respect to all areas held by us prior to such date.
Below, we include a brief description of each type of contract that we have entered with the ANH:
Technical Evaluation Agreements
This type of contract grants the contractor the exclusive right to develop technical evaluation operations with operational autonomy at its own cost and risk, seeking to appraise the hydrocarbon potential of an area under specific conditions, with the purpose of identifying the zones of prospective interest in the area by means of the execution of an exploratory program. The contractor has the option to request the conversion of a technical evaluation agreement (“TEA”) into one or more E&P contracts that cover the area of the TEA (or a portion thereof). The contractor will be subject to payment of rights for the use of the subsoil, other applicable economic compensation.
The contractor can conduct evaluation activities for terms that vary between 18, 24, and 36 months, depending on the terms of reference of the ANH’s bidding round.
E&P Contracts
The ANH enters into concession contracts pursuant to which the Nation grants exploration and production rights and receives royalties and taxes. In turn, the contractor provides 100% of the investment and expenses resources and receives 100% of the production after royalties and taxes. The ANH has named this contract an “Exploration and Production Contract” or an “E&P contract”.
The ANH only receives a percentage of oil revenues in two cases:
when the international oil prices rise beyond a specified price (high price fee), above which the ANH has a right to participate in a share of the increased revenues generated, or
in the case of recognition of production rights in an extended contractual phase (additional production share).
Since the 2008 bidding round held by the ANH, the ANH receives a percentage of the production share from E&P contracts, from the commencement of the production phase (instead of solely from the extension phase of the contract (additional production share) as mentioned in the previous paragraph). In addition, the ANH acquires economic rights when the price of oil exceeds a reference price set in the contract (high price fee) as well as when the surface fee based on the hectares of the assigned area of the contract (both with and without production) exceeds the reference number set in the contract.
E&P contracts have three phases: (i) an exploration period of up to six years counted from the effective date, which may be extended for two additional years, (ii) an evaluation period of two years, assuming reserves are discovered, to determine the commercial potential of the discovered reserves, and (iii) a production period, with respect to each production field, which may last for up to 24 years plus extensions, counted from the date in which the commercial viability of the corresponding field is declared. The abovementioned terms were modified during ANH’s 2014 bidding round for unconventional and offshore reservoirs, resulting in an exploration period of nine years and a production period of 30 years. On June 29, 2018, a new model E&P contract was published by the ANH. In accordance with the new model for E&P contracts, offshore contracts entered into in or after 2019 will have evaluation periods of three, five, or seven years, depending on the depth of the water where the discovered reserves are located. In 2021, for the fourth round of its Permanent Area Assignment Process (Proceso Permanente para la Asignación de Areas or “PPAA” for its acronym in Spanish), the ANH introduced to the model of the E&P contract, the concept of an “economic value for the exclusivity” of exploration and production of a specific area. Such value must be expressed in dollar amounts and must be offered by each bidder to the ANH, as remuneration for receiving the exclusive exploration and production rights and acts as a guarantee for the obligations of the contractor during the exploration phase of the executed E&P contract.
ANH and Ecopetrol Agreements (Convenios)
Decree-Law 1760 of 2003 established that the rights over the production area and over the personal and real property assets of (i) all fields that were directly operated by Ecopetrol S.A. as of December 31, 2003, and (ii) all fields in which there was an association contract before said date would continue to belong to Ecopetrol S.A.
Pursuant to Article 2 of Decree 2288 of 2004, which regulates Decree Law 1760 of 2003, Ecopetrol S.A. must execute an agreement with the ANH to regulate the exploration and exploitation terms and conditions of the relevant area, which was previously subject to an association contract.
Decree 2288 of 2004 also established that Ecopetrol S.A. would have to execute agreements with the ANH, covering fields directly operated by Ecopetrol S.A. Under these agreements, the ANH recognizes the exclusive right of Ecopetrol S.A. to explore and exploit the hydrocarbons which are property of the Nation and might be obtained in the areas covered by the corresponding agreements. Ecopetrol S.A.’s rights shall last until resources are depleted or Ecopetrol S.A. returns such areas to the Nation through the ANH.
These agreements also provide the conditions under which Ecopetrol S.A. may, either partially or completely, assign to third parties its rights and obligations thereunder.
3.6
Transport and Logistics
3.6.1
Transportation Activities
The transport and logistics segment includes the transportation of crude oil, motor fuels, fuel oil, and other refined products including diesel, jet, and biofuels. We conduct most of these activities through our wholly owned subsidiary Cenit and its subsidiaries.
The map below shows the locations of the main transportation networks owned by our business partners and us.
Graph 5 – Map of Oil Pipelines
50
Graph 6 – Map of Multi-purpose Pipelines
51
The table below sets forth the volumes of crude oil and refined products transported through the crude oil pipelines and multi-purpose pipelines owned by us.
Table 37 – Volumes of Crude Oil and Refined Products Transported
Crude oil transport(1)
804.1
815.2
807.0
Refined products transport(2)
298.3
303.5
305.9
1,102.4
1,118.7
1,112.9
The crude oil transported volumes correspond to the following systems: Ocensa Segment 3, ODC, Vasconia-Galan, Ayacucho-Galan, Ayacucho-Coveñas and Trasandino Pipeline.
The pipelines transporting refined products include the following: Galan-Sebastopol, Galan-Salgar, Galan-Bucaramanga, Buenaventura-Yumbo, Cartagena-Baranoa and Sebastopol.
The volume of crude oil transported by Cenit’s main systems and those of its subsidiaries decreased by 1.4% in 2025, compared to the previous year, as a result of lower third-party production, blockades and impacts to the infrastructure, partially offset by the incorporation into the transportation system of third-party volumes that were previously outside the network, the intake of imported crude into the Barrancabermeja Refinery through the Coveñas-Ayacucho reversal and ensuring the availability of light crude and higher deliveries of Castilla Norte Crude. Of the total volume of crude transported by oil pipelines, approximately 90.6% belonged to the Ecopetrol Group.
The volume of refined products transported by Cenit decreased by 1.7% in 2025 compared to the previous year, mainly due to lower deliveries from refineries, partially offset by the strategic intake to ensure supply in the interior of the country. Of the total volume of refined products transported by multi-purpose pipelines in 2025, 31.5% belonged to the Ecopetrol Group.
Transportation Capacity
Our main crude oil pipeline systems’ operating capacity was 1,286 thousand barrels per day in 2025. Our main multi-purpose pipeline transportation capacity increased from 588 thousand barrels per day in 2024 to 598 thousand barrels per day in 2025.
References to our crude oil transportation capacity in this annual report refer to the capacity of the pipelines that belong to Cenit and its subsidiaries to transport crude oil volumes either to the refineries or to our export facilities. In addition, we have other feeder systems that transport oil volumes from producing facilities or other pumping stations to these main pipelines. References to our refined products’ transportation capacity refer to the capacity of pipelines that begin in the Galan station (Barrancabermeja refinery) and Cartagena station (Cartagena Refinery).
3.6.1.1
Pipelines
As of December 31, 2025, we, directly or indirectly with private partners, own, operate and maintain an extensive network of crude oil and multi-purpose pipelines. These pipelines connect our own and third-party production centers, import facilities and terminals to refineries, major distribution points, and export facilities in Colombia.
Cenit directly owns 37% of the total crude oil pipeline shipping capacity in Colombia. When aggregated with the crude oil pipelines in which Cenit owns an interest, Cenit owns 84% of the oil pipeline shipping capacity in Colombia. By December 31, 2025, our network of crude oil and multi-purpose pipelines was approximately 9,064 kilometers in length. The transportation network consists of approximately 5,356 kilometers of main crude terminals and oil pipeline networks connecting various fields to the Barrancabermeja refinery and Cartagena Refinery, as well as to our export facilities.
We also own 3,707 kilometers of multi-purpose pipelines for transportation of refined products from the Barrancabermeja and Cartagena refineries to major distribution points. Out of the approximately 5,356 kilometers of crude oil pipelines, owned by us, 3,355 kilometers of crude oil pipeline are wholly owned, and 2,002 kilometers of crude oil pipeline are owned through non-wholly owned subsidiaries.
The following table sets forth our main pipelines in which we have an indirect interest as of December 31, 2025.
Table 38 – Our Main Pipelines
Indirect
Capacity
Product
Ownership
Pipeline
Kilometers
(mbd)
Transported
Origin
Destination
Percentage
Caño Limón-Coveñas
773
(1)
Caño Limón
Coveñas
100.00
Oleoducto de Alto Magdalena (OAM)
391
102
Tenay
Vasconia
93.62
Oleoducto de Colombia (ODC)
483
231
78.19
Oleoducto Central – Ocensa
848
745
(2)
72.65
Oleoducto de los Llanos (ODL)
279
297
(3)
East fields
Monterrey Cusiana
65.00
Oleoducto Bicentenario de Colombia
139
Araguaney
Banadia
Caño Limón – Coveñas has three systems with different capacities. 213 mbd refers to the capacity of the system OCLC Caño Limón – Banadia L18” with Drag Reducing Agent (“DRA”). The capacity of the other systems is as follows:
a.
OCLC Banadia – Ayacucho L18”L20” – L24”: 171 mbd without DRA.
b.
OCLC Ayacucho – Coveñas L24”: 100 mbd without DRA
Ocensa has four segments with different capacities. 745 mbd refers to the capacity of segment two (El Porvenir-Vasconia). The capacity of the other segments is as follows:
Cupiagua-Cusiana (segment zero): 198 mbd
Cusiana-El Porvenir (segment one): 745 mbd
c.
Vasconia-Coveñas (segment three): 550 mbd
(3)Transportation capacity for this pipeline is measured by using crude oil viscosity of 1.350 cStk (30° C).
As of December 31, 2025, we owned 76 stations, 43 located in crude oil pipelines, 29 in refined products pipelines, two in crude oil ports and two in refined product ports.
As of December 31, 2025, we had a nominal storage capacity associated with the transportation network of 16.5 million barrels of crude oil and 6.2 million barrels of refined products. We do not own any tankers.
Pipeline Projects
Operational Storage Program
The operational storage program’s objectives and scope include ensuring a storage of more than one million barrels of refined products in five different stations. The program foresees the construction of more than 10 tanks distributed through four projects divided in this way: (i) one tank of 260,000 barrels for Nafta and one tank of 323,000 barrels for Biodiesel Extra (B2E) or Gasoline (GM) in Pozos Colorados Terminal, (ii) two tanks of 100,000 barrels each in Sebastopol station and one tank of 62,000 barrels in Yumbo station (all this storage is for Biodiesel Extra (B2E) and Gasoline (GM)). We are currently evaluating the construction of: (i) two tanks of 70,000 barrels each, to storage B2E and GM in Cartago Station and (ii) four new tanks in Medellín that in total has 254,000 barrels of capacity to storage Jet (JA1), Gasoline Extra (GE) and B2E. The construction phase began in 2020 in Pozos Terminal and Sebastopol station and in 2021 in Yumbo station. According to construction, startup phase and commissioning, the systems in Pozos Terminal were completed in August 2022. Startup of the new tank at Yumbo took place in the first quarter of 2023.
In 2025, Tank K707 began operations, increasing the storage capacity of the Pozos Colorados Maritime Terminal by 323,000 barrels. With this project, the terminal reaches a total capacity of over 1.5 million barrels, significantly strengthening its operational flexibility for refined products.
Andina Reliability Project
The aim of the Andina project is to recover reliability of delivering of refined hydrocarbons to Bogotá and the center of Colombia, including the Dorado Airport, by means of the reposition of twelve main updated pumping units in capacity, efficiency and technology for each of the pumping stations (Puerto Salgar, Guaduero, Villeta and Albán). The construction of the new facilities started in August 2022, and the system is currently operating with nine new pumping units for the stations of Puerto Salgar, Guaduero and Villeta.
In 2025, the project achieved significant operational and sustainability milestones, including the successful commissioning of two new units at the Albán station. The integration of these units into the Salgar–Mansilla system reduced energy consumption, resulting in cost savings of approximately USD 1 million and the avoidance of nearly 600 tons of CO₂ emissions during the year. These improvements also enhanced system reliability, reaching a service factor of 95%, which supports safer and more efficient operations.
For 2026, the project is expected to advance through the commissioning of a third pumping unit at Albán. These actions reinforce our commitment to operational excellence and sustainability, contributing to measurable environmental benefits and long-term resilience.
Replacement of the “La Valeria” Single Point Mooring in Pozos Colorados Terminal.
The “La Valeria” Single Point Mooring (SPM) operating in the Pozos Colorados Maritime Terminal had to be replaced in 2024, as the operational term specified in its safety certificate had come to an end, and at which point the asset reached its 30-year lifespan.
During the third quarter of 2024, the new Valeria SPM (Single Point Mooring) was put into operation. This unmanned unit plays a critical role in transferring refined hydrocarbons, such as gasoline, naphtha, and diesel, from ships to the Pozos Colorados Maritime Terminal in Santa Marta through an underwater pipeline.
The replacement required, among other things, (i) procuring the design and construction of the SPM, (ii) transportation and delivery of materials, (iii) obtaining permits, registrations, and authorizations for the new unit and decommissioning of the current one, (iv) dismantling and final disposal of the current SPM; (v) assembly, commissioning, and operational start-up of the new SPM; and (vi) stabilization of operations. The project represented an approximate investment of USD 27 million and involved 270 professionals for more than two years.
In 2025, the project SPM Valeria was awarded as project of the year 2024 in the Gulf International Energy Awards, held in Houston in October 2025.
Caño Sur Pipeline
The objective of this project is to enable the transportation of 100% of the production projection of the Caño Sur field owned by Ecopetrol, through a pipeline of approximately 20 kilometers long, between Caño Sur and the kilometer 30 of the Oleoducto de los Llanos Orientales - ODL transportation system. The producer could benefit from an efficient transportation system, with a greater oil evacuation capacity updated to 47,840 bpd and with lower risks compared to the current transportation conditions. In 2024, the project completed the following milestones: (i) construction began on July 15, 2024, (ii) progress of Centauros station works, which consisted of location and excavation of the firefighting system pipeline, CCM construction and correspondent equipment placement, and installation of booster pumps, and (iii) pipeline progress, consisting of the completion of pipe welding, pending closure of ties, progress in river tunnel drilling, and progress in trenching, pipe lowering and covering activities.
In 2025, the project achieved the following milestones: (i) construction of a 1.8-kilometer-long power transmission line; (ii) commissioning of electrical systems at the MCC; (iii) construction of electromechanical facilities for the operation of booster pumps and main pumps under a 1+1 operating scheme; (iv) construction of the pipeline along nearly 20 kilometers; (v) construction of two sub-fluvial crossings; (vi) connection of the pipeline to the Llanos Oil Pipeline through a hot tap; (vii) construction of three fully automated sectionalizing valves; (viii) start-up on March 26, 2025; and (ix) transportation of more than 13.2 million barrels through the pipeline.
This pipeline was built to the highest automation standards in the O&G industry, safeguarding process safety, with an average fluid transportation rate of 50 mbd for heavy crude oil of 13° API and is currently in the administrative close-out phase. The project generated savings of approximately 120 tCO₂ associated with circular economy strategies through the reuse of existing company assets. During construction, a peak workforce of 420 workers was reached, with a total of 500,000 man-hours worked, prioritizing the hiring of local labor from the project’s area of influence.
Electric Interconnection of the Estación el Porvenir (ENERGEPO)
Ocensa established a strategic framework to reduce emissions by 51% by 2030. In connection with such goal, Ocensa’s analyses indicate that the El Porvenir station is one of the plants with highest number of emissions, contributing 30% of the total tons of CO2e from Ocensa.
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The station’s energy source is natural gas, which feeds a system of electricity generation turbines. An alternative for reducing CO2e is the electrical connection to the National Interconnected System (Sistema Interconectado Nacional or “SIN” for its acronym in Spanish), which emission factor is lower than that of gas.
Based on this strategic plan, Ocensa is developing projects that aim to guarantee safe, reliable, and eco-efficient operations such as the 115 kilo Volts (“KV”) electrical connection between the El Porvenir station and the SIN, which project started during the first quarter of 2022.
Currently, the ENERGEPO project is subject to the completion of the Alcaraván expansion project, which consists of expanding the 230 KV and 115 KV electrical networks between San Antonio in Nobsa Boyacá and the new Alcaraván electrical substation in Yopal, by the Mining and Energy Planning Unit (Unidad de Planeación Minero-Energética or “UPME” for its acronym in Spanish).
During 2022, the project achieved the following milestones: (i) a collaboration agreement was signed with Cenit to update the connection study with new information uploaded by UPME that allows the analysis of different scenarios regarding synergies with the Alcaraván project, (ii) companies and entities such as ISA, Grupo Energía Bogotá, Genersa S.A.S E.S.P, UPME, Empresa de Energía de Casanare S.A. E.S.P, Empresa de Energía de Boyacá S.A E.S.P, among others, were approached to analyze a connection alternative that does not depend on Alcaraván, and (iii) the preliminary analyses of additional alternatives, such as solar farms, wind energy, and carbon capture.
In 2023, we updated and defined the connection study and analysis regarding the importance of repowering the existing system with the execution of the Alcaraván project. In October 2023, OCENSA submitted a new request for connection to the STR. This request was based on analyzed connection and a pre-feasibility study, considering a technical variant that removes the need for the Alcaraván project. Considering the time required to establish a reliable connection to the STR, efforts have been coordinated with subsidiary companies to identify efficient and beneficial solutions for the business group. Among the alternatives considered is the potential installation of solar farms. In November 2023, UPME officially awarded this project (Alcaraván) to Alupar Colombia SAS.
In 2024, we moved forward with the ENERGEPO project as we (i) held meetings with regional energy companies to validate their interest in building connection assets and explore third-party financing alternatives, (ii) conducted field sessions with different companies in the midstream sector to understand their energy needs and connections to the STR, (iii) concluded that the connection to the STR is essential, and (iv) explored options for electricity supply from solar farms and energy storage systems. The project is currently in its second phase of development: conceptualization.
In 2025, the project aligned its efforts by completing Phase II of conceptualization, identifying the integrated solar option with storage and connection to the Local Distribution System (SDL), and obtaining approval from the decision-making body to move forward with Phase III of project maturation. This phase involves defining and planning the project and authorizing its execution, with an estimated operational start-up horizon in 2029.
Solar Energy Farms
The Ecopetrol Group aims to develop projects that help to achieve the energy transition to non-conventional renewable energies and that contribute to Colombia’s decarbonization strategic goals. For this reason, within the framework of the investment program in the energy category, Ocensa is developing two initiatives focused on the construction of solar farms at the Coveñas and Vasconia stations, which leverages current resources to achieve safe, reliable, eco-efficient and sustainable operations.
These solar farms are currently in the execution stage. The Miraflores solar farm (0.4 MW) came online in 2023. In 2024, the following goals were achieved: (i) Vasconia Solar farm (7 MW) completed 100% of its pre-operational stage, including the execution of a power purchase agreement, and (ii) Coveñas Solar farm (5 MW) started operations and completed its testing and stabilization phases.
We believe these projects have potential to create renewable energy sources to contribute to our 2030 decarbonization strategy, as we aim to include a 51% reduction in emissions compared to the baseline, the installation of 12 MW of renewable sources, optimization of the cost associated with the station’s energy consumption due to a reduction in the average kWh rate, and opportunity for synergies within the Ecopetrol Group through surplus energy.
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In 2025, the study and analysis of the benefits that would be achieved through the integration of a solar park supplying solar energy to the Cusiana station—currently dependent on gas for its operation—was conducted. A rigorous assessment of the station’s energy strategy determined that integrating a solar park could optimize the energy source and deliver operational cost benefits for both Ecopetrol and Ocensa. The year concluded with the launch of a contracting process to select the company that would provide a reliable, long-term, and comprehensive solution for solar energy supply, including energy storage as an alternative, which further enhances the project’s energy benefits.
Caucasia Main Units Replacement Project
With the objective of ensuring the reliability of the system and transport capacity while reducing CO2 direct emissions, the Ecopetrol Group started the Caucasia Main Units Replacement Project, which consists of replacing the three internal combustion engines at the ODC Caucasia station with three new electric motors. The total investment estimated for the project is USD 19.2 million.
The project is divided into several stages. In 2021, investments were made in long-term procurement and project management. In 2022, construction began with detailed engineering, soil studies and equipment procurement. In 2023, construction was completed, with the project currently being fully operational.
As for the energization phases, temporary thermal generation with natural gas supply has been used since 2023. In October 2024, Caucasia solar farm came into operation, with an installed capacity of 6.7-Megawatt peak (MWP).
In 2025, a large-scale illegal occupation in the municipality of Caucasia continued to represent an external constraint affecting the implementation of the 110 kV connection. In this context, the energization strategy for the Caucasia Pumping Station continued, based on the integrated operation of three (3) energy vectors: solar power supplied by the solar farm, thermal power generation using natural gas, and connection to the existing power grid operated by EPM, with an installed capacity of 1 MW and the management of its expansion up to 1.8 MW.
Throughout 2025, this strategy was further strengthened with the objective of optimizing the station’s energy mix, prioritizing greater use of the solar farm and increasing electricity consumption from the power grid, progressively replacing gas-fired thermal generation. This approach enabled tangible progress in reducing natural gas consumption and achieving a reduction of 6,216 tons of CO₂e in associated greenhouse gas emissions.
As a result of the strategy, since October 2024 natural gas consumption has been reduced by an average of 162 MBTU per day. In August 2025, with the connection to the EPM grid at a capacity of 1 MW, the reduction increased to 371 MBTU per day. With the subsequent expansion of the EPM grid capacity to 1.8 MW, an average reduction of 455 MBTU in natural gas consumption was achieved, consolidating a more efficient operation aligned with the company’s sustainability and energy transition objectives.
Installation of units in Salgar Gualanday
The scope of this project is to improve the reliability and availability of the Puerto Salgar – Gualanday – Neiva 10” oil pipeline to address the volumetric demand for refined products in the south of the country projected to 2040, through the replacement of five main pumping units in two stations (Puerto Salgar and Gualanday). Each new pumping package includes an electric motor, pump and variable speed drive, control and communications panels and shelter.
In 2024, the procurement and manufacturing of the packaged units for both Salgar and Gualanday were completed, along with the development of detailed engineering, enabling the contracting of installation works for 2025–2026.
The civil work began for the installation of frequency converters at both Salgar and Gualanday stations and is expected to be completed in the first half of 2026. In addition, the process to certify the integration of the converters in the free trade zone was secured.
Emissions Reduction at Monterrey Station
This project focused on operational efficiencies, seeks to enhance the safety, reliability, and environmental performance of Monterrey Station. The initiative involves replacing natural gas internal combustion engines with modern electric motors and optimizing operations to match pumping needs. These changes are expected to significantly reduce CO2 emissions and noise levels, improve coexistence with neighboring communities, and minimize operational risks associated with the use of combustion engines.
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In 2024, the project achieved significant milestones, including the completion of the 34.5 KV electric line, installation of a 10 megavolt-amperes (MVA) transformer, and placement of critical equipment like switchgear and motor shelters. Maintenance on one of the main units was finalized, and construction of the primary electrical paths continues.
In 2025, the main electrical equipment, including the switchgear and the nine variable frequency drivers (VFDs), were installed, and have approximately 80% of mechanical completion. The new unit 4490 was installed and became operational at the end of the year. The project remains on schedule, with the final commissioning planned for 2026, marking a significant step toward safer and more sustainable operations.
Replacement of units Galán Chimitá
The project to upgrade the Galán - Chimitá system aims to increase its transportation capacity to 42 thousand barrels per day (mbd) improving operational efficiency and reliability while reducing risks. Key achievements in 2024 included advancing the installation of new equipment, strengthening infrastructure, and ensuring the readiness of critical components to support the system’s expansion. These upgrades also ensure smoother operations and reliable deliveries to key locations, including the Lizama station and Río Sogamoso.
On August 29, 2025, the new main crude oil and refined products pumping units (BPC) 2430/2440 at the Galán Chimitá system L10 became operational. The corridor’s capacity is stabilizing with a rate of 35 to 42 mbd with Diesel and Gasoline. These units are packaged with state-of-the-art equipment that guarantees energy efficiency, control and monitoring systems that facilitate fault location and correction, reduced maintenance frequency and spare parts requirements, less environmental impact from sound pollution, and the ability to manage higher flow rates at low pressure.
Nafta Cusiana (NAFCUS)
The Nafta Cusiana (NAFCUS) project was developed to support the transportation of heavy and extra-heavy crude oils by reducing the risk of volume diversion, increasing the use of existing infrastructure, and improving access to naphtha and other diluents required for pipeline transportation.
The project connects the Andino multiproduct pipeline with the Monterrey–Araguaney crude oil pipeline through new connections at the Monterrey and Cusiana stations, enabling the delivery of diluents to the Oleoducto de los Llanos (ODL) facilities. The system operates under a batch transportation scheme with an operational capacity of approximately 8,000 barrels per day. Commercial agreements were executed with the Ecopetrol Group companies to support diluent supply and infrastructure works. As of 2025, the project reached 46% completion, with the Cusiana facilities completed in December 2025 and full project start-up expected by late February 2026.
Nafta Nodo Llanos
This project aims to provide strategic storage capacity for Nafta at the Apiay station by converting the existing TK-403 crude oil tank into a Nafta storage unit with a capacity of 50 thousand barrels. The scope includes: (i) tank conversion and upgrades (installation of a dome roof (EFRT), lightning protection system, and updates to measurement and control systems); (ii) integration (connection of TK-403 to the Poliandino receipt system and existing Nafta pumping system, ensuring full integration with station control and auxiliary systems); (iii) safety enhancements (upgrades to fire protection systems, including water and foam networks, and integration of fire and gas detection devices); and (iv) environmental and operational compliance (isolation of Nafta lines from crude systems to prevent cross-contamination and adherence to Cenit’s asset incorporation standards). This initiative strengthens operational flexibility and supports long-term volumetric plans for crude dilution in the Llanos region, aligned with Cenit’s strategic objectives for reliability and efficiency.
As of December 31, 2025, there was progress achieved in maintenance and tank adaptations. Dome acquisition process is underway. Interconnection works are scheduled for assignments in the first quarter of 2026. The tank and associated facilities are expected to be ready for operation by November 2026.
Reversal of the Ayacucho–Coveñas 16” Pipeline: Strategic Import Route for Light Crudes
In 2025, Cenit commissioned the reversal of the Ayacucho–Coveñas 16-inch pipeline, enabling the first direct import of light crude to the Barrancabermeja Refinery to strengthen supply flexibility and national energy security. This initiative was made possible by the expansion of the Ayacucho–Coveñas 24-inch corridor, the capacity of which increased from 82 to 148 thousand barrels through a dual pumping configuration. Between September and December 2025, more than 800 thousand barrels of imported crude were delivered to the refinery, enhancing feedstock availability and reducing reliance on alternate ports and road transport. The reversal is expected to generate approximately USD 11 million per year in incremental revenue and provides the option to secure up to 10,000 bpd of firm supply, ensuring a continuous and competitive source of crude for refining operations.
3.6.1.2
Export and Import Facilities
We currently have concessions granted by the Colombian Government for four export/import docks for crude oil and refined products: Coveñas, Tumaco, Pozos Colorados, and Cartagena. Our export capacity reached 2.4 million barrels per day for crude oil. Our import capacity of refined products and crude oil reached 0.3 million barrels per day and 0.3 million barrels per day, respectively. Our crude oil loading facilities can load tankers of up to 350 thousand deadweight tonnage (DWT). Adjacent to these loading facilities we also have storage facilities with 9.9 million barrels of capacity. Our docks, used for importing and exporting refined products, can load tankers of 80 thousand DWT. Additionally, these facilities have a storage capacity of up to 1.8 million barrels.
3.6.2
Other Transportation Facilities
We have entered into transportation agreements with tanker trucks and barge companies to transport crude oil from locations that do not have pipeline connections to refineries and export facilities. The volume of refined products that cannot be transported by pipelines or tanker trucks due to capacity limitation is transported by barges. During 2025, 38.2 million barrels of crude oil and refined products were transported by tanker trucks, and 10.1 million barrels of refined products were transported by barges, particularly using the Magdalena River, connecting Barrancabermeja with Barranquilla and Cartagena.
3.6.3
Marketing of Transportation Services
Cenit and its subsidiaries main line of business is the crude oil pipeline transport (77% of revenues), followed by the refined products pipeline transport (16% of revenues) and ports and related services (7% of revenues). Both crude and refined product pipeline transport are regulated activities; crude oil pipeline transport services are regulated by the Ministry of Mines and Energy, while refined product pipeline transport services are regulated by the Energy and Gas Regulatory Commission (Comisión de Regulación de Energía y Gas or “CREG” by its acronym in Spanish).
Transportation contracts of crude oil may take several forms: ship or pay (payment for the availability of a fixed capacity in the system), ship and pay (payment for volumes transported), or spot contracts. The main users for the crude oil transportation business are Ecopetrol S.A., Frontera Energy, Parex, Hocol, Trafigura and Vitol, who collectively represented 77% of this business segment’s revenues in 2025. Transportation services for crude oil provided to Ecopetrol S.A. represented 92% of this business segment’s crude oil transport revenues in 2025.
Cenit also transports refined products, and its main client is Ecopetrol S.A., which accounted for 39% of refined products pipeline transport revenues in 2025, mainly due to the transport of naphtha, diesel, and gasoline. Cenit also has 32 other fuel wholesalers’ customers for whom it transports refined products. The most significant among them are Ecopetrol, Organización Terpel, Primax Colombia, Chevron Petroleum Company, Biocombustibles S.A.S., Terpel Exportaciones and Petrobras Colombia.
Deregulated businesses, such as ports and crude-loading facilities, represent a smaller portion of Cenit and its subsidiaries revenue (7% in 2025). Clients for these businesses include some of the same parties for which Cenit provides crude oil and refined products transportation services.
3.7.1
Refining
Our main refineries are the Barrancabermeja refinery, which Ecopetrol S.A. directly owns and operates, and a refinery in the Free Trade Zone in Cartagena owned by Refinería de Cartagena S.A.S., a wholly owned subsidiary of Ecopetrol S.A., who operates this refinery and two other minor refineries -Orito and Apiay-, but these are considered part of the exploration and production segment since most of the production is for self-consumption.
Our refineries produce a full range of refined products, including gasoline, diesel, jet fuel, LPG and heavy fuel oils, among others. Regarding electrical reliability in Cartagena, work continued in 2025 on risk management and reduction, with the goal of reaching a ‘tolerable risk’ level in 2026. As of December 2025, 81% progress had been achieved (13 out of 16 plan milestones were completed), and connection to the National Interconnected System was secured (70 megawatts of backup capacity), reducing exposure to grid events and supporting stable operations
The following table sets forth our average daily installed and actual refinery capacity for each of the last three years:
Table 39 – Average Daily Installed and Actual Refinery Capacity
Throughput
Use
(bpd)
(%)
Barrancabermeja
250,000
224,545
90
221,609
221,810
Cartagena(1)
210,000
192,556
192,205
197,824
94
2,500
1,717
69
1,658
1,290
Orito
2,200
1,643
75
1,407
2,300
1,699
74
464,700
464,800
Includes crudes and recirculated products.
3.7.1.1
Barrancabermeja Refinery
The Barrancabermeja refinery produced approximately 38.2% of the fuels consumed in Colombia in 2025, according to internal calculations made by us and Colombia’s fuel consumption as reported by the Ministry of Mines and Energy.
The following table sets forth the production of refined products of the Barrancabermeja refinery for the periods indicated.
Table 40 – Production of Refined Products from the Barrancabermeja Refinery
LPG, Propylene and Butane
9,358
11,446
11,252
Gasoline Fuels and Naphtha
57,373
57,385
60,034
Diesel
55,469
57,931
58,143
Jet Fuel and Kerosene
26,789
23,526
25,548
Fuel Oil
23,480
23,260
26,490
Lube Base Oils and Waxes
1,175
1,087
883
Aromatics and Solvents
2,446
2,517
2,298
Asphalts and Aromatic Tar
45,874
44,958
40,645
Polyethylene, Sulphur and Sulphuric Acid
1,172
1,351
1,376
223,136
223,461
226,669
Difference between Inventory of Intermediate Product
4,035
1,511
(1,286)
Total Production
227,171
224,972
225,383
In 2025, total production from the Barrancabermeja refinery increased by 1.0% compared to 2024, mainly due to a lower receipt of Caño Limon crude oil to the refinery partially offset by a higher receipt of domestic and imported light crude oil, which implied a reduction in gasoline and diesel yields and an increase in the production of jet fuel and heavy intermediate products. Moreover, the production of bases and waxes increased to serve the national and international market.
We own and operate four petrochemical plants and one paraffin and lube plant located within the Barrancabermeja refinery. In 2025, we produced 37,651 tons of low-density polyethylene, a decrease of 14.9% compared to the production of 44,237 tons in 2024. This decrease was primarily due to the operational availability of the units associated with the polyethylene chain. We produced 584 mboe of aromatics (benzene, toluene, xylene, orthoxylene, heavy aromatics, and cyclohexane), a 10.8% of decrease as compared to the production of 655 mboe of aromatics in 2024, mainly due to reduced operational availability resulting from a scheduled turnaround in the first quarter of 2025.
The gross refining margin increased from USD 10.3/Bl in 2024 to USD 14.1/Bl in 2025, primarily due to higher prices for refined products relative to crude oil, particularly in the petrochemical and industrial segments, combined with a general decline in international refining crack spreads. Additionally, reduced receipts of Caño Limón crude oil resulted in lower yields of high-value products. The average conversion index for the Barrancabermeja refinery was 90.7% in 2025 and 91% in 2024. This slight decrease was primarily due to increased exports of asphalt and other industrial products to international markets, alongside sustained operational availability of the refinery unit.
3.7.1.2
Cartagena Refinery
The following table sets forth the production of refined products from the Cartagena Refinery for the periods indicated.
Table 41 – Production of Refined Products from the Cartagena Refinery
4,365
3,430
3,962
54,190
54,511
61,861
83,775
80,438
93,575
12,016
11,798
12,312
16,870
16,124
18,920
Sulphur
453
441
550
171,669
166,742
191,180
12,531
17,071
1,339
Total Production (1)
184,200
183,813
192,519
Petcoke (Metric Tons)
1,047,077
1,036,703
1,023,556
Does not include petcoke.
The following tables set forth the imports and sales of refined products from the Cartagena Refinery for the periods indicated.
Table 42 – Imports and Sales of Refined Products from the Cartagena Refinery
Imports
Motor Fuels
1,010
LPG and Butane
471
1,524
1,538
Total Imports
1,481
31,840
33,208
35,626
83,887
80,653
94,004
12,022
11,738
12,329
16,338
15,638
15,365
Other Products
48,477
58,224
52,143
Total Sales
192,564
199,461
209,467
Total sales decreased from USD 6,031 million in 2024 to USD 5,499 million in 2025. A total of 70.3 million barrels of crude were processed in 2025 compared to 70 million barrels of crude processed in 2024. Exports to international markets represented 16% of total sales (USD 876 million).
The gross refining margin increased to USD 11.9/Bl in 2025 from USD 9.4/Bl in 2024, mainly due to favorable product cracks, such as medium distillates and gasoline, in 2025.
3.7.1.3
Esenttia S.A.
In 2025, Esenttia’s production totaled 373.3 thousand tons of petrochemical products, a 12% increase compared to the 322.8 thousand tons produced in 2024, mainly attributable to the commercial strategy, particularly the Customer Reconquest Plan and selective negotiations with Rubberon to ensure stable purchasing volumes during 2025.
Table 43 – Operating Capacity of Esenttia
(Metric Tons)
Average capacity
570,000
505,940
373,291
332,862
440,783
% Use
65
3.7.1.4
Invercolsa
During 2025, Inversiones de Gases de Colombia S.A. (“Invercolsa”), registered 1.58 million users of natural gas, an increase of 3.8% compared to the 1.51 million users of natural gas in 2024. Additionally, non-controlled companies registered 2.67 million users of natural gas in 2025, an increase of 3.3% compared to the 2.59 million users of natural gas in 2024. Throughout 2022, Invercolsa completed the integration of its operations into the Ecopetrol Group, in connection with the increase in stake completed by Ecopetrol in November 2019.
3.7.1.5
Biofuels
As of the date of this annual report, we have investments in the biofuel company Ecodiesel Colombia S.A., in which we own 50% of the shares, currently in operation with a capacity of 150 thousand tons of biodiesel per year.
In 2025, Ecodiesel managed to capitalize on opportunities and achieved historical production results. Our production increased from 140 thousand tons in 2024 to 148 thousand tons in 2025. This represents a year-to-year increase of 5.9% and was due mainly to higher plant efficiency, an increase in throughput, from 17.4 tons/hour in 2024 to 18.1 tons/hour in 2025.
3.7.2
Marketing and Supply of Refined Products
We are the main producer and supplier of refined products in Colombia. We market a full range of refined and feedstock products, including regular and high-octane gasoline, diesel fuel, jet fuel, LPG and petrochemical products, among others.
Domestic sales of refined products totaled 349.5 mboed and decreased by 2.4 mboed in 2025, 1% lower than compared to 2024. This decrease is primarily the result of a decrease in the LPG, partially offset by an increase in the demand for asphalt and gasoline.
In 2025, 16.4 million barrels of diesel and 2.2 million barrels of gasoline produced by the Cartagena Refinery were allocated to complement the supply from the Barrancabermeja refinery and fulfill Colombia’s demand, avoiding larger imports and allowing us to maintain the share of the national market. In the same way, 8.5 million barrels of diluent produced by the Cartagena Refinery were used to transport crude, reducing diluent imports. In addition, we imported petrochemicals to complement the national supply, generating additional sales of lubricating bases, polyethylene, hexanes, and others.
Exports of products decreased by 7% (7.5 mboed) in 2025 compared to 2024, explained by a decrease of 5.8 mboed in exports of coque and 4.2 mboed in exports of vacuum gas oil partially offset by an increase of 2.5 mboed in exports of propane.
3.8
Our energy transmission and toll roads concessions segment includes the offering of services such as electricity transmission and the designing, building, operating, and maintaining toll road infrastructure in various countries in Latin America. We conduct these activities through ISA and its subsidiaries.
3.8.1
ISA
ISA was founded as a joint stock company in Bogotá, Colombia, in 1967. Since then, it has grown into a multi-Latin corporate group operating in Colombia, Brazil, Peru, Chile, Bolivia, Argentina, and Central America. ISA and its 50 subsidiaries operate and maintain electricity transmission networks, with the broadest presence of any Latin American electricity transmission company in terms of the number of countries where ISA operates. ISA is also involved in toll-road concessions, telecommunications, and information and communications technology (ICT) businesses.
ISA is organized as a Colombian stock corporation and as a mixed public services company. As of December 31, 2025, we owned 51.41% of ISA’s capital stock and other shareholders (including Colombian pension funds, international and local institutional investors, and retail shareholders) owned the remaining 48.59% of ISA’s capital stock.
The majority of ISA’s consolidated revenues are derived from (i) contracts with customers, (ii) the regulated payments that ISA and its consolidated subsidiaries operating in the electricity transmission segment receive from making their electricity transmission assets available to the national interconnected systems of the countries where they operate, (iii) revenues related to interconnection charges, the dispatch and coordination of the National Dispatch Center (Centro Nacional de Despacho or “CND” for its acronym in Spanish) in Colombia and administration services of the Wholesale Energy Market (MEM) in Colombia, (iv) revenues recognized by reference to the stage of completion of contract activity in the energy transmission and toll roads concessions segment and (v) as concessionaire, with the right to retain most of the toll revenues derived from operation of the toll road for the term of the concession.
3.8.2
Electricity Transmission Activities
ISA is one of the largest international energy transmission companies in Latin America in terms of kilometers of electricity lines in operation, according to ISA’s internal calculation of the total kilometers of high-voltage network circuits of the energy transmission and toll roads concessions segment in each country in which ISA operates. ISA owns 50,564 kilometers of high-voltage grid circuits, which support the supply of energy in Latin America. As of December 31, 2025, ISA is in the process of constructing an additional 8,448 kilometers of high-voltage grid circuits, which are expected to begin operations in the short term.
The energy transmission companies of ISA operate and maintain a high-voltage transmission network in Colombia, Brazil, Bolivia, Peru, and Chile, as well as some international interconnections that operate between Colombia–Ecuador and Ecuador–Peru. In Central America, the company holds a stake in Empresa Propietaria de la Red (EPR), a company incorporated under the laws of Panama and headquartered in San José, Costa Rica, which operates the Energy Interconnection System for the Countries of Central America (Sistema de Interconexión Eléctrica de los Países de América Central or “SIEPAC” for its acronym in Spanish).
The revenues associated with the provision of energy transmission services are regulated and are not affected by the supply or demand for electricity. Additionally, revenues are indexed to macroeconomic variables such as the Colombian peso to U.S. dollar exchange rate, the Producer Price Index (PPI), the Consumer Price Index (“CPI”), or the corresponding indexes in the different countries.
In Colombia, ISA’s subsidiary, XM Compañía Expertos en Mercados S.A. E.S.P. (“XM”), exclusively operates, plans and coordinates the resources of the National Interconnected System (Sistema Interconectado Nacional or “SIN” for its acronym in Spanish), and also manages the Commercial Settlement System (Sistema de Intercambios Comerciales or “SIC” for its acronym in Spanish) in the MEM, the International Electricity Transactions (Transacciones Internacionales de Electricidad or “TIE” for its acronym in Spanish) with Ecuador, and carries out the settling and clearing of charges for use of the SIN’s grids. XM also develops solutions and provides energy and information services. As the sole operator of the Colombian SIN, XM guarantees the balance between production and consumption of energy in the country. Also, based on energy demand estimates, XM conducts the coordinated real-time operation of the generation plants and the grid to ensure that power plants’ generation continuously responds to consumers’ demand in a cost-effective, reliable, and safe manner with quality standards.
The following table sets forth certain metrics related to ISA’s energy transmission operations for the periods indicated:
Table 44 – Key Electricity Transmission Metrics
In Operation
Km of Circuit
MVA Installed Capacity
119,822
113,365
109,258
In Construction
8,448
8,200
6,897
MVA Capacity
20,836
15,306
16,321
Operational Results
Reliability
99.99
Availability
99.60
99.83
99.72
3.8.2.1
Electricity Transmission Activities in Colombia
In 2025, ISA’s subsidiaries electricity transmission activities in Colombia included 14,144 km of transmission lines. As of December 31, 2025, ISA owned and operated an aggregate transformation capacity of 25,655 MVA (Megavolt-Amperes), transforming high voltage electricity into low voltage electricity, and vice versa.
The following table sets forth ISA’s transmission lines and transformation capacity relating to electricity transmission activities in Colombia, for the periods indicated.
Table 45 - Transmission Infrastructure in Colombia
Transmission
Transformation
Lines
(Km)
(MVA)
14,144
25,655
13,694
23,471
13,635
23,371
3.8.2.2
Electricity Transmission Activities Outside Colombia
In 2025, ISA’s subsidiaries electricity transmission activities outside Colombia included 36,420 km of controlled transmission lines, where Brazil represents 43% of the total transmission infrastructure.
The following table sets forth ISA’s electricity transmission activities outside Colombia, for the periods indicated.
Table 46 - Transmission Infrastructure Outside Colombia
Brazil
21,509
71,558
21,293
67,403
21,065
64,307
Peru
12,377
16,289
12,155
16,172
12,191
15,260
Chile
1,948
5,850
Bolivia
587
470
36,421
94,167
35,983
89,895
35,791
85,887
3.8.3
Toll Roads Concessions Activities
ISA designs, builds, operates, and maintains toll road infrastructure that connects millions of people in Chile, Colombia and Panamá. As of December 31, 2025, ISA’s total road infrastructure was 1,107 km. ISA was one of the largest intercity road operators and operated four concessions in Chile (Ruta del Maipo, Ruta de la Araucanía, Ruta de los Ríos and Ruta del Loa - A Sector), while in Colombia, it operated the Ruta Costera Concession. In total, it operated five toll roads concessions, which covered a total of 811 kilometers in these two countries and had 296 kilometers of new road infrastructure under construction in Ruta del Este in Panamá (which is also being operated) and Ruta Orbital Sur and Ruta del Loa - B Sector, in Chile. In the year ended December 31, 2025, 142.2 million vehicles traveled on roads operated by ISA.
The following tables set forth certain metrics related to ISA’s toll road concession operations in Colombia and Chile for the periods indicated:
Table 47 - Total Traffic (Vehicles)
Road Length
Ruta Costera
146
9,183,452
8,685,033
9,032,156
CHILE
Ruta del Maipo
237
97,107,199
95,877,049
95,492,117
Ruta del Bosque
3,225,017
Ruta de la Araucania
144
24,057,193
23,476,965
23,740,110
Ruta de los Ríos
172
10,038,781
10,079,544
10,471,290
Ruta del Loa
112
1,839,584
743,345
811
142,226,209
138,861,936
141,960,690
(1)Road length for the year ended December 31, 2025.
(2)Expired in February, 2023.
3.8.4
Telecommunications and ICT
Within the telecommunications segment, InterNexa provides connectivity solutions, especially in urban and interurban fiber optics, in a wholesale model, to provide network and data center infrastructure in Colombia and Peru, and with commercial presence in the United States. As of December 2025, InterNexa had over 14,000 kilometers of optical fiber and operated data centers in Medellín and Bogotá. Its strategy focuses on strengthening their position as a wholesale operator of fiber optic connectivity services and data center integration, while increasing its scale with attributes of reliability, proximity and agility to maximize efficiency and productivity, and on accompanying the evolution and growth of its clients.
Additionally, InterNexa is developing infrastructure businesses under the “InfraCo” model, focused on acquiring or building networks to lease them under long-term partnerships, enhancing its capacity to deliver high-value solutions to its clients.
In 2025, InterNexa was recognized as a Center for Innovation and Productivity by the Ministry of Science, Technology and Innovation of Colombia. This recognition reaffirms its commitment to the country’s digital transformation and to the development of technological capabilities. Being granted this designation makes InterNexa an active member of the National Science, Technology and Innovation System, enabling participation in public calls, co-creation initiatives with universities, research centers and the development of new products and services for the market.
In Colombia, InterNexa is working with the Ministry of Information and Communication Technologies (MinTIC) in the “ConectiVIDAd para Cambiar Vidas” project, which aims to bring connectivity to remote areas of the country and contribute to closing the digital gap.
3.9Research and Development; Intellectual Property
As a key lever of our TESG strategy, technology and innovation are essential to our efforts to add value to our business segments. Value generation is achieved through the development of proprietary technologies and competitive advantages and the adaptation of third-party technologies to our processes.
Our main innovation and technology development center is the Colombian Petroleum and Energies of the Transition Institute (Instituto Colombiano del Petróleo or “ICPET” for its acronym in Spanish), established in 1985 and located in Piedecuesta, Santander. The scope of the ICPET activities covers our entire value chain: exploration, production refining, transportation, trading, and marketing including asset integrity and environmental sustainability and energy transition technologies.
Ecopetrol has focused its research, technology development and innovation efforts on four main areas:
(i) Hydrocarbons Management: The main goal of this pillar is to support the results of the traditional business of Ecopetrol by reaching differential goals in their exploration, production and refining activities with technology. It includes seismic processing technologies, geological modeling, enhancing oil recovery methods, new additives for improving production/transport of oil and advance technologies and modeling of refining processes.
(ii) Energy transition Management: We support decarbonization and energy transition corporate plans through studies related to energy efficiency, and to the implementation of CCUS, sustainable fuels, renewables energies and the hydrogen value chain. We are incorporating multi-scale technological approaches to identify, quantify, characterize, and abate methane emissions to reduce our impact on climate. Furthermore, we are conducting studies to establish carbon stocks and fluxes associated to strategic ecosystems, to promote transparent carbon compensation projects related to nature-based solutions, and to reduce the risk of biodiversity loss in Colombia and we also work modeling and developing tools to optimize the energy value chain.
(iii) Technology Transfer and Scaling Management: Scaling and transferring technologic solutions of the Ecopetrol group, integrating capabilities, knowledge, and business models to generate value and sustainable growth in Ecopetrol’s strategic segments and Ecopetrol Group.
(iv) Technology Services Management: We lead the various strategies to ensure the delivery of laboratory work-based solutions as part of the technology support provided by ICPET to the corporate business plan covering both hydrocarbons and energy transition projects. Additionally, management aims to continuously improve the research and development facilities at ICPET’s location in Piedecuesta, Colombia. This includes specialized maintenance, updates, automation, robotization and the implementation of digital transformation solutions to ensure the sustainable and more efficient operation of our technology assets.
Each year we bring to the Colombian National Council for Tax Benefits (Consejo Nacional de Beneficios Tributarios, or “CNBT” for its acronym in Spanish) our research, technology development projects and innovation initiatives, to obtain certifications for its science and technology investments. The CNBT certifies eligible science and technology investments, which are tax credit for income tax upon execution.
Our intangible assets are preserved through a technology valuation process and an intellectual property protection process, which include the consolidation of trade secrets, patents, copyrights, trademarks, industrial designs, publications in peer reviewed journals and presentations in prime level technical events. Ecopetrol has filed multiple patents applications in the last 20 years, six of them during 2025.
As of December 31, 2025, we held 152 patents. In Colombia, we have been also granted new patents related to the following technologies, (i) online inspection tool for the efficient detection and classification of damage in pipelines, (ii) method for obtaining functionalized nanoparticles and composite nanofluid for well stimulation processes, (iii) chemical product inhibiting the formation of calcium carbonate scale in crude oil extraction processes, (iv) device for separating heavy crude oils at the surface, including a hydro cyclone, (v) method for obtaining a hydrophilic/oleophobic membrane for the separation and removal of fats and oils in aqueous matrices and in México, (vi) formulation of additives for improving flow capacity and enhancing the dilution capacity of diluents and their application process in the production and transportation of heavy crude oils and (vii) process for obtaining a pipeline-transportable hydrocarbon composed of heavy and extra-heavy crude oils with unconventional diluents. We currently hold patents in Colombia, the United States, Mexico, Argentina, Peru, Venezuela, Brazil, Russia, Nigeria, Indonesia, India, and Malaysia.
As of December 31, 2025, 30 technologies have been commercialized, with different business and technology transfers models to Colombian and multinational companies, thus achieving their monetization and generating additional income for the Company for USD 1.4 million.
Ecopetrol has an analytics and artificial intelligence adoption program with the purpose of maximizing asset efficiency, integrating renewable energies, increasing personal productivity, and improving the quality of life of our employees. The program has four objectives outlined in its artificial intelligence policy:
3.10
Applicable Laws and Regulations
3.10.1
Regulation of Exploration and Production Activities
3.10.1.1
Business Regulation
Pursuant to the Colombian Constitution, the Nation is the exclusive owner of minerals and non-renewable resources located in the subsoil and has full authority to determine the rights to be held and royalties or compensation to be paid by investors for the exploration and production of any hydrocarbon resources. The hydrocarbon industry is under governmental supervision and control. The MME and the ANH are the authorities responsible for regulating all activities related to the exploration and production of hydrocarbons in Colombia.
Decree Law 1056 of 1953 (the Petroleum Code, or Código de Petróleos) declares that the hydrocarbon industry and its activities of exploration, exploitation, refining, transportation, and distribution are of public interest, which means that, in the interest of the hydrocarbon industry, the Colombian Government may order, for example, necessary expropriations in order to develop such industry. The hydrocarbon industry is under governmental supervision and control, regulated mainly by the Ministry of Mines and Energy and the ANH.
Ministry of Mines and Energy Resolution 180742 of 2012, partially repealed by Resolutions 90341 of 2014 and 40303 of 2022, includes a series of technical regulations for unconventional hydrocarbon resources, including the procedures for advancing the exploration and exploitation of unconventional reserves. It also establishes the types of wells and their classification, as well as the fulfillment of those minimum (drilling and abandoning) conditions necessary to initiate or perform E&P activities. In addition, Resolution 40303 of 2022, as amended by Resolution 40358 of 2025 contemplates the applicable procedure to resolve disputes between the mining sector and the oil and gas sector, regarding the coexistence of their rights in some specific projects.
Decree 3004 of 2013, amended by Decree 2638 of 2014, issued by the MME and compiled by the Regulatory Decree 1073 of 2015, sets forth guidelines regarding future regulation related to the exploration and exploitation of unconventional hydrocarbon resources in Colombia. Under Decree 3004, an unconventional field is defined as a rock formation with low primary permeability that requires stimulation in order to improve the conditions of mobility and recovery of hydrocarbons. This regulation contains a series of guidelines regarding the regulation for unconventional hydrocarbon resources, including a definition of unconventional reservoirs and the term in which the MME has to issue the specific technical regulation regarding the exploration and exploitation of unconventional hydrocarbons and the proceedings that interested actors have to follow in order to seek the exploration and exploitation of unconventional hydrocarbons in Colombia. Resolution 90341 was issued on March 27, 2014, by the MME in development of the mandate of Decree 3004 setting the technical conditions, requirements and procedures for the exploration and exploitation of unconventional fields.
On May 26, 2015, Decree 1073 compiled the majority of Colombian decrees in force regarding the administrative sector of mines and energy.
Decree Law 4137 of 2011, which modified the legal nature of the ANH regulates what corresponds to the integral administration of the hydrocarbon reserves and resources owned by the nation of Colombia.
In accordance with the aforementioned Decree Law, it is the responsibility of the Board of Directors of the ANH to define the criteria for administration and allocation of the areas; approve model contracts for their exploration and exploitation, while establishing the rules and criteria for their management and monitoring the contribution to the economic and social development of the country through the promotion and sustainable use of reserves and resources.
The contracts for the exploration and exploitation of hydrocarbons signed with the ANH are regulated through “Agreements” (Acuerdos in Spanish) issued by the ANH. Notwithstanding the ongoing modifications to the area allocation regime established by the ANH, the rules and agreements under which the aforementioned contracts were originally executed or subsequently modified shall govern these contracts until their termination.
Agreement 004 of 2012, as issued by the ANH, repealed Agreement 008 of 2004 and sets forth the rules governing the award of exploration and production areas and the execution of contracts. As set forth below, Agreement 002 of 2017 replaces this Acuerdo and was amended by Agreement 009 of 2021 and Agreement 003 of 2022 (amended by Agreement 002 of 2023). Each agreement executed with ANH is ruled by the Acuerdo that was in effect on the date of execution of the relevant agreement.
Agreement 003 of 2014, as issued by the ANH and modified by Agreement 005 of 2015, complements Agreement 004 of 2012 (which was replaced by Agreement 002 of 2017) by setting forth the contractual framework for the carrying out of activities in unconventional reservoirs, the procurement regulations for the exploration and exploitation of unconventional fields and the procurement process for the awarding of hydrocarbon exploration and exploitation areas.
Agreement 002 of 2015, as issued by the ANH, partially amends Agreement 004 of 2012 and sets forth the initial rules and measures the Government can take to mitigate the adverse effects of the decline of international oil prices.
Agreement 003 of 2015, as issued by the ANH, modifies and partially amends Agreement 004 of 2012, and provides certain rules and measures the Government can take to mitigate the adverse effects of the decline of international oil prices. This agreement permits performance guarantees required under E&P contracts to be reduced in the same amount as the works actually performed during the term of the respective phase.
Agreement 004 of 2015, as issued by the ANH, also partially amends Agreement 004 of 2012, and provides certain rules and measures for the Government to mitigate the adverse effects of the decline of international oil prices. This agreement allows contractors to attribute additional activities conducted under a TEA to commitments under the first phase of an E&P contract.
Agreement 002 of 2017, modified by Annex I of Agreement 03 of 2022, replaces Agreement 004 of 2012, Agreement 003 of 2014, and Agreements 002, 003, 004 and 005 of 2015. It establishes the general structure of the New Regulation for Administration and Assignment of Areas and the general guidelines regarding hydrocarbon contracts in Colombia. Seeking the interests of the Nation, the market conditions, the national hydrocarbon sector strategy, the competitive context of producer countries and the Nation’s social and environmental evolution.
Agreement 002 of 2017 adopts the existing regulations for the selection of contractors, and the applicable rules for the award, execution, termination, liquidation, monitoring, control and surveillance of the contracts signed with the ANH. Regarding unconventional reservoirs, this agreement also establishes the need to sign additional contracts and additional arrangements for the industry to exploit unconventional reservoirs in Colombia.
On November 8, 2018, the High Court for Administrative Matters (Consejo de Estado) analyzed the potential annulment of Decree 3004 of 2013 and Resolution 90341 of 2014 and issued an interim order to suspend their effects as of such date. However, the aforementioned Court established that, “… if the Colombian Government is interested in investigation, clarifying and exploring the feasibility of the hydraulic fracturing procedure for the exploration and exploitation of hydrocarbons in unconventional reservoirs, it could advance in the PPII to identify the risks of unconventional activity.” On July 7, 2022, the High Court for Administrative Matters resolved the claim against the aforementioned regulations, denying the requested annulment claims. With this decision, the suspension of Decree 3004 of 2013 and Resolution 90341 of 2014 was lifted.
On February 4, 2019, the ANH published the new model contract for offshore exploration and production. The purpose of this new model contract was to foster and stimulate investments in exploration and the exploitation of offshore hydrocarbons, enhancing Colombia’s competitiveness to attract and retain investments from large and experienced O&G operators.
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On February 5, 2019, the ANH by implementing the Acuerdo No. 002 (Agreement No. 002 of 2017) opened a PPAA, which aimed to select, among previously qualified proponents on equal terms, the most favorable offers to allocate the areas previously determined, marked and classified by the ANH. Several addendums have modified the terms of references of the PPAA, but, as to date, the applicable terms of reference of such bidding process are included in Addendum No. 25 of November 23, 2021.
On February 18, 2019, the ANH issued the Agreement 003 to clarify the moment in which contractors may withdraw from the contracts signed with the ANH and also presents another alternative for those interested in the PPAA when they belong to business groups, other than the issuance of a parent company guarantee.
Resolution 078 of 2019, as issued by the ANH, approved the final terms of reference and the model of the onshore and offshore contract for the PPAA. Pursuant to this procedure, the ANH selects areas over which proposals may be received at any time, without the need to launch specific bidding procedures for their allocation.
As a result, in 2019, the ANH issued terms of references for the PPAA and carried out two cycles both of which were divided into the following four stages: (i) submission of the proposals and selection of the initial proponent, (ii) submission of counterproposals and selection of the most favorable counterproposal, (iii) the exercise by the initial proponent of the option to improve the initial proposal, and (iv) allocation of areas, contract awards and execution of contracts. In 2020, a third cycle was conducted by the ANH.
As result of the first cycle of the PPAA, the ANH awarded 11 onshore areas and one offshore area. As part of the second cycle, the ANH allocated 14 onshore blocks. Finally, as a result of the third cycle, the ANH awarded four onshore areas.
Agreement 001 of March 27, 2020 of the ANH regulates the transfer of activities or investments between legal instruments signed with the ANH to promote exploratory investment in the country and to seek the incorporation of new reserves, repealing specific articles of Agreement 002 of 2017.
Agreement 006 of September 11, 2020 of the ANH, amended by Agreement 004 of 2021, added certain rules from Agreement 18 of 2004, Agreement 04 of 2005, Agreement 21 of 2006, and Agreement 02 of 2017 to the Contracting Regulations for the Exploration and Exploitation of Hydrocarbons, to allow entities to carry out PPII on hydrocarbons in unconventional reservoirs with the use of the Multistage Hydraulic Fracturing with Horizontal Drilling (Fracturamiento Hidráulico Multietapa con Perforación Horizontal or “FHPH” for its acronym in Spanish) technique. These terms and conditions were modified by Agreements 007, 008 and 009 of 2020 establishing the final terms and conditions for the selection of contractors by the ANH to perform the aforementioned hydrocarbons activities, as well as the final terms of the CEPI to be executed.
Through Resolution 0613 of September 14, 2020, the ANH opened a competitive process for the development of research projects in unconventional reservoirs using the FHPH technique.
Agreement 001 of February 5, 2021, issued by the ANH, established the requirements for the request of extension by mutual agreement to conduct additional exploratory activities in the exploration period, subsequent exploration program, and appraisal programs, as each of these phases are defined in the law. Furthermore, it regulated the requests and granting of term extensions to comply with contractual obligations.
Agreement 003 of February 11, 2021, issued by the ANH, approved the model agreement for the exploration and production of hydrocarbons.
Agreement 004 of February 26, 2021, issued by the ANH, amended Agreement 006 of 2020 regarding the accreditation of commitments and counteroffer requirements applicable to the PPAA.
Considering the remaining impact caused by the COVID-19 pandemic, the ANH issued Agreement 005 of July 14, 2021, and established additional temporary measures to aid hydrocarbon companies in Colombia, including: (i) approving the transfer of activities or investments allowed under Agreement 001 of 2020 to areas included in the fourth cycle of the PPAA process undertaken in 2021; and (ii) extensions to comply with contractual obligations with the ANH.
Agreement 006 of July 14, 2021, issued by the ANH, established general PPAA guidelines, in addition to those listed in the ANH Agreement 002 of 2019.
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Agreement 009 of October 12, 2021, issued by the ANH, amended Agreement 002 of 2017 and established the annex 1 with the compiled and updated rules to allocate and entitle areas to develop exploration and production of hydrocarbons in Colombia and the procedures to perform the contractual obligations agreed according to these rules.
Resolution 728 of October 14, 2021, issued by the ANH, provided the terms and conditions to conduct “Benefit Programs for the Communities” established in the geographic areas covered by E&P agreements. In accordance with this resolution, E&P contracts oblige operators to develop programs for the benefit of the communities where the E&P activities take place.
The ANH also issued Agreement 10 of November 12, 2021, and established the possibility to comply with exploratory obligations in E&P and TEA agreements, as well as in any Convenios by drilling A3 or A2 wells in any area of the Colombian territory that is included in the land map provided by the ANH. This possibility would apply for wells that were drilled in 2021 and 2022. If any company wants to use this possibility, its legal representative shall previously notify the ANH. Regarding CEPI contracts ruled by Agreement 06 of 2021, this Agreement, established specific procedures and alternatives that the contractor has for certification of compliance obligations under this type of special agreement including: effective investment performance criteria, obligation to deliver technical information to the Petroleum Information Bank of the Colombian Geological Service and allocation of the investment performed by the contractor. This Agreement was regulated by Resolution 10882 of 2021, issued by the ANH as well.
On December 1, 2021, the hearing for the presentation and opening of bids for the fourth round of the PPAA was held, according to the schedule of the terms of reference, in which Ecopetrol S.A. submitted four proposals corresponding to three areas offered at the initiative of the Company and one area offered at the initiative of the ANH.
Per the terms of reference and the declaration of initial bidder for the fourth round of the PPAA by the ANH, dated December 14, 2021, concerning the areas labeled “LLA 141,” “VMM 4-1,” “VMM 14-1,” and “VMM 65,” the ANH, through Resolution 20919 of December 20, 2021, awarded the four areas to Ecopetrol S.A.
As a result of the award, on January 18, 2022, the ANH and ECOPETROL S.A. signed the TEA contracts VMM 65, VMM 141 and VMM 41, and the E&P Llanos 141.
In 2022, several agreements were issued by ANH related to the modification of concessions awarding conditions and contractual terms as follows:
Agreement 001 of June 29, 2022, issued by the ANH, regulates the termination by mutual consent, of contracts and agreements for the evaluation, exploration, exploitation and production of hydrocarbons.
Agreement 003 of July 25, 2022, issued by the ANH and amended by Agreement 003 of 2024, by which the regulations for the selection of contractors and allocation of areas for exploration and exploitation of hydrocarbons are adopted and partially superseded Agreement 002 of 2017.
Agreement 004 of July 25, 2022, issued by the ANH, establishes the conditions for the nomination of areas returned to the ANH in the frame of PPAA process. This Agreement was repealed by Agreement 008 of 2024.
Agreement 005 of July 25, 2022, issued by the ANH, establishes new criteria for the administration of contracts and agreements for hydrocarbon exploration and production and extended the term provided by Agreement 10 of 2021 for drilling of A2 and A3 wells until the ANH’s council determines otherwise.
Agreement 006 of August 5, 2022, issued by the ANH, by which the model minute for “shared production” was approved for areas which are under production and are being returned to the nation. This Agreement was repealed by Agreement 008 of 2024.
Agreement 007 of August 5, 2022, by which the ANH approved the definitive terms of reference for the Open Process for the Nomination of Areas (Proceso Abierto de Nominación de Áreas or “PANA” for its acronym in Spanish) and included the commitment to carbon management as a primary factor in the evaluation and qualification of bids for the award of E&P contracts.
Agreement 009 of November 4, 2022, that authorizes the ANH to enter into amendments to the CEPI with the contractors.
Agreement 002 of January 11, 2023, issued by the ANH, eliminated a phrase of Articles 17 and 18 of Agreement 003 of 2022, both related to the process of “Direct Allocation with Counteroffer”. Such process requires the prior establishment of rules, capacity requirements, and conditions and terms required of the proponent, which have not yet been established by the ANH. In this regard, these amendments were made to avoid confusion among proponents, and to prevent the ANH from becoming involved in the initiation of “Direct Allocation with Counteroffer” procedures which rules and conditions have not been established.
Agreement 003 of July 19, 2023, issued by the ANH, allows the use of a three-month term SOFR (Secured Overnight Financing Rate) plus a spread equivalent to 4%, as a measure to mitigate the adverse effects caused by the change in the international reference interest rate for obligations denominated in U.S. dollars within contracts and other legal transactions administered by the ANH.
Agreement 006 of September 28, 2023, issued by the ANH, seeks to promote exploratory investment in hydrocarbons in the country to favor and ensure the maintenance and increase of oil and gas reserves, as well as to drive the national government’s policy of a “Just Energy Transition”. The agreement establishes the following four criteria, with the following application requirements:
1)
Extension of deadlines for exploration periods or subsequent exploratory programs phases for additional exploratory activity.
2)
Reduction of guarantees for additional exploratory activity.
3)
Conversion of unconventional reservoir contracts.
4)
Allocation of up to fifty percent (50%) of the remaining investment for power generation through sources of unconventional energy (fuentes no convencionales de energía or “FNCE” for its acronym in Spanish).
This Agreement is limited to existing hydrocarbon contracts and agreements, except for those signed under the fourth cycle of PPAAs, as they do not align with the timelines of the Agreement.
Resolution 40622 of October 17, 2023, issued by the Ministry of Mines and Energy establishes the technical requirements for the temporary suspension, and the temporary and definitive abandonment of hydrocarbon exploration and production activities, and partially modified Resolution 181495 of 2009. This resolution clarified the possibility of temporarily abandoning offshore wells and is expected to have a positive impact on the development of deepwater projects in Colombia.
Agreement 002 of April 30, 2024, issued by the ANH, established that, in all cases involving E&P contracts and additional contracts for unconventional reservoirs, where an exploratory program with unconventional techniques was agreed, contractors may voluntarily adhere to the Agreement and choose one of the following alternatives: (i) modification of the Exploratory Program to restrict it to conventional techniques; (ii) suspension by mutual agreement of all obligations assumed by the contractor, including economic and financial obligations; or (iii) termination by mutual agreement. As of the ANH approves the contractor’s request to adhere to the Agreement, all obligations related to the contracts, including economic rights, will cease and will only resume when the exploratory program is modified, under the terms agreed in the respective amendment of the contracts.
Additionally, this Agreement sets forth the conditions under which contractors of unconventional reservoirs contracts or additional contract for unconventional reservoirs may request the modification of the agreed exploratory program to modify its execution toward the exploration and production of hydrocarbons using conventional techniques. In such cases, the obligations derived from the exploratory program for unconventional reservoirs have been terminated.
Finally, regarding the performance guarantees for the contracts under this Agreement, contractors may request a reduction to a minimum amount of USD 100,000 for the period during which the activities remain suspended or until the selected alternative becomes effective.
Agreement 003 of April 30, 2024, issued by the ANH, amended Agreement 003 of 2022 and established that the ANH may contract the operation and management of areas with productive assets that become property of the Nation due to termination of the production period, reversion of productive assets, or any other situation where the management of productive assets of the Nation is necessary. This Agreement was regulated through Agreement 008 of 2024 as explained below.
Agreement 004 of September 27, 2024, issued by the ANH, amended Agreement 002 of 2017, Agreement 009 of 2021, and Agreement 003 of 2022 and established guidelines (definition, scope, mechanisms, and methods of compliance) related to the obligations of contributions for training, institutional strengthening, and technology transfer under the contracts and agreements entered with the ANH.
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Agreement 008 of December 2, 2024, issued by the ANH, repealed Agreement 004 of 2022 and Agreement 006 of 2022 and established the terms and conditions for contracting the operation and management of areas with productive assets owned by the Nation, due to events such as the end of the production period, reversion of productive assets, or, in general, when the management of the Nation’s productive assets is necessary for production in discovered reservoirs.
Agreement 009 of December 2, 2024, issued by the ANH, approved the final terms of reference for the “Permanent Process for Selecting Contractors for the Operation and Management of Areas with Productive Assets” and the draft of the “Contract for the Operation and Management of Areas with Productive Assets”. Additionally, it authorized the President of the ANH to direct and manage the “Permanent Process for Selecting Contractors for the Operation and Management of Areas with Productive Assets” until its conclusion and to issue the contract drafts necessary to incorporate new areas with productive assets.
Resolution 40537 of December 11, 2024, issued by the Ministry of Mines and Energy, repealed Resolution 181495 of 2009 and established new technical measures for the development of activities related to exploration and production of hydrocarbons in the national territory. Some measures established by the Resolution are: (i) the unification and updating of applicable technical regulations; (ii) the authorization of an initial production period under certain conditions while the definitive environmental license is being processed; (iii) the definition of criteria for classifying wells and procedures for drilling and exploitation; (iv) goals and measures regarding carbon neutrality and climate resilience are highlighted, encouraging the oil industry’s plans and strategies for decarbonization and energy efficiency, among others.
Agreement 003 of 16 May 2025, issued by the ANH, adopts measures to promote compliance with and regularization of existing hydrocarbon contracts and agreements within the framework of a just energy transition. The measures adopted are special measures, rules, and certain technical and contractual criteria and conditions regarding: (i) the non-execution of evaluation programs and assessment at points of exploratory activities; (ii) the removal of the obligation to submit a certificate issued by the statutory auditor in contracts with exploratory programs agreed in U.S. dollars; (iii) the types of guarantees, their validity, and reduction; (iv) early extension of the production or exploitation period; (v) breach procedure; (vi) termination and settlement of contracts; (vii) rules to promote the utilization of allocated areas; (viii) modifications regarding compliance with commitments involving investments in renewable energies; (ix) rules on freedom of contract and assignment of contracts; (x) termination and reduction of commitments due to the impossibility of executing the object of the contracts; and (xi) settlement and final report of contracts terminated prior to 2022.
Resolution 0672 of 2025 developed and regulated Article 7 of Agreement 03 of 2025 regarding the first demand guarantee issued in Colombia by non-financial entities under URDG 758, establishing the procedure for due diligence, the documentary requirements, and the formalization through an addendum.
Agreement 007 of 24 October 2025, issued by the ANH, amended Agreement 006 of 2023, establishing that, to request an extension of deadlines during the exploration period or in any subsequent exploratory program, the contractor must, in addition to submitting and/or fulfilling the requirements set forth in Agreement 006, (i) submit updated financial statements, so that the authority may verify the continued maintenance of the contractor’s capacities under the same terms and criteria required at the time of contract execution; and (ii) expressly declare the commitment to maintain the necessary legal, financial, technical, operational, environmental, and corporate social responsibility capacity for the execution of the activities.
Temporary regulation for the Comprehensive Research Pilot Projects (PPII)
We have actively participated in the formulation of specific regulation for the implementation of the PPII. The regulatory framework includes:
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Resolution 1541 of 2021 of the Ministry of Health guidelines for the development of PPII
3.10.1.1.1
Environmental Licensing and Prior Consultation
The ANLA, created by means of Decree 3573 of 2011 (modified by means of Decree 376 of 2020), is the authority responsible for evaluating the applications and issuing the environmental licenses for O&G-related activities, as well as surveilling and overseeing all hydrocarbon projects and monitoring the environmental compliance of such activity.
If the projects or activities could have a direct impact over the territories or the interests of indigenous, Afro-Colombian or Raizal communities, the Colombian Constitution provides that the companies developing such projects or activities must conduct a consultation process with those communities before initiating such projects or activities. This consultation process is a prerequisite for obtaining the required environmental licenses, meaning it is necessary for conducting any intervention, work, or project that generates a direct impact on these ethnically differentiated communities, regardless of whether such impact is positive or negative.
Any person or company that intends to conduct projects, works and/or activities is required to file a request for a statement from the Directorate of the National Authority of Prior Consultation (DANCP by its acronym in Spanish) regarding the applicability of prior consultation. The DANCP will consider the following factors in its decision: (i) the presence of ethnically differentiated communities within or nearby the area of the project, work and/or activity; (ii) the positive or negative impact over the social, economic, environmental or cultural conditions of said communities, and that could be derived from the project, work or activity. Presidential Directive 10 of 2013 (which was subsequently amended by Presidential Directive 8 of 2020), Decree 1066 of 2015, and the Constitutional Court case law have established the phases applicable to the prior consultation process. In August of 2023, the Constitutional Court declared the invalidity of certain provisions applicable to the prior consultation process.
In addition, the Colombian Constitution and laws establish that, as part of the public participation mechanisms, Colombian citizens may request information regarding the activities of the project and their potential impacts. They may also request to undertake an environmental hearing to obtain information on the project subject to environmental licensing.
In this context, the Colombian Constitutional Court has declared the Escazú Agreement to be constitutional, as an instrument that develops and strengthens the principle of environmental participation and access to information. Under this principle, a reinforcement of the role of all stakeholders involved in projects, work, or activities with environmental impacts is expected. Although this treaty remains subject to regulatory development, certain environmental authorities have already cited and applied principles contained in the Escazú Agreement in their administrative actions.
Under Decree 1076 of 2015, Colombian environmental law also provides for figures known as environmental public hearings, which constitute an additional mechanism for environmental participation in connection with projects, works, or activities that may generate significant environmental impacts. Environmental public hearings allow citizens, communities, and other stakeholders to obtain information, present observations, and express concerns regarding projects subject to environmental licensing or control, before the competent environmental authority. These hearings may be requested by citizens, public authorities, or ordered ex officio by the environmental authority, and are intended to strengthen transparency, access to information, and public participation in environmental decision making, particularly in cases where the potential impacts of a project warrant enhanced social dialogue and institutional scrutiny.
On May 26, 2015, the Ministry of Environment and Sustainable Development (Ministerio de Ambiente y Desarrollo Sostenible or “MADS” for its acronym in Spanish) issued Decree 1076 of 2015, which compiles most of Colombian regulations in force regarding environment and sustainable development, including those applicable to environmental licenses.
The environmental license encompasses all the necessary permits, authorizations, concessions and other control instruments necessary under Colombian environmental law to undertake a project or activity that may result in the serious deterioration of renewable natural resources, or that has the capacity of materially modifying the physical environment. The license defines specific conditions under which the license holder shall undertake such project or activity. The procedure to obtain an environmental license begins when the company files an EIA related to the project before the ANLA. The licensing process includes an application for the use of natural renewable resources (water, soil, and air). When the project or activity requires permits for the use of forestry banned species, these should be included in the environmental license process, according to Decree 2106 of 2019. The EIA must be filed as well as a plan to prevent, mitigate, correct, and compensate for any activity that may harm the environment, known as the Environmental Management Plan (Plan de Manejo Ambiental or “PMA” for its acronym in Spanish).
The environmental licensing procedure in Colombia is included in Decree 1076 of 2015. According to the regulation currently in effect, the procedure to obtain an environmental license shall not take more than 90 business days. But, depending on the complexity of the information requested by the ANLA and administrative delays, including an oral hearing to request additional information for the EIA assessment, the procedure may take between 165 and 265 business days, depending on whether the applicant is required to file additional information.
The environmental licensing process for the PPII is established in Decree 1076 of 2015. However, the Ministry of Environment and Sustainable Development issued Resolution 0821 of September 24, 2020, which established the terms of reference for the preparation of the Environmental Impact Study of the PPII.
The MADS is also responsible for issuing regulation and establishing climate change policies for different sectors in Colombia. The Ecopetrol Group complies with all applicable regulations. MADS is responsible for issuing regulation regarding Law 1931 of 2018 (amended by Law 2294 of 2023) (also known as the “Climate Change Law”), which outlines provisions for the establishment of a National Program of Greenhouse Gas (“GHG”) Tradable Emission Quotas (Programa Nacional de Cupos Transables de Emisión de Gases de Efecto Invernadero or “PNCTE” for its acronym in Spanish). The PNCTE must be fully implemented by 2030. The MADS is also responsible for the National Emission Reductions Registry (Registro Nacional de Reducción de Emisiones de Gases de Efecto Invernadero or “RENARE” for its acronym in Spanish), in which companies must register verified GHG emission reductions (Article 175 of Law 1753 of 2015, modified by article 230 of Law 2294 of 2023, and partially regulated by Resolution 418 of 2024, issued by MADS) RENARE started operating in 2021. As part of our continuous monitoring of climate change requirements, we also participated in a regulatory process related to the issuance of Resolution 40066 of 2022 regarding the reduction of fugitive emissions and routine flaring, led by the Ministry of Mines and Energy. A company that does not comply with the applicable environmental laws and regulations, does not execute the corresponding PMAs approved by the environmental authority or ignores the requirements imposed by an environmental license may be subject to an administrative sanction proceeding initiated either by the ANLA or the regional environmental authorities established by Law 1333 of 2009, modified by Law 2387 of 2024, without disregard to the criminal actions that may take place in accordance with law 2111 of 2021. The proceeding may result in oral or written warnings, monetary penalties, fines, license revocation or the temporary or permanent suspension of the activity being undertaken. Besides administrative sanctions, the Colombian judiciary or other law enforcement authorities may also impose civil and even criminal sanctions if environmental damages are verified as a consequence of having breached the environmental laws and regulations applicable to the project.
The Escazú Agreement, which emerged from the 2012 United Nations Conference on Sustainable Development (Rio+20), was negotiated and approved in Escazú, Costa Rica in 2018. Civil society as well as human rights and environmental experts participated in this process and played an essential role in the adoption of this agreement.
This agreement provides for access to information, public participation and justice in environmental matters in Latin America and the Caribbean as well as regional environmental human rights to set forth a framework for environmental democracy, international cooperation and multilateralism in connection with efforts to build back better using a human rights-based approach.
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Colombia is one of the 14 countries to approve the Escazú Agreement. Said agreement was adopted by means of Law 2273 of 2022. On August 28, 2024, the Colombian Constitutional Court confirmed the constitutionality of this law. In this sense, no significant changes are expected in its content that could affect the meaning or main objective of the Escazú Agreement, which is in line with Article 23 of the Escazú Agreement, which expressly establishes that deviations are not admitted. For more information see section Risk Review—Risk Factors—Risks Related to Our Business—Our operations, including our activities in areas classified as indigenous reserves and Afro-Colombian lands, could be subject to opposition from members of various communities.
New environmental regulations
Law No. 2327 dated September 13, 2023 (the “Environmental Liabilities Law”), issued by the National Congress. It contains provisions related to the definition of environmental liability, guidelines for its management, and, in general, provides for a general legal framework for environmental liabilities arising out of the development of projects and works, particularly concerning those environmental liabilities for which a responsible party cannot be easily determined. The law is particularly relevant in the context of hydrocarbon projects, which carry environmental contingencies that may result in environmental liabilities.
The National Government had one year as of the enactment date of the Environmental Liabilities Law to draft and release the environmental liability management public policy guidelines. MADS, in coordination with the Ministry of Finance and Public Credit, would establish the system and method for the financing and allocation of resources for environmental liabilities management. MADS had a term of six months as of the enactment date of Law No. 2327 to issue new regulations to structure the application of the Environmental Liabilities Law. In October 2025, the National Government issued the Guidelines for the formulation, implementation, and evaluation of a public policy for the management of environmental liabilities in Colombia, this document sets out the guidelines for the formulation, implementation, and evaluation of a public policy for the management of environmental liabilities in Colombia, in compliance with Law 2327 of 2023. Prepared by the National Planning Department and the Ministries of Environment and Health, with intersectoral support, the guidelines provide a diagnostic of environmental liabilities, define institutional roles, and establish transversal and strategic axes to guide prevention, intervention, financing, information management, and citizen participation. The guidelines are intended to serve as the technical and policy basis for the adoption of a coordinated national policy aimed at reducing unacceptable risks to human health, life, and the environment associated with environmental liabilities.
In October 2025, MADS issued Resolution 1516 of 2025, which regulates the composition and functioning of the National Committee for the Management of Environmental Liabilities. This resolution advances the institutional framework for implementing the Law by establishing requirements for interinstitutional coordination, governance, and oversight of future public policy on environmental liabilities. In addition, the resolution establishes an Environmental Liabilities Information System, which includes an Environmental Liabilities Registry (REPA, for its acronym in Spanish) to serve as the primary information management tool.
Decree 0582 of July 5, 2024, MADS modified Decree 1076 of 2015 regarding environmental licenses grants for projects of exploration and use of virtually polluting alternative energy sources in Colombia. This new rule extends the definition of virtually polluting alternative energy sources to Non-Conventional Renewable Energy Sources (FNCER) defined in Decree 1715 of 2014. ANLA is the competent environmental authority to issue environmental licenses for exploitation projects of virtually polluting alternative energy sources with installed capacity equal to or greater than 50 MW. Prior to the issuance of this Decree, ANLA’s competence covered projects with installed capacity equal to or higher than 100 MW. The Regional Authorities are granted competence to issue environmental licenses for projects of exploitation of virtually polluting alternative energy sources with installed capacity greater than 10 MW and less than 50 MW. Prior to the issuance of this Decree, CAR’s competence covered projects with installed capacity higher than 10 MW and less than or equal to 100 MW. This Decree only applies to projects that file a license application after October 5, 2024.
In 2025, MADS issued Decree 1033 and Decree 1186, amending Decree 1076 of 2015 to introduce optimized environmental licensing regimes for solar and wind energy projects, known as LASolar and LAEólica, respectively, within the framework of the Fair Energy Transition. Both decrees apply to projects with installed capacity between 10 MW and 100 MW and fall under ANLA’s competence. They incorporate specific environmental siting, technological, and design criteria intended to reduce administrative burdens while maintaining environmental safeguards. Notably, both decrees also clarify when solar and wind projects may be developed in Forest Reserve Areas without requiring a prior subtraction process. This permitted provided the projects meet strict requirements for environmental management, biodiversity protection, and social engagement.
On July 11, 2024, by means of ruling C-280 of 2024, the Constitutional Court of Colombia declared the conditional constitutionality of the second paragraph of Article 57 of Law 99 of 1993, under the understanding that there is a constitutional protection deficit and establishes the obligation to include an evaluation of climate change impacts in the Environmental Impact Assessments (EIA). This requirement is expected to be enforceable for environmental license applications or renewals submitted on or after August 1, 2025. However, to this date there is no update on the reference terms for environmental licensing to include the evaluation of climate change impacts in the EIA submission. As of the date hereof, the MADS has submitted a draft Resolution to set forth generic terms of reference for the preparation of environmental impact studies in relation to the evaluation of climate change impacts that may be produced by works or activities whose execution requires an environmental license.
Law 2387 dated July 25, 2024, issued by the National Congress, which modifies the environmental administrative sanctioning regime. The most relevant aspects of this regulation include the following: (i) the increase of the liability and the amount of pecuniary fines (the new law establishes that the fines will be of up to 100,000 minimum legal monthly salaries); (ii) the inclusion of stage of closing arguments in the environmental administrative investigation process, as established in Article 48 of Law 1437 of 2011 (this stage was previously granted by certain regional environmental authorities, but it was not standardized as a stage of the procedure at the national level); (iii) the possibility of suspension and early termination of the environmental administrative investigation process (this provision allows the environmental administrative investigation process to be suspended and eventually terminated if the infringer proposes and conducts corrective measures and/or compensation for the environmental damage caused); (vi) the definition of Environmental Damage, understood as the partial or total deterioration, alteration or destruction of the environment, and; (v) the event of liquidation, reorganization, or insolvency of a legal entity, according to which the legal counsel or liquidator must inform the environmental authority immediately and provide guarantees to ensure the payment of the obligations arising from the environmental administrative investigation. This new regulation is in force as of its enactment, repealing all contrary provisions. These modifications have direct effects on the ongoing environmental administrative investigations.
On August 28, 2024, the Colombian Constitutional Court issued its decision regarding the constitutionality of Law 2273 of 2022, which approves the Regional Agreement on Access to Information, Public Participation, and Access to Justice in Environmental Matters in Latin America and the Caribbean, commonly known as the Escazú Agreement. The primary objectives of Law 2273 of 2022 are to: (i) ensure access to environmental information, (ii) promote public participation in environmental decision-making processes, (iii) guarantee access to justice in environmental matters, and (iv) protect human rights defenders in environmental issues.
The Ministry of the Internal Affairs issued Decree 1094 dated August 28, 2024, which recognizes the mandate of the Territorial Economic and Environmental Authority (ATEA) as an instrument of law of the traditional authorities of the indigenous peoples of the Regional Indigenous Council of Cauca-CRIC. The aforementioned Decree establishes the powers of the ATEA, the operation and coordination mechanisms with the public authorities for its exercise in the territories that comprise it within the framework of autonomy and self-determination.
On October 15 of 2024, MADS issued Decree 1275, which established the measures required for the operation of the indigenous territories in environmental matters and the development of the environmental powers assigned to the indigenous authorities and their effective coordination with other administrative authorities and/or entities. The traditional indigenous authorities, the authorities of the indigenous territories, the indigenous cabildos and other similar self-government structures in their indigenous reserves, among others, will become part of the National Environmental System (“SINA” for its acronym in Spanish) and will perform its powers related to territorial environmental planning, determination of regulation, management and governance mechanisms for the preservation, conservation, restoration, protection, care, use and management of natural resources in accordance with Article 15 of OIT Convention 169. Said Decree 1275 does not indicate who will have the authority to authorize or deny procedures, permits and/or authorizations for projects whose area of influence includes Indigenous Territories, nor does it mention the implications on projects, works or activities with instruments in force, which are being executed in areas of Indigenous Territories. It is also important to note that according to the scope of application of said Decree, established in Article 4, Afro-descendant people were not included as part of the recognition as environmental authorities.
By means of Resolution 418 of 2024, MADS partially regulated article 175 of Law 1753 of 2015 (modified by article 230 of Law 2294 of 2023) regarding the definition of the administration of the National Greenhouse Gas Emissions Reduction and Removal Registry – RENARE.
On December 15, 2025, MADS issued Resolution 1491 of 2025, through which Law 2173 of 2021 is regulated and other provisions are established. Under Law 2173 of 2021, medium and large companies duly registered in Colombia must implement, on an annual basis, a tree planting program aimed at contributing to ecological restoration, including the planting of at least two trees per employee.
Resolution 1491 of 2025 develops the technical criteria and guidelines for the effective implementation of these programs and for the consolidation of the so-called “Areas of Life.” It clarifies that restoration is not limited to tree planting, but also includes maintenance, monitoring, and follow up activities, including the survival of the planted vegetation, during the first two years. It further establishes that planting activities must be carried out within Areas of Life, understood as zones defined and designated by municipalities or districts, in coordination with the competent environmental authorities, for their identification, management, and ecological restoration purposes. However, there is still uncertainty regarding the practical way these obligations should be complied with and how this framework should work in cities such as Bogotá, where Areas of Life have not yet been formally designated.
3.10.1.1.2Royalties
In Colombia, the Nation is the owner of minerals and non-renewable resources located in the subsurface, including hydrocarbons. Thus, companies engaged in exploration and production of hydrocarbons, such as us, must pay to the ANH, as representative of the Government of Colombia, a royalty on the production volume of each production field, as determined by the ANH.
Royalties may be paid in kind or in cash. Each production contract has its applicable royalty arrangement in accordance with applicable law. In 1999, a modification to the royalty regime established a sliding scale for royalty payments for crude oil and natural gas production fields discovered after July 29, 1999, and depending on the quality of the crude oil produced. Since 2002, as a result of the enactment of Law 756 of 2002, the royalty rate was fixed as a sliding scale depending on the produced volume from 8% for fields producing up to 5 mbd to 25% for fields producing more than 600 mbd. Notwithstanding the royalties for Incremental Production Contracts, Contracts for Undeveloped and Inactive Fields, and Incremental Production Projects defined in paragraph 3 of Article 16 of Law 756 of 2002, and Article 29 of Law 1753 of 2015, the changes in the royalty regime only apply to new discoveries and do not apply to fields already in the production stage as of July 29, 1999. Producing fields pay royalties in accordance with the royalty law in force at the time of the discovery.
With the issuance of Law 2056 of 2020 (“Through which the organization and operation of the general system of royalties is regulated”), the royalties’ regime applicable to the hydrocarbon fields on which there have been made additional investments aimed at increasing the recovery factor of existing deposits was established. Article 18 of this law established that all the volumes produced in these fields will be considered incremental.
For crude oil, the ANH issued Resolution 164 of 2015, modified by Resolutions 907 of 2016, 855 of 2020, and 122 of 2026 to determine the procedures and terms for liquidation of the royalties caused for crude oil production in Colombian territory.
Regarding natural gas, in accordance with Resolution 877 of 2013, as amended by Resolution 640 of 2014, and Resolution 165 0f 2015, starting on January 1, 2014, the ANH has received royalties in cash rather than in kind. Thus, the producer may dispose of its gas production volumes corresponding to royalties paid in cash. Through Resolution 165 of 2015 modified by Resolution 436 of 2021, the ANH established the procedure to liquidate royalties of natural gas.
On September 23, 2021, the Ministry of the Interior issued Decree 1142 “Whereby Decree 1821 of 2020, Sole Regulatory Decree of the General Royalties System, is added and modified.” Article 3.1.1.2.1 of this Decree established that the total volume of hydrocarbons produced that is additional to that stipulated in the basic production curve of incremental production projects or incremental production contracts will enjoy the benefits provided in paragraph 3 of Article 16 of Law 756 of 2002, whereby such additional production is subject to a variable royalty in accordance with the scale set forth in Article 16 of Law 756 of 2002.
Law 2294 of May 19, 2023 amended Article 50 of Law 2056 of 2020 to, among other matters, allow the distribution of royalty resources for the financing of projects related to the creation and updating of roadmaps for the management of environmentally protected areas.
3.10.2
Regulation of Transportation Activities
Hydrocarbon transportation activity is a public interest activity in Colombia and a public service. As such, it is under governmental supervision and control, regulated mainly by the Ministry of Mines and Energy and the Energy and Gas Regulatory Commission.
Transportation and distribution of crude oil, liquefied petroleum gas and refined products must comply with the Petroleum Code, the Code of Commerce and all governmental decrees and resolutions. However, CREG regulates liquefied petroleum gas-related activities. According to Law 681 of 2001, multi-purpose pipelines owned by Cenit (a company wholly owned by Ecopetrol S.A.) must be open to third-party use based on equal access to all.
Moreover, the Ministry of Mines and Energy issued Resolution 40745 of 2023, which regulates (i) multiphase pipeline transportation, which consists of the transportation of a combination of hydrocarbons known as multiphase fluids, (ii) the conditions and requirements for requesting the reclassification of a common crude pipeline to a multiphase pipeline, (iii) the applicable guidelines to access multiphase pipelines, (iv) the transportation contracts and permitted tariffs for multiphase pipelines, and (v) defining the obligations of both, the shipper and the transporter; for this subject matter.
Notwithstanding the general rules for hydrocarbon transportation in Colombia, Law 142 of 1994 defines the regulatory framework for the provision of public utility services, including the provision of natural gas and liquefied petroleum gas. Moreover, natural gas transportation is subject to regulations specific to the natural gas industry as issued by CREG, due to the categorization of natural gas distribution as utility, and therefore, a public interest activity under Colombian laws.
According to Resolution CREG 057 of 1996, natural gas producers, such as us, are not allowed to have significant economic interests in gas transportation companies. Accordingly, we currently do not perform any natural gas transportation activities. On the other hand, and by virtue of the publication of Decree 1467 of 2024, where the Ministry of Mines and Energy incorporates the definition of Infrastructure Conversion and the possibility of using existing infrastructure from hydrocarbon transportation activities for natural gas transportation. In such cases, the Decree establishes that the transportation service provided through converted infrastructure must be provided by a Natural Gas Transporter agent.
Transportation systems, classified as crude oil pipelines and multi-purpose pipelines, may be owned by private parties. Pipeline construction, operation, and maintenance must comply with environmental, social, technical, and economic requirements under national guidelines and international standards for the oil and gas industry.
Construction of transportation systems requires endorsements, licenses and local permits awarded by MME, ANLA and regional environmental authorities, respectively.
Crude oil transportation
Crude Oil Pipelines
According to Resolution 72145 of 2014, the regulatory framework relating to crude oil transportation accounts for both private use and public use pipelines. Private use pipelines are those built by the operating or refining entity for its own exclusive rights and that of its affiliates. Public use pipelines are defined as pipelines built and operated by a public or private legal entity, for the purpose of publicly providing crude oil transportation services. The Colombian Government, through the ANH, has a preferential right to use up to 20% of the total capacity of any public or restricted access pipeline to transportation its crude oil royalties, as provided by Resolution 72145 of 2014. However, for both private and public access pipelines, the ANH must pay the tariff for the pipeline use to transportation its percentage of production.
The Ministry of Mines and Energy is responsible for reviewing and approving the design of and tracks for crude oil pipelines and establishing transportation rates based on information provided by the service providers. It also oversees the calculation and payment of hydrocarbon transport-related taxes and manages the information system for the oil product distribution chain.
In 2014, MME updated the transportation regulation and the rate calculation method for this line of business. It introduced a framework for the secondary market and incentives for new pipeline construction and current pipeline capacity expansions. According to the Petroleum Code, rates must be revised every four years.
During the scheduled revision of 2019, MME, by means of Resolutions 31123 and 31132 of 2019, modified Resolution 72146 of 2014 and established the applicable rules for transportation and oil production companies to negotiate tariffs for the next four years. Once the negotiation period was over, MME issued a series of resolutions to set the applicable tariffs for transportation of crude oil through pipelines. Such resolutions were in line with the tariff methodology that has been in place since 2014, providing more regulatory stability to midstream companies until June 2023.
In August 2022, MME started a consultation process to review, adjust, and update the methodology for setting crude oil tariffs. The scope of the study required contractors to prepare a document proposing changes to the current methodology determined by Resolution 72146 of 2014. The main results of such study were published and analyzed, and the various stakeholders presented their comments to MME.
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On March 30, 2023, MME published Resolution 279 of 2023, which determined that the tariffs set for the period of July 2019 to June 2023 would remain in force until new tariffs were set for the period of July 2023 to June 2027, according to a new methodology yet to be defined. Any tariff or methodology revision must always be developed under the premise of adequate compensation for investments and incentives for access and proper provision of the service for all agents, for which the Ministry must publish the proposed resolution for comments from the agents before its final issuance.
On May 16, 2024, MME published a draft resolution to update the Pipeline Tariff Methodology but maintaining the essence of the current regulation, introducing modifications concerning contingency management and procedures that shippers must follow to certify the crude oils entering the system for transportation, and rules for volumetric compensation applicable to determine the tariff for this activity. The proposed tariff methodology promotes direct agreements between transporters and shippers. Additionally, compared to the current methodology established in Resolution MME 72146 of 2014, various adjustments were proposed, analyzed, and commented on by Cenit and its subsidiary companies within the stipulated period.
On August 26, 2024, MME issued Resolution 895 of 2024 to (i) lift the suspension indicated in Resolution No. 279 of 2023 and allow transporters to conduct the annual update of pipeline tariffs starting on September 1, 2024; and (ii) maintain the suspension of negotiation period regulations established in articles 5A, 5B, 5C, and 5D of Resolution 72146 of 2014.
During 2025, the MME’s regulatory agenda focused on updating pipeline transportation regulations and the corresponding tariff methodology. Midstream companies closely monitored these regulatory developments, particularly the tariff methodology. Through this ongoing engagement, they communicated key concerns to mitigate risks identified during the update process, and to ensure adequate compensation for pipeline transportation activities. Looking ahead, the MME plans to issue the updated transportation regulations in the first quarter of 2026 and the tariff methodology in the third quarter of 2026.
Hydrocarbon Ports
Port Superintendence is the authority that oversees the port business for crude oil and refined products. Although this business is not highly regulated, market participants are required to report certain information to Port Superintendence.
With the purpose of regulating the administrative management of the ports, Law 1 of 1991 was issued, which defines the Port Concession Contract. This document allows a port company to temporarily occupy and use the beach, low tide and accessory areas in exchange for a consideration paid to the nation.
As a result of the enactment of Decree 119 of 2015, operators of private use hydrocarbon ports are currently able to provide hydrocarbon transportation services to third parties pursuant to a mechanism established under that decree.
Decree 119 of 2015 was incorporated into Decree 1079 of 2015 issued by the Ministry of Transport, which compiles most Colombian decrees and regulations in force regarding the administrative sector of transportation. During 2025, Cenit conducted active and coordinated management to obtain authorization from the National Infrastructure Agency (ANI) that would allow a temporary access to the Tumaco port, a strategic facility for the transportation and handling of hydrocarbons in the south of the country. This authorization was issued by ANI in December 2025 for a period of three years.
Refined products and liquefied petroleum gas transportation
In 2014, CREG assumed responsibility for regulating product pipeline transportation from the Ministry of Mines and Energy, in addition to its pre-existing regulatory responsibility for liquefied petroleum gas, natural gas, and electric energy transportation.
In February 2021, CREG issued Resolution 004 of 2021, partially modified by Resolutions 073 of 2021 and 105 003A of 2022 by which CREG defined the Weighted Average Cost of Capital (WACC) methodology applicable to the different activities that CREG regulates. The activities regulated by CREG include energy distribution and transmission, gas distribution and transportation and refined products transportation. The discount rate for transportation of refined products is calculated in accordance with the inputs defined by the resolution and will be applicable once the tariff methodology for this activity is updated and published.
In December 2021, CREG issued Resolution 208 of 2021, partially amended by Resolution 104 002 of 2022, which established the regulations for transportation by multi-purpose pipelines, including transportation of LPG. The main objectives of the regulation are: (i) to ensure access to the transportation system without discrimination; and (ii) to offer optimal conditions in the operation and provision of the public transportation service.
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Also in December 2021, the MME published Resolution 40408 of 2021, which established the refined products pipelines expansion plan.
With draft Resolution CREG 705 002 of 2022, CREG proposed a tariff methodology for the remuneration of the transportation of liquid fuels and liquefied petroleum gas (LPG) through pipelines. This regulatory proposal aims to guarantee a fair and efficient tariff structure, promoting investment in infrastructure and improving service quality. Among the most relevant elements of the resolution are the integration of remuneration for liquid fuels and LPG, the consideration of the technical conditions of the transported products, and the inclusion of mechanisms for the remuneration of infrastructure defined by the central planner.
In 2025, CREG issued draft Resolution CREG 705 009 of 2025, setting forth an updated proposal for the pipeline transportation tariff methodology. This revised proposal includes several of the comments submitted by Cenit in response to the version published in 2022. Although this update represents meaningful progress toward establishing a tariff framework aligned with the sector’s needs, additional work is necessary to adequately promote investment and operational efficiency. Given the potential impact of this initiative on the development of new infrastructure in the liquid fuels sector, CREG submitted the proposal to the Superintendence of Industry and Commerce for its competition advocacy review. This review is a process through which the superintendence evaluates proposed regulations to determine whether they may create unnecessary restrictions on competition, ensuring that new regulatory measures do not unduly hinder market entry, investment, or efficient market functioning. Notably, CREG’s indicative preliminary regulatory agenda for 2026 does not include any reference to this tariff methodology, which suggests that the rulemaking process is in its final stages and that a definitive resolution may be expected in the near term.
In 2025, CREG also presented Resolution CREG 704 008 of 2025 concerning certain procedures for the Pipeline Network Expansion Plan and the Continuity Plan, adopted by the MME. Such resolution is an important regulatory step for the development and execution of strategic projects which ensure the continuity and reliability of refined products transportation in the country, and where Cenit is called to participate.
3.10.3
Regulation of Refining and Petrochemical Activities
Article 58 of the Petroleum Code establishes that oil refining activities can be developed throughout the Colombian territory and are not reserved to the Nation. However, Article 4 establishes that such activities are considered of public interest subject to governmental regulation, and the development of those activities must comply with technical requirements established by regulation.
Law 1205 of 2008, further developed by Resolution 180689 of 2010, issued by the Ministry of Mines and Energy, has the main purpose of contributing to a cleaner environment. It established the minimum quality specifications for liquid fuels in Colombia. Since August 2010, we have been producing and selling diesel and gasoline that comply with the requirements of the aforementioned law.
Since 1995, under Resolution 898 of August 23, 1995, the Ministries of Environment and Sustainable Development and of Mines and Energy, have regulated the environmental criteria for liquid and solid fuels used in commercial and industrial furnaces and boilers, as well as automobile internal combustion engines. Resolution 898 has been subject to numerous modifications through the years, the most recent by Resolution 40444 of June 30, 2023, which states diesel quality requirements to protect the environment, health, and quality of liquid fuels in general.
Article 2.2.1.1.2.2.1.1. and following of Decree 1073 of 2015 establishes the general regulation related to buying and selling fuels in Colombia. With respect to refining activity, the aforementioned Decree provides the requirements and authorization procedures to develop this activity in Colombia. We are duly registered as a refining agent and therefore is authorized to sell fuels in Colombian territory to specific agents and use and acquire fuels as a large consumer, as well in specific oil plants as is published in the information system of liquid fuels of the Ministry of Mines and Energy.
3.10.3.1
Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels
Wholesale marketing, transportation, distribution and retail marketing of LPG are mainly regulated by CREG Resolution 74 of 1996, as amended by CREG Resolutions 96 of 1996, 131 of 2001 and 71 of 2002 and subsequent resolutions. LPG in Colombia is primarily obtained through our refineries, field production and imports. The LPG must meet minimum quality standards to be marketed. Our marketing activities are regulated by CREG Resolution 53 of 2011 (as amended by CREG Resolutions 108 of 2011, 154 of 2014, 19 of 2015, 18, 63, 64 of 2016, 171 of 2017 and 103 00-2 of 2022). The LPG price is regulated by CREG Resolutions 66 of 2007 (as amended by CREG Resolutions 59 of 2008, 002 of 2009, 123 of 2010, 95 of 2011, and 65 and 129 of 2016) as well as by CREG Resolution 80 of 2017 which sets forth that the price of LPG imported by us, which is meant to be marketed for the provision of public utilities, shall be the result of competitive procedures. In Resolution 108 of 2021, issued by CREG, was established the “opción tarifaria” mechanism or “rate option”, which was a temporary mechanism that deferred the impact of the international rate hikes on the selling price of LPG to the final user.
According to Article 4 and 212 of the Petroleum Code and Law 39 of 1987 (added by Law 26 of 1989 and as amended by Law 812 of 2003), the distribution of crude oil and its derivatives have a public purpose (utilidad pública), and the distribution of fuel oil and crude oil by-products is considered a public utility activity. Consequently, individuals or entities engaged in these activities are subject to regulations issued by the Colombian Government. The Government has the power to determine quality standards, measurement, and control of liquid fuels, and establish penalties that may apply to dealers who do not operate in compliance therewith.
The Ministry of Mines and Energy is the entity that controls and exercises technical supervision over the distribution of liquid fuels derived from petroleum, including the refining, import, storage, transportation, and distribution in the country. Article 61 of Law 812 of 2003 (whose validity was extended by Law 1955 of 2019 and Law 2294 of 2023) identified the agents of the supply chain of petroleum-based liquid fuels.
The distribution of liquid fuels, except LPG, is governed by Decree 1073 of 2015 (as amended), which establishes the requirements, obligations, and penalties applicable to supply agents in the distribution, refining, import, storage, wholesale, transportation, retail sale and consumption of liquid fuels.
Decree 1073 of 2015 establishes the minimum technical requirements for the construction of storage plants and service stations. This Decree also regulates the distribution of liquid fuels, except LPG establishing the minimum requirements for distributors and the activities and types of agreements permitted for these agents. The Ministry of Mines and Energy also regulates the types of liquid fuels that can be sold and purchased and the penalties for noncompliance with governmental regulations. Decree 1310 of 2024 amended Decree 1073 of 2015, including some rules regarding the strategic storage of GLP and liquid fuels in the border areas.
Pursuant to Law 1430 of 2010, modified by Article 220 of Law 1819 of 2016, the distribution of fuels in areas near Colombian borders is the responsibility of the Ministry of Mines and Energy and is subject to specific regulations that impose strong control procedures and requirements. The Ministry of Mines and Energy establishes safety standards for LPG, storage equipment, maintenance, and distribution of LPG.
Pursuant to Law 2294 of 2023, National Congress approved article 245 to assign the volume of fuels with tax and economic benefits to the final consumers of the municipalities. During 2026, the National Government is expected to define the methodology for applying tax benefits and mechanisms to control market saturation in the wholesale and retail distribution segment of liquid petroleum fuels in border areas.
The Superintendence of Public Domestic Utilities also oversees the liquefied petroleum gas transportation business.
3.10.3.2
Regulation Concerning Production and Prices
According to the Decree - Law 4130 of 2011 and Decree 1260 of 2013, CREG is responsible for setting the prices of petroleum by-products throughout the entire chain of production and distribution, except for gasoline, diesel and biofuels. On the other hand, by Decree 381 of 2012, as amended by Decree 1617 of 2013, and Decree 2881 of 2013, the Ministry of Mines and Energy is in charge of setting the methodology to determine the reference price of gasoline, diesel, biofuels and mixtures thereof.
Since May 2012, CREG sets the prices for most crude oil by-products, except for gasoline, diesel, and biofuels. CREG determines the methodology to calculate their price while the Ministry of Mines and Energy sets the relevant prices in accordance with said methodology. The ANH does not intervene in the definition of prices of gasoline and diesel fuel. In addition, under Resolution 007 of 2017, CREG determined the basis for the methodology of compensation of terrestrial transportation of liquid fuel-oil, including gasoline, diesel and biofuels between the storage plant and the fuel service station.
The methodology for calculating jet fuel prices is set out in Law 1450 of 2011, and jet fuel prices are set by CREG according to Resolution 40193 of 2021, issued by MME and the Ministry of Finance and Public Credit.
The ANH determines the formula that is used to calculate royalty payments corresponding to the production of crude oil.
Decree 381 of 2012 and 1617 of 2013, as amended by Decree 2881 of 2013, as compiled in Decree 1073 of 2015, restructured the Ministry of Mines and Energy and gave it the responsibility to study industry problems and implement short and long-term refining planning policies. The Ministry is also responsible for establishing the governmental policies and goals to ensure the reliability, stability, and continuity to produce liquid fuels, biofuels and others.
Pursuant to Article 58 of the Petroleum Code, if there is a fuel shortage, any refining company operating in Colombia must offer to sell a portion or, if needed, the total of its production to supply local demand prior to exporting any production.
Fuel Price Stabilization Fund (FEPC)
The Fuel Price Stabilization Fund was created by Law 1151 of 2007. It is a fund assigned and administered by the Ministry of Finance and Public Credit. Its function is to attenuate, in the domestic market, the impact of fluctuations on fuel prices in international markets.
Article 35 of the National Development Plan 2018-2022 (Law 1955 of 2019) established that the Ministry of Finance and Public Credit and the Ministry of Mines and Energy would define the methodology for calculating the producer’s income value of liquid fuels and biofuels, as well as the rates and margins associated with the remuneration of the entire chain of transportation, logistics, marketing, and distribution of such fuels that are part of the regulated market.
Article 244 of the National Development Plan 2022-2026 (Law 2294 of 2023) amended the aforementioned Article 35, adding that the Ministry of Finance and Public Credit and the Ministry of Mines and Energy may determine differential stabilization mechanisms for the structure of reference prices for the public sale of regulated fuels, considering the principles of efficiency and progressiveness.
According to Article 2.3.4.1.3 of Decree 1068 of 2015, amended by Decree 1451 of 2018, the resources for the functioning of the FEPC come from the following sources: (a) financial returns of resources of the FEPC; (b) extraordinary credit resources received from the National Treasury; (c) funds allocated to the FEPC in the national general budget; (d) fuel taxes and; (e) bonds or other public debt securities issued by the Nation in favor of the FEPC, in order to cover the obligations of the FEPC.
The operation of the FEPC is governed by Decree 1068 of 2015 Chapter 1, and Title 4 (compilation decree regarding treasury public sector), amended by Decree 1451 of 2018. First, refiners and/or importers of regular gasoline and diesel must report to the Ministry of Mines and Energy the volume of regular gasoline and diesel sold in the previous month including imported fuel that was subsequently distributed to meet national demand. Such reports must be made within the next 35 calendar days following the month in which the operations took place.
The aforementioned report must also contain, among other matters: information corresponding to each fuel commercialization operation, including a summary of such operations, the discrimination of the volumes sold, and the origin national or imported of the gasoline and diesel sold. Additionally, the report must include the date on which the operation was accrued and if any subsidy applies. If regular gasoline or diesel is produced in Colombia, the local refiner must inform the refinery where it was produced.
Secondly, the Ministry of Mines and Energy calculates and liquidates, by resolution, the net position of each refiner/importer and each fuel to be stabilized by the FEPC on a quarterly basis.
Decree 1068 of 2015, amended by Decree 1451 of 2018, provides that the FEPC pays in Colombian pesos the value corresponding to the calculation and settlement of the Net Position of each refiner and/or importer within the term defined by the Ministry of Mines and Energy and based on availability of FEPC resources.
Law 1819 of 2016 as amended created a tax related contribution to finance the FEPC. This contribution is caused when the sum of the Differentials of Participation (difference between the Producer Revenue and the International Parity Price, when the first is greater than the second on the date of issuance of the sales invoice, multiplied by the volume of fuel sold) is greater than the sum of the Differentials of Compensation (the difference presented between the Producer Revenue and the International Parity Price, when the second is greater than the first on the date of issuance of the sales invoice, multiplied by the volume of fuel sold).
The event that generates the contribution is the sale in Colombia of gasoline or diesel by the refiners and/or importers to the wholesale distributor of fuels, according to the price set by the Ministry of Mines and Energy, however, if the importer is at the same time a wholesale distributor, the triggering event shall be the withdrawal of the product to be sold. The taxpayer responsible for the contribution is the refiner and/or importer and the active subject is the Nation. The tax base corresponds to the positive difference between the sum of the Differentials of Participation and the sum of the Differentials of Compensation.
The Ministry of Mines and Energy calculates the contribution through the liquidation of the Net Position of each refiner or importer with respect to the FEPC based on the report that the refiners and/or importers submit. If the sum of the Differentials of Participation is greater than the sum of the Differentials of Compensation and the contribution is caused, the Ministry of Mines and Energy will order the refiner or the importer to pay the contribution to the National Treasury within the 30 days following the execution of the liquidation resolution.
Subsequently, Law 1837 of 2017 (Article 16) provided that the remaining resources that were in our accounts as of December 2014, as a result of the collection of the Differential Contribution from the FEPC, would be transferred to the General Direction of Public Credit and Treasury of the Ministry of Finance and Public Credit (DGCPTN for its acronym in Spanish). In addition, Law 1955 of 2019 (Article 33) authorizes the Ministry of Finance and Public Credit to enter into hedging agreements and establishes the conditions thereof, for purposes of guaranteeing the sustainability and the functioning of the FEPC. Law 1955 of 2019 authorizes the Ministry of Finance and Public Credit, as administrator of the FEPC, among others, to carry out, directly or indirectly, the design, management, acquisition and/or execution of hedges on the Ministry of Finance’s direct exposure to (i) crude oil and liquid fuel oils prices in the international market or (ii) the exchange rate of the Colombian Peso. This law also authorizes the Ministry of Finance to set stabilization mechanisms of the reference recommended retail prices of regulated fuel oil, as well as the subsidies to such regulated fuel oils to be executed through the FEPC. Law 2342 of 2023, which sets forth the 2024 national general budget, gave the MHCP the ability to utilize different budgetary tools to address the debts relating to the FEPC, and to set off these debts against dividends that it would be entitled to receive from Ecopetrol as its major shareholder. This provision was subsequently modified by Article 71 of Law 2559 of 2025, which enacted the Budget of Income and Capital Resources and Appropriations Law for fiscal year of 2025. Under Article 71, the Ministry of Finance and Public Credit may use the following payment alternatives to meet FEPC obligations, including those incurred in prior periods: (i) issue bonds or other public debt securities, which would not constitute a budgetary operation and would only be budgeted for purposes of redemption and interest payments; (ii) use available uncommitted debt service budget appropriations; (iii) use available FEPC cash balances; and/or (iv) offset, in whole or in part, the FEPC’s liquidated obligations to the Ecopetrol Group against dividends declared by Ecopetrol S.A. in favor of the Nation, without requiring cash movement between the parties or constituting a budgetary operation. These provisions will remain in effect until the national government implements alternative sustainable energy and gas sources.
As of December 31, 2023, Ecopetrol S.A. recorded COP 16.4 trillion in accounts receivable due from FEPC and Cartagena Refinery recorded COP 4.1 trillion in accounts receivable due from FEPC.
On April 1, 2024, the Ministry of Mines and Energy settled its net position corresponding to the first quarter of 2023 in favor of (i) Ecopetrol S.A., for an amount of COP 6,305,038,090,159.81, by means of Resolution 00297, and (ii) Refinería de Cartagena S.A.S., for an amount of COP 1,534,914,852,627.40, by means of Resolution 00296. See section Financial Review—Factors Affecting Our Operating Results—Fuel Price Stabilization Fund (FEPC).
On June 8, 2024, the Ministry of Mines and Energy settled its net position corresponding to the second quarter of 2023 in favor of (i) Ecopetrol S.A., for an amount of COP 4,109,054,714,024.82, by means of Resolution 0540, and (ii) Refinería de Cartagena S.A.S., for an amount of COP 1,008,291,095,755.84, by means of Resolution 00541.
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On September 10, 2024, the Ministry of Mines and Energy settled its net position corresponding to the third quarter of 2023 in favor of (i) Ecopetrol S.A., for an amount of COP 3,749,512,065,086.77, by means of Resolution 01012, and (ii) Refinería de Cartagena S.A.S., for an amount of COP 965,950,525,099.75, by means of Resolution 01011.
On November 15, 2024, the Ministry of Mines and Energy settled its net position corresponding to the fourth quarter of 2023 in favor of (i) Ecopetrol S.A., for an amount of COP 2,286,216,138,799.36, by means of Resolution 01507, and (ii) Refinería de Cartagena S.A.S., for an amount of COP 555,059,027,840.35, by means of Resolution 01508.
On June 18, 2024, the MHCP issued Decree 0763, establishing that the income for fossil fuel producers of regular motor gasoline and diesel acquired by (i) agents authorized as large consumers; or (ii) those final consumers with an average annual consumption exceeding 20,000 gallons per month, regardless of their consumption per facility or delivery point, must be at least the international parity price. This means that the fuel acquired by these entities will not be stabilized or subsidized by the FEPC.
Resolution 40304 of August 2, 2024, established the procedure for determining the international parity price to be used as producer income within the price stabilization differential mechanism. It is the obligation of the refining or importing agent to calculate the producer income, publish it on their official website, and communicate it to their wholesale distributor clients and maritime service stations. Subsequently, wholesale distributors must communicate the resulting prices to retail distributors acting as industrial marketers, who, in turn, must communicate them to their large consumer and final consumer clients subject to the differential mechanism.
Resolution 40305 of August 2, 2024, established that, twice a year, the MME will publish on the SICOM platform and its website a list of large consumers and final consumers to whom the price stabilization differential mechanism applies. To determine inclusion on this list, the MME will use data on the volume of liquid fuels dispatched by refining agents, importers, wholesale distributors, and retail distributors acting as industrial marketers or maritime service stations over the last twelve (12) months as of each cutoff date.
On March 18, 2025, the Ministry of Mines and Energy settled its net position corresponding to the first quarter of 2024 in favor of (i) Ecopetrol S.A., for an amount of COP 1,727,183,344,199.28 by means of Resolution 299, and (ii) Refinería de Cartagena S.A.S., for an amount of COP 501,867,931,397.22 by means of Resolution 300. On April 25, 2025, the Ministry of Mines and Energy settled its net position corresponding to the second, third and fourth quarter of 2024 in favor of (i) Ecopetrol S.A., for an amount of COP 4,269,421,463,317 by means of Resolution 544, and (ii) Refinería de Cartagena S.A.S., for an amount of COP 1,159,252,875,942 by means of Resolution 543.
Payments received from FEPC in 2024 and 2025 are made in cash or through Colombian Government treasury securities, which remain in Ecopetrol’s treasury until they are sold.
3.10.3.3
Regulation of Biofuels, Biogas and Related Activities
The sale and distribution of biofuels and biogas is regulated by the Ministry of Mines and Energy. Regulations establish the quality and pricing standards for biofuels and impose minimum requirements for mixing ethanol with gasoline and biodiesel with diesel. Resolution 40447 of October 31, 2022, amended by Resolution 40391 of 2023 and 40431 of 2024, orders retail distributors, such as fuel service stations, and wholesale or large distributors of fuel, to only commercialize blended fuels with a specific percentage of biofuel or fuel alcohol per gallon, depending on the month and year of the commercialization.
