ECOPETROL S.A. [EC] Filings

20-F 1 ec-20221231x20f.htm 20-F

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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

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022

☐ 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

BOGOTA – COLOMBIA

(Address of principal executive offices)

Tel. (57) 310 315 8600

Carolina Tovar Aragón

Investor Relations Officer

investors@ecopetrol.com.co

Tel. (57) 310 315 8600

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)
5.875% Notes due 2023	EC23	New York Stock Exchange
4.125% Notes due 2025	EC25	New York Stock Exchange
5.375% Notes due 2026	EC26	New York Stock Exchange
6.875% Notes due 2030	EC30	New York Stock Exchange
4.625% Notes due 2031	EC31	New York Stock Exchange
8.875% Notes due 2033	EC33	New York Stock Exchange
7.375% Notes due 2043	EC43	New York Stock Exchange
5.875% Notes due 2045	EC45	New York Stock Exchange
5.875% Bonds due 2051	EC51	New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

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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.

⌧ Yes ◻ No

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).

⌧ Yes ◻ No

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

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Table of Contents

	Page
1. Introduction	1
1.1 About This Annual Report	1
1.2 Forward-looking Statements	2
1.3 Selected Operating Data	3
2. Strategy and Market Overview	3
2.1 Our Corporate Strategy	5
2.1.1 2040 Strategy: Energy that Transforms	5
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	6
2.1.1.4 Competitive Returns	6
2.1.2 2023 Investment Plan	6
3. Business Overview	8
3.1 Our History	8
3.2 Our Corporate Structure	9
3.3 Recent Developments	11
3.4 Our Business	12
3.5 Exploration and Production	12
3.5.1 Exploration Activities	12
3.5.1.1 Exploration Activities in Colombia	13
3.5.1.2 Exploration Activities Outside Colombia	15
3.5.2 Production Activities	18
3.5.2.1 Production Activities in Colombia	18
3.5.2.1.1 Ecopetrol S.A.’s Production Activities in Colombia	18
3.5.2.1.2 Ecopetrol S.A.’s Affiliates and Subsidiaries’ Production Activities in Colombia	25
3.5.2.2 Production Activities Outside Colombia	28
3.5.2.3 Unconventional Hydrocarbons	31
3.5.2.4 Marketing of Crude Oil and Natural Gas	32
3.5.3 Reserves	34
3.5.4 Joint Venture and Other Contractual Arrangements	43
3.6 Transportation and Logistics	46
3.6.1 Transportation Activities	46
3.6.1.1 Pipelines	49
3.6.1.2 Export and Import Facilities	53
3.6.2 Other Transportation Facilities	53
3.6.3 Marketing of Transportation Services	54
3.7 Refining and Petrochemicals	55
3.7.1 Refining	55
3.7.1.1 Barrancabermeja Refinery	56
3.7.1.2 Cartagena Refinery	57
3.7.1.3 Esenttia S.A.	58
3.7.1.4 Invercolsa	58
3.7.1.5 Biofuels	58
3.7.2 Marketing and Supply of Refined Products	58
3.8 Electric Power Transmission and Toll Roads Concessions	59
3.8.1 ISA	59
3.8.2 Electricity Transmission Activities	59
3.8.2.1 Electricity Transmission Activities in Colombia	60
3.8.2.2 Electricity Transmission Activities Outside Colombia	61
3.8.3 Toll Roads Concessions Activities	61
3.8.4 Telecommunications and ICT	62
3.9 Research and Development; Intellectual Property	62
3.10 Applicable Laws and Regulations	63
3.10.1 Regulation of Exploration and Production Activities	63
3.10.1.1 Business Regulation	63
3.10.1.1.1 Environmental Licensing and Prior Consultation	67
3.10.1.1.2 Royalties	69
3.10.2 Regulation of Transportation Activities	69
3.10.3 Regulation of Refining and Petrochemical Activities	71
3.10.3.1 Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels	72
3.10.3.2 Regulation Concerning Production and Prices	72

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3.10.3.3 Regulation of Biofuels, Biogas and Related Activities	74
3.10.4 Regulation of the Natural Gas Market	75
3.10.5 Regulation of the Electric Energy Commercialization Activity	76
3.10.6 Regulation of the Electricity Self-Generation Activity	78
3.10.7 Regulatory Framework for Energy Transmission	80
3.10.8 Regulation of the Toll Roads Concessions	82
3.11 Technology, Environment, Social and Governance (TESG)	84
3.11.1 Energy Initiatives	89
3.11.2 HSE	90
3.11.2.1 Ecopetrol S.A.	90
3.11.2.2 Cenit	95
3.11.2.3 Cartagena Refinery	95
3.11.2.4 ISA	96
3.12 Related Party and Intercompany Transactions	96
3.13 Insurance	102
3.13.1 Downstream, Upstream, and Midstream	102
3.13.2 Electric Power Transmission and Toll Roads Concessions	105
3.14 Human Resources/Labor Relations	106
3.14.1 Employees	106
3.14.2 Collective Bargaining Arrangements	108
4. Financial Review	109
4.1 Factors Affecting Our Operating Results	109
4.2 The COVID-19 Pandemic	113
4.3 Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results	114
4.3.1 Taxes	114
4.3.2 Exchange Rate Variation	118
4.3.3 Effects of Inflation	119
4.3.4 Effects of Crude Oil and Refined Product Prices	119
4.4 Accounting Policies	120
4.5 Critical Accounting Judgments and Estimates	120
4.6 Operating Results	120
4.6.1 Consolidated Results of Operations	120
4.6.1.1 Total Revenues	121
4.6.1.2 Cost of Sales	122
4.6.1.3 Operating Expenses before Impairment of Non-Current Assets Effects	124
4.6.1.4 Impairment of Non-Current Assets	125
4.6.1.5 Finance Results, Net	126
4.6.1.6 Income Tax	127
4.6.1.7 Net Income (Loss) Attributable to Owners of Ecopetrol	127
4.6.1.8 Segment Performance and Analysis	128
4.6.1.9 Exploration and Production Segment Results	129
4.6.1.10 Transportation and Logistics Segment Results	132
4.6.1.11 Refining and Petrochemicals Segment Results	133
4.6.1.12 Electric Power Transmission and Toll Roads Concessions Segment Results	135
4.7 Liquidity and Capital Resources	135
4.7.1 Review of Cash Flows	136
4.7.2 Capital Expenditures	137
4.7.3 Dividends	137
4.8 Summary of Differences between Internal Reporting Policies (Colombian IFRS) and IFRS	137
4.9 Financial Indebtedness and Other Contractual Obligations	139
4.10 Off Balance Sheet Arrangements	142
4.11 Trend Analysis and Sensitivity Analysis	142
5. Risk Review	145
5.1 Risk Factor Summary	145
5.2 Risk Factors	148
5.2.1 Risks Related to Our Business	148
5.2.2 Risks Related to Colombia and the Region’s Political and Regional Environment	163
5.2.3 Legal and Regulatory Risks	169
5.2.4 Risks Related to Our ADSs	173
5.2.5 Risks Related to the Controlling Shareholder	176
5.3 Risk Management	176
5.3.1 Integrated Risk Management System and Internal Control System	176
5.3.2 Managing Low Carbon Economy and Climate Change Risks	178
5.3.3 Managing Information Security and Cybersecurity	178

iii

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5.3.4 Managing Financial Risk	179
5.4 Legal Proceedings and Related Matters	182
6. Shareholder Information	191
6.1 Shareholders’ General Assembly	191
6.2 Dividend Policy	192
6.3 Market and Market Prices	193
6.4 Description of Ecopetrol Registered Debt Securities	193
6.5 Description of Ecopetrol ADRs	194
6.6 Taxation	195
6.6.1 Colombian Tax Considerations	195
6.6.2 U.S. Federal Income Tax Consequences	199
6.7 Exchange Controls and Limitations	202
6.8 Exchange Rates	203
6.9 Major Shareholders	203
6.10 Enforcement of Civil Liabilities	204
7. Corporate Governance	205
7.1 Bylaws	208
7.2 Code of Ethics and Conduct	211
7.3 Board of Directors	212
7.3.1 Board Practices	217
7.3.2 Board Committees	218
7.4 Compliance with NYSE Listing Rules	220
7.5 Management	221
7.6 Compensation of Directors and Management	225
7.7 Share Ownership of Directors and Executive Officers	226
7.8 Controls and Procedures	226
8. Financial Statements	228
9. Signature Page	230
10. Exhibits	231
11. Cross-reference to Form 20-F	233

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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 in this annual report relate to the Republic of Colombia (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, 2020, 2021, and 2022 were prepared in accordance with IFRS 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 companies, 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 4,257.12 per USD 1.00, which corresponds to the average Tasa Representativa del Mercado (TRM), or Representative Market Exchange Rate, for 2022. 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 25, 2023, the Representative Market Exchange Rate was COP 4,741.76 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.

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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:

●

changes in international crude oil and natural gas prices;

●

our exploration and production activities, including drilling; and import and export activities;

●

our liquidity, cash flow, and sources of funding;

●

the results of our electric power transmission and toll roads activities through our subsidiary, Interconexión Eléctrica S.A. (“ISA”) and our ability to continue to integrate ISA’s operations;

●

our projected and targeted capital expenditures and other cost commitments and revenues; and

●

dates by which certain areas will be developed or will come on-stream; and

●

future growth and development of the energy industry and its transition into lower carbon sources of energy.

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:

●

general economic and business conditions, including increased and prolonged inflation in Colombia and worldwide, volatility in crude oil and other commodity prices, refining margins and prevailing exchange rates;

●

competition;

●

our ability to obtain financing;

●

our ability to find, acquire or gain access to additional reserves and our ability to develop existing reserves;

●

uncertainties inherent in making estimates of our reserves;

●

the modification, adjustment or reduction of the tariffs, rates or fees charged by the electricity transmission businesses in the countries where they operate;

●

significant political, economic and social developments in Colombia and other countries where we do business;

●

natural disasters, pandemics and other public health events, including the coronavirus (“COVID-19”) pandemic;

●

the continuing Russian invasion of Ukraine;

●

other military operations, terrorist acts, wars or embargoes;

●

regulatory developments, including regulations related to climate change;

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●

receipt and maintenance of government approvals and licenses;

●

technical difficulties; and

●

other factors discussed in section Risk Review—Risk Factors of this document as “Risk Factors.”

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	2022		2021		2020		2019		2018
Oil and gas production (mboed)	709.5		679.0		697.0		725.1		720.4
Proved oil and gas reserves (mmboe)⁽¹⁾	2,011		2,002		1,770		1,893		1,727
Exploratory wells⁽²⁾⁽³⁾	29		16		18		20		17
Refinery throughput (bpd)⁽⁴⁾	360,451		355,895		322,038		375,754		375,666
1P Reserves replacement ratio	104	%	200	%	48	%	169	%	129	%
Transmission Lines (km)	48,766		48,330		47,358		46,374		45,142

(1)	Include natural gas royalties and exclude crude oil royalties.

(2)	Gross exploratory wells.

(3)

The table does not include stratigraphic wells. Although these wells are considered to be exploratory wells, we do not include them as part of our exploratory wells information in the table above as these wells are plugged and abandoned after the relevant study is completed. The table includes wells drilled by partners at sole risk.

(4)	Includes the Barrancabermeja, Cartagena, Apiay and Orito refineries.

2.	Strategy and Market Overview

Global oil demand increased significantly in 2022, characterized by a higher Brent price during 2022 as compared to 2021.

On the demand front, while concerns about COVID-19 variants negatively affected the price of crude oil during early 2022, such concerns were mitigated as a result of the phase-out of COVID-19 related restrictions. During the second half of the year, however, demand was negatively affected by inflationary pressures and high fuel prices, which weakened consumption. In this regard, and in an attempt to manage inflationary pressures, central banks around the world embarked on an upward interest rate cycle that negatively impacted the economic outlook and activity. Additional factors which affected demand included high natural gas prices in Europe and China’s “zero-COVID” policy. In the case of China, oil consumption decreased significantly during 2022 to the lowest levels in recent years. This decline in demand during the second half of 2022 led members of the Organization of Petroleum Exporting Countries (“OPEC”), and ten of the world’s major non-OPEC oil-exporting countries including Russia (“OPEC+”), to announce a production cut of 2 mmbd (million barrels per day) in October, to mitigate further deterioration in oil prices.

On the supply front, the Brent price remained elevated partly due to Russia’s continued full-scale military invasion of Ukraine and actions taken by OPEC. Russia’s invasion of Ukraine, and the sanctions and penalties imposed on Russia by the United States and Europe have led to many buyers’ reluctance to purchase crude-oil and refined products from Russia. These factors, along with the prospects of a lower Russian crude oil supply, fueled an increase in Brent prices from 86 USD/Bl in January 2022 to 118 USD/Bl in June 2022. Similarly, during 2022, production by OPEC countries stood below the agreed quotas and production by non-OPEC countries grew very slowly, consistent with the strict capital discipline that has characterized the industry over the last few years. Accordingly, geopolitical factors played a crucial role in the Brent price volatility in 2022, as the market prepared for slight build-up of global inventories, with average supply estimated at 101.2 mmbd, or 0.7 mmbd above demand during 2022. As a result, for 2022, the Brent averaged 99 USD/Bl, far exceeding the 71 USD/Bl average during 2021.

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The table 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: Platts, Bloomberg

Regarding refined products in 2022, global demand continued to recover as a result of the phase-out of COVID-19 related restrictions, and as a consequence of Russia’s continued full-scale military invasion of Ukraine. In this regard, historical figures were observed in U.S. “cracks” products, such as gasoline (Crack 29 USD/Bl vs. Brent), ultra-low-sulfur diesel (Crack 83 USD/Bl vs. Brent) and jet fuel (Crack 64 USD/bl vs. Brent).

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 Colombia.

The Colombian economy, as measured by GDP, grew at a rate of 7.5% in 2022, one of the highest in the region, despite exhibiting a slight deterioration as compared to the 10.6% growth rate in 2021. During 2022, GDP growth was mainly driven by an increase in private consumption, which expanded at a rate of 9.5%, with more than 1.6 million jobs added in 2022. Investment spending also contributed favorably to GDP, with growth averaging 11.8% in 2022. In contrast, the external sector contributed negatively to GDP growth, with imports growing much faster than exports (23.9% vs. 14.9%, respectively, in 2022), widening the current account deficit and weakening the exchange rate.

Local sales of refined products increased 13% in 2022 compared to 2021, mainly explained by strong gasoline and jet fuel sales and increased demand. In 2022, jet fuel demand jumped 40%, while diesel and gasoline demand grew 13% and 12%, respectively, compared to 2021, primarily driven by the loosening of the COVID-19-related mobility restrictions and a buoyant economic recovery, which surpassed pre-pandemic levels, and also by the effect of ethanol blends on the price of gasoline, which further boosted its demand. Overall, Colombia’s demand for refined products reached 343 kbd (thousand barrels per day) in 2022, exceeding pre-pandemic levels.

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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”, being the first company in the oil and gas industry in Latin America to disclose a roadmap for the next 20 years. The 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 that participates in all segments of the hydrocarbon chain (upstream, midstream, downstream and commercialization) as well as energy infrastructure, with the ambition to diversify into low-emission businesses that allow us to continue reducing our carbon footprint and achieve net-zero carbon emissions (scopes 1 and 2) and a 50% reduction in total emissions (scopes 1, 2 and 3), all 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 strategy is based on the following oil price assumptions: (i) for the 2023 – 2025 Plan: USD 80/Bl, and (ii) for the long-term plan: 2025 – 2040: USD 45 – 55 /Bl. Within this context, the main long-term objectives are presented below.

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 in the decarbonization and diversification strategy of low-emission businesses. This pillar aims to maintain the Ecopetrol Group’s competitiveness in the integrated hydrocarbon value chain and increasing gas supply, offshore exploration, enhanced recovery, and the development of unconventional reservoirs, 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 USD 5.2 and USD 6.0 billion annually by 2040. In production, investment is expected to be focused on enhanced recovery technologies, new activity in the Piedemonte Llanero region, 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 that begins at 20 USD/tCO2e today and reaches 40 USD/tCO2e by 2030.

In the upstream segment, we expect to reach between 800 and 850 thousand barrels of oil equivalent per day (“mboed” or “mmboed”) of production by 2030, even under conservative price scenarios (i.e., using a Brent price range of between USD 45 - 55/Bl).

In terms of gas, production is expected to increase, along with new commercialization options, with a 33% participation target of total production by 2040. The latter is expected, among others, to maintain market share in Colombia at 78% for gas and 77% for Liquefied Petroleum Gas (“LPG”).

In the midstream segment, the long-term objectives of the segment include, among others, capturing over 90% share of the Colombian hydrocarbon transport market.

The downstream 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 on green 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 electric power transmission business, represented by ISA, responds competitively to the challenges of decarbonization and diversification and satisfies new demands in the context of the energy transition.

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For the electric power transmission and toll roads concessions segment, the aim is to continue the growth trajectory in both new and existing geographies, taking advantage of ISA’s strategic leadership position in the power transmission business in Latin America, in line with ISA’s 2030 Strategic Plan.

The diversification towards low-emission businesses in the long term contemplates: (i) between 2019 and 2030 carry out investments of USD 8.3 billion in current businesses and geographies and USD 2.2 billion in new geographies, and (ii) having non-conventional renewable energies achieve a share of between 25% and 40% in our self-generation matrix by 2040.

The aforementioned is expected to be supported by a gradual incursion into emerging businesses that are aligned with new global trends that seek to mitigate the effects of climate change, such as the production of low-carbon hydrogen as an energy source, Carbon Capture, Utilization, and Storage (“CCUS”), and Natural Climate Solutions (“NCS”). The value proposition includes diversifying into low-emission businesses, for which more than USD 200 million are expected to be invested over the next three years, in green hydrogen projects in the Cartagena and Barrancabermeja refineries, and in CO2 capture projects through both emerging technologies and NCS projects.

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 act as catalysts to accelerate solutions for future challenges. To achieve this, the Ecopetrol Group has identified five strategic lines: (i) build and generate value through an efficient, clean and safe production, (ii) accelerate and prioritize decarbonization 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, with a focus on inclusion and on reactivating local economies.

Environmentally, the long-term TESG targets include the achievement of: (i) net-zero emissions of CO2 equivalent by 2050 (scopes 1 and 2), (ii) zero routine gas flaring by 2030, (iii) 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.

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 (CT+i for its acronym in Spanish), 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 by means of training programs to optimize performance (upskilling) or fill new positions (reskilling).

Thus, the expected long-term goals are, among others: (i) having approximately 70% of workers complete reskilling programs by 2030, and (ii) achieving automation of 100% of human talent processes by 2030.

2.1.1.4

Competitive Returns

Finally, 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 at between 40% and 60%, in line with operating results. The long-term strategy will allow transfers to the Nation between USD 3.4 and USD 5.3 billion annually on average, through royalties, taxes, and dividends.

2.1.2

2023 Investment Plan

On December 9, 2022, the Board of Directors approved the 2023 investment plan (the “2023 Investment Plan”), which contemplates a budget of between USD 5.6 and USD 6.6 billion.

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The 2023 Investment Plan continues to be aligned with the four strategic pillars of its 2040 Strategy position and aimed at supporting the Group’s commitment to Colombia’s energy self-sufficiency, as well as to accelerate the path toward energy transition, while maintaining competitive returns for all its stakeholders. The assumptions under the 2023 Investment Plan are, among others, a Brent price of USD 80/Bl and an exchange rate of COP 4,500/USD. The 2023 Investment Plan is expected to be financed mainly with internal cash generation, collection of accounts receivable from the Fuel Price Stabilization Fund (Fondo de Estabilización de Precios de los Combustibles or “FEPC” for its acronym in Spanish), and marginal leverage compliant with a gross debt to EBITDA ratio lower than 2.1. This plan could be subject to revisions during 2023 based on the evolution of these assumptions.

Hydrocarbons

During 2023, the Ecopetrol Group expects to invest approximately USD 4.3 billion in production and exploration of hydrocarbons. The Ecopetrol Group expects to achieve organic production of between 720 thousand and 725 thousand barrels of oil equivalent per day in 2023, corresponding to 76% oil and 24% gas and natural gas liquids. These investments are primarily focused on improved recovery projects that maximize existing resources and offset the natural decline of the fields.

Exploration and production projects are expected to be primarily located in the Piedemonte, Llanos, North Colombia, Middle and Upper Magdalena Valley, Permian and Caribbean offshore.

The investments in the midstream business represent 5% (USD 0.4 billion) of the 2023 investment plan and are primarily focused on integrity and reliability projects as well as on the expansion of the existing multi-purpose pipeline infrastructure.

Finally, investments in the downstream business represent 7% (USD 0.5 billion) of the 2023 investment plan. The funds are expected to ensure the reliability, availability and sustainability of the Cartagena and Barrancabermeja refineries.

Low Carbon Solutions

In 2023, investments in gas projects are expected to range between USD 800 and USD 900 million and produce around 174 to 177 thousand barrels of oil equivalent per day (includes natural gas and natural gas liquids).

In 2023, the Ecopetrol Group also expects to advance low carbon hydrogen projects in the Barrancabermeja and Cartagena refineries as well as to develop solar energy farms in existing assets such as the Cira Infantas, Casabe and Cantagallo oil fields as well as the Cartagena and Barrancabermeja refineries, among others. These projects are in furtherance with the Business Plan’s goals for this business line.

Transmission and Toll Roads Concessions

The 2023 investment plan allocates approximately USD 1.4 billion for electric power transmission and toll roads concessions purposes, of which, consistent with the Business Plan, approximately 86% are expected to support the energy transmission business in the development of energy transmission lines.

In addition to the previously mentioned business segments, the 2023 investment plan includes USD 105 million in social investments to strengthen our commitment to local communities through support for the construction of 240 kilometers of tertiary roads, education access for 90,000 students, access to drinking water for 16,000 inhabitants and providing 13,000 new home gas users, among others.

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The table below sets forth the details of the investment plan per business segment announced in December 2022:

Table 2 – 2023 Investment Plan


Business Segment	% Percentage⁽¹⁾
Exploration	11	%
Production	54	%
Midstream	5	%
Downstream	7	%
Electric Power Transmission and Toll Roads	21	%
Other	2	%
TOTAL	100	%

(1)	Percentage over the upper range.

The Company is currently updating its three-year plan (2023 – 2025 Business Plan), which will be timely disclosed to the market in compliance with its disclosure obligations.

3.	Business Overview

3.1

Our History

We were formed 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, and 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 were transformed into a governmental, industrial, and commercial company.

In 2003, pursuant to Decree Law 1760, 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 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 carried out 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 carried out a follow-on public offering in Colombia in August 2011.

In June 2012, Cenit Transporte y Logística de Hidrocarburos S.A.S. (“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.

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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 ecopark in Meta, with an installed capacity of more than 20MW 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.

3.2

Our Corporate Structure

We are currently organized into five corporate operational divisions: (i) Exploration and Production; (ii) Transportation and Logistics; (iii) Refining, Petrochemicals and Biofuels; (iv) Sales and Marketing, and (v) Electric Power Transmission and Toll Roads Concessions. However, as discussed above in Our Corporate Strategy—2023 Investment Plan, given the recent transformation of our Company with the ISA acquisition and in line with our 2040 Strategy, we have started a process to align our current segments more closely to the vision of the 2040 Strategy for the Ecopetrol Group.

In the above regard, for operational purposes, we are in the process of realigning our corporate operational divisions to the following: (A) Hydrocarbons, which includes the Exploration and Production, Transportation and Logistics, Refining and Petrochemicals; (B) Low Emissions Solutions, which includes natural gas, biogas, LPG, power, renewables, hydrogen and CCUS; and (C) Transmission and Toll Roads. However, for purposes of this annual report, we continue to present our operational and financial reporting information under the prior business lines. We expect our annual report for the fiscal year ended December 31, 2023 to reflect the new operational business lines and new financial reporting segmentation to align with such business lines. Thus, investors should be aware that starting with next year’s annual report on Form 20-F our operational and financial segments will differ from those presented in this annual report and our historical reports.

Our subsidiaries, Refinería de Cartagena S.A.S. (“Reficar” or “Cartagena Refinery”), Cenit, ISA, Ecopetrol Trading Asia Pte Ltd. (“Ecopetrol Trading Asia”), Esenttia S.A., Ecopetrol Permian LLC (“Permian”), and Oleoducto Central S.A. (“Ocensa”)¹ are significant subsidiaries, as such term is defined under SEC Regulation S-X.

We have several directly and indirectly held subsidiaries both in Colombia and abroad. As of February 28, 2023, we have twelve directly owned and 60 indirectly owned subsidiaries.

In 2022, the Ecopetrol Group’s corporate structure changed as follows:

●

In July 2022, ISA Inversiones Chile incorporated the company Conexión Kimal Lo Aguirre, together with Transelec and China Southern Power Grid International (CSG) as shareholders.

●

In November 2022, with the purpose of capturing optimizations, ISA CTEEP created three new companies in Brazil: IEJ6 Interligação Elétrica Jaguar 6 S.A., IEJ6 Interligação Elétrica Jaguar 8 S.A. and IEJ6 Interligação Elétrica Jaguar 9 S.A.

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●

On November 16, 2022, we incorporated Ecopetrol US Trading LLC, a wholly owned subsidiary indirectly owned by the Company 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 December 12, 2022, the shareholders of Concentra Inteligencia en Energía S.A.S. decided to liquidate the company and as a result, the liquidation process is ongoing.

●

On December 23, 2022, Esenttia S.A. acquired Topili Servicios Administrativos S.R.L. de C.V. Following this acquisition, Esenttia S.A. changed its bylaws, corporate purpose and was renamed Esenttia Resinas de México, S.R.L. de C.V.

●

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.

The table below sets forth our corporate structure as of March 30, 2023:

Graph 2 – Ecopetrol’s Corporate Structure

The stock ownership percentage listed next to each entity refers to Ecopetrol S.A.’s direct and indirect participation therein as of March 30, 2023. 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.

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As we seek to execute our 2040 Strategy, the Ecopetrol Group is working to re-align its current segments to the business lines defined in the 2040 Strategy and its work in the field of energy transition. In that regard, for operational purposes, we are in the process of realigning our corporate operational divisions from Exploration and Production, Transportation and Logistics, Refining, Petrochemicals and Biofuels, and Sales and Marketing, to the following: (i) Hydrocarbons, which includes the Exploration and Production, Transportation and Logistics, Refining and Petrochemicals, (i) Low Emissions Solutions, which includes exploration, production and commercialization of gas, biogas, LPG, power, renewables, hydrogen, and Carbon Capture, Utilization and Storage (CCUS), and (iii) Energy Transmission and Toll Roads, while maintaining Sales and Marketing as a cross-sectional front. For purposes of this annual report, we continue to present our operational information under our traditional business lines. We expect to reflect the new business lines at the operational and financial level in the 2023 annual report.

In this regard, we are working to re-align all entities in Ecopetrol’s corporate structure under the aforementioned business lines. The following would be the main companies integrating each business line: (A) Hydrocarbons: Ecopetrol S.A., Ecopetrol Óleo e Gás do Brasil Ltda. (“Ecopetrol Brasil”), Ecopetrol America LLC (“Ecopetrol America”), Ecopetrol USA Inc. (“Ecopetrol USA”), Hocol S.A. (“Hocol”), Cenit, Ocensa, Cartagena Refinery and Esenttia S.A. (“Esenttia”); (B) Low Emissions Solutions: Ecopetrol S.A. and Inversiones de Gases de Colombia S.A. (“Invercolsa”); and (C) Transmission and Toll Roads: Interconexión Eléctrica S.A, ISA Intercolombia S.A. E.S.P. (“Intercolombia”), Intervial Chile S.A. (“Intervial Chile”), Intervial Colombia S.A.S. (“Intervial”), Transelca S.A. (“Transelca”), and Internexa S.A. (“Internexa”).

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).

Additionally, as of June 2022 and in order to respond to the Ecopetrol Group's 2040 strategy, a new operating model was approved for the Upstream (Exploration and Production), which seeks to ensure an integrated vision of the segment, give greater autonomy to the regions and achieve better integration and synergies with the subsidiaries.

The new structure of the segment concluded in the creation of the Upstream Vice-presidency, which in turn oversees the following areas: Upstream’s Excellence and Competitiveness, and Upstream’s Planning and Performance, and the following Vice-presidencies: Development, and Projects; Subsidiaries and Assets with Partners; Exploration; Central Region; Orinoquía Region; East -Andean Region; Piedemonte Region; and Offshore.

3.3

Recent Developments

Ecopetrol Trading Asia

Ecopetrol Trading Asia (ECPTA), our subsidiary in Singapore, began operations in March 2022 and has allowed us to consolidate exports of our crudes and strengthen new relationships with clients in the Asian market and generate additional value for Ecopetrol in trading operations. This subsidiary generated a revenue of 3.7 billion dollars and an EBITDA of 61.7 million dollars for the sale of 42 million barrels of crude oil in its first year of operation

Public Debt Offering

On January 13, 2023, Ecopetrol S.A. issued USD 2,000,000,000 in 8.875% notes due 2033. The net proceeds of the issuance were used to prepay the remaining outstanding principal amount under the loan agreement use to finance the ISA acquisition and for general corporate purposes. See section Business Overview—Related Party and Intercompany Transactions—ISA Acquisition). The notes are listed on the New York Stock Exchange.

Tender Offer

On January 17, 2023, Ecopetrol S.A. launched a tender offer for cash to purchase up to USD 1,000,000,000 in aggregate principal amount of its 5.875% senior notes due 2023. The tender offer expired on February 13, 2023. The tendered notes were cancelled and following the cancellation of the Notes, the outstanding aggregate principal amount of the Company’s 5.875% senior notes due 2023 is USD 821,476,000.

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Management

On January 26, 2023, we announced that our current Chief Executive Officer, Felipe Bayón Pardo, will step down from the Company on March 31, 2023.

On March 24, 2023, the Board of Directors appointed Alberto Consuegra Granger as interim CEO of Ecopetrol S.A. effective from April 1, 2023, and until the date on which the successor to Felipe Bayón Pardo is appointed.

To date, the Board of Directors, with the support of the Nomination, Compensation, and Culture Committee and the advice of an international headhunter firm, continues to advance the selection process of the new CEO in accordance with the Succession Policy of the CEO of Ecopetrol S.A. See section Management.

3.4

Our Business

We are the largest company in Colombia and one of the most relevant integrated energy companies in Latin America, with a presence primarily in Colombia and activities in the U.S. (U.S. Gulf of Mexico and Permian Basin), Brazil, Mexico, Peru, Chile and Bolivia. In Colombia, we are responsible for more than 60% of the hydrocarbon production, transportation, logistics, and hydrocarbon refining systems, and hold a leading position in the petrochemicals and gas distribution segment. Through ISA, we have a strong position in the electric power transmission business, toll roads and telecommunications sectors throughout Latin America. The Nation currently owns 88.49% of our voting capital stock. We are among the world’s largest public companies, ranking 296 on the Forbes 2022 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. We began local exploration in 1955 and international exploration in 2006. Exploration and production activities 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, 2022, 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 2022, our exploration strategy was focused on three working fronts: Colombian onshore, Caribbean offshore, and overseas.

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 offshore Brazil in pre-salt and post-salt Santos and Campos basins and the Deepwater basin in the U.S. Gulf of Mexico.

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Graph 3 – Sedimentary Basins where Ecopetrol Executes Exploration Activities

3.5.1.1

Exploration Activities in Colombia

In 2022, Ecopetrol S.A. and its subsidiaries drilled 28 wells in Colombia, out of which 23 were exploratory (A3/A2) and five were appraisal (A1) wells. Additionally, we drilled one stratigraphic well. As of December 31, 2022, 8 wells were successful, 12 were dry, 8 were under technical evaluation and 1 stratigraphic well was plugged and abandoned. It should be noted that 6 of these wells correspond to activity operated at the exclusive risk of partners. This drilling activity was concentrated in basins of interest around Colombia, including the Caribbean offshore, Llanos, the Lower, Middle and Upper Magdalena Valley, Sinú-San Jacinto and Putumayo.

The 8 successful wells drilled by Ecopetrol S.A. and its partners in Colombia during 2022 were:

●

(i) El Niño-2 well, in which Ecopetrol S.A. holds a 50% working interest, CNOOC holds a 20% and Perenco Colombia Limited holds the remaining 30% and acts as operator through the Boqueron Contract, (ii) Tejón-1 well, in which Ecopetrol S.A. holds a 55% working interest and acts as operator, and Repsol holds the remaining 45%, through the CPO-9 Contract, (iii) Morito-1 well, in which Ecopetrol S.A. holds a 100% working interest, through the Magdalena Medio Exploitation Agreement, (iv) Gorgón-2 well, composed of Gorgón-2 ST1 (pilot well) and Gorgón 2-ST2, in which Ecopetrol S.A. holds a 50% working interest, and Shell holds the remaining 50% and acts as operator through the Col-5 offshore E&P contract, (v) Uchuva-1 well, in which Ecopetrol S.A. holds a 55.56% working interest and Petrobras holds the remaining 44.44% and acts as operator through the Tayrona offshore contract, (vi) Fidalga-1 ST2 well, in which Ecopetrol holds a 20% working interest and Parex Resources holds the remaining 80% working interest and acts as operator, drilled at Parex Resources’ sole risk, through the Fortuna Association contract, (vii) Coralino-1 well, in which Ecopetrol holds a 100% working interest, through its subsidiary Hocol S.A. (“Hocol”), through the VIM 8 Contract, and (viii) Ibamaca-2 ST well, in which Ecopetrol holds a 100% working interest, through its subsidiary Hocol, through the Tolima Exploitation Agreement.

●

Gas discoveries in Gorgón-2 and Uchuva-1 wells confirmed deep-water gas potential in offshore Colombia. Notwithstanding the successful results, both wells were plugged and abandoned, to comply with the regulations of the Ministry of Mines and Energy which require that wells which are not under production must be plugged to prevent the loss of their integrity.

The following table sets forth, for the periods indicated, the number of gross and net productive, dry, and under evaluation exploratory wells drilled by us and by our joint venture partners, and the exploratory wells drilled by third parties pursuant to sole risk contracts with us.

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Table 3 – Exploratory Drilling in Colombia


	For the year ended December 31,
	2022	2021	2020

	(Number of wells)
COLOMBIA
Ecopetrol S.A.
Gross exploratory wells
Owned and operated by Ecopetrol
Productive	1.00	2.00	—
Dry⁽¹⁾	1.00	1.00	2.00
Under Evaluation⁽²⁾	1.00	—	1.00
Total	3.00	3.00	3.00
Operated by a partner in Joint Venture
Productive	3.00	1.00	—
Dry⁽¹⁾	2.00	2.00	—
Under Evaluation⁽²⁾	1.00	1.00	1.00
Total	6.00	4.00	1.00
Operated by Ecopetrol in Joint Venture
Productive	1.00	—	—
Dry⁽¹⁾	—	—	—
Under Evaluation⁽²⁾	1.00	—	2.00
Total	2.00	—	2.00
Net Exploratory Wells⁽³⁾
Productive	3.10	2.50	—
Dry⁽¹⁾	2.00	2.00	2.00
Under Evaluation⁽²⁾	1.75	0.48	2.50
Total	6.85	5.00	4.50
Sole Risk
Productive	1.00	—	1.00
Dry⁽¹⁾	3.00	1.00	1.00
Under Evaluation⁽²⁾	2.00	3.00	3.00
Total	6.00	4.00	5.00
Hocol
Gross Exploratory Wells
Productive	2.00	—	1.00
Dry⁽¹⁾	6.00	—	2.00
Under Evaluation^(2)(4)(5)	3.00	3.00	2.00
Total	11.00	3.00	5.00
Net Exploratory Wells⁽³⁾
Productive	2.00	—	1.00
Dry⁽¹⁾	5.50	—	2.00
Under Evaluation⁽²⁾⁽⁴⁾	2.50	2.50	1.00
Total	10.00	2.50	4.00

(1)	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.

(2)

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 carried out to determine the hydrocarbon production capacity or some petrophysical parameter of the rocks or fluids in the reservoir.

(3)	Net exploratory wells were calculated according to our percentage of ownership in these wells.

(4)	Yoda A-1 and Tororoi-1 are under evaluation. Nevertheless, in 2022, Hocol recognized a write off for the value of a portion of both wells due to the abandonment resulting from a deeper exploratory target.

(5)	The Arrecife Norte-1 well was classified as “under evaluation” for the year ended December 31, 2022. However, as of March 2023, it has been declared successful well drilling, confirming gas presence.

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Note:

The table does not include stratigraphic wells. Although these wells are considered to be exploratory wells, we do not include them as part of our exploratory wells’ information in the table above as these wells are plugged and abandoned after the relevant study is completed.

In March 2022, Parex Resources and Ecopetrol entered into an addendum to the Farm-Out Agreement for the Capachos asset located in the department of Arauca in the Llanos basin, in which Ecopetrol and Parex each have a 50% stake. The agreement contemplates investments in the second exploratory phase which is expected to extend productive horizons of oil and gas and enable the possibility of incorporating new reserves from this asset.

In May 2022, Ecopetrol and Anadarko Colombia Company (“Anadarko”), a subsidiary of Occidental Petroleum, entered into a joint exploration agreement for blocks COL 1, COL 2, COL 6 and COL 7, located in deep waters in the northeast of the Colombian Caribbean. Ecopetrol holds a 40% stake in the exploration and production rights and Anadarko as operator of the blocks, holds the remaining 60%. The agreement has been formalized by the ANH.

In August 2022, Hocol and Lewis Energy Colombia (“LEC”) entered into a joint exploration agreement for E&P blocks SSJN 3-1 and VIM-42, located in the Colombia Norte areas of the Sinú-San Jacinto Basin and Lower Magdalena Valley, respectively. Each of Hocol and LEC holds a 50% participation, and LEC acts as operator. The agreement has been formalized by the ANH.

Additionally, the ANH approved the partial assignment by Petrobras, to Ecopetrol S.A., of rights, interests, and obligations of the Exploration and Exploitation Tayrona Orca contract (which is part of the ORCA Assessment Program), resulting in Ecopetrol S.A. becoming the sole owner and operator of the contract.

Seismic

In Colombia, during 2022, Ecopetrol purchased 2,639 km2 of 3D seismic information in the Llanos Orientales to improve its technical understanding of this prolific basin. Ecopetrol also began the Flamencos 3D program in the Middle Magdalena Valley, which consists in the acquisition of 311 km2 of 3D seismic information. By the end of 2022 the Flamencos 3D program had made important advances in topography and drilling and is expected to be completed during the first semester of 2023.

In addition, in 2022, Ecopetrol S.A. reprocessed and re-analyzed 4,262 km2 of 3D seismic information and 4,856 km of 2D seismic information, and purchased the reprocesses (PSTM&PSDM) above 52,000 km of Colombia's Vintage Offshore 2D Seismic Data through the ION-ANH Multiclient Project, with the purpose of improving subsurface imaging. This has allowed us to continue identifying and evaluating the potential of certain basins and to mature the existing prospects within the Company’s portfolio.

During 2022, Hocol started the 2D seismic program of 210 km across the SSJN-1 and Perdices (northern area) blocks, in which each of Hocol and LEC hold a 50% working interest, and RC-7 block, in which Hocol holds a 100% working interest. By the end of 2022, this program was in the phase of permitting and communication to main stakeholders. The recording phase is expected to be finalized in 2023. In terms of seismic data purchased from the national databank, Hocol purchased 923 km² of 3D and 472 Km of 2D data across different geographic areas of interest, from the Llanos basin to northern Colombia. Regarding seismic reprocessing, Hocol reprocessed 536 km² of 3D and 95 km of 2D data on its areas of interest.

3.5.1.2

Exploration Activities Outside Colombia

Our international exploration strategy is focused on basins with high materiality, aiming at mitigating our risk exposure and ultimately increasing our reserves. This strategy is supported by an efficient, business-oriented portfolio management, which involves the 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.

In the central area of the Gulf of Mexico, our subsidiary Ecopetrol America participated in the Chevron operated Starman-1 well. The well reached total depth in October, encountered hydrocarbon volumes below Ecopetrol America’s threshold for standalone development, and was permanently plugged and abandoned. The parties are still evaluating the results.

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In Brazil, Ecopetrol, through its subsidiary, Ecopetrol Óleo e Gás do Brasil Ltda., strengthened its portfolio in the prolific Santos Basin. In April 2022, as a result of the “Third Cycle of Open Acreage - Concession” held by the Brazilian National Petroleum Agency (Agência Nacional do Petróleo, or “ANP” for its acronym in Portuguese), our subsidiary Ecopetrol Óleo e Gás do Brasil Ltda., in consortium with Shell Brasil Petróleo Ltda., acquired six offshore blocks in the southern region of the basin, for a total acreage of 4,106 km² where Ecopetrol has a 30% ownership stake and Shell, as operator, has a 70% ownership stake. High quality 3D seismic data is expected to be acquired during 2023, to fulfill the work commitment in the area, aiming at a potential drilling campaign in 2025.