The sale and distribution of biogas is provided under CREG Resolution 240 of 2016, which particularly regulates: a) the sorts of market that will be served with biogas and biomethane; b) the quality and safety conditions; and c) the tariff regime. Pursuant to Article 4 of the foregoing Resolution, biogas supply through isolated networks to serve non-regulated users and natural gas vehicles (GNV as per its acronym in Spanish), shall be incorporated as a public utility company. Furthermore, Article 5 provides that biomethane supply through isolated networks or interconnected networks to the National Transportation System shall also be incorporated as a public utility company. Finally, Article 12 states that biogas suppliers may develop the production, transportation, distribution, and commercialization activities through integrated structures, provided that they keep separate accounts for each activity and grant free access to the networks to both regulated and non-regulated users. To the same extent, production, distribution, and commercialization of biomethane through interconnected networks to the National Transportation System may be developed through integrated structures, as long as the supplier keeps separate accounts for each activity and grants free access to the networks to both regulated and non-regulated users.
In May 2023, the National Congress approved National Development Plan 2022-2026 through Law 2294 of 2023. In connection with biofuels, biogas and related activities provides that the Ministry of Agriculture and Rural Development, the MADS and the MME regulate the proportion of biofuels present in the mix of liquid fuels, due to the relationship between biofuels and the agricultural sector. It also established the framework to intervene in the FEPC regulation prices methodology as well as regulation related to strategic storage of fuels, biofuels, LPG and others.
In December 2025, the MME published a draft regulatory framework for public comment aimed at enhancing the supply of natural gas, biogas, and biomethane. Among other matters, the proposed framework addresses biomethane targets in the energy mix, conditions for biogas in isolated networks, energy community participation, and technical requirements for pilot projects.
3.10.4
Regulation of the Natural Gas Market
Decree 1073 of 2015, Part 2, Title 2, Chapter 2, modified by Decree 1467 of 2024, established that all producers have to issue a production statement that includes the volumes of natural gas available for sale for a period of ten years. This decree established the regime for the selling and marketing of natural gas in Colombia, including specific procedures that regulate the Colombian market in order to manage the remaining natural gas reserves owned by the Nation, and to protect domestic consumers, especially residential consumers, by prioritizing delivery of gas to residential consumers, regulating the export of natural gas and setting forth the export restrictions applicable during an internal shortage of natural gas.
Currently in Colombia the price of natural gas is determined freely by the market. In relation to transportation of gas, CREG issued Resolutions 185 of 2020 as amended by CREG Resolutions 126 and 175 of 2021, 102-11 of 2022, 102-05 of 2023, 102-10 of 2024 and 102 021 of 2025.
Pursuant to Decree 1073 of 2015 and article 19 of CREG Resolution 102-015 of 2025 the commercialization procedures do not apply to the following activities: (a) supply agreements that are executed to respond to specific natural gas system contingencies; (b) natural gas that will be used for petrochemical activities; nor (c) negotiations for natural gas produced in the natural gas testing wells.
In 2024, Colombia faced a potential natural gas deficit due to several factors, including the El Niño phenomenon (which significantly increased demand for natural gas for thermal energy production), a decline in natural gas reserves, and a reduction in exploration contracts. These circumstances culminated in the issuance of MME Resolution 40444 of 2024, declaring a scheduled natural gas rationing. In response, CREG issued Resolutions 102 007 and 102 009 of 2024, aimed at adjusting natural gas commercialization rules to enhance efficiency in the allocation and distribution of natural gas. CREG Resolution 102-015 of 2025 consolidates Colombia’s wholesale gas commercialization regime, replacing Resolution 186 of 2020 and updating market rules to align with current policy. The resolution became effective on June 1, 2025, with certain provisions becoming effective upon publication. Key changes under the resolution include: (i) streamlined primary market mechanisms while preserving existing seller and buyer classifications; (ii) a more flexible, codified procedure to prioritize supply for essential demand; (iii) authorization for specific cases of joint commercialization, subject to CREG approval; (iv) updated contract types and minimum terms, including firm contracts subject to conditions and price indexation provisions; (v) stricter requirements for import sellers, who must now demonstrate access to import infrastructure through appropriate certification (CIDVF/PTDVF); and (vi) transitional measures to coordinate supply arrangements with in-year transport capacity contracting.
CREG determines which agents can participate in the primary and secondary markets. We are authorized to participate as a seller in the primary market as a natural gas producer and as a buyer to acquire natural gas for our operation. We can also participate in the secondary market when we require natural gas from other producers for our own needs. CREG regulations provide that a natural gas producer cannot participate as a merchant of natural gas in the secondary market, except for the purchase of gas to meet its existing contractual obligations. We are also able to resell available natural gas transportation capacity into the secondary market as a non-regulated consumer.
On February 16, 2023, President Gustavo Petro issued Presidential Decree 227 of 2023 by means of which he “reassumed” (as stated in such Presidential Decree) the powers to regulate the natural gas market that were delegated to CREG, in accordance with article 68 of Law 142 of 1994. Nonetheless, Presidential Decree 227 of 2023 was suspended by the High Court for Administrative Matters (Consejo de Estado) via writ 00045 of 2023, in response to an annulment action filed before said organism. On July 7, 2023, the High Court for Administrative Matters (Consejo de Estado) confirmed the initial decision to suspend the aforementioned Presidential Decree after the appeal presented by the National Government. As of the date of this annual report, Presidential Decree 227 of 2023 is suspended until the High Court for Administrative Matters (Consejo de Estado) issues a final decision on the annulment action.
Decree 1467 of December 10, 2024 amended Decree 1073 of 2015 to adopt public policy measures aimed at enabling offshore natural gas sources and natural gas imports. Among these measures Decree 1467: (i) regulated the priority in the supply of natural gas; (ii) established that producers must declare their disaggregated production on a monthly and long-term basis, and import gas marketers must declare the quantities available for sale during the year; (iii) set forth certain exceptions to commercialization mechanisms; and (iv) regulated commercialization mechanisms for firm contracts subject to certain conditions.
In December 2024, the Colombian Public Utilities Superintendence (Superintendencia de Servicios Públicos Domiciliarios, or SSPD) published for public comment a draft regulatory amendment intended to align its supervisory framework with Decree 1467 of 2024, which updated the rules applicable to the importation and regasification of natural gas. Following this consultation process, on January 13, 2025, the SSPD issued Resolution No. 20251000008335, which partially repealed Resolution No. 20201000057975 of 2020 by eliminating the following: (i) certain definitions and requirements applicable to gas import and regasification activities, including the obligation for participating agents to adopt the legal form of a public utilities company (E.S.P.); (ii) assimilation of marketing of imported gas to marketing activities under Colombian natural gas regulation and (iii) assimilation of regasification activities to transportation activities under Colombian natural gas regulation. These regulatory changes seek to streamline oversight, reduce entry barriers, and enhance flexibility and competition in the Colombian natural gas import market.
In December 2025, the MME published for public comments a draft regulatory framework to enhance natural gas, biogas and biomethane offer, among other matters. The draft regulatory framework establishes precedent conditions for offshore basins supply contracts, removes intermediation in the secondary market, and introduces updated definitions to clarify gas availability, self-consumption and commercialization rules within the wholesale gas market.
Priority for the Supply of Natural Gas
The export of natural gas, in contrast, is not considered a public utility activity under Colombian law and therefore is not subject to Law 142 of 1994. Nevertheless, the domestic supply of natural gas is a priority for the Colombian Government and therefore, extends such priority and commitment to all agents working within the natural gas market (producers, producers-retailors, retailors, transporting and exporting agents - article 2.2.2.2.15 of Decree 1073 of 2015) and is considered a public utility complementary activity, and therefore public utility regulations apply to the internal supply of natural gas.
Decree 1073 of 2015 (amended by Decree 2345 of 2015) provides that in the event the supply of natural gas is reduced or halted as a result of a shortage, the Colombian Government has the right to suspend the supply of natural gas for export. If such export contracts are suspended by the Colombian Government, the export agents are entitled to receive compensation in accordance with Article 2.2.2.2.15 and 2.2.2.2.38 of Decree 1073, 2015. Notwithstanding the foregoing, Decree 1073 of 2015 establishes freedom to export natural gas under normal gas-reserve conditions. Producers of natural gas may enter into natural gas export contracts if the ratio of proved reserves to consumption exceeds seven years, as determined by the Colombian Energy Planning Authority (or UPME for its acronym in Spanish).
On January 30, 2025, the Colombian Ministry of Mines and Energy issued Resolution 40031 of 2025, which formally adopted the Natural Gas Supply Plan for 2023–2032, based on the technical study prepared by the UPME. This plan establishes the Government’s medium- and long-term framework to ensure the security and reliability of natural gas supply in Colombia, identifying priority infrastructure projects, supply sources, demand coverage strategies and demand segments. The plan applies to calendar year 2025 and subsequent years and reinforces the prioritization of essential demand, including residential users, critical industrial activities and electricity generation, particularly under supply-constrained scenarios. Complementing this planning framework, Resolution CREG 102-015 of 2025 operationalized demand prioritization within the wholesale gas market by defining methodologies for the allocation and maximum contracting of gas volumes subject to priority criteria, thereby integrating supply security considerations directly into market contracting practices.
Decree 1073 of 2015 (amended by Decree 1467 of 2024) establishes a mandatory order of supply when restrictions are placed on the supply of natural gas or serious emergency situations arise that preclude the continued provision of certain services, as follows: (i) essential demand, as established in Decree 1073 of 2015, (ii) non-essential demand under an existing firm agreement, and (iii) firm exports delivery.
The order of priority for the supply of natural gas is as follows: (i) the operation of the compressor stations of the National Transportation System, (ii) residential users and small business users engaged in the distribution network, (iii) vehicular compressed natural gas and (iv) gas refineries, excluding those destined for self-generation of electricity that can be replaced with energy from National Transportation System, which has priority. The Ministry of Mines and Energy also establishes distribution priorities in the event of a natural gas shortfall derived from supply or infrastructure issues. This order of priority is based on the type of contract, with firm supply contracts having priority over interruptible supply contracts.
Circular 40039 of December 15, 2025, issued by the Ministry of Mines and Energy, informs the wholesale natural gas market of the immediate application of measures and regulations adopted to ensure the continuity, reliability, and security of supply for essential demand within the framework of a fair energy transition, particularly through the prioritization of essential demand via interruptible supply contracts, as provided in MME Resolution 40563 of 2025 and CREG Resolution 102 015 of 2025. The Circular sets out:
Natural gas waste restrictions
The Ministry of Mines and Energy issued Resolution 40066 of 2022 as amended by Resolution 40317 of 2023 by means of which it regulates the use of natural gas, establishing the obligation for hydrocarbon producers to carry out the necessary studies for its efficient use. It also establishes that natural gas waste is prohibited in Colombia and provides certain examples of what it considers could constitute natural gas waste during hydrocarbon exploration and exploitation activities.
The Resolution establishes the scenarios in which burning and venting of gas is allowed in the stages of exploration and exploitation of hydrocarbons, as well as the technical parameters to efficiently and responsibly execute these activities, when expressly authorized. This Resolution also sets standards for natural gas leak detection, quantification, repair, and control in respect of the activities performed on natural gas exploration and exploitation fields. This Resolution regulates the detection and repair programs to prevent leaks, the elements included therein, as well as the reports that must be delivered to Colombian authorities.
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For the Company’s progress in complying with this Resolution, see section Risk Review—Legal and Regulatory Risks—Our operations might be affected by rising climate change and energy transition regulatory developments.
3.10.5
Regulation of the Electric Energy Commercialization Activity
As determined by article 11 of Law 143 of 1994, commercialization activities, which are developed by commercialization agents, consist of the purchase of electricity in the MEM and the subsequent resale to other participants of the wholesale market such as commercialization agents, generation agents, or to end-customers, both regulated and non-regulated. Ecopetrol Energía S.A.S E.S.P. (“Ecopetrol Energía”), a subsidiary of Ecopetrol S.A., was registered as a commercialization agent before the manager of the commercial exchanges systems and performs commercialization activities within the MEM. However, explained below, Ecopetrol Energía faced winding up procedures due to a possible interpretation of competition rules which could prohibit Ecopetrol’s participation in other complementary activities of the energy sector other than transmission, due to its acquisition of ISA Intercolombia S.A. E.S.P. (ISA) in 2021.
Commercialization activity is regulated by CREG Resolution 156 of 2011, which establishes regulations, rights and duties of agents. The main income of commercialization agents is derived from the variable and fixed components of the unit cost tariff formula described in CREG Resolution 119 of 2007, as modified by CREG Resolutions 156 of 2009, 173 of 2011, 191 of 2014, 30 of 2018, 101-03 of 2022, 101-18 of 2022, and 101-28 of 2023. The variable component considers:
The Regulated Market is comprised of individual and industrial customers, residential or commercial, with electricity demands below 0.10 MW or monthly consumption lower than 55 megawatt-hours (“MWh”). Regulated Customers are free to select any service provider. However, tariffs are subject to a regulated freedom of choice regime, whereby commercialization agents are required to follow the criteria and methodology set forth by CREG, which establishes the parameters that must be used by electric energy agents in setting forth the maximum applicable charges for the services they provide. Purchases of electricity in the Regulated Market are made through public bids to ensure open and free access; however, during 2024, due to the impact of the “El Niño” phenomenon, CREG issued CREG Resolution 101 057 of 2024 implementing a transitory rule. The transition consisted of contracts with a maximum performance term until December 31, 2025. Under this provision, retail agents serving the demand of regulated users were authorized to execute contracts under the pay-as-contracted modality directly, without the requirement to conduct an auction.
The Non-Regulated Market is comprised of electricity consumers that either have a peak demand greater than 0.10 MW or a minimum monthly consumption greater than 55.0 MWh. This segment is attended by companies conducting the generation and commercialization activities. Purchases of electricity in this segment can be freely agreed among participants at freely negotiated prices for the commercialization and generation components of the tariff’s unitary price.
Resolution CREG 015 of 2018 establishes the obligations for Network Operators (owner of the physical networks) and commercialization agents for the transportation and distribution of energy. It also regulates the quality standards for the delivery of energy at the point of consumption, and the applicable methodology for calculating the distribution charges of each Network Operator.
As determined by article 74 of Law 143 of 1994, as modified by article 298 of Law 1955 of 2019, any utility company that makes part of the SIN can generate electricity (which consists of the production of electricity through any generation plant connected to the National Interconnected System (SIN as for its acronym in Spanish), activity performed by generation agents, who participate in the MEM by selling electric energy to other generation and commercialization agents, or to Non-Regulated Users), distribution (which consists of transporting and delivering electric energy to end users through the STR, and the Local Distribution Systems (SDL for its acronym in Spanish) deploying tension levels under 220 kV; agents in charge of providing the distribution utility are called Distribution Agents or Grid Operators (OR for its acronym in Spanish)), and commercialization activities in an integrated manner. Nevertheless, these companies are not allowed to perform transmission activities, as explained below.
This provision described above, also applies to companies having the same controlling party or between those where there is a situation of control, which encompasses the real beneficiary rationale applicable under Colombian electric energy regulation (for reference see article 74 of 1994, as amended by Law 1955 of 2019. A situation of control is defined by article 260 of the Code of Commerce, as follows: “a company will be subordinated or under a situation of control when its decision-making power is subject to the will of another or other persons who will be deemed its parent or controlling company (…)”. On the other hand, transmission companies are prevented by law from holding market shares in generation, commercialization, or distribution companies (see CREG Resolution 001 of 2006).
In relation with transmission, (which comprises the transportation of electrical energy in the Colombian National Transmission System (STN for its acronym in Spanish), deploying tension levels of 220 kV or higher, guaranteeing the required quality standards and the availability of the transmission assets; the owners of the transmission assets must ensure free access to the transmission networks to the users and to generation agents.) companies carrying out this activity are not able to perform commercialization, distribution or generation activities. However, commercialization, distribution and generation companies are allowed to hold shares, quotas, or equity stakes of transmission companies, if they represent no more than 15% of the company’s capital. Please note that, in this case, neither the transmission company nor the other companies may have a control situation over the other.
Exceptionally, commercialization, distribution and generation companies may own more than 15% of a transmission company if the income of the transmission company does not represent more than 2% of the total transmission income from the SIN. If the company engaged in the transmission activity, with a cut-off date of December 31 of each year, exceeds this limit, the commercialization, generation, or distribution company who has shares, quotas or interest shares in the capital of the company must sell, within six months following the occurrence of this fact, the shares, quotas or interest shares that exceed 15% of the capital stock of the transmission company. This, unless within the same period, the transmission company sells the assets that makes it exceed the 2% limit of the total income. (see CREG Resolution 95 of 2007). Notwithstanding the foregoing, pursuant to CREG Resolution 101-74 of 2025, generation and commercialization companies may exceptionally hold shares, quotas or equity interests representing more than 15% of the share capital of a company engaged in National Transmission activities that represents more than 2% of the total transmission income of the National Transmission System, provided that such generation or commercialization company has submitted a voluntary withdrawal request from the Wholesale Energy Market (MEM) before the Administrator of the Commercial Exchange System (ASIC), in accordance with CREG Resolutions 024 of 1995 and 156 of 2011, as amended, supplemented or replaced, and provided further that it: (i) has no firm energy obligations in force, whether directly or indirectly; (ii) does not represent, directly or indirectly, any commercial metering points in the energy market; (iii) does not have, directly or indirectly, contracts registered in the MEM or in any other market instances where energy purchases and sales are carried out; (iv) has received an official communication from the ASIC confirming that the voluntary withdrawal request is admissible and that the process for effective withdrawal from the market has commenced; and (v) maintains the conditions set forth in items (i) through (iii) above for as long as it holds such participation in the transmission company.
As presented above, Ecopetrol Energía and, since August 2021, ISA, were subsidiaries of Ecopetrol S.A. Ecopetrol Energía was a commercialization company and ISA has a significant percentage of the market share of the national transmission activity. Therefore, and considering the competition rules mentioned above, CREG established that we shall divest from Ecopetrol Energía or cease any commercialization activity as soon as reasonably practicable. As mentioned above, on October 1, 2024, the Company concluded the liquidation process of Ecopetrol Energía S.A.S. E.S.P.
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Accordingly, on August 15, 2022, we entered into an electric energy commercialization agreement with Gecelca S.A. E.S.P. to meet the non-regulated energy demand of the Ecopetrol Group. The contract, which term extends until December 31, 2036, is to ensure a service structure for the supply of electric energy through the SIN for the Ecopetrol Group in order to provide the necessary coverage while optimizing costs. Gecelca S.A. E.S.P. was selected through a competitive process to which 17 agents among generators and retailers of the Wholesale Energy Market were invited.
Law 142 and 143 establish specific rules that apply to ISA regarding its participation in certain activities. Articles 167 of Law 142 and 32 of Law 143 establish that ISA is not allowed to participate in any generation, commercialization, or distribution activity. However, the National Development Plan issued by Law 2294 of May 2023 removed these specific restrictions to ISA. The Constitutional Court admitted a lawsuit against this provision and its final decision is pending. In any case, limitations set forth by article 74 of Law 142 of 1994 described above, may prevent Ecopetrol or any of its subsidiaries from conducting generation, commercialization, or distribution activities.
3.10.6
Regulation of the Electricity Self-Generation Activity
Law 1715 of 2014 (amended by Law 2099 of 2021) regulates the integration of non-conventional and renewable energies to the SIN. Among other aspects, this law obliges the Colombian Government and CREG to develop the regulatory framework for the promotion of the electricity self-generating activity from non-conventional renewable energy sources and the sale of self-generation surpluses.
The self-generation activity is defined as the activity conducted by either people or legal entities to produce electricity mainly to meet their own needs. In case there is a surplus of energy, not consumed by the self-generator, such surplus may be delivered to the grid on the terms established by CREG (See CREG Resolutions 024 of 2015 and 174 of 2021, which application depends on whether the self-generator is a large-scale or a small-scale self-generator, as explained below).
Based on Law 1715 of 2014, Decree 2469 of 2014, as compiled by Section 4 of Decree 1073 of 2015, which established energy policy guidelines regarding the delivery of self-generation surpluses through the SIN. In addition, this decree sets forth the parameters for a person to be considered as an electricity self-generator. Specifically, it states that in order to be considered a self-generator a person must (a) receive electricity for its consumption without it being necessary to use assets of the SIN, (b) the electricity surpluses may be higher in any measure, and without any regulatory limit or restrictions, than the value of its own consumption, (c) for the delivery of surpluses to the SIN it will be necessary for the self-generator to submit itself to the regulation of CREG, case in which large-scale self-generators must be represented before the wholesale energy market, and (d) the generation assets may be owned by the self-generator and may be owned and operated by third parties.
Decree 348 of 2017, as currently compiled by Section 4A of Decree 1073 of 2015, establishes public policy guidelines on efficient energy management and delivery of small-scale electricity self-generation surpluses. In addition, this regulation establishes the conditions for the connection of small-scale self-generators (AGPE for its acronym in Spanish) to the SIN, the parameters to be an AGPE, the reporting of surpluses to the UPME and the remuneration of surplus energy. Note that, as determined by Resolution UPME 281 of 2015, the maximum electricity generation limit to be considered an AGPE is one (1) MW and will correspond to the installed capacity of the self-generator’s generation system. Above that limit, an electricity self-generator will be considered a big-scale electricity self-generator (“AGGE” as per its acronym in Spanish).
The specific regulation for AGGE is currently determined by CREG Resolution 024 of 2015, whereas the specific regulation for AGPE is currently set by CREG Resolution 174 of 2021.
CREG Resolution 024 of 2015 (modified by CREG Resolution 140 of 2017) sets conditions for surplus sales of an AGGE, connection and metering conditions, and back-up and energy supply conditions. Specifically, this resolution determines that AGGE must follow the general connection rules to the SIN for a generation plant, that they must have a remote telemetry system, and that they must have a back-up power purchase agreement, among others.
CREG Resolution 174 of 2021 establishes the connection conditions for AGPE, and for the AGGE with a capacity under 5 MW surplus sales conditions, metering conditions and energy commercialization rules for AGPE.
The Ecopetrol Group has invested in several projects that are considered projects from AGGE, which means that CREG Resolution 024 of 2015 is the main regulation that applies to our self-generation projects, notwithstanding the rules applicable pursuant CREG Resolution 174 of 2021. As of the date of this annual report, we comply with all regulations, as set forth in the above-mentioned resolution and Decree 2469 of 2014 regarding the delivery of electricity surpluses to the SIN and to its subsidiaries or controlled parties.
In July 2021, Congress issued Law 2099 of 2021, modified by Law 2294 of 2023. These pieces of legislation regulate aspects related to energy transition and updated provisions with respect to the development and promotion of unconventional sources of energy, energy efficiency and clean hydrogen.
Listed below are certain relevant aspects of Law 2099 of 2021 as amended:
The new law brought amendments to Law 1715 of 2014 on the declaration of public and social interest, which consists in the promotion, stimulation and incentive to the development of generation activities, use, storage, administration, operation and maintenance of non-conventional energy sources, mainly those of renewable sources (“FNCER” for its acronym in Spanish). The qualification of public utility or social interest is expected to have positive impacts in such projects and grant them preference rights in issues related to land use, planning and environmental planning, economic promotion, positive valuation in administrative procedures and forced expropriation. The new regulation includes those projects related to storage within those that can be part of the declaration of public and social interest, which is a nod to the development of such projects for the purposes of energy efficiency and energy transition;
Green hydrogen was added as a FNCER and blue hydrogen as FNCE. Green hydrogen is produced from FNCER such as biomass, wind energy, geothermic energy, solar energy, tidal energy and small hydropower. Nevertheless, Law 2294 of 2023 establishes that green hydrogen can be produced by energy coming from the SIN. On the other hand, blue hydrogen is produced from fossil fuels, especially by the decomposition of methane and its production process has a system of carbon capture, use and storage. Finally, white hydrogen was added as a FNCER through Law 2294 of 2023. White hydrogen is “associated with geological processes in the earth’s crust and found in its natural form as free gas in different geological environments either in layers of the continental crust, in the oceanic crust, in volcanic gases, and in hydrothermal systems, such as geysers” (definition introduced by Law 2294 of 2023);
The Ministry of Mines and Energy, or the entity designated by it, was appointed as the entity to establish guidelines for the development of geothermal energy in Colombia and must create a geothermal registry in which all projects intended to explore and exploit geothermal energy to generate electricity will be registered. The Ministry of Mines and Energy may establish special registration conditions for already existing projects of co-production of electric energy and hydrocarbons, to avoid the overlapping of projects, define the areas that will not be subject to registration and determine conditions, terms, requirements and obligations;
The law states that the Colombian Government will develop the necessary regulations for the promotion and development of carbon capture, use and storage systems (CCUS) technologies. CCUS should be understood as the set of technological processes the purpose of which is to reduce carbon emissions in the atmosphere, capturing the CO2 generated on a large scale from fixed sources to store it under earth in a safe and permanent manner. Under the same logic, the Colombian Government will design a public policy to promote research and local development of technologies for the production, storage, conditioning, distribution, re-electrification, energy and non-energy uses of hydrogen and other low-emission technologies within six months after the entry into force of this law. Furthermore, the Ministry of Mines and Energy will promote the reconversion of mining and hydrocarbon projects that contribute to the energy transition. For this purpose, the ANH and the National Mining Agency may design mechanisms and agree on conditions in current and future contracts that encourage the generation of energy through FNCE, the use of alternative energy sources, and the capture, storage and use of carbon; and
The policy for the development of electric energy services in the so-called non-interconnected zones is strengthened through: (i) service reliability, (ii) transfer of resources for lower tariffs, (iii) transfer of assets, and (iv) hybrid solutions.
In July 2022, the Colombian Government published Decree 1318 of 2022 setting out the general terms and definitions of exploration and production of electric energy from geothermal activities. The provisions of this decree were further developed through CREG Resolution 40302 of 2022. Decree 1598 of 2024, issued by the Colombian MME, amends Decree 1073 of 2015 to establish a regulatory framework aimed at fostering the exploration and utilization of geothermal energy. This initiative is part of Colombia’s broader energy transition strategy to diversify its energy matrix and promote non-conventional renewable energy sources (FNCER), including geothermal energy.
In August 2022 the Colombian Government issued Decree 1476 of 2022 regulating articles 21 and 23 of Law 2099 of 2021 and adding a new chapter to promote innovation, research, production, storage, distribution and use of low-emission hydrogen. Decree 1598 of 2024, issued by the MME, amends Decree 1073 of 2015 to establish a regulatory framework aimed at fostering the exploration and utilization of geothermal energy. This initiative is part of Colombia’s broader energy transition strategy to diversify its energy matrix and promote non-conventional renewable energy sources (FNCER), including geothermal energy. Among others: (i) it introduced a system to certify the origin of hydrogen, ensuring traceability for both domestic consumption and export markets; (ii) enhanced the Ecosystem H2 Colombia, a national information system to promote and manage the hydrogen value chain and (iii) set forth several regulations regarding Colombia’s commitment to achieve carbon neutrality in 2050 by incentivizing the production and use of low-emission hydrogen.
By means of Resolution MME 40284 of 2022, as amended by Resolution MME 40712 of 2023 and further updated by Resolution MME 40368 of 2024, the Ministry of Mines and Energy established the general terms for granting temporary occupation permits for maritime areas, as well as the granting of maritime concessions intended for the development of offshore wind energy projects. These permits will be awarded through a competitive process to be conducted by the ANH, which began on December 4, 2023. During 2024, the prequalification process was initiated for the first round, qualifying companies such as Parque Eólico Offshore Vientos Alisios SAS ESP, CI GMF III COOPERATIEF UA, JAN DE NUL NV, Ecopetrol SA, Powerchina International Group Limited, CTG Colombia Holding SAS, Duna Energy Latinamerica, Seynekun ESG Solutions SAS, Enterprize Energy (UK Limited), Celsia Colombia SA ESP and DEME Concessions Wind. The successful bidders must form a consortium, temporary association or partnership with a public or mixed company of the oil & gas or energy sector (first paragraph of article 18 of MME Resolution 40284 of 2022 as amended by MME Resolution 40368 of 2024).
In November 2024, the MME issued Decree 1403, amending Decree 1073 of 2015 to update Colombia’s energy policy guidelines on self-generation and marginal production of electricity. This decree introduced the possibility for self-generators and marginal producers to use the National Interconnected System (SIN) to consume electricity at locations different from where it is produced, eliminating previous regulatory barriers. To implement these policy guidelines, the MME subsequently issued MME Resolution 40379 of 2025— later extended in its validity by MME Resolution 40575 of 2025—which establishes the temporary rules, requirements, and enabling obligations applicable to remote self-generators and marginal producers using the SIN, while expressly providing that such rules shall remain in force until CREG issues the corresponding final regulation. These changes aim to foster the use of non-conventional renewable energy sources, supporting Colombia’s transition to a more sustainable energy landscape. For companies engaged in self-generation and potentially entering into distributed marginal production (such as Ecopetrol), Decree 1403 presents significant opportunities to expand operations and optimize energy distribution across various locations, aligning with the country’s commitment to renewable energy integration.
During 2025, Colombia’s regulatory framework for electricity self-generation experienced significant developments through executive and regulatory actions, rather than legislative reform. In April 2025, CREG issued Resolution 101-072 of 2025, which established a harmonized regulatory framework for collective self-generation and energy communities. This regulation enabled groups of users to jointly self-generate electricity, including through virtual aggregation mechanisms within the same distribution system and commercial market, and defined technical, commercial, and remuneration rules applicable to surplus energy injected into the grid. This marked a shift from a predominantly individual self-generation model toward collective and community-based schemes.
In addition, during 2025 the UPME adopted measures that expanded the scope and system integration of self-generation activities. Through Decree No. 972 of 2025, the Government created the “Colombia Solar” program, formally recognizing solar self-generation by residential users in lower-income strata as a policy instrument and an alternative to traditional electricity subsidies. Separately, the UPME issued Resolution 000749 of 2025, which unified and updated the procedures for the registration of generation projects, including self-generation and remote self-generation, making such registration mandatory for projects operating in the National Interconnected System. Together, these measures increased regulatory visibility, broadened participation in self-generation schemes, and reinforced the role of self-generation within Colombia’s electricity system planning and energy transition policy.
In accordance with the guidelines established in Decree 1403 of 2024, the CREG issued Resolution 101099 of 2026, which regulates the conditions applicable to remote self-generation and remote marginal production. This resolution is the result of the regulatory process initiated with the publication of the draft regulation in 2025, and establishes the technical, commercial, and operational requirements under which self-generators and remote marginal producers may use the networks of the National Interconnected System (SIN) to meet their own demand or that of economically linked users.
3.10.7
Regulatory Framework for Energy Transmission
In the countries in which ISA operates, energy transport is a regulated and independent activity within the electricity sector’s production chain and is considered a natural monopoly, although there are different business models in the electricity industry in those countries. In Colombia and Chile, the transmission companies own the assets and infrastructure. In Peru and Brazil, companies obtain concessions to operate assets and infrastructure and revert ownership to governments once the concessions expire; In Bolivia, transmission is part of the National Interconnected System (SIN) under a regime regulated by the Government/Republic of Bolivia, where the National Electricity Company (ENDE), through its subsidiaries, is the main operator and responsible for most of the transmission infrastructure. In each of those models, the companies must provide the service with the quality standards defined by the regulation and, by virtue of this, receive the corresponding remuneration. The revenues are not affected by the supply and demand for electricity or the volume of electricity consumed by end users.
In general, the revenues of transmission companies are comprised of two components: the first remunerates the investment at a regulated revenue, while the second remunerates the administration, operation and maintenance expenses required to provide the service with quality and efficiency. The revenues are adjusted on an annual, semiannual or monthly basis, based on inflation, as measured by the relevant consumer and producer price indexes or in some cases by the PPI or the WPI.
Electricity transmission is defined by article 1 of CREG Resolution 24 of 1995 and article 3 of CREG Resolution 11 of 2009, applicable CREG regulations, as the transportation of electricity through national electricity transmission systems at a tension level equal to or greater than 220 kV and is remunerated through usage charges for constructive units that comprise the National Transmission System (STN).
Colombian regulations establish the responsibility of the Nation, through UPME, to prepare the Reference Generation Transmission Expansion Plan. The projects proposed in the STN expansion plans must be technically and economically feasible and must have the approval of the relevant environmental authorities mentioned above. The STN expansion procedure, as provided in applicable regulations including CREG Resolution 022 of 2001, guarantees a competitive bidding process summoned by UPME with respect to the construction, operation and maintenance of new electricity transmission expansion projects.
Pursuant to number IV of section a of article 4 of Resolution CREG 22 of 2001, ISA must present a proposal to participate in every bidding process summoned by UPME. Such bidding processes are awarded to the investor or bidder who offers the lowest present value to be received as expected annual income (IAE) for a period of 25 years. Once the 25-year payment period elapses, the successful bidder is expected to be compensated through the regulated revenue tariff methodology established by Resolution CREG 011 of 2009 (or the transmission activity methodology that is in effect at that time), for agents who operate existing transmission assets.
The remuneration applicable to existing assets is regulated by CREG Resolution 011 of 2009 by means of a regulated revenue tariff methodology, which establishes usage charges for constructive units, considering the reposition value; the administration, operation and maintenance costs; and some asset availability and quality indexes. Thus, the quality of the transmission service is defined according to asset availability and Energy Not Supplied (ENS). Transmission companies may be liable for deductions from their regulated revenue, when they are unable to provide a good service.
The most recent plan prepared by UPME and adopted by the MME was the Transmission Expansion Plan for 2024–2038, aimed at modernizing the National Transmission System (STN) and implementing new tenders. Additionally, through Resolution 40004, published on January 14, 2026, the MME declared as urgent a set of projects that had been under review and approval by UPME as part of the planning analyses conducted during 2025. These projects incorporate the development of new technologies, including a group of synchronous condensers, expected to be developed and to start operations in 2029. The development of the works approved in the resolution is expected to begin shortly under the procedures established in the regulation.
Meanwhile, Decree 227 of 2023, by means of which President Gustavo Petro “reassumed” (as stated in such Presidential Decree) the powers to regulate the energy market that were delegated to the CREG, in accordance with article 68 of Law 142 of 1994, remains suspended by the Council of State, and therefore the CREG still holds its regulatory functions.
The public electricity transmission service of the SIN comprises the facilities of the Basic Grid (“RB”), Other Transmission Installations and International Interconnection Installations. In accordance with Regulatory Resolution 67 of July 8, 2004, the RB comprises the SIN facilities with voltage level equal to or higher than 230 kV, while the RBF comprises the SIN power transformer units with voltage level higher than or equal to 230 kV on the high voltage side and lower than or equal to 230 kV on the low voltage side. Transmission services are operated exclusively through concessions, in which the Brazilian government grants private agents, through bids, the right to build, operate and maintain the facilities.
The planning for the sector is centralized and conducted by Energy Research Company and National Electric System Operator, which, with the support of the other agents of the sector, evaluate the need for expansion or reinforcement of the transmission system, identifying the necessary works that will be indicated to the Brazilian Ministry of Mines and Energy to compose the concession plan that National Electric Energy Agency (Agencia Nacional de Energía Eléctrica or “ANEEL”) intends to use to issue reinforcement authorizations or bidding notices. It is ANEEL’s responsibility, based on the indications and definitions of the electricity transmission subsidy plan, to proceed with the concession process of the indicated works, promoting transmission tendering or authorizing existing transmission companies to implement the indicated works in their facilities.
As defined in module 4 of the Transmission Standards in Brazil, the quality of the transmission service is measured by the availability and operational capacity of the Transmission Function. When the Transmission Function is available or operates with capacity restrictions, the transmission company suffers a reduction of its Allowed Annual Revenue proportionate to this unavailability.
Brazil currently operates under ANEEL’s 2025–2026 Regulatory Agenda, approved through Ordinance 6,909/2024 and revised by Ordinance 6,997/2025. The agenda establishes regulatory priorities regarding transmission system use-of-system charges (UST), climate resilience, market liberalization, and the regulation of concession terminations, guiding ongoing regulatory adjustments and bidding processes.
Transmission lines belong to four national systems: Guaranteed, Complimentary, Principal and Secondary, with this last one being the largest one.
There are basically three transmission plans that allow the expansion of the transmission network: (i) the transmission plan that is designed by Committee of Economic Operation of the Electrical System (“COES”) every two years and subject to the approval of MME, (ii) the Investment Plan approved by Energy and Mining Supervisory Authority and (iii) the expansion plan of the network subject to REP’s concession which must filed by REP before the MME.
Once the transmission plan is approved, the binding plan projects (facilities that are part of the guaranteed system) must be tendered through international public bidding for the granting of new concessions through the signing of a contract under the build–own–operate–transfer modality. The bidding processes have been entrusted by the Peruvian Energy and Mines Ministry (“MINEM”) to the Peruvian Private Investment Promotion Agency. The tender is awarded to the investor who offers the lowest investment cost. The works defined as expansions or reinforcements can be granted to those concessionaires who express their right of preference if such expansions or reinforcements involve their facilities.
The quality of the electricity service is governed by the Technical Standard for the Quality of Electricity Services, approved by Supreme Decree 020-97-EM of 1997. This standard establishes the minimum quality levels of the electrical services with regard to the quality of the product, supply, commercial and public lighting; as well as the obligations of the electricity companies and the clients that operate under the regime of the Electricity Concessions Law, Decree Law 25844.
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Currently, the country operates under the Transmission Plan 2025–2034, approved by Ministerial Resolution 483-2024-MINEM/DM, which has been effective from January 1, 2025, and is expected to be effective until December 31, 2026. This plan includes 19 major transmission projects, with an emphasis on 500 kV links, substation expansions, and strategic works. Commercial operation of such projects is expected between 2029 and 2030, in accordance with Law No. 28832 and the Transmission Regulations (DS 027-2007-EM). Likewise, COES updates the methodologies and expansion criteria to provide the technical and economic basis for prioritizing new works in the backbone system and in connection facilities.
The public electricity transmission service provided in the National Electric System (“SEN” for its acronym in Spanish) includes the installations of the following segments: (i) the National Transmission System, (ii) the Local Transmission System, (iii) the Dedicated Transmission System and (iv) the Transmission Systems for Development Poles.
Regarding the process of planning investments in transmission, the General Law of Electric Services establishes centralized planning directed by the National Energy Commission for the National, Local and Development Poles Transmission Systems. This process is for a term of at least 20 years and is intended to result in the expansion plan which defines new and expansion works will be mandatory. The regulation then defines two types of works, which are remunerated differently: (i) new work is a transmission line or electrical substation that does not exist and is projected to increase the capacity or safety or quality of service of the SEN and (ii) extension work is one that increases the capacity or the safety and quality of service of existing electrical lines and substations.
For new works, the investor is selected through public tenders organized by the National Electric Coordinator (“CEN”). If the bids exceed the maximum allowed value, the tender is repeated. For expansion/reinforcement, the transmission company tenders the projects, and the developer with the lowest bid is awarded. The project is developed under the EPC modality; that is, the awardee must take care of the detailed engineering, the supply of materials, and the construction of the work, and payment is made by milestones during execution.
The conditions of safety and quality of service are contained in the Technical Standard of Safety and Quality of Service. The quality of supply of generation and transmission services is evaluated through the index of unavailability of the transmission facilities.
As of 2026, the SEN is facing increasing levels of congestion and curtailment of renewable energy, which exceeded 6,127 GWh in 2024 according to recent reports. This situation has driven the prioritization of projects classified as “necessary and urgent” under Article 91 bis of Law 20,936. The CEN continues to publish the Transmission Expansion Proposals corresponding to the 2025 and 2026 processes, along with analyses highlighting the need for new structural works, including HVDC links toward the 2036 horizon. At the same time, the Ministry of Energy and the CEN continue advancing the Transmission Planning Regulation, a key component for the full implementation of Law 20,936, which is being developed through technical working groups with sector stakeholders.
In Bolivia, electric transmission is regulated under the Electricity Law 1604 of 1994, which separates generation, transmission, and distribution under concession schemes and regulates tariffs, open access, and service quality through regulations such as the Electricity Market Operation Regulation (DS 26093), the Prices and Tariffs Regulation (DS 26094), and the Transmission Quality Regulation (DS 24711). The transmission network forms the backbone of the National Interconnected System (“SIN” for its acronym in Spanish), connecting generators, distributors, and unregulated consumers, while in remote areas Vertically Integrated Isolated Systems (SAVI) operate, performing all three activities.
The main operator and developer of transmission infrastructure is the Boliva itself through the National Electricity Company (ENDE), a state-owned company that, through its subsidiaries, concentrates most of the strategic transmission and generation assets, leads expansion and interconnection projects, and executes works prioritized by the government. Network planning is based on the Referential Electric Plan of the Plurinational State of Bolivia 2035, which defines reinforcements, expansions, and new interconnections to integrate isolated systems and meet growing demand, in line with the country’s energy transition policy and the objectives of the PDES (Economic and Social Development Plan) 2021–2025.
Projections from the CNDC (National Load Dispatch Committee) estimate that the SIN’s peak demand will reach approximately 1,907 MW in 2025 and 1,967 MW in 2026, highlighting the need for network expansion under ENDE’s leadership
3.10.8
Regulation of the Toll Roads Concessions
Beginning in the early 1990s, Colombia adopted modernization and economic liberalization policies, and implemented structural, institutional and industry specific reforms. These have included the expansion and promotion of infrastructure and public utilities in conjunction with the private sector. Different regulatory reforms have been implemented, such as Law 80, Law 105 and Law 1508 of 2012 (the Public Private Partnerships Law, “PPP Law”).
The PPP Law is one of the most representative in this sector, by implementing the regulatory framework for the development of public and private partnerships (“PPP”) for different types of infrastructure, including transportation.
Likewise, some laws related to PPP projects and the public procurement regime in general have been enacted, such as Law 1150 of 2007, Law 1474 of 2011, Law 1682 of 2013, Decree 1082 of 2015, Law 1778 of 2016, Law 1882 of 2018, Decree 438 of 2021, Law 2195 of 2022, Law 2294 of 2023 oriented to introduce different mechanisms and procedures to strengthen and streamline the development of PPP projects. Also, Decrees 050 and 2287 of 2023 were issued as means of reducing high inflation by controlling when toll rates/tariffs could be increased.
Regulation of Public Private Partnerships (PPP)
The PPP Law allows the execution of concession contracts for different types of infrastructure, including transportation infrastructure (i.e. roads & highways, airports, seaports, rails, etc). Under this law, payments to concessionaires are subject to meeting and maintaining key performance indicators (KPIs) defined in any given contract.
PPP contracts assign risks to the party in the best position to control and mitigate its effects. Likewise, it must contain formulas for recognition of economic compensation to the concessionaire for the early termination of the contract and the constitution of a trust fund to manage the project’s resources.
The PPP Law introduced a distinction between public and private initiatives for PPP Projects. Public initiatives are defined by the granting authority and a qualified concessionaire is selected through a competitive bidding process. On the other hand, private initiatives have been introduced to allow the private sector to structure and propose to the granting authority a specific project or service.
The implementing legislation of the PPP Law is compiled by Decree 1082 of 2015 and was modified by Decree 438 of 2021, through which, some definitions associated with PPP were implemented, in order to align rules between projects and national and territorial prioritization, define liquidity mechanisms to avoid early termination of contracts in Private Initiative PPPs, promote competition and establish requirements for the presentation of private initiatives, among others. Decree 1082 of 2015 was also modified by Decree 142 of 2023 to promote access to the Public Procurement system for medium and small-sized companies (Mipymes), Cooperatives, and other entities of the solidarity economy. It incorporates social and environmental criteria in the contracting processes of State entities and includes the title of communal entrepreneurship.
Furthermore, Law 1682 of 2013 provides tools to overcome common bottlenecks that usually affect the feasibility of transport infrastructure projects. The main contributions of Law 1682 of 2013 are:
4G – 5G Highway Concessions
In Colombia, five generations of road concessions have been developed since 1994, which have had as a differentiating aspect the allocation of risks between the contracting agency of the Nation and the private partner, as well as the complexity of the transactions.
The 4G Program, which includes Public and Private Initiative Projects, aims to reduce Colombia’s infrastructure deficit, and consolidate the national road network by creating continuous and efficient connectivity between production centers, the country’s main ports and country boundaries.
Since 2019, some modifications to the 4G program have been promoted, giving rise to the creation of the 5G Program, which was launched through the document CONPES 4060 “Bicentennial Concessions” and seeks to regulate some key aspects for the development of infrastructure, under the premises of project sustainability based on four pillars: institutional, social, environmental, and financial. This 5G Program implements contractual modifications aimed at improving property management, risks associated with natural disasters, climate change, economic compensation for commercial risk, among others. As a characteristic feature, the 5G program comprises not only toll roads concessions, but also river dredging and navigation concessions, airport concessions and railway concessions.
In January 2023, the Ministry of Transportation of Colombia signed Decree 050 of 2023, prohibiting an increase in toll rates based on the 2022 CPI, as defined in the PPP contracts. This decision is based on the government’s effort to control inflation, which led CPI to experience a 13,12% increase in 2022. However, the concession agreements provide mechanisms that compensate the difference between (i) the toll rate’s structure foreseen when the concessionaire submitted its bid, and (ii) the effects that the Decree 050 of 2023 has on the income of the toll rates; since the risk associated to toll rates increases is contractually assigned to the grantor.
During 2023, the CPI dropped. Thus, on December 29, 2023, the Ministry of Transportation issued Decree 2287 establishing that such entity will issue resolutions regulating toll rates increase beginning in January 2024, for toll stations under the purview of the National Institute of Roads (Instituto Nacional de Vías or “INVIAS” for its acronym in Spanish) and ANI. According to such Decree, toll rates will be adjusted in January in accordance with 2022 CPI. On January 15, 2024, the Ministry of Transportation issued Decree 20243040001125, to increase the toll rates for the INVIAS and ANI stations.
Pursuant to Decree 050 of 2023, the Ministry of Transport, the National Institute of Roads (Invías), and the National Infrastructure Agency (ANI) have been designing mechanisms to restore the toll rates before December 31, 2024, in order to normalize the system. In this regard, they have published a resolution mandating the gradual normalization of toll rates in two phases: the first on January 1, 2025, and the second on April 1, 2025. This aims to implement a gradual transition of toll costs, minimizing the immediate impact on users. Toll rates have been normalized since.
Furthermore, at the beginning of 2025 the National Government issued Decree 069 of 2025, which amid several budgetary measures, aimed to introduce the possibility to postpone future budgetary allocations (vigencias futuras) of some specific projects, either because mutual agreement between the private party and public entity was reached or because the project schedule was breached. However, it is important to clarify that, despite the issuance of Decree 069 of 2025, there has not been a unilateral postponement of future budgetary allocations, meaning that each postponement has been a bilateral agreement between the concerned parties.
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Moreover, the National Government further issued, on December 29, Decree 1472 of 2025, by means of which an amendment to the future budgetary allocations (vigencias futuras) regime was introduced. Through this decree, an article in Decree 1082 of 2015 regarding the postponement of future budgetary allocations was amended, regulating a procedure to request before the Fiscal Superior Economic Council – CONFIS an amendment on deadlines and amounts of future budgetary allocations in PPP projects, so long as several requirements are met.
In summary, although Decree 1082 of 2015 already provided for the postponement of future budgetary allocations, amendments were permitted only with respect to their term, not their value. Now, with the issuance of Decree 1472 of 2025, a request may be submitted to CONFIS to amend either the term or value of the annual disbursement of future budgetary allocations so long as the overall approved value of future budgetary allocations is not modified. Said request to CONFIS must include:
To improve the level of maintenance of the Chilean road infrastructure and reduce the demands on public finances, starting in the early 1990s, the Chilean government began to grant concessions, with a pre-assigned model of obligations and rights between the public and private sectors.
The execution, repair and conservation of public works are governed by the Statute of the Public Works Concessions Law, originally contained in Decree with Force of Law No. 164 of 1991, which allows people and entities, to exploit the works and services of said public works that are the object of a concession.
Likewise, the following laws and decrees have been promoted in relation to Public and Private Partnerships (PPP) projects: Law No. 19,252 of 1993 Supreme Decree No. 900 of the Ministry of Public Works (MOP), Supreme Decree No. 956 of 1997 of the MOP, Law No. 20,128 of 2006, Law No. 20,190 of 2007 and Law No. 20,410 of 2010, all of which are aimed at facilitating the execution of projects under the PPP scheme.
The provisions of the concession contracts generally govern the term and termination of the concessions, the works to be carried out, the operation and maintenance obligations, government supervision, the maintenance reserve funds, certain fees payable to the government and the fees for toll that can be charged.
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The concessionaire is responsible for the construction, financing, operation, and maintenance of the infrastructure in accordance with the standards, specifications, and designs established by the Ministry of Public Works or, failing that, in the bidding conditions, and is obliged to correct any defect in the road that arises during the term of the concession. In exchange for developing these activities, the concessionaire is entitled to retain substantially all toll revenues derived from the operation of the toll road during the term of the concession. The road itself and the accessories related to its operation remain the property of the government during the term of the concession.
Each concession establishes a schedule of tolls by vehicle category. Most concessions allow concessionaires to increase tolls annually in accordance with Chile’s CPI. Such toll increases can be made without government approval, although supporting documentation must be submitted to the MOP. All other toll rate increases must be approved by the MOP. The MOP has the right to terminate a concession without compensation before the expiration of its term in the event of the occurrence of specified events. Furthermore, the government has the legal right to seize any concession and claim all assets related to it.
Panamá
Panamá developed PPP legislation for long-term contracts between public and private entities, allowing private companies to finance, build, operate, and maintain infrastructure projects or provide public services in exchange for fees.
Law 93 of September 19, 2019 establishes the framework for PPPs in Panama, aiming to promote private investment, social development, and job creation. Furthermore, Executive Decree No. 840 of December 31, 2020, partially modified by Executive Decree No 119 of May 4, 2020, implemented Law 93, providing detailed regulations and guidelines for the execution of PPP projects.
The provisions of the concession contracts generally govern the term and termination of the concessions, the works to be carried out, the operation and maintenance obligations, government supervision and the yearly provisions on Panama’s budget to cover the project costs.
3.11
Technology, Environment, Social and Governance (TESG)
The TESG pillar of the 2040 Strategy reflects Ecopetrol’s commitment to responsible business conduct. The Company aims to operate safely and efficiently while minimizing environmental impact and upholding human rights. These objectives are supported by an ethical and transparent governance framework, along with the technological capabilities needed to develop innovative solutions for current and future challenges.
Ecopetrol strives to strengthen its metrics and reporting practices related to TESG matters, by complying with national regulation and certain international standards published by organizations such as the Global Reporting Initiative (“GRI”), the Sustainability Accounting Standards Board (“SASB”), and the Task Force on Climate-related Financial Disclosures (“TCFD”). The Company discloses clear short, medium-, and long-term targets, while measuring its performance against these commitments and tracking progress over time. GRI standards are a widely used framework for sustainability reporting, providing standardized guidelines that enable organizations to measure and communicate their environmental, social, and governance performance in a consistent and comparable manner. On November 10, 2025, Ecopetrol published its first 2024 Financial Sustainability Report in accordance with the GRI framework, in line with its commitment to transparency, sustainable value creation, and a fair and equitable energy transition for Colombia.
Ecopetrol’s sustainability performance was assessed through S&P Global’s Corporate Sustainability Assessment (CSA) as part of its participation in the 2025 Dow Jones Sustainability Index (“DJSI”), based on 2024 performance. Ecopetrol achieved a score of 62 points, placing the Company in the 93rd percentile among its peers in the Oil & Gas Upstream & Integrated sector.
In 2023, the Company updated its materiality assessment, which is the basis of its sustainability agenda, by applying a double materiality approach and engaging a broad group of internal and external stakeholders. This methodology provides a comprehensive perspective on sustainability management by considering both (i) the actual and potential impacts of Ecopetrol on its environment, and (ii) the actual and potential implications of TESG issues on the Company’s financial performance, strategic objectives and reputation. This approach reinforces transparency and accountability in Ecopetrol’s engagement with stakeholders.
As a result of this assessment, 14 TESG issues were prioritized, and four elements were identified as crosscutting: just transition, human rights, corporate governance, and circularity. These four elements were not treated as discrete issues to be managed; instead, they were recognized for their strategic and enabling role across all material issues. Each of these matters is considered equally important within Ecopetrol’s management framework. The 14 material issues represent topics with significant impact (positive or negative) on Ecopetrol’s ability to create value in the short, medium, and long term, and/or topics of high relevance for stakeholders.
The 14 prioritized material issues are:
In 2025, the Company updated and approved 11 out of 14 roadmaps for the issues above; these roadmaps completed the full revision cycle and received formal governance approval. The remaining three roadmaps (water; innovation, science and technology; and financial sustainability) were reviewed and presented to the Strategic Committee for initial guidance, with formal approval pending completion of the revision cycle.
The identification and prioritization of Ecopetrol’s stakeholders was also updated in 2023. This process enables the Company to build more effective relationships grounded in trust and mutual benefit. As a result of this assessment, the Company expanded its stakeholder map from seven to 11 groups: (i) the Nation, (ii) employees, (iii) communities, (iv) partners, (v) suppliers and their workers, (vi) controlled companies, (vii) shareholders and investors, (viii) media and opinion leaders, (ix) clients, (x) civil society and cooperation organizations, and (xi) the scientific and academic community.
To strengthen its management and communication with stakeholders, Ecopetrol conducts an annual perception and expectations survey. This assessment evaluates the relevance and level of satisfaction of different stakeholders associated with key issues, identifies opportunities for improvement and emerging matters, and detects potential risks that could affect the Company’s reputation or stakeholder trust. Through this process, Ecopetrol ensures that its corporate strategy remains aligned with stakeholder expectations. These results are key inputs for reviewing and prioritizing the material issues mentioned above. These results also enable the Company to design and implement annual engagement plans for each stakeholder, translating the value propositions defined for them into specific actions. This approach allows Ecopetrol to strengthen both business continuity and trust within its surroundings, particularly in the territories where the Company operates.
In 2025, the percentage of respondents who reported being “very satisfied” or “satisfied” with their relationship with Ecopetrol was as follows: controlled companies: 96%, employees: 95%, partners: 92%, media and opinion leaders(*): 87%, suppliers and their workers(*): 86%, civil society and cooperation organizations: 84%, communities: 78%, clients: 74%, scientific and academic community(*): 67%, the Nation: 65%, and shareholders and investors(*): 38%.
(*) The participation rate was below 30%. For the stakeholder groups State, Communities, and Civil Society and Cooperation Organizations, the participation level was not calculated, as there was no initial database available to establish this indicator. Consequently, the databases were progressively built as the consultations were carried out.
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Human Rights
Throughout 2025, Ecopetrol worked on taking concrete steps to implement its human rights strategy. As a result of this exercise, we achieved the strengthening of public commitment to respect human rights by updating internal guidelines (Guide on Human Rights and Business and Human Rights Risk Management Cycle Guide), on the identification and management of human rights risks, as well as on value chain management (both with suppliers and partners). Ecopetrol carried out two human rights risks assessments at a regional level (Caribe and Central), contributed to the risk assessment at Guajira and followed up on the risk assessments of Orinoquía, Andina Oriente and Piedemonte Regionals, and of its security process. These due diligence exercises allow the Company to identify, prevent, mitigate and, if applicable, remedy impacts on human rights. As a result, Ecopetrol established actions that counteract the risks and impacts identified. The Company’s human rights management has undergone scrutiny by the Dow Jones Sustainability Index (DJSI), which highlights that Ecopetrol’s performance in this area has steadily improved over the years. This improvement is evident in its alignment with the UNGPs, as well as in the prevention and mitigation of human rights risks at the operational level, in communities, and with other stakeholder groups. It is noteworthy that, in the last measurement conducted in 2025 for the period 2024, the Company demonstrated the best performance in the human rights category. A score of 100/100 was achieved in four (4) out of the four (4) categories assessed: commitment, due diligence, evaluation and remediation.
Environmental Planning and Compliance
Based on the mitigation hierarchy principle, Ecopetrol S.A. undertakes a robust field baseline environmental and social sensitivity information within the project’s area of influence and conducts EIAs to identify potential environmental and social impacts at the early stages of project planning and design. Environmental Studies and diagnosis are developed to comply with regulatory requirements for environmental licenses and permits and environmental and social management plans are developed to minimize, mitigate, or compensate impacts.
In 2025, 54 total authorizations were granted, of which one was granted by the National Authority for Environmental Licenses (ANLA for its acronym in Spanish) and 53 were granted by the Regional Autonomous Corporations (CAR for its acronym in Spanish). These include environmental licenses and permits for the use and exploitation of natural resources. Moreover, 69 environmental permits were submitted for local and national authorities’ evaluation, and 38 archaeological programs were developed on site, based on the archaeological permits granted by the Anthropology and History Colombian Institute (ICANH, for its acronym in Spanish).
Climate Change
As part of our efforts to contribute to the Sustainable Development Goals, the Paris Agreement and Colombia’s Nationally Determined Contribution (NDC), on March 25, 2021, we announced our plan to achieve net-zero GHG emissions by 2050 (scopes 1 and 2), in line with our commitment to mitigate climate change and further the energy transition and the TESG agenda.
By 2030, we seek to reduce our CO2e emissions by 25% as compared to the 2019 baseline for scopes 1 and 2. In addition, we intend to reduce 50% of our total emissions (scopes 1, 2, and 3) by 2050. However, we cannot offer any assurance on our ability to meet these goals by such dates.
In 2023, Ecopetrol S.A. announced a methane emissions reduction target of (i) 45% by 2025 and (ii) 55% by 2030, with respect to a 2019 baseline. This target applies to direct operations in the exploration and production business. Also, in 2023, Ecopetrol joined the sectorial initiative “Aiming for Zero Methane Initiative” led by the Oil and Gas Climate Initiative (OGCI) and confirmed its commitment to action on climate change by adhering to the Oil & Gas Decarbonization Charter (OGDC). Between 2020 and 2025, Ecopetrol implemented 61 methane emission reduction projects in the production activities, achieving a cumulative reduction of 46% compared to the 2019 baseline year. Of this total, around 21 ktCH₄ correspond to initiatives between 2020 and 2024, reductions that are already consolidated in the emissions inventory closed in 2025. The remaining 14 ktCH₄ correspond to projects carried out in 2025. We expect to reflect on the results of these projects in the GHG emissions inventory at the end of 2026. Also in 2025, the Company obtained Gold Standard recognition for advances in methane emissions management, awarded for the third consecutive year by the Oil and Gas Methane Partnership (OGMP 2.0) of the United Nations Environment Programme (UNEP). In addition, it achieved a “Best Performers” rating in the International Energy Agency’s “Turning Pledges into Progress” report for transparency in its decarbonization strategy, climate commitments, and GHG emissions management.
To achieve GHG reduction targets, we launched a decarbonization program focusing on five components: (i) management of GHG emissions information, ensuring the quality, integrity, consistency and transparency of the information reported; (ii) reduction of GHG emissions, identifying and implementing initiatives associated with the optimization of energy consumption, renewable energies, reduction of flaring, fugitive emissions and venting (methane), and development of emerging low-emission technologies; (iii) strategic portfolio management; (iv) emissions offsetting of residual emissions; and (v) climate risk management of physical and transition risks to define adaptation actions and assess business resilience.
In 2025, we reduced 561,454 tCO2e from new projects implemented during that year, exceeding the established annual target by 165%. The accumulated reduction for the 2021-2025 period is 2.8 MtCO2e. In addition to the efforts to decarbonize our operations, we took additional measures to manage our climate-related risks and opportunities, through the following actions:
Climate related risks: In 2025, Ecopetrol updated its analysis of climate-related physical risks for the exploration and production segment by constructing a Climate Risk Index (IRC, for its Spanish acronym) under current conditions and three IPCC scenarios (SSP1-2.6, SSP2-4.5, and SSP5-8.5) for the 2011–2040 horizon. This analysis was developed across 34 polygons, covering 100% of the licensed production areas. This result allows Ecopetrol to advance in the consolidation of climate information for its assets and establish coherent and viable adaptation actions aimed at reducing the exposure and vulnerability of its operations to climate change. The IRC methodology is based on the conceptual framework established by the IPCC in its AR5 (2014) and AR6 (2021) assessment reports, in which climate risk is defined as the result of the interaction between hazard, exposure, and vulnerability. These three components are dynamically and synergistically interrelated, determining the level of risk to which each analysis area is exposed.
For transition risks, Ecopetrol developed energy transition scenarios, based on S&P Global Market Energy and Climate Scenarios, for monitoring trends in each of the three business lines, which aims to be a solid and unified reference framework that allows the Ecopetrol Group (EG) to anticipate and understand the challenges and opportunities of the energy transition, through the presentation and comparison of three scenarios:
These scenarios provide a unified framework to anticipate opportunities and risks arising from the energy transition, decarbonization, and diversification toward clean energy sources. Under this approach, the 2040 Strategy recognizes the importance of a just, gradual, and safe transition that balances climate change mitigation with economic development and social well-being.
While the first and third scenarios do not represent the group’s core vision, assessing different perspectives on the global energy transition remains necessary. According to the 2040 Strategy, Ecopetrol considers the second scenario the most likely, aligning with a gradual energy transition.
Innovation, research, and development: we advanced in further exploring opportunities to implement emerging low-carbon technologies like CCUS, hydrogen and renewable energy projects, in testing top-down and bottom-up technologies for the detection and measurement of fugitive emissions and vents in the exploration and production and refining and petrochemicals segments, and natural carbon sinks.
Participation in public policy discussions: the company articulates its climate ambition with government plans and strategies and participates in the construction of climate change regulations.
In 2025, the transport and logistics segment companies (Cenit, ODL, ODC, Oleoducto Central Ocensa), ISA, and Ecodiesel, continued with their commitment to be carbon neutral. To maintain this goal, the companies implemented a work plan under three focus areas: (i) a GHG emissions inventory, which estimates the total tons of CO2e emitted by the companies on an annual basis, (ii) an emissions reduction portfolio in energy efficiency and renewable energies, and (iii) applying the Natural Climate Solutions (NCS) as an offsetting alternative, identifying opportunities to restore strategic ecosystems, protect biodiversity, improve ecosystem services and contribute to the construction of more sustainable economies in the regions where they operate.
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In 2025, Ecopetrol’s Carbon and Crude Area continued strengthening its strategy for trading carbon offset products.
The company sold more than 1.13 million barrels of carbon compensated premium gasoline to wholesale distributors and 25,000 tons of carbon compensated asphalt in Colombia. Ecopetrol’s carbon offset strategy covers direct GHG emissions generated throughout the product’s lifecycle, from its production process to the point of delivery agreed with our customers.
In 2025, ISA defined an annual consolidated goal relating to the company’s reduction of CO2e emissions aligned with the ISA Net Zero commitment. This goal integrated potential CO2e emissions reductions from voluntary actions including Scope 1, Scope 2 and Scope 3 emissions (water consumption, generation of waste, employee commuting, and business travel). The specific goal of CO2e emissions reductions was to comply with the consolidated Net Zero pathway for ISA in the 2022-2025 period. ISA’s emissions performance includes greenhouse gas emissions from SF6, fuel combustion, fugitive emissions, energy, water consumption, generation of waste, employee commuting, and business travel. By the end of 2025, the consolidated performance of CO2 emissions for ISA showed a 110% achievement of the 2022-2025 net zero pathway, 17,497 tons of CO2e below the company carbon budget for the period.
In order to achieve these results, ISA has implemented several practices such as the use of real-time meters to identify SF6, preventive maintenance or refurbishing of high voltage circuit breakers to avoid gas leaks, development of a prototype to capture of SF6 before it is released into the atmosphere, reusing this kind of gas when the conditions allow it and appropriating final disposal of it. Moreover, some companies have been implementing different actions to reduce the consumption of energy, such as the installation of solar panels in some of ISA’s locations and electrical substations, the implementation of LED technology, the purchase of international renewable energy certificates I-REC.
Water Neutrality
Ecopetrol S.A. aims to improve water use efficiency to reduce water-related impacts and potential associated conflicts, as well as promoting water security within the operation’s areas of influence. Water use is optimized also, to ensure production sustainability due to the operation’s dependence on water resources.
In 2023, Ecopetrol ratified its commitment to be water neutral by 2045. The objective is to achieve a balance between the water required to operate, and the actions that reduce the direct water footprint, as much as economically and technically feasible, as well as to replenish the remaining water consumption through actions that improve the water security in our operation basins. To achieve this goal, Ecopetrol has undertaken proactive actions, beyond environmental compliance, which have enabled it to manage water risks in the physical, regulatory, and reputational components, and generate social and environmental benefits.
During 2025, Ecopetrol’s direct operations recycled 181 million cubic meters of water, that is, 82% of the total water required to operate, which means a 10% increase compared to 2024. In addition, 38.98 million cubic meters of freshwater were withdrawn, which account for 18% of the total water required to operate, resulting in a 1% decrease compared to 2024 and a 24% decrease compared to Ecopetrol’s water neutrality baseline (2019).
These figures indicate efforts towards improving water efficiency, not only by the increase in water recycling and reuse (the highest in Ecopetrol’s history) but also in terms of freshwater intensity which was reduced to 1.18 barrel of water/barrel of oil (Bbl-water/Bbl-oil) in the refining and petrochemicals segment (a decrease of 1% compared to 2024) and decreased to 0.32 Bbl-water/Bbl-oil in the exploration and production segment. These results were leveraged by the fulfillment of the water management efficiency targets for 2025 and allow us to continue the path towards water neutrality by 2045.
In 2025, Ecopetrol received an “A-” score in CDP Water Security for the third consecutive year, which ratifies us in the “Leadership” band as one the best company in the oil & gas sector in water stewardship practices. In addition, five assets were successfully verified by a third-party in the water footprint calculation, based on the NTC-ISO 14046 standard, achieving a total of 23 assets verified to date.
Sustainable Production System and Biodiversity
Our biodiversity strategy is based on two components: (i) prevention and mitigation of biodiversity impacts and (ii) implementation of nature-based solutions, to offset residual impacts and actively respond to challenges related to climate change, water resources, and biodiversity management, food security, or disaster risks, among others. Each of these themes is described below.
Prevention and mitigation of biodiversity impacts:
Implementation of nature-based solutions:
Results related to positive impacts on biodiversity:
Circular Economy
The double materiality exercise highlighted circular economy as a transversal issue within the group. Under this approach, the circular economy model was updated.
Our circular economy model is a key driver that contributes to advance in the energy transition, achieve the net-zero emissions and water neutrality targets, and advance in achieving closed-loop cycles of materials and waste, and diversification of new businesses. Specifically, the adoption of a circular economy model allows us to:
further promote the efficiency in the use of materials, waste and resources like water and increase the recovery capacity of ecosystems,
foster the identification of new business models that generate economic, environmental, and social benefits, and
increase innovation, technological advances and research and development of new products and services.
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Over the course of recent years, Ecopetrol has renewed its commitment to environmental sustainability through the implementation of circular economy strategies, focusing on the optimization of resources and the minimization of environmental impacts.
During 2025, the Ecopetrol Group adopted the Guide for the Management of the Circular Economy Model, which establishes premises, requirements, and governance to optimize efficiency in the use of resources, minimize environmental impacts, promote the regeneration of natural systems and generate value for stakeholders, demonstrating the commitment to the 2040 Strategy and the Sustainable Development Goals (SDGs).
Sustainable Territories - Social Investment for Territorial Transformation
In 2025, the Ecopetrol group allocated resources for the execution of the sustainable territorial development portfolio amounting to COP 335,152 million, this includes both strategic and mandatory social, environmental, and relationship investments. These initiatives generated 19,423 direct and indirect jobs, of which 57% correspond to Ecopetrol S.A.
Due to social investment initiatives and a reduction in territorial conflicts, COP 93,563 million were contributed to the company’s net profit in 2025, representing a 184% increase year over year compared to 2024. Furthermore, the company generated an impact on the regional GDP of COP 1,110,167 million, exceeding the 2024 impact by 41% through the execution of projects, job creation and economic impact of the projects.
The Company’s social investment projects are grouped into three programs: (i) Improvement of Essential Living Conditions, (ii) Income Generation, and (iii) Human Capital Transformation. The Company contributes comprehensively to the agenda and goals of the United Nations’ Sustainable Development Goals (“SDG”), with SDG 7 (Affordable and Clean Energy), SDG 6 (Clean Water and Sanitation), SDG 4 (Quality Education), and SDG 10 (Reduced Inequalities) being the most impacted, as follows:
i.
Improvement of Essential Living Conditions: With the purpose of improving access and coverage in basic care of essential public services for vulnerable communities in the areas of influence, in 2025 we obtained the following results:
ii.
Income Generation: In 2025, we focused efforts on diversifying and dynamizing local economies, promoting programs to encourage productive vocations, job creation, entrepreneurship, and innovation. We also contributed to improving land connectivity and public community infrastructure with the following results:
iii.
Human Capital Transformation: During 2025, we developed various programs and projects focused on achieving greater school permanence and coverage in education, as well as improving educational quality, by which 256,496 children and young people benefited from. This includes interventions such as provision of school kits, school furniture, training for energy transition, teacher training, higher education scholarships, and improvement of educational infrastructure.
Works in lieu for Taxes: The “Works for Taxes” program is a mechanism created by the National Government in 2017 that allows companies to pay up to 50% of their income and complementary taxes through the direct execution of social impact projects in the Areas Most Affected by the Armed Conflict (ZOMAC). These projects aim to construct, improve, optimize, or expand infrastructure and provide the necessary equipment for services such as roads, drinking water and sanitation, energy, education, and public health, among others.
During 2025, the Ecopetrol Group completed 21 projects for an amount of COP 109,681 million benefiting more than 419,473 inhabitants in 31 municipalities of 12 departments, the works include the improvement of 2.6 km of road in Prado (Tolima), Ovejas (Sucre) and Buenaventura (Valle del Cauca), the delivery of school supplies in 781 educational establishments in the departments of Antioquia, Bolívar, Casanare, Cesar, Córdoba, Huila, Putumayo, Santander, Sucre and Valle del Cauca; and the provision of 27 Child Development Centers (CDIS) of the Colombian Institute of Family Welfare (ICBF) in Antioquia, Bolivar, Casanare and Sucre, also, on the front of energy transition, 1,119 photovoltaic solar solutions were delivered for dispersed rural housing, which benefited 4,879 inhabitants with the electricity service, in Putumayo and La Guajira.
Social Dialogue Processes: During 2025, Ecopetrol S.A. carried out 17 dialogue processes. 16 were continuations of cycles initiated in previous years, ensuring institutional memory, traceability, and consolidation of agreements. One dialogue was initiated in 2025, with the following distribution:
Ethnic Relations: In 2025, Ecopetrol S.A. carried out the following ethnic relationship activities:
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Dialogue and Participation Initiatives: During 2025, Ecopetrol S.A. designed and implemented a territorial management strategy focused on implementing 61 dialogue and participation initiatives in eight areas of the country, targeting citizen participation, social dialogue, legal compliance and data analysis. These initiatives have allowed us to fulfill our obligations, proactively address alerts and properly manage our incidents.
Clean Air and Quality of Fuels
Ecopetrol seeks to promote prevention and mitigation actions for reducing air quality impacts, through a clean air roadmap which aims to reduce emissions of criteria pollutants, and to ensure environmental compliance based on operational practices.
Air quality was identified as a material issue in the 2023 materiality analysis. In the past three years, specific actions have been defined to improve operational discipline and to identify synergies for reduction of criteria pollutants based on ongoing decarbonization initiatives as well as energy transition and clean fuels agendas.
Actions undertaken include internal verification of the criteria pollutant’s emissions inventory for the 2022-2025 period and the evaluation of key initiatives in accordance with the best practices related to air quality management. As a result, in 2025, Ecopetrol reduced the emission of 5016 tons of VOC (Volatile Organic Compound) and 1992 tons of NOx (nitrogen oxides) in the exploration and production sector. Additionally, in the refining and petrochemicals sector, emission reductions achieved at refineries amounted to 41 tons of VOCs and 65 tons of NOx. Moreover, 2024-2027 targets were defined for the exploration and production and refining and petrochemicals segments, aiming to gradually reduce nitrogen oxide, sulfur oxide and volatile organic compound emissions, which are expected to be reviewed and updated on a yearly basis.
Ecopetrol is also committed to improving fuels quality to contribute to better air quality across the whole country and comply with and exceed fuel quality regulations. Taking advantage of being an integrated company, after April 2018, we have been significantly reducing the sulfur content in our diesel B2 (98% fossil and 2% biodiesel). In 2025, the diesel and the gasoline that we distributed in Colombia had an average of 10.3 ppm and 52 ppm of sulfur, respectively and Ecopetrol delivered gasoline an average of 44.5 ppm in the mesh from its refineries and diesel B2 8.0ppm; the current local regulations of 10 ppm in diesel and 50 ppm in gasoline. In 2025, Ecopetrol started the distribution of premium gasoline with less than 8.2 ppm of sulfur to make the introduction of vehicles with cutting edge emissions control technologies viable.
Waste Management
Ecopetrol aims to substantially act on waste prevention, reduction and reuse, based on a circular economy framework. The waste management strategic pillar has three main objectives: (i) source reduction (ii) material recovery, and (iii) implementation of new technologies.
During 2025, a total of 638,983 tons of waste were generated, this represents a 19% increase in total waste generation compared to 2024 mainly due to (i) higher generation of construction and demolition waste, (ii) the increase in the generation of drilling cuttings associated with the execution of additional drilling campaigns, with 24 more wells drilled compared to the previous year, (iii) the increase in the generation of oily sludge resulting from higher volumes of produced water treatment;, and (iv) more soil contaminated with hydrocarbons due to operational incidents that caused greater impact and a higher volume of affected soil, among others. Additionally, in 2025, the waste recovery rate was 44%, compared to 36% in 2024, reducing the volume of waste sent to final disposal.
Prevention and Remediation of Environmental Impacts caused by Operational Incidents
During 2025, 25.31 total barrels of oil were spilled due to operational causes in operated assets. Of these, four incidents were greater than one barrel, accounting for 11.83 barrels spilled. While this represents a 51.1% increase compared with 2024 (7.83 barrels) for incidents above one barrel, the overall performance remained strong: total spill volume stayed below the internal maximum threshold of 28 barrels set for 2025, marking the Company’s best result in the last five years. These results demonstrate that the organization continues to uphold its commitment to risk management and environmental protection by implementing targeted actions to prevent incidents and strengthen operational integrity and control.
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3.11.1
Energy Initiatives
We have been undertaking significant efforts to make efficient and rational use of energy resources in our production processes and to reduce energy consumption, costs, and carbon dioxide emissions. Our pillars are efficiency, reliability, optimization, and energy diversification.
By 2025, the Ecopetrol Group accumulated an incorporation of approximately 950.6 MW from non-conventional renewable energy sources into its energy portfolio, 221.1 MW under execution, 50.4 MW under construction, 381.3 MW in operation, and the remaining 297.9 MW corresponding to renewable energy purchases.
During 2025, our production segment had an electricity consumption of 5.83 TWh (Terawatts per hour) for its direct operation, of which 48.9% was provided through self-generation and the remaining 51.1% with non-regulated energy purchased from the National Transmission System.
In renewable energy:
La Cira Solar farm, located in the municipality of Barrancabermeja, incorporated 56 MW in operation since September 2024, and Quifa solar project in Puerto Gaitan, Meta with an installed capacity of 50 MW under construction by the end of 2025.
Transport
During 2025, our transport segment consumed 1.16 TWh (Terawatts per hour) of electricity for its direct operations, from which 41.2% was provided through self-generation and the remaining 58.8% was provided by regulated and non-regulated electricity purchased from the National Electric Grid.
During 2025, Barrancabermeja and Cartagena refinery’s average electricity consumption was 1.65TWh (Terawatts per hour). Approximately 91.6% of this demand was met through self-generation, with the remainder sourced from the electricity market.
The Cartagena Refinery Solar farm, located in the municipality of Cartagena, was under construction with an installed capacity of 22 MW by the end of 2025.
La Iguana Solar farm, located in the municipality of Barrancabermeja with an installed capacity of 26 MW, started construction in 2024. The solar farm entered operation in the fourth quarter of 2025.
3.11.2
HSE
This section describes the health, safety and environmental (HSE) practices of Ecopetrol S.A. Subsidiaries guidelines must be consistent with those established by Ecopetrol S.A.
3.11.2.1
One of the principles that guides Ecopetrol S.A. is the commitment to our employees and the development of the communities in which we operate. For that reason, Ecopetrol S.A. is devoted to improving our health, safety and environmental practices.
The results of the HSE performance in 2025, compared to the prior year, were as follows:
We have several programs in place aimed at increasing the safety of our industrial processes and minimizing the number of occupational accidents and other major incidents. Our HSE management model is based on key focus areas that are aligned with our integrated management system.
Total Recordable Injuries Frequency – Employees and Contractors
Ecopetrol S.A. places an important emphasis on understanding, monitoring, and controlling the health and safety impacts on workers and contractors.
In 2025, 30 recordable injuries occurred, where 10% led to restricted work, 3% required medical treatment, 83% led to lost days, and one were fatal incidents. Additionally, we had a 11.76% decrease in the number of recordable injuries compared to 34 injuries in 2024, primarily because of an assurance of high-risk activities, improvement of risk analysis in operational activities, prior assurance of HSE risks and skills development, and strengthening HSE skills in refining.
Graph 7 – Total Recordable Injuries Frequency – Employees and Contractors (*) (**)
* Number of employees or contractor injuries requiring minimum medical treatment for every million hours worked.
** Includes data for Ecopetrol S.A. but does not include data for subsidiaries of Ecopetrol.
Contingency Plans and Environmental Remediation
To protect and minimize potential damage to people, the environment, or assets, due to contingencies, Ecopetrol has developed emergency and contingency plans to guarantee immediate, timely and effective intervention in the event of emergencies or contingencies that may occur in our facilities and operations. These plans have been appropriately documented, updated, and distributed internally, with our professionals that oversee these plans having been trained to do so.
Emergency and contingency response plans are prepared in accordance with Colombian legal requirements and considering internal emergency guidelines. These plans, which have the approval of the ANLA, are articulated with municipal emergency response strategies and risk management procedures of the territories where we operate.
The main results obtained in the implementation of the emergency and contingency plans for 2025 by Ecopetrol S.A. are presented below:
Ecopetrol S.A. continuously implement training programs for all personnel involved in emergency or contingency response plans. In 2025, 3,391 training sessions took place to improve our employees’ skills.
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Graph 8 – Trained Personnel 2025
Frequency of Process Safety Incidents
Process safety is designed to achieve the best operational performance by intervening in the highest technological risk and implementing the necessary measures and actions to prevent and mitigate the release of dangerous substances or energy. The impact of these measures is focused on the reduction of operational and occupational accidents with the potential of causing major accidents or disasters, providing an effective management framework for Ecopetrol’s operations, and demonstrating commitment to the first principle of the Company’s cultural statement, “Life First”.
Ecopetrol’s ambition is to become a global benchmark in industrial safety, adopting best practices and undertaking operations under tolerable risk levels for process safety. To this end, the Company works on three fronts: (i) comprehensive risk management based on HSE methodologies (including onsite/offsite risk, notch risk management, risk management high consequence scenarios), (ii) risk awareness (process safety competency management) (iii) efficient and simple HSE management system (contractor management with process safety focus).
We report Tier 1 process safety events per million hours worked, which are the losses of primary containment of greatest consequence causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities according to API754. The reporting thresholds for API754 Tier 1 is an unplanned or uncontrolled release of any material, including non-toxic and non-flammable materials, from a process that results in one or more health, safety or environmental consequences set forth under those guidelines. In 2025, there were 0.03 Tier 1 process safety incidents per million hours worked, consistent with a decrease from the 0.04 recorded in 2024.
Frequency of Tier 1 process safety incidents per hour worked (per million hours worked):
Graph 9 – Tier 1 Process Safety Incidents (*) (**)
* Tier 1 process safety incidents per million hours worked (API-754).
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** Includes data for Ecopetrol S.A. classified according to the criteria in API-754 Tier 1 but does not include Ecopetrol S.A.’s subsidiaries.
Incidents with an impact on the environment
In 2025, eight incidents were reported involving hydrocarbon spills greater than one barrel that caused environmental impact, with a total spilled volume of 16.99 barrels of hydrocarbons (an incident caused by third parties could not be measured due to public order conditions in the area).
Of these eight incidents, four were due to operational causes, with a total spilled volume of 11.83 barrels. This represents an increase of 51.1% compared to 2024 (7.83 barrels) for operational incidents, and a decrease of 22.63% compared to 2023 (15.29 barrels). The volume of hydrocarbons spilled from operational incidents causing environmental impact in 2025 reflects the ongoing challenges in asset integrity management at Ecopetrol. Ecopetrol’s integrity strategy continues to focus on maintenance and/or replacement of production lines, maintaining an up-to-date inventory of facilities, continuously evaluating criticality and risk, implementing preventive inspection and maintenance plans, and monitoring the condition of high-impact infrastructure. Between 2022 and 2025, more than 240 km of production lines were replaced as part of these activities.
The remaining four incidents, which involved spills greater than one barrel, were caused by third-party attacks and thefts, with a total spill volume of 5.16 barrels. This represents a decrease of 96.64% compared to the 153.66 barrels reported in 2024.
Ecopetrol S.A. monitors performance through the IOGP index for hydrocarbon spills greater than one barrel from operational causes, normalized by hydrocarbon production. In 2024, the global index for onshore operations was 6.05, while Ecopetrol’s value was 0.05, representing a 99.17% improvement. The 2025 index will be published by IOGP in the fourth quarter of 2026.
As of December 31, 2025, hydrocarbon spills greater than one barrel reported, both operational and caused by third parties, were as follows:
Corrective and mitigation actions implemented by Ecopetrol S.A.
In due course, Ecopetrol S.A. carried out all the social, environmental, and technical actions to fully attend the event and mitigate potential damages and manage the incident, in compliance with corporate practices, contingency plans and national requirements established in Law 1523 of 2012 and the Decree 1868 of 2021.
Investigations and legal claims
Investigations
As of the date of this annual report the following investigations are being conducted by environmental authorities and control agencies in respect of the incident:
On January 20, 2020, Ecopetrol S.A. was informed that the ANLA, during the administrative process initiated by said authority because of the Lisama 158 well spill, decided to impose a fine on Ecopetrol S.A. in an amount of COP 5,155 million. During said administrative process, the ANLA exonerated Ecopetrol S.A. from liability for some charges, because ANLA evidenced that Ecopetrol S.A. had activated its contingency plan and implemented the corresponding actions. It also mentioned that Ecopetrol S.A.’s environmental control actions were taken in an appropriate manner. Nonetheless, it decided to impose the fine, because the ANLA considered that the actions were not taken in a timely manner and because, it considered that Ecopetrol S.A. did not adopt and implement the necessary actions to correct the mechanic failures in the well, to prevent the environmental damage. On February 11, 2020, Ecopetrol S.A. filed a reconsideration appeal before ANLA requesting the reversal of this decision. On February 9, 2021, through Resolution 290, the decision of the ANLA was announced and reduced the fine to approximately COP 3,864 million. The proceeding was closed by the environmental authority.
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Ecopetrol S.A. complied with ANLA’S decision and paid the penalty on February 17, 2021. However, Ecopetrol S.A. requested the annulment of the sanction before the High Administrative Court on June 9, 2021. The lawsuit was admitted by the court on February 18, 2022. As of the date of this annual report, the process is ongoing and Ecopetrol S.A. is awaiting the start of the evidence gathering stage.
Ecopetrol S.A. has completed most of the tasks related to the Environmental Recovery Plan for the Lisama 158 well spill, which occurred in 2018. The plan is expected to be fully executed by December 2026. The National Specialized Unit against Human Rights Violations – Environmental Crimes Subunit of the Office of The Attorney General opened a criminal investigation into the possible environmental contamination caused by the oil well exploitation, following a request from the Minister of Environment. The case was registered under the file number 110016099043201800044. In August 2021, the prosecutor in charge agreed to grant a conditional suspension of the prosecution, based on a deal with Ecopetrol. We promised to compensate the local fishermen affected by the spill with COP 6,500 million (about 1.4 million dollars) and to restore the environment according to an environmental reparation plan, which consisted of 11 major actions, under the supervision of the ANLA. The first hearing to partially approve the conditional suspension took place on July 28, 2021 before a judge in Barrancabermeja, and the decision was confirmed on November 19, 2021, and March 25, 2022. Later, on May 9 and August 18, 2023, the Sixth Criminal Municipal Judge with Mixed Duties and the Third Criminal Circuit Judge with Knowledge Duties, both from Barrancabermeja, verified in the first and second instance, respectively, that we had fulfilled 100% of the monetary obligations and most of the environmental obligations. The case is currently on hold until we complete the remaining environmental tasks. However, annual follow-up is carried out with the authorities.
Agreement with fishermen and fish traders reviewed by the Prosecutor’s Office
On July 28, 2021, Ecopetrol S.A. and a fishermen group certified by the Fishing and Aquaculture National Authority (“AUNAP” for its acronym in Spanish), arranged for an economic recognition regarding the effects of the Lisama 158 event. Ecopetrol S.A. reached an arrangement with AUNAP, as well with the local fish traders associations from Barrancabermeja ASOCORAMB (Asociación De Comerciantes Del Sector La Rampa De La Ciudad De Barrancabermeja) and ASOCOPROPAL (Asociación de Comerciantes de Pescado). Due to these arrangements, 940 fishermen and 118 fish traders received compensation of COP 8,426,680,523. The Prosecutor’s Office reviewed and approved such agreement in the application of the discretionary prosecution principle (“Principio de Oportunidad” in Spanish). Additionally, two criminal judges have also reviewed and approved the agreement and have monitored and verified its full compliance to the present day. The last of these decisions was issued on August 18, 2023 by the Third Criminal Judge of Barrancabermeja Circuit.
Ecopetrol S.A. simultaneously agreed to continue with the actions described in the Environmental Recovery Plan, which were accepted by the ANLA as environmental recovery efforts for the affected area.
Legal Claims
As of the date of this annual report:
There are two more actions that have been filed before the Administrative Court of Santander, related to the Lisama 158 incident:
Approximately 600 people, members of the community and fishermen who live in the vicinity of where the incident took place, filed a class action in the amount of COP 614,503,232,689, seeking compensation for damages allegedly suffered as consequence of the incident. On September 25, 2020, Ecopetrol S.A. informed Mapfre Seguros Generales de Colombia S.A. that it was seeking to invoke guarantee coverage by the guarantors. Through the order issued on November 7th, 2025, the Court declined to schedule a conciliation hearing, since the sued institutions stated they had no intention to conciliate. Consequently, the Court proceeded to order the evidence. Against that decision, Ecopetrol filed an appeal, due to the Court’s refusal to decree the evidence previously requested by the company.
Senator Antonio Eresmid Sanguino filed a class action, seeking protection of collective rights (no compensation or indemnification petitions), arguing that the incident led to the destruction of (i) people’s health and (ii) damages to the environment caused by the incident.
On October 2, 2018, the Administrative Court of Santander (competent judge) issued an interim measure whereby the latter ordered different authorities and Ecopetrol S.A. to perform various activities to prevent any additional environmental damage to occur.
On January 16, 2020, the High Court for Administrative Matters (Consejo de Estado) revoked the interim measure imposed by the Administrative Court of Santander, considering that with the abandonment of the well “the risk that caused the production of the spill has been surpassed”. In its ruling, the High Court for Administrative Matters also mentioned that Ecopetrol S.A. has been taking the necessary actions to solve the damages produced by the incident and also implemented the actions to repair the alleged damage. On June 17, 2024, Ecopetrol was notified of a first-instance judgment dated June 13, 2024, which, among other provisions, ordered: to declare that Ecopetrol violated the collective rights and interests set forth in subsections a) and c) of Article 4 of Law 472 of 1998, but that, as of the date the decision was issued, the case had lost its purpose due to the matter being overcome. On June 20, 2024, Ecopetrol filed an appeal against the first-instance judgment.
On March 22, 2018, Ecopetrol S.A. made a claim to Mapfre Seguros Generales de Colombia S.A., based on its Control of Well Policy and received the USD 19 million in October 2019. Thereafter, because of the third-party liability policy claim objection, Ecopetrol S.A. has taken the relevant actions to obtain the guaranteed coverage of guarantors. On February 27, 2020, Ecopetrol S.A. filed a lawsuit against Mapfre Seguros Generales de Colombia S.A. to obtain recognition and payment of COP 128,807,833,685 based on civil liability. The court admitted the lawsuit on January 20, 2022, but as of the date of this annual report the court has not scheduled a hearing date.
3.11.2.2
Cenit
Cenit incorporates the Occupational Health and Safety Management System through its “Commitment to Life and Process Safety” element, which defines a set of principles, actions, tools and documentation, articulated among themselves to manage industrial safety risks, health at work, environment and process safety in the Company. The “Commitment to Life and Process Safety” element is based on HSE regulatory compliance, as well as the best practices in the industry, which allows us to protect the integrity of our staff, the environment and infrastructure.
The scope of coverage of the Occupational Health and Safety Management System under its Element Commitment to Life and Safety of Processes, applies to all Cenit workers directly linked, by temporary mission or other type of connection established by law, and/or those who carry out their work in any of the facilities, pipeline network, polyduct network and/or under the control Cenit operation. In addition, it applies to all Cenit processes, activities and tasks carried out by our own personnel, contractors, subcontractors and visitors.
The objective of SG SST Cenit is to define a strategy to achieve results and demonstrating actions that prioritize people’s safety, care for the environment and assurance of the operations, with generation of healthy work environments.
The following table covers Cenit’s TRIF for 2023, 2024 and 2025, which includes direct employees and subcontractors. The table presents statistics related to the maintenance, operation and execution of projects in the transportation of hydrocarbons.
Table 48 – Performance Indicators(1)
Metric
Man-hours
19,985,536
22,324,197
25,144,351
Recordable accidents
Total recordable incidents frequency (TRIF)
0.35
Includes data for Cenit but does not include data for subsidiaries of Cenit.
3.11.2.3
In 2025, approximately 4,983,585 million man-hours were employed conducting Cartagena Refinery’s business activities. Our TRIF indicator remained within our expectations.
The following table covers Cartagena Refinery’s TRIF for 2023, 2024, and 2025 which includes Ecopetrol Operation and Maintenance (O&M), Cartagena Refinery and subcontractors. The table presents statistics related to operating and maintenance activities. Cartagena Refinery has not reported fatalities during the period 2023 – 2025.
Table 49 – Performance Indicators
4,983,585
5,845,318
4,990,444
0.68
0.80
Environmental Incidents (EI*)
Process Safety Incidents (PSI)
*Incident with hydrocarbon spill greater than 1-barrel due operational causes
3.11.2.4
For ISA and its subsidiaries and affiliates, it is important to protect and preserve the health and safety of workers, regardless of the type of contractual relationship, guaranteeing safe work environments, self-care, and the application of good prevention practices. This high commitment to people is expressed in the occupational health and safety policy, which seeks to offer safe working environments and healthy lifestyles.
ISA monitors two main indicators that contain its goals in terms of safety and health at work and that are part of the comprehensive management chart and variable compensation: (i) reduce events with a high potential for seriousness and (ii) TRIF, which is calculated as: the number of injuries from all workplace incidents or illnesses that either took place at work or were the result of work-related activities divided by the numbers of hours worked, multiplied by 1,000,000.
There is a process of continuous improvement of the occupational health and safety management system in ISA’s subsidiaries with high-risk activities, whose purpose is to manage occupational hazards and contemplate the execution of activities aimed at protecting the lives of people and that is maintained through the health and safety management systems certified under quality management systems and complying with the provisions of the legislation of each of the countries in which ISA is present.
Accident Management
During 2025, exposure to occupational risk increased by 23.30%, with 10,243,899 more man-hours of work compared to 2024, primarily because of the implementation of the “Primero la vida” (Life first) since 2025, new controls and the implementation of the cultural transformation model. Also, in 2025, the integrated accident frequency rate (own personnel and contractors) decreased by 12.33% with the new TRIF methodology specified below compared to 2024. Throughout the year, the number of work accidents per 1,000,000 hours of work has been higher, as set forth in the table below:
Table 50 – Integrated Frequency Index for Employees and Contractors
Man-hours worked
54,205,949
43,962,050
44,400,342
Total accidents
119
Total recordable incidents frequency (TRIF)(1)
3.09
Before 2022 the calculation method used was the frequency rate.
Fatal Accidents
During 2025, ISA had five fatal accidents (i.e., five fatal accidents occurred in companies controlled by ISA).
Related Party and Intercompany Transactions
Set forth below is a description of material related-party transactions. For additional information about related parties, see Note 31 to our consolidated financial statements.
Oleoducto Central S.A.S. (Ocensa)
Ecopetrol S.A. has entered into several agreements with its 72.65%-owned subsidiary, Ocensa, of which the following are the most significant:
In March 1995, Ecopetrol S.A. entered into an agreement for the transportation of crude oil through the Ocensa pipeline. Pursuant to the terms of this agreement, Ecopetrol S.A. was required to make monthly payments that varied, depending on both the volume of crude oil transported through the pipeline and a tariff imposed by Ocensa based on Ocensa’s financial projections and their expected volumes of crude oil. On January 17, 2013, this agreement was amended because of Ocensa’s new business model. Among other changes, this amendment to the transportation agreement establishes the payment of the tariff, calculated according to resolutions issued by the Ministry of Mines and Energy. In 2013, another amendment was implemented that modified the terms by which the payments of invoices should be made. In 2020, an amendment including security standards for the supply chain was executed. On July 29, 2014, after Ocensa implemented and carried out an open process to receive offers to enter into transportation agreements for an extended capacity of approximately 135,000 barrels per day in Ocensa’s pipeline (the P135 Project), Ocensa accepted the proposal made by Ecopetrol S.A. to enter into a ship-or-pay transportation agreement for 70,000 barrels per day of crude.
On November 20, 2014, after a total and definitive assignment agreement that was notified to Ocensa on December 15, 2016, Ecopetrol S.A. became the successor of Hocol, of a ship-or-pay transportation agreement for 17,500 barrels per day, thus increasing our contracted capacity in the P135 Project to 87,500 barrels per day. On July 1, 2017, with the consent of Ecopetrol S.A. and Ocensa, and as contemplated in the Act of Commencement of Operations issued by the Ministry of Mines and Energy (Resolution 31344 dated April 27, 2017), Ocensa started supplying increased capacity in the P135 Project.
On July 17, 2018, Ecopetrol S.A. and Ocensa entered into an amendment to the P135 Project ship-or-pay transportation agreements mentioned above (consisting of a capacity of 87,500 barrels of crude per day) in order to adjust the standard tariff and monetary conditions. This followed Ocensa having entered into a settlement agreement as approved by an arbitration panel with Frontera Energy Colombia and executed on May 15, 2018, pursuant to which the transportation tariff and monetary conditions in Ocensa’s ship-or-pay transportation agreement with Frontera Energy Colombia in respect of the P135 Project were adjusted. Therefore, in application of regulatory principles, Ocensa offered similar terms to the remaining shippers of the P135 Project, including Ecopetrol S.A., and executed (i) settlement agreements with those who accepted Ocensa’s offer and (ii) the corresponding amendments to the transportation agreements. In 2025, the transportation services provided by Ocensa to Ecopetrol S.A. under these two agreements amounted to USD 1,365.6 million.
On October 28, 2013, Ecopetrol entered into a natural gas supply contract in force until November 30, 2018, pursuant to which Ecopetrol S.A. supplies gas to Ocensa and receives a fixed price per MBTU (Million British Thermal Units). This agreement replaced the contract for natural gas supply in Cusiana entered in December of 2004, under which Ocensa paid a variable rate to Ecopetrol. Since December 1, 2018, the parties have agreed to extend the term of the agreements for one-year terms, most recently on November 25, 2022, when the term of the agreement was again extended for another one-year term until November 24, 2023. In January 2022, Ecopetrol and Ocensa entered a crude oil supply contract, pursuant to which Ecopetrol is required to supply blending and light mixing crude oils for the operation of Ocensa’s pumping equipment. The price of the contract is determined by a formula for each type of crude oil. The term of the contract is one year, renewable for an additional one-year term. In 2025, Ecopetrol S.A. received an aggregate sum of USD 7.39 million, with taxes included.
Ecopetrol and Ocensa also have a gas supply agreement for the electricity generation of the Cusiana pump station. The term of the contract is one year, renewable for an additional one-year term. In 2025, Ecopetrol S.A. received an aggregate sum of USD 4.84 million.
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Ocensa has entered into the following agreements, among others, with some of our other subsidiaries:
In March 1995, Equion and Santiago Oil Company entered into agreements for the transportation of crude oil through the Oleoducto Central S.A. (Ocensa) pipeline. Equion and Santiago Oil Company held 5% of transportation rights in Ocensa. In 2014, the transportation fees billed by Ocensa were: Equion (USD 44.4 million), Santiago Oil Company (USD 3.8 million) and Hocol (USD 30.8 million). On January 17, 2013, this agreement was amended as a result of Ocensa’s new business model. Among other changes, the amendment to the transportation agreement establishes that tariff payments are to be calculated according to resolutions issued by the Ministry of Mines and Energy, and that the transportation capacity is expressed as a number of barrels for each segment of the pipeline. On May 23, 2013, another amendment was executed that modified the terms by which the payments of invoices should be made. On October 26, 2022, Equion and Santiago Oil Company made a total and definitive assignment of their transportation agreements with Ocensa, to J Energy Colombia SAS. In 2025, Ocensa provided transportation services to Hocol, as assignee of transportation rights from original shippers and was paid USD 23.88 million for such services.
Oleoducto de Colombia S.A. (ODC)
Ecopetrol S.A. entered into the following agreements with its 78.19 %-owned subsidiary, ODC:
In July 1992, a ship-and-pay agreement was signed for the transportation of hydrocarbons. Pursuant to this agreement, Ecopetrol S.A. must pay a previously agreed tariff for the volume of hydrocarbons transported. The duration of this agreement is indefinite; however, the contract is intended to remain in force as long as Ecopetrol S.A. holds shares in Oleoducto de Colombia S.A., whether directly, or through an affiliate. As of January 2013, the parties agreed that the applicable tariff would be the one set by the Ministry of Mines and Energy (the MME Tariff). The tariff was updated by the MME in July 2025, valid until June. In 2025, payments made by Ecopetrol S.A. under this agreement amounted to USD 167.71 million.
ODC has entered into the following agreements with some of our other subsidiaries:
Between March 1992 and January 1993, Hocol, Equion and Santiago Oil Company each entered into agreements with ODC for the transportation of crude oil through the Vasconia-Coveñas pipeline. The term of each of these agreements is indefinite. As of January 2013, the applicable tariff is the one set by the Ministry of Mines and Energy. In 2025, the transportation fees billed by ODC were: Equion (USD 0.03 million) and Hocol (USD 3.58 million). On December 23, 2022, ODC entered a crude oil transportation contract with Equion. The term of this agreement is one year, effective as of January 1, 2023. The agreement applies the current tariff established by the Ministry of Mines and Energy. On December 26, 2023, an amendment to the agreement was executed to extend its term for an additional year. On December 26, 2024, another amendment to the agreement was executed to extend its term for an additional year. On December 18, 2025, a new amendment to the agreement was executed to extend its term for an additional year. As of December 31, 2025, the advance payment balance is USD 33.40.
Oleoducto de los Llanos Orientales (ODL)
Ecopetrol S.A. has entered into the following agreements, among others, with its 65%-owned subsidiary, ODL:
In December 2009, Ecopetrol S.A. entered into a service agreement with ODL to transport crude oil. This agreement was subsequently replaced in January 2014 by a new agreement that expired in December 2020. The contract stipulated a ship-or-pay clause for the transportation of 167,000 barrels per day (bpd) in 2014, 149,000 bpd in 2015 and 139,000 bpd until 2020. In January 2017, the agreement was amended to maintain the economic and commercial balance for the parties, based on changes to the system’s standard condition of the system (to transport crude oil with a 690 cStk viscosity), reducing the “ship-or-pay” capacity from 139,000 bpd to 129,139 bpd until December 2020. On March 5, 2021, Ecopetrol S.A. and ODL entered into an amendment that adjusted terms and definitions, allowing for the transportation of barrels that had been paid but not transported. On November 25, 2021, an amendment was made to adjust terms and definitions of the applicable TRM and to extend the term for providing ship-and-pay transportation services until November 2026. Payments by Ecopetrol S.A. under this contract were COP 1,210 billion in 2025.
On August 1, 2015, ODL entered into an indefinite management agreement with Oleoducto Bicentenario by means of which ODL receives legal representation and provides management services to Oleoducto Bicentenario. On August 1, 2017, the agreement was amended to change the way ODL is remunerated by this service, improving the structure of the agreement. In 2023, Oleoducto Bicentenario and Cenit merged, and Cenit assumed all rights and obligations under the agreement with ODL. Pursuant to the terms of this agreement, Cenit paid to ODL COP 940 million plus applicable taxes in 2025.
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Ecodiesel
Ecopetrol S.A. entered into a supply agreement for the Barrancabermeja refinery, with Ecodiesel Colombia S.A. (“Ecodiesel”), a company in which Ecopetrol S.A. has a 50% equity interest. The current agreement began on February 1, 2021 and expires on January 31, 2027. Pursuant to the terms of this agreement, Ecodiesel must deliver to Ecopetrol S.A. and Ecopetrol S.A. must, in turn, purchase a minimum of 50,880 barrels of Ecodiesel’s biodiesel production each month. Payments vary depending on the purchased volumes and the prices of biodiesel. In 2025, Ecopetrol S.A. paid a total of COP 567.5 billion under the current agreement.
Additionally, on October 4, 2023, Ecopetrol S.A. as Cartagena Refinery’s legal agent, signed a supply agreement with Ecodiesel, that was in effect until March 31, 2025. On March 31, 2025, Ecopetrol S.A. as Cartagena Refinery’s legal agent, signed a new supply agreement with Ecodiesel, that is in effect until March 31, 2028. Under the terms of the new agreement, Cartagena Refinery must purchase a minimum of 13,500 barrels of Ecodiesel’s biodiesel production monthly. These agreements were signed to purchase the biodiesel that is used to blend Diesel B2. On August 13, 2025, Ecopetrol S.A. as Cartagena Refinery’s legal agent, signed another supply agreement with Ecodiesel, that was in effect until January 31, 2026. This last agreement was signed to purchase the biodiesel that is used to blend Marine Diesel B2. In 2025, Cartagena Refinery paid a total of COP 171.8 billion to Ecodiesel under these agreements.
In 2025, Ecopetrol S.A. bought COP 567.5 billion worth of biodiesel from Ecodiesel for its own consumption and COP 171.8 billion worth of biodiesel for Cartagena Refinery’s consumption.
Transactions with Other State-Controlled Entities
In the ordinary course of business, we enter into transactions with other state-owned enterprises that include but are not limited to the following:
We have an agreement with the ANH by which we purchase all crude oil delivered to the ANH as royalties and economic rights by us and by third parties. The purchase price is calculated according to a formula set forth in a contract between Ecopetrol S.A. and the ANH that reflects our crude export sales prices, a quality adjustment for API gravity and sulfur content, transportation rates from the wellhead to the export ports or internal refineries, marketing fee and diluent cost. We export and incorporate into Ecopetrol’s refining segment the physical product purchased from the ANH as part of our ordinary business.
For the period between January 2025 and December 2025, we purchased 31.32 million barrels of crude oil from the ANH corresponding to royalties and economic rights paid in kind by oil producers in Colombia. The previous agreement between the ANH and us ended on June 30, 2023, and a new agreement was then executed by ANH and us for a term of July 2023 to June 2026. See section Business Overview—Applicable Laws and Regulations—Regulation of Exploration and Production Activities—Business Regulation—Royalties for a description of the current royalty scheme.
The ANH is a state agency responsible for the administration and regulation of the nation’s hydrocarbon resources and therefore it is controlled by the Nation. The Nation’s control of the ANH arises from the fact that it is a state agency and hence a part of the Colombian Government. On the other hand, Ecopetrol S.A. is a state-owned enterprise and the Nation’s control of Ecopetrol S.A. results from the fact that it is one of our shareholders and owns more than most of our common shares. Neither Ecopetrol S.A. nor the ANH can control each other’s actions. Notwithstanding that as a matter of Colombian law neither entity can influence the other, as a matter of U.S. regulation, they are under common control.
In addition, as an importer and refiner of hydrocarbons in Colombia, Ecopetrol S.A. and Cartagena Refinery are counterparties of the FEPC. See section Business Overview—Applicable Laws and Regulations—Regulation of Refining and Petrochemical Activities—Regulation Concerning Production and Prices—Fuel Price Stabilization Fund (FEPC). Pursuant to that regulatory framework, for the year ended December 31, 2025, Ecopetrol S.A. recorded COP 2.4 trillion (USD 647 billion) in accounts receivable due from FEPC, while Cartagena Refinery recorded COP 0.6 trillion (USD 159 billion) in accounts receivable due from FEPC. As of December 31, 2024, Ecopetrol S.A. recorded COP 5.96 trillion in accounts receivable due from FEPC, while Cartagena Refinery recorded COP 1.66 trillion in accounts receivable due from FEPC. See Note 7 to our consolidated financial statements for more detail.
3.13
Insurance
As part of the risk retention and transfer strategy, the Ecopetrol Group has insurance programs that seek local and international coverage for assets, operations and personnel in the exploration and production, refining and petrochemicals and transport and logistics segments for hydrocarbons and energy transmission and toll roads concessions, as summarized below.
Also, as part of our insurance strategy, Ecopetrol has a wholly owned subsidiary denominated Black Gold Re Limited (BGRe), which is a Captive Reinsurance company that began operations on August 24, 2006, and oversees and optimizes the management of the Ecopetrol Group’s Corporate insurance program. BGRe meets its objectives by adjusting the levels of transfer and retention of risk, with the goal of protecting the Ecopetrol Group’s assets and operations, strengthening negotiation capabilities in the insurance market and minimizing adverse effects from market cycles.
BGRe designs and implements retention and risk transfer strategies, according to the needs of each business segment, optimizing the placement of the corporate insurance program, generating technical and economic efficiencies for the Ecopetrol Group.
In 2025, BGRe increased its level of retention from USD 185 million to USD 205 million, supported by a retention analysis, which was carried out in 2024.
As of the date of this annual report, the policies in which retention has been successful are Property All Risk, Sabotage & Terrorism (S&T), Crime, Cyber, as well as deductible differences (DID Multi).
The Ecopetrol Group also has a directors’ and officers’ (D&O) liability insurance policy.
Finally, ISA also has a robust underwriting strategy that provides coverage for the main risks and complies with its risk retention and transfer guidelines. Below you will also find the detailed scope of its program.
3.13.1
Exploration and Production, Refining and Petrochemicals and Transport and Logistics segments
We have a clear and defined corporate policy based on risk financing guidelines that summarizes the Company’s risk transfer and retention alternatives and provides support and guidance for all the insurance-related issues of all our affiliated and subsidiary companies.
As a proactive strategy to deal with the hardening conditions of the worldwide reinsurance market until 2019, in July 2020, Ecopetrol S.A. became a member of the Everen, which is an energy industry mutual insurance company based in Hamilton, Bermuda, established since 1972. This organization operates based on the concept of mutualization, in which several companies threatened by similar risks and with comparable exposure profiles decide to constitute a common fund, based on the individual contribution of each one, depending on the size of their operation and the estimated losses they may suffer as a result of the materialization of such risks. Everen is insuring over USD 4 trillion of global energy assets. Its credit rating is A (S&P) and A2 (Moody’s). Currently, 74 companies in the world are members of Everen. Ecopetrol Group, as a member of Everen, has access to cost-effective insurance capacity with a minimum deductible of USD 10 million and up to USD 450 million per occurrence for all owned assets.
Under the model described above, the corporate insurance program has been consolidated in two main categories:
Category A: Coverage through Everen and reinsurance market that includes the risks of physical damage, control of wells and leakage, pollution or contamination (which for the purposes of this annual report, are included in the limit of the third-party liability coverage).
Category B: Coverage only through the traditional insurance and reinsurance market that includes third party liability, directors and officers, cargo, crime, charterers’ liability, and cyber-attack insurance.
These structures provide coverage for our consolidated exploration and production, refining and petrochemicals and transport and logistics operations in excess of our local insurance programs (when applicable).
In the tables below, we set forth our insurance program for our exploration and production, refining and petrochemicals and transport and logistics operations and the companies covered, along with related limits and coverage details.
Table 51 – Category A: Coverages through the Everen and Reinsurance and Insurance Market for the Refining and Petrochemicals segment
Limit (eel / agg)(1)
Deductible
Ecopetrol
USD Millions
Onshore
Offshore
Esenttia
Policies
Property all risk
2,700
X
Sabotage and terrorism
600
(1) Eel: each and every loss. Agg: Aggregate.
Table 52 – Category A: Coverages through the Everen and Reinsurance and Insurance market for the Exploration and Production segment
ECP
E&P
Permian
Property all risk(2)
650
Sabotage and terrorism (3)
450
Control of wells(4)
800
5.0/6.0
(2) USD 200 million Property All Risk but USD 350 million Maximum Loss limit and in the aggregate in respect of earthquake. Everen limit of USD 450 million applies as primary layer of those limits.
(3) S&T offshore applies only in Colombia
(4) USD 350 million Control of Wells Maximum Loss limit. Everen limit of USD 450 million applies as primary layer of those limits.
Table 53 – Category B: Transversal Coverages through the Traditional Insurance and Reinsurance Market for the Exploration and Production, Refining and Petrochemicals and Transport and Logistics Segments
Limit
Cartagena
Santiago
(eel / agg)(1)
Refinery
MB
Equión
Ocensa
ODL
OBC
ODC
Trading Asia
Trading LLC
Third party liability(2)
500
Crime
60 / 120
Directors & Officers
207
Various
Cargo
50 / 120
3% dispatch
Charterers
750
0.02
Cyber(3)
85 / 150
Eel: each and every loss. Agg: Aggregate.
Ecopetrol Permian’s limit is USD 175 million.
Coverage through the Everen and reinsurance and insurance market. Coverage under section 1 (buyback for property) does not apply to transport and logistics subsidiaries.
Our third-party liability insurance policy covers Ecopetrol S.A., our subsidiaries and affiliates in excess of local underlying policy limits for claims made against them by third parties. Our commercial general liability coverage will pay on behalf of or indemnify amounts for which an insured becomes legally obligated to pay, including damages in respect of bodily injury, property, pollution, and product liability. Coverage of bodily injury and property damage is subject to coverage territory during the policy period. The Ecopetrol Group also has a directors’ and officers’ (D&O) liability insurance policy.
Ecopetrol S.A.’s transport and logistics subsidiaries continue having an independent program for their oil transportation companies (including crime and D&O policies).
Table 54 – Transport and Logistics Program
Sabotage and terrorism(3)
70/25
0.075/0.250
0.15
Third party liability(4)
0.1/0.5
Environmental Liability(5)
Directors & Officers(6)
0.175
Cyber(7)
(1)Eel: each and every loss. Agg: Aggregate.
(2)USD 200 million each company and an aggregated excess shared limit of USD 750 million (aggregate for the policy period of 18 months).
(3)Does not include Caño Limón – Coveñas (CLC) and Oleoducto Transandino (OTA) systems owned by Cenit. Deductible applies 0.075 for stations and 0.250 for pipelines.
(4)Onshore deductible of USD 0.1 million, except for seepage and pollution of USD 0.5 million.
(5)Environmental liability gradual pollution coverage, which consists of two different policies; one for pipelines and one for stations (Tanks).
(6)Aggregate limit increased to USD 100 million worldwide coverage. Deductible only for coverage No.2 in the USA.
(7)Cyber Risk. Property damage exclusion which includes buy-back coverage.
Regarding the offshore operations in the U.S. Gulf Coast, Ecopetrol America LLC is party to Operating Agreements, or OAs, which include customary conditions, and which contain similar terms and provisions to those in the Model Form of Offshore Deepwater Operating Agreement of the American Association of Professional Landmen. In general, pursuant to these OAs, the obligations, duties, and liabilities of the contract parties are several, and not joint or collective, for all operations covered by the OAs.
Regarding the onshore operations in the U.S., Permian has been included since its beginning in the Control of Wells, D&O, and cyber and crime policies. Since 2020, we have held a stand-alone policy for the third-party liability coverage. Ecopetrol S.A. has a contract with an insurance broker for local policies related to domestic operations. The local policies relate to transit, accidents, mandatory policies, liability mandatory policies, and personal accidents policies, among others.
Our corporative insurance program is focused on addressing insurance needs related to operating a hydrocarbons-oriented business, however, the “Risk Retention and Transfer” strategy is currently designing and reviewing our current insurance needs to get coverage for the new energy transition projects. We are constantly monitoring the international insurance markets to analyze and review alternatives solutions and assure proper coverage for future projects. In 2026, we intend to continue our review of different coverage options for the energy transition segment, seeking to start implementing as soon as the Company gets ready to begin the low emission projects.
3.13.2Energy Transmission and Toll Roads Concessions
ISA and its subsidiaries have a robust insurance program, which sets basic guidelines for its risk retention and transfer policy. Consistent with its insurance guidelines, ISA transfers risk to the traditional market under regional and local insurance programs. We are currently assessing the potential for efficiencies to optimize ISA’s risk retention and transfer strategy.
In order to strengthen its insurance program, in 2014, ISA registered Linear Systems Re as the captive insurance company for the group. As of the date of this annual report, Linear Systems Re has USD 12.6 million as shareholder equity and participated in the placement and risk retention of property damage, sabotage & terrorism policies allowing direct access to the commercial reinsurance markets. In 2025, Linear Systems Re maintained its annual level of USD 1.0 million, supported by a retention capacity study which was carried out during 2024.
Likewise, along with the corporate risk team and its brokers, on an annual basis, ISA examines the need to conduct various analyses, such as Probable Maximum Loss studies, Estimated Maximum Losses, to support and/or define coverages, limits and deductibles among others.
The insurance program responds to high placement standards, which include, among many others: (i) hiring policies with reinsurers with a minimum rating standard of A- or higher, and (ii) contracting with insurance companies and brokers that are present across all the countries in which ISA operates.
According to the above, the main policies of the corporate insurance program correspond to the following:
Table 55 – ISA’s Program
Limit (eel /
ISA &
agg)(1)
Perú
Argentina
Sabotage and terrorism (S&T)
Equipment Electric (EE)(3)
188
Construction All Risk
Cyber(4)
Crime(5)
15/30
(2)The deductible of 2% loss and a minimum that depends on the sum insured for machinery and equipment in each country.
(3)Deductible applies 10% each and every loss with a minimum of USD 250.
The policy is composed of two limits: (i) Traditional Cyber, with a limit of USD 35 million, and (ii) cyber damage, with a limit of USD 25 million, excess of 2% insurable value of the asset.
Deductible applies:
Roads: USD 250,000 each loss.Telecommunications: USD 750,000 each loss.
Energy Sector: One Energy Company affected: Deductible USD 1,000,000 per event/Multiple Energy Companies affected: Deductible USD 2,000,000 per event.
(5)Deductible USD 200,000, except for the following coverages:
a. Expenses: 10% minimum USD 5,000b. Works of Art: 10% minimum USD 5,000 / Other countries: USD 100,000
Note: Different coverages and conditions may apply in each country for each subsidiary.
The policies detailed above for Ecopetrol Group, are subject to particular conditions, limits, sub-limits, deductibles, guarantees and exclusions applying for each line of insurance and each coverage. For purposes of this annual report, only the main limits and deductibles were mentioned in each group.
3.14Human Resources/Labor Relations
3.14.1
Employees
As of December 31, 2025, the Ecopetrol Group had 19,581 employees, there was no increase or decrease in the overall number of employees compared to 2024.
The table below presents the breakdown of our employees according to the business segments where they work, and the personnel of our subsidiaries for the years ended December 31, 2025, 2024 and 2023.
Table 56 – Ecopetrol Group’s Employees
(Number of employees)
Hydrocarbons
Exploration
196
205
211
2,561
2,563
2,624
Others
1,190
1,273
1,268
Total Exploration and Production
3,947
4,041
4,103
2,602
2,522
2,576
Total Refining and Petrochemicals
123
Marketing*
157
162
Total Hydrocarbons
6,779
6,843
6,841
Low-Emissions Solutions
166
Total Operations
6,945
6,981
6,949
Corporate
2,822
2,684
2,901
Total Ecopetrol S.A.
9,767
9,665
9,850
Ecopetrol America LLC.
Ecopetrol Permian LLC.
Ecopetrol USA
Ecopetrol US Trading
Capital AG
Hocol S.A.
385
397
400
Equion Energía Limited
Refinería de Cartagena S.A.S.
379
406
422
Esenttia MB
2,171
2,226
2,181
Ecopetrol Asia Trading
Oil and Gas Pipeline Transport
Cenit Transporte y Logistica de Hidrocarburos S.A.S.
1,209
1,142
1,140
Oleoducto Central S.A.
281
277
Oleoducto de Colombia S.A.
Oleoducto de los Llanos S.A.
Interconexión Eléctrica S.A. E.S.P
5,085
5,101
5,011
19,581
19,657
During 2025, 454 employees left Ecopetrol due to voluntary or dismissal retirement at the professional-technical, operative and management level. Therefore, as of December 31, 2025, the Ecopetrol’s employee turnover rate was 4.65%. We calculate the employee turnover rate by dividing the number of employees who left the company by the total number of employees at the end of the period.
The Company implemented the Átomo Organizational Transformation Project, a strategic initiative designed to advance the execution of its 2040 Strategy by adopting a new operating model. The project entered on redesigning end-to-end process flows and structuring the organization to enhance efficiency, agility, and strategic alignment across the enterprise. As a result, the Company established a more streamlined and simplified organizational structure, reducing functional complexity and layers of middle management, while reinforcing a lean corporate center responsible for overseeing the Company’s three business lines: hydrocarbons, transmission and roads, and energies for the transition.
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These structural changes are expected to generate recurring annual efficiencies of COP 69.4 billion, beginning in 2024 and extending through 2025 and 2026. Notably, the project was executed entirely with internal talent and resulted in the largest reduction of leadership positions within Ecopetrol S.A. in the past decade, with an 18.6% decrease equivalent to 111 positions. This adjustment was designed to enable faster decision-making and greater organizational flexibility.
Furthermore, during 2025, approximately 50% of the Company’s value chain processes were redesigned and updated, including the integration of the energies for the transition business line through three newly defined processes. This redesign seeks to promote operational efficiency, improve cross-business integration, and reduce organizational silos, positioning the Company to more effectively execute its long-term strategic priorities.
Loans and investment in training and development for our employees
To improve the quality of life of our employees and their families, Ecopetrol S.A. extends various types of loans to its employees, including housing loans and general-purpose loans and the amount depends on the applicant’s position level and payment capacity. Ecopetrol S.A. does not guarantee any loans made by third parties. In 2025, Ecopetrol S.A. extended 1,461 housing loans for a total of COP 716.6 billion, education loans for a total of COP 1.77 billion and 2,237 general-purpose loans for a total of COP 61.7 billion. In 2025, Ecopetrol S.A. also provided on-site and external training and development, which totaled to COP 30.0 billion, and it extended a total of COP 291.5 billion in subsidies for education.
We have not provided loans (including housing loans), extended, or maintained credit lines, arranged for the extension of credit by third parties, materially modified or renewed an extension of credit lines, in the form of a personal loan to or for any of our executive officers since our ADSs were registered under the Exchange Act.
We do not offer loans to any of our executive officers.
Labor Regulation
In accordance with Article 123 of the Colombian Political Constitution and Article 7 of the Law 1118 of 2006, our employees are considered “public servants,” even though they are subject to the common labor law. As such, their conduct is subject to the rules of those who manage public goods and assets and can be considered responsible for their illegal actions and omissions in accordance with the following regimes: (i) disciplinary (Law 1952 of 2019), (ii) criminal or (iii) civil.
Principles of the Culture Statement.
The Ecopetrol Group continues to strengthen the adoption and practice of the Principles of its Corporate Culture Statement, which guide organizational behavior and decision-making at all levels. These principles are: (i) life first, (ii) ethics and transparency, (iii) excellence, (iv) leadership, (v) innovation and (vi) collaboration.
As part of this commitment, in 2025, the Culture and Work Environment survey—independently conducted by the Great Place to Work® Institute—was administered to 11,832 employees across the Ecopetrol Group. This international assessment evaluates employee perceptions of the key elements that define the organization’s culture and work environment.
A central metric in this assessment is the GPTW® eNPS© (Employee Net Promoter Score), which reflects the level of cultural strength as evidenced by employees’ willingness to recommend the organization as a great place to work. This indicator represents the overall perception of the Ecopetrol Group’s cultural environment.
The results of the main indices are presented below:
Based on the workplace survey conducted in May 2024, we actively listened to our employees’ feedback, which guided the implementation of initiatives focused on enhancing their well-being and overall experience.
These initiatives had a direct and measurable impact on employees ‘s experience. Over the year, the Ecopetrol Group achieved significant progress in the workplace climate indicator from the Great Place to Work Institute ® eNPS© (Employee Net Promoter Score) rising from a score of 68 in 2024- which was rated as satisfactory – to 80, reaching a “very satisfactory” rating. This demonstrates the effectiveness of the actions implemented and the sustained strengthening of the work environment.
The Ecopetrol Group is committed to adding value to diversity, embracing differences, and promoting the development of increasingly inclusive environments where everyone feels welcomed, appreciated, treated fairly and with respect, and where they receive equal opportunities to contribute their best. In 2025, Ecopetrol S.A. implemented its Human Richness Policy with the aim of “living diversity, equity, inclusion, and belonging in our culture, creating safe environments and alliances that strengthen human richness in all territories.
This objective is supported by four strategic lines:
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In 2025, three advances at Ecopetrol S.A. stand out, reflecting the impact of the Human Richness Policy and the goal of consolidating a more diverse, inclusive, and sustainable organization:
3.14.2
Collective Bargaining Arrangements
The collective bargaining agreement was signed with the Workers Union of the Petroleum Industry – USO, ADECO, SINDISPETROL, ASINTRAHC, SINTRAMEN, ASOPETROGAS, SUP, ASTECO and UTIPEC, and was valid from January 1, 2023, to December 31, 2026. However, on November 4, 2025, the Unión Sindical Obrera (USO) and Ecopetrol signed an extracontractual agreement under which both parties mutually agreed to modify Article 169 of the Collective Bargaining Agreement executed in 2023. The modification updated the term of validity, clarifying that the agreement shall remain in force for a period of three years, from January 1, 2023, through December 31, 2025.
On December 19, 2025, the Unión Sindical Obrera (USO) filed with the Ministry of Labor a formal notice of complaint of the Collective Bargaining Agreement in its entirety. Such notice was filed within the legally established sixty-day period prior to the agreed expiration date and constitutes the legal basis for the potential initiation of an early collective bargaining process, in accordance with Articles 478 and 479 of the Substantive Labor Code.
In accordance with applicable law, the parties signing the Collective Bargaining Agreement are entitled to express their intention to modify it through such notice and, should the unions submit a list of demands, Ecopetrol and the labor organizations would be required to initiate negotiations for a new collective bargaining agreement.
The agreements reached include improvements in the working conditions of its workers, the commitment to continue promoting diversity, equity and inclusion with a gender focus, and new hiring of personnel to strengthen the company’s operation, among other aspects, with criteria of reasonableness, austerity, and efficiency. As of December 31, 2025 there were 47 industry-level unions and 34 company-specific unions, for a total of 81 coexisting unions within Ecopetrol S.A. During 2025, the Company fully complied with the agreements and commitments derived from the collective bargaining agreements.
The Company manages compliance with union rights regarding the deduction of union dues, permits and union guarantees. Likewise, it fully observes the rules that regulate aspects such as trade union rights and other rights related to freedom of association. As of December 31, 2025, Ecopetrol S.A. had a workforce of 9,767 active workers of which, and in accordance with current legal provisions, 94.49% received benefits from the application of the collective bargaining agreements. In addition, 67.15% of the active workforce of Ecopetrol S.A. was affiliated with at least one of the 81 recognized unions. Moreover, the Company held a total of 598 meetings with union organizations in 2025.
Interconexión Eléctrica S.A.
There are 21 labor unions within ISA and its subsidiaries with a total of 1,370 members. Additionally, 1,490 employees benefit, by extension, from the collective bargaining agreements entered into with the unions. Furthermore, there are two collective bargaining agreements (“pactos colectivos”) with employees who are not union members, that cover 472 employees (or 9.0% of ISA’s total workforce). The collective bargaining agreements establish certain employment terms and conditions and are individually and voluntarily signed by the employees.
Cenit Transporte y Logística de Hidrocarburos S.A.S.
There are 14 industrial labor unions that coexist within Cenit’s workforce, to which 35% of Cenit’s employees are affiliated. In October 2019, Cenit signed a collective bargaining agreement with the Unión Sindical Obrera de la Industria del Petróleo-USO for a term of four years ending on August 30, 2023. The collective bargaining agreement awards union protections and benefits which exceed those established by law. The Agreement was denounced by the Unión Sindical Obrera de la Industria del Petróleo-USO on August 30, 2023. As of the date of this annual report, the union has not submitted its list of demands to Cenit, accordingly, the current collective bargaining agreement remains in force.
4.
Financial Review
Our consolidated financial statements for the years ended December 31, 2025, 2024 and 2023 were prepared in accordance with IFRS as issued by the IASB.
IFRS differs in certain significant aspects from Colombian IFRS (the accounting standard we use for local statutory reporting purposes). As a result, our financial information presented under IFRS is not directly comparable to certain of our financial information presented under Colombian IFRS. A description of the differences between Colombian IFRS and IFRS is presented under Financial Review— Summary of Differences between Internal Reporting Policies (Colombian IFRS) and IFRS in section 4.8.
Our consolidated financial statements were consolidated line by line and all transactions and - balances between subsidiaries have been eliminated. These financial statements include the financial results of all subsidiaries companies controlled, directly or indirectly, by Ecopetrol S.A. See Exhibit 1—Consolidated subsidiaries, associates and joint ventures, to our consolidated financial statements included in this annual report.
4.1
Factors Affecting Our Operating Income
Our operating results were affected mainly by: (i) international prices of crude oil, international prices for refined products and local prices for natural gas, (ii) volumes, product mix, and our operational performance, (iii) specific macroeconomics factors, such as inflation, higher interest rates, and the COP/USD exchange rate, (iv) public order situations, (v) regulatory changes, including higher taxes, and (vi) local regulation in Colombia for consumer gasoline and diesel prices and their impact in the Fuel Price Stabilization Fund.
Crude oil prices and volumes are particularly important to the results of our exploration and production segments. This is because as export volumes or export prices of crude oil and products decrease or increase, our revenues also do. Results from our refining activities are also affected by the price of crude oil used as raw material, changes in international prices for refined products, drastic changes in demand due to market factors, conversion ratios and utilization rates and refining capacity, all of which affect our refining margins. In the transport and logistics segment, terrorist attacks by guerillas against our pipelines, illegal valves used to siphon off crude, and other facilities or social unrest can lead to loss of revenues by restricting the availability of transport systems for exports or sales of crude oil and products and/or production activities, in addition to the direct costs of repairing and cleaning.
The inflation rate and the GDP corresponding to countries such as Brazil, Colombia, and Chile, where ISA provides energy transmission services, have a direct effect on the results of the energy transmission and toll roads concessions segment. Results from our energy transmission and toll roads concessions activities are also affected by availability and competitiveness of alternative energy sources in the markets served by us, expiration or termination of significant contracts or concessions, the operational availability of the electricity transmission systems of other electricity transmission companies that are interconnected with our electricity transmission systems, interest rate fluctuations, changes in regulation and economic policies of the countries where we operate and changes in availability or demand of electricity.
Finally, changes in the value of foreign currencies, particularly the U.S. dollar against the Colombian Peso, can also have a significant effect on our financial statements. See section Financial Review—Trend Analysis and Sensitivity Analysis for further information.
Sales volumes and prices
Our results from the exploration and production segment depend mainly on our sales volumes and average local and international prices for crude oil and natural gas. Additionally, sales volumes also reflect the purchase of crude oil that we make from third parties and the ANH.
We sell crude oil and natural gas in the local and international markets. We also process crude oil at the Barrancabermeja and Cartagena refineries and sell refined and other petrochemical products in the local and international markets.
Local sales and prices
We have several short-term crude oil commercial agreements with local customers, and natural gas short and long-term supply contracts with gas-fired power plants and local natural gas distribution companies. Local sale prices are determined in accordance with existing regulation, contractual arrangements, and the spot market, in turn, linked to international benchmarks. Local sales represented 48.5% of our total sales, on average, for the past three years.
International sales and prices
Our international sales represented 51.5% of our total sales, on average, for the past three years.
International sale prices are determined in accordance with contractual arrangements and the spot market, in turn, linked to international benchmarks primarily the ICE Brent benchmark.
A market diversification strategy has allowed us to capture markets where we have been able to obtain higher prices for our crude and refined products. We sell our crudes and refined products in various regions, such as the U.S., Central America and the Caribbean, Asia and Europe. In our negotiations with potential customers, we seek to use the most liquid benchmark reference prices in each region.
Exploration costs
We account for exploratory drilling costs using the successful efforts method, whereby all costs associated with the exploration and drilling of productive wells are initially capitalized. Costs incurred in exploring and drilling dry or unsuccessful wells are expensed in the period in which the well is determined to be a dry or unsuccessful well and are accounted for under “Operations and project expenses.” Consequently, an increase in the number of exploratory wells we declare as dry or unsuccessful is expected to negatively affect our results and may cause volatility in our operating expenses. See Note 4.7 to our consolidated financial statements for a summary of our accounting policy for exploration costs.
Royalties
Each of our production contracts has its own royalty arrangement in accordance with applicable law. Law 141 of 1994 established a royalty fixed rate equivalent to 20% of total production. In 1999, a modification to the royalty system established a sliding scale for royalty percentage linked to the production level of crude oil and natural gas to fields discovered after July 29, 1999, depending on whether the production is crude oil or natural gas, and on the quality of the crude oil produced. Since 2002, as a result of the enactment of Law 756 of 2002, the royalty percentage has ranged from 8% for fields producing up to 5 mbd to 25% for fields producing more than 600 mbd. Producing fields pay royalties in accordance with the applicable royalty rate at the time of the discovery. Also, Law 756 of 2002 establishes that in the fields of the association contracts that terminate or revert an additional royalty rate of 12% of the basic production applies.
Since January 2014, the ANH has collected natural gas production royalties from producers settled in cash based on a formula, regardless of whether a producer has sold the gas. As a result, we no longer commercialize this gas on behalf of the ANH. In addition, since royalties are now payable to the ANH in cash, all the gas that we produce is considered part of our reserves and production, without any deduction for royalties. The cost of natural gas royalties totaled COP 874 billion in 2025.
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On September 30, 2020, Law 2056 of 2020 was issued (“Whereby the organization and operation of the general system of royalties is regulated”), under which the definition of incremental production was extended to all production from fields in which additional investments have been made to increase the recovery factor. According to above, the total production of these fields of the association contracts benefits from the variable royalty established in article 16 of Law 756 of 2002, and therefore, the additional 12% royalty referred to in article 39 of Law 756 of 2002 does not apply to these fields.
On September 23, 2021, the Ministry of the Interior issued Decree 1142 (“Whereby Decree 1821 of 2020, Sole Regulatory Decree of the General Royalties System, is incorporated and modified”), Article 3.1.1.2.1 of Decree 1142 established that the total volume of hydrocarbons produced that is in excess to that stipulated in the basic production curve of incremental production projects or incremental production contracts will also enjoy the benefits of Article 16 of Law 756 of 2002.
On September 2, 2022, Ecopetrol sued for the annulment of Article 3.1.1.2.1 of this Decree, citing legal grounds. The lawsuit against Decree 1142 of 2021 was filed by Ecopetrol on September 2, 2022, before the contentious administrative courts. On January 16, 2024, the lawsuit was admitted and is currently ongoing. On December 13, 2022, Law 2277 of 2022 was adopted. Law 2277 of 2022 adopted amendments to the Colombian tax system, including the non-deductibility of crude oil and gas royalties.
On November 16, 2023, the Constitutional Court in Colombia issued ruling C-489, in which it determined that royalties are a deductible cost of income tax. In December of 2023, the Ministry of Mines and Energy and the Ministry of Finance and Public Credit requested a review of the ruling to the Constitutional Court, alleging a fiscal impact and nullity, respectively. Law 2277 of 2022 came into force on January 1, 2023, and resulted in the payment of higher income taxes and higher effective tax rates by Colombian companies such as Ecopetrol S.A. and Hocol.
In March 2024, the Constitutional Court rejected the request for nullity filed by the Ministry of Mines and Energy. With respect to the fiscal impact argument filed by the Ministry of Finance and Public Credit, such ministry filed related correspondence on March 11, 2024. The Constitutional Court rejected the case of fiscal impact filed by the Minister of Finance and Public Credit, stating that the arguments presented did not meet the constitutional threshold.
On December 11,2025, Ecopetrol entered into agreements with the ANH, authorizing the allocation of crude oil royalties amounting to 95.8 million boe from the Activo Castilla, Akacias, Caño Sur Este, Chichimene, Rubiales, and Yariguí-Cantagallo fields, as well as 4.5 million boe in economic rights from the Tello-La Jagua field. These allocations were made pursuant to a commercial agreement between the parties governing the payment of royalties in cash.
On December 22, 2025, the National Government issued Decree 1390, declaring a State of Economic Emergency across the national territory for a period of 30 days in response to unforeseen circumstances that materially worsened the country’s fiscal position. Subsequently, on December 29, 2025, the Government issued Decree 1474 introducing tax measures intended to finance expenditures under the General National Budget for fiscal year 2026. Of particular relevance, Article 14 of Decree 1474 establishes that royalties paid by taxpayers in connection with the extraction of non-renewable natural resources are no longer deductible for income tax purposes.
On February 11, 2026, the National Government issued Decree 1050 of 2026, declaring a new State of Economic, Social and Ecological Emergency. Pursuant to Decree 1050, the Government issued Decree 173 of 2026 introducing a temporary wealth tax applicable to Colombian legal entities and assimilated entities for fiscal year 2026. The tax takes effect upon publication and is triggered by the possession of net equity as of March 1, 2026. For extractive industries, the applicable rate is 1.6%. The tax includes specific exclusions and anti-avoidance rules, and must be declared and paid in two installments during 2026.
See section Financial Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results—Taxes and section Risk Review—Risk Factors—Risks Related to Our Business—New or higher taxes resulting from changes in tax regulations or the interpretation thereof in Colombia could adversely affect our results of operations and financial condition.
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Purchases of hydrocarbons
We purchase all crude oil delivered to the ANH as royalties by Ecopetrol and by third parties. The purchase price is calculated according to a formula set forth in a contract between Ecopetrol S.A. and the ANH that reflects our export sales prices, a quality adjustment for API gravity and sulfur content, a marketing fee, and transportation rates from the wellhead to ports and refineries. We sell the physical product purchased from the ANH as part of our ordinary business. The contract between the ANH and Ecopetrol S.A. was extended until June 30, 2026.
We import crude oil for Cartagena and Barranca refineries’ feedstock when such imports result in the better operational or economic performance of the Ecopetrol Group.
Electricity transmission rates
Electricity transmission is a regulated activity in all jurisdictions where ISA operates. We must maintain certain quality, safety, and maintenance standards with respect to our businesses. Periodic adjustment of transmission rates or reviews of the methodologies established by applicable regulations for the calculation of such rates may result in a decrease of the sales of the energy transmission and toll roads concessions segment and may have a material adverse effect on our consolidated results of operations and financial condition. Regulatory agencies could penalize ISA if we fail to comply with the terms of the rules and regulations applicable to our ISA’s businesses.
Conflict between Russia and Ukraine
We monitor the Russia-Ukraine conflict to identify factors that could impact our financial performance. These factors include the ongoing conflict, interruptions in the export of Russian energy due to sanctions, disruptions in supply chain, price volatility and others. In addition, we continue to monitor potential changes in demand, geopolitical risks, and regulatory changes that could affect our operations. Despite the conflict persisting throughout 2025, the market corrected oil and gas prices downwards.
United States Special Operation in Venezuela
On January 3, 2026, the United States conducted a special operation in Venezuela that resulted in the capture and removal from the country of Nicolás Maduro. In the ensuing weeks, U.S. authorities indicated that Venezuelan crude would be administered and marketed through U.S.-supervised accounts, and diplomatic engagement between the United States and Venezuela resumed. Concurrently, the U.S. Treasury issued guidance on developing oil and gas in Venezuela and related revenue flows, while Venezuela advanced an overhaul of its hydrocarbons framework to allow greater private participation (including self-marketing, lower fiscal burdens, and international arbitration). Several international oil companies executed or advanced framework and preparatory agreements. Taken together, these developments increased expectations of higher Venezuelan output and incremental availability of heavy and medium crude streams into the U.S. Gulf Coast (“USGC”) and other heavy-sour hubs.
These changes have affected relative pricing dynamics in our target markets. An increase in Venezuelan exports of heavy and medium grades—featuring API gravity and sulfur profiles comparable to certain Colombian blends—competes for the same refinery capacity in the USGC and other specialized hubs, given that these barrels are operational substitutes within similar crude slates. As availability rises in this quality segment, buyers gain negotiating leverage and relative discounts for comparable Latin American crudes tend to widen. As of the date hereof, increased availability has put pressure on pricing differentials, and our export crude may be adversely affected.
Significant uncertainties persist regarding the duration and scope of U.S. actions, the pace and durability of Venezuelan production recovery, and the stability of Venezuela’s policy framework necessary to attract and sustain private investment and infrastructure rehabilitation. Geopolitical tensions, supply-chain constraints, and trade-policy shifts may continue to influence market conditions, input costs, and project schedules. We continue to monitor these developments and implement mitigation measures, including destination diversification, quality-based optimization in commercial strategies, and robust sanctions compliance controls. We cannot assure that future developments will not have a material adverse effect on our operational or financial performance.
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Escalation of the Iran–Israel–United States Conflict
On February 28, 2026, the United States and Israel launched a coordinated military strike campaign against Iran, which included the killing of Supreme Leader Ayatollah Ali Khamenei and extensive attacks on Iranian military infrastructure. In retaliation, Iran carried out missile and drone attacks against Israel, U.S. military installations, and targets across several Gulf states. These events triggered a severe deterioration in maritime security conditions in the Strait of Hormuz, where commercial shipping volumes declined by more than 70% within days and subsequently fell to near zero, effectively closing one of the world’s most critical energy chokepoints. The resulting disruption affected approximately 20% of global seaborne oil supply and a significant volume of liquefied natural gas flows. Although limited commercial transit through the Strait of Hormuz has since resumed following multilateral naval escort arrangements, shipping volumes remain substantially below pre-conflict levels, and the timeline for a full reopening of the waterway remains uncertain.
Throughout 2026, we have maintained continuous monitoring of geopolitical developments, market disruptions, and regulatory changes associated with the Iran–Israel–U.S. conflict. Key factors under review include the duration and scope of the ongoing disruption in the Strait of Hormuz, the potential for additional attacks on regional energy infrastructure, the evolution of sanctions or maritime restrictions affecting crude and product flows, and the broader effects of sustained price volatility on global demand patterns. We also continue to monitor the progress of multilateral peace talks among the principal parties to the conflict; while negotiations remain at a preliminary stage, their outcome could materially affect the pace at which regional energy transit and trade normalize. Uncertainty remains elevated, and future developments, including the trajectory of diplomatic efforts, could continue to materially influence our revenues, costs, margins, and operational planning.
The Fuel Price Stabilization Fund (previously defined herein as FEPC) is a mechanism designed to react to drastic and sudden changes in hydrocarbon prices and prevent substantial increases or decreases in gasoline and diesel prices for Colombian consumers. In this way, the FEPC prevents substantial increases or decreases in prices for national consumers by using the difference between the local producer’s income and the parity (market) price, should there be drastic and sudden changes in hydrocarbon prices.
In 2023, the FEPC balance was COP 20.5 trillion due to the difference between the international market prices of regular motor gasoline and diesel, and the regulated prices in Colombia. The balance of this account was reduced by COP 12.9 trillion in 2024. In 2025, the balance of this account decreased to COP 3.03 trillion, representing the lowest level recorded since the onset of the COVID-19 pandemic.
The reduction in the balance of the FEPC in recent years is attributable to a combination of factors that have contributed both to reducing the generation of new deficits and to lowering the level of accumulated balances. First, the Colombian National Government implemented a gradual adjustment of domestic gasoline prices, progressively aligning them with international price levels, which significantly reduced the price differential compensated through the FEPC. Second, the National Government made substantial payments to settle historical balances of the FEPC, resulting in an effective reduction of outstanding obligations. Additionally, beginning in September 2024, a partial adjustment to diesel prices was implemented. Diesel has historically represented the primary source of pressure on the FEPC, and this adjustment contributed to moderating the growth of the deficit, although it has not fully eliminated it. Finally, these effects were reinforced by a less adverse international crude oil price environment compared to the exceptionally high levels observed in 2022, thereby reducing the cost of compensation associated with the stabilization mechanism.
The FEPC accounts receivable represent 20% of Ecopetrol’s total short-term accounts receivable as of December 31, 2025, and created a strain on working capital needs, including payment obligations to suppliers, taxes, payroll, and other short-term expenses. The balance of the FEPC account also impacts the comparison of solvency and liquidity levels against industry peers. Nevertheless, the Government of Colombia has outlined potential ways to manage the payment of outstanding accounts receivable balances and finding structural solutions to close the current gaps in the FEPC. See section Regulation Concerning Production and Prices - Fuel Price Stabilization Fund (FEPC).
4.2
[Reserved]
4.3
Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results
4.3.1
Taxes
By virtue of Law 2277 of 2022, the Certificado de Reembolso Tributario (“CERT”) incentive has ceased to exist as of January 1, 2023.
Refundable VAT on oil and gas exploration:
Taxpayers in the oil and gas industry are entitled to refund VAT paid in the exploration phase for offshore projects. Taxpayers can request this VAT as of the next fiscal year in which the investment was made. VAT that is reimbursed cannot be used as a higher cost or expense for income tax purposes.
Additionally, in December 2018, the Colombian Congress adopted Law 1943, which introduced the following key changes to the Colombian tax system, applicable beginning in 2019, including the following aspects:
The corporate income tax rates were set to be reduced gradually from 33% to 30% as follows: 33% in 2019, 32% in 2020, 31% in 2021 and 30% from 2022 onward. However, in September 2021, the Colombian Congress adopted Law 2155, which changed the corporate income tax rates to 35% from 2022 onward.
The presumptive income tax rate was reduced to 0% from fiscal year 2021 onward.
Taxpayers must calculate their taxable income taking as initial base the year and result under Colombian IFRS. Accounting profit is reconciled to obtain the taxable income, which is the basis to calculate the income tax.
For fiscal years 2023, 2024, and 2025 the dividends tax applied as follows:
In accordance with Article 245 of the Colombian Tax Code, the dividends tax applicable to non-resident shareholders is as follows: (i) a 20% dividend tax for dividends paid out of profits that were accrued as of January 1, 2017 and were taxed at the corporate level; (ii) no dividend tax on dividends paid out of profits that accrued until December 31, 2016 and were taxed at the corporate level; (iii) a withholding tax at the statutory corporate income tax rate (35% as from 2022) on dividends distributed from profits not taxed at the corporate level if the dividend is paid out of profits that accrued as of January 1, 2017, plus an additional, 20% dividend tax, as applicable, after applying the initial corporate income withholding tax rate.
In accordance with Article 242 of the Colombian Tax Code, for Colombian individuals: For fiscal years of 2023, 2024 and 2025 dividends paid greater than 1,090 UVT were taxed at rate of 15%.
In accordance with Article 242-1 of the Colombian Tax Code, dividends distributed from taxed profits to local corporations for fiscal years 2023, 2024 and 2025, the tax rate increased to 10%.
Tax losses accrued as of fiscal year 2017 may be offset against ordinary net income obtained in the following 12 taxable years.
Depreciation and amortization methods and annual percentages must be determined in accordance with accounting rules and are limited to those established in the tax rule and depend on the type of asset. For example, machinery and equipment depreciate at an annual rate of 10%, infrastructure (including pipelines) at 2.22%, vehicles at 10% and computers at 20%, among others.
Income tax for free trade zone users increased from 15% to 20% as of fiscal year 2017. The tax rate for free trade zone users with a legal stability agreement (in which the income tax rate was stabilized) remains at 15% during the term of said agreement.
The general value added tax (VAT) rate increased to 19% and a differential rate of 5% for certain goods and services is maintained. The modification of the general VAT rate is effective from January 1, 2017.
The charge on financial transactions is 0.4%, with half of the tax liability being deductible.
In accordance with Resolutions No. 07 of 2024 and 08 of 2025, issued by the tax authority, the carbon tax accrues on the carbon content of fossil fuels used for combustion. The rate was COP 25,799.56 and COP 27,399.14 per ton of CO2, for fiscal years 2024 and 2025, respectively.
In October 2019, the Law 1943 of 2018 (the Financing Law) was declared unconstitutional by the Constitutional Court, effective January 1, 2020. Therefore, the Financing Law continued to have full effect for the full fiscal year 2019.
In December 2019, the Colombian Congress adopted Law 2010, which introduced changes to the Colombian tax system, which became effective in 2020.
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As of 2020, in accordance with Article 115 of the Colombian Tax Code, taxes are fully deductible if they are effectively paid during the fiscal year, except for: (i) income tax, equity tax and normalization tax are non-deductible; and (ii) only 50% of the financial transactions tax is deductible.
VAT paid on the acquisition, import, creation or construction of tangible fixed assets used in income generating activities may be treated as discount (tax credit) for income tax purposes, in the same year or in future years.
On September 14, 2021, the Colombian Congress passed Law 2155 which introduced, among others, the following key changes to the Colombian tax system:
The Corporate Income Tax rate will be 35% as from 2022 onward.
A “normalization tax” was re-introduced for taxpayers to declare omitted assets or reject nonexistent liabilities subject to the payment of a 17% tax. This tax applies only for 2022, and a 50% prepayment is to be remitted in 2021.
iv.
A new definition of final (effective) beneficiary for tax purposes was created (Article 16).
In 2022, the Colombian Congress adopted Law 2277 of 2022, which introduced the following modifications to the Colombian tax system, applicable from January 1st, 2023: (i) a new permanent equity tax applicable to Colombian individuals and non-residents, at rates ranging from 0.5% to 1.5% based on the level of net equity at January 1st every year, (ii) an increase in the dividend tax rate for local and foreign shareholders (0% to 39% progressive marginal rates for Colombian individuals, and 20% flat withholding for non-resident shareholders), (iii) an increase in the long-term capital gains tax rate (increases from 10% to 15%), (iv) the elimination of specific tax benefits and exemptions, (v) a minimum corporate income tax based on effective tax rate (effective rate calculated on book profit should be at least 15%, considering certain adjustments to accounting profits and certain exempted companies), (vi) the application of taxes based on significant economic presence (primarily for non-resident persons and entities that provide digital services, but including other services and commercial activities), (vii) the elimination of the ability to claim 50% of the ICA as an income tax credit, (viii) an additional percentage points to the nominal tax rate for companies engaged in the extraction of crude oil and coal of 0%, 5%, 10% or 15% and based on international prices.
For the fiscal years 2024 and 2025, additional percentage points will be applied to the nominal of 10% and 0%, given that the Brent price was USD 78.76 and USD 67.73, according to ANH Resolutions No. 0044 and No. 0061 from January 31, 2025 and 2026, respectively. Note that the revenues from the sale of natural gas are not subject to these additional percentage points to the nominal tax rate, (ix) non-deductibility of royalties, and (x) the modification of section 221 of Law 1819 of 2016, with an adjustment to the taxable event and establishing that the national carbon tax will be levied on the carbon equivalent content (CO2eq) of all fossil fuels, including all petroleum derivatives, fossil gas and solids used for combustion.
On November 16, 2023, the Constitutional Court in Colombia issued ruling C-489, in which it determined that royalties are a deductible cost of income tax. In December of 2023, the Ministry of Mines and Energy and the Ministry of Finance and Public Credit requested a review of the ruling to the Constitutional Court, alleging a fiscal impact and nullity, respectively. In March of 2024, the Constitutional Court rejected the request for nullity filed by the Ministry of Mines and Energy. The Constitutional Court rejected the case of fiscal impact filed by the Minister of Finance and Public Credit and granted a term of five business days to correct the written statement and provide additional information. In May 2024, the Constitutional Court rejected the case of fiscal impact filed by the Minister of Finance and Public Credit, stating that the arguments presented did not meet the constitutional threshold. In July 2024, the Constitutional Court rejected the request for insistence filed by the Ministry of Mines and Energy.
On February 22, 2025, the National Government issued Decree 0175, which creates the Catatumbo special tax for the first sales and exports of oil. The rate of this tax is 1%. Additionally, it increases the stamp tax from 0% to 1%. The Decree was valid until December 31, 2025.
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On December 22, 2025, the National Government issued Decree 1390, declaring a State of Economic Emergency throughout the national territory for a period of 30 days due to unforeseen circumstances that worsened the country’s fiscal situation. Consequently, in response to this emergency, the Government issued Decree 1474 on December 29, 2025, introducing tax measures intended to fund expenditures under the General National Budget for fiscal year 2026. Among these measures is the provision set out in Article 14 of the decree, which establishes the non-deductibility of royalties for taxpayers required to pay them in connection with the production of non-renewable natural resources. This decree is subject to automatic review by the Constitutional Court, which must assess, among other aspects, the constitutionality of this measure. The Court’s analysis should consider its 2023 ruling that declared unconstitutional the royalty non-deductibility provision enacted under Law 2277 of 2022. Additionally, the decree established the Special Tax for Fiscal Stability, which imposes a 1% levy on the extraction of hydrocarbons within the national territory, applicable on the first sale or export of oil. On January 29, 2026, through Press Release No. 01, the Constitutional Court announced its decision to suspend the legal effects of the Economic Emergency Decrees.
On February 11, 2026, the National Government issued Decree 0150 of 2026 declaring a new State of Economic, Social and Ecological Emergency. Under Decree 1015 of 2026, Decree 173 of 2026 was issued, introducing introduced temporary wealth tax applicable for fiscal year 2026 to Colombian legal entities and assimilated entities, effective as from its publication and triggered by the possession of net equity as of March 1, 2026.
The tax applies at a 1.6% rate for extractive industries and includes specific exclusions and anti-avoidance rules. The tax return must be declared and paid in two installments in 2026.
For information related to Pillar II, see Note 10 of our consolidated financial statements.
Part A: Applicable Taxpayers for the Equity Tax (2023 and onwards)
Part B: Tax Accrual Rules
The equity tax will accrue at a rate of 0.5%, 1% and 1.5% every year on January 1 of each fiscal year. The taxable base is the taxpayer’s net equity on each of the accrual dates (gross assets less liabilities and certain exclusions, including a portion of the value of the dwelling house). Note that equity tax will only apply on taxable net equity exceeding 72,000 tax value units (UVTs, per the acronym in Spanish). Due to the State of Economic Emergency declared by the National Government on December 22, 2025, through Decree 1390, the Government issued Decree 1474 on December 29, 2025, establishing various tax measures. Among these, and on a temporary basis for fiscal year 2026, the decree broadens the wealth tax base by lowering the entry threshold from 72,000 UVT to 40,000 UVT at a rate of 0.5%, 1%, 2%, 3% and 5%.
Thin capitalization: A 2:1 debt-to-equity ratio determines the amount of deductible interests on loans with related parties.
Laws 2010, 2155 and 2277 maintain the tax regime for profits derived from indirect transfer of Colombian assets.
A special regime (the Mega Investments Regime) was created for taxpayers who (i) generate at least 400 direct jobs and (ii) make new investments in Colombia in an amount equal to or greater than 30,000,000 UVT (COP 1,140,120,000,000) by 2022, with a view for them to calculate and settle their income tax liability for the next 20 years using the following metrics and/or policies:
27% income tax rate;
Two-year term for the depreciation for fixed assets;
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Exclusion from the presumptive income regime;
Exclusion from the wealth tax; and
v.
0.75% premium over the investment value to be paid on an annual basis.
In addition, legal taxpayers who qualify for this Mega Investment Regime are required to enter into agreements with the tax authority.
These rules do not apply to taxpayers engaged in the exploration of non-renewable natural resources.
Law 2277 of 2022 repealed the Mega Investments Regime, which ceased to apply on January 1, 2023. However, taxpayers who met the eligibility requirements or obtained approval under the Mega Investments Regime before January 1, 2023, still hold the rights acquired under such regime.
As of January 1, 2026, the stamp tax, reactivated through Decree 0175 of February 22, 2025, at a 1% rate, was reduced to 0%.
4.3.2
Exchange Rate Variation
The functional currency of each of the companies of Ecopetrol Group is determined in relation to the main economic environment where each company operates; however, our consolidated financial results are reported in Colombian Pesos, which is the Ecopetrol Group’s functional and presentation currency. A substantial part of our consolidated sales come from the Ecopetrol Group’s companies whose functional currency is the Colombian Peso. The conversion effect from U.S. dollar to Colombian Peso is mainly due to local sales and exports of crude oil, natural gas, and refined products, whose prices are based on benchmarks quoted in U.S. dollars. Therefore, they are exposed to foreign currency exchange risks on sales, capital expenditures and financial instruments that are denominated in a currency other than its functional currency.
Fluctuations in the U.S. dollar-Colombian Peso exchange rate have effects on our consolidated financial statements. As crude oil is priced in U.S. dollars, fluctuations in the exchange rate of the Colombian Peso against the U.S. dollar may have a significant impact on sales, cost, monetary assets, and liabilities held in foreign currency.
An appreciation of the Colombian Peso has a negative impact on our results of operations because our sales from exports of crude oil, natural gas, and refined products are primarily expressed in U.S. dollars. Costs of imported products and contracted services expressed in U.S. dollars will also be lower when expressed in Colombian Pesos, but on balance, our operating income in Colombian Pesos tends to decline when the Colombian Peso appreciates, other factors being equal. The appreciation of the Colombian Peso against the U.S. dollar will also decrease the debt service requirements of our Companies with the Colombian Peso as their functional currency and with indebtedness in U.S. dollars, as the amount of the Colombian pesos necessary to pay principal and interest on foreign currency debt decreases with the appreciation of the Colombian Peso.
Conversely, when the Colombian Peso depreciates against the U.S. dollar, our reported sales, costs related to imported products and services, operating income, and debt service requirements of foreign-denominated debt all tend to increase.
With the acquisition of ISA, an amount of our sales started being generated in currencies other than the Colombian peso, and some of the operating and other expenses we incur are paid in the local currency of the countries where ISA operates. As a result, we may be exposed to foreign exchange and translation risk when local currency financial statements are translated to Colombian pesos. In addition, around 81% of ISA’s debt is denominated in foreign currency. Therefore, our consolidated financial results could be affected by an increase in financial costs due to the devaluation of the currencies in the jurisdictions where ISA operates. As a result, the devaluation of the Colombian peso would lead to the recognition of currency conversion losses due to the increase in the affected debt balance upon the translation of U.S. dollar-denominated debt or other currencies to Colombian pesos.
During 2025, the Colombian Peso appreciated on average 0.46% against the U.S. dollar. In comparison, during 2024, the Colombian Peso appreciated on average 5.87% against the U.S. dollar, while in 2023, the Colombian Peso depreciated on average 1.64% against the U.S. dollar. Additionally, on December 31, 2025, the Colombian Peso/U.S. dollar exchange rate appreciated 14.79% as compared to the same date in 2024, while the Colombian Peso/U.S. dollar exchange rate had depreciated 15.36% in 2024 as of December 31, 2024, and appreciated 20.54% as of December 31, 2023, in relation to the rate on the same date of the immediately preceding year.
In 2025, our consolidated debt in foreign currency increased by a total of USD 1,241 million, due to new debt issued during the year. By contrast, in 2024, our consolidated debt in foreign currency decreased by a total of USD 331 million, due to the repayment of principal at maturity. In 2023, our consolidated debt in foreign currency increased by a total of USD 2,684 million, due to new debt acquired during the year, mainly from the issuance of international bonds.
As of December 31, 2025, our U.S. dollar denominated total debt was USD 29,065 million, recognized in our financial statements at its amortized cost, which corresponds to the present value of cash flows, discounted at the effective interest rate of each loan. Out of the total U.S. dollar denominated debt, USD 18,695 million are in Ecopetrol S.A.’s balance sheet, whose functional currency is the Colombian Peso. Therefore, when the Colombian Peso depreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate loss. In contrast, when the Colombian Peso appreciates against the U.S. dollar, Ecopetrol S.A. has an exchange rate gain. Some of the Ecopetrol Group’s companies have the U.S. dollar as their functional currency and are not exposed to a material exchange rate risk resulting from fluctuations in the Colombian Peso against the U.S. dollar. When the financial statements of the Ecopetrol Group are consolidated, the exchange rate differential of the subsidiaries’ assets and liabilities whose functional currency is the U.S. dollar is recognized directly in equity, as part of other comprehensive income.
Since 2015, Ecopetrol adopted hedge accounting, using two types of natural hedges with its U.S. dollar debt as a financial instrument: (i) a cash flow hedge for exports of crude oil, and (ii) a hedge of the net investment in foreign operations. As a result of the implementation of both hedges, 91% (USD 16,956 million) of Ecopetrol S.A.’s debt in U.S. dollars, as of December 31, 2025, was designated as a hedge. Similarly, since 2022, ISA adopted hedge accounting for the net investment in foreign operations. As a result, USD 392 million of ISA’s debt was designated as a hedge as of December 31, 2025. The total debt of foreign currency designated as a hedge as of December 31, 2025, was USD 17,348 million. With the adoption of hedge accounting, the effect of the volatility of the foreign exchange rate on the hedged portion of the debt is recognized directly in equity, as part of other comprehensive income.
The remaining portion of Ecopetrol S.A.’s U.S. dollar-denominated debt, as well as the financial assets and liabilities denominated in foreign currency, continues to be exposed to the fluctuation in the exchange rate, which means that an appreciation of the Colombian Peso against the U.S. dollar could generate a loss for companies whose functional currency is the Colombian Peso that have a net asset position in U.S. dollars or a gain if they have a net liability position in U.S. dollars. Conversely, a depreciation of the Colombian Peso against the U.S. dollar could generate a gain for companies whose functional currency is the Colombian peso that have a net asset position in U.S. dollars or a loss if they have a net liability position in U.S. dollars.
As of December 31, 2025, the Ecopetrol Group’s companies have the equivalent of a net U.S. dollar liability position of USD 84 million after the implementation of the accounting hedges previously mentioned above, minimizing the effect of exchange rate fluctuations in their results for the year.
4.3.3
Effects of Inflation
The average annual rate of inflation in Colombia for the past ten years is 5.7%. As measured by the general consumer price index, the annual inflation rate in Colombia for the years ended December 31, 2025, 2024 and 2023 was 5.1%, 5.2%, and 9.3%, respectively. The decrease in inflation in 2025 is mainly driven by (i) the continued moderation of core inflation, reflecting lower pressures from food and tradable goods prices, and (ii) the lagged effects of the restrictive monetary policy implemented by the Nation’s Central Bank (Banco de la República), which has helped temper domestic demand and inflation expectations.
Inflation has had a positive and a negative effect on the Group. On one hand, it has increased sales for the transmission and roads segment, given that the rates are indexed to inflation, and it has also produced higher yields from our investment portfolio. On the other hand, it has increased costs, expenses and capital expenditures mainly due to the rising cost of inputs, higher tariffs in contracts, as well as a higher financial cost of the debt with floating rates (33.6% of the total financial obligations on December 31, 2025). The effects of inflation vary over time and between each market segment.
4.3.4
Effects of Crude Oil and Refined Product Prices
The average price of ICE Brent crude in 2025 was USD 68.2 per barrel as compared to USD 79.9 per barrel in 2024 and USD 82.2 per barrel in 2023. See section Strategy and Market Overview.
Our average crude oil basket price was USD 63.6 per barrel in 2025, as compared to USD 73.4 per barrel in 2024 and USD 73.5 per barrel in 2023. The decrease in 2025 compared to 2024 due to lower international crude oil prices, reflected in the decline of the Brent reference price during the year. This effect was partially offset by improved crude differentials, resulting from the strengthening of our crude oils in international markets and the implementation of a commercial strategy aimed at optimizing crude placement by prioritizing markets and geographic destinations with more favorable demand conditions, thereby maximizing realized differentials during the period.
In addition, our average product basket price was USD 81.6 in 2025, USD 86.8 in 2024, and USD 96.1 in 2023. The decrease in 2025 as compared to 2024 was primarily due to lower international refined product prices, consistent with the decline in benchmark crude prices, partially offset by improvements in refined product cracks in the market supported by high refinery utilization during the year.
In the Operating Results section below, we present the impact of the price decrease on our sale and cost of sales. Additionally, fluctuations in the price of oil have had an impact on the value of our oil and gas reserves. Reserves’ valuation is made in accordance with SEC price regulations. Volatility in hydrocarbon prices, refining margins and reserves, as well as changes in environmental regulations may lead to the recognition of impairment or recovery of non-current assets.
For additional information about impairment charges and reversals, see sections Financial Review—Operating Results—Consolidated Results of Operations—Impairment of Non-Current assets, Segment Performance and Analysis and Note 18 to our consolidated financial statements.
Accounting Policies
Our consolidated financial statements for the years ended December 31, 2025, 2024, and 2023 were prepared in accordance with IFRS. The details of the accounting policies are described in Note 4 to our consolidated financial statements.
In 2025 and 2024, there were no new or amended standards or interpretations adopted that had a significant impact on our consolidated financial statements. The main accounting regulatory change for 2023 was the adoption of IFRS 17 Insurance Contracts that provides a new general model for accounting for contracts by combining a measurement of the current balance of insurance contracts with the recognition of earnings during the period in which the services are rendered. This change did not have any material impact.
For more information regarding the adoption of new accounting standards and their effects on our financial statements, see Note 5 to our consolidated financial statements included in this annual report.
Material accounting judgments and estimates
Critical accounting policies are those policies that require us to exercise judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations. The accounting judgments and estimates we make in these contexts require us to calculate variables and make assumptions about matters that are highly uncertain. In each case, if we made other estimates, or if changes in the estimates occur from period to period, our financial condition and results of operations could be materially affected.
See Note 3 to our consolidated financial statements for a summary of the material accounting judgments and estimates applicable to us. There are many other areas in which we use estimates about uncertain matters, but we believe the reasonably likely effect of changes or differences within critical accounting judgments and estimates would not have a material impact on our financial statements.
4.6
Operating Results
The following discussion is based on information contained in our audited consolidated financial statements and should be read in conjunction therewith.
4.6.1
Consolidated Results of Operations
The following table sets forth components of our income statement for the years ended December 31, 2025, 2024, and 2023.
Table 57 – Summarized Consolidated Statement of profit or loss
Income Statement
For the Years ended December 31,
% Change
(COP billion)
2025/2024
2024/2023
119,694
133,330
143,189
(10.2)
(6.9)
Cost of Sales
82,057
86,481
88,178
(5.1)
(1.9)
Gross Profit
37,637
46,849
55,011
(19.7)
(14.8)
Administrative, operations and project expenses net
10,981
9,254
11,154
18.7
(17.0)
Impairment of non-current assets
(23)
(867)
2,098
(97.3)
(141.3)
Operating Income
26,679
38,462
41,759
(30.6)
(7.9)
Finance results, net
(8,528)
(8,519)
(5,665)
0.1
50.4
Share of profits of associates and joint ventures
710
764
805
(7.1)
Profit before income tax expense
18,861
30,707
36,899
(38.6)
(16.8)
Income tax expense
(4,417)
(12,208)
(11,516)
(63.8)
Net profit for the year
14,444
18,499
25,383
(22.0)
(27.1)
Net profit attributable to:
Owners of parent
10,488
13,841
21,061
(24.2)
(34.3)
Non–controlling interest
3,956
4,658
4,322
(15.1)
7.8
Net profit
(21.9)
4.6.1.1
The following table sets forth our principal sources of third-party sales by business segment for the years ended December 31, 2025, 2024, and 2023. An explanation of how we classify our operations into business segments is included in section 4.6.1.8 below.
Table 58 – Third-Party Sales by Business Segment
% change sales
Volume
(barrels
Average price
Sales by segment
equivalent)
US dollars / Barrels
(COPS billion)
Local Crude oil
452
1,151
65.4
433,524
(100.0)
Foreign Crude oil(1)
155,915,134
63.5
40,086
159,096,981
73.4
47,517
151,460,951
73.2
47,651
(15.6)
(0.3)
Natural gas local
24,652,186
27.1
4,162
31,071,560
33,432,168
30.7
4,358
1.6
(6.0)
Foreign natural gas
6,220,621
5,146,252
3,629,325
6.7
131.8
(58.1)
Other income(2)
10,424,462
478
9,984,441
903
9,005,330
(47.1)
388.1
Exploration and production sales
197,212,855
44,828
205,300,385
52,560
197,961,298
52,429
(14.7)
0.3
Local refined products(1)
124,262,235
91.1
45,846
125,038,118
97.4
49,544
126,731,492
108.5
59,319
(7.5)
(16.5)
Foreign refined products(1)
32,082,345
8,356
35,813,033
9,968
36,672,668
70.9
11,167
(16.2)
(10.7)
Foreign Crude oil
704,881
74.5
4,087,113
77.1
1,282
5,776,131
79.9
2,028
(83.2)
(36.8)
1,777
1,458
2,516
1,103
21.9
32.2
Refining and petrochemicals
157,049,461
56,195
164,938,264
62,252
169,177,775
73,617
(9.7)
(15.4)
Transportation services
2,642
2,716
2,979
(2.7)
(8.8)
Energy Transmission and Toll Roads services
16,029
15,803
14,165
1.4
Energy Transmission and Toll Road(3)
Total sales
354,262,316
370,238,649
367,139,073
156,620,467
40,302
163,185,245
73.5
48,799
157,670,606
49,808
(17.4)
(2.0)
Natural gas
30,872,807
22.4
4,264
36,217,812
27.8
4,140
37,061,493
28.4
4,464
(7.2)
Refined products
166,769,042
81.6
54,680
170,835,592
86.8
60,414
172,409,490
96.1
70,670
(9.5)
(14.5)
20,448
19,977
18,247
2.4
Includes the effects of strategic and tactical hedging instruments related to crude oil, fuel oil and diesel. For qualifying cash flow hedges, gains and losses initially recognized in other comprehensive income are reclassified to profit or loss in the same periods in which the hedged transactions affect earnings, primarily within revenues and cost of sales, in accordance with IFRS 9.
In the exploration and production segment, other income mainly comprises the effects of natural hedges used to mitigate foreign exchange exposure related to forecast crude oil sales and debt, together with services and sales of refined products (mainly LPG and asphalt). In the case of the refining and petrochemicals segment, other income corresponds mostly to industrial services.
The energy transmission and toll roads concessions segment’s sales mainly include: (i) electricity transmission services, (ii) designing, building, operating and maintaining road concessions infrastructure roads, and (iii) telecommunications services.
In 2025, total sales decreased by 10.2% as compared to 2024, representing a COP 13,636 billion decline driven mainly by (i) lower commodity prices, which accounted for a COP 9,663 billion decrease in sales: our average refined products basket price fell by 6.0%, (USD 5.2 per barrel), and our average crude oil basket price fell by 13.6% (USD 9.7 per barrel), in each case primarily due to a lower Brent benchmark price, partially offset by the strengthening of spreads against Brent for refined products and the negotiated crude oil differential, (ii) a 0.5% appreciation of the Colombian Peso against the U.S. dollar, —from an average exchange rate of COP 4,071.35 / USD 1.00 in 2024 to an average exchange rate of COP 4,052.71 / USD 1.00 in 2025—reduced export sales by COP 443 billion, and (iii) lower sales volumes (as further explained below) resulted in a COP 3,608 billion decrease in sales. This decrease was partially offset by a COP 378 billion increase in service sales, primarily due to enhanced results in energy transmission.
The decrease in our sales volumes in 2025 as compared to 2024 was driven by: (i) a COP 1,692 billion, or a 4.0%, or 6.6 mmboe, decrease in crude oil sales, primarily associated with higher export crude realizations in 2024 due to volumes in transit from year-end 2023, while in 2025 such prior period transits volumes were recognized, (ii) a COP 939 billion, or a 14.8%, or 5.3 mmboe decrease in our natural gas sales associated with lower domestic sales of natural gas and LPG, reduced contracted volumes with customers and declining production in Guajira field and (iii) a COP 977 billion, or a a 2.4%, or 4.1 mmboe, decrease in refined products volumes due to lower sales of refined products for export and reduced domestic demand for diesel and gasoline as result of direct imports by customers.
In 2024, total sales decreased by 6.9% as compared to 2023, primarily as a result of a COP 6,125 billion decrease in sales mainly due to (i) 9.3%, or USD 9.4 per barrel decrease of our average refined products basket price and a 0.1 %, or USD 0.1 per barrel decrease of our average crude oil basket price, which in turn was primarily due to a lower Brent benchmark price and narrower spreads against Brent for refined products partially offset by the strengthening of the negotiated crude oil differential, and (ii) a COP 5,341 billion decrease in sales resulting from a 5.87% appreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP 4,325.05 / USD 1.00 in 2023 to an average exchange rate of COP 4,071.35 /USD 1.00 in 2024, resulting in a decrease in sale from exports. This decrease was partially offset by (i) a COP 1,516 billion increase in service sales, primarily due to enhanced results in energy transmission due to the recognition of non-recurring income from the tariff review of ISA Subsidiaries in Brazil, toll roads, transport, the positive impact of contractual escalators and the entry into operation of projects, and (ii) a COP 88 billion increase in revenues attributable to an increase in our sales volume (as further explained below).
The increase in our sales volumes in 2024 as compared to 2023 was the result of a 3.5%, or 5.5 mmboe increase in our crude sales, primarily associated with higher crude oil production. This increase was partially offset by (i) a 0.9% or 1.6 mmboe in refined products volumes due to scheduled major maintenance of the Hydro-cracking unit the effect of the electrical failure in the Cartagena Refinery, and (ii) a 2.3%, or 0.8 mmboe decrease in our natural gas sales associated with the natural decline of the Guajira, Floreña and Cusiana fields.
4.6.1.2
Our cost of sales was principally affected by the factors described below. See Note 26 to our consolidated financial statements for more detail.
Cost of sales in 2025 was COP 82,057 billion, representing a COP 4,424 billion or 5.1% decrease as compared to 2024, primarily as a result of the following factors:
The decrease in cost of sales was partially offset by a COP 2,358 billion increase as a result of:
(a)
A COP 879 billion increase in depreciation, amortization, and depletion expenses primarily due to: (i) a higher level of capital investment, and (ii) the increase in crude production. The above was partially offset by a lower depreciation rate associated with the mitigating effect of the higher incorporation of reserves during 2025.
(b)
A COP 654 billion increase in construction services costs mainly explained by: (i) an increase in construction activity associated with the execution of energy transmission infrastructure projects in ISA, and (ii) the inflationary effect on the contracts.
(c)
A COP 143 billion increase in labor cost primarily related to higher salary increases in 2025 as compared to 2024.
(d)
A COP 547 billion increase in maintenance activities, contracted services, operation supplies and other operational activity costs, as a result of the net effect between: (i) greater execution of operational support activities, (ii) the inflation effect on costs, (iii) lower average exchange rate for costs, (iv) cost control and efficiencies, and (v) higher taxes and contributions.
(e)
A COP 121 billion increase in transportation costs primarily related to: (i) higher transportation tariffs resulting from tariff updates, (ii) higher costs from contingent operations at Banadía–Araguaney, partially offset by lower average exchange rate for costs.
(f)
A COP 13 billion increase in other minor items, including general costs.
Cost of sales in 2024 was COP 86,481 billion, representing a COP 1,697 billion or 1.9 % decrease as compared to 2023, primarily as a result of the following factors:
The decrease in cost of sales was partially offset by a COP 3,272 billion increase as a result of:
A COP 1,441 billion increase in depreciation, amortization, and depletion expenses primarily due to: (i) a higher level of capital investment, and (ii) the increase in production of Permian. The above was partially offset by a lower depreciation rate associated with the mitigating effect of the higher incorporation of reserves during 2023 and the exchange rate effect in appreciation for the Group’s subsidiaries, which use the U.S. dollar as a functional currency, given the revaluation of the Colombian peso against the U.S. dollar.
A COP 985 billion increase in construction services mainly explained by: (i) increase in construction activity of ISA in Brazil, and (ii) the inflationary effect on the contracts.
A COP 323 billion increase in labor cost primarily related to higher salary increase in 2024 as compared to 2023.
A COP 244 billion increase in maintenance activities, contracted services, operation supplies and other operational activity costs, as a result to the net effect between: (i) greater execution of operational support activities, (ii) the inflation effect on costs, and (iii) lower average exchange rate for costs.
A COP 228 billion increase in transportation costs primarily related to: (i) higher volume of crude oil transported for tanker trucks due to an increase in the production from Caño Sur in Colombia, and (ii) higher transportation tariffs impacted by the inflationary effect.
A COP 52 billion increase in other minor items, including higher taxes and contributions, and general costs.
4.6.1.3
Administrative, operations and project expenses, net of other income before Impairment of Non-Current Assets Effects
Operating expenses, net of other income include administrative, operations and project expenses and other operating (expenses) income before impairment or recovery of non-current assets. For 2025, these amounted to COP 10,981 billion, representing a COP 1,727 billion, or 18.7%, increase as compared to 2024, mainly as a result of the following factors (see Notes 27 and 28 to our consolidated financial statements for more detail):
These factors were partially offset by a COP 818 billion decrease in exploration expenses and other operational expenses in 2025 compared to 2024, mainly reflecting lower write-offs of exploration assets.
For 2024, operating expenses, net of other income amounted to COP 9,254 billion, a COP 1,900 billion or 17% decrease as compared to 2023, mainly as a result of the following factors:
Each of our operating segments bears the costs and expenses incurred for product use and marketing and each segment assumes administrative expenses and all non-operational transactions related to its activity. Discussion of operating expenses by business segment is included in the section Financial Review—Operating Results—Consolidated Results of Operations—Segment Performance and Analysis.
4.6.1.4
Impairment recovery (loss) of long-term non–monetary assets
The impairment of our non-current assets includes losses (or recovery) of impairment of property, plant and equipment and natural resources, investments in companies, goodwill, and other non-current assets. The Company is exposed to future risks derived mainly from variations in: (i) oil prices outlook, (ii) refining margins and profitability, (iii) cost profile, (iv) investment and maintenance expenses, (v) amount of recoverable reserves, (vi) market and country risk assessments reflected in the discount rate, and (vii) changes of local and international regulations, among others.
Any change in the foregoing variables used to calculate the recoverable amount of a non-current asset can have a material effect on the recognition of either losses or recovery of impairment charges in the profit or loss statement in any given fiscal year. In our business segments highly sensitive variables can include, among others: (i) in the exploration and production segment, variations of hydrocarbon prices, (ii) in the refining segment, changes in finished products and crude oil prices, the discount rate, refining margins, (iii) in the transport and logistics segment, transported volumes and exchange rate, and (iv) in energy transmission and toll roads concessions, internal and external factors that affect the recoverable value of the assets versus the book value of the assets, such as currency devaluation, network capacity, modest economic growth, among others.
In 2025, we recognized impairment recovery of non-current assets of COP 22 billion, as compared to impairment recovery of COP 867 billion in 2024 and impairment losses of COP 2,098 billion in 2023. These impairments are a non-cash accounting effect and consequently do not involve any disbursement or cash inflow. Further, any cumulative impairment amount of non-current assets, except for goodwill, is susceptible to reversion when the fair value of the asset exceeds its book value. On the contrary, in the event that the book value exceeds the fair value of the asset, an additional impairment expense could be recognized.
The 2025 impairment gains, net of non-current assets of COP 22 billion, correspond to the net result of:
The 2024 impairment gains, net of non-current assets of COP 867 billion, correspond to the net result of:
The 2023 impairment losses, net of non-current assets of COP 2,098 billion, correspond to the net result of:
141
This impairment loss was partially offset by an impairment recovery in refining and petrochemicals Segment of COP 1,482 billion, primarily due to an impairment recovery in Cartagena Refinery, which in turn is due to (i) higher price differentials in middle distillates in the medium and long-term projection, (ii) imported crude oils more discounted on the brent marker, and (iii) operational improvements executed in 2023, which together with energy efficiency initiatives, have managed to optimize the operational costs of the refinery and reduce energy consumption.
For more information regarding impairment by segment, see section Financial Review—Operating Results—Consolidated Results of Operations—Segment Performance and Analysis.
4.6.1.5
Finance Results, Net
Finance results, net, mainly include exchange rate gains or losses, interest expenses, yields and interest from our investments and non-current liabilities financial costs (asset retirement obligation and post-benefits plan).
Finance results, net, amounted to a loss of COP 8,528 billion in 2025, as compared to a loss of COP 8,519 billion in 2024. This increase in loss was mainly due to:
A COP 227 billion increase in financial expenses related to long term obligations, primarily due to higher indebtedness levels by the Ecopetrol Group during 2025.
A COP 214 billion decrease in financial income related primarily to valuation and yields of the investment portfolio and bank accounts primarily as a result of a lower average cash position in 2025 as compared to 2024.
A COP 91 billion increase in financial update of long-term liability, which in turn was mainly to the increase in our asset retirement and pension obligations.
A COP 108 billion increase in foreign exchange gain primarily driven by the lower exposure from net U.S. dollar position presented in 2025, managed through natural accounting exchange rate hedges. In 2025, our exchange rate gain was COP 159 billion, as compared to a gain of COP 52 billion in 2024.
Finance results, net, amounted to a loss of COP 8,519 billion in 2024, as compared to a loss of COP 5,665 billion in 2023. This increase in loss was mainly due to:
A COP 2,346 billion decrease in foreign exchange gain primarily driven by the lower exposure presented in 2024, managed through natural accounting exchange rate hedges. In 2024, our exchange rate gain was COP 52 billion, as compared to a gain of COP 2,398 billion in 2023.
A COP 453 billion increase in financial expenses related to long term obligations, primarily due to higher interest rates in refinancing operations during 2024.
A COP 297 billion decrease in financial income related primarily to valuation and yields of the investment portfolio and bank accounts derived from a decrease in market yield rates.
A COP 269 billion increase in financial update of long-term liability mainly due to the cost of retirement obligation and the net interest on post-employment benefits and other long-term employee benefits.
The decrease in foreign exchange gain and increase in financial expenses were partially offset by a COP 511 billion decrease in other minor items, primarily due to the recognition of interests from a tax litigation ruling against Ecopetrol.
For more details on our financial income and expenses see Note 29 of our consolidated financial statements.
4.6.1.6
Income Tax
Income taxes amounted to COP 4,417 billion in 2025, COP 12,209 billion in 2024, and COP 11,516 billion in 2023. The above is equivalent to an effective tax rate of 23.4%, 39.8%, and 31.2% in 2025, 2024, and 2023, respectively.
The decrease in the effective tax rate from 2024 to 2025 was mainly due to i) the effect to deferred tax to exchange rate effects on tax bases (~ COP 2,555 billion -13.5% ) ii) the lower surtax, which was 0% in 2025 compared to 10% in 2024 (~ COP 1,270 billion -6.7%), partially offset by the impact of different tax rates on the results of certain Ecopetrol’s subsidiaries and others (~ COP 750 billion+4.0%).
The increase in the effective tax rate from 2023 to 2024 was mainly due to lower profits generated by lower average prices for the basket of crude oil, natural gas and refined products, the effect of the exchange rate on companies with a dollar functional currency in Colombia, the adjustment in the projections for the calculation of the surcharge for the following years and the effect of the acquisition of 45% participating interest in the CPO-09 Block by Ecopetrol S.A., from Repsol Colombia Oil & Gas Limited.
See Note 10 to our consolidated financial statements for more details.
4.6.1.7
Net Profit Attributable to Owners of Parent
As a result of the foregoing, in 2025, net profit attributable to owners of Ecopetrol was COP 10,488 billion. In 2024, net profit attributable to owners of Ecopetrol was COP 13,841 billion, whereas in 2023, net profit attributable to owners of Ecopetrol was COP 21,061 billion.
4.6.1.8
Segment Performance and Analysis
In this section, including the tables below, we present our financial information by segment: (i) exploration and production, (ii) refining and petrochemicals, (iii) transport and logistics; and (iv) energy transmission and toll roads concessions. See section Business Overview for a description of each segment.
The following tables present our sales from contracts with customers by business segment for the years ended December 31, 2025, 2024 and 2023:
Table 59 – Sales by Business Segment
(COP Billion)
71,052
81,088
81,515
(12.4)
(0.5)
Third parties
52,430
Local crude oil
Foreign crude oil
Local natural gas
4,096
186
385.5
Inter-segment net operating sales
26,224
28,528
29,085
(8.1)
64,699
69,220
82,148
(6.5)
(15.7)
62,251
Local refined products
Foreign refined products
Other income
8,504
6,969
8,531
22.0
(18.3)
15,337
15,134
15,510
(2.4)
12,695
12,418
2.2
(0.9)
Energy Transmission and Toll Roads Concessions(1)
16,033
15,806
14,168
16,030
(25.0)
Eliminations of consolidations
(47,427)
(47,916)
(50,151)
(4.5)
Net Sales from Contracts with Customers
143,190
Table 60 – Operating and Net profit by Business Segment
For year ended December 31
10,821
20,819
20,091
(48)
5,338
9,163
10,207
(42)
(10)
(811)
374
5,456
(317)
(93)
(419)
(1,408)
5,354
(70)
(126)
10,135
9,594
9,486
5,118
5,111
4,830
0
6,492
7,656
6,645
(15)
451
966
674
(53)
(75)
(89)
(291)
(31)
(8)
Net Profit
(24)
(34)
We are currently organized into three corporate business lines: (A) hydrocarbons, which includes three operating segments: (i) exploration and production, (ii) transport and logistics; and (iii) refining and petrochemicals, (B) energy transmission and toll roads concessions, and (C) energies for the transition. This organization seeks to maintain the competitiveness of the Hydrocarbons business, the development and scaling of the businesses in the energies for the transition portfolio, and the growth of the transmission and toll roads concessions line.
For purposes of this annual report, financial information is presented and organized into the following segments: (i) exploration and production, (ii) transport and logistics, (iii) refining and petrochemicals, and (iv) energy transmission and toll roads concessions. This segmentation is consistent with the Company’s prior annual reports. We expect to use this segmentation until the Company’s management completes the restructuring of its operating and financial reporting model, with the objective of aligning it more effectively with the 2040 Strategy. See section Business Overview—Our Corporate Structure for more information on this restructuring process.
4.6.1.9
Exploration and Production Segment Results
In 2025, exploration and production segment sales were COP 71,052 billion, compared to COP 81,088 billion in 2024. In 2025, our segment sales decreased by 12.4% as compared to 2024, mainly as a result of:
(i)An 8.1% or COP 2,304 billion decrease in inter-segment net operating sales in 2025 as compared to 2024 mainly due to: (i) lower Brent reference prices, and the appreciation of the Colombian Peso against the U.S. dollar.
(ii)A 14.7% or COP 7,732 billion decrease in sales of crude oil to third parties in 2025 as compared to 2024 primarily due to: (i) lower price of our crude oil basket of USD 9.7 per barrel partially offset by the strengthening of the negotiated crude oil differential, and (ii) the appreciation of the Colombian Peso against the U.S. dollar.
In 2024, exploration and production segment sales were COP 81,088 billion, compared to COP 81,515 billion in 2023. In 2024, our segment sales decreased by 0.5% as compared to 2023, mainly as a result of:
(i)A 1.9% or COP 557 billion decrease in Inter-segment net operating sales in 2024 as compared to 2023 mainly due to: (i) the decrease in Brent reference prices partially offset by the strengthening of the negotiated crude oil differential, and (ii) the appreciation of the Colombian Peso against the U.S. dollar.
(ii)A 0.2% or 131 billion increase in sales of crude oil to third parties in 2024 as compared to 2023 primarily due to: (i) higher sales volumes of 19.7 mbd, due to an increase in the production from Permian and Caño Sur in Colombia, and (ii) higher price of our crude oil basket of USD 0.1 per barrel; partially offset by the appreciation of the Colombian Peso against the U.S. dollar.
Cost of sales affecting our exploration and production segment are mainly related to: (i) the amortization and depletion of our production assets, (ii) contracted services and (iii) costs related to maintenance, operational services, electric power, projects, and labor cost. In addition, this segment’s costs are impacted by the purchases of crude oil from ANH and third parties, naphtha for dilution and transportation services.
In 2025, the cost of sales for this segment decreased by 1.7% as compared to 2024 due to the net effect of:
(i)Fixed costs decreasing by 5.6%, or COP 819 billion in 2025 as compared to 2024, mainly due to lower operating costs resulting from the optimization of the operation and maintenance model and reductions in service contract rates, despite the increase associated with inflationary effects.
(ii)Variable costs decreasing by 0.2%, or COP 94 billion in 2025 as compared to 2024, as a result of lower purchases from third parties driven by a lower Brent reference price and lower purchased volumes, mainly associated with royalty crude volumes acquired from the ANH. These decreases were partially offset by the inflationary effect on the rates of materials required for well interventions and chemical treatment.
In 2024, the cost of sales for this segment increased by 5.9% as compared to 2023 due to the net effect of:
(i)Fixed costs increasing by 2.5%, or COP 352 billion in 2024 as compared to 2023, mainly due to: (i) higher activity including well interventions, maintenance and contracted services to support the production including the preparation and operational support for the start-up of the Orotoy station and the new Caño Sur facilities, as well as the specific maintenance required in the Gunflint and K2 fields of Ecopetrol America LLC; and (ii) an increase in depreciation, amortization and depletion, associated with higher production and Capex.
(ii)Variable costs increasing by 7.1%, or COP 2,683 billion in 2024 as compared to 2023, as a result of (i) higher energy consumption, chemical treatment and transportation costs associated with production increase, (ii) inflationary effect on the rates of materials needed for well interventions and chemical treatment; (iii) transportation costs associated with the execution of reversal cycles in the Bicentenario Pipeline, resulting from fewer days of operation of the Caño Limón Pipeline, and (iv) higher purchased volumes from third parties. These increases were partially offset by lower average exchange rate on cost denominated in dollar.
In 2025, operating expenses, net of other income before impairment of non-current assets increased by 20.9% as compared to 2024 primarily as a result of a non-recurring income recognized in 2024 of COP 1,721 billion, associated with the acquisition of the CPO-09 block; partially offset by (i) a COP 818 billion decrease in exploratory asset expenses, and (ii) lower administrative expenses.
In 2024, operating expenses, net of other income before impairment of non-current assets decreased by 28.2% as compared to 2023 primarily as a result of: (i) the transaction with Repsol Colombia Oil & Gas Limited to acquire the remaining 45% of its participation in the CPO-09 Block, due to the market prices valuation of both the acquired portion and Ecopetrol S.A.’s existing 55% participation interest in compliance with International Financial Reporting Standards for Business Combinations, (ii) lower updating of provisions and contingencies, and (iii) lower write-off of exploration assets in 2024 versus 2023.
The impairment of non-current assets recognized in the exploration and production segment in 2025 was COP 325 billion, as compared to COP 480 billion recognized in 2024. The impairment recognized in this segment in 2025 was mainly attributable to Ecopetrol S.A´s lower short-term price assumptions, partially offset by the execution of asset profitability management plans and a reduction in the discount rate.
The impairment of non-current assets recognized in the exploration and production segment in 2024 was COP 480 billion, as compared to COP 2,741 billion recognized in 2023. The impairment in this segment in 2024 was mainly in Ecopetrol America LLC due to lower short- and long-term prices as well as the reclassification of reserves.
The segment recorded a net profit attributable to owners of Ecopetrol of COP 5,257 billion in 2025 as compared to net profit attributable to owners of Ecopetrol of COP 9,163 billion in 2024 and net profit attributable to owners of Ecopetrol of COP 10,207 billion in 2023.
Lifting and Production Costs
The aggregate average production cost, on a Colombian Peso basis, decreased from COP 54,274 per boe during 2024 to COP 53,191 per boe during 2025. Moreover, this indicator decreased from USD 13.33 per boe in 2024 to USD 13.13 per boe in 2025.
The aggregate average lifting cost, on a Colombian Peso basis, decreased from COP 50,833 per boe during 2024 to COP 49,449 per boe during 2025. On a dollar basis, the cost reduced from USD 12.49 per boe in 2024 to USD 12.20 per boe in 2025, partly due to a 0.5% appreciation of the Colombian Peso against the U.S. dollar in 2025 compared to 2024.
In 2025, both the average production cost and the average lifting cost decreased compared to 2024, mainly due to:
The difference between the production and lifting costs is that first one additionally includes the production cost of the refineries and natural gas liquid plants located in the production fields.
The following table sets forth crude oil and natural gas average sales prices, the average lifting cost and the average production cost for the years ended December 31, 2023, 2024 and 2025.
Table 61 – Crude Oil and Natural Gas Average Prices and Costs
Crude Oil Average Sales Price (USD per barrel)(1)
Crude Oil Average Sales Price (COP per barrel)(1)
257,322
299,040
315,947
Natural Gas Average Sales Price (USD per barrel equivalent)
Natural Gas Average Sales Price (COP per barrel equivalent)
138,131
114,299
130,361
Aggregate Average Unit Production Costs (USD per boe)(2)
13.13
13.33
11.58
Aggregate Average Unit Production Cost (COP per boe)(2)
53,191
54,274
50,098
Aggregate Average Lifting Costs (USD per boe)(3)(4)(5)
12.20
12.49
10.91
Aggregate Average Lifting Costs (COP per boe)(3)(4)(5)
49,449
50,833
47,204
Corresponds to our average sales price on a consolidated basis.
Unit production costs correspond to consolidated average costs on total production volumes net of royalties. Production costs do not include costs related to transport, commercialization and administrative expenses.
Lifting costs per barrel are calculated based on total production (excluding production tests and discovered undeveloped fields), which are net of royalties, and correspond to our lifting costs on a consolidated basis.
The cost indicator is calculated by using the cost of production (does not include costs related to hydrocarbons consumption by Ecopetrol in the production process, such as by our refineries and natural gas liquid plants) and divided by the net produced volume (excluding royalties) as the denominator.
As a result of the evaluation of control over companies under IFRS, Ecopetrol does not consolidate Equion.
4.6.1.10
Transport and logistics Segment Results
In 2025, our transport and logistics segment sales were COP 15,337 billion compared to COP 15,134 billion in 2024. The 1.3% increase in 2025 as compared to 2024 was mainly due to: (i) tariff updates and (ii) higher contingent operations in the pipeline systems. These effects were partially offset by decreases in: (i) sales associated with the release of “Ship or Pay” capacity in the Bicentenario and Caño Limón-Coveñas pipelines, (ii) transported volume due to external operating conditions, and (iii) third-party domestic crude production.
In 2024, our transport and logistics segment sales were COP 15,134 billion compared to COP 15,509 billion in 2023. The 2.4% decrease in 2024 as compared to 2023 was mainly due to: (i) lower average COP/USD exchange rate, and (ii) completion in September 2023 of the “ship or pay” contract with Cenit (prior to the merger between Cenit and Oleoducto Bicentenario, with Oleoducto Bicentenario). This decrease was partially offset by: (i) the tariff update on oil pipelines, (ii) higher incomes from contingent operation, and (iii) the increase in industrial services.
The cost of sales for our transport and logistics segment is mainly related to: (i) project costs associated with the maintenance of transportation networks, and (ii) operating costs related to these systems, including the costs of labor, energy, fuels and lubricants and others.
The cost of sales amounted to COP 4,322 billion in 2025 as compared to COP 4,378 billion in 2024. The cost of sales for this segment decreased by 1.3% in 2025 as compared to 2024 mainly due to lower execution of maintenance activities and the positive results of cost-control and optimization strategies implemented in the segment, which effectively mitigated inflationary pressures.
The cost of sales amounted to COP 4,378 billion in 2024 as compared to COP 4,380 billion in 2023. The cost of sales for this segment decreased by 0.1% in 2024 as compared to 2023 mainly due to lower depreciation derived from the update of the useful life of the Bicentenario Pipeline; offset by: inflationary effect on maintenance contract fees, operating support area costs, and personnel costs, among others.
In 2025, operating expenses before the impairment of non-current assets decreased by 4.8% as compared to 2024 mainly due to (i) lower inventory impairments, (ii) lower asset write-offs and dismantling costs, and (iii) higher insurance claim recoveries. These effects were partially offset by the income recognized in 2024 from the sale of excess line-fill volumes.
The recovery of impairment loss of non-current assets recognized in the segment in 2025 was COP 346 billion, compared to the recovery of impairment loss of non-current assets of COP 127 billion in 2024. This recovery of impairment was primarily due to (i) the decrease in the discount rate; (ii) updates to transportation tariffs based on macroeconomic variables; and (iii) a decrease in projected costs.
The recovery of impairment loss of non-current assets recognized in the segment in 2024 was COP 127 billion, compared to the impairment loss of non-current assets of COP 630 billion in 2023. This recovery of impairment was primarily due to (i) the increase in the exchange rate for year-end 2024 versus 2023; (ii) the new tariffs for oil pipes regulated by the Ministry of Mines and Energy; and (iii) volumetric projection based on the financial plan and the long-term volumetric balance.
The segment recorded net profit attributable to owners of Ecopetrol of COP 5,118 billion in 2025, as compared to a net profit of COP 5,111 billion in 2024 and COP 4,829 billion in 2023.
4.6.1.11
Refining and Petrochemicals Segment Results
In 2025, the refining and petrochemical segment sales were COP 64,699 billion compared to COP 69,220 billion in 2024. In 2025, sales of refined products and petrochemicals decreased by 6.5% as compared to 2024, mainly due to: (i) lower prices of middle distillate products and gasoline, and an increase in refined product spreads, in both cases associated with market factors, and (ii) lower average COP/USD exchange rate. Invercolsa’s sales increased as a result of the higher commercialization of natural gas volumes. Esenttia’s sales volume decreased 39 ktons due to market dynamics, prompting the development of a commercial plan with short-, medium-, and long-term actions to reallocate sales toward potential markets and to implement a recovery strategy for key clients in Colombia.
In 2024, the refining and petrochemical segment sales were COP 69,220 billion compared to COP 82,148 billion in 2023. In 2024, sales of refined products and petrochemicals decreased by 15.7% as compared to 2023, mainly due to: (i) lower prices of middle distillate products and gasoline, and a decrease of refined product spreads, in both cases associated with market factors, (ii) scheduled major maintenance of the hydrocracking unit and the effect of the electrical failure at Cartagena Refinery, and (iii) lower average COP/USD exchange rate. Invercolsa’s sales increased as a result of the higher commercialization of natural gas volumes. Esenttia’s sales volume decreased 108 tons, due to a strategy based on pursuing sales with higher margins instead of pursuing the target volume, increasing year-on-year sales results and total margin of USD 85.9 per ton in 2023 to USD 177.6 per ton in 2024.
The cost of sales for our refined products and petrochemicals segment is mainly related to the purchase of crude oil and natural gas for our refineries, imported crude oil and products to supply local demand, feedstock transportation services, services contracted for maintenance of the refineries and the amortization and depreciation of refining assets.
The cost of sales amounted to COP 62,805 billion in 2025, compared to COP 67,718 billion in 2024 and COP 75,716 billion in 2023. In 2025, the cost of sales for this segment decreased by 7% as compared to 2024, mainly due to (i) lower crude oil raw material costs, (ii) greater savings associated with the cost optimization strategy, and (iii) lower crude oil purchases associated with inventory management at the refineries.
Cost of sales amounted to COP 67,718 billion in 2024, compared to COP 75,716 billion in 2023 and COP 80,332 billion in 2022. In 2024, the cost of sales for this segment decreased 10.6% as compared to 2023, mainly due to (i) lower crude feedstock cost, (ii) higher savings associated with the cost optimization strategy, and (iii) lower crude oil purchases associated with inventory management at the refineries.
In 2025, operating expenses, net of other income and before the impairment reversal of non-current assets increased by 13% as compared to 2024, mainly due to the update of provisions and higher taxes.
In 2024, operating expenses, net of other income and before the impairment reversal of non-current assets decreased by 2.6% as compared to 2023, mainly due to the incorporation of efficiencies and optimizations in administrative expenses.
For the year ended December 31, 2025, no gain or loss was recognized in the impairment for the refining segment, as the total impairment previously recorded was fully recovered during 2024. In 2025, higher refined product differentials and a lower discount rate improved the recoverable value of the refining and petrochemicals cash-generating units. Furthermore, a qualitative assessment of internal and external indicators of impairment was performed, and no requirement was identified to estimate the recoverable amount, as the main value drivers reflected a positive outlook for the segment.
In 2024, we recognized an impairment recovery of non-current assets in this segment totaling COP 1,266 billion, as compared to an impairment recovery of COP 1,482 billion in 2023. The recovery recorded in 2024 was generated primarily due to an impairment recovery in Cartagena Refinery due to (i) higher price differentials in middle distillates in the medium and long-term projection, (ii) prioritization of local crudes, and (iii) lower discount rate versus 2023, according to market conditions.
As mentioned earlier, the refining segment is highly sensitive to changes in product prices and feedstock in the international market, discount rate and refining margins, among others.
The refining and petrochemicals segment recorded net loss attributable to owners of Ecopetrol of COP 419 billion in 2025, compared to a net loss of COP 1,409 billion in 2024 and a net profit of COP 5,352 billion in 2023.
4.6.1.12
Energy Transmission and Toll Roads Concessions Segment Results
In 2025, the energy transmission and toll roads concessions segment sales from contracts with customers were COP 16,033 billion, which included COP 13,159 billion for electricity transmission, COP 2,358 billion for toll road concessions and COP 516 billion for telecommunication technologies and other operating sales.
In 2025, income increased mainly due to (i) progress in construction and commissioning of projects, (ii) positive effects from contractual price escalators, (iii) higher sales from remunerated maintenance and road concession’s returns, (iv) new telecommunications contracts, (v) the annual revenue cycle (Receita Anual Permitida – RAP) in Brazil, (vi) the impact positive of a judicial ruling in favor of ISA Energia Brasil related to the Paulista concession, which, in connection with the 2023 periodic tariff review process, affected the expected future cash flows of existing concession contracts, including adjustments to tariff-related revenues and the residual value of contractual assets. These increases were partially offset by the positive impact of the 2024 Periodic Tariff Review (RTP) and the negative effect in 2025 of the adjustment to the Existing System Basic Network (RBSE) in Brazil.
In 2024, the energy transmission and toll roads segment concessions sales from contracts with customers were COP 15,806 billion, which included COP 12,999 billion for electricity transmission, COP 2,352 billion for toll road concessions and COP 455 billion for telecommunication technologies and other operating sales.
In 2024, income increased mainly due to the energy business due to the one-off recognition of the Periodic Tariff Review (“RTP”) in Brazil. Additionally, new operative projects, the positive impact of contractual escalator clauses and the end of the provisions applied by the CREG associated with the voluntary decrease in fees, resuming the use of the PPI as a revenue escalator in Colombia. Likewise, the telecommunications business increased its sales mainly due to the “National Connectivity Plan” at Internexa Colombia.
In 2023, the energy transmission and toll roads concessions segment sales from contracts with customers were COP 14,168 billion, which included COP 10,941 billion for electricity transmission, COP 2,753 billion for toll road concessions and COP 475 billion for telecommunication technologies and other operating sales.
In 2023, income increased mainly due to the energy business with projects that began operations, the positive impact of contractual escalator clauses, and higher returns on contractual assets. Additionally, adjustments to construction margins, along with new energizing improvements and reinforcement in Brazil projects, contributed positively, and the end of the provisions applied by CREG associated with the voluntary decrease in fees, resuming the use of the PPI as a revenue escalator in Colombia. These effects were partially offset by (i) the sale decreases in the toll road business due to the financial impact in the valuation of financial assets in Chile changed from UF (Unidad de Fomento) to CLP (Chilean pesos) in 2022, along with the end of the Ruta del Bosque concession; and (ii) in the telecommunications business, due to lower customer acquisitions, disconnections, reduced capacities, and loss of internet service users in Brazil, Colombia, and Peru.
In 2025, the cost of sales amounted to COP 7,892 billion, compared to COP 6,952 billion for 2024. In 2025, the cost of sales for this segment increased by 13.5% compared to 2024, mainly due to inflationary pressures, higher construction activity, and entry into operation of new projects.
The operating costs for our energy transmission and toll roads concessions segment, which is mainly related to construction costs of concession contracts, operation and maintenance costs, amounted to COP 7,711 billion for 2025, compared to COP 6,769 billion for 2024.
In 2024, the cost of sales amounted to COP 6,952 billion, compared to COP 5,929 billion for 2023. These costs primarily encompass construction expenses associated with concession contracts, as well as operation and maintenance costs within our energy transmission and toll roads concessions segment.
The operating costs for our energy transmission and toll roads concessions segment, which is mainly related to construction costs of concession contracts, operation and maintenance costs, amounted to COP 6,769 billion for 2024, compared to COP 5,742 billion for 2023.
Administrative expenses amounted to COP 1,287 billion in 2025, compared to COP 1,151 billion for 2024. The administrative expenses include depreciation, personnel services, commissions, fees expenses and services.
The increase in cost of sales and administrative expenses is mainly due to higher impairment of receivables recorded in the energy transmission business in Colombia, primarily from customer Air-e, and the positive effect in 2024 from the update of the major maintenance provision in Peru’s energy transmission business. The change is also explained by the inflationary pressures, higher construction activity, and entry into operation of new projects.
The energy transmission and toll roads concessions segment and the companies of the Ecopetrol Group engaged in this segment continue to implement initiatives aimed at controlling these expenses by monitoring productivity indicators and designing a cost model based on the asset’s life cycle.
In 2025, the share of profit of associates and joint ventures was COP 494 billion, which corresponded to the participation in the results mainly of Transmissora Aliança de Energia Elétrica, Interligação Elétrica do Madeira and Interligação Elétrica Ivaí, energy transport companies in Brazil.
In 2024, the share of profit of associates and joint ventures caused a positive effect in our results of COP 540 billion, which corresponded to the participation in the results mainly of Transmissora Aliança de Energia Elétrica, Interligação Elétrica do Madeira and Interligação Elétrica Ivaí, energy transport companies in Brazil.
In 2023, the share of profit of associates and joint ventures caused a positive effect in our results of COP 530 billion, which corresponded to the participation in the results mainly of Transmissora Aliança de Energia Elétrica, Interligação Elétrica do Madeira and Interligação Elétrica Garanhuns, energy transport companies in Brazil.
In 2025, there was a net reversal of impairment losses of non-current assets amounting to COP 2 billion, which included a reversal of impairment loss on intangible assets in ISA Bolivia by COP 15 billion, as a result of the comprehensive strategy that improved the company’s expected future net cash flows. The change was partially offset by the recognition of impairment loss of non-current assets of COP 10 billion due to the cancellation of the project “Connection of the Colombia Pipeline to the ISA Caucasia 110 kV (CAUC) Substation.” Additionally, InterNexa Colombia recognized an impairment loss of submarine capacity rights of COP 3 billion as a consequence of price erosion in the market due to the substantial increase in supply, as well as an impairment loss on other non-current assets.
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The impairment of non-current assets recognized in the segment in 2024 was COP 45 billion. This impairment was primarily due to: (i) impairment of COP 27 billion in ISA Bolivia due to an increase in WACC from country risk and the effect of exchange rate differences on the dollar-denominated cash flow, (ii) impairment of COP 16 billion in Internexa Colombia due to in the right to submarine capacity, as a consequence of price erosion in the market due to the substantial increase in supply.
In 2023, we recognized an impairment loss of non-current assets in this segment totaling COP 209 billion mainly due to: (i) impairment of COP 85 billion in Consorcio Transmantaro due to a lower fair market value in Yaros project, (ii) impairment of COP 98 billion in Internexa Brazil, COP 11 billion in Internexa Colombia, and COP 15 billion in Internexa Argentina, considering the update of the business plan that reflected decrease in sales and operating margins to the South Cash Generating Unit.
The energy transmission and toll roads concessions segment recorded net profit attributable to owners of Ecopetrol of COP 451 billion in 2025, as compared to net profit attributable to owners of Ecopetrol of COP 966 billion in 2024 and COP 675 billion in 2023.
Liquidity and Capital Resources
Our principal sources of liquidity in 2025 were: (i) cash flows amounting to COP 33,342 billion from our operations, (ii) cash flows from investing activities mainly due to interest received amounting to COP 1,246 billion, (iii) cash flows proceeds from sale of financial assets amounting to COP 2,265 billion and (iv) cash flow from dividends amounting to COP 772 billion.
Our main uses of cash in 2025 were: (i) COP 22,308 billion in capital expenditures, which included investments in property, plant and equipment, natural and environmental resources and intangibles, (ii) dividend payments amounting to COP 11,717 billion, which included dividends of COP 8,784 billion to Ecopetrol’s shareholders, including minority shareholders, and dividends paid to the non-controlling shareholders of our subsidiaries totaling COP 2,933 billion, and (iii) COP 4,989 billion related to net effect of proceeds and payments of principal and payments of interest. For more information regarding our debt, see section Financial Review—Financial Indebtedness and Other Contractual Obligations.
4.7.1
Review of Cash Flows
Cash from operating activities
Net cash provided by operating activities decreased by 26.1% in 2025 when compared to 2024, mainly as a result of:
Cash used in investing activities
In 2025, net cash used in investing activities decreased by 18.7% as compared to 2024, mainly as a result of: (i) A COP 4,339 billion decrease in cash flow used, primarily due to net proceeds from the sale during 2025 of financial instruments received in the portfolio in 2024 as payment from the Nation under the FEPC and lower interest receive. This increase was partially offset by a COP 429 billion increase in capital expenditure.
In 2024, net cash used in investing activities increased by 10.1% as compared to 2023, mainly resulting from a 9.5% increase in capital expenditures due to: (i) development wells in Rubiales, Caño Sur, Castilla, Floreña, (ii) acquisition of CPO09, (iii) higher investment in Permian, (iv) investments focused on operational continuity in the transport and logistics and refining and petrochemicals segments, among others.
Cash used in financing activities
Net cash used in financing activities decreased by 23.5% in 2025, compared to 2024, from COP 22,687 billion used in financing activities in 2024 to COP 17,365 billion used in financing activities in 2025. The difference was mainly due to (i) a COP 1,540 billion decrease from borrowings, net of related repayments of principal and payments of interest, and (ii) a COP 3,848 billion decrease in dividend payments.
Net cash used in financing activities increased by 6,298% in 2024, as compared to 2023, from COP 355 billion used in financing activities in 2023 to COP 22,687 billion used in financing activities in 2024. The difference was mainly due to (i) a COP 12,324 billion increase from borrowings, net of related repayments of principal and payments of interest, as compared to 2023 due mainly to the devaluation of the Colombian peso against the dollar, and (ii) a COP 9,994 billion increase in dividend payments in 2024 as compared to 2023 is mainly explained by the partial offset of the 2023 payment to the majority shareholder against accounts receivable from the Nation under the Fuel Price Stabilization Fund (FEPC), which reduced the cash outflow during that year.
4.7.2
Capital Expenditures
Our consolidated capital expenditures in 2025, 2024, and 2023 were COP 20,827 billion, COP 22,917 billion, and COP 24,091 billion, respectively. On average over the past three years, these investments were distributed by business segment as follows: 77.3% for exploration and production, 8.7% for transport and logistics, 6.7% for refining and petrochemicals and 5.0% for energy transmission and toll roads concessions. Capital expenditures were directed primarily toward development wells in Rubiales, Caño Sur, Castilla, Floreña, and the Permian basin within the exploration and production segment; operational continuity initiatives within the transport and logistics and refining and petrochemicals segments; and the construction of power lines, and investments to increase grid reliability and comply with regulatory requirements within the energy transmission and toll roads concessions segment. See Note 33.3 to our consolidated financial statements for more detail about capital expenditures by segment.
The amount of our investment plan approved for 2026 is between COP 22 and 27 trillion. See section Strategy and Market Overview—Our Corporate Strategy—2026 Investment Plan for further information and implicit Brent prices.
The resources required for the investment plan can be funded through internal cash generation, collection of the accounts receivable from the FEPC and loans.
4.7.3
Dividends
In the General Assembly of Shareholders held on March 27, 2026, a distribution of ordinary dividends for the fiscal year ended December 31, 2025, was approved as follows: COP 4,975 billion, or COP 121 per share, based on the number of outstanding shares as of December 31, 2025. The total dividends approved correspond to an ordinary dividend pursuant to our current dividend policy. The payment is expected to be made no later than June 30, 2026 to all our shareholders, including the Nation, considering the payment schedule of the balance of the Fuel Price Stabilization Fund (FEPC) corresponding to its 2025 accumulation.
In 2025, we paid dividends of COP 8,784 billion to our shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP 2,934 billion. COP 7,786 billion in dividends corresponded to the Nation.
In 2024, we paid dividends of COP 12,803 billion to our shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP 2,762 billion. COP 7,352 billion in dividends corresponding to the Nation were offset against the FEPC accounts receivable owed to Ecopetrol.
In 2023, we paid dividends of COP 24,323 billion to our shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP 2,806 billion. COP 21,576 billion in dividends corresponding to the Nation were offset against the FEPC accounts receivable owed to Ecopetrol.
4.8
Summary of Differences between Internal Reporting Policies (Colombian IFRS) and IFRS
We prepare our interim and annual statutory financial information in accordance with our internal reporting policies, which follow Colombian IFRS and differ in certain significant aspects from IFRS. The following table sets forth our consolidated net profit and equity for years ended December 31, 2025, 2024 and 2023, in accordance with Colombian IFRS and IFRS:
Table 62 – Consolidated Net Profit and Equity
Net profit attributable to owners of Ecopetrol (IFRS)
Cash flow hedge for future company exports
(54)
Exchange rate effects on tax bases – Deferred tax
(1,459)
1,096
(1,941)
(233.1)
(156.5)
Insurance Contracts IFRS 17
50.0
Net profit Attributable to owners of Ecopetrol (Colombian IFRS)
9,029
14,935
19,062
(39.5)
(21.7)
Total Equity (IFRS)
106,739
105,913
100,252
0.7
5.6
2,507
4,063
2,845
(38.3)
42.8
Total Equity (Colombian IFRS)
109,246
109,976
103,099
(0.8)
As noted above, certain differences exist between our net profit and equity as determined in accordance with our internal reporting policies, which follow Colombian IFRS, which are used for management reporting purposes, as presented in the business segment information, and our net profit and equity as determined under IFRS, as presented in our consolidated financial statements.
The primary differences between Colombian IFRS and IFRS as they apply to our results of operations are summarized below:
Cash flow hedge for future company exports. In September 2015, to hedge the effect of exchange rate volatility on our foreign currency debt, Ecopetrol S.A.’s Board of Directors approved a cash flow hedge for future crude oil exports. According to IAS 39 – Financial Instruments, we implemented this hedge beginning on October 1, 2015, the date on which we formally completed the related hedging documentation.
Under Colombian IFRS, the General Accounting Office of the Nation (CGN for its acronym in Spanish) issued Resolution 509, which allows companies to apply hedge accounting for non-derivative financial instruments from any date within the transition period or the first period of application of International Accounting Standards in Colombia, even if such company has not yet formally documented the hedging relationship, the objective or the risk management strategy. Under these rules, we applied cash flow hedge accounting from January 1, 2015, in our financial statements under Colombian IFRS.
For the year ended December 31, 2025, there is no adjustment in the cash flow hedge for the Company’s future exports, considering that the hedging operation related to exports was fully settled during 2024.
Exchange rate effects on tax bases – Deferred tax. According to IAS 12.41, companies with a U.S. dollar functional currency and profit or tax loss in Colombian Pesos are required to recognize deferred taxes attributable to the difference between the carrying amounts of non-monetary assets in their financial statements and their respective tax bases converted from Colombian Pesos to U.S. dollars using the exchange rate on the closing date. The effect of the temporary difference is charged to profit and losses without a cash outflow expected in the future. Under local accounting principles (The General Accounting Office opinion No. 20162000000781 dated January 18, 2016), the result attributable to the aforementioned difference in accounting policies does not generate any deferred taxes.
Our functional currency is the Colombian Peso. We consolidate certain subsidiaries whose functional currency is the U.S. dollar; however, those subsidiaries settle their tax obligations in Colombian Pesos. As a result of the application of paragraph 41 – IAS 12, such subsidiaries are required to calculate deferred taxes under IFRS.
As a result of this accounting policy difference, for the year ended December 31, 2025, our net profit attributable to owners of Ecopetrol as reported under IFRS was COP 1,459 billion higher than our net profit attributable to owners of Ecopetrol as reported under Colombian IFRS.
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IFRS 17 – Insurance Contracts. In May 2017, the International Accounting Standards Board issued IFRS 17 which replaced IFRS 4 that was issued in 2005. IFRS 17 applies to all types of insurance and reinsurance contracts, regardless of the type of entities issuing them, as well as certain guarantees and financial instruments with discretionary participation features. The standard should be applied as of January 1, 2023. This standard applies specifically to our subsidiary Black Gold Re, domiciled in Bermuda. That entity provides, through a dual insurance program structure (World General Package (WUP) program and Global Energy Package (GEP) program), reinsurance to the Ecopetrol group. Since this standard has not been introduced in Colombian regulations by decree, the accounting policy based on IFRS 4 continues to be applied in the Financial Statements of the Business Group disclosed under the standards of the local accounting regulatory entities. As of December 31, 2025, this accounting policy difference did not result in any adjustment to our income attributable to owners of Ecopetrol as reported under IFRS compared to Colombian IFRS.
As a result of these accounting policy differences described above, for the year ended December 31, 2025, we reported net profit attributable to the owners of Ecopetrol under IFRS of COP 10,488 billion as opposed to a net income attributable to the owners of Ecopetrol of COP 9,029 billion reported under Colombian IFRS for the same period. For the year ended December 31, 2024, we reported net income attributable to the owners of Ecopetrol under IFRS of COP 13,841 billion as opposed to a net income attributable to the owners of Ecopetrol of COP 14,935 billion reported under Colombian IFRS for the same period. For the year ended December 31, 2023, we reported net income attributable to the owners of Ecopetrol under IFRS of COP 21,061 billion as opposed to a net income attributable to the owners of Ecopetrol of COP 19,062 billion reported under Colombian IFRS for the same period.
4.9
Financial Indebtedness and Other Contractual Obligations
As of December 31, 2025, we had outstanding consolidated indebtedness of COP 106,172 billion (USD 28.3 billion), which corresponded primarily to the following long-term transactions:
Table 63 – Consolidated Financial Indebtedness
Outstanding
Balance as of
Dec. 31, 2025
Company
Type
Initial Date
Original Amount
Maturity
Interest Rate
Amortization
(in nominal values)
Bonds
September 18, 2013
USD 850 million
September 18, 2043
7.375
Bullet
May 28, 2014
USD 2,000 million
May 28, 2045
5.875
April 29, 2020
April 29, 2030
6.875
October 27, 2021
USD 1,250 million
November 2, 2031
4.625
USD 750 million
November 2, 2051
January 13, 2023
USD 1,528 million
January 13, 2033
8.875
USD 472 million
July 6, 2023
USD 300 million
USD 1,200 million
January 19, 2029
8.625
January 19, 2024
USD 1,850 million
January 19, 2036
8.375
October 21, 2024
USD 1,750 million
February 1, 2032
7.750
August 27, 2013
COP 348 billion
August 27, 2028
Floating
COP 263 billion
August 27, 2043
December 1, 2010
COP 284 billion
December 1, 2040
Bank Loans
December 20, 2022
USD 576 million
December 20, 2027
Semi-annual
USD 247 million
May 16,2023
USD 250 million
February 27, 2031
USD 150 million
June 20, 2023
USD 124 million
USD 53 million
July 2, 2024
April 12, 2029
June 16, 2023
COP 693 billion
June 16, 2028
COP 1,000 billion
July 26,2024
COP 642 billion
July 26, 2029
COP 208 billion
COP 150 billion
May 7, 2025
USD 500 million
April 30, 2030
November 28, 2025
USD 281 million
November 25, 2030
USD 249 million
ECAs
December 30, 2011**
USD 2,650 million
Fixed
USD 179 million
USD 100 million
USD 7 million
USD 97 million
USD 210 million
USD 14 million
Invercolsa & Subsidiaries
COP 840 billion
COP 608 billion
Bond
July 14, 2020
July 14, 2027
4.000
USD 400 million
Lease
November 5, 2015
COP 308 billion
November 4, 2032
Monthly
COP 145 billion
ISA & Subsidiaries
USD 2,859 million
USD 2,697 million
USD 4,134 million†
USD 4,018 million
COP 3,604 billion
COP 3,354 billion
USD 372 million
USD 236 million
USD 759 million†
USD 394 million
COP 3,437 billion
COP 2,958 billion
Energuana
COP 288 billion
April 15, 2035
COP 286 billion
COP 106,172 billion
* Reopening of Notes due 2033
** Debt originally obtained by Cartagena Refinery for the refinery modernization and voluntarily assumed by Ecopetrol.
**** For the total outstanding balance as of Dec. 31, 2025, in amortized values, please refer to page F-73 of the notes to our financial statements.
† Equivalent USD amount of debt issued/acquired in other currencies, except COP.
The Financial Superintendence of Colombia (Superintendencia Financiera de Colombia or “SFC” for its acronym in Spanish), through Resolution 1654 of November 18, 2022, authorized the renewal of the term of the Issuance and Placement Program of Internal Debt Bonds and Commercial Papers of the Company for five (5) additional years, until December 22, 2027. This authorization itself does not constitute an approval for the issuance of securities or any financing transaction.
During 2025, the SFC, through Resolution 1139 dated June 11, 2025, authorized an amendment to the prospectus for the issuance and placement program (the “PEC” or the “Program”) of Ecopetrol’s local public bonds and commercial paper.
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This amendment, formalized through Addendum No. 5, was incorporated into the Program’s prospectus, and included the following key updates:
This amendment aligned the Program with Ecopetrol’s corporate strategy for decarbonization and energy transition, while also expanding the range of alternatives available in capital markets. Since the first bond issuance under the Program in August 2013, totaling COP 900 billion, no additional issuances have been made. As a result, Ecopetrol may still issue additional bonds and commercial papers for up to COP 2,100 billion. Ecopetrol will duly inform the market of any future issuances carried out under the Program.
The short and long-term debt transactions executed in 2025 were as follows:
For more details on these transactions, see Financial Statements - Note 20 Loans and borrowing.
The short and long-term debt transactions executed in 2024 were as follows:
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The short and long-term debt transactions executed in 2023 were as follows:
Contractual Obligations
We execute various commitments and contractual obligations that may require future cash payments. The following table summarizes our contractual obligations as of December 31, 2025.
Table 64 – Our Material Contractual Obligations
Payments due by period
Short Term
Long Term
(Less than 1
(More than 1
COP Billions
year)
Employee Benefit Plan
53,269
2,238
51,031
Contract Service Obligations
52,202
12,023
40,179
Natural Gas Supply Agreements
3,911
1,720
2,191
Purchase Obligations
4,694
1,669
3,025
Energy Supply Agreements
12,458
183
12,275
21,531
12,282
9,249
Financial Sector Debt*
16,793
3,563
13,230
Bonds*
55,919
3,865
52,054
220,777
37,543
183,234
* Financial sector debt and bonds include principal plus interest (recognized at its amortized cost)
4.10
Off Balance Sheet Arrangements
As of December 31, 2025, we did not have off-balance sheet arrangements of the type that is required to be disclosed under Item 5 of Form 20-F.
4.11
Statements of Financial Position
Table 65 - Consolidated Balance Sheet
As of December 31,
(COP million)
Total assets
282,220
298,241
280,141
5.4
6.5
Liabilities
175,481
192,328
179,889
8.8
6.9
Equity
0.8
Total liabilities and equity
In 2025, assets decreased by 5.4% or COP 16,021 billion compared year-on-year, mainly due to:
In 2025, liabilities decreased by 8.8% or COP 16,847 billion compared to 2024, mainly due to:
In 2024, assets increased by 6.5% or COP 18,100 billion compared year-on-year, mainly due to:
In 2024, liabilities increased by 6.9% or COP 12,439 billion compared to 2023, mainly due to:
Total equity of the Ecopetrol Group for year-end 2025 was COP 106,739 billion. Equity attributable to Ecopetrol’s shareholders was COP 81,383 billion, an increase of COP 1,528 billion compared to December 2024, mainly as a result of the profits of the period, partially offset by distribution of dividends for the period and the effect of the exchange rate on subsidiaries with a functional currency other than the Colombian Peso.
In 2024, total equity of the Ecopetrol Group as of December 2024 was COP 105,913 billion. Equity attributable to Ecopetrol’s shareholders was COP 79,855 billion, an increase of COP 4,148 billion compared to December 2023, mainly as a result of net income for the period, partially offset by the distribution of dividends for the period and the effect of the exchange rate on subsidiaries with a functional currency other than the Colombian Peso.
4.12
Trend Analysis and Sensitivity Analysis
We updated our 2026 Investment Plan on November 27, 2025. See section Strategy and Market Overview—Our Corporate Strategy—2026 Investment Plan for a discussion of the trends recognized in the development of that plan.
Sensitivity Analysis
Sensitivity Analysis of our Results
The following table provides information about the sensitivity of our results as of December 31, 2025, due to variations of USD 1 in the price of ICE Brent crude and of 1% in the COP / USD exchange rate.
Table 66 – Sensitivity Analysis of our Results
Income
Difference
Summarized
Statement
Between
Case ICE
Real 2025
Case
Brent(1) +
and Case
TRM(2)
COP Billion
USD1
ICE Brent
+1%
TRM
121,005
1,310
120,698
1,004
Cost of sales
82,585
529
82,436
38,420
781
38,262
624
Administrative, operations and projects expenses, net
0.00
Operating income
27,461
27,303
Share of profit of associates and joint ventures
19,644
19,486
Income Tax Expense
(4,611)
(183)
(4,574)
(147)
Net Profit for the year
15,032
598
14,911
ICE Brent = USD 68 per barrel
Exchange rate (TRM) = COP 4.053 / USD 1.00
Assumptions for the Sensitivity Analysis of our Results:
The table below sets forth the line items that are being affected by the variation on the reference prices or the average exchange rate.
Table 67
VARIATION ON ICE BRENT REFERENCE PRICE
VARIATION ON AVERAGE EXCHANGE RATE
SALES
Sales of crude oil
Sales of refined products
Sales of natural gas
COST OF SALES
Local purchases from business partners
Local purchases of hydrocarbons from the ANH
Local purchases of natural gas
Imports of products
5.
Risk Review
5.1
Risk Factor Summary
The following is a summary of the principal risks we face:
Risks Related to Our Business
Risks Related to Colombia’s and the Region’s Political Environment
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Legal and Regulatory Risks
Risks Related to Our ADSs
44.Holders of our ADSs may encounter difficulties in protecting their interests.
Risks Related to the Controlling Shareholder
5.2
Risk Factors
The risks discussed below could have a material adverse effect, separately or in combination, on our business’s operating results, cash flows, liquidity, and financial condition. Investors should carefully consider these risks.
5.2.1
This section describes the most significant potential risks to our business.
Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time.
Reserves estimates are prepared using generally accepted geological and engineering evaluation methods and procedures. Estimates are based on geological, topographical, and engineering facts. Actual reserves and production may vary materially from estimates shown in this annual report, and downward revisions in our reserve estimates could lead to lower future production which could affect our results of operations and financial condition.
Hydrocarbon reserves presented in this annual report were calculated in accordance with SEC regulations. As required by those regulations, reserves were valued based on the unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2025, 2024, and 2023, as well as other conditions in existence at those dates. The average of closing prices of ICE Brent crude oil for the first day of each month in the 12-month periods was USD 83/Bl in 2023, USD 79.7/Bl in 2024, and USD 68.64/Bl in 2025. In 2025, the Company recognized an increase in oil and gas proven reserves of 2.7% as compared to 2024, to 1,944 mmboe in 2025 from 1,892.7 mmboe in 2024. For more information, see section Business Overview—Exploration and Production—Reserves.
Furthermore, at least once a year, or more frequently if the circumstances require, the Company ascertains whether there are indicators of impairment to its assets or CGUs due to the difference between the carrying amount of such assets or CGUs against to their recoverable amounts, using reasonable assumptions, based on internal and external factors, which reflect market conditions. The recoverable amount is considered to be the higher of the fair value less costs of disposal and value in use, based on the free cash flow method, discounted at the Weighted Average Cost of Capital (WACC). Whenever the recoverable amount of an asset or CGU is lower than its net carrying amount, such amount is reduced to its recovery amount, recognizing a loss for impairment as an expense in the consolidated statement of profit or loss. External and internal sources of information may indicate that an impairment loss recognized for an asset, other than goodwill, may no longer exist or may have decreased, in this case, the reversal is recognized as an impairment recovery in the consolidated statement of profit or loss.
The 2025 impairment gains, net of non-current assets of COP 22,000 million, correspond to the net result of:
Any significant change in estimates, including capital expenditures reductions related to exploration and production projects, and judgments could have a material effect on the quantity and present value of our proved reserves and subsequently on the recognition or recovery of impairment charges. Changes to estimations of reserves are applied prospectively to the amounts of depreciation, depletion and amortization charged and, consequently, the carrying amounts of exploration and production assets.
On the contrary, any upward revision in our estimated quantities of proved reserves would indicate higher future production volumes, which could result in lower expenses for depreciation, depletion, and amortization for properties to which we apply the units of production method for calculating these expenses. These lower expenses, and any higher revenues as a result of actual production volumes and realized prices, could benefit our results of operations and financial conditions.
Achieving our long-term growth depends on our ability to execute our strategy, our capacity to adapt our business to the transition to a low-carbon economy, generate value by managing sustainability-related risks and opportunities, as well as on having cutting-edge knowledge and technologies and our ability to successfully diversify our portfolio and develop additional hydrocarbon reserves.
Our long-term growth objectives depend largely on our ability to strengthen the competitiveness of our oil and gas business, diversify our portfolio into energy transition businesses, and achieve decarbonization targets. Our 2040 Strategy, “Energy that Transforms” aims to position the Ecopetrol Group as a leading integrated energy group in the Americas, focusing on energy diversification. This strategy seeks to bolster the company’s oil and gas business, while decarbonizing its processes through technological advancements. Additionally, our growth relies on developing the recovery potential of existing fields and discovering or acquiring new reserves. We strongly believe that successfully developing these reserves is key for contributing to energy security and achieving our long-term ambitions.
Our exploration activities expose us to inherent geological and drilling risks including the possibility of not discovering commercially viable crude oil or natural gas reserves. There is also the risk that some initially budgeted exploratory wells may be drilled later than planned or not drilled at all. Despite our efforts to control drilling costs, these expenses are often uncertain, and numerous factors beyond our control can cause drilling operations to be curtailed, delayed, or cancelled.
Our ability to add and develop reserves also depends on our capacity to structurally reduce costs to maintain the profitability of oil fields already being exploited without compromising infrastructure integrity and HSE performance. See section Strategy and Market Overview——Our Corporate Strategy—2026 Investment Plan and section Strategy and Market Overview—Our Corporate Strategy—2040 Strategy: Energy That Transforms. If we are unable to maintain the competitiveness of our oil and gas business and achieve expected recovery factors in our existing fields, add projects with proven reserves, successfully develop our current projects, acquire new exploration assets, or successfully execute our exploration plans (whether as a result of the impossibility of obtaining or extending exploratory licenses, capital restrictions, or any other limitation), our ability to discover and develop additional reserves may be affected and our reserves portfolio could be expected to decline. Failure to secure additional reserves may impede us from achieving or maintaining production targets and may have a negative impact on our results of operations and financial condition. In addition, changes in the operation and development costs of the projects could impact the reserves.
We face the challenge of ensuring our assets generate value across the oil and gas segments. We assess their financial attractiveness and strategic relevance using an index methodology that considers two key elements: financial attractiveness (contribution to profitability, payback period of investments, and viability in the short, medium, and long term) and strategic relevance (synergies and complement to the hydrocarbon chain, resilience in different energy transition scenarios, and contribution to the decarbonization of the Ecopetrol Group).
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Regarding our energy transmission business line, we face risks associated with energy transition. To achieve our energy transition objectives, we have developed the “Grid of the Future” vision with three main priorities: adaptation of the existing grid and better utilizing available capacity; connecting renewable energy sources to transmission networks; and developing interconnections that enable regional electrical integration. This vision faces long-term risks associated with changes in remuneration schemes and political instability in the region. Additionally, greater social and environmental requirements for business development may impose more restrictions on our operations and growth expectations. Market and competition risks in our energy transmission and toll roads concessions businesses may result in new projects not being awarded, affecting our medium-term growth.
In terms of energy transition, we face the risk of not successfully incorporating alternative options into our portfolio as traditional businesses or segments lose their capacity to maintain value due to changes in global or local energy consumption patterns. Specifically, we face risks related to our ability to implement measures to reduce and offset carbon and methane emissions and adapt to climate variability and climate change. We also face regulatory risks related to new climate change regulations in Colombia, such as the updated NDC, the oil & gas industry’s climate change management plan, the Mandatory GHG Emissions Reporting (ROE, for its acronym in Spanish) and the implementation of the National Program of Tradable GHG Emissions Quotas (PNCTE, for its acronym in Spanish). Other regulatory risks include the incorporation of new low-carbon businesses within our portfolio, due to insufficient regulation that may impact their proper development.
Ecopetrol has developed energy transition scenarios, which consider global and Latin American perspectives and integrate information from multiple international agencies. These scenarios reflect equilibrium perspectives and a gradual transition in which different energy sources are complementary, while also capturing recent developments and short-term projected changes in the energy market based on current geopolitical conditions, which aims to provide a solid and unified reference framework that is expected to allow the Ecopetrol Group to anticipate and understand the challenges and opportunities of the energy transition by presenting three scenarios: (i) Climate Alignment (1.7° - 1.8°C): Transformation to low-emission economies aligns governments and institutions around climate change. In addition, developed countries reach a net zero goal, while other countries follow a slower path. This is not enough to achieve the global net-zero goal of 1.5 ℃; (ii) Energy Balance (1.9° - 2.3°C): Fundamental changes in governments, markets, and society set in motion a long-term energy transition, the debate continues between energy security and accelerating the transition; and (iii) Climate Divergence (2.5° - 2.8°C): Dissimilar interests in decarbonization despite policy, regulation and market changes. Global public policy decisions are insufficient to close the climate ambition gap. While the first and third scenarios do not represent the group’s core vision, assessing different perspectives on the global energy transition remains necessary. According to the 2040 Strategy, Ecopetrol considers the second scenario the most likely, aligning with a gradual energy transition. However, we are not certain about the alignment between strategic decision making, considering the analysis derived from the use of these scenarios.
These changes could lead to increased costs and investments in the short and medium term. We have already incurred costs related to these regulations and it is expected that to comply with this evolving regulatory framework we may have additional costs and investments in the short term. This could impact the achievement of the Company’s growth targets and its resilience. See section Risk Review—Risk Factors—Legal and Regulatory Risks—Our operations might be affected by rising climate change and energy transition regulatory developments. Our business growth and sustainability depend on our ability to manage our capital investments and operate efficiently, in accordance with our corporate strategy guidelines. See section Strategy and Market Overview—Our Corporate Strategy for a discussion of our strategic plan.
Ecopetrol is expanding into low-emission energy-diversification businesses as part of its Corporate Strategy, following a gradual transition approach aligned with the conditions of the regions where it operates. Fossil fuels are expected to continue supporting energy security and system reliability, particularly in developing economies. Ecopetrol does not view the transition as a competition between energy sources, but rather as a process of complementarity. Investments in low-emission energy are intended to support the Company’s decarbonization goals and long-term value creation. However, their success depends on the development of cost-competitive technologies, appropriate regulatory frameworks, and sufficient energy demand. There is no assurance that these conditions will materialize as expected, which could affect the performance and implementation of these initiatives.
Furthermore, we are subject to physical risks related to climate change. We are exposed to Colombia’s current climate conditions which may affect water availability and increase the vulnerability of our assets and operations to potential damages. These conditions could result in water shortages, floods, fires, storms, hurricanes, and rising sea levels that change in frequency and intensity. Extreme weather events could damage our assets and negatively affect our operations and financial condition. Additionally, the exposure of our assets under the three climate scenarios presented by the Intergovernmental Panel on Climate Change (SSP 1- RCP 2.6°C, SSP 2- RCP 4.5, and SSP 5- RCP 8.5) could result in potential damage to our assets or cause business disruptions such as water availability, limited transportation and access, and workforce disruptions.
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Sharp movements of prices for crude oil, natural gas and refined products could adversely affect our business prospects, results and cash position.
In 2025, approximately 83% of the revenues came from sales of crude oil, natural gas, and refined products and 96% of the total volume sold of these products was indexed to international reference prices or benchmarks such as ICE Brent. Consequently, fluctuations in those international indexes have a direct effect on our financial condition and results of operations.
Prices of crude oil, natural gas and refined products have traditionally fluctuated as a result of various factors including, among others, competition within the international oil and natural gas industry, long-term changes in the demand for crude oil, natural gas and refined products, notably associated to the transition to a low carbon economy, the economic policies in the United States, China, India and the European Union, regulatory changes, changes in global supply, inventory levels, changes in the cost of capital, adverse or favorable economic conditions, global financial crises, substitute sources of energy, development of new technologies, global and regional economic and political developments in the OPEC+, the willingness and ability of the OPEC+ and its members to set production levels, local and global demand and supply for crude oil, refined products and natural gas, trading activity in oil and natural gas; weather conditions, natural events or disasters, which are changing in intensity and frequency due to climate change, and terrorism and global conflict. Disagreements among OPEC+ members on production levels, changes in the trade policies from the US administration, uncertainty surrounding Venezuela, the continued conflict between Russia and Ukraine and the escalation of conflicts in the Middle East, including the Israel-Hamas conflict, and most recently, the escalation of the conflict between the U.S. and Israel on one side and Iran on the other, could impact international reference prices.