Also in the Santos Basin, the partnership among BP plc (“BP”), CNOOC, Ecopetrol Óleo e Gás do Brasil Ltda., in which the aforementioned partners have a 50%, 30% and 20% ownership stake, respectively, is moving forward with the preparation of the first exploration well in the Pau-Brasil pre-salt block, which is planned for the first half of 2024.

The following table sets forth information on our international exploratory drilling for the periods indicated.

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Table 4 – Exploratory Drilling Outside Colombia


	For the year ended December 31,
	2022	2021	2020

	(Number of wells)
UNITED STATES
Ecopetrol America LLC
Gross Exploratory Wells
Productive	—	—	—
Dry⁽¹⁾	1.00	1.00	—
Under Evaluation⁽²⁾	—	—	—
Total	1.00	1.00	—
Net Exploratory Wells⁽³⁾⁽⁴⁾
Productive	—	—	—
Dry⁽¹⁾	0.25	0.10	—
Under Evaluation⁽²⁾	—	—	—
Total	0.25	0.10	—
BRAZIL
Ecopetrol Óleo e Gás do Brasil Ltda.
Gross Exploratory Wells
Productive⁽⁵⁾	—	—	1.00
Dry⁽¹⁾	—	—	1.00
Under Evaluation⁽²⁾	—	—	—
Total	—	—	2.00
Net Exploratory Wells⁽³⁾⁽⁴⁾
Productive	—	—	0.30
Dry⁽¹⁾	—	—	0.10
Under Evaluation⁽²⁾	—	—	—
Total	—	—	0.40
MEXICO
Ecopetrol Mexico
Gross Exploratory Wells
Productive	—	—	—
Dry⁽¹⁾	—	1.00	—
Under Evaluation	—	—	—
Total	—	1.00	—
Net Exploratory Wells⁽²⁾⁽³⁾
Productive	—	—	—
Dry⁽¹⁾	—	0.50	—
Under Evaluation	—	—	—
Total	—	0.50	—

(1)	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.

(2)

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 carried out to determine the hydrocarbon production capacity or some petrophysical parameter of the rocks or fluids in the reservoir.

(3)	Net exploratory wells were calculated according to our percentage of ownership in these wells.

(4)	None of our international wells were drilled pursuant to a sole risk contract.

Note: The table does not include stratigraphic test wells. Although these wells are considered to be exploratory wells, we do not include them as part of our exploratory wells’ information in the table above as these wells are plugged and abandoned after the relevant test study is completed.

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Seismic

During 2022, our subsidiary Ecopetrol Óleo e Gás do Brasil Ltda, purchased 2,595 km² of 3D seismic data located in the Santos and Campos basins to evaluate the exploratory potential of those basins and to mature the existing prospects within the portfolio.

3.5.2

Production Activities

In 2022, our consolidated average production was 709.5 thousand boepd, showing an increase of 30.5 thousand boepd as compared to 2021, primarily due to the following factors: (i) the entry into operation of the first fluid treatment train in the Caño Sur field during the second half of 2022, which increased production by 18 thousand boepd by December 2022; (ii) incremental production from Permian, (iii) recovery of gas sales due to increased activity in the industrial and thermal market and new commercial strategies, (iv) restarting production in the Castilla field, which had been temporarily closed for water management, (v) receipt of assets from the Nare fields, after termination of the partnership agreement with Mansarovar, and (vi) increased production share from La Cira-Infantas, Caño Limon and Quifa fields.

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

For the year ended December 31,

2022

2021

2020

Oil

Gas⁽¹⁾

Total

Oil

Gas⁽¹⁾

Total

Oil

Gas⁽¹⁾

Total

(Thousand boepd)

Total gross production in Colombia⁽²⁾

509.9

152.5

662.4

504.0

144.6

648.6

537.4

138.1

675.5

Total international gross production⁽³⁾

31.9

15.2

47.1

23.1

7.3

30.4

17.4

4.2

21.5

Total gross production of Ecopetrol Group

541.8

167.7

709.5

527.1

151.9

679.0

554.7

142.3

697.0

Total production of Ecopetrol Group for presentation of reserves⁽⁴⁾

502.1

155.2

657.3

485.9

146.2

632.2

508.5

138.8

647.3

(1)	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.

(2)	Total production in Colombia corresponds to Ecopetrol S.A., Hocol and Equion Energía Limited (“Equion”) (until February 2020). Includes royalties.

(3)	Total International production corresponds to Ecopetrol Permian LLC; Savia Perú and Ecopetrol America LLC. Includes royalties.

(4)

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 include NGL and oil self-consumption, which is immaterial.

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, 2022, Ecopetrol S.A. was the largest participant in the Colombian hydrocarbons industry, accounting for approximately 65% of crude oil production and 60% 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 2022, Ecopetrol S.A. drilled and completed 412 development wells, mainly in the Central, Orinoquía, and Andina regions (241 through direct operations and 171 through associated companies).

Ecopetrol S.A. manages its production operations through a regional organization, which comprises a total of 82 oil fields with active production in 2022 in four regions: (i) Central Region, (ii) Orinoquía Region, (iii) Andina Oriente Region, and (iv) Piedemonte Region. Additionally, we operate 73 fields with active production through associated operations with different partners.

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The map below shows the locations of Ecopetrol S.A.’s operations by region.

Graph 4 – Ecopetrol S.A. Operations in Colombia

Note: Associated operations are conducted through a countrywide Vice-Presidency of Subsidiaries and Assets with Partners.

Crude Oil Production

The average daily production of crude oil in Colombia by Ecopetrol S.A. (excluding its subsidiaries), was 492.8 thousand bopd in 2022, 6.9 thousand bopd higher than in 2021, which represents a year-to-year increase of 1.4%.

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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.

Table 6 – Ecopetrol S.A.’s Average Daily Crude Oil Production in Colombia by Region


	For the year ended December 31,
	2022	2021	2020

	(Thousand bpd)
Central Region
La Cira – Infantas	17.31	18.11	19.51
Casabe	12.67	12.33	13.11
Yarigui	16.81	18.66	18.90
Nare⁽¹⁾	15.66	2.31	9.53
Other	16.35	17.23	16.95
Total Central Region	78.80	68.64	78.00
Orinoquía Region
Castilla	102.77	96.29	112.22
Chichimene	62.62	67.41	68.80
CPO-09	8.95	9.23	5.25
Apiay	4.70	5.09	6.33
Other	7.07	7.06	7.15
Total Orinoquía Region	186.11	185.08	199.75
Piedemonte Region
Floreña	20.02	23.35	25.54
Cupiagua	5.05	6.29	6.22
Cusiana	1.10	1.58	2.13
Recetor	2.37	2.18	—
Gibraltar⁽²⁾	0.74	—	—
Total Piedemonte Region	29.28	33.40	33.89
Andina Oriente Region
Rubiales	101.58	100.43	106.27
Caño Sur	7.66	3.65	5.06
San Francisco	3.54	3.33	4.05
Huila Area	4.09	4.49	5.55
Tello	4.38	4.54	4.33
Other	8.52	8.66	7.50
Total Andina Oriente Region	129.77	125.10	132.76
Associated Operations
Quifa	13.97	11.63	14.72
Caño Limon	26.10	24.32	24.14
Nare	—	7.03	—
Floreña	—	—	2.62
Other	28.76	30.71	30.15
Total Associated Operations	68.83	73.69	71.63
Total average daily crude oil production Ecopetrol S.A. (Colombia)	492.79	485.91	516.03

(1)

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.

(2)

Since 2022, Gibraltar field is included in Table 6 pursuant to the ANH's request to consider condensate as crude oil production and not as natural gas liquids in this field.

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Table 7 – Ecopetrol S.A. Production per Type of Crude


	2022	Year-on-Year		2021	Year-on-Year		2020
	(Mbod)	∆ (%)		(Mbod)	∆ (%)		(Mbod)
Light	29.9	(12.8)	%	34.3	(12.0)	%	39.0
Medium	132.6	(4.1)	%	138.3	(1.7)	%	140.6
Heavy	330.3	5.4	%	313.3	(6.9)	%	336.4
Total	492.8	1.4	%	485.9	(5.8)	%	516.0

Ecopetrol S.A.’s crude oil production in Colombia during 2022 was approximately 67% heavy crudes and 33% light and medium crudes. In 2021, approximately 64% of the crude oil production consisted of heavy crudes, and 36% of the crude oil production consisted of light and medium crudes. In 2020, approximately 65% of the crude oil production consisted of heavy crudes and 35% consisted of light and medium crudes.

Natural Gas Production

In 2022, the average daily production of natural gas by Ecopetrol S.A. (excluding its subsidiaries) reached 132.7 thousand boepd, including natural gas liquids (NGLs), corresponding to a 6% increase compared to 2021 production. This production was supplied from the following fields: Cupiagua (34%), Floreña (30%), Cusiana (17%), Guajira (9%), and the remaining 10% from other fields.

By the end of December 31, 2022, the Liquefied Petroleum Gas (LPG) plant of the Cupiagua field produced 7,099 LPG barrels per day. The plant produces LPG and other products such as natural gas liquids (NGL), and penthane (C5).

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Table 8 – Ecopetrol S.A.’s Average Daily Natural Gas Production in Colombia


	For the year ended December 31,
	2022		2021		2020
	Thousand		Thousand		Thousand
	bpd	mmcfpd	bpd	mmcfpd	bpd	mmcfpd
Central Region
La Cira – Infantas	0.29	1.51	0.39	2.23	0.10	0.57
Provincia	1.00	2.29	1.17	3.07	1.48	4.84
Yarigui	0.29	1.70	0.41	2.33	0.42	2.41
Other ⁽¹⁾	1.68	8.98	1.85	9.77	2.00	10.42
Total Central Region	3.26	14.48	3.82	17.40	4.00	18.24
Orinoquía Region
Apiay	0.12	—	0.21	—	0.32	—
Other	0.41	—	0.56	—	0.58	—
Total Orinoquía Region	0.53	—	0.77	—	0.90	—
Piedemonte Region
Floreña	39.53	197.18	27.34	138.74	24.37	119.84
Cupiagua	45.19	205.29	47.69	216.77	42.68	194.99
Cusiana	23.02	106.47	26.58	126.30	29.57	136.63
Gibraltar ⁽²⁾	6.46	36.81	4.35	22.24	5.71	29.12
Total Piedemonte Region	114.20	545.75	105.96	504.05	102.33	480.58
Andina Oriente Region
Huila Area	0.29	0.94	0.16	0.31	0.19	0.34
Tello	0.07	0.32	0.03	—	0.08	0.47
Other	0.38	1.88	0.25	1.12	0.19	0.53
Total Andina Oriente Region	0.74	3.14	0.44	1.43	0.46	1.34
Associated Operations
Guajira	12.23	69.70	12.58	71.69	12.80	72.92
Other	1.73	7.22	1.66	6.57	1.33	5.37
Total Associated Operations	13.96	76.92	14.24	78.26	14.13	78.29
Total Natural Gas Production (Colombia)	132.69	640.29	125.23	601.14	121.82	578.45

(1)	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.

(2)	The Gibraltar field used to be classified as part of the Central Region, but as of January 1, 2021, the field was reclassified to the Piedemonte Region.

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. Ecopetrol S.A.’s sales of natural gas liquids represented less than 3.3% of the Ecopetrol S.A.’s consolidated production for the periods presented in this annual report.

Projects to Increase Recovery Factor

In 2022, we continued the implementation of secondary and tertiary recovery programs to improve the fields’ recovery factor. By the end of 2022, the fields with secondary and enhanced oil recovery programs contributed 40% of the daily production of Ecopetrol S.A. Such a significant contribution is the combined result of (i) a 1.8 thousand boed increase in production in the Chicheme field, resulting from the performance of the air injection plant; (ii) a 30 thousand boed production, resulting from the performance of the water injection operations in the Chicheme field, and (iii) an approximately 54 thousand boed increase in production, resulting from the successful implementation of the water injection recovery cycle in the K2 arena in the Castilla field and the optimization of processes in the K1 arena of the same field.

The recovery programs increased proven reserves by 81 million barrels of oil equivalent (“mmboe” or “million boe”) with an investment of approximately USD 566 million distributed on 32 recovery projects, 30 of which correspond to secondary recovery and 2 to tertiary recovery.

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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, that reached total depth for the years ended December 31, 2022, 2021 and 2020.

Table 9 – Ecopetrol S.A.’s Gross and Net Development Wells in Colombia⁽¹⁾


	For the year ended December 31,
	2022		2021		2020
	Productive	Dry	Productive	Dry	Productive	Dry
	Wells	Wells	Wells	Wells	Wells	Wells
Central Region
Gross development wells owned and operated by Ecopetrol	43.0	—	57.0	—	51.0	—
Orinoquía Region
Gross development wells owned and operated by Ecopetrol	12.0	—	11.0	—	32.0	—
Andina Oriente Region
Gross development wells owned and operated by Ecopetrol	185.0	—	113.0	1.0	73.0	—
Piedemonte Region
Gross development wells owned and operated by Ecopetrol	1.0	—	—	—	—	—
Total gross development wells owned and operated in Colombia	241.0	—	181.0	1.0	156.0	—
Associated Operations
Gross development wells in joint ventures	171.0	1.0	99.0	5.0	45.0	—
Net development wells	103.96	0.55	67.9	1.9	29.0	—
Total gross development wells in joint ventures Ecopetrol S.A. in Colombia	171	1.0	99.0	5.0	45.0	—
Total net development wells in joint ventures Ecopetrol S.A. in Colombia⁽²⁾	103.96	0.55	67.9	1.9	29.0	—
Total gross development wells Ecopetrol S.A. in Colombia	412	1.0	280.0	6.0	201.0	—
Total net development wells Ecopetrol S.A. in Colombia⁽²⁾	344.96	0.55	248.9	2.9	185.0	—

(1)	Includes only wells that were drilled and completed or plugged and abandoned.

(2)	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.

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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, 2022.

Table 10 – Ecopetrol S.A.’s Gross and Net In Process Wells


	For the year ended December 31, 2022
	Drilled
	but not		Being	Being
	completed	Mobilization	drilled	completed

	(Number of wells)
COLOMBIA
Central Region
Gross in process wells owned and operated by Ecopetrol	—	—	1.0	—
Orinoquía Region
Gross in process wells owned and operated by Ecopetrol	4.0	—	2.0	7.0
Andina Oriente Region
Gross in process wells owned and operated by Ecopetrol	3.0	2.0	5.0	5.0
Piedemonte Region
Gross in process wells owned and operated by Ecopetrol	—	1.0	2.0	1.0
Total gross in process wells owned and operated in Colombia	7.0	3.0	10.0	13.0
Associated Operations
Gross in process wells in joint ventures	9.0	2.0	3.0	1.0
Net in process wells⁽¹⁾	7.12	0.70	1.47	0.52
Total gross in process wells in joint ventures Ecopetrol S.A.	9.0	2	3.0	1
Total net in process wells in joint ventures Ecopetrol S.A.⁽¹⁾	7.12	0.70	1.47	0.52
Total gross in process wells Ecopetrol S.A. in Colombia	16.0	5.0	13.0	14.0
Total net in process wells Ecopetrol S.A. in Colombia⁽¹⁾	14.12	3.70	11.47	13.52

(1)	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, 2022.

Table 11 – Ecopetrol SA.’s Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production in Colombia


	For the year ended December 31, 2022
	Developed		Undeveloped
	Gross	Net (Acres)	Gross	Net (Acres)


Ecopetrol S.A.	414,941	358,185	3,917,367	2,796,208

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, 2022.

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Table 12 – Ecopetrol S.A.’s Gross and Net Productive Wells by Region⁽¹⁾⁽²⁾


	For the year ended December 31, 2022
	Crude Oil⁽³⁾		Natural Gas⁽⁴⁾
	Gross	Net⁽⁵⁾	Gross	Net⁽⁵⁾

	(Number of wells)
COLOMBIA
Central Region	3,256	2,807	4.0	4.00
Orinoquía Region	956	940	—	—
Andina Oriente Region	1,230	1,187	8.0	8.00
Piedemonte Region	53	53	19.0	19.00
Associated Operations Region	1,500	970	30.0	16.00
Total	6,995	5,957	61.0	47.00

(1)	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.

(2)	Includes only wells that were drilled and completed.

(3)	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.

(4)	Natural gas wells are those in which operations are directed only toward the production of commercial gas.

(5)	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 2022, the subsidiaries’ production in Colombia came from Hocol, with a production of 36.9 thousand boepd, which represents 5.2% of the Ecopetrol Group’s total production.

Crude Oil Production

The following table sets forth our average daily crude oil production from Hocol and Equion, prior to deducting royalties, for the periods indicated.

Table 13 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Crude Oil Production⁽¹⁾


	For the year ended December 31,
	2022	2021	2020

	(Thousand bpd)
COLOMBIA
Hocol
Joint venture operation	1.35	1.11	1.06
Direct operation	15.75	16.98	19.14
Total Hocol	17.10	18.09	20.20
Equion⁽¹⁾
Joint venture operation	—	—	—
Direct operation	—	—	1.13
Total Equion (1)	—	—	1.13
Production Tests	—	—	—
Total Average Daily Crude Oil Production (Subsidiaries in Colombia)	17.10	18.09	21.33

(1)	Equion fields were in operation until February 2020.

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Natural Gas Production

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


	For the year ended December 31,
	2022		2021		2020
	Thousand		Thousand		Thousand
	bpd	mmcfpd	bpd	mmcfpd	bpd	mmcfpd
COLOMBIA
Hocol
Joint venture operation	2.71	15.45	2.49	14.18	2.18	12.43
Direct operation	17.06	97.24	16.90	96.32	13.24	75.48
Total Hocol	19.77	112.69	19.39	110.50	15.42	87.91
Equion⁽¹⁾
Joint venture operation	—	—	—	—	—	—
Direct operation	—	—	—	—	0.86	4.10
Total Equion	—	—	—	—	0.86	4.10
Production Tests	—	—	—	—	—	—
Total Average Daily Gas Production (Subsidiaries in Colombia)	19.77	112.69	19.39	110.50	16.28	92.01

(1)	Equion fields were in operation until February 2020.

Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd.

Development Wells

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⁾


	For the year ended December 31,
	2022		2021		2020
	Productive	Dry	Productive	Dry	Productive	Dry
	Wells	Wells	Wells	Wells	Wells	Wells

	(Number of wells)
Hocol
Gross development wells owned and operated by Hocol	18.0	1.0	22.0	—	24.0	—
Gross development wells in joint ventures	2.0	—	—	—	—	—
Net development wells⁽²⁾	19.0	1.0	22.0	—	24.0	—
Equion
Gross development wells owned and operated by Equion⁽³⁾	—	—	—	—	—	—
Gross development wells in joint ventures	—	—	—	—	—	—
Net development wells⁽²⁾	—	—	—	—	—	—
Total gross development wells owned and operated in Colombia	18.0	1.0	22.0	—	24.0	—
Total gross development wells in joint ventures in Colombia	2.0	—	—	—	—	—
Total net development wells (Subsidiaries in Colombia)⁽²⁾	19.0	1.0	22.0	—	24.0	—

(1)	Includes only wells that were drilled and completed.

(2)	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.

(3)	Equion fields were in operation until February 2020.

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Table 16 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net In Process Wells⁽¹⁾


	For the year ended December 31, 2022
	Drilled but
	not		Being	Being
	completed	Mobilization	drilled	completed

	(Number of wells)
Hocol
Gross in process wells owned and operated by Hocol	—	—	1.0	—
Gross in process wells in joint ventures	1.0	—	—	—
Net in process wells⁽¹⁾	0.5	—	1.0	—
Total gross in process wells owned and operated in Colombia	—	—	1.0	—
Total gross in process wells in joint ventures in Colombia	1.0	—	—	—
Total net in process wells (Subsidiaries in Colombia)⁽¹⁾	0.5	—	1.0	—

(1)	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.

Production Acreage

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, 2022.

Table 17 – Ecopetrol S.A.’s Subsidiaries in Colombia Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production


	For the year ended December 31, 2022
	Developed		Undeveloped
	Gross	Net	Gross	Net

	(Acres)
Hocol	62,851	38,466	47	46
Total	62,851	38,466	47	46

The following table sets for the expiration dates of material concentrations of the Company’s consolidated undeveloped acreage by geographic area as of December 31, 2022.

Table 18 – Undeveloped Production Acreage as of December 31, 2022 by Expiration Year


	For the year ended December 31,
	2023		2024		2025		2026		2027 and beyond
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net

	(Acres)
COLOMBIA
Ecopetrol S.A.⁽¹⁾	—	—	—	—	—	—	—	—	872,887	454,777
Hocol	—	—	—	—	—	—	—	—	—	—
Equión	—	—	—	—	—	—	—	—	—	—
Total Colombia	—	—	—	—	—	—	—	—	872,887	454,777
UNITED STATES OF AMERICA
Ecopetrol America LLC	—	—	—	—	—	—	—	—	—	—
Ecopetrol Permian LLC⁽²⁾	388	126	6,180	5,953	299	299	—	—	—	—
Total United States of America	388	126	6,180	5,953	299	299	—	—	—	—

(1)	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.

(2)	Net acres correspond to our share and includes only acreage under direct operation by Occidental Petroleum. Non-operated acreage is not included because they are not considered material.

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Gross and Net Productive Wells

The following table sets forth our subsidiaries’ total gross and net productive wells in Colombia for the year ended December 31, 2022.

Table 19 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Productive Wells⁽¹⁾⁽²⁾


	For the year ended December 31, 2022
	Crude Oil⁽³⁾		Natural Gas⁽⁴⁾
	Gross	Net⁽⁵⁾	Gross	Net⁽⁵⁾

	(Number of wells)
Hocol	284.0	250.8	42.0	23.3
Total (Subsidiaries in Colombia)	284.0	250.8	42.0	23.3

(1)	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.

(2)	Includes only wells that were drilled and completed.

(3)	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.

(4)	Natural gas wells are those in which operations are directed only towards the production of commercial gas.

(5)	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.

3.5.2.2

Production Activities Outside Colombia

In 2022, the subsidiaries’ production outside Colombia came mainly from Ecopetrol America LLC and Ecopetrol Permian LLC. In 2022, the production obtained from these two companies was 47.10 thousand boepd, which represents 6.6% of the Ecopetrol Group’s total production.

Crude Oil Production

The following table sets forth our average daily crude oil production outside Colombia, prior to deducting royalties, for the periods indicated.

Table 20 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Crude Oil Production


	For the year ended December 31,
	2022	2021	2020

	(Thousand bpd)
PERÚ
Savia Perú⁽¹⁾	—	0.15	3.11
UNITED STATES OF AMERICA
Ecopetrol America LLC	8.10	9.45	10.41
Ecopetrol Permian LLC	23.84	13.48	3.85
Total average daily crude oil production (International)	31.94	23.08	17.37

(1)	In January 2021, Ecopetrol S.A. divested its 50% equity share in Savia Perú as the result of a competitive bidding process led jointly with its partner Korea National Oil Corporation (“KNOC”).

Natural Gas Production

The following table sets forth our average daily natural gas production outside Colombia, prior to deducting royalties, for the periods indicated.

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Table 21 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Natural Gas Production


	For the year ended December 31,
	2022		2021		2020
	Thousand		Thousand		Thousand
	bpd	mmcfpd	bpd	mmcfpd	bpd	mmcfpd
PERÚ
Savia Perú⁽¹⁾	—	—	0.02	0.00	0.91	2.44
UNITED STATES OF AMERICA
Ecopetrol America LLC	1.21	6.89	1.46	8.33	1.78	10.15
Ecopetrol Permian LLC	13.95	35.77	5.81	14.52	1.46	3.26
Total average daily natural gas production (International)	15.16	42.66	7.29	22.85	4.15	15.85

(1)	In January 2021, Ecopetrol S.A. divested its 50% equity share in Savia Perú as the result of a competitive bidding process led jointly with its partner KNOC.

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 16.3% of the consolidated production by Ecopetrol S.A.’s subsidiaries outside Colombia for the periods presented in this annual report.

Development Wells

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 22 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Development Wells⁽¹⁾


	2022		2021		2020
	Productive	Dry	Productive	Dry	Productive	Dry
Number of wells	Wells	Wells	Wells	Wells	Wells	Wells
PERÚ
Savia Peru⁽²⁾
Gross development wells	—	—	—	—	—	—
Net development wells⁽³⁾	—	—	—	—	—	—
UNITED STATES OF AMERICA
Ecopetrol America LLC
Gross development wells	—	—	—	—	—	—
Net development wells⁽³⁾	—	—	—	—	—	—
Ecopetrol Permian LLC⁽⁴⁾
Gross development wells	102.0	1	85.0	—	18.0	—
Net development wells⁽³⁾	50.0	0.5	41.7	—	8.8	—
Total gross wells (International)	102.0	1	85.0	—	18.0	—
Total net wells (International)⁽³⁾	50.0	0.5	41.7	—	8.8	—

(1)	Includes only wells that were drilled and completed.

(2)	In January 2021, we divested our 50% equity share in Savia Perú as the result of a competitive bidding process led jointly with its partner KNOC.

(3)	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.

(4)	Includes only wells drilled and completed under direct operation by Occidental Petroleum. Non-operated wells are not included because they are not considered material. Wells operated by others are not included because our share is not material.

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Table 23 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net In Process Wells


	For the year ended December 31, 2022
	Drilled
	but not		Being	Being
	completed	Mobilization	drilled	completed

	(Number of wells)
UNITED STATES OF AMERICA
Ecopetrol America LLC
Gross in process wells	1.0	—	1.0	—
Net in process wells⁽¹⁾	0.3	—	0.3	—
Ecopetrol Permian LLC⁽²⁾
Gross in process wells	6.0	—	7.0	4.0
Net in process wells⁽¹⁾	2.9	—	3.4	2.0
Total gross in process wells (International)	7.0	—	8.0	4.0
Total net in process wells (International)⁽¹⁾	3.2	—	3.7	2.0

(1)	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.

(2)	Includes only wells under direct operation by Occidental Petroleum. Non -operated wells are not included because they are not material.

Production Acreage

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, 2022.

Table 24 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production


	For the year ended December 31, 2022
	Developed		Undeveloped
	Gross	Net	Gross	Net

	(Acres)
UNITED STATES OF AMERICA
Ecopetrol America LLC	55,440	14,479	980	294
Ecopetrol Permian LLC⁽¹⁾	67,249	48,666	6,517	6,377
Total (International)	122,689	63,145	7,497	6,671

(1)	Inclusive of acreage held by production.

Gross and Net Productive Wells

The following table sets forth our total gross and net productive wells outside Colombia for the year ended December 31, 2022.

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Table 25 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Productive Wells⁽¹⁾


	For the year ended
	December 31, 2022
	Crude Oil⁽²⁾
	Gross	Net⁽³⁾

	(Number of wells)
UNITED STATES OF AMERICA
Ecopetrol America LLC	18	4.3
Ecopetrol Permian LLC⁽⁴⁾	207	119.6
Total (International)	225	123.9

(1)	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.

3.5.2.3

Unconventional Hydrocarbons

In September 2019, the High Court for Administrative Matters (Consejo de Estado) (the highest administrative court in Colombia) sustained the suspension of the effects of Decree 3004 of 2013 and Resolution 90341 of 2014 that established the technical requirements for the development of unconventional reservoirs. Despite the suspension of the effects of such regulation, the court authorized the execution of Comprehensive Research Pilot Projects (“PPIIs”) to obtain information on the possible effects of using multi-stage hydraulic fracture technology in the country.

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, and, 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 October 29, 2021, the environmental impact study (estudio de impacto ambiental, or “EIA” for its acronym in Spanish) for the Kalé project was submitted to the National Environmental Licensing Authority (Autoridad Nacional de Licencias Ambientales, or “ANLA” for its acronym in Spanish). On March 25, 2022, the ANLA granted the environmental license for the Kalé project.

On February 15, 2022, Ecopetrol submitted the EIA for the Platero project to the ANLA, and on March 10, 2022, as part of the process to grant the environmental license for the Platero project, the ANLA ordered the scheduling of an environmental public hearing, which is still pending.

On April 21, 2022, the First Administrative Court of the Barrancabermeja Judicial Circuit suspended Ecopetrol’s environmental license for the Kalé PPII and the licensing process for the Platero project. Ecopetrol challenged the decision, which resulted in a favorable ruling by the Santander Court, which found that prior consultation was not required, thus allowing us to continue with the pilot program. As a result, the National Prior Consultation Authority Directorate cancelled the consultation process for the Kale PPII on June 2, 2022. See section Risk Review—Risk Factors—Legal and Regulatory Risks—More stringent environmental requirements or commitments imposed through regulation or public demand may lead to potential increased expenses or reduced demand for our products, as well as hardship in achieving timely permits and licenses.

The Government of Colombia (Ministry of Mines and Energy and Ministry of Environment and Sustainable Development) has 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 to 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. requested to the ANLA the suspension of the environmental obligations of Resolutions 00648 of March 25, 2022, and 01283 of June 10, 2022, 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.

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On October 24, 2022, Ecopetrol and Exxon Mobil requested to the ANH the reassignment of interest, rights, and obligations of (i) the Platero CEPI contract to Exxon Mobil, and (ii) the Kalé CEPI contract to Ecopetrol S.A.

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 7, 2022, the ANH approved the partial assignment requests submitted by Ecopetrol and ExxonMobil on October 24, 2022. On December 21, 2022, Ecopetrol, ExxonMobil and the ANH entered into an amendment of CEPI Kalé and CEPI Platero to formalize such reassignment, resulting in the sole ownership of CEPI Kalé by Ecopetrol, and the sole ownership of CEPI Platero by ExxonMobil.

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. The ANH and Ecopetrol are currently working on for the terms for the suspension of CEPI Kalé.

For more information see Applicable Laws and Regulations and Risk Factors – Risks Related to Our Operations.

In addition, in connection with our 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 from 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%), as well as to extend to 2025 its current carry obligations.

On June 17, 2022, Ecopetrol Permian LLC (a subsidiary of Ecopetrol) signed a Joint Development Agreement (JDA) with certain Occidental Petroleum subsidiaries to carry out drilling and production programs from 2022 to 2027, in an area of approximately 21,000 acres located in the Delaware sub-basin of the Permian basin. The agreement allowed us to expand our presence in the Permian with an approximately 49% interest stake of drilling and production programs in this area. Activity in the Delaware sub-basin started in December 2022 and will start contributing to production during the second part of the first quarter of 2023.

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 2022, we sold 953.3 mboed, out of which 448.1 mboed represented sales of fuels and petrochemicals (47%), 403.4 mboed represented sales of crude oil (42%), and 101.8 mboed sales of natural gas (11%).

Crude Oil Export Sales

In 2022, crude oil export sales totaled 400.3 and increased by 24.6 mboed compared to 2021, mainly due to increased availability of inventories, as a result of an increase in production (15 mboed), an increase in the release of crude oil from refineries (6 mboed), and improved reconstituted crude. 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 281.2 mboed sold during 2022 (a 70% share of the crude oil basket) followed by the Apiay blend with 49.0 mboed (a 12% share of the crude oil basket), Vasconia blend with 19.1mboed (a 5% share of the crude oil basket), the Mares blend with 16.2 mboed (a 4% share of the crude oil basket), South blend with 4.9 mboed (a 1% of the crude oil basket), the domestic crudes sold by Ecopetrol Permian LLC with 18.4 mboed, (a 4% share of the crude oil basket), and others with the remaining 4%.

We place our exports in markets that provide the best value for its crudes. In 2022, Asia was the main destination, representing 50% of crude oil exports, followed by the United States with 46%. The expansion of the refining capacity in countries like China as well as the fast recovery in crude demand of key refining hubs in Asia have supported the increase of crude oil flows from Colombia to that region. At the same time, the United States kept a strong position as a result of its economic reactivation.

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In November 2022, we incorporated Ecopetrol US Trading LLC into our Business Group, intending to consolidate our position as a worldwide trader of crude oil and natural gas as well as refined, petrochemical and industrial products. The company is expected to begin operations in the second half of 2023.

Ecopetrol US trading is our second trading subsidiary, following the incorporation of Ecopetrol Trading Asia in Singapore in July 2021, which began operations during the second quarter of 2022. Ecopetrol Trading Asia has already reached trades volumes and sold 42 mmboe of crude in 2022.

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 increased by USD 24.1/Bl year over year, due to market conditions stemming from the recovery effects of the COVID-19 pandemic mentioned above.

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, 2022, 2021 and 2020.

Table 26 – Ecopetrol Consolidated Crude Oil Purchases


	For the year ended December 31,
	2022	2021	2020

	(Million barrels)
Crude oil purchased from ANH royalties	27.2	27.2	31.0
Crude oil purchased from third parties	42.2	41.8	34.0
Crude oil imported from third parties	12.1	9.0	5.6

During 2022, 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.

Import of Diluents

In 2022, we increased the imports of diluent by 26% (7 mboed) compared to 2021, due to the use of domestically produced naphtha. 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 2022 increased by 7% (7 mboed) compared to 2021, mainly due to recovery of national demand resulting from fewer Covid-19 related restrictions and increased production in the Permian (4 mboed).

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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 27 – Ecopetrol Consolidated Natural Gas Delivery Commitments


	For the year ended December 31,
	2023	2024	2025	2026

	(gbtud)
Volume for sales third parties	503.9	447.0	335.4	125.1
Volume for self-consumption	158.1	165.2	159.2	156.0
Volume for intercompany sales	93.9	93.7	83.6	80.3
Total Commitments	755.9	705.8	578.3	361.4

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 2022. 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 exploratory 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, 2022, 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 2022, the average ICE Brent price was USD 97.9/Bl.

Our crude oil and natural gas net proved reserves include reserves from our subsidiaries located in the United States, and from Hocol’s assets in Colombia.

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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, 2022, 2021 and 2020.

Table 28 – Net Proved Developed Reserves


			South
			America
		North	excluding
	Colombia	America	Colombia	Total
Net Proved Developed oil reserves in million barrels oil equivalent
At December 31, 2022	893.3	44.6	—	937.9
At December 31, 2021	823.0	33.0	—	856.0
At December 31, 2020	757.4	16.3	2.3	776.0
Net Proved Developed NGL reserves in million barrels oil equivalent
At December 31, 2022	44.0	12.9	—	56.9
At December 31, 2021	59.0	6.0	—	65.0
At December 31, 2020	57.0	1.1	0.4	58.0
Net Proved Developed gas reserves in billion standard cubic feet
At December 31, 2022	2,101.9	72.1	—	2,174.0
At December 31, 2021	2,517.0	44.0	—	2,561.0
At December 31, 2020	2,617.0	15.0	4.4	2,636.4
Net Proved Developed oil, NGL and gas reserves in million barrels oil equivalent
At December 31, 2022	1,306.0	70.1	—	1,376.1
At December 31, 2021	1,323.6	46.6	—	1,370.0
At December 31, 2020	1,273.3	20.0	3.5	1,296.8

(1)	Oil Reserves included 17.5 million barrels of Fuel Oil.

(2)	Gas Reserves included 368.9 bcf of Fuel Gas.

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. However, the ANH’s Resolution 877 of 2013, Resolution 351 of 2014 and Resolution 640 of 2014 require natural gas royalties to be paid in cash, which has the effect of determining the amount to be paid in royalties, based on property rights to the total volume of natural gas produced, without deductions on account of royalties. The main producing gas fields are Cupiagua, Pauto, Cusiana, Chuchupa and Cupiagua Sur.

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 2020, 2021 and 2022 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 17.5 million barrels of fuel oil, 368.9 billion standard cubic feet of fuel gas within our natural gas results and 375.7 billion cubic feet of royalties, as of December 31, 2022.

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Table 29 – Proved Oil, NGL and Natural Gas Reserves for 2022


			Natural	Total Oil
		NGL	Gas	and Gas
	Oil (mmb)	(mmb)	(bcf)	(mmboe)
PROVED DEVELOPED RESERVES
Colombia	893.3	44.0	2,101.9	1,306.0
International
North America	44.6	12.9	72.1	70.1
South America	—	—	—	—
TOTAL PROVED DEVELOPED RESERVES	937.9	56.9	2,174.0	1,376.1
PROVED UNDEVELOPED RESERVES
Colombia	375.0	14.1	503.4	477.5
International
North America	101.1	29.8	151.1	157.4
South America	—	—	—	—
TOTAL PROVED UNDEVELOPED RESERVES	476.2	43.9	654.4	634.9
TOTAL PROVED RESERVES	1,414.0	100.8	2,828.5	2,011.0

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 16.9 million barrels of fuel oil, 413 billion standard cubic feet of fuel gas within our natural gas results and 450 billion cubic feet of royalties, as of December 31, 2021.

Table 30 – Proved Oil, NGL and Natural Gas Reserves for 2021


		NGL	Natural Gas	Total Oil and
	Oil (mmb)	(mmb)	(bcf)	Gas (mmboe)
PROVED DEVELOPED RESERVES
Colombia	823.0	59.0	2,517.0	1,323.6
International
North America	33.0	6.0	44.0	46.6
South America	—	—	—	—
TOTAL PROVED DEVELOPED RESERVES	856.0	65.0	2,561.0	1,370.0
PROVED UNDEVELOPED RESERVES
Colombia	364.0	10.0	444.0	452.0
International
North America	120.5	34.0	146.6	180.0
South America	—	—	—	—
TOTAL PROVED UNDEVELOPED RESERVES	485.0	43.6	590.0	632.0
TOTAL PROVED RESERVES	1,341.0	108.5	3,151.0	2,002.0

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.

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The following table summarizes our proved oil, NGL and natural gas reserves, which includes 14 million barrels of fuel oil, 411 billion standard cubic feet of fuel gas within our natural gas results and 429 billion cubic feet of royalties, as of December 31, 2020.

Table 31 – Proved Oil, NGL and Natural Gas Reserves for 2020


				Total Oil
		NGL	Natural Gas	and Gas
	Oil (mmb)	(mmb)	(bcf)	(mmboe)
PROVED DEVELOPED RESERVES
Colombia	757.4	56.8	2,617.0	1,273.3
International
North America	16.3	1.1	15.0	20.0
South America	2.3	0.4	4.4	3.5
TOTAL PROVED DEVELOPED RESERVES	776.0	58.2	2,636.4	1,296.8
PROVED UNDEVELOPED RESERVES
Colombia	290.5	6.1	179.9	328.2
International
North America	105.8	21.0	105.1	145.2
South America	-	-	-	-
TOTAL PROVED UNDEVELOPED RESERVES	396.4	27.1	285.0	473.4
TOTAL PROVED RESERVES	1,172.4	85.3	2,921.5	1,770.2

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.

Changes in Proved Reserves

Table 32 – Changes in Proved Reserves


	For the year ended December 31,
	2022	2021	2020

	(Mmboe)
Revisions of previous estimates	63.0	315.1	(71.5)
Improved Recovery	80.9	138.9	113.1
Extensions and discoveries	57.5	11.9	42.7
Purchases	47.7	—	29.9
Sales	—	(3.5)	(1.0)
Total reserves additions	249.0	462.4	113.2
Production	(239.9)	(230.7)	(236.3)
Net change in proved reserves	9.0	231.7	(123.0)

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 2022, 2021 and 2020.

The reserves replacement ratio for 2022 was 104% compared to 200% in 2021 and 48% in 2020.

The average replacement ratio for the last three years was 117%.

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Table 33 – Reserves Replacement Ratio (Including Purchases and Sales)


	For the year ended December 31,
	2022		2021		2020
Annual	104	%	200	%	48	%
Three-year average	117	%	139	%	115	%

Revisions of Previous Estimates

In 2022, revisions increased reserves by 63 million boe, mainly as a result of:

(i)

An increase of 54 million boe in reserves due to new areas included in the approved development plan for the North American fields.

(ii)

An increase of 40 million boe in reserves due to new projects mainly in the Caño Sur, Palogrande and Recetor fields.

(iii)

An increase of 70 million boe in reserves due to better performance in development activities in existing fields, including, among others, the Rubiales and Caño Sur fields.

This increase was partially offset by a decrease of 101 million boe in reserves due to changes in the development plan in some of the North American fields where Ecopetrol holds working interest, as well as a reduction in Ecopetrol’s working interest in some fields in Colombia.

In 2021, revisions increased reserves by 315 million boe, mainly as a result of:

(i)

An increase of 115 million boe in reserves due to new areas included in the approved development plan for our North American fields, which increased reserves by 67 million boe and new projects mainly in the Cupiagua Sur, Chuchupa, Cusiana, Ballena, Cajúa and Rubiales fields, which increased reserves by 48 million boe.