On January 3, 2026, the United States carried out a military operation in Venezuela that resulted in the capture of President Nicolás Maduro. While these events mark a significant geopolitical escalation, their implications for Venezuelan oil supply, sanctions policy, and global crude balances are still unclear and will depend on the duration of the transition process and the stance adopted by U.S. authorities toward Venezuelan exports. Although Venezuela currently accounts for only around 1% of global crude oil production (approximately 850 mbd), it represents close to 5% of global supply of heavy and extra-heavy crude oils (approximately 400 mbd) and holds the largest volume of proved oil reserves worldwide, estimated at nearly 300 billion barrels. This segment is particularly relevant for certain refining complexes in the United States and Asia that are configured to process heavier crude slates. In the short term, heightened institutional, operational and logistical uncertainty may lead to partial disruptions to production and export flows, which could support a premium in heavy crude markets. Such a premium could gradually dissipate as geopolitical uncertainty surrounding Venezuela declines; however, the timing and magnitude of any normalization remain uncertain. A material recovery in Venezuelan crude oil production is not expected during 2026, given the extent of accumulated operational deterioration, ongoing technical constraints, and the need to restructure contractual arrangements, regulatory frameworks and investment schemes. Notwithstanding the above, flows of heavy crude to the U.S. Gulf Coast could increase on average by approximately 200 to 300 mbd over the year, primarily reflecting trade re-routing from flows previously directed to China. Under these conditions, Venezuelan crude oil production is expected to remain broadly in line with current levels, with relatively stable flows but limited capacity for meaningful growth in the near term.
The Russia-Ukraine conflict has also increased volatility in the oil and refining business. Although the conflict has generally had a positive effect on crude oil prices and refining margins globally, the global economy has been adversely affected, which could lead to a rapid price correction in the future. Additionally, in the medium term, it could create incentives to accelerate decarbonization strategies, especially in Europe given its intention to cut hydrocarbon imports from Russia, thus potentially leading to a deterioration of the outlook for oil demand.
Year to date, oil markets have remained sensitive to geopolitical risk stemming from ongoing tensions in the Middle East, which have continued to generate price volatility due to concerns over potential supply disruptions in a region that produces roughly one-third of global crude. Market uncertainty fluctuated as perceptions of a potential U.S.–Iran confrontation evolved, and these concerns escalated sharply on February 28, 2026, when the United States and Israel launched coordinated attacks on Iran under Operation Epic Fury, resulting in the killing of Iran’s Supreme Leader Ayatollah Ali Khamenei and other senior officials as part of an effort to eliminate nuclear and ballistic missile capabilities. Following the strikes, oil and gas tankers began avoiding the Strait of Hormuz, a corridor that normally handles about 20 million barrels per day of crude and refined products—one in every five barrels traded globally—and for which no alternative routes of comparable scale exist, as overland options can divert only about 4.5 million barrels per day, leaving over 80% of flows exposed to its operability. Maritime traffic dropped from 90 vessels to nine within 48 hours, and by March 4, 2026 large-tanker transit had effectively ceased, contributing to indirect production losses of roughly 3.5 million barrels per day.
The disruption also affects approximately 5.5 million barrels per day of refined products, including nearly 33% of seaborne naphtha outside the Gulf, 23% of LPG, 16% of global jet fuel, and 1.3 million barrels per day of diesel destined primarily for Africa and Europe—factors that contributed to diesel margins on the U.S. Gulf Coast increasing from USD 26 to nearly USD 50 per barrel within weeks, while floating storage has increased and freight rates for crude tankers have risen, reflecting precautionary disruptions in regional flows. Iran has emerged as the sole Middle Eastern producer maintaining exports through the Strait of Hormuz during its conflict. Platts data show that Iranian exports reached 2.26 million barrels per day in February and 1.50 million barrels per day in March, compared with a 2025 average of 1.68 million barrels per day. Nevertheless, forward-looking production scenarios for the region and their implications for global balances remain uncertain, and the overall evolution and impact of the conflict continue to depend on the outcome of ongoing diplomatic contacts between the United States, Israel, and Iran.
During 2025, our crude oil basket average price was USD 63.6/Bl versus USD 73.3/Bl in 2024, the refined product basket average price was USD 81.6/Bl versus USD 86.8/Bl in 2024; and the natural gas average price was USD 28.6 per barrel equivalent in 2025 versus USD 27.8 per barrel equivalent in 2024.
Moreover, our prices are indexed to international benchmarks such as the Brent and light distillates in the Gulf of Mexico (aka Gulf of America), therefore our revenues are affected by the fluctuation of those prices. The difference between the producer revenue and the international parity price recognized by the government to Ecopetrol S.A. for diesel and gasoline can fluctuate significantly due to: (i) volatility in international oil prices, (ii) the methodology to determine the reference price of gasoline and diesel, and (iii) the sensitivity of retail price to monthly variations. As a result, these differences generate account receivables or account payables for Ecopetrol to or from the Fuel Prices Stabilization Fund (FEPC). A significant and permanent increase in the prices of gasoline and diesel in international markets, as compared to the regulated price in Colombia, can substantially increase the size of the receivable account corresponding to the FEPC. As a result, this increase could impact Ecopetrol’s working capital, solvency and liquidity metrics in absolute terms as well as relative to its industry peers; consequently, the Company might not be able to reduce its financial leverage, or capture value through cash flow derived from oil prices which are relatively higher than those budgeted internally. The easing of the account receivable problem is conditioned on the willingness of the Colombian Government and availability of sources to make direct payments and/or the ability to make quick and significant increases in the regulated price in Colombia. As settlement and payments dates are not regulated, the Ecopetrol Group’s cash flow could be affected, increasing its financial cost of debt, challenging the ability to execute the investment plan and the capacity to pay dividends. While producer’s rights are protected by law, we cannot provide any certainty as to when we would receive such payments.
Additionally, the rating agencies’ perception associated with the accumulation of FEPC balances, as a stand-alone credit baseline (without assuming the support of the National Government), represents a credit risk. The following metrics of Ecopetrol’s rating could be reassessed at any time given a perception of higher liquidity/cash risk: (i) liquidity and hedging metrics due to lower cash availability; (ii) indebtedness metrics in case of additional borrowing, resulting in financial ratios different from those forecasted in Ecopetrol’s financial plans; (iii) Ecopetrol’s relative situation compared to peer companies at the same rating level; and (iv) Ecopetrol’s rating in the event of a possible adjustment in the sovereign’s rating, based on the rating agencies’ perception of the impact of the FEPC on public finances. As of December 31, 2025, Ecopetrol S.A. recorded COP 2.4 trillion (USD 647 billion) in accounts receivable due from FEPC and Cartagena Refinery recorded COP 0.6 trillion (USD 159 billion) in accounts receivable due from FEPC. For further information see section Business Overview—Applicable Laws and Regulations—Regulation Concerning Production and Prices—Fuel Price Stabilization Fund (FEPC).
A reduction of international crude oil prices could also result in a delay or a change in our capital expenditure plan, in particular delaying exploration and development activities, thereby delaying the development of reserves and affecting future cash flows. To maintain a profitable operation and preserve the cash flow of the Company at certain oil price levels, some of our producing fields may have to be closed or their operations temporarily suspended, which would affect our production levels and expected revenues.
Foreign currency exchange rate fluctuations may affect our financial results.
Most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars and other currencies such as Brazilian real (BRL), the Peruvian Sol (PEN) and the Chilean peso (CLP). Therefore, when the Colombian Peso depreciates against the U.S. dollar, our revenues converted into Colombian Pesos, increase. Conversely, when the Colombian Peso appreciates against the U.S. dollar, our revenues decrease.
On the other hand, imported goods, oil services and the debt, which is mainly denominated in U.S. dollars, become less expensive when the Colombian Peso appreciates against the U.S. dollar and more expensive when the Colombian Peso depreciates against the U.S. dollar.
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As of December 31, 2025, our U.S. dollar-denominated total debt aggregate principal amount was USD 21.1 billion; recognized in our consolidated financial statements at its amortized cost, which corresponds to the present value of cash flows discounted by an annual effective interest rate. Out of this total, a principal of USD 17.8 billion corresponds to Ecopetrol S.A., whose functional currency is the Colombian Peso. Therefore, when the Colombian Peso depreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate loss. In contrast, when the Colombian Peso appreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate gain. Some of the Ecopetrol Group’s affiliates have the U.S. dollar as functional currency and are not exposed to a material exchange rate risk resulting from fluctuations in the Colombian Peso against the U.S. dollar. On the asset side, when the financial statements of the Ecopetrol Group are consolidated, the exchange rate differential of the affiliates’ assets and liabilities whose functional currency is the U.S. dollar is recognized directly in the equity, as part of other comprehensive income.
The U.S. dollar/Colombian Peso exchange rate has fluctuated during the last several years. On average, the Colombian Peso appreciated 0.46% in 2025, appreciated 5.87% in 2024, and depreciated 1.64% in 2023. Additionally, as of December 31, 2025, the Colombia Peso had appreciated 14.79%; as of December 31, 2024, the Colombian Peso had depreciated 15.36%; and as of December 31, 2023, the Colombian Peso had appreciated 20.54%; in each case in relation to the year-end exchange rate for the immediately preceding year. In addition, given the possible effects of rising inflation, increasing interest rates in the U.S. and Colombia, different global growth perspectives, political tensions in the world’s largest economies, geopolitical conflicts, current and expected crude oil prices in the next few years and political uncertainty in Colombia, there is no clear view of how the U.S. dollar and the Colombian peso will behave in the medium to long-term. Continued market volatility is expected to lead U.S. dollar fluctuations that remain difficult to forecast.
A continued depreciation trend in the exchange rate of the Colombian Peso against the U.S. dollar may affect our financial results when converted into Colombian Pesos, given our current net position in U.S. dollars, the fact that most of our revenues are collected in U.S. dollars and the portion of our U.S. dollar debt that is not designated as hedge instrument, and the future debt we may acquire whenever translation affects the debt balance. Please see our sensitivity analysis on our results of operation to exchange rate fluctuations in the section Financial Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results—Exchange Rate Variation and in Note 30.1 to our consolidated financial statements.
Increased competition from local and foreign oil companies may have a negative impact on our ability to gain access to additional crude oil and natural gas reserves in Colombia and abroad.
Access to new reserves is focused on the existing areas under production or exploration contracts. The access to new areas depends on available opportunities in the market and their potential. The financial resources available for this purpose is a key factor that can impede the inorganic growth of reserves in Colombia and abroad.
We are also exposed to international competition because of our international exploratory and production activities. Currently, we are conducting exploration and development activities in Brazil and exploration and production operations in the United States, where we partner and compete with other oil and gas companies operating in those locations. If we are unable to adequately compete with local and foreign oil and gas companies, or if we cannot enter into agreements with market players having high potential exploration and production projects, our exploration and production activities may be limited. This could reduce our market share and our reserves to production ratio and adversely affect our financial condition.
Operational risks may materialize and affect the health and safety of our workforce, the local and ethnic communities and the environment, and cause disruptions, delays or shutdowns of our operations.
Our hydrocarbon, energy transmission and toll roads concessions businesses and energy transition businesses in Colombia and in the foreign countries in which we operate are exposed to operational incidents and external events that could harm the health and safety of our workforce, local and ethnic communities and the environment, and could disrupt our operations. These risks may be triggered by adverse or abnormal weather conditions and other events with natural causes, including climate variability and climate change impacts, as well as accidental incidents such as spills, leaks, fires or explosions. Failures of facilities and infrastructure, and shortages or delays in critical equipment and services may also affect execution and continuity of operations.
In addition, our operations may be curtailed, delayed or interrupted by social, regulatory and security-related factors beyond our control, including labor strikes, public protests, civil disturbances, road or infrastructure blockades, delays or cancellation of environmental licenses or other governmental authorizations, as well as adverse judicial decisions which are critical conditions for the execution and continuity of our activities. Such events may arise from opposition by local or ethnic communities or disagreements related to public policies or regulatory decisions affecting our activities.
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We also face security incidents, including sabotage, theft or attacks against our facilities and infrastructure by non-State armed groups (NSAGs) or other illegal actors. Certain activities take place in remote or uninhabited areas, which may increase exposure to these events and complicate response and logistics.
We may be required to incur in additional costs and expenses to allocate funds to industrial safety and health compliance under Colombian law and international industrial safety regulations. Additionally, if any operational incident occurs that affects local communities and/or ethnic communities in nearby areas, we will need to incur additional costs and expenses to return affected areas to normality and to compensate for any damages we may cause. These additional costs may have a negative impact on the profitability of current operations and the projects we may decide to undertake. See Our Business – Production Activities – Unconventional Hydrocarbons for a summary of community issues related to the PPIIs.
Any such occurrence could result in damage to property and infrastructure, clean-up and remediation responsibilities, third-party liability claims, government investigations, imposition of fines, and withdrawal of environmental licenses. These impacts could reduce our revenues and lead to the suspension or shutdown of operations. Any of these outcomes could adversely affect our financial condition and results of operations.
Our involvement in deep-water drilling either as direct operator or in conjunction with our business partners involves risks and costs, which may be out of our control.
Deep-water drilling activities present a variety of inherent operational risks with the potential for severe consequences, including loss of primary containment, blow out, ignition, fire and explosions, marine collision, weather, platform instability and natural disasters.
The occurrence of any of these unwanted events or other incidents could result in personal injuries, loss of life, severe environmental damage, property damage, clean-up and repair expenses, equipment damage, liability in civil and administrative proceedings, and even more stringent government regulation for deep-water operations. This could lead to increased costs and longer timeframes for our deep-water drilling operations and consequently, heightened risks and costs associated with deep-water drilling.
These factors may have a negative effect on our results of operations and financial condition and in our reputation. See section Business Overview—Exploration and Production for a summary of our current deep-water drilling activities.
We are exposed to the credit, political and regulatory risks of our key customers.
Some of our customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, many of our customers finance their activities through their cash flows from operations, short- and long-term debt or equity.
The combination of decreasing cash flows as a result of declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities, government sanctions which may include monetary penalties, executive orders and/or trade restrictions, and the lack of availability of debt or equity may result in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform their obligations to us according to their contractual terms.
Furthermore, some of our customers may be highly leveraged and subject to their own operating expenses. Therefore, the risk we face in doing business with these customers may increase. Other customers may also be subject to regulatory changes, which could increase the risk of defaulting on their obligations to us. We also could have disagreements with customers regarding tariffs, excusable events, or other aspects of our commercial relations that could lead to contract breaches by our clients. See Note 30.7 to our consolidated financial statements for more details.
Such financial problems experienced by our customers or deterioration in our relations with our customers could result in the impairment of our assets, a decrease in our operating cash flows and may also reduce or restrict our customers’ future use of our products and services, which may have an adverse effect on our revenues and our ability to make payments under our existing debt obligations.
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Our ability to access credit markets may be limited by the deterioration of these markets, changes in credit ratings, and limited offering from financial institutions to participants in the oil and gas industry.
Our and our subsidiaries’ ability to access international and local capital markets and finance our operations and potentially refinance our debt maturities on terms acceptable to us could be adversely affected due to the volatility in prices in the oil and gas sector, the continued military conflict between Ukraine and Russia, the disruptions on Russia’s energy exports as a result of sanctions, conflicts in the Middle East, including the most recent escalation of conflicts in Iran and regionally, and their impact on global supply chains, the global economy impacts due to energy supply shocks, the potential impacts on demand of future pandemics or epidemics, the spread of protectionist policies in the United States, global geopolitical risks associated with unexpected shifts in trade policies, including tariff announcement imposed by trading partners, the lack of consensus among OPEC+ members, the political uncertainty in Latin America (including Venezuela) and other parts of the developed world, the awareness of corruption by governments and private companies in emerging markets, which in turn could worsen risk perception with respect to the emerging markets, or the occurrence of any of the risks described in the section Risk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Environment. These conditions, along with the possibility of systemic banking crises, significant write-offs in the financial services sector and the re-pricing of credit risk, can make it difficult for us to obtain funding for our capital needs on favorable terms. Our cost and ability to obtain capital might be affected as well if our creditors and potential investors believe that we are not actively responding to the new low carbon economy, integrating TESG considerations in our operation and management, addressing risks related to climate change and energy transition, and meeting TESG targets; considering further the evolving restrictions to invest in pure fossil fuels companies announced by certain investors worldwide.
Access to credit and capital markets depends on a number of factors, many of which we cannot control, including changes in: our credit ratings because of external factors, interest rates, the structured and commercial financial markets, tax rates due to new or changes to existing tax laws, foreign exchange and investment controls and restrictions, market perceptions of the industries in which we operate, which are mainly determined by our financial and operational strength, and the support that could be provided by the Colombian Government as well as the sovereign credit rating. We cannot assure that our credit ratings will continue for any given period or that the ratings will not be further lowered or withdrawn. An assigned rating may be raised or lowered depending, among other things, on the respective rating agency’s assessment of our financial strength. In addition, a downgrade in the rating of the Republic of Colombia could also trigger a downgrade on ours, as it is capped by the rating of the Republic of Colombia and the implicit support that can potentially be provided to the Company. Our credit ratings have been subject to multiple reviews since 2023. Moody’s initially rated us at Baa3 with a negative outlook and a Baseline Credit Assessment (BCA) of ba3 in 2023, but has since downgraded our rating to Ba2 with a negative outlook and a BCA of b1. Similarly, Fitch Ratings, which had reaffirmed a BB+ rating with a stable outlook in both 2023 and 2024, modified Ecopetrol’s rating to BB with a revised outlook on December 22, 2025. Most recently, on April 8, 2026, S&P Global Ratings revised Ecopetrol’s global credit rating from BB+ to BB- with a stable outlook, in line with Colombia’s sovereign rating adjustment, while affirming Ecopetrol’s Stand-Alone Credit Profile at bb+.
As a result of these factors, we may be forced to revise the timing and scope of our capital projects as necessary to adapt to existing market and economic conditions, downgrades to our credit ratings or to access the financial markets on terms less favorable, therefore negatively affecting our results of operations and financial condition.
With respect to our renewable energy and low carbon emission project portfolio, we cannot assure that the projects will be able to raise financing on the terms expected or required to develop such portfolio.
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In addition, under applicable regulation, most of our indebtedness must be previously authorized by the Colombian Ministry of Finance and Public Credit and the National Planning Department and local bond issuances by the Financial Superintendence of Colombia. Likewise, our equity offerings must comply with the terms set forth in Law 1118 of 2006 and any operation within the domestic equity capital market must be previously approved by the Financial Superintendence of Colombia. As such, our access to debt and equity funding is subject to the Government’s time frames and policies, and we cannot guarantee that such authorizations would be granted in a timely fashion or granted at all.
We may be exposed to increases in interest rates, thereby increasing our financial costs.
We may incur debt locally and in the international capital markets and, consequently, may be affected by changes in prevailing interest rates.
When market interest rates increase, our financing expenses are likely to increase, which could have an adverse effect on our results of operations and financial condition. Our future success depends on our ability to access capital markets and obtain financing at cost-effective rates.
As of December 31, 2025, approximately 33.7%, or a principal of USD 9.5 billion (COP 35.8 trillion, using a COP 3,757.08/1.00 U.S. exchange rate as of December 31, 2025), of our total indebtedness consisted of floating rate debt. If market interest rates rise, our financing expenses could be expected to increase and our cost of capital could be expected to deteriorate, which could have an adverse effect on our ability to execute certain projects, and our results of operations and financial condition. In addition, as we refinance our existing debt in the coming years, the mix of our indebtedness may change, specifically as it relates to the ratio of fixed to floating interest rates, the ratio of short-term to long-term debt, and the currencies in which our debt is denominated in or indexed to. We cannot assure that such changes will not result in increased financing expenses presented by us. Finally, as we incur new debt in the future to fund our working capital, capital projects or inorganic acquisitions, or pursue liability management transactions, the prevailing interest rates and spreads at any specific time could be less favorable in terms of cost when compared to our previous financing transactions, which could adversely affect our financial condition and results of operations.
Our current and planned investments, divestments and business activities outside Colombia are exposed to political and economic risks.
We began exploration activities outside Colombia in 2006 through our Brazilian subsidiary, Ecopetrol Óleo e Gás do Brasil Ltda. We operate through business partners, subsidiaries, or affiliates outside Colombia. We currently have investments, joint ventures and direct and indirect subsidiaries incorporated in Peru, Brazil, Chile, Argentina, Bolivia, Mexico, Bermuda, Panama, the Cayman Islands, Switzerland, Spain, the United Kingdom, Singapore, and the United States, and we are continuously assessing our investments, including any potential divestments, in these countries, as well as investments in other countries. Our investment and divestment decisions may be subject to risks related to economic and political conditions, as well as potential governmental actions, such as investigations or legal proceedings. Furthermore, we cannot predict the positions of foreign governments relating to the oil and gas industry, electricity transmission, toll roads concessions, land tenure, protection of private property, environmental standards, regulation, or taxation; nor can we assure that future governments will maintain policies favorable to foreign investment or repatriation of capital. Additionally, we may face new and unexpected risks involving environmental and other legal requirements beyond those we currently experience.
The results of operations and financial condition of our subsidiaries in these countries also may be adversely affected not only by risks associated with hydrocarbon exploration and production or energy transmission and toll roads concessions, but also by fluctuations in their local economies, political instability and government actions, including: the imposition of price controls, the imposition of restrictions on hydrocarbon exports, electricity transmission limitations, fluctuation of local currencies against the Colombian peso, the nationalization of oil and gas reserves or electricity transmission, increases in export and income tax rates for crude oil and oil products, energy transmission, toll roads concessions, and unilateral (governmental) institutional and contractual changes, including controls on investments and limitations on new projects.
Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas, or our production to decline, limit our ability to pursue new opportunities, affect the recoverability of our assets, cause us to incur additional costs or delay the timeline of our projects, be unable to realize the original expected value or recover the value of our initial investment, or be unable to divest assets at acceptable prices or within the planned business timelines because of economic or political conditions or market risk.
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Our future performance depends on successful selection, development and deployment of new technologies and our knowledge about them.
Technology, knowledge, science, and innovation are essential to our business, especially for the addition of reserves in complex settings, reducing operational costs, reducing the carbon footprint of our operations and adapting to the energy transition. If we do not develop the right technology, or do not secure access to required third-party technology, or if we fail to deploy the right technology, do not obtain the expertise to operate our deployed technology or to improve our processes, or do not deploy the knowledge necessary to improve such technology effectively, the achievement of our corporate goals, our profitability, and our earnings may be adversely affected. Furthermore, as we address climate change and the transition to a lower-carbon economy, we face the risk that our progress may be curtailed due to the high cost or limited access to low-carbon and water management technologies. In the case of our enhanced oil recovery program, we depend on the successful selection, adaptation, demonstration, and deployment of appropriate technologies that are also energy and environmentally efficient.
The selection, access, development, integration, operation, and retirement of emerging technologies (including AI, advanced automation, supercomputing, multi-agent systems, confidential computing, data platforms, and energy innovations) may affect Ecopetrol´s ability to achieve its strategic objectives, maintain operational resilience, ensure energy and environmental efficiency, and sustain its competitiveness in the energy transition.
Organizational structure that does not enable the execution of the corporate strategy.
Our ability to execute the corporate strategy may be compromised if our structure (processes, organizational architecture, and human talent) does not evolve at the pace required by business needs. Misalignment between roles, processes, capabilities, and strategic objectives can limit agility, efficiency, and our capacity to respond effectively to the challenges of the energy sector.
This situation poses a risk if the Company lacks the structure, systems, and talent with the necessary skills to drive business transformation, support the energy transition, and implement strategic initiatives in a timely and sustainable manner.
If the strategic plans associated to natural gas fail or underdeliver, we may be unable to keep pace with increasing domestic demand.
Through Resolution 40031 of January 30, 2025, as amended by Resolution 40302 of July 1, 2025, the Ministry of Mines and Energy issued the Natural Gas Supply Plan for 2023-2032, based on the Technical Study for the Natural Gas Supply Plan prepared in June 2024, by the Mining and Energy Planning Unit (Unidad de Planeación Minero Energética, “UPME” for its acronym in Spanish) which was complemented in January 2025. In this document, the UPME has established a possible deficit of natural gas in Colombia between 2026 and 2030 in some scenarios. It is important to note that, pursuant to CREG Resolution 102 015 of 2025, the natural gas market is a physical market. Consequently, suppliers must comply with the quantities agreed in their contracts with firm gas commitments.
We are currently developing offshore projects to incorporate gas reserves; we cannot assure that they will go into operation in the short or mid-term. Additionally, we are party of several national gas supply contracts that have firm gas commitments. If we were unable to deliver natural gas to these clients because of cuts in operations or higher decline rates in our gas fields, among other reasons, we may be required to compensate our customers for our failure to supply natural gas.
Delays in the implementation of our strategic plans associated to natural gas and NGL could result in us losing market share if clients choose to secure their supply with other sources instead (such as third-party gas suppliers or imports). As a result, our financial condition, results of operations and market share could be impacted.
We depend on others for the construction and availability of natural gas transportation infrastructure for the transport of our gas, which may limit our ability to develop new or existing fields or lead to the deterioration of related assets and may not allow us to recover the cost of capital invested in natural gas discoveries.
Ecopetrol S.A. can only hold up to 25% of the equity of any natural gas transportation company according to Article 5 of CREG Resolution 057 of 1996 (except for transportation assets acquired before this Resolution). Therefore, there can be no assurance that the transportation infrastructure necessary to transport natural gas from the fields to distribution points and our customers will be built by third parties, or that if built in that location, there will be sufficient capacity available to us for the exploitation of new natural gas discoveries or the development of existing fields due to the non-financial closure of transport projects or lack of signed contracts with transporters. The failure to commercially exploit new or existing discoveries may result in impairment of the related assets and our inability to recover the capital expenditures invested to make these natural gas discoveries.
Our operations could be affected by demonstrations and other actions of labor unions, social organizations, communities and contractors.
Social organizations, including those in the communities where we operate, individuals representing specific communities, contractors and their workers, labor unions and other social movements may, exercising their rights, engage in demonstrations, protests, and other actions related to climate, labor (including expectations to increase the local employment or a higher spend on goods and services), health, indigenous rights and other social issues of local, national, or global significance. Such demonstrations, protests and actions may disrupt our operations, escalate into conflicts, lead to increased or unexpected costs, or otherwise have a material adverse effect on our business.
Regarding the emerging environmental and climate change concerns, some communities have shown strong opposition to the development of Integral Research Pilot Projects (“PPIIs” from its acronyms in Spanish), leading their representatives to propose bills aimed at banning PPIIs. Although none of these bills has materialized into law, we cannot guarantee that similar bills will not continue to be proposed or that none of them may eventually gain sufficient support to be enacted.
We cannot guarantee that the actions taken by labor unions will not affect the normal development of our operations, that we will not experience strikes or labor unrest, or that our labor costs will not increase significantly. The occurrence of any of these events could have an adverse effect on our operations and financial condition.
Our activities may be interrupted or affected by external factors, such as climate change and its effect on weather and natural disasters.
In the past decade, the “El Niño” and “La Niña” have intensified, increasing the risk of extreme climate events, such as floods, landslides, wildfires, droughts, increased temperature and rising sea and river levels, among others, as well as related water scarcity, which may affect our infrastructure and business operations.
“El Niño” phenomenon is characterized by: (i) the lack of rainfall, may drastically decrease surface waterbodies flows, affecting both freshwater use and wastewater discharges because of the reduction on dilution potential of receiving waterbodies, (ii) increased temperatures, which causes heat waves and could have a direct impact on the health of our workers and cause an increase in epidemics and diseases, and (iii) potential negative impact on energy supply due to the decrease in the level of the rivers that feed the hydroelectric generation system of the country. In addition to the “El Niño” climate phenomenon, some basins in Colombia may be affected by seasonal variability in some periods of the year (normally January to March - June to July), which could reduce water flows, affecting freshwater withdrawals and surface discharges, as mentioned previously. Moreover, such adverse weather events can result in transmission restrictions caused by the increase in a transmission line’s load from the coast to the center of the country and negatively impact our energy transmission business.
Furthermore, “La Niña” climate phenomenon is characterized by increased rainfall, which can generate frequent landslides and flooding, which may cause delays on transportation due to road blockades, increase pipeline integrity risks that may cause hydrocarbon spills and limit operations in our production fields and facilities, as well as cause infrastructure loses, such as collapse of transmission towers and lines that restrict our energy transmission business’ operations.
These risks could result in fatalities, property damage, project delays, production deferrals, loss of revenue, pollution, harm to the environment, damage roads as well as temporary disruptions to our services, among others. If any of these occur, we may be exposed to economic sanctions, damages, fines, or penalties in addition to the negative effects these events may have on our operations and the costs required to repair or remediate the related damage. These costs, fines and penalties may adversely affect our financial condition, reputation, and results of operations. Natural disasters or similar events could also result in substantial volatility in our results of operations or the interruption of our essential services for our country, such as our ability to transport natural gas and transmit electricity.
During 2025, ENSO conditions were not consolidated; meteorological conditions were modulated by the reference climatology.
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Our operations, including our activities in areas classified as indigenous reserves and Afro-Colombian lands, could be subject to opposition from members of various communities.
We currently carry out and plan to continue carrying out activities in areas recognized under Colombian Law as indigenous reserves and Afro-Colombian collective territories. To undertake these activities, we must first comply with prior consultation processes, set forth by Colombian law. The prior consultation process is required for obtaining environmental licenses to start our projects, works or activities in areas inhabited by ethnic communities. In addition, consultations can be seen as a potential instrument to involve communities in decisions regarding the development of extractive industry and infrastructure projects in their territories. Generally, such processes last between six months to one year depending on the community expectations but may be significantly delayed if we cannot reach an agreement with the communities. We are committed to be respectful of the Constitution and laws and the autonomy of indigenous and Afro-descendant communities, and we therefore refrain from entering their territories for project execution purposes until we have reached an agreement with them. We also design management plans to prevent, mitigate, repair or offset the impact of our projects, as identified by local communities. Issued environmental licenses for these projects may be subject to scrutiny as a result of claims filed by local community interest groups.
In recent years, indigenous communities have also been claiming their ancestral territories and requesting recognition of their right to be consulted about projects already in operation before International Labour Organization Convention No. 169 entered into force in Colombia. Such claims and opposition may arise from, among other factors, the communities’ concerns regarding the exploitation of natural resources, environmental impacts and the potential effects of our activities on their cultures, territories and spiritual beliefs. In addition, the increased presence of illegal armed groups in certain territories where we operate may further exacerbate these tensions. The presence of such groups could increase threats against human rights defenders and heighten the risk of attacks on oil infrastructure, which could result in operational disruptions and environmental damage. As a result, we may be exposed to operational restrictions or delays as a result of the opposition of these communities.
No certainty can be given that we will be able to reach an agreement with the different communities that object to our operations or that such communities will participate in consultation processes where applicable. We may be exposed to similar delays due to the objection from local communities in other countries where we carry out our activities.
Our activities may be subject to objection, including protests by non-ethnic communities. We are also subject to other participation mechanisms, such as popular actions (acciones populares), through which local communities or groups of interest may challenge the development of extractive industry projects. Any such situation may affect our future projects. See section Risk Review—Legal Proceedings and Related Matters for detailed information related to consultation processes with Afro-descendant communities.
Furthermore, allegations regarding potential human rights violations affecting indigenous peoples in areas where we operate could adversely affect our reputation and relationship with our stakeholders. Such allegations could negatively influence market perception and lead certain investors to divest based on similar arguments.
We have made and may make significant investments and divestments, and we may not realize their expected value.
We continuously analyze investments and joint ventures in Colombia and abroad and will continue to do so as part of our 2040 Strategy. We have made investments and may continue to do so from time to time depending on the environment and strategic needs of the Company. Some of our investments, joint ventures and new business lines may be less profitable than planned and, as a result, we may not achieve consistent profitability in the future.
Obtaining the expected benefits of acquisitions, including ISA’s, or joint venture investments, will depend, in part, on our ability to: (i) obtain the expected results of operations and financial condition from these acquisitions or joint venture investments, (ii) manage different sets of assets and operations and integrate distinct corporate cultures or investment goals, (iii) manage our objectives as a corporate group, and (iv) institute our corporate governance rules as well as other factors beyond our control such as the economic and regulatory environment in countries in which we have made acquisitions or joint venture investments, as well as all other risks affecting the oil and gas industry or the industries of the businesses we acquire or invest in. See section Risk Review–– Legal Proceedings and Related Matters––Interconexión Eléctrica S.A.
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Similarly, in our shale operations in the U.S., the ability to drill and develop different locations is subject to uncertainties such as natural gas and oil prices, drilling and production costs, availability of drilling services and equipment, lease acquisitions and expirations, the natural decline of the reservoir, processing capacity constraints, pipeline transportation bottlenecks, access to and availability of water sourcing and distribution systems, regulatory approvals, among others. We cannot assure that all the well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil at the planned levels. As a result, our efforts may not succeed and our failure to successfully obtain the expected results from our acquisitions or joint venture investments could adversely affect our financial condition and results of operations.
Our organic and inorganic investments in renewable energy self-generation projects, which are intended to reduce the cost of meeting our electricity demand, are subject to risks that could prevent the realization of the expected savings and adversely affect our results of operations. These risks include deviations in consumption levels, underperformance of the assets relative to expectations—resulting, among other factors, from changes in weather and climatic conditions—higher-than-expected operation and maintenance costs, interconnection constraints, increased reliance on grid-supplied power under less favorable conditions, and changes in the applicable regulatory framework. With respect to inorganic investments, including those structured through partnerships, joint ventures or capital structure arrangements that may result in equity dilution, the assumptions used to estimate the anticipated economic benefits may not materialize, or unidentified contingencies may exist, which could result in lower returns or an impairment of the value of such assets.
In addition, as a result of strategic reassessments of our core operations and portfolio management analysis, in the past we have executed and may determine as part of our short- or long-term strategy to execute partial or total divestments in our current businesses, and the sale prices for these transactions may not be enough to realize the original expected value or recover the value of our initial investment. We may also retain liabilities following a divestment or be held liable for past acts, failures to act or liabilities that are different from those foreseen.
We might be required to provide financial support to our subsidiaries or affiliates in Colombia or abroad.
Since 2025, we have issued short-term parent guarantees to third parties to support short-term financing facilities of our trading and pre-operative subsidiaries or affiliates. Financial support at any point in time might be needed to assure the long-term viability of such subsidiaries or affiliates when exposed to unexpected conditions, results, or when it is utterly required to support projects in their developing phase, in particular with respect of those pre-operative affiliates.
Any situation that could affect the operations of our subsidiaries or affiliates, or make them financially non-viable, particularly for those that are about to enter into their development phase or for those that recently entered into operations, may have a negative impact on their profitability as well as on their ability to pay their liabilities, which in turn could adversely affect our financial condition and results of operations.
Investigations and other actions by Colombian control entities involving our current or former employees or those of our current or former subsidiaries may impact our reputation.
Because Ecopetrol is a majority-owned state entity, its current and former employees are considered public servants and, together with the current and former employees of its subsidiaries, they are subject to oversight by various administrative control entities and other authorities in Colombia, including the Office of the Comptroller General (Contraloría General de la República) and the Attorney General’s Office (Procuraduría General de la Nación). Such oversight could result in proceedings, the imposition of fines or penalties, or other actions by Colombian administrative control entities, which could impact our reputation. Furthermore, our employees may be subject to criminal investigations and proceedings by the Prosecutor’s Office (Fiscalía General de la Nación), which could also impact our reputation.
On October 8, 2024, the National Electoral Council opened a formal investigation for alleged irregularities in the financing and presentation of the income and expenditure report of Mr. Gustavo Petro’s 2022 presidential campaign, of which Mr. Ricardo Roa Barragán was the campaign manager, before he joined Ecopetrol as its Chief Executive Officer. Separately, on December 12, 2023, the Attorney General’s Office initiated a disciplinary investigation for the same reasons, after a Colombian citizen filed a petition before Colombia’s Prosecutor’s Office.
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According to public records, on November 27, 2025, the National Electoral Council decided to sanction Mr. Gustavo Petro’s 2022 presidential campaign for violating electoral spending limits and receiving prohibited contributions, leading to fines of nearly COP 6 billion being imposed on the then-campaign manager Mr. Ricardo Roa, and the treasurer and auditor. This decision was appealed and, according to public records, on April 29, 2026, the National Electoral Council confirmed the decision. The decision made on November 27, 2025 included notifying the Prosecutor’s Office to investigate possible violations by Mr. Ricardo Roa. The Prosecutor’s Office scheduled a charging hearing (imputación de cargos) against Mr. Ricardo Roa for April 8, 2026, and according to public records it was rescheduled for May 8, 2026. In Colombian criminal procedure, the charging hearing marks the formal notification to a suspect of specific criminal charges and the factual and legal basis supporting them; although it means that the Prosecutor considers that there is sufficient evidence to attribute criminal responsibility, it is not a conviction. The reported charges relate to the alleged violation of campaign spending limits, potentially engaging offenses under electoral and criminal law concerning unlawful campaign financing.
In addition, on January 26, 2024, the Attorney General’s Office initiated a preliminary investigation against Mr. Ricardo Roa for alleged irregularities that occurred in December 2022, before he joined Ecopetrol as its Chief Executive Officer, regarding his purchase of an apartment from Princeton International Holding, represented at the time by Mr. Serafino Iacono, who allegedly had business interests with the Ecopetrol Group. On June 4, 2025, the Attorney General’s Office opened a formal disciplinary investigation against Mr. Ricardo Roa for a possible conflict of interest related to such apartment purchase. The investigation aims to determine whether Mr. Ricardo Roa’s decisions at Ecopetrol could have favored interests linked to Mr. Serafino Iacono. The Attorney General’s Office also requested information on whether Mr. Ricardo Roa properly submitted and updated required conflict-of-interest declarations during his tenure as Chief Executive Officer. This investigation is administrative and disciplinary, not criminal, and remains ongoing with no conclusions or sanctions to date.
On December 16, 2024, the Attorney General’s Office initiated a disciplinary investigation against Mr. Ricardo Roa as Ecopetrol’s Chief Executive Officer, based on a complaint alleging that his statements of April 24, 2023, regarding the signing of oil and gas exploration and exploitation contracts and the intention to import gas from Venezuela, could have adversely affected Ecopetrol’s finances, including the value of its shares on the markets in which Ecopetrol participates. The investigation is in the evidentiary phase.
In June 2025, the Attorney General’s Office initiated a disciplinary investigation against a former Compliance Director, former Vice President of Technology and an employee of the supply department of Ecopetrol as subjects of disciplinary action, for alleged irregularities related to the planning, signing and execution of a contract and related addendum with an external legal consultant. According to public records, on September 9, 2025, two former members of Ecopetrol’s Board of Directors were also included in the investigation as subjects of disciplinary action. The contract with the external legal consultant was terminated upon the expiration of its term. The investigation is in the evidentiary phase.
On March 11, 2026, the Prosecutor General’s Office brought charges against Mr. Ricardo Roa for his alleged responsibility for the crime of influence peddling by a public servant. The Prosecutor General’s Office reported that Mr. Ricardo Roa allegedly instructed the president of Ecopetrol’s subsidiary Hocol to award the Chuchupa-Ballena LNG regasification project to GAXI ESP S.A.S., a company owned by Juan Guillermo Mancera, through whom Mr. Ricardo Roa allegedly completed the purchase of the apartment from Princeton International Holding. Under Colombian law, the indictment is an act of communication that formally links Mr. Ricardo Roa to the criminal proceedings, discloses the facts under investigation and their potential legal consequences, and activates his right to defense.
Mr. Ricardo Roa decided to use accrued vacation days from April 7 to May 27, 2026, and Ecopetrol’s Board of Directors approved Mr. Ricardo Roa’s unpaid leave of absence for 30 calendar days starting May 28, 2026. During his absence, Juan Carlos Hurtado Parra, the Executive Vice President of Hydrocarbons, is serving as the Acting President of the company.
In 2024, in connection with the allegations related to Mr. Ricardo Roa, Ecopetrol’s Board of Directors commissioned a report from an external risk consultant. The key recommendations of the report, which remain valid to date, were the need for the Board of Directors and management of Ecopetrol to constantly monitor publicly available information for any new developments regarding the CEO; evaluate potential risks and the likelihood of their coming to pass; and maintain a continuing dialogue with external counsel expert in regulatory issues in the United States to ensure a prompt response by Ecopetrol and the Board of Directors to any recommendations made.
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There are also investigations concerning certain employees and former employees of Ecopetrol, Bioenergy and Reficar and certain members of the Board of Directors of Offshore International Group, where Ecopetrol formerly held a stake, which remain ongoing. Ecopetrol is not aware of any allegations related to acts of corruption in connection therewith. See sections Risk Review—Legal Proceedings and Related Matters and Risk Review—Risk Factors—Legal and Regulatory Risk—We may incur losses and spend time and money defending pending lawsuits and arbitrations and responding to administrative investigations for additional information.
Our results may be affected by supply chain disruptions and high price volatility impacting our suppliers, partners and other third-parties.
Global supply chains face a new operating reality – one defined by persistent volatility and disruptions embedded in the global economy. Global supply chains have entered a new era of structural volatility, not cyclical– shaped by scarcity, fragmentation, systemic constraints and continuous disruption. Rising geopolitical tensions, technological acceleration, national industrial policies and slowing uneven growth driven by inflation and tighter capital, are not isolated shocks but disruptive forces that redefine how the world sources, produces and delivers.
A set of 32 most relevant supply indexes has been identified and monitored. Most of the international indexes keep a stable trend such as chemicals, iron steel, aluminum, cement, oil and gas machinery and oil and gas support activities, logistics, among others. However, certain commodities have shown a countercyclical trend, such as copper and electrical machinery. Domestically, there has been heightened pressure across indices related to healthcare, education, food and minimum-wage compensation, this situation has affected and could continue to affect suppliers and agreed commercial conditions and might contribute to inflationary trends in the short term. The above-mentioned factors are expected to have a potential impact between 3.5% and 3.8% inflation, with an estimated impact equivalent to USD 114 million and USD 123 million based on certain modeled scenarios.
In 2025 alone, tariff escalations between major economies have reshuffled trade flows. In addition, the combination of geopolitics, oil and gas market balances, energy transition, technological acceleration, reactivation of Venezuela’s oil industry, and other shocks have created a complex environment that may affect our results and the performance of our suppliers, subcontractors, and third-party service providers. These scenarios were modeled based on an assumed market surplus ranging from 0.2 to 1.2 million barrels per day of crude oil, with Brent crude prices projected to range between USD 50 and USD 58 per barrel.
The above factors may affect the economic fundamentals underlying oil and gas operations and project development, and additionally, inflationary pressure will be concentrated across labor cost structures, administrative expenditures, regulated input categories and corporate financing costs. In addition, some of our suppliers may face financial or operational problems that could lead them to a breach of their obligations settled under contractual arrangements. Other suppliers may also be subject to regulatory changes or sanctions that could increase the risk of defaulting on their obligations to us, which could have an adverse effect on our operations and financial condition.
Most of our activity depends on suppliers, subcontractors and third-party service providers that provide goods and services for our operations and projects. In addition, some of our operations and projects are performed through joint ventures or other contractual arrangements with our business partners or third-party service providers. Consequently, we depend on the performance of our business partners or third-party service providers. The weak performance of our suppliers, or our business partners or third-party providers, in any criteria such as operational efficiency, deadlines, administrative aspects, HSE, especially in those projects in which we do not act as operator, could negatively impact the execution of projects and operating performance, which in turn could have a negative impact on our results of operations and financial condition. We are exposed to the risk of not finding business partners or suppliers with the proper skills and performance we require for our projects. We are also indirectly exposed to supply agreements and other third-party services contracted by our business partners acting as operators under joint venture agreements.
Our insurance policies do not cover all liabilities and may not be available for all risks.
There can be no assurance that incidents will not occur in the future, that insurance will adequately cover the entire scope or extent of our losses or that our employees or former employees will not be found liable by investigations by Colombian State control entities in connection with claims arising from these and other events, which could adversely affect our financial condition and results of operations.
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New trends in the insurance sector in the face of climate change may impact our financial condition and results of operations.
We have identified three main insurance trends arising from climate change and the transition to a lower carbon that could have a negative impact on the Company: (i) insurance and reinsurance companies are imposing new requirements regarding decarbonization targets, which may affect the insurability of assets or higher premiums, (ii) policy coverage may change as climate risk modeling and assessment advance, leading to changes in underwriting policies and new policy exclusions, and (iii) increase frequency or intensity of climate related events may lead to increase in premium prices. We have been strengthening communications with the reinsurance market, regarding the TESG strategy and its commitment to comply with it, which allows us to support the negotiations of the corporate insurance program. However, we cannot assure that these trends will not increase our insurance costs or reduce our insurance coverage, which could adversely affect our financial condition and results of operations.
A failure in our information technology systems or cyber security attacks may adversely affect our financial results.
We depend on the reliability and security of our information technology systems to conduct certain exploration, development and production activities, process financial records and operating data and communicate with our employees and business partners, and for many other activities related to our business. Our information technology systems may fail or have other significant shortcomings due to operational system flaws or employee misuse, tampering or manipulation. In addition, we may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss, or destruction of proprietary and other information. Any of these occurrences could disrupt our business, result in potential liability or reputational damage, or otherwise have an adverse effect on our financial results.
During 2025, our internal cybersecurity systems played a critical role in protecting the organization from a variety of cyber threats of different nature, including malware, phishing, abusive content, malicious code, advanced persistent thread (APY), information gathering, intrusions, availability, fraud and denial of service. We did not have any critical incidents in 2025, as we included in the cybersecurity guidelines that all cyber incidents must be assessed in accordance with the RAM (risk assessment matrix). Although we have not experienced any material losses related to failures of our information technology systems or cyber incidents, there can be no assurance that we will not suffer such losses in the future.
Information and processing systems are vital to the ability to monitor the operation and network performance of assets, achieve operating efficiencies, and meet service targets and standards. Any failure of any of these information and processing systems could have a material adverse effect on our financial condition and results of operations. In addition, we may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.
The use, integration, and reliance on AI capabilities (including GenAI and agents) in Ecopetrol Group’s IT/OT processes and assets can lead to erroneous decisions, operational disruptions, exposure of sensitive information, regulatory non-compliance, and loss of value/industrial security due to data/model failures, attacks/adversarial ML, human overreliance, or geopolitical/digital fragmentation; affecting production, safety, costs, reputation, and compliance.
We are exposed to behaviors incompatible with our ethics and compliance standards.
Given the extent, dimension and nature of our business and corporate sector, the frequent interaction with national and foreign Government Officials, the large number of contracts that we are a party to in Colombia and abroad with local and foreign suppliers, the geographic distribution of our operations and the great variety of actors that we interact within the course of our business, we are subject to possible violations of our Codes of Ethics and Conduct (the Code applicable to the Ecopetrol Group and the Code applicable to third parties with whom we interact), as well as applicable legal provisions related to compliance with regulations of anti-money laundering, U.S. Foreign Corrupt Practices Act (“FCPA”), fraud, corruption and bribery. Such acts may impact on our reputation, and eventually could affect the commercial relations of the Company.
The performance of our partners, subsidiaries and affiliates in Colombia and elsewhere may negatively impact our image and reputation.
As part of our strategy, we have carried out and plan to carry out substantial investments, divestitures, partnerships and joint ventures in Colombia and elsewhere. Failures, errors, accidents in the performance of such partners, affiliates and subsidiaries, among other factors, could potentially negatively impact our image and reputation.
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There may be situations wherein product failures and/or accidents are not properly mitigated, making our relationship with our stakeholders difficult. We cannot ensure that there will be no impact on our relationship with local governments, customers and third parties as a result of such product failures and/or accidents, which could affect our image and reputation, negatively impacting us in the business environment and challenging the implementation of our strategies and achievement of our objectives.
The reliability and capacity of national power supply systems may affect or limit the continuity of our operations or limit growth.
Our energy consumption in 2025 was 8.6 TWh/year, of which 56% was supplied through self-generation, and the remaining 44% through power grid. Our electricity demand is equivalent to 10.25% of the total energy demand in the SIN (National Interconnected System, as referred to in the Colombian electricity market). Our self-generation is subject to fuel and solar availability. In addition, several producing fields are connected to the national transmission system and depend on its expansion and reliability to keep steady production levels. The national electricity market is volatile due to changes in hydrology and availability of fuels (natural gas, diesel, etc.), bringing uncertainty to prices. If energy were to become unavailable or difficult to obtain, our results of operation and financial condition could be adversely affected.
Rising water production levels may affect or constrain our crude oil production.
During 2025, the Ecopetrol Group produced approximately 13.6 million barrels of water per day which includes direct operations, and operations with partners and subsidiaries. Considering the nature of our reservoirs, the water production levels to be managed by the Company may increase in the future. To achieve our oil and gas production goals and to avoid any production restrictions going forward, we will need to secure the required capacity to manage water levels. Factors that may trigger a possible constraint in our crude oil production due to the rising water production levels are: (i) ineffective project management of the required facilities, (ii) the Company’s and its partners’ ability to timely obtain the environmental permits related to water management, (iii) social and community interactions that could affect the development and operation of these projects, and (iv) the availability of capital to execute the required projects.
5.2.2
Risks Related to Colombia and the Region’s Political and Regional Environment
This section discusses potential risks related to our extensive operations in Colombia, as well as our operations in other countries of Latin America.
Changes in economic, energy transition and oil & gas policies in Colombia, Peru, Brazil, Chile and the United States of America could materially affect our financial condition and results of operations.
Our financial condition and results of operations may be adversely affected by changes in the political climate of Colombia, Peru, Brazil and Chile to the extent that such changes affect the economic policies, growth, stability, outlook or regulatory environment of these countries.
For the year ended December 31, 2025, revenues derived from Colombia represented 48% of our total revenues. The Colombian Government has historically exercised substantial influence on the local economy, and governmental policies are likely to continue to have an important effect on companies operating in Colombia and on market conditions. Natural resources are owned by the Nation but may be exploited by third parties who pay grants to the Government in exchange for exploitation rights. The President of Colombia and the Colombian Central Bank have considerable power and independence as policymakers to determine governmental policies, regulations and actions relating to the economy and may adopt policies that negatively affect us. We cannot predict which policies will be adopted by the Government or whether those policies would have a negative impact on the Colombian economy or our business and financial performance.
In addition, Colombia is expected to hold presidential elections in 2026. The first round of the presidential election is scheduled to take place in late May 2026, and if no candidate obtains an absolute majority, a second-round runoff between the top two candidates is expected to be held in June 2026. The newly elected president is scheduled to take office on August 7, 2026.
Electoral processes may result in changes in public policy, regulatory approaches, and government priorities, including those related to the energy sector. While we cannot predict the outcome of the elections or the policies that future administrations may adopt, any significant changes could affect the business environment in which we operate.
In December 2023, the Minister of Mines and Energy, Andrés Camacho, announced the progress made by the Colombian Government in relation to energy and hydrocarbons, as well as challenges that remain in these sectors. The Colombian Government developed the “Roadmap for an Equitable Energy Transition,” following its presentation of the “Construction of principles, methodology and launch of the Social Dialogue to define the Roadmap for the Just Energy Transition in Colombia” during the United Nations Conference on Climate Change COP27 in Egypt in November 2022. This roadmap was built through technical analysis and in conjunction with existing regulations, including Law 2099 of 2021 and CONPES 4075 of 2022. The Colombian Government has also presented bills to definitively prohibit fracking in Colombia. It is unclear how such policies may affect our business, what form they could take, or whether we would need to adjust our business strategy in response.
Although elected governments and the Colombian Congress have historically pursued free market economic policies with limited economic intervention, we cannot predict which policies, if any, will be adopted by the new Government and/or Congress, or whether those policies would have a negative impact on the Colombian economy or our business and financial performance. See section Business Overview—Applicable Laws and Regulations—Regulation of Exploration and Production Activities—Business Regulation—Temporary regulation for the Comprehensive Research Pilot Projects (PPII).
In August 2022, the MHCP submitted a tax reform bill to Congress proposing changes to the Colombian tax regime. The bill was sanctioned by President Petro as Law 2277 of 2022 on December 13, 2022, and became effective on January 1, 2023.
Decree 175 of February 14, 2025 (“Decree 175”) introduced tax measures intended to address the state of internal commotion declared by the National Government through Decree 062 of 2025. These measures included two new taxes: (i) the special tax for the Catatumbo; and (ii) the reactivation of the stamp tax rate. Both taxes were temporary and in effect from February 22, 2025, through December 31, 2025.
Subsequently, on December 22, 2025, the National Government issued Decree 1390, declaring a State of Economic Emergency throughout the national territory for 30 days due to unforeseen circumstances that worsened the country’s fiscal situation. In response, the Government issued Decree 1474 on December 29, 2025, introducing tax measures to fund expenditures under the General National Budget for fiscal year 2026. On January 29, 2026, with Press Release No. 01, the Constitutional Court announced its decision to suspend the legal effects of the Economic Emergency Decrees.
On February 11, 2026, the National Government issued Decree 0150 of 2026, declaring a new State of Economic, Social and Ecological Emergency. Under this authority, Decree 173 of 2026 was issued pursuant to Decree 1015 of 2026, introducing a temporary wealth tax applicable for fiscal year 2026 to Colombian legal entities and assimilated entities, effective as of its publication and triggered by the possession of net equity as of March 1, 2026.
For a description of the most relevant changes introduced by Law 2277, Decree 175, Decree 1390 and Decree 173, see “Financial Review – Effect of Taxes, Exchange Rate Variation, Inflation and the Price of oil on our Results.”
Additionally, the Colombian Congress approved the bill on pension reform, which restructures the pension system into a “pillar system” that manages and assigns funds based on age, the condition of the affiliates and other criteria, and includes changes to pension schemes applicable to women. Although the bill was approved by Congress, the Constitutional Court is analyzing whether the law complies with the Colombian Constitution. On March 6, 2025, the Chamber of Representatives voted in favor of the healthcare reform presented by President Petro for review by the Colombian Congress. In April 2025, the Seventh Commission of the Senate began its review of the project and reached the decision to shelve it on December 16, 2025. On June 17, 2025, the Senate approved the labor reform, which is expected to have a progressive implementation starting in 2026. Among other changes, the reform reduced the workweek to 42 hours and modified the costs applicable to work performed during extra hours, Sundays and holidays. The reform also recognizes the existence of a full labor contract with apprentices from the Servicio Nacional de Aprendizaje (SENA), requiring companies to pay a salary of up to 75% of the monthly minimum salary during the instructive stage and 100% during the practice stage. On December 29, 2025, the Government of Gustavo Petro declared a 23.7% increase in the monthly minimum salary, equivalent to two million Colombian pesos (COP 2,000,000) including the transportation subsidy.
Following this announcement, market expectations collected by the Banco de la República reflected a significant reassessment of the inflationary and macroeconomic outlook for Colombia. Between the December 2025 survey (prior to the announcement) and the January 2026 survey (following the announcement), the median expectation for twelve-month headline inflation increased from 4.59% to 6.15%, an upward revision of 1.56 percentage points. Core inflation expectations (excluding food and regulated prices) rose from 4.58% to 6.18%, an increase of 1.60 percentage points, suggesting that market participants perceived the wage adjustment as having broader second-round effects beyond volatile or administratively regulated components.
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Monetary policy expectations also adjusted materially. The expected Banco de la República policy rate at twelve months increased from 9.25% in December 2025 to 11.25% in March 2026, an upward shift of 2.00 percentage points, indicating that analysts anticipate a tighter and more prolonged monetary policy stance in response to increased inflationary pressures and potential risks to inflation convergence.
Foreign exchange expectations showed a more moderate but visible adjustment. The median USD/COP exchange rate expectation at twelve months declined from COP 3,966.40 to COP 3,850.00, an appreciation of COP 116.40, which may reflect expectations of tighter monetary policy, higher nominal interest rates and improved carry attractiveness partially offsetting inflationary concerns.
Taken together, these changes in market expectations suggest that the minimum wage increase was perceived as a macro-relevant policy decision with potential implications for inflation dynamics, monetary policy normalization and domestic demand conditions. A sustained deviation of inflation expectations from the Colombian Central Bank’s target range could weigh on economic growth, increase financing costs and contribute to higher volatility in interest rates and macroeconomic variables. Such effects could, in turn, adversely affect operating costs, capital expenditures, financing conditions and the overall financial performance of companies operating in Colombia, including us.
In its January/February 2026 monetary policy meeting, the Board of Directors of the Banco de la República approved a 100 basis point increase in the benchmark policy interest rate, from 9.25% to 10.25%, marking a significant tightening of monetary policy. In March 2026, the rate was increased to 11.25%. This decision was motivated by persistent inflationary pressures, a rebound in core inflation, rising inflation expectations and risks stemming from fiscal imbalances and strong domestic demand. The decision reflects the Board’s intention to reinforce its commitment to bringing inflation back toward its 3% target, even though not all members agreed—four supported the hike, two preferred a rate cut and one favored no change.
As of February 13, 2026, Colombia’s Council of State, acting as the country’s highest administrative court, provisionally suspended the Government’s decree setting a 23.7% increase in the legal monthly minimum wage for 2026. The suspension is a precautionary temporary measure while the court reviews the legality of the original decree. The Council ordered the Executive Branch to issue a new temporary decree within eight days establishing a minimum wage figure that complies with statutory standards. This temporary figure will apply until the court issues a final ruling on the merits of the challenge. The suspension does not constitute a final judgment on the decree’s legality, and amounts already paid under the current wage level remain valid.
In April 2026, the Constitutional Court declared the unconstitutionality of Decree 1390 of 2025, which had declared a State of Economic, Social, and Ecological Emergency at the national level. The Court concluded that the conditions required under the Colombian Constitution to justify the use of emergency powers were not met and, as a result, the decree ceased to have legal effects. Consequently, the extraordinary measures adopted pursuant to that emergency declaration, including certain fiscal and regulatory provisions, were rendered without effect, subject to any further judicial determinations applicable to specific implementing decrees. The Constitutional Court’s decision does not affect other states of emergency declared for different purposes, nor does it constitute a finding regarding the merits of any subsequent legislative initiatives that may be pursued through ordinary constitutional channels. The implications of this decision for public policy, regulatory frameworks and future government actions remain subject to legal, legislative and political developments.
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United States
With respect to United States of America, for the year ended December 31, 2025, revenues derived from our consolidated subsidiaries in this country represented 36% of our total revenues. On April 2, 2025, U.S. President Donald J. Trump announced new tariffs on imports into the United States of America. These tariffs include a “baseline” tariff of 10% on imports from many countries, including Colombia. In October 2025, the U.S. administration publicly threatened to increase tariffs on Colombian exports to 25%, in connection with disputes related to counternarcotics cooperation. These developments were accompanied by Colombia’s decertification as a counternarcotics partner, which further increased trade uncertainty and resulted in the application or threat of higher tariffs on specific Colombian export products. U.S. trade policy has continued to be characterized by a high degree of discretion, with tariffs used as a negotiable instrument in broader diplomatic, trade and security discussions. The imposition of these tariffs may have significant adverse effects on global trade, which could have a material adverse effect on Colombia’s economy, trade balance, and key industries. A significant portion of Colombia’s exports are directed to the United States of America, making it vulnerable to changes in U.S. trade policy. Higher tariffs could reduce demand for Colombia’s goods in the United States of America, disrupt supply chains, and lead to job losses in affected industries. Additionally, retaliatory measures by other nations could exacerbate economic uncertainty, impacting investor confidence and foreign direct investment, and countries facing even higher tariff rates could decide to sell excess products into the Colombian market, adversely affecting Colombian producers. The tariffs may also contribute to global trade tensions and volatility in currency markets, which could put pressure on exchange rates and inflation. Colombia’s limited ability to negotiate exemptions or mitigate these effects through alternative trade agreements has adversely affected economic growth and fiscal stability. These developments could have a material adverse effect on our business, financial condition, or results of operations in Colombia.
With respect to Brazil, for the year ended December 31, 2025, revenues derived from our consolidated subsidiaries in this country represented 6% of our total revenues. On January 8, 2023, demonstrators invaded the Planalto presidential palace, the National Congress and the Federal Supreme Court (STF) in Brasilia, protesting the defeat of then-president Jair Bolsonaro in the 2022 Brazilian general election and the inauguration of his successor Luiz Inácio Lula da Silva. As of January 23, 2025, approximately 1200 people had been tried and sentenced with up to 17 years of imprisonment in the cases involving the most serious crimes related to the events of January 8, 2023. Former President Jair Bolsonaro has been directly affected by these developments as he was declared ineligible to hold public office until 2030 due to findings of abuse of political power during the 2022 electoral process. In addition, following criminal proceedings related to the attempted coup and broader antidemocratic conduct between 2022 and 2023, Bolsonaro was convicted in September 2025 and sentenced to approximately 27 years of imprisonment, and began serving his sentence in late 2025. On electoral aspects, on October 6, 2024, municipalities held elections for mayors and city council members. A second round of voting took place on October 27, 2024, in 51 municipalities in which none of the mayoral candidates obtained more than half of the valid votes (excluding blank and invalid votes) in the first round. The elected mayors and city council members were sworn into office on January 1, 2025. The National Congress enacted a tax reform on December 20, 2023 (the “Brazil Tax Reform”). The Brazil Tax Reform includes: (i) merging four levies into value-added tax (VAT) rates managed in a dual format (partially federal and partially regional), (ii) changing tax collection from a tax on production to a tax on consumption, (iii) reduced tax rates on certain sectors of the economy, (iv) sets the framework for a creation of a cashback system, and (v) increases tax rates on luxury vehicles and inheritances. On April 25, 2024, the Federal Government submitted the bill for the first complementary law regulating aspects of the Brazil Tax Reform to the National Congress for consideration. The bill provides for a “cashback” or rebate mechanism for low-income families on certain goods and utility services, such as gas, electricity and water, and a “split payment” system that electronically splits tax payments relating to transactions by recipient. On January 16, 2025, the bill was enacted by President Lula as Complementary Law 214/2025 after having gone through its congressional approval process. On June 5, 2024, the Federal Government submitted bill No. 108/2024, the second complementary law regulating aspects of the Brazil Tax Reform to the National Congress for consideration. The bill creates the IBS Steering Committee (Comitê Gestor do Imposto sobre Bens e Serviços or “CG-IBS”, for its acronym in Portuguese) and regulates the administrative proceedings within the CG-IBS, as well as the collection and distribution of the tax on goods and services and the transition to the new tax system. The bill was approved and turned into Complementary Law 227 of January 13, 2026.
Changes in economic or other policies by the government of the president Luiz Inácio Lula da Silva could negatively affect our industry in general, or our Brazilian subsidiaries’ results of operations, in particular.
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With respect to Peru, for the year ended December 31, 2025, revenues derived from our consolidated subsidiaries in Peru represented 2% of our total revenues. Peru has experienced prolonged political instability, having had eight presidents since 2018 amid repeated impeachments, corruption scandals and fragile governing coalitions. Following the impeachment of President Dina Boluarte in October 2025 and the subsequent impeachment of her interim successor José Jerí in February 2026, José María Balcázar became Peru’s ninth acting president in a decade.
In March 2024, Congress approved a constitutional reform reinstating a bicameral legislature, comprising a 130-member House of Representatives and 60 member Senate. The reform also limited the president’s power to dissolve Congress to the House of Representatives only; the Senate cannot be dissolved and is expected to wield considerable political power. On April 12, 2026, Peru held general elections for President, 60 Senators and 130 Deputies, the first bicameral election in more than 30 years, with a record 35 presidential candidates. With approximately 94% of ballots tallied, no candidate was near the 50% threshold required to avoid a runoff; Keiko Fujimori led with approximately 17%, followed by Roberto Sánchez at approximately 12.0% and Rafael López Aliaga at approximately 11.9%, with the race for second place separated by roughly 14,000 votes and still fluctuating. Following the April 2026 elections, no candidate secured a majority, triggering a runoff scheduled for June 7, 2026, with final first-round results expected no later than May 15, 2026.
Although Peru’s economy has shown resilience, posting more than 3% growth in 2024 and 2025 aided by its status as a major copper producer, the combination of an interim administration, ongoing investigations of senior political figures, heightened polarization and the prospect of a contested runoff contribute to a highly volatile political environment. We cannot assure that policies against free market and minimal intervention of the government in the Peruvian economy will not be taken by a new administration or any new congress. Any changes in the Peruvian economy or the Peruvian government’s economic policies may have a negative effect on our business, financial condition, and results of operations. Changes in economic or other policies by the Peruvian government or other political developments in Peru could adversely affect the business, financial condition, and results of operations of our subsidiaries.
With respect to Chile, for the year ended December 31, 2025, revenues derived from our consolidated subsidiaries in this country represented 2% of our total revenues.
Following social unrest in 2019, Chile undertook two successive attempts to draft a new constitution, both of which were rejected by voters. Following the second rejection, the Chilean government declared the constitutional reform process closed, with no further initiatives to be pursued during the presidential term that ended on March 11, 2026. The existing constitution accordingly remains in effect.
Elections for regional governors took place on October 26 and 27, 2024. In all regions except Tarapacá, Ñuble, Los Ríos, Aysén and Magallanes — where candidates were elected in the first round — a second-round election was held on November 24, 2024. The results reflected a notable shift in Chile’s political landscape. The ruling center-left alliance, “Por Chile y sus Regiones,” secured seven governorships, while the center-right coalition “Chile Vamos” won six, demonstrating strengthened regional influence. Independent candidates secured two governorships, and the “Tu Región Radical” movement claimed one, for a total of sixteen regional administrations.
In December 2025, Chile held presidential elections in which José Antonio Kast, a right-wing candidate, won the second round with approximately 58% of the vote. President Kast assumed office on March 11, 2026, marking a significant shift in political leadership driven in part by voter concerns regarding security, economic performance and governance. While the new administration has signaled a different policy orientation from that of the prior government, the scope, pace and impact of any changes to economic, regulatory, tax or energy policies remain uncertain. We cannot predict what policies will ultimately be adopted by the Kast administration or whether such policies will have a negative impact on the Chilean economy, our industry sector in Chile, or the business and financial performance of our Chilean subsidiaries.
Ecuador
Uncertainty in Colombia’s bilateral relationship with Ecuador—a market that remains structurally integrated with Colombia across trade and energy systems—has increased materially during 2026. In January 2026, Ecuador announced a 30% “security charge” on Colombian imports effective February 1, citing a widening trade deficit and border-security concerns. In response, Colombia suspended electricity exports to Ecuador and imposed a 30% tariff on 20 Ecuadorian products, describing these actions as temporary and subject to review. Ecuador then raised transport fees for Colombian crude shipped through the SOTE pipeline system by 900%—from USD 3/bl to USD 30/bl—and signaled additional adjustments on the OCP network. In late February, Ecuador announced it would increase tariffs on Colombian exports to 50%, effective March 1, 2026, and Colombia subsequently matched that rate on imports from Ecuador. In April 2026, Ecuador announced a further increase in tariffs on Colombian imports to 100%, effective May 2026.
These escalating measures have already disrupted cross-border power flows and crude-logistics corridors. Given Ecuador’s significance as a commercial and strategic partner for Colombia, and the high degree of bilateral interdependence in electricity supply and crude-export routing, a prolonged dispute could pose operational risks to energy-sector activities and create broader adverse implications for Colombia’s economic performance.
We cannot provide any assurances that political or social developments in Colombia, Peru, Brazil, Chile, or Ecuador, over which we have no control, will not have an adverse effect on our respective economic situations or adversely affect the business, financial condition, and results of operations of our consolidated subsidiaries and their ability to pay dividends or make other distributions to us. Any such developments could have a material adverse effect on our business, results of operations, and financial condition.
Our business operations and financial condition could be negatively affected by pandemic or epidemic diseases and other health events.
Pandemic diseases and other health events, have the potential to negatively impact economic activities in many countries, including those in which we operate or have trade links, with consequent adverse effects on our customers and business by causing changes in the demand for energy, the movement of people and availability of services and our ability to address such future conditions, could again disrupt our business and operations.
As the potential impact of a new pandemic or other diseases is difficult to predict, the extent of the impact on our business and financial results will ultimately depend largely on future developments, including the duration, characteristics of the new outbreak (e.g., new diseases, new variants of the virus, capacity for infection and transmission, treatment developments and vaccination coverage), the impact on capital and financial markets and the related impact on consumer confidence and spending, and the actions taken by authorities to contain it, all of which are highly uncertain and cannot be accurately predicted.
Colombia has experienced internal security issues that have had or could have a negative effect on the Colombian economy and on us.
Colombia has experienced internal security issues, primarily due to the activities of guerrillas, paramilitary groups, drug cartels and organized armed groups known as GAOs. From time to time, guerrillas target crude oil and multi-purpose pipelines, including the Transandino Pipeline, Caño Limón - Coveñas and Oleoducto Bicentenario pipelines, and other related infrastructure disrupting our activities and those of our business partners.
During 2025, the attacks against our pipeline infrastructure decreased by 24% in relation to 2024 (31 attacks in 2025 compared to 41 attacks in 2024). Nonetheless, the attacks especially affected infrastructure located in the Norte de Santander and Arauca departments, and the Caño Limón – Coveñas and Bicentenario pipelines. As a result, there was a deferred production of 762,684 barrels directly related to these attacks in 2025, as compared to 114,505 barrels in 2024. As of March 2, 2026, four attacks against our pipeline infrastructure have been identified.
Terrorist attacks have resulted in unscheduled shutdowns of our transportation systems to repair or replace sections of pipelines that have been damaged, with deferral of production in certain fields, as well as caused us to undertake environmental remediation. In respect of the pipeline infrastructure, the direct cost of repairs due to terrorist attacks in 2025 was approximately COP 321,203 million (USD 85.49 million using a COP 3,757/1.00 US exchange rate as of December 31, 2025).
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During 2025, we also experienced one attack on our production infrastructure in Santander, specifically on Lufkin Mark II 640 mechanical pumping unit and the Cira 1775 well. As a result, there was a deferred production of 184 barrels directly related to these attacks in 2025, as compared to 1,021.33 barrels in 2024. In respect to the production infrastructure, the direct cost of repairs due to guerrilla attacks in 2025 was approximately COP 1,265,813,000 (USD 0.31 million using a COP 4,052,71/1.00 USD exchange rate as of December 31, 2025).
Likewise, the theft of refined products and crude oil, as a result of security issues, may impact our operating and financial results in the future, as well as our reputation, due to the potential use of these products within the alkaloid chain production and the possible impact to communities and the environment, derived from this illegal practice. The main impact during 2025 was on the Pozos Colorados–Galán multi-product pipelines in the Cesar Department, with a loss of 2,107 bpd. The stolen product has been used for cocaine processing, illegal sales, and illegal mining, according to national security sources. Due to the terrorist attacks recorded during 2024, the Caño Limón–Coveñas pipeline ceased operations between the Banadía and Ayacucho stations, operating instead under a contingency scheme through the Bicentenario pipeline. However, hydrocarbon demand in the region persisted. Consequently, some of the structures previously involved in hydrocarbon theft along the Caño Limón pipeline shifted their activities to the Pozos Colorados–Galán multiproduct pipeline. This situation has been further exacerbated by the critical public order conditions in the Cesar Department, through which the pipeline runs, as well as by illegal economies operating in neighboring departments. To address hydrocarbon theft along this pipeline, inspections to the pipeline, the deployment of technological monitoring tools, and coordinated operations with the Public Security Forces continue to be implemented. Associated with the above, the theft of refined products has increased from approximately 179 bpd in 2024 to 2,197 bpd in 2025. Furthermore, crude oil theft has decreased by 95%, primarily due to the contingency operation that rerouted the Caño Limón–Coveñas pipeline through the Bicentenario pipeline. Losses reached 1,483 bpd in 2024 and 79 bpd in 2025.
In recent years, social protests have resulted in blockades of the country’s main roads and isolated incidents against certain of our infrastructure, which in turn has momentarily adversely affected the operations of our exploration and production, refining and petrochemicals and transport and logistics segments, leading to decreases in our crude oil and refined products production and transported volumes.
These activities and their possible escalation and the effects associated with them have had, and may have in the future, a negative impact on the Colombian economy or on us, which may affect our customers, employees, assets, or the environment, with resulting containment, clean-up and repair expenses.
Despite the current government’s announcement of a bilateral ceasefire with some armed groups, non-conformism may arise in the process of these dialogues spoken out through illegal and terrorist activities.
The dynamics of security in Colombia in 2024 were characterized by processes and public order situations led primarily by the ELN (Ejército de Liberación Nacional) and the FARC (Fuerzas Armadas Revolucionarias de Colombia) dissidents or EMC (Estado Mayor Central). The six-month extension of the bilateral ceasefire between the Colombian Government and the ELN in February 2024 was initially met with optimism, particularly in conflict-stricken areas such as Arauca, Chocó, Cauca and Norte de Santander. This agreement offered temporary relief to affected communities, facilitated humanitarian access in critical zones, and reinforced the government’s commitment to negotiated solutions. However, challenges in verification and mutual distrust jeopardized its implementation, underlining the need for improved monitoring mechanisms. The ceasefire, initiated on August 3, 2023, ultimately lapsed on August 3, 2024, without renewal, sparking uncertainty and rising tensions in regions like Arauca and Norte de Santander. The cessation of the agreement led to a resurgence of violence, including a wave of terrorist attacks targeting oil infrastructure and security forces, exacerbating instability. A significant blow to the process occurred when the ELN’s Domingo Laín Sáenz Front carried out an attack, killing two soldiers on September 17, which prompted the government to suspend negotiations, reflecting its zero-tolerance stance toward violence during peace talks. The event further eroded trust, reignited violence in vulnerable regions, and diminished prospects for regional stability.
In 2024, the peace process with the Estado Mayor Central (EMC) of the FARC dissidents faced considerable challenges, such as intensified violence in areas like Catatumbo. This group is not currently engaged in dialogue with the government. Driven by clashes between the EMC and ELN, which have caused numerous casualties and mass displacement, undermining public confidence in the peace talks process. Despite these setbacks, the EMC peace process aimed to promote territorial transformation by strengthening state presence, advancing economic development, and addressing social disparities in Catatumbo Norte de Santander. Plans included reintegrating ex-combatants, providing essential services such as health and education, and supporting sustainable economic projects to replace illicit economies. The success of these initiatives depends on political will, the fulfillment of agreements, and governmental capacity to ensure security and economic alternatives.
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At the beginning of 2025, security conditions deteriorated significantly due to numerous clashes between the ELN and dissident factions of the FARC in the Catatumbo region. These confrontations, driven by ideological differences and territorial disputes, created a severe crisis affecting both security and humanitarian conditions, with the municipality of Tibú, in Norte de Santander, being one of the most impacted areas.
On January 24, 2025, the Government declared State of Internal Commotion due to the increased violence in the Cúcuta and Catatumbo regions. This was executed through a Decree that ruled until December 31, 2025 with some tax implications regarding hydrocarbons and coil.
On October 20, 2025, Ecopetrol suspended its activities in the Catatumbo region due to more than seven-armed intrusions by illegal armed groups, which resulted in the theft of crude oil and persistent threats against Ecopetrol. This generated a deferred production of 25,535 barrels. Due to these episodes, the production of 1,400 barrels of oil and 900,000 cubic feet of gas was put at risk, affecting not only the energy sector but also the local supply of these services.
On December 21, 2025, ELN announced a unilateral ceasefire until January 3, 2026, as well as EMC (FARC), that announced a unilateral ceasefire until January 7, 2026.
The persistent confrontations between armed groups and the government have further intensified instability in the country, directly affecting Ecopetrol’s operations in regions such as Arauca and Norte de Santander. These areas have witnessed most terrorist acts carried out by these groups, posing serious risks to both the safety of the employees, contractor’s employees and the Company’s infrastructure. As a result, Ecopetrol’s operations are frequently disrupted by the volatile security environment.
During 2025, the National Government advanced various negotiation initiatives and issued public statements aimed at opening peace dialogue processes with several organized armed groups. These efforts included FARC dissident groups, particularly the Calarcá faction; the organized armed group Comuneros del Sur, which remained the only formally active dialogue table with the Government; as well as the initiation of process-validation dialogue tables with the Clan del Golfo and the Autodefensas Conquistadoras de la Sierra. However, within this context, no announcement was made by the National Government during 2025 of a prolonged ceasefire that would entail a general suspension of military operations against organized armed groups throughout the national territory. The ceasefires that were decreed were limited in scope, temporary in nature, and strictly confined to the development of specific dialogue scenarios. One such case was the 72-hour bilateral ceasefire agreed on April 12, 2025, with dissident groups of the Calarcá faction, within the framework of an extraordinary meeting held in the department of Meta. This ceasefire was not extended, despite requests from the insurgent delegations, a decision that was formally communicated by the Government and the Office of the High Commissioner for Peace.
Additionally, toward the end of 2025, several unilateral ceasefire announcements were made by different armed groups. These declarations lacked official endorsement or verification mechanisms and did not result in an effective reduction of armed actions. In December 2025, the ELN unilaterally announced a ceasefire lasting until January 3, 2026, which was not effectively complied with. Similarly, FARC dissident groups, both from the Calarcá faction and the faction led by Iván Mordisco, declared unilateral ceasefires extending until mid-January 2026, without verifiable outcomes in terms of de-escalation of the armed conflict.
As of February 2026, there is no active, government-recognized ceasefire with the ELN or FARC dissident factions in Colombia. While these groups have issued unilateral or seasonal announcements of temporary suspension of hostilities, such declarations have not led to observable reductions in violence, lacked official verification mechanisms, and were not endorsed by the National Government.
Government decisions and security dynamics are the key factors that impact stability in the areas where Ecopetrol operates. For this reason, the Company must maintain constant communication with security state organizations, such as the Colombian army, and the National Police Force. However, despite our efforts, we cannot ensure the safe development of our operations.
It is important to know that the processes advanced by the Government with common criminal groups and organized crime structures have not been framed as traditional political negotiations, but rather as socio-legal dialogue mechanisms aimed at reducing violence, protecting the civilian population, and creating pathways for submission to justice. Within this framework, two cases are particularly relevant. The first is Medellín and the Aburrá Valley, where the process reached an advanced stage and led to the proposal of a conditional urban peace agreement, although the dialogue was later paused. The second is Quibdó, where the process remained active as of March 2026, with a fifth round underway and with official assessments indicating an overall reduction in crime levels.
As of April 2026, the National Government’s current peace framework is composed of several differentiated tracks rather than a single nationwide negotiation. Officially referenced processes include the main political negotiating table with the ELN, which remains suspended; the territorial peace table with Comuneros del Sur in Nariño; the dialogue table with the EMBF (Calarcá faction); the dialogue table with the Coordinadora Nacional Ejército Bolivariano; the socio-legal conversation space with the EGC (Clan del Golfo); the process with the Autodefensas Conquistadores de la Sierra Nevada; and the urban peace processes in Buenaventura, Quibdó, and Medellín–Aburrá. In institutional terms, this architecture combines political dialogue, territorial peace building, urban violence-reduction arrangements, and socio-legal mechanisms aimed at de-escalation and transition toward legality.
Additional here is no active, government-recognized ceasefire with the ELN or FARC dissident factions in Colombia. While these groups have issued unilateral or seasonal announcements of temporary suspension of hostilities, such declarations have not led to observable reductions in violence, lacked official verification mechanisms, and were not endorsed by the National Government.
Regional and global events may have an impact on Colombia’s social, economic and political situation as well as on us and our operations.
Regional and global events, such as humanitarian crises, conflicts and natural disasters, may have an impact on Colombia’s social, economic and political situation as well as on us and our operations. In addition, borders with some of Colombia’s neighboring countries have been, may remain or be in the future shut down or restricted, affecting the economy and migration patterns in towns and cities close to such borders and commerce with those countries. We cannot make any assurances that such events will not negatively impact Colombia’s social, economic and political situation, nor on our company and its operations.
We are subject to the prevailing economic conditions and investment climate in Colombia, which may be less stable than those in developed countries.
Market prices of securities issued by Colombian companies, including us, are subject to the prevailing economic conditions in Colombia. A large portion of our assets and operations are located in Colombia and most of our sales are currently derived from our local crude oil and natural gas production and the production of our refineries located in Colombia. Accordingly, our financial condition and results of operations depend on a significant extent on macroeconomic and political and regulatory conditions prevailing from time to time in Colombia and on the exchange rates between the Colombian Peso and the U.S. dollar.
If the perception of improved overall security in Colombia deteriorates or if the investment climate worsens, the Colombian economy may face lower growth rates than the ones posted recently, which could negatively affect our financial condition and results of operations.
Furthermore, the market price of our shares and American Depositary Shares, or ADSs, may be adversely affected by changes in governmental policies, particularly those affecting economic growth, exchange rates, interest rates, inflation, and taxes. Furthermore, the proposed bill for pension reform may affect the assets under management of private funds, which could affect the market of our shares. The Government has changed monetary, fiscal, taxation, labor and other policies over time and has thus influenced the performance of the Colombian economy. We have no control over the extent and timing of changes in these variables or government intervention and policies.
Developments in U.S. foreign policy toward Colombia and Venezuela may adversely affect us.
Political, economic, and security conditions in Colombia and Venezuela continue to evolve in ways that may affect the regional energy market and the operating environment in which we conduct our business.
In Colombia, political developments and changes in the domestic and international policy environment may influence investor sentiment, market perceptions, and the operating context for state-owned enterprises. Shifts in government priorities, public policy debates, and external political relationships may contribute to uncertainty affecting the energy sector, including perceptions of country risk and sovereign exposure. These factors may impact our ability to execute our commercial strategy, maintain stable relationships with international partners, and access global markets on competitive terms.
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In Venezuela, prolonged political instability, economic deterioration, and constraints affecting the country’s oil sector have contributed to persistent volatility in regional crude supply, pricing, and trade flows. Disruptions or uncertainty surrounding Venezuelan production, exports, and infrastructure may influence competitive dynamics in the Caribbean and Latin American energy markets, affecting pricing conditions, customer behavior, and commercial planning. In addition, heightened security concerns and geopolitical tensions in and around Venezuelan territory may increase risks associated with maritime transportation, logistics, and the availability or cost of shipping and insurance services used for crude oil and refined product movements in the region. Although we do not operate in Venezuela, these developments may indirectly affect the Company through regional market fluctuations and changes in commercial conditions.
Taken together, regional political and security conditions in Venezuela may increase volatility in the markets in which we operate, affect demand and pricing for our products, influence logistics and transportation costs, and contribute to uncertainty in long-term planning and investment decisions. Any of these circumstances could materially and adversely affect our business, financial condition, cash flows, and results of operations.
Potential economic sanctions and enforcement measures administered by the Office of Foreign Assets Control (OFAC) could adversely affect our business, financial condition and results of operations.
U.S. sanctions programs are subject to frequent change, evolving interpretations, discretionary enforcement, and potential extraterritorial application, particularly in relation to geopolitical and national security developments. Such changes may be implemented rapidly through executive actions, regulatory determinations, new designations or guidance, and could affect our operations, counterparties, suppliers, customers, financing arrangements, insurance coverage, logistics and other aspects of our business, including where we have no direct operations in the sanctioned jurisdiction.
In addition, OFAC sanctions risks may arise even when a company is not designated. OFAC may impose liability based on “causing” a violation or where prohibited dealings occur through U.S. nexus points, such as U.S.-dollar payments, use of U.S. financial institutions, U.S. persons, U.S.-origin goods or services, or other connections to the U.S. financial system. As a result, our use of U.S.-dollar clearing, banking relationships, U.S.-linked service providers and cross-border transactions could expose us to heightened sanctions compliance risk, including the risk of investigations, penalties, operational disruptions and reputational harm.
This situation has recently intensified as a result of sanctions measures targeting politically exposed persons in Colombia. In October 2025, OFAC imposed full blocking sanctions on Colombia’s President and other senior Colombian individuals. While sanctions against an individual do not automatically sanction our company, the President’s potential indirect influence over certain governance decisions, combined with any direct or indirect involvement by a blocked person in activities with a U.S. nexus, could increase the risk that we could be viewed as facilitating or “causing” a sanctions violation if appropriate safeguards are not maintained. In addition, if any blocked person were determined to have an ownership interest in, transact with, or obtain an economic benefit from our activities in a manner involving a U.S. connection (e.g. U.S.-dollar payments), we could face increased compliance complexity, constraints on transaction structures and heightened enforcement exposure.
Furthermore, the imposition of blocking sanctions on high-level government officials has, in certain historical precedents, served as a precursor to broader agency-level, sectoral or government-wide sanctions. If the United States were to impose sanctions against the Government of Colombia similar to those applied in other jurisdictions, entities owned 50% or more by the Government of Colombia—as in our case—could become sanctioned as a matter of law under applicable OFAC principles, which could severely restrict our ability to conduct transactions involving U.S. nexus, including U.S.-dollar payments and dealings with U.S. persons and U.S. financial institutions, and could materially impair our access to international financing, trade flows and critical suppliers. In addition, the United States could attempt to impose sanctions directly against us; although there is currently no U.S. sanctions program specifically targeting Colombia, changes in U.S. policy could alter that posture.
Any of the foregoing could result in increased costs, delays or interruptions in operations, constraints on counterparties and payment channels, impairment of our ability to raise capital or refinance indebtedness, limitations on procurement and contracting, loss of business opportunities, and even investigations or adverse actions by U.S. authorities, all of which could significantly impact our operations, financial condition, and results.
5.2.3
This section discusses potential legal and regulatory risks to us, including the risk of having to comply with new laws and regulations.
Our operations are subject to extensive regulation, which is subject to change from time to time by the applicable regulatory authorities.
The Colombian hydrocarbons industry is subject to extensive regulation and supervision by the Government and regulatory agencies in matters including the award of exploration and production blocks by the ANH, the imposition of specific drilling and exploration obligations, restrictions on production, price controls, capital expenditures, liquidation of the Net Position of each refiner or importer with respect to the FEPC and required divestments. Existing regulation applies to virtually all aspects of our operations in Colombia and abroad. The commercialization activities of some of our products also face extensive regulation. Such regulation is subject to change by the applicable regulator affecting our ability to commercialize our products. See section Business Overview—Applicable Laws and Regulations. In particular, under Decree 1068 of 2015, as amended by Decree 1451 of 2018, the Ministry of Mines and Energy is required to calculate and liquidate each refiner and/or importer of fuel’s participation differential (i.e., this arises when the International Parity Price is lower than the reference price established by the Ministry of Mines and Energy, leading to a “Net Position” every three months to be paid by the FEPC). Accordingly, Ecopetrol S.A. and Cartagena Refinery rely on the FEPC settling their respective Net Position each year in connection with amounts due to them from FEPC. As of December 31, 2025, Ecopetrol S.A. recorded COP 2.43 trillion (USD 647 billion) in accounts receivable due from FEPC and Cartagena Refinery recorded COP 0.60 trillion (USD 159 billion) in accounts receivable due from FEPC. We cannot offer any assurance as to when or if Ecopetrol S.A.’s or Cartagena Refinery’s Net Position will be settled by FEPC and such amounts will be paid. If their respective Net Position is not settled, the Ecopetrol Group’s consolidated financial statements and results of operations could be adversely impacted. See section Business Overview—Applicable Laws and Regulations—Regulation of Refining and Petrochemical Activities—Regulation Concerning Production and Prices—Fuel Price Stabilization Fund (FEPC). In addition, Ecopetrol Group has recorded tax credits for sales tax and income tax. The Group complies with the procedures established in actual tax legislation to obtain refunds of these credits within the established timeframes; however, the tax authority has mechanisms to extend these timeframes. As explained before, natural gas is a highly regulated activity in Colombia, that may be subject to amendments related to commercialization rules. Specific commercialization procedures apply, that may be modified by the Colombian authorities. Ecopetrol’s natural gas marketing activities are subject to Superintendence of Public Utilities’ supervision and control.
The terms and conditions of the agreements with the ANH under which we explore and produce crude oil and natural gas generally reflect negotiations with the ANH and other governmental authorities and may vary by fields, basins and hydrocarbons discovered. We are required, as are all oil companies undertaking exploratory and production activities in Colombia, to pay a percentage of our production to the Government as royalties. The Colombian Congress has modified the royalty program for crude oil and natural gas production several times in the last 20 years, as it has modified the regime regulating new contracts entered into with the Government. In the future, the Colombian Congress may once again amend royalty payment levels, and such changes could have an adverse effect on our future exploration and production in Colombia. See section Business Overview—Applicable Laws and Regulations—Regulation of Exploration and Production Activities—Business Regulation—Royalties for a description of the current royalty scheme.
Our operations in Colombia are subject to extensive national, state, and local environmental regulations. Environmental rules and regulations are applicable to our exploration, production, refining, transportation, supply, and marketing activities, as well as the biofuels we produce. These regulations establish, among other things, quality standards for hydrocarbon products, air emissions and greenhouse gases, water discharges and waste disposal, soil remediation, water pollution and the general storage, handling, transportation, and treatment of hydrocarbons in Colombia. Currently, all exploratory drilling projects in areas that do not yet have a license must undergo an environmental impact assessment and must receive an environmental license from the governmental agency responsible for awarding environmental licenses, the ANLA. Environmental authorities with jurisdiction over our activities routinely inspect our crude oil fields, refineries, and other production sites, and they may decide to open investigations or sanction proceedings, which may result in the imposition of fines, restrictions on operations or other sanctions in connection with potential non-compliance of the environmental licenses granted to Ecopetrol and environmental laws.
We are also subject to control and monitoring by the regional autonomous corporations (CAR for its acronym in Spanish), which are regional environmental authorities that grant permits for the use and exploitation of natural resources in areas or fields that have an Environmental Management Plan (PMA for its acronym in Spanish), in the same way they establish compensation measures for the use of these resources and perform monitoring, control, and impose sanctions as result of investigations.
If we fail to comply with any of these national or regional environmental regulations, we could be subject to administrative and criminal penalties, including warnings, fines, or closure orders of our facilities. Any such criminal penalty would be imposed on the legal representatives of the Company, including any legal representative, director or worker who participated or failed to take action related to the activities that lead to environmental damage. See section Business Overview—Applicable Laws and Regulations—Regulation of Exploration and Production Activities—Business Regulation—Environmental Licensing and Consultations.
Some of the companies in the business group perform exploratory activities outside of Colombian territory. As such, those companies are subject to foreign environmental regulations for the exploratory activities conducted by the business group outside of Colombia. Failure to comply with foreign environmental regulations may result in investigations by foreign regulators, which could lead to fines, warnings or temporary suspensions of our operations, which could have a negative impact in the consolidated financial statements and results of operations of the Ecopetrol Group.
In addition, the companies of the Ecopetrol Group conducting exploration and production activities outside Colombia may be subject to foreign health, safety, and environmental regulations. Foreign health and safety regulations may be more severe than those established under Colombian law and, therefore, we may be required to make additional investments to comply with those regulations.
Furthermore, our energy transmission and toll roads concessions segment, carried on by ISA and its subsidiaries are heavily regulated in Colombia, Brazil, Peru and Chile by government ministries and authorities, as well as various other national, state, and local regulatory agencies. Regulatory actions taken by those agencies and, in particular, tariff reviews and revised compensation terms of transmission investments, could materially adversely affect the profitability of these businesses. In addition, increased regulatory requirements relating to the integrity of our facilities or the quality of the services provided by ISA and its subsidiaries may require additional spending in order to maintain compliance with these requirements.
We are subject to a broad range of environmental laws, which require us to incur ongoing costs and capital expenditures and expose us to substantial liabilities in the event of non-compliance. These laws and regulations require us to, among other things, minimize natural and socio-environmental risks, while maintaining the quality, safety, and efficiency of our facilities. These laws and regulations also require us to obtain and maintain environmental permits, licenses, and approvals for the operation of our business, which can lead to cost overruns or to changes in our investment plans. Some of these permits, licenses and approvals are subject to periodic renewal. Government environmental agencies could take enforcement actions against us for any failure to comply with applicable laws and regulations. Such enforcement actions could include, among other things, the imposition of fines, revocation of licenses, suspension of operations or imposition of criminal liability for non-compliance.
Environmental laws and regulations can also impose strict liability for the environmental remediation of spills and discharges of hazardous materials and waste and require us to indemnify or reimburse third parties for environmental damages. We cannot assure that we will obtain approval for any future projects, or that existing approvals, authorizations, licenses, and permits will not be questioned, revoked or otherwise suspended due to any alleged non-compliance or legal action. Environmental regulation has become more stringent in the countries where we operate in recent years. As a result, our operating costs have increased to comply with these new technical environmental requirements as well as the need to strengthen our specialized team in charge of environmental compliance in project and operations. If environmental laws continue to impose additional costs on us, we may need to reduce our investments on strategic projects to allocate funds to environmental compliance, delaying projects or having an adverse effect on our results of operations and financial condition. Moreover, more stringent environmental protection programs in the countries or industries where we operate could impose constraints and additional costs on our operations and require us to make significant capital expenditures in the future. We cannot assure that future legislative, regulatory, international law, industry, trade, or other developments will not have a material adverse effect on our business, properties, results of operations, financial condition or prospects.
Finally, under certain of our credit agreements, we are under an obligation to comply with international environmental standards established by our lenders or by multilateral institutions. Failure to comply with such environmental standards could result in an event of default under the relevant credit agreements that we, or our subsidiaries, have entered into, which would affect our financial condition.
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More stringent environmental regulation may lead to increased expenses or reduced demand for our products, as well as affect timely permits.
In terms of climate change, the Colombian Government enacted the Climate Action Law (Law 2169) in 2021 which advances Colombia’s focus on strengthening its strategy and actions against climate change, when considering the initiatives being taken at a global level. The Carbon Neutrality Colombian Strategy launched in April 2021 by the Ministry of Environment and Sustainable Development reaffirmed its commitment to these initiatives and accelerated Colombia’s goal to reduce GHG emissions to reach carbon neutrality by 2050. In 2023, the Ministry of Energy and Mines issued guidelines for the formulation of the Comprehensive Corporate Climate Change Plan, which seeks to advance the identification, definition, implementation and monitoring of initiatives or measures for climate change management associated with (i) the reduction of greenhouse gas (GHG) emissions, (ii) the reduction and management of climate risks, and (iii) internal governance actions. Additionally, the regulatory agenda of the MADS for 2026 includes plans to adopt significant new regulations related to greenhouse gas emissions reduction, carbon markets, and the carbon tax, which suggests that further regulatory developments in this area are forthcoming. These anticipated changes should be closely monitored, as they may introduce stricter regulatory standards and result in a more heavily regulated climate and environmental compliance framework. This regulatory framework may establish new requirements at the operational level that seek to accelerate the reduction of GHG emissions such as methane, reduction of fugitive emissions and venting, reduction of flaring, and the implementation of specific actions in adaptation to climate change, which may be reflected in the increase of operating and production costs. To anticipate these changes, we participate in different spaces of discussion and regulatory construction to prepare and respond to these requirements and not be affected by the fulfillment of our climate objectives. However, we cannot make any assurances that we will be able to achieve our goals or those set out in government climate change and sustainability initiatives (e.g., proposed Colombian Climate Action Law, carbon tax, carbon offsets, among others) or meet other stakeholders’ expectations with respect to such requirements, or that we will be able to apply reliable and cost-effective green alternatives. If we are unable to reach our carbon neutrality goals or governments’ or other stakeholders’ expectations with respect to such goals, our energy diversification portfolio and strategic priorities would be adversely impacted and could lead to increased expenses related to low-carbon initiatives and reduced demand for our core products.
We may not be able to keep pace with changing environmental requirements related to impacts to Colombia’s biodiversity and nature.
As we operate in a country that is recognized as a megadiverse territory where complexity, fragility, and biological diversity are interwoven with a rich history and a dynamic and complex social, economic, and political landscape, and where the government looks to businesses to participate in the country’s sustainability development goals implementation, we may not be able to adequately adapt and align our technology capabilities and strategy (e.g., Nature Based Solutions, Big Data Analytics, Remote Sensing, Robotics and Drones, Artificial Intelligence) to effectively enable, assess, and report on the reduction of its impact to Colombia’s biodiversity and nature (e.g., contamination, habitat loss, deforestation, and GHG emissions), considering the increase in Colombian sustainable development commitments leading to increased regulatory scrutiny and impacting our strategic efforts and operations for minimizing its impacts to relevant ecosystems.
In 2024, Ecopetrol introduced the Taskforce on Nature-related Financial Disclosures (TNFD) recommendations framework, in which it actively participates as member. This engagement has allowed us to better identify environmental impacts and dependencies related to nature while effectively managing the associated risks and opportunities.
Our operations might be affected by rising climate change and energy transition regulatory developments.
The increase in global temperature due to the substantial increase of GHG is a concern worldwide. The Paris Agreement calls for immediate and forceful actions to be taken to limit the increase of global temperature below 1.5°C. In response, government agendas have increasingly been defining normative and regulatory frameworks that determine local actions related to climate change.
As a result, companies are increasingly subject to regulatory risks and public policy changes related to climate change. In Colombia, the climate change regulatory framework has developed substantially, defining goals, measures, and means of implementation that bind companies. In 2021, the Climate Action Law (Law 2169 amended by Law 2294 of 2023) was issued, which promotes the low-carbon development of the country through establishing goals and measures related to carbon neutrality and climate resilience. This law is aligned with the country’s NDCs (51% GHG reduction by 2030) and its Long-Term Climate Strategy (E2050). The above is binding for Ecopetrol, among other aspects in: (i) mandatory reporting of GHG, (ii) National Registry of GHG Emissions Reduction and Removal, and (iii) low carbon development, carbon neutrality, and climate resilience implementation and monitoring plan. This regulation will be under continuous review by Ecopetrol to mitigate the potential financial effects and the impact on the company’s climate goals. To this end, the Company has developed a decarbonization roadmap to achieve medium and long-term goals. However, developments and new regulations could affect the fulfillment of the Company’s climate goals, increase costs and negatively impact its financial and operational results.
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Moreover, in 2022, the Energy Transition Policy (CONPES 4075), which promotes strategies for sustainable economic development, was issued. The Government also issued a regulation associated with fugitive emissions and venting and routine flaring (Resolution 40066 of 2022). To this end, the Company has been making progress in improving activities to detect and measure these emissions in the different operating areas, through top-down and bottom-up technologies, and in closing these leaks. However, the implementation and enforcement of these regulations could generate additional costs for the company. These regulations will be under continuous review by Ecopetrol; however, we cannot assure that the Company is able to mitigate the potential financial effects and the impact on the Company’s climate goals.
New or higher taxes resulting from changes in tax regulations or the interpretation thereof in Colombia could adversely affect our results of operations and financial condition.
New tax laws and regulations, and uncertainties in the interpretation with respect to existing and future tax policies pose risks to us. In recent years, the Colombian Congress and tax authorities have enacted modifications to taxes related to financial transactions, income, value added tax (VAT), and taxes on net worth. In December 2019, Congress passed Law 2010 called “Ley de Crecimiento Económico” or “Economic Growth Law”, which largely maintains the changes of the previous tax reform (Law 1943 of 2018) along with some changes to tax legislation. On September 14, 2021, the Colombian Congress enacted a tax reform called “Ley de Inversión Social” or “Social Investment Law”, which became effective as of January 1, 2022. This law increased the tax rate from 30% to 35%, which generated in Ecopetrol a deferred tax income of COP 306,312 million, recognized in the financial statements for the fiscal year ended 2021.
On December 13, 2022, the Colombian Congress enacted a tax reform (Law 2272 of 2022) effective from January 1, 2023. The tax reform includes, among others: (i) a new permanent equity tax applicable to Colombian individuals and non-residents, at rates ranging from 0.5% to 1.5% based on the level of net equity at January 1st every year, (ii) an increase in the dividend tax rate for local and foreign shareholders (0% to 39% progressive marginal rates for Colombian individuals, and 20% flat withholding for non-resident shareholders), (iii) an increase in the long-term capital gains tax rate (increasing from 10% to 15%); (iv) the elimination of specific tax benefits and exemptions, (v) a minimum corporate income tax based on effective tax rate (effective rate calculated on book profit should be at least 15%, considering certain adjustments to accounting profits and certain exempted companies), (vi) the application of taxes based on significant economic presence (primarily for non-resident persons and entities that provide digital services, but including other services and commercial activities) that took effect on January 1, 2024, (vii) the elimination of the ability to claim 50% of the Industry and Commerce Tax as an income tax credit, (viii) an income tax surcharge for companies engaged in the extraction of crude oil and coal of 0%, 5%, 10% or 15% and, based on international prices.
For fiscal year 2023, the surtax of 5%, 10% or 15% applied when the Brent price reaches USD 66.36, USD 74.20 and USD 80.73, respectively, according to ANH Resolution 0061 of January 31, 2024 (revenues from the sale of natural gas are not subject to this surtax). For fiscal year 2023, the surtax applied was 10%, (ix) the introduction of a minimum tax based on effective tax rate determined on accounting profits, (x) non-deductibility of royalties. However, the Colombian Constitutional Court ruled that the limitation rule is unconstitutional, thus, not applicable. In a final effort to mitigate the effect of this ruling on the public finances, the Ministry of Mines and Energy and the Ministry of Finance and Public Credit requested the review of the ruling to the Constitutional Court in December of 2023, alleging a fiscal impact and nullity, respectively.
In March 2024, the Constitutional Court rejected the request for nullity filed by the Ministry of Mines and Energy. The Constitutional Court rejected the fiscal impact claim filed by the Minister of Finance and Public Credit, stating that the arguments presented did not meet the constitutional threshold.
On February 14, 2025, the Colombian Government issued Decree 175 of 2025, which temporarily reinstated the stamp tax at a rate of 1% on public and private documents exceeding certain amounts, except for specific exemptions provided by law. This stamp tax was in force until December 31, 2025.
On December 22, 2025, the National Government issued Decree 1390, declaring a State of Economic Emergency throughout the national territory for a period of 30 days due to unforeseen circumstances that worsened the country’s fiscal situation. Consequently, in response to this emergency, the Government issued Decree 1474 on December 29, 2025, introducing tax measures intended to fund expenditures under the General National Budget for fiscal year 2026. Among these measures is the provision set out in Article 14 of the decree, which establishes the non-deductibility of royalties for taxpayers required to pay them in connection with the production of non-renewable natural resources. This decree is subject to automatic review by the Constitutional Court, which must assess, among other aspects, the constitutionality of this measure. On April 2026, the Constitutional Court declared the unconstitutionality of Decree 175 of 2025, as of April 2026, the measures adopted are revoked.
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On February 11, 2026, the National Government issued Decree 0150 of 2026 declaring a new State of Economic, Social and Ecological Emergency. Under Decree 1015 of 2026, Decree 173 of 2026 was issued, introducing introduced temporary wealth tax applicable for fiscal year 2026 to Colombian legal entities and assimilated entities, effective as from its publication and triggered by the possession of net equity as of March 1, 2026. Decree 0150 of 2026 is subject to an automatic constitutional review to determine its legality.
For a description of taxes affecting our results of operations and financial condition in 2024, see section Financial Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on Our Results—Taxes. Changes in tax-related laws and regulations, and interpretations thereof, can affect tax burdens by increasing tax rates and fees, creating new taxes, limiting tax deductions, and eliminating tax-based incentives and untaxed income. In addition, tax authorities and tax courts may interpret tax regulations differently than we do, which could result in tax litigation and associated costs and penalties.
In relation to income tax applicable to our shareholders, until 2016, for Colombian income tax purposes, dividends that were distributed from profits taxed at the corporate level were not taxed or subject to withholding tax at the shareholder level. However, beginning in 2017, the regulation changed so that dividends paid to non-resident shareholders are subject to a withholding tax. For further detail and a description of such changes, see section Financial Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results – Taxes. Further changes to Colombian tax laws may subject us and our shareholders to higher taxes and could adversely affect our results of operations and financial condition.
During the first quarter of 2025, Refinería de Cartagena S.A.S. and Ecopetrol S.A. became subject to administrative proceedings initiated by the National Tax Authority of Colombia (DIAN) in connection with the alleged application of value added tax (VAT) to certain gasoline and diesel importations carried out between 2022 and 2024. These proceedings have resulted in the issuance of official assessments and penalties, which the companies are actively challenging through administrative and judicial actions. As of the date of this report, the related claims remain pending before the competent administrative courts, while others remain under discussion at the administrative level with DIAN. See Details in Section 5.4 “Legal Proceedings and Related Matters – Requirements related to VAT by the National Tax Authority of Colombia.
We may incur losses and spend time and money defending pending lawsuits and arbitrations and responding to administrative investigations.
We are currently a party to several legal proceedings filed against us. We are also subject to labor-related lawsuits filed by current and former employees in connection with pension plans and retirement benefits. As of December 31, 2025, Ecopetrol S.A. was a party to 7,827 legal proceedings relating to civil, criminal, administrative, tax, constitutional, arbitration and labor claims, of which 5,380 were filed against us in the Colombian courts and arbitration tribunals and of which 400 had an accrual provision. We allocate substantial amounts of money and time to defend against these claims, in which the claimants often seek substantial sums of money as well as other remedies. See Note 23 to our consolidated financial statements and see section Risk Review—Legal Proceedings and Related Matters. In addition, in accordance with Colombian law, we and our employees are subject to surveillance and investigations by certain administrative control entities in Colombia, which are intended to determine whether public funds have been misused, mismanaged, or misappropriated or whether they have been used in compliance with applicable law. Such investigations may divert the attention of management and subject the Company to reputational risk and increase difficulties in retaining talent. See section Risk Review—Legal Proceedings and Related Matters.
The Colombian Government could seize or expropriate our assets under certain circumstances for fair compensation.
Pursuant to Articles 58 and 59 of the Colombian constitution, the Government can exercise its eminent domain powers in respect of private property assets in the event such action is deemed by the Government to be required in order to protect public interests. According to Law 388 of 1997, eminent domain powers may be exercised through: (i) an ordinary expropriation proceeding, or (ii) an administrative expropriation. In all cases, we would be entitled to a fair compensation for the expropriated assets. Also, as a general rule, compensation must be paid before the asset is effectively expropriated. However, the compensation may be lower than the price for which the expropriated asset could be sold in a free-market sale or the value of the asset as part of an ongoing business. The aforementioned Article 59 of the Colombian constitution establishes a temporary expropriation for war reasons, which does not require that compensation be paid before expropriation.
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5.2.4
This section discusses potential risks associated with an investment in our American Depository Shares (as opposed to our common shares) by investors outside Colombia.
Holders of our American Depositary Shares (ADSs) may encounter difficulties in protecting their interests.
Holders of our ADSs do not have the same voting rights as holders of our common shares. As set forth in the amended and restated deposit agreement, dated January 12, 2018 (as amended on December 30, 2021), among Ecopetrol S.A., JP Morgan Chase Bank, N.A., as depositary (the Depositary), and all holders from time to time of our American Depositary Receipts (as amended and restated, the “Deposit Agreement”), holders of our ADSs may instruct the Depositary, to vote on shareholder matters prior to a shareholders’ meeting.
Given that holders of our ADSs may require proxies that entitle the Depositary to vote on shareholder matters prior to shareholders meetings, such holders may be unable to instruct the Depositary in time to vote their shares.
The Deposit Agreement provides holders of our ADSs with the right to instruct the Depositary to vote common shares separately. Pursuant to certain regulations and opinions issued by Financial Superintendence of Colombia, it is currently understood that the depositary may vote common shares of a Colombian corporation in an American Depositary Receipt, or ADR, program separately. Notwithstanding this, if new opinions or regulations are issued which prevent either the custodian or the Depositary to vote the common shares (including the right to receive common shares in the form of ADRs) deposited under the Deposit Agreement and any other securities, cash or property from time to time held by the Depositary in respect or in lieu of deposited common shares (the “Deposited Securities”) separately, all such Deposited Securities shall be voted based on the majority vote of the voting instructions timely received from holders of ADRs. In the case of such single block voting, all holders of ADRs, including holders of ADRs for which no voting instructions are timely received and holders of ADRs with voting instructions contrary to the voting instructions of a majority of the Deposited Securities timely received, should be aware that the Deposited Securities shall all be voted as a single block and that the voting instructions of such holders of ADRs will be deemed given in the manner stated above.
The Depositary will not itself exercise any voting discretion in respect of any Deposited Securities. The holders of our ADRs will be solely responsible for any exercise of the voting rights of the Deposited Securities represented by the ADRs if such vote is made pursuant to the procedures described in the Deposit Agreement. Holders of ADRs are strongly encouraged to forward their voting instructions as soon as possible as voting instructions will not be deemed received until such time as the ADR department responsible for proxies and voting has received such instructions, notwithstanding that such instructions may have been physically received by the Depositary, prior to such time.
In the future, the Colombian regulatory authorities may clarify their interpretation as to how the voting rights should be exercised by holders of our ADSs, and such possible interpretation could adversely affect the value of the common shares and ADSs.
Our ADS holders may be subject to regulations on foreign investment in Colombia.
Colombia’s International Investment Statute (the set of rules and regulations which govern the international investment and the foreign exchange regime, which include Decree 1068 of 2015, Resolution 1 of 2018 and External Circular DCIP83 issued by the Colombian Central Bank among others), regulates the way in which non-Colombian residents can invest in Colombia and participate in the Colombian securities market. Among other requirements, Colombian law requires foreign investors to register certain foreign exchange transactions with the Colombian Central Bank and outlines the necessary procedures to authorize certain types of foreign investments. Colombian law requires that certain foreign exchange transactions, including international investment in foreign currency between Colombian residents and non-Colombian residents, must be made through the foreign exchange market, either through authorized intermediaries for the foreign exchange market or compensation accounts, which are regular bank accounts held abroad by Colombian residents and registered with the Colombian Central Bank. Any income or expenses under our ADR program must be made through the foreign exchange market.
Investors acquiring our ADRs are not required to register with the Colombian Central Bank directly, as they will benefit from the registration to be obtained by the custodian for our common shares underlying the ADRs in Colombia. If foreign investors in ADRs choose to surrender their ADRs and withdraw common shares, they must register their investment with the Colombian Central Bank in the common shares as a portfolio investment through their local representative, which may be a brokerage firm, trust company or investment management companies supervised by the Financial Superintendence of Colombia. Foreign investors will only be allowed to transfer dividends abroad after their foreign investment registration procedure with the Colombian Central Bank has been completed. Investors withdrawing common shares could incur expenses and/or suffer delays in the application process. The failure of an investor to report or register foreign exchange transactions with the Colombian Central Bank on a timely basis may prevent the investor from remitting dividends abroad or result in the initiation of an investigation and in the imposition of fines.
Nonresidents who acquire ADRs and either receive profits from this investment, surrender their ADRs or liquidate their investment in ADRs, must register their investment by means of the procedures set forth in section 7.4.1. and 7.4.2. of the External Regulation of the Circular DCIP-83 of the Colombian Central Bank.
The Colombian Government, the Colombian Congress, or the Colombian Central Bank may amend Colombia’s International Investment Statute or the foreign exchange regime, which could result in more restrictive rules and could negatively affect trading of our ADSs or any transfer of currencies from Colombia to other countries or vice versa.
Colombia currently has a free convertibility system. If a more restrictive convertibility system is implemented, the Depositary may experience difficulties when converting Colombian Peso amounts into U.S. dollars to remit dividend payments. Also, currently Colombia has a floating exchange rate system that might be subject to change in the future. See section Shareholder Information—Exchange Controls and Limitations.
Holders of our ADSs may not be able to effect service of process on us, our directors, or executive officers within the United States, which may limit your recovery in any foreign judgment you obtain against us.
We are a mixed economy company organized under the laws of Colombia. In addition, most of the members of our Board of Directors and executive officers reside outside the United States. All or a substantial portion of our assets and the assets of these persons are located outside of the United States. As a result, it may not be possible for ADSs holders to effect service of process within the United States upon us or these persons or to enforce judgments against us or them in U.S. courts obtained in such courts predicated upon the civil liability provisions of the U.S. federal securities laws. Colombian courts determine whether to enforce a U.S. judgment predicated on the U.S. securities laws through a procedural system known as exequatur. For a description of these limitations, see section Shareholder Information—Enforcement of Civil Liabilities.
The protections afforded to minority shareholders in Colombia are different from those in the United States and may be difficult to enforce.
Under Colombian law, the protections afforded to minority shareholders are different from those in the United States. While regulation provides, among others, the possibility of initiating class actions against issuers such as Ecopetrol, the legal framework with respect to shareholder disputes is substantially different under Colombian law than U.S. law and there are different procedural requirements for commencing shareholder lawsuits, such as shareholder derivative suits. As a result, it may be more difficult for our minority shareholders to enforce their rights against us or our directors or controlling shareholder than it would be for shareholders of a U.S. company.
ADRs do not have the same tax treatment as other equity investments in Colombia.
Although ADRs represent Ecopetrol S.A.’s common shares, for Colombian tax purposes, ADRs are securities different from their underlying assets. Therefore, ADR holders are not entitled to the tax treatment granted to holders of the common shares. Such tax treatment includes, among others, benefits relating to dividends and to profits derived from sale of Colombian common shares. For further information, see section Shareholder Information—Taxation—Colombian Tax Considerations.
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Judgments of Colombian courts with respect to our ADSs will be payable only in Colombian Pesos.
If proceedings are brought in the courts of Colombia seeking to enforce the rights of ADS holders of common shares, we will be required to discharge our obligation amounts in Colombian Pesos. Colombian law provides that an obligation in Colombia to pay amounts denominated in foreign currency may only be satisfied in Colombian currency at the Representative Market Exchange Rate of the date the judgment is rendered, and such amounts are then adjusted to reflect exchange rate variations through the effective payment date.
The relative volatility and illiquidity of the Colombian securities markets may substantially limit our investors’ ability to sell our ADSs at the price and time they desire.
Investing in securities that are traded in emerging markets, such as Colombia, often involves greater risk when compared to other world markets, and these investments are generally considered to be more speculative in nature. The Colombian securities market is substantially smaller, less liquid, more concentrated, can be more volatile, and subject to greater political, economic and market risk than other securities markets in the United States. As an example, in the past, the value of our shares has experienced sharp intra-day declines, as a result of political risk and the lost in value of the Colombian peso against the dollar. These conditions have triggered declines in our market capitalization and our removal from commonly followed indexes.
As of December 31, 2025, the Colombian Stock Exchange (Bolsa de Valores de Colombia or “BVC” for its acronym in Spanish) had a market capitalization of approximately COP 462,482 billion (USD 122 billion using the rate as of December 30, 2025), and 44% increase when compared to the amount at the end of 2024 considering COP figures. By comparison, the New York Stock Exchange (the “NYSE”) had a market capitalization of USD 45 trillion as of December 31, 2025, and a daily trading volume of approximately USD 274 billion in 2025.
As of December 31, 2025, our shares represented the second highest market capitalization of the BVC accounting for 7.67% of the total MSCI COLCAP index. Measures taken by Ecopetrol in this regard include fulfilling issuer responsibilities through the publication of periodic and relevant information, holding meetings with investors/shareholders, and participating in initiatives/working groups aimed at boosting market liquidity. In November 2022, Ecopetrol was removed from the MSCI Colombia (USD) index due to market variables such as changes in the COP/USD exchange rate and our stock price, which adversely affect an increased market capitalization in U.S. dollars, and therefore affect our compliance with the Minimum Free Float Market Capitalization Requirement of such index. As of the date of this annual report, we cannot determine when we may try to be re-included in the MSCI Colombia (USD) index. Nevertheless, in 2025, Ecopetrol remained in the FTSE Emerging index with a share of 0.0239% in the FTSE Emerging Market Index and 0.0038% in the FTSE Global All Cap Index.
Our subsidiary listed on the BVC, ISA, is also exposed to these risks. As of December 31, 2025, ISA’s shares accounted for 9.08% of the total MSCI COLCAP index.
Given the current ownership structure of our shares, it may be difficult for you to purchase large quantities of shares from a single shareholder. We cannot assure you that a liquid trading market for our ADSs will develop or, if developed, that it will be maintained. Without a liquid trading market coupled with the volatility of the Colombian securities market, the ability of investors in our ADSs to sell them at the desired price and time could be substantially limited.
We are not required to disclose as much information to investors as a U.S. issuer is required to disclose.
We are subject to the reporting requirements set by Law 964 of 2005, Decree 2555 of 2010, the SFC and the BVC. As a “foreign private issuer” under U.S. securities law, the corporate disclosure requirements that apply to us may not be equivalent to the disclosure requirements that apply to a U.S. issuer and, as a result, you may receive less interim information about us than you would receive from a U.S. issuer. However, in June 2025, the SEC issued a concept release soliciting public comment on potential changes to the definition of foreign private issuer. If the SEC were to adopt changes to the foreign private issuer definition, we could potentially lose our status as a foreign private issuer. If we were to lose our foreign private issuer status, we would be required to comply with all of the disclosure and procedural requirements applicable to U.S. domestic issuers, including the preparation of financial statements in accordance with U.S. GAAP, more frequent periodic reporting and compliance with Regulation FD, among others. Such compliance would increase our legal, accounting and other expenses and would require our management to devote substantial time and resources to comply with these additional regulatory requirements.
5.2.5
Our controlling shareholder’s interests may differ, from time to time, from those of certain minority shareholders, or may affect our long-term strategy.
The Nation currently holds 88.49% of our outstanding capital stock, making it our controlling shareholder. The Nation as our controlling shareholder has majority voting rights at the General Shareholders Assembly to elect the members of our Board of Directors and may propose and approve decisions that may be in its own interest and that may not necessarily benefit minority shareholders or be aligned with our long-term strategic goals.
For example, our controlling shareholder may suggest and approve dividend proposals at the ordinary General Shareholders Assembly, notwithstanding the interest of certain minority shareholders, in an amount that results in us having to reduce our capital expenditure or increase our debt levels. In addition, our controlling shareholder may support decisions to undertake projects that may diverge resources from the company’s long-term strategic goals or make announcements about its intentions related to its holding of the Company’s stock, which may not be in our best interest or in the best interest of our minority shareholders, including holders of our ADSs, and could affect the price of our shares or ADSs. Consequently, to the extent permitted by law, the actions of our controlling shareholder may thereby negatively affect our prospects, results of operations, financial condition and credit rating. See section Shareholder Information—Dividend Policy.