(ii)

An increase of 178 million boe in reserves due to economic factors. More specifically, we were positively impacted by the increase in oil prices, with the ICE Brent crude price being 59% higher in 2021 as compared to 2020, which resulted in better economic conditions in some of our fields. The Brent reference price used in our reserve estimation process was USD 69.2/Bl in 2021 as compared to USD 43.4/Bl in 2020.

(iii)

An increase of 22 million boe in reserves due to field performance studies and development activities in existing fields, such as Rubiales, Caño Limon, Caño Sur and Gibraltar, among others.

In 2020, revisions decreased reserves by 71 million boe, mainly as a result of:

(i)

A 215 million boe decrease attributed to economic factors and reevaluated projects. More specifically, we were negatively impacted by the substantial decrease in oil prices, with the ICE Brent crude price being 32% lower in 2020 as compared to 2019, which resulted in the lowering of economic limits in some of our fields and some projects becoming uneconomical under SEC standards.

(ii)

An offsetting positive 114 million boe increase in reserves related to new projects in the Caño Sur, Quifa, Cusiana, Pauto and Rubiales fields as well as new areas included in the approved five-year development plan for our North American fields.

(iii)

An offsetting positive 30 million boe increase related to field performance studies and development activities in existing fields.

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Improved Recovery

In 2022, improved recovery activities increased reserves by 81 million boe, mainly due to new proved areas under water flooding in the Chicheme, Castilla, Akacias, Dina Terciario and Rio Ceibas fields.

In 2021, improved recovery activities increased reserves by 139 million boe, mainly due to new proved areas under water flooding in the Chichimene, Akacias, Yarigui, Casabe and Castilla fields, and optimization of the gas injection and blowdown strategy in the Cupiagua and Pauto fields.

In 2020, improved recovery activities increased reserves by 113 million boe, associated with new proved areas under water flooding in the Chichimene and Castilla fields, and optimization of the gas injection and blowdown strategy in the Cupiagua field.

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 34 – Changes in Proved Reserves Attributed to Extensions and Discoveries


	For the year ended December 31,
	2022	2021	2020

	(Mmboe)
Extensions and discoveries
Total change	57.5	12.0	42.7
Proved Undeveloped Reserves Change	51.7	6.0	14.6
Change from unproved to proved developed reserves	5.8	6.0	28.0

Note: Totals may not exactly equal the sum of the individual entries due to rounding.

The difference between the change of developed proved reserves and undeveloped proved reserves is related to the drilling of new wells in unproved acreage that led to new proved producing reserves.

The Company’s extensions and discoveries during 2022 amounted to 57 million boe, primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales and Quifa fields, among others, which accounted for 47 million boe of the increase. The remaining 10 million boe corresponds to newly discovered fields and reservoirs in the Recetor West, Ibamaca, El Niño and Capachos fields.

The Company’s extensions and discoveries during 2021 amounted to 12 million boe, primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Castilla and Llanito fields, which accounted for 10 million boe of the increase. The remaining 2 million boe corresponds to smaller changes in 13 fields with variations of between 0.006 to 0.7 million boe.

The Company’s extensions and discoveries during 2020 amounted to 43 million boe primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Suria, Yarigui and Llanito fields (accounting for 38.5 million boe of the total change) and newly discovered fields Andina and Esox (accounting for 4 million boe of the total change).

Purchases

In 2022, Ecopetrol S.A., through its wholly owned subsidiary, Ecopetrol Permian LLC, entered into a joint development agreement with affiliates of Occidental Petroleum and acquired participation rights in certain future drilling locations in the Delaware Basin, including access to up to 21,000 net acres in Lea County, New Mexico and Loving County, Texas. Also, Ecopetrol Permian LLC, through its joint venture with Occidental Midland Basin LLC, acquired additional acreage extending the South Curtis Ranch Field in the Midland Basin. These purchases increased proved reserves as of December 31, 2022 by 48 million boe.

In 2021, there were no purchases or acquisitions of reserves.

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Starting May 2020, Hocol took on the position of operator of the Guajira Contract, after the approval of the transaction in which Ecopetrol S.A. through its wholly-owned subsidiary, Hocol, acquired 100% of Chevron Petroleum Company’s participation in the contract (comprising the Ballena and Chuchupa fields in Colombia which corresponds to 43% of the total contract). This purchase increased proved reserves by 29.9 million boe.

Sales

In 2022, there were no sales of reserves.

In 2021, we sold 100% of our interest in Savia Perú S.A.

In December 2020, pursuant to a public auction process carried out by us and Hocol, an offer was received from Cordillera Resources SAS, Nikoil Energy Corp and Petroleum Blending International for 100% of our working interest in the La Punta and Santo-Domingo fields, which was declared the winning offer. An agreement was executed for this transaction. However, on November 28, 2022, the term established for the completion of the conditions precedent expired, and, because conditions precedent were not met, the agreement was terminated. Therefore, Hocol S.A. continues to hold 100% of our working interest in the La Punta and Santo-Domingo Fields.

Development of Reserves

As of December 31, 2022, our total proved undeveloped oil and gas reserves amounted to 635 million boe, 75% of which is related to development activities at the Rubiales, Castilla, Chichimene, Caño Sur, Pauto, Cupiuagua, Akacias, Quifa and Casabe fields in Colombia, among others, and 25% of which is related to development activities in North American fields. The proved undeveloped reserves estimated for the Cajúa and Caño Sur Este fields include locations with production start dates that extend beyond the five-year initial disclosure period and are associated with the current water-handling capacities in these fields. The development plan in the Rubiales field includes investments beyond the next five years due to the limitations in water-handling capacities in the field, which require the scheduling of the entry of new wells based on spare capacity of the plant. These exemptions were reviewed and approved by an external certification agent.

As of December 31, 2021, our total proved undeveloped oil and gas reserves amounted to 632 million boe, 72% of which was related to development activities at the Rubiales, Castilla, Chichimene, Caño Sur, Pauto, and Akacias fields in Colombia, among others, and 28% of which was related to development activities in North American fields. The proved undeveloped reserves estimated for the Cajúa, Caño Sur Este, and Quifa 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 the Rubiales field extended beyond the initial five-year period due to the limitations in water-handling capacities in the field. Reserves in the United States Gulf of Mexico were estimated for one undeveloped location with a production start date outside of five years from initial booking because we represented that a portion of the capital expense required for the projects would be spent within five years. These exemptions were reviewed and approved by an external certification agent.

As of December 31, 2020, our total proved undeveloped oil and gas reserves amounted to 473 million boe, 69% of which was related to development activities at the Rubiales, Castilla and Chichimene fields in Colombia, among others, and 31% of which was related to development activities in North American fields. Our year-end development plans were consistent with SEC guidelines for the development of proved undeveloped reserves within five years. The development plan of Rubiales field goes beyond the five years due to the water disposal restrictions in the facilities. The drilling of two wells in the United States Gulf of Mexico and one well onshore in Colombia also goes beyond five years due to drilling schedule. These wells are part of the ongoing development projects and all remaining development investments for the latter three wells will be completed within six years from their initial disclosure. These exemptions were reviewed and approved by an external certification agent.

The following table reflects the developed and undeveloped proved reserves estimates through the past three fiscal years.

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Table 35 – Developed and Undeveloped Proved Reserves


				Total Oil
	Oil	NGL	Natural Gas	and Gas
	(mmb)	(mmb)	(bcf)	(mmboe)
2022 Proved Reserves
Developed	938	57	2,174	1,376
Undeveloped	476	44	654	635
2021 Proved Reserves
Developed	856	65	2,561	1,370
Undeveloped	485	44	590	632
2020 Proved Reserves
Developed	776	58	2,636	1,297
Undeveloped	396	27	285	473

Of the total amount of proved undeveloped reserves that we had at the end of 2021 (632 million boe), we converted approximately 119 million boe, or 19%, to proven developed reserves during 2022. Approximately 80% of the total conversion is mainly associated with the development of crude oil and gas projects in the Castilla, Rubiales, Caño Sur, Cupiagua and Cusiana fields, among others, and 20% is associated with development execution in fields in the United States. The cash amount of investments made during 2022 to convert proved undeveloped reserves to proved developed reserves was USD 1,066 million.

Of the total amount of proved undeveloped reserves that we had at the end of 2020 (473 million boe), we converted approximately 87 million boe, or 18%, to proven developed reserves during 2021. Approximately 75% of the total conversion is mainly associated with the development of crude oil and gas projects in the Castilla, Rubiales, and Cupiagua fields, among others, and 25% is associated with development execution in fields, such as the Ocelote field and others. The cash amount of investments made during 2021 to convert proved undeveloped reserves to proved developed reserves was USD 528 million.

Of the total amount of proved undeveloped reserves that we had at the end of 2019 (529 million boe), we converted approximately 69 million boe, or 13%, to proven developed reserves during 2020. Approximately 86% of the total conversion is mainly associated with the development of crude oil and gas projects in the Castilla, Rubiales, and Cupiagua fields, among others, and the 14% is associated with development execution in fields, such as the Ocelote fields and others. The cash amount of investments made during 2020 to convert proved undeveloped reserves to proved developed reserves was USD 353 million.

Changes in Undeveloped Proved Reserves

The following table reflects the main changes in undeveloped proved reserves as of December 31, 2022, 2021 and 2020.

Table 36 – Changes in Undeveloped Proved Reserves


	For the year ended December 31,
	2022	2021	2020

	(Mmboe)
Consolidated companies
Revisions of previous estimates	(2.5)	141.0	(46.3)
Improved Recovery	26.6	98.0	45.9
Extensions and discoveries	51.7	6.0	14.6
Purchases	46.4	—	—
Proved undeveloped converted to proved developed	(119.1)	(87.0)	(69.4)
Net change in unproved reserves	(3.1)	158.0	(55.2)

Note: The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent. Totals may not exactly equal the sum of the individual entries due to rounding.

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Undeveloped proved reserves converted to developed proved reserves: Of the total amount of undeveloped proved reserves that we had at the end of 2021 (632 million boe), we converted approximately 119 million boe, or 19%, to developed proved reserves during 2022. Approximately 80% of the total conversion was mainly associated with the development of crude oil and gas projects in the Castilla, Rubiales, Caño Sur, Cupiagua and Cusiana fields, among others, and 20% is associated with development execution in fields in the United States.

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 Corporate 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 received his engineering degree from Universidad Central de Venezuela and a financial management specialist degree from Pontificia Universidad Javeriana. He reports to the Upstream 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 fifteen 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, Gaffney Cline & Associates, 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 Corporate Resources and Reserves Manager consolidates the results and together, with the Upstream Vice-President and the Upstream Chief Financial Officer, presents the outcome to the Resources and Reserves Committee, which comprises the Ecopetrol Group’s CEO, CFO, COO and the Upstream 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 Corporate Resources and Reserves unit, the Upstream unit and the Vice-Presidency of Development and Production presented the reserves balance to the Board of Directors, who approved it in February 2023.

The aforementioned external independent engineering consultants have estimated and certified our proved reserves as of December 31, 2022. These external engineers estimated 99% of our estimated net proved reserves for the year ended December 31, 2022, 2021 and 2020. 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. The majority 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, 2020 through 2022, and the changes therein.

Table 37 – Estimated Proved Reserves of Oil and Gas


			South America
		North	excluding
	Colombia	America	Colombia	Total

	Net proved oil, NGL and gas reserves in mmboe
At December 31, 2020	1,601.1	165.1	3.5	1,770.2
Revisions	245.0	70.0	—	315.0
Improved Recovery	139.0	—	—	139.0
Extensions and Discoveries	12.0	—	—	12.0
Purchases	—	—	—	—
Sales	—	—	(3.5)	(3.5)
Production	(222.0)	(8.9)	—	(231.0)
At December 31, 2021	1,775.1	226.2	—	2,001.7
Revisions	97.2	(34.3)	—	63.0
Improved Recovery	79.5	1.3	—	80.9
Extensions and Discoveries	57.5	—	—	57.5
Purchases	—	47.7	—	47.7
Sales	—	-	—	—
Production	(226.3)	(13.6)	—	(239.9)
At December 31, 2022	1,783.0	228.0	—	2,011.0

Note: Totals may not exactly equal the sum of the individual entries due to rounding. For more information regarding the potential impacts of oil prices on our reserve estimates, see 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 business 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, 2022.

Association Contracts

The purpose of this type of contract, created by Decree 2310 of 1974, is the exploration of the areas covered by the contract, and the exploitation of hydrocarbons found in that area. This type of contract, together with exploration and production (“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.

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. will participate in the field’s development. A joint account will be created, and Ecopetrol S.A. and the partner will participate in the expenses and investments in the proportions established in the corresponding contract. Ecopetrol S.A. will 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.

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 1 or 2 additional years at the partner’s request. The remaining time is for the exploitation phase.

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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. 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), will 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 3 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 taking 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 annual budget, 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-Corcorná 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 lasts 180 days, the second lasts 730 days, and the third phase lasts up to the date in 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. will occur if there are high production levels or high prices.

The Teca-Cocorná joint venture is divided into two phases. The first phase lasts three years and may be extended for up to an additional year; the second term is 20 years and will be reduced by the term of any extensions of the first phase.

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. will occur if there are high production levels and high prices.

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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 from 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.

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 into with the ANH:

Technical Evaluation Agreements

This type of contract grants the contractor the right to develop technical evaluation operations with operational autonomy at its own cost and risk, seeking to appraise the hydrocarbon potential, 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 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:

(i)

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

(ii)

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.

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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 E&P contract, 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 Process for the Allocation of Acreage (“PPAA”), 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 movable and immovable 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 will 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

Transportation and Logistics

3.6.1

Transportation Activities

The transportation 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.

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Graph 5 – Map of Oil Pipelines

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Graph 6 – Map of Multi-purpose Pipeline

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.

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Table 38 – Volumes of Crude Oil and Refined Products Transported


	For the year ended December 31,
	2022	2021	2020

	(Thousand bpd)
Crude oil transport⁽¹⁾	772.6	730.0	785.6
Refined products transport⁽²⁾	298.1	277.2	231.5
Total	1,070.7	1,007.2	1,017.1

(1)	The crude oil transported volumes correspond to the following systems: Ocensa Segment 3, ODC, Vasconia-Galan, Ayacucho-Galan, Ayacucho-Coveñas and Trasandino Pipeline.

(2)	The pipelines transporting refined products include the following: Galan-Sebastopol, Galan-Salgar, Galan-Bucaramanga, Buenaventura-Yumbo and Cartagena-Baranoa. From 2022, they also include the receipt and transportation of products through Sebastopol.

The volume of crude oil transported by Cenit’s main systems and those of its subsidiaries increased by 5.8% in 2022, compared to the previous year, as a result of higher production in the country, mainly in the Llanos area, and additional third-party barrels captured, that were previously outside the pipeline infrastructure network. Of the total volume of crude transported by oil pipelines, approximately 84.2% belonged to the Ecopetrol Group.

The volume of refined products transported by Cenit increased by 7.5% in 2022 compared to the previous year, mainly due to the continued recovery of economic activity following the lifting of restrictions related to the COVID-19 pandemic, higher production availability at refineries and operational optimizations in the transportation systems. Of the total volume of refined products transported by multi-purpose pipelines in 2022, 26% belonged to the Ecopetrol Group.

Transportation Capacity

Our main crude oil pipeline systems’ operating capacity was 1,472 thousand barrels per day in 2022. Our main multi-purpose pipeline transportation capacity increased from 524 thousand barrels per day in 2021 to 535 thousand barrels per day in 2022.

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, 2022, 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 45% 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 85% of the oil pipeline shipping capacity in Colombia. By December 31, 2022, our network of crude oil and multi-purpose pipelines was approximately 9,127 kilometers in length. The transportation network consists of approximately 5,388 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 3,739 kilometers of multi-purpose pipelines for transportation of refined products from the Barrancabermeja and Cartagena refineries to major distribution points. Out of the 5,388 kilometers of crude oil pipelines, owned by us, 3,175 kilometers of crude oil pipeline are wholly owned, and 2,212 kilometers of crude oil pipeline are owned through non-wholly owned subsidiaries.

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The following table sets forth our main pipelines in which we own an indirect interest as of December 31, 2022.

Table 39 – Our Main Pipelines


						Indirect
		Capacity	Product			Ownership
Pipeline	Kilometers	(mbd)	Transported	Origin	Destination	Percentage
Caño Limón-Coveñas	774	250	Crude Oil	Caño Limón	Coveñas	100.00	%
Oleoducto de Alto Magdalena (OAM)	391	103	Curde Oil	Tenay	Vasconia	93.62	%
Oleoducto de Colombia (ODC)	483	229	Crude Oil	Vasconia	Coveñas	73.00	%
Oleoducto Central – Ocensa⁽¹⁾	848	745	Crude Oil	Cupiagua	Coveñas	72.65	%
Oleoducto de los Llanos (ODL)⁽²⁾	260	297	Crude Oil	East fields	Monterrey Cusiana	65.00	%
Oleoducto Bicentenario de Colombia	230	150	Crude Oil	Araguaney	Banadia	100.00	%

(1)	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 are as follows:

Cupiagua-Cusiana (segment zero): 198 mbd

Cusiana-El Porvenir (segment one): 745 mbd

Vasconia-Coveñas (segment three): 550 mbd

(2)	Transportation capacity for this pipeline is measured by using crude oil viscosity of 1.350 cStk (30° C).

As of December 31, 2022, we owned 75 stations, 41 located in crude oil pipelines, 30 in refined products pipelines, 2 in crude oil ports and 2 in refined product ports.

As of December 31, 2022, we had a nominal storage capacity associated with the transportation network of 16.7 million barrels of crude oil and 5.4 million barrels of refined products. We do not own any tankers.

Pipeline Projects

Coveñas- Cartagena

The objective of the Coveñas - Cartagena project is to increase this system’s reliability, capacity, and pipeline infrastructure. To date, this pipeline has a nominal capacity of 135,000 barrels per day and feeds the Cartagena Refinery with national crudes. As the demand for national crudes from the Cartagena Refinery continued to increase, Cenit identified a need to expand this system. In May 2020, Cenit approved the project to increase the system’s nominal capacity by 20,000 barrels per day to 155,000 barrels per day and has been in operation since November 2021.

Operational Storage Program

The operational storage program’s objectives and scope includes ensuring a storage of 916,000 barrels of refined products in 5 different stations. The program foresees the construction of 10 tanks distributed through 4 projects divided in this way: (i) 1 tank of 260,000 barrels for Nafta in Pozos Colorados Terminal, (ii) 2 tanks of 100,000 barrels each in Sebastopol station and 1 tank of 62,000 barrels in Yumbo station (all this storage is for Biodiesel Extra (B2E) and Gasoline (GM)), (iii) 2 tanks of 70,000 barrels each, to storage B2E and GM in Cartago Station and (iv) 4 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 the construction, startup phase and commissioning, the systems in Pozos Terminal, was completed in August 2022. Eventually, with those new tanks in Pozos and Sebastopol, the storage capacity of the system increased by 360,000 barrels. Startup of the new tank at Yumbo station and the left tank in Sebastopol station is estimated for the first quarter of 2023.

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Andina Project

The aim of the Andina project is to increase reliability in the Salgar, Manasilla System through the replacement of 12 main pumps in 4 stations (Salgar, Guaduero, Villeta and Albán) to guarantee the supply of refined product to the interior of the country, mainly to the city of Bogotá and El Dorado International Airport. The construction of the new facilities started in August 2022 and is estimated to be completed by the third quarter of 2023.

Pozos Colorados Fuel Loading Dock

Seeking fuel supply flexibility in the area, the Fuel Loading Dock Project was developed in Pozos Colorados Terminal. As such, the scope of the project consists of enabling the facilities to deliver gasoline and load fuel trucks inside the station. The project was completed in December 2022 and is ready to use based on fuels demand in the area.

Apiay Fuel Loading Dock

Seeking fuel supply flexibility in the area, the Fuel Loading Dock Project was developed in Apiay. This asset allows alternative delivery of fuels by the dock in this Crude Oil Station. As such, the scope consists of enabling the receipt of fuels from the Poliandino pipeline to the fuel tank at the station in Apiay and the construction of the facilities required to load fuel trucks inside the station. The project was completed in November 2021 and is ready to use based on fuels demand in the area.

Replacement of Tanker Loading Unit TLU - Coveñas

In 2020, Ocensa invested USD 9.1 million in offshore infrastructure according to an updated investment plan signed with the Infrastructure National Agency (ANI) on December 4, 2019. The new Catenary Anchor Leg Mooring Turret buoy and Pipeline End Manifold (PLEM) are in Colombia and are in the preparation phase with integration tests currently taking place prior to the replacement of the TLU system. The installation of two fiber optic systems was successfully completed.

In 2021, Ocensa invested USD 9.8 million in offshore infrastructure according to an updated investment plan signed with the ANI on December 4, 2019. The installation, testing, and start-up of the TLU2 was carried out in a 60-day window, once the delays derived from the pandemic were overcome, which forced the system to change the window, initially scheduled for 2020, to be postponed by 5 months. During this period, technical support, verification, and guarantee assistance activities were carried out for the TLU-2 system by specialists and allies within the scope of the contract for the Comprehensive Standardization and Validation Plan of the offshore system. The maintenance of floating marine hoses and the integrity works of the subsea pipeline were performed according to the plan. The project was completed on May 8, 2021 and achieved its first ship loading on May 12, 2021. During 2022, TLU-2 operated without interruption.

Ocensa Segment 3 Connection to Cenit Tanks in Coveñas

Seeking operational efficiencies for the Ocensa terminal in Coveñas, the Segment 3 Connection Project was developed. This connection consists of enabling direct deliveries from the entrance of the Ocensa pipeline to the tank system of the Cenit station in Coveñas. Previously, crude oil was received in Ocensa’s tanks in Coveñas and then transferred to Cenit’s tanks. The operation of this connection is governed by an agreement between Cenit and Ocensa, which defines the rate and operating conditions that should be in place with the project expected to result in additional income for Ocensa.

In 2020, due to the impact of the COVID-19 pandemic in the oil and gas industry, construction was postponed until October 2020, with construction, pre-commissioning, and commissioning activities completed in December 2020. The tests and entry into service of the system were undertaken in January 2021 and the project is currently fully operational.

In 2021, stabilization of the system of the Coveñas Segment III Connection to Cenit Tanks - SEG3COV project was accomplished during the first days of January 2021. This connection has allowed direct delivery of barrels since the beginning of its operation, with a daily average in 2021 of 32,059 barrels per day, complying with the nomination of deliveries to customers and ensuring the stable condition of the delivery system by operators of Ocensa, Cenit, and Ecopetrol.

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Vasconia Energy Recovery (RECVA)

In connection with Ecopetrol Group’s focus on energy efficiency, we developed the Vasconia Energy Recovery (“RECVA”) project, which seeks to capture energy dissipated in the transportation process. Such energy is captured and converted from hydraulic principles into electrical energy to be used in the operation of the station, which reduces the consumption of energy supplied by the Regional Transmission Systems (Sistema de Transmisión Regional or “STR” for its acronym in Spanish).

Given that the Vasconia station operates 24 hours a day, an opportunity was identified to recover energy from the system, converting hydraulic energy (flow and pressure) into electrical energy through the installation of a hydraulic power recovery turbine (“HPRT”). In 2019, the HPRT was purchased, manufacturing was completed, and the engineering development was concluded.

In May 2020, the HPRT was received on-site, and during Ocensa’s scheduled plant shutdown in November 2020, the turbine connection points were installed in the existing process lines, and 20” valves were installed in the high- and low-pressure line.

In 2021, once the inconveniences derived from the pandemic were overcome, (i) the execution phase continued; (ii) the construction contract was awarded; and (iii) the civil, mechanical, electrical, and instrumentation works began. During that same year, pre-commissioning activities, including the selection of vendors for the commissioning stage, took place. In April 2022, the construction phase and commissioning stage were completed, and, in July 2022, HPRT operating tests and stabilization process, along with the environmental program (energy recovery and the reduction of CO2 emissions) were commenced.

The HPRT operating tests confirmed the conversion capacity of the equipment (2.2MW), and the reliability and stability of the system in terms of power generation. They also served to integrate the generation system with the transportation of crude oil to the interior of the station.

During the testing stage, the system achieved an accumulated recovery of 143 KWh, and a maximum recovery of 17.14KW/h, which further confirmed the system’s capacity of 2.2MW.

Based on our calculations, under current operating conditions, one year of HPRT operation has the potential to reduce an equivalent of 800 ToN in CO2 emissions.

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.

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 SIN, 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 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 (during 2023, the focus will be looking for alternatives that make the connection viable), and (iii) the preliminary analyses of additional alternatives, such as solar parks, wind energy, and carbon capture.

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Solar energy projects

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 projects are currently in the execution stage. During 2022, the following relevant goals were achieved: (i) structuring the process for contracting the purchase and sale of energy under a power purchase agreement (“PPA”) model, (ii) progress in the structuring of the energy sale contract with economic partners, (iii) defining the applicable regulatory framework, (iv) structuring of the process for contracting archaeological prospecting and rescue at the Vasconia station, and (v) a PPA contract award to Greenyellow Energía de Colombia S.A.S. We believe these projects have potential to create renewable energy sources to contribute to the Company's 2030 decarbonization strategy, whose goals include a 51% reduction in emissions compared to the baseline, the installation of 12MW 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.

During 2023, we expect to: (i) begin the execution phase of both projects, (ii) commence operations of the Coveñas solar park, and (iii) make progress in the assembly of the infrastructure of the Vasconia solar project.

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.

In 2021, the construction of the project began, and ODC registered USD 2.41 million in investments related to long-delivery purchases and project management. During 2022, the construction and development of the project reached 61%, and ODC invested USD 9.88 million in detailed engineering, soil study, acquisition of motor/pump skids, electrical rooms, power transformer, civil works, supervision and project management.

We anticipate that the new engines will come into operation during 2023 and that the ODC Caucasia station will be able to connect to the STR by 2025. In addition, it is expected that the ODC Caucasia station will also receive solar energy, which will further reduce the amount of CO2 emissions by the system.

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 2.33 million barrels per day for crude oil. Our import capacity of refined products and crude oil reached 0.61 million barrels per day and 0.34 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 9.98 million barrels of capacity. Our docks, used for import and export refined products, can load tankers of 55 thousand DWT. Additionally, these facilities have a storage capacity of up to 1.4 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 2022, 24.3 million barrels of crude oil and refined products were transported by tanker trucks, and 11.9 million barrels of refined products were transported by barges, particularly using the Magdalena River, connecting Barrancabermeja with Barranquilla and Cartagena.

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3.6.3

Marketing of Transportation Services

Cenit and its subsidiaries’ main line of business is the crude oil pipeline transport (77.16% of revenues), followed by the refined products pipeline transport (15.88% of revenues) and ports and related services (6.95% 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 actually transported), or spot contracts. The main users for the crude oil transportation business are Ecopetrol S.A., Frontera Energy, Parex, Trafigura, Hocol, and Vitol, who collectively represented 75.22% of this business segment’s revenues in 2022. Transportation services for crude oil provided to Ecopetrol S.A. represented 88.45% of this business segment’s crude oil transport revenues.

Cenit also transports refined products, and its main client is Ecopetrol S.A., which accounted for 38.46% of refined products pipeline transport revenues in 2022, mainly due to the transport of naphtha, diesel, and gasoline. Cenit also has 26 other fuel wholesalers’ customers for whom it transports refined products. The most significant among them are Organización Terpel, Primax Colombia, Chevron Petroleum Company, Biocombustibles S.A.S. and Petrobras Colombia.

Deregulated businesses, such as ports and crude-loading facilities, represent a smaller portion of Cenit and its subsidiaries revenue (6.95% in 2022). Clients for these businesses include some of the same parties for which Cenit provides crude oil and refined products transportation services.

Developments with certain clients of Bicentenario and Cenit

Bicentenario, Cenit and Frontera Settlement Agreement

On November 17, 2020, Cenit, Bicentenario and Frontera reached an agreement, for the joint filing of a petition for a binding settlement which, upon completion and approval by the competent Colombian court, resolved all the disputes pending among them, related to the Caño Limón – Coveñas pipeline and the Oleoducto Bicentenario de Colombia pipeline, and terminated all the pending arbitration proceedings related to such disputes. The arrangement was conditioned to certain regulatory approvals, including approval of the settlement arrangement as a conciliation under Colombian law, which required an opinion from the Attorney General’s Office (Procuraduría General de la Nación), which was issued on March 24, 2021, and approval of the Administrative Tribunal of Cundinamarca, which was notified on November 5, 2021, and became effective and binding on November 10, 2021. All approvals were obtained and the parties performed all their obligations under the agreement on November 11, 2021.

This transaction eliminated any uncertainty related to the potential outcomes of the disputes, thus protecting the interests of all the parties and those of their stakeholders and creating new business opportunities for the parties involved. The settlement arrangement included a full and final mutual release of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for the Bicentenario and Caño Limón – Coveñas pipelines. Frontera entered into new transportation contracts with Cenit and Bicentenario. The new initial ship or pay commitment is 2,811 barrels per day, which is based on the oil price as of the date of closing, for a term of five years, subject to adjustments. Frontera will not have to make payments for oil it may have to ship through alternate pipelines. These contracts allow Cenit and Bicentenario to obtain payment of certain amounts included in the settlement, during the term of the contracts. Additionally, as part of the agreement, Frontera transferred to Cenit its 43.03% stake of the outstanding shares of Bicentenario (Ecopetrol Group’s stake in Bicentenario is now 100%) and transferred to Bicentenario its participation in the Bicentenario pipeline line fill.

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Bicentenario and Canacol Settlement Agreement

On March 8, 2021, Bicentenario and Canacol reached an agreement to settle all their disputes, which was approved by the competent arbitration tribunal on April 23, 2021; and entered into a transaction agreement on March 16, 2021, to settle all their disputes on the storage agreement, the later subject to the approval of the settlement of the transportation agreement disputes by the competent arbitration tribunal.

The parties performed all their obligations under the settlement agreement on April 30, 2021. The settlement arrangements included a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contract for the Bicentenario pipeline and the storage agreement for the Terminal de Coveñas, ended all contractual obligations between the parties, and settled all the outstanding obligations between the companies. Additionally, as part of the settlement, Canacol entered into a new transportation contract with Bicentenario. This contract will allow Bicentenario to obtain payment of certain amounts included in the settlement, during the term of the contract.

Bicentenario and Vetra Settlement Agreement

On January 13, 2021, Bicentenario and Vetra reached an agreement to settle all their disputes. The settlement was approved by the competent arbitration tribunal on April 28, 2021, and the parties performed all their obligations under the agreement on May 5, 2021.

The arrangement included a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for the Bicentenario pipeline, ended all contractual obligations between the parties and settled all the outstanding obligations between the companies.

3.7

Refining and Petrochemicals

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 Cartagena Refinery, 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 upstream 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.

The following table sets forth our average daily installed and actual refinery capacity for each of the last three years:

Table 40 – Average Daily Installed and Actual Refinery Capacity


	For the year ended December 31,
	2022				2021				2020
	Capacity	Throughput	Use		Capacity	Throughput	Use		Capacity	Throughput	Use
	(bpd)	(bpd)	(%)		(bpd)	(bpd)	(%)		(bpd)	(bpd)	(%)
Barrancabermeja	250,000	217,720	87	%	250,000	211,004	84	%	250,000	179,210	72	%
Cartagena⁽¹⁾	210,000	140,005	67	%	150,000	142,898	95	%	150,000	140,866	94	%
Apiay	2,500	1,253	50	%	2,500	886	35	%	2,500	887	35	%
Orito	2,300	1,372	60	%	2,300	1,107	48	%	2,300	1,074	47	%
Total	464,800	360,350	78	%	404,800	355,895	88	%	404,800	322,038	80	%

(1)	Includes crudes and recirculated products.

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3.7.1.1

Barrancabermeja Refinery

The Barrancabermeja refinery produced approximately 39.4% of the fuels consumed in Colombia in 2022, according to internal calculations made by us and Colombia’s fuel consumption as reported by the Ministry of Finance.

The following table sets forth the production of refined products of the Barrancabermeja refinery for the periods indicated.

Table 41 – Production of Refined Products from the Barrancabermeja Refinery


	For the year ended December 31,
	2022	2021	2020

	(bpd)
LPG, Propylene and Butane	10,695	11,475	9,101
Gasoline Fuels and Naphtha	59,421	61,919	50,167
Diesel	55,272	59,200	54,261
Jet Fuel and Kerosene	24,413	20,404	11,910
Fuel Oil	28,454	26,969	25,112
Lube Base Oils and Waxes	782	694	577
Aromatics and Solvents	2,337	2,333	2,274
Asphalts and Aromatic Tar	36,396	31,373	27,018
Polyethylene, Sulphur and Sulphuric Acid	1,282	1,078	856
Total	219,052	215,445	181,276
Difference between Inventory of Intermediate Product	1,720	(829)	1,046
Total Production	220,772	214,616	182,322

In 2022, total production from the Barrancabermeja refinery increased by 1.7% compared with 2021, largely attributable to the continued increase in fuels demand, in line with the normalization of the economy after the easing of restrictions related to the COVID-19 pandemic and the increase in the national demand of fuels and asphalt for the national and international markets.

We own and operate four petrochemical plants and one paraffin and lube plant located within the Barrancabermeja refinery. In 2022, we produced 40,864 tons of low-density polyethylene, an increase of 38% compared to the production of 29,519 tons in 2021. This increase was primarily due to the operational availability of the units associated with the polyethylene chain. We produced 578,807 mboe of aromatics (benzene, toluene, xylene, orthoxylene, heavy aromatics, and cyclohexane), a 9.1% increase as compared with the production of 530,667 mboe of aromatics in 2021, mainly as a result of the operational availability of the units, which were not partially available in 2021 due to scheduled maintenance activities.

The gross refining margin increased from USD 11.5/Bl in 2021 to USD 19.8/Bl in 2022, primarily due to strengthening of the prices of refined products compared against crude, due to a higher differential in all indicators, which in turn was primarily due to a recovery in demand as a result of the economic reactivation previously discussed. The average conversion index for the Barrancabermeja refinery was 88.3% in 2022 and 88.9% in 2021. This decrease was primarily due to scheduled maintenance of TEA # 6 and the temporary closing of the Demex, Visbreaker II, HCM and UOP I units.

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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 42 – Production of Refined Products from the Cartagena Refinery


	For the year ended December 31,
	2022	2021	2020

	(bpd)
LPG, Propylene and Butane	3,011	3,440	3,321
Gasoline Fuels and Naphtha	46,914	41,201	43,259
Diesel	61,732	76,798	72,170
Jet Fuel and Kerosene	7,870	5,951	7,424
Fuel Oil	15,871	3,983	2,375
Sulphur	361	456	466
Total	135,759	131,829	129,015
Difference between Inventory of Intermediate Product	74	4,757	5,318
Total Production⁽¹⁾	135,833	136,586	134,333
Petcoke (Metric Tons)	710,867	854,808	828,931

(1)	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 43 – Imports and Sales of Refined Products from the Cartagena Refinery


	For the year ended December 31,
	2022	2021	2020

	(bpd)
Imports
Motor Fuels	1,633	6,835	—
Jet Fuel and Kerosene	616	274	—
LPG and Butane	2,204	303	1,132
Total Imports	4,452	7,412	1,132


	For the year ended December 31,
	2022	2021	2020

	(bpd)
Sales
Motor Fuels	36,747	27,844	43,979
Diesel	61,864	77,560	73,188
Jet Fuel and Kerosene	8,628	5,975	7,394
Fuel Oil	12,521	1,390	2,552
Other Products	30,666	41,940	24,275
Total Sales	150,427	154,709	151,388

During 2022, the Cartagena Refinery imported butane in order to achieve the planned feed of the Butamer Unit and to increase the production of alkylate.

Total sales increased from USD 4,104 million in 2021 to USD 6,313 million in 2022. A total of 51 million barrels of crude were processed in 2022 compared to 52 million barrels of crude processed in 2021. Exports to international markets represented 17% of total sales (USD 1,078 million).

The Cartagena Refinery’s 2022 figures already reflect the operation of all units. The gross refining margin increased to USD 22.9/Bl in 2022 from USD 8.5/Bl in 2021 mainly due to strengthening of refined products prices.

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In terms of growth opportunities, the project for the “Interconnection of the Crude Plants at the Cartagena Refinery – IPCC” achieved mechanical completion and commissioning stage, stabilizing its operation during September 2022. With this project we were able to reach higher refining capacity of 210 mbd.

3.7.1.3

Esenttia S.A.

During 2022, Esenttia’s production totaled 468 thousand tons of petrochemical products, a 6% decrease compared to the 500 thousand tons produced in 2021, primarily due to the demand slowdown, mainly due to global inflationary pressures which caused a price increase in these products. The total contribution margin in 2022 (including the contribution of polypropylene, polyethylene and masterbatches) was 15% lower than in 2021 (from USD 253.00 per ton in 2021 to USD 214.92 per ton in 2022).

The decrease in contribution margin is primarily a result of price pressures, primarily due to the supply of cheaper Asian products in our region, and the global economic slowdown which decreased demand for these products.

Table 44 – Operating Capacity of Esenttia


	For the year ended December 31,
	2022		2021		2020

	(Metric Tons)
Average capacity	494,695		499,873		480,000
Throughput	467,765		499,759		489,627
% Use	95	%	100	%	102	%

3.7.1.4

Invercolsa

During 2022, Inversiones de Gases de Colombia S.A. (“Invercolsa”), registered 1.39 million users of natural gas, an increase of 5.5% compared to the 1.32 million users of natural gas in 2021. Additionally, non-controlled companies registered 2.41 million users of natural gas in 2022, an increase of 4.3% compared to the 2.31 million users of natural gas in 2021, due to the continued economic reactivation following the restrictions imposed as a result of the COVID-19 pandemic and the recovery of the facilities hookup processes. 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. In May 2022, Ecopetrol reported that it had initiated the divestment of its participation in Invercolsa. As of the date of this annual report, this process is ongoing.

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 130 thousand tons of biodiesel per year.

During 2022, we managed to capitalize on opportunities and achieved historical results in production, going from a production of 133 thousand tons in 2021 to 138 thousand tons in 2022. This represents a year-to-year growth of 3.76% and was due mainly as a result of higher plant efficiency, which allowed for an increase in load from 16.0 tons/hour in 2021 to 16.59 tons/hour in 2022.

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 products totaled 365.1 mboed and increased by 42.9 mboed in 2022, 13% higher as compared to 2021. This increase is primarily the result of increased demand for fuels and gasoline (16.8 mboed), diesel (17.0 mboed) and jet fuel (9.2 mboed). The aforementioned was mainly driven by increased economic activity and mobility due to the phase-out of COVID-19 related restrictions.

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In 2022, 7.90 million barrels of diesel and 13.26 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, 4.2 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 15% (15.2 mboed) in 2022 compared to 2021, explained by a decrease of 26.6 mboed in exports of middle distillates, which was partially offset by an increase of 11.6 mboed in fuel exports.

3.8

Electric Power Transmission and Toll Roads Concessions

Our new electric power transmission and toll roads concessions segment arose directly out of the Acquisition (as defined in section Related Party and Intercompany Transactions—ISA Acquisition) and 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, 2022, 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 (Mercado de Energía Mayorista or “MEM” for its acronym in Spanish) in Colombia, and (iv) revenues recognized by reference to the stage of completion of contract activity in the electricity transmission business.

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 segment in each country in which ISA operates. 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 of 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 addition, ISA, through its subsidiaries, transmits 444,000 GWh annually, by means of 48,766 kilometers of high-voltage network circuits, which support the supply of energy in Latin America. As of December 31, 2022, ISA is in the process of constructing an additional 6,879 kilometers of high-voltage network circuits, which are expected to start operations in the near term.

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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 carries out 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 45 – Key Electricity Transmission Metrics


	For the year ended December 31,
	2022		2021		2020
In Operation
Km of Circuit	48,766		48,330		47,358
MVA Installed Capacity	104,438		104,138		95,720
In Construction
Km of Circuit	4,928		7,133		6,529
MVA Capacity	16,451		14,007		15,603
Operational Results
Reliability	99.99	%	99.99	%	99.99	%
Availability	99.82	%	99.81	%	99.87	%

3.8.2.1

Electricity Transmission Activities in Colombia

In 2022, ISA’s subsidiaries electricity transmission activities in Colombia included 13,569 km of transmission lines. As of December 31, 2022, ISA owned and operated an aggregate transformation capacity of 22,721 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 46 - Transmission Infrastructure in Colombia

For the year ended December 31,

2022

2021

2020

Transmission

Transformation

Transmission

Transformation

Transmission

Transformation

Lines

Capacity

Lines

Capacity

Lines

Capacity

(Km)

(MVA)

(Km)

(MVA)

(Km)

(MVA)

Colombia

13,569

22,721

13,226

22,721

12,543

21,661

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3.8.2.2

Electricity Transmission Activities Outside Colombia

In 2022, ISA’s subsidiaries electricity transmission activities outside Colombia included 35,199 km of controlled transmission lines, where Brazil represents 59% of the total transmission infrastructure.

The following table sets forth ISA’s electricity transmission activities outside Colombia, for the periods indicated.

Table 47 - Transmission Infrastructure Outside Colombia


	For the year ended December 31,
	2022		2021		2020
	Transmission	Transformation	Transmission	Transformation	Transmission	Transformation
	Lines	Capacity	Lines	Capacity	Lines	Capacity
	(Km)	(MVA)	(Km)	(MVA)	(Km)	(MVA)
Brazil	20,828	62,157	20,734	61,857	20,536	56,375
Peru	11,836	13,240	11,836	13,240	11,745	12,714
Chile	1,948	5,850	1,948	5,850	1,948	4,500
Bolivia	587	470	587	470	587	470
Total	35,199	81,717	35,105	81,417	34,816	74,059

3.8.3

Toll Roads Concessions Activities

ISA designs, builds, operates, and maintains toll road infrastructure that connects millions of people in Chile and Colombia. As of December 31, 2022, ISA was the largest intercity road operator and operated four concessions in Chile (Ruta del Maipo, Ruta del Bosque, Ruta de la Araucanía and Ruta de los Ríos), while in Colombia, it operated the Ruta Costera Concession. In total, it operated five toll roads concessions, which covered a total of 860 kilometers in these two countries and had 136.46 kilometers of new toll roads under construction in Ruta del Loa Concession. During the year ended December 31, 2022, 128.9 million passenger car units 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 48 - Total Traffic (Vehicles)


	For the year ended December 31,
	Road Length
	(Km)⁽¹⁾	2022	2021	2020
COLOMBIA
Ruta Costera	146	7,453,152	4,808,287	3,183,506
CHILE
Ruta del Maipo	237	100,780,722	93,396,012	69,192,576
Ruta del Bosque	161	21,874,196	21,023,883	15,822,778
Ruta de la Araucania	144	25,883,823	24,287,331	18,023,487
Ruta de los Ríos	172	11,255,310	10,381,272	7,725,255
Total	860	167,247,203	153,896,785	113,947,602

(1)Road length for the year ended December 31, 2022.

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3.8.4

Telecommunications and ICT

Within the telecommunications and ICT segment of its business, Internexa and its subsidiaries provide connectivity services, managed services, cloud services, data center and security services to customers across Latin America. These ISA subsidiaries also maintain a fiber-optic network that totals 56,462 kilometers as of December 31, 2022. Internexa has existing data centers in Medellín, Bogotá, Río de Janeiro and Santiago. Currently, their strategy is focused on diversifying their client portfolio (companies and over-the-top) and services (Cloud, DataCenter, Security, and Managed Services), while increasing their scale with attributes such as proximity, agility, and flexibility.

3.9

Research and Development; Intellectual Property

Technology and innovation are essential to our efforts to add value to our business segments and a key factor of our TESG strategy. 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 Institute (Instituto Colombiano del Petróleo or “ICP” for its acronym in Spanish), established in 1985 and located in Piedecuesta, Santander. The scope of the ICP activities covers our entire value chain: exploration, production refining, transportation, trading, and marketing, including asset integrity and environmental sustainability. From October 29, 2021, the ICP carries out its activities as a unit of the Technology, Science and Innovation Vice-Presidency.

Ecopetrol has focused its research, technology development and innovation efforts in seven main clusters:

(i) Asset resilience cluster. The main goal of this cluster is extending the economic limits of the Ecopetrol’s assets to support our oil and gas (“O&G”) value chain by means of the implementation of new processes and technologies, such as, optimized oil recovery and production methods, enhanced refinery seismic processing methods for complex geological areas, optimized value O&G chain analysis, enhanced refinery methods and the use of state-of-the-art digital tools related to data analytics and artificial intelligence.

(ii) Decarbonization and (iii) energy transition clusters. Through these clusters, 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 project related to nature-based solutions, and to reduce the risk of biodiversity loss in Colombia. We also work on modeling and developing tools to optimize the energy value chain.

(iv) Circular economy and (v) sustainability clusters. In these clusters we are exploring opportunities to increase circularity in our operations, considering not only recycling and the safe disposal of residues, but also initiatives for reuse, remanufacturing, and repurposing. Since water represents a critical resource, this area includes a technology-enabled water management program that encompasses the conservation, recycling, reuse, and valuation of productive water streams. The production and upscaling of high-performance materials from petroleum molecules, that could be the base for advanced, sustainable, reusable, non-combustion products, are also part of our research, development, and innovation efforts, aimed at reducing our scope 3 CO2 emissions. We are working mainly in mechanical and chemical plastic recycling and biopolymer.

(vi) Fifth Industrial Revolution and (vii) electric power transmission clusters. Digital, technologies such as artificial intelligence (AI), blockchain, internet of things (IoT) and augmented and virtual reality (AR/VR) are being implemented at each point along the value chain, namely, upstream, middle, and downstream. In addition, we are working to enhance operational safety, agility, and productivity, and unlock new revenue streams increasing the position and competitiveness of the current electric power transmission and toll road concession businesses.

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Each year, we present 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 our science and technology investments. The CNBT certifies eligible science and technology investments, which are deductible from income tax upon execution; and we apply the tax benefit.

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. The Ecopetrol Group has filed 332 patent applications in the last 17 years, 23 of them in 2022. Our most recent patent applications include innovative technologies, such as (i) titanium zinc and carbon oxides composites photocatalysts and their preparation method, (ii) method for obtaining fluorescent carbon nanomaterials from petroleum by products and its products, (iii) anticorrosive coating from asphaltene oxide and the method for obtaining such coating, (iii) activated carbon composite materials with metal nanoparticles and their preparation method, (iv) methods for obtaining reinforced cements with materials based on silicon dioxide nanoparticles coated with carbon oxides and their related products, (v) method for obtaining adsorbent materials from functionalized carbon oxides, (vi) metal functionalized with activated carbon nanostructured composites for the removal of sulfur, and (vii) development of a water nanofluid for changing wetting in heavy hydrocarbon reservoirs, using silica nanoparticles functionalized with polyethylene glycol.

In 2022, we obtained 18 new patents, 15 in Colombia and 3 abroad (2 in Venezuela and 1 in the United States). We currently hold 137 patents in Colombia, the United States, Mexico, Argentina, Peru, Venezuela, Ecuador, Brazil, Russia, Nigeria, Indonesia, India, and Malaysia. In the last three years, about 10% of the patents obtained have been related to biofuels aligned to our energy transition strategy.

To date, 55 technologies have been commercialized, with different business and technology transfers model to Colombian and multinational companies, thus achieving their monetization and generating additional income for the Company.

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 State 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 181495 of 2009, as amended by Resolutions 40048 of 2015 and 40230 of 2022, establishes a series of regulations regarding hydrocarbon exploration and production.

Ministry of Mines and Energy Resolution 180742 of 2012, partially repealed by Resolution 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. Furthermore, it 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.

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Decree 3004 of 2013, 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.

Agreement (Acuerdo, a type of regulation) 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. Each agreement entered into 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, complements Agreement 004 of 2012 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 also 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 carried out 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 as issued by the ANH on May 18, 2017, 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 future 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 adapts 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. In regard to unconventional reservoirs, this agreement also establishes the need to sign additional contracts and additional arrangements for the industry to exploit unconventional reservoirs in Colombia.

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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 (YNC), 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 is 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.

On February 5, 2019, the ANH by implementing the Acuerdo No. 002 (Agreement No. 002 of 2017) opened a PPAA, which aims 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.

The Agreement 002 of 2017 was partially modified by agreement 003 of February 18, 2019, 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 will select areas over which proposals may be received at any time, without the need of launching 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 carried out by the ANH.

As result of the first cycle of the PPAA, the ANH awarded 11 onshore areas and 1 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 4 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 the articles of Agreement 002 of 2017.

Agreement 006 of September 11, 2020 of the ANH 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 (yacimientos no convenionales or “YNC” for their acronym in Spanish) 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 by means of which the contractors were selected 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 carry out 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.

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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.

For 2021, 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.

Agreement 009 of October 12, 2021, issued by the ANH, compiled all amendments to Agreement 002 of 2017 and established the 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 carry out “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 will apply for wells that are 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, 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.

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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.

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.

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:

●

Resolution 40185 of 2020, modified by Resolution 40011 of 2021, of the Ministry of Mines and Energy. Technical regulations for the development of PPII.

●

Resolution 0904 of 2020 of the Ministry of Interior and the Ministry of Mines and Energy. Social Guidelines for the development of PPII.

●

Resolution 304 of 2020 of the Colombian Geological Service. Guidelines for the monitoring of seismicity and the inclusion of a seismic traffic light for the PPII.

●

Agreement 006 of 2020 of the ANH, modified by Agreements 007, 008 and 009 of 2020 and Agreement 004 of 2021. Regulations for the selection of contractors for CEPIs.

●

Decree 328 of 2020 issued by the Ministry of Mines and Energy providing the general guidelines for developing PPII on unconventional reservoirs.

●

In January 2021, the Colombian Geological Service office issued the third version of the technical guidelines for the laboratory sampling and analysis procedure of radioactive materials produced by the PPII.

●

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

Law 99 of 1993 and other environmental regulations, such as Decree 1076 of 2015 in particular (compilation decree regarding the administrative sector of environment and sustainable development), impose to companies, including oil and gas companies, the obligation to obtain an environmental license prior to undertaking any activity that may result in a serious deterioration of renewable natural resources, or that may have the capacity of materially modifying the physical environment.

The ANLA, created by means of Decree 3573 of 2011, 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.

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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 of the project subject to environmental licensing.

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, which compiles most of Colombian regulations in force regarding environment and sustainable development.

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. In particular, MADS is responsible for issuing regulation regarding Law 1931 of 2018 (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. 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, 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. Apart from 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. Notwithstanding the foregoing, the text of the agreement has yet to be submitted to the Colombian Constitutional Court for review of its constitutionality. 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.

3.10.1.1.2Royalties

In Colombia, the State 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 National Hydrocarbons Agency, 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 in excess of 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 and 855 of 2020 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 351 of 2014, 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.

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, liquefied petroleum gas-related activities are regulated by CREG. 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 on the basis of equal access to all.

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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.

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 right 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 private 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, the Ministry 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, the Ministry of Mines and Energy, 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, the Ministry of Mines and Energy through a series of resolutions 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 for the Midstream companies through June 2023.

In August 2022, the MME started a consultation process to carry out a study 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 the MME. An MME proposal is expected to be discussed among all the stakeholders prior to any change to the current methodology.

Hydrocarbon Ports

The 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 the Port Superintendence.

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.

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Decree 119 of 2015 was incorporated into Decree 1079 of 2015 issued by the Ministry of Transport, which compiles the majority of Colombian decrees and regulations in force regarding the administrative sector of transportation.

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 Resolution 073 of 2021, 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 free access to the transportation system without discrimination; and (ii) to offer optimal conditions in the operation and provision of the public transportation service.

Also in December 2021, the MME published Resolution 40408 of 2021, which established the refined products pipelines expansion plan.

In January 2023, CREG issued a resolution to amend Resolution 004 of 2021 to establish that when specific information for a specific activity from the Global Industry Classification Standard (GICS) is not available at Duff & Phelps (now Kroll), Bloomberg shall be the alternate source of information that will be used to determine the capital structure and Beta of the activity.

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, was issued with 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 40103 of April 7, 2021, which states diesel quality requirements to protect the environment, health, and quality of liquid fuels in general.

Decree 1073 of 2015 under article 2.2.1.1.2.2.1.1. 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.

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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, 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, 34, 63, 64 of 2016 and 171 of 2017). 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 the Resolution 108 of 2021, issued by CREG, is established the “opción tarifaria” mechanism or “rate option”, which is a mechanism that defers on time 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 has 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) identified the agents of the supply chain of petroleum-based liquid fuels. In this context, the Ministry of Mines and Energy through Resolution 40344 of 2017, published the required actions to ensure the LPG supply for the priority sectors in the country.

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.

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 the safety standards for LPG, storage equipment, maintenance, and distribution of LPG.

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.

Then, 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.

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The methodology for calculating jet fuel prices is set out in Law 1450 of 2011, and jet fuel prices are set by the 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 for the production of 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.

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 Fund; (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 Fund.

The operation of the FEPC is governed by Decree 1068 of 2015, amended by Decree 1451 of 2018, Chapter 1, and Title 4 (compilation decree regarding treasury public sector). 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 and such reports must be made within the next 35 calendar days of each month.

The report must also contain, among other matters: information corresponding to each fuel disaggregated daily; the discrimination of the volumes sold, and the origin national or imported of the gasoline and diesel sold. If the regular gasoline or the diesel is of national origin, the refiner/importer must inform from which refinery they come. 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.

Decree 1068 of 2015, amended by Decree 1451 of 2018, provides that the FEPC will pay 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.

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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 Spanish acronym). 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 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 2159 of 2021, which sets forth the 2022 national general budget, gave the MHCP the ability to utilize different budgetary tools to address the debts relating to the FEPC, and to even to set-off these debts against dividends that it would be entitled to receive from Ecopetrol as its major shareholder.

The Ministry of Mines and Energy issued Resolution 01192 of 2021, which contains the settlement of our Net Positions corresponding to the third and fourth quarter of 2020 and Resolution 01195 of 2021 corresponding to the first and second quarter of 2021. Accordingly, DGCPTN transferred to us COP 286,284,645,376.82 for the third and fourth quarter of 2020, and COP 2,784,715,144,662.42 for the first and second quarter of 2021.

Also, by means of Resolution 01193 of 2021, the MME instructed the DGCPTN to transfer COP 32,477,822,614.02 to Cartagena Refinery for the settlement of the company’s Net Positions corresponding to the third and fourth quarter of 2020 and, under Resolution 01194 of 2021, the MME ordered the DGCPTN to transfer COP 749,990,624,690.13 to Cartagena Refinery for the settlement of the company’s Net Positions corresponding to the first and second quarter of 2021.

On May 31, 2022, we reached an agreement with the MHCP for the payment and compensation of the COP 14.2 trillion account receivable due to us from the FEPC as of the first quarter of 2022. The accrued FEPC subsidy for the second quarter of 2022 due to us amounts to COP 10.6 trillion, which, by virtue of the provisions of the Government’s Medium-Term Fiscal Framework, are expected to be partially paid from fiscal surpluses during 2022 or with resources approved by Congress as part of the 2023 Budget for such purpose.

As of December 31, 2022, Ecopetrol S.A. recorded COP 24.4 trillion in accounts receivable due from FEPC and Cartagena Refinery recorded COP 1.9 trillion in accounts receivable due from FEPC. For a description of recent developments related to the FEPC, see section Financial Review—Factors Affecting Our Operating Results—Fuel Price Stabilization Fund (FEPC).

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 40158 of 2023, 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 Spanish acronym), 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.

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On February 2023, the Government submitted to National Congress the draft of the National Development Plan 2022-2026 in connection with biofuels, biogas and related activities, which provides that the Ministry of Agriculture and Rural Development, the MADS and the MME will regulate the proportion of biofuels present in the mix of liquid fuels, due to the relationship between biofuels and the agricultural sector. Regulation related to these products and related activities is expected during 2023. The National Development Plan is expected to be approved by Congress before May 2023.

3.10.4

Regulation of the Natural Gas Market

Decree 1073 of 2015, Part 2, Title 2, Chapter 2, 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. CREG issued Resolutions 185 (for transportation) and 186 (for supply) of 2020, which jointly replaced Resolution 114 of 2017 and its amendments, related to commercial aspects of the wholesale natural gas market in Colombia. However, pursuant to Decree 1073 of 2015 and article 19 Resolution CREG 186 of 2020, such procedures do not apply to the following activities: a) natural gas exports; b) natural gas as raw material in petrochemical production; c) natural gas commercialization from minor fields (production capacity under 30 million SCFD); d) natural gas commercialization from hydrocarbon fields under testing phase or which have not yet been declared commercially viable; e) natural gas commercialization from unconventional reservoirs; and f) internal consumption from natural gas producers.

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 participate also 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 that it may purchase 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 the 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. 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.

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 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 Spanish acronym).

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Decree 1073 of 2015 (amended by Decree 2345 of 2015) establishes an 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.

Decree 1073 of 2015 and CREG Resolution 186 of 2020: (i) provide specific procedures and forms of supply pursuant to which an agent may sell and buy natural gas in the Colombian primary and secondary market produced from large fields (capacity of more than 30 million CFPD); as well as the minimum terms that shall be included in the natural gas supply agreements, and (ii) establish the general procedure and minimum requirements for the sale of natural gas from small fields (capacity under 30 million CFPD).

Natural gas waste restrictions

The Ministry of Mines and Energy issued Resolution 40066 of 2022 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 execute efficiently and responsibly these activities, when expressly authorized. This Resolution also sets standards for the natural gas leaks detection, quantification, repair, and control in respect of the activities performed on natural gas exploration and exploitation fields. The detection and repair programs to prevent leaks are regulated by this Resolution as well as the elements included therein, as well as the reports that must be delivered to Colombian authorities.

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 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., is registered as a commercialization agent before the manager of the commercial exchanges systems and performs commercialization activities within the MEM.

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 and 101-18 of 2022. The variable component considers:

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the costs of commercialization services, as determined by article 12 of CREG Resolution 180 of 2014,

the amount that these agents must pay to the manager of the commercial exchanges system, calculated by the Trade Exchange System Administrator (“ASIC,” for its acronym in Spanish) based on the mathematic methodology set forth by CREG Resolution 174 of 2013 (as modified by CREG Resolutions 175 of 2016 and 100 of 2015) and which is paid monthly,

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the amount that these agents must pay to the Public Utilities Superintendence and to CREG, which is defined every year by CREG following the rules set in article 85 of Law 142 of 1994. These payments must be made each year,

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the cost of the guarantees that the agent must provide to participate in the MEM by following the rules of CREG Resolution 024 of 1995 (as modified, among others, by CREG Resolutions 116 of 1998, 068 of 1999, 066 of 2000, 019 of 2006, 089 of 2009, 011 of 2010, 038 of 2010, 073 of 2010, 157 of 2011, 110 of 2014, 184 of 2015, 060 of 2019 and 044 of 2020), this shall be calculated considering article 19 of CREG Resolution 180 of 2014,

the total sales to users of the commercialization agent, regulated and non-regulated, and

●

regarding the markets that commercialization agents attend, Law 143 of 1994 divides the market into two segments: regulated market (“Regulated Market”) and the non-regulated market (“Non-Regulated Market”).

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 the 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 in order to ensure open and free access.

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 generation and commercialization companies. 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 and 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 public utilities company that makes part of the SIN can perform the generation, (which consists of the production of electricity through any generation plant connected to the SIN, 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 Spanish acronym) deploying tension levels under 220 kV;. agents in charge of providing the distribution public utility are called Distribution Agents or Grid Operators (OR for its Spanish acronym) and commercialization activities in an integrated manner.

This provision 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, or “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 develop commercialization, distribution or generation activities. However, commercialization, distribution and generation companies are allowed to hold shares, quotas, or participation of corporate interest in the capital of transmission companies, as long as 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.

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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).

Ecopetrol Energía and, since August 2021, ISA, are subsidiaries of Ecopetrol S.A. While Ecopetrol Energía is a commercialization company, ISA has a significant percentage of the market share of the national transmission activity. As a result, and considering the competition rules mentioned above, the CREG established that we shall divest from Ecopetrol Energía or cease any commercialization activity as soon as reasonably practicable.

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.

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 the 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 carried out by either natural or legal persons to produce electricity mainly to meet their own needs. In case that 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 the 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 currently 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 the 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 Spanish acronym) 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.

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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 delivering of electricity surpluses to the SIN and to its subsidiaries or controlled parties.

In July 2021, Congress issued Law 2099 of 2021 which regulates 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:

(i)

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 (“FNCE” for its acronym in Spanish), mainly those of renewable sources (“FNCER” for its acronym in Spanish). The qualification of public utility or social interest will 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;

(ii)

green hydrogen was added as a FNCER and blue hydrogen as FNCE. Green hydrogen is that produced from FNCER such as biomass, wind energy, geothermic energy, solar energy, tidal energy and small hydropower. 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;

(iii)

the Ministry of Mines and Energy, or the entity designated by it, was designated 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, in order to avoid the overlapping of projects, define the areas that will not be subject to registration and determine conditions, terms, requirements and obligations;

(iv)

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, reelectrification, 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 National Hydrocarbons Agency 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;

(v)

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.

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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 clean hydrogen.

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 particular, 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 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 actually consumed by the 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.

Colombia

Electricity transmission is defined by article 1 of CREG Resolution 24 of 1995 and article 1 of CREG Resolution 22 of 2001, 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 State, through Mining and Energy Planning Unit (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 years payment period elapses, the successful bidder would be remunerated through the regulated revenue tariff methodology established by Resolution CREG 011 of 2009 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, taking into account 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.

In September 2022, the CREG, through Resolutions 101 027 and 101 031, adjusted the indexation scheme for income established in Resolution 011 of 2009. This adjustment was proposed for a transition period of one year and has been voluntarily adopted by companies. The transition period began in November 2022 and will end in October 2023.

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 energy market that were delegated to the CREG, in accordance with article 68 of Law 142 of 1994. Nonetheless, as of the date of this annual report, Presidential Decree 227 of 2023 has been suspended by the High Court for Administrative Matters (Consejo de Estado). For a more detailed description and status of such Presidential Decree, see section Regulation of the Natural Gas Market.

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Brazil

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 No. 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 higher than or equal to 230 kV and lower than 230 kV. 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”) will 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.

Peru

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 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.

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.

Chile

The public electricity transmission service provided in the National Electric System (“SEN”) 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 will 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.

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.

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3.10.8

Regulation of the Toll Roads Concessions

Colombia

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 “PPP Law”), with this latter one being one the most representative in this sector, by implementing the regulatory framework for the development of Public and Private Partnerships (PPP) in the different modes of transport, among others. 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, oriented to introduce different mechanisms and procedures to strengthen and streamline the development of PPP projects.

Regulation of Public Private Partnerships

The PPP Law allows the execution of concession contracts in the different modes of transport, among other infrastructure. Under this law, payments to contractors are subject to delivery, availability and compliance by the contractor based on the criteria for availability and service levels defined in the contract.

PPP agreements must distribute the foreseeable risks among the parties, assigning them to the party in the best position to control the risk and mitigate its effects. Likewise, it must contain formulas for recognition of economic compensations to the contractor for the early termination of the contract and the constitution of a trust fund for the management of a project’s resources.

The PPP Law introduced a distinction between Public Initiative PPP Projects, which are proposed by the granting authorities and a qualified concessionaire is selected through a competitive bidding process, and Private Initiative PPP Projects, which were introduced to facilitate the structuring infrastructure projects or public services by the private sector. The implementing legislation of the PPP Law is compiled by Decree 1082 of 2015 and was recently 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.

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:

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Improved planning. Requiring the public entities and persons responsible for planning transportation infrastructure projects to consider the impact the project will have on utility networks, cultural and archeological heritage sites, protected areas, communities and land acquisition, among other things, during the structuring phase.

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Land acquisition. Authorizing both administrative and judicial expropriation procedures. Real estate owners are allowed to grant a voluntary irrevocable permission to access and perform the required works in the property and if such permission is not granted within 15 days following the administrative expropriation order, the granting authority may request the eviction of the owner. Judges may seize the property on the grounds of public interest within ten business days following the request of the corresponding granting authority.

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Utility Networks. Providing guidelines for the relocation of utility networks, in particular regarding the allocation of costs between the infrastructure project and the public utilities suppliers.

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Environmental licenses. Not requiring environmental licenses for works or activities related to maintenance, rehabilitation and improvement of transportation infrastructure projects. Instead, the concessionaire may prepare an adaptation plan for the environmental guide (Plan de Adaptation of the Environmental Guide, or “PAGA”). Decree 769 of 2014 provides which works and activities are considered “improvement” of transportation infrastructure projects and do not require an environmental license.

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PAGA. Pursuant to Decree 769 of 2014, PAGA is an environmental plan that provides, among other things, an identification and evaluation of the environmental impacts that could be caused by the relevant project, activity or work, the related environmental management program, a list of the required environmental permits and a contingency plan. Unlike the environmental licenses, PAGAs do not need to be approved by the environmental authorities. The concessionaire submits PAGAs to ANI and the intervenor for their approval or non-objection. However, any environmental permits listed on the PAGAs must be requested from and granted by the applicable environmental authorities prior to commencing construction of the respective functional unit.

4G – 5G Highway Concessions

In Colombia, 5 generations of road concessions have been developed since 1994, which have had as a differentiating aspect the allocation of risks between the state 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 4 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.

The Ministry of Transportation of Colombia issued Decree 050 of 2023, which prohibits the increase in toll rates for vehicles that transit through the toll stations under the purview of the National Institute of Roads (Instituto Nacional de Vías or “INVIAS”) and the National Agency of Infrastructure (Agencia Nacional de Infraestructura or “ANI” for its acronym in Spanish). However, the concession agreements provide mechanisms that compensate the difference between (i) the toll rates 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.

Chile

In order 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 persons 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. 19,292 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 normally responsible for the construction, financing, operation, and maintenance of the highway 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.

3.11

Technology, Environment, Social and Governance (TESG)

We have a long-standing commitment to make positive economic, social, and environmental contributions, grounding our behavior on a solid corporate governance, a business conduct based on values and ethical principles, with transparency at the core. For this reason, Ecopetrol has strengthened the metrics and reporting of environmental, social and governance (“ESG”) issues, in line with international standards, disclosing clear short, medium, and long terms targets as well as, measuring our performance against targets, and trends.

Our commitment was recognized in the increase in our total score in the Dow Jones Sustainability Index for 2022, which climbed to a four-year high and placed us in the top 10% of companies in the Oil & Gas Upstream & Integrated (“OGX”) industry and enabled us to be included in the Emerging Markets Index and the Latin American Integrated Market (Mercado Integrado Latinoamericano or “MILA”) Index, the latter of which is made up of companies from Mexico, Colombia, Chile and Peru. Additionally, Ecopetrol was selected as a member of Standard & Poor (“S&P”) Global’s 2022 Sustainability Yearbook.

Additionally, in the results of the Carbon Disclosure Project (“CDP”), a non-for-profit organization which helps businesses and cities to disclose their environmental impact, for 2022, Ecopetrol performed above industry regional and global performance averages, and was included in CDP’s “leadership level” in the Oil & Gas industry category. Our water management initiatives, policies and results also garnered recognition at the same level as some of the most recognized companies in water management.

The TESG pillar integrates technological innovation to environmental, social, economic and governance issues, enabling the exploration of innovative solutions which accelerate implementation and enhance scalability. In 2023, the Company again will undertake a materiality assessment through which 28 TESG issues that have or could have a significant impact (positive or negative) on the ability to generate value in the short, medium, and long term and/or a significant relevance to stakeholders were initially identified in 2020. Based on this analysis, we identified and prioritize the following topics:

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Climate Change

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Water Management

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Local Development

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Occupational Health and Industrial Safety

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Biodiversity and Ecosystem Services

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Talent Attraction, Development, and Retention

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Circular Economy

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Air Quality

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Fuel Quality

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Energy Use Alternative Sources

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Process Safety

Corporate Responsibility (which is overseen by Ecopetrol’s Vice-Presidency of Corporate Affairs and Ecopetrol’s Secretary General) is the area responsible for consulting the perceptions and expectations of the seven stakeholder groups with respect to the 28 TESG issues and the Company’s attributes as a corporate citizen. In 2021, the Company’s annual stakeholder survey collected stakeholder perceptions on our management of material issues, the level of satisfaction with our delivery of value promises to each of the stakeholders, and stakeholder prioritization of ESG issues. The perceptions and expectations of the stakeholders and the results of the annual consultation are a vital input to allow us to update and maintain a current materiality assessment, which is the basis of the TESG element of the sustainability pillar of our corporate strategy.

Human Rights

In 2022, Ecopetrol completed an update to its human rights strategy, which emphasizes the need to embed a human rights perspective in the Company’s corporate strategy. Throughout 2023, Ecopetrol will work on taking concrete steps to implement this human rights perspective.

Additionally, during 2022, Ecopetrol performed three human rights risks assessments at a regional level and for security purposes.

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 2022, 119 total authorizations were granted:7 environmental licenses/management plans modifications and 44 general authorizations were granted by the ANLA and 68 permits were granted by environmental local authorities. In addition, 56 environmental permits were submitted for local and national authorities’ evaluation, and 367 archaeological programs were developed on site, based on the archaeological permits granted by the Anthropology and History Colombian Institute (ICANH, for its Spanish acronym).

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, which correspond to direct and indirect emissions associated with the purchase of energy. In addition, the Ecopetrol Group will seek to reduce 50% of our total emissions (scopes 1, 2, and 3) associated with the company’s value chain, which includes the use of its products, by 2050. However, we cannot offer any assurance on our ability to meet these goals by such dates.

To achieve these targets, we launched a program entitled “Net Zero Roadmap” focusing on four components: (i) permanent update and verification of the GHG inventory, (ii) review and optimization of a high emission intensity portfolio, and carbon price incorporation in the valuation process of future projects, (iii) gradual incorporation of competitive low carbon technologies (e.g., energy efficiency, reduction of gas flaring and fugitive emissions and vents, renewable energies, biofuels) and emergent technologies (e.g., green hydrogen and CCUS, energy storage of renewable energies), and (iv) implementation of Natural Climate Solutions (“NCS”) to abate residual emissions.

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In 2021, we verified our GHG emissions inventory for the 2017 – 2020 period through a third-party, Ruby Canyon Engineering, and the next third-party verification for the 2021-2022 period is expected to be undertaken in 2023. In 2022, we reduced 416,672 tCO2e from new projects implemented during that year, exceeding the established annual target by 59%.

In addition to the efforts on decarbonizing our operations, we took additional measures to manage our climate-related risks and opportunities, through the following actions:

(i)

Adaptation to physical risks: climate risks have been evaluated in 95 strategic locations of our assets in Colombia, to identify and implement adaptation measures in the comprehensive management of water, ecosystems and biodiversity, infrastructure and to increase the capacity and resilience to extreme weather events. The analysis has considered seven physical risks related to chronic hazards (drought and heat stress) and acute hazards (precipitation, coastal flooding, river flooding, wildfire, and wind speed) under three climate scenarios presented by the Intergovernmental Panel on Climate Change (“IPCC”): (i) SSP 1- RCP 2.6°C, (ii) SSP 2- RCP 4.5, and (iii) SSP 5- RCP 8.5.

(ii)

Innovation, research, and development: we advanced in further exploring opportunities to implement emerging low-carbon technologies like CCUS, and 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 upstream and downstream segments, and natural carbon sinks.

(iii)

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 2022, Esenttia and the midstream segment companies (Cenit, Oleoducto de los Llanos (ODL), Oleoducto Bicentenario (OBC), Oleoducto de Colombia (ODC) and Oleoducto Central Ocensa) received the Carbon Neutral certification from the Colombian Institute of Technical Standards and Certifications (ICONTEC). To achieve this, the companies developed a work plan with three major focus areas that also enabled their certification to extend for the next three years: (i) an emissions inventory, which requires tabulating a monthly and annual emissions estimate regarding the companies’ tons of CO2 emission, (ii) an emissions reduction portfolio to continue the companies’ expansion into renewable energies, and (iii) continuing to apply NCS as a compensation alternative, identifying opportunities for restoring strategic ecosystems, protecting biodiversity, enhancing ecosystem services, and contributing to the construction of more sustainable economies in the regions where they operate.

During 2022, as part of our decarbonization strategy and in line with our commitment to achieve net zero carbon emissions by 2050, we sold four shipments of 4.0 million barrels of carbon offset Castilla Blend to the United States, India and Spain. Additionally, we began to sell carbon offset premium gasoline to wholesale distributors in Colombia and created a carbon credit trading desk to manage our needs at national and international levels.

In 2022, ISA defined an annual consolidated goal relating to the company’s reduction of CO2e emissions. This goal integrated potential CO2e emissions reductions from the “Conexión Jaguar” program and emissions reductions generated from voluntary actions of eco-efficiency for the management of SF6, energy and water consumption, generation of waste, and other emissions reductions relating to remote work. The specific goals of CO2e emissions reductions associated with SF6 and energy consumption were 4,591 tCO2e and 550 tCO2e. By the end of 2022, the consolidated performance of CO2 emissions reduction by SF6 was 4,544 tCO2e, which represents 99% of the goal, and the reduction of CO2 by energy consumption was 934 tCO2e (including INTERVIAL fuel), which represents a fulfillment of 170% of the established goal.

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.

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Water Neutrality (towards water net positive)

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 2022, Ecopetrol disclosed its commitment to be water neutral by 2045. The objective is to achieve the balance between the water required for our operations, and the actions that reduce our direct water footprint, as much as economically and technically possible, as well as to replace at least 100% of the remaining water consumption through offsetting actions. To achieve this goal, we intend to undertake proactive actions, beyond environmental compliance, which we expect would enable us to manage water risks in the physical, regulatory, and reputational components, and generate benefits for the community and the environment, increasing the business sustainability in territories that progressively increase their social and environmental protection expectations.

During 2022, 131.5 million cubic meters of water were recycled, that is, 77.5% of the total water we require to operate, an 18 % increase compared to 2021. In addition, 38.1 million cubic meters of freshwater were withdrawn (22.5% of total water required for our operations), resulting in an 8.6% decrease compared to 2021.

In 2022, the water footprint of products generated in La Cira Infantas and Castilla oil fields, and Cartagena and Barrancabermeja refineries, was successfully verified by a third-party under the NTC-ISO 14046 standard, making Ecopetrol the first company in the oil and gas sector in Latin America to verify their water footprint results.

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.

(i)

Prevention and mitigation of biodiversity impacts:

Updated biodiversity information for decision-making and resilience analysis.

Incorporate the mitigation hierarchy in the planning and implementation of projects and operations.

(ii)

Implementation of nature-based solutions:

Large-scale interventions in priority areas to capture GHG emissions through NCS and generate additional biodiversity and social co-benefits.

Conservation initiatives to positively impact biodiversity and ecosystem services.

Sustainable cattle grazing systems were developed in 37.8 hectares, agroforestry actions were developed in 71.73 hectares and 53.64 forest hectares were planted. In addition, 455 new conservation agreements were signed, and 164 conservation agreements were continued from previous years which are continuously being monitored.

In 2022, Ecopetrol continued its partnerships with TNC, WCS, Fundación Natura, South Pole, the Alexander Von Humboldt Biological Resources Research Institute, and entered into a partnership with Cataruben to prevent the transformation, deforestation and degradation of ecosystems in the Orinoco highlands. ISA continued with the “Conexión Jaguar” program.

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Circular Economy

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:

(i)

further promote the efficiency in the use of materials and water and increase the recovery capacity of ecosystems,

(ii)

foster the identification of new business models that generate economic, environmental and social benefits, and

(iii)

increase innovation, technological advances and research and development of new products and services.

To date, Ecopetrol has 342 circular initiatives which are in different stages of maturity.

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 an outstanding issue based on the Company’s 2020 materiality analysis. In the past two years, specific actions have been defined through the clean air roadmap 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 verifying the criteria pollutants emissions inventory for the 2021-2022 period, which is expected be verified by a third party by 2023, and develop key initiatives in accordance with the best practices related to air pollutants emissions and objectives of the World Health Organization (WHO) Air Quality Guidelines.

Based on the above, 2023 goals were defined for the upstream and downstream segments, aiming to gradually reduce nitrogen oxide, sulfur oxide and volatile organic compound emissions.

Ecopetrol is also committed to improving fuels quality in order to contribute to a better air quality and comply with 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 particular, during the first half of 2022, the diesel and the gasoline that we distributed in Colombia had an average of 12.6 ppm and 52.7 ppm of sulfur, respectively, below the then-current local regulations of 20 ppm in diesel and 100 ppm in gasoline. Starting July 1, 2022, local regulations established new limits of sulfur in gasoline. The limit was reduced from 100 ppm to 50 ppm. Once this was implemented, the average sulfur content in Colombian gasoline decreased to 44.5 ppm. The Barrancabermeja and Cartagena refineries made adjustments to their operating schemes to apply the new regulation, which became effective in July 2022.

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 2022 a total of 459,089 tons of waste were generated, which implies a 27 % increase as compared to 2021 due to (i) an increase in drilling activities (262 wells drilled in 2022 compared 183 wells drilled in 2021) (ii) scheduled maintenance activities of pool and tanks in the Barrancabermeja refinery, and (iii) an increase in oil sludge due to a greater removal of total suspended solids from produced water, which is reused in reinjection activities.

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Prevention and Remediation of Environmental Impacts caused by Operational Incidents

This strategic pillar focuses on the prevention of operational incidents that may impact the environment, as well as remediating sites which have been historically impacted by improper practices used various decades ago, mainly by former operators.

During 2022, three incidents (greater than one barrel) lead to the spillage of 63.7 barrels, which had an impact on environmental features (surface water, groundwater, soil, flora and/or fauna). This decrease in the number of incidents in relation to 2021 and 2020 (seven and five, respectively) is primarily as a result of integrity management investments and operational discipline actions.

Production facilities have more than 16,000 kms of pipelines transporting more than 1,300 million barrels of produced fluids per year. Thus, since 2019 the Company has focused on identifying the high-risk infrastructure to integrity loss, in order to develop integrity plans for each infrastructure piece and mitigate integrity loss risks. These plans aim to address corrective actions and include specific tasks including preventive maintenance activities, pigging, and pipeline and infrastructure replacements, among others. As a result, 88.7 km of pipelines were replaced in 2022, which represented an investment of approximately USD 27.7 million.

In addition, during 2022, 91.4 hectares of soil were remediated by using bioremediation techniques on 23 affected sites that had been previously identified and prioritized.

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.

During 2022, we achieved 208 MW of renewable energy capacity, equivalent to 14.4% of total installed capacity and a 95 MW increase, compared to 2021, mainly due to the additional capacity of the Guayepo Solar Park, the Cantayús Hydroelectric Projects and the Brisas Solar Ecopark. We also began the construction of photovoltaic solutions with an additional 102 MW capacity (La Cira, Solar Cartagena and others), and the commissioning of other renewables projects (Quifa Solar Park, Wind Park Araguaney, La Estrella Solar Park, Casablanca-Membrillal), which will add 400-450 MW by the end of 2024.

Production

During 2022, our production segment had an average monthly energy consumption of 411 GWhm (gigawatts per hour per month) for its direct operation, of which 58% was provided through self-generation and the remaining 42% with non-regulated energy purchased from the National Transmission System.

Brisas Solar Ecopark, located in the municipality of Aipe (Huila) was commissioned in December 2022 and has an installed capacity of 26 MW. In addition, during 2022, the construction of Solar Park La Cira with an installed capacity of 23 MW started.

Ecopetrol is the offtaker of PPAs with Brisas Solar Ecopark for 26 MW and Guayepo Solar Park for 65 MW.

Transport

During 2022, our transport segment had an average monthly energy consumption of 56 GWhm (gigawatts per hour per month) for its direct operation, from which 99% was provided by non-regulated energy purchased from the National Transmission System and the remaining 1% was provided through self-generation.

In December 2022, Cenit acquired the small hydroelectric power station Cantayús (4.3 MW) which added to its renewable sources for self-consumption, along with the current capacity of the Castilla Solar Ecopark (21 MW) and San Fernando Solar Ecopark (61 MW).

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Refining

During 2022, the Barrancabermeja refinery’s average monthly energy consumption was 58 GWhm (gigawatts per hour per month), provided through self-generation, compared to 58 GWhm in 2021. Similarly, in 2021, the Cartagena Refinery’s average monthly energy consumption was 57 GWhm (gigawatts per hour per month), provided through self-generation, compared to 59 GWhm in 2021.

In September 2022, Ecopetrol contracted a third-party for the construction for the solar farm at the Cartagena Refinery with a capacity of 23MW.

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

Ecopetrol S.A.