5.3
Risk Management
5.3.1
Integrated Risk Management System and Internal Control System
Under the leadership of the Corporate Compliance Department and its Risk Office, in 2025, Ecopetrol S.A. kept strengthening its Integrated Risk Management System based on the international technical standard ISO 31000, which establishes a set of principles, frame of reference and process or cycle that allow the organization to manage the effects of uncertainty on meeting objectives, to maximize opportunities and assist in establishing strategies and making informed decisions.
Our risk management approach consists of four main stages: planning, identifying, evaluating, and managing risks, as well as cross-cutting stages of communication and consulting, record and reporting and monitoring. This cycle is supported by the principles of risk management: integration, continuous improvement, structure, information, culture, organizational structure, and normative and management tools.
Three of our most important tools within our risk management approach are:
Mitigation Plans: Each year, by performing the stages of the risk management cycle, we define and implement mitigation plans to reduce the levels of exposure to risk through mitigation or elimination of some of its causes. Metrics and goals must be defined during the development of each plan to ensure its effectiveness and to prioritize our efforts on those with the greatest impacts.
Monitoring Indicators: As part of the monitoring stage of the risk management cycle, we have implemented Key Risk Indicators (KRIs) which are metrics used to provide early signals of increasing risk exposures. These signals constitute information for preventative decision making to avoid risk materialization.
The Integrated Risk Management System establishes the definition of risk as the effect of uncertainty on the fulfillment our objectives, considering the effect as the deviation positive, negative or both, compared to what is expected. Our risks can be classified as:
Enterprise Risks: Risks that are directly associated with the business strategy plan of the Company and are systematically monitored by the Management Committee. When defining enterprise risks, the analysis of the internal and external environment is carried out to determine the topics and trends that could have potential or real impact on our strategy. The management of those risks is led by the person accountable for the process and each risk has a defined treatment plan and monitoring indicators. Further information can be found on our Enterprise Risk Map on our website.
Processes Risks: Risks that tend to identify potential failures in the activities related to our core and support business processes that drive us to achieve our objectives. At this level, our processes have identified risks with their respective mitigation methods, including financial and non-financial controls, treatment plans and/or monitoring indicators.
Operational Risks: Risks that are at an operational level of detail and occur in our day-to-day activities and tasks.
On the other hand, emerging risks are those that are expected to have a long-term future impact on the company (three to five years and beyond) or, in some cases, have already started to impact Ecopetrol. Emerging risks are considered those that meet some of the following characteristics: (i) the risk is new, developing, or significantly increasing in relevance, (ii) a known risk in a new or unknown context or under re-emerging conditions, (iii) the potential financial or reputational impact of the risk is long-term and significant, (iv) it is an external risk arising from events outside the company’s influence or control, (v) the risk and its impact on the company are specific, and (vi) it has a high potential impact to Ecopetrol S.A. and may require it to adapt its strategy and/or business model.
We have also continued consolidating our internal control systems into a unified system that integrates the best practices called for by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013), Sarbanes–Oxley Act (SOX), governance and management of enterprise IT (COBIT), and our ethics and compliance rules, with the aim of establishing a management system for all control components, thereby allowing us to strengthen all of our control system.
We have also defined guidelines and implemented an Internal Control System (which includes subsidiaries through the subsidiary´s compliance officers), the main purpose of which is to provide reasonable assurance regarding the achievement of all the Company’s objectives relating to operations, strategy, reporting and compliance, through the appropriate risks management and ensuring the effectiveness of our controls and the scope of which includes our subsidiaries. Under those guidelines, each subsidiary must implement and report the performance of its Internal Control System to Ecopetrol S.A. to ensure compliance with the above measures, and the subsidiaries have methodological support from Ecopetrol S.A. when requested. Ecopetrol S.A. also has implemented periodic reporting mechanisms for its subsidiaries to assure all the components and principles of their Internal Control Systems are present and operating. The system performance is systematically monitored by the Board of Directors.
The risk management component of our Internal Control System is in charge of identifying negative events or situations that may affect our defined objectives, assessing and prioritizing them to implement the most appropriate response.
Ecopetrol S.A.’s Internal Control System is aligned to the Company’s strategy and business processes and gives responsibility to all employees to manage risk, to maintain the effectiveness of controls, to report incidents to preventively correct possible deficiencies and to provide reasonable assurance of achieving corporate objectives and goals. The scope of this system includes the Company’s subsidiaries who must implement and report on the performance of its internal control system to the Company to ensure compliance with the above measures.
5.3.2
Managing Low Carbon Economy and Climate Change Risks
To manage and mitigate the risks related to the transition to a low carbon economy and climate change, Ecopetrol, in line with the goal of generating value through TESG, expects to invest around COP 0.9 trillion (3% of 2026 Investment Plan) in non-conventional renewable energy and energy efficiency projects, among others. Approximately 750 MW of additional clean energy generation capacity is expected from projects in operation, construction, and development.
Additionally, we have set shadow price for carbon at USD 40/TCO2 for the years between 2026 and 2029, and USD 50/TCO2 from 2030 onwards which is expected to be used to assess and evaluate current and future projects and investments. To properly adapt the Ecopetrol Group’s business strategy to the transition to a low carbon economy and ensure long-term value creation, we have been conducting energy transition scenario analysis since 2018. In 2023, following the ratification of the 2040 Strategy, three scenarios were constructed to provide a solid and unified frame of reference and to enable us to anticipate and understand the challenges and opportunities of the energy transition. Since 2024, we have started monitoring trends based on these scenarios. The three scenarios developed by Ecopetrol are: (i) Climate Alignment (1.7° - 1.8°C): Transformation to low-emission economies aligns governments and institutions around climate change. In addition, developed countries reach a net zero goal, while other countries follow a slower path. This is not enough to achieve the global net-zero goal of 1.5 ℃; (ii) Energy Balance (1.9° - 2.3°C): Fundamental changes in governments, markets, and society set in motion a long-term energy transition, the debate continues between energy security and accelerating the transition; and (iii) Climate Divergence (2.5° - 2.8°C): Dissimilar interests in decarbonization despite policy, regulation and market changes. Global public policy decisions are insufficient to close the climate ambition gap. See section Strategy and Market Overview—Our Corporate Strategy—2040 Strategy: Energy That Transforms for detailed information on our strategy and carbon shadow price.
Ecopetrol finds it essential to compare the three potential scenarios. While the first and third scenarios do not represent the group’s core vision, assessing different perspectives on the global energy transition remains necessary. According to the 2040 Strategy, Ecopetrol considers the second scenario the most likely, aligning with a gradual energy transition. This transition envisions increased use of low-emission energy sources while retaining conventional energy in the overall energy mix. Additionally, this scenario is expected to enhance sustainability and resilience in energy supply. In this context, the Ecopetrol Group is committed to diversifying its energy portfolio, emphasizing the incorporation of low-emission energy sources, such as renewables and natural gas, to mitigate climate change and reduce reliance on traditional fossil fuels.
In November 2025, we presented our first Ecopetrol Group’s Financial Sustainability Report for 2024, prepared using an approach that integrates the standards of the TCFD and the SASB, highlighting progress in strengthening climate-related risk and opportunity management processes through discussions on governance, strategy, risks, metrics and targets. Our climate risk strategy is also being aligned with IFRS S2 Climate-related Disclosures from the ISSB. In addition, at the end of 2025, the risks associated with climate change, water, and biodiversity were updated in the enterprise risk map.
5.3.3
Information Security and Cybersecurity Management
Ecopetrol S.A. has a dedicated management team specialized in information security issues such as risk analysis, information processing, secure information management practices and classification of critical business information, compliance with control systems, effectiveness of available information security technologies, and third-party management to identify and monitor cybersecurity risks. This is articulated with the ERM system at the enterprise level.
Ecopetrol has established governance mechanisms designed to direct, supervise, and ensure effective information security management across the organization. These mechanisms operate at three levels: (i) oversight by the Board of Directors through two specialized committees (the Technology and Innovation Committee and the Audit and Risk Committee); and (ii) a senior executive role responsible for leading and coordinating the Company’s information security, cybersecurity, and cyber defense strategy in alignment with corporate objectives.
Within this framework, the Board of Directors oversees digital and cybersecurity matters through the Technology and Innovation Committee, which reviews the Group’s digital strategy and the operating model for information security, cybersecurity, cyber defense, privacy, and data recovery. The Audit and Risk Committee, within the scope of its functions, oversees risks associated with cybersecurity and information security threats. In addition, an executive role within the Vice Presidency of Science, Technology, and Innovation is responsible for directing, coordinating, and aligning the cybersecurity and information security strategy with the organization’s objectives.
In accordance with the Internal Regulations of the Technology and Innovation Committee of Ecopetrol S.A., the Board of Directors is informed of cybersecurity risks through the Technology and Innovation Committee. In Chapter 4 – Functions of the Technology, and Innovation Committee, include in Article 10:
The Cybersecurity and Cyber Defense Management is part of the Vice Presidency of Science, Technology and Innovation, reporting to senior management and the Board of Directors of the Company. In addition, as part of Ecopetrol’s cybersecurity management, ongoing training and awareness plans are carried out and implemented with the Board of Directors, senior management, and users in general, as well as specialized training for our cybersecurity team.
Emerging risks at an industrial and global level keep us constantly evolving in our capabilities and improvements in our processes. New technologies and hybrid ways of working expand the cyber threat landscape in critical infrastructures, making this risk necessary for management, monitoring, and improvement.
Ecopetrol S.A. has incorporated cybersecurity risk as one of its main business risks. Currently, there is a Cybersecurity and Defense Management, composed of a highly qualified, certified and high-performance team, which allows Ecopetrol to raise its cybersecurity measures. This team effectively manages and mitigates cybersecurity risks by implementing various activities aimed at identifying and protecting critical digital assets. Through capabilities such as protecting business operations, protecting supply chain, culture, privacy and data, and operational effectiveness in cybersecurity, the team prevents and contains cyber threats, while monitoring and reporting cybersecurity risks globally. In addition, cybersecurity risks and strategy are overseen by the committees of the board of directors, namely the technology and innovation committee and the audit and risk committee.
The cybersecurity team continues to integrate practices aimed at improving risk awareness and adjusting current information security capabilities in response to evolving cyber threats. As a result of this process, we continuously integrate elements related to cybersecurity threat management. These elements cover several aspects, including the proper configuration of storage devices, comprehensive information security controls, development of policies and procedures for information security, specialized monitoring and cyber threat services, vulnerability management, cyber incident response management, deployment of protection tools, monitoring and response to malicious activities, threat hunting, threat intelligence, security by design, and cybersecurity insurance coverage, among others.
Ecopetrol S.A. has a Security Operations Center (SOC) service, to improve the organization’s ability to identify trends in attacks on both its information technology infrastructure and its Operation Technology, while monitoring its online reputation. Throughout 2025, SOC capabilities remained operational, with a scope of services covering Operation Technology (OT) digital assets. Cybersecurity risk assessments and advanced security testing exercises (RedTeam) carried out on the IT/OT infrastructure of Ecopetrol and its subsidiaries were included, which allowed identifying gaps to improve the overall cybersecurity posture. In addition, specialized monitoring capabilities such as user behavior analysis remain. Although cyberattacks occurred during 2025, all reported events were successfully controlled, with no material effects on processes, equipment, products, services, customer or supplier relationships, competitive conditions, or critical information.
We updated our cybersecurity policies and cyber incident response procedures, by developing wargames that cover several of the business segments and their subordinates. These exercises document how to manage the activation of the cyber insurance policy, the unified command post and the operating model for cyber incident response with Ecopetrol’s internal teams. The action protocol for business crisis scenarios is also regularly reviewed, establishing timely notifications and communication processes with internal and external entities, as well as the roadmap to define and analyze the materiality of a cybersecurity incident. The cyber incident management guide includes the roles, responsibilities, and activities of those involved in responding to a cybersecurity event or alert.
In addition, during 2025, the internal audit department carried out audits of cybersecurity processes to follow up on previous improvement plans. Consequently, action plans were developed to address the identified findings.
Ecopetrol S.A. remains committed to the NGO-C2M2 framework (Cybersecurity Oil and Gas Capability Maturity Model) to manage its maturity and maintain its cybersecurity management system. This involves implementing practices and focusing our capabilities on domains such as information protection, cyber incident response, third-party cybersecurity management, and architecture.
Ecopetrol S.A. has also strengthened its cybersecurity capabilities in 2025 by continuing to incorporate fundamental “Zero Trust” practices and critical information protection controls to mitigate cyber risks in its business units. Another significant initiative throughout 2025 was the cultural awareness campaign focused on three management pillars: (i) training, which consists of the development of new skills, (ii) mobilization, which consists of the promotion and appropriation of change, and (iii) communication, which consists of the promotion of understanding and conviction of behaviors). In addition, the information life cycle was executed to identify, evaluate and manage cybersecurity risks associated with critical information assets and the Ecopetrol Group CSIRT (Cyber Incident Response Center) was inaugurated, which strengthens coordination with public and private entities in the management of cybersecurity incidents. This initiative made it possible to evolve the cybersecurity model leveraged on threat profiling and reduce the detection times of cybersecurity events and incident response times using emerging technologies such as machine learning and artificial intelligence.
The integrated cybersecurity and cyber defense plan defined for the period 2025 to 2040, which applies to a quantitative cyber risk model, was updated and aligned with the integrated plan for Science, Technology and Innovation, as well as with the Ecopetrol Group’s 2040 strategy. The integrated cybersecurity and cyber defense plan includes the following four pillars:
Digital trust: To promote excellence, innovation and cyber collaboration, putting the customer, the Ecopetrol Group and the supply chain at the core of every decision.
Cyber resilience: To strengthen the capacity to respond to cyberattacks and ensure continuous monitoring of cyber activities, covering intelligence, visibility, response and recovery.
Efficiency and Consolidation: To protect data and privacy, establish ethical guidelines and ensure the safe use of artificial intelligence, promoting privacy and ethics in the handling of AI.
Industrial Protection: To include security measures that optimize the comprehensive protection of information and industrial infrastructure, promoting defense and collaboration.
Ecopetrol has an analytics and artificial intelligence policy that establishes the ethical principles the Company follows: transparency, fairness, risk management, privacy, the role of humans, and accountability for AI systems. The policy also identifies key technical risk groups to mitigate when implementing AI projects, such as: risks from poor quality, biased, unrepresentative, or inappropriate data that can impact model accuracy; issues in algorithm development and training; lack of expertise leading to bias or degraded predictions; exposure of models to malicious actors or spurious patterns; risks associated with sharing personal information or data with analytics and AI models; non-compliance with regulations due to limited knowledge among development teams; overlooking variables and perspectives, which may result in adverse organizational decisions through model bias; and risks to confidentiality from using unclassified data and lacking security measures.
The Board of Directors oversees matters related to the adoption and responsible use of artificial intelligence through the Technology and Innovation Committee, which serves as a permanent supporting body. Specifically, the Board receives and evaluates, with prior analysis and recommendations from the Committee, strategic issues concerning technology and innovation, including the use of emerging technologies, digital strategy, and operating models associated with information management, cybersecurity, privacy, and data protection. In this way, the Board of Directors guides and ensures that the adoption of new technologies—such as AI—is carried out in alignment with the corporate strategy, under principles of corporate governance, risk management, and regulatory compliance, guaranteeing responsible and secure use consistent with the interests of the Company and the Ecopetrol Group.
At Ecopetrol, the management of artificial intelligence within the field of Cybersecurity is structured on a comprehensive approach that combines risk analysis, strengthening of technical capacities and development of human talent. For the period 2025–2026, the organization has established a set of actions to ensure the responsible, safe and resilient use of AI-based technologies.
First, an analysis of emerging risks associated with AI is carried out, which includes the identification of vulnerabilities in AI systems, as well as the evaluation of the operational and strategic risks that these technologies can introduce into the corporate environment.
At the same time, the adoption of technologies, tools, and new AI-based approaches aimed at strengthening cybersecurity and information security is being promoted, with the purpose of increasing the capacity for defense, monitoring, and protection of the digital ecosystem.
Likewise, cybersecurity controls aligned with Artificial Intelligence Secure Threat Risk (AISTR) are implemented, which strengthen the capabilities of identification, detection, protection, response and recovery against threats related to AI systems, guaranteeing a safe and resilient operation.
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Finally, the strategy contemplates people’s awareness, promoting, safe use and consumption of services based on artificial intelligence. This human component is essential to ensure the mature adoption of AI and prevent risks arising from the lack of knowledge or inappropriate use of these technologies.
5.3.4
Managing Financial Risk
We are exposed to certain risks associated with the nature of our operations and the financial instruments we use. Among the risks that affect our financial assets, liabilities and expected future cash flows are changes in commodity prices, currency exchange rates, interest rates and the credit quality of our counterparties.
Commodity price risk is associated with our day-to-day operations as we export and import crude oil, natural gas, and refined products. We occasionally use hedges to partially protect our financial results from price fluctuations considering that part of our financial exposure under sale and purchase contracts for crude oil and refined products depends on international oil prices. We believe that the risk of such exposure is partially naturally hedged since we are an integrated group (with operations in the exploration and production, refining and petrochemicals, transport and logistics and energy transmission and toll roads concessions segments) and either export crude oil at international market prices or sell refined products at prices that are correlated to international market prices. During 2025, Ecopetrol S.A. and Refinería de Cartagena S.A.S executed strategic commodities hedging operations oriented to mitigate the impact on financial results of the companies for a total of 18.5 million barrels; additionally Ecopetrol S.A., Ecopetrol Trading Asia Pte Ltd, Ecopetrol US Trading LLC, Esenttia S.A. and Refinería de Cartagena S.A.S executed tactical hedging operations due to its exposure to pricing indices different from the commercialization benchmark and different pricing periods between the buying and the selling or processing of physical barrels. A total of 43.2 million barrels and 4.4 million pounds were the subject of tactical hedges oriented at mitigating risks associated with crude oil or commodity imports, supply to refineries and international sales delivered at the destination port. We do not use
for speculative or profit-generating purposes.
Currency risk arises in our operations given the fact that most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars. Therefore, when the Colombian Peso depreciates against the U.S. dollar, our revenues converted into Colombian Pesos increase. Conversely, when the Colombian Peso appreciates against the U.S. dollar, our revenues decrease. On the other hand, imported goods, oil services and the debt, which is mainly denominated in U.S. dollars, become less expensive when the Colombian Peso appreciates against the U.S. dollar and more expensive when the Colombian Peso depreciates against the U.S. dollar.
As of December 31, 2025, out of our total debt of USD 28.3 billion, debt denominated in U.S. dollars (USD 21.1 billion) and other currencies (USD 4.4 billion) amounted to USD 25.5 billion in principal. This amount is recognized in our consolidated financial statements at amortized cost, corresponding to the present value of cash flows discounted at the effective interest rate. Of this total, USD 17.8 billion is owed by Ecopetrol S.A., whose functional currency is the Colombian Peso. Therefore, when the Colombian Peso depreciates against the U.S. dollar, the Colombian debt denominated in Colombian Pesos increases year-over-year, and Ecopetrol S.A. is exposed to an exchange rate loss. In contrast, when the Colombian Peso appreciates against the U.S. dollar, the Colombian debt denominated in Colombian Pesos decreases year-over-year, and Ecopetrol S.A. is exposed to an exchange rate gain. Some of the Ecopetrol Group’s subsidiaries have the U.S. dollar as functional currency and are not exposed to a material exchange rate risk resulting from fluctuations in the Colombian Peso against the U.S. dollar. On the asset side, when the financial statements of the Ecopetrol Group are consolidated, the exchange rate differential of the subsidiaries’ assets and liabilities whose functional currency is the U.S. dollar is recognized directly in equity, as part of other comprehensive income. The total consolidated debt expressed in Colombian Pesos as of December 31, 2025, decreased 10.3% on a year-to-year basis, meanwhile the total debt denominated in U.S. dollars and other currencies (excluding debt denominated in Colombian pesos) increased by 3.5%, explained by the effect of exchange rates.
Taking previous considerations into account, we seek to identify and manage currency risk in a comprehensive manner, using an integrated analysis of natural hedges to benefit from the correlation between income or investments in a foreign operation and debt denominated in foreign currency. We adopted accounting hedge as part of our risk management strategy, using two types of natural hedges with our U.S. dollar denominated debt as a financial instrument: (i) cash flow hedge for exports of crude oil, and (ii) hedge of a net investment in a foreign operation. In addition, we may involve the use of financial derivative instruments, and non-derivative financial instruments. As a part of its risk management strategy, using the natural hedge between exports and dollar-denominated debt, in October 2015, USD 7.3 billion of Ecopetrol S.A.’s debt in U.S. dollars was designated as hedge instrument of its future export sales for the period 2015 – 2025. In 2023, Ecopetrol S.A. hedged (i) a new portion of the dollar-denominated debt against future revenues in an amount of USD 1.9 billion, and (ii) USD 2.2 billion with its foreign investments and future revenues. In 2024, Ecopetrol S.A. hedged (i) a new portion of the dollar-denominated debt against future revenues in an amount of USD 1.1 billion, and (ii) USD 0.6 billion with its foreign investments and future revenues. In 2025, no new accounting hedges were designated.
As of December 31, 2025, the outstanding value of the natural accounting hedges was USD 17.0 billion. With the adoption of hedge accounting, the effect of the volatility of the foreign exchange rate on the hedged portion of the debt is highly mitigated and is recognized directly in equity, as part of other comprehensive income.
In addition, we may involve the use of financial derivative instruments, and non-derivative financial instruments. During 2025, Ecopetrol S.A. executed strategic currency hedging operations for a total of USD 1.27 billion.
The remaining portion of our dollar-denominated debt, as well as the financial assets and liabilities denominated in foreign currency continue to be exposed to the fluctuation of the exchange rate. Finally, the Company maintains enough cash in Colombian pesos and U.S. dollars to meet its expenses in each currency (see Note 4.1.5 to our financial statements for further explanation of our accounting policy and Note 30.1 for details of the hedge accounting adopted).
Interest rate risk arises from our exposure to changes in interest rates mainly because of the issuances of floating rate debt linked to SOFR, CPI, IPCA, IBR, CDI and others (with 13.4%, 4.9%, 7.5%, 4.6%, 2.4%, and 1.0% respectively, of the nominal debt balance as of December 31, 2025). Thus, volatility in interest rates may affect the fair value of and cash flows related to our investments and floating rate debt. For 2025 our analysis of credit risk events and global financial markets led us to decide not to hedge interest rate risk. Nevertheless, our capital markets office continuously monitors the performance of interest rates and the effect of interest rates on our financial statements.
The trust funds linked to Ecopetrol S.A.’s pension obligations (PAP for its acronym in Spanish) are also exposed to changes in interest rates, as they include fixed and floating-rate instruments that are marked to market. This exposure is continuously monitored by our treasury office given the potential impact volatility may have on our financial results. The treasury office’s information is gathered from reports provided by the asset managers. These reports refer to regulatory limits as well as market, credit and liquidity risks. The investment guidelines with respect to the PAPs are issued by the Colombian regulation for pension funds, as stipulated in Decree 941 of 2002 and Decree 1913 of 2018, where it is indicated that they must follow the same regime as the regular obligatory pension funds in their moderate (i.e., neither conservative nor aggressive) portfolio. For further information regarding the trust funds linked to the pension obligations of the company, see Note 30.8 to our consolidated financial statements.
Regarding liquidity risk, Ecopetrol S.A. forecasts and monitors its cash position daily to review updated expectations for liquidity conditions and the capacity to attend short term obligations. This forecast mainly includes operational income and expenses, capital expenditures expectations, debt and dividend related cash-flows, and other financial cash movements. Additionally, on a monthly basis, management and the Board of Directors review cash evolution, availability and forecasts under Brent scenarios.
Finally, counterparty risk is the potential probability that a borrower or counterparty defaults on any obligation. In our case, we are exposed to this risk as we invest in different financial instruments and receive letters of credit to mitigate our exposure to our commercial counterparties. We manage this risk by monitoring and analyzing the counterparty’s creditworthiness, stock price behavior, spreads on credit default swaps, probability of default, among others.
Hedging guidelines for Ecopetrol S.A. and its subsidiaries
Ecopetrol S.A.’s management established a set of guidelines for hedging strategies for Ecopetrol S.A. and its subsidiaries. These guidelines allow us to use financial instruments to mitigate the impacts in our financial statements as a result of the fluctuation of risk factors, such as commodity prices, exchange rates, interest rates and others.
These guidelines determine general principles governing hedging operations, corporate governance, the process for implementing operations which includes the identification of risk exposition as an integrated group, the identification and design of the financial structures, and execution and monitoring, among others.
The guidelines also include a list of allowable financial assets, such as forwards, futures, options, and swaps and describe the differences between strategic and tactical hedging, where the former focus on protecting our financial results from market volatility and the latter is mainly designed to hedge the market risk of specific trading in physical markets.
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Investment Guidelines Ecopetrol S.A.
Ecopetrol S.A.’s management established guidelines for our investment portfolios. These guidelines determine that investments in Ecopetrol S.A.’s U.S. dollar portfolio and the Colombian Peso portfolio may be invested in fixed income securities issued by entities with a rating equal to or greater than Ecopetrol S.A’s credit risk rating, as rated by any of the internationally recognized rating agencies (Standard & Poor’s, Moody’s, and Fitch Ratings). In order to diversify risk in both our U.S. Dollar and Colombian Peso portfolios, Ecopetrol S.A.’s management will determine both short- and long-term limits by issuer and issuance based on internal analyses and external risk ratings.
Additionally, the portfolios in U.S. Dollar and Colombian Peso of Ecopetrol S.A. is expected to be segmented in the tranches determined by Ecopetrol S.A.’s management, meeting the Company’s working capital and liquidity needs, benchmarks and cash flow projections.
Legal Proceedings and Related Matters
We are a party to various legal proceedings in the ordinary course of business. Other than the proceedings disclosed in this annual report, we are not involved in any pending (or, to our knowledge, threatened) litigation or arbitration proceeding that we expect to have a material adverse effect on our Company. Other legal proceedings that are pending against or involve us and our subsidiaries are incidental to the conduct of our and their business. We believe that the ultimate disposition of such other proceedings individually or in an aggregate basis will not have a material adverse effect on our consolidated financial condition or results of operations.
As of December 31, 2025, Ecopetrol S.A. was a party to 7,827 legal proceedings relating to civil, criminal, administrative, tax, constitutional, arbitration and labor claims, out of which 5,380 were filed against us in the Colombian courts and arbitration tribunals, of which 400 had an accrual provision. We allocate enough money and time to defend these claims. Historically, we have been successful in defending lawsuits filed against us. Other than the environmental administrative proceedings described in the last paragraph of this section, based on the advice of our legal advisors, it is reasonable to assume that the litigation procedures brought against us will not materially affect our financial position or solvency regardless of the outcome. See Note 23 to our consolidated financial statements included in this annual report for a discussion of our legal proceedings.
Caño Limón – Coveñas Crude Oil Pipeline Spill
On December 11, 2011, the Caño Limón - Coveñas oil pipeline ruptured and caused the spill of approximately 3,267 barrels of crude oil into the Iscala creek, which connects with the Pamplonita River that provides water to the city of Cúcuta. The incident did not cause any fatalities or injuries.
In 2012, a class action lawsuit was filed against Ecopetrol S.A. and against employees of the Company, and the First Administrative Court of Cúcuta has jurisdiction to conduct the case, which is in the evidentiary stage, pending a first instance judgment.
The Regional Environmental authority of Norte de Santander, or Corporación Autónoma Regional de la Frontera Nororiental (CORPONOR) also filed a lawsuit against Ecopetrol S.A. before the Administrative Court of Norte de Santander claiming for (i) the environmental loss caused by the incident and (ii) for compensation costs relating to the environment damage for approximately COP 33 billion. Ecopetrol S.A.’s legal counsel filed a motion to dismiss the lawsuit on June 2, 2014, based on three grounds: (i) there is no proof of environmental loss, (ii) CORPONOR does not have the authority to file this lawsuit and (iii) CORPONOR’s petition for direct compensation is not the proper legal action according to the applicable procedural rules. In July 2020 the evidentiary stage closed. On July 27, 2023, the Administrative Court of Norte de Santander issued its ruling and denied the compensation claims for damages by CORPONOR. As of the date of this annual report, no appeal has been filed in connection to this decision.
Ecopetrol S.A. and national and local authorities agreed to develop a project consisting of an alternative to the water supply intake of the aqueduct in Cúcuta. In December 2011, our Board of Directors approved our participation in the project as part of the support of our contingency plans and relationship with stakeholders. On November 10, 2017, an agreement was signed with the purpose of building the alternative water supply at a cost of approximately COP 425.09 billion. According to the agreement, we oversee the construction of the aforementioned infrastructure. As of the date of this annual report, the construction projects continue their progress. Their statuses are currently the following: (i) for subproject 1, the initial delivery process was made official to the municipality of Cúcuta and overall progress is of 100%, and (ii) for subprojects 3 and 4, the infrastructure corresponding to the gantry and storage tanks has been delivered, the commissioning of the sludge treatment system is underway, and overall progress stands at 98.7%.
BT Energy Challenger
On October 22, 2014, we were served with a class action suit against us seeking monetary damages of approximately COP 7.4 trillion related to an incident that occurred on August 21, 2014, during the loading operations of the BT Energy Challenger vessel. The claimants alleged possible damage to the port area of Ecopetrol S.A.’s terminal in Coveñas, as well as of marine and submarine areas and beaches that form the geographical area of the Morrosquillo Gulf. This allegation is currently under investigation by the Harbor Master of Coveñas. Ecopetrol S.A. filed a motion requesting the judge to require the claimants to amend their claim to more precisely set forth the facts and evidence that allegedly support Ecopetrol S.A.’s liability.
On March 3, 2015, Ecopetrol S.A. filed its statement of defense arguing the exclusive fault of a third party. On October 20, 2015, the Court denied a class action of more than 100 informal traders in the region because there is no common identity with the initial class (hotel employees). However, during 2016 the Sucre Administrative Court accepted another 1,208 informal traders and fishermen as claimants.
On March 10, 2017, a mandatory settlement hearing was held to seek an agreement, but it failed.
In January 2018, a judicial order was issued to commence the evidence production phase, a decision which was objected to by the parties.
In September 2018, all the ordered statements were made, the evidentiary stage was finalized, and the parties filed their final closing arguments.
Afterwards, once the requests and appeals were resolved, the Court admitted the evidence, closed the evidentiary period, and the final arguments were presented. The closure of evidentiary period was appealed by several parties on the grounds that it was premature.
As of the date of this annual report, a first instance judgment is pending. The Court has consolidated several process-related judicial proceedings related to the class action suit, despite some objections and annulment motions from some of the parties involved and is currently reviewing the arguments on the appeals against its decision.
Class Action and Constitutional Protection Claim of the AWA Indigenous Community
Class Action
On April 2, 2018, a class action lawsuit was filed against Ecopetrol S.A. and Cenit by the Inda Guacaray and Inda Sabaleta reservations of the AWA Indigenous community who claim damages to their communities by environmental contamination and damage to natural resources that the defendants supposedly caused by act or omission during various environmental incidents. In August 2018 Ecopetrol S.A. answered the complaint.
On November 14, 2020, the Administrative Court of Cundinamarca declared that an inadequate claim was filed by the AWA community, considering that the claims related to the re-establishment of measures specific to restitution, rehabilitation, satisfaction and guarantees of non-repetition, could not be sought through a class action.
Although the plaintiffs did not clearly determine the amount of their claims, Ecopetrol S.A. and the National Agency for Legal Defense of the State (Agencia Nacional de Defensa Jurídica del Estado or “ANDJE”) had initially estimated the amount to be approximately COP 358,201,371,800.
On July 9, 2025, the conciliation hearing was held. However, the parties did not reach an agreement. Although the evidentiary stage was meant to start, by means of writ dated December 5, 2025, the Tribunal admitted the amendment of the complaint that had been filed by the plaintiffs in August 2022. The writ was challenged by Cenit, and the motion of reconsideration is still pending to be decided.
Constitutional Protection Claim
In February 2024, the AWA people filed a constitutional protection action against Ecopetrol, Cenit and other entities, for the alleged violation of the fundamental rights to a healthy environment, health, water, food, rights of future generations and comprehensive reparation of the plaintiffs, due to crude oil spills that have occurred in their territory derived, mainly, from the installation of illicit valves and the perpetration of terrorist attacks on the Pipeline Transandino (“OTA”). Therefore, the lawsuit invokes the same facts and claims of the class action that was filed by the same Indigenous people. The constitutional protection lawsuit, which was denied in the first and second judicial instances, was revoked by the Constitutional Court.
In the abovementioned judgement, the court ordered Cenit and Ecopetrol to maintain the suspension of the OTA operations until at least five conditions are met: (i) access to potable water is guaranteed for the affected communities; (ii) the baseline diagnostic study of the contamination caused by the spills is finalized; (iii) a comprehensive risk analysis is conducted, covering all impacts derived from the development of the operation; (iv) all appropriate measures are adopted to prevent threats or risks of spills and the safety of the affected people is guaranteed; and (v) the possibility of changing the route or location of the pipeline is studied. No financial reparations were ordered.
Reficar Class Action Lawsuit
On September 30, 2022, Ms. Yira Paola Ramos Avendaño and 48 others filed a lawsuit seeking damages against current and former officials of Ecopetrol S.A. and Reficar, alleging cost overruns and irregularities during the expansion and remodeling of the Cartagena Refinery. The claims were estimated at USD 5,106,000,000. The Administrative Court of Cundinamarca admitted the lawsuit on December 12, 2023, and ordered Reficar and Ecopetrol to appear in court. On February 4, 2025, the court declared null and void the order that mandated the summons and ordered the inclusion of Ecopetrol and Reficar as interested third parties. This order was upheld on reconsideration and appeal, and on July 1, 2025, Ecopetrol responded to the lawsuit and filed preliminary objections.
Helicol
The dispute emerged after the Ecopetrol Group companies (Ecopetrol, Cenit, ODL, ODC, and Ocensa) terminated early, on March 3, 2025, the CW215358 synergy contract signed by them and Helicol, as well as the individual contracts derived from the synergy contract (including, among others, Ecopetrol contract CW215366), which were intended to provide helicopter air transport services for the Ecopetrol Group. In this regard, the aforementioned companies found that Helicol breached its obligations relating to the preparation of the requirements necessary to initiate operations on the agreed date, without having been able to prove its alleged diligent and good-faith conduct, since its actions were untimely and incomplete, and, on the other hand, the existence of an exemption from liability, because the administrative delay by the Civil Aviation Authority did not constitute an irresistible, unforeseeable, or external cause.
As a result of the early termination of the contracts, on July 22, 2025, Helicol filed suit against the group companies through the contract disputes proceeding, primarily seeking a declaration that it had duly and in good faith complied with the obligations incumbent upon it, among other relief, and requesting that the defendants be ordered to pay the corresponding damages.
On December 9, 2025, Ecopetrol filed its statement of defense and brought a counterclaim seeking that Helicol compensate it for the losses caused by Helicol’s breach, as well as payment of the penalty (liquidated damages) clause agreed in the synergy contract and in contract CW215366.
On January 14, 2026, Helicol amended its complaint, mainly to correct one of its claims and to supplement the facts and evidence. By order dated February 2, 2026, notified on February 3, 2026, the aforementioned amendment to the complaint filed by Helicol was admitted, and the defendants were served notice to respond thereto.
Environmental Administrative Proceedings
As of December 2025, Ecopetrol S.A. was part of 172 environmental administrative proceedings, of which 168 were initiated before 2024 and five during 2025. It is not possible for us to determine whether the pending proceedings could have a material effect on Ecopetrol S.A. During 2025, 12 proceedings were concluded, in one of them, we were subject a COP 93,703,928 monetary fines through ANLA Resolution 0739 of April 16, 2025.
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Ecopetrol’s stake in Offshore International Group investigation
In 2009, Ecopetrol acquired a 50% ownership interest in Offshore International Group Inc. (OIG). OIG carries out crude oil exploration and production activities in Peru. This equity interest was recognized as an investment in a joint venture (entity over which the Ecopetrol Group had significant influence but did not control and as a result was not considered an affiliate or subsidiary) and recorded using the equity method of accounting. On January 19, 2021, Ecopetrol consummated the sale of all of its shares in OIG.
On December 7, 2022, the Office of the Comptroller General (Contraloría General de la República) commenced a formal investigation (Proceso de Responsabilidad Fiscal) against certain members of OIG’s Board of Directors, which as of the date of this annual report, is ongoing. According to the Comptroller General’s public statements, the investigation relates to “possible insufficient oversight of the investment by the members of OIG’s Board of Directors to prevent the materialization of related risks”.
As of the date of this annual report, the Office of the General Comptroller’s investigation names two former members of senior management—the Chief Operating Officer of Ecopetrol (until May 2024), and the Chief Executive Officer of Cenit S.A. (until July 2024), in each case, in their capacity as members of OIG’s Board of Directors.
Although the content and status of the investigation is confidential, Ecopetrol has collaborated and provided the information requested by the General Comptroller’s Office, and Ecopetrol is not aware of any allegations related to acts of corruption, bribery or fraud in connection therewith.
Reficar Investigations
According to Colombian regulations, Ecopetrol and Reficar employees are public servants, and as such can be held liable for negligent use or mismanagement of public funds. In this context, given that Ecopetrol is majority owned by the Colombian Government and Reficar is a wholly owned subsidiary of Ecopetrol, Ecopetrol and Reficar administer public funds.
As a result, Ecopetrol and Reficar employees are subject to the control and supervision of the following control entities, among others:
The Office of the Comptroller General (Contraloría General de la República) oversees the adequate use of public funds and has the authority to investigate public employees or private sector employees that manage public resources.
The Attorney General’s Office (Procuraduría General de la Nación) supervises compliance with applicable law by public employees and private sector employees that carry out public functions. The Attorney General’s Office investigates and sanctions individuals for such compliance failures.
The Prosecutor’s Office (Fiscalía General de la Nación) investigates infringements and prosecutes alleged crimes before the court in judicial proceedings.
The following are the most significant investigations and proceedings carried out by the Office of the Comptroller General and the Prosecurtor’s Office. All investigations and proceedings by the Attorney General’s Office and the Office of the Comptroller General closed on 2024 without liability for Ecopetrol (for information on such proceedings by the Attorney General’s Office, see our annual report on Form 20-F for the fiscal year ended December 31, 2024, filed with the Securities and Exchange Commission on April 23, 2025).
The Office of the Comptroller General’s investigations and proceedings.
Because of the amendment of the schedule and budget related to Cartagena refinery’s expansion and modernization project (the “Project”), the Office of the Comptroller General conducted a special audit action of the Project in 2016 and issued a final report to Reficar on December 5, 2016. The report detailed 36 findings, most of which were related to increased costs compared to the budget for services, labor and materials. As requested, Reficar executed an action plan addressing the 36 findings. See our annual report on form 20-F for the fiscal year ended December 31, 2024 for further information regarding the Attorney General’s Office decision on December 10, 2021, in relation to the 36 findings.
As a result of the findings described above, on March 10, 2017, the Office of the Comptroller General opened an investigation pertaining to the financial responsibility (proceso de responsabilidad fiscal) of 36 individuals involved in the Project, including former members of Ecopetrol’s Board of Directors, former members of Reficar’s Board of Directors, former employees of Ecopetrol S.A., and former employees of Reficar, along with four contractors who provided their services during the execution of the Project CB&I Americas Ltd., CB&I UK Limited, CBI Colombiana S.A. and, Foster Wheeler USA Corporation and Process Consultants Inc.
These investigations were conducted based on the Office of the Comptroller General’s thesis that lower than expected profitability at Reficar could have been caused by (i) amendments to the schedule and, (ii) the increase of the budget for the Project.
On June 5, 2018, the Office of the Comptroller General split the initial proceeding into two different proceedings. The first one is related to the increase in the Project’s budget and the second one is related to the lost profits due to extension in the Project’s schedule:
1.2.1.
Regarding the first proceeding, on June 5, 2018, the Office of the Comptroller General indicted: (i) 15 individuals, which include former members of Reficar’s Board of Directors, a former employee of Ecopetrol, and former employees of Reficar, (ii) CB&I Americas Ltd., CB&I UK Limited, CBI Colombiana S.A., Foster Wheeler USA Corporation and Process Consultants Inc, and the following insurance companies, Compañía Aseguradora de Finanzas S.A, Coaseguro Confianza S.A., Liberty Seguros S.A., CHUBB de Colombia Compañía de Seguros S.A., Seguros Colpatria S.A. and Mapfre Seguros Generales de Colombia S.A., as third parties with joint liability.
As for the other 21 individuals initially investigated in 2017, the Office of the Comptroller General closed the investigations.
On April 26, 2021, the Office of the Comptroller General decided on the charges for violation of financial responsibility for an amount of COP 2.95 trillion in connection with the approval of the capital expenditure modifications to the Project. This decision was made against seven former members of Reficar’s Board of Directors, five former Reficar employees, four contractors that rendered their services during the execution of the Project and four insurance companies. They were found liable among others, for: (i) having approved of additions to the Project’s capital expenditure, knowing that the value proposition and profitability of the investment would be affected; (ii) not having ensured the adequate application of the business group investment guidelines. See our annual report on Form 20-F for the fiscal year ended December 31, 2024 for additional detail on the Attorney General’s Office pronouncement issued on May 4, 2021.
Nonetheless, in the ruling there was no allegation related to acts of corruption, bribery or fraud. As of the date of this annual report, no current or former member of Ecopetrol’s Board of Directors has been charged or found guilty in the first proceeding related to the increase in the Project budget.
The decision is of an administrative nature. Consequently, those deemed financially responsible have filed lawsuits before the judges of the Republic of Colombia to seek the annulment of the ruling. In connection with one of these lawsuits related to Hernando José Gómez Restrepo, a former member of the Board of Directors of Reficar from March 29, 2012 to April 19, 2013, on November 8, 2024, the Administrative Court of Cundinamarca issued a first-instance judgment annulling the decision of the Office of the Comptroller General, citing, among other reasons, the absence of pecuniary damage. The annulment of the Comptroller General’s decision applies exclusively to Mr. Hernando José Gómez Restrepo. On December 13 and 18, 2024, the Office of the Comptroller General and the Attorney General’s Office filed appeals against the judgment. The appeals will be decided by the High Court for Administrative Matters (Consejo de Estado). Reficar is not a party to these legal proceedings.
1.2.2.
In relation to the second proceeding, on February 3, 2022, the Intersectoral Delegate Comptroller’s Office concluded the investigative proceedings, with a favorable decision for the individuals that were under investigation.
1.3.
The Office of the Comptroller General also ordered the commencement of an additional investigation in relation to amounts executed in the Project and its sources of funding. In this investigation, on August 24, 2021, the Comptroller’s Office started a new financial responsibility proceeding pursuant to which eight former employees of Reficar are under investigation (three former presidents and five former financial vice presidents).
In February 2023, the Office of the Comptroller General conducted a special visit to the refinery to investigate expenses related to the destination of financial costs, among others, which according to the Comptroller’s Office, entered the project, and their allocation remained unidentified. On April 14, 2023, the Office of the Comptroller General released a technical report of the visit, which, based on information provided by Reficar, concluded that all expenses were properly identified, supported, and associated with services provided by third parties.
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On April 19, 2023, it was mandated to include the technical report in the process and make it accessible to the parties involved in the proceedings.
Subsequently, on October 2, 2024, the proceedings were formally closed. The Intersectoral Delegate Comptroller 15 determined that the facts in the case did not constitute damage to public assets.
Currently there is no allegation related to acts of corruption, bribery, or fraud.
As of the date of this annual report, both Ecopetrol and Reficar have not been found liable under these proceedings.
1.4.
From 2017 to 2024, the Office of the Comptroller General conducted and reported on special and financial audits of Reficar, concluding that the company’s financial statements from 2016 through 2023 did not reasonably reflect its financial position as of each year-end. This situation stemmed from differing interpretations of the applicable accounting principles.
However, on May 22, 2025, the Office of the Comptroller General issued the financial audit report for fiscal year 2024, concluding that Reficar’s financial statements do reasonably present, in all material respects, the company’s financial position as of year-end 2024. The report also confirmed that Reficar’s internal controls are adequate and effective.
As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar are not part of the Comptroller General proceedings.
The Prosecutor’s Office investigations:
The Prosecutor’s Office has been conducting the following legal proceedings in which Ecopetrol and Reficar have been recognized as victims:
Between July 25 and August 2, 2017, the Prosecutor’s Office indicted the following individuals with charges, the majority of which are related to offenses against the public administration and illegal interest in the execution of agreements: (i) Orlando José Cabrales Martínez (Reficar CEO, 2009-2012); (ii) Reyes Reinoso Yánez (Reficar CEO, 2012-2016); (iii) Felipe Laverde Concha (Reficar General Counsel, 2009-March 2017); (iv) Pedro Alfonso Rosales Navarro (Ecopetrol S.A. Downstream Executive Vice President, 2008-2015); (v) Masoud Deidehban (CB&I Executive Project Director); (vi) Phillip Asherman (CB&I CEO) and (vii) Carlos Lloreda (Reficar’s statutory auditor from 2013-2015). The arraignment hearing began on May 30, 2018, and concluded on August 22, 2019.
The Prosecutor’s Office made public the factual basis for such charges. On May 9, 2017, Ecopetrol’s audit and risk committee retained a U.S.-based outside law firm to commence a third-party investigation into the matters set forth in the Prosecutor’s Office announcement. The results were presented in December 2017 to Ecopetrol’s audit and risk committee. This investigation concluded that to date there has been no evidence of possible unlawful acts that affect Ecopetrol’s internal control over the financial reporting of the Company, on the allegations made by the Prosecutor’s Office.
The preparatory trial hearing took place between November 25, 2019 and February 2, 2024. The evidentiary stage concluded on November 14, 2025. Additional hearings are scheduled for April 2026, during which the parties are expected to present their closing arguments.
As of the date of this annual report, no member of Ecopetrol’s current management team, nor the current Boards of Directors of Ecopetrol or Reficar are subject to this process.
On October 22 and 23, 2018, the Prosecutor’s Office indicted the following individuals with charges related to improper management and obtaining false public documents: Javier Genaro Gutiérrez Pemberthy (Ecopetrol S.A. CEO, 2007-2015), Reyes Reinoso Yánez (Reficar CEO, 2012-2016), Pedro Alfonso Rosales Navarro (Ecopetrol S.A. Downstream Executive Vice President, 2008-2015), and Diana Constanza Calixto Hernández (Ecopetrol S.A. Head of the Corporate Finance Unit, 2009-2014). In the arraignment hearing that took place on August 5, 2019, Ecopetrol and Reficar were recognized as victims.
The Prosecutor’s Office made public the factual basis of the charges, which is based on the theory that the indicted directors hid necessary information from Ecopetrol’s Board of Directors before the approval of amendment No. 3 of the internal budget of the project (Control de Cambio No. 3).
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The trial hearing commenced on October 28, 2024. During the hearing, defense attorneys sought the dismissal of the investigation, citing the expiration of the statute of limitations for the criminal action. However, the presiding judge denied the request. The defense attorneys subsequently filed appeals. On December 10, 2024, the Superior Court of Bogotá upheld the lower court’s decision, ordering the continuation of the oral trial.
As of the date of this annual report, the oral trial remains ongoing.
No member of the current management team of Ecopetrol, nor the current Boards of Directors of Ecopetrol or Reficar are part of the process.
2.3
On March 18, 2019, the Prosecutor’s Office indicted the following individuals with charges related to entering into agreements without compliance with legal requirements: Orlando José Cabrales Martínez (Reficar CEO, 2009-2012) and Felipe Castilla (Reficar CEO, 2009). The arraignment hearing took place on January 27, 2020.
The Prosecutor’s Office made public the factual basis of the charges, which is based on the theory that hiring FPJVC as the project manager consultant of the Project through a sole source process violated the objective selection principle.
On May 9, 2022, the judge found the indicted citizens guilty and condemned them to 64 months of prison. On August 18, 2022, the verdict was read, and the defense appealed.
On October 19, 2023, the Criminal Chamber of the Superior Court of Bogotá upheld the initial verdict. Attorneys representing the convicted parties subsequently lodged an extraordinary appeal in cassation before the Supreme Court of Justice challenging this ruling. On March 5, 2025, the Supreme Court of Justice declared the proceeding against Orlando José Cabrales Martínez—regarding the execution of a contract without compliance with legal requirements—terminated, on the grounds that the action was barred due to the defendant’s death, which extinguished the cause of action. A decision remains pending on the cassation claim filed by Felipe Castilla Canales. As of the date of this annual report, there have been no significant updates to the appeal process.
As of the date of this annual report, Ecopetrol and Reficar have no knowledge of any legal proceeding in the United States regarding the project.
On April 24, 2018, the Prosecutor’s Office indicted Nicolás Isaksson, former employee of Reficar, with alleged charges for offenses against the public administration and illegal interest in the execution of certain agreements. The criminal action is currently suspended until November 2026, due to the application of a plea agreement (principio de oportunidad).
Arbitration Tribunal
On March 8, 2016, Reficar filed a Request for Arbitration before the International Chamber of Commerce (the “ICC”), against Chicago Bridge & Iron Company N.V., CB&I UK Limited, and CBI Colombiana S.A. (jointly “CB&I”) concerning a dispute related to the EPC contract entered into by and between Reficar and CB&I for the expansion of the Cartagena refinery in Cartagena, Colombia. Reficar was the claimant in the ICC arbitration and sought no less than USD 2 billion in damages plus lost profits.
On May 25, 2016, CB&I filed its Answer to the Request for Arbitration and Counterclaim for approximately USD 106 million and COP 324,052 million. On June 27, 2016, Reficar filed its reply to CB&I’s counterclaim denying and disputing the declarations and relief requested by CB&I. On April 28, 2017, CB&I submitted its Statement of Counterclaim increasing its claims to approximately USD 116 million and COP 387,558 million. On March 16, 2018, CB&I submitted its Exhaustive Statement of Counterclaim further increasing its claims to approximately USD 129 million and COP 432,303 million (including in each case interest), and also filed its Exhaustive Statement of Defense to Reficar’s claims. On this same date, Reficar filed its Exhaustive Statement of Claim seeking, among others, USD 139 million for provisionally paid invoices under the Memorandum of Agreement(“MOA”) and Project Invoicing Procedure (“PIP”) Agreements and the EPC Contract.
On June 28, 2019, CB&I submitted its Reply to the Non-Exhaustive Statement of Defense to Counterclaim increasing its claims to approximately USD 137 million and COP 503,241 million (including in each case interest, respectively). On this same date, Reficar filed its Reply to CB&I’s Non-Exhaustive Statement of Defense and its Exhaustive Statement of Defense to CB&I’s counterclaim, updating its claim for provisionally paid invoices under the MOA and PIP Agreements and the EPC Contract to approximately USD 137 million.
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In January 2020, McDermott International Ltd, formerly McDermott International Inc. (hereinafter “McDermott”), CB&I’s parent company, filed for bankruptcy and announced that it would initiate a reorganization plan pursuant to Chapter 11 of the United States Bankruptcy Law. In response to this situation, Reficar implemented actions to protect its interests and is being advised by a group of experts with whom it continued to analyze other available measures under these new circumstances.
On January 21, 2020, Comet II B.V., the successor in interest to Chicago Bridge & Iron Company N.V., commenced a bankruptcy case under Chapter 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. Upon the bankruptcy filing, an automatic stay of the commencement or continuation of any action or proceeding, or the enforcement of any judgment or award, against Comet II B.V. became effective, staying the arbitration against Comet II B.V. On January 23, 2020, Comet II B.V. obtained an order from the Bankruptcy Court permitting it to, in its discretion, modify the automatic stay to permit it to proceed with litigation or other contested matters. On March 14, 2020, the Bankruptcy Court entered an order confirming a plan of reorganization, and the order provides for the stay against the arbitration to end upon the earlier of the effective date of the plan and August 30, 2020.
As a consequence of the bankruptcy filing, the arbitration was stayed until July 1, 2020, as described below.
In respect of the arbitration involving Reficar, the confirmation order provided that the proper forum for adjudication of the merits of the arbitration is an International Tribunal under the arbitration rules of the International Chamber of Commerce, the arbitration claims would not be subject to estimation in the Bankruptcy Court, and the stay would not be violated if the parties discuss logistical items with the International Chamber of Commerce tribunal or each other. The order reserved all rights and arguments of the parties related to the arbitration schedule, hearing location, and arbitration logistics and recognizes that, without waiving any arguments, including but not limited to the Debtors’ objections to alternative hearing locations and long gap(s) between hearing dates. On June 30, 2020, McDermott notified the relevant parties of the occurrence of the effective date of the plan of reorganization, and thus the stay on the arbitration was lifted on July 1, 2020.
On May 6, 2020, the Superintendence of Companies ordered the liquidation of CBI Colombiana S.A., a respondent in the arbitration against CB&I. On October 22, 2020, Reficar submitted a proof of claim in the liquidation proceeding to seek recognition as a creditor of CBI Colombiana S.A. for the amounts of its claims in the arbitration. On January 15, 2021, the liquidator of CBI Colombiana S.A. accepted Reficar’s petition.
On September 22, 2020, the Tribunal scheduled the commencement of the hearing in May 2021.
Between May 17, 2021, and June 16, 2021, the first two blocks of the merits of hearing took place. On June 16, 2021, the Tribunal ordered the parties to submit two post-hearing briefs, the first one on October 15, 2021, and the second one on November 5, 2021. Additionally, the Tribunal scheduled the hearing for the parties to present their closing arguments on November 18 and 19, 2021.
The post-hearing briefs were submitted on October 22, 2021, and November 10, 2021, respectively and on November 18, 2021, the parties presented their closing arguments.
Later, on December 20, 2021, Reficar filed its Statement on Costs, and on February 11, 2022, CB&I filed its Statement on Costs.
On June 7, 2023, Reficar was notified of the decision of the international arbitral tribunal (the “Award”) that resolved the dispute in relation to the EPC Contract. The arbitral tribunal ordered CB&I to pay USD 1,008 million plus interest accruing from December 31, 2015 until paid, in favor of Reficar, as follows: (i) USD 845.4 million in damages for exceeding costs, (ii) USD 152.75 million in damages for delays, and (iii) USD 10.3 million in damages for corrections of defects.
On June 8, 2023, Chicago Bridge & Iron Company N.V. (now McDermott Holdings B.V.) and CB&I UK Limited filed an action to vacate the Award before the U.S. District Court for the Southern District of New York, seeking denial of its recognition and enforcement in the United States.
On August 4, 2023, Reficar replied to the request for annulment and in turn, requested its confirmation. Moreover, on September 22, 2023, the Company filed its reply memorandum concerning the request for confirmation of the Award.
On September 8, 2023, McDermott publicly announced that it would initiate financial restructuring proceedings for its subsidiaries in the United Kingdom and the Netherlands, CB&I UK Limited and Chicago Bridge & Iron Company N.V. respectively.
On October 10, 2023, Chicago Bridge & Iron Company N.V. and CB&I UK Limited filed a petition before the Texas Bankruptcy Judge to initiate a procedure for recognition of financial restructuring processes abroad, known as Chapter 15 of the Bankruptcy Code of the United States of America. Specifically, they requested recognition of the financial restructuring processes that were announced by McDermott International on September 8, 2023. The action to vacate and the request of confirmation of the Award – which would determine the possibility of executing and therefore collecting the amounts decreed – was temporarily suspended by order of the bankruptcy judge overseeing the matter in the State of Texas.
On November 29, 2023, a hearing was held to request the lifting of the temporary suspension, however, the judge overseeing the matter in the State of Texas did not grant the request and determined that when new facts are available, Reficar may file another request to lift the provisional suspension measure.
On February 27, 2024, Reficar was notified of the decision of the Court of the United Kingdom in which it was determined that the financial restructuring plan of CB&I UK Limited was approved by the Court of the United Kingdom.
With respect to the reorganization process initiated by Chicago Bridge & Iron N.V. in the Netherlands on September 8, 2023. On February 25, 2024, an independent restructuring expert appointed by the Court voted on an alternative reorganization plan under which Refinería de Cartagena would receive, among others, certain shares of McDermott.
On March 21, 2024, Reficar was notified of the decision by the District Court of Amsterdam to approve the alternative financial restructuring plan of Chicago Bridge & Iron Company N.V. Under the plan, which was presented by an independent expert appointed by the court, Reficar received convertible preferred shares representing 19.9% of the share capital of McDermott, holding company of a group of entities with presence in more than 54 countries which specialize in engineering services for the energy industry and low-carbon solutions, and that includes CB&I N.V. These shares do not grant Reficar the right to vote, designate a member of its board of directors, nor exercise control over McDermott.
On March 22, 2024, the United States Bankruptcy Judge for the United States Bankruptcy Court for the Southern District of Texas issued (1) an order granting verified petition for (a) recognition of foreign proceedings in England, (b) recognition of foreign proceedings in the Netherlands, and (2) the order recognizing and giving full force and effect to (a) the restructuring plan and the order of the English Court sanctioning the restructuring plan, and (b) the parallel restructuring plans (the “WHOA Plans”) and the order of the Dutch Court sanctioning the WHOA Plans. The effective date and the consummation date of the restructuring was March 25, 2024. On March 31, 2024, because of the aforementioned plans, Reficar became the beneficiary of (i) USD 70 million and USD 95 million draw under two different letters of credits; and (ii) USD 9 million corresponding to the reimbursement of legal fees.
As of September 30, 2024, Reficar carried out the financial valuation of the shares for the amount of USD 234,525,440, which represents an increase in the financial assets account for Refinería de Cartagena compared to a lower value of the property, plant and equipment.
On December 9, 2024, McDermott announced that it has completed the sale of its storage business (CB&I’s tank business) to a consortium of financial investors led by Mason Capital Management. Under the terms of the deal announced on October 7, 2024, McDermott would receive USD 475 million of pre-tax income and transaction expenses. Pursuant to the terms of McDermott’s credit agreement, the proceeds from the sale would be used to repay CB&I’s existing tank business term loan, secure certain McDermott letters of credit in cash, and reduce an existing McDermott term loan.
On January 16, 2025, Refinería de Cartagena S.A.S. was notified of the decision issued by the Court of the Southern District of New York, by which it denied the request presented by Chicago Bridge & Iron Company N.V., CB&I UK Limited to vacate the arbitration award dated June 2, 2023 in relation to the EPC Contract (Engineering, Procurement, and Construction Contract) executed between Reficar and CB&I for the expansion and modernization of the refinery located in the city of Cartagena, accordingly resolving the disputes between Reficar and Chicago Bridge & Iron Company N.V., CB&I UK Limited and CBI Colombiana S.A. Consequently, the arbitration award in question was confirmed in its entirety.
Ecopetrol continuously monitors the operations of McDermott to identify any potential changes in the fair value of the investment and/or risk premiums associated with the valuation model.
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Requirements related to VAT by the National Tax Authority of Colombia
During the first quarter of 2025, Refinería de Cartagena S.A.S. and Ecopetrol S.A. received customs requirements (REAs) — REA 211, REA 264, and REA 289, respectively — from the National Tax Authority of Colombia (DIAN) regarding certain gasoline and diesel import filings for the period from 2022 to 2024. During the second to fourth quarters (2Q–4Q) of 2025, Refinería de Cartagena received additional customs requirements: REA 483, REA 526, REA 525 and REA 533, and Ecopetrol received requirement: REA 525. DIAN considers that the importation of gasoline and diesel during 2022 to 2024 should have been subject to Value Added Tax (VAT) at the general rate of 19%. Nevertheless, Refinería de Cartagena and Ecopetrol believe that their filings were prepared in accordance with current tax and customs legislation and have submitted their responses to the aforementioned requirements.
Subsequently, DIAN issued Official Corrective Liquidations (LOCs) and penalties to Refinería de Cartagena and Ecopetrol, due to the failure to pay VAT on the mentioned filings and periods. Specifically, the LOCs issued against Refinería de Cartagena were identified under the following numbers: LOC 676, LOC 675, LOC 1357, LOC 1380, LOC 1372, and LOC 1373; and against Ecopetrol S.A.: LOC 2078 and LOC 2507.
Both Refinería de Cartagena and Ecopetrol duly lodged the pertinent legal remedies provided by law, formally contesting the claims established by DIAN in all the aforementioned LOCs. In all proceedings against Refinería de Cartagena (6) and Ecopetrol (2), DIAN upheld its determinations and declared that the importation of gasoline and diesel carried out by the companies from 2022 to 2024 should have been subject to VAT, thereby imposing penalties on the companies.
In December 2025, Refinería de Cartagena filed two claims challenging LOC 676 and LOC 675, as well as the resolutions that upheld DIAN’s VAT determinations and the related penalties. These claims were admitted by the competent Administrative Court (Tribunal Administrativo de Bolívar) and are progressing in accordance with the applicable legal framework. With respect to LOC 2078 issued to Ecopetrol and the subsequent resolution that affirmed DIAN’s initial position, in March 2026, Ecopetrol filed a claim challenging these official acts before the competent administrative court (Tribunal Administrativo de Cundinamarca). With respect to the remaining LOCs 1357, 1380, 1372, and 1373 of Refinería de Cartagena, and the resolutions upholding DIAN’s VAT determinations and the associated penalties, the company remain within the statutory period to file the corresponding claims challenging DIAN’s position. Regarding LOC 2507 of Ecopetrol, the claim was filed on April 8, 2026, and it is currently pending admission by the competent administrative court (Tribunal Administrativo de Cundinamarca).
The total amount currently under dispute in relation to the VAT applicable to fuel imports is as follows: (i) COP 2.10 trillion for Refinería de Cartagena; and (ii) COP 10.53 trillion for Ecopetrol. These amounts encompass the assessed VAT, the corresponding penalty, and the interest accrued as of April 30, 2026.
6.
Shareholder Information
Shareholders’ General Assembly
As of the date of this annual report, two meetings of the General Shareholders Assembly have been held in 2026: an extraordinary meeting on February 5 and the ordinary meeting on March 27.
At the extraordinary meeting, among other matters, the election of the members of the Board of Directors for the remainder of the 2025- 2029 term, was approved.
At the ordinary meeting, among other matters, the following items were approved:
The plan for distribution of the Company’s profits, which establishes the distribution of an ordinary dividend per share of COP 121, payable to minority shareholders in a single installment no later than April 30, 2026. With respect to majority shareholder, a payment of COP 4.0 trillion will be made no later than April 30, 2026, with the remaining amount of COP402,559,398,481 to be paid no later than June 30, 2026.
The establishment of an occasional reserve of COP 21,141,420,537,494 in order to support Ecopetrol S.A.’s financial sustainability and flexibility in the execution of its strategy.
The Board of Directors’ Corporate Governance Report.
The 2025 Integrated Management Report.
The audited individual and consolidated financial statements as of December 31, 2025.
The merger and the merger agreement to be entered into by and between Ecopetrol (as surviving company), and Parque Solar Portón del Sol S.A.S. (as absorbed company).
6.2
Dividend Policy
In 2018, the Board of Directors approved a dividend policy consisting of the ordinary distribution of between 40% and 60% of the adjusted net income of the Company of each fiscal year (subject to the annual review, the amount of distributable earnings may be adjusted or left unchanged). For this purpose, the Board of Directors shall assess overall delivery against the Company’s financial targets, as well as the macroeconomic environment, projected cash requirements for delivering on our Business Plan and strategy, while maintaining appropriate financial flexibility in keeping the Company’s debt metrics in line with an investment grade rating. The policy does not preclude the distribution of extraordinary dividends above the 40% to 60% range, under exceptional circumstances and with due consideration of the above criteria. The maximum amount to be distributed is the profits available to shareholders (net income after release and appropriation for legal, fiscal and occasional reserves).
Pursuant to Colombian law, dividend distribution to our shareholders must be approved by a 78% majority of the shares represented in the corresponding General Shareholders Assembly. In the absence of this special majority, at least 50% of the net profits must be distributed.
On March 27, 2026, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of COP 121 per share, for the fiscal year ended December 31, 2025; based on the number of outstanding shares as of December 31, 2025. The payment is expected to be made in one installment on April 30, 2026 to our minority shareholders. The payment to the majority shareholder will be made in two installments on April 30 and June 30, 2026.
On March 28, 2025, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of COP 214 per share for the fiscal year ended December 31, 2024; based on the number of outstanding shares as of December 31, 2024. The payment was made in two different installments on April 4 and April 29, 2025, to our minority shareholders. The payment to the majority shareholder was made in three installments on April 4, April 29, and June 27, 2025.
On March 22, 2024, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of COP 278 per share for the fiscal year ended December 31, 2023 and an extraordinary dividend of COP 34 per share for the above mentioned fiscal year, amounting to a total of COP 312 per share; both based on the number of outstanding shares as of December 31, 2023. The payment was made in two different installments on April 3, 2024, and June 26, 2024 to our minority shareholders. The payment to the majority shareholder was made before December 31, 2024, considering the payment schedule of the balance of the Fuel Price Stabilization Fund (FEPC) corresponding to its 2023 accumulation.
On March 30, 2023, our shareholders at the ordinary General Shareholder’s Assembly approved an ordinary dividend of 60% of our net income for the fiscal year ended December 31, 2022 amounting to COP 20,023,830 million, or COP 487 per share, and an extraordinary dividend of 13% of our net income for the above mentioned fiscal year, amounting to COP 4,358,369 million or COP 106 per share; both based on the number of outstanding shares as of December 31, 2022. The payment was made in three different installments on April 27, September 28 and December 21, 2023, to our minority shareholders amounting COP 2,806,020 and for the majority shareholder, the total dividend payment was offset against the accounts receivable from the FEPC for the amount of COP 21,576,179 million.
Ecopetrol S.A. S.A. is required to maintain legal reserves equal to 50% of its subscribed capital. If the legal reserves are less than 50% of subscribed capital, we intend to allocate 10% of net income to our legal reserves on an annual basis until our legal reserves meet the required level.
See section Financial Review—Liquidity and Capital Resources—Dividends.
6.3
Market and Market Prices
Registration and Transfer of Shares
Under Colombian law, transfers of shares must be registered on the issuer’s stock ledger. Only those holders registered on the stock ledger are considered by law as shareholders. Ecopetrol S.A.’s shares are in electronic form, other than those shares held by the Nation, which are in physical form.
Transfers of electronic shares is required to be negotiated through the Colombian Stock Exchange. In Colombia, only brokerage firms called Sociedades Comisionistas de Bolsa are authorized to make the transfer of shares through the Colombian Stock Exchange. The transfer of shares is registered in the Centralized Security Deposit (Depósito Centralizado de Valores) or DECEVAL, through the relevant stockbrokers. DECEVAL records the share transfer on its systems, to make the corresponding registration in the issuer stock ledger.
Under Colombian legislation, if a transfer of shares has a value equivalent to or higher than 66,000 UVR (the UVR was COP 397.12 as of December 31, 2025) it must be made through the BVC if the shares are registered with the BVC. Otherwise, shareholders can freely negotiate a transfer of shares.
Nevertheless, pursuant to Decree 2555 of 2010 Article 6.15.1.1.2 the following transfers are not required to be performed through the BVC:
Purchase and sale transactions of shares listed on the stock exchange that are carried out as part of temporary transfers of securities in the over-the-counter market; and
For the purposes described above, multiple transfer transactions made within one hundred twenty (120) calendar days, between the same parties on shares of the same issuer and under similar conditions, are considered a single transfer.
During the first quarter of 2025, Ecopetrol announced that, in compliance with Article 2.27.2.1.1 of Decree 2555 of 2010, it implemented a market maker program for Ecopetrol’s shares listed on the Colombian Stock Exchange, for a 12-month period. For this purpose, Ecopetrol entered into agreements with Valores Bancolombia S.A. Comisionista de Bolsa and Andes Investment Group Inc., a subsidiary of the Chilean group Larraín Vial. Andes Investment Group Inc. began operating on March 3, 2025, while Valores Bancolombia S.A. Comisionista de Bolsa, began operating on March 14, 2025, upon authorization from the Colombian Stock Exchange. With this program, Ecopetrol aimed to contribute to the improvement of trading conditions, price formation, depth and liquidity of its shares in Colombia, thereby strengthening the Colombian capital markets and generating value for its shareholders.
As a result of the implementation of the market maker program the trading volume of Ecopetrol shares grew by 196% between January and December 2025, compared to the same period in 2024. The average daily trading volume of the stock was 12,300,000 million shares, which was driven by the participation of liquidity providers who maintain constant buy and sell orders, facilitating trading of the stock. Considering these results, the agreement with Valores Bancolombia S.A. Comisionista de Bolsa was extended until December 31, 2026. For the case of Andes Investment Group Inc, a new agreement was signed with its stock brokerage firm in Colombia, Larrain Vial Colombia S.A. Comisionista De Bolsa, until December 31, 2026.
Description of Ecopetrol Registered Debt Securities
Ecopetrol S.A. has issued the following classes of registered notes under an indenture (the Indenture), dated as of July 23, 2009, and amended as of June 26, 2015, between the Company and the Bank of New York Mellon, as trustee:
Please refer to Exhibits 4.7 to 4.16 and 4.31 to this annual report for the information relating to these debt securities required by Item 12.A of Form 20 - F.
Description of Ecopetrol ADRs
Fees and Charges That a Holder of Our ADSs May Have to Pay, Either Directly or Indirectly
In January 2025, Ecopetrol reached an agreement with JPMorgan Chase Bank N.A., the depositary bank of its American Depositary Receipts (ADR) program, to reduce the conversion cost by 50% for the issuance and cancelation of ADRs in the United States. This temporary measure has been effective since 2025 and will remain in effect until December 31, 2026. This initiative has strengthened international demand for the stock, improved liquidity, and reduced access barriers for foreign investors, thereby facilitating greater exposure to Ecopetrol’s shares.
JPMorgan Chase Bank, N.A. may charge each person to whom ADSs are issued, including, without limitation, issuances against deposits of shares, issuances in respect of share distributions, rights and other distributions, issuances pursuant to a stock dividend or stock split declared by us or issuances pursuant to a merger, exchange of securities or any other transaction or event affecting the ADSs or Deposited Securities, and each person surrendering ADSs for withdrawal of Deposited Securities in any manner permitted by the Deposit Agreement or whose ADSs are cancelled or reduced for any other reason, USD 5.00 for each 100 ADS (or any portion thereof) issued, delivered, reduced, cancelled or surrendered, as the case may be. The Depositary may sell (by public or private sale) sufficient securities and property received in respect of a share distribution, rights and/or other distribution prior to such deposit to pay such charge.
The Depositary collects its fees for issuance and cancellation of ADSs directly from investors depositing common shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The Depositary may collect its annual fee for Depositary services by deduction from cash distributions, or by directly billing investors, or by charging the book-entry system accounts of participants acting for them. The Depositary may generally refuse to provide services to any holder until the fees and expenses owing by such holder for those services or otherwise are paid.
The following additional charges may be incurred by holders of ADRs, by any party depositing or withdrawing common shares or by any party surrendering ADSs and/or to whom ADSs are issued (including, without limitation, issuance pursuant to a stock dividend or stock split declared by us or an exchange of stock regarding the ADRs or the Deposited Securities or a distribution of ADSs), whichever is applicable:
Fees and Other Direct and Indirect Payments Made by the Depositary to Us
Our Depositary has agreed to reimburse us for certain expenses we incur that are related to establishment and maintenance of the ADR program, including investor relations expenses and exchange application and listing fees. In 2023, reimbursements were made in the amount of approximately USD 2,591,158.19. In 2024, reimbursements were made in an amount of approximately USD 2,705,924.38. In 2025, reimbursements were made in an amount of approximately USD 2,924,562.70.
For more information, see section Recent Developments—Temporal reduction in the conversion cost of Ecopetrol’s ADR.
Please refer to Exhibit 2.1 to this annual report for the remaining information relating to our American Depository Shares required by Item 12.D of Form 20-F.
6.6
Taxation
6.6.1
Colombian Tax Considerations
The following is a general description of the Colombian tax considerations for investments in common shares in Colombia or for the purchase of ADSs, in a foreign securities market. This description is based on applicable law in effect as of the date of this annual report is issued, which may be subject to changes.
Prospective purchasers of common shares or ADSs should consult their own tax advisors for a detailed analysis of the tax consequences in Colombia, resulting from the acquisition, ownership and disposition of common shares or ADSs.
General Rules
Colombian entities and individuals who are deemed to be residents within the Colombian national territory for Colombian tax purposes are subject to Colombian income tax on their worldwide income. Foreign entities and individuals who are not deemed to be residents in Colombia, are subject to income tax in Colombia only with respect to their Colombian-source income, which is generally defined as income obtained from (i) the rendering of services inside Colombian territory, (ii) the exploitation of tangible and intangible assets in Colombia, and (iii) the sale of tangible or intangible assets that are located inside Colombian territory at the time of the sale among others. Double taxation treaties signed by Colombia, if applicable, may provide for special regulations regarding income taxation. Foreign tax residents with a permanent establishment in Colombia will be subject to income tax on their global source income attributable to their operation in Colombia.
Dividends paid by Colombian companies, as well as profits distributed by branches/permanent establishments of foreign entities, are deemed as a dividend and as Colombian income. However, the applicable tax depends on an imputation system set forth in Articles 48 and 49 of the Colombian Tax Code. For more information related to the Colombian dividends tax regime, see Risk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Information.
Dividend payments made to foreign shareholders out of profits accrued at the corporate level as of 2023 are subject to withholding tax as follows:
Dividends paid to non-resident shareholders: (i) a 20% dividend tax on dividends distributed from profits taxed at the corporate level (except that dividends paid to non-resident shareholders out of profits taxed at the corporate level prior to and including December 31, 2016 are not subject to this tax); or (ii) 35% withholding tax rate on dividends distributed from profits not taxed at the corporate level, plus additional 20% dividend tax after applying the initial 35% withholding tax rate.
For Colombian individuals: dividend income in excess of 1,090 UVT are taxed at progressive rates up to 39% in respect of profits taxed at the corporate level, and 35% withholding tax rate on dividends distributed from profits not taxed at the corporate level, plus an additional dividend tax (at the aforementioned progressive rates) after applying the initial 35% withholding tax rate. Additionally, resident individuals may take a marginal 19% discount on the portion of dividend income exceeding 1,090 UVT in the same taxable period.
Relief or reduced tax rates may apply under an applicable treaty to avoid double taxation, but the application of any such rules must be analyzed on a case-by-case basis.
For Colombian tax purposes, an individual is considered a Colombian resident when he/she meets any of the following criteria:
He/she remains in Colombia continuously or discontinuously for more than 183 calendar days within any given 365-consecutive-day term;
He/she is related to the Colombian Government’s foreign service or to individuals who are in the Colombian Government’s foreign service and who, by virtue of the Vienna Conventions on diplomatic and consular relations, are exempted from taxes during the time of their service; or
He/she is a Colombian national and meets one or more of the following:
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He/she has a tax residency in a country considered by the Colombian Government to be a low tax jurisdiction or a tax haven.
Law 1739 of 2014 clarifies that Colombian nationals who otherwise falls under point (iii) above will not be deemed tax residents if meet any of the following conditions:
If more than 50% of his or her annual income has its source in the jurisdiction where he or she is domiciled and whose country of domicile is not Colombia.
If more than 50% of his/her assets are located in the jurisdiction where he or she is domiciled and whose country of domicile is not Colombia.
For purposes of Colombian taxation, an entity is deemed to be a “national” or a “Colombian entity” and, therefore, subject to taxation in Colombia on its worldwide income, if it meets any of the following criteria:
It has its place of effective management, in Colombia during the corresponding year or taxable period;
It has its main domicile in the Colombian territory; or
It has been incorporated in Colombia, in accordance with Colombian laws.
Pursuant to the Colombian Tax Code, a foreign company or non-resident individual has a permanent establishment in Colombia when said company or individual performs activities in Colombia through: (i) a fixed place of business (i.e., branches, factories or offices), or (ii) an individual who is not an independent agent empowered to execute agreements on behalf of the foreign company.
A foreign company or entity will not be deemed to have a permanent establishment by the sole fact that it acts through a broker or any other independent agent provided that such people act in the ordinary course of their business. However, if the independent agent conducts all or nearly all its activities on behalf of that company, and the commercial or financial conditions established between independent enterprises, that agent will no longer be considered an independent agent for these purposes. In addition, passive-income generating activities, such as dividends, royalties and interests, typically do not qualify as entrepreneurial and are not deemed to create permanent establishments.
Tax Treatment of a Non-Colombian Entity and a Non-Resident Individual of Colombia Who Purchases an ADS in a Foreign Securities Market
As a general rule, dividends paid to foreign companies, foreign entities or non-resident individuals who are investing in ADSs which underlying assets are Colombian shares are treated as Colombian-source income and are thus subject to Colombian income tax.
To avoid double taxation, dividends paid by Colombian entities are not subject to income tax at the shareholder level when they are paid out of corporate profits that have been previously taxed at the corporate level.
From fiscal year 2023 and onwards, applicable tax rates on dividends paid to non-resident shareholders are as follows: (i) a 20% dividend tax on dividends distributed from profits taxed at the corporate level (except that dividends paid to non-resident shareholders out of profits taxed at the corporate level prior to and including December 31, 2016 are not subject to this tax); or (ii) 35% withholding tax rate on dividends distributed from profits not taxed at the corporate level, plus additional 20% dividend tax after applying the initial 35% withholding tax rate.
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Further to the above, non-resident entities or non-resident individuals whose investment qualifies as portfolio investments (i.e., investing through a Foreign Funds Administration Account - FFAA) will be taxed upon distribution by means of a withholding tax mechanism. In this case, pursuant to Article 18-1 of the Colombian Tax Code, the applicable withholding tax rate on taxable dividends is 25%, assuming that the dividends cannot be attributed to a permanent establishment in Colombia belonging to the shareholder and were not subject to taxation at the corporate level. The abovementioned 20% dividend tax rates, as applicable, apply on the balance of dividends to be distributed to the shareholder investing through an FFAA, or on the gross amount in such cases the dividend is paid out of profits that were subject to taxation at the corporate level. These foreign shareholders subject to this withholding tax are not required to file an income tax return in Colombia.
Taxation of Capital Gains from the Sale of ADSs
Capital gains obtained from the sale of ADSs by non-Colombian entities, Colombian individuals who are non-residents in Colombia and foreign non-resident individuals, are not subject to income tax in Colombia, as such sale does not generate Colombian-source income to the extent that the ADSs are not deemed to be sourced in Colombia. If the holder of the ADSs who is a non-resident entity, a Colombian individual who is not a resident in Colombia or a foreign non-resident individual, decides to surrender the ADSs and withdraw the underlying common shares, it is arguable that such transaction does not generate a capital gain subject to income tax in Colombia. However, different interpretations may be adopted by the Colombian Tax Authorities on this matter.
Tax Treatment in Colombia of a Non-Colombian Entity and a Non-Resident Individual of Colombia Who Purchases Ecopetrol’s Shares in Colombia’s Securities Market.
As a rule, dividends paid to foreign companies, foreign entities, or to non-resident individuals in Colombia, who are investing in Colombian shares directly or through a FFAA, are treated as national-source income; thus, they are subject to Colombian income tax.
The dividend tax regime was modified as of fiscal year 2023, onwards, dividend taxation will be as follows:
For Colombian individuals: dividend income in excess of 1,090 UVT are taxed at progressive rates up to 39% in respect of profits taxed at the corporate level, and 35% withholding tax rate on dividends distributed from profits not taxed at the corporate level, plus an additional dividend tax (at the aforementioned progressive rates) after applying the initial 35% withholding tax rate.
Non-resident entities or non-resident individuals whose investment qualifies as portfolio investment (i.e., investing through a FFAA), will be taxed upon distribution by means of the withholding tax mechanism. In this case withholding will apply at 25% on dividends that are distributed by the Colombian entity are not taxed at the corporate level. Pursuant to Article 18-1 of the Colombian Tax Code, assuming that the dividends cannot be attributed to a permanent establishment in Colombia belonging to the shareholder. These foreign shareholders subject to this withholding tax are not required to file an income tax return in Colombia, nevertheless those rules would not apply to foreign investments whereby the final beneficiary is a tax resident in Colombia who has control over such investments. This treatment was modified by Law 1943/2018 and Law 2010/2019. See section Financial Review—Effect of Taxes, Exchange Rate.
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Taxation of Capital Gains for the Sale of Shares
Pursuant to Article 36 - 1 of the Colombian Tax Code, capital gains derived from the sale of shares listed on the BVC and owned by the same beneficial owner, are deemed as non-taxable income in Colombia, provided that the shares sold during the same taxable year do not represent more than 10% (3% as of 2023) of the outstanding shares of the listed company. Pursuant to Section 1.6.1.13.2.19 of Regulatory Decree 1625 of 2016, sellers of shares are not required to file an income tax return for the transfer of securities that are listed in the National Registry of Securities and Issuers (Registro Nacional de Valores y Emisores) as long as the foreign investment is treated as a portfolio investment according to Article 3 of Decree 2080 of 2000 (currently compiled in Article 2.17.2.2.1.2 of Decree 1068 of 2015) and the abovementioned 10% (3% as of 2023) threshold is not surpassed.
If the abovementioned requirements are not met, the capital gain obtained in the sale of shares is subject to income tax or capital gains tax, under the following rules:
The gain or loss arising therefrom will be the difference between the sale price and the tax basis of the shares. As a rule, the tax basis of shares is equal to the price paid for such shares (i.e., cost of acquisition).
The applicable tax rate and the withholding tax rate must be determined case-by-case basis. Generally, if the shares have been owned for at least two years and qualify as fixed assets (i.e., they are not sold within their ordinary course of business), the profits from the sale will qualify as capital gains taxable at 15%; otherwise, profits will qualify as ordinary income, subject to a 35% income tax for fiscal year 2022 onwards.
Tax Treatment of Non-Residents Who Purchase Ecopetrol’s Shares in the BVC Market and Exchange Them for ADSs
Payment of dividends by Colombian entities to foreign companies, foreign entities or to non-resident individuals who are investing in ADSs which underlying assets are Colombian shares or in Colombian shares directly are subject to the tax treatment described above.
Taxation on Capital Gains for the Sale of Shares
If the holder of the Colombian shares is a non-resident entity, a Colombian individual who is not a resident in Colombia or a foreign non-resident individual, and such holder decides to exchange such common shares for ADSs, it is arguable that such transaction should not generate a capital gain subject to income tax in Colombia. However, different interpretations may be adopted by the Colombian tax authorities on this matter. For instance, assuming that the exchange of securities is treated as a sale of Ecopetrol S.A.’s shares, the seller would be subject to the tax treatment described above in connection with the taxation of capital gains for the sale of shares. Absent any specific rules or regulations addressing this specific situation, a case-by-case analysis would be necessary.
Extraordinary Taxes Decreed Under Decree 175 of 2025
Decree 1474 introduced tax measures intended to address the State of Economic Emergency declared by the National Government through Decree 1390 of 2025. These measures include, among other measures, the introduction of: (i) the Special Tax for Fiscal Stability; and (ii) the non-deductibility of royalties.
Special Tax for Fiscal Stability
This tax applies to: (i) the first sale of hydrocarbons and coal within or from Colombia; and (ii) the submission and acceptance of the export clearance request for hydrocarbons and coal for outside Colombia.
Decree 1474 specifies that the taxable products are those classified under the following tariff classifications: 27.01 (Coal; briquettes, ovoids, and similar solid fuels manufactured from coal); 27.09 (Crude petroleum oils or oils obtained from bituminous minerals).
As of April 2026, the Constitutional Court rules that Decree 175 of 2025 is unconstitutional, therefore, measures adopted under said decree have been revoked.
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Below are the main elements of this tax, based on the taxable event:
Element
First sale within or from the national territory
Exports
Moment of accrual
Occurs upon issuance of the invoice, or upon the first delivery if no invoice is issued.
Hydrocarbons received by the ANH as royalty payments only trigger the tax at the time of export
Occurs upon filing and acceptance of the export clearance request for shipments outside the country.
If the party extracting hydrocarbon or coal is also the direct exporter, the tax only accrues upon the sale.
From the first clarification, it follows that the tax may accrue twice if the extractor and the exporter are not the same entity. In that scenario, the tax is triggered (i) at the time of the first sale, and (ii) upon export.
Tax Base
Sale Price
The FOB value (in pesos) of the product. If the amount is in U.S. dollars, the exchange rate (TRM) on the date of filing and acceptance of the export clearance request shall apply.
Rate
1%
Taxable and responsible party
Any individual or legal entity that sells hydrocarbons.
Any individual or legal entity that carries out definitive export operations.
Collection
Must be remitted within the first five business days of each month, consolidating the previous month’s sales transactions.
Must be paid at the time the export clearance request is filed and accepted. This rule applies to clearance requests filed and accepted on or after December 30, 2025.
In the event the export clearance request contains provisional data that differs from the final data reported in the export return, the Decree 175 authorizes: (i) payment of any additional tax amount within ten business days after the final export return is filed; or (ii) a refund request if there is an overpayment.
Penalties
Any incomplete payment of the tax triggers a penalty of 5% on the FOB value of the goods, without prejudice to the calculation and payment of the outstanding tax amount and any applicable interest.
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During taxable year 2026, the royalties established under Articles 360 and 361 of the Political Constitution of Colombia will not be treated as a cost or deductible expense for taxpayers required to pay them. The non-deductible amount corresponding to royalties paid in cash or in kind will equal the total production cost of the non-renewable natural resources associated with generating the economic consideration paid as royalties.
The total production cost of non-renewable natural resources (CTP, per its acronym in Spanish) will be determined by summing the annual production costs of the non-renewable natural resources paid as royalties (ΣCP, per its acronym in Spanish):
The annual production cost (CP, per its acronym in Spanish) of non-renewable natural resources paid as royalties is calculated by multiplying the volume of non-renewable natural resources paid as royalties (VR, per its acronym in Spanish) by the unit production cost (CU, per its acronym in Spanish):
CU is calculated by dividing the total annual cost (CT, per its acronym in Spanish) by the total annual volume produced of the non-renewable natural resource (VT, per its acronym in Spanish):
The annual CT corresponds to the sum of all costs associated with production, including, but not limited to, those listed in Article 143-1 of the Colombian Tax Code, as well as costs incurred in the extraction, collection, processing, and storage phases.
Extraordinary Taxes Decreed Under Decree 173 of 2026
Decree 173 of 2026 introduced extraordinary tax measures in the context of the Economic, Social and Ecological Emergency declared by the Decree 0150 of 2026, including the temporary wealth tax applicable to legal entities for fiscal year 2026. The payment of this tax must be made during the months of April and May 2026.
Such measures are subject to automatic review by the Constitutional Court of Colombia, which will assess their constitutionality, while the tax is triggered by the possession of net equity as of March 1, 2026 and subject to specific rates, exclusions, and compliance obligations.
6.6.2
U.S. Federal Income Tax Consequences
This summary describes the principal U.S. federal income tax consequences of the ownership and disposition of common shares or ADSs, but it does not purport to be a comprehensive description of all of the U.S. tax consequences that may be relevant to a decision to hold or dispose of common shares or ADSs. This summary applies only to purchasers of common shares or ADSs who will hold the common shares or ADSs as capital assets for U.S. federal income tax purposes and does not apply to special classes of holders such as dealers in securities or currencies, holders whose functional currency is not the U.S. dollar, holders of 10% or more of our shares (taking into account shares held directly or through depositary arrangements) by vote or by value, tax-exempt organizations, financial institutions, holders liable for the alternative minimum tax, securities traders who elect to account for their investment in common shares or ADSs on a mark-to-market basis, partnerships or other pass-through entities or arrangements and investors therein, insurance companies, U.S. expatriates, persons that purchase or sell common shares or ADSs as part of a wash sale for tax purposes, and persons holding common shares or ADSs in a hedging transaction or as part of a straddle, conversion or other integrated transaction for U.S. federal income tax purposes. The statements regarding U.S. tax law set forth in this summary are based on the Internal Revenue Code of 1986, as amended, the “Code,” its legislative history, existing and proposed U.S. Treasury regulations, published rulings and court decisions, all as in force on the date of this annual report, and changes to such law subsequent to the date of this annual report may affect the tax consequences described herein (possibly with retroactive effect). This summary is also based in part on the representations of the Depositary and the assumption that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms.
Each holder is encouraged to consult such holder’s tax advisor concerning the overall tax consequences to it, including the consequences under laws other than U.S. federal income tax laws, of an investment in common shares or ADSs. In this discussion, references to a “U.S. Holder” are to a beneficial owner of a common share or an ADS that is for U.S. federal income tax purposes (1) an individual citizen or resident of the United States, (2) a corporation, or any other entity taxable as a corporation, organized under the laws of the United States, any state thereof or the District of Columbia, (3) an estate whose income is subject to U.S. federal income tax regardless of its source, or (4) a trust if (i) a United States court can exercise primary supervision over the trust’s administration and one or more United States persons are authorized to control all substantial decisions of the trust or (ii) it has in effect a valid election under applicable U.S. Treasury regulations to be treated as a U.S. person.
For U.S. federal income tax purposes, holders of ADSs generally will be treated as owners of the common shares represented by such ADSs.
This discussion does not address any aspect of U.S. federal taxation other than U.S. federal income taxation (such as the estate and gift tax or the Medicare tax on net investment income). Holders of common shares or ADSs should consult their own tax advisor regarding the U.S. federal, state and local and other tax consequences of owning and disposing of common shares and ADSs in their particular circumstances.
Distributions on Common Shares or ADSs
A distribution to U.S. Holders made by us of cash or property with respect to common shares or ADSs generally will be treated as a dividend for U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Distributions in excess of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, will be treated first as a tax-free return of capital reducing such U.S. Holder’s adjusted tax basis in the common shares or ADSs. Any distribution in excess of such adjusted tax basis will be treated as capital gain and will be either long-term or short-term capital gain depending upon whether the U.S. Holder held the common shares or ADSs for more than one year. Distributions of additional common shares or ADSs to U.S. Holders that are part of a pro rata distribution to all of our shareholders generally will not be subject to U.S. federal income tax. We do not maintain calculations of our earnings and profits under U.S. federal income tax principles, and, therefore, except as described in the previous sentence, U.S. Holders should expect that any distributions generally will be reported as dividends for U.S. federal income tax purposes. As used below, the term “dividend” means a distribution that constitutes a dividend for U.S. federal income tax purposes. The amount of any distribution will include the amount of any Colombian tax withheld on the amount distributed, and the amount of a distribution paid in Colombian Pesos will be measured by reference to the exchange rate for converting Colombian Pesos into U.S. dollars in effect on the date the distribution is received by the Depositary (or by a U.S. Holder in the case of a holder of common shares) regardless of whether the payment is in fact converted into U.S. dollars. If the Depositary (or U.S. Holder in the case of a holder of common shares) does not convert such Colombian Pesos into U.S. dollars on the date it receives them, generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend payment is included in income to the date the payment is converted into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income (as discussed below). The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.
If you are a non-corporate U.S. Holder, dividends that constitute qualified dividend income will be taxable to you at the preferential rates applicable to long-term capital gains, provided that you meet certain holding requirements. Dividends paid on the ADSs will be treated as qualified dividend income if (1) the ADSs are readily tradable on an established securities market in the United States and (2) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a passive foreign investment company (PFIC). The ADSs are listed on the New York Stock Exchange and will qualify as readily tradable on an established securities market in the United States, as long as they are so listed. Based on our audited financial statements and relevant market and shareholder data, we believe that we were not treated as a PFIC for U.S. federal income tax purposes with respect to our 2025 year. In addition, based on our audited financial statements and our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC for the 2026 taxable year. However, this conclusion is a factual determination that is made annually and thus may be subject to change. Based on existing guidance, it is not clear whether dividends received with respect to the common shares will be treated as qualified dividends. Holders of ADSs and common shares should consult their own tax advisers regarding the availability of the reduced dividend tax rate in the light of the considerations discussed above and their own particular circumstances.
A U.S. Holder may be eligible, subject to a number of complex limitations and conditions and the Foreign Tax Credit Regulations (as defined below), to claim a U.S. foreign tax credit in respect of any Colombian income taxes withheld on dividends received on common shares or ADSs. For purposes of calculating the foreign tax credit, dividends paid on our common shares or ADSs will be treated as income from sources outside of the United States and will generally constitute passive category income. However, Treasury regulations that apply to taxes paid or accrued in taxable years beginning on or after December 28, 2021 (the Foreign Tax Credit Regulations) impose additional requirements for foreign taxes to be eligible for a foreign tax credit, and there can be no assurance that those requirements will be satisfied. A notice from the IRS provides temporary relief from the Foreign Tax Credit Regulations by allowing taxpayers to apply a modified version of the regulations for taxable years ending before the date that a notice or other guidance withdrawing or modifying the temporary relief is issued (or any later date specified in such notice or other guidance), provided that the taxpayer consistently applies such modified version of the U.S. Treasury regulations and complies with specific requirements set forth in a previous notice. Any taxes imposed by Colombia on dividends received generally will qualify as potentially creditable taxes if a U.S. Holder applies a modified version of the U.S. Treasury regulations pursuant to the notice. However, a U.S. Holder will generally be denied a foreign tax credit for foreign taxes imposed with respect to the dividends where the U.S. Holder does not meet a minimum holding period requirement. In the case of all other U.S. Holders, the application of these requirements to the Colombian tax on dividends is uncertain and we have not determined whether these requirements have been met. If the Colombian tax is not a creditable tax or a U.S. Holder does not elect to claim a credit for any foreign income taxes paid during the taxable year, such U.S. Holder may instead, at such U.S. Holder’s election, deduct such Colombian income taxes in computing U.S. taxable income, subject to generally applicable limitations and conditions. The rules relating to the eligibility and deductibility of foreign tax credits are extremely complex, and U.S. Holders are urged to consult their own independent tax advisors regarding the availability of foreign tax credits with respect to any Colombian income taxes withheld.
Sale, Exchange or Other Taxable Dispositions of Common Shares or ADSs
A U.S. Holder generally will recognize capital gain or loss upon the sale, exchange or other taxable disposition of common shares or ADSs in an amount equal to the difference between the U.S. dollar value of the amount realized on the sale, exchange or other taxable disposition of the common shares or ADSs and the U.S. Holder’s adjusted tax basis, determined in U.S. dollars, in the common shares or ADSs. Any gain or loss will be long-term capital gain or loss if the common shares or ADSs have been held for more than one year. Certain non-corporate U.S. Holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. The deductibility of capital losses is subject to limitations under the Code.
If you are a U.S. Holder of common shares or ADSs, the initial tax basis of your common shares or ADSs will be the U.S. dollar value of the Colombian Peso-denominated purchase price determined on the date of purchase. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis U.S. Holder, or, if it elects, an accrual basis U.S. Holder, will determine the dollar value of the cost of such common shares or ADSs by translating the amount paid at the spot rate of exchange on the settlement date of the purchase. Such an election by an accrual basis U.S. Holder must be applied consistently from year to year and cannot be revoked without the consent of the IRS. If you convert U.S. dollars to Colombian Pesos and immediately use that currency to purchase common shares or ADSs, such conversion generally will not result in taxable gain or loss to you. With respect to the sale or exchange of common shares or ADSs, the amount realized generally will be the U.S. dollar value of the payment received determined on (1) the date of receipt of payment in the case of a cash basis U.S. Holder and (2) the date of disposition in the case of an accrual basis U.S. Holder. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis taxpayer, or, if it elects, an accrual basis taxpayer, will determine the U.S. dollar value of the amount realized by translating the amount received at the spot rate of exchange on the settlement date of the sale.
Deposits and withdrawals of common shares in exchange for ADSs, and of ADSs for common shares, generally will not result in the realization of gain or loss for U.S. federal income tax purposes.
Backup Withholding and Information Reporting
In general, dividends on common shares or ADSs, and payments of the proceeds of a sale, exchange or other taxable disposition of common shares or ADSs, paid within the United States, by a U.S. payer through certain U.S.-related financial intermediaries to a U.S. Holder are subject to information reporting and may be subject to backup withholding at a current rate of 24%, unless the holder (1) establishes that it is an exempt recipient or (2) with respect to backup withholding, provides an accurate taxpayer identification number and certifies that it is a U.S. person and that no loss of exemption from backup withholding has occurred.
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Backup withholding is not an additional tax. The amount of any backup withholding tax from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability, provided that the required information is timely furnished to the IRS. A U.S. Holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed its U.S. federal income tax liability by timely filing a refund claim with the IRS.
U.S. Tax Considerations for Non-U.S. Holders
A holder or beneficial owner of common shares or ADSs that is not a U.S. Holder for U.S. federal income tax purposes (a “non-U.S. Holder”) generally will not be subject to U.S. federal income or withholding tax on dividends received on common shares or ADSs, unless the dividends are “effectively connected” with the non-U.S. Holder’s conduct of a trade or business within the United States. In such a case, a non-U.S. Holder generally will be taxed in the same manner as a U.S. Holder. In the case of “effectively connected” dividends received by a corporate non-U.S. Holder, the corporate non-U.S. Holder may, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate.
A non-U.S. Holder of common shares or ADSs will not be subject to U.S. federal income or withholding tax on gain realized on the sale of common shares or ADSs, unless (i) the gain is “effectively connected” with the non-U.S. Holder’s conduct of a trade or business in the United States or (ii) in the case of gain realized by an individual non-U.S. Holder, the non-U.S. Holder is present in the United States for 183 days or more in the taxable year of the sale and certain other conditions are met. In the case of “effectively connected” gains realized by a corporate non-U.S. Holder, the corporate non-U.S. Holder may, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate.
Although non-U.S. Holders generally are exempt from backup withholding and information reporting requirements, a non-U.S. Holder may be required to comply with certification and identification procedures in order to establish its exemption from information reporting and backup withholding.
Exchange Controls and Limitations
Certain foreign exchange transactions with foreign exchange control restrictions including international investments and some transactions between Colombian residents and non-Colombian residents must be conducted through the foreign exchange market. In Colombia, foreign investment transactions are subject to foreign exchange control restrictions, and the acquisition of shares registered in the National Registry of Securities and Issuers (Registro Nacional de Valores y Emisores). ADRs by non-residents are considered a type of portfolio investment and must be registered before the Colombian Central Bank. Therefore, any foreign currency income or expense under the ADRs must be transferred through the appropriate channels of the foreign exchange market, which means using an intermediary of the foreign exchange market or a bank account opened abroad of Colombia and registered as compensation account before the Colombian Central Bank.
Transactions conducted through intermediaries of the foreign exchange market are made at market rates freely negotiated with authorized intermediaries (local banks, financial corporations, administrators and others) or using a bank account opened abroad and registered as a compensation account (in this case, without effective conversion of the currencies into Colombian Pesos). Since September 25, 1999, the Colombian foreign exchange regime is structured under the system of free flotation of the exchange rate, whereby market forces determine the level of exchange rate from time to time.
Foreign portfolio investments must be made through authorized foreign exchange investment management companies, that will act as the administrator. Only brokerage firms, trust companies and investment management companies, subject to the inspection and supervision of the SFC, are allowed to act in the local Colombian stock market on behalf of foreign investors. Such brokerage firms, trust companies and investment management companies also act as the foreign investors’ local representatives for tax, foreign exchange purposes, remittance of information and any other purpose defined by the supervisory entity.
Non-residents are also allowed to register the acquisition of shares registered in the National Registry of Securities and Issuers, as direct investments in Colombian companies. The registration must be completed before the Colombian Central Bank, considering the method of payment of the acquisition and the formalization of the agreement in accordance to which the acquisition has been made.
Colombian law provides that the Colombian Central Bank may regulate the foreign exchange regime at its own discretion at any time (i.e., it is allowed to temporarily limit the remittance of dividends from abroad whenever the international reserves of the Colombian Central Bank fall below an amount equal to three months of imports or those reserves are at the highest allowable level). Additionally, from time to time, the Colombian Government introduces amendments to the International Investment Statute. Hence, we cannot assure you that the Colombian Central Bank will not intervene in the future imposing restrictions to the free convertibility system currently applicable in Colombia. See section Risk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Environment.
Registration of Foreign Investment Represented in Underlying Shares
Colombia’s International Investment Statute as approved by the Government and the foreign exchange regulations issued by the Colombian Central Bank, which have been amended from time to time through decrees and regulations, govern the manner in which non-Colombian resident entities and individuals can invest in Colombia and participate in the Colombian securities markets. Among other requirements, the International Investment Statute and Colombian Central Bank regulations establish the liability of registration of foreign investment transactions with the Colombian Central Bank and specify procedures to authorize and administer such foreign investment transactions. Additionally, pertinent information related to foreign investment transactions must be updated on a regular basis (on a monthly basis by the administrator with the submission of the “Statistical Report on Foreign Portfolio Equity Investments in Colombia - IPEXT”).
Under the International Investment Statute and Colombian Central Bank regulations, the failure of a foreign investor to report or register with the Colombian Central Bank foreign exchange transactions relating to investments in Colombia on a timely basis may (i) prevent the investor from obtaining remittance rights, (ii) constitute an exchange control infraction and (iii) result in economic fines.
Notwithstanding the regulations described above, foreign investors who acquire ADRs are not required to directly register this investment with Colombian authorities as such registration is made in the name of the ADR program administrator. Holders of ADRs will benefit from the registration to be obtained by the local custodian for our common shares underlying the ADRs in Colombia. Such registration allows the custodian to convert dividends and other distributions with respect to the common shares into foreign currency and remit the proceeds abroad. If investors in ADRs choose to surrender their ADRs and withdraw common shares, they must retain an administrator, who will act as a local representative for the investments and register their investments in common shares as a portfolio investment through said local representative. The local representative is the brokerage firm, trust company or investment management company that acts on behalf of the holders of the ADRs in Colombia, and the request for registration is made by them.
Colombian residents who acquire ADRs and either receive profits from this investment, surrender their ADRs or liquidate their investment in ADRs, are considered as a type of financial investment and/or in assets located abroad by resident in Colombian and in that case, may be registered with the Colombian Central Bank depending on whether the payment was performed using the foreign exchange market.
In case of obtaining its own foreign investment registration, an investor who surrenders its ADRs and sells common shares may incur expenses and/or suffer delays in the application process. Investors would only be allowed to transfer dividends abroad or transfer funds received as distributions relating to our common shares after their foreign investment registration procedure with the Colombian Central Bank has been completed. In addition, the Depositary’s foreign investment registration may also be adversely affected by future legislative changes, but its rights to transfer dividends abroad or profits arising from distributions relating to our common shares must be maintained according to Colombian law and foreign investment treaties entered into by Colombia in force at the time of the registration of the investment, except when Colombia’s international reserves fall below an amount equivalent to three months’ worth of imports. Prospective purchasers of common shares or ADSs should consult their own foreign exchange advisors.
Exchange Rates
On March 31, 2026, the Representative Market Exchange Rate was COP 3,669.96 per USD 1.00. The Federal Reserve Bank of New York does not report a noon-buying rate for Colombian Pesos. The SFC calculates the Representative Market Exchange Rate based on the weighted averages of the buy and sell foreign exchange rates quoted daily by foreign exchange rate market intermediaries including financial institutions for the purchase and sale of U.S. dollars. The SFC also calculates the Representative Market Exchange Rate for each month for purposes of preparing financial statements and converting amounts in foreign currency to Colombian Pesos.
Major Shareholders
The following table sets forth the names of our major shareholders, and the number of shares and the percentage of outstanding shares owned by them on March 31, 2026:
Table 68 – Major Shareholders
As of March 31, 2026
Shareholders
Number of shares
% Ownership
Nation(1) – Ministry of Finance and Public Credit
36,384,788,417
88.49
Public float
4,731,906,273
11.51
41,116,694,690
Includes 1,600 shares owned by other state entities.
All our ordinary shares have identical voting rights.
As of February 13, 2026, the registration date of our annual general shareholders’ meeting, 3.12% or 1,282,355,460 of our common shares were held of record in form of American Depositary Shares, we had 57 registered holders, and 45,649 beneficiaries of common shares, or ADSs representing common shares, in the United States.
Changes in the Capital of the Company
There are no conditions in our bylaws governing changes in our capital stock that are more stringent than those required under Colombian law, with the exception that the Nation must hold a minimum of 80% in any stock issuance undertaken under Law 1118 of 2006.
On August 27, 2021, our Board of Directors approved the framework for the Third Round of the Program for the Issuance and Placement of Common Stock (the “Program”), in accordance with Law No. 1118 of 2006 (“Law 1118”). As provided by Law 1118, to the extent any potential public offerings of common shares are carried out under the Program, the Nation will at all times continue to maintain at least 80% of the common equity interest of Ecopetrol S.A. The Program contemplates a five-year term during which we may carry out one or more public offerings of common shares for the specific purposes set forth therein. On October 13, 2021, the SFC approved the Program. Any offerings to be undertaken pursuant to the Program remain subject to approval by the SFC and any such approvals, if and when granted, do not imply any commitment or obligation on Ecopetrol S.A. to issue common shares.
6.10
Enforcement of Civil Liabilities
We are a Colombian company. Most of our directors and executive officers and some of the experts named in this annual report reside outside the United States. All or a substantial portion of our assets and the assets of these persons are located outside of the United States. As a result, it may not be possible for you to effect service of process within the United States upon us or these persons who are residents in Colombia or to enforce against us or these persons who are residents in Colombia judgments in U.S. courts obtained in such courts predicated upon the civil liability provisions of the U.S. federal securities laws. Colombian courts will enforce a U.S. judgment predicated on the U.S. securities laws through a judicial proceeding known under Colombian Law as “exequatur.” The Colombian Supreme Court will enforce a foreign judgment, without reconsideration of the merits only if the judgment satisfies the requirements set forth in Articles 605 through 607 of Law 1564 of 2012 (Código General del Proceso) which entered into force on January 1, 2016, pursuant to Acuerdo No. SAA1510392, of October 1, 2015, issued by the Colombian Superior Council of the Judiciary (Consejo Superior de la Judicatura), as follows:
The United States and Colombia do not have a bilateral treaty providing for automatic reciprocal recognition and enforcement of judgments in civil and commercial matters. The Colombian Supreme Court has in the past accepted that reciprocity exists on a case-by-case basis, when it has been proven that either the U.S. court that has rendered the relevant judgement has enforced similar decisions by a Colombian court, or that the relevant U.S. court would enforce a foreign judgment, including a judgment issued by a Colombian court. However, such enforceability decisions are considered by Colombian courts on a case-by-case basis.
Proceedings for enforcement of a money judgment by attachment or execution against any assets or property located in Colombia are within the exclusive jurisdiction of Colombian courts, and such proceedings are conducted in Spanish. All parties affected by a foreign judgment in exequatur proceedings must be summoned to the exequatur proceedings in accordance with the rules that apply to the Colombian courts. In the course of such proceedings, both the plaintiff and the defendant are afforded the opportunity to request that evidence to be produced in connection with the requirements listed above. In addition, before the judgment is rendered, each party may file final allegations in support of such party’s position regarding the abovementioned requirements.
Assuming that a foreign judgment complies with the standards set forth in the preceding paragraphs and the absence of any condition referred to above that would render a foreign judgment not subject to recognition under Colombian law, such foreign judgment would be enforceable in Colombia in an enforcement proceeding under the laws of Colombia, provided that the Colombian Supreme Court has previously granted exequatur upon the foreign judgment.
We reserve our right to plead sovereign immunity under the United States Foreign Sovereign Immunities Act of 1976 with respect to actions brought against us under United States federal securities laws or any state securities laws.
7.
Corporate Governance
Since 2004, Ecopetrol S.A. has voluntarily adopted transparency, governance and control practices to facilitate corporate governance to generate confidence among stakeholders and ensure the sustainability of its business. The corporate governance practices at Ecopetrol S.A. aim to:
Evolution of the Ecopetrol Group’s Management Model
The Ecopetrol Group’s management model, which was based on the segment management of the oil and gas business, evolved to reflect the Group’s updated composition and strategy as a diversified energy Group.
In line with the 2040 Strategy, since 2022, the organization and management of the Ecopetrol Group’s operations has evolved into three business lines: (i) hydrocarbons, (ii) energies for the transition and (iii) transmission and roads. For each business line, the objective and focus of Ecopetrol as head of the group were identified and the leaders responsible for its development and promotion within the group were defined. The Hydrocarbons business line, led by Ecopetrol’s Chief Operating Officer, focuses on maintaining its efficiency, competitiveness and the decarbonization of its operations, leading the management of its own business segments. The Energies for the Transition business, led by Ecopetrol’s Vice President of Energies for the Transition, concentrates on incubating and developing energy solutions businesses associated with gas, biogas, LPG, energy, hydrogen, renewables and CCUS. Finally, the Transmission and Roads business line is established at the Ecopetrol Group level, is led by ISA’s president, with a focus on maximizing value and capturing synergies with respect to mature energy transmission, road infrastructure and telecommunications businesses. See section Business Overview—Our Corporate Structure.
The evolution in the management of the Ecopetrol Group by business lines, recognizes the dual nature of Ecopetrol as an operating company and as a parent company or investor, and is based on other key elements for its management, such as organizational structure, corporate governance model and the processes needed to strategically guide the Ecopetrol Group as a diversified energy group.
The main milestones in corporate governance are described along this chapter.
Corporate Governance System
Corporate governance is the system of rules and practices that govern the decision-making process and delegation of authority between the governing bodies of the Ecopetrol Group, as well as the relationships between the companies that comprise it. Corporate Governance in Ecopetrol is more than a key element for organizational management—it is an element of our strategy that our stakeholders value and monitor continuously, as it generates trust, sustainable results over time and results in long-term value relationships.
Our model is structured based on the law, international standards, the corporate governance principles of the Organization for Economic Cooperation and Development (OECD), good corporate governance practices and the Ecopetrol Group’s strategy. Our corporate governance provides safeguards for adequate decision-making of the governing bodies of the Ecopetrol Group in terms of agility, clarity and consistency, as well as the promotion of the realization of synergies between Ecopetrol S.A. and the Ecopetrol Group companies.
By virtue of the foregoing, the scope of the role that Ecopetrol plays as head of the group is defined according to the following criteria: (i) percentage of Ecopetrol’s participation in the different companies of the group; (ii) existence or not of a control situation (direct or indirect) by Ecopetrol; and (iii) relevance of companies in the group’s strategy. Therefore, in companies in which Ecopetrol has 100% direct or indirect participation, there is a high level of influence as a parent company; while in companies in which shareholding is shared with other companies, guidelines of the parent company are adopted considering the corporate governance of the respective companies.
Within the mechanisms and instruments of articulation that the group has, several elements of corporate governance stand out, which support Ecopetrol’s role as head of the group, such as the guidelines and positions of business lines and segments, which are adopted through different corporate governance bodies, such as the boards of directors (or equivalent body) of the companies of the Ecopetrol Group. In accordance with the nominees to which Ecopetrol is entitled according to the level of shareholding.
The President of Ecopetrol has the duty to appoint the employees of Ecopetrol or Ecopetrol’s subsidiaries to the board of directors (or equivalent body) of the companies of the Group in which Ecopetrol has a participation as a shareholder. The general principles and criteria to consider in the appointment process are, among others: (i) Good name; (ii) Professional suitability; (iii) Integrity; (iv) experience in leadership and administration; and (v) commitment and professionalism. Consequently, the evaluation of the boards of directors is a corporate governance practice adopted by the Ecopetrol Group and constitutes a tool through which the boards of directors annually evaluate their management to identify the strengths in their operation, contribute to the fulfillment of the goals set in the group’s strategy and opportunities for improvement.
To leverage the business strategy, Ecopetrol has a Corporate Governance System that aims to provide a consistent, sustainable and objective framework for action to safeguard Ecopetrol’s governance as well as generate synchrony and articulation with the companies of the Ecopetrol Group. The main elements of this system are:
Boards of Directors: Ecopetrol and Subsidiaries
Promote best management practices on the Boards of Ecopetrol and in the other Ecopetrol Group’s companies.
Ensure alignment of the strategy under the Ecopetrol Group’s management by business lines.
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Senior Management Committees
Establish the structure of the Senior Management Committees (operating, monitoring and improvement mechanisms).
Optimize Ecopetrol senior management time.
Matrix of Decisions and Attributions
Define the key or more relevant decisions of the Ecopetrol Group.
Establish which governing bodies are responsible for making key decisions.
Define how these decisions are made.
Relationship Model
Establish the way in which the areas within the Ecopetrol Group’s scope are related to the Ecopetrol Group’s companies.
Capture the Ecopetrol Group’s synergies.
Manage articulation through management or administration by business lines.
Key Corporate Governance Milestones in 2025
In 2025, within the framework of the corporate governance model, strategic decisions were adopted to support the achievement of the goals set forth in the 2040 Strategy, contributing to the strengthening of sustainability and value creation for the Ecopetrol Group.
In this context, progress was made in enhancing the governance of the Ecopetrol Group through greater alignment and strategic synchronization among corporate bodies and governance structures, fostering the adoption of best practices in processes and decision-making.
The following milestones reflect the key advancements achieved in corporate governance during the year:
i. Bylaw Amendment: Inclusion of an Employee as a Member of the Board of Directors
The OECD has highlighted that the inclusion of company employees as members of boards of directors or supervisory boards can generate benefits such as stronger commitment to long-term strategy, improved information flow between employees and management, and a more cohesive organizational culture.
In this context, and in compliance with the decision adopted by the General Shareholders’ Meeting during its ordinary session held on March 28, 2025, an extraordinary meeting of the highest corporate body was convened on November 11, 2025. During this session, a bylaw amendment was approved. This amendment included, among other aspects, the incorporation—within the seventh position of the list of candidates to the Company’s Board of Directors presented by the Nation—of one employee previously elected through a voting process conducted among Ecopetrol employees.
This adjustment reflects the evolution of Ecopetrol’s corporate governance practices without altering the fundamental principles of the fiduciary duty of Board members, who must always act in the best interest of the Company and all shareholders, regardless of the origin of their nomination.
ii. Integration into the Ecopetrol Group of Subsidiaries within the Energy for the Transition Business Line
In 2025, the Ecopetrol Group integrated eight (8) new companies into the Energy for the Transition business line, all dedicated to renewable energy generation. In July, the Company acquired Wind Autogeneración S.A.S., owner of the Windpeshi wind project. In November, it completed the acquisition of an operating company and six special-purpose entities that own solar projects in Colombia, including Parque Solar Portón del Sol S.A.S.
The integration of these companies into the Ecopetrol Group strengthens the Energy for the Transition business line with assets that contribute to decarbonization and self-consumption of energy, in alignment with the objective of reducing it from our cost base in our operations and gain competitiveness considering the gap in the market. These transactions represent a milestone in Ecopetrol’s entry into the development of non-conventional renewable energy projects in Colombia.
From a Corporate Governance standpoint, these companies were aligned with the Ecopetrol Group’s governance model to ensure effective articulation with the parent company. The measures adopted included: (i) registration of control situations and the Ecopetrol S.A. business group structure; (ii) amendments to bylaws to incorporate good practices and guidelines established by Ecopetrol; and (iii) updates to governance bodies and their authorities, including the establishment of Boards of Directors as governing and oversight bodies in the case of operational companies.
iii. Update of the Ecopetrol Relationship Model with the Ecopetrol Group
The Group Relationship Model defines the way in which Ecopetrol (a) guides the Ecopetrol Group companies and their businesses through guidelines, controls, and services/synergy capture; and (b) the way in which these companies adopt and implement such guidelines and controls.
In alignment with the updates to the Company’s organizational structure and certain processes, in 2025 Ecopetrol updated the thematic areas through which it provides guidance to the Ecopetrol Group companies, with the following objectives:
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Strengthen a unified Ecopetrol Group vision, promote coordinated management between the parent company and its subsidiaries, and support the achievement of the Ecopetrol Group’s strategic objectives.
Standardize interactions for critical and high-impact matters, based on the GE Strategy and its material topics, regardless of the type of controlled company.
Corporate Governance Benchmark
Ecopetrol’s Implementation of the Colombian Code of Best Corporate Practices (Código País)
In 2025, Ecopetrol achieved a score of 91.89% in the implementation of the recommended practices established in Colombia’s Code of Best Corporate Practices (Código País). The survey on the adoption of best practices is submitted to the Financial Superintendence of Colombia and reflects Ecopetrol S.A.’s level of alignment with the corporate governance recommendations set forth in the Colombian’s Code of Best Corporate Practices.
Positive Evolution of Female Representation on Boards
Law 2294 of 2023 (National Development Plan 2022-2026) established that, starting in 2026, issuers must have 30% women on their boards of directors. Ecopetrol incorporated this requirement into its bylaws in 2024.
From 2022 to 2025, the Ecopetrol Group achieved a steady strengthening of female representation on the boards of its controlled companies, reflecting its ongoing commitment to diversity and inclusive governance. The indicator increased from 24% in 2022 and 2024, reaching 29% in 2025 - its highest level in the period. This sustained progress highlights the Group’s efforts to promote balanced leadership structures, enhance decision-making through gender diversity, and align with global best practices in corporate governance.
Statement of the Nation as Majority Shareholder
Ecopetrol’s majority shareholder (the Nation, represented by the Ministry of Finance and Public Credit), is unilaterally committed to protect the interests of the minority shareholders in the following topics:
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7.1
Bylaws
The Bylaws of Ecopetrol S.A. are contained in Public Deed No. 5314 of December 14, 2007, issued by the Second Notary of Bogotá; amended by Public Deed No. 560 of May 23, 2011, issued by the Notary Forty-Six of Bogotá, Deed No. 666 of May 7, 2013, issued by the Notary Sixty-Five of Bogotá, Deed No. 1049 of May 19, 2015, issued by the Notary Second of Bogotá, Deed No. 0685 of May 2, 2018, issued by the Notary Twenty of Bogotá, Deed No. 888 of May 28, 2019 issued by the Notary Twenty Third of Bogotá, Deed No. 6527 issued by the Notary Twenty Nine of Bogotá of June 08, 2020, Deed No. 10976 of May 6, 2021 issued by the Notary Twenty Nine of Bogotá, Deed No. 9184 of May 11, 2022 issued by the Notary Twenty Nine of Bogotá, Deed No. 137 of February 20, 2024, issued by the Notary Six of Bogotá, Deed No. 3136 of May 21, 2024 issued by the Notary Sixty Eight of Bogotá, Deed No. 1273 of June 18, 2024, issued by the Notary Fifty Two of Bogotá. The most recent amendment to the corporate bylaws, approved by the General Shareholders’ Meeting on November 11, 2025. As of the date of this annual report, such amendment is in the process of being formalized and registered, which are necessary for it to be effective against third parties. An English translation of the amended bylaws is included as Exhibit 1.1 to this annual report.
The latest amendment to the Company’s bylaws, change the composition of the board of directors include one employee-elected candidate (seventh seat in the Nation’s list of the Board of Directors).
This summary does not purport to be complete and is qualified by reference to our bylaws, which are filed as an exhibit to this annual report. For a description of the provisions of our bylaws relating to our Board of Directors and its committees, see sections Corporate Governance—Board of Directors—Board Practices and Corporate Governance—Board of Directors—Board Committees.
General Shareholders’ Meetings
Shareholders’ Meetings may be ordinary or extraordinary. Ordinary meetings will take place in our legal domicile located in Bogotá, Colombia, within the first three months following the end of each fiscal year, on the day and at the time set forth in the notice for the General Shareholders’ Meeting. The call for the General Shareholders’ Meeting is published on the Ecopetrol S.A. website and in a newspaper of national circulation, in physical or digital form, 30 calendar days prior to the date on which the meeting will take place.
The Annual General Shareholders’ Meeting provides shareholders with the opportunity to make key management decisions reserved to shareholders. At the General Shareholders’ Meeting, our Board of Directors and the external auditor are appointed. Decisions are taken regarding the company’s annual financial statements, profit distribution, audit and management reports, including our corporate governance report and sustainability report, and any other matter provided under applicable law or our corporate bylaws.
Extraordinary Shareholders’ Meetings are summoned by our Board of Directors, by our president or chief executive officer, by our external auditor, or directly summoned by the Financial Superintendent of Colombia, when requested by shareholders holding at least 5% of the outstanding shares, when unforeseen or urgent needs of the Company require it, or when requested by shareholders representing at least 10% of the outstanding shares. An Extraordinary Shareholders’ Meeting should be called no later than 15 calendar days prior to the date of the meeting (article 424 of the Colombian Commercial Code). The only exception is when the law requires a greater time between the summons and the meeting. Such notice of the Extraordinary Shareholders’ Meeting is published on the Ecopetrol S.A. website and in a newspaper of national circulation, in physical or digital form. The notice informs the agenda for the meeting to the Company’s shareholders. Additionally, on the Sunday preceding the date of the Shareholders’ Meeting and as best corporate governance practice, a reminder notice regarding the convening of the General Shareholders’ Meeting is published both on the Company’s website and in a newspaper of national circulation.
For both the ordinary and extraordinary meetings, the quorum required is a plural number of shareholders representing 50% plus one of the subscribed shares entitled to vote. Decisions are approved by a majority of the members present. This quorum is exempted in the case of “second-call meetings,” which may take place when a meeting fails to obtain the required quorum and is called within a period between 10 business days and 30 business days from the first date, in which case decisions may be adopted by a majority of the shares present regardless of the number represented.
Decisions made at ordinary and extraordinary shareholders’ meeting must be approved by a plural number of shareholders representing the majority of the shares present. Colombian law requires higher majorities in the following cases:
The vote of at least 70% of the shares present and entitled to vote at the ordinary shareholders’ meeting is required to approve the issuance of stock not subject to preemptive rights.
The vote of at least 78% of the shares represented entitled to vote is required to approve the distribution of the annual net profits. In the absence of this special majority, at least 50% of the net profits must be distributed. If the sum of all legal reserves (statutory, legal and optional) exceeds the amount of the outstanding capital, the Company must distribute at least 70% of the annual net profits.
The vote of at least 80% of the shares represented is required to approve the payment of dividends in shares; and
The vote of 100% of the outstanding and issued shares is required to replace a vacancy on the Board of Directors without applying the electoral quotient system.
Shareholders may be represented by proxies, provided that the proxy: (i) is in writing (faxes and electronic documents are valid), (ii) specifies the name of the representative, (iii) specifies the date or time of the meeting for which the proxy is given and (iv) includes other information specified by the applicable law. Proxies granted abroad do not require legalization or an apostille.
During our ordinary annual shareholders’ meeting, our employees and Directors are only allowed to represent their own shares, unless they act as legal representatives.
Our 2025 Shareholders’ General Assembly was held on March 28, 2025, and the following matters were approved, among others:
The plan for distribution of the Company’s profits, which establishes the distribution of an ordinary dividend per share of COP 214, as follows: payment of dividends to minority shareholders to be made in two equal installments on April 4, 2025 and April 29, 2025; and the payment to the majority shareholder will be made in three installments as follows: 1) COP 2,200,000,000,000 on April 4, 2025, 2) COP 2,300,000,000,000 on April 29, 2025, and 3) COP 3,286,344,378,880 on June 27, 2025.
The establishment of a special reserve of COP 16,635,492,094,077 in order to support Ecopetrol S.A.’s financial sustainability and flexibility in the execution of its strategy.
Election of Deloitte & Touche S.A.S., as the statutory auditor for the 2025 – 2029 period and assignment of their remuneration.
Election of Board Members for the 2025 - 2029 period
Approval of amendments to the Internal Regulations of the General Shareholders’ Meeting.
Approval of amendments to the succession policy for the members of the Board of Directors.
As of 2026, two meetings of the General Shareholders’ Meeting have been held: an extraordinary meeting on February 5, 2026, and the ordinary meeting on March 27, 2026.
The election of the members of the Board of Directors for the remainder of the 2025 – 2029 term.
The proposal for distribution of the Company’s profits, of an ordinary dividend per share of COP 121, payable to minority shareholders in a single installment no later than April 30, 2026. With respect to the majority shareholder, a payment of COP 4.0 trillion will be made no later than April 30, 2026, with the remaining amount to be paid no later than June 30, 2026.
The establishment of an occasional reserve of COP 20,689,136,895,901 to support Ecopetrol S.A.’s financial sustainability and flexibility in the execution of its strategy.
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The merger and the merger agreement to be entered into by and between Ecopetrol (as surviving company) and Parque Solar Portón del Sol S.A.S. (as absorbed company).
Preference Rights and Restrictions Attaching to Our Shares
There are only ordinary shares, and these carry no special rights or restrictions (ordinary shares). Our current shareholders do not have any type of preemptive rights. However, in the case of a future equity offering, we will review whether existing shareholders would be entitled to preemptive or similar rights and, if that were the case, the corporate approvals and offering documents for any such equity offering would regulate the subject matter accordingly. In connection with any future public offering of ordinary shares within the five-year Program for the Issuance and Placement of Common Stock authorized by the Superintendence of Finance of Colombia on October 13, 2021, we have determined that preemptive rights will be available to our registered holders of common shares to purchase additional common shares in Colombia, in accordance with applicable regulations.
Under Commercial Colombian law, our shareholders have the following economic privileges and voting rights:
to participate and vote on the decisions of the General Shareholders Assembly;
to receive dividends based on the financial performance of the Company in proportion to their share ownership;
to transfer and sell shares according to our bylaws and Colombian law;
to inspect corporate books and records 15 business days prior to the ordinary shareholders’ meeting where the year-end financial statements are to be approved;
upon liquidation, to receive a proportional amount of the corporate assets after the payment of external liabilities; and
to sell the shares, known as right of withdrawal (derecho de retiro), if a corporate restructuring affects the economic or voting rights of the shareholders in the terms and conditions established under Colombian law.
Ecopetrol S.A.’s bylaws provide additional rights to our minority shareholders. These rights include:
Sale of Assets. For a ten-year period counted from the date of subscription of the declaration of the Nation dated February 16, 2018 or until the Nation loses its status as majority shareholder, the Nation guarantees that any sale of 15% or more of our assets requires the approval of the General Shareholders Assembly and that the Nation would only be allowed to vote its shares in favor of the proposal if 2% or more of our minority shareholders accept the proposal.
Candidate List. Pursuant to our bylaws and Law 1118 of 2006, the Nation will include in its candidate list for election of members of the Board of Directors one member nominated by the departments that produce hydrocarbons. In addition, pursuant to the declaration of the Nation dated February 16, 2018, the Nation will include in its candidate list for election of members of the Board of Directors one member nominated by the ten largest minority shareholders. The minority shareholders’ right to appoint a candidate loses its effect when minority shareholders, according to their share participation, name a member to our Board of Directors. According to the amendment to the bylaws approved by the General Shareholders Meeting held on November 11, 2025, the Nation will also include in its candidate list for election one employee-elected candidate.
Extraordinary Shareholders Meetings. Our bylaws provide that the entity exercising permanent control over Ecopetrol S.A. must instruct the Company’s CEO or External Auditor to call an extraordinary meeting of the Company’s shareholders or by the Financial Superintendent of Colombia, when is requested by shareholders holding at least 5% of the outstanding shares, when unforeseen or urgent needs of the Company require it, or when is requested by shareholders representing at least 10% of the outstanding shares (article 182 of the Colombian Commercial Code). Such requests shall be made in writing and must clearly indicate the purpose of the meeting.
During 2025 Extraordinary Shareholders Meeting occurred on November 11. There was also an Extraordinary Shareholders Meeting on February 5 of 2026.
Investor Relations Office. Ecopetrol S.A. has an investor relations office, a specialized unit responsible for our shareholders. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may request that the investor relations office
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conduct a special audit, provided that such audit does not hinder the day-to-day operations of the Company, of the following documents: the income statement; the proposal for the distribution of profits; the report of the Board of Directors as to the economic and financial status of our Company; the report from our general counsel as to the legal status of our Company; and the report from the independent auditors. Special audits cannot be made of documents that contain scientific, technological or statistical information of our Company, or agreements that give us competitive and economic advantages over our competitors, or in respect of any document related to intellectual property. Shareholders also have the right to propose good corporate governance recommendations to the office for the protection of investors.
Others. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may propose recommendations to our Board of Directors pertaining to the management of our Company. Any shareholder may file a written petition to our Board of Directors to investigate corporate governance violations that the shareholder believes to have been committed.
Amendments to Rights and Restrictions to Shares
We have only one class of stock and it has no special rights or restrictions (ordinary shares). Our shareholders do not have any type of preemptive rights. The rights given to our shareholders by law are described in our bylaws and may only be modified through an amendment to the law.
The additional rights given to our minority shareholders in our bylaws and corporate governance code may only be modified through an amendment of those internal documents.
Limitations on the Rights to Hold Securities
There are no limitations in our bylaws or Colombian law on the rights of Colombian residents or foreign investors to own the shares of our Company, or on the right to hold or exercise voting rights with respect to those shares, except in cases of legal representation.
Restrictions on Change of Control, Mergers, Spin-offs or Transformations of the Company
Under Colombian law and our bylaws, the General Shareholders Assembly has full authority to approve any mergers, spin-offs or transformations, subject to compliance of applicable law. Corporate restructurings are subject to the requirement that the Nation must hold a minimum of 80% of our common stock in any issuance of stock pursuant to Law 1118 of 2006.
Ownership Threshold Requiring Public Disclosure
The Corporate Governance Code, Title III, Chapter 1, Section 5, states: Identification of Major Shareholders. The shareholding composition of the Company, indicating at least the twenty (20) people with the greatest number of shares, is disclosed on Ecopetrol’s website at www.ecopetrol.com.co. Colombian securities regulations set forth the obligation to disclose any material event or “información relevante”. Any transfer of shares equal to or greater than 5% of our capital stock, or any legal entity or individual acquiring a percentage of shares that would make him the beneficial owner of 5% or more of our capital stock, is a material event, and therefore, must be disclosed to the SFC. The regulation includes other criteria to identify when to report a material event other than the situations described in the previous sentence.
External Auditor
Pursuant to our bylaws, the external auditor will be appointed for periods of four (4) years and may be reelected consecutively for up to ten (10) years, and it may once again be hired after one (1) period away from the position. The partner assigned to the Company must be replaced after a term of five (5) years holding this position.
7.2
Code of Ethics and Conduct
In 2024, Ecopetrol introduced significant enhancements to the Code of Ethics and Conduct, aligning it with evolving business practices, market expectations, and the highest international standards of ethics and compliance.
The Code of Ethics and Conduct applies to the companies of the Ecopetrol Group, members of the Board of Directors, legal representatives, employees (and their families) at all levels of each of the affiliate companies, and the beneficiaries of the services provided by the Ecopetrol Group.
The most significant change introduced within the update was the release of a Code of Ethics and Conduct exclusively applicable to all individuals or legal entities that have any relationship with Ecopetrol, including contractors (as well as third parties hired by contractors), suppliers, agents, partners (including in joint ventures) and customers. Additionally, all our agreements with suppliers or third parties include a provision regarding compliance with applicable anti-bribery, anti-corruption, and general compliance regulations, to prevent and detect improper conduct in our business. In the agreements, we also require our suppliers and third parties to acknowledge our Code of Ethics and Conduct, as well as our compliance guidelines.
The Code of Ethics and Conduct establishes integrity as the guiding principle for all its recipients. Furthermore, the Code of Ethics and Conduct requires strict compliance with national and international laws, standards and provisions applicable in the countries where Ecopetrol operates, including the United States and Colombia, as well as adherence to internal regulations adopted by Ecopetrol.
The Code of Ethics and Conduct provides guidelines for the following aspects: conflict of interest; ethical conflict; prohibition of bribery, other forms of corruption and violations of the U.S. Foreign Corrupt Practices Act (FCPA); accounting integrity; prevention and rejection of money laundering, financing of terrorism and proliferation of weapons of mass destruction; gifts, hospitality, and entertainment practices; protection and responsible use of resources; information management; security and confidentiality; prohibition of insider trading; environmental policy; social responsibility; respect for human rights and rejection of discrimination; antitrust and anticompetitive practices; prevention and rejection of workplace sexual harassment; and examples of ethical behavior.
In addition, Ecopetrol’s Code of Ethics and Conduct explicitly forbids facilitation payments, political contributions and charitable contributions, lobbying, and the diversion of funds from social investment or sponsorships activities to political activities or unauthorized purposes.
The Code of Ethics and Conduct also highlights its ethics hotline to encourage reporting of any conduct that may breach the Codes or any of the Ecopetrol Group companies’ ethical and compliance guidelines. The Code of Ethics and Conduct emphasizes the protection of whistleblowers acting in good faith.
Our Code of Ethics and Conduct is available on our website.
7.3
Board of Directors
Board of Directors from February 2026
The Board of Directors was elected at the Extraordinary Shareholders Meeting held on February 5, 2026. The current Board of Directors is composed as follows:
Non-independent members:
Juan Gonzalo Castaño Valderrama
Lilia Tatiana Roa Avendaño
Alberto José Merlano Alcocer
César Eduardo Loza Arenas (nominated by the Company’s workers)
Independent members:
Ángela María Robledo Gómez
Carolina Arias Hurtado
Hildebrando Velez Galeano
Ricardo Rodríguez Yee (nominated by the hydrocarbon producing Departments)
Luis Felipe Henao Cardona (nominated by the minority shareholders with largest shareholding)
Since February 5, 2026, Ángela María Robledo Gómez is the Chairwoman and Hildebrando Vélez Galeano is the Vice Chairman
The information below sets forth the names and business experience of each of the current directors of Ecopetrol S.A.
Juan Gonzalo Castaño Valderrama currently serves as Legal Representative and Chair of the Board of Directors of Fundación Nuevo Liceo Antioqueño. In addition, he works as an advisor, consultant, and independent expert on energy-related matters, with a particular focus on the hydrocarbons sector. He is a Petroleum Engineer from the Gubkin State University of Oil and Gas (I.M. Gubkin), Moscow, Russia. He holds a Master of Science in Engineering from the same institution and a master’s degree in Industrial Engineering from the Andes University. He served as Scientific and Technical Director at PetroLife Enhanced Oil Recovery and as Technical Director at CI Multiservicios de Ingeniería S.A.S. He worked for more than 20 years at Ecopetrol S.A. until 2021, where his most recent position was Integrated Reservoir Engineer within the Innovation and Technology Excellence Management of the Colombian Petroleum Institute (ICP, now ICPET). He has also served as an advisor to the Fifth Committee of the Chamber of Representatives, an assistant at the Senate of the Republic, and a consultant to CENSAT. Mr. Castaño Valderrama has experience in: (i) energy transition and the energy industry; (ii) administration, senior management, and leadership; (iii) government and public policy matters; (iv) financial and capital markets matters; (v) enterprise risk management; (vi) talent development; (vii) technology and innovation; (viii) industrial safety and environmental matters; (ix) sustainability; and (x) business strategy and project management. He has been a non-independent member of Ecopetrol’s Board of Directors since February 2026.
Lilia Tatiana Roa Avendaño served between January 2024 and December 2025 as Vice Minister of Environmental Land-Use Planning at the Ministry of Environment and Sustainable Development. She is a Petroleum Engineer from the Universidad Industrial de Santander, and holds a Master’s degree in Latin American Studies from Universidad Andina Simón Bolívar in Quito, Ecuador and a Ph.D. in Humanities from the University of Amsterdam. Her professional trajectory integrates critical thinking, public management, and territorial action. She served as Coordinator of the Energy and Climate Justice Area of Censat Agua Viva – Amigos de la Tierra, Colombia, along with other positions in this organization. She has been a consultant to the Vincent Price Art Museum, Rosa Luxemburg Foundation, Heinrich Boll Foundation, Pax Christi, Ecofondo, Transnational Institute and Colombia’s Mining and Energy Planning Unit – UPME. She has been a non-independent member of Ecopetrol’s Board of Directors since March 2024. Ms. Roa Avendaño has expertise in (i) energy transition and socio-ecological transitions; (ii) administration, senior management, and leadership; (iii) government and/or public policy; (iv) human resources and/or talent development; (v) corporate governance; (vi) environmental matters; (vii) sustainability; (viii) climate change; (ix) territorial development; (x) water and/or wastewater matters; and (xi) business strategy and/or project management. As a member of Ecopetrol’s board of directors, she is periodically trained in ethics, compliance and risk management matters.
Alberto José Merlano Alcocer, currently serves as a Management Consultant at Escala Humana with a focus on corporate conflict management. Moreover, he teaches postgraduate lessons at the business school of Universidad de los Andes and as professor at the business and law schools of Universidad del Norte. At the latter, he is co-creator and professor of the specialization and master’s programs in negotiation and conflict resolution. He holds a bachelor’s degree in business administration from Universidad EAFIT in Medellín and a master’s degree in industrial administration from Universidad del Valle. He was Administrative Vice-President at Ecopetrol for 12 consecutive years, Manager of UT Kapital Geophysical, and General Manager of the Empresa de Acueducto de Bogotá under two different district administrations. He was also Dean of the School of Business at the Universidad del Norte, Director of the SENA business advisory program on the Atlantic Coast, National Director of Human Development at Carvajal S.A., Director of the Management Advisory Center at INCOLDA and of the master’s in business administration program at EAFIT in Cali, and served as Manager of “Educación para la Acción” in Cali. He has been a non-independent member of Ecopetrol’s Board of Directors since March 2025. Mr. Merlano Alcocer has expertise in: (i) the energy industry; (ii) administration, senior management and leadership; (iii) government and/or public policy; (iv) financial matters; (v) human resources and/or talent development; (vi) corporate governance; (vii) occupational health and industrial safety; (viii) human development in territories (territorial development); and, (ix) business strategy and/or project management. As a member of Ecopetrol’s board of directors, he is periodically trained in ethics, compliance and risk management matters.
César Eduardo Loza Arenas currently serves as a Grade A Supervisor at Ecopetrol, where he has built a professional career spanning approximately 37 years, holding various positions throughout his tenure. He is a Systems Technology Specialist from Corporación Tecnológica CENTROSISTEMAS and an Economist from Corporación Universitaria de Ciencia y Desarrollo – UNICIENCIA. He is currently pursuing a Master’s degree in Mining and Energy Regulation at Universidad Externado de Colombia. He has served as President of the Unión Sindical Obrera (USO) on three occasions. In this capacity, he has actively participated in and led the successful conclusion of negotiations for several Collective Bargaining Agreements. He has been a non-independent member of Ecopetrol’s Board of Directors since February 2026. Mr. Loza Arenas has experience in: (i) the energy industry; (ii) operations; (iii) leadership; (iv) technology; and (v) business strategy.
Ángela María Robledo is currently part of the National Government delegation in the peace negotiation in the Department of Nariño with the group “Comuneros del Sur”. She holds a bachelor’s degree in Psychology and a master’s degree in Political Science and International Relations from the Pontificia Universidad Javeriana in Bogotá. She served as a member of the Advisory Committee for the Development of the National Care System of the Ministry of Equality and served on the National Participation Committee representing the National Government in dialogue with the ELN. She was a member of the First and Seventh Commissions of the House of Representatives of the Republic of Colombia, Co-President of the Peace Commission, and a member of the Gender Equity Commission of such body. She has served as an Advisor to the Office of the Dean of Universidad Pedagógica Nacional, on Peace and Gender Affairs, she served as Academic Dean of the School of Psychology of the Pontificia Universidad Javeriana and was a member of the Academic Council and the Superior Council of such institution, where she also served as professor and researcher for its Faculty of Psychology. She has also served as Director of the Administrative Department for Social Welfare of Bogotá. She served as Social Director, Manager, and Policy Coordinator in the fields of health, education, rural development, and the protection of women’s, youth, children’s and teenagers’ rights for the Antonio Restrepo Barco Foundation. She has been an independent member of Ecopetrol’s Board of Directors since March 2024. Ms. Robledo has expertise in: (i) energy transition; (ii) administration, senior management, and leadership; (iii) government affairs and/or public policy matters; (iv) enterprise risk management; (v) human resources and/or talent development; (vi) legal and corporate governance matters; (vii) health, safety, and environmental matters; (viii) sustainability; (ix) human development in the territories (territorial development) and (x) business strategy and project management. As a member of Ecopetrol’s board of directors, she is periodically trained in ethics, compliance and risk management matters.
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Carolina Arias Hurtado is a tenured professor at the Faculty of Environmental Sciences of the Technological University of Pereira (UTP). She currently serves as: (i) a researcher on extractives and just energy transition within the Sociocultural Studies and Environmental Issues Research Line (IESPA) at UTP; (ii) Advisor to the Association of Indigenous Authorities of the Southwest (AISO); and (iii) solidarity advisor to the Ríos Vivos Colombia Movement and other social movements. She is an Environmental Administrator from the Technological University of Pereira, holds a master’s degree in Heritage Management and Territorial Development from Universidad Mayor de San Simón (Bolivia), and a Ph.D. in Development Studies from the Autonomous University of Zacatecas (Mexico). As a researcher with IESPA, she participates in projects focused on: (i) sociocultural and political strategies for environmental sustainability of territories as heritage and social rights within the framework of a just energy transition, including case studies of the Ríos Vivos Colombia Movement and environmental organizations in Risaralda (ongoing); and she has also conducted research on: (ii) environmental conditions and power and gender asymmetries associated with hydroelectric extractivism in the context of the energy transition, with case studies in Antioquia and Risaralda; (iii) socio-environmental conflicts related to water and mining in western and north-central Mexico; and (iv) 21st-century extractivism, analyzed through social struggles in Mexican and Colombian Potosí, among others. In her role as advisor to AISO, she has served as Coordinator of: (i) the Free, Prior and Informed Consultation for the Indigenous Environmental Policy; and (ii) the Free, Prior and Informed Consultation for the Regulatory Decree governing the institutional response of the National Care System for Indigenous Peoples. She has also acted as advisor to: (iii) the Free, Prior and Informed Consultation of the Mining Law Bill for Just Energy Transition, National Reindustrialization, and Mining for Life, among others. She has been a non-independent member of Ecopetrol’s Board of Directors since February 2026. Ms. Arias Hurtado has experience in: (i) the energy industry; (ii) energy transition; (iii) administration and leadership; (iv) public policy; (v) financial matters; (vi) human resources and talent development; (vii) legal matters; (viii) environmental matters; (ix) sustainability; (x) climate change; (xi) human development in territories (territorial development); and (xii) project management.
Hildebrando Vélez Galeano, worked as a consultant and advisor for the Administrative Department of the Environment of Cali (DAGMA) and as advisor to the Ministry of Equality and Equity. He is a chemical engineer from the Universidad Nacional, has a PhD in Environmental Sciences from the Universidad del Valle, and master’s degree in Philosophy from the Pontificia Universidad Javeriana. He has served as director of Censat Agua Viva, as advisor to Universidad Nacional in the Advisory Group for Trade Unions in Occupational Health, and as a member of the Colombian Safety Council. He has been a member of Ecopetrol’s board of directors since March 29, 2025. He was a non-independent member until January 13, 2026, and as of January 14, 2026, he is an independent member. Mr. Vélez Galeano has expertise in: (i) the energy industry; (ii) energy transition; (iii) administration, senior management and leadership; (iv) government and/or public policy matters; (v) human resources and/or talent development; (vi) technology and/or innovation; (vii) health, safety and/or the environment (viii) sustainability; (ix) business strategy and/or project management. As a member of Ecopetrol’s board of directors, he is periodically trained in ethics, compliance and risk management matters.
Ricardo Rodríguez Yee is an Industrial Engineer from the Universidad Distrital Francisco José de Caldas, and a Ph.D. candidate at the Università degli Studi di Palermo in the Model Based Public Planning, Policy Design and Management program. He holds master’s degrees in Organizational Management from the Université du Québec à Chicoutimi and in Industrial Engineering from the Universidad de los Andes. He has served as Delegate Comptroller for the Mining and Energy Sector and Deputy Comptroller at the office of the Comptroller General of the Republic, leading fiscal investigations into companies such as Reficar, Bioenergy, Propilco, Hidroituango and Electricaribe. Also, he served as Director of the Mining and Energy Planning Unit, contributing to the indicative planning and strategic development of the sector. He led corporate restructurings in state-owned companies such as Enertolima, Barranquilla Telecomunicaciones, Gecelca, Emsirva and Cedelca and acted as an advisor on investment and strategy to the Chief of Staff of the National Army, the General Commander of the Colombian Armed Forces, the UNDP, the FNG, the Ministry of Mines and Energy, the Office of the Inspector General, the National Federation of Departments and Ecopetrol. Mr. Rodríguez Yee has expertise in: (i) the energy industry; (ii) energy transition; (iii) administration, senior management and leadership; (iv) government and/or public policy matters; (v) financial matters; (vi) enterprise risk management; (vii) human resources and talent development; (viii) legal and corporate governance matters; (ix) technology and innovation; (x) health, safety, and environmental matters; (xi) sustainability; and (xii) business strategy and project management. He has been an independent member of Ecopetrol’s Board of Directors since March 2025. Currently, he is the financial and accounting expert of the Board of Directors of Ecopetrol. As a member of Ecopetrol’s board of directors, he is periodically trained in ethics, compliance and risk management matters.
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Luis Felipe Henao Cardona currently is a member of the board of directors of EPM and AV Villas Bank, and legal representative of Lambda Soluciones Consultoría. He holds a degree in Law from Universidad del Rosario and is a Ph.D. candidate in Law at the University of Salamanca. He also holds specialization degrees in business law from Universidad del Rosario and Criminal Law from the University of Salamanca. He served as Minister of Housing, Land, and Territory (2013–2016) and previously held roles as Vice Minister of Housing and Vice Minister of Citizen Participation and Rights. Additionally, he was Secretary General of the Ministry of the Interior and Justice and the Ministry of Environment, Housing, and Territorial Development. He has been a columnist for El Espectador and El Tiempo and a panelist for Hora 20. Mr. Henao Cardona has expertise in: (i) the energy industry; (ii) energy transition; (iii) administration, senior management and leadership; (iv) government affairs and public policy matters; (v) financial affairs; (vi) human resources and/or talent development; (vii) legal and/or corporate governance matters; (viii) environmental issues; and (ix) business strategy and project management. He has been an independent member of Ecopetrol’s Board of Directors since March 2025. As a member of Ecopetrol’s board of directors, he is periodically trained in ethics, compliance and risk management matters.
Board of Directors from March 2025 to February 2026:
Hildebrando Vélez Galeano
Mónica de Greiff Lindo (she presented her resignation on October 14, 2025, which became effective on October 15, 2025)
Guillermo García Realpe (he presented his resignation on November 25, 2025, which became effective on December 12, 2025)
Álvaro Torres Macías
Ricardo Rodríguez Yee (nominated by the hydrocarbon producing departments)
The information below sets forth the names and business experience of former directors Mónica de Greiff Lindo, Guillermo García Realpe and Álvaro Torres Macías. For the business experience of directors Lilia Tatiana Roa Avendaño, Alberto José Merlano Alcocer, Hildebrando Vélez Galeano, Ángela María Robledo Gómez, Ricardo Rodríguez Yee and Luis Felipe Henao Cardona, please refer to title “Board of Directors from February 2026” immediately above.
Mónica de Greiff Lindo is currently a member of the boards of directors of EPS Sanitas S.A.S., Lagos de Aurea S.A.S., the Aris Mining Corporation, located in Canada, One Young World, located in London, Fiducoldex S.A., and Corporación Historia PAR. She holds a bachelor’s degree in law and a graduate degree in administrative law, both from Universidad del Rosario in Bogotá. She served as Ambassador to Kenya and Permanent Representative to the United Nations for Environment and Habitat, CEO of the Bogotá Chamber of Commerce and of the Bogotá Energy Group, as well as a District Secretary of Economic Development of Bogotá. She served as presidential advisor for international affairs, Minister of Justice of Colombia, Vice Minister of Justice of Colombia, and Secretary General at the Ministry of Mines and Energy. In addition to her positions in the public sector, she also served as Vice President of Legal and Public Affairs at Shell Colombia Inc. and was a member of the board of the International Chamber of Commerce of Paris, Promigas S.A., Corporación de Ferias y Exposiciones S.A., Grupo Keralty S.A.S and Gran Colombia Gold. She was a member of Ecopetrol’s board of directors since October 24, 2022. She was a non-independent member until October 2, 2023, and as of such date she was an independent member. Mrs. de Greiff Lindo has expertise in: (i) the energy industry and energy transition; (ii) administration, senior management, and leadership; (iii) government affairs and/or public policy; (iv) business risk management; (v) human resources and talent development; (vi) legal affairs and corporate governance; (vii) health, safety and/or environment; (viii) sustainability; (ix) climate change; and (x) business strategy and project management.
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Guillermo García Realpe currently serves as an advisor and consultant, specializing in matters related to environmental conservation and regional development. He holds an undergraduate degree in law and a specialization degree in Socioeconomic Sciences from Pontificia Universidad Javeriana. He has served as Secretary General of the Ministry of the Interior, Senator of the Republic of Colombia, Vice President of the Senate, and member of the Third Commission of the Senate. He has also served as President and Member of the Fifth Commission of the Senate, advisor in the National Planning Department in regional development affairs, Director of planning of Nariño, Director of planning of the University of Nariño, and Departmental Secretary of Planning. He was an independent member of the board of directors since March 2024. Mr. García Realpe has expertise in: (i) energy industry and/or energy transition; (ii) administration, senior management and leadership; (iii) governance and/or public policy matters; (iv) finance; (v) human resources; (vi) legal and/or corporate governance matters; (vii) technology; (viii) health and environment; (ix) sustainability; and (x) business strategy.
Álvaro Torres Macías currently serves as chief executive officer (CEO) of Electryon Power Inc. in Canada. He is an electrical engineer from the Universidad Industrial de Santander in Colombia. He holds a graduate degree in electrical transmission networks from the L’Institut National Polytechnique de Lorraine in Nancy, France, a Master’s degree (M.Eng. and M.Sc.) in electric power engineering and computer and systems engineering from Rensselaer Polytechnic Institute in Troy, USA, and a Ph.D. in electric power engineering from the same institution. He served as a member of the boards of directors of Empresa de Energía de Boyacá - EBSA, Transportadora de Gas Internacional - TGI, Transportadora de Energía de Centroamérica S.A. in Guatemala, Cálidda Energía S.A.C. in Perú, Contugas S.A.C. in Peru, Empresa de Energía de Cundinamarca - EEC, companies of the Grupo de Energía de Bogotá - GEB, ITANSUCA, OPAIN, the technology business incubator Innovar of COLCIENCIAS, SOFTEC, and was an alternate board member of PROMIGAS. He also served as Country Manager of Northland Power Inc. and Electryon Power Inc., both Canadian companies, Manager of Delphi Capital Partners, president of CONALVIAS, Vice President of corporate planning and shareholders portfolio of Empresa de Energía de Bogotá (currently Grupo de Energía de Bogotá - GEB), general manager of SNC Lavalin Inc., as well as senior partner, Technical Manager and General Manager of Consultoria Colombiana S.A. – CONCOL. Similarly, in his former leadership roles, Mr. Torres has contributed with his expertise in cybersecurity and cyber defense policies and practices. Between 1980 and 2012, he was a professor at Universidad de Los Andes in the Faculty of Electrical and Electronic Engineering. He was an independent member of Ecopetrol’s board of directors since March 2024. He was the financial and accounting expert of the Board of Directors of Ecopetrol. Mr. Torres Macías has expertise in (i) the energy business; (ii) energy transition; (iii) administration, senior management, and leadership; (iv) finance; (v) business risk management; (vi) human resources and/or talent development; (vii) legal matters and/or corporate governance; (viii) technology and/or innovation; (ix) health, safety, and/or environment - HSE; (x) sustainability; (xi) cybersecurity; (xii) climate change; and (xiii) business strategy and project management.
Board of Directors from March 2024 to March 2025
Edwin Palma Egea
Mónica de Greiff Lindo
Luis Alberto Zuleta Jaramillo
Gonzalo Hernandez Jiménez (Independent since May 1st, 2024)
Guillermo García Realpe
Álvaro Torres Macías (nominated by the hydrocarbon producing departments)
Juan José Echavarría Soto (nominated by the minority shareholders with largest shareholding)
Mr. Edwin Palma Egea presented his resignation as member of Ecopetrol’s Board of Directors, effective on March 6, 2025.
On August 30, 2024, Mr. Juan José Echavarría Soto and Mr. Luis Alberto Zuleta Jaramillo presented their resignations as independent members of the Ecopetrol’s Board of Directors, which became effective on November 9, 2024.
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The information below sets forth the names and business experience of directors Gonzalo Hernández Jiménez, Edwin Palma Egea, Luis Alberto Zuleta Jaramillo and Juan José Echavarría Soto. For the business experience of directors Lilia Tatiana Roa Avendaño, Ángela María Robledo Gómez, Mónica de Greiff Lindo, Guillermo García Realpe and Álvaro Torres Macías, please refer to the titles “Board of Directors from March 2025 to February 2026” and “Board of Directors from February 2026” immediately above.
Gonzalo Hernández Jiménez currently holds the position of Professor at Pontificia Universidad Javeriana’s department of economics. He is also a member of the board of directors of Financiera de Desarrollo Nacional (FDN), and of the Aris Mining Corporation, located in Canada. He is an economist from the Pontificia Universidad Javeriana, with a master’s degree and Ph.D. in Economics from the University of Massachusetts, Amherst. He was a member of the boards of directors of Grupo Bicentenario S.A.S., and the Administrator of Resources of the General System of Social Security in Health (ADRES, for its acronym in Spanish). He was a member of Ecopetrol’s Board of Directors since October 24, 2022. He was a non-independent member of Ecopetrol’s Board of Directors until April 30, 2024, and as of May 1, 2024, he was an independent member. Mr. Hernández Jiménez has expertise in: (i) administration, senior management and leadership; (ii) financial and securities markets; (iii) human resources and talent development; (iv) legal affairs and/or corporate governance; (v) business strategy and project management; (vi) health, safety and/or environment; (vii) sustainability, (viii) energy industry, and (ix) government affairs and public policy.
Edwin Palma Egea currently serves as Minister of Mines and Energy of Colombia and previously served as special agent for AIR-E S.A.S. and as Vice Minister of Labor Relations and Inspection at the Ministry of Labor. He holds a bachelor’s degree in law from Universidad Cooperativa de Colombia in Barrancabermeja, as well as graduate degrees in labor law and social security from the Universidad Libre de Colombia in Socorro, Santander. He also holds a graduate degree in constitutional law and a master’s degree in law with a focus on labor law, both from Universidad Externado de Colombia in Bogotá. He also completed the Specialization Course for Latin American Experts in Labor Relations at Universidad de Castilla-La Mancha, Spain. He worked for Ecopetrol for approximately two decades, served as an arbitrator in legal disputes for the Company for more than 10 years, and led the Unión Sindical Obrera (USO) as the National Board Chair from 2018 to 2021. He was a non-independent member of Ecopetrol’s Board of Directors from March 2024 to March 2025. Mr. Palma Egea has expertise in: (i) administration, senior management, and leadership; (ii) governance and/or public policy; (iii) human resources and/or talent development; (iv) legal matters and/or corporate governance; (v) energy industry and energy transition; and (vi) health, safety and/or environment.
Luis Alberto Zuleta Jaramillo is an economist from the Universidad de Antioquia with a Master of Sciences in Economic Development from the University of Strathclyde in the United Kingdom. He is currently an economic and financial consultant to the audit committee of Bancolombia, Banco Agromercantil of Guatemala and Banistmo of Panama, as well as an Associate Researcher for Fedesarrollo, and a university professor. He has been a member of the boards of directors of Medellín’s Metro, Carbocol, Banco Caja Social, Corporación de Ahorro y Vivienda Colmena, Compañía de Financiamiento Comercial Sufinanciamiento, Bancolombia, Suramericana, Bolsa Mercantil de Colombia, Protección S.A. and member of the governing board of Fundación Social. Mr. Zuleta has served in the following committees: financial and audit committee of the manufacturing company Grupo Crystal S.A.S. and financial committee of ICETEX. Additionally, he is a member of the board of directors of the nonprofit Fundación Pro Niñez Gabriel Herrera Rogelis. He was an independent member of the Board of Directors of Ecopetrol, Chairperson of the Board´s Audit and Risk Committee and financial and accounting expert from March 2023 to November 9, 2024. Mr. Zuleta has expertise in: (i) energy industry and energy transition; (ii) administration, senior management and leadership; (iii) government affairs and/or public policy; (iv) financial and securities markets; (v) business risk management; (vi) human resources and talent development; (vii) legal affairs and corporate governance; (viii) technology and innovation; (ix) health, safety and environment; (x) sustainability; (xi) cybersecurity; and (xii) business strategy and project management.
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Juan José Echavarría Soto is an Administrative Engineer from the School of Mines, Universidad Nacional de Colombia, he completed a non-degree program in economics at Harvard University and holds a master’s degree in economics from Boston University and a PhD in Economics from Oxford University. He served as a member of the board of directors of Ecopetrol for four months in 2016. He has been an associate researcher at Fedesarrollo and a university professor He previously served as general manager and director of the Nation’s Central Bank (Banco de la República), as a Consultant of the Development Bank of Latin America (CAF), the Inter-American Development Bank (IDB), the Ministry of Commerce and Finagro, Director of the Mission for the Restructuring of Coffee in Colombia, Executive Director of Fedesarrollo, Plenipotentiary Minister of the Colombian Mission to the Organization of American States (OAS), advisor in the area of international trade at the OAS, Vice Minister of Foreign Trade of Colombia and principal negotiator of the Colombia- Chile, Colombian– Central America, Colombia – Caricom, and Colombia ‐ G3 trade agreements, and dean of the Faculty of Economics at Universidad Nacional de Bogotá. Mr. Echavarría has served on the Boards of Directors of Isagen S.A., Banco de la República, Bolsa y Banca, and Fiduciaria Bogotá. He has been a member of the board of directors of the nonprofit Alejandro Ángel Escobar Foundation. He was an independent member of Ecopetrol’s board of directors, nominated by the minority shareholders with the second largest shareholding (after the Nation), from March 2023 to November 9, 2024, and was the Chairperson of the Board’s Corporate Governance and Sustainability Committee from November 2023 to November 2024. Mr. Echavarría has expertise in: (i) the energy industry; (ii) the energy transition; (iii) administration, senior management, and leadership; (iv) government affairs and/or public policy; (v) financial and securities market; (vi) human resources and talent development; and (vii) legal affairs and corporate governance.
7.3.1
Board Practices
Currently, our Board of Directors is composed of nine members and is responsible for, among other roles, establishing our general business policies. The majority of the Board of Directors must be independent, their independence is determined pursuant to the criteria set out in paragraph two, Article 44, Law 964, 2005, and they must be elected in accordance with the procedure determined in Decree 3923, 2006, or any other provisions that regulate, amend, replace or add such regulations. In addition, pursuant to our bylaws and in accordance with the procedures described therein, the slate of candidates must include, for the last three seats in the Board of Directors, the name of one individual jointly proposed by departments that produce hydrocarbons, one individual jointly proposed by the ten minority shareholders with the largest shareholding participation and one individual nominated by the Company’s workers.
According to the Colombian law and the internal regulations, the members of the Board of Directors must be elected by the General Shareholders Assembly in accordance with a proportional representation system similar to cumulative voting (through an electoral quota voting system). The number of votes required to fill each position is calculated by dividing the number of possible votes by the number of open board positions. The members of the Board of Directors may be elected without an electoral quota voting system when there is unanimity. Pursuant to our bylaws, (i) positions on our Board of Directors are appointed in a personal capacity, (ii) at least three members appointed for a specific period must be current members from the preceding period, without including candidates for seats eight and nine, (iii) with retroactive effect to 2021, Directors will be elected for a four-year institutional term, and (iv) members of the Board may be re-elected more than once for the same four-year term without exceeding a total of three terms. Our current Directors were elected at the General Shareholders Assembly held on February 5, 2026.
Our CEO is appointed by the Board of Directors and, as the Company’s general legal representative, should have at least two personal alternates. The CEO is elected and freely removed by the Board of Directors. In accordance with our bylaws, the Board of Directors must evaluate the performance of the CEO. Such results are published in Ecopetrol’s website or in an alternative media vehicle.
The remuneration of our Directors is set exclusively by the shareholders at the General Shareholders Assembly. Currently, Directors are remunerated for attending board meetings and committee meetings. A Board meeting requires a quorum of at least five members and decisions are approved with a majority of the Directors present.
Under Colombian law, a director or executive officer must abstain from participating in any transaction that may result in a conflict of interest or that involves competing with the company, unless authorized at a General Shareholders Assembly. The general shareholders may approve or reject the participation of the director or executive officer in the transaction, giving rise to the conflict of interest with the vote of the majority of the shares present at the General Shareholders Assembly. If the director or executive officer who has the conflict is a shareholder, his or her vote must be excluded. We disclose the number of conflicts of interest of our employees, executive officers and Directors in our annual reports.
Neither our bylaws nor our corporate governance code provide a retirement age for our Directors. Under our bylaws, there is no requirement for a person to have a minimum number of shares to be elected as a Director. Colombian law provides that Directors willing to sell or purchase shares in our Company need prior authorization from the entire Board of Directors. Colombian law does not impose any limitation as to the number of shares that may be acquired by a Director.
Succession Policy of the Board of Directors
In 2021 Ecopetrol’s Board of Directors adopted the Board of Directors’ succession policy, with the purpose of (i) ensuring an organized replacement of its members, (ii) minimizing the possible economic and reputational impact that may arise from the change in board membership, (iii) promoting the attraction of human talent, and (iv) ensuring the long-term stability and sustainability of the Ecopetrol Group’s strategy.
On March 22, 2024, the General Shareholders Assembly approved, among others, an amendment to the Company’s bylaws consisting of that the General Shareholders Assembly must approve the succession policy for the members of the Board of Directors.
On March 28, 2025, the General Shareholders Assembly approved, among others, the succession policy for the members of the Board of Directors, as being the corporate body responsible for its approval. The succession policy maintains the purpose of ensuring an organized replacement of its members and reflects the Company’s preparedness to face any changes arising from handovers in its directorate, a characteristic valued by the Company’s shareholders. The succession policy reduces uncertainty and provides additional surety regarding the transparency and dependability of the selection process for the members of the Board of Directors.
The policy regulates the capacities, obligations, and requirements for the nomination and election of the board members to strengthen the transparency of the selection process and guarantee that their capacities contribute to the fulfillment of Ecopetrol’s objectives and strategic plans.
This Policy is part of the corporate rules concerning the succession of the Board of Directors.
Gender diversity
Furthermore, in 2021 Ecopetrol became part of the 30% Club, a global campaign intended to increase gender diversity on boards of directors, whereby Ecopetrol committed itself to boosting efforts to achieve 30% participation of women in senior positions at the Company within a reasonable timeframe; and also, on the boards of the other affiliates of the Ecopetrol Group by adopting a progressive plan. In 2023, the Company ratified its goal to promote an increased participation of women in the boards of directors of companies of the Ecopetrol Group.
Part of this commitment is reflected in the appointment of women on the boards of directors of the Ecopetrol Group, with a participation of 29% in 2025. In 2025, 114 of the 390 positions on the boards of directors of the Group’s companies were held by women.
As for Ecopetrol’s Board of Directors, on January 10, 2024, the General Shareholders Assembly approved an amendment to the Company’s bylaws that requires that at least 30% of the members of the Board of Directors must be women. The amendment aims to promote gender plurality and anticipates the requirement set forth in Colombia’s National Development Plan (PND for its acronym in Spanish) according to which 30% of the board members of the boards of directors of securities issuers must be women as of 2026.
The Board of Directors, whose members were appointed on February 18, 2026, is comprised of three women.
7.3.2
Board Committees
Pursuant to our bylaws, our Board of Directors may constitute the committees it considers necessary. The Board of Directors currently has six committees (audit and risk committee, corporate governance and sustainability committee, remuneration, nomination and culture committee, business committee, territorial transformation and HSE (health, security and environment) committee and technology and innovation committee). These committees establish guidelines, set specific actions and evaluate and submit proposals designed to improve performance in the areas under their supervision and control. The committees are solely comprised of members of the Board of Directors who are also appointed by the same members. The chairperson of each of the committees must be an independent Director. In addition to applicable regulations, the committees also have their own specific regulations that establish their purposes, duties and responsibilities.
In accordance with applicable regulations, each committee also has its own specific regulations that set out its purposes, duties and responsibilities.
Table 69– Composition of committees of the Board of Directors since February 18, 2026
Audit and Risk Committee
Remuneration, Nomination, and Culture Committee
Ricardo Rodríguez Yee(Chairman)
Ángela María Robledo Gómez(Chairwoman)
César Eduardo Loza Arenas
Luis Felipe Henao Cardona
Corporate Governance and Sustainability Committee
Business Committee
Luis Felipe Henao Cardona (Chairman)
Ricardo Rodríguez Yee(Chairperson)
Territorial Transformation and HSE Committee
Technology and Innovation Committee
Hildebrando Vélez Galeano(Chairman)
Ricardo Rodríguez Yee
Our audit and risk committee, which must be comprised of at least three members, all of them independent Directors, is our highest internal control body and provides support to our Board of Directors on risk, accounting and financial matters. It oversees our internal control over financial reporting. It also analyzes the annual hydrocarbons reserves report and provides support for our Board by analyzing topics related to financial matters, risks, control and the assessment of the Company’s internal and external auditors.
All committee members are required to be knowledgeable in accounting matters and at least one of them is required to be an expert in financial and accounting matters.
Our Board of Directors has determined that Ricardo Rodríguez Yee qualifies as an “audit committee financial expert” and he is independent under the definition of “independent” applicable to us under the rules of the NYSE.
The audit and risk committee approves on a case-by-case basis any engagement of our external independent auditors to provide services different than those related to auditing our financial statements. The audit and risk committee reviews that the additional services do not affect the external auditor’s independence.
Remuneration, Nomination and Culture Committee
Our remuneration, nomination and culture committee, which must be comprised of at least three members, and a majority of independent directors, provides general guidelines for the selection and remuneration of our executive officers and employees, and within the framework of the Ecopetrol Group’s strategy, oversees matters of organizational culture.
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Our corporate governance and sustainability committee, which must be comprised of at least three members, and a majority of independent directors, supports the Board of Directors in the analysis and decision making related to systems for the adoption of best practices in corporate governance for the oil and gas industry and the energy sector, which include matters related to the adoption of specific measures regarding the Ecopetrol Group’s governance. This committee also supports the analysis and provides recommendations related to the Ecopetrol Group’s sustainability agenda and TESG topics.
Our business committee, which must be comprised of at least five members, and a majority of independent directors, assists our Board in analyzing potential business ventures. Based on its delegation of power, the committee studies and analyzes capital expenditure policies, major investment projects, strategy, new businesses and other matters that would help us move forward in our efforts toward the consolidation of our strategy. The primary criteria used in the committee’s decision-making process are the optimization of our portfolio and the proper allocation of our resources.
Our Territorial Transformation and Health, Safety, and Environment Committee (the “HSE Committee”), which must be comprised of at least three members, the majority of which must be independent, supports the management of the Board of Directors with respect to monitoring and management of risks associated with the health and safety of our employees, contractors and partners. The HSE Committee is also responsible for monitoring Ecopetrol’s environmental management strategy, which includes matters related to the adoption of specific metrics regarding, for example, decarbonization, industrial and process safety, occupational health, territorial transformation strategy, and environmental performance across the Ecopetrol Group. In addition, the HSE Committee reviews and recommends annual objectives and goals related to territorial transformation, occupational health, industrial and process safety, and environmental management, and monitors the implementation and effectiveness of HSE Committee and territorial management plans. The Committee is also responsible for evaluating critical events or high-potential incidents, reviewing the integral territory management strategy, and advising the Board on measures or initiatives that could impact Ecopetrol’s performance in territorial transformation, health, safety and environmental matters.
Our technology and innovation committee, which must be comprised of at least three members, the majority of which must be independent, supports the management of the Board of Directors with respect to technological and digital transformation, as well as the cultural change that Ecopetrol is undergoing to transform itself into a leading company in the use of technology and digital innovation in the hydrocarbons sector. The technology and innovation committee also reviews TESG-related topics and oversees reviewing and monitoring the Ecopetrol Group’s digital strategy, as well as computer security, cybersecurity, cyber defense, privacy and data recovering strategies.
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7.4
Compliance with NYSE Listing Rules
The following is a summary of the significant differences between our corporate governance practices and those required for U.S. companies under the NYSE listing standards.
NYSE Standards
Our Corporate Governance Practices
Director Independence
The majority of the board of directors must be independent. §303A.01. “Controlled companies,” which would include Ecopetrol if we were a U.S. issuer, are exempt from this requirement. A controlled company is one in which more than 50% of the voting power is held by an individual, group or another company, rather than the public. §303A.00.
Pursuant to our bylaws, the majority of the Board of Directors must be independent. As of the date of this annual report, we have five independent Directors and four non-independent Directors. The criteria to determine the independent status of Board members is set forth in Colombian Law 964 of 2005, Article 44, Paragraph Two.
Executive Sessions
The non-management directors of each listed company must meet at regularly scheduled executive sessions without management. §303A.03.
A comparable rule does not exist under Colombian law. All Board members are non-management directors. Our Board of Directors’ regular scheduled executive sessions are usually with the Company’s management, but Directors may at any time request sessions without management.
Nominating/Corporate Governance and Sustainability Committee
A nominating/corporate governance and sustainability committee composed entirely of independent directors is required. The committee must have a charter specifying the purpose, duties and evaluation procedures of the committee. §303A.04. “Controlled companies” are exempt from these requirements. §303A.00.
Colombian law does not require the establishment of a nominating and a corporate governance and sustainability committee composed entirely of independent directors. Pursuant to our board charter, these committees shall be composed of a majority of independent Directors. Both the remuneration, nomination and culture committee and the corporate governance and sustainability committee have charters specifying their purpose and duties.
Remuneration Committee
A remuneration committee composed entirely of independent directors is required, which must evaluate and approve executive officer compensation. The committee must have a charter specifying the purpose, duties and evaluation procedures of the committee. §303A.05. “Controlled companies” are exempt from this requirement. §303A.00.
Colombian law does not require the establishment of a remuneration committee composed entirely of independent directors. Pursuant to our board charter, this committee shall be composed of a majority of independent Directors. The remuneration, nomination and culture committee has a charter specifying its purpose and duties.
An audit committee with a minimum of three independent directors satisfying the independence and other requirements of Rule 10A-3 under the Exchange Act and the more stringent requirements under the NYSE standards is required. §§303A.06 and 303A.07.
According to Law 964 of 2005, Colombian companies that are authorized to issue securities by the Superintendence of Finance of Colombia must have an audit committee that satisfies the requirements of Law 964 of 2005, including its minimum number of members, independence criteria and audit related duties. Our audit and risk committee is composed entirely of independent Directors, and the committee meets the requirements of Law 964 of 2005 and Rule 10A-3 under the Exchange Act.
Equity Compensation Plans
Equity compensation plans and all material revisions thereto require shareholder approval, subject to limited exemptions. §§303A.08 and 312.03.
Under Colombian law, no similar right to vote on equity compensation plans and material revisions thereto is given to shareholders. We do not give our shareholders the right to vote on equity compensation plans and material revisions thereto.
Listed companies must adopt and disclose corporate governance guidelines. §303A.09.
The Superintendence of Finance of Colombia recommends the adoption of corporate governance guidelines to all Colombian issuers. According to Superintendence of Finance Circular No. 028, 2014, the adoption of corporate governance guidelines is voluntary. Listed companies must annually publish a corporate governance survey comparing their corporate governance standards with those recommended by the Superintendence of Finance. Our corporate governance code and our survey of the adoption of Colombian practices are available on our website at http://www.ecopetrol.com.co.
Code of Ethics for Directors, Officers and Employees
Corporate governance guidelines and a code of business conduct and ethics is required, with disclosure of any waiver for directors or executive officers. The code must contain compliance standards and procedures that will facilitate the effective operation of the code. §303A.10.
We have adopted a code of ethics which complies with applicable U.S. and Colombian law. Our code of ethics applies to our chief executive officer, chief financial officer, principal accounting officer, persons performing similar functions and to all of the employees, members of the Board of Directors, suppliers, and contractors of Ecopetrol S.A. and its corporate group. Our code of ethics is available on our website at http://www.ecopetrol.com.co
7.5
The term “Executive Officers” is used in accordance with the definition set forth under the SEC’s rules and refers to the following officers of Ecopetrol: the Chief Executive Officer (CEO), the Chief Financial Officer (CFO), the Executive Vice President of Hydrocarbons, the Executive Vice President of Energies for the Transition, the President of ISA and the Vice President of Commercial and Marketing. See details in Exhibit 7.1 Company Clawback Policy
Ecopetrol’s organizational structure is defined in accordance with Law 1118 of 2006 and its bylaws. Senior management comprises positions responsible for overall leadership, policy formulation, and the approval and execution of strategic plans and projects. The principal responsibilities of senior management include: (i) defining, implementing and evaluating the Company’s long-term strategy, (ii) formulating corporate policies and directing Ecopetrol’s operations, (iii) approving strategic plans and major projects, (iv) overseeing performance and decision-making through senior management committees, and (v) ensuring the effectiveness of our internal control and risk management system. The senior management positions described in this chapter report to the Chief Executive Officer. This includes Vice Presidents reporting to the Executive Vice President of Hydrocarbons and to the Executive Vice President of Energies for the Transition, as applicable.
On January 15, 2025, we announced the following senior management changes:
Walter Fabián Canova, who had served as Vice President of Refining and Industrial Processes, performed his duties until January 15, 2025 and terminated his employment contract by mutual agreement after working at the Company for more than seven years.
Felipe Trujillo López, was appointed as Vice President of Refining and Industrial Processes.
Julio César Herrera serves as Vice President of Commercial and Marketing in charge and until a permanent appointment is made.
On January 31, 2025, we announced the following senior management changes:
María Cristina Toro Restrepo was confirmed as Corporate Legal Vice President and General Secretary. This Vice Presidency reports directly to the President.
Rafael Ernesto Guzmán Ayala was appointed Executive Vice President of Hydrocarbons. He will continue to report directly to the President.
On April 23, 2025, we announced the following senior management changes:
Diana Marcela Jimenez Rodriguez was confirmed as Director of Institutional Relations and Communication.
Julian Fernando Lemos Valero was confirmed as Corporate Vice President of Strategy and Business Development.
Julio César Herrera was confirmed Vice President of Commercial and Marketing.
On July 25, 2025, we announced the following senior management changes:
Sergio Andrés Moreno Acevedo was appointed Corporate Vice President of Science, Technology and Innovation.
Bayron Triana Arias was appointed Executive Vice President of Energy Transition.
On November 11, 2025, we announced the following senior management changes:
Juan Carlos Hurtado Parra was appointed as Executive Vice President of Hydrocarbons;
Rafael Ernesto Guzmán Ayala, who previously served as Executive Vice President of Hydrocarbons, took on new professional challenges within the Ecopetrol Group;
Rodolfo Mario García Paredes was appointed as Chief Compliance Officer and Compliance Officer
On February 26, 2026, ISA announced the following senior management changes:
Jorge Andrés Carrillo Cardoso ceased served as President and legal representative of the company with immediate effect. His employment contract has been temporarily suspended. Once the Council of State’s decision becomes final, his employment contract will be terminated.
Gabriel Jaime Melguizo Posada was unanimously appointed as Acting President.
On April 6, 2026, we announced the following senior management update:
Ricardo Roa requested to use his accrued and entitled vacation days from April 7 to May 27. He also requested an unpaid leave of absence for 30 days, starting from May 28. Both requests were approved by the board of directors.
Juan Carlos Hurtado Parra was appointed as Acting Chief Executive Officer.
The following presents information concerning our executive officers and senior management as of March 10, 2026. Unless otherwise noted, the majority of these individuals are Colombian citizens.
Executive Officers
Ricardo Roa Barragán has served as the Chief Executive Officer of Ecopetrol S.A. since April 2023. Since joining Ecopetrol, he has led the Group’s energy transition, achieving significant progress in energy efficiency, in the expansion of renewable energy portfolio within the Group’s operations, as well as strengthening ISA’s energy transmission and roads businesses. Mr. Roa has also strengthened the role of the hydrocarbons business and its contribution to the national economy and to Ecopetrol’s shareholders. He has an extensive 30-year-plus professional career as CEO, General Manager and Director, with significant achievements in energy and gas companies in United States, Brazil, Peru, Guatemala, Honduras and Colombia. His vast experience includes roles as General Manager of Electrificadora de Santander, Director of Commercialization and Business Manager in Energy and Methanol of Ingenios Incauca and Providencia, President of Transportadora de Gas Internacional TGI, President of Grupo Energía Bogotá, General Manager of Controles Eléctricos de Colombia, President of Central Termoeléctrica La Luna, and General Manager of Empresa Energía Honduras. He holds a degree in Mechanical Engineering from Universidad Nacional de Colombia, and a postgraduate degree in Engineering Management Systems from Pontificia Universidad Javeriana.
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Camilo Barco Muñoz has served as Chief Financial Officer since August 30, 2024. He is a Senior Executive with more than 30 years of successful experience in management positions, both in the public and private sectors. Currently, certified ESG Member of several Boards of Directors in Colombia– Jaramillo Mora Constructores JMC, Banco Agrario de Colombia BAC, FONDES, OZONO ESP and former member of other important Boards in large companies across Latin America, including among others: Ecopetrol, Bancoldex, Telefónica, ISA Capital do Brasil, CTEEP, Red Eléctrica del Perú, Intervial Chile, INFRAMCO and Metro de Bogotá. He is a dynamic and encouraging leader with strong competencies in high performance team management, strategic planning, corporate governance, corporate finance and new business structuring and development. As an Investment Banker, he participated in the structuring and execution of an extensive number of transactions, either in advisory (M&A), structured finance and debt capital markets. Previously, as a Consultant, he accompanied the Colombian Government and a wide list of public and private companies in the execution of strategic projects aimed at sustainability and value generation. In addition, Mr. Barco served as Country Head of Investment Banking of Banco Itaú in Colombia; General Director of State-Owned Enterprises in the Ministry of Finance and Public Credit (holding entity of state companies); Managing Director Head of Investment Banking at BBVA Colombia; CFO of Grupo ISA; Manager of Financial Consulting at Deloitte; and Advisor to UNDP for the Privatization and Concessions Program in Colombia. He is a Lawyer from Universidad del Rosario, has a postgraduate degree in Financial Law from Universidad de los Andes, has carried out various executive courses in Corporate Finance, Capital Markets and International Finance at Chicago Booth School of Business and at the London School of Economics-LSE.
Juan Carlos Hurtado Parra currently appointed as Acting Chief Executive Officer, served as Vice President of Hydrocarbons from November 11, 2025 until April 6, 2026. In light of Mr. Roa’s vacations and unpaid leave of absence, Mr. Hurtado has served as Acting Chief Executive Officer since April 7, 2026. He is an electrical engineer from Industrial University of Santander, and has a Master in Business Administration (MBA) in international oil and gas from University of Dundee as well as a specialization in Project Evaluation and Development from Universidad del Rosario. Mr. Hurtado has worked for over 27 years in the oil and gas sector, including extensive experience in executive positions within Ecopetrol and Transportadora de Gas Internacional (TGI). Mr. Hurtado’s professional expertise includes resource management and coordination, processes and project methodologies, the development and operation of hydrocarbon production fields, and gas transport system operation and maintenance processes management, among others.
Carlos Mauricio Ávila Saldarriaga assumed the role of acting Vice President of Hydrocarbons on April 7, 2026. He is a seasoned executive with 30 years of experience in the hydrocarbons industry, bringing deep expertise across exploration and production (E&P) operations, new business development, corporate strategy and planning, finance and project management. Previously, he served as Vice President of Exploration, Development and Production since November 2025. Earlier in his career at the company, he held the position of Joint Venture Assets, as well as leadership roles including Manager of New E&P Businesses, Head of Project Planning, Evaluation, and Portfolio Management, and Production Engineer. Mr. Ávila is a Petroleum Engineer from Fundación Universidad de América, with graduate studies in project management and evaluation, finance, and oil and gas business. His professional background also includes senior leadership roles at Occidental de Colombia Inc., Halliburton, SierraCol, and Frontera Energy, where he led new business development initiatives across Colombia and Latin America.
Bayron Triana Arias has served as Executive Vice President of Energies for the transition at Ecopetrol since August 1, 2025. He is an industrial engineer with a Master’s degree in Business Administration, and an expert in energy markets. He has over 15 years of experience in finance, public policy, commercial strategies, and the development of energy projects. He is currently leading the development of Ecopetrol’s energies for the transition business line and has held strategic roles such as: Manager of Energy Transition Strategy at Ecopetrol; Manager of New Business Development and the Wholesale Energy Market at AIR-E; General Manager at JTL Consultores; and acting CEO of the Colombian Association of Electric Powers Generators – ACOGEN - among others.
Julio César Herrera is the Vice President of Commercial and Marketing since April 23, 2025. He is a Certified Public Accountant from Universidad Javeriana and has completed studies in Marketing and Sales from Kellogg School of Management at Northwestern University in Chicago, as well as in Finance from Wharton School of Business at the University of Pennsylvania. With over 30 years of experience in the oil and gas industry. Throughout his career, he has excelled in leadership roles in Finance and Strategy, Planning, Business Development, Operations, Upstream, Downstream, and Midstream. From his various positions at ExxonMobil, BP, Ecopetrol and other American private energy companies, he has been a key player in complex international ventures across the Americas, the Caribbean, Europe, Africa, the Middle East, and Australia. In recent years, he has focused on Crude and Product trading marketing in the Americas.
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Gabriel Melguizo Posada has served as Acting President of ISA since February 27, 2026, and Chief of Energy Transmission of the Ecopetrol Group since January, 2023. He is an Electrical Engineer from the Polytechnic Institute of Belarus with a Master’s Degree in Engineering Sciences from the same Institute and an MBA from EAFIT University. He has been working at ISA since 1998 and has been in charge of ISA’s energy transmission business unit in Chile for the last four years. As CEO of ISA INTERCHILE, he contributed to strengthening ISA’s presence by ensuring operations and promoting sustainable growth. He previously served as Director of Corporate Operations at ISA. In his 25 years of experience at ISA, he has worked at all levels of the energy transmission business unit as Operations Engineer, Operations Director, Maintenance Director, Deputy Maintenance Manager, and Deputy Technical Manager.
Senior Management Team
Alexander Cadena Motezuma has served as head of the transport and logistics business, as President of Cenit since May 2024. He previously served as President of Ocensa during 2020, President of ODL from 2018 to 2020, and Director of Strategy and New Business at Cenit from 2012 to 2016. Alexander has held multiple leadership positions in Ecopetrol, including New Business Manager for Downstream, Head of the Risk Management Unit in the Financial Vice Presidency, Gas Management Coordinator in the Business Management area, and served as Process Engineer at the Barrancabermeja Refinery. Additionally, he has been member of the board of directors of Ocensa, ODL, ODC, Empresa de Energía de Bogotá, Bioenergy, Gases de la Guajira, Gasoriente, Surtigas, and Invercolsa, among others. A Chemical Engineer from the Universidad Industrial de Santander, Mr. Cadena boasts over 31 years of experience in the energy sector in the areas of production and transportation of hydrocarbons, natural gas, electricity, renewable energies, regulation, and competitiveness. Additionally, he holds a Master’s in Business Administration from Universidad Externado de Colombia.
Felipe Trujillo López is the Vice President of Refining and Industrial Processes of Ecopetrol since January 2025. He has been a member of the board of directors of Ecodiesel, Ecopetrol US Trading, Ecopetrol Trading Asia, Ecopetrol USA and Refinería de Cartagena S.A.S. He is an Industrial Engineer from Pontificia Universidad Javeriana, with a degree in Strategic Marketing from Colegio de Estudios Superiores de Administración - CESA and has an MBA from Universidad de Los Andes. He has 27 years of experience in leadership positions in the commercial and marketing departments, including new business structuring. The last 21 years of his work experience have been in the oil and gas industry at Ecopetrol, working in various positions such as Commercial and Marketing Vice President of the Ecopetrol Group, National Commercialization Manager, Petrochemicals and Industrials Manager, Downstream New Business Manager and Gas Manager.
Julián Fernando Lemos Valero is the Corporate Vice President of Strategy and Business Development since April 23, 2025. He graduated as a Mechanical Engineer from Universidad Nacional de Colombia and has a postgraduate degree in Economic and Social Evaluation of Projects from Universidad de los Andes. Mr. Lemos has around 20 years of professional experience in the energy sector, primarily in the assessment of investment opportunities in energy, gas, petrochemicals, and biofuels. His previous positions include Business Development Manager and Strategy Manager at Mitsubishi Corporation, a Japanese multinational. In Ecopetrol, he has been part of the Corporate Vice Presidency of Strategy and Business Development since 2017, with responsibilities for developing the energy, gas infrastructure, and petrochemicals businesses, among others. He played a prominent role in the team that completed the purchase of ISA in August 2021 and successfully headed the Mergers and Acquisitions Management area from December 2022 to September 2024.
Sandra Lucia Rodriguez Rojas has served as Corporate Vice President of Territorial Transformation and HSE since October 2023. In this role, she is responsible for social prosperity, stakeholder relations, sustainability and environmental management, territorial planning and monitoring, and HSE for hydrocarbons and energy transition. Ms. Rodriguez is a lawyer from Pontificia Universidad Javeriana (Bogotá, Colombia), who specialized in business law at the same university, and in administrative law from Universidad Santo Tomás (Bogotá, Colombia). She holds two master’s degrees from Universidad Carlos III (Madrid, Spain): in public law and in environmental policy and management. Prior to her current position, she served as Colombia’s Deputy Ombudsman for Environmental and Collective Rights beginning in 2018. She is a founding member of the Center for Environmental Law Studies at Pontificia Universidad Javeriana and serves as a professor of administrative and environmental law in graduate programs.
Sergio Andrés Moreno Acevedo was appointed Corporate Vice President of Science, Technology, and Innovation at Ecopetrol on July 28, 2025. He is a Systems Engineer from the Industrial University of Santander, with a degree in Technology Management. He has more than 25 years of experience in transformation, digital strategy, and innovation, having held key roles in globally oriented companies. He has led digital transformation initiatives. His career includes high-responsibility positions with multiple achievements in process optimization from tactical, operational, and strategic perspectives, contributing to operational efficiency and service experience. His skills in transformational leadership, strategic planning, adaptability, critical thinking, innovation, and problem-solving stand out. He serves as CTO (Chief Technology Officer), DPO (Data Protection Officer), and CISO (Chief Information Security Officer) at Ecopetrol S.A. In carrying out these roles, he leads the organization’s cybersecurity and cyber defense strategy, aligning his actions with the vision and objectives of the business strategy.
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Jaime Andrés García Cuello was appointed as Vice President of Administration and Services in September 2024. Prior to this appointment, he was Executive Vice President of Banco Agrario. Mr. Garcia has 24 years of professional experience, having served in strategic positions in both national and multinational companies. His expertise concentrates on supply chain, operations, purchasing, finance, and shared services management, in roles such as Procurement and Supply Chain Director and Human Capital Supply Chain Vice President of ETB S.A. - E.S.P; Vice President of operations of dexFreight Corp.; Procurement, Administrative and Organizational Development Director of Grupo Empresarial Oleoflores; and Procurement Director of DIRECTV Colombia Ltd. He has also served as advisor to board of Directors in companies and has been a professor at the Universidad del Norte in purchasing and supply management, organizational development and culture, and strategic management and organizational design. He graduated as a Civil Engineer from Universidad de los Andes and has a Master’s in Business Administration from Universidad Politécnica de Madrid, Spain.
María Cristina Toro Restrepo has served as Corporate Vice President of Legal Affairs and General Secretary since May 7, 2024. She holds a degree in Law from Universidad de Caldas and a postgraduate degree in Mining-Energy Law at Universidad Externado de Colombia and Commercial Law and Tax and Customs Legislation at Universidad de Caldas. In her 27 years of professional experience, she served as General Secretary of Empresas Públicas de Medellín (EPM), headed the Legal Counsel Office of the Metro de Bogotá, acted as General Secretary of the Metro de Medellín, headed the Labor Relations Management area of EPM, served as General Secretary and Legal Vice President of Grupo Energía de Bogotá, General Secretary of Central Hidroeléctrica de Caldas S.A. and Legal Director of Aguas de Manizales. Ms. Toro is a member of Women in Connection, and both the Women Corporate Directors’ Community and Leadership Advisory Board of CESA, a private business administration college in Bogota.
Rodolfo Mario García Paredes was appointed as Corporate Compliance Director and Compliance Officer of Ecopetrol as of 16 November 2025. Between June 4 and November 15, 2025, he served in this role in an acting capacity. He holds a degree in Law from Universidad del Rosario and a postgraduate degree in Public Management and Institutions’ Administration from Universidad de los Andes. He has more than 25 years of experience in the Corporate Legal and General Secretariat Vice Presidency of Ecopetrol, during which he has held leadership positions such as Hydrocarbons Legal Manager, Exploration Legal Advisory Manager, and New Business and Corporate Legal Manager, among others. He has developed his professional career across various areas of the Oil & Gas sector, including contracting, exploration and production, transportation and refining, as well as in Ecopetrol’s internationalization process and corporate affairs. He has also served on several occasions as Acting Corporate Legal and General Secretariat Vice President.
Victoria Irene Sepúlveda Ballesteros has served as the Corporate Vice President of Organizational Talent since January 19, 2024. She is a lawyer with a postgraduate degree in Commercial Law and holds an MBA, with nearly 20 years of experience in administrative and human management roles. She has extensive expertise in human talent management and labor relations within companies and business groups in the energy sector in Colombia. Previously, she was the Human Management Manager at Chilco, the parent company in Colombia of the Lipigas Group. She has also held corporate roles in business groups as Director of Subsidiaries and Resource Manager. Among her notable projects, her strategic planning stands out, addressing complex situations assertively, constantly seeking to engage with peers and superiors to find the best solutions that add value. She has experience in organizational transformation projects, project management, process management, and continuous improvement.
Ricardo Augusto Montes Gómez has served as Corporate Director of Internal Audit for the Ecopetrol Group since September 1, 2016. Mr. Montes is a Public Accountant from the Universidad Externado of Colombia, holds an MBA (Master in Business Administration) from the INALDE Business School of Universidad de la Sabana of Colombia, and completed the Financial Planning certificate program of Southern Methodist University located in Dallas, USA. He has over 40 years of professional experience both locally and internationally in the Oil & Gas sector, undertaking various leadership roles within Internal Audit and Financial Management, as well as serving as Chief Financial Officer (CFO) and Comptroller of public and private companies within this sector.
Diana Marcela Jimenez Rodriguez is the director of Institutional Relations and Communication since April 23, 2025. She is an electrical engineer from the Universidad de los Andes, with additional qualifications in business administration. She holds a postgraduate degree in Business Administration from UCUF Spain, and an Executive Master’s in Business Administration from EADA Business School. With over 20 years of experience, Diana has held strategic positions in the energy sector both nationally and internationally. She has served as director for the Ecopetrol Group in Gas and LPG, and Regulatory Strategy, and as vice-president for Institutional Relations, Regulation, and the Environment for the Enel Group in Colombia and Central America. Moreover, she has been business development manager (VP) for Enel Group companies in Colombia and advisor to CREG
None of our directors, executive officers or members of senior management has any familiar relationship with any other director, executive officer or member of senior management.
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7.6
Compensation of Directors and Management
Based on a resolution adopted at our annual shareholders’ meeting in 2012, remuneration for directors’ attendance at meetings of the Board of Directors and/or committee meetings was set to six minimum monthly wage salaries, which totals approximately COP 10.5 million for 2026 and COP 8.5 million for 2025. See Note 31.1 to our consolidated financial statements for more details.
During 2025, the total remuneration paid to our Board Directors amounted to COP 4,014 million and the remuneration paid to Executive Officers and senior management amounted to COP 30.47 billion. The latter includes amounts paid to certain directors, executive officers and senior management pursuant to a bonus plan under which such people are entitled to receive variable compensation based on the Company’s results for each year. Ecopetrol has a short-term and long-term variable compensation programs.
The short-term variable compensation for senior management is recognized based on the annual company’s results associated with the achievement of strategic objectives and the goals of the Company’s Balanced Scorecard (“BSC”). 2025 BSC includes metrics based on four strategic pillars: (i) Grow with the Energy Transition (that weighs 35% of the BSC); (ii) Generate Value with sustainability (10%), (iii) Cutting-edge Knowledge (10%), and (iv) Competitive Returns (30%). The remaining 15% of the BSC corresponds to the most important cultural principle for Ecopetrol, “Life First”.
None of the members of our management team are eligible to receive pension and retirement benefits from us.
Implementation of the Long-Term Incentive Plan
Companies have increasingly incorporated incentive compensation plans into their compensation structures, in line with good international practices, to drive exceptional and sustainable results to meet stakeholder expectations. Long-Term Incentives Plans (ILPs for its acronym in Spanish) are designed to generate incremental value for shareholders based on the Company’s proposed objectives and goals. These plans offer senior management a compensation mechanism consistent with the achievement of those strategic objectives and align incentives for beneficiary leaders with the Company’s success in meeting these strategic objectives.
Ecopetrol’s Long-Term Incentives Plans (ILPs for its acronym in Spanish) are managed through a voluntary pension fund administered by a legally authorized financial entity, as required under Colombian law. The fund receives cash contributions from Ecopetrol with the mandate of investing such cash in ordinary shares of the Company, through open market purchases in Colombia. Once the plan expires and the company confirms and provided that the goals are met, the contributions become equity for the beneficiaries, and they will be able to determine the allocation of any earned contributions according to the following options:
Keep the contributions in the portfolio that invests in Ecopetrol shares and over which Ecopetrol does not exercise investment decisions.
Monetize the equity to invest the contributions (totally or partially) in other investment portfolios offered by the fund’s manager.
Monetize the equity by withdrawing the cash (totally or partially) from the fund.
Every year the Board of Directors approves a set of metrics and objectives that align with the corporate strategy and business plan. These objectives are periodically updated and remain in effect for a three-year term. The metrics and objectives are designed to accelerate the Company’s energy transition efforts and ensure the country’s energy sovereignty. They are regularly monitored to verify that the Company remains on track and is making measurable progress toward its strategic goals. Currently, there are three Long-Term Incentives Plans in effect: for 2024-2026, for 2025-2027 and for 2026-2028. The indicators and weights of these plans are: Free Cash Flow - FCF (40%), Return on Average Capital Employed - ROACE (20%), Reserve Replacement Ratio - RRR (20%), and Energy Reduction Cost (20%).
Currently, the ILPs are part of the compensation scheme applicable to the CEO, Vice Presidents, equivalent positions, and other positions at Ecopetrol, according to their level of responsibility and relevant performance criteria. This compensation scheme applies to all of Ecopetrol’s subsidiaries.
7.7
Share Ownership of Directors and Executive Officers
The following table sets forth the executive officers and directors that own shares of Ecopetrol S.A. as of March 16, 2026. Under Colombian law, all of our shareholders have the same economic privileges and voting rights.
Table 70 – Executive Officers and Directors owning Ecopetrol’s shares
Executive Officer
Number of shares(1)
Juan Carlos Hurtado Parra
2,000
0.0000050
Bayron Triana Arias
28,000
0.000068
Controls and Procedures
Disclosure Controls and Procedures
As required by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as of December 31, 2025, we evaluated the design and effectiveness of our financial disclosure controls and procedures under the supervision and participation of our management, including our Chief Executive Officer and Chief Financial Officer. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even if effective, disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.
Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of the end of the period covered by this annual report, our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in the reports that we file and submit under the Securities Exchange Act of 1934 is recorded, summarized and reported as and when required and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a - 15(f) and 15(d) - 15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and monitored by our board of directors, management and other personnel, in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles, and it includes those policies and procedures that: i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets; ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorization of our management and directors; and iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, effective control over financial reporting cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projection of any evaluation of the effectiveness of the internal controls to future periods is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
As of the year ended December 31, 2025, our management conducted an assessment of the effectiveness of our internal control over financial reporting in accordance with the criteria established in the publication “Internal Control – Integrated Framework (2013),” issued by the Committee of the Sponsoring Organizations of the Treadway Commission, as well as the rules set by the SEC in its Final Rule “Management’s Report on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports.”
Consistent with the guidance issued by the SEC that an assessment of recently acquired businesses may be omitted from management’s annual report on internal control over financial reporting in the year of acquisition, management excluded the assessment of the effectiveness of internal control over financial reporting of Wind Autogeneración S.A.S., Córdoba Solar 2 S.A.S., El Roble Solar S.A.S., Enerfin Servicios S.A.S., Girasol 1 S.A.S., La Cayena Solar S.A.S., Parque Solar Portón Del Sol S.A.S. ESP., Planta Solar Sahagún S.A.S. These subsidiaries, which are included in the 2025 consolidated financial statements of the Company, represented 0.25% and 0.33% of total and net assets respectively as of December 31, 2025, and 0.01% and (0.05)% of revenues and net income respectively, for the year then ended. More details regarding these acquisitions can be found in Note 2.3 of our 2025 consolidated financial statements.
Based on the assessment performed, management concluded that our internal control over financial reporting was effective as of December 31, 2025.
The effectiveness of our internal control over financial reporting has been audited by Deloitte & Touche S.A.S., an independent registered public accounting firm, as stated in their audit report accompanying our consolidated financial statements.
Audit and Non-Audit Fees
Our consolidated financial statements for the fiscal year ended December 31, 2025 were audited by Deloitte & Touche S.A.S. Our consolidated financial statements for the fiscal years ended December 31, 2024 and 2023 were audited by Ernst & Young Audit S.A.S.
The following table sets forth the fees billed to us by Deloitte & Touche S.A.S. during the fiscal year ended December 31, 2025.
Table 71 – Fees Billed to us by Deloitte & Touche S.A.S.
COP Millions, excluding 19% Value Added Tax
Audit fees
22,269
Tax fees
All other fees
22,403
Audit Fees. The audit fees listed in the table above are the aggregated fees billed by Deloitte & Touche S.A.S and its affiliates for 2025 in connection with their audits of our annual consolidated financial statements (IFRS), interim consolidated financial statements (under IFRS), statutory audits of Ecopetrol S.A. and its consolidated subsidiaries and some of its associate entities (under local GAAP) and review of periodic documents filed with the SEC. In addition, these audit fees include fees related to our independent auditors’ audits of our internal controls over financial reporting.
All Other Fees. The all other fees listed in the table above are the aggregated fees billed by Deloitte & Touche S.A.S. in connection with the review of our sustainability report.
The following table sets forth the fees billed to us by Ernst & Young Audit S.A.S. during the fiscal years ended December 31, 2025, 2024 and 2023
Table 72 – Fees Billed to us by Ernst & Young Audit S.A.S.
24,649
23,845
24,782
23,977
256
Audit Fees. The audit fees listed in the table above are the aggregated fees billed by Ernst & Young and its affiliates. in connection with their audits of our annual consolidated financial statements (IFRS), interim consolidated financial statements (under IFRS), statutory audits of Ecopetrol S.A. and its consolidated subsidiaries and some of its associate entities (under local GAAP) and review of periodic documents filed with the SEC. In addition, these audit fees include fees related to our independent auditors’ audits of our internal controls over financial reporting.
Tax fees. Tax fees on the above table are fees billed by Ernst & Young for pre-approved services related to technical compliance with tax matters of one of our subsidiaries.
All Other Fees. The all-other fees listed in the table above are the aggregated fees billed by Ernst & Young Audit S.A.S. in connection with the review of our sustainability report.
Changes in Internal Control over Financial Reporting
There were no changes made in our internal control over financial reporting for the year ended December 31, 2025, that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
Attestation Report of the Registered Public Accounting Firm
Deloitte & Touche S.A.S.’s attestation report on our internal control over financial reporting is included in their audit report accompanying our consolidated financial statements. See Report of Independent Registered Public Accounting Firm to the consolidated financial statements.
Clawback Policy
On November 30, 2023, we approved its claw-back policy providing for the recovery of erroneously awarded incentive-based compensation “received” by current and former executive officers in connection with a financial restatement, regardless of fault or misconduct, on or after October 2, 2023. On March 3, 2026, the Board of Directors approved an updated designation of executive officers. A copy of our claw-back policy is attached hereto as Exhibit No. 7.1.
Insider Trading Policy
On March 25, 2025, the Company updated its insider trading prevention policy, which provides the guidelines to assist the members of the Board of Directors and their respective committees, the senior management, employees, interns and trainees of the Company, and anyone who by their job, profession or function has access to non-public information of Ecopetrol, to comply with their obligations under the securities and exchange laws and regulations of the Company’s jurisdiction and the jurisdictions in which the Company’s securities are traded. A copy of our insider trading prevention policy is attached hereto as Exhibit 7.2. On April 22, 2026 the Company updated the insider trading prevention policy, following amendments to Section 16 of the Securities Exchange Act.
257
Consolidated Financial Statements
As of December 31, 2025, and 2024 and for each of the three years ended December 31, 2025, 2024 and 2023
Index
Report of Independent Registered Public Accounting Firm ID 1183
F-3
Report of Independent Registered Public Accounting Firm
F-6
Report of Independent Registered Public Accounting Firm ID 1522
F-8
Consolidated statement of financial position
F-9
Consolidated statement of profit or loss
F-10
Consolidated statement of comprehensive income
F-11
Consolidated statement of changes in equity
F-12
Consolidated statement of cash flows
F-13
Reporting entity
F-14
Basis for preparation
F-18
Accounting policies
F-21
New standards and regulatory changes
F-41
Cash and cash equivalents
F-43
Trade and other receivables
F-45
8.
Inventories
F-47
9.
Other financial assets
10.
F-51
11.
Other assets
F-61
12.
Business combination
13.
Investments in associates and joint ventures
F-63
14.
Property, plant, and equipment
F-66
15.
Natural and environmental resources
F-68
16.
Right-of-use assets and lease liabilities
F-70
17.
Intangible assets
F-71
18.
Impairment of long-term assets
F-72
19.
Goodwill
F-78
20.
Loans and borrowings
21.
Trade and other payables
F-81
22.
Provisions for employees’ benefits
23.
Accrued liabilities and provisions
F-85
24.
F-94
25.
Revenue from contracts with customers
F-97
26.
F-102
27.
Administrative, operative, and project expenses
F-103
28.
Other operating income (expenses)
29.
Financial result
F-104
30.
Risk management
31.
Related parties
F-112
32.
Joint operations
F-114
33.
Business segment information
F-116
34.
Subsequent and relevant events
F-124
Exhibit 1 – Consolidated subsidiaries, associates, and joint ventures
F-128
Exhibit 2 – Consolidated subsidiaries, associates, and joint ventures in Interconexión Eléctrica SA ESP
F-133
Exhibit 3 – Conditions of the most significant debt
F-135
Exhibit 4. Quantitative information of concession services contracts
F-145
Supplemental information on oil and gas producing activities (unaudited)
F-147
F-2
To the shareholders and the Board of Directors of Ecopetrol S.A.
Opinion on the Financial Statements
We have audited the accompanying consolidated statement of financial position of Ecopetrol S.A. and subsidiaries (the “Company”) as of December 31, 2025, the related consolidated statements of profit or loss, comprehensive income, changes in equity, and cash flows, for the year ended December 31, 2025, and the related notes and the schedules listed in the exhibits 1, 2 , 3 and 4 (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025, and the results of its operations and its cash flows for the year ended December 31, 2025, in conformity with IFRS Accounting Standards as issued by the International Accounting Standards Board (IASB).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated April 30, 2026, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Estimation of Oil and Gas Reserves on Significant Accounting Estimates
Critical audit matter description
Oil and gas reserves estimates are used in the calculation of depreciation and depletion expense and impairment loss of oil and gas properties. The risk is the inappropriate determination of oil and gas reserves, impacting these accounting estimates.
As described in Notes 14 and 15 to the financial statements, as of December 31, 2025, the Company has Property, plant and equipment (Property and plant) and Natural and environmental resources (Oil investments) related to oil and gas properties with net book values of $33,015 billion (with an associated depreciation expense of $3,288 billion) and $34,909 billion (with an associated depletion expense of $7,447 billion), respectively. As further described in Notes 14 and 15, reversal of impairment loss of $3 billion and impairment loss of $244 billion were recorded for the year ended December 31, 2025.
The estimation of oil and gas reserves involves subjective judgements and determinations based on available technical, contractual, geopolitical and economic information. Estimates can change over time because of new information from production or drilling activities, changes in economic factors, such as oil and gas prices, changes in the regulatory policies of governments, or other events. Downward adjustments to oil and gas reserves could indicate lower future production volumes and could also lead to revised depreciation, depletion, and amortization rates and to impairment loss of oil and gas properties.
The estimation of oil and gas reserves is a higher risk estimate given the significant judgement by management, including the use of management’s specialists and specialized firms, when developing the estimates of oil and gas reserve volumes, which in turn led to a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating audit evidence obtained related to the data, methods and assumptions used by management (with the assistance of its specialists) in developing the estimates of oil and gas reserves volumes.
The estimates of oil and gas reserves volume are derived from evaluations prepared by the management (with the assistance of management´s specialists). These evaluations include their assessments of the volumes of petroleum initially in place, projected production profiles over time, and other key assumptions. Such assumptions specifically include commodity price forecasts, the expiration dates of applicable licenses, expected capital expenditures, and operating expenditures. The oil and gas reserves volume have been independently reviewed and certified by specialized firms.
How the Critical Audit Matter was Addressed in the Audit
We obtained an understanding of the controls over the Company’s oil and gas reserve estimation process. We then evaluated the design of these controls and tested their operating effectiveness, including management’s review controls over changes to year-on-year estimated oil and gas reserve volumes.
We involved our oil and gas reserve specialists in evaluating the key assumptions and methodologies applied by management.
With the assistance of our oil and gas reserve specialists, our procedures included, amongst others:
F-4
/s/ Deloitte & Touche S.A.S.
Deloitte & Touche S.A.S.
Bogotá, ColombiaApril 30, 2026
We have served as the Company´s auditors since 2025.
F-5
NIT 860.005.813-4
Carrera 9 nro. 78-31. Piso 1
Bogotá, D. C.
Tel: +57 (601) 426 2000
www.deloitte.com/co
To the Shareholders and the Board of Directors of Ecopetrol S.A.
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Ecopetrol S.A. and subsidiaries (the “Company”) as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2025, of the Company and our report dated April 30, 2026, expressed an unqualified opinion on those financial statements.
As described in Management’s Annual Report on Internal Control over Financial Reporting appearing in section 7.8, management excluded from its assessment the internal control over financial reporting at Wind Autogeneración S.A.S., Córdoba Solar 2 S.A.S., El Roble Solar S.A.S., Enerfin Servicios S.A.S., Girasol 1 S.A.S., La Cayena Solar S.A.S., Parque Solar Portón Del Sol S.A.S. ESP., Planta Solar Sahagún S.A.S., which were acquired on November 13. 2025, and whose financial statements constitute 0.25% and 0.33% of total and net assets respectively as of December 31, 2025, and 0.01% and (0.05)% of revenues and net income respectively, of the consolidated financial statement amounts as of and for the year ended December 31, 2025. Accordingly, our audit did not include the internal control over financial reporting at Wind Autogeneración S.A.S., Córdoba Solar 2 S.A.S., El Roble Solar S.A.S., Enerfin Servicios S.A.S., Girasol 1 S.A.S., La Cayena Solar S.A.S., Parque Solar Portón Del Sol S.A.S. ESP., Planta Solar Sahagún S.A.S..
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting appearing in section 7.8. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
F-7
AS-4013-26
We have audited the accompanying consolidated statements of financial position of Ecopetrol S.A. (the Company) as of December 31, 2024 and 2023, the related consolidated statements of profit or loss, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2024, and the related notes and financial statement schedules listed in exhibits 1, 2 and 3 (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity IFRS Accounting Standards as issued by the International Accounting Standards Board (IASB).
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Ernst & Young Audit S.A.S.
A member practice of Ernst & Young Global Limited
We served as the Company’s auditor from 2016 to 2024
Bogotá D.C., Colombia
April 23, 2025
Ernst & Young Audit S.A.S.
Bogotá, D.C.
Medellín – Antioquia
Cali – Valle del Cauca
Barranquilla - Atlántico
Avenida Carrera 72 No. 81B – 13
Carrera 43A No. 3 Sur-130
Avenida 4 Norte No. 6N – 61
Calle 77B No 59 – 61
Piso 15, Torre Fura
Edificio Milla de Oro
Edificio Siglo XXI
Edificio Centro Empresarial
Connecta 80 Conexión Empresarial
Torre 1 – Piso 14
Oficina 502
Las Américas II Oficina 311
Tel. +57 (601) 484 7000
Tel: +57 (604) 369 8400
Tel: +57 (602) 387 6688
Tel: +57 (605) 310 0444
A member firm of Ernst & Young Global Limited
(In billions of Colombian pesos)
Note
Assets
Current assets
10,694
14,054
14,880
20,426
8,609
10,028
1,838
851
Current tax assets
14,514
11,455
2,910
3,845
Total current assets
53,445
60,659
Non–current assets
35,130
32,136
4,389
Investment in associates and joint ventures
8,048
8,652
106,104
107,455
48,407
47,666
Right-of-use assets
994
980
14,041
16,413
Non-current tax assets
8,069
12,908
4,832
5,146
1,692
1,837
Total non–current assets
228,775
237,582
Current liabilities
10,080
11,288
15,759
19,302
Provisions for employee benefits
3,481
3,369
Current tax liabilities
2,368
2,769
1,647
1,620
Other liabilities
1,179
1,286
Total current liabilities
34,514
39,634
Non–current liabilities
99,120
108,677
10,472
14,008
Non-current tax liabilities
14,808
14,929
14,801
12,736
1,766
2,344
Total non–current liabilities
140,967
152,694
Total liabilities
Subscribed and paid in capital
24.1
25,040
Additional paid in capital
24.2
6,608
24.3
30,292
24,156
Accumulated other comprehensive income
24.5
11,752
11,912
Retained earnings
7,691
12,138
Equity attributable to owners of parent
81,383
79,854
Non controlling interest
25,356
26,059
Total equity
(In billions of Colombian pesos, except for basic and diluted earnings per share, which are expressed in Colombian pesos)
(82,057)
(86,481)
(88,178)
Gross profit
Administrative expenses
(5,024)
(5,103)
(5,026)
Operations and project expenses
(5,321)
(5,648)
(5,702)
867
(2,098)
Other operating (expense) income
(636)
1,497
(426)
Financial results
Finance income
2,094
1,748
2,321
Finance expenses
(10,781)
(10,319)
(10,384)
Foreign exchange gain (loss)
2,398
Total financial result
Net profit for the year attributable to:
Basic and diluted earnings per share
24.6
255.1
336.6
512.2
Other comprehensive income
Other comprehensive income that may be reclassified to profit or loss in subsequent periods -net of taxes:
Unrealized (loss) gain on hedges:
Cash flow hedge for future exports
2,814
(2,181)
3,071
Hedge of a net investment in a foreign operation
3,749
(3,326)
6,213
Cash flow hedge with derivative instruments
(85)
Financial instruments measured at fair value
(143)
Foreign currency translation
(11,601)
7,371
(18,178)
(4,797)
1,636
(8,722)
Other comprehensive income that will not to be reclassified to profit or loss in subsequent periods (net of taxes):
Actuarial gain (loss)
22.1
2,355
1,308
(2,734)
Equity financial instruments measured at fair value
2,511
Other comprehensive income for the year, net of tax
(2,286)
2,944
(11,456)
Total comprehensive income for the year, net of tax
12,158
21,443
13,927
Total comprehensive income for the year attributable to:
10,328
17,080
13,938
1,830
4,363
(11)
Attributable to owners of parent
Accumulated
Subscribed
Additional
other
Non
and paid
paid in
comprehensive
Retained
controlling
in capital
capital
income
earnings
interest
equity
Balance as of December 1, 2024
Release of reserves
(12,502)
12,502
Dividends declared
24.4
(8,799)
(2,515)
(11,314)
Equity restitution to minority shareholders
(18)
Appropriation of reserves:
Legal
1,494
(1,494)
Fiscal and statutory reserves
509
(509)
Other reserves
16,635
(16,635)
Other comprehensive income:
Gain (loss) of hedging instruments:
2,826
(12)
3,644
293
(9,361)
(2,240)
Actuarial gains
2,343
Balance as of December 31, 2025
Balance as of December 1, 2023
17,923
8,674
17,462
75,707
24,546
100,253
(8,175)
8,175
(12,829)
(2,764)
(15,593)
Acquisition of subsidiaries
(103)
(56)
(159)
1,906
(1,906)
Occasional
11,993
(11,993)
Loss on hedging instruments:
(2,179)
(3,231)
(95)
(67)
7,607
(236)
1,251
Balance as of December 31, 2024
Balance as of December 31, 2022
8,899
15,797
29,812
86,156
27,748
113,904
Adoption of new standards
Balance as of January 1, 2023, after adoption
29,807
86,151
113,899
(2,491)
2,491
(24,382)
(3,146)
(27,528)
(45)
3,340
(3,340)
7,666
(7,666)
3,075
6,054
(13,762)
(4,416)
Actuarial losses
(2,611)
(123)
Balance as of December 31, 2023
From the year ended December 31,
Cash flow from operating activities:
Adjustments to reconcile the net profit to net cash provided by operating activities:
4,417
12,208
11,516
Depreciation, depletion, and amortization
14, 15, 16, 17
16,107
15,197
13,812
Foreign exchange gain
(52)
(2,398)
Finance cost of loans and borrowings
7,604
7,377
6,924
Finance cost of post–employment benefits and abandonment costs
2,556
2,466
2,197
Write off exploratory assets and dry wells
717
1,108
1,472
(Gain) loss on disposal of non–current assets
(32)
Profit on business combinations
(1,699)
Profit on reversal of fields
(28)
Impairment (recovery) loss of non–current assets
Impairment loss of current assets
346
262
Gain on fair value adjustment of financial assets and interest
(1,486)
(1,675)
(1,972)
(Gain) loss on hedging transactions with derivatives
(710)
(764)
(805)
Loss on the sale of assets held for sale
Hedge ineffectiveness
30.3
Realized (gain) loss on foreign exchange cash flow hedges
(150)
480
Movements in provisions
311
853
Net change in operational assets and liabilities:
296
9,052
(20,439)
897
533
808
(1,290)
(1,277)
507
Tax assets and liabilities
(334)
(1,999)
(5,855)
(549)
(496)
(178)
Provisions and contingencies
(827)
(1,061)
(1,169)
Other assets and liabilities
339
(2,092)
(601)
Income tax paid
(9,029)
(10,219)
(12,832)
Net cash provided by operating activities
33,342
45,127
19,801
Cash flow from investing activities:
Investment in joint ventures
(6)
(20)
Acquisition of subsidiaries, net of cash acquired
(65)
(158)
Consideration paid in business combination, net of cash and cash equivalents
(301)
Consideration paid for the acquisition of assets
(1,109)
(880)
Investment in property, plant, and equipment
(9,773)
(9,521)
(9,350)
Investment in natural and environmental resources
(10,552)
(10,541)
(13,964)
Acquisitions of intangibles
(502)
(866)
(776)
Proceeds from sales of other financial assets
2,265
(2,455)
976
Interests received
1,246
1,627
1,884
Dividends received
13.1
772
425
482
Proceeds from sales of assets
355
729
Net cash used in investment activities
(17,912)
(22,034)
(20,020)
Cash flow from financing activities:
Proceeds from loans and borrowings
20.1
18,402
27,155
34,035
Repayment of loans and borrowings
(15,192)
(26,158)
(21,660)
Interest payments
(8,199)
(7,526)
(6,582)
Lease payments
(641)
(563)
(533)
Payment of restitution of equity to minority shareholders
(30)
(44)
Dividends paid
(11,717)
(15,565)
(5,571)
Net cash used in financing activities
(17,365)
(22,687)
(355)
Exchange difference in cash and cash equivalents
(1,425)
1,312
Net increase (decrease) in cash and cash equivalents
(3,360)
1,718
(3,065)
Cash and cash equivalents at the beginning of the year
12,336
15,401
Cash and cash equivalent at the end of the year
Notes to the consolidated financial statements
(Figures expressed in billions of Colombian pesos, unless otherwise stated)
Ecopetrol S.A. is a mixed economy company, with a commercial nature, formed in 1948 in Bogotá – Colombia, headquarters of the Ecopetrol Group (collectively called “Ecopetrol Group”); which is engaged in commercial and industrial activities related to the exploration, exploitation, refining, transportation, storage, distribution and marketing of hydrocarbons, their derivatives and products, as well as the energy transmission services, design, development, construction, operation and maintenance of road and energy infrastructure projects and the provision of information technology and telecommunications services.
An 11.51% of Ecopetrol S.A.’s shares are publicly traded on the Stock Exchanges of Colombia and New York, USA. The remaining shares (88.49% of the total outstanding shares) are owned by the Colombian Ministry of Finance and Public Credit.
The address of the main office of Ecopetrol S.A. is Bogotá – Colombia, Carrera 13 No. 36 – 24.
2.Basis for preparation
Statement of compliance and authorization of consolidated financial statements
The consolidated financial statements of Ecopetrol S.A. and its subsidiaries as of December 31, 2025 and for each of the three years in the period ended December 31, 2025, 2024 and 2023 have been prepared in accordance with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB).
Accounting policies described in Note 4 have been applied consistently in all years presented.
These consolidated financial statements were approved and authorized for issuance by the Board of Directors of Ecopetrol S.A. in April 30, 2026.
Reclassifications
For presentation purposes, the Ecopetrol Group reclassified the current assets held for sale and non-current trade and other payables within Other assets (Note 11 – Other Assets) and Other liabilities, respectively, in the comparative figures as of December 31, 2024. These reclassifications have no material impact on the items in the statement of financial position, profit or loss, comprehensive income, changes in equity, or cash flows.
Basis for consolidation
The consolidated financial statements were prepared by consolidating all companies set out in Exhibits 1, which are those over which Ecopetrol S.A. exercises direct or indirect control. Control is achieved when the Ecopetrol Group:
a)
the percentage of the Ecopetrol Group’s voting rights relative to the size and apportionment of the shares of other vote holders;
b)
potential voting rights held by the Ecopetrol Group, other vote holders or other parties;
c)
rights arising from other contractual arrangements; and
d)
any additional facts and circumstances that indicate that the Ecopetrol Group has, or does not have, the current ability to direct the relevant activities, at the time that decisions need to be made, including voting patterns at previous shareholders’ meetings.
Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases.
All intercompany assets and liabilities, equity, income, expenses, and cash flows relating to transactions between entities of the Ecopetrol Group were eliminated on consolidation. Unrealized losses are also eliminated. Non–controlling interest represents the proportion of profit, other comprehensive income and net assets in subsidiaries that are not attributable to Ecopetrol shareholders.
The consolidated financial statements as of December 31, 2025 were prepared on the basis that the Ecopetrol Group will continue to operate as a going concern.
The following were the significant changes in the consolidation of the Group:
F-15
Ocensa Ductos S.A.S
In July 2024, Oleoducto Central S.A. acquired 100% of the shares of the company Repsol Ductos de Colombia – RDC (named as of October 2, 2024 as Ocensa Ductos S.A.S.), an entity dedicated to investment activities that currently has a 7.14% investment in Oleoducto de Colombia (ODC), which is a subsidiary of the Ecopetrol Group. The net cash paid corresponds to $157,705.
Econova Technology & Innovation, S.L.
On March 17, 2023, Ecopetrol S.A. concluded the establishment process of the company called Econova Technology & Innovation, S.L., domiciled in Spain. Its main corporate purpose is oriented to activities related to science, technology, and innovation (CT+i). Ecopetrol S.A. is the direct owner of 100% of the share capital, subscribed in accordance with the regulatory requirements of the Spanish jurisdiction.
2.4Basis of measurement
The consolidated financial statements have been prepared on a historical cost basis, except for financial assets and liabilities that are measured at fair value through profit or loss and/or changes in other comprehensive income at the end of each reporting year, as explained in the accounting policies included below.
Historical cost is generally based on the fair value of the consideration given in exchange for goods and services.
The fair value is the price that would be received from selling an asset or that would be paid for transferring a liability among market participants, in an orderly transaction, on the date of measurement. When estimating the fair value, the Ecopetrol Group uses assumptions that market participants would use for pricing an asset or liability at current market conditions, including risk assumptions, which maximize the value (highest and best use) of the asset or liability.
2.5
Functional and presentation currency
The functional currency of Ecopetrol S.A. is the Colombian peso, and these consolidated financial statements are presented in this currency. For each entity of the Ecopetrol Group, its functional currency is determined based of the main economic environment where it operates.
From 2025 onwards, consolidated financial statements are presented in Colombian pesos rounded to the nearest billion (COP $000,000,000), except where otherwise indicated.
2.6
Translation to the presentation currency
The consolidated statements of profit or loss and cash flows of subsidiaries with functional currencies different from Ecopetrol S.A.’s functional currency (Colombian peso) are translated at the exchange rates on the dates of the transaction or based on the monthly average exchange rate. Assets and liabilities are translated at the closing exchange rate, and other equity items are translated at exchange rates at the time of the transaction. All resulting exchange differences are recognized in other comprehensive income. On disposal of all or significant parts of a foreign operation, the proportional cumulative translation adjustment related to the foreign operation is reclassified to profit or loss.
F-16
2.7
Foreign currency transactions
Transactions in foreign currencies are initially recorded by the Ecopetrol Group’s entities at their respective functional currency spot rates at the transactions date. Monetary items denominated in foreign currencies are translated at the functional currency spot rates prevailing at the reporting date. Differences arising on settlement, or translation, or monetary items are recognized in profit or loss, in financial results, net, except those resulting from the conversion of loans and borrowings designated as cash flow hedges (note 4.1.6) or net investment in a foreign operation hedge (note 4.1.7), which are recognized in other comprehensive income within equity. When the hedged item affects the financial results, exchange differences accumulated in equity are reclassified to profit or loss as part of operating results.
Non–monetary items measured at fair value that are denominated in a foreign currency are translated using the exchange rates prevailing on the date when the fair value is determined. The gain or loss arising on translation of non–monetary items measured at fair value is treated in line with the recognition of the gain or loss on the change in fair value of the item. Likewise, non-monetary items recorded at historical cost in foreign currency are converted using the exchange rate on the date of the transaction and are not adjusted for changes in the exchange rate at closing.
2.8
Classification of assets and liabilities as current and non–current
The Ecopetrol Group presents assets and liabilities in the consolidated statement of financial position based on whether assets are classified as current or non–current.
An asset or liability is classified as current when:
Other assets and liabilities are classified as non–current.
Deferred tax assets and liabilities are classified as non–current assets and liabilities.
2.9
Earnings per share
Basic earnings per share is calculated by dividing the profit for the year attributable to ordinary shareholders of Ecopetrol S.A., the parent company, by the weighted average number of ordinary shares outstanding during the year. There is no potential dilution of shares.
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3.Material accounting judgments and estimates
The preparation of the consolidated financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts of assets, liabilities, sales, cost of sales, income, expenses and commitments recognized in the consolidated financial statements and the accompanying disclosures. The Ecopetrol Group based its assumptions and estimates on parameters available when these consolidated financial statements were prepared. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to the carrying amount of assets or liabilities affected in future years. Changes in estimates are adjusted prospectively in the year in which the estimate is revised.
In the process of applying the Ecopetrol Group’s accounting policies, management has made the following judgments and estimates which have the most significant impact on the amounts recognized in the consolidated financial statements:
Oil and gas reserves
Oil and gas reserves are estimates of the amounts of hydrocarbons that can be economically and legally extracted from the Ecopetrol Group’s oil and gas properties.
The reserves estimation is performed annually as of December 31 in accordance with the United States Securities and Exchange Commission (SEC) definitions and rules set forth in Rule 4–10(a) of SEC Regulation S–X and the disclosure guidelines contained in the SEC final rule – Modernization of Oil and Gas Reporting.
As required by current regulations, the future estimated date on which a field will no longer produce for economic reasons, is based on actual costs and average of crude prices (calculated as the arithmetical average of prices on the first day of the past 12 months). The estimated date for end of production will affect the amounts of reserves, unless the prices have been defined by contractual agreements; therefore, if the prices and costs change from one year to the next, the proved reserves estimate also changes. Generally, our proved reserves decrease as prices go down and increase when prices go up.
Reserves estimation is an inherently complex process, and it involves professional judgments. Reserves estimation is prepared using technical and economic factors, including projections of future production volumes, oil prices, engineering data and duration and amounts of future investments, and they imply a certain degree of uncertainty. These estimations reflect the regulatory and market conditions existing on the date of reporting, which could significantly differ from other conditions during the year or in future years.
Any changes in regulatory and/or market conditions and assumptions could materially affect the reserves estimation.
Impact of oil reserves and natural gas in depreciation and depletion
Changes to estimations for proved developed reserves may affect the carrying amounts of exploration and production assets, natural resources and environment, liabilities for dismantling and depreciation and depletion. With all other variables remaining unchanged, a decrease in estimated proved developed reserves would increase, prospectively, depreciation, depletion, and amortization costs, while an increase in proved developed reserves would reduce depreciation and amortization expenses, as depreciation, depletion and amortization charges are calculated using the units of production method.
Information about the carrying amounts of exploration and production assets and the amounts charged to income, including depreciation and depletion, is presented in Notes 14 and 15. In addition, the movements of proved developed reserves is presented in Note 34.
Impairment (recovery) of long-term non-monetary assets
Management of the Ecopetrol Group uses its professional judgment in assessing the existence of evidence of an impairment loss or reversal, based on internal and external factors.
When an indicator of impairment loss or reversal of impairment of prior year impairment exists, the Ecopetrol Group estimates the recoverable amount of the cash generating units (CGU), which is considered the greater of fair value less costs of disposal and the value in use.
The assessments require the use of estimates and assumptions, such as, among other factors: (1) future investments and costs; (2) useful life of assets; (3) future prices, and (4) discount rate before taxes, which is reviewed annually, and is determined as the weighted average cost of capital (WACC). Specifically, for crude oil and gas assets, the following are also included: (5) estimation of volumes and market value of oil and natural gas reserves and (6) production profiles of oil fields and future production of refined and chemical products. The recoverable amount is compared with the net book value of the asset, or of the cash-generating unit (CGU), thus determining whether the asset is impaired or if the impairment recognized in prior years should be reversed.
A previously recognized impairment loss is reversed, only if there has been a change in the assumptions used to determine the assets or in the CGU’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of an asset or CGU, other than goodwill, does not exceed either its recoverable amount, or the carrying amount that would have been determined (net of amortization or depreciation) had no impairment loss been recognized for the asset or CGU in prior years.
Future oil and refined products prices assumptions are estimated at current market conditions. For oil and gas asset, expected production volumes, which comprise proven, unproved, probable, and possible reserves are used for impairment testing because Management believes this to be the most appropriate indicator of expected future cash flows, which would also be considered by market participants. Reserves estimates are inherently imprecise and subject to uncertainty risk. Furthermore, projections about unproved volumes are based on information that is necessarily less robust than what is available for mature reservoirs.
These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may also impact the recoverable amount of assets and/or CGUs, hence, may also affect the recognition of an impairment loss or the reversal of prior years impairment amounts.
Also, in December of each year, the Ecopetrol Group performs an annual impairment test on goodwill to assess if its carrying amount may be recoverable. Goodwill is assigned to each cash generating unit (or groups of CGU). The determination of the recoverable amount is described in Note 4.11, and its calculation requires assumptions and estimates. The Ecopetrol Group considers that the assumptions and estimations used are reasonable and supportable based on the current market conditions and are aligned to the risk profile of the related assets. However, if different assumptions and estimations are used, they could lead to different results. Valuation models used to determine fair value are sensitive to changes in the underlying assumptions. For example, sales volumes and prices that will be paid for the purchase of raw materials are assumptions that may vary in the future. Adverse changes in any of these assumptions could lead to the recognition of goodwill impairment.
Exploration and evaluation costs
The application of the Ecopetrol Group’s accounting policy for exploration and evaluation costs requires judgment to determine whether future economic benefits are likely, either from future exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. Certain exploration and evaluation costs are initially capitalized when it is expected that commercially viable reserves will result. The Ecopetrol Group uses its professional judgment of future events and circumstances and makes estimates to assess annually the generation of future economic benefits for extracting oil resources, as well as technical and commercial analyses to confirm its intention of continuing their development. Changes regarding available information, such as level of drilling success or changes in the project’s economics, production costs, and investment levels, as well as other factors, may result in capitalized exploration drilling costs being recognized in profit or loss for the year. The expenses for dry wells (write - off of exploratory assets and dry wells), as a cost of the year, are included in the adjustments to reconcile the net profit to net cash provided by operating activities in the consolidated statement of cash flows.
Determination of cash generating units (CGU)
The allocation of assets in cash generating units requires significant judgment, as well as assessments regarding integration among assets, the existence of active markets, and similar exposure to market risk, shared infrastructure, and the way in which management monitors the operations. See Note 4.13 – Impairment of long-term non-monetary assets for more information.
F-19
3.5
Abandonment and dismantling costs of fields and other facilities
According to environmental and oil regulations, the Ecopetrol Group is required to bear the costs for the abandonment of oil extraction, refining plants and transportation facilities, which include the cost of plugging and abandoning wells, dismantling facilities, and environmental remediation in the affected areas.
Estimated abandonment and dismantling costs are recorded at the time of the installation of the assets and are reviewed annually.
The calculations for these estimations are complex and involve significant judgments by Management. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing, extent and amount of expenditure may also change, for example, in response to changes in internal cost projections, changes in reserve estimates, future inflation rates and discount rates. The Ecopetrol Group considers that the abandonment and dismantling costs are reasonable, based on the experience of the Ecopetrol Group and market conditions; nevertheless, significant variations in external factors used for the calculation of the estimation could significantly impact the amounts recorded in the consolidated financial statements. See Note 4.14 - Provisions and contingent liabilities (asset retirement obligation).
Pension plan and other benefits
The determination of expenses, liabilities and adjustments relating to pension plans and other defined retirement benefits makes it necessary for Management to use its judgment in the application of actuarial assumptions made in the actuarial calculation. The actuarial assumptions include estimates regarding future mortality, retirement, changes in compensation, and discount rate to reflect the time value of money, in addition to the rate of return on the plan’s assets. Due to the complexity in the valuation of these variables, as well as their long-term nature, the estimated amounts are quite sensitive to any change in these assumptions.
These assumptions are reviewed on an annual basis and may differ materially from actual results due to changes in economic and market conditions, regulatory changes, judicial rulings, higher or lower retirement rates, or longer or shorter life expectancies among employees.
Litigation
The Ecopetrol Group is subject to claims relating to regulatory and arbitration proceedings, tax assessments, and other claims arising in the normal course of business. Management evaluates these claims based on their nature, the likelihood that they materialize, and the amounts involved, to decide on the amounts recognized and/or disclosed in the consolidated financial statements.
This analysis may require considerable judgments, including the assessment of current regulatory and arbitration proceedings, tax assessments and other claims brought against the Ecopetrol Group and claims not yet initiated. The Ecopetrol Group recognizes a provision when it has a present obligation derived from a past event, it is likely that an outflow of resources of economic benefits will be required to settle the obligation, and a reliable estimate of the amount of such obligation can be made.
Income taxes
Calculating the income tax requires interpreting the tax law in the jurisdictions where the Ecopetrol Group operates. Significant judgment is required to determine estimates for income tax on taxable profits and to evaluate the recoverability of deferred tax assets. These estimates are based on projections of future taxable income and the capacity to generate sufficient taxable income during the periods in which the deferred taxes are deductible. Deferred tax liabilities are recorded according to the estimates of net assets that will not be tax-deductible in the future.
To the extent that future cash flows and taxable income differ significantly from the estimates, the Ecopetrol Group’s ability to realize the deferred tax assets recorded could be affected.
Furthermore, changes in tax rules could impact the capacity of the Ecopetrol Group to obtain tax deductions in future years, as well as the recognition of new tax liabilities resulting from auditing conducted by the tax authorities.
F-20
Tax positions taken involve a thorough assessment by Management and are reviewed and adjusted in response to situations such as expiration in the applicability of laws, closing of tax audits, additional disclosures caused by any legal issue or a court decision relevant to a particular tax issue. The Ecopetrol Group records provisions based on estimated potential liabilities that could be derived from a tax audit. The amount of these provisions depends on factors such as previous experience in tax audits and different interpretations of tax legislation. The actual results may differ from the estimates recorded.
3.9Hedge accounting
The process of identifying hedging relationships between hedged items and the underlying instruments (derivative and non–derivative, such as long–term, foreign currency–denominated debt), and their corresponding effectiveness, requires the use of judgment by Management. The Ecopetrol Group periodically monitors the alignment between its hedge instruments and its risk management policy.
3.10Traffic projections for road concessions
The revenue for the services provided under the road concessions related to certain contracts, which are accounted for using the financial asset model of IFRIC 12, is calculated through the present value of future revenue cash flow. This estimation is based on traffic studies made by an independent entity based on GDP (Gross domestic product) projections among other variables according to the concession.
4.Accounting policies
Financial instruments
A financial instrument is any contract that creates a financial asset for an entity and a financial liability or equity instrument for another entity. This concept includes elements such as debt instruments, shares (without control, joint control or significant influence), accounts payable, accounts receivable, financial derivatives, among others.
The classification of financial instruments depends on the nature and purpose for which the financial assets or liabilities were acquired and is determined at the time of initial recognition. Financial assets and financial liabilities are initially measured at their fair value.
Transaction costs that are directly attributable to the acquisition or issuance of financial assets and liabilities, other than those measured at fair value through profit or loss, are added to or deducted from the fair value of financial assets and liabilities on initial recognition. Transaction costs directly attributable to the acquisition of financial assets and liabilities measured at fair value through profit or loss are immediately recognized in profit or loss.
Loans and borrowings (See Note 20 – Loans and borrowings) and trade and other receivables (See Note 7 - Trade and other receivables) and financial assets (See Note 9 – Other financial assets) held to maturity are subsequently measured at amortized cost using the effective interest rate method. However, for those receivables and payables for which payment is expected to be received or made in the short term, their subsequent recognition corresponds to transaction value, considering that the effect of the value of money over time is not material due to short maturities.
Additionally, equity instruments are measured at fair value.
Measurements at fair value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in the principal market of the asset or liability or in the absence of a principal market in the most advantageous market.
The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that the market participants act in their best economic interest.
A fair value measurement of a non-financial asset considers a market participant’s ability to generate economic benefits by using the asset for its most profitable use or by selling it to another market participant that would use the asset in its highest and best use.
The Ecopetrol Group uses valuation techniques that are appropriate for the circumstances and for which the data is available and enough to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs.