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 2022, compared with the prior year, were as follows:

The severity of occupational incidents increased in 2022 compared to 2021. However, there were zero fatalities recorded in 2022, consistent with zero fatalities in 2021;

The Total Recordable Injuries Frequency (TRIF) was 0.33 in 2022, compared to 0.44 in 2021. The TRIF represents the number of employee or contractor injuries that require minimum medical treatment for every million hours worked, including fatalities, days away from work, restricted work and medical treatment cases;

The incidence of road accidents remained stable, at seven road accidents in 2022 and seven accidents in 2021, despite increased activity and higher exposure observed in 2022, given the reactivation of operations, particularly in activities that have historically recorded higher accident rates and affected the indicator. Specifically, there was an increase in the mobilization of drilling and subsurface equipment, as well as an increase in the mobilization of personnel between the company’s facilities and/or operating bases;

●

An improvement in reporting minor oil spills and identifying their causes, due to a better asset integrity and maintenance programs monitoring;

Two Tier 1 process safety incidents in 2022 compared to three incidents in 2021;

A decrease of 60% in the amount of oil spilled. In 2022, 63.7 barrels were spilled as compared to 157.8 barrels in 2021.

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 2022, 43 recordable cases occurred, where 7% led to restricted work, 19% required medical treatment and 74% led to lost days. There were no fatal incidents. Additionally, we had a 12% decrease in the number of recordable cases compared to 2021, primarily as a result of improvement of risk analysis in operational activities, prior assurance of HSE risks and skills development, and strengthening HSE skills in refining.

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Graph 7 – Total Recordable Injuries Frequency – Employees and Contractors (*) (**)

* Number of employee 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

In order to protect and minimize damage to people, the environment, and assets, Ecopetrol S.A.’s operational areas have documented, updated, disclosed and trained emergency and contingency plans to guarantee immediate, timely and effective intervention in the event of emergencies and disasters that may occur in our facilities and operations.

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 2022 by Ecopetrol S.A. are presented below:

Twenty-seven updated emergency and contingency plans that include identifying emergency and disaster scenarios, strategies, and procedures to respond to emergencies of a technological origin (spills, fires, explosions, events involving hazardous materials, emergencies of natural origin, socio-natural, anthropic, of electrical origin, events that affect people, among others) caused by other types of operational or environmental risks.

Definition and implementation of resources, equipment, and tools.

Planning and management of emergencies under the “Incident Command System” model adopted in 2011 under the USAID – BHA (United States Agency for International Development – Bureau for Humanitarian Assistance) methodology.

Execution of 130 drills in 2022 where all types of emergency scenarios were tested.

Definition of mechanisms for activation, notification, reporting to entities and authorities, and early warning system to communities.

Signing of eight mutual assistance schemes with formalized cooperation and coordination schemes in various regions of the country signed with other oil and gas companies located in the geographic area of influence of the Company's facilities.

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Consolidation and management of geographic, thematic, operational and situational information of emergencies supported by technological enablers such as the OGI (opportunity, geo-positioning and innovation) and COBRA (Ecopetrol’s tool for the creation and operation of an emergency brigade) software.

Training programs for workers who are part of the emergency response brigades.

Ecopetrol S.A. continuously implements training programs for all personnel involved in emergency or contingency response plans. In 2022, 218 trainings took place to improve our employees’ skills.

Graph 8 – Trained Personnel 2022

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 four fronts: (i) coherence, commitment, and visible leadership in process safety, (ii) risk-based process safety management, (iii) trend analysis and learning from experience and (iv) emerging risk management.

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 API-754. The reporting thresholds for API-754 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 2022, there were 0.02 Tier 1 process safety incidents per million hours worked, a decrease from the 0.03 recorded in 2021.

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Frequency of Tier 1 process safety incidents per hours worked (per million hours worked):

Graph 9 – Tier 1 Process Safety Incidents (*) (**)

* Tier 1 process safety incidents per million hours worked (API-754).

** 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 2022, Ecopetrol S.A. recorded three incidents greater than one barrel, compared to seven in 2021. The volume of oil spilled in these incidents was 63.7 in 2022, a decrease from 157.8 barrels of crude oil in 2021.

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 Presidential Decree 321 of 1999.

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, in the course of the administrative process initiated by said authority as a consequence of the events occurred during the Lisama 158 well spill, decided to impose a fine on Ecopetrol S.A. in an amount of COP 5.155 million. In the course of said administrative process, the ANLA exonerated Ecopetrol S.A. from liability for some charges, due to the fact that 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, in order 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 COP 3,863,918,267. The file is now 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.

The Attorney General’s Office (First Solicitor’s Office Delegate for Administrative Supervision) opened disciplinary investigations against certain of Ecopetrol S.A.’s employees for alleged disciplinary infringements related to the oil well abandonment process.

An initial suspension order against those Ecopetrol S.A. workers was at first issued and lifted in August 2018. Currently, their investigations finished the probationary stage.

The Prosecutor’s Office – National Human Rights Unit and International Human Rights has conducted a preliminary investigation against Ecopetrol S.A. and governmental employees for the alleged crime of environmental pollution due to the exploitation of mining or hydrocarbon deposits. Currently, the investigation is in the pre-trial stage.

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), made an arrangement 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, criminal judges have also reviewed and approved the agreement, and have monitored and verified its full compliance to the present day.

Ecopetrol S.A. simultaneously agreed to continue with the actions contained in the Environmental Recovery Plan (PRA for its acronym in Spanish), which were accepted by the ANLA as environmental recovery of the area affected by the event.

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. As of the date of this annual report the court has not scheduled a hearing date.

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. As of the date of this annual report, both complaints were properly answered, and we are still awaiting for the commencement of the evidentiary stage.

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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, as a result 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 “MAPRE 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

In order to manage occupational health and safety risks and in order to maintain a healthy, clean, safe and sustainable operation within the framework of compliance with current regulations, Cenit has implemented the Occupational Health and Safety Management System in accordance with the requirements established in Decree 1072 of 2015 and Resolution 0312 of 2019, and will monitor and evaluate compliance and performance on an annual basis.

The scope of Cenit’s Occupational Health and Safety Management System (“OSH SG”), includes its workers, contractors, interested parties and all parties that contribute to the management of operational risks with our HSE cultural principles.

The core principle of Cenit’s OSH SG is to improve care for life and occupational safety and health culture through the fulfillment of goals, continuous improvement, process optimization and operational excellence.

The following table covers CENIT’s TRIF for 2020, 2021 and 2022, 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 49 – Performance Indicators


	For the year ended December 31,
Metric	2022	2021	2020
Man-hours	22,682,665	20,006,240	16,317,616
Recordable accidents	4	6	9
Total recordable incidents frequency (TRIF)	0.18	0.30	0.55

(1)	Includes data for CENIT but does not include data for subsidiaries of CENIT

3.11.2.3

Cartagena Refinery

In 2022, approximately 7,254,165 man-hours were employed conducting Cartagena Refinery’s business activities. Our HSE performance indicators for Total Recordable Incidents Frequency (TRIF), Process Safety Incident (PSI), and Environmental Incident (EI) were well within our established expectations.

The following table covers Cartagena Refinery’s TRIF for 2020, 2021 and 2022, 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 2011 – 2022.

Table 50 – Performance Indicators


	For the year ended December 31,
Metric	2022	2021	2020
Man-hours	7,254,166	6,194,468	5,179,194
Recordable accidents	2	8	1
Total recordable incidents frequency (TRIF)*	0.28	1.29	0.19
Environmental Incidents (EI)	—	—	—
Process Safety Incidents (PSI)	—	—	—

*	These risks were associated with normal operations.

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3.11.2.4

ISA

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) the frequency of work accidents in own workers and contractors.

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 2022, exposure to occupational risk increased by 9.1%, with 4.0 million additional man-hours of work compared to 2021, primarily as a result of an increase in its workforce. Nonetheless, the integrated accident frequency rate (own personnel and contractors) decreased by 16.10% compared to the same period. Throughout the year, the number of work accidents per 1,000,000 hours of work has been lower, as set forth in the table below:

Table 51 – Integrated Frequency Index for Employees and Contractors


	For the year ended December 31,
Metric	2022	2021	2020
Man-hours worked⁽¹⁾	48,602,913	36,526,796	36,033,784
Total accidents	347	319	457
Frequency rate⁽²⁾	7.14	8.73	12.68

(1)	The Ruta Costera company is included in 2022 results.

(2)	Frequency Rate calculated as: (Occupational accidents in the period/man-hours of exposure during the period)*1,000,000. It considers all workplace accidents, including those that did not result in lost time injuries. These risks were associated with normal operations.

Fatal Accidents

During 2022, three fatal accidents occurred in companies controlled by ISA as follows:

Intervial: two fatal accidents at a road construction contractor company; and

ii.

Companhia de Transmissäo de Energia Elétrica Paulista (“CTEEP”): one fatal accident of a CTEEP worker during the inspection of a power substation.

3.12

Related Party and Intercompany Transactions

Set forth below is a description of material related-party transactions. For additional information about transactions with related parties, see Note 31 to our consolidated financial statements.

Oleoducto Central S.A.S. (Ocensa)

Ecopetrol S.A. has entered into a number of agreements with its 72.65%-owned subsidiary, Ocensa, of which the following are the most significant:

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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 as a result 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 executed 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 2022, the transportation services provided by Ocensa to Ecopetrol S.A. under these two agreements amounted to USD 1,067.4 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 into 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 into a crude oil supply contract, pursuant to which Ecopetrol will 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 2022, Ecopetrol S.A. received an aggregate sum of USD 8.5 million; under these two agreements.

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.

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In 2022, Ocensa provided transportation services to Hocol, as assignee of transportation rights from original shippers and was paid USD 23.3 million for such services.

Oleoducto de Colombia S.A. (ODC)

Ecopetrol S.A. entered into the following agreements with its 73%-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 will 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 last tariff update by the MME was in 2019 for a four-year term, with a yearly adjustment based on macroeconomic variables. In 2022, payments made by Ecopetrol S.A. under this agreement amounted to USD 144 million.

In August 1992, an operation and maintenance agreement was signed for the Vasconia and Coveñas terminals both property of ODC. The duration of this agreement is indefinite but can be terminated by any party upon six months’ notice. The initial contract included services rendered by Ecopetrol S.A. directly or by third-party contractors hired by Ecopetrol S.A. through mandate, with a variable surcharge over expenses and third-party contracts between 5% and 12% plus any applicable taxes. In 2014, an amendment to the agreement was signed, adjusting the monthly fixed rate to include expenses of services rendered directly by Ecopetrol S.A., plus an additional 10% fee, and to eliminate the administrative surcharge. The contract also includes a variable sum related to contracts and purchases made by Ecopetrol S.A. through mandate. In March 2015, the monthly rate was adjusted for both Vasconia and Coveñas Stations. In March 2016, an amendment to the agreement was signed, adjusting the agreement’s scope to include the pipeline’s maintenance and adjusting the monthly fixed rate. In December 2017, an amendment to the agreement was signed, adjusting the agreement’s scope according to the change of the maintenance model of the midstream segment and including the Caucasia station and the Vasconia-Coveñas pipeline system into the scope. In March 2018, the parties amended the agreement in order to narrow the scope to the purchase and contracting management and adjust the monthly rate. In February 2019 the scope of this agreement was amended to include planning, structuring, administration, and execution of the agreements signed with the Ministry of National Defense (Fuerzas Militares de Colombia). In July 2020, an amendment to the agreement was signed, adjusting the monthly fixed rate. In 2021, three amendments to the agreement were signed, adjusting the scope of the contract and the monthly fixed rate. This agreement expired May 31, 2021, was not renewed and pursuant to its terms, on December 28, 2022, Ecopetrol S.A. reimbursed ODC USD 0.21 million as a result of the liquidation of the contract.

In March 1998, a joint operation agreement was signed for the TLU-1 Coveñas buoy. The duration of this agreement is indefinite and can be terminated by mutual agreement. In December 2013, Ecopetrol S.A. assigned its rights under this agreement to Cenit, though Ecopetrol S.A. kept its role as operator under the agreement. On September 15, 2021, Ecopetrol S.A. ceased its role as agreement´s operator. Pursuant to the terms of this agreement, on October 24, 2022, Ecopetrol S.A. reimbursed ODC USD 1.8 million for the return of prepayments generated in the operations executed in the framework of the contract.

In September 1999, a joint operation agreement was signed for the TLU-3 Coveñas buoy between Ocensa, ODC and Ecopetrol. The duration of this agreement is indefinite. In December 2013, Ecopetrol S.A. assigned its rights under this agreement to Cenit, though Ecopetrol S.A. kept its role as operator under the agreement. On September 15, 2021, Ecopetrol S.A. ceased its role as operator and pursuant to the terms of the agreement.

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 2022, the transportation fees billed by ODC were: Equion (USD 0.42 million) and Hocol (USD 0.93 million).

On December 23, 2022, ODC entered into 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 28, 2022, ODC received USD 0.03 million from Equion as an advance payment.

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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 replaced in January 2014 by a new agreement that expired in December 2020. This is a ship-or-pay agreement covering 167,000 bpd for 2014, 149,000 bpd for 2015 and 139,000 bpd until 2020. In January 2017, this agreement was amended in order to maintain the economic and commercial balance for the parties, based on changes to the 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, in order to transport barrels that were paid for but were not transported. On November 25, 2021, Ecopetrol S.A. entered into an amendment that adjusted terms and definitions of the applicable TRM and extended the term to provide ship-and-pay transportation services until November 2026. Payments by Ecopetrol S.A. under this contract were COP 881.15 billion in 2022.

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 in order to change the way ODL is remunerated by this service, improving the structure of the agreement. Pursuant to the terms of this agreement, Bicentenario paid to ODL COP 9.99 billion plus applicable taxes in 2022.

Oleoducto Bicentenario de Colombia S.A.S.

Ecopetrol S.A. has entered into the following agreements, among others, with its 100% owned subsidiary, Oleoducto Bicentenario:

In June 2012, Ecopetrol S.A. entered into ship-or-pay and ship-and-pay agreements with Oleoducto Bicentenario for the transportation of crude oil from Araguaney to Banadía that established a price which requires the payment of Oleoducto Bicentenario’s indebtedness to local banks for 12 years. This tariff is collected through a trust; the trust is also responsible for making the debt service payments to the banks. The duration of the ship-or-pay agreement is the earlier of 12 years or when the credit has been entirely paid, and the duration of the ship-and-pay agreement is 20 years after the ship-or-pay terminates. Under these agreements, Oleoducto Bicentenario has committed to transport at least 110,000 bpd, of which 55% of the agreement volume is provided directly by Ecopetrol S.A. and 0.97% indirectly by Hocol. In March 2014, the parties signed an amendment to these agreements under which Oleoducto Bicentenario acknowledges having received an advance tariff payment which can be amortized through volumes of crude transported in excess of 110,000 bpd. In April 2015, these agreements were amended to modify certain definitions to reflect new terms from the negotiation of the debt, which included a modification of participant banks and a reduction of the interest rate. In March 2017, the parties signed an amendment to these agreements in order to include the terms and conditions of the “contingent service” that involves the transportation of crude oil from Banadía to Araguaney when this service is required and includes a ship-or-pay commitment of 270,000 bpd when the contingent service is needed. In addition, this amendment includes an equivalent credit note of one and a half days of service into the original ship-or-pay agreement for the transportation of crude oil from Araguaney to Banadía. Hocol has signed an amendment to the transportation agreement from Araguaney to Banadía, in order to receive the related credit note in case that the availability of the service in that direction is suspended in order to enable the contingent service (Banadía-Araguaney). In September 2017 the agreement was amended to specify that the “contingent capacity” could be over 180,000 barrels per any “contingent service” operation and to extend the term until July 30, 2018. In July 2018, the agreement was amended to extend the term to provide the “contingent service” until March 23, 2019. In September 2018, this agreement was assigned by Hocol to Ecopetrol S.A. In November 2018, the agreement was amended to remove the restriction on the number of contingent services during 2018. Since 2019, this agreement has been amended from time to time to extend the term to provide the “contingent service”, most recently in November 2022 to allow such extension until May 31, 2023. On November 9, 2021, the agreement was amended to adjust the conditions pursuant to which it may be assigned to third parties without prior approval of banks. Pursuant to the terms of these agreements, in 2022, Ecopetrol S.A. paid COP 710.76 billion to Bicentenario S.A.

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In June 2012, Ecopetrol S.A. and Hocol entered into storage or pay and storage and pay agreements with Oleoducto Bicentenario. Under these agreements, Oleoducto Bicentenario is committed to receive, store, preserve and deliver our crude oil. The storage or pay agreement will terminate when Oleoducto Bicentenario’s indebtedness to local banks has been entirely paid, and the duration of the storage and pay agreement is 20 years after the storage or pay agreement terminates. In April 2015, this contract was amended to modify certain definitions to reflect new terms from the negotiation of the debt, which included a modification of participant banks and a reduction of the interest rate. In September 2018, this agreement was assigned by Hocol to Ecopetrol S.A. Pursuant to the terms of this agreement, Ecopetrol S.A. paid to Oleoducto Bicentenario COP 39.67 billion, plus applicable taxes, in 2022.

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 (“renewed agreement”) and expires on January 31, 2026. Pursuant to the terms of the renewed 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 2022, Ecopetrol S.A. paid a total of COP 619.3 billion under the current agreement.

Additionally, Ecopetrol S.A., as Cartagena Refinery’s legal agent, signed another supply agreement with Ecodiesel on October 1, 2020, that is valid until September 30, 2023. Pursuant to the terms of this agreement, Ecodiesel must deliver to Cartagena Refinery, and Cartagena Refinery must in turn purchase a minimum of 10,400 barrels of Ecodiesel’s biodiesel production each month. In 2022, Cartagena Refinery paid a total of COP 148.6 billion to Ecodiesel under this agreement.

In 2022, Ecopetrol S.A. bought COP 619.3 billion worth of biodiesel from Ecodiesel for its own consumption and COP 148.6 billion worth of biodiesel for Cartagena Refinery’s consumption.

Savia Perú S.A.

On February 19, 2016, Ecopetrol S.A., as lender and shareholder of 50%, and Savia Perú S.A., as borrower, entered into a five-year loan agreement for an aggregate principal amount not to exceed USD 70 million. The proceeds of the facility were used to (i) repay short term loans and (ii) pay shortfalls related to final judgments (in case they materialize). The loan agreement accrues interest at an annual rate of 4.99%, which can be adjusted on an annual basis, with semi-annual interest payments and principal payments beginning on the 21st month following the disbursement date. Total disbursement was USD 57 million through the disbursement period ended on December 31, 2017. On December 11, 2019, Ecopetrol S.A. and Savia Perú agreed on an amendment to the terms of the loan agreement, in order to revise the payment schedule of the loan, without changing the original maturity, nor the interest rate. As of December 2020, the outstanding balance of the obligation with Ecopetrol S.A. is USD 28.3 million under the loan agreement. KNOC, as shareholder of the other 50% of Savia Perú S.A., signed a facility under the same terms and conditions as described above.

On January 19, 2021, Ecopetrol S.A. signed a Share Purchase Agreement with De Jong Capital LLC, through one of its subsidiaries as buyer, pursuant to which Ecopetrol S.A. sold its 50% ownership interest in Offshore International Group Inc. (OIG; Savia Perú’s parent company). KNOC also sold its participation on OIG (the remaining 50%) to De Jong Capital LLC, under the same terms and conditions as Ecopetrol S.A.

On the same date, Ecopetrol S.A. and Savia Perú agreed on an amendment to the terms of the loan agreement described above, in order to revise the payment schedule of the loan and its maturity, with the interest rate remaining unchanged.

After the occurrence of an event of default due to failure to make a principal repayment by Savia Perú S.A. on September 2021, a restructuring process began in coordination with KNOC which sought to maximize the possibility of recovering the outstanding loan. The process concluded in February 2022 with the execution of a new set of documentation that incorporates: (i) an increase in the interest rate to 6.5%, (ii) the creation of a pledge over 100% of the shares of Procesadora de Gas Pariñas S.A.C. (a subsidiary of OIG), (iii) the creation of a trust structure holding the collection rights of Savia Perú S.A. derived from its sales to PetroPeru with Ecopetrol and KNOC as beneficiaries, (iv) monthly interest and principal payments, (v) mandatory prepayments under certain specific circumstances, and (vi) the obligation by Savia Perú S.A. to apply commercially reasonable efforts to prepay all the loans with any excess cash. The final maturity of the loan remains unchanged and is December 2023.

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As of the date of this annual report, Savia Perú owed USD 8.8 million to Ecopetrol S.A. under this loan agreement, however, Savia Perú is no longer a related party to the Ecopetrol Group.

ISA Acquisition

On August 11, 2021, Ecopetrol S.A. signed the Inter-Administrative Share Purchase Agreement with the Colombian Government, represented by the MHCP, pursuant to which Ecopetrol S.A. agreed to acquire 51.4% of the outstanding shares of ISA from the MHCP for a purchase price of COP 14,236,814,025,000, or USD 3,672,992,823.94 (the “Acquisition” and the “Acquisition Price,” respectively) based on the COP/USD market exchange rate of COP 3,876.08 to USD 1.00 in effect on August 20, 2021. The acquisition was consummated on August 20, 2021. Ecopetrol S.A. financed the Acquisition through the Acquisition Loan, from which USD 3,672,000,000 was disbursed in connection with the closing of the Acquisition. As of the date of this annual report, the Acquisition Loan has been repaid in full through proceeds obtained from the issuance of Ecopetrol securities in the international capital markets in 2021 and 2023, as the full disbursement of a USD 1.2 billion credit facility it entered into in August 2021 with a group of international banks, as approved by the MHCP through Resolution 1824 of July 30, 2021.

See section Financial Review––Financial Indebtedness and Other Contractual Obligations.

Although the Colombian Government, through the MHCP, was the majority shareholder of ISA, as well as our largest shareholder, the Acquisition was structured and negotiated on an arm’s length basis. Ecopetrol S.A. and the Colombian Government each engaged their own financial advisors and legal counsels for purposes of consummating the Acquisition. In addition, for purposes of determining ISA’s valuation, Ecopetrol S.A. engaged two experienced investment banking firms and a separate independent advisor to deliver a fairness opinion related to ISA’s valuation and Ecopetrol S.A.’s final purchase price proposal. Moreover, our Board of Directors, which is composed by a majority of independent members (8 of 9 members are independent), retained full oversight and autonomy to approve the Acquisition, with the non-independent member abstaining from determinations relating to the Acquisition. In line with the aforementioned, on March 25, 2021, our Board of Directors approved the establishment of a temporary special committee comprised of independent board members to help it evaluate the valuation of ISA, the price range and/or the price of the Acquisition. The Acquisition Price for our 51.4% acquired interest in ISA was unanimously approved on July 30, 2021, by our Board of Directors.

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:

●

Selling and purchasing goods, including crude oil purchases of ANH royalties (see below);

●

Selling and purchasing properties and other assets;

●

Rendering and receiving services;

●

Leasing assets;

●

Depositing and borrowing money; and

●

Using public utilities.

We have an agreement with the ANH by which we purchase all crude oil delivered to the ANH as royalties 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 sell the physical product purchased from the ANH as part of our ordinary business.

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For the period between January 2022 and December 2022, we purchased 27 million barrels of crude oil from the ANH corresponding to royalties paid in kind by oil producers in Colombia. The contract between the ANH and us is in force and was extended until June 30, 2023. 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 State. The State’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 a majority of our common shares. Neither Ecopetrol S.A. nor the ANH have the ability to 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 considered to be 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, 2022, Ecopetrol S.A. recorded COP 24.41 trillion in accounts receivable due from FEPC, while Cartagena Refinery recorded COP 1.9 trillion in accounts receivable due from FEPC.

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 downstream, upstream and midstream segments for hydrocarbons and electric power transmission and toll roads concessions, as summarized below.

Also, as part 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 is in charge of overseeing and optimizing 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 2022 BGRe increased its level of retention from USD 93 million to USD 127.5 million, supported by a retention capacity study, which was carried out in the same year.

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

Downstream, Upstream, and Midstream

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.

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As a proactive strategy to deal with the hardening conditions of the worldwide reinsurance market for the last three years, in July 2020, Ecopetrol S.A. became a member of the Everen. Everen 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 insures assets worldwide for a total value over USD 3 trillion. Its credit rating is A (S&P) and A2 (Moody’s). Currently, more than 60 companies in the world are members of Everen.

Under the model described above, the corporate insurance program has been consolidated in two main categories:

(i)

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).

(ii)

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 downstream, upstream, and midstream operations in excess of our local insurance programs (when applicable).

In the tables below we set forth our insurance program for our downstream, upstream and midstream operations and the companies covered, along with limits and coverage details.

Table 52 – Category A: Coverages through the Everen and Reinsurance and Insurance Market for the Downstream Segment

Limit (eel / agg)⁽¹⁾

Deductible

Ecopetrol

USD Millions

Onshore

Offshore

Onshore

Offshore

Downstream

Cartagena Refinery

Esenttia

Policies

Property all risk

3,000

N/A

5.0

N/A

Sabotage and terrorism

600

N/A

0.5

N/A

(1)	Eel: each and every loss. Agg: Aggregate.

Table 53 – Category A: Coverages through the Everen and Reinsurance and Insurance market for the Upstream segment

Limit (eel / agg)⁽¹⁾

Deductible

Ecopetrol

Santiago

ECP

ECP Costa

USD Millions

Onshore

Offshore

Onshore

Offshore

Upstream

Equión

Hocol

Oil

America

Permian

Afuera

Policies

Property all risk⁽²⁾

200

N/A

1.0

N/A

Sabotage and terrorism

600

N/A

0.5

N/A

Control of wells

350

350.0

1.0

5 / 6

N/A

(1)	Eel: each and every loss. Agg: Aggregate.

(2)	USD 200 million Property All Risk but USD 350 million Maximum Loss limit and in the aggregate in respect of earthquakes.

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Table 54 – Category B: Transversal Coverages through the Traditional Insurance and Reinsurance Market for the Downstream, Upstream and Midstream Segments

Limit

Esenttia

Santiago

ECP

ECP Costa

USD Millions

(eel / agg)⁽¹⁾

Deductible

Ecopetrol

Cartagena Refinery

Esenttia

Equión

Hocol

Oil

America

Permian

Brazil

Afuera

Cenit

Ocensa

ODL

OBC

ODC

Invercolsa

Policies

Third party liability

500

10.0

N/A

Crime

50 / 100

0.5

N/A

Directors & Officers

125

Various

Cargo

50 / 120

3% dispatch

N/A

Charterers

750

0.02

N/A

Cyber(2)

35 / 150

Various

(1)	Eel: each and every loss. Agg: Aggregate.

(2)	Coverage through the Everen and Reinsurance and Insurance Market. Coverage under Section one (buyback for property) does not apply to midstream 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 midstream subsidiaries continue having an independent program for their oil transportation companies (including crime and (D&O) policies).

Table 55 – Midstream’s Program

Limit (eel / agg)⁽¹⁾

Deductible

USD Millions

Onshore

Offshore

Onshore

Offshore

Cenit

Ocensa

ODL

OBC

ODC

Policies

Property all risk⁽²⁾

200

0.250

0.50

Sabotage and terrorism⁽³⁾

70/25

200

0.150

0.50

Third party liability

100

0.1

0.1/0. 5

Directors & Officers⁽⁴⁾

—

Crime

0.180

Cyber⁽⁵⁾

0.25

0.50

Environmental Liability⁽⁶⁾

1.00

(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 12 months).

(3)	Does not include Caño Limón – Coveñas (CLC) and Oleoducto Transandino (OTA) systems owned by Cenit. Limits: USD 70 pumping stations, USD 25 pipelines

& USD 25 Third Party Liability from acts of Sabotage and Terrorism. For Pollution liability the deductible USD 0.500 million

(4)	Aggregate limit of USD 90 million worldwide coverage. Deductible only for coverage No.2 in the USA.

(5)	Coverage under Property All Risk policy, buyback of cyber exclusion. Limit Aggregate for the Midstream.

(6)	Coverage for environmental liability for the pumping stations. Limit Aggregate for the Midstream.

The corporate insurance programs detailed above 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.

Regarding the offshore operations in the U.S. Gulf Coast, Ecopetrol America is party to Operating Agreements, or OAs, that 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.

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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. In 2020, we obtained 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.

3.13.2

Electric Power 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 1 million as authorized capitalization and participated in the placement of Property damage, Sabotage & Terrorism and Construction All Risk Policies (AR/EAR) allowing direct access to the commercial reinsurance markets.

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 56 – ISA’s Program

Limit (eel /

ISA &

USD Millions

agg)

Deductible

Colombia

Perú

Chile

Bolivia

Brasil

Argentina

Policies

Property all risk⁽²⁾

Various

70.00

25.0

N/A

Sabotage and terrorism⁽³⁾

Various

20.00

N/A

Equipment Electric⁽³⁾

129

37.30

9.30

N/A

16.3

1.8

Construction All Risk

250

N/A

Directors & Officers

N/A

11.0

Cyber

25.0

5.0

Crime

0.20

N/A

1.0

N/A

1.0

(1)	Eel: each and every loss. Agg: Aggregate.

(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 of the loss minimum USD 250,000.

Note: Different coverages and conditions may apply in each country for each subsidiary.

The policies detailed above 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.

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3.14

Human Resources/Labor Relations

3.14.1

Employees

As of December 31, 2022, the Ecopetrol Group had 18,903 employees, an increase of 2.9% compared to 2021, equivalent to 525 employees, primarily due to an 8.9% increase in the number of ISA employees and a 1.9% increase in the number of employees of Ecopetrol S.A., which increases are due to the replacement or filling of vacancies approved within the organization. These increases were offset by a 3.1% decrease in Invercolsa S.A.’s workforce, equivalent to 68 employees.

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, 2022, 2021 and 2020.

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Table 57 – Ecopetrol Group’s Employees


	For the year ended December 31,
	2022	2021	2020

	(Number of employees)
Ecopetrol S.A.
Hydrocarbons
Upstream
Exploration	191	215	208
Production	2,334	2,335	2,271
Others	1,391	769	712
Total Upstream	3,916	3,319	3,191
Downstream	—	—	—
Refining	2,532	2,497	2,526
Marketing		158	145
Others		127	38
Total Downstream	2,532	2,782	2,709
Transport	—	—	802
Others	—	818	820
Marketing*	142	—	—
Total Hydrocarbons	6,590	—	—
Low-Emissions Solutions	95	—	—
Total Operations	6,685	6,919	7,522
Corporate	2,811	2,403	2,248
Total Ecopetrol S.A.	9,496	9,322	9,770
Ecopetrol America LLC.	36	38	47
Ecopetrol Permian LLC.	54	43	16
Ecopetrol USA	36	34	29
Bioenergy S.A.S.	—	—	—
Bioenergy Zona Franca S.A.S.	—	—	—
Hocol S.A.	367	349	346
Equion Energía Limited	23	24	38
Oleoducto Central S.A.	272	279	283
Oleoducto de Colombia S.A.	26	24	15
Oleoducto de los Llanos S.A.	75	78	77
Oleoducto Bicentenario de Colombia S.A.S.	—	—	—
Ecopetrol del Perú S.A.	—	—	—
Ecopetrol Costa Afuera de Colombia S.A.S.	—	—	—
Refinería de Cartagena S.A.S.	47	50	98
Ecopetrol Óleo e Gás do Brasil Ltda.	37	36	35
Esenttia S.A.	416	426	417
Esenttia MB	41	42	41
Cenit Transporte y Logistica de Hidrocarburos S.A.S.	1,107	1,079	511
Invercolsa	2,153	2,221	2,247
Ecopetrol Energía S.A. E.S.P	—	7	7
Ecopetrol Asia Trading	4	—	—
Electric Power Transmission and Toll Roads Concessions	—	—	—
Interconexión Eléctrica S.A. E.S.P	4,713	4,326	—
TOTAL	18,903	18,378	13,977

As of December 31, 2022, Kalixpan Servicios Técnicos, S. de R.L. de C.V. was in liquidation, and Topili Servicios Administrativos S. de R.L. de C.V. was acquired by Esenttia and did not have direct employees. Additionally, Ecopetrol Capital AG and Black Gold RE did not have direct employees.

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Loans and investment in training and development for our employees

To improve the quality of life of our employees, Ecopetrol S.A. extends various types of loans to its employees, including housing loans and general-purpose loans. The principal amount of the loan depends on the applicant’s tenure. Ecopetrol S.A. does not guarantee any loans made by third parties. In 2022, Ecopetrol S.A. extended 1,195 housing loans for a total of COP 353.0 billion and 2,123 general-purpose loans for a total of COP 26.2 billion. In 2022, Ecopetrol S.A. also provided on-site and external training and development, which totaled to COP 48.0 billion, and it extended a total of COP 208.7 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 7th 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 has made progress in the internalization of the Principles of the Culture Statement, which were updated in 2020 to include the following principles: (i) life first, (ii) collaboration, (iii) ethics & transparency, (iv) innovation, (v) excellence, and (vi) leadership.

Every two years Ecopetrol conducts a third-party survey to measure its “Organizational Culture Index”. The survey includes questions relating to three main topics: (i) “culture”, which measures the extent to which employees are behaving consistently with the Principles of the Culture Statement, (ii) “leadership”, which measures the way the Company’s leaders are fostering the expected behaviors among employees, and (iii) “work environment”, which measures the extent to which employees are satisfied with and feel valued by the organization. In 2021, Ecopetrol reached a “Cultural Adoption Level” of “Favorable” where employees expressed that the Principles of the Culture Statement had been internalized.

In addition, the organization has implemented a “listening strategy,” in which employees are continuously surveyed about specific topics related to the culture. In 2022, Ecopetrol conducted an employee survey to receive feedback on the most and least favorable items of the Organizational Culture Survey. The results were “very favorable” compared to the benchmark.

3.14.2

Collective Bargaining Arrangements

Ecopetrol S.A.

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There are 19 industrial labor unions and 9 company-specific labor unions, for a total of 28 coexisting labor unions within Ecopetrol S.A. During 2022, the Group fulfilled its obligations under the 2018-2022 collective bargaining agreement, as well as its other obligations within the framework of the collective bargaining process. During 2022, the Company held a total of 375 meetings with its unionized workers. The Company manages compliance with union rights with respect to the discount of union dues, permits and union guarantees. Likewise, it fully observes the rules that govern aspects such as trade union rights and other rights related to freedom of association.

As of December 31, 2022, Ecopetrol S.A. had a staff of 9,496 active workers of which, and in accordance with current legal provisions, 78% received benefits from the application of the Collective Bargaining Agreement. In addition, 51% Ecopetrol S.A. active workforce was affiliated with at least one of the 28 labor unions.

Interconexión Eléctrica S.A.

There are 23 labor unions within ISA and its subsidiaries with a total of 1,372 members are covered by 24 collective bargaining agreements that also benefit, per extension, 1,356 additional syndicate members. Additionally, there are two collective bargaining agreements that cover 350 employees (or 7.4% of ISA’s total workforce). The collective bargaining agreements establish certain terms and conditions of employment and are subscribed to on an individual, voluntary basis by employees. Collective bargaining agreements are not negotiated by unions or other representative bodies on behalf of our employees, but rather are developed through informal discussions between management and employees.

Cenit Transporte y Logística de Hidrocarburos S.A.S.

There are seven labor unions in Cenit, to which 21% 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 with a term of four years, expiring on August 31, 2023. The collective bargaining agreement award union protections and benefits which exceed those established by law.

4.	Financial Review

Our consolidated financial statements for the years ended December 31, 2022, 2021 and 2020 were prepared in accordance with IFRS as issued by the IASB.

IFRS differs in certain significant aspects from the current Colombian IFRS (which is 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 (Colombian IFRS) and IFRS below.

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 companies, associates and joint ventures, to our consolidated financial statements included in this annual report.

4.1

Factors Affecting Our Operating Results

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, particularly in Latin America, higher interest rates, and the COP/USD exchange rate, (iv) public order situations, (v) regulatory changes, including higher taxes and amendments to the fiscal regime of crude oil and gas royalties, 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, change in environmental regulations, 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 Midstream segment, terrorist attacks by guerillas against our pipelines 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.

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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 financial results of the new Electric Power Transmission and Toll Roads Concessions segment. Results from our electric power transmission and toll roads 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 a number of crude oil short-term 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 regulations, contractual arrangements, and the spot market, in turn, linked to international benchmarks. Local sales represented 50.1% of our total revenues, on average, for the past three years.

International sales and prices

Our international sales represented 49.9% of our total revenues, 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 crudes 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 “Exploration and Project expenses.” Consequently, an increase in the number of exploratory wells we declare as dry or unsuccessful will 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.

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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 five thousand bpd to 25% for fields producing more than 600 thousand bpd. 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 we produce is considered part of our reserves and production, without any deduction for royalties. The cost of natural gas royalties totaled COP 1,149,664 million in 2022.

On September 30, 2020, Law 2056 of 2020 was issued, (“Whereby which 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. To this date there has been no pronouncement by the court on whether it is admitted or not.

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, which will result in the payment of higher income taxes and higher effective tax rates by Colombian companies such as Ecopetrol S.A. and Hocol. 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.

Purchases of hydrocarbons

We purchase all crude oil delivered to the ANH as royalties 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 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, 2023.

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.

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Electricity transmission rates

Electricity transmission is a regulated activity in all jurisdictions where our subsidiary 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 revenues of the new Electric Power 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

On February 24, 2022, Russia launched its military invasion of Ukraine, with strong ramifications for global crude and oil product supply and a surge in prices. Brent crude average prices surged from USD 70.9/Bl in 2021 to USD 99.0/Bl in 2022, peaking at USD 128.0/Bl in early March 2022.

The increase in prices has had both positive and negative impacts on our Group. On one hand, the rise in the average price of ICE Brent has increased revenues from the sale of our crudes, and higher prices of diesel, gasoline, jet fuel and other refined products have been favorable for the 2022 financial results of our Cartagena and Barrancabermeja refineries. However, the increase in prices has also had a negative effect on our Group, including the weakening of our crude oil differential versus Brent. To mitigate this, Ecopetrol has worked to improve the positioning of our crude oil and diversify destination markets. In addition, the high prices have affected our purchases of crude oil and oil products, which are used as inputs and raw materials for our production processes as well as to meet the growing national demand for fuels. Lastly, higher energy costs, coupled with the international logistics crisis, have generated pressures on our operating costs and project execution timelines.

We maintain a close and constant monitoring of various Russia-Ukraine related 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 its operations.

Fuel Price Stabilization Fund (FEPC)

The Fuel Price Stabilization Fund – 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 Fund 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.

At the beginning of 2022, the Russia-Ukraine conflict caused sharp increases in international crude oil and product prices, resulting in a significant gap between the international market prices of regular motor gasoline and diesel, and the regulated prices in Colombia. This led to an increase in the accumulation of the FEPC balance. During the year 2022, the FEPC balance grew by COP 36.7 billion due to the difference between the international market prices of regular motor gasoline and diesel, and the regulated prices in Colombia. However, the balance of this account was reduced by COP 18.3 trillion in 2022, resulting in a final balance of COP 26.3 trillion in accounts receivable as of December 31, 2022.

Since September 2022, the Colombian government has implemented a series of gasoline price increases, including three successive increases in regular motor gasoline of 200 Colombian pesos and subsequent increases of 400 Colombian pesos in January 2023, 250 Colombian pesos in February 2023, and 400 Colombian pesos in March 2023. These price increases were necessary to mitigate the impact of rising international prices and maintain a stable domestic market. The difference in prices generated an account deficit in the FEPC, and a final balance of COP 26.3 trillion in accounts receivable as of December 31, 2022, in favor of Ecopetrol.

These accounts receivable represent 67% of Ecopetrol’s total short-term accounts receivable as of December 31, 2022, and create 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 fund.

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The proposal for the distribution of dividends on the results of the year 2022 made by the Board of Directors of Ecopetrol establishes the payment of a dividend for a total amount of COP 24,382,200 million, of which of COP 21,576,180 million would correspond to the Nation as a majority shareholder. If approved by Ecopetrol’s General Assembly of Shareholders on March 30, 2023, dividend payments to the Nation will be used to offset a portion of FEPC’s accounts receivables owed to Ecopetrol.

Integration of ISA

On August 20, 2021, Ecopetrol acquired 569,472,561 shares of ISA, equivalent to 51.4% of its outstanding shares, for which Ecopetrol paid the agreed price of COP 14,236,814 million or COP 25,000 per share to the Ministry of Finance and Public Credit. The payment was made in US Dollars, for an equivalent amount of USD 3,672,992,824, financed through the Acquisition Loan and cash on hand.

Once the transaction closed, as of August 31, 2021, ISA and its subsidiaries began to be fully integrated into Ecopetrol’s consolidated financial statements as a new reporting segment, the Electric Power Transmission and Toll Roads Concessions segment. During 2022, we continued to integrate ISA into the Ecopetrol Group. The primary effects on our consolidated financial statements reflecting a full year of ISA’s operations, as of and or the year ended December 31, 2022 are presented below:

(i)

Consolidated statement of profit and loss:

Contribution to the net income attributable to owners of Ecopetrol over ISA’s results of COP 1,156,798 million in 2022, as compared to COP 261,690 million for four months in 2021.