All assets and liabilities for which fair value is measured or disclosed in the financial statements are classified within the following scale, based on the lowest level input that is significant to the fair value measurement, as follows:
For derivative contracts for which a quoted market price is not available, fair value estimates are generally determined using models and other valuation methods, the key inputs for which include future prices, volatility estimates, price correlation, counterparty credit risk, and market liquidity, as appropriate.
Effective interest rate method
The effective interest rate method is a method of calculating the amortized cost of a financial instrument and accounting of income or financial cost over the relevant year. The effective interest rate is the discount rate that exactly discounts estimated future cash receipts or payments (including all fees, transaction costs and other premiums or discounts) through the expected life of the financial instrument (or, when appropriate, at a shorter period), to the net carrying amount on initial recognition.
Impairment
The Ecopetrol Group measures expected credit losses on financial assets using both the simplified model (for instruments such as current trade receivables) and the general model (for other financial instruments measured at amortized cost) in accordance with IFRS 9. Under these models, an impairment is recognized for expected credit losses based on possible default events within twelve (12) months for long-term performing assets and short-term assets, or over the lifetime of the financial instrument for those long-term assets that have experienced a significant increase in credit risk since initial recognition. The Group updates the expected loss amount at each reporting date to reflect changes in credit risk since initial recognition. In determining the recoverable amount, it considers variables such as the historical payment behavior of the obligations, the debtor’s geographic location, and any collateral provided by the counterparty to mitigate the risk of default.
The measurement of expected credit losses is based on a forward‑looking credit assessment at the portfolio or individual‑instrument level to ensure that assets are not overstated in the financial statements.
4.1.1
Cash and cash equivalents include cash on hand, financial investments that are highly liquid, bank deposits, and special funds with original maturity dates of ninety days or less which are subject to an insignificant risk of changes in value.
F-22
4.1.2Financial assets
The classification of financial assets at initial recognition depends on the financial asset’s contractual cash flow characteristics and the Ecopetrol Group’s business model for managing them. Except for trade receivables that do not contain a significant financing component or for which the Ecopetrol Group has applied the practical expedient,the Ecopetrol Group initially measures a financial asset at its fair value plus, and, in the case of a financial asset not at fair value through profit or loss, at transaction costs. Trade receivables that do not contain a significant financing component or for which the Ecopetrol Group has applied the practical expedient are measured at the transaction price determined under IFRS 15.
The Ecopetrol Group classifies its financial assets in the following categories:
Financial assets measured at fair value with changes in other comprehensive income
Debt instruments that meet the following conditions are subsequently measured at fair value through other comprehensive income:
Credit losses and interest of debt instruments measured at fair value with changes in other comprehensive income are recognized in profit or loss. Changes in fair value recorded in other comprehensive income is reclassified to profit and loss when realized.
For equity instruments, at initial recognition, the Group may make an irrevocable election to designate investments in equity instruments at fair value through other comprehensive income. The election to measure equity instruments at fair value through other comprehensive income is not permitted if the equity investment is held for trading or represents contingent consideration recognized by an acquirer in a business combination.
Equity investments measured at fair value through other comprehensive incomes are initially recognized at fair value plus transaction costs. Subsequently, they are measured at fair value, with gains and losses arising from changes in fair value recognized in other comprehensive income and accumulated in the investment revaluation reserve. The cumulative gain or loss cannot be reclassified to profit or loss upon disposal of the equity investments; instead, it is transferred to retained earnings. Dividends are recognized in profit and loss.
Financial assets at amortized cost
This category is the most relevant to the Ecopetrol Group. The Group’s financial assets at amortized cost include trade receivables, other receivables, trade and other payables, and borrowings.
The Ecopetrol Group measures financial assets at amortized cost if both of the following conditions are met:
Financial assets measured at amortized cost are subsequently measured using the effective interest method, net of impairment. Gains and losses are recognized in profit or loss when the asset is derecognized, modified, or impaired.
F-23
Financial assets at fair value with changes in profit or loss
By default, all other financial assets are subsequently measured at fair value through profit or loss.
This category includes financial assets that do not fall within the previously mentioned classifications (amortized cost and fair value through other comprehensive income). Changes in the fair value of these instruments are recognized in profit or loss for the year.
Derecognition of financial assets
The Ecopetrol Group derecognizes a financial asset only upon the expiration of the contractual rights to the cash flows of the asset or, when it has transferred its rights to receive such cash flows or has assumed the obligation to pay the cash flows received in full without material delay to a third party and (a) it has transferred substantially all the risks and benefits inherent in the ownership of the financial asset or (b) it has neither transferred nor retained substantially all the risks and benefits of the asset, but has transferred control of the asset.
When the Ecopetrol Group has neither transferred nor retained substantially all the risks and rewards of the asset, nor transferred control of the asset, the Ecopetrol Group continues to recognize the asset to the extent of its continuing involvement and recognizes the associated liability for the amounts payable. If the Group retains substantially all the risks and rewards of ownership of a transferred financial asset, it continues to recognize that financial asset and recognizes a secured borrowing for the funds received.
4.1.3Financial liabilities
Financial liabilities correspond to the financing obtained by the Ecopetrol Group through bank credit facilities and bonds, accounts payable to suppliers, and creditors.
Bonds and bank credit facilities are initially recognized at their fair value, net of directly attributable transactions cost. After initial recognition, interest–bearing credit facilities and bonds are subsequently measured at amortized cost, using the effective interest rate method. The effective interest method amortization is included as a financial expense in the statement of profit or loss. Amortized cost is calculated by considering any discount or premium on acquisition and fees or costs that are an integral part of the effective interest rate (EIR). The EIR amortization is included as finance costs in the statement of profit or loss.
Accounts payable to suppliers and other creditors are short-term financial liabilities recognized at their transaction value upon subsequent recognition, considering that the effect of the time value of money is not significant as they have short maturities.
Derecognition of financial liabilities
A financial liability is derecognized when the obligation specified in the contract is discharged, cancelled, or expires. When an existing financial liability has been replaced by another from the same lender, under substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as the de–recognition of the original liability and recognized as a new liability. The difference between the respective carrying amounts is recognized in the statement of profit or loss.
4.1.4Derivative financial instruments
Derivative financial instruments are initially recognized in the consolidated statement of financial position as assets or liabilities at their fair value. Subsequent changes in fair value are recorded in profit or loss in the consolidated statement of profit or loss, except when they are designated as cash flow hedges, in which case such changes are recognized in other comprehensive income and subsequently reclassified to profit or loss when the hedged item affects profit or loss.
Gains or losses arising from derivative financial instruments that are neither qualified nor designated as hedges, including forward contracts for the purchase and sale of commodities that are traded for physical delivery or receipt of commodity, are recognized in the consolidated statement of profit or loss.
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4.1.5Hedging operations
For purposes of hedge accounting, hedges are classified as:
At the inception of a hedge relationship, the Ecopetrol Group formally designates and documents the hedge relationship to which it wishes to apply hedge accounting and the risk management objective and strategy for undertaking the hedge. Such hedges are expected to be highly effective in achieving offsetting changes in fair value or cash flows and are assessed on an ongoing basis to determine whether they have been highly effective throughout the financial reporting years for which they were designated.
4.1.6
Cash flow hedge
The effective portion of the gain or loss on the hedging instrument is recognized in Other Comprehensive Income (OCI) in the cash flow hedge reserve, while any ineffective portion is recognized immediately in the statement of profit or loss, within net financial results. The amounts previously accumulated in OCI are recognized in profit or loss when the hedged transaction affects the statement of profit or loss. If the hedged item is a non - financial asset or liability, the amounts previously recognized in OCI are transferred as a reclassification adjustment and included in the initial carrying amount of the cost of the non - financial asset or liability.
If the hedging instrument expires or is sold, terminated, or exercised without replacement or rollover, or if its designation as a hedge is revoked or when the hedge no longer meets the criteria for hedge accounting, any cumulative gain or loss previously recognized in other comprehensive income remains separately in equity until the forecast transaction occurs is recognized in the consolidated statement of profit or loss. When it is no longer expected that the originally hedged transaction will occur, any amount accumulated in equity is immediately recognized in the consolidated statement of profit or loss.
The Ecopetrol Group designates certain loans as a hedging instrument for its exposure to exchange rate risk in future crude oil exports. Additionally,The Group enters positions with derivative financial instruments such as commodity swaps, cross currency swaps or interest rate swaps to hedge commodity price risks, exchange rate risk and interest rate risk, respectively, which may also be designated as cash flow hedges.
4.1.7Hedge of net investment in a foreign operation
Hedges of a net investment in a foreign operation are accounted for similarly to cash flow hedges.
Gains or losses on the hedging instrument relating to the effective portion of the hedge are recognized as OCI while any gains or losses relating to the ineffective portion are recognized in the statement of profit or loss. On the disposal of a foreign operation, the cumulative value of any such gains or losses recorded in equity is transferred to the statement of profit or loss.
The Ecopetrol Group designates long–term loans as hedging instruments for its exposure to foreign exchange risk on its investment in subsidiaries whose functional currency is the U.S. dollar. See Note 29- Financial result.
4.1.8Fair value hedge
The gain or loss on the hedging instrument is recognized in profit or loss or other comprehensive income if the hedging instrument hedges an equity instrument for which an entity has elected to present changes in fair value in other comprehensive income.
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The hedging gain or loss on the hedged item shall adjust the carrying amount of the hedged item (if applicable) and be recognized in profit or loss. If the hedged item is a financial asset (or a component thereof) that is measured at fair value through other comprehensive income, the hedging gain or loss on the hedged item shall be recognized in profit or loss.
Inventories are recorded at the lower of cost and net realizable value.
Inventories mainly comprise crude oil, fuels and petrochemicals, and materials for goods production.
The cost of crude oil, fuels and petrochemicals includes the production costs and the transportation costs related to the process of giving the products the current conditions and locations. Inventories of crude oil, fuels and petrochemicals are valuated using weighted average method.
The cost of materials for goods production (mainly raw materials) is determined based on the weighted average cost method, which includes acquisition costs (deducting commercial discounts, rebates, and other similar items), transformation, and other costs incurred to bring inventory to their current location and condition, such as transportation costs.
Materials for goods production are recognized as inventory and then charged to expense, maintenance, or project to the extent that such items are consumed.
The Ecopetrol Group estimates the net realizable value of inventories at the end of the year. When the circumstances that previously caused inventories to be written down below cost no longer exist, or when there is clear evidence of an increase in the net realizable value because of a change in economic circumstances, the amount of the write down is reversed. The reversal cannot be greater than the amount of the cumulative write-down, so that the new carrying amount will always be the lower of the cost and the revised net realizable value.
Related parties are considered those where one of the parties can control the other, has joint control, or exercises significant influence in the financial or operational decision making of the investee or is a member of key management personnel (or close family member of key personnel). The Ecopetrol Group has considered as related parties the associated companies, joint businesses, key management executives, the entities managing the resources for payment of post-employment benefit plans for employees and some relevant transactions entered with entities of the Colombian Government, such as the purchase of hydrocarbons and the oil stabilization fund. (See Note 31 – Related Parties).
4.3.1Investments in associates
An associate is an entity over which the Ecopetrol Group has significant influence but not control. Significant influence is the power to participate in the financial and operational policy decisions of the investee, but it is not control or joint control over those policies. Generally, these entities are those in which the Ecopetrol Group holds an equity interest with voting rights of 20% to 50%. (See Exhibit 1 and 2 – Consolidated subsidiaries, associates, and joint ventures).
Investments in associates are accounted for using the equity method. Under this method, the investment in an associate is initially recognized at cost. The carrying amount of the investment is adjusted to recognize changes in the Ecopetrol Group’s share of net assets of the associate since the acquisition date. Goodwill related to the associate is included in the carrying amount of the investment and it is not tested for impairment separately.
The Ecopetrol Group’s share of the results of operations of the associate is recognized in the consolidated statement of profit or loss. Any change in the investee’s other comprehensive income is recognized by the Group.
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After application of the equity method, the Ecopetrol Group determines if it is necessary to recognize an impairment on its investment in its associate. The Ecopetrol Group determines at each reporting date whether there is objective evidence that the investment is impaired. If there is such evidence, the amount of impairment is calculated as the difference between the recoverable amount and the carrying value, and then the impairment is recognized in the consolidated statement of profit or loss.
When necessary, the Ecopetrol Group adjusts the accounting policies of associates to ensure consistency with the policies adopted by the Group. Additionally, the equity method of these companies is measured on their most recent financial statements.
Joint ventures
A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. Joint control exists only when decisions about the relevant activities require unanimous consent of the parties sharing such control. The accounting treatment for the recognition of joint ventures is the same as investments in associates.
A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement.
Joint operation contracts are entered into between the Ecopetrol Group and third parties to share risk, secure capital, maximize operating efficiency, and optimize the recovery of reserves. In these joint operations, one party is designated as operating partner to execute the operations and report to partners according to their participating interests. Likewise, each party takes its share of the produced hydrocarbons (crude oil or gas), according to their share in production.
When the Ecopetrol Group acquires or increases its participation in a joint operation in which the activity constitutes a business combination, such transaction is recognized applying the acquisition method in accordance with IFRS 3 – Business combination. The acquisition cost is the sum of the consideration transferred, which corresponds to the fair value, on the date of acquisition of the assets transferred and the liabilities incurred.
The excess of the sum of the consideration transferred and the amount paid in the operation is recognized as goodwill. If the result is in an excess value of the net assets acquired over the amount paid in the purchase transaction, the difference is recognized as income in the consolidated statement of profit or loss on the date of recognition of the transaction.
Non–current assets held for sale
Non–current assets are classified as held for sale if their carrying values will be recovered principally through a sale transaction rather than through continued use. Non–current assets are classified as held for sale only when the sale is highly probable within one year from the classification date and the asset (or group of assets) is available for immediate sale in its present condition. These assets are measured at the lower of their carrying amount and fair value less related costs of disposal.
Recognition and measurement
Property, plant, and equipment are stated at cost less accumulated depreciation and impairment losses. Tangible components related to natural and environmental resources are part of property, plant, and equipment.
The initial cost of property, plant and equipment comprises its purchase price or construction cost, including import duties and non–refundable purchase taxes, any costs directly attributable to bringing the asset into operation, costs of employee benefits arising directly from the construction or acquisition, borrowing costs incurred that are attributable to the acquisition and construction of qualifying assets and the initial estimate of the costs of dismantling and abandonment of the property, plant and equipment.
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Spare parts and servicing equipment are recorded as inventories and recognized as an expense as they are used. Major spare parts and stand–by equipment that the Ecopetrol Group expects to use during more than one year are recognized as property, plant, and equipment.
Any gain or loss arising from the disposal of a property, plant, and equipment is recognized in the consolidated statement of profit or loss.
Subsequent disbursements
Subsequent disbursements correspond to all payments to be made on existing property, plant and equipment to increase or extend the initial expected useful life, increase productivity or productive efficiency, allow for significant reduction of operating costs, increase the level of reserves in exploration or production areas or replace a part or component of a property, plant and equipment that is considered critical for the operation.
The costs of repair, conservation and maintenance of a day-to-day nature are expensed as incurred. However, disbursements related to major maintenance (primarily including replaced components) are capitalized.
Depreciation
Property, plant, and equipment is depreciated using the straight–line method, except for those associated with exploration and production activities which are depreciated using the units–of–production method. Technical useful lives are updated annually considering factors such as: additions or improvements (due to parts replacement or critical components for the asset’s operation), technological advances, obsolescence, and other factors; the effect of this change is recognized from the year in which it was executed. Depreciation of an asset starts when it is ready to be used.
Useful lives are determined based on the year over which a property, plant and equipment is expected to be available for use, physical exhaustion, technical or commercial obsolescence and legal limits or restrictions over the use of the property, plant and equipment. Depreciation is classified as cost or expense, depending on the activities for which the assets are used.
The estimated useful life of property, plant and equipment fluctuates in the following ranges:
Plant and equipment
18 –100 years
Pipelines, networks, and lines
16 – 63 years
Buildings
18 – 55 years
9 – 30 years
Lands are recognized separately from buildings and facilities, have unlimited useful lives, and they are not subjected to depreciation.
Depreciation methods and useful lives are reviewed annually and adjusted prospectively if appropriate.
Property, plant and equipment are subject to review for possible impairment in their recoverable amount. See notes 3.2 – Impairment (recovery) of long – term non-monetary assets and 4.13 – Impairment of long – term non-monetary assets.
The Ecopetrol Group uses the successful efforts method to account for exploration and production of crude oil and gas activities, following the provisions of IFRS 6 – Exploration for and evaluation of mineral resources.
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Acquisition and exploration costs are recorded as assets in natural and environmental resources until the determination of whether the exploration drilling is successful or not; if determined to be unsuccessful, all acquisition and exploration costs incurred are recognized as expenses in the consolidated statement of profit or loss as operations and project expenses.
Exploration costs are those incurred with the objective of identifying areas that are considered to have prospects of containing oil and gas reserves, including geological and geophysical, seismic costs, viability, and others, which are recognized as expenses when incurred. Furthermore, disbursements associated with the drilling of exploratory wells and those related to stratigraphic wells of an exploratory nature are recorded as assets until it is determined if they are commercially viable; otherwise, they are recognized in the consolidated statement of profit or loss as operations and project expenses. Other expenditures are recognized as expenses when incurred.
An exploration and evaluation asset will not be classified as such when the technical feasibility and commercial viability of extracting a mineral resource are demonstrable. Exploration and evaluation assets are assessed for impairment, and any impairment loss is recognized prior to reclassification.
All exploration and evaluation assets are subjected to technical and commercial revisions at least once a year to confirm the evaluation and exploration efforts continue the fields; otherwise, these exploration and evaluation assets are written off through to profit or loss.
Development costs
Development costs correspond to those costs incurred to obtain access to prove reserves and to provide facilities for extracting, treating, gathering, and storing. When a project is approved for development, the corresponding exploration and evaluation assets are classified as natural and environmental resources and costs incurred after the exploration phase are capitalized as development costs of the properties that contain such natural resources. All development costs are capitalized, including drilling costs of unsuccessful development wells.
Production costs
Production costs are those incurred to operate and maintain productive wells and are part of the corresponding equipment and facilities. Production activity includes extraction of oil and gas to the surface, its gathering, treatment, and processing as well as storage in the field. Production costs are expenses recorded in the consolidated statement of profit or loss as incurred unless they add oil and gas reserves, in which case they are capitalized.
Production and support equipment are recognized at cost and is part of property, plant, and equipment subject to depreciation.
Capitalized costs also include decommissioning, dismantling, retiring, and restoration costs, as well as the estimated cost of future environmental obligations. The estimated cost includes plugging and abandonment costs, facility dismantling and environmental remediation of areas and wells. Changes arising in new abandonment liability estimations and environmental remediation are capitalized in the carrying amount of the related asset.
Capitalized costs also include the value of revenues obtained, net of costs, from the sale of crude oil from extended well tests, as these are considered necessary to complete the asset.
Depletion
Depletion of natural and environmental resources is determined using the unit–of–production method per field, using proved developed reserves as a base, except in limited exceptional cases that require greater judgment by Management to determine a better depletion factor of future economic benefits over the useful life of the asset. Depreciation/depletion rates are reviewed annually, based on proved developed reserves reports and the impact of any changes in such factors on depreciation/depletion cost is recognized prospectively in the consolidated financial statements.
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Proved developed reserves are independently estimated by internationally recognized external consultants and approved by Ecopetrol’s Board of Directors. Proved developed reserves consist of the estimated quantities of crude oil and natural gas demonstrated with reasonable certainty by geological and engineering data to be recoverable in future years from known reserves under existing economic and operating conditions, which are at the prices and costs that apply for the date of the estimation.
Assets associated to exploration, evaluation and production are subject to review for possible impairment in their carrying amount. See Notes 3.2 — Impairment (recovery) of long – term non-monetary assets, 4.13 — Impairment of long-term non-monetary assets.
Capitalization of borrowing costs
Borrowing costs related to the acquisition, construction or production of a qualifying asset that requires a substantial year to get ready for its intended use are capitalized as part of the cost of such asset when it is probable that future economic benefits associated with the asset will flow to the Ecopetrol Group and costs can be measured reliably. Other borrowing costs are recognized as financial expenses. Projects that have been suspended but that the Ecopetrol Group intends to continue to pursue their development in the future, are not considered qualifying assets for the purpose of capitalization of borrowing costs.
Separately acquired intangible assets with finite useful are stated at cost less accumulated amortization and any impairment loss. Intangible assets are amortized under the straight–line method, over their estimated useful lives. The estimated useful lives and amortization methods are revised at the end of each reporting year; any change in estimates is recognized on a prospective basis. The disbursements related to research activities are recognized as expense as incurred. Amortization is classified as cost or expense, depending on the activities for which the assets are used.
Easements
Easements are rights obtained for the use of part of land for the installation of a transmission line or pipelines. This implies restrictions on the use of the land by the owner and authorizations to the Ecopetrol Group to build, operate, or maintain the transmission lines. These intangible assets are permanent rights with an indefinite term of use. Although the transmission lines to which these easements are related have a finite useful life, the rights do not expire, and the Group may replace the transmission lines at the end of their useful life or make use of said rights for any other service related to transmission electricity and telecommunications. In the case of pipelines, the right – of - way associated with easements has a finite useful life. Easements with indefinite useful lives are not amortized and are subject to review annually for impairment.
Service concession agreements
The Ecopetrol Group operates concessions under public service concession agreements, in which the grantor controls or regulates the services provided by the concessionaire, whom they are provided to, and price of the service.
IFRIC 12, Service Concession Arrangements, establishes general guidelines for the recognition and measurement of rights and obligations related to concession agreements and applies when the granting authority controls or regulates which services the concessionaire should provide with the infrastructure, to whom the services should be provided and at what price, and controls any significant residual interest in the infrastructure at the end of the concession period.
Concession arrangements that meet the above criteria and in which the Ecopetrol Group is required to return the infrastructure to the grantor, or where the grantor retains a residual interest in the infrastructure at the end of the concession term, are accounted for in accordance with IFRIC 12 – Service Concession Arrangements.
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The Ecopetrol Group applies the guidance of IFRIC 12 to concession arrangements that meet the above criteria; otherwise, the Ecopetrol Group applies the guidance of IAS 16. Service revenues are measured and recognized in accordance with IFRS 15 – Revenue from Contracts with Customers (Note 4.17- Revenue from contracts with customers). Financial concession assets are measured and recognized in accordance with IFRS 9 – Financial Instruments. Concession arrangements in which the Ecopetrol Group has a contractual right to receive cash or another financial asset from the grantor are accounted for under the financial asset model (see description of the concession financial asset model below).
Concession arrangements in which the Ecopetrol Group does not have a contractual right to receive cash or another financial asset from the grantor but has the right to charge users for the services provided, are accounted for under the intangible asset model (see description of the concession intangible asset model below).
Revenues from construction services or enhancements to concession services are recognized based on the percentage of completion of the construction, determined by the costs actually incurred, including the construction margin. Operating and maintenance costs related to the concession are recognized in profit or loss once the concession infrastructure is available for its intended use. Revenues are recognized based on the services provided and the tariff established in the concession agreements.
Details of each type of concession by country are disclosed in Note 25 – Revenue from contracts with customers.
The Ecopetrol Group periodically performs a qualitative impairment assessment of concession-related assets to identify events or circumstances, at the CGU level, defined as the concession contract together with any related extensions, if applicable, that indicate that the carrying amount of the assets exceeds their recoverable amount. When such events are identified, a quantitative impairment test is performed, and any resulting impairment loss is recognized in profit or loss for the period (Note 4.13 - Impairment of long-term non–monetary assets).
Intangible asset model
Concessions under which the Ecopetrol Group does not have a contractual right to receive cash or another financial asset from the grantor but has the right to collect to the users in exchange for the services provided, are accounted under the intangible asset model. Costs incurred by the Ecopetrol Group for the construction of the concession infrastructure are recognized as intangible assets and are amortized on a straight-line basis over the term of the concession, recognized in profit or loss for the year.
Infrastructure expansions are recognized as intangible assets when they are expected to generate future economic benefits. The renovations costs, improvements and additions are capitalized, while routine maintenance and repairs that do not extend the useful life of the assets are recognized in the profit or loss statement (Note 4.17- Revenue from contracts with customers).
Financial asset model
Concessions in which the Ecopetrol Group has a contractual right to receive cash or another financial asset from the grantor for the services provided under the concession agreements and the grantor has little or no power to avoid payment are recognized under the financial asset model. In this model, the financial asset is classified as a financial asset concession, according to IFRS 9 – Financial Instruments, and it is presented as current and non-current concessions in the financial position of the Group. This asset accrues interest using the effective interest rate method (see Note 4.1 - Financial instruments).
Mixed model for concessions
This model is applied when the contract simultaneously includes remuneration commitments guaranteed by the grantor and remuneration commitments that depend on the level of use of the concession infrastructure.
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Contractual asset model for concessions
This business model is developed under energy concession agreements associated with the obligation to construct and implement power transmission infrastructure and is classified under the contractual asset model in accordance with IFRS 15 – Revenue from Contracts with Customers (Note 4.17 - Revenue from contracts with customers). The contractual asset arises as the Ecopetrol Group satisfies its obligation to construct and implement the infrastructure, and revenue is recognized over the duration of the project.
4.11Goodwill
Goodwill is initially measured at cost (being the excess of the aggregate of the consideration transferred and the amount recognized for non–controlling interest and any previous interest held over the net identifiable assets acquired and liabilities assumed in a business combination). After initial recognition goodwill is measured at cost less any accumulated impairment loss. Goodwill is not amortized but tested for impairment annually.
4.12Leases
At the inception of a contract, the Ecopetrol Group assesses whether a contract is, or contains, a lease. This situation arises if the contract transfers the right to use an identified asset for a period in exchange for consideration. For this assessment, the Ecopetrol Group applies the definition of a lease set out in IFRS 16.
Ecopetrol Group as a lessee
At the commencement date of the lease, the Ecopetrol Group recognizes lease liabilities for lease payments and corresponding right-of-use assets representing the right to use the underlying asset over the lease term. The interest expense on the lease liability and the depreciation expense on the right-of-use asset are recognized separately.
In subsequent recognition, the Group remeasures the lease liability (and makes a corresponding adjustment to the related right-of-use asset) upon the occurrence of events such as a) changes in the lease term and b) changes in future lease payments resulting from variations in an index or in the rate used for determining the payments. The amount of the remeasurement of the lease liability is recognized as an adjustment to the right-of-use asset.
Ecopetrol Group as a lessor
The Group classifies as financial leases those contracts in which the terms of the lease substantially transfer to the lessees all the risks and inherent rewards to ownership of the asset. All other leases are classified as operating.
If the lease is classified as financial, an account receivable is recorded in the statement of financial position, for an amount equal to the net investment in the lease.
For leases classified as operating leases, income from payments is recognized on a straight-line basis in the profit and loss statement.
The Ecopetrol Group recognizes right-of-use assets on the commencement date of the lease (that is, the date on which the underlying asset is available for use). The right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of the lease liabilities. Right-of-use assets are amortized in a straight-line basis during the lease term. Right-of-use assets are subject to impairment assessment.
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Lease liabilities
At the commencement date of the lease, the Ecopetrol Group recognizes lease liabilities measured at the present value of the lease payments to be made during the term of the lease. Variable payments that do not depend on an index or rate are recognized as expenses in the year in which an event or condition indicates that the payment will occur. To calculate the present value of the lease payments, the Ecopetrol Group uses the incremental borrowing rate on the lease’s commencement date. The carrying amount of lease liabilities is remeasured if there is a change in the lease term, in fixed lease payments, or in the assessment of an option to purchase the underlying asset.
Short-team leases and low-value asset leases
The Ecopetrol Group elected to use the recognition exemptions for lease contracts that, at the commencement date, have a lease term of 12 months or less and do not contain a purchase option, and lease contracts for which the underlying asset is of low value. For these leases, the Group recognizes lease payments as an operating expense on a straight-line basis over the lease term, unless another systematic basis is more representative of the pattern over which the economic benefits of the leased assets are consumed.
Joint Operating Agreements (JOA)
In JOAs, an analysis is conducted to determine who controls the use of the asset, and the method for recognizing right-of-use assets is determined accordingly. If The Operating partner controls the use of the asset, they must recognize 100% of the right in their financial statements. If the JOA controls the right, an analysis is conducted to determine if the agreement meets the characteristics of a sublease. If so, each party must recognize the right-of-use assets proportionally to their share. Ecopetrol recognizes 100% of the right-of-use in the JOA in which it participates as The Operating partner.
4.13Impairment of long-term non–monetary assets
In order to evaluate if any non-current assets are impaired, Ecopetrol Group compares its carrying amount with its recoverable amount at least annually or earlier, if there is any indicator that an asset may be impaired.
For purposes of impairment testing, assets are grouped into cash generating units (CGU), provided that those assets individually considered do not generate cash inflows that, to a greater extent, are independent from those generated by other assets or CGUs. The grouping of assets in different CGUs requires the exercise of professional judgment and the consideration, among other parameters, of the business segments. In this sense, in the Exploration and Production segment, each CGU corresponds to each one of the different contractual areas commonly called “fields”; by exception, in those cases where the cash inflows generated by several fields are interdependent from each other, those fields are grouped into a single CGU. In the case of the Refining and Petrochemicals, each CGUs corresponds to each one of the refineries, petrochemical plants, and companies in this segment of the Ecopetrol Group, for the Transportation and logistics segment, each pipeline system is considered an independent CGU, and for the Energy transmission and toll roads concessions segment, which also includes telecommunication business, the CGUs correspond to three groups: energy power transmission, toll roads and telecommunications; these units are distributed in identified and independent groups of assets, agreements, subsidiaries, associates, and joint ventures defined within Interconexión Eléctrica S.A. E.S.P.
The recoverable amount of an asset is the higher amount of the fair value less costs of disposal and its value in use. If the recoverable amount of an asset (or of a CGU) is lower than its net carrying amount, such amount (or that of the CGU) is reduced to its recoverable amount, recognizing an impairment loss in profit or loss.
Fair value less costs of disposal is usually higher than the value in use for the asset in the production segment due to some significant restrictions in the estimation of future cash flows, such as: a) future capital expenses that improve the CGU performance, which could result in expected increase of net cash flows, and b) items that reflect specific business risks, resulting in a higher discount rate.
Fair value less costs of disposal is determined as the sum of the future discounted cash flows adjusted to the estimated risk. The estimations of expected future cash flows used in the assessment of impairment of the assets include estimates of futures commodity prices, supply and demand estimations, and the margins of the products.
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Fair value less costs of disposal, as described above, is compared to valuation multiples and quoted prices of shares in companies comparable to the Ecopetrol Group to determine if it is reasonable. In the case of assets or CGUs that participate in the evaluation and exploration of reserves, proven, probable, and possible reserves are considered, with a risk factor associated with them.
When an impairment loss is recorded, future amortization expenses are calculated based on the adjusted recoverable amount. Impairment losses may be recovered only if the reversal is related to a change in estimations used after impairment loss was recognized in previous years. These recoveries do not exceed the carrying amount of the assets net of depreciation or amortization that would have been determined if such impairment had not been recognized.
For the case of concessions, the Ecopetrol Group periodically performs a qualitative impairment test on the assets related to the concession to identify events or circumstances, at the CGU level, which is the concession contract with its corresponding amendments, if any, events that indicate that the carrying amount exceeds the recoverable amount. When such events are identified, the quantitative calculation is made, and any impairment is recognized in profit or loss statement.
4.14Provisions and contingent liabilities
Provisions are recognized when the Ecopetrol Group has a current obligation (legal or constructive) because of a past event, it is probable that Ecopetrol will be required to settle the obligation, and a reliable estimation can be made of the amount of the obligation. Where applicable, they are recorded at present value, using a rate reflecting the risk specific to the liability.
If the effect of the time value of money over time is significant, the provisions are discounted using a current market rate before taxes that reflects, when applicable, the specific risks of the liability. The increase in the provision due to interest unwinding is recognized as a financial expense in the statement of profit and loss.
Disbursements related to environmental conservation, linked to revenue from current or future operations, are recognized as expenses or assets, as appropriate. Disbursements related to past operations, which do not contribute to obtaining current or future revenue, are recorded as expenses.
The recognition of these provisions coincides with the identification of an obligation related to environmental remediation and the Ecopetrol Group uses all available information to determine a reasonable estimate of their respective cost.
A contingent liability is: (a) a possible obligation arising from past events whose existence will be confirmed only by the occurrence or non-occurrence of one or more uncertain future events not wholly within the entity’s control; or (b) a present obligation arising from past events, but which is not recognized because: (i) it is not probable that an outflow of resources representing economic benefits will be required to settle the obligation; or (ii) the amount of the obligation cannot be measured reliably.
In cases where the provision is expected to be reimbursed in whole or in part, for example under an insurance contract, the reimbursement is recognized as a separate asset only in cases where such reimbursement is practically certain. The amount recognized for the asset does not exceed the amount of the provision.
Asset retirement obligation
Liabilities associated with the retirement of assets are recognized when there are current obligations, either legal or constructive, related to the abandonment and dismantling of wells, facilities, pipelines, buildings, and equipment.
The obligation is usually recorded when the assets are installed or when the surface or the environment are altered at the operating sites. These liabilities are calculated using the discounted cash flow method, using a pre–tax rate reflecting current market conditions similar liabilities and considering the economic limits of the field or the useful life of the respective asset. When it is not possible to determine a reliable estimation in the year in which the obligation originates, a provision is recognized when there is enough information available to make the best estimation.
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The carrying amount of the provision is reviewed and adjusted annually considering changes in the assumptions used for its estimation, using a risk-free rate adjusted by a premium that reflects the risk and the company credit rating under the current market conditions. Any change in the present value of the estimated expenditure, due to a modification in the estimated outflow of resources that represent economic benefits or a change in the current market-based discount rate is reflected as an adjustment to the provision and the corresponding property, plant, and equipment and natural and environmental resources. When a decrease in the asset retirement obligation related to a producing asset, due to changes in the present value of the estimated expenditure or the discount rate, exceeds the carrying amount of the asset, the excess is recognized in the statement of profit or loss. The increase in the provision due to the passage of time is recognized as a financial expense.
4.15
Income tax and other taxes
Income tax expense is comprised of current income tax and the effect of deferred taxes in each year.
Current income taxes are recognized in profit or loss except when they relate to items recognized in other comprehensive income, in which case the corresponding tax effect is also recognized in other comprehensive income. Income tax assets and liabilities are presented separately in the consolidated statement of financial position, except where there is a right of setoff within fiscal jurisdictions and an intention to settle such balances on a net basis.
4.15.1
Current income tax
The Ecopetrol Group determines the provision for income tax based on the highest amount between taxable income and presumptive income (the minimum estimated amount of taxable profit on which the law expects to quantify and collect income taxes). Taxable income differs from profit before tax as reported in the consolidated statement of profit or loss, because of items of income or expense that are taxable or deductible in other years, special taxable deductions, tax losses and income and line items measured that, according to applicable tax laws in each jurisdiction, are considered nontaxable or nondeductible.
4.15.2Deferred income tax
Deferred tax is measured using the liability method for differences between the carrying amounts of existing assets and liabilities in the consolidated financial statements and their respective tax bases. A deferred tax liability is recognized for all taxable temporary differences. A deferred tax asset is recognized for all deductible temporary differences and for all accumulated tax losses, if there is a reasonable expectation that the Ecopetrol Group will generate future tax profits against which they will be used.
Deferred taxes on assets and liabilities are calculated based on the tax rates that are expected to apply during the years in which temporary differences between the carrying amounts and tax bases are expected to be reversed, considering the tax legislation that is enacted or substantially enacted at the time of measurement.
The carrying amount of a deferred tax asset is subject to review at the end of each reporting year, and it is reduced to the extent that it is no longer probable that the corresponding legal entity will generate enough future taxable profit to realize such deferred tax asset.
In the statement of financial position, deferred tax assets are reflected net and as an offset against deferred tax liabilities, depending on the overall tax position in a particular jurisdiction and on the same taxable entity.
Deferred taxes are not recognized when they arise in the initial recognition of an asset or liability in a transaction (except in a business combination) and at the time of the transaction, do not affect the accounting or tax profit, and that, at the time of the transaction, does not give rise to an equal, taxable and deductible temporary difference. Nor are recognized in respect of the possible future distribution of accumulated profits of investments in associated and joint ventures, except to the extent that the Ecopetrol Group is able to control the timing of the reversal of the temporary difference, and it is likely that the temporary difference will not reverse in the foreseeable future.
4.15.3Other taxes
The Ecopetrol Group recognizes in profit or loss the costs and expenses related to other taxes than the income tax, such as the wealth tax, which is determined based on the tax equity, the industry and commerce tax on income obtained in the municipalities for performance of commercial, industrial, and service activities, and the transport tax on volumes loaded in the transport systems. Taxes are calculated in accordance with current tax regulations.
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4.16Employee benefits
Salaries and benefits for the Ecopetrol Group’s employees are governed by the Colombian Collective Labor (Agreement 01 of 1977), and, by the Colombian Substantive Labor Code. In addition to the benefits determined by labour laws, employees are entitled to fringe benefits which are subject to the place of work, type of work, length of service, and basic salary. An annual interest of 12% is recognized on accumulated severance amounts for each employee, and the payment of compensation is provided for when special circumstances arise resulting in the non–voluntary termination of the contract, without justified cause, and in years other than the probationary period.
Employee benefits are divided into four groups comprised as follows:
Short–term employee benefits and post–employment defined benefits:
Benefits to employees in the short term mainly correspond to those which payment will be made in the term of twelve months following the closing of the year in which the employees have provided their services. These mainly include salaries, severance payments, vacation, bonuses, and other benefits.
Post–employment benefits of defined contributions plans correspond to the periodic payments for severance, pensions, and labor risk payments that the Ecopetrol Group makes to the respective funds that assume these obligations in their entirety.
The above benefits are recognized as an expense with an associated liability after deducting any already paid amounts.
Post–employment defined benefit plans:
In the defined benefits plan, the Ecopetrol Group granted the benefits agreed to current and former employees and assumes the actuarial and investment risks.
The following benefits are classified as long–term defined benefit plans recognized in the financial statements according to the calculations of an independent actuary:
Liabilities recognized in the statement of financial position with respect to these benefit plans are determined based on the present value of the defined benefit obligation at the date of the statement of financial position less the fair value of plan assets.
The defined benefit obligation is calculated annually by independent actuaries using the projected credit unit method, which considers employees’ years of service and, for pensions, average or final pensionable remuneration. This obligation is discounted at its present value using interest rates of high–quality government bonds denominated in the currency in which the benefits will be paid and of a duration consistent with the plan obligations.
These actuarial calculations involve several assumptions that could differ from the events that will effectively take place in the future. Said assumptions include the determination of a discount rate, future salary increases, mortality rates and future pension increases. Because of the complexity of the calculation, the underlying assumptions and long–term nature of these plans, the obligations for defined benefits are extremely sensitive to changes in assumptions. All key assumptions are revised at the end of the reported year.
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In determining the appropriate discount rate, in absence of a broad high quality bond market, Management considers interest rates corresponding to the class B TES bonds issued by the Colombian Government as its best reference, at an appropriate discount rate with maturities extrapolated in line with the term expected for each benefit plan. The mortality rate is based on the country’s rate, the latest version of which is the RV08 mortality table published in resolution 1555 of October 2010. The future salary and pension increases are linked to the country’s future inflation rates. Note 22 – Provisions for employee benefits, provides further details on key assumptions used.
The amounts recognized in the consolidated statement of profit or loss related to employees defined benefit plans are comprised mainly by service cost and the net financial expense. Service cost includes mainly the increase in present value of the benefit obligation during the year (current service cost) and the amount resulting from a new benefit plan. Plan amendments correspond to changes in benefits and are usually recognized when all legal and regulatory approvals have been obtained and the effects have been conveyed to the employees involved. The net financial expense is calculated using the net liability for defined benefits as compared with the yield curve of the discount rate at the beginning of each year for each plan. The net defined benefit obligation or asset resulting from actuarial profits and losses, the asset ceiling effect, and the asset profitability, excluding the value of recognized in the consolidated statement of profit or loss, are recognized in other comprehensive income.
When the plan assets exceed the gross obligation, the recognized asset is limited to the lower of the surplus in the defined benefits plan and the ceiling of assets determined using a discount rate based on Colombian Government bonds.
Others long-term benefits
Others long–term benefits include the five–year term bonus which is also considered in the actuarial calculation. This benefit is a cash bond that accumulates annually and is paid every five years to employees. The Ecopetrol Group recognizes in the consolidated statement of profit or loss the service cost, the net financial cost and the adjustment to the obligation of the defined benefit plan.
Termination benefits
Termination benefits are recognized only when a detailed plan exists and there is no possibility to withdraw the offer. The Ecopetrol Group recognizes a liability and an expense for termination benefits at the earliest date between the date when the offer of such benefits cannot be withdrawn and the date when the restructuring costs are recognized.
All employees benefits that impact the consolidated profit or loss, are classified as cost or expense, depending on the activities performed by the employees.
4.17Revenue from contracts with customers
The Ecopetrol Group’s business is based on four principal sources of revenue from customer contracts: 1) sales of crude oil and natural gas, 2) services associated with the transport of hydrocarbons, 3) sales of refined and petrochemical products and biofuels (such as mid-distillates, gasolines and turbo fuels, asphalts, plastic and rubber, LPG and propane), and 4) energy transmission and toll roads concessions. In contracts with clients Ecopetrol is rarely committed to perform multiple performance obligations regarding oil and gas industry. These sources of revenues are based on contract types such as product supply, nominations, and sales orders. Revenue from customer contracts is recognized when control of the goods or services are transferred to the customer at an amount that reflects the consideration that the Ecopetrol Group expects to receive in exchange for those goods or services (See notes 7 – Trade and other receivables, 25 – Revenue from contracts with customers and 33 – business segment information).
Sales of crude oil and natural gas
Revenue from sales of crude oil and natural gas is recognized upon transfer of control to the buyer. This generally occurs when the product is physically transferred into a vessel, pipeline or by another delivery method, considering its risks and benefits, such as the legal transfer of title, thus fulfilling the Ecopetrol Group’s performance obligations to its customers.
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For some natural gas supply contracts, a distinction is made between quantities of gas consumed and not consumed to recognize the respective revenue or liability relating to quantities that will be requested in the future. Once the customer claims such natural gas, the revenue is recognized.
Services associated with the transport of hydrocarbons
Revenue from hydrocarbons transport services is recognized when the service is provided to the customer and there are no contractual conditions that prevent recognition of the revenue.
Ship/Take or Pay contracts for the sale of products, storage, and transportation specify minimum quantities of product or service that a customer will pay for, even if they do not receive or use them (shortages). If the Ecopetrol Group expects the customer to recover all the shortages to which they are contractually entitled, any payment received in advance related to temporary shortages that will be made up in a future period will be accounted for other liabilities, and that amount will be recognized as revenue when any of the following situations occur:
The customer exercises its right to deficient volumes or services, or
The probability that the customer will exercise its right to deficient volumes or services is remote.
Refined and petrochemical products and biofuels
In the case of refined products and petrochemicals, such as fuel oil, asphalt, polyethylene, LPG and propane and gasoline, etc., revenue is recognized when the products are shipped and delivered by the refinery; subsequently, they are adjusted for price changes, in the case of products with regulated prices, as described below (also see Note 7). In the case of the companies that distribute natural gas and LPG, the revenue from the services is recognized when the service is provided to the customer.
Ecopetrol Group recognizes revenue when the performance obligation is satisfied, giving rise to the certain, probable, and quantifiable right to demand payment.
Under current local regulation, the Group sells regular gasoline and ACPM in Colombia at a regulated price.
In accordance with Decree 1068 of 2015, the Ministry of Mines and Energy semiannually calculates and settles Ecopetrol’s net position to be stabilized for each fuel by the Fuel Price Stabilization Fund (FEPC, for its acronym in Spanish). The net position corresponds to the sum of the spreads throughout the year, the result of which is the amount in pesos owed to the Company and charged to the resources of the FEPC. The differential corresponds to the product between the volume reported by the Company at the time of sale and the difference between the parity price and the reference price, the parity price being that which corresponds to the daily prices of motor and diesel gasoline observed during the month, expressed in pesos, referenced to the Gulf of the United States market, calculated by applying Resolution 18 0522 of 2010, and the reference price is the Producer Income defined by the Ministry of Mines and Energy for these purposes. Therefore, this differential constitutes a greater or lesser value of sales revenue and a receivable or payable account for Ecopetrol and is recognized simultaneously with the fulfillment of performance obligations to customers.
According to risk profiles, the Ecopetrol Business Group manages advance payment systems for some of its contracts with clients.
Energy transmission and toll roads concessions
This source of revenue refers to 1) supplying of electricity transmission services in Latin America through the operation and maintenance of high-voltage transport networks and interconnections 2) design, construction, operation, and maintenance of road infrastructures, 3) supplying of information technology and telecommunications services.
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The recognition of revenue from energy transmission services occurs according to performance obligations based on the conditions of the contracts that include requirements established by the electricity market regulators in the countries in which the Ecopetrol Group operates. This is generally achieved when the performance obligations agreed with the regulatory entities are executed, considering the year and the quality of the service established in the contracts. Technology and telecommunications services revenue is also recognized according to the performance obligations defined in contracts with customers. ISA and its subsidiaries Intercolombia, Transelca and XM are providers of electricity transportation services and other services associated with these and are regulated by the Energy and Gas Regulatory Commission (CREG, for its acronym in Spanish).
Regarding the concessions associated with the energy transmission and roads business, the Group measures the revenue in accordance with IFRIC 12, applicable to the energy transmission subsidiaries in Brazil, Bolivia and Peru and to the roads subsidiaries in Chile, Panama and Colombia, at the fair value of the consideration received or receivable, considering the payment defined in the contracts.
The following specific criteria must be met to recognize revenue in accordance with IFRIC 12. See Note 4.10 Service concession agreements:
In concession agreements (Note 4.10), the Group determines that its performance obligations (construction, operation, and maintenance) are met over time and measures progress toward completion to determine the stage of completion for revenue recognition using a method that represents the transfer of goods or services to the customer and/or grantor. The Group considers the nature of the products or services provided and the terms of the contract, such as the right to cancel, rights to demand or withhold payments, and the legal title to work, in a process to determine the best input or output method for measuring progress toward fulfilling a performance obligation.
The Group applies a single method to measure progress on each performance obligation in a contract. The method is based on the costs incurred to fulfill each performance obligation, in terms of capital expenditures (capex) and operating expenditures (opex), with a technically defined implicit rate that is subject to review when there is a change in the circumstances that gave rise to it. Revenue estimates, costs, or the stage of completion are revised if circumstances change. Any increase or decrease in estimated revenues or costs is reflected in the profit or loss statement in the year in which management became aware of the circumstances that led to the revision.
Significant financing component
Payments received from customers are generally short term (except for revenue of concessions). Using the practical expedient in IFRS 15, the Ecopetrol Group does not adjust the promised amount of consideration for the effects of a significant financing component if it expects, at contract inception, that the period between the transfer of the promised good or service to the customer and the customer’s payment for that good or service to be one year or less.
Considering that revenues related to concessions generates long term accounts receivables, a financial component is applied considering the measurement of the asset at amortized cost, defining the future cash flows, and applying and discount rate, according to IFRS 9 – Financial Instruments.
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Variable considerations
Upon fulfillment of the obligations set forth in agreements with customers, via delivery of the product or provision of the service, variable components of the transaction price may exist, such as the exchange rate for crude exports or international price fluctuations. In these cases, the Ecopetrol Group makes its best estimate of the transaction price that reflects the goods and services transferred to customers and adjusted subsequently when new information appears or final settlement is made.
Agreements signed with customers do not include material variable considerations such as rebates, refunds, or discounts.
Customer advances
They correspond to contractual obligations in which the Ecopetrol Group receives monetary resources from customers to subsequently transfer goods and services. These advances made by customers are part of the policies and risk assessment defined by the Ecopetrol Group and they are recognized as a liability until the performance obligation to the client is fulfilled.
4.18Costs and expenses
Costs and expenses are presented according to their function; they are detailed in the related disclosures in cost of sales, and administrative, operating, projects, and other associated expenses.
4.19Finance income (expenses)
Finance income and expenses include mainly: a) borrowings costs on loans and financing, except for those that are capitalized on qualifying asset, b) gains and losses on changes in fair value of financial instruments measured at fair value through profit or loss, c) currency exchange differences of monetary assets and liabilities, except for debt instruments designated as hedging instruments, d) interest expenses as a result of discounting long–term liabilities (abandonment costs and pension liabilities).
4.20Business segment information
The operations of the Ecopetrol Group are performed through four reportable segments: 1) Exploration and Production, 2) Transport and Logistics, 3) Refining and Petrochemical, and 4) Energy transmission and Toll Roads Concessions. The measure of profit or loss reviewed by the chief operating decision makers is the net income by operating segments.
Segments are determined based on the Ecopetrol Group Management objectives and corporate strategic plans, considering that these businesses: (a) are engaged in different commercial activities, which generate sales revenue and incur costs and expenses; (b) the operational results are revised regularly by the Ecopetrol Group’s Governance that makes operational decisions to allocate resources to the various segments and assess their performance; and (c) there is differentiated financial information available. Internal transfers represent sales to inter–company segments and are recognized and presented at market prices.
Exploration and production: This segment includes activities related to the exploration and production of oil and gas. Revenues are derived from sales of oil and natural gas at market prices to other segments and to third parties (domestic and foreign distributors). Costs include costs incurred in production. Expenses include all exploration costs that are not capitalized.
Transport and logistics: This segment includes sales revenue and costs associated with the transport and distribution of hydrocarbons and derivative products.
Refining and petrochemicals: This segment mainly includes activities performed at the Barrancabermeja and Cartagena refineries, where crude oil from production fields is refined or processed. Additionally, this segment includes distribution of natural gas and LPG activities performed by Invercolsa Group. Revenues are derived from the sale of products to other segments and to domestic and foreign customers and include refined and petrochemical products at market prices and some fuels at regulated price. This segment also includes industrial service sales to customers.
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Energy transmission and toll roads concessions: This segment includes activities of supplying energy transmission services, design, development, construction, operation, and maintenance of road and energy infrastructure projects. Revenues come from the supply of these services to domestic and foreign clients (mainly Latin America). This segment also includes the supply of information technology and telecommunications services.
See more data in Note 33 – Information by segments.
4.21Business combinations
The Ecopetrol Group accounts for business combinations using the acquisition method. Identifiable assets acquired and liabilities assumed are initially measured at fair value on the acquisition date, except for deferred taxes and employee benefits. The Group recognizes separately, at the acquisition date, the identifiable assets and liabilities of the acquiree that meet the appropriate criteria for recognition, regardless of whether they had been previously recognized in the financial statements of the acquiree.
On the acquisition date, the Group will recognize separately the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree.
The group recognizes the goodwill generated as an asset on the acquisition date, measured as the difference between (i) the sum of the fair value of the consideration transferred, the amount of any non-controlling interest, and the fair values on the date of acquisition of the any previously held interest in the acquiree, and (ii) the net amount of the acquisition date of the identifiable assets acquired and the liabilities assumed.
4.22Royalties
Royalties are payments made to mineral rights owners for the extraction of natural resources made by Ecopetrol Group. Royalties can be paid in kind or in cash. Royalties paid in kind do not give rise to a recognition of revenue or expense for Ecopetrol Group. Accordingly, the volumes corresponding to the royalties paid in kind are deducted directly from production. On the other hand, royalties paid in cash are accounted for cost of sales.
5.New standards and regulatory changes
5.1New standards issued by the IASB effective from January 1, 2025
Amendment to IAS 21 - The Effects of Changes in Foreign Exchange Rates. The amendment establishes criteria for assessing whether a currency is interchangeable and when it is not, to determine the exchange rate to use and the disclosures to be provided. The amendment applies to annual periods beginning on or after January 1, 2025. It was subject to public consultation between July and September 2025, and the Technical Council of Public Accounting (Colombia) recommended its adoption for incorporation into Colombian regulations through a decree that is currently pending issuance.
These amendments have not generated material impacts for the Ecopetrol Group.
New standards issued by the IASB that will come into effect in future periods
The Group is in the process of assessing the impact on the presentation of its financial statements resulting from the implementation of this standard.
The Ecopetrol Group does not expect the implementation of this standard to have a material impact on the consolidation of its financial statements.
The amendments to address how IFRS 9 Financial Instruments should be applied to power purchase agreements with specific characteristics and amend IFRS 7 Financial Instruments: Disclosures to include specific disclosure requirements relating to those contracts.
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The IASB’s previous pronouncements have initiated the process determined by the Technical Council of Public Accounting and the Ministry of Commerce, Industry, and Tourism to be included in Colombian regulations by decree soon.
As of the reporting date, the Ecopetrol Group does not expect material impact on its financial figures because of the implementation of these standards. With respect to IFRS 18, the Group anticipates changes in the presentation of its financial statements.
New standards issued by the ISSB that with effect in future periods
The International Sustainability Standards Committee (ISSB), in September 2023 issued the first international sustainability and climate standards: IFRS S1 General Requirements for the Information to be Disclosed on Sustainability related to Financial Information and IFRS S2 Weather-related Disclosures. The purpose of these standards is for entities to disclose information about their risks and opportunities related to sustainability and climate that are useful to the primary users of financial information for decision-making. An entity will apply these standards for reports for annual periods beginning on or after January 1, 2024. Starting in August 2023, the Ecopetrol Group began assessing and understanding the new regulations, identifying the information requested in the regulations across their pillars (Governance, Strategy, Risks, Metrics and Objectives) versus the information already contained in the ESG reports adopted by the Group to develop a roadmap for their implementation. Likewise, Likewise, the Ecopetrol Group remains attentive to any guidance or regulations that may be issued at the country level through the Technical Council of Public Accounting and the sustainability committees established in Colombia.
The Group is in the process of assessing this standard.
6.Cash and cash equivalents
Cash and banks
6,425
8,992
Short–term investments
4,269
5,062
As of December 31, 2025, the balance of cash and cash equivalents (short-term investments) includes an amount of total cash with specific purpose for $2,026 ($1,905 as of December 2024) in Interconexión Eléctrica S.A. E.S.P. These cash amounts will be used in the next 12 months to: i) the payment of principal and interest on loans, ii) meet short-term business needs, and iii) exclusively for specific activities related to the operation of the concessions.
The fair value of cash and cash equivalents approximates its book value due to its short-term nature (less than three months) and its high liquidity. Cash equivalents are convertible to a known amount of cash and are subject to a non-significant risk of changes in value. The effective rate of return on cash and cash equivalents as of December 31, 2025 was 3.28% (2024 – 6.7%).
The following table reflects the credit quality of banks in which the Ecopetrol Group has deposits and check accounts, and issuers of investments included in cash and cash equivalents, according to Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings:
Rating
A
1,961
702
BB
1,335
F1
1,320
1,887
AAA
1,288
1,994
AA
1,018
A+
962
1,791
F2
810
332
A-1
641
BBB
440
353
F1+
408
1,027
BRC1+
527
P AAA
Baa2
AAAmmf
AAAF
F3
1,419
P-1
1,058
Ba1
A1
B
BRC1
Not available rating
285
1,425
See credit risk policy in Note 30.7.
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7.Trade and other receivables
Current
Concessions (1)
4,391
4,392
Fuel Price Stabilization Fund (2)
3,029
7,623
Customers
Foreign
3,632
4,737
Domestic
2,705
2,606
Related parties (Note 31)
Accounts receivable from employees
Industrial services
1,424
1,038
15,484
20,770
Allowance for expected losses (3)
(604)
(344)
Non-current
30,903
28,270
Accounts receivable from Sao Paulo State (4)
2,237
2,194
815
531
347
Other (4)
939
996
35,718
32,741
Allowance for expected losses (3) (4)
(588)
(605)
The movement of the account receivable from the Fuel Price Stabilization Fund is as follows:
Opening balance
20,505
Settlements for the year (Note 25)
2,921
7,525
Mobilizations and others
Collections (2.1)
(7,657)
(20,514)
Closing balance
(2.1) For the year ended December 31, 2025, the Ministry of Finance and Public Credit made payments to the Ecopetrol Group for $7,658 corresponding to the balances accrued in 2024 as follows: Ecopetrol S.A. for $5,997 and Refinería de Cartagena S.A.S. for $1,661.
The book value of trade and other receivables approximates their fair value.
The changes in the allowance for expected losses for the year ended December 31, 2025, 2024 and 2023 are as follows:
948
814
906
Additions (1)
335
Currency translation
(81)
(111)
Accounts receivable write–off and uses
(39)
1,192
For 2025, the movement includes the recognition of a provision for expected losses for the accounts receivables from AIR-E S.A.S. E.S.P.
Movement of the contractual asset regulated by Law No. 12,783 – RBSE
The balance of contractual assets includes the contractual rights arising from the extension of the concession contract of ISA ENERGÍA Brasil (formerly ISA CTEEP), pursuant to Law No. 12,783/2013, which extended concession contract 059 of 2001 until December 2042. This extension gave rise to the right to recognize and recover the values associated with the undepreciated transmission assets existing as of May 31, 2000, under the concept of RBSE (Rede Básica do Sistema Existente in Portuguese). The future cash flows of the RBSE are composed of: (a) a portion corresponding to the remuneration base (economic component); and (b) another portion corresponding to the monetary update at the cost of equity (Ke) (financial component).
During 2025 ISA ENERGÍA Brasil’s contractual asset in Brazil, associated with the RBSE (Basic Network of the Existing System), included the Remuneration of concession assets (accrual) for $667, a Regulatory adjustment on remuneration according to Resolução Homologatória (REH) nº 3,466/2025 for $(652) and a payment for concession assets in cash for $1,389.
Related to the Regulatory adjustment on remuneration, on June 10, 2025, at the ANEEL (Agência Nacional de Energia Elétrica by its name in Portuguese) Board of Directors meeting, the administrative discussion concluded regarding the request submitted in 2021 by trade associations and market participants in Brazil to reconsider the calculations presented for the payment of the financial component (ke) of the RBSE (Rede Básica do Sistema Existente in Portuguese) to all energy transmission companies that renewed their concessions in 2012. Considering this decision, the payment schedule for the last three installments of the financial component of the RBSE payment was modified, decreasing from BRL $1,578 million annually to BRL $1,271 million (base date: June 2024). In June 2025, an adjustment of $652 was made to the consolidated financial statements, which reduced the contractual asset by $592 net of PIS/Confins.
Additionally, the figures of remunerations and payments for concession assets for 2025, less PIS/Confins taxes, corresponds to $614 and $592, respectively.
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8.Inventories
The inventories balance is presented net of the allowance for inventory losses.
Crude oil (1)
3,311
3,936
Fuels and petrochemicals
2,040
2,783
Materials for goods production (2)
3,258
3,309
As of December 31, 2025, the crude oil inventory includes 478,225 barrels (2024: 0 barrels) of crude oil in transit by Ecopetrol US Trading. Revenue associated with these barrels is not recognized until the performance obligation with client (delivery at the point defined in the contract) is satisfied.
Materials for goods production include spare parts, supplies and raw materials. Materials for goods production recognized as part of the cost of sales during 2025 were $2,879 (process materials for $1,994 and materials and operating supplies for $885) and 2024 were $2,410 (process materials for $1,559 and materials and operating supplies for $851) (Note 26).
The following are the changes in the allowances for inventory losses for the years ending December 31, 2025, 2024 and 2023:
Additions
(77)
(16)
Crude oil, fuel, and petrochemicals inventories are adjusted to the lower of cost and net realizable value, mainly due to fluctuations in international crude oil prices.
9.Other financial assets
Assets measured at fair value
Assets measured at fair value through profit or loss
Investment portfolio – local currency (1)
Investment portfolio – foreign currency
589
693
Investments in equity securities and trust funds (2)
552
331
Hedging instruments (3)
Assets measured at fair value through other comprehensive income
Equity investments and others (4)
1,041
1,036
Investment portfolio – local currency (5)
2,677
3,280
4,835
Assets measured at amortized cost
405
3,296
5,240
Non–current
It corresponds to National Government TES securities to meet liquidity needs at Ecopetrol S.A.
They include deposits in trusts companies and restricted funds in Brazil, Peru, Chile, and Colombia. See note 9.1.
Includes mainly forward contracts for $127 to hedge exchange rate risk and put options for $92 to hedge cash flows in Ecopetrol S.A.
It corresponds mainly to 75,000 redeemable Series B non-voting preferred shares (the “Series B Preferred Shares”) of McDermott that were issued in favor of Refinería de Cartagena S.A.S. (see note 23). The variation between 2025 and 2024 corresponds to the effect of changes in fair value.
It corresponds to Colombian National Government TES bonds, whose business model of the Ecopetrol Group generates recognition of their valuation at fair value with changes in other comprehensive income. The variation corresponds to the sale of bonds, in accordance with the Group’s liquidity needs.
The fair value measurement is recognized against other comprehensive income (Note 24.5) or financial results (Note 28), in accordance with the business model established by the Ecopetrol Group.
The securities in the Ecopetrol Group’s portfolio are valued daily following the regulations defined by the Financial Superintendency of Colombia. For this purpose, information provided by authorized entities is used, which corresponds to collected data from active markets. In cases where market data is unavailable, other directly or indirectly observable data is used.
For investments denominated in US dollars, Bloomberg is the information provider, and for those denominated in Colombian pesos, Precia, an entity authorized by the Financial Superintendency of Colombia to provide this service, is the provider.
Within the investment rating process, in addition to the information used for valuation, other relevant aspects are considered, such as the issuer rating, investment classification, liquidity, active market, and the issuer risk analysis carried out by the Ecopetrol Group, which permit the appropriate hierarchy level classification of the investments.
9.1
Restrictions
As of December 31, 2025 and 2024, there were restricted funds for $39, which have a specific destination, mainly in: i) ISA, for $13, associated with administration and payment trusts established for the projects of the Mining and Energy Planning Unit (UPME), resources retained by judicial seizures and the resources to develop the Conexión Jaguar program and, ii) Interligação Elétrica Norte e Nordeste, for $12, related to a guarantee granted to Banco do Nordeste do Brasil (BNB) until the debt with the bank is paid.
9.2
The following is the balance of other financial assets by date to maturity as of December 31, 2025, and 2024:
Up to 1 year
1,832
852
1 – 2 years
315
1,001
2 – 5 years
1,178
> 5 years
1,173
Without maturity (1)
1,037
It corresponds to participating securities without contractual maturity.
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9.3
Fair value
The following is the balance of other financial assets by fair value hierarchy level as of December 31, 2025, and 2024:
Level 1
Level 2 (1)
Level 3 (2)
Investment portfolio
3,052
1,194
352
1,400
3,404
Investments in equity securities and trust funds
Hedging instruments
Equity investments
1,083
1,034
1,991
749
Ecopetrol Group is a holder of the Series B Preferred Shares, and the Group has the right to demand that all the Series B Preferred Shares be converted at any time after June 30, 2028, into common shares representing up to 19.9% of the Company’s equity interest.
The valuation technique applied to the shares of McDermott International Ltd. is an income approach, projecting discounted cash flows to present value, and considering factors such as risk premiums, available information from McDermott International Ltd., the absence of significant influence and control by the Refinería de Cartagena, and restructuring scenarios over time. The valuation process for this stock is reviewed quarterly to identify changes in the established variables.
Within the measurement performed, the most significant unobservable input data are the following:
After analyzing the information available for updating the valuation as of June 2025, a fair value update was performed. Sensitivity analyses of risk premiums were conducted for both the initial fair value calculation of the shares and its update in June 2025, resulting in a valuation range that incorporates minimum and maximum risk levels with incremental increases. Within this range, the medium risk range is considered, reflecting the fair value for accounting purposes.
As of December 2025, it is concluded that market data is insufficient to provide an updated financial valuation of McDermott’s 2025 results and projected cash flows.
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The following is the movement of equity investments in level 3 for the years ended December 31, 2025, and 2024:
Changes in fair value through other comprehensive income (OCI)
Currency translation through other comprehensive income (OCI)
(107)
Changes in inputs used in the valuation of McDermott shares do not give rise to new fair value measurements that can be materially different from the amount recorded in the financial statement as of December 31, 2025 and 2024.
There were no transfers between hierarchy levels for the years ended December 31, 2025, and 2024.
Credit rating
The following table reflects the credit quality of the issuers of other financial assets, according to Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings:
597
BB+
3,061
AA+
Not available rating (1)
1,863
1,431
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10.Taxes
10.1Current and non-current tax assets and liabilities
VAT refund (1)
7,840
5,424
Income tax (2)
4,184
3,446
Other taxes
2,490
2,585
Deferred tax assets (3)
8,011
12,876
Income tax credits
Income tax payable
1,551
Industry and commerce tax
361
377
National tax and surcharge on gasoline
Carbon tax
Value added tax
488
Deferred tax liabilities
12,499
12,956
Income tax
2,309
1,973
The variation corresponds mainly to the balance in favor in value added tax (VAT) in Ecopetrol S.A. and Refinería de Cartagena, resulting from the payment of VAT on the import of Gasoline and Diesel.
The variation corresponds to the increase in the balance in favor of the income tax generated in Ecopetrol S.A. due to a lower profit generated mainly by the lower average prices of the basket of crude oil, natural gas and refined products.
The variation corresponds mainly to: i) the effect of the variation in the exchange rate for loans and borrowings in dollars, ii) the update of the actuarial calculation, iii) variations in the elements to calculate the present value of the technical costs for the abandonment provision, and iv) the update of the projected surcharges in Ecopetrol.
10.2Income tax
In accordance with Law 2010/2019 and Laws 2155/2021 and 2277/2023, the tax provisions applicable in Colombia for taxable years 2022 are the following:
The income tax rate applicable to national companies and foreign entities operating in Colombia will be 35% for 2022 and beyond.
From the year 2021, the presumptive income rate was 0% of the taxpayer’s net equity from the previous year.
The income tax for tax free trade zone users will be 20%. If the company located in the free zone has a Legal Stability Agreement (hereinafter LSA), the income tax rate is 15% during the term of said contract. This is the case of Refinería de Cartagena S.A.S. until 2023 and Esenttia Masterbatch Ltda. until 2028.
For fiscal years ended December 2025, 2024 and 2023, the Ecopetrol Group has subsidiaries that are subject to 35% income tax rate, subsidiaries located in free trade zones, Refinería de Cartagena S.A.S. and Esenttia Masterbatch Ltda., which were subject to 20% and 15% income tax rate, respectively, and other subsidiaries in Brazil, Chile, Peru, United States of America, that were subject to 34%, 27%, 29.5%, 21%, respectively.
For Ecopetrol S.A. and Hocol S.A., additional surcharge must be added to the general income tax rate of 35%. This surcharge will be calculated taking as reference the average Brent price of the last 10 years, which will be updated by the inflation index of the United States of America to update them to constant values. Based on these, the percentiles that give rise to the additional surcharge to the general rate are determined as indicated below:
< percentile 30
> = to percentile 30 and < to percentile 45
> = to percentile 45 and < to percentile 60
> = to percentile 60
The tax depreciation percentages are adjusted based on the table established in Law 1819 of 2016. On the other hand, oil investments depletion will be calculated based on the technical production units as it is recorded for accounting purposes.
Expenses for the acquisition of exploration rights, geology and geophysics, exploration drilling, among others, are capitalizable until the technical feasibility and commercial viability of extracting the resource are determined.
Fluctuations in items expressed in foreign currency will only have tax effects at the time of disposal or payment in the case of assets, or liquidation or partial payment in the case of liabilities.
Tax losses generated as of January 1, 2017, may be offset against ordinary net income obtained in the following 12 taxable years, except for companies that signed a legal stability contract, and included within it the article that they contemplated that tax losses did not have an expiration date.
Statute of limitations of tax returns
In Colombia, the income tax returns of the taxable years 2015, 2017, 2018, 2019, 2020, 2021, 2022, 2023, and 2024 and income tax for equality - CREE - of the taxable years 2016 can still be reviewed by the tax authorities. Management of the Ecopetrol Group considers that the amounts recorded as liabilities for taxes payable are sufficient and are supported by the law to meet any claim that may be established with respect to such years.
In Colombia, as of January 1, 2017, the statute of limitations for the income tax return corresponds to three-year (3) counted from the due date to file the return or the filing date, when these have been lately filed. In the case of Ecopetrol S.A., because it is subject to compliance with transfer pricing rules, the final term is 6 years. However, Law 2010 of 2019 established that this term will be 5 years, for returns submitted after January 1, 2020.
For the years 2024 and 2025, in accordance with Law 2155 of 2021, the time in which the tax authorities can audit an income tax return is reduced, which goes from 5 years to between 6 to 12 months, depending on if the net income increased to 35% or 25% compared to that was declared in the immediately previous year.
Regarding those returns on which balances are presented in favor, the final term is 3 years, from the date of presentation of the request for refund or compensation.
Starting in 2020, tax returns that present tax losses can be reviewed by tax authorities within 5 years from the date of filing and/or correction.
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Year ended December 31
Current income tax (1)
6,121
8,972
12,807
Deferred income tax (2)
(1,642)
(3,310)
Deferred income tax – rate change
1,510
1,942
Adjustments to prior years’ current and deferred tax
(62)
(22)
Income tax expenses
The variation between 2025 and 2024 by ($2,851) corresponds mainly to the decrease in results obtained in the year in Ecopetrol S.A., generated by the decrease in revenues given the lower average prices of the crude basket oil, natural gas, and refined products, among others.
The variation between 2025 and 2024 of $3,390 corresponds mainly to the effect of the exchange rate applied on loans and borrowings in US dollar, the update of the actuarial calculation, variations in the items to calculate the present value of the technical costs of the abandonment provision, among others.
Reconciliation of the income tax expenses
The reconciliation between the income tax expense and the income tax at statutory rate to the Ecopetrol Group is as follows:
Statutory rate (Colombia)
35.0
Income tax at statutory rate
6,601
10,747
12,915
Effective tax rate reconciliation items:
Effect of non-monetary assets and liabilities measured in different functional currency
(2,032)
Non–deductible expenses
274
290
647
Rate differential adjustment
(390)
(442)
(1,631)
Non–taxable income
(1,619)
(1,205)
(1,080)
Prior years’ taxes
Foreign currency translation and exchange difference
436
578
Tax discounts and tax credit
651
Effect of recognition of shares of McDermott International, Ltd.
(124)
Effect of tax reform
Effective tax rate
23.4
39.8
31.2
6,059
8,954
12,867
Deferred
3,254
(1,351)
The effective tax rate as of December 31, 2025 is 23.4% (2024 – 39.8%, 2023 –31.2%). The variation compared to the previous year is mainly due to lower profits generated mainly by lower average prices for the basket of crude oil, natural gas and products, and adjustments to projections for calculating the surcharge for subsequent years, among other factors.
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Deferred income tax
Deferred tax assets (1)
(12,499)
(12,956)
Net deferred income tax
(4,488)
(80)
The financial projections of the Ecopetrol Group suggest that, in the future, sufficient profits will be generated to ensure the recoverability of the active deferred tax asset.
The details of deferred tax assets and liabilities are as follows:
Deferred tax assets (liabilities)
Loss carry forwards (1)
6,595
6,892
Provisions (2)
5,876
4,660
Employee benefits (3)
1,180
2,895
Accounts payable
(470)
(662)
(693)
Intangible
(1,063)
(1,403)
Loans and borrowings (4)
(1,927)
3,425
(3,299)
(3,448)
Accounts receivable
(3,859)
(3,761)
Property plant and equipment and Natural and environmental resources (5)
(7,275)
(8,657)
Tax losses that do not expire: Ecopetrol USA for $1,312 (2024 - $1,088); Refinería de Cartagena for $2,096 (2024 - $1,236); and ISA Group companies in Chile for $61 (2024 - $66).
Tax losses that expire in 12 years in Invercolsa for $15 (2024 - $16) and Esenttia for $186 (2024 - $118).
Tax losses that expire in 20 years from the date they were recognized by Ecopetrol USA Inc. for $910 (2024 - $1,165).
Tax losses expiring in 2025 of Ruta de la Araucanía for $1 (2024 - $39); 2027: Ruta Costera for $306 (2024 - $241); 2029: Ruta del Maipó for $641 (2024 - $705); 2040: from ISA Interchile for $969 (2024 - $1,157); and 2044: Ruta del Loa for $98 (2024 - $61).
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The Ecopetrol Group offsets tax assets and liabilities only if it has a legally enforceable right to offset current tax assets and liabilities, and to the extent that they relate to income taxes required by the same tax jurisdiction and by the same tax authority.
The movements of deferred income tax for the years December 31, 2025, 2024 and 2023 are as follows:
(1,302)
(87)
Deferred tax recognized in profit or loss
1,614
(3,254)
Deferred tax recognized in other comprehensive income (a)
(6,094)
4,259
(3,726)
1,160
(a)The following is the detail of the income tax recorded in other comprehensive income:
December 31. 2025
Pre–tax
Deferred tax
After tax
Actuarial valuation gains (losses) (Note 22.1)
4,235
(1,880)
Cash flow hedging for future crude oil exports (Note 30.3)
4,589
(1,775)
Hedge of a net investment in a foreign operation (Note 30.4)
6,642
(2,893)
Hedge with derivative instruments
(136)
Valuation of financial instruments at fair value
(90)
680
15,933
9,839
December 31. 2024
1,682
(374)
(3,654)
1,473
(6,305)
(172)
(237)
(8,686)
(4,427)
December 31. 2023
Pre-tax
(4,460)
1,726
Cash flow hedging for future crude oil exports
5,695
(2,624)
8,973
(2,760)
(68)
10,450
6,724
Deferred tax assets
Deferred tax assets related to tax loss carryforwards incurred by the subsidiaries of ISA Group for $220, are not recognized, since Management has assessed and reached the conclusion that it is not probable that the deferred tax asset related to these tax losses and presumptive excess income is recoverable in a short term.
As of December 31, 2025, deferred tax liabilities are not recognized on the difference between the accounting and tax bases associated with investments in subsidiaries, joint ventures of Ecopetrol S.A., Cenit, among others.
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Adjusted Tax Rate
In accordance with numeral 2 of paragraph 6 of article 240 of the Tax Code, taxpayers who are tax residents in Colombia whose financial statements are subject to consolidation must calculate the adjusted tax rate in a consolidated manner. If adjusted tax rate is less than 15%, Ecopetrol S.A. is subject to additional income tax up to a minimum 15%.
For the taxable year 2025, according to the calculation made by Ecopetrol Group, the minimum tax rate of the companies with tax residence in Colombia of the Ecopetrol Group is greater than 15%. Given the above, Ecopetrol S.A. does not recognize an additional expense from adjusted tax rate.
Adjusted tax
Net income tax of Colombia Group companies
(+) Tax discounts or tax credits
(-) Income tax on passive income from controlled entities abroad
Total Tax Adjusted
4,440
Adjusted profit
Profit before income tax expense of Colombia Group companies
(+) Permanent differences enshrined in law and that increase net income
9,568
(-) Income that does not constitute income or occasional profit, which affects accounting or financial profit
(6,596)
(-) Share of profits of associates and joint ventures of the respective taxable year of Colombia companies
(12,364)
(-) Net value of income from occasional gains that affect accounting or financial profit
(-) Exempt income due to the application of treaties to avoid double taxation
(2,281)
(-) Offsetting of tax losses or excesses of presumptive income taken in the taxable year and that did not affect the accounting profit of the year
Total Adjusted Profit
7,186
Adjusted tax rate
61.79
Income tax to add
Pillar II
The Ecopetrol Group has a presence in the jurisdictions of Argentina, Bahamas, Brazil, Bolivia, Cayman Island, Chile, Colombia, Spain, United States, Mexico, Panama, Peru, United Kingdom, Singapore, and Switzerland. The Ecopetrol Group reviewed its corporate structure to determine possible impacts of the introduction of the Pillar model rules, as well as to determine the progress of each jurisdiction in implementing this international standard.
The ongoing assessment is based on the most recent 2024 tax returns and country-by-country report, as well as the 2025 financial information. The development of the Pillar II standards in which the group is involved is summarized as follows:
F-56
Based on the analysis and calculations performed, the Ecopetrol Group will not recognize an effect in its consolidated financial statements from the implementation of Pillar II standards in the countries where it operates, given that there are no regulations for collecting the additional tax through the UTPR. In case that any effect from the implementation of Pillar II standard should be recognized, the effect on the financial statements would be $3.
Notwithstanding, based on the mandatory temporary exception contemplated in the Amendment to IAS12, the Ecopetrol Group does not recognize deferred tax assets or liabilities associated with the Pillar II income taxes, in its consolidated financial statement for taxable year 2025.
Uncertain tax positions - IFRIC 23
The Ecopetrol Group’s strategy is to avoid making aggressive tax decisions that may cause questioning of its tax returns, by tax authorities.
Regarding uncertain tax positions where it has been determined that there may be a possible controversy with the tax authority that could result in an income tax increase, a success threshold has been established by IFRIC 23, which has been calculated based on current regulations and tax opinion provided by our tax advisors.
In accordance with the aforementioned interpretation, the Ecopetrol Group considers that uncertain tax positions included in its determination of income tax will not affect the results if it is probable that the position will be accepted by the tax authorities. Notwithstanding, the Ecopetrol Group will continue to monitor new tax regulations and rulings issued by the tax authority and other entities.
10.3.Other taxes
Dividend taxes
Starting with the profits generated from the year 2017, the tax on dividends applies to resident natural persons, national companies, and foreign entities.
Law 1943 of 2018 established that, as of January 1, 2019, dividends and participations paid or credited to the account from profit distributions that have been considered as income that does not constitute income or occasional profit between Colombian companies, are subject to a withholding for dividend tax at a rate of 10% from 2022 according to Law 2277 of 2022. This withholding is transferable to the final beneficiary, foreign entity, or natural person tax resident in Colombia. On the other hand, if the profits charged to which the dividends were distributed were not subject to tax at the company level, said dividends are taxed with the income tax applicable in the period of distribution. In this case, the 10% withholding will apply to the value of the dividend once decreased with the income tax (35% for the year 2025).
The non-taxed dividends that the Ecopetrol Group will receive will not be subject to withholding at source by express provision of the regulation, which states that dividends distributed within business groups duly registered with the Chamber of Commerce, to decentralized entities or Colombian Holding Companies, they will not be subject to withholding at source for this concept.
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Transfer prices
In Colombia, income taxpayers who enter into operations with economic associates or related parties from abroad and located in free zones, or with residents located in countries considered non-cooperative jurisdictions with low or no taxation, are required to determine for income tax purposes, their ordinary and extraordinary revenue, their costs and deductions, assets and liabilities, considering for these operations the prices and profit margins that would have been used in comparable operations with or between those not economically related.
The Ecopetrol Group submitted in 2025 the transfer pricing information for 2024 corresponding to the informative return, the supporting documentation, the country-by-country report, and the master file, in accordance with current tax regulations.
For the taxable year 2025, the transactions with economic related parties abroad, as well as the business conditions under which such operations were made and the general structure, did not vary significantly with respect to the previous year. For this reason, it is possible to infer that said transactions were recognized in accordance with the arm’s length principle. It is estimated that no adjustments related to the transfer pricing analysis of the year 2025 will be required, which implies changes in the income provision of the same year.
Value Added Tax
The VAT already paid by the user of the free zone is excluded from the basis to settle the VAT on imports of goods from the free zone. Article 491 of the Tax Code expressly prohibits the possibility to consider the VAT paid on the acquisition of fixed assets as deductible tax. In addition, three VAT exemption days a year are established in Colombia for certain products, with limits depending on the units purchased.
Additionally, the list of goods and services excluded from VAT enshrined in articles 424, 426, and 476 of the Tax Code was modified, and article 437 of the Tax Code was added, regarding guidelines on compliance with formal duties regarding to VAT on the part of service providers from abroad and it was indicated that VAT withholding may be up to 50% of the value of the tax, subject to regulation by the National Government. The VAT rate remains at 19%. (Art. 424, Art. 426, Art. 476 Tax Code).
Tax procedures
In terms of procedure, there are modifications: (i) withholding that, despite being ineffective, will be enforceable, (ii) electronic notification of administrative acts, (iii) payment of glosses in the statement of objections to avoid default interest, (iv) elimination of the extension of the finality to additional three years for offsetting of tax losses, and (v) the term of the finality will be five years, compared to the years in which there is an obligation to comply with the transfer pricing regime.
In addition, an audit benefit was included for taxable years 2020 and 2021. By virtue of this benefit, the private settlement of income taxpayers and complementary taxpayers who increase their net income tax by at least a percentage a minimum of 30%, related to the net income tax of the immediately preceding year, will become final within six months after the date of presentation if a notification to correct or special requirement has been notified, or provisional settlement and, considering that the declaration must be presented in a timely manner and the payment must be made within the established deadlines.
If the increase in the net income tax is at least 20% over the net income tax of the immediately preceding year, shall be considered for twelve (12) months, after the date the presentation if not notified of a deadline for correction or special requirement, or a special deadline or provisional settlement, provided that the return is filed timely, and the payment is made within the established deadlines.
The above benefit does not apply to: (i) taxpayers who enjoy tax benefits due to their location in a specific geographical area; (ii) when it is shown that declared withholdings are non-existent; (iii) when the net income tax is less than 71 UVT. The term set forth in this regulation does not extend to declarations of withholding or sales tax, which will be governed by the general regulations.
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Tax Reform - Law 2155 of September 14, 2021
In general terms, this reform increased the general income tax rate to 35% as of January 1, 2022 and maintained the discount for the Industry and Commerce Tax at 50%. This Tax Reform introduced other changes in value added tax and tax procedure obligations. Before the passing of this Law, the rate from the year 2023 was 30% and the discount of the Industry and Commerce Tax was 100%.
Audit benefit: For the fiscal years 2022 and 2023, this Law reduces the time in which the tax authorities can audit an income tax return, from 5 years to between 6 to 12 months, depending on whether the net income tax increased to 35% or 25% with respect to that income tax return in the last fiscal year.
Works for Taxes Mechanism: The assumptions under which the “works for taxes” can be accessed are expanded, including those territories that, not being ZOMAC, are in some of these situations: (i) They have high rates of poverty, (ii) totally or partially lack infrastructure for the provision of residential public services, (iii) are in non-interconnected areas and (iv) are in Orange Development Areas (ADN acronyms in Spanish).
This mechanism will also be applicable to those projects declared of national importance that are strategic for the economic and/or social reactivation of the Nation, even if they are not located in the previous territories (subject to the approval of the Ministry of Finance and Public Credit in Colombia).
Tax reform for equality and social justice and other issues - Law 2277 of December 13, 2022
The most relevant aspects of this reform in the Business Group’s taxes.
Non-deductibility of royalties: The deductibility of oil royalties paid to the Colombian Government for the exploitation of non-renewable resources is restricted, regardless of the denomination of the payment.
On November 16, 2023, the Constitutional Court in Colombia issued ruling C-489 in which it determined that royalties are a deductible cost of income tax.
In December 2023, the Ministry of Mines and Energy and the Ministry of Finance and Public Credit requested the Constitutional Court to review the ruling issued, alleging a fiscal impact and its nullity. Given that the National Government has not filed the corresponding request, the Constitutional Court has not issued any consideration. If the Court decides to modulate the effects of the judgment issued in November 2023, the effects must be reflected in 2024.
Free zone rate: The rate of taxable income and complementary taxes applicable to offshore free zones; industrial users of special permanent free zones for port services, industrial users of special permanent free zones, whose main corporate purpose is the refining of petroleum-derived fuels or refining of industrial biofuels; industrial users of services that provide the logistics services of numeral 1 of article 3 of Law 1004 of 2005 and operator users, will be 20%.
Minimum tax rate: A minimum tax rate is established for income taxpayers, which will be calculated from the adjusted financial profit, which may not be less than 15% and will be the result of dividing the adjusted tax on the net profit. This minimum rate is called the adjusted tax rate and cannot be less than 15%. This rate is determined by dividing the adjusted tax by the adjusted profit. In turn, the factors that make up the adjusted profit and the tax are established to delimit their determination. If the adjusted tax rate is less than 15%, there must be an adjusted to recognize the minimum 15%. The tax rate is determined by dividing the net tax (NT) by the net profit (NP). The factors that make up the NT and NP are established to define its calculation. If the tax rate is less than 15%, it must be adjusted to reach the minimum of 15%.
This minimum taxation does not apply in several cases, including foreign legal entities without residence in the country; Special Economic and Social Zones, during the year that their income tax rate is 0%; the ZOMAC; income from hotel services subject to a 15% rate; publishing companies with the exclusive corporate purpose of publishing books; industrial and mixed economy companies in the Government with a 9% rate; and concession contracts.
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Taxation of non-resident entities with significant economic presence in Colombia: Non-residents that sell goods and/or provide certain digital services (listed in the standard) to people located in Colombia, could have a significant economic presence in the country and would be subject to a withholding tax of 10%, or they could choose to file an income tax return and apply a 3% rate on gross income.
Significant economic presence would exist when the non-resident (also considering its related parties):
Discount for investments made in research, technological development, or innovation: Investments in projects qualified by the National Council of Tax Benefits in Science and Technology in Innovation will have the right to discount 30% of the value invested in said income tax projects in the taxable year in which the investment was made. It is not possible to take the cost or deduction simultaneously with the discount.
Tax benefits and incentives limits: For income taxpayers, other than natural persons and illiquid successions, the value of income that does not constitute income for tax purposes or occasional gain, special deductions, exempt income, and tax discounts may not exceed the 3% per year of ordinary liquid income before deducting the special deductions contemplated in the regulations.
Industry and commerce tax deduction: The industry and commerce tax paid will be 100% deductible as of taxable year 2023, it can no longer be treated as a tax discount.
Dividend tax: Dividends and shares paid to national companies will be subject to the rate of ten percent (10%) as withholding tax on income, which will be transferable and attributable to the natural person (resident or resident investor abroad).
The income tax rate applicable to dividends and shares paid to permanent establishments in Colombia of foreign companies will be 20%.
Concurrent benefits: The prohibition of taking concurrent tax benefits is extended to exempt income, revenue that does not constitute income for tax purposes or occasional gain, and the reduction of the income tax rate.
Decree 0175 of February 2025
Through the issuance of this decree, issued within the framework of the State of Internal Disturbance declared by the Colombia National Government, the following taxes were created, which impacted the Company results:
Special Tax for the Catatumbo Region: This tax is levied on (i) the first sale within or from the national territory, and (ii) exports. The rate will be one percent (1%).
Stamp Tax: The stamp tax rate will be one percent (1%). The taxable event remained unchanged; that is, the granting or acceptance of public or private documents in the country, and those granted outside the country but executed within the national territory, the value of which exceeds six thousand (6,000) Tax Value Units (COP $298,794,000 for 2025).
This decree will be in effect from February 22 to December 31, 2025.
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Decree 1474 of December 2025
Through the issuance of this decree, issued within the framework of the State of Economic Emergency, declared by the Colombia National Government, the following tax was created, which will affect the Company’s results:
Special Tax for Fiscal Stability: This tax is levied on (i) the first sale within or from the national territory, and (ii) exports. The rate will be one percent (1%).
This decree will be in effect until December 31, 2026.
Through Press Release No. 01 of January 29, 2026, the Constitutional Court provisionally suspended the legal effects of the decree.
11.Other assets
Prepaid expenses
1,079
Partners in joint operations
912
1,145
Trust funds
521
594
Advanced payments to contractors and suppliers
349
423
Non-current assets available for sale
Abandonment fund
524
692
Employee loans
417
384
416
Judicial deposits and attachments
Advanced payments and deposits
270
326
12.Business combination
Acquisition of a group of renewable energy generation companies in Colombia
On November 13, 2025, once the parties fulfilled the conditions precedent and the required legal requirements, the transaction between Ecopetrol S.A. and Statkraft European Wind and Solar Holding AS for the acquisition of seven companies was successfully completed comprising of six renewable energy generation companies in Colombia ((i) Parque Solar Portón del Sol S.A.S. E.S.P. (“Portón del Sol”), (ii) El Roble Solar S.A.S. (“El Roble”), (iii) Córdoba Solar 2 S.A.S. (“Romosinuano”), (iv) Planta Solar Sahagún S.A.S. (“El Espino”), (v) Girasol 1 S.A.S. (“Hojarasca”) and (vi) La Cayena Solar S.A.S. (“La Cayena”)) and one administrative support company (Enerfin Services S.A.S. (“Energuana”)). Effective November 13, 2025, Ecopetrol S.A. assumed control of the seven companies, which constitutes a business combination. According to the accounting analysis performed by Ecopetrol S.A., this transaction is recognized under IFRS 3 and was accounted using the acquisition method
With the acquisition of these companies, Ecopetrol S.A. becomes the sole owner of the shares and adds a portfolio of more than approximately 0.5 GW of solar energy.
Through this acquisition, Ecopetrol S.A. advances its decarbonization and energy transition goals, aligned with its 2040 Strategy, Energy that Transforms. This acquisition promotes the competitive generation of low-emission energy for the self-consumption of the Ecopetrol Group and complements the traditional oil and gas business portfolio.
Identifiable Assets Acquired and Liabilities Assumed
The amounts recognized for acquired and existing assets and liabilities assumed as of the acquisition date are summarized below:
565
Right of use assets
Total Assets
601
Total Liabilities
313
Fair value of identifiable net assets
288
Goodwill arising from the acquisition (Note 19)
Consideration transferred, net of cash and cash equivalents acquired
301
The fair value of the property, plant, and equipment reflects the cost associated with the Portón del Sol solar plant, located in the municipality of La Dorada, Caldas, in the Magdalena Medio region, with an installed capacity of 102 MW. This solar plant connects to the Purnio substation at a level of 230 kV via a 1.3 km transmission line, through which it delivers its capacity to the National Interconnected System. Ecopetrol S.A. then uses the energy produced for its own operations under a self-generation model with remote delivery.
The goodwill is primarily attributable to the future profitability of the energy business, management’s know-how in generating new business, and other factors not included in other intangible assets. The recognized goodwill is not tax-deductible in Colombia.
The costs related to the acquisition of $7 were recognized as operating expenses in the period, primarily associated with commissions and fees for legal and financial advisory services.
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13.Investments in associates and joint ventures
Composition and movements
Interligação Elétrica do Madeira S.A.
1,698
Transmissora Aliança de Energia Elétrica S.A.
1,434
1,514
1,077
Interligação Elétrica Ivaí S.A.
473
Interligação Elétrica Garanhuns S.A.
466
479
Interligação Elétrica Paraguaçu S.A.
515
Interligação Elétrica Aimorés S.A.
323
Conexión Kimal Lo Aguirre S.A.
Ecodiesel Colombia S.A.
Consorcio Eléctrico Yapay S.A.
Transnexa S.A. E.M.A.
PA Energía para la paz
Interconexión Eléctrica Colombia Panamá S.A.
Derivex S.A.
5,987
6,475
Less impairment:
(393)
(9)
5,585
6,073
Associates
Gases del Caribe S.A. E.S.P.
1,518
1,529
ATP Tower Holdings
655
756
Gas Natural del Oriente S.A. E.S.P.
Gases de la Guajira S.A. E.S.P.
E2 Energía Eficiente S.A. E.S.P.
Extrucol S.A.
Serviport S.A.
Sociedad Portuaria Olefinas y Derivados S.A.
2,472
2,588
Less impairment: Serviport S.A.
2,463
2,579
The following is the movement of investments in associates and joint ventures:
For the year ended December 31, 2025:
Joint
ventures
Capital contributions
Effects of equity method through:
Profit or loss
(590)
(671)
Dividends declared (1)
(180)
(469)
(649)
For the year ended December 31, 2024:
2,544
5,875
8,419
629
(117)
(349)
(527)
Impairment recovery (Note 18)
For the year ended December 31, 2023:
2,693
6,804
9,497
607
(169)
(1,181)
(1,350)
(348)
(526)
Impairment (Note 18)
F-64
13.2
Additional information about associates and joint ventures
The following is the detail of assets, liabilities, and results of the main investments in associates and joint ventures, as of December 31, 2025, and 2024:
Interligação
Transmissora
Equion
Elétrica do
Aliança de
Energía
Madeira
Energia Elétrica
Limited
Statement of financial position
622
1,856
1,649
4,300
12,062
1,387
4,729
11,582
1,563
4,922
13,918
1,453
5,379
13,231
1,668
1,224
1,412
1,637
7,498
1,843
6,876
1,851
8,722
2,260
8,288
5,196
1,390
3,119
4,943
1,597
Other complementary information
Statement of profit or loss
Sales revenue
555
1,804
572
Costs
(412)
(261)
Other operating expenses, net
(168)
Financial (expenses) income
(91)
(78)
(19)
(92)
Financial year results
1,244
1,341
Other comprehensive results
1,711
1,014
Depreciation and amortization
This is a reconciliation of equity of the significant investments and the carrying amount of investments as of December 31:
Equity of the joint venture
1,389
% of Ecopetrol’s ownership
51.00
14.88
Ecopetrol’s ownership
1,566
709
1,591
735
Additional value of the investment
383
376
Unrealized gain
Carrying amount of the investment
892
684
878
785
The information on assets, liabilities, and profits of the other associated companies and joint ventures is found in exhibit 1.
F-65
14.Property, plant, and equipment
Plant
Pipelines,
Construction
and
networks,
in
equipment
and lines
progress
Lands
Cost
63,183
63,501
18,304
19,528
5,137
3,290
172,943
Additions/capitalizations (1)
3,145
3,347
1,723
1,203
343
9,773
Acquisition of wind and solar energy companies (2)
556
630
Abandonment cost update (Note 23)
370
573
Capitalized financial interests (3)
469
Exchange differences capitalized
Disposals
(505)
(79)
(847)
(5,008)
(3,020)
(227)
(1,221)
(324)
(171)
(9,971)
Reclassifications/transfers
1,821
(190)
62,156
65,864
17,563
19,923
4,843
3,444
173,793
Accumulated depreciation and impairment losses
(28,174)
(26,049)
(1,659)
(8,139)
(167)
(1,300)
(65,488)
Depreciation expense
(3,288)
(2,701)
(903)
(130)
(7,022)
Recovery (loss) impairment (Note 18)
475
725
1,967
1,260
463
3,811
(142)
(29,141)
(27,330)
(1,422)
(8,518)
(1,161)
(67,689)
Net balance as of December 31, 2024
35,009
37,452
16,645
11,389
4,970
1,990
Net balance as of December 31, 2025
33,015
38,534
16,141
11,405
4,726
2,283
It mainly includes: i) Ecopetrol S.A. ongoing projects associated with the Caño Sur, Rubiales, Akacias, Castilla, and Chichimene fields and the Barrancabermeja Refinery; ii) Interconexión Eléctrica S.A. E.S.P. ongoing projects: UPME 04-2019 La Loma - Sogamoso 500 kV Transmission Line, connection of the Alpha and Beta wind farms to the Nueva Cuestecitas substation, connection of the Windpeshi wind project to the Cuestecitas 200 kV substation, asset optimization plan, and the San Mateo and Betania substation renovation projects.
The assets in this acquisition consist of the Windpeshi wind project in La Guajira ($65) and a portfolio of solar project companies in Colombia ($565) (See Note 12).
Financial interest is capitalized based on the weighted average rate of borrowing costs.
54,897
58,585
15,520
16,668
4,833
3,338
153,841
2,999
2,427
3,121
9,521
CPO-09 assets in business combination (2)
716
275
1,239
Fair value adjustment in business combination (2)
1,011
350
1,436
428
(918)
(276)
(71)
(105)
(1,384)
Field reversal
4,509
2,639
1,100
292
8,867
Reclassifications/transfers (4)
(279)
(896)
(156)
(1,013)
(24,981)
(23,488)
(1,688)
(7,146)
(1,197)
(58,668)
(2,821)
(2,354)
(734)
(6,068)
807
299
(138)
1,261
834
1,197
(1,722)
(1,046)
(411)
(83)
(3,277)
316
(174)
Net balance as of December 31, 2023
29,916
35,097
13,832
9,522
4,665
2,141
95,173
Mainly includes: i) Ecopetrol S.A. projects in progress associated with the Akacías, Caño Sur, Rubiales, Castilla, Chichimene, Cupiagua fields and the Barrancabermeja Refinery ii) Interconexión eléctricas S.A. E.S.P projects in progress: UPME 09-2016 Copey–Cuestecitas, 500 kV and Copey–Fundación, 220 kV, UPME 04-2019 La Loma - Sogamoso 500 kV Transmission Line, Connection of the Alpha and Beta wind farms to the Nueva Cuestecitas substation, Copey - Cuestecitas 500kV Second Circuit Project, Connection of the Windpeshi wind farm to the Cuestecitas 200kV substation and asset optimization plan.
Ecopetrol signed a binding sale and purchase agreement (SPA) with Repsol Colombia Oil & Gas Limited (“Repsol”) to acquire a 45% interest in Block CPO-09 for USD $452 million, making it the owner of 100% of the participating interest in said block. As established in the agreement, December 31, 2024, was defined as the economic and control date of operations, on which Ecopetrol S.A. assumed the rights, responsibilities and obligations, including any income, costs and expenses of the asset. This transaction was recognized as a business combination (step acquisition).
It corresponds mainly to i) recognition of McDermott’s shares in Refinería de Cartagena S.A.S. (see Note 23.4) and ii) additions and transfers in transmission lines of Interconexión eléctricas S.A. E.S.P due to the entry into operation of the projects.
F-67
Asset
retirement
investments
cost
evaluation
108,855
8,249
10,052
127,156
4,691
5,843
10,552
1,608
1,578
(35)
(36)
Write off exploratory assets and dry wells (2)
(717)
334
426
(5,694)
(152)
(357)
(6,203)
Transfers/reclassifications
3,972
(4,206)
(218)
112,125
9,739
10,677
132,541
Accumulated depletion and impairment losses
(72,930)
(6,444)
(116)
(79,490)
Depletion expense
(7,447)
(315)
(7,762)
(Loss) recovery of impairment (Note 18)
(244)
(41)
(272)
3,323
3,420
(77,216)
(6,885)
(33)
(84,134)
35,925
1,805
9,936
34,909
2,854
10,644
Includes mainly: a) Ecopetrol Permian for investments made in the drilling of wells and construction of facilities carried out in Midland/Delaware, b) Ecopetrol S.A. mainly the Rubiales, Caño Sur, Akacias and Castilla fields, and c) Hocol S.A. mainly the execution of the Llanos 100, Llanos 123, Saman, Vim8, Llanos 86-87-104, Malacate, La Cañada, SN-18, La Punta, Guarrojo and SSJN1 projects.
Includes the recognition in the expense of the exploratory activity of Ecopetrol S.A., mainly of the Papayuela and Buena Suerte wells.
Asset retirement
94,176
10,147
9,719
114,042
9,101
1,417
10,541
424
(2,085)
(2,088)
Write off exploratory assets and dry wells (3)
(1,108)
Capitalized financial interests (4)
345
381
4,507
4,719
(478)
(280)
(63,010)
(5,478)
(337)
(68,825)
(7,083)
(874)
(7,957)
Loss of impairment (Note 18)
(254)
(333)
(2,431)
(2,511)
(243)
300
31,166
4,669
9,382
45,217
Includes mainly: a) Ecopetrol Permian for investments made in the drilling of wells and construction of facilities executed in Midland/Delaware, b) Ecopetrol S.A. mainly Caño Sur, Rubiales, Floreña and Castilla fields and c) Hocol S.A. mainly for the execution of the Llanos, Guarrojo, Perdices, Cor 9, VIM8, SN-18, Upar, Malacate, Guajira, Ocelote, Rancho Hermoso, and SSJN1 projects.
Includes: a) Ecopetrol S.A. mainly the Orca1, Arantes1, Machin1, and Morito1 wells b) Hocol S.A mainly the Milonga, Yoda A, Arbolito Norte, Sabanales, Toritos, and Saltador wells and exploration and seismic expenses mainly in Llanos, VIM8, Perdices, Cor-9, SN-18, SSJN1, Upar, YD SN-1, SN-15, RC-7, c) Ecopetrol Brasil Pau Brasil well.
F-69
Accounting for suspended exploratory wells
The following table shows the classification by age, from the completion date, of the exploratory wells that are suspended as of December 31, 2025, 2024 and 2023:
Between 1 and 3 years (a)
Total suspended exploratory Wells
Number of projects exceeding 1 year
Projects under 1 year of suspended (c)
For 2025 and 2024, the suspended exploratory wells mainly correspond to Ecopetrol: Gibraltar, Hocol: Pollera Norte 1, which were under evaluation.
For 2025, it mainly corresponds to Ecopetrol: Maicero and Kalalu, Hocol: Matraquero-1. For 2024, it mainly corresponds to Ecopetrol: Atalayas, Hocol: Toritos Sur 2. For 2023, it corresponds mainly to Ecopetrol: Kale and Gibraltar, Hocol: SSJN1 BO5, Pollera Norte A3 and YDSN-1 Yoda A.
16.Right-of-use assets and lease liabilities
The following is the movement of right-of-use assets and lease liabilities for the years ended December 31, 2025 and 2024:
Lands and
Plant and
Right-of-use
buildings
Vehicles
assets
liabilities (2)
Net carrying amount as of December 31, 2024
459
1,506
273
Depreciation of the year
(98)
(121)
(379)
Remeasurements (1)
Impairment loss (Note 18)
Finance cost
Repayment of borrowings (capital)
(506)
Payment of interests
(135)
Transfers
Exchange difference
(109)
Net carrying amount as of December 31, 2025
272
458
1,396
Net carrying amount as of December 31, 2023
842
1,383
414
(21)
(51)
(140)
(319)
(26)
(27)
Effect of loss of control in subsidiaries
(452)
(13)
It corresponds mainly to updating rates and conditions in lease contracts.
Lease liabilities are presented as part of loans and borrowings (Note 20).
17.Intangible assets
The following is the movement of intangibles and their amortization and impairment for the years ended December 31, 2025, and 2024:
Licenses
Concessions
software
intangibles
and rights
Easements (1)
2,125
1,210
16,025
1,662
21,022
Acquisitions
271
502
(29)
(61)
(118)
(2,768)
(3,024)
2,276
1,090
13,551
18,566
Accumulated amortization and impairment losses
(1,185)
(3,098)
(148)
(4,609)
(288)
(634)
(945)
Impairment (loss) recovery
975
(1,400)
(2,817)
(4,525)
940
1,032
12,927
876
934
10,734
Easements correspond to acquired rights for the passage of its operating assets, mainly energy transmission lines. These assets are acquired in perpetuity, so they do not have a specific term or contractual limit established and the right is maintained over time. The Ecopetrol Group also owns easements associated with rights-of-way for oil pipelines, which do have a finite useful life and generate amortization charges.
1,659
970
13,659
1,557
17,845
530
322
866
(153)
(96)
2,055
2,067
336
415
(961)
(256)
(1,781)
(132)
(3,130)
(263)
(568)
(7)
(853)
Losses for impairment
(43)
(46)
(25)
(713)
(650)
698
714
11,878
14,715
18.Impairment of long-term assets
As mentioned in Note 4.13, each year the Ecopetrol Group assesses whether there is an indication that a non-current asset or cash–generating unit may be impaired or if impairment losses recognized in previous years should be reversed.
The impairment of non-current assets includes property, plant, and equipment, natural resources, investments in companies, and goodwill. The Ecopetrol Group is exposed to future risks derived mainly from variations in (a) the estimate of future oil prices, (b) the refining margins and profitability, (c) the cost profile, (d) the investments and maintenance expenses, (e) the amounts of recoverable reserves, (f) the market and country risk assessments reflected in the discount rate and (g) changes in national and foreign regulations, among others.
Any changes in the above estimates used to calculate the recoverable amount of a non–current assets can have a material impact on the recognition impairment losses or reversals in consolidated statement of profit or loss. Highly sensitive significant estimates affecting each business segments, among others include (a) in the exploration and production segment, variations of hydrocarbon prices, (b) in the refining segment, changes in finished products and crude oil prices, the discount rate, refining margins, (c) in the transport and logistics segment, transported volumes and exchange rate, and (d) in energy transmission and toll roads concessions, infrastructure construction margins, asset remuneration flow estimates, network capacity, among others.
Based on the impairment tests conducted by the Ecopetrol Group, the following are the impairments or reversals of impairment for the years ended on December 31, 2025, 2024 and 2023:
Impairment reversal (loss) by segment
Exploration and production
(325)
(480)
(2,741)
1,265
1,482
(630)
(209)
Recognized in:
Property, plant, and equipment (Note 14)
1,262
Natural and environmental resources (Note 15)
(271)
(2,154)
Investment in associates and joint ventures (Note 13)
Right of use assets (Note 16)
Other non-current assets
(50)
18.1Exploration and production
The impairment (loss) reversal of assets of the Exploration and Production segment for the years ended December 31 of 2025, 2024 and 2023 is the following:
Oilfields
(495)
(2,733)
18.1.1
In 2025, a net impairment loss of $325 was recognized, generated in: i) Ecopetrol S.A., mainly in the cash-generating units Llanito, Tibu, Tisquirama, and Casabe; and a recovery in assets such as Teca Cocorná, Arauca, Moriche, and Ariari; ii) Hocol S.A., offsetting the impairment of the cash-generating units Bullerengue, Espinal, and Llanos with the recovery in Cicuco, Toldado, La Hocha, Upía, and Chenche; and iii) a recovery in the K2 and Gunflint fields of Ecopetrol América. The impairment incurred during the year resulted from the decrease in future hydrocarbon prices, which was partially offset by the implementation of asset profitability management plans and a decrease in the discount rate.
In 2024, a net impairment expense of $495 was recognized: generated in: i) in the K2 and Gunflint fields of Ecopetrol America, ii) Ecopetrol S.A. due to the offsetting effect between an impairment mainly in the Llanito, Orito, and Sur cash-generating units; and a recovery mainly in assets such as Suria, Dina Cretaceo, Jazmin, and San Francisco; and iii) in Hocol S.A. due to the offsetting effect between the impairment of the Espinal cash-generating unit and the recovery in La Hocha, Chenche, Toldado, Cicuco, and Upía. The lower impairment compared to the previous year is mainly due to the success in the implementation of plans to mitigate the impairment loss for lower future hydrocarbon prices in the short and medium term. The plans considered the following aspects: acceleration in the addition of incremental volumes through profitable projects and decision-making, efficiencies, the decrease of fixed costs, optimization of technical abandonment costs, net book value management, among others
In 2023, an impairment loss was recognized, considering CAPEX variables, OPEX effects and prices mainly in the cash-generating units (CGU) Casabe, Llanito, Suria, and Tibú; and a recovery mainly in the Piedemonte unit, which was the subject of unification of Floreña, Cupiagua and Cusiana assets during 2024, considering that these fields share facilities with each other, possess synergies, and jointly manage the surface fluids across the three large infrastructures. Likewise, impairment losses were recognized in Hocol S.A. in the Cicuco, Toldado, La Hocha, Espinal, and Chenche CGUs and a recovery in Upía CGU. In the CGUs abroad, an impairment loss was recognized in K2 CGU of Ecopetrol America.
F-73
The following is the breakdown of oilfields impairment losses or reversals for the years ended December 31, 2025, 2024 and 2023:
Carrying
Recoverable
Cash generating units
amount
reversal (loss)
Oil fields in Colombia
Reversal
2,534
3,991
Loss
3,209
2,493
(716)
3,109
6,131
880
3,739
2,364
(1,375)
9,815
18,113
364
10,048
6,951
(3,097)
The assumptions used to determine the recoverable amount include the following:
F-74
18.1.2Investments in joint ventures
Investments in joint ventures in the Exploration and Production segment are recorded using the equity method of accounting. The Ecopetrol Group evaluates if there is any objective evidence that indicates that the fair value of such investments has been impaired in the year, especially those for which goodwill has been recognized.
As a result, Ecopetrol Group recognized a recovery (loss) of impairment on the carrying value as of December 31, as follows:
In 2025, there was no evidence that the book value of associates and joint ventures was below their recoverable amount.
In 2024, an impairment recovery was recognized on the investment in Equion, which adjusts the book value of the assets evaluated to their current fair value.
In 2023, an impairment loss was recognized on the investment in Equion, mainly due to the update of its non-current assets in the model.
18.2Refining and Petrochemical
18.2.1
Refinería de Cartagena
During 2025, no situations or conditions were identified in external or internal variables that could generate indications of impairment charges for the refinery.
In 2024, an impairment recovery of $1,271 was recognized, mainly due to: i) higher price differentials for middle distillates in the medium- and long-term projections, ii) a greater share of domestic crude oils in the refinery’s feedstock, iii) the inclusion of energy efficiency initiatives and the commissioning of the U-111 unit capacity expansion project to 50 kilobarrels per day, with the medium- and long-term goal of maintaining operational efficiency, and iv) a decrease in the discount rate based on market conditions. Additionally, an impairment loss of $6 was recognized, corresponding to the surplus from the expansion project.
Cash–generating units
28,237
35,330
F-75
During 2023 there was a recovery of $1,494 mainly due to: i) higher price differentials in mid–distillates in the medium and long-term projection, ii) imported crude oils more discounted on the brent marker, and iii) operational improvements executed in 2025, which together with energy efficiency initiatives have managed to optimize the operational costs of the refinery and reduce energy consumption. Additionally, a loss for impairment of office-type containers was recognized as a result of their appraisals and leftovers from the expansion project for $12.
26,423
27,906
The impairment recoveries for Refinería de Cartagena at year-end 2024 and 2023 were calculated based on fair value less costs to dispose of, which is higher than its value in use. Fair value, less costs to dispose of, were determined based on after-tax cash flows derived from the business plans projected by Management. These plans are based on market prices provided by a third party, considering long-term macroeconomic variables and fundamental assumptions regarding the supply and demand of crude oil and refined products. The fair value category is Level 3.
The estimates derived from the valuation of the impairment of the assets of Refinería de Cartagena S.A.S. The valuations for 2024 and 2023 were based on: i) exogenous and market variables beyond management control, such as prices that define refinery revenues (refined products) and costs (raw materials), and macroeconomic variables that determine the discount rate for cash flows used to value assets; and ii) operational and corporate variables subject to management control, such as plant efficiency, operational availability, and the corresponding cost and expense management. The assumptions used in the model to determine recoverable values include volumes, prices, projected operating expenses (Opex) and capital expenditures (Capex), as well as an investment component for the implementation of new technologies.
18.2.2Refinería de Barrancabermeja
As of December 31, 2025, 2024, and 2023, qualitative assessment of the assets associated with the refining segment were executed, including the Barrancabermeja Refinery Modernization Project. As a result, there are no indicators of impairment loss or recovery.
18.3Transport and Logistics
The recoverable amount of these assets was determined based on its fair value with costs of disposal, which corresponds to discounted cash flows based on the hydrocarbon production curves and refined products transport curves. The fair value hierarchy is 3.
The assumptions used in the model to determine the recoverable amount included:
F-76
In 2025, an impairment recovery of $346 was presented due to: i) economic update in the life of the assets, ii) better results in the volume projections, iii) increase in rates, iv) decrease in operating costs and v) a lower discount rate.
In 2024, there was an impairment reversal of $127 due to the effect of: i) tariff update in oil pipelines, ii) better results in volumetric projections, and iii) higher closing exchange rate for 2024 versus 2023.
In 2023, for the volumetric projection exercise until 2040, there is a decrease in the North, South and Yaguará-Tenay CGUs compared to 2022. This means that an impairment loss of $630 was recognized, caused mainly by the variation in the exchange rate.
18.4Energy transmission and roads
According to the impairment test, as of December 31, 2025, 2024 and 2023, ISA and its companies considered that there are no operational or economic issues indicating that the net book value of its non-current non-financial assets cannot be recovered, except for the facts evidenced in the year, which were recognized and assessed in accordance with the applicable accounting standard.
2023 (4)
Intangibles (1)
Property, plant and equipment (2)
Non-current assets held for sale (3)
F-77
19.Goodwill
Interconexión Eléctrica S.A. E.S.P. (1)
3,220
3,552
Oleoducto Central S.A.S.
683
Hocol Petroleum Ltd.
538
Invercolsa S.A.
434
Andean Chemical Ltd
Parque Solar Portón del Sol S.A.S y Energuana S.A.S.
5,129
5,443
Less impairment Hocol Petroleum Ltd.
(297)
(1)The variation corresponds to the effect of currency translation applied from subsidiaries functional currencies to Ecopetrol’s functional and presentation currency (COP).
20.Loans and borrowings
20.1Composition of loans and borrowings
Weighted average effective
interest rate as of December 31
Local currency
9.8
4,985
5,193
Commercial and syndicated loan
11.7
6,199
5,302
818
12,002
11,371
Foreign currency (1)
79,222
88,881
Commercial and syndicated loans
16,670
18,254
Loans from related parties (Note 31)
728
829
97,198
108,594
109,200
119,965
The reduction in foreign currency debt is primarily due to the decline in the exchange rate. Spot rate fell from $4,409.15 to $3,757.08 between December 31, 2024 and December 31, 2025, respectively.
During 2025, loans and borrowings for $18,402 were acquired mainly: in Ecopetrol S.A. for $13,174 and Interconexión Eléctrica S.A. E.S.P. for $4,375. Among these, the following stand out:
-A dollar-denominated commercial loan from Banco Santander maturing in April 2030.
-Disbursement of a long-term dollar-denominated loan maturing in 2030 from Sumitomo Mitsui Banking Corporation and Banco Latinoamericano de Exportaciones S.A. - Bladex totaling USD 530 million, with the proceeds earmarked for the company’s acquisitions and a debt restructuring transaction.
As of December 31, 2025, U.S. dollar denominated total debt corresponds to USD $29,065 million, recognized in financial statements at its amortized cost, which corresponds to the present value of cash flows, discounted at the effective interest rate of each loan and borrowing.
As a result of the Business Group’s strategy, related to the comprehensive management of maturities, during 2025 capital payments were made for $15,192: mainly in Ecopetrol S.A. for $11,590, and Interconexión Eléctrica S.A. E.S.P. for $2,833. Likewise, interest payments were made for $8,199 mainly in Ecopetrol S.A. for $5,767, and in Interconexión Eléctrica S.A. E.S.P. for $2,250.
20.2Fair value of loans
The following are the fair values of loans and borrowings as of December 31, 2025, and 2024:
4,904
5,153
6,024
5,973
11,746
Foreign currency
77,440
83,721
Commercial, syndicated loans and related parties
15,072
20,784
Lease liabilities and related parties
93,090
105,135
104,836
117,137
The fair value of loans and borrowings is classified as Level 2.
20.3Maturity of loans and borrowings
The following are the maturities of loans and borrowing as of December 31, 2025:
Up to 1
year
1 - 5 years
5-10 years
> 10 years
1,675
1,181
563
3,914
580
927
6,169
2,924
1,982
4,896
27,658
29,195
17,473
Commercial and syndicated loans and lease liabilities
3,529
12,024
1,621
17,248
Loans from related parties
9,153
39,682
30,816
17,547
45,851
33,740
19,529
F-79
The following are the maturities of loans and borrowing as of December 31, 2024:
375
1,256
1,385
2,177
554
3,299
1,324
1,154
4,996
2,918
2,303
5,548
24,886
37,937
20,510
13,827
462
333
10,134
38,964
38,604
20,892
43,960
41,522
23,195
20.4Breakdown by type of interest rate and currency
The following is the breakdown of loans and borrowing by type of interest rate as of December 31, 2025, and 2024:
Fixed rate
1,688
1,800
Floating rate
10,314
9,571
70,864
83,481
26,334
25,113
20.5Loans designated as hedging instrument
As of December 31, 2025, the Ecopetrol Group designated USD$17,348 million (2024 – USD$17,612 million) of foreign currency debt as a hedging instrument, of which USD$10,001 million (2024 - $10,269 million) is used to hedge the net investment in foreign operations with the US dollar as their functional currency, and USD$7,347 million (2024 – USD$7,343 million) is used to hedge the cash flows of future crude oil exports. See Notes 30.4.
20.6Guarantees and covenants
Ecopetrol S.A. has commitments (covenants) related to the delivery of periodic financial information and the fulfillment of obligations arising from credit agreements with financial institutions, fiduciary entities, bondholders, rating agencies, auditors, among others.
As of December 31, 2025, the estimated value of the current guarantees granted by ISA and its companies, within the framework of the definition in paragraph 14 of IFRS 7, used to support growth in its different business units and to ensure commercial, operational, and strategic viability amounts to $19,771 (2024 - $22,665), mainly in i) Chile for $13,189 (2024 - $15,799) in Intervial Chile, Ruta del Loa, Ruta de los Ríos, Ruta de la Araucaría and Ruta del Maipo, b) Brazil in ISA CTEEP for $3,907 (2024 - $4,187), and c) Colombia on the Ruta Costera for $2,679 (2024 - $2,679).
ISA and its companies have commitments (covenants) related to the delivery of periodic financial information and the fulfillment of the obligations originated in the credit contracts with the financial entities, the Ministry of Public Works of Chile, the bondholders, the rating agencies risks, auditors, and municipalities, among others.
F-80
Ecopetrol USA Inc. and its subsidiaries have commitments (covenants) related to the delivery of periodic financial information and compliance with the obligations arising from a volumetric prepayment agreement, a commercial contract in which Ecopetrol Group receives payments in advance for production, with a third party. The opening and closing balance in 2025 for this contract correspond to $255 MUSD and $159 MUSD, respectively.
During the reporting year, the Ecopetrol Group has complied with its payment obligations, guarantees and commitments with its bondholders and local and/or international financing entities.