The segment as a whole obtained a net profit attributable to Ecopetrol shareholders of COP 673,688 million in 2022, compared with COP 386,438 million for four months of 2021.

For additional information regarding the integration of ISA and its effect on our financial statements see section Financial Review—Operating Results—Electric Power Transmission and Toll Roads Concessions Segment Results and Note 33 to our consolidated financial statements.

4.2

The COVID-19 Pandemic

Effect on our 2022 Results

The National Government, through the Ministry of Health and Social Protection, during the first semester of 2022, issued regulations associated with preventive measures such as international travel controls, restrictions on schools, workplaces, and restrictions on public gatherings, among others. However, the issued regulations had a mainly preventive approach and did not generate mandatory lockdown for the country.

In 2022, our Group experienced a significant upturn in economic activity, which had a direct and positive impact on our operational performance. This was largely attributed to the easing of COVID-19-related restrictions and the resulting stabilization of the economy. Consequently, we observed a marked increase in gas and refined products local demand as well as a rise in transportation volumes. Additionally, the improved financial position of the Group enabled us to increase our capital expenditures, which in turn provided us with the opportunity to invest in growth and development initiatives. Moreover, the increase in economic activity enabled us to undertake major maintenance activities in all our operating segments that had been delayed in previous years due to the need to operate under minimum essential services. This has helped us to enhance our operational capacity and ensure that our facilities are operating at maximum efficiency.

Ecopetrol Group continues to take measures to ensure the sustainability of the business, prioritizing the opportunities for cash generation with better equilibrium prices, maintaining growth dynamics with a focus on executing strategic asset development plans and preserving the value of assets through investments that provide reliability, integrity, and continuity to the current operation in refineries, transportation systems, and production fields.

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Effect on our 2021 Results

The effects of the COVID-19 pandemic on the Ecopetrol Group’s business and the measures undertaken by us to ensure the sustainability of the business have been highlighted in the section Effect of the COVID-19 Pandemic on our 2021 Results of our annual report on Form 20-F for the year ended December 31, 2021 filed with the SEC on April 25, 2022.

Effect on our 2020 Results

The effects of the COVID-19 pandemic on the Ecopetrol Group’s business and the measures undertaken by us to ensure the sustainability of the business have been highlighted in the section Effect of the COVID-19 Pandemic on our 2020 Results of our annual report on Form 20-F for the year ended December 31, 2020 filed with the SEC on April 9, 2021.

4.3

Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results

4.3.1

Taxes

In December 2016, the Colombian Congress adopted Law 1819, which introduced changes to the Colombian tax system, applicable beginning in 2017.

The 2016 Tax Reform included two tax benefits that are expected to improve the operations of the oil and gas industry:

Certificado de Reembolso Tributario (“CERT”) incentive:

For exploration activities, the CERT incentive was approved, consisting of the reimbursement of part of the investment made in the exploration phase.

The CERT is granted when the income tax return is filed.

The CERT can only be redeemed to pay taxes at the national level and its effective maturity date is two years after it is issued. Nevertheless, Decree 2253 of 2017 establishes that a CERT redemption can be made from year two to year five, as from the date of the granting of the incentive. The CERT can also be sold and traded in fixed income market.

For production activities, the CERT reimbursement is granted exclusively to investments that increase the recovery factor, i.e., investments that increase the reserves that are currently proved in certain wells.

On December 29, 2017, the Colombian Government issued Decree 2253, which establishes that companies who (i) qualify as operators of association agreements entered into with Ecopetrol S.A., (ii) have exploration and production of hydrocarbons agreements and (iii) are currently involved in the exploration and production of hydrocarbons, among others, can also qualify for the CERT. Additionally, the CERT will not qualify as taxable income or capital gain for the taxpayer receiving or acquiring such incentive.

On March 23, 2018, the following Resolutions were issued in order to regulate the procedures and requirements that companies must comply to claim the CERT: 0860 of Ministry of Finance and Public Credit, 108 of ANH and 40284 and 40285 of Ministry of Mines and Energy.

On December 20, 2019, the Ministry of Finance and Public Credit informed the Company that the PGN includes the resources of CERT. By virtue of Law 2277 of 2022, CERTs 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 for 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:

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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 net income tax, which is the basis to calculate the income tax.

For fiscal years 2020, 2021 and 2022, the dividends tax applied as follows:

(i)

In accordance with Article 245 of the Colombian Tax Code, the dividends tax applicable to non-resident shareholders is as follows:  (i) a 10% 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, 10% dividend tax after applying the initial corporate income withholding tax rate.

(ii)

In accordance with Article 242 of the Colombian Tax Code, for Colombian individuals: for fiscal years 2020, 2021 and 2022, dividends paid greater than 300 UVT (Spanish acronym for Unidad de Valor Tributario) were taxed at 10%.

(iii)

In accordance with Article 242-1 of the Colombian Tax Code, dividends distributed from taxed profits to local corporations for fiscal years 2021 and 2022 are taxed at 7.5%, or a 31% withholding tax for 2021 and 35% as from 2022 on dividends distributed from untaxed profits, plus an additional 7.5% dividend tax after applying the initial corporate income withholding tax rate.

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 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. 007 of 2021 and 019 of 2022, issued by the tax authority, the carbon tax accrues on the carbon content of fossil fuels used for combustion. The rate will be COP 17,660 and COP 18,829 per ton of CO2, for fiscal year 2021 and 2022, respectively.

For additional information see Note 10 of our consolidated financial statements.

In October 2019, the Constitutional Court declared Law 1943 of 2018 (the Financing Law) unconstitutional effective January 1, 2020. Therefore, the Financing Law continued to have full effect for the full fiscal year 2019.

On December 2019, the Colombian Congress adopted Law 2010, which introduced changes to the Colombian tax system, which became effective in 2020.

The creation of a “normalization tax” for 2020 to enable taxpayers to regularize certain omissions of information about their assets and/or incorrect information about their liabilities, subject to the payment of a 15% tax on the value of the amount of the omitted information.

Introduces the Colombian Holding Companies (CHC) regime.

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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; (ii) only 50% of the financial transactions tax is deductible; and (iii) only 50% of the industry and commerce tax can be taken as a discount (tax credit) to income tax.

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.

The dividend tax regime was modified and, as of 2021, is as follows:

(i)

Dividends paid to non-resident shareholders (Article 245 of the Colombian Tax Code): (i) a 10% 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) 31% withholding tax rate on dividends distributed from profits not taxed at the corporate level (35% from 2022 onward), plus an additional 10% dividend tax after applying the initial 31% (or 35%) withholding tax rate.

(ii)

Dividends paid to Colombian companies (Article 242-1 of the Colombian Tax Code): (i) a 7.5% dividend tax on dividends distributed from taxed profits, or (ii) a 31% (or 35%) withholding tax on dividends distributed from untaxed profits (35% from 2022 onward), plus an additional 7.5% dividend tax on the balance of the dividend amount after the initial 31% withholding.

(iii)

For Colombian resident individuals: dividend income in excess of 300 UVT is taxed at a rate of 10%.

On September 14, 2021, the Colombian Congress passed Law 2155 which introduced, among others, the following key changes to the Colombian tax system:

(i)

The Corporate Income Tax rate will be 35% as from 2022 onward.

(ii)

The alternative to credit 100% of the Industry and Commerce Tax (“ICA”) against Corporate Income Tax as from 2022 was eliminated (Article 65). However, the current alternative to credit 50% of the ICA remains going forward.

(iii)

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).

On August 8, 2022, the MHCP submitted a tax reform bill to Congress proposing several changes to the Colombian tax regime. The Colombian Congress adopted Law 2277 of 2022, which introduced the following modifications to the Colombian tax system, applicable from January 1, 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 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% will apply when the Brent price reaches USD 65.43, USD 73.17 and USD 79.92, respectively, according to ANH Resolution No. 0181 (revenues from the sale of natural gas are not subject to this surtax), (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.

Part A: Applicable Taxpayers for the Equity Tax (2023 and onwards)

●

Resident individuals with assets located in Colombia and abroad.

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●

Non-resident individuals with their assets located in Colombia (either with or without permanent establishment).

●

Non-residents with non-cash assets in Colombia.

●

Foreign entities that are not income taxpayers in Colombia but who possess assets located in Colombia, other than shares of Colombian companies, accounts receivables sourced in Colombian (i.e., with Colombian debtors), portfolio investments (i.e., investing through a foreign funds administration account (FFAA)), provided that these entities have complied with the foreign exchange regime in respect of such excluded assets. Additionally, non-residents with financial leasing agreements with Colombian borrowers (lessees) are also not liable for the tax (arguably in connection with that specific asset).

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).

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:

(i)

27% income tax rate;

(ii)

Two-year term for the depreciation for fixed assets;

(iii)

Exclusion from the presumptive income regime;

(iv)

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 will cease to apply on January 1, 2023. However, taxpayers who have met the eligibility requirements or obtained approval under the Mega Investments Regime before January 1, 2023, will maintain the rights acquired under such regime.

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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 revenues comes 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 risk on revenues, 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 revenues, 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 revenues 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 revenues, 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 revenues is now 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 84% 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 translation 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 2022, the Colombian Peso depreciated on average 13.61% against the U.S. dollar. During 2021 and 2020, the Colombian Peso depreciated on average 1.52% and 12.46%, respectively, against the U.S. dollar. Additionally, as of December 31, 2022, 2021, and 2020, the Colombian Peso/U.S. dollar exchange rate had depreciated 20.82%, 15.98% and 4.74% respectively from the rate a year earlier.

In 2022, our consolidated debt in foreign currency increased by a total of USD 378 million, mainly due to the execution of short-term treasury lines of credit by Ecopetrol S.A. In 2021, our consolidated debt in foreign currency increased by a total of USD 9,170 million mainly due to: (i) the effect of the ISA’s debt consolidation, equivalent to USD 5,749 million for the year ended 2021, and (ii) Acquisition Loan, which was then partially prepaid with the proceeds from the SEC-registered bonds in an aggregate amount of USD 2,000 million issued by Ecopetrol. In 2020, our consolidated debt in foreign currency increased by a total of USD 2,420 million as Ecopetrol S.A. entered into committed lines of credit in an aggregate principal amount of USD 665 million and issued a SEC-registered bond in an aggregate amount of USD 2,000 million.

As of December 31, 2022, our U.S. dollar denominated total debt was USD 22,276 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 16,340 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.

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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, 86.9% (USD 14,205 million) of Ecopetrol S.A.’s debt in U.S. dollars, as of December 31, 2022, was designated as a hedge. Similarly, since 2022, ISA adopted hedge accounting of the net investment in foreign operations. As a result, USD 307 million of ISA’s debt was designated as a hedge. The total debt of foreign currency designated as a hedge as of December 31, 2022 was USD 14,512 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, 2022, the Ecopetrol Group’s companies have the equivalent of a net U.S. dollar liability position of USD 221 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 4.95%. As measured by the general consumer price index, average annual inflation in Colombia for the years ended December 31, 2022, 2021 and 2020 was 13.12%, 5.62% and 1.61%, respectively. The inflation in 2022 is the highest in the last 24 years, and its increase was mainly due to: (i) the significant depreciation of the exchange rate during the second half of 2022, affecting the purchasing power of importers and increasing borrowing costs in external markets, (ii) higher prices of imported products caused by supply chain issues generated by the ongoing conflict between Russia and Ukraine and the COVID-19 pandemic, and (iii) a substantial increase in domestic demand.

Inflation has had a positive and a negative effect on the Group. On one hand, it has increased revenues for the transmission and roads segment, given that the rates are indexed to inflation, and 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 (26% of the total financial obligations on December 31, 2022). 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 2022 was USD 99.0 per barrel as compared to USD 70.9 per barrel in 2021 and USD 43.2 per barrel in 2020. See section Strategy and Market Overview.

Our average crude oil basket price was USD 90.9 per barrel in 2022, as compared to USD 66.8 per barrel in 2021 and USD 34.4 per barrel in 2020. The increase in 2022 as compared to 2021 was mainly due to the increase in the average price of ICE Brent, as a result of the conflict between Russia and Ukraine, and a lower negotiated oil spread supported by an increase in the supply of Russian and Canadian crude oil. In addition, our average product basket price was USD 118.2 in 2022, USD 79.6 in 2021, and USD 49.2 in 2020. The increase in 2022 as compared to 2021 was primarily due to the strengthening of the international reference price, improved refined products indicators, as well as our commercial efforts.

In the Operating Results section below, we present the impact of the price decrease on our revenue and cost of sales. Additionally, fluctuations in the price of oil 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.

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4.4

Accounting Policies

Our consolidated financial statements for the years ended December 31, 2022, 2021 and 2020 were prepared in accordance with IFRS. The detail of the accounting policies is described in Note 4 to our consolidated financial statements.

The main accounting regulatory change for 2022 was the amendments to IAS 16, which prohibit deducting from the cost of an item of property, plant and equipment under construction any proceeds and related costs from selling items produced while bringing these types of assets to the location and condition necessary for them to be capable of operating in the manner intended by management. Instead, the proceeds and related costs are recognized in the consolidated statement of income, in accordance with applicable accounting policies. Prior to these IAS 16 amendments, Ecopetrol’s policy was to deduct any proceeds and related costs from selling items produced against property, plant and equipment under construction. The change has not had any material impact.

For more information regarding the adoption of new accounting standards and their effects on our financial statements, see Note 5.1 New standards adopted by the Ecopetrol Group to our consolidated financial statements included in this annual report.

4.5

Critical 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 had 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 critical 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, 2022, 2021 and 2020.

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Table 58 – Consolidated Income Statement


Income Statement	For the year ended December 31,			% Change
(COP Million)	2022	2021	2020	2022/2021	2021/2020
Revenue	159,611,078	91,881,204	50,223,393	73.7	82.9
Cost of sales	89,458,148	55,581,776	37,567,472	60.9	48.0
Gross Profit	70,152,930	36,299,428	12,655,921	93.3	186.8
Operating expenses	9,635,178	6,568,370	4,841,000	46.7	35.7
Impairment of non-current assets, net	287,999	33,351	633,156	763.5	(94.7)
Operating Income	60,229,753	29,697,707	7,181,765	102.8	313.5
Finance results, net	(6,834,757)	(3,698,054)	(2,481,587)	84.8	49.0
Share of profit of companies	768,422	426,164	76,336	80.3	458.3
Income before income tax	54,163,418	26,425,817	4,776,514	105.0	453.2
Income tax	(18,963,938)	(8,795,263)	(2,038,661)	115.6	331.4
Net Income	35,199,480	17,630,554	2,737,853	99.7	544.0
Net income attributable to:
Company’s shareholders	31,604,781	15,649,143	1,586,677	102.0	886.3
Non-controlling interest	3,594,699	1,981,411	1,151,176	81.4	72.1
Net Income	35,199,480	17,630,554	2,737,853	99.7	544.0

4.6.1.1

Total Revenues

The following table sets forth our principal sources of third-party revenues by business segment for the years ended December 31, 2022, 2021 and 2020. An explanation of how we classify our operations into business segments is included in section 4.6.1.8 below.

Table 59 – Third-Party Revenues by Business Segment


	2022			2021			2020			Change Sales Revenues (%)
	Volume			Volume			Volume
	(barrels	Average price	Sales revenues	(barrels	Average price	Sales revenues	(barrels	Average price	Sales revenues
Revenue by segment	equivalent)	USD/barrels	( COPS Million)	equivalent)	USD/barrels	(COP Million)	equivalent)	USD/barrels	(COPS Million)	2022/2021	2021/2020
Local Crude oil	1,137,432	75.5	375,790	858,085	59.5	193,476	2,208,356	28.6	230,520	94.2	(16.1)
Foreign Crude oil⁽¹⁾	145,916,897	91.0	56,155,120	137,149,375	66.8	34,768,509	153,185,623	34.4	19,498,553	61.5	78.3
Natural gas local	35,032,930	27.6	4,162,876	33,577,157	25.3	3,200,069	31,391,611	24.5	2,845,155	30.1	12.5
Foreign natural gas	2,121,931	27.7	254,054	1,181,357	16.0	71,529	554,742	8.6	17,231	255.2	315.1
Other income⁽²⁾	7,211,899		(227,937)	6,151,816		318,989	5,409,528		263,466	(171.5)	21.1
Exploration and production sales	191,421,089		60,719,903	178,917,790		38,552,572	192,749,860		22,854,925	57.5	68.7
Local refined products⁽¹⁾	128,369,639	129.8	70,911,613	112,638,375	111.1	36,138,729	90,659,046	54.1	17,745,376	96.2	103.7
Foreign refined products⁽¹⁾	27,956,878	86.4	10,113,351	34,614,613	70.7	9,174,488	39,668,072	42.4	6,165,364	10.2	48.8
Foreign Crude Oil	200,332	105.1	92,147	—		—	—		29	—	(100.0)
Other income⁽²⁾	—	—	1,611,764	—		1,344,979	—		894,118	19.8	50.4
Refining and petrochemicals	156,526,849	—	82,728,875	147,252,988		46,658,196	130,327,118		24,804,887	77.3	88.1
Transportation services	—	—	2,807,031	—		2,557,238	—		2,563,581	9.8	(0.2)
Transportation and logistics	—	—	2,807,031	—		2,557,238	—		2,563,581	9.8	(0.2)
Electric Power Transmission and Toll Roads Concessions	—	—	13,355,269	—		4,113,198	—		—	224.7	0.0
Electric Power Transmission and Toll Roads Concessions⁽³⁾	—		13,355,269	—		4,113,198	—		—	224.7	0.0
Total sales	347,947,938		159,611,078	326,170,778		91,881,204	323,076,978		50,223,393	73.7	82.9
Crude Oil	147,254,661	90.9	56,623,057	138,007,460	66.8	34,961,985	155,393,979	34.4	19,729,102	62.0	77.2
Natural gas	37,154,861	27.6	4,416,930	34,758,514	24.9	3,271,598	31,946,353	24.3	2,862,386	35.0	14.3
Refined products	163,538,416	118.2	80,797,027	153,404,804	79.6	45,632,206	135,736,646	49.2	24,174,206	77.1	88.8
Transportation services and others	—		17,774,064	—		8,015,415	—		3,457,699	121.7	131.8
Total sales	347,947,938		159,611,087	326,170,778		91,881,204	323,076,978		50,223,393	73.7	82.9

(1)	Includes strategic and tactical hedges, which are related to crude oil, fuel oil and Diesel.

(2)	In the case of the exploration and production segment, other income corresponds mostly to 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.

(3)	The electric power transmission and toll roads concessions segment’s revenues mainly include: (i) electricity transmission services, (ii) designing, building, operating and maintaining road concessions infrastructure roads, and (iii) telecommunications services.

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In 2022, total revenues increased by 73.7% as compared to 2021, primarily as a result of: (i) a COP 37,711,635 million increase in revenues mainly due to a 36.1%, or USD 24.1 per barrel increase of our average crude oil basket price and a 48.6%, or USD 38.7 per barrel increase of our average refined products basket price, which in turn was primarily due to a higher Brent benchmark price and product spreads versus a stronger Brent, given global supply constraints from the conflict between Russia and Ukraine, (ii) a COP 14,557,099 million increase in revenues resulting from a 13.61% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP 3,747.24/USD 1.00 in 2021 to an average exchange rate of COP 4,257.12/USD 1.00 in 2022, resulting in an increase in revenue from exports, (iii) a COP 9,738,060 million increase in service revenue, primarily due to the incorporation of ISA’s service revenue during the 12 months of 2022, compared to the four months of 2021, and (iv) a COP 5,723,080 million increase in revenues attributable to an increase in our sales volume (as further explained below).

The increase of our sales volume in 2022 as compared to 2021 was the result of: (i) a 6.6%, or 10.1 mboe increase in refined products volumes, which in turn was primarily due to the recovery in domestic demand and the related increase in sales of fuel products, (ii) a 6.7% or 9.3 mboe increase in our crude sales, primarily associated with increased crude oil production, and (iii) a 6.9% or 2.4 mboe increase in natural gas sales volume, which resulted from higher production by Permian and the recovery in demand mainly due to higher economic activites. This increase was partially offset by a decrease in our exports of middle distillates, as a result of major maintenances scheduled at the refineries.

In 2021, total revenues increased by 82.9% as compared to 2020, primarily as a result of: (i) a COP 33,357,735 million increase in revenues mainly due to a 94.2%, or USD 32.4 per barrel increase of our average crude oil basket price and a 61.8%, or USD 30.4 per barrel increase of our average refined products basket price, which in turn was primarily due to the strengthening of the international reference prices, a better negotiated oil spread as a result of our commercial efforts, and improved refined products indicators, (ii) a COP 4,165,354 million increase in the service revenue, primarily due to the consolidation of ISA’s revenues from September 2021, (iii) a COP 2,797,025 million increase in revenues resulting from a 1.52% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP 3,691.27/USD 1.00 in 2020 to an average exchange rate of COP 3,747.24/USD 1.00 in 2021, resulting in an increase in revenue from exports, and (iv) a COP 1,337,697 million increase in revenues attributable to an increase in our sales volume (as further explained below).

The increase of our sales volume in 2021 as compared to 2020 was the result of: (i) a 13.0%, or 17.7 mboe increase in refined products volumes, which in turn was primarily due to the recovery in domestic demand which exceeded pre-COVID-19 pandemic levels, and (ii) a 8.8%, or 2.8 mboe increase in natural gas sales volume, which resulted from higher production by Hocol and Permian. This increase was partially offset by a 11.2%, or 17.4 mboe decrease in our crude sales, primarily associated with lower availability due to lower production and higher throughput at our refineries.

4.6.1.2

Cost of Sales

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 2022 was COP 89,458,148 million, representing a COP 33,876,372 million or 60.9% increase as compared to 2021, primarily as a result of the following factors:

A COP 24,535,563 million increase in the purchase costs of crude oil, natural gas and refined products, which were purchased for sales or for refining, resulting primarily from (i) higher average purchase prices by COP 14,788,090 million, which in turn was primarily due to the increase in international benchmark prices for crude oil and refined products, (ii) a COP 6,177,985 million increase in costs in Colombian Peso terms due to the depreciation of the average exchange rate of the Colombian Peso against the U.S. dollar, mentioned above, and (iii) a COP 3,569,488 million increase in volumes purchased, primarily due to an increase in our imports of refined products to ensure domestic supply given the economic reactivation and the execution of scheduled maintenance work in our refineries, as well as an increase in our imports of crude oil associated with the commissioning of the “Interconnection of the Crude Plants at the Cartagena Refinery – IPCC”.

A COP 3,936,349 million increase as a result of the incorporation of ISA’s results for all of 2022, versus four months of incorporation in 2021.

A COP 2,674,823 million increase in contracted services, maintenance activities, operation supplies and other operational activity costs, as a result of an increase in operating activities, higher average exchange rate and the inflation effect in contracts.

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A COP 1,184,643 million increase in depreciation, amortization, and depletion expenses primarily due to: (i) a higher level of capital investment, (ii) the exchange rate effect in depreciation for subsidiaries of the Group with U.S. dollars as functional currency, given the devaluation of the Colombian Peso, as mentioned above, and (iii) the increase in production of Ecopetrol S.A. and Permian. The above was partially offset by a lower depreciation rate associated with the mitigating effect of the higher incorporation of reserves during 2021.

A COP 583,582 million increase in inventory fluctuation primarily due to the import of oil products to attend local demand during the periods of scheduled maintenance of our refineries.

A COP 423,493 million increase in transportation costs primarily related to: (i) higher volume of crude oil and products transported for cabotage and tanker trucks due to an increase in economic activity during 2022 and (ii) higher transportation tariffs.

A COP 351,508 million increase in labor cost related to: (i) a 7.3% salary increase in 2022 as compared to 2021, and (ii) an increase in medical services.

A COP 186,411 million increase in other minor items, including higher payments of royalties, taxes and contributions.

Cost of sales in 2021 was COP 55,581,776 million, representing a COP 18,014,304 million or 48.0% increase as compared to 2020, primarily as a result of the following factors:

A COP 18,111,853 million increase in the purchase costs of crude oil, natural gas and refined products, which were purchased for sales or for refining, resulting primarily from (i) higher average purchase prices by COP 14,531,550 million, which in turn was primarily due to the increase in international benchmark prices for crude oil and refined products, (ii) a COP 2,841,612 million increase in volumes purchased, primarily due to an increase in our imports of refined products to ensure domestic supply given the economic reactivation, as well as an increase in our domestic purchases of crude oil associated with new commercialization contracts in line with the commercial strategy, and (iii) a COP 738,691 million increase in costs in Colombian Peso terms due to the depreciation of the average exchange rate of the Colombian Peso against the U.S. dollar, mentioned above.

A COP 1,740,738 million increase as a result of our consolidation of ISA’s cost of sales from September 2021, which includes services, depreciation, labor, taxes, and general costs.

A COP 692,509 million increase in contributions and taxes mainly due to: (i) an increase in non-deductible VAT associated with higher purchase levels in 2021, and (ii) an increase in gas royalties due to higher production levels in 2021.

A COP 642,088 million increase in contracted services, maintenance activities, operation supplies and other operational activity costs, as a result of execution of activities related to the economic reactivation, greater participation in fields such as Nare and Piedemonte and higher tariffs and inflation effect in contracts.

A COP 327,591 million increase in depreciation, amortization, and depletion expenses primarily due to: (i) a higher level of capital investment, and (ii) the increase in the production of our subsidiaries in the Permian. The above was partially offset by a lower depreciation rate associated with decreased levels of production in Ecopetrol S.A.’s fields.

A COP 63,673 million increase in labor cost related to: (i) a 3.31% salary increase in 2021 as compared to 2020, and (ii) an increase in medical services.

A COP 103,186 million increase in other minor items.

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The factors mentioned above were partially offset by a COP 3,667,334 million decrease in inventory fluctuation primarily due to: (i) the valuation of the price of crude oil and products purchased given the recovery of international reference prices, (ii) higher inventory of crude oil in transit, associated with higher “delivery at place” sales scheduled for 2021 compared against “free on board” sales during the previous year, and (iii) higher inventory levels due to crude oil evacuation restrictions and maintenance activities in some refining units.

4.6.1.3

Operating Expenses before Impairment of Non-Current Assets Effects

Operating expenses, which include selling, general and administrative expenses before impairment of non-current assets amounted to COP 9,635,178 million in 2022, a COP 3,066,808 million or 46.7% increase as compared to 2021, mainly as a result of the following factors (see Notes 27 and 28 to our consolidated financial statements for more detail):

COP 672,145 million decrease in other income, as a result of the Frontera settlement approved by the Administrative Court of Cundinamarca and received by the Group in 2021.

A COP 640,028 million increase in commissions, fees and services, mainly associated with customs operation due to the higher number of sales under “delivery at place” modality in 2022 versus 2021.

A COP 552,706 million increase in exploration expenses mainly due to: (i) recognition of exploratory activity of unsuccessful wells and (ii) higher activity in Ecopetrol Óleo e Gás do Brasil Ltda. and Hocol.

A COP 450,192 million increase in labor expenses, mainly due to: (i) a 7.3% salary increase in 2022 as compared to 2021, (ii) an increase in medical services, and (iii) incorporation of ISA’s results for all of 2022 versus four months of 2021.

A COP 402,644 million increase in general operating expenses mainly in social investment projects and community programs in the areas where we operate.

A COP 270,388 million increase in contribution and taxes expenses mainly due to higher industry and commerce tax due to increased local sales.

A COP 78,705 million increase in other minor items, which mainly includes depreciation, amortization, and depletion expenses and provisions and contingencies.

Operating expenses, which include selling, general and administrative expenses before impairment of non-current assets amounted to COP 6,568,370 million in 2021, a COP 1,727,370 million or 35.7% increase as compared to 2020, mainly as a result of the following factors (see Notes 27 and 28 to our consolidated financial statements for more detail):

A lower effect of COP 1,370,398 million from profit on acquisition of participations and interests resulting from Hocol’s acquisition in 2020 of 100% of Chevron Petroleum Company’s participation in the Guajira association contract, which generated: (i) a COP 1,284,372 million revaluation gain of the assets that Hocol already had in the Guajira association at Ecopetrol, and (ii) a COP 86,026 million gain at Hocol, as its acquisition of the remaining 43% stake was considered a bargain purchase.

A COP 510,948 million increase in provisions, mainly associated with environmental aspects and the public works contribution process.

A COP 270,475 million increase in exploration expenses mainly due to: (i) increased exploratory activity mainly associated with seismic in Brazil, (ii) updating of dry well abandonment costs, and (iii) recognition of the exploratory activity of unsuccessful wells.

A COP 236,528 million increase in depreciation, amortization, and depletion expenses primarily due to a recognition of fixed cost of some plants in the Cartagena Refinery that suspended its production, and the consolidation of ISA’s depreciation cost starting in September 2021.

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A COP 213,781 million increase in other operating expenses mainly in social investment projects, especially those carried out for the Misión Internacional de Sabios, aimed at the advancement of science, technology and innovation, which was convened by the Colombian Government and communities, among others.

A COP 188,860 million increase in other minor items, which mainly includes transaction costs related to the acquisition of ISA and other professional services.

These results were partially offset by:

A COP 672,145 million increase in other income, as a result of the approval of the Frontera settlement agreement by the Administrative Court of Cundinamarca as further described in Business Overview––Transportation and Logistics––Marketing of Transportation Services––Developments with certain clients of Bicentenario and Cenit.

A COP 391,475 million decrease in labor expenses was mainly due to the lower recognition of the voluntary retirement plan in 2021 compared to 2020.

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 of Non-Current 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 in domestic and international regulations, (viii) future cash flows expected, 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 the hydrocarbon prices outlook, (ii) in the refining segment, changes in product and crude oil prices, discount rate, refining margins, changes in environmental regulations, cost structure and the level of capital expenditures; (iii) in the transportation and logistics segment, changes in tariffs regulation and transported volumes; (iv) in the electric power transmission and toll roads concessions segment, changes in expected future cash flows.

In 2022, we recognized impairment losses of non-current assets of COP 287,999 million as compared to impairment losses of COP 33,351 million in 2021 and COP 633,156 million in 2020. 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 2022 impairment losses, net of non-current assets of COP 287,999 million, corresponds to the net result of:

(i)

An impairment of non-current assets in the exploration and production segment of COP 890,248 million, mainly due to: (i) a decline in the reserves of Ecopetrol's Cusiana and Llanito fields, (ii) lower prospects in Hocol's Upía and Cicuco fields, (iii) an increase in the discount rate, and (iv) the impact of the tax reform.

(ii)

A recovery of impairment in the Cartagena Refinery of COP 1,096,021 million, primarily as a result a better operating performance and higher refining margins captured in the short and medium term, which have partially offset the increase of the discount rate.

(iii)

An impairment of non-current assets in the transportation and logistics segment of COP 406,229 million, primarily due to a lower volume outlook, which results in a decrease of the utilization of the Southern Cash Generating Unit (Puerto Tumaco and TransAndino pipeline) and the Northern Cash Generating Unit (Caño Limón).

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(iv)

An impairment of non-current assets in the electric power transmission and toll roads concessions segment of COP 87,543 million mainly due to lower margins and decreased performance of Internexa Brasil Operadora de Telecomunicações S.A. (“Internexa Brazil”).

The 2021 impairment losses, net of non-current assets of COP 33,351 million, corresponds to the net result of:

(i)

A recovery of impairment of non-current assets in the exploration and production segment of COP 438,020 million, mainly due to favorable outlook of international prices and increase in reserves.

(ii)

An impairment of non-current assets in the refining and petrochemicals segment of COP 305,466 million, primarily related to the Barrancabermeja refinery modernization plan which led to an impairment of COP 340,019 million, considering the progress in technical analysis of the project and to other minor adjustments in the amount of COP 97 million. The foregoing was partially offset by a reversal of impairment in the Cartagena Refinery of COP 34,650 million, primarily due to operating and financial management improvements that permitted capturing greater refining margins in the short and medium-term.

(iii)

An impairment of non-current assets in the transportation and logistics segment of COP 165,901 million, primarily due to a lower volume outlook for the Southern Cash Generating Unit, which is comprised of the Tumaco Port and the Transandino pipeline (OTA).

(iv)

An impairment of non-current assets in the electric power transmission and toll roads concessions segment of COP 4 million.

The 2020 impairment losses, net of non-current assets of COP 633,156 million, corresponds to the net result of:

(i)

An impairment of non-current assets in the exploration and production segment of COP 192,693 million, mainly due to the decrease in crude oil price forecast in the short and long term.

(ii)

An impairment of non-current assets in the refining and petrochemicals segment of COP 781,528 million, primarily related to the lower refining margins at the Cartagena Refinery by COP 440,525 million and the Barrancabermeja refinery Modernization Plan by COP 341,000 million, considering the progress in technical analysis of the project.

(iii)

A reversal of impairment of non-current assets in the transportation and logistics segment of COP 341,065 million, primarily as a result of a recovery in transported volumes in 2020 through: (i) South CGU, which includes the Transandino pipeline (OTA) and the port of Tumaco and (ii) North CGU, which includes the Banadía–Ayacucho’s pipeline, part of the Caño Limón-Coveñas system.

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 includes exchange rate gains or losses, interest expense, 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 6,834,757 million in 2022 as compared to a loss of COP 3,698,054 million in 2021. This loss was mainly due to:

(i)

A COP 2,422,193 million increase in interest expenses, primarily due to (i) the higher interest expenses related to the debt acquired in the second half of 2021 to finance the purchase of ISA, the exchange rate effect on the interest of the U.S. dollar-denominated debt and higher rates of inflation in debt with variable rates, and (ii) the incorporation of ISA’s results for all of 2022 versus four months of 2021.

(ii)

A COP 959,959 million increase in financial expenses related to long term obligations, which in turn was mainly to the increase in our asset retirement and pension obligations.

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(iii)

A COP 454,652 million increase in foreign exchange expense primarily driven by the negative impact that the depreciation of the Colombian Peso against the U.S. dollar in 2022 had on our U.S. dollar net liability position. In 2022, our exchange rate loss was COP 124,650 million, as compared to a gain of COP 330,002 million in 2021, mainly due to positive effect of the foreign change expense in 2021 on the sale of our equity investment in Savia Perú.

(iv)

A COP 18,925 million increase in other minor items.

The factors mentioned above were partially offset by a COP 719,026 million increase in valuation to fair value and higher yields on the securities portfolio, primarily as a result of higher market rates and a higher average cash position in 2022 as compared to 2021.

Finance results, net, amounted to a loss of COP 3,698,054 million in 2021 as compared to a loss of COP 2,481,587 million in 2020. This loss was mainly due to:

(i)

A COP 710,882 million increase in interest expenses, primarily due to (i) the increase in Ecopetrol’s debt in 2021, which in turn was due to the Acquisition Loan and the SEC-registered bonds in an aggregate amount of USD 2,000 million issued in connection with the acquisition of ISA, and (ii) the consolidation of ISA’s debt.

(ii)

A COP 218,175 million decrease in valuation to fair value and lower yields of the securities portfolio, primarily as a result of low market rates and a lower average cash position in 2021 as compared to 2020.

(iii)

A COP 170,741 million increase in financial expenses related to long term obligations, which in turn was mainly to the increase in our asset retirement and pension obligations.

(iv)

A COP 16,772 million decrease in foreign exchange primarily driven by the negative impact that the depreciation of the Colombian Peso against the U.S. dollar in 2021 had on our U.S. dollar net liability position. In 2021, our exchange rate loss was COP 31,726 million, as compared to a gain of COP 346,774 million in 2020. This decrease was partially offset by a revenue from the realization in our equity results of the accumulated exchange rate valuation (conversion adjustment), resulting from the US dollar sale of our investment in Savia Perú.

For more details on our financial income and expenses see Note 29 to our consolidated financial statements.

4.6.1.6

Income Tax

Income taxes amounted to COP 18,963,938 million in 2022, COP 8,795,263 million in 2021 and COP 2,038,661 million in 2020. The above is equivalent to an effective tax rate of 35.0%, 33.3% and 42.7% in 2022, 2021 and 2020, respectively.

The increase in the effective tax rate from 2021 to 2022 was mainly due to: (i) a higher nominal rate for the companies in Colombia from 31% to 35%, (ii) a positive net tax rate effect resulting from the higher tax rate of Ecopetrol S.A. and the lower tax rate for some of the Company’s subsidiaries, as is the case of the Cartagena Refinery, ISA Brazil and the subsidiaries in the United States, and (iii) the effect of updating the deferred tax asset as a result of a tax reform in Colombia.

The decrease in the effective tax rate from 2020 to 2021 was mainly due to: (i) the effect of the tax reform issued in 2021 under net deferred tax (increase in the nominal tax rate from 2022, which will go from 30% to 35%), (ii) a positive net effect resulting from a lower tax rate for some of the Company’s subsidiaries compared to the tax rate of the parent company, and the effect of exchange rate variations on taxable profits in 2021, and (iii) the effect on deferred tax liabilities during the corresponding period in 2021 of the devaluation of the peso against the U.S. dollar on our subsidiaries whose functional currency is the U.S. dollar but pay their taxes in Colombian pesos. This decrease was partially offset by the net effect between non-deductible expenses and untaxed income.

See Note 10 to our consolidated financial statements for more details.

4.6.1.7

Net Income (Loss) Attributable to Owners of Ecopetrol

As a result of the foregoing, in 2022, net income attributable to owners of Ecopetrol was COP 31,604,781 million. In 2021, net income attributable to owners of Ecopetrol was COP 15,649,143 million, whereas in 2020 net income attributable to owners of Ecopetrol was COP 1,586,677 million.

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4.6.1.8

Segment Performance and Analysis

In this section, including the tables below, we present our financial information by segment: Exploration and Production, Refining and Petrochemicals, Transportation and Logistics, and Electric Power Transmission and Toll Roads Concessions. See section Business Overview for a description of each segment.

The following tables present our revenues and net income by business segment for the years ended December 31, 2022, 2021 and 2020:

Table 60 – Revenues by Business Segment


	For the year ended December 31,			% Change
	2022	2021	2020	2022/2021	2021/2020

	(COP Million)
Exploration and Production	91,020,465	63,248,952	36,839,997	43.9	71.7
Third parties	60,719,903	38,552,572	22,854,925	57.5	68.7
Local crude oil	375,790	193,476	230,520	94.2	(16.1)
Foreign crude oil	56,155,120	34,768,509	19,498,553	61.5	78.3
Local natural gas	4,162,876	3,200,069	2,845,155	30.1	12.5
Foreign natural gas	254,054	71,529	17,231	255.2	315.1
Other income	(227,937)	318,989	263,466	(171.5)	21.1
Inter-segment net operating revenues	30,300,562	24,696,380	13,985,072	22.7	76.6

Refining and Petrochemicals	89,178,947	50,976,385	26,104,351	74.9	95.3
Third parties	82,728,875	46,658,196	24,804,887	77.3	88.1
Local refined products	70,911,613	36,138,729	17,745,376	96.2	103.7
Foreign refined products	10,113,351	9,174,488	6,165,364	10.2	48.8
Foreign crude oil	92,147	—	29	100.0	(100.0)
Other income	1,611,764	1,344,979	894,118	19.8	50.4
Inter-segment net operating revenues	6,450,072	4,318,189	1,299,464	49.4	232.3

Transportation and Logistics	13,955,992	12,158,466	12,194,440	14.8	(0.3)
Third parties	2,807,031	2,557,238	2,563,581	9.8	(0.2)
Inter-segment net operating revenues	11,148,961	9,601,228	9,630,859	16.1	(0.3)

Electric Power Transmission and Toll Roads Concessions⁽¹⁾	13,357,506	4,113,198	—	224.7	100.0
Third parties	13,355,269	4,113,198	—	224.7	100.0
Inter-segment net operating revenues	2,237	—	—	100.0	—
Eliminations of consolidations	(47,901,832)	(38,615,797)	(24,915,395)	24.0	55.0
Total revenues	159,611,078	91,881,204	50,223,393	73.7	82.9

(1)	The electric power transmission and toll roads concessions segment’s revenues mainly include: (i) electricity transmission services, (ii) designing, building, operating and maintaining road concessions infrastructure roads, and (iii) telecommunications services.

Total revenues by segment include exports and local sales to third-parties and inter-segment sales. See section Financial Review—Operating Results—Consolidated Results of Operations—Total Revenues for prices and volumes to third parties.