21.Trade and other payables
Suppliers (1)
11,586
Advances for associated operations
1,198
982
Withholding tax (2)
1,023
Insurance and reinsurance
280
Deposits received from third parties
Dividends payable
Agreements in transport contracts
Various creditors
886
687
The variation includes $1,109 from the consideration paid to Repsol in the first quarter of 2025 for the acquisition of Block CPO09.
Includes withholding taxes on income generated primarily by Ecopetrol S.A.
The carrying amount of trade accounts and other accounts payable approximates their fair value due to their short–term nature.
22.Provisions for employees’ benefits
Post–employment benefits
Healthcare
9,004
11,450
Pension
1,980
2,788
Education
433
Other plans
Termination benefits – Voluntary retirement plan
828
12,696
16,131
Social benefits and salaries
1,219
1,206
Other employee benefits
13,953
17,377
22.1Post–employment benefits liability (asset)
The following table shows the movement in liabilities and assets, net of post-employment benefits and termination benefits, as of December 31, 2025:
Pension and bonds
Liabilities for employee benefits
14,831
13,030
27,861
Current service cost
Past service cost
Interest expense
2,373
Gains from financial assumptions
(1,054)
(3,118)
(4,172)
Benefits paid
(1,301)
(837)
(2,138)
13,768
10,458
24,226
Plan assets
11,693
11,730
Return on assets
989
991
Contributions to funds
825
11,501
11,530
Net post–employment benefits liability
2,267
10,429
The following table shows the movement in liabilities and assets, net of post-employment benefits and termination benefits, as of December 31, 2024:
16,412
12,750
29,162
1,163
928
2,091
(1,520)
(298)
(1,818)
(1,232)
(742)
(1,974)
11,974
12,011
850
Payments and contributions to funds
(1,183)
(1,187)
3,138
12,993
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The following table shows the movement in profit and loss and in other comprehensive income as of December 31, 2025, 2024 and 2023:
Recognized in profit or loss
Interest expense, net of return on plan assets
1,382
1,241
1,088
1,671
1,666
Recognized in other comprehensive income
Pension and pension bonds
3,035
(2,664)
1,132
1,404
(1,714)
(82)
22.2Plan assets
Plan assets are resources held by pension trusts for payment of pension obligations. Payments for health and education post–employment benefits are Ecopetrol Group’s responsibility. The plan assets and future return on those assets cannot be returned to Ecopetrol Group.
The following is the composition of the plan assets by type of investment as of December 31, 2025, and 2024:
Securities denominated in local currency
3,242
1,930
Bonds issued by the national government
3,090
3,190
Other foreign currency denominated securities
3,046
2,935
Bonds issued by private entities
1,705
2,932
Other public bonds
Variable yield bonds
512
The 48.48% (2024 – 58.09%) of the securities in the plan assets are classified as level 1 in the fair value hierarchy where prices for the assets are directly observable on actively traded markets, and 51.52% (2024 – 41.91%) are classified as level 2. The following is the balance of plan assets by fair value hierarchy level as of December 31, 2025, and 2024:
330
2,912
1,901
1,981
1,109
3,042
2,917
1,691
2,821
337
5,590
6,815
5,940
4,915
F-83
The main risk to which the plan assets are exposed to is the market risk (Note 30.8) derived from credit rating issued by credit ratings agencies. The following table reflects the credit ratings of the issuers and counterparties in assets held by the Plan assets, according to rating Company such as Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings:
6,525
6,696
Nation
4,029
4,293
380
344
Other ratings
Rating not available
The securities in the plan assets are valued following the regulations defined by the Financial Superintendency of Colombia, regarding the use of an authorized market data provider. For this purpose, information provided by authorized market-data provider is used, which corresponds to collected data from active markets. In cases where market data is unavailable, other directly or indirectly observable data is used.
Within the investment rating process, in addition to the information used for valuation, other relevant factors are considered, such as the issuer rating, investment classification, liquidity, and active market, which permit the appropriate hierarchy level classification of the investments.
22.3Actuarial assumptions
The following are the actuarial assumptions used in determining the present value of defined employee benefit obligations used for the actuarial calculations as of December 31, 2025, and 2024:
Health
Discount rate
9.9%-12
10.25%-12.5
4%-10.25
9.85%-12.87
Salary growth rate
3.0%-4.94
Expected inflation rate
3.0%-4.0
3.30
Pension growth rate
3.0%-3.30
Cost trend
Short–term rate
4.30
Long–term rate
4.0%-4.30
6.85%-10.9
8.75
8.75%-11.2
9.0%-11.0
5.7%-11.6
2.0%-3.0
4.0-5.0
3.0%-3.3
13.5
N/A: Not applicable for this benefit.
The cost trend is the projected increase for the initial year, which includes the expected inflation rate.
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22.4Maturity of benefit obligation
The cash flows required for payment of post–employment obligations of Ecopetrol Group are the following:
Year
Other benefits
1,428
806
2,234
1,471
2,305
1,493
869
2,362
2,329
1,459
923
2,382
22.5Sensitivity analysis
The following sensitivity analysis as of December 31, 2025 shows the effect of such possible changes on defined benefit obligation, while keeping the other assumptions constant:
–50 basis points
12,977
9,307
+50 basis points
1,092
8,359
Inflation rate
11,957
1,093
858
13,038
1,131
9,305
394
23.Accrued liabilities and provisions
Environmental
contingencies and
obligation
others
11,211
797
2,348
14,356
Abandonment costs update
2,151
Additions (recoveries) (1)
(339)
525
Uses (2)
(543)
(146)
(377)
(1,066)
Financial costs and interest (2)
642
(55)
(240)
13,314
541
2,593
16,448
992
12,322
2,038
It mainly includes the recognition of provisions related to environmental compensation at Ecopetrol S.A., among others.
This represents the financial cost associated with the discounting of the liability and its respective use.
13,102
723
2,318
16,143
(2,097)
Uses
(766)
(381)
(1,297)
Financial costs and interest
636
931
Fair value adjustment in business combination
Reversal of fields (2)
1,134
449
10,077
760
1,899
It mainly includes the recognition of provisions related environmental compensation at Ecopetrol S.A., among others.
It corresponds to the abandonment provision associated with the assets delivered to Ecopetrol S.A. of the La Cañada and La Hocha fields.
10,006
898
1,852
12,756
Abandonment costs update (1)
3,465
Additions (2)
755
Uses (3)
(680)
(905)
(383)
(1,968)
Financial costs and interest (3)
477
1,331
(137)
(454)
1,105
420
11,997
653
1,898
14,548
Main variations in the abandonment cost are due to 1) an increase in activity in Rubiales and Caño Sur, 2) an increase in operating costs in Cira-Infantas fields, and 3) upgrades in the equipment and tariff increases.
It mainly includes the recognition of provisions related to potential obligations and environmental contingencies (Note 23.3) at Ecopetrol S.A., among others.
It mainly includes uses and interest expenses originating from rulings against the claims of Ecopetrol S.A. related to public works contributions. The recognition applied Law 2277 of 2023 with which a benefit was obtained by reducing interest payable to the tax authority by 50%.
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23.1Asset retirement obligation
The estimated liability for asset retirement obligation costs corresponds to the future obligation that the Ecopetrol Group has to restore environmental conditions to a level similar to that exist before the start of projects or activities, as described in Note 4.14. As these relate to long–term obligations, this liability is estimated by projecting the expected future payments and discounting at present value with a rate indexed to the Ecopetrol Group’s financial obligations, considering the temporariness and risks of this obligation. The discount rates used in the estimate of the obligation as of December 31, 2025 were Exploration and Production 5.24% (2024 - 5.88%), Refining and Petrochemicals 5.83% (2024 - 6.59%), and Transportation and Logistics 5.64% (2024 - 6.94%).
23.2Litigations
The following table details the main litigations recognized in the consolidated statement of financial position as of December 31, whose loss expectations are probable and could imply an outflow of resources and the estimated provision:
ISA Energía Brasil. Civil contingency: Nullity of merger of EPTE by CTEEP, issued by Joana D Arc Tensol Rodrigues Pereira. It corresponds to a declaratory action in which minority shareholders claim the nullity of the merger of the Paulista Energy transmission Company (EPTE) by the company or, jointly and severally, the declaration of their right to withdraw and the determination of the payment of the redemption value of their shares. In 2024, the process was classified as a contingent liability.
Regulatory Contingency: Eletrobras Billing - RBNI: This corresponds to the collection action filed by Eletrobras against ISA CTEEP requesting the return of the amount overcharged by the Company as part of the compensation payment resulting from the extension of Concession Contract No. 059/2001 under Law No. 12,783/201, relating to the new investment facilities that had been transferred to the Company by Eletrobras.
Unfavorable first instance ruling for Ecopetrol Group in the process of remediating the damages associated with the hydrocarbon spill that occurred in Guaduas, Vereda Raizal and Cajón, in the property called “La Floresta” in May 2004.
Administrative processes of a sanctioning type issued by PRONATEL and OSIPTEL Internexa Peru: Procedure for failure to pay contributions during the years 2011 to 2023 or the provision of the Dark Optical Fiber service.
Transelca. Regulatory contingency: Unavailability of service. Compensation for energy not supplied. In June 2020, a shot occurred in the Bay of Line BL2 Sabanalarga-Fundación, at the Sabanalarga substation, 220 kV; the substation went out of operation, as well as other assets operated by Transelca and other third parties, leaving a large region of the Atlantic Coast without electricity service. In accordance with the provisions of Resolution GREC 011 of 2009, numeral 3.8.3, this event may cause the company to pay compensation for energy not supplied.
Ecopetrol S.A. as responsible for the damages caused by export activities in influence of the municipalities of Cicuco, Talaigua Nuevo and Mompox.
23.3Environmental contingencies and others
These correspond to contingencies for environmental incidents and obligations related to environmental compensation and mandatory investment of no less than 1% for the use of, exploitation of or effect on natural resources imposed by national, regional, and local environmental authorities. Mandatory investment of no less than 1% is based on the use of water taken directly from natural sources in accordance with the provisions of Law 99 of 1993, Article 43, Decree 1900 of 2006, Decree 2099 of 2017 and 075 and 1120 of 2018 and article 321 of Law 1955 of 2019 in relation to the projects that the Ecopetrol Group develops in Colombia.
F-87
The Colombian Government, through the Ministry of Environment and Sustainable Development, issued Decrees 2099 and 075 in December 2016 and January 2017, through which it modified the Single Regulatory Decree of the environment and sustainable development sector, Decree 1076 of 2015, in relation to the mandatory investment for the use of water taken directly from natural sources. The main changes established by these decrees were in relation to the areas of implementation, investment lines and the basis for liquidation of obligations. In addition, June 30, 2017, was defined as the maximum date to modify the Investment Plans that are in execution.
From the Company’s Environmental Management, with the regional environmental departments and allies in the territory, Ecopetrol executes more than 245 current plans for environmental offsetting and forced investment of 1%.
The resources allocated to these obligations have been directed towards environmental protection, conservation, and preservation through the implementation of more than 700 voluntary conservation agreements. Progress has also been made in acquiring land for conservation, ecological restoration processes, and reforestation programs. Additionally, through an agreement with IDEAM for the execution of the mandatory 1% investment, a specific line item was incorporated for monitoring water resources through the installation and operation of hydrometeorological stations for tracking climatological and hydrological variables.
23.4Contingencies
VAT on Imports of Gasoline and Diesel Fuel
The National Tax and Customs Directorate (DIAN by its acronym in Spanish) issued Ruling No. 100202208-2305 on December 19, 2024 (and reaffirmed in July 2025) stating, according to its interpretation, that the importation of gasoline and diesel fuel is subject to Value-Added Tax (VAT) at the general rate of 19%. According to DIAN’s interpretation, the tax base is the customs value of the products.
Ecopetrol S.A. and Refinería de Cartagena S.A.S. disagree with this interpretation made by the DIAN; DIAN considers that the importation of gasoline and diesel during 2022 to 2024 should have been subject to Value Added Tax (VAT) at the general rate of 19%. Nevertheless, Refinería de Cartagena S.A.S and Ecopetrol S.A. believe that their filings were prepared in accordance with current tax and customs legislation. The National Tax and Customs Directorate, in line with its interpretation and current application of the law, has issued six official assessments to Refinería de Cartagena S.A.S. totaling COP $1.3 trillion in VAT and penalties, and has also issued two official assessments to Ecopetrol S.A. totaling COP $6.5 trillion in VAT and penalties for the periods between 2022 and 2024; interest has been accrued on these amounts to date, which would amount to approximately COP $4.9 trillion. These amounts could be significantly higher as time passes or if additional demands are received from DIAN. At this time, all administrative remedies have been exhausted in all cases filed against Refinería de Cartagena and Ecopetrol S.A. On November 25 and December 5, 2025, Refinería de Cartagena filed two (2) lawsuits for annulment and restoration of rights before the Administrative Court of Bolívar and is within the legal timeframe to file the remaining four (4) lawsuits. Ecopetrol S.A. filed its two lawsuits against the official tax assessments and their confirmatory resolutions on March 2 and April 8, 2026, before the Administrative Court of Cundinamarca.
Refinería de Cartagena S.A.S. and Ecopetrol S.A., acting in accordance with due diligence and to protect their legitimate interests, have responded to DIAN’s actions within the timeframes established by law, challenging the decisions issued by the DIAN and questioning its interpretation of the regulations. In its interpretation, DIAN may continue with the collection process in accordance with the procedural rules of the customs regime and the Tax Statute, which include enforcement collection procedures, without prejudice to Refinería de Cartagena S.A.S. and Ecopterol S.A. exercising the appropriate administrative or judicial remedies, in accordance with the same regulations. Although Refinería de Cartagena S.A.S. and Ecoptrol S.A. plan to exercise these remedies, any eventual enforcement of collection could have a material adverse effect on the operations, liquidity, and financial position of Refinería de Cartagena S.A.S. and Ecopterol S.A., depending on the amount involved and the duration of the process. Likewise, based on the opinions issued by our external advisors, who consider the probability of success to be greater than 50%, the Company believes there are grounds for not recording any accounting provision.
F-88
Given that DIAN has decided to apply its regulatory interpretation, since January 2025 Ecopetrol S.A. and Refinería de Cartagena S.A.S. have been making VAT payments on gasoline and diesel fuel imports, in accordance with the DIAN’s interpretation, at a rate of 19%. The payment of VAT does not affect the rights that Ecopetrol S.A. and Refinería de Cartagena S.A.S. reserve to challenge this interpretation legally at the appropriate time before the relevant authorities, as mentioned above.
According to Grupo Ecopetrol, the total value of VAT payments related to gasoline and diesel imports for 2025 amounted to COP $4.2 trillion, of which approximately COP $3.9 trillion would be recovered through the VAT credit and refund process. For the first quarter of 2026, payments amount to COP $0.71 trillion.
Ecopetrol S.A. and Refinería de Cartagena S.A.S. reiterate their commitment to fully comply with their customs and tax obligations and will respect the decisions rendered regarding this dispute by the relevant authorities.
Below are the most recent changes related to contingencies associated with the operations of Refinery de Cartagena S.A.S.
Arbitration tribunal:
On March 8, 2016, Refinería de Cartagena S.A.S filed a request for arbitration with the International Chamber of Commerce (the “ICC”) against Chicago Bridge & Iron Company NV, CB&I UK Limited and CBI Colombiana SA (jointly, “CB&I”), concerning a dispute related to the engineering, procurement, and construction agreements entered into by and between Refinería de Cartagena S.A.S and CB&I for the expansion of the Refinería de Cartagena S.A.S, Colombia. Refinería de Cartagena S.A.S was the Claimant in the ICC arbitration and seeked no less than USD $2 billion in damages plus lost profits.
On May 25, 2016, CB&I filed its response to the Request for Arbitration and the preliminary version of its counterclaim against Reficar, for approximately USD $213 million. On June 27, 2016, Reficar filed its reply to CB&I’s counterclaim denying and disputing the declarations and relief requested by CB&I.
On April 28, 2017, Refinería de Cartagena S.A.S filed its non-detailed claim, and, on the same date, CB&I submitted its Statement of Counterclaim increasing its claims to approximately USD $116 million and COP $387,558 million, including USD $70 million for a letter of credit compliance. On March 16, 2018, CB&I submitted its Exhaustive Statement of Counterclaim further increasing its claims to approximately USD $129 million and COP $432,303 million (including in each case interest) and filed its Exhaustive Statement of Defense to Refinería de Cartagena’s claims. On this same date, Reficar filed its Exhaustive Statement of Claim seeking, among others, USD $139 million for provisionally paid invoices under the Memorandum of Agreement (“MOA”) and Project Invoicing Procedure (“PIP”) Agreements and the EPC Contract.
On June 28, 2019, Chicago Bridge & Iron NV Company filed a response to Refinería de Cartagena’s non-detailed defense of the counterclaim, updating the value of its claim to approximately USD $137 million and COP $503,241 million, including interest. Likewise, CB&I presented its detailed defense to Refinería de Cartagena’s claim.
On this same date, Reficar filed its response to CB&I’s Non-Exhaustive Statement of Defense and its Exhaustive Statement of Defense to CB&I’s counterclaim, updating its claim for provisionally paid invoices under the MOA and PIP Agreements and the EPC Contract to approximately USD $137 million.
In January 2020, McDermott International Inc. (now McDemott International Ltd and hereinafter “McDermott”) – CB&I parent company – commenced a bankruptcy case under title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. Faced with this situation, Refinería de Cartagena S.A.S took actions to protect its interests and had a group of experts with whom it will continue to evaluate other measures it may adopt in this new circumstance.
As a consequence of the initiation of the reorganization process, the arbitration was suspended until July 1, 2020, as described below.
F-89
On January 21, 2020, Comet II BV, the successor in interest to Chicago Bridge & Iron Company N.V., commenced a bankruptcy proceeding under title 11 of the Bankruptcy Code of the United States before the Bankruptcy Court for the Southern District of Texas. Before the beginning of the insolvency process of Comet II BV, an automatic suspension of the initiation or continuation of any action, process or execution of judgment or award against Comet II BV became effective, which suspended the arbitration.
On March 14, 2020, the Bankruptcy Court entered an order confirming a plan of reorganization, and the order provided for the stay against the arbitration to end upon the earlier of the effective date of the plan or August 30, 2020, whichever would occur first. On June 30, 2020, McDermott notified the occurrence of the effective date of the reorganization plan, thus the suspension of arbitration was lifted on July 1, 2020.
On May 6, 2020, the Superintendence of Companies of Colombia ordered the judicial liquidation of CBI Colombiana S.A., one of the defendants in the CB&I arbitration. On October 22, 2020, Reficar requested its recognition as a creditor of CBI Colombiana S.A., up to the maximum amount of its claims in the arbitration. On January 15, 2021, the liquidator of CBI Colombiana S.A. accepted Reficar’s request.
On September 22, 2020, the tribunal scheduled the start of the hearings for May 2021.
Between May 17 and June 16, 2021, the first two blocks of the hearing were held, in which the evidence in the arbitration against CB&I was presented. On June 16, 2021, the tribunal ordered the submission of post-hearing briefs on October 15 and November 5, 2021. Likewise, the tribunal summoned the parties to a hearing on closing arguments for November 18, and 19, 2021.
On August 16, 2021, the parties requested the tribunal to modify the procedural calendar, consisting of slightly altering the dates of presentation of the post-hearing briefs. On August 26, 2021, the tribunal granted the request of the parties, so the post-hearing briefs were presented on October 22 and November 10, 2021, respectively. The closing arguments hearing was held in a single session on November 18, 2021, and the session scheduled for November 19, 2021, was cancelled.
Subsequently, on December 20, 2021, Refinería de Cartagena S.A.S. presented its memorial for costs in arbitration against CB&I. On February 11, 2022, CB&I presented its memorial for costs.
On June 7, 2023, Refinería de Cartagena S.A.S. was notified of the decision of the International Arbitration Court that resolved the claim filed against. The Arbitration Court ordered CB&I to pay approximately $1,000 USD million plus interest in favor of Refinería de Cartagena. Similarly, the arbitral tribunal dismissed CB&I’s claims for approximately to USD $400 million. Chicago Bridge & Iron Company N.V. and CB&I UK Limited requested the annulment of the award on June 8, 2023, the before Southern District Court of New York.
On August 4, 2023, Refinería de Cartagena answered to the annulment request and, in addition, and likewise requested the confirmation of the award Moreover, On January 10, 2025, the Southern District Court of New York confirmed the Arbitration Award and denied the request for annulment filed by Chicago Bridge & Iron Company N.V. and CB&I UK Limited.
On September 8, 2023, McDermott reported that it will initiate financial restructuring procedures for its subsidiaries in the United Kingdom and the Netherlands, CB&I UK Limited and Chicago Bridge & Iron Company N.V. respectively, considering the arbitral issued award against them and in favor of Refinería de Cartagena S.A.S. The Company advised by a global team of lawyers and experts, became an active part of the business reorganization processes in said countries to defend its own interests.
Subsequently, on October 10, 2023, CB&I UK Limited and Chicago Bridge & Iron Company N.V. requested before the Texas Bankruptcy Judge the initiation of a procedure for recognition of financial restructuring processes abroad, known as Chapter 15 of the Bankruptcy Code of the United States of America. Specifically, they requested recognition of the financial restructuring processes that were announced by McDermott on September 8, 2023.
F-90
Based on the above, the process of annulment and recognition of the Arbitration Award - which determines the possibility of executing it and therefore collecting the decreed sums – was temporarily suspended by order of the Bankruptcy Judge. In this regard, it should be noted that the judge only issued an order suspending proceedings in the United States of America and which intended to execute assets of CB&I UK Limited and Chicago Bridge & Iron Company N.V. located in the United States. go against the assets of the Convicted parties.
On February 27, 2024, Refinería de Cartagena S.A.S. was notified of the decision of the United Kingdom Court in which it was determined that the financial restructuring plan of CB&I UK Limited was approved by said court.
Regarding the reorganization process initiated by Chicago Bridge & Iron Company (now McDermott Holdings N.V.) in the Netherlands on September 8, 2023. On February 16, 2024, an independent restructuring expert appointed by the Court submitted to a vote an alternative reorganization plan under which Refinería de Cartagena S.A.S. would receive, among others, an equity stake in the McDermott. On March 21, 2024, Cartagena Refinery was notified of the decision of the Netherlands Court approving the alternative financial restructuring plan of Chicago Bridge & Iron Company N.V.
Given the sanction of the plan, Refinería de Cartagena S.A.S was the beneficiary of (i) USD $70 million and USD $95 million arranged under two different letters of credit and (ii) USD $9 million corresponding to reimbursement of legal fees. Likewise, by court order of the Amsterdam District Court dated March 21, 2024, arising from a judicial restructuring process before said jurisdiction, 75,000 redeemable Series B non-voting preferred shares (the “Series B Preferred Shares”) of McDermott were issued in favor of Refinería de Cartagena S.A.S.
The Series B Preferred Shares have priority over the common shares and are on equal terms with respect to dividends and payments in the event of liquidation with the Series A Preferred Shares. They are entitled to cumulative quarterly dividends.
The holder of the Series B Preferred Shares may also require that all of the Series B Preferred Shares be converted at any time on or after June 30, 2028, into common shares representing up to 19.9% of the Company’s ownership interest, subject to adjustments pursuant to certain anti-dilution provisions.
The Series B Preferred Shares are subject to mandatory redemption requirements in the event of liquidation or change of control of the Company and other similar events.
As of September 30, 2024, Refinería de Cartagena S.A.S performed the valuation of McDermott’s shares considering an income approach, projecting discounted cash flows at present value and aspects such as risk premiums, information available from McDermott, the absence of significant influence and control by Refinería de Cartagena S.A.S and restructuring scenarios over time. As a result of the fair value valuation, the accounting record was made as a financial instrument for USD $234.5 million (COP $915,003 million), which represented for Refinería de Cartagena S.A.S an increase in the financial assets account compared to a lower value of the property, plant, and equipment.
Ecopetrol S.A. continuously monitors the operations of McDermott International Ltd. to identify and measure any potential changes in the fair value of the investment and/or risk premiums associated with the valuation model.
On December 9, 2024, McDermott announced that it has completed the sale of its storage business (CB&I’s tank business) to a consortium of financial investors led by Mason Capital Management. Under the terms of the agreement announced on October 7, 2024, McDermott received USD $475 million in proceeds before taxes and transaction expenses. Pursuant to the terms of McDermott’s credit agreement, the proceeds from the sale will be used to repay CB&I’s existing tank business term loan, cash guarantee certain McDermott letters of credit and reduce an existing McDermott term loan.
Investigations of control entities – Refinería de Cartagena S.A.S.
Refinería de Cartagena S.A.S is a wholly owned subsidiary of Ecopetrol, and since Ecopetrol is majority owned by the Government of Colombia, both companies manage public resources. In this context and in accordance with Colombian regulations, the employees of Ecopetrol and Refinería de Cartagena S.A.S are considered public servants and, as such, may be held responsible for the negligent use or management of public resources.
F-91
Consequently, the employees of Ecopetrol and Refinería de Cartagena S.A.S, in general, are subject to the control and supervision of the control entities.
Currently, derived from the Expansion and Modernization Project of the Refinería de Cartagena S.A.S (hereinafter, the “Project”), the processes described below are underway:
1.Office of the Comptroller General (Contraloría General de la República – CGR):
-PRF-80011-2018-33300
Through Order No. 1328 of August 24th, 2021, the CGR closed the preliminary investigation UCC-IP-005-2019 and opened a new fiscal responsibility process. In this, eight former officials of Refinería de Cartagena S.A.S (three former presidents and five former financial vice-presidents) are investigated.
In this process, 8 former officials of the Refinería de Cartagena S.A.S. are being investigated (3 former presidents and 5 former financial vice presidents).
The CGR made a special visit to the refinery facilities between February 20 and 24, 2023, which focused on two main points related to: (i) unidentified expenses, for $22 MUSD from the periods 2015 to 2018 and, (ii) $269 MUSD that, according to the CGR, entered the Project, and its use could not be identified.
On March 1, 2023, through Auto No. 0335, the CGR decreed the preparation of a technical report by the CGR team that participated in the visit.
On April 14, 2023, the officials assigned by the CGR presented the technical report in which, based on the information provided and the explanations provided by the Refinería de Cartagena S.A.S, it was concluded that in all records the destination of the associated expense was identified to each of the third parties.
On April 19, 2023, by Order No. 0665, it was ordered to incorporate the technical report into the process and make it available to the procedural subjects. It is expected that, based on the conclusions of the report, the CGR will make the decision to charge or archive the process.
On October 2, 2024, by means of Order No. 1762, the ordinary fiscal responsibility process was ordered to be archived, considering that the facts investigated did not constitute damage to public property.
Procedurally, the file had to be sent, within 3 business days following notification by status, to the Fiscal and Sanctioning Chamber of the CGR, in consultation status.
On October 31, 2024, by Order ORD-801119-257-2024, the Decision Chamber of the Fiscal and Sanctioning Chamber of the CGR ordered the total archiving of the proceedings carried out related to this process, confirming, in consultation status, Order No. 1762 of October 2, 2024, issued by the Intersectoral Delegate Comptroller’s Office No. 15 of the Special Investigations Unit Against Corruption of the CGR.
2.Prosecutor’s Office (Fiscalía General de la Nación - FGN)
Proceeding 1 – 110016000101201600023 - MOA - PIP and EPC
This process is being carried out against some ex-members of the Board of Directors and ex-employees of Refinería de Cartagena S.A.S, workers of the Chicago Bridge and Iron Company (CB&I) and the Statutory Auditor of Refinería de Cartagena S.A.S between 2013 and 2015, for crimes of undue interest in the execution of contracts, embezzlement by appropriation in favor of third parties, illicit enrichment of individuals in favor of third parties and ideological falsehood in a public document.
F-92
The pretrial hearing concluded on February 2, 2024. To date, the oral trial hearings are still ongoing; the evidentiary phase has already concluded, and the presentation of closing arguments is scheduled for 2026.
As of December 31, 2025, there were no changes to the process.
Proceeding 2 - 110016000101201800132 Business line
This process is being carried out against ex-members of the Board of Directors and an ex-president of Refinería de Cartagena S.A.S, for the crimes of aggravated unfair administration, and obtaining a false public document.
The trial began on October 28, 2024, and hearings have been taking place since then.
Proceeding 3 – 110016000101201800134 – Subscription of contract PMC - Foster Wheeler
This case is being brought against two former employees of the Refinería de Cartagena S.A.S., who formerly served as president and acting president, for the crime of entering a contract without complying with legal requirements.
Following convictions in the first and second instances, an extraordinary appeal is currently pending before the Supreme Court of Justice.
On March 5, 2025, the Criminal Cassation Chamber of the Supreme Court of Justice declared the criminal action regarding the death of Orlando José Cabrales Martínez extinguished and, consequently, dismissed the proceedings against him for the crime of entering a contract without complying with legal requirements.
The case was returned to the court for the issuance of the corresponding decision regarding the appeal filed on behalf of Felipe Castilla Canales.
As of December 31, 2025, there were no changes in the process.
Proceeding 4 - 110016000000201702546 – Principle of opportunity
This proceeding has been initiated against a former employee of Refinería de Cartagena S.A.S. on charges related to crimes against the public administration and improper influence in the execution of contracts.
On November 21, 2025, Resolution No. 00561 established a one-year term for the extension of the suspension of criminal proceedings, effective from the date on which the supervisory judge formalizes the application of the principle of opportunity.
F-93
23.5Details of contingent liabilities
The following is a summary of the main contingent liabilities that have not been recognized in the consolidated statement of financial position as, according to the evaluations made by internal and external advisors of the Ecopetrol Group, the expectation of loss is not probable as of December 31:
Number of
Amounts
Type of process
processes
involved
Labor
667
Ordinary administrative
2,437
2,980
Constitutional
644
Civil
Penal
Arbitration
771
3,248
3,812
23.6Details of contingent assets
The following is a breakdown of the Ecopetrol Group’s principal contingent assets, where the associated contingent gain is likely, but not virtually certain:
583
526
1,847
1,075
1,119
1,319
1,409
1,115
3,730
24.Equity
Subscribed and paid–in capital
Ecopetrol S.A.’s authorized capital amounts to $36,540, and is comprised of 60,000,000,000 ordinary shares, of which 41,116,694,690 are outstanding and 18,883,305,310 are treasury shares. Of all outstanding shares, 11.51% (4,731,906,273 shares) are held privately and 88.49% (36,384,788,417 shares) held by the Colombian Government. The treasury shares amounts to $11,500 comprised of 18,883,305,310 shares. As of December 31, 2025 and 2024, subscribed and paid in capital amounts to COP$25,040 and there were no potentially dilutive financial instruments outstanding during the fiscal years ended December 31, 2025, 2024 and 2023.
24.2Additional paid–in capital
As of December 31, 2025 and 2024, additional paid in capital mainly corresponds to: (i) share premium from the Ecopetrol Group’s capitalization in 2007, for $4,458, (ii) share premium from the sale of shares awarded in the second capitalization, which took place in September 2011, of $2,118, iii) a $32 share premium from the placement of shares on the secondary market, arising from the calling of guarantees from debtors in arrears, according to the provisions of Article 397 of the Code of Commerce, and (iv) additional paid in capital receivables for ($143) Colombian pesos.
24.3Equity reserves
The following is the composition of the Ecopetrol Group’s reserves as of December 31, 2025, and 2024:
Legal reserve
13,148
11,654
Other reserves(1)
The movement of equity reserves is the following for the years ended December 31, 2025, and 2024:
Allocation to reserves
18,638
14,408
24.4Retained results and dividends
The Ecopetrol Group distributes dividends based on its financial statements prepared under International Financial Reporting Standards accepted in Colombia (NCIF, as its acronym in Spanish).
The shareholders, in an Ordinary General Meeting of Shareholders held on March 28, 2025, approved the distribution of profits for the 2024 fiscal year and payment of ordinary dividends of $8,799 (2024: $12,829). The dividend paid on the shares corresponds to $214 COP (2024: $312 COP).
The shareholders approved the payment of dividends to minority shareholders in two equal installments on April 4 and April 29, 2025. On the other hand, the shareholders approved the payment of dividends to the majority shareholder in three installments, which were made on the following dates: i) April 4, 2025 for $2,200, ii) April 29, 2025 for $2,300 and iii) June 27, 2025 for $3,286.
Dividends were paid as follows:
8,784
12,804
2,747
Interconexión Eléctrica S.A. ESP
1,426
1,507
Oleoducto Central S.A. - Ocensa
833
809
Oleoducto de los Llanos Orientales S.A. - ODL
Oleoducto de Colombia S.A. - ODC
11,717
15,565
5,571
F-95
24.5Accumulated other comprehensive income attributable to owners of parent
The following is the composition of the accumulated other comprehensive income attributable to the shareholders of the parent, Ecopetrol S.A., net of tax:
Accumulated foreign currency translation
13,301
22,662
15,055
(2,752)
(6,396)
(3,165)
Accumulated actuarial gain on defined benefit plans
(2,691)
(3,942)
Cash flow hedges for future exports
1,248
(1,578)
602
24.6Earnings per share
Profit attributable to Ecopetrol’s ordinary shareholders
Weighted average number of outstanding ordinary shares
Basic and diluted ordinary shares earnings per share (Colombian pesos)
COP $
F-96
25.Revenue from contracts with customers
National sales
Mid–distillates (1)
26,792
28,672
32,606
Gasoline and turbo fuels (1)
16,044
17,804
23,129
3,439
Services
3,301
3,877
3,233
Energy transmission services (2)
3,266
3,226
2,770
Fuel gas service
1,363
Asphalts
794
938
Plastic and rubber
872
920
1,225
LPG and propane
631
762
Roads and construction services (2)
368
Polyethylene
304
329
314
Aromatics
298
Fuel oil
Crude oil
Other products
682
626
608
58,038
62,656
71,744
Foreign sales
40,324
48,805
49,560
6,402
5,465
4,761
5,269
6,134
5,667
3,491
3,920
1,229
1,231
1,394
696
4,097
501
302
Cash flow hedges (3)
412
(345)
(468)
Gasoline and turbo fuels
360
3,160
3,508
61,656
70,674
71,445
Sales by geographic areas
48.5
47.0
71,745
50.1
27,379
22.9
27,094
20.3
24,992
17.5
China
7,708
8,387
13,944
9.7
6,977
5.8
6,919
5,444
India
6,025
8,900
6,377
Singapore and other Asian countries
5,925
7,009
8,520
2,359
2,330
1.7
2,864
2,208
1.8
2,396
2,322
Other South America countries
4,564
1,594
Central America and the Caribbean
691
2,637
Europe
2,663
2,750
1.9
100.0
Concentration of customers
During 2025, Organización Terpel S.A. represented 11% of sales for the year (2024 – 11% and 2023 – 8%); no other customer represented more than 10% of total sales. There is no risk of the Ecopetrol Group’s financial situation being affected by a potential loss of Organization Terpel S.A. as a client, which is located in Colombia. The commercial relationship with Organization Terpel S.A. is for the sale of refined products and transportation services.
Revenues from concession contracts
ISA, through its companies, promotes development in several countries through concessions acquired for the supplying of public energy transport services, services associated with the management of real time systems in Colombia and public road transport, through concessionaires in Chile, Panama and Colombia.
The ISA concessions contain the obligation to carry out major works and at the end of the concession to deliver the infrastructure assets to the grantors in optimal conditions. These major maintenance works are accounted for i) when the works are executed and ii) when the value of the outflow of resources is known.
The current contracts signed by the ISA, except the contracts from Peru and Bolivia, have guaranteed cash flows.
ISA meets its obligations under the concession contracts and provides the contracted services with the use of infrastructure assets determined in each concession contract. Upon the expiration of each concession, ISA can present a bid for its renewal.
The main concessions are the following:
Concessions in Colombia
Inteia S.A.S (before Sistemas Inteligentes en Red)
Through a business collaboration agreement entered into with UNE EPM Telecomunicaciones S.A. and Consorcio ITS, executes the addendum No. 5 of the Inter-administrative Agreement No. 5400000003 of 2006 with the Municipality of Medellín to “provide under the concession modality, the necessary technological infrastructure, the services for its modernization and optimization of the management of the administrative services of the Secretaría de Transporte y Tránsito of Medellín, through a complete solution of technology, information, communications and operation of the information and communications technology (ICT’s)”. As payment for such services, Intelligent Network Systems receives a portion of the penalty fees collected through the photodetection system within the municipality.
F-98
This contract is within the scope of IFRIC 12 under the intangible model, considering the following aspect:
The concession ended on December 31, 2025.
In accordance with Law 1508 of 2012 which regulates public-private partnerships, the National Infrastructure Agency (“ANI”), by means of Resolution No. 862 of July 2, 2014, awarded Public Tender No. VJ-VE-IP-LP-0011-2013 and, on September 10, 2014, executed Concession Contract No. 004 of 2014 with Concesion Costera Cartagena-Barranquilla, an indirect subsidiary of ISA. The contracted services consist of executing “the final studies and designs, environmental management, property, social management, construction, rehabilitation, improvement, operation, and maintenance of the corridor Cartagena-Barranquilla Project and Circunvalar de la Prosperidad”.
This concession is within the scope of IFRIC 12 under the financial asset model for investment in construction (construction services). As compensation, the concessionaire receives: revenues from commercial exploitation, including toll collections, and payments from ANI, to the extent applicable. If the concessionaire does not achieve the expected revenue from toll collection, the grantor (ANI) will pay the concessionaire a collection differential in years 8, 13 and 18. Such collection differential has been contractually defined as the present value of toll collections for any given reference month. This revenue arrangement represents an unconditional contractual right to receive a specific and determinable amount of cash or other financial assets for the construction services provided.
As of December 31, 2025, the concession contract is in the operation and maintenance stage of all six functional units that comprise the project.
In addition to the concession contract, Unit Price Fixing Acts have been signed with the ANI, for the development of the following projects on the road:
Concessions in Brazil
As concessionaires for power transmission services in Brazil, the Company has the obligation to build and operate the transmission infrastructure, while the grantor retains ownership rights to the concession assets. Upon expiration of the concession, concession assets are to be transferred back to the grantor who must pay any pending compensation to the concessionaire.
The concession contracts of ISA Energía Brasil and Taesa were analyzed and classified in the financial asset model. In accordance with IFRS 15 - Revenue from contracts with customers, a contract asset is recognized during construction.
The value of the contractual asset of the energy transmission concessions is equal to the present value of future cash flows, which are determined at the beginning of any given concession or renewal. Such future cash flows are revaluated periodically, in previously determined tariff review years.
F-99
Cash flows are defined based on payments received by concessionaires for supplying power transmission services to end-users. Such payments are known as Receita Anual Permitida or “RAP” and serve to compensate the cost of investments made in the transmission infrastructure. Any investment costs that are not fully compensated through the receipt of RAPs trigger the right to receive payment from the grantor. This flow of future collections is updated for inflation (IPCA/IGPM) and paid at a discount rate at the beginning of each project.
During the construction stage, the concessionaire has the right to receive consideration in accordance with progress made on construction of the network and the performance of its obligations, and not only in accordance with the time used for construction. Revenue is equivalent to the value of construction expenses plus a construction margin, as a result of the application of the pronouncement of the CVM (Brazilian Securities and Exchange Commission) on the accounting treatment for contract assets (CVM Official Communication 4/2020), which is in consistent with the requirements of IFRS 15 – Revenue from Contacts with Clients to recognize revenue.
Revenues from these concession assets generate taxes under the Social Integration Program and the Contribution for the Financing of Social Security (Cofins) program. These may be registered as deferred taxes (non-current liabilities).
Concessions in Chile
For the construction of road infrastructure in Chile, the Group may be remunerated in one or two ways: variable revenues, which may account for traffic risk (the variation of projected demand) or fixed revenue, that is, a guaranteed total amount subject to a revenue distribution mechanism or calculated at the present value of future cash flows. In the latter case, the total revenue is guaranteed at present value. Additionally, in some concession contracts other concepts are included, such as the minimum guaranteed revenue and subsidies (both in construction and in operation stages); both correspond to payments from the State, subject to specific compliance of conditions by the concessionaire.
The model applied to concessions in Chile will depend on whether revenue is guaranteed or not (whether it is subject to traffic risk or not) and whether it is enough to pay for the investment. On one hand, if the concession contract considers traffic risk, it is recognized according to IFRIC 12 as an intangible asset. This asset is amortized over the life of the concession operation. On the other hand, if the contract establishes income and compensation guarantee mechanisms, it is recognized as a financial asset. This financial asset is extinguished through payments received from road users, through the collection of tolls, or directly through payments from the Ministry of Public Works. Currently, ISA has road concessions in Chile applying the financial asset model.
Concessions in Panama
The road concession in Panama operates under a public-private partnership (PPP) model, as defined by Law 1 of January 5, 1984, amended by Law 21 of May 10, 2017, the PPP Law, and the PPP Regulations. This framework stems from the award of Public Tender No. 2024-0-09-0-99-AP-008446, issued by the Ministry of Public Works (MOP) through Resolution No. APP-001-2025 of January 10, 2025, whose objective is the “Rehabilitation, improvement, and maintenance of the Pan-American Road East to meet performance standards.”
This PPP contract for the Pan-American Road East is a service concession agreement, in which the grantor controls or regulates the services provided by the concessionaire, to whom they are provided, and at what price.
Since the contract meets the above criteria and includes an obligation to return the assets to the grantor, or the grantor retains any residual interest in the infrastructure, at the end of the concession term, it is accounted for according to IFRIC 12 Service Concession Arrangements. This also includes operation and maintenance services. Assets constructed to operate concessions where the grantor has no residual interest in the infrastructure asset and Ruta del Este has no obligation to return those infrastructure assets are accounted for under IAS 16. Service revenues are measured and recorded in accordance with IFRS 15 and IFRS 9, depending on the asset model.
F-100
The project will cover 246.2 km and will be called the Pan-American Road East. It extends from the community of Las Garzas, in the district of Pacora, municipality of Panama, and ends in the municipality of Yaviza, in the province of Darién. Among the communities along this road are: Las Garzas, Tanara, Unión de Azuero, Chepo, Cañita, El Llano, the Guna indigenous territory of Madungandí, Ipetí, Tortí, Cañazas, Agua Fría, Santa Fe, Metetí, Sansón, Canglón, and Yaviza. The Pan-American Road East’s primary importance lies in its role as the main axis connecting the various centers of attraction that generate local and interprovincial travel, as well as facilitating communication for the operation of different institutions and organizations involved in the comprehensive management of these areas. The project is currently in the pre-construction phase.
Concessions in Peru
Due to their terms and conditions, as well as the rights and obligations of concessionaires, the concession contracts of ISA REP, ISA Perú, and Consorcio Transmantaro are recognized as intangible assets. The intangible asset model applies when the services provided by the concessionaire are paid by end-users or when the grantor does not unconditionally guarantee the collection of revenues. These contracts grant the concessionaire the right to charge end-users for the energy transmission service, but do not establish an unconditional right to receive cash.
In November 2020, through a corporate reorganization process (merger by absorption), ISA Perú acquired the companies Etenorte S.R.L. (220 KV Carhuaquero - SE Chiclayo Oeste lines and 138 KV Huallanca - SE Chimbote 1 and SE Chimbote 2 lines) and Eteselva S.R.L. (SE Aguaytia - SE Tingo María - SE Paramonga Nueva 220 lines), which have an unlimited useful life.
All the concession contracts for the supply of power transmission services in Peru contain similar terms and conditions.
Concessions in Bolivia
Similar to concession contracts in Peru, concessions to provide public energy services in Bolivia do not guarantee the unconditional receipt of cash by the concessionaire. In these concession contracts, we assume the risk associated with the collection of amounts invoiced and may not be able to recover the entire value of the investment made. Additionally, the Bolivian State is not obliged to guarantee shortages, either due to the non-existence of demand or due to non-payment by any of the market agents; therefore, the grantor has no obligation to pay for the construction services received and, in this sense, the model applicable under IFRIC 12 is the intangible asset model.
Committed investments
ISA and its companies have committed investments of $25.5 trillion pending execution in the 2026-2030 period. These investments correspond to the balance pending execution of contracts already awarded, and to estimated needs for reinforcement and expansion of existing infrastructure and replacement of assets. These investments represent a strategic commitment to expand and modernize infrastructure, improve operational efficiency, and promote the adoption of sustainable technologies, increasing cash flow generation and the value of ISA for its shareholders.
The committed investments pending of execution for 2026-2030 period are distributed as follows: Projects awarded $19.9 trillion in energy transmission (78%), $3.2 trillion in construction and improvement businesses roads (13%), $1.6 trillion in energy solutions development (6%) and $0.8 trillion in telecommunications business development (3%). It includes projects such as:
F-101
The value of committed investments pending execution may vary, among other things, due to adjustments in the scope of the projects, equipment and material prices, and variations in macroeconomic estimates, such as exchange rates and price indexes.
26.Cost of sales
Variable costs
Imported products (1)
18,637
20,528
24,204
Depreciation amortization and depletion
10,494
9,780
8,126
Purchases of crude
9,189
12,435
13,390
Purchases of hydrocarbons - ANH (2)
6,638
8,232
8,519
Electric energy
2,361
2,294
Process materials
1,559
1,564
Hydrocarbon transport services
1,846
1,729
1,587
Purchases of other products and natural gas
1,478
1,201
Gas royalties in cash
874
995
1,293
Contracted services in associations
319
338
284
Taxes and contributions
289
419
Others (3)
796
823
1,152
54,865
60,324
64,033
Fixed costs
Maintenance
5,235
4,643
5,031
4,866
5,079
Labor costs
4,442
4,299
3,976
Construction cost
4,239
3,585
2,600
Services contracted
3,748
3,764
3,523
1,456
1,171
1,123
1,169
1,468
Materials and operating supplies
885
881
General costs
648
603
27,192
26,157
24,145
Imported products correspond mainly to mid-distillates, gasolines and thinner. The decrease occurred due to lower requirements due to greater operations in Barrancabermeja Refinery.
It corresponds to purchases of crude oil by the Ecopetrol Group from the National Hydrocarbons Agency derived from national production.
It includes i) the result of the process of valuation of inventories of crude oil and refining products, ii) measurement at net realizable value, and iii) other capitalizable charges to projects.
27.Administrative, operative, and project expenses
Labor expenses
2,248
2,029
General expenses
2,097
2,403
2,379
535
Taxes other than taxes on income
5,024
5,103
5,026
Commissions fees freights and services
1,433
1,685
1,683
819
839
Exploration costs (1)
952
1,770
2,089
393
Fee for regulatory entities
721
5,321
5,648
5,702
28.Other operating income (expenses)
Expense for legal provisions
(459)
(686)
(Loss) gain on sale of assets
Impairment loss of current assets (1)
(346)
(262)
Profit in business combinations and field reversal (2)
1,727
It corresponds mainly to the impairment of 99% of the receivables of the client AIR-E S.A.S. E.S.P. in the companies ISA, Intercolombia, and Transelca; the intervention process of the client is the main indicator to determine that there is a high credit risk.
Includes the profit from: a) the acquisition of Repsol’s 45% of Block CPO-09 by Ecopetrol S.A. and the revaluation at fair value of the pre-existing 55% ($1,698,862), and b) the reversion of the San Jacinto field ($28).
29.Financial result
Yields and interests
Financial assets measured at fair value
504
Gain on remeasurement of derivatives
Other financial income
Interest (1)
(7,604)
(7,377)
(6,924)
Financial cost of other liabilities (2)
(2,556)
(2,466)
(2,197)
(294)
(246)
Other financial expenses
(327)
(445)
(1,017)
Gain (loss) from exchange difference
As of December 31, 2025, interests on natural and environmental resources and property, plant, and equipment were capitalized for $895 (2024 $810).
Includes the financial expense for the update of the liability for cost of retirement obligation and the net interest on post-employment benefits and other long-term employee benefits.
30.Risk management
30.1Exchange rate risk
The Ecopetrol Group operates mainly in Colombia and makes sales in the local and international markets, for that reason, it is exposed to exchange rate risk.
As of December 31, 2025, the Colombian peso appreciated by 14.79%, rising from a closing rate of $4,409.15 on December 31, 2024, to $3,757.08 pesos per dollar. When the Colombian peso appreciates, export revenues, when converted to pesos, decrease, and imports and foreign debt service become less expensive.
The balance of financial assets and liabilities denominated in foreign currency for the years ended December 31 is presented in the following table:
(in USD$Million)
544
777
Trade receivables and payables, net
432
(18,702)
(18,320)
Other assets and liabilities, net
(483)
Net liability position
(17,432)
(17,313)
Of the total net position, USD$(16,813) million correspond to net liabilities of companies with Colombian peso functional currency, of which USD$(17,348) million correspond to loans used as hedging instruments whose valuation is recognized in other comprehensive income, the exchange difference valuation of the remaining net assets for USD$535 million affects the statement of profit and loss. Likewise, USD$(619) million of the net position correspond to monetary assets and liabilities of Business Group companies with a functional currency other than the Colombian peso, whose valuation is recognized in the profit or loss statement.
30.2
Sensitivity analysis for exchange rate risk
The following is the effect of a change of 8% and 15% in the exchange rate of the Colombian peso as compared with the U.S. dollar, on the balance of financial assets and liabilities denominated in foreign currency as of December 31, 2025:
Scenario / Variation in
Effect on income
Effect in other
the exchange rates
before taxes +/–
comprehensive income +/–
8%
(5,214)
15%
(47)
(9,777)
30.3Cash flow hedge for future exports
To express in the consolidated financial statements, the effect of the existing natural hedge between exports and indebtedness, understanding that the exchange rate risk materializes when exports are made, On September 30, 2015, the Board of Directors made the first designation of Ecopetrol’s debt as a hedging instrument for its future income from crude oil exports.
Ecopetrol Group has designated part of its loans and borrowings (Note 20) denominated in US Dollars to hedge the exposure to future cashflows exports in USD. The following is the movement of this non-derivative hedging instrument designated in this hedge relationship:
(US$Million)
Hedging instrument at the beginning of the year
7,343
6,265
Reassignment of hedging instruments
1,316
1,200
Realization of exports
(1,316)
(1,207)
Designation of new hedge items
1,085
Hedging instrument at the end of the year
7,347
The following is the movement in accumulated other comprehensive income for the years ended December 31, 2025, 2024 and 2023:
(602)
2,474
(4,737)
3,898
(5,195)
Reclassification to profit or loss (Note 25)
(239)
Ineffectiveness reclassified to profit and loss
(14)
Deferred income tax (Note 10)
1,775
(1,472)
(1,248)
F-105
The expected reclassification of the cumulative exchange difference from other comprehensive income to the profit or loss is as follows:
Before taxes
After taxes
1,076
(418)
658
(73)
2030
2031
2032
2033
2,027
(779)
30.4Hedge of a net investment in a foreign operation
The Board of Directors approved the application of net investment hedge accounting from June 8, 2016. The measure is intended to reduce the volatility of non–operating income due to exchange rate variations. The net investment hedge will be applied on a portion of the Ecopetrol Group’s investments in foreign operations, in this case on investments in subsidiaries which have the U.S. dollar as their functional currency, using a portion of the Ecopetrol Group’s U.S. dollar denominated debt as the hedging instrument.
As of December 31, 2025, the total hedged balance is USD$10,001 million, which includes: i) Ecopetrol S.A. USD$9,671 million and ii) ISA Colombia for USD$330 million in net investment coverage on investments in the companies ISA REP, ISA Perú, Consorcio Transmantaro and Proyectos de Infraestructura del Perú.
The following is the movement in accumulated other comprehensive income attributable to owners of parent:
6,467
3,141
9,354
(6,642)
6,305
(8,973)
2,893
(2,979)
2,760
2,718
30.5Hedging with financial derivatives to mitigate exchange rate and interest rate risk
The ISA Group and Oleoducto Central S.A. have hedges with derivative financial instruments – CCS (Cross Currency Swaps) and nondelivery forward to hedge exchange rates. These hedges are recognized as cash flow hedges.
Derivative instrument
Intervial Chile (1)
Cross currency swap
ISA CTEP
As of December 2025, it corresponds to a cross-currency swap ISA Intervial, which belongs to the toll roads segment in Chile. This derivative contract was signed in May 2021 with Itaú Corpbanca, to exchange the flows of debt contracted in Chilean pesos to Unidades de Fomento (UF).
30.6Commodity price risk
The price risk of raw materials is associated with the Ecopetrol Group’s operations, both exports and imports of crude oil, natural gas, and refined products. To mitigate this risk, the Ecopetrol Group has implemented hedges to partially protect the results from price fluctuations, considering that part of the financial exposure under contracts for the purchase of crude oil and refined products depends on the international oil prices.
F-106
The risk of such exposure is partially hedged in a natural way, as an integrated Business Group (with operations in the exploration and production, transportation and logistics and refining segments) and carries out both crude exports at international market prices and sales of refined products at prices correlated with international prices.
The Ecopetrol Group has a policy for the execution of hedges and implemented processes, procedures, and controls for their management:
As of the date of this report, the Ecopetrol Group holds positions in: Brent $48 put options and TRM collars $33. These derivative transactions are accounted for under cash flow hedge accounting.
Credit risk
Credit risk is the risk that the Ecopetrol Group may suffer financial losses because of default of: (a) payments by its clients for the sale of crude oil, gas, products, or services; (b) financial institutions in which it keeps investments, or (c) by counterparties with which it has contracted financial instruments.
Credit risk related to customers
In the process of selling crude oil, natural gas, refined products, and petrochemicals, and in providing transportation, power transmission, infrastructure, and telecommunications services, the Ecopetrol Group may be exposed to credit risk, which corresponds to the expected loss resulting from a customer’s failure to meet its payment obligations. The Group has implemented mechanisms and procedures designed to minimize the likelihood of such risks materializing, thereby safeguarding the Ecopetrol Group’s cash flow.
The Ecopetrol Group performs a continuous analysis of the financial strength of its counterparties under a simplified model (Note 4.1), by classifying them according to their risk level and financial guarantees in the event of a default of payments. Similarly, the Group continuously monitors national and international market conditions for early alerts of major changes that may have an impact on the timely payment of obligations from customers.
The Ecopetrol Group performs administrative and legal actions required to recover amounts past due and charges interest from customers that fail to comply with payment policies.
An aging analysis of the accounts receivable portfolio in arrears, but not impaired, as of December 31, 2025, and 2024 is as follows:
Less than 3 months overdue
Between 3 and 6 months overdue
More than 6 months overdue
307
F-107
Credit risk in financial assets
Following the promulgation of Decree 1525 of 2008, which provides general rules on investments for public entities, Ecopetrol’s management established guidelines for its investment portfolios. These guidelines determine that investments in Ecopetrol’s U.S. dollar portfolios are generally limited to investments of cash excess in fixed–income securities issued by entities rated A or higher in the long term and A1/P1/F1 or higher in the short term (international scale) by Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings.
In addition, the Ecopetrol Group may also invest in securities issued or guaranteed by the United States of America or Colombia governments, without regard to the ratings assigned to such securities. In Ecopetrol Group’s Colombian Peso portfolio, it must invest the cash excess in fixed–income securities of issuers rated AAA in the long term, and F1+/BRC1+ in the short term (local scale) by Fitch Ratings Colombia or BRC Standard & Poor’s. Likewise, the Ecopetrol Group may also invest in securities issued or guaranteed by the National Government of Colombia without qualification restrictions.
To diversify the risk in the Colombian Peso portfolio, the Ecopetrol Group does not invest more than 10% of the cash excess in one specific issuer. In the case of the U.S. dollar portfolio, the Ecopetrol Group does not invest more than 5% of the cash excess in one specific issuer in the short term (up to one year), or 1% in the long term.
The credit rating of issuers and counterparties in transactions involving financial instruments is disclosed in Note 6 – Cash and cash equivalents, Note 9 – Other financial assets, and Note 22.2 – Plan assets.
30.8
Interest rate risk
Interest rate risk arises from Ecopetrol’s exposure to changes in interest rates because the Ecopetrol Group has investments in fixed and floating–rate instruments and has issued floating rate debt linked to SOFT, DTF, and CPI interest rates. Thus, interest rate volatility may affect the fair value and cash flows of the Group’s investments and the financial expense of floating rate loans and financing.
As of December 31, 2025, 31.11% (2024, 28.91% and 2023, 31.02%) of the Ecopetrol Group’s indebtedness is linked to floating interest rates. As a result, if market interest rates rise, financing expenses will increase, which could have an adverse effect on the results of operations.
The Ecopetrol Group controls the exposure to interest rate risk by establishing limits to the portfolio duration, Value at Risk – VAR and tracking error.
Autonomous equities linked to the Ecopetrol Group’s pension obligations are also exposed to changes in interest rate, as they include fixed and floating rate instruments that are recognized according to the market. Colombian regulation for pension funds, as stipulated in the Decree 941 of 2002 and Decree 1861 of 2012, indicates that they must follow the same regime as the regular obligatory pension funds in their moderate portfolio.
The following table provides information about the sensitivity of the Ecopetrol Group’s results and other comprehensive income for the next 12 months to variations in interest rate of 100 basis points:
Effect on Other
Effect on profit or loss (+/–)
Comprehensive Income (+/–)
Financial
Assets *
Plan Assets
+100 basis points
(1,073)
–100 basis points
1,074
(*)
This sensitivity was executed for portfolios of Ecopetrol S.A. and Black Gold Re. These are the most relevant of the Ecopetrol Group.
A sensitivity analysis of discount rates on pension plan assets and liabilities is disclosed in Note 22 – Provisions for employees’ benefits.
F-108
30.9Liquidity risk
The ability to access credit and capital markets to obtain resources for the investment plan execution for the Ecopetrol Group may be limited due to adverse changes in market conditions. A global financial crisis could worsen risk perception in emerging markets.
Events that could affect the political and regional environment of Colombia may make it difficult for our subsidiaries to access the capital markets. These conditions, together with potential significant losses in the financial services sector and changes in credit risk assessments, may make it difficult to obtain resources on favorable terms. As a result, the Ecopetrol Group may be forced to review the conditions of the investment plan, or access financial markets under unfavorable terms, thereby negatively affecting the Ecopetrol Group’s results of operations and financial results.
Liquidity risk is managed in accordance with the Ecopetrol Group’s policies aimed at ensuring that enough cash flows to comply with the Ecopetrol Group’s financial commitments within the established dates and with no additional costs. The main method for the measurement and monitoring of liquidity is cash flow forecasting.
The following is a summary of the maturity of financial liabilities as of December 31, 2025. The amounts disclosed in the table are the contractual undiscounted cash flows. The payments in foreign currency were restated taking a constant exchange rate of COP$3,757.08 per U.S. dollar:
1–5 years
5–10 years
Loans (payment of principal and interest)
9,494
62,582
41,826
34,313
148,215
25,253
163,974
30.10Risk and opportunities related to climate (Unaudited)
The Group carries out two types of analysis for climate-related risks and opportunities. The first seeks to adapt the business strategy to the energy transition and the other focuses on climate scenarios to identify the level of risk.
●
Physical risks: They are related to the exposure and vulnerability of the Ecopetrol Group to the impacts of climate change and climate variability, which could affect operational continuity and increase the exposure of assets to possible damage and loss. Physical risks are classified as acute and chronic.
o
Acute risks are those caused by extreme weather events, the frequency and intensity of which have been increasing due to the gradual rise in global temperature. In Colombia, they are mainly reflected in the occurrence of the climate variability phenomenon “El Niño” and its opposite phase “La Niña”. These conditions could result in, among others, water shortages, heat waves, floods and fires.
Chronic risks, arising from a sustained medium- and long-term change in climate conditions, which for the Ecopetrol Group can be reflected in rising sea levels, thermal overload and droughts beyond 2050.
The physical risk analysis considered the following climate change scenarios from the Intergovernmental Panel on Climate Change (IPCC), with a horizon up to 2100, inclusive: (i) Aligned with the objective of the Paris Agreement (SSP / RCP 2.6), (ii) Peak emissions in 2040 (SSP2 / RCP4.5), and (iii) ‘Business as Usual’ (SSP5 / RCP8.5). Under these scenarios, seven (7) chronic (drought and thermal stress) and acute (precipitation, coastal and river flooding, fires and winds) threats were evaluated at 95 points associated with the main assets of the Ecopetrol Group. The results must provide an additional local-scale analysis, prioritizing the assets with the greatest exposure and vulnerability in the long term.
F-109
Transition risk: They are related to the challenges that the Ecopetrol Group has identified to transition towards a low-carbon, sustainable and competitive operation. The Ecopetrol Group carried out a prioritization of transition risks, identifying the following:
Regulatory risk, associated with regulatory changes that may directly affect the Ecopetrol Group in the short and medium term. Notable regulatory changes include the following: (i) new requirements for environmental license applications, license modifications, or minor changes to production and exploration, associated with the quantification of GHG emissions, mitigation actions, vulnerability and climate risk analysis, and adaptation actions, within the framework of the Comprehensive Corporate Climate Change Management Plan (PIGCCe), (ii) stricter regulatory requirements for the detection and repair of gas leaks, flaring, and venting, (iii) limitations on the use of offsets to meet decarbonization targets, (iv) new requirements for the validation and verification of reduction projects and their registration in the National Registry of GHG Emission Reductions (RENARE), (v) launch of the National Program for Tradable Emission Allowances (PNCTE), similar to an Emissions Trading System, in which emission allowances would be allocated. This program is currently in the design and development phase of its regulatory framework and is scheduled to begin in 2025 with full implementation by 2030.
Legal risk, associated with the negative reactions and lawsuits against the climate action of the Ecopetrol Group.
Risk of assets trapped in the traditional business of hydrocarbon production, transportation, and refining, considering factors such as fuel demand prospects and asset profit horizons.
Market risk, related to the change in preferences in the use of low-carbon products in the long term, which implies a risk for the Ecopetrol Group of not being able to meet market demand and of not advancing effectively in the development of these products.
Reputational risk, associated with the impossibility of responding in a timely way to the expectations and demands of investors and other interest groups to establish ambitious objectives regarding climate change, which would affect the image and brand of the Ecopetrol Group.
Technological risk, associated with the negative effects on the profitability of the business if there is no preparation and capacity to adapt to new technologies because of the transition process.
To manage the identified risks, the Ecopetrol Group defined as business risks: “Inadequate response to challenges associated with climate change, water, and biodiversity,” which relates to the company’s exposure to negative impacts due to its limited capacity to respond in a timely, efficient, and effective manner to commitments, obligations, and expectations regarding climate change, water, and biodiversity; and “Low-emission businesses that do not generate the expected value in light of the energy transition,” which relates to the Ecopetrol Group’s exposure to negative impacts due to failures to deliver on the value proposition and meet the energy transition goals of the business lines that are part of the energy transition portfolio, related to: i) power transmission and infrastructure, ii) low-emission businesses, and iii) Gas and LPG supply.
These business risks include mitigation actions, Key Risk Indicators (KRIs), and controls to effectively manage the causes and mitigate the materialization of the risk.
As of December 31, 2025, no events related to the risks previously identified by the Ecopetrol Group materialized.
Ecopetrol has developed three energy transition scenarios designed to serve as a robust, unified framework that enables the Ecopetrol Group (GE) to anticipate and understand the challenges and opportunities of the energy transition:
F-110
The Ecopetrol Group considers it important to compare three possible scenarios. Although the first and third scenarios do not reflect the Group’s baseline vision, it is necessary to compare other possible perspectives on the global energy transition. Based on the strategic vision for 2040, the Ecopetrol Group considers the second scenario to be the most likely and aligned with situations in which the energy future will be led by a gradual energy transition, which involves the additional use of low-emission energy sources without eliminating the existence and use of conventional energy within the energy mix.
In this regard, climate-related opportunities stem from risk analysis, the review of energy transition scenarios, and alignment with corporate strategy. In the process of identifying and evaluating opportunities, the Ecopetrol Group monitors and assesses the energy market and the business environment. Opportunities have been identified related to the diversification of traditional business, diversification into sustainable businesses, energy efficiency, and renewable energy.
30.11Capital management
The main objective of the capital management of the Ecopetrol Group is to ensure a financial structure that optimizes the cost of capital, maximizes the rate of return to its shareholders and allows access to financial markets at a competitive cost to cover financial needs.
The following is the leverage ratio as of December 31:
Loans and borrowings (Note 20)
Cash and cash equivalents (Note 6)
(10,694)
(14,054)
Other financial assets (Note 9)
(3,296)
(5,240)
Net financial debt
95,210
100,671
Equity (Note 24)
Leverage (1)
47.15
48.73
F-111
31.Related parties
Balances with associates and joint ventures as of December 31, 2025 and 2024 are as follows:
Trade and
other receivables
Loans and
receivables
– Loans
payables
borrowings (1)
liabilities
Joint Ventures
Consorcio Eléctrico Yapay
547
(Note 7)
(Note 21)
(Note 20)
Loans:
Resource deposited by Equion in Ecopetrol Capital AG.
The main transactions with related parties are detailed as follows:
- Purchases
and others
Equion Energy Limited
567
516
559
628
591
31.1Directors and key management personnel
In accordance with the approval given by the shareholders on its meeting held in 2012, which was recorded in Minute No. 026, the directors’ fees for attending the meetings of the Board of Directors and / or the committees increase from four to six legal monthly minimum legal monthly salaries in force.
On the other hand, in the General Shareholders Meeting held in 2018, the amendment of the Corporate Bylaws that appears in Minute No. 036 was approved, by virtue of which, the fourth paragraph of article 23 was eliminated that made the differentiation between the fees for face-to-face and non-face-to-face meetings. The members of the Board of Directors do not have any kind of variable remuneration. The amount paid in 2025 for fees to members of the Board of Directors amounted to $4 (2024 - $6).
The total compensation paid to Executive Officers and Senior Managers as of December 31, 2025, amounted to $33 (2024 – $23). Executive Officers and Senior Managers are not eligible to receive pension and retirement benefits.
Germán González – Vice-president of Corporate Affairs is the only one of the key directors of management that owns shares of Ecopetrol S.A. As of December 31, 2025, none of the key directors of management, including Germán González, owned shares of Ecopetrol S.A., that exceeded 1% of the outstanding shares of the Company.
31.2Post–employment benefit plans
The administration and management of resources for payment of Ecopetrol’s pension obligations are managed by autonomous pension funds (PAPs, by its acronym in Spanish) which serve as guarantee and payment sources. In 2008, Ecopetrol S.A. received the authorization to partially commute the value corresponding to monthly payments, bonds, and quotas, transferring said obligations and the money that support them to autonomous patrimonies of a pension nature, in accordance with the requirements of Decree 1833 of 2016.
Since 2016, the entities that manage the resources were: Fiduciaria Bancolombia, Fiduciaria de Occidente, and Consorcio Ecopetrol PACC (formed by Fiduciaria La Previsora, Fiduciaria Bancoldex, Fiduagraria, and Fiduciaria Central). These fiduciaries managed the pension resources for a period of seven years (2016-2023) and as compensation they received a remuneration with fixed and variable components, the latter were settled on the gross returns of the portfolios and and a success fee for the manager with the best profitability and risk/return ratio.
Starting in 2022, and after a rigorous selection and asset allocation process, the new administrators of the Pension Liabilities until December 2028 are: BBVA Asset Management, Fiduciaria Bogotá and the Ecopetrol PACC 2021 Consortium made up of Fiduciaria La Previsora, Fiduciaria Bancoldex, Fiduagraria, and Fiduciaria Central.
F-113
31.3
Government related parties
The Colombian Government controls Ecopetrol S.A. with a stock ownership of 88.49%. The most significant transactions with governmental entities are comprised as follows:
(a) Purchase of oil from the National Hydrocarbons Agency – ANH
The ANH, an entity which operates under the rules of the Ministry of Mines and Energy, has as objective to manage the oil and gas reserves and resources owned by the Colombian Nation.
In accordance with the provisions of numeral 10 of Article 3 of Decree 714 of 2012, the National Hydrocarbons Agency (ANH, for its acronym in Spanish) has entered into a legal agreement with Ecopetrol S.A. for the purchase and sale of crude oil royalties generated by certain oil-producing fields in the country. These royalties are delivered in kind, and their prices are calculated according to a predetermined formula that reflects the sales prices, adjusted for API (American Petroleum Institute) gravity, sulfur content, and transportation costs to export ports or to the Barrancabermeja and/or Cartagena refineries. The Purchase and Sale Agreement between the ANH and Ecopetrol is in effect from July 1, 2023 to June 30, 2026.
For the period between January 2025 and December 2025, Ecopetrol Group purchased 31.32 million barrels of crude oil from the ANH corresponding to royalties and economic rights paid in kind by oil producers in Colombia.
The purchase value of oil and gas from ANH is detailed in Note 26 - Cost of sales.
(b) Refined Price Stabilization Fund
The sale prices of regular gasoline and diesel are regulated by the National Government. In that way, there are differentials between the volume reported by the companies at the time of sale and the difference between the parity price and the reference price, the parity price being the one that corresponds to the daily prices of motor gasoline and diesel observed during the month. This differential can be for or against the producers. The value of this differential is detailed in Note 25 - Revenue from contracts with customers and in Note 7 - Trade and other receivables.
(c) National Tax and Customs Direction
The Ecopetrol Group, just like any other company in Colombia, has tax obligations that it must comply with and does not have any other kind of association or commercial relationship with the National Tax and Customs Direction of Colombia.
(d) Comptroller General of the Republic
The Group, just like any other state entity in Colombia, is obliged to comply with the requirements set out by the Comptroller General of the Republic and make an annual payment to this entity on account of a maintenance fee. The Ecopetrol Group does not have any other kind of association or commercial relationship with this entity.
32.Joint operations
The Ecopetrol Group carries out exploration and production operations through Exploration and Production (E&P) Contracts, Technical Evaluation (TEA) Contracts and Agreements signed with the ANH, as well as through Partnership Contracts and other types of contracts.
Ecopetrol Group is into association contracts introduced by Decree 2310 of 1974, as amended, between private companies and Ecopetrol between 1975 and 2003. Through an association contract, Ecopetrol partners with a petroleum company or a consortium to explore and, upon successful discovery, exploit the found oil and gas resources. An operator is defined among them or hired as a third party.
On the other hand, Ecopetrol Group also entered in incremental production contracts to obtain additional hydrocarbon production beyond a base production curve that is established based on the proven reserves of a specific field or well, originating from contracts entered into by Ecopetrol with third parties or from projects undertaken by Ecopetrol. This incremental production results from new investments to increase the recovery factor of reservoirs or to add new reserves.
The main joint operations in 2025 are as follows:
32.1Contracts in which the Ecopetrol Group is not the operator
Geographic area of
Partners
Contract
Participation
operations
Chipirón
30%+Production Factor (1)
SierraCol Energy Arauca, LLC
Cosecha
30%
Cravo Norte
55%+High Prices of Oil
Rondón
65%
Frontera Energy Colombia Corp
40%+PAP
57%
Union Temporal Ismocol Joshi Parko
CPI Palagua
100% According amendment number 5
Colombia (Puerto Boyacá – Santander)
LLA-122
Parex Resources Colombia LTD
LLA-121
50%
Colombia (Piedemonte Central)
LLA-4-1
E&P COL 1
Anadarko Colombia Company (OXY)
E&P COL 2
40%
Offshore North Caribe
E&P COL 6
E&P COL 7
Petrobras
E&E GUA OFF-0
55.56%
Mana
Interoil Colombia
Rio Opia
Ambrosia
Llanos 86
Llanos 87
Geopark Colombia SAS
Llanos 104
Llanos 123
Llanos 124
SSJN1
Perdices
Lewis Energy Colombia
VIM-42
SSJN3-1
Perenco Oil & Gas
El Guando
75%
El Niño
Quarter North Energy
Gunflint
32%
Gulf of Mexico
Murphy Exploration and Production Company – USA
Dalmatian
OXY (Anadarko) - K2
K2
21%
HESS
ESOX
S-M-1707
S-M-1715
S-M-1717
S-M-1719
S-M-1709
S-M-1908
Shell
S-M-1601
S-M-1713
S-M-1817
S-M-1599
S-M-1910
Sul de Gato do Mato
BM-S-54
BP Energy
Pau Brasil
20%
Occidental Midland Basin, LLC (Oxy)
Rodeo Midland Basin
49%
Midland, Texas, USA
Delaware Basin
Delaware, TX/NM, USA
PC Carigali Mexico Operation S.A.
Bloque 6
F-115
32.2Contracts in which the Ecopetrol Group is the operator
VMM29
ExxonMobil Exploration Colombia
CR2
C62
CPVEN E&P Corp Sucursal Colombia
VMM32
51%
Repsol Exploration Colombia S.A.
Catleya
Emerald Energy PLC Suc. Colombia
Cardon
ORC401 CRC-2004-01
OJANOM
Parex Resourses Colombia Ltd.
OJAOCN
100%
OJAORM
OJASUM
SierraCol Energy Arauca
La Cira Infantas
52%+PAP
Teca
100% Basic y 60% incremental
Emerald Energy
Oleoducto Alto Magdalena
45%
Colombia Energy Development CO
Rio Paez
68%
Asociación Guajira
43%
Perenco Oil and Gas
Asociación Boqueron
San Jacinto
San Jacinto (Mandato)
0%
Ecopetrol Group acquires investment commitments upon receipt of the exploration and/or exploitation rights of a particular area determined by competent authority. As of December 31, 2025, investment commitments with the ANH reach USD $452 million (2024 - USD $469 million).
Ecopetrol Permian LLC has commitments related to business plan in the Midland Basin in accordance with the agreement governing the operations of Rodeo Midland Basin LLC, which may be amended annually by the members of the agreement, as well as commitments arising from the development plan of the Delaware Basin through annual plan authorizations and authorizations for expenditure (AFEs). Ecopetrol America LLC has commitments arising from joint operations in the Gulf of Mexico through project-related authorizations for expenditure (AFEs).
33.Business segment information
A description of the Ecopetrol Group’s business segments is in Note 4.20 – Business segment information.
The segmented information used by the Board of Directors, the highest strategic and operational decision-making body for these business segments, is prepared in accordance with our internal reporting policies, which follow the guidelines provided by IFRS. The performance of the business segments is based primarily on an analysis of income, costs, expenses, and results for the year generated by each business segment which are regularly monitored.
The information disclosed in each business segment is presented net of transactions between the Ecopetrol Group companies.
33.1Net profit by operating segment
Below are the measures of profit or loss by business segment for the years ended December 31, 2025, 2024 and 2023:
Energy
and Toll
Refining and
Roads
Petrochemicals
Logistics
Inter-segments
Third–party sales
Inter–segment sales
Sales from contracts with customers
(53,950)
(62,805)
(4,322)
(7,892)
46,912
17,102
1,894
11,015
8,141
(515)
(2,584)
(857)
(1,287)
Operation and project expenses
(3,222)
(561)
Impairment (loss) reversal of non–current assets
Other operating (expenses) income net
(364)
Financial income
1,552
706
(461)
Financial expenses
(5,281)
(1,529)
(4,046)
Foreign exchange (loss) gain
(194)
(3,806)
(1,035)
(3,291)
495
7,036
(1,652)
3,696
(1,785)
(3,368)
(695)
Net profit (loss) for the year
5,251
(221)
6,412
3,001
Net profit (loss) for the year attributable to:
1,294
2,552
Supplementary information
Depreciation, depletion and amortization
11,149
2,149
1,361
1,448
F-117
For the year ended December 31, 2024
Transport and
and Production
(47,918)
(54,864)
(67,718)
(4,378)
(6,952)
47,431
1,502
10,756
8,854
(487)
(2,665)
(959)
(718)
(1,151)
390
(3,843)
(1,457)
(553)
1,266
1,583
(88)
7,655
1,121
(501)
(5,037)
(1,679)
(326)
(3,767)
490
(177)
(40)
(3,946)
(1,689)
(3,086)
540
16,903
(1,121)
9,807
5,109
(7,826)
(3,486)
(807)
9,077
(1,210)
6,321
4,302
(86)
3,336
10,477
2,071
1,321
1,328
F-118
For the year ended December 31, 2023
Exploration and
and Logistics
143,191
12,530
15,509
(51,828)
(75,716)
(4,380)
(5,929)
49,675
29,687
6,432
11,129
8,239
(476)
(2,605)
(962)
(621)
(4,102)
(1,393)
(427)
1,483
(210)
(104)
(201)
871
(652)
(4,873)
(1,748)
(3,984)
570
2,009
(273)
(1,391)
(893)
(3,109)
18,727
4,815
9,296
4,065
(8,611)
753
(3,129)
(529)
10,116
5,568
6,167
3,536
1,337
8,658
2,184
1,487
F-119
33.2Sales revenue by product
The sales by product for each segment are detailed below for the years ended December 31, 2025, 2024 and 2023:
Local sales
Mid-distillates
26,810
19,352
(3,324)
Gas natural
5,283
(1,844)
575
3,009
499
(16,119)
Electric power transmission services
1,384
813
Roads and construction services
3,163
(2,488)
23,601
(23,601)
29,939
56,058
4,133
(47,429)
40,108
Roads and Construction Services
3,490
Cash flow hedging
2,939
41,113
8,640
11,901
64,698
16,034
F-120
28,687
21,936
(4,132)
5,253
(1,157)
520
536
445
(12,758)
1,094
396
27,190
(27,190)
Energy transmission services
3,228
327
328
3,239
(2,625)
33,477
57,946
4,003
(47,903)
62,657
47,534
1,281
3,924
3,274
47,610
11,273
11,804
70,673
81,087
69,219
15,807
(47,917)
F-121
32,638
26,965
(3,836)
5,551
(1,193)
1,442
(14,002)
998
873
505
(17)
312
27,871
(27,742)
Other income gas contracts
3,692
(3,100)
33,982
68,725
3,457
(49,930)
47,632
1,928
5,666
4,315
(204)
(460)
1,500
47,535
13,419
10,712
81,517
82,144
14,169
F-122
33.3Capital expenditures by segments
The following are amounts of the investments made by each segment for the years ended December 31, 2025, 2024 and 2023:
and Toll Roads
5,495
1,792
1,147
Intangibles
369
16,077
1,881
1,161
1,708
20,827
6,419
1,535
10,761
11,291
865
18,047
1,747
1,545
22,917
738
2,702
1,651
9,350
13,964
623
18,283
822
3,325
1,661
24,091
F-123
34.Subsequent and relevant events
●Tax effects of Decree 1474 of 2025
The Company reports that Decree1474 of 2025 established the Special Tax for Fiscal Stability, which levies a one percent (1%) tax on the first sale or export of crude oil extracted in the country.
Through Press Release No. 01 dated January 29, 2026, the Constitutional Court (Colombia) announced its decision to provisionally suspend the legal effects of the Economic Emergency Decrees, including Decree 1474 of 2025.
On February 3, 2026, Ecopetrol S.A. was notified of Official Letter No. 142 (Reference No. 100153156-158), through which the Colombian Tax Authority (DIAN) stated that the Special Tax for Fiscal Stability accrued between January 1 and January 29, 2026 was validly generated while Decree 1474 of 2025 was in force and, consequently, must be paid by Ecopetrol S.A. in accordance with the applicable statutory due date.
Additionally, DIAN stated that the decree is currently suspended by decision of the Honorable Constitutional Court (Colombia); therefore, DIAN is granting full legal effect to the Constitutional Court’s decision referenced above.
As a result, Ecopetrol S.A. will not recognize the Special Tax for Fiscal Stability on crude oil sale transactions (first sale) or crude oil exports carried out as of January 30, 2026, and until a final ruling is issued regarding the constitutionality of the State of Emergency.
It is clarified that, during fiscal year 2025, the Company did not experience any effects arising from the application of Decree 1474 of 2025.
At the ordinary meeting held on September 25, 2025, the Board of Directors of Ecopetrol S.A. unanimously approved the authorization of the capitalization of Refinería de Cartagena S.A.S for an amount of up to USD 800 million (USD 800 million). The transaction will be carried out through the issuance of shares by the Cartagena Refinery, which will be delivered to Ecopetrol as consideration for the crude oil supplied, within the framework of the crude oil sales agreement currently in force between the companies.
The execution of the transaction took place between January and February 2026, once approved by the General Shareholders’ Meeting of the Cartagena Refinery. The transaction will be recognized in financial statements based on the date on which such approval is granted.
According to the regulatory update issued by the Government of Ecuador, the tariff for crude oil transportation through the Transecuadorian Pipeline System (SOTE) increases from USD 3 to USD 30 per barrel as of January 23, 2026. This measure represents a 900% increase in the cost applied to foreign users, including crude oil transported from Colombia.
Based on the foregoing, a significant increase in transportation costs is expected for 2026, proportional to the new tariff established by Ecuador’s Agency for the Regulation and Control of Hydrocarbons.
On March 17, 2026, Ecopetrol and Frontera Energy announced the execution of a strategic agreement for regasification services. The agreement is intended to support the timely and reliable supply of natural gas to Colombia beginning in the third quarter of 2026. The project’s initial phase provides for early capacity of 126 mmcfpd in 2026, followed by a phased expansion to up to 370 mmcfpd by 2028. This incremental capacity is expected to strengthen Colombia’s medium-term natural gas supply and enhance the reliability of the national energy system.
On March 19, 2026, ISA Energía Brasil S.A., informs that it has entered into a share purchase agreement with “Centrais Elétricas Brasileiras S.A.” (“Axia Energia”) to unwind the cross-holdings in Interligação Elétrica do Madeira S.A. (“IE Madeira”) and Interligação Elétrica Garanhuns S.A., through:
Closing of the transaction is subject to the satisfaction of customary conditions precedent for transactions of this nature, including the applicable approvals/clearances from the Brazilian Electricity Regulatory Agency (“ANEEL”), the Brazilian antitrust authority (“CADE”), and the required consents from certain creditors.
On December 30, 2025, the Company obtained approval for a total fundraising of $751 (USD $200 million dollars) through Credit Notes with Banco Santander, to be disbursed in 6 installments in 2026. The payment due date is November 26, 2026, with an annual interest rate of 5.41%.
Between February 21 and March 25, 2026, $143 (USD 38 million dollars) was received.
In the General Assembly of Shareholders held on March 27, 2026, a distribution of ordinary dividends for the fiscal year ended December 31, 2025, was approved as follows: COP 4,975 billion, or COP 121 per share, based on the number of outstanding shares as of December 31, 2025. The total dividends approved correspond to an ordinary dividend pursuant to our current dividend policy. The payment is expected to be made no later than June 30, 2026 to all shareholders, taking into account the payment schedule of the balance of the Fuel Price Stabilization Fund (FEPC) corresponding to its 2025 accumulation.
F-125
The MHCP has reviewed and authorized the terms of the loan agreement, which includes customary borrower events of default, such as failure to pay principal or interest, potential impairment of the borrower’s payment capacity, impairment of the integrity of its financial information, and breach of covenants. If any such event occurs, the lenders may demand early repayment of the debt, following the procedure set forth in the agreement. The agreement also provides Ecopetrol with the right to seek recourse against the lenders if they fail to disburse funds as required. The agreement is governed by the laws of the State of New York.
On April 23, 2026, Ecopetrol S.A announces that entered into a Share Purchase Agreement with Jive, Yellowstone and Bloco Somah Printemps Quantum, which together constitute a group of significant shareholders holding approximately 26% of the outstanding common shares of the Brazilian company Brava Energia S.A., for the acquisition by Ecopetrol S.A., or one of its affiliates or subsidiaries within the Ecopetrol Group, of 120,813,490 shares of Brava, representing approximately 26% of Brava’s share capital.
Brava was incorporated in 2024 from the merger between 3R Petroleum Óleo e Gás S.A. and Enauta Participações S.A., two oil and gas companies operating in Brazil. Brava currently conducts crude oil and natural gas production activities in offshore and onshore fields across multiple basins in Brazil as well as participates in the midstream and downstream segments. As of December 2025, according to Brava’s public information, the Company reported EBITDA of USD $806 million, with an EBITDA margin of 39%. Brava is positioned as the second-largest independent company listed in the Brazilian market in terms of reserves and production.
The completion of this transaction is subject to certain customary conditions precedent, including, among others, approval by Brazil’s Administrative Council for Economic Defense, the grant of certain waivers and consents considering Brava’s financing instruments and relevant commercial agreements, as well as the purchase by Ecopetrol S.A., or one of its affiliates or subsidiaries within the Ecopetrol Group, of the number of shares required to achieve a 51% controlling stake of Brava’s voting share capital.
Therefore, Ecopetrol S.A., or one of its affiliates or subsidiaries within the Ecopetrol Group, plans to launch a Voluntary Tender Offer (Oferta Pública de Aquisição) on the B3 stock exchange in Brazil, at a price of R$23.00 per share, to acquire the additional number of Brava shares required to secure a 51% equity interest in the Company. This offer price represents a premium of approximately 27.8% over the Volume-Weighted Average Price of the Company’s shares during the 90 trading days immediately preceding the date of this announcement. The tender offer is addressed to all of Brava’s shareholders, ensuring equal treatment and conditions, and will be subject to applicable regulatory requirements and certain conditions precedent.
Ecopetrol S.A., or one of its affiliates or subsidiaries within the Ecopetrol Group expects to secure the funding required to consummate the transaction through a bridge loan, subject to the fulfillment of the applicable conditions precedent.
F-126
Once the applicable conditions precedent and legal requirements for closing the transaction have been satisfied, Ecopetrol will disclose relevant information in accordance with the applicable legal and regulatory framework through this same channel and/or any other required means.
On April23, 2026, the credit rating agency Moody’s Ratings downgraded the Company’s global credit rating from Ba1 to Ba2 and revised the outlook from stable to negative. In contrast, the agency affirmed Ecopetrol’s Baseline Credit Assessment (BCA), or stand-alone credit profile, at b1, highlighting the Company’s intrinsic strength.
On February 11, 2026, the National Government issued Decree 1050 of 2026, declaring a new State of Economic, Social and Ecological Emergency. Pursuant to Decree 1050, the Government issued Decree 173 of 2026 introducing a temporary wealth tax applicable to Colombian legal entities and assimilated entities for fiscal year 2026. The tax takes effect upon publication and is triggered by the possession of net equity as of March 1, 2026. For extractive industries, the applicable rate is 1.6%. The tax includes specific exclusions and anti-avoidance rules and must be declared and paid in two installments during 2026.
F-127
Geographic
Profit
Functional
Country/
area of
(loss) of
currency
Activity
Domicile
the year
Subsidiaries
US Dollar
Refining of hydrocarbons, commercialization and distribution of products
21,317
32,997
11,680
Cenit transporte y logística de hidrocarburos S.A.S.
Colombian Peso
Storage and transport by pipelines of hydrocarbons
16,513
5,258
19,370
2,857
Ecopetrol Global Energy S.L.U.
Investment Vehicle
Spain
17,061
605
Oleoducto Central S.A.S - Ocensa
Transportation by crude oil pipelines
3,334
3,256
6,745
3,411
Hocol Petroleum Limited.
Bermuda
3,908
609
3,945
Ecopetrol América LLC.
Exploration and exploitation of hydrocarbons
1,184
2,166
Cayman Islands
3,419
5,100
Production and commercialization of polypropylene resin
2,502
2,791
Ecopetrol Capital AG
Collection of surpluses from, and providing funds to, companies of the Ecopetrol Group
Switzerland
1,399
8,909
7,510
Oleoducto de Colombia S. A. – ODC
789
Black Gold Re Ltd.
Reinsurer for companies of the Ecopetrol Group
1,095
1,432
Andean Chemicals Ltd.
1,890
1,896
Oleoducto de los Llanos Orientales S. A. - ODL
Panama
792
685
1,332
51.41
Public transmission service of electric power, the development of infrastructure projects and their commercial exploitation and the development of information technology systems, activities and services and telecommunications.
Latin-America
28,307
2,420
76,130
47,823
Inversiones de Gases de Colombia S.A. Invercolsa S.A.
51.88
Holding with investments in natural gas and LPG transportation and distribution companies in Colombia
286
Alcanos de Colombia S.A. E.S.P.
29.61
Residential public fuel gas service, construction and operation of gas pipelines, distribution networks, regulation, measurement, and compression stations.
342
950
Metrogas de Colombia S.A E.S.P.
33.49
Public service of commercialization and distribution of fuel gas; the exploration, exploitation, storage, use, transportation, refining, purchase, sale and distribution of hydrocarbons and their derivatives.
Gases del Oriente S.A. E.S.P.
48.50
Home public service of distribution of fuel gas and the development of all complementary activities to the supplying of said service.
Promotora de Gases del Sur S.A. E.S.P.
31.44
Promote the linking of national or foreign capital, public or private, to achieve the gas massification project.
Combustibles Líquidos de Colombia S.A E.S.P.
41.61
Wholesale marketing of fuel gas, the supplying of the residential public service of LPG distribution and the development of complementary activities to supply the service.
F-129
Ecopetrol USA Inc.
14,121
715
14,467
10,441
13,451
3,010
Ecopetrol Oleo é Gas do Brazil Ltda.
Real
2,844
3,179
Esenttia Masterbatch Ltda.
Manufacture of polypropylene compounds and masterbatches
Ecopetrol del Perú S. A.
ECP Hidrocarburos de México S.A. de C.V.
Offshore exploration
Mexico
Ecopetrol Costa Afuera S.A.S.
Esenttia Resinas del Peru SAC
Commercialization polypropylene resins and masterbatches
Esenttia Resinas de México
Mexican Peso
Kalixpan Services Técnicos S de RL De CV.
Specialized services related to oil and gas industry
Ecopetrol US Trading LLC
International trading of crude oil and refined products
586
413
1,871
1,285
Econova Technology & innovation S.L.
Execution of activities related to science, technology, and innovation (ST+i)
Ecopetrol Singapore PTE. LTD
Singapore dollar
Holding company with investment in an international trading company for crude oil and refined products
Singapore
Asia
615
Ecopetrol Trading Asia PTE. LTD
614
2,792
2,178
F-130
Wind Autogeneración S.A.S.
Wind energy production
Parque Solar Porton del Sol S.A.S E.S.P.
Enerfin Services S.A.S.
Planta Solar Sahagun S.A.S.
El Roble Solar S.A.S.
Girasol I S.A.S.
La Cayena Solar S.A.S.
Córdoba Solar 2 S.A.S.
F-131
Profit (loss) of
Services for the support of loading and unloading of oil ships, supply of equipment, technical inspections, and load measurements
Construction, use, maintenance and administration of port facilities, ports, private docks.
United Kingdom
Production, trading, and distribution of biofuels and oleochemicals
(58)
283
F-132
Functional currency
Profit (loss)
Concesión Costera-Cartagena-Barranquilla S.A.S
Colombian peso
2,425
Transelca S.A. E.S.P.
Electric power
1,972
1,073
899
Internexa S.A.
Telecommunications
676
Intercolombia S.A E.S.P.
427
XM Compañía de Expertos en Mercados S.A. E.S.P.
371
317
Inteia S. A. S.
Intervial Colombia S.A.S.
HUB Digital de Servicios ISA S.A.S
Servicios
ISA Energía Brasil S.A.
Brazilian real
ISA Capital do Brasil
ISA Investimentos e Participações S.A.
Interligação Elétrica Riacho Grande
Interligação Elétrica Aguapeí S.A.
Interligação Elétrica Evrecy S.A.
Interligação Elétrica Itaquerê S.A.
Interligação Elétrica Itaúnas S.A.
Interligação Elétrica de Minas Gerais S.A.
Interligação Elétrica Jaguar 9 S.A.
Interligação Elétrica Norte E Nordeste S.A.
Interligação Elétrica Biguaçu S.A.
Fundo de Investimento Xavantes Referenciado DI
Interligação Elétrica Serra do Japi S.A.
Interligação Elétrica Tibagi S.A.
Interligação Elétrica Jaguar 8 S.A.
Interligação Elétrica Sul S.A.
Interligação Elétrica Jaguar 6 S.A.
Interligação Elétrica Itapura S.A.
Fundo De Investimento Barra Bonita Renda
Fundo De Investimento Referenciado Di Bandeirantes
Interligação Elétrica Pinheiros S.A.
Fundo De Investimento Assis
Ruta del Maipo Sociedad Concesionaria S.A.
Chilean peso
1,733
1,039
694
Intervial Chile S.A.
1,003
ISA Inversiones Chile Vías Spa
Ruta del Loa Sociedad Concesionaria S.A.
399
Ruta de la Araucanía Sociedad Concesionaria S.A.
ISA Inversiones Costera Chile Spa
Ruta de los Ríos Sociedad Concesionaria S.A.
Ruta Orbital Sur Sociedad Concesionaria S.A.
Interchile S.A.
US dollar
ISA Inversiones Chile Spa
Ruta del Bosque Sociedad Concesionaria S.A.
ISA Inversiones Tolten Ltda.
Interconexiones del Norte S.A.
Interconexiones Viales Spa
Interconexiones Eléctricas Qoyllur Spa
Consorcio Transmantaro S.A.
Red de Energía del Perú
ISA Perú
Internexa Perú
Proyectos de Infraestructura del Perú S.A.C.
Ruta del Este Sociedad Concesionaria S.A.
Linear Systems Re Ltd.
ISA Bolivia
F-134
Balance as
of
Interest
Debt
Issue date
Currency
Amount disbursed
December 2025
rate
payment
National currency bond
Dec-10
Dec-40
COP
Semi-annually
Aug-13
Aug-28
348
Aug-43
Dec-11
Dec-41
May-13
May-28
Quarterly
May-15
May-25
May-30
May-35
Feb-16
Feb-28
Feb-41
Apr-17
Apr-32
Apr-42
Nov-17
Nov-25
Nov-31
Nov-47
Jul-18
Jul-27
Jul-33
Jul-43
Aug-20
Aug-29
Nov-23
Nov-30
Annually
Nov-37
Nov-44
Jun-24
Jun-30
Jun-39
Issue
date
Foreign Currency Bond
Jul-23
Jan-29
USD
Apr-20
Apr-30
Nov-21
1,250
Oct-24
Feb-32
Jan-23
Jan-33
Jan-24
Jan-36
1,850
Sep-13
Sep-43
May-14
May-45
Nov-51
Nov-33
Jul-16
Jan-34
UVR
1,183
1,359
Oct-11
Oct-26
100,000
Jan-11
Jan-26
Oct-12
Apr-31
Apr-19
Apr-34
Apr-22
Apr-38
PEN
May-18
Apr-25
BRL
621
Dec-19
Dec-29
409
Dec-20
Nov-28
May-44
895
F-136
Feb-21
Jul-44
673
967
Oct-21
Oct-31
669
826
Oct-38
Apr-29
700
Mar-23
Mar-30
Oct-23
Oct-33
784
862
1,116
1,228
Mar-24
Mar-29
Mar-31
Mar-34
May-24
May-31
1,000
Oct-36
1,053
Oct-39
752
Mar-25
Jun-33
511
Mar-33
900
Jul-25
Jun-35
Oct-25
Oct-37
1,002
Oct-40
Jun-18
Jun-25
UF
Dec-30
Jun-50
Nov-22
Sep-23
Jul-24
Jul-21
Jun-56
F-137
National currency credit
Apr-23
Dec-23
Dec-35
Dec-34
Apr-36
Dec-16
Jan-28
561
Oct-28
Jul-22
Oct-34
Nov-24
Nov-34
Nov-35
May-19
May-29
Sep-20
Sep-30
Nov-20
Jun-21
Jun-31
Jun-22
Jun-27
Aug-22
Aug-27
F-138
Foreign currency credit
Sep-19
Sep-25
Dec-22
Feb-23
Nov-26
Sep-22
Sep-32
Apr-24
Apr-26
Dec-25
May-22
May-27
Oct-22
Jan-14
Aug-17
Mar-32
Mar-22
487
May-10
1,020,000
419,800
Mar-19
27,368
23,437
Sep-18
31,849
318,302
127,349
CLP
1,479
May-21
May-26
88,518
26,555
59,143
45,640
850,000
480,000
180,000
8,947
F-139
Conditions of the most significant debt as of December 2024
December 2024
Bonds, domestic currency
Aug -28
Half-yearly
Interconexión Eléctrica S.A. E.S.P.
Feb-24
261
Aug-40
446
F-140
Bonds, foreign currency
Jul-20
Interconexión Eléctrica S.A. E.S.P and subsidiaries
Mar-17
Dec30
Dec24
Dec19
Dec29
Dec20
F-141
International commercial loans
Quaterly
Dec41
F-142
Dec22
Dec23
Dec17
Dec25
359
Dec27
May-23
Oct-29
F-143
Domestic commercial loans
Dec16
511,954
211,357
jul-18
nov-18
nov-28
nov-23
oct-24
Dec34
Dec35
F-144
Limitation
on the
termination
for service
Asset concession
Revenues
of the
conditions
(Million COP)
Business
Concessionaire
Country
contract
Y/N
Intangible asset
Sep-53
Y
6,195,665
7,333,984
1,215,407
1,252,084
Red de Energía del Perú S.A. - ISA REP
1,153,416
1,448,924
836,528
811,312
ISA Perú S.A.
Apr-33
619,271
739,721
138,387
131,870
Total Peru
7,968,352
9,522,629
2,190,322
2,195,266
Jan-39
40,243
48,429
33,741
30,981
Inteia S. A. S. (antes Sistemas Inteligentes de Red S. A. S.)
665
37,255
33,777
Total concessions, Intangible asset
8,008,595
9,571,723
2,261,318
2,260,024
Contractual assets
Sep-52
19,225,760
16,785,220
4,863,726
3,840,524
Aug-47
546,798
551,546
61,838
70,757
463,987
471,989
52,030
54,788
Feb-47
447,335
451,017
56,716
70,667
Sep-48
376,117
382,111
40,000
40,240
Mar-38
373,371
385,827
47,797
51,461
418,108
414,858
57,994
84,657
Nov-39
337,627
346,684
39,679
49,773
Mar-50
446,370
435,705
64,067
68,798
271,197
230,114
71,706
50,635
154,014
166,781
12,240
20,804
426,643
441,438
43,563
194,823
172,208
178,033
18,439
25,249
151,059
154,087
15,156
30,845
203,622
110,630
108,197
20,489
Interligação Elétrica Riacho Grande S.A.
Mar-51
707,650
416,559
324,386
279,824
45,634
46,435
5,967
6,176
Total concessions, asset contractual
24,767,500
21,969,034
5,883,501
4,960,510
Maintenance for
service
Financial asset
Dec-42
65,094
143,786
827,237
940,992
3,238
3,695
7,739
5,580
3,701
3,531
8,031
6,002
713
5,257
3,310
9,119
6,943
3,231
2,266
4,751
4,784
2,326
6,434
3,213
5,482
13,035
12,099
2,987
3,918
7,254
1,258
1,504
6,458
6,197
2,630
6,596
3,093
974
2,035
2,661
2,395
3,547
10,447
10,629
5,946
2,803
1,371
2,574
3,770
3,189
2,012
1,769
8,496
6,837
12,549
Total Brazil
108,243
192,583
917,329
1,026,847
Apr-35
6,312,424
6,412,889
1,218,232
877,003
Apr-49
1,543,347
1,537,355
190,050
323,645
14,957
224,489
154,513
191,956
Mar-26
42,051
79,482
163,852
208,587
Jun-70
48,810
23,523
27,314
22,862
Nov-42
1,162
Total Chile
7,962,751
8,277,738
1,754,176
1,624,053
Concesión Costera-Cartagena-Barranquilla S.A.S.-Ruta Costera
Feb-42
2,103,684
2,168,476
368,091
262,890
Ruta del Este Sociedad Concessionaria S.A.
351,320
53,605
234,028
49,512
Total Panama
Total concessions, financial asset
10,525,998
10,692,402
3,273,624
2,963,302
Total concessions
43,302,093
42,233,159
11,418,443
10,183,836
F-146
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
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.
Acquisition of proved properties (1)
Acquisition of unproved properties (2)
3,354
3,378
15,839
15,965
19,976
19,193
21,893
22,926
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.
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:
Net revenues
58,845
67,411
66,258
12,207
13,677
15,257
Production costs (1)
20,552
21,568
20,545
Depreciation, depletion, and amortization (2)
11,083
10,357
Other production costs (3)
22,315
22,938
22,752
Exploration expenses (4)
Other expenses (5)
5,329
3,636
7,508
60,231
60,269
61,425
Income before income tax expense
20,090
(2,755)
(9,627)
(9,250)
Results of operations for exploration and production activities
8,066
11,192
10,840
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.
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.
Includes transportation costs and naphtha that are not part of the Ecopetrol Group’s lifting cost.
Exploration expenses include the costs of geological and geophysical activities, as well as the non–productive exploratory wells.
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.
F-148
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:
(Mbls)
(Gpc)
(Mbe)
Proved reserves:
1,522
2,116
1,892
2,346
1,515
2,828
Revisions of previous estimates (1)
(165)
Improved recovery
(199)
(277)
(248)
(250)
(247)
1,755
Proved developed reserves:
2,007
1,435
2,174
1,204
1,539
1,474
Proved undeveloped reserves:
435
366
498
388
448
654
635
Some values were rounded for presentation purposes.
Mbls = Million barrels
Gpc: Giga cubic feet
Mbe = Million barrels of oil equivalent
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.
F-149
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.
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)
(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
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:
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
Previously estimated development costs incurred during the year
23,283
27,042
34,815
Accretion of discount
17,713
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)
F-150
Signature Page
SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
By:
/s/ Juan Carlos Hurtado Parra
Name:
Title:
Acting Chief Executive Officer
/s/ Alfonso Camilo Barco Muñoz
Alfonso Camilo Barco Muñoz
Chief Financial Officer
Dated: April 30, 2026
10.Exhibits
Exhibit No.
Description
Amended and Restated Bylaws of Ecopetrol S.A., dated June 27, 2024.
Form of Deposit agreement between Ecopetrol, JPMorgan Chase Bank as depository, and the holders from time to time of ADSs (incorporated by reference to Exhibit 99.A to our registration statement on Form F-6 filed with the U.S. Securities and Exchange Commission on December 29, 2017 (File No. 333-222378).
Form of Amendment No. 1 to the Deposit Agreement between Ecopetrol, JPMorgan Chase Bank as depository, and the holders from time to time of ADSs (incorporated by reference to Exhibit (a)(2) to our registration statement on Form F-6 filed with the U.S. Securities and Exchange Commission on December 17, 2021 (File No. Form F-6 filed with the U.S. Securities and Exchange Commission on December 29, 2017 (File No. 333-222378).
Description of Securities other than Equity Securities
Transportation Agreement between Ecopetrol S.A. and Oleoducto Central S.A., dated March 31, 1995 (incorporated by reference to Exhibit 4.1 on Form 20-F filed with the U.S. Securities and Exchange Commission on September 12, 2008 (File No. 001-34175)) (English Translation).
Supplementary Agreement to Transportation Agreement between Ecopetrol S.A. and Oleoducto Central S.A., dated January 17, 2013 (incorporated by reference to Exhibit 4.2 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 29, 2013 (File No. 001-34175)) (English Translation).
Crude Oil Transportation Services Agreement between Ecopetrol S.A. and Cenit Transporte y Logística de Hidrocarburos S.A.S., dated April 1, 2013 (incorporated by reference to Exhibit 4.6 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 29, 2013 (File No. 001-34175)) (English Translation).
Refined Products Transportation Services Agreement between Ecopetrol S.A. and Cenit Transporte y Logística de Hidrocarburos S.A.S., dated April 1, 2013 (incorporated by reference to Exhibit 4.7 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 29, 2013 (File No. 001-34175)) (English Translation).
Amendment No. 6, dated April 25, 2016, to the Crude Oil Transportation Services Agreement between Ecopetrol S.A. and Cenit Transporte y Logística de Hidrocarburos S.A.S., dated April 1, 2013 (incorporated by reference to Exhibit 4.13 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 5, 2019 (File No. 001-34175)) (English Translation).
Amendment No. 7, dated December 28, 2016, to the Crude Oil Transportation Services Agreement between Ecopetrol S.A. and Cenit Transporte y Logística de Hidrocarburos S.A.S., dated April 1, 2013 (incorporated by reference to Exhibit 4.14 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 5, 2019 (File No. 001-34175)) (English Translation).
Indenture, dated as of July 23, 2009, between the Company and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Form F-4 filed with the U.S. Securities and Exchange Commission on July 31, 2009 (File No. 333-160965)).
Amendment No. 1 to the Indenture, dated as of June 26, 2015, between the Company and The Bank of New York Mellon, as trustee (incorporated by reference to Exhibit 4.10 on Form 6-K of the Company furnished to the U.S. Securities and Exchange Commission on June 25, 2015 (File No. 001-34175)).
Prospectus Supplement relating to Ecopetrol S.A.’s 7.375% Notes due 2043 filed with the U.S. Securities and Exchange Commission on September 13, 2013 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on September 13, 2013 (File No. 333 - 190198)).
Prospectus Supplement relating to Ecopetrol S.A.’s 5.875% Notes due 2045 filed with the U.S. Securities and Exchange Commission on May 21, 2014 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on May 21, 2014 (File No. 333-190198)).
Prospectus Supplement relating to Ecopetrol S.A.’s 6.875% Notes due 2030 filed with the U.S. Securities and Exchange Commission on April 27, 2020 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on April 27, 2020 (File No. 333-225381)).
Prospectus Supplement relating to Ecopetrol S.A.’s 4.625% Notes due 2031 filed with the U.S. Securities and Exchange Commission on October 28, 2021 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on October 28, 2021 (File No. 333-256623)).
4.13
Prospectus Supplement relating to Ecopetrol S.A.’s 5.875% Bonds due 2051 filed with the U.S. Securities and Exchange Commission on October 28, 2021 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on October 28, 2021 (File No. 333-256623)).
4.14
Prospectus Supplement relating to Ecopetrol S.A.’s 8.875% Bonds due 2033 filed with the U.S. Securities and Exchange Commission on January 12, 2023 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on January 12, 2023 (File No. 333-256623)).
Prospectus Supplement relating to Ecopetrol S.A.’s 8.375% Bonds due 2036 filed with the U.S. Securities and Exchange Commission on January 9, 2024 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on January 11, 2024 (File No. 333-256623)).
Prospectus Supplement relating to Ecopetrol S.A.’s 7.750% Bonds due 2032 filed with the U.S. Securities and Exchange Commission on October 18, 2024 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on October 18, 2024 (File No. 333-278823)).
4.17
Inter-Administrative Share Purchase Agreement dated August 11, 2021 between Ecopetrol S.A. and the Ministerio de Hacienda y Crédito Público (incorporated by reference to Exhibit 4.20 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 25, 2022 (File No. 001-34175) (English translation).
Loan Agreement among Ecopetrol, S.A., as borrower, UMB Bank, National Association, as Administrative Agent, Sumitomo Mitsui Banking Corporation and The Bank Of Nova Scotia, as Joint Lead Arrangers, and The Bank Of Nova Scotia, as Sole Bookrunner dated as of December 19, 2022 (incorporated by reference to Exhibit 4.22 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 18, 2024 (File No. 001-34175).
Loan agreement among the Ecopetrol, S.A., as borrower, MUFG Bank, LTD, as administrative agent, and Banco Bilbao Vizcaya Argentaria, S.A. New York Branch and MUFG Bank, LTCD, as bookrunners and lead arrangers, dated as of May 15, 2023 (incorporated by reference to Exhibit 4.23 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 18, 2024 (File No. 001-34175).
4.20
4.21
Amendment No. 3 to the transport agreement dated November 22, 2023, executed among Oleoducto Central S.A., and Ecopetrol, S.A. (English Translation) (incorporated by reference to Exhibit 4.25 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
260
4.22
Amendment No. 3 to the transport agreement dated November 22, 2023, executed among Oleoducto Central S.A., and Ecopetrol, S.A. (English Translation) (incorporated by reference to Exhibit 4.26 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
Amendment No. 19 to the crude oil services framework agreement dated May 28, 2024, executed among Ecopetrol, S.A., and Cenit Transporte y Logística de Hidrocarburos S.A.S. (English Translation) (incorporated by reference to Exhibit 4.27 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
4.24
Amendment No. 22 to the products service framework agreement dated April 9, 2024, executed among Cenit Transporte y Logística de Hidrocarburos S.A.S., and Ecopetrol S.A. (English Translation) (incorporated by reference to Exhibit 4.28 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
4.25
Loan agreement, executed among Ecopetrol, S.A., as borrower, Banco Bilbao Vizcaya Argentina, S.A. New York Branch, as administrative agent, and The Bank of Nova Scotia, BBVA Securities Inc., Bank of America, N.A., JPMorgan Chase Bank, N.A., Itau Chile New York Branch, and Standard Chartered Bank (Hong Kong) Limited, as joint lead arrangers and joint bookrunners, dated as of April 12, 2024 (incorporated by reference to Exhibit 4.31 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
4.26
Purchase and sale agreement dated May 1, 2021, executed among Enterprise Products Operating LLC, and Esenttia S.A. (incorporated by reference to Exhibit 4.35 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
4.27
First amendment to the purchase and sale agreement dated May 1, 2021, executed among Enterprise Products Operating LLC, and Esenttia S.A. (incorporated by reference to Exhibit 4.36 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
Second amendment dated December 19, 2022, to the purchase and sale agreement dated May 1, 2021, executed among Enterprise Products Operating LLC, and Esenttia S.A. (incorporated by reference to Exhibit 4.37 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
4.29
[Reserved.]
Third amendment dated January 1, 2024, to the purchase and sale agreement dated May 1, 2021, executed among Enterprise Products Operating LLC, and Esenttia S.A. (incorporated by reference to Exhibit 4.38 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 23, 2025 (File No. 001-34175)).
4.31
Prospectus Supplement relating to Ecopetrol S.A.’s 8.625% Notes due 2029 and 8.875% Bonds due 2033 filed with the U.S. Securities and Exchange Commission on January 12, 2023 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on June 30, 2024 (File No. 333-256623)).
4.32
Loan agreement among Ecopetrol S.A., as borrower, the lending parties thereto, Banco Santander S.A., as administrative agent and Banco Santander S.A. as lead arranger, dated as of April 30, 2025.
4.33
Loan agreement among Ecopetrol S.A., as borrower, the lending parties thereto, Banco Latinoamericano de Comercio Exterior, S.A., as administrative agent and Banco Latinoamericano de Comercio Exterior, S.A. and Sumitomo Mitsui Banking Corporation, as joint lead arrangers and joint bookrunners, dated as of November 25, 2025.
4.34
First Amendment, dated as of December 30, 2025, to the Loan agreement among the Ecopetrol, S.A., as borrower, MUFG Bank, LTD, as administrative agent, and Banco Bilbao Vizcaya Argentaria, S.A. New York Branch and MUFG Bank, LTCD, as bookrunners and lead arrangers, dated as of May 15, 2023
4.35
Amendment No. 21 to the crude oil services framework agreement dated June 12, 2025, executed among Ecopetrol, S.A., and Cenit Transporte y Logística de Hidrocarburos S.A.S. (English Translation).
4.36
Amendment No. 22 to the crude oil services framework agreement dated August 26, 2025, executed among Ecopetrol, S.A., and Cenit Transporte y Logística de Hidrocarburos S.A.S. (English Translation).
4.37
Amendment No. 23 to the crude oil services framework agreement dated December 24, 2025, executed among Ecopetrol, S.A., and Cenit Transporte y Logística de Hidrocarburos S.A.S. (English Translation).
4.38
Amendment No. 23 to the Refined Products Transportation Services Agreement dated April 22, 2025, executed among Ecopetrol, S.A., and Cenit Transporte y Logística de Hidrocarburos S.A.S. (English Translation).
4.39
Compensation differentials payment agreement entered into on April 1, 2026, by and among the Nation of Colombia, Ecopetrol S.A. and Refinería de Cartagena S.A.S.
4.40
Framework Contract for the Commercialization of Energy entered into on August 12, 2022 between Ecopetrol S.A. and Generadora y Comercializadora de Energía del Caribe S.A. E.S.P. – Gecelca.
4.41
Addendum No. 4, dated November 8, 2024, to Framework Contract for the Commercialization of Energy entered into between Ecopetrol S.A. and Generadora y Comercializadora de Energía del Caribe S.A. E.S.P. – Gecelca.
4.42
Loan agreement, dated March 17, 2023, between Bancolombia S.A. and Ecopetrol S.A.
4.43
Amendment No. 1, dated June 13, 2023, to the Loan agreement between Bancolombia S.A. and Ecopetrol S.A.
4.44
Amendment No. 2, dated May 23, 2024, to the Loan agreement between Bancolombia S.A. and Ecopetrol S.A.
4.45
Loan contract, dated June 28, 2024, among Banco de Bogotá S.A., Banco de Occidente S.A., Banco Popular S.A., and Ecopetrol S.A.
4.46
Amendment No. 1, dated October 10, 2025, to the Loan contract among Banco de Bogotá S.A., Banco de Occidente S.A., Banco Popular S.A., and Ecopetrol S.A.
Company Clawback Policy
8.1
List of subsidiaries of Ecopetrol S.A.
12.1
Section 302 Certification of the Chief Executive Officer.
12.2
Section 302 Certification of the Chief Financial Officer.
Section 906 Officer Certification.
23.1
Consent of Deloitte & Touche S.A.S.
23.2
Consent of Ernst & Young Audit S.A.S.
23.3
Consent of Ryder Scott Company, L.P.
Consent of DeGolyer and MacNaughton
23.5
Consent of Gaffney, Cline & Associates
99.1
Third-Party Reserve Report of Ryder Scott Company, L.P.
99.2
Third-Party Reserve Report of DeGolyer and MacNaughton
99.3
Third-Party Reserve Report of Gaffney, Cline & Associates
101.INS
XBRL Instance Document
101.SCH
XBRL Taxonomy Extension Schema Document
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
101.LAB
XBRL Taxonomy Extension Labels Linkbase Document
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document
Sections
Item 1.
Identity of Directors, Senior Management and Advisers
A. Directors and Senior Management
B. Advisers
C. Auditors
Item 2.
Offer Statistics and Expected Timetable
A. Offer Statistics
B. Method and Expected Timetable
Item 3.
Key Information
A. Reserved
B. Capitalization and Indebtedness
C. Reasons for the Offer and Use of Proceeds
D. Risk Factors
Item 4.
Information on the Company
Note 1 to the consolidated financial statements - 3.4 Our Business
A.History and Development of the Company
2.1; 3.1; Note 1 to the consolidated financial statements
B. Business Overview
2; 3.4 – 3.14; 4.1, 4.6, Note 1 and Supplemental information on Oil and Gas producing activities (unaudited by Deloitte) to the consolidated financial statements
C. Organizational Structure
D. Property, Plants and Equipment
3.4 – 3.8; 4.7.2; 4.11; Notes 14, 15,16 and 17 to the consolidated financial statements
Item 4A.
Unresolved Staff Comments
None
Item 5.
Operating and Financial Review and Prospects
A. Operating Results
3.4 – 3.8; 4
B. Liquidity and Capital Resources
2.1; 4.7; Consolidated statements of cash flow and Notes 6, 9, 20, and 29 to the consolidated financial statements
C. Research and development, Patents and Licenses, etc.
3.9; Note 17 to the consolidated financial statements
D. Trend Information
E. Critical Accounting Estimates
4.5; Note 3 to the consolidated financial statements
Item 6.
Directors, Senior Management and Employees
7.3; 7.5
B. Compensation
7.6; Notes 4, 22 and 31 to the consolidated financial statements
C. Board Practices
D. Employees
3.14
E. Share Ownership
F. Disclosure of a registrant’s action to recover erroneously awarded compensation
Item 7.
Major Shareholders and Related Party Transactions
A. Major Shareholders
6.9; 7.7
B. Related Party Transactions
3.12; Note 31 to the consolidated financial statements
C. Interests of Experts and Counsel
Item 8.
Financial Information
A. Consolidated Statements and Other Financial Information
4; 6.2; 8
B. Significant Changes
4; 7.8; Note 33 and 34 to the consolidated financial statements
Item 9.
The Offer and Listing
A. Offer and Listing Details
6.4, 6.5
B. Plan of Distribution
C. Markets
D. Selling Shareholders
E. Dilution
F. Expenses of the Issue
Item 10.
Additional Information
A. Share Capital
B. Memorandum and Articles of Association
C. Material Contracts
3,12; 4.9; Exhibits 4.1 – 4.9, 4.20 and 4.28
D. Exchange Controls
5.3.4; 6.7
E. Taxation
4.3.1; 6.6; Note 10 to the consolidated financial statements
F. Dividends and Paying Agents
G. Statements by Experts
H. Documents On Display
I. Subsidiary Information
J. Annual Report to Security Holders
Item 11.
Quantitative and Qualitative Disclosures About Market Risk
4.1; 5.2.1; 5.2.4; 5.3.4; Note 30 to the consolidated financial statements
Item 12.
Description of Securities Other than Equity Securities
A. Debt Securities
4.9; 6.4; Exhibits 4.12–4.28
B. Warrants and Rights
C. Other Securities
D. American Depositary Shares
5.2.4; 6.5; Exhibit 2.1 – 2.2
Item 13.
Defaults, Dividend Arrearages and Delinquencies
Item 14.
Material Modifications to the Rights of Security Holders and Use of Proceeds
Item 15.
Item 16.
Reserved
Item 16A.
Audit Committee Financial Expert
Item 16B.
Code of Ethics
7.2; 7.4
Item 16C.
Principal Accountant Fees and Services
Item 16D.
Exemptions from the Listing Standards for Audit Committees
Item 16E.
Purchases of Equity Securities by the Issuer and Affiliated Purchases
Item 16F.
Changes in Registrant’s Certifying Accountant
Item 16G.
Item 16H.
Mine Safety Disclosure
Item 16I.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Item 16J.
Item 16K.
Cybersecurity
Item 17.
Financial Statements
Item 18.
Item 19.
Exhibits
264