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Table 61 – Operating and Net Income by Business Segment


	For the year ended December 31,			% Change
	2022	2021	2020	2022/2021	2021/2020

	(COP Million)
Exploration and Production
Operating Income	37,358,934	18,863,444	1,149,291	98	1,541.3
Net income	21,761,164	11,829,119	(139,279)	84	(8,593.1)
Refining and Petrochemicals
Operating Income	7,694,598	417,450	(2,185,511)	1,743	(119.1)
Net income	4,686,009	(1,198,619)	(2,848,511)	(491)	(57.9)
Transportation and Logistics
Operating Income	8,732,561	8,462,604	8,218,724	3	3.0
Net income	4,483,060	4,635,354	4,574,800	(3)	1.3
Electric Power Transmission and Toll Roads Concessions
Operating Income	6,345,153	1,921,037	—	230	100.0
Net income	673,688	386,438	—	74	100.0
Eliminations of consolidations
Operating Income	98,507	33,172	(739)	197	(4,588.8)
Net income	860	(3,149)	(333)	(127)	845.6
TOTAL
Operating Income	60,229,753	29,697,707	7,181,765	103	313.5
Net income	31,604,781	15,649,143	1,586,677	102	886.3

As we seek to execute our 2040 Strategy, the Ecopetrol Group is working to re-align its current segments to the business lines defined in the 2040 Strategy and its work in the field of energy transition. In that regard, for operational purposes, we are in the process of realigning our corporate operational divisions from Exploration and Production, Transportation and Logistics, Refining, Petrochemicals and Biofuels, Electric power transmission and toll roads concessions, and Sales and Marketing, to the following: (i) Hydrocarbons, which includes the Exploration and Production, Transportation and Logistics, Refining and Petrochemicals, (ii) Low Emissions Solutions, which includes exploration, production and commercialization of gas, biogas, LPG, power, renewables, hydrogen, and Carbon Capture, Utilization and Storage (CCUS), and (iii) Energy Transmission and Toll Roads, while maintaining Sales and Marketing as a cross-sectional front. For purposes of this annual report, we continue to present our operational information under our traditional business lines. We expect to reflect the new business lines at the operational and financial level in the 2023 annual report.

4.6.1.9

Exploration and Production Segment Results

In 2022, exploration and production segment sales were COP 91,020,465 million, compared to COP 63,248,952 million in 2021. In 2022, our segment sales increased by 43.9% as compared with 2021 mainly as a result of:

(i)

A 57.5% increase in sales of crude oil to third parties in 2022 as compared to 2021 primarily due to: (i) an increase in the price of our crude oil basket of USD 24.1/Bl, (ii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars, and (iii) a higher production of 30.5 mboed, primarily due to an increased production from the Caño Limón, Quifa, la Cira Infantas, Castilla and Caño Sur fields, as well as increased production of Permian.

(ii)

A 22.7% increase in inter-segment revenues in 2022 as compared to 2021 mainly due to: (i) the increase in Brent reference prices, (ii) a higher refinery load due to global demand recovery, and (iii) the depreciation of the Colombian Peso against the U.S. dollar.

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In 2021, exploration and production segment sales were COP 63,248,952 million, compared to COP 36,839,997 million in 2020. In 2021, our segment sales increased by 71.7% as compared with 2020 mainly as a result of:

(i)

A 68.7% increase in sales of crude oil to third parties in 2021 as compared to 2020 primarily due to: (i) an increase in the price of our crude oil basket of USD 32.4 per barrel, (ii) an increase in the crude oil basket spread compared against the Brent price of USD 5 per barrel, (iii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars, and (iv) an increase in sales of natural gas (8.4 mboed) primarily due to higher production by Hocol and a higher production related with a demand recovery. This increase was partially offset by a decrease in local and exports sales of crude oil (48.9 mboed) mainly due to the company’s lower production as a result of operational and public order issues, including roadblocks and strikes.

(ii)

A 76.6% increase in inter-segment revenues in 2021 as compared to 2020 mainly due to: (i) a higher refinery load due to global demand recovery, and (ii) the depreciation 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 2022, the cost of sales for this segment increased by 15.9% as compared with 2021 due to the net effect of:

(i)

Fixed costs increasing by 22.7%, or COP 2,237,445 million in 2022 as compared to 2021, mainly due to: (i) higher transportation costs, which in turn are the result of a higher exchange rate, annual increases of tariffs in pipelines and larger amounts of gas produced and transported from Teca-Nare; (ii) higher activity in well interventions, maintenance, process material, integrity work and activities to support the operation and improvements in wells with production decline; and (iii) an increase in labor expenses due to salary increases. This increase was partially offset by lower costs for reversals.

(ii)

Variable costs increasing by 13.7%, or COP 4,176,843 million in 2022 as compared to 2021, as a result of (i) increased oil basket price and a higher COP/USD exchange rate resulting in a higher cost of crude oil and nafta purchases to third parties, (ii) higher gas royalties and economic rights associated with higher production and price increases; (iii) higher contract and energy rates given worldwide inflation, a higher COP/USD exchange rate, and the shutdown of generators to reduce carbon footprint increasing energy consumption. These increases were partially offset by savings in tariffs resulting from the acquisition of the El Morro-Araguaney pipeline and a higher availability of the Caño Limón – Coveñas pipeline during 2022.

In 2021, the cost of sales for this segment increased by 22.6% as compared with 2020 due to the net effect of:

(i)

Fixed costs increasing by 4.0%, or COP 382,670 million in 2021 as compared to 2020, mainly due to: (i) reactivation of the operational activity resulting in an increase in well interventions, maintenance, process material, integrity work and activities to support the operation, (ii) higher rates in contracts given the economic reactivation, inflation and higher COP/USD exchange rate, and (iii) the shutdown of generators to reduce carbon footprint increasing energy consumption.

(ii)

Variable costs increasing by 30.1%, or COP 7,044,043 million in 2021 as compared to 2020, as a result of (i) increased oil basket price resulting in a higher cost of oil and nafta purchases to third parties and impacting the economic rights contracts clause in certain fields and inventory valuation, and (ii) higher transportation costs due to Caño Limón - Coveñas pipeline un-availability during the second half of the year, pipelines tariffs annual update and the depreciation of the Colombian Peso against U.S. dollar. This increase was partially offset by (i) less transported volume due to a lower production, (ii) transit of sales to third parties in the Asian market to be recognized in January 2022, and (v) decrease in nafta purchase volume to third parties.

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In 2022, operating expenses before impairment of non-current assets increase by 34.2% as compared to 2021 primarily as a result of: (i) higher exploratory expenses in 2022 mainly as a result of the recognition of spending on exploratory and seismic activity in Brazil, (ii) increase in asset write-off after the completion of a viability analysis in the Saturno and Rydberg fields, (iii) increase in freight costs for exports to America, Europe and Asia under the “delivery at place” model, (iv) increase in maintenance of external roads and facilities and attention to operational contingencies, (v) increase in labor expenses due to salary increases, and (vi) loss of crude due to damages by third parties to our infrastructure. This increase was partially offset by (i) lower expenses related to the updating of processes, resulting from new legal, tax and environmental provisions, and (ii) the profit from the sale of the Casanare, Estero, Garcero, Orocue and Corocora fields in 2022.

In 2021, operating expenses before impairment of non-current assets increased by 73.3% as compared to 2020 primarily as a result of: (i) higher exploratory expenses in 2021 mainly as a result of the recognition of spending on exploratory activity at the Moyote, Silver Back, Ceará fields and the update of the cost of abandonment of dry wells, (ii) the impact from the updating process of tax and environmental provisions, (iii) increase in freight costs for exports to China and Korea under the “delivery at place” model, and (iv) loss of crude due to damages by third parties to our infrastructure. This increase was partially offset by lower labor expenses due to a recognition of the voluntary retirement plan in 2020 and no similar recognition in 2021.

In 2020, operating expenses before impairment of non-current assets decreased by 4.5% as compared to 2019 primarily as a net result of: (i) recorded gain/losses on interests derived from Hocol’s acquisition of 100% of Chevron Petroleum Company’s participation in the Guajira Contract (which corresponds to 43% of the total contract) and (ii) a decrease in exploratory activity mainly as a result of lower drilling and seismic activity. The latter was partially offset by (i) higher labor expenses due to certain employees choosing to accept a voluntary retirement plan we offered in 2020, (ii) the write off of certain assets due to the completion of economic feasibility studies, (iii) higher environmental provisions and asset retirement obligations for noncommercial wells, (iv) social investment costs associated with our support to the country to combat the COVID-19 pandemic, and (v) increase in fees and freight costs for exports to China and Korea.

There was an impairment of non-current assets recognized in the exploration and production segment in 2022, totaling COP 890,248 million in 2022 as compared to a recovery of COP 438,020 million in 2021. The impairment loss in this segment in 2022 was mainly due to: (i) the decline in reserves of the Cusiana and Llanito fields, (ii) lower prospectivity in the Upía and Cicuco fields in Hocol, (iii) the increase in discount rates, and (iv) the impact of the tax reform in terms of non-deductibility of royalties and higher tax rate.

There was a recovery of impairment of non-current assets recognized in the exploration and production segment in 2021, totaling COP 438,020 in 2021 as compared to a COP 192,693 million in 2020. The recovery impairment in this segment in 2021 was mainly due to the better predict of international prices and an increase in the reserve balance.

There was an impairment of non-current assets recognized in the exploration and production segment in 2020, totaling COP 192,594 million in 2020 as compared to a COP 1,982,044 million in 2019. The impairment loss in this segment in 2020 was mainly due to the decrease in the crude oil price forecast in the short and long term.

Because of all the above, the segment recorded a net income attributable to owners of Ecopetrol of COP 21,761,164 million in 2022 as compared to net income attributable to owners of Ecopetrol of COP 11,829,119 million in 2021 and net loss attributable to owners of Ecopetrol of COP 139,279 million in 2020.

Lifting and Production Costs

The aggregate average production cost, on a Colombian Peso basis, increased to COP 41,841 per boe during 2022 from COP 31,685 per boe during 2021. The aggregate average production cost increased to USD 9.83 per boe in 2022 from USD 8.46 per boe in 2021, primarily due to a 16.15% depreciation of the Colombian Peso against the U.S. dollar in 2022.

The aggregate average lifting cost, on a Colombian Peso basis, increased to COP 39,187 per boe during 2022 from COP 31,075 per boe during 2021. On a dollar basis, the aggregate average lifting cost increased to USD 9.21 per boe in 2022 from USD 8.30 per boe in 2021 due to a 10.92% depreciation of the Colombian Peso against the U.S. dollar in 2022.

In 2022, both the aggregate average production cost and the aggregate average lifting cost increased compared to 2021, mainly due to:

(i)

increase in electricity costs primarily due to: (i) higher global energy rates, (ii) increased consumption of the SIN, and (iii) the effect of inflation.

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(ii)

greater cost execution in subsoil maintenance, due to an increase in the number and complexity of well interventions and services, mainly to improve the status of fields.

(iii)

greater number of operation maintenance, civil works, and activities as part of the normalization of operations in the aftermath of the Covid-19 pandemic.

(iv)

increase in contracted services and deployment of a greater number of equipment in the aftermath of the Covid-19 pandemic.

(v)

increase in costs related to operational support areas given our increased operational activity.

The difference between the aggregate average lifting cost and aggregate average production cost is that lifting costs does not include costs related to consumption of hydrocarbons by the Company in our production process or the output that the Company sells to our refineries and natural gas liquid plants.

The following table sets forth crude oil and natural gas average sales prices, the aggregate average lifting costs and aggregate average unit production cost for the years ended December 31, 2022, 2021 and 2020.

Table 62 – Crude Oil and Natural Gas Average Prices and Costs


	2022	2021	2020
Crude Oil Average Sales Price (USD per barrel)⁽¹⁾	90.9	66.8	34.4
Crude Oil Average Sales Price (COP per barrel)⁽¹⁾	384,525	253,334	126,962
Natural Gas Average Sales Price (USD per barrel equivalent)	4.8	4.4	4.3
Natural Gas Average Sales Price (COP per barrel equivalent)⁽²⁾	20.856	16,513	15,719
Aggregate Average Unit Production Costs (USD per boe)⁽³⁾	9.83	8.46	7.75
Aggregate Average Unit Production Cost (COP per boe)⁽³⁾	41,841	31,685	28,634
Aggregate Average Lifting Costs (USD per boe)^(4)(5)(6)	9.21	8.30	7.46
Aggregate Average Lifting Costs (COP per boe)^(4)(5)(6)	39,187	31,075	27,555

(1)	Corresponds to our average sales price on a consolidated basis.

(2)	Since 2020, Invercolsa’s sales are recognized as income from gas service without associated volume. In order to give comparability to our financial information, the values reported as residential gas were classified as “other income” in 2019.

(3)	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.

(4)	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.

(5)

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 dividing by the net produced volume (excluding royalties) as the denominator.

(6)	As a result of the evaluation of control over companies under IFRS, Ecopetrol does not consolidate Savia Perú and Equión.

4.6.1.10

Transportation and Logistics Segment Results

In 2022, our transportation and logistics segment sales were COP 13,955,992 million compared to COP 12,158,466 million in 2021. The 14.8% increase in 2022 as compared with 2021 was mainly due to: (i) the COP/USD exchange rate effect, (ii) the annual increase of tariffs, (iii) higher crude transported volumes primarily as a result of the increase in production and the capture of barrels from third parties, and (iv) an increase in the volume of refined products transported primarily due to the recovery of economic activity in Colombia. These effects were partially offset by: (i) a decrease in the number of reversal cycles of the Bicentenario pipeline in 2022 (one cycle) versus 2021 (19 cycles), and (ii) the one-time recognition of operating income in 2021, derived from the settlement agreement with Frontera.

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In 2021, our transportation and logistics segment sales were COP 12,158.466 million compared to COP 12,194,440 million in 2020. The 0.3 % decrease in 2021 as compared with 2020 was mainly due to: (i) lower crude transported volumes as a result of the reduction in production, and (ii) the termination of the receipt of the Continuity Plan Margin (charge included in the hydrocarbon price structure, corresponding to the recovery of the investment of the Pozos Colorados – Galán multi-purpose pipeline) by Cenit in the pricing structure for refined products as of April 2021. These effects were partially offset by an increase in revenues associated with increased refined products transported volumes, which in turn was primarily due to the recovery of demand and higher reversal cycles in the Bicentenario pipeline.

The cost of sales for our transportation 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 3,893,210 in 2022 as compared to COP 3,260,309 million in 2021. The cost of sales for this segment increased by 19.4 % in 2022 as compared with 2021 mainly due to: (i) higher depreciation due to the change in depreciation method of the Bicentenario pipeline, higher capital investment and the exchange rate effect in the depreciation of subsidiaries of the segment with U.S. dollar as their functional currency; (ii) higher operation and maintenance activities, and (iii) the increase in the variable costs of materials and electricity, mainly related to higher volumes of crude and oil products transported and increases in tariffs, derived from market conditions.

The cost of sales amounted to COP 3,260,309 in 2021 as compared to COP 3,381,357 million in 2020. The cost of sales for this segment decreased by 3.6% in 2021 as compared with 2020 mainly due to: (i) lower depreciation due to the extension of the useful lives of Bicentenario and ODL pipelines, and (ii) a reduction in the variable costs of materials, mainly related to lower crude transported volumes.

In 2022, operating expenses before the impairment of non-current assets increased by 242.7% as compared to 2021 mainly due to the effect of the income generated in 2021 by the Frontera settlement agreement.

In 2021, operating expenses before the impairment of non-current assets decreased by 71.2% as compared to 2020 due to the effect of the settlement agreement in which Frontera recognized to Bicentenario the value equivalent to a portion of the syndicated debt, as well as a compensation in favor of Cenit for the early termination of the contracts.

The impairment loss of non-current assets recognized in the segment in 2022 was COP 406,229 million, compared to the impairment losses of non-current assets of COP 165,901 million in 2021. This impairment loss was primarily due to decrease in the volumetric forecast, which results in a decrease in the use of the Southern Cash Generating Unit (Port of Tumaco and Transandino pipeline) and the Northern Cash Generating Unit (Caño Limón).

The impairment of non-current assets recognized in the segment in 2021 was COP 165,901 million, compared to the reversal of impairment losses of non-current assets of COP 341,065 million in 2020. This impairment loss was primarily due to the South Cash Generating Unit, which includes the Transandino pipeline – (OTA) and the port of Tumaco, which in turn was primarily due to a decrease in our estimate of its long-term volume capability.

The segment recorded net income attributable to owners of Ecopetrol of COP 4,483,060 million in 2022 as compared to a net income of COP 4,635,354 million in 2021 and COP 4,574,800 million in 2020.

4.6.1.11

Refining and Petrochemicals Segment Results

In 2022, the refining and petrochemical segment sales were COP 89,178,947 million compared to COP 50,976,385 million in 2021. In 2022, sales of refined products and petrochemicals increased by 74.9% as compared with 2021, mainly due to: (i) an increase of our volumes of gasoline and diesel sales in line with the general increase in domestic demand for fuels due to the reactivation of the economy, and (ii) higher prices of the product basket given external market factors. Invercolsa’s revenues increased as a result of the higher commercialization of: (i) natural gas volumes, primarily due to progress in campaigns to encourage gas consumption in commercial and vehicular natural gas, and (ii) installation strategies for residential users to increase their volumes. Additionally, Esenttia’s sales volume and its total cumulative margin decreased compared to 2021, primarily due to market conditions associated with: (i) increased inflation levels, (ii) increased price competition resulting from the entry of Asian products to the region, (iii) increased product supply in South American countries, and (iv) supply chain issues in the region.

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In 2021, the refining and petrochemical segment sales were COP 50,976,385 million compared to COP 26,104,351 million in 2020. In 2021, sales of refined products and petrochemicals increased by 95.3% as compared with 2020, mainly due to: (i) an increase of our volumes of gasoline and diesel sales in line with the general increase in demand due to the reactivation of the economy, and (ii) higher prices of the product basket given external market factors. Invercolsa’s revenues increased as a result of the higher commercialization of: (i) natural gas volumes, primarily due to progress in campaigns to encourage gas consumption in commercial and vehicular natural gas, and (ii) installation strategies for residential users to increase their volumes. Additionally, Esenttia’s sales volume remained stable compared to 2020, while its total cumulative margin increased, primarily due to favorable market conditions associated with: (i) increased demand that favored prices, (ii) lower Asian product availability due to logistic constraints, (iii) the stable operation of the main polymer grade polypropylene raw material supplier, and (iv) the implementation of a sales strategy to strengthen relations with traditional clients and increase market share in countries with higher profitability.

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.

Cost of sales amounted to COP 80,331,998 million in 2022, compared to COP 48,535,388 million in 2021 and COP 25,825,555 million in 2020. In 2022, the cost of sales for this segment increased 65.5% as compared with 2021, principally due to: (i) increased in volume purchases of crude oil to be used by our refineries primarily due to higher throughput and higher products imports, (ii) higher average purchase prices, (iii) increase in diesel and gasoline imports associated with the higher demand caused by the economic recovery and major maintenance activity at our refineries, (iv) commissioning of the Cartagena Crude Plant Interconnection Project and (v) the higher average COP/USD exchange rate.

In 2021, the cost of sales for this segment increased 87.9% as compared with 2020, principally due to (i) increased in volume purchases of crude oil to be used by our refineries primarily due to higher throughput, (ii) higher average purchase prices, (iii) increase in diesel and gasoline imports associated with the higher demand caused by the economic recovery and major maintenance at our refineries. This increase was partially offset by the inclusion of a higher percentage of domestic crude in the Cartagena Refinery, which resulted in a more cost-effective crude slate.

In 2022, operating expenses before the impairment of non-current assets increased by 30.9% as compared to 2021, mainly due to: (i) an increase in commercialization expenses directly tied to the increase in sales, and (ii) the recognition of the fixed cost of plants temporarily halted at the Cartagena Refinery as a result of scheduled major maintenance works.

In 2021, operating expenses before the impairment of non-current assets increased by 2.1% as compared to 2020, mainly due to: (i) an increase in commercialization expenses directly tied to the increase in sales, and (ii) the recognition of the fixed cost of plants temporarily halted at the Cartagena Refinery, which in turn was primarily as a result of: (a) operational events and public order related obstructions, (b) continuing restrictions resulting from the continuation of the COVID-19 pandemic, and (c) scheduled major maintenance and operational events.

In 2022, we recognized an impairment recovery of non-current assets in this segment totaling COP 1,096,021 million, as compared to an impairment loss of COP 305,466 million in 2021. The recovery recorded in 2022 was generated for the Cartagena Refinery, mainly due to better operating performance and the capture of higher refining margins in the short and medium term. The above was partially offset by the effect of the increase in the discount rate.

In 2021, we recognized an impairment loss of non-current assets in this segment totaling COP 305,466 million, as compared to a reversal of impairment of COP 781,528 million in 2020. The impairment loss recorded in 2021 is primarily the result of an impairment loss of COP 340,116 million attributable to the Barrancabermeja refinery modernization plan, considering the progress in the technical analysis and fit of the project under current market conditions and challenges. The above was partially offset by a reversal of impairment of COP 34,650 million attributable to the Cartagena Refinery, mainly due to higher refining margins

As mentioned earlier, the refining segment is highly sensitive to changes in product prices and feedstock in the international market, discount rate, refining margins, changes in environmental regulations and cost structure and the level of capital expenditures, among others.

The refining and petrochemicals segment recorded net income attributable to owners of Ecopetrol of COP 4,686,009 million in 2022 compared to a net loss of COP 1,198,619 million in 2021 and a net loss of COP 2,848,511 million in 2020.

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4.6.1.12

Electric Power Transmission and Toll Roads Concessions Segment Results

As mentioned above, our Electric Power Transmission Toll Roads Concessions Segment was created in September 2021 as a result of the ISA acquisition and as such the information below presents the results for the 12 months in 2022, compared with results for four months in 2021.

In 2022, the electric power transmission and toll roads segment revenues from contracts with customers were COP 13,357,506 million, which included COP 10,004,902 million for electricity transmission, COP 2,867,499 million for toll road concessions and COP 485,105 million for telecommunication technologies and other operating revenues. In 2022, electricity transmission revenues were positively affected by the completion of projects under construction that will enable a cleaner energy matrix in the region. Seven power transmission projects, one battery project, and 76 expansions and reinforcements were activated. Together, these projects are expected to generate annual revenues of USD 167 million and add more than 2,200 km of circuit to the transmission network. Toll road concession revenues were positively affected by the change in the treatment of financial assets from Chilean pesos to UF, together with higher revenues associated with the operation and management of road infrastructure. Telecommunication technologies were positively affected by higher sales of connectivity, sales of capacity, Internet and Ethernet services and other telecommunications services in Colombia and Peru, and the growth of the over the top operators segment in Colombia.

In 2021, the electric power transmission and toll roads segment revenues from contracts with customers were COP 4,113,198 million, which included COP 2,556,089 million for electricity transmission, COP 1,348,322 million for toll road concessions and COP 208,787 million for telecommunication technologies and other operating revenues. Electricity transmission revenues were positively affected by the entry into operation of certain energy transmission projects, the consolidation with Piratininga-Bandeirantes Transmissora de Energia (PBTE) in March 2021, and the positive impact of macroeconomic variables in Brazil and Colombia. Toll road concession revenues were positively affected by higher returns on contract assets and higher revenues from maintenance of concessions and toll management in Chile, partially offset by the negative effects of the termination of the Ruta del Maule concession contract. Telecommunication technologies were positively affected by higher sales of connectivity services given the increase in internet consumption, sales of capacity and other telecommunications services in Colombia and Peru.

The operating costs for our electric power transmission and toll roads concessions segment, which is mainly related to construction costs of concession contracts, operation and maintenance costs, amounted to COP 5,854,832 million for the 12 months of 2022, compared to COP 1,817,491 million for the four months of 2021 following our acquisition of ISA and its integration to our Group. Administrative expenses, which include depreciation, commissions and fees, impairment of non-current assets and services, including acquisition costs related to our acquisition of ISA, amounted to COP 1,157,522 million in 2022, compared to COP 374,670 million for the four months of 2021 following our acquisition of ISA and its integration to our Group. The electric power transmission and toll roads segment and its companies 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 2022, the share of profit of associates and joint ventures caused a positive effect in our results of COP 515,746 million, 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 2021, the share of profit of associates and joint ventures caused a positive effect in our results of COP 214,698 million, which corresponds 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.

The electric power transmission and toll roads concessions segment recorded income attributable to owners of Ecopetrol of COP 673,688 million in 2022, as compared to net income attributable to owners of Ecopetrol of COP 386,438 million in 2021.

4.7

Liquidity and Capital Resources

Our principal sources of liquidity in 2022 were: (i) cash flows from our operations amounting to COP 36,234,570 million, (ii) cash flow from dividends amounting to COP 1,471,134 million, and (iii) cash flows from our investing activities mainly due to the net sales of securities investment portfolio amounting to COP 1,301,394 million.

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Our main uses of cash in 2022 were: (i) COP 21,877,770 million in capital expenditures, which included investments in property, plant and equipment, natural and environmental resources and intangibles, (ii) dividend payments amounting to COP 13,356,947 million, which included dividends of COP 11,622,778 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to the non-controlling shareholders of our subsidiaries totaling COP 1,734,169 million, and (iii) COP 5,057,716 related to 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 increased by 60.8% in 2022 as compared to 2021, mainly as a result of:

(i)

A 82.1% increase in our operating income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to: (i) favorable crude and refined product prices in the international, Asian and European markets, (ii) higher results in the refineries, (iii) higher sales volumes associated with increase in domestic production of gas and refined products and the increase of our consolidated production in Permian, and (iv) the consolidation of ISA’s results for the 12 months of 2022. The above was partially offset by: (i) inflation and the exchange rate effect on operating costs and expenses, (ii) higher interest on debt, (iii) higher exploratory expenses, and (iv) an increase in the nominal income tax rate for 2022 as compared to 2021.

(ii)

Higher working capital needs mainly due to an increase in accounts receivable from the FEPC, linked to higher prices of gasoline and diesel in the international markets as compared to the domestic market. For more information see section Financial Review—Factors Affecting Our Operating Results—FEPC.

Net cash provided by operating activities increased by 145.3% in 2021 as compared to 2020, mainly as a result of:

(i)

A 132.7% increase in our operating income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to: (i) a favorable Brent price environment and notable commercial management that allowed us to materialize better crude, product and petrochemical price spreads, (ii) higher product and gas sales volumes, associated with higher domestic demand as a result of the economic reactivation, (iii) a solid operating performance in all business segments despite the public and social order situation in Colombia that continued in 2021, (iv) the increased contribution of our subsidiaries in the Permian to our consolidated production, and (v) the acquisition of ISA and subsequent consolidation of its positive operating results since September 2021.

(ii)

Higher working capital needs mainly due to an increase in accounts receivable from the FEPC, (ii) increase of inventories by sales in transit and price effect, and (iii) increase in tax assets give that income tax advances did not offset the charged taxes of Ecopetrol S.A.

Cash used in investing activities

In 2022, net cash used in investing activities decreased by 11.8% as compared to 2021, mainly as a result of the extraordinary use of cash for the acquisition of ISA in 2021, and a 614% increase in dividends received from our associations and joint ventures. The decrease in net cash used in investing activities was partially offset by a 64.6% increase in capital expenditures, mainly in development wells in Rubiales, Caño Sur, Castilla, Casabe, and Permian in the upstream segment, investments focused on operational continuity in the midstream and downstream segments, investments in the construction of power lines, and investments to increase the reliability of the grid and comply with regulation.

In 2021, net cash used in investing activities increased by 140.6% as compared to 2020, mainly as a result of: (i) a 19.6% increase in capital expenditures, mainly in development wells in Rubiales, Castilla, Middle Magdalena Valley, and Permian in upstream segment, investments in pipelines infrastructure’s integrity and reliability in midstream segment and focused on operational continuity in downstream segment, and (ii) the acquisition of ISA for COP 8,951,587 million, net of acquired cash.

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Cash used in financing activities

Net cash used in financing activities increased by 372.1% in 2022, as compared to 2021, due to: (i) a COP 10,585,660 increase in dividend payments in 2022 as compared to 2021. This increase was partially offset by a decrease from borrowings, net of related repayments of principal and payments of interest, of COP 15,123,413 million as compared to 2021.

Net cash provided by financing activities increased by 364.7% in 2021, as compared to 2020, due to: (i) an increase in cash from borrowings, net of related repayments of principal and payments of interest, of COP 10,065,697 million as compared to an increase of COP 6,455,835 million in 2020, which in turn primarily reflects Ecopetrol S.A. entering into committed lines of credit for the purchase of ISA by COP 14,232,966 million in August 2021 which were partially repaid with the issuance of SEC-registered bonds in an aggregate amount of USD 2,000 million, and (ii) a COP 5,963,064 million decrease in dividend payments in 2021 as compared to 2020

4.7.2

Capital Expenditures

Our consolidated capital expenditures in 2022, 2021 and 2020 were COP 21,877,770 million, COP 13,294,962 million and COP 11,116,861 million, respectively. These investments were distributed by business segment on average, for the past three years as follows: 75.7% for the exploration and production segment, 10.2% for refining and petrochemicals, 9.9% for the transportation and logistics segment and 4.2% for the electric power transmission and toll roads concessions segment. See Note 33.3 to our consolidated financial statements for more detail about capital expenditures by segment.

Our investment plan approved for 2023 is a range of between COP 25.3 trillion and COP 29.8 trillion. See section Strategy and Market Overview—Our Corporate Strategy—2023 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

The Board of Directors has proposed, for approval in the General Assemble of Shareholders to be held on March 30, 2023, a distribution of ordinary dividends for the fiscal year ended December 31, 2022, amounting to COP 24,382,200 million, or COP 593 per share, based on the number of outstanding shares as of December 31, 2022. Of the total dividends that would be paid, if approved, COP 487 per share corresponds to an ordinary dividend pursuant to our current dividend policy and COP 106 per share corresponds to an extraordinary dividend given the strong operational results of the Company in 2022. The dividend payment is proposed to be made in three installments for the minority shareholders of Ecopetrol in April, September and December 2023 and offset with the FEPC accounts receivable for the Nation during 2023.

In 2022, we paid dividends of COP 11,622,778 million to our shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP 1,734,169 million. COP 6,788,385 million in dividends corresponding to the Nation were offset against the FEPC accounts receivable owed to Ecopetrol.

In 2021, we paid dividends of COP 696,387 million to our shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP 2,074,900 million.

In 2020, we paid dividends of COP 7,369,499 million to our shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP 1,364,852 million.

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 income and equity for years ended December 31, 2022, 2021 and 2020, in accordance with Colombian IFRS and IFRS:

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Table 63 – Consolidated Net Income and Equity


	For the year ended December 31,			% Change
	2022	2021	2020	2022/2021	2021/2020

	(COP Million)
Net income attributable to owners of Ecopetrol (IFRS)	31,604,781	15,649,143	1,586,677	102.0	886.3
Cash flow hedge for future company exports	(104,567)	(108,198)	(122,375)	(3.4)	(11.6)
Exchange rate effects on tax bases – Deferred tax	1,906,077	1,153,739	223,775	65.2	415.6
Net income Attributable to owners of Ecopetrol (Colombian IFRS)	33,406,291	16,694,684	1,688,077	100.1	889.0
Net Equity (IFRS)	113,903,089	90,583,772	53,499,363	25.7	69.3
Exchange rate effects on tax bases – Deferred tax	5,183,961	3,459,908	2,319,907	49.8	49.1
Purchase Price Allocation ISA	—	(291,608)	—	(100.0)	100.0
Net Equity (Colombian IFRS)	119,087,050	93,752,072	55,819,270	27.0	68.0

As noted above, certain differences exist between our net income 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 income 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, in order 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 Spanish acronym) 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.

As a result of this accounting policy difference, for the year ended December 31, 2022, our net income as reported under IFRS was COP 104,567 million higher than our net income as reported under Colombian IFRS.

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 and it consolidates some subsidiaries whose functional currency is the U.S. dollar but who settled their taxes 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, 2022, our net income attributable to owners of Ecopetrol as reported under IFRS was COP 1,906,077 million lower than our net income attributable to owners of Ecopetrol as reported under Colombian IFRS.

The application of IAS12.41 also generated adjustments to our goodwill and investments in companies impairments of COP 0 million in 2022 and 2021 and COP 12,435 million in 2020 in connection with our purchase of subsidiaries whose functional currency is the U.S. dollar as well as adjustments to our revenue from the equity method of COP 0 million in 2022 and 2021 and COP 12,091 million in 2020 in connection with our associates and joint ventures whose functional currency is the U.S. dollar.

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As a result of these accounting policy differences described above, for the year ended December 31, 2022, we reported net income attributable to the owners of Ecopetrol under IFRS of COP 31,604,781 million as opposed to a net income attributable to the owners of Ecopetrol of COP 33,406,291 million reported under Colombian IFRS for the same period. For the year ended December 31, 2021, we reported net income attributable to the owners of Ecopetrol under IFRS of COP 15,649,143 million as opposed to a net income attributable to the owners of Ecopetrol of COP 16,694,684 million reported under Colombian IFRS for the same period. For the year ended December 31, 2020, we reported net income attributable to the owners of Ecopetrol under IFRS of COP 1,586,677 million as opposed to a net income attributable to the owners of Ecopetrol of COP 1,688,077 million reported under Colombian IFRS for the same period.

4.9

Financial Indebtedness and Other Contractual Obligations

As of December 31, 2022, we had outstanding consolidated indebtedness of COP 23.5 billion, which corresponded primarily to the following long-term transactions:

Table 64 – Consolidated Financial Indebtedness

Company

Type

Initial Date

Original Amount

Maturity

Interest Rate

Amortization

Ecopetrol S.A.

Bonds

September 18, 2013

USD 1,300 million

September 18, 2023

5.875

Bullet

September 18, 2013

USD 850 million

September 18, 2043

7.375

Bullet

May 28, 2014

USD 2,000 million

May 28, 2045

5.875

Bullet

September 16, 2014

USD 1,200 million

January 16, 2025

4.125

Bullet

June 26, 2015

USD 1,500 million

June 26, 2026

5.375

Bullet

June 15, 2016*

USD 500 million

September 18, 2023

5.875

Bullet

April 29, 2020

USD 2,000 million

April 29, 2030

6.875

Bullet

November 02, 2021

USD 1,250 million

November 02, 2031

4.625

Bullet

November 02, 2021

USD 750 million

November 02, 2051

5.875

Bullet

December 1, 2010

COP 284,300 million

December 1, 2040

Floating

Bullet

August 27, 2013

COP 168,600 million

August 27, 2023

Floating

Bullet

August 27, 2013

COP 347,500 million

August 27, 2028

Floating

Bullet

August 27, 2013

COP 262,950 million

August 27, 2043

Floating

Bullet

Bank Loans

December 30, 2011**

USD 440 million

December 20, 2025

Floating

Semi-annual

August 17, 2021

USD 3,672 million

August 17, 2023

Floating

Quarterly

September 29, 2022

USD 1,200 million

August 17, 2023

Floating

Semi-annual

December 20, 2022

USD 822 million

December 20, 2027

Floating

Semi-annual

Various

USD 465 million

Various

Floating

Various

ECAs

December 30, 2011**

USD 2,650 million

December 20, 2027

Fixed

Semi-annual

December 30, 2011**

USD 100 million

December 20, 2027

Floating

Semi-annual

December 30, 2011**

USD 97 million

December 20, 2027

Fixed

Semi-annual

December 30, 2011**

USD 210 million

December 20, 2027

Floating

Semi-annual

Invercolsa & Subsidiaries

Bank Loans

Various

COP 442,998 million

Various

Ocensa

Bond

July 14, 2020

USD 500 million

July 14, 2027

4.000

Bullet

Oleoducto Bicentenario

Bank Loan

July 5, 2012

COP 2.1 trillion

July 5, 2024

Floating

Quarterly

ODL

Lease

November 5, 2015

COP 308,221 million

November 4, 2032

Floating

Monthly

ISA & Subsidiaries

Bonds

Various

USD 2.81 billion

Various

USD 2.2 billion†

Various

COP 3,260 billion

Various

Bank Loans

Various

USD 264 million

Various

USD 607 million†

Various

COP 1,550 billion

Various

*	Reopening of bond due to 2023.

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Debt originally obtained by Cartagena Refinery for the refinery modernization and voluntarily assumed by Ecopetrol. In prior annual reports on form 20-F, there was a typographical error in respect of the original amount outstanding of the Bank Loan. It was listed as USD 321 million and the correct amount as listed in the table above is USD 440 million.

^†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 do not constitute an approval for the issuance of securities or any financing transaction.

On January 10, 2023, Ecopetrol priced a 10-year, 8.875% coupon note, due on January 13, 2033. In addition, on January 17, 2023, the Company announced a tender offer for up to USD 1 billion nominal amount of its notes due on September 18, 2023; offers for an aggregated amount of USD 976 million were received. For more detail on these transactions, see Financial Statements—Subsequent and relevant events.

The short and long-term debt transactions executed in 2022 were as follows:

Between March and August 2022, Transelca S.A. and Internexa S.A., subsidiaries of ISA in Colombia, raised an aggregate of COP 279,907 million by executing several loan transactions with different maturities, in the local market.

Between March and December 2022, several of ISA’s subsidiaries in Perú (CTM, Internexa, Red de Energía del Perú, ISA Perú) raised an aggregate of USD 166.2 million and PEN 249.3 million by means of bank loans with different maturities, executed with local and international counterparties.

On April 4, 2022, Consorcio Transmantaro S.A. (“CTM”), one of ISA’s electric power transmission subsidiaries in Perú issued 5.200% amortizing notes due 2038 in an aggregate amount of USD 500 million under an unregistered Rule 144A/Regulation S notes offering (COP 1.89 trillion according to the COP/USD exchange rate as of April 04, 2022). The notes were listed on the Official List of the Luxemburg Stock Exchange. This follows CTM’s announcement on March 22, 2022, of an any and all tender offer with allocation codes and consent solicitation to holders of CTM’s 4.375% senior notes due 2023.On April 18, 2022, Companhia de Transmissão de Energia Elétrica Paulista (“ISA CTEEP"), ISA’s electric power transmission subsidiary in Brazil, issued BRL 700 million of local amortizing notes (debentures) due in 2026. The notes bear an interest rate of CDI 1.55%. In addition, the Company raised BRL 233.7 million by means of a 20-year loan bearing an interest rate of TLP 2.01%.

Between June and December 2022, Internexa Brazil raised an aggregate of BRL 65.6 million.

The toll roads operated by Intervial Chile, executed the following debt transactions during 2022:

On November 15, 2022, Ruta del Loa Sociedad Concesionaria S.A. issued local inflation-linked bonds due 2050, with a face value of Unidad de Fomento (“UF”) 1,927,500. The bonds bear an interest rate of 3.85%.

On March 15, 2022, Ruta del Bosque Sociedad Concesionaria S.A., prepaid its notes due June 15, 2022. The outstanding nominal value as of the prepayment date amounted to UF 1,500,500.

On September 15, 2022, Ruta de la Araucanía Sociedad Concesionaria S.A., raised funds through an inflation-linked loan for an aggregate amount of UF 1,347,515. The bonds bear a floating interest rate of TAB (180) 1.28%.

The short and long-term debt transactions executed in 2021 were as follows:

On August 17, 2021, we entered into a committed line of credit for up to USD 1.2 billion with Banco Bilbao Vizcaya Argentaria, S.A. New York Branch, Banco Santander, S.A., JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd., Sumitomo Mitsui Banking Corporation and The Bank of Nova Scotia, as lenders. As of the date of this annual report, no disbursements have been made from this line of credit.

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On August 17, 2021, we entered into a loan agreement for an amount of up to USD 4.0 billion with Banco Santander, S.A., Citibank, N.A., JPMorgan Chase Bank, N.A. and The Bank of Nova Scotia, from which USD 3,672,000,000 were disbursed to finance the acquisition of ISA. The loan is payable at maturity on August 18, 2023, and bears an interest rate of 3-month LIBOR plus 80 basis points. As of the date of this annual report, the outstanding balance on this loan is USD 472,000,000.

On November 2, 2021, we issued 4.625% Notes due 2031 in an aggregate amount of USD 1.25 billion (COP 4.98 trillion according to the COP/USD exchange rate as of December 31, 2021) and 5.875% Bonds due 2051 in an aggregate amount USD 750 million (COP 2.99 trillion according to the COP/USD exchange rate as of December 31, 2021) in a SEC-registered transaction. The notes and bonds were listed on the NYSE. The proceeds thereof were used to partially refinance the loan described above disbursed in connection with the Acquisition. On November 26, 2021, ISA issued 3.825% Notes due 2033 in an aggregate amount of USD 330 million (COP 1.31 trillion according to the COP/USD exchange rate as of December 31, 2021) under an unregistered Rule 144A/Regulation S notes offering. The notes were listed on the Official List of the Singapore Exchange Securities Trading Limited.

The short and long-term debt transactions executed in 2020 were as follows:

Between March and April 2020, Ecopetrol S.A. executed short term debt transactions (trade finance and short-term loans) in Colombian pesos and US dollars, for an aggregate of COP 775 billion and USD 221.5 million, respectively (totaling COP 1.7 trillion according to the COP/USD exchange rate as of the day of execution of each transaction). All loans were prepaid in September 2020.

On April 15, 2020, Bank of Nova Scotia and Mizuho Bank disbursed an aggregate amount of USD 665 million (COP 2.3 trillion according to the COP/USD exchange rate as of December 31, 2020) under a committed credit facility due in September 2023.

On April 24, 2020, Ecopetrol S.A issued 6.875% Notes due 2030 in an aggregate amount of USD 2 billion (COP 6.9 trillion according to the COP/USD exchange rate as of December 31, 2020) in an SEC-registered transaction. The notes were listed on the NYSE.

On July 14, 2020, Ocensa issued 4% Notes due 2027 in an aggregate amount of USD 500 million (COP 1.7 trillion according to the COP/USD exchange rate as of December 31, 2020) in an unregistered Rule 144A/Regulation S notes offering. The notes were listed on the Luxembourg Stock Exchange. The proceeds were used to redeem, on September 18, 2020, Ocensa’s bonds originally due on May 7, 2021

Contractual Obligations

We enter into various commitments and contractual obligations that may require future cash payments. The following table summarizes our contractual obligations as of December 31, 2022.

Table 65 – Our Material Contractual Obligations


	Payments due by period
		Short Term	Long Term
		(Less than 1	(More than 1
COP Millions	Total	year)	year)
Employee Benefit Plan	45,221,255	1,785,694	43,435,561
Contract Service Obligations	22,537,776	7,961,928	14,575,848
Natural Gas Supply Agreements	24,543,428	10,373,553	14,169,875
Purchase Obligations	6,271,494	2,874,610	3,396,884
Energy Supply Agreements	16,061,618	49,056	16,012,563
Capital Expenditures	39,481,754	8,228,213	31,253,540
Financial Sector Debt	25,709,137	8,292,302	17,416,835
Bonds	87,398,300	12,814,206	74,584,094
Total	267,224,763	52,379,563	214,845,200

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4.10

Off Balance Sheet Arrangements

As of December 31, 2022, 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

Trend Analysis and Sensitivity Analysis

We updated our 2023 – 2025 Business Plan on December 7, 2022. See section Strategy and Market Overview—Our Corporate Strategy—2023–2025 Business Plan for a discussion of the trends recognized in the development of that plan.

Sensitivity Analysis

Sensitivity Analysis of Reserves

The following table provides information about the sensitivity analysis conducted on our oil and gas reserves as of December 31, 2022, considering ICE Brent crude oil prices that reasonably reflect management’s view of crude oil prices given prevailing market conditions, and management portfolio costs.

Table 66 – Sensitivity Analysis of Reserves


			Total Oil
	Oil and	Natural Gas	and Gas
	NGL (mmb)	(bcf)	(mmboe)
Reserves as of December 31, 2022	1,515.0	2,828.0	2,011.0
Sensitivity Scenario	1,478.0	2,807.0	1,971.0
Difference (mmb)	(37.0)	(21.0)	(40.0)
Difference (%)	(2.0)	(1.0)	(2.0)

The conversion rate used is 5,700 cf = 1 boe.

Assumptions for the Sensitivity Analysis of Reserves:

●

The sensitivity analysis assumes a constant ICE Brent price of USD 94.6 per barrel in 2023, between USD 88.2 and USD 81.4 per barrel in the period 2024-2030, and between USD 81.2 and USD 77.7 onwards.

●

The base scenario on which our sensitivity analysis is made corresponds to 100% of our oil, NGL and natural gas reserves, as of December 31, 2022, as presented elsewhere in this annual report.

●

Other variables such as the operating costs, capital costs and portfolio price remain unchanged for purposes of the analysis.

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Sensitivity Analysis of our Results

The following table provides information about the sensitivity of our results as of December 31, 2022, due to variations of USD 1 in the price of ICE Brent crude and of 1% in the COP/USD exchange rate.

Table 67 – Sensitivity Analysis of our Results


		Income	Difference	Income	Difference
		Statement	Between	Statement	Between
	Income	Case ICE	Real 2022	Case	Real 2022
	Statement	Brent^{(1) +}	and Case	TRM⁽²⁾	and Case
COP$Million	2022	USD1	ICE Brent	+1%	TRM
Revenue	159,611.08	160,933.64	1,322.56	161,061.28	1,450.20
Cost of sales	89,458.15	90,030.71	572.56	90,047.76	589.61
Gross Income	70,152.93	70,902.93	750.00	71,013.52	860.59
Operating expenses	9,635.18	9,635.18	—	9,635.18	—
Impairment of non-current assets	288.00	288.00	—	288.00	—
Operating income	60,229.75	60,979.75	750.00	61,090.34	860.59
Finance results, net	(6,834.76)	(6,834.76)	—	(6,834.76)	—
Share of profit of associates and joint ventures	768.42	768.42	—	768.42	—
Income before income tax	54,163.41	54,913.41	750.00	55,024.00	860.59
Income Tax	(18,963.94)	(19,226.53)	(262.59)	(19,265.26)	(301.32)
Net Income	35,199.47	35,686.88	487.41	35,758.74	559.27

(1)	ICE Brent = USD 99 per barrel

(2)	Exchange rate (TRM) = COP 4,255/USD 1.00

Assumptions for the Sensitivity Analysis of our Results:

●

Our sensitivity analysis is based on the Consolidated Statement of Profit or Loss for 2022, as presented elsewhere in this annual report.

●

The sensitivity of the ICE Brent price index is in reference to an increase of USD 1 per barrel of crude oil in the average ICE Brent reference price based on a 365-day year for 2022. Prices assumed correspond to realized prices for crude oil, natural gas and refined products for 2022, adjusted to account for the differences between such realized prices and the ICE Brent reference price.

●

The sensitivity of our results to changes in the exchange rate is in reference to a 1% average depreciation of the Colombian Peso against the U.S. dollar during 2022. Prices are the realized prices of crude oil, natural gas and refined products in 2022 and are expressed for the sensitivity using the adjusted exchange rate (i.e., a 1% average depreciation of the Colombian Peso against the U.S. dollar during 2022).

●

The income tax for each of our sensitivity analyses (price of ICE Brent and COP/USD exchange rate) is estimated using the effective corporate tax rate of 35% for 2022.

●

This sensitivity analysis keeps everything constant. In the case of significant variations of the ICE Brent price, we will perform interventions in our operating expenditures.

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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 68


VARIATION ON ICE BRENT REFERENCE PRICE		VARIATION ON AVERAGE EXCHANGE RATE
REVENUE
Sales of crude oil		Sales of crude oil
Sales of refined products		Sales of refined products
Sales of natural gas		Sales of natural gas
COST OF SALES
Local purchases from business partners		Local purchases from business partners
Local purchases of hydrocarbons from the ANH		Local purchases of hydrocarbons from the ANH
Local purchases of natural gas		Local purchases of natural gas
Imports of products		Imports of products

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5.	Risk Review

5.1

Risk Factor Summary

The following is a summary of the principal risks we face:

Risks Related to Our Business

Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time, which could adversely affect our ability to generate revenue.

Achieving our long-term growth depends on our ability to execute on 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 business depends substantially on international prices for crude oil, natural gas and refined products. The prices for these products are volatile; a sharp decrease or increase on such prices could adversely affect our business prospects, results of operations and cash position.

Foreign currency exchange rate fluctuations may affect our financial results. Given the amount of U.S. dollar denominated debt held by us and the fact that most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars, we are particularly exposed to fluctuations in the U.S. dollar/Colombian Peso exchange rate.

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.

If operational risks to which we are exposed in Colombia or overseas materialize, the health and safety of our workforce, the local community and the environment may be affected. In addition, we may suffer a disruption or shutdown of our operational activities.

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.

We are exposed to the credit, political and regulatory risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

Our ability to access the credit markets to finance our operations or refinance our debt may be limited due to, among others, the deterioration of these markets, any change to our credit ratings, and limited offering from financial institutions to participants in the oil and gas industry.

10.

We may be exposed to increases in interest rates, thereby increasing our financial costs.

11.

Our interest rate expense may be subject to uncertainty associated with the replacement or reform of benchmark indices, particularly London Interbank Offered Rate (“LIBOR”).

12.

Our current and planned investments and business activities, including any divestments, outside Colombia are exposed to political and economic risks.

13.

Our future performance depends on the successful selection, development and deployment of new technologies and the knowledge to operate, maintain, and improve them.

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14.

Our performance could be negatively affected by the lack of employees with the skills needed to execute our business strategy.

15.

If the strategic plans associated to natural gas and NGL fail to yield the expected results, our operations may not be able to keep pace with the increasing domestic demand for these products.

16.

Our operations could be affected by reactions of labor unions, social organizations, communities and contractors to Colombia’s political and social environment, environmental and climate change concerns and organizational changes.

17.

Our activities may be interrupted or affected by external factors, such as abnormal weather conditions and natural disasters that can be exacerbated by climate change.

18.

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.

19.

We have made and may make significant investments in acquisitions and joint ventures and have made and may make significant divestments, and we may not realize the expected value of any such investments.

20.

We might be required to provide financial support to our subsidiaries in Colombia or abroad.

21.

Ongoing Colombian State control entities investigations of certain employees or former employees, regarding our subsidiary Reficar and our former subsidiary Bioenergy, and, certain members of the board of directors of Offshore International Group, where Ecopetrol formerly held a stake, could affect our reputation.

22.

Our results may be affected by supply chain disruptions and high price volatility impacting the performance of our suppliers, our business partners or their third-party service providers.

23.

Our insurance policies do not cover all liabilities and may not be available for all risks.

24.

New trends in the insurance sector in the face of climate change may bring additional costs or create new conditions to be addressed by our corporate insurance program.

25.

A failure in our information technology systems or cyber security attacks may adversely affect our financial results.

26.

We are exposed to behaviors incompatible with our ethics and compliance standards.

27.

The reliability and capacity of national power supply systems may affect or limit the continuity of our operations or limit growth.

28.

Rising water production levels may affect or constrain our crude oil production.

Risks Related to Colombia’s and the Region’s Political Environment

29.

Changes in economic policies in Colombia, Peru, Brazil and Chile could materially adversely affect our business, financial condition and results of operations.

30.

Our business operations and financial condition could be negatively affected by the COVID-19 pandemic or other pandemic diseases and health events.

31.

The Colombian Government could seize or expropriate our assets under certain circumstances for fair compensation.

32.

Colombia has experienced internal security issues that have had or could have a negative effect on the Colombian economy and on us.

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33.

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.

34.

There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries.

35.

Companies operating in Colombia, including us, are subject to the prevailing economic conditions and the investment climate in Colombia, which may be less stable than the prevailing economic conditions and investment climate in developed countries.

Legal and Regulatory Risks

36.

Our operations are subject to extensive regulation, which is subject to change from time to time by the applicable regulatory authorities.

37.

More stringent environmental requirements or commitments imposed through regulation or public demand may lead to potential increased expenses or reduced demand for our products, as well as hardship in achieving timely permits and licenses.

38.

We may not be able to keep pace with changing requirements related to impacts to Colombia’s biodiversity and nature.

39.

Our operations might be affected by rising climate change and energy transition regulatory developments.

40.

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.

41.

We may incur losses and spend time and money defending pending lawsuits and arbitrations and responding to administrative investigations.

Risks Related to Our ADSs

42.

Holders of our ADSs may encounter difficulties in protecting their interests.

43.

Our ADS holders may be subject to regulations on foreign investment in Colombia.

44.

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.

45.

The protections afforded to minority shareholders in Colombia are different from those in the United States and may be difficult to enforce.

46.

ADSs do not have the same tax treatment as other equity investments in Colombia.

47.

Judgments of Colombian courts with respect to our ADSs will be payable only in Colombian Pesos.

48.

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.

49.

We are not required to disclose as much information to investors as a U.S. issuer is required to disclose.

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Risks Related to the Controlling Shareholder

50.

Our controlling shareholder’s interests may differ, from time to time, from those of certain minority shareholders, or that may affect our long-term strategy.

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

Risks Related to Our Business

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, which could adversely affect our ability to generate revenue.

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, 2022, 2021 and 2020, 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 43/Bl in 2020, USD 69 in 2021 and USD 98/Bl in 2022. In 2022, the Company recognized an increase in oil and gas proven reserves of 0.5% as compared to 2021, to 2,011 mmboe in 2022 from 2,002 mmboe in 2021. 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 cash-generating units (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 2022 impairment losses, net of non-current assets of COP 287,999 million, corresponds to the net result of:

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An impairment of non-current assets in the exploration and production segment of COP 890,248 million, mainly due to (i) a decline in the reserves of the Ecopetrol’s Cusiana and Llanito fields, (ii) lower prospects in Hocol’s Upía and Cicuco fields, (iii) an increase in the discount rate, and (iv) the impact of the tax reform.

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A recovery of impairment in the Cartagena Refinery of COP 1,096,021 million, primarily due to operating and performance improvements that permitted capturing greater refining margins in the short and medium-term. The recovery was partially offset by an increase in the discount rate.

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An impairment of non-current assets in the transportation and logistics segment of COP 406,229 million, primarily due to a lower volume outlook for the Southern Cash Generating Unit, which is comprised of the Tumaco Port and the Transandino pipeline (OTA) and the Northern Cash Generating Unit, comprised of Caño Limón.

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An impairment of non-current assets in the electric power transmission and toll roads concessions segment of COP 87,543 million, mainly due to lower margins and decreased performance of Internexa Brazil.

Any significant change in estimates, including capital expenditures reductions related to upstream 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.

In order to assess the possible impact of current expected oil price scenarios and market conditions, as well as of further developments driven by the economic environment for the oil and gas industry, the Company has performed a sensitivity analysis over its proved reserve balance as of December 31, 2022. Based on these calculations, assuming an average price per barrel of ICE Brent price of USD 94.6 per barrel in 2023, USD 88.2 - USD 81.4 per barrel between 2024 and 2030, and between USD 81.2 and USD 77.7 onwards, Ecopetrol could recognize a decrease in oil and gas proved reserves of approximately 2%. This analysis considers our estimates and expectations regarding the main assumptions used in its proven reserve calculation, which final actual result may fluctuate and differ substantially from those provided herein due to several factors outside of the control of the Company. For additional information see section Financial Review—Trend Analysis and Sensitivity Analysis.

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 condition.

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 continue to strengthen the competitiveness of our Oil and Gas business, diversify our portfolio in energy and low emissions, and achieve decarbonization targets. In this regard, our 2040 Strategy seeks to grow the company´s Oil and Gas business by increasing production, while decarbonizing its process, leveraged on technologies. In addition, our business depends on developing the reserves recovery potential in existing fields and discovering and/or acquiring new reserves, and in turn developing them successfully is pivotal to this growth, and to contribute with energy security and sovereignty.

Our exploration activities expose us to inherent geological and drilling risks including the risk of not discovering commercially viable crude oil or natural gas reserves, and the risk that some exploratory wells initially budgeted for may be drilled at a later stage or not be drilled at all. Despite the effort we make to control costs associated with drilling, these are often uncertain, and numerous factors beyond our control may 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—2023 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, 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 will be affected and our reserves portfolio will 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.

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Additionally, we face the risk of having stranded assets across our business segments. Specifically, we define a stranded asset as an asset or investment that loses its capacity to create economic return before ending its life cycle due to the changes brought about by the low carbon energy transition. Stranded asset risk is measured through a stranded asset risk index methodology that takes into account three risk elements: market (increasing uncertainty in price, accelerated peak oil demand); sustainability (reduced probability of developing an asset because of less community and society support to fossil fuels developments, increased pressure from investors to produce cleaner energies, regulatory changes), and capability (lack of technological capabilities to produce in the short term). Assets that have a score over a threshold in this index are considered in high risk. Our analysis resulted in assets in our upstream, midstream and downstream segments with high, medium, and low risk of becoming stranded, and those with high-risk and potential (in terms of volume) are being prioritized to define an action plan. While we have begun to implement a mitigation plan in respect of assets with a high risk of becoming stranded, such as prioritizing short cycle projects, starting projects earlier, making current production cleaner and more efficient, and divesting less strategic assets, we can offer no assurance that certain of our assets will not become stranded in the medium to long term.

In relation with the energy transition, we also face the risks of not being able to successfully incorporate alternative options to our portfolio in the face of traditional businesses or segments that lose the capacity to generate value due to changes in energy consumption patterns at a global or local level. This could impact the achievement of the Company’s growth targets and its resilience in the long term.

Regarding our energy transmission business line, we face risks associated with energy transition. To achieve energy transition objectives, we have developed the “Grid of the Future” vision with three main priorities: first, the adaptation of the existing grid and better use of available capacity; second, the connection of renewable energy sources to transmission networks; finally, the development of interconnections that make regional electrical integration feasible. This vision faces long-term risks associated with changes in remuneration models and political instability in the region. Additionally, the greater social and environmental requirements for business development, may bring more restrictions to our operations and growth expectations. Market and competition risks in our electric power transmission and toll roads segment may affect our medium-term growth.

In terms of energy transition risks, we face risks related to our capacity to implement measures to reduce and offset carbon and methane emissions, our adaptation to climate variability and climate change, regulatory risks related to the new climate change regulations implemented in Colombia, such as the updated NDC, and the oil & gas industry’s climate change plan that includes new national mitigation and adaptation measures. We evaluate risks associated with the market (crude oil and natural gas demand) and regulatory (carbon pricing and offsetting) under three International Energy Agency’s (“IEA”) World Energy Outlook 2022 scenarios, to analyze the resilience of our long-term strategy. These changes could lead to increases in our costs and investments in the short term and medium term (we have already incurred in costs related with these regulations and it is expected that continuing to comply with this evolving regulatory landscape will bring additional costs and investments for us in the short term). See section Risk Review—Risk Factors—Legal and Regulatory Risks—Our operations might be affected by rising climate change and energy transition regulatory developments. In addition, 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.

To successfully achieve our 2040 Strategy, we are venturing into low-emission energy-diversification businesses, such as hydrogen as source of energy, CCUS and NCS investments to mitigate the effects of climate change. These investments require the development of new technologies at competitive costs, and the growth of potential markets, such as demand of these alternative sources in transportation segment or mobility. We cannot assure that the pace of the technological developments nor, that they will be successful or that demand growth will occur by the time we expect to achieve expected returns.

Furthermore, we are subject to physical risks related to the transition to a low carbon economy and to climate change. In this regard, 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, among others, in water shortages, floods, fires, storms, and hurricanes, rising sea levels that can change in frequency and intensity. Extreme weather events could result in damages to 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 ((i) SSP 1- RCP 2.6°C, (ii) SSP 2- RCP 4.5, and (iii) 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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In 2022, approximately 90% of the revenues came from sales of crude oil, natural gas, and refined products and 97% 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 a variety of 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 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. In particular, disagreements among OPEC members on production levels, the continued hostilities between Russia and Ukraine have impacted the international reference prices.

Furthermore, the COVID-19 pandemic and the emergence of new variants contributed to a sustained economic downturn and increased volatility in both the local and the international financial markets and economic indicators, such as exchange rates, interest rates, credit spreads and commodity prices. A new health pandemic or emergence of vaccine resistant or deadlier strains may have a negative impact on the prices of crude oil, natural gas, and refined products.

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.

During 2022, our crude oil basket price was USD 90.9/Bl versus USD 66.8/Bl in 2021, the refined product basket price was USD 118.2/Bl versus USD 79.6/Bl in 2021; and the natural gas price was USD 27.6 per barrel equivalent in 2022 versus USD 24.9 per barrel equivalent in 2021. However, it is important to consider that the margin on refined products can result either in higher or lower margins due to a change in price of crude the same way gas prices can be impacted by local conditions, such as local demand and weather conditions.

Moreover, our prices are indexed to international benchmarks such as the Brent and light distillates in the US Gulf of Mexico, 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 the retail price to monthly variations. As a result, these differences generate account receivables or account payables for Ecopetrol to or from the 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 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, the ability to pay off the receivable account against dividends of the principal shareholder, 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 will receive any such payments due to us.

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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, 2022, Ecopetrol S.A. recorded COP 24.41 trillion in accounts receivable due from FEPC and Cartagena Refinery recorded COP 1.9 trillion 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. In order 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.

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) the sol 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.

As of December 31, 2022, our U.S. dollar-denominated total debt aggregate principal amount was USD 22.3 billion, which we recognize in our consolidated financial statements at its amortized cost, which corresponds to the present value of cash flows, discounted at the effective interest rate. Out of this total, a principal of USD 16.3 billion relate 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 depreciated 13.61% in 2022, depreciated 1.52% in 2021 and depreciated 12.46% in 2020. Additionally, as of December 31, 2022, the Colombian Peso had depreciated 20.82%; as of December 31, 2021, it had depreciated 15.98%; and as of December 31, 2020, it had depreciated 4.47%, in each case in relation to the year-end exchange rate for the immediately preceding year. In addition, given the effect of COVID-19 on the world’s economies for the next years, rising inflation, increasing interest rates in the U.S. and Colombia, different global growth perspectives, political tensions in the world’s largest economies, 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 continue to lead to U.S. dollar fluctuations that will 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. 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.

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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.

We must bid for exploration blocks offered by the ANH in Colombia and similar authorities in other countries, which means we compete under the same conditions as other domestic and foreign oil and gas companies and receive no special treatment. Our ability to obtain access to potential fields also depends on our ability for evaluating and selecting potential opportunities and to adequately bid for such opportunities.

We are also exposed to international competition as a result of our international exploratory activities. Currently, we are exploring in Brazil and 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 companies, or if we cannot enter into joint ventures with market players having high potential exploration projects, our exploration activities may be limited. This could reduce our market share and, in turn, adversely affect our financial condition.

Our exploration, production, refining, transportation and electric power transmission and toll roads concessions businesses in Colombia and in the foreign countries in which we operate are subject to industry-specific operating risks, some of which, despite our internal procedures and adherence to industry best practices, are beyond our control. Our operations may be curtailed, delayed or cancelled due to adverse or abnormal weather conditions and natural disasters (mainly due to climate variability or climate change), strikes and demonstrations by local actors aimed at blocking operations, equipment failures or accidents, oil or natural gas spills or leaks, shortages or delays in the availability or in the delivery of equipment, delays or cancellation of environmental licenses or other government authorizations or judicial decisions, fires, explosions, ruptures, surface cratering, pipeline failures, sabotage, thefts, damage and attacks to our transportation and production infrastructure caused by terrorist acts of illegal armed groups. Additionally, external factors, such as disagreements over local or national government policies or decisions may cause roads and infrastructure blockades, among other factors beyond the Company’s control.

Some of our operations in Colombia and abroad could be conducted in remote and uninhabited locations that involve health and safety risks that could affect our workforce. By our own Company policy and practices, as well as under Colombian law and international industrial safety regulations, we are required to have health and safety practices that minimize risks and health issues faced by our workforce. Failure to comply with health and safety regulations in the jurisdictions where we operate may lead to investigations by health officials that could result in lawsuits or fines.

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 ethnic communities in nearby areas, we will need to incur in 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.

The occurrence of any of these operating risks could result in substantial losses or slowdowns to our operations, including injury to our employees, malfunction or destruction of property, equipment and infrastructure, clean-up responsibilities, third-party liability claims, government investigations and imposition of fines, withdrawal of environmental licenses and other government permits, suspension or shutdown of our activities and loss of revenue. The occurrence of any of these events may have a material adverse effect on our financial condition and results of operations.

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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.

Our deep-water drilling activities present severe risks, such as the risk of spills, explosions on platforms and drilling operations, and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings. As a result, more stringent government regulation may result in increased costs and longer exploration and development timeframes for our deep-water drilling operations and consequently could adversely affect our results of operations and financial condition. Heightened risks and costs associated with deep-water drilling 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.

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.

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, the global economy impacts due to energy supply shocks, the potential impacts on demand of further lockdowns or outbreaks of COVID-19, the lack of consensus among OPEC+ members, the political uncertainty in Latin America and other parts of the developed world, the discovery 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.

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Access to credit and capital markets depends on a number of factors, many of which we cannot control, including changes in: our credit ratings, 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. We cannot assure that our credit ratings will continue for any given period of time 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. On May 19, 2021, S&P Global Ratings downgraded Colombia’s long-term foreign currency debt rating from BBB- to BB+, one level below investment grade. On July 1, 2021, Fitch Rating also downgraded Colombia’s long-term foreign currency debt rating from BBB- to BB+. As a result of such sovereign downgrades, our credit rating was also downgraded by (i) S&P Global Ratings from BBB-, with a negative outlook, to BB+, with a stable outlook, while our stand-alone rating was maintained at BBB- and (ii) Fitch Ratings from BBB- to BB+, while maintaining our stand-alone rating (without incorporating government support) at BBB. On August 24, 2022, Moody’s Investors Service re-affirmed our rating at Baa3, with a negative outlook and downgraded our Baseline Credit Assessment (BCA) to ba3 from ba1. On November 18, 2022, Fitch Ratings reaffirmed our rating at BB+ with a stable outlook and our individual credit rating (stand alone credit profile) at bbb.

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.

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 abide by 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, 2022, approximately 25.9%, or a principal of USD 6.1 billion (COP 28.9 trillion, using a COP 4,765.9/1.00 U.S. exchange rate as of December 31, 2022), of our total indebtedness consisted of floating rate debt. If market interest rates rise, our financing expenses will increase and our cost of capital will 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 borne 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.

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Our interest rate expense may be subject to uncertainty associated with the replacement or reform of benchmark indices, particularly London Interbank Offered Rate (“LIBOR”).

Interest rate, equity, foreign exchange rate and other types of indices which are deemed to be “benchmarks,” including those in widespread and long-standing use, have been the subject of ongoing international, national, and other regulatory scrutiny and initiatives and proposals for reform. Some of these reforms are already effective while others are still to be implemented or are under consideration. These reforms may cause benchmarks to perform differently than in the past, or to disappear entirely, or have other consequences, which cannot be fully anticipated.

Any of the benchmark reforms that have been proposed or implemented, or the general increased regulatory scrutiny of benchmarks, could also increase the costs and risks of administering or otherwise participating in the setting of benchmarks and complying with regulations or requirements relating to benchmarks. Such factors may have the effect of discouraging market participants from continuing to administer or contribute to certain benchmarks, trigger changes in the rules or methodologies used in certain benchmarks or lead to the disappearance of certain benchmarks.

In this regard, on March 5, 2021, the U.K. Financial Conduct Authority (FCA, the authority that regulates LIBOR) confirmed that all LIBOR settings would either cease to be provided by any administrator or no longer be representative immediately after December 31, 2021, in the case of all sterling, euro, Swiss franc and Japanese yen settings and the 1-week and 2-month US dollar settings; and immediately after June 30, 2023, in the case of the remaining US dollar settings.

Regulators and market participants in various jurisdictions have identified alternative reference rates that are compliant with the standards of the International Organization of Securities Commissions. In the U.S., the Alternative Reference Rates Committee, a committee convened by the Federal Reserve that includes market participants, has recommended the Secured Overnight Financing Rate (“SOFR”), a new index calculated by short-term repurchase agreements, backed by Treasury securities, as a reference rate alternative to U.S. dollar LIBOR. Publication of SOFR began on April 3, 2018, and it therefore has a limited history. In addition, the future performance of SOFR is impossible to predict and therefore no future performance of SOFR may be inferred from any historical simulations or its limited historical performance.

As of December 31, 2022, 25.89 of our nominal consolidated debt was subject to floating interest rates that used LIBOR, SOFR, ICP and other floating interest rates as benchmarks. As of December 31, 2022, 8.33% of our nominal consolidated debt was subject to LIBOR as the benchmark. All our LIBOR referenced debt uses the 3-month or 6-month US dollar settings, which no longer will be representative after June 30, 2023, as per FCA announcements. Although we began to adapt such contracts as developments relating to a LIBOR replacement have arisen, currently, we cannot ascertain that we will complete the transition of our LIBOR-referenced contracts to alternative reference rates before June 30, 2023 and cannot reasonably estimate the impact that the transition to alternative reference rates may have on the valuation, pricing and operation of our LIBOR-based financial obligations, however such changes could have a material adverse effect on our financial condition and results of operations.

Our current and planned investments and business activities, including any divestments, 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, 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.

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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 electricity transmission and toll roads, 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, electricity 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.

Our future performance depends on the successful selection, development and deployment of new technologies and the knowledge to operate, maintain, and improve 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.

Our performance could be negatively affected by the lack of employees with the skills needed to execute our business strategy.

As the oil and gas industry and the energy sector faces an increasing number of challenges, the ability to react quickly to these challenges has become a key factor in achieving efficiency, profitability, growth, and sustainability. Our ability to achieve these goals could be negatively affected by a lack of key skilled employees that can execute our business strategy and transition to a low carbon economy with competency, creativity, and determination. This situation poses a risk if we are unable to timely strengthen or develop the capacities of management at all levels of the organization or attract new employees with the necessary skills to implement climate-resilient initiatives and to achieve our decarbonization goals.

If the strategic plans associated to natural gas and NGL fail to yield the expected results, our operations may not be able to keep pace with the increasing domestic demand for these products.

According to the latest Natural Gas Supply Plan issued by the Mining and Energy Planning Unit in July 2020 (Unidad de Planeación Minero Energética-UPME), there is expected to be a natural gas deficit in Colombia as of January 2024. Considering the CREG Resolution 186 of 2020, the natural gas market is a physical market, which means that 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 entry into operation in the short term. Additionally, we are party to a number of national gas supply contracts that have firm gas commitments. If we were unable to deliver natural gas to these clients as a result 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.

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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 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.

Due to Colombia’s political and social environment, emerging environmental and climate change concerns and organizational changes, social organizations in the communities where we have operations, communities in general, contractors, and unions, may have reactions and present their demands through social movements or other manners that may affect our operations. For example, in relation to the emerging environmental and climate change concerns, some communities have shown a special interest in avoiding the development of PPIIs, which has led to their representatives presenting bills in recent legislatures to ban PPIIs. Although none of these bills has materialized into a law, we cannot make any assurances that such bills will cease being presented or that none of them could eventually garner substantive attention to become implemented into law.

The collective bargaining agreement executed among Ecopetrol S.A. and its unionized workers in 2018, expired on December 31, 2022. This agreement established the working conditions and benefits of the Company’s unionized workers for the period from 2018 and 2022. In accordance with labor legislation, the parties signing an agreement have the power to express their intention to modify its text through a petition process before the Ministry of Labor within the two months prior to its expiration. In this regard, some unions have filed a petition against the current agreement. Likewise, the Company has also filed a petition, which does not cover provisions related to worker benefits. Ecopetrol expects to receive additional petitions from other unions in the Company. During the first quarter of 2023, the Company started a new negotiation process of the collective bargaining agreement, consistent with customary labor relations and interaction with union organizations, and in an attempt to achieve an agreement that is beneficial to all parties. We cannot guarantee that the new negotiation process will be successful, that the actions taken by the labor unions will not affect the normal development of our operations, that we will not experience strikes or labor unrest in the future, 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.

In addition, in the legislative field in Colombia, new labor legislation is expected to be enacted during 2023. The proposed law includes an 18-point reform to individual and collective labor legislation. Some of the changes cover areas such as: job stability and hiring modalities; outsourcing/subcontracting; parameters on the use of service contracts; apprenticeship contracts; workday length; decarbonization; work on digital platforms; informal and migrant work, among others. We cannot assure you regarding the contents of the final legislation or that it will not have an adverse effect on our operations and financial condition.

Our activities may be interrupted or affected by external factors, such as abnormal weather conditions and natural disasters that can be exacerbated by climate change.

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.

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“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 electric power 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 electric power transmission business’ operations.

These risks could result in fatalities, property damage, project delays, production deferrals, loss of revenue, pollution, and 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.

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 classified by the Government as indigenous reserves and Afro-Colombian lands. To undertake these activities, we must first comply with prior consultation processes, set forth by Colombian law. These prior consultation processes are 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 the decision of developing extracting industry and infrastructure projects in their territories. Generally, these consultation 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 strive to be respectful of the Constitution and laws and the autonomy of indigenous and afro-descendant communities, and we therefore do not enter their territories until we have reached an agreement with them. We also strive to structure management plans to prevent, mitigate, repair or offset the impact of our projects, as identified by local communities.

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. This opposition results from, among other factors, the communities’ view on the exploitation of natural resources, the environment, and the effects on their cultures, territories and spiritual beliefs. According to this, we may be exposed to operational restrictions 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 do not agree and object to our operations or that such communities will participate in consultation processes if available. 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 not-ethnic communities. We are also subject to other participation mechanisms, such as popular consultation “acción popular”, where local communities vote against the development of extractive industry projects. Any such similar 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.

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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 acquired interests in several companies, such as a joint exploration agreement with Anadarko Colombia Company in May 2022, our joint venture with Shell Brasil in April 2022, the acquisition of ISA in August 2021 and our joint venture with Occidental Petroleum in the U.S. Permian Basin in 2019, and may continue to do so from time to time. See sections Business Overview—Our Corporate Structure and Related Party and Intercompany Transactions––ISA Acquisition.

Obtaining the expected benefits of the 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.

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, 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.

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 in Colombia or abroad.

Although currently we are not the sponsor and have not provided guarantees to third parties to support the financing activities of any of our subsidiaries, some financial support at any point in time might be needed to assure the long-term viability of such subsidiaries 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 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.

As a majority-owned state entity, Ecopetrol’s employees and those from its subsidiaries may be subject to oversight by various administrative control entities in Colombia, which could result in preliminary or formal investigations and/or ultimately subject those employees to litigation, as well as to the imposition of fines or penalties by administrative control entities.

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Investigations of certain employees and former employees of Ecopetrol S.A., Bioenergy and Reficar and certain members of the board of directors of Offshore International Group, where Ecopetrol formerly held a stake, remain ongoing and we are cooperating fully with the authorities related to these cases. Notwithstanding, adverse developments in connection with these proceedings, could eventually impact our reputation. Additionally, if any other investigation were carried out by any other authority, there can be no assurance that our employees will not be exposed to sanctions and lawsuits, any of which could adversely impact our reputation. See section 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 the performance of our suppliers, our business partners or their third-party service providers.

Global supply chains have been strongly impacted by different economic factors, logistics disruptions, and the continued conflict between Russia and Ukraine, which has resulted in severe commercial disruption in the flow of goods and services in Europe. All of these factors, coupled with the tightening of monetary policy to slow down inflationary trends, continue to impact the global gas and energy markets. In addition, on the domestic side, the double-digit CPI and PPI, plus the tax reform are generating high volatility, shortages of some materials and/or goods relevant to our operations and have affected the performance of inbound logistics. A set of 26 most relevant supply indexes has been identified and monitored, showing significant growth (greater than 10%) and high volatility in 14 of them, and in certain raw materials such as steel, cement, and fuel, among others. This situation has affected suppliers and agreed commercial conditions and is also expected to contribute to secondary inflation effects in the medium term.

Likewise, the global logistics situation has generated record increases in international freight transport rates, limited capacity in ports, and delays in the delivery times. The combination of inflationary impact and the logistical situation generates complex environment that may affect our results and the performance of our suppliers, subcontractors, and third-party service providers. Some of our suppliers may face financial or operational problems that could led 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, sub-contractors 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 poor performance of our suppliers, in any criteria such as operational efficiency, deadlines, administrative aspects, HSE, or our business partners or third-party providers, 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 appropriate 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.

Our insurance policies do not cover all liabilities, and insurance 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.

Additionally, due to worldwide market conditions and limitations associated to interpretations and decisions made by the Colombian Surveillance and the Office of the Comptroller General with regards to director and officer insurance, in recent years the terms and conditions of our director and officer insurance policy have been affected as such coverage has become more costly, which could affect future decisions expected to be made by such directors and officers and lead to an adverse effect on our financial condition and results of operations.

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New trends in the insurance sector in the face of climate change may bring additional costs or create new conditions to be addressed by our corporate insurance program.

We have identified three main insurance trends arising from the transition to a lower carbon economy and climate change that could have a negative impact on the Company: (i) insurance and reinsurance companies are considering retiring from the oil and gas industry or are imposing new demands 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. While we plan to address these trends by quantifying their financial impact and in assessing the need for new risk transfer and risk retention strategies, including strengthening our communication in relation to the TESG strategy and investments with clear goals to show our commitment and support our corporate insurance program, we cannot make any assurances 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 2022, our internal cyber security systems identified and contained cyber security attacks such as malware, phishing, and denial of service. We did not have any critical incidents during the year and although we have not experienced any material losses relating to failure of our information technology systems or cyber incidents, there can be no assurance that we will not suffer such losses in the future.

For the electric power transmission and toll roads concessions businesses, 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.

We are exposed to behaviors incompatible with our ethics and compliance standards.

Given 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 Code of Ethics and Conduct that contains guidelines related to compliance with regulations of anti-money laundering, U.S. Foreign Corrupt Practices Act (“FCPA”), fraud, corruption and bribery. Such acts may impact our reputation and eventually could affect the commercial relations of the Company.

The reliability and capacity of national power supply systems may affect or limit the continuity of our operations or limit growth.

Our average energy consumption in 2022 was 7,237 GWh/year, of which 60% was supplied through self-generation, and the remaining 40% through power grid. Our demand is 9% of the total energy demand in the SIN. 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.

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Rising water production levels may affect or constrain our crude oil production.

During 2022, the Ecopetrol Group produced approximately 12 million barrels of water per day. Taking into account the nature of our reservoirs, the water production levels to be managed by the Company may increase in the future. In order 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 policies in Colombia, Peru, Brazil and Chile could materially adversely affect our business, 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.

With respect to Colombia, for the year ended December 31, 2022, revenues derived from Colombia represented 81% 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 state, but they can be exploited by a third party and pay grants to the Government for that exploitation. 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 may negatively affect us. We cannot predict which policies will be adopted by the Government and whether those policies would have a negative impact on the Colombian economy or our business and financial performance.

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The Colombian parliamentary elections were held on March 13, 2022, the results of which suggested a fragmented Congress despite left-wing parties increasing their overall representation. On August 7, 2022, Gustavo Petro was sworn in as the new President of Colombia. During his presidential campaign, Mr. Petro indicated support for certain changes to Colombian oil exploitation policies to make Colombia less dependent on the oil industry and to accelerate the transition to cleaner energy sources, as well as support for pension and tax reforms. In the first months of Mr. Petro’s Government, the current Minister of Mines and Energy, Irene Vélez Torres, discussed the possibility of suspending new agreements for oil exploration, while respecting the agreements currently in place. Notwithstanding, on November 3, 2022, she announced that the Colombian Government does not intend to end oil exploration and extraction in Colombia, and that instead, the Colombian Government intends to promote an energy transition to support the reliability and stability of the energy system. Furthermore, in the context of such energy transition, the Colombian Government presented 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 is designed to be built through technical analysis and together with existing regulations such as Law 2099 of 2021 and CONPES 4075 of 2022. On January 20, 2023, at the World Economic Forum in Davos, Switzerland, the Minister of Mines and Energy, Irene Vélez, reiterated the Government’s commitment to the country’s transition from an economy dependent on fossil resources to a productive economy. The Minister discussed the country’s plan to increase gas and oil reserves to support the transition and guarantee energy self-sufficiency, and continued support for current projects. The Minister also reiterated that the National Hydrocarbons Agency (ANH), reviewed existing exploration and exploitation contracts in Colombia, which it expects would guarantee the national supply of oil and gas through at least through the year 2037. On March 15, 2023, the Colombian Government published a statement indicating that, as part of the strategy for a “sustainable and just energy transition” (“transición energética justa y sostenible”), it will continue to explore and exploit liquid fuels and gas. Moreover, the Colombian Government has presented a bill to definitively prohibit fracking in Colombia. At this time, 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 to any such policies. 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). Furthermore, although throughout recent history elected governments (and the Colombian Congress as well) have pursued free market economic policies with almost no economic interventions, we cannot predict which policies, if any, will be adopted by the new Government and/or congress and whether those policies would have a negative impact on the Colombian economy or our business and financial performance.

On August 2022, the MHCP submitted a tax reform bill to Congress proposing changes to the Colombian tax regime. The tax reform bill was sanctioned by President Petro as Law 2277 of 2022 on December 13, 2022, and became effective starting January 1, 2023. The law is expected to increase tax collection to approximately COP 20 trillion by the end of 2023 (approximately 3% of the country GDP). 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), (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% will apply when the Brent price reaches USD 65.43, USD 73.17 and USD 79.92, respectively, according to ANH Resolution No. 0181 (revenues from the sale of natural gas are not subject to this surtax); (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. Additionally, the Colombian Government has recently presented a bill for a pension reform (which restructures the pension system into a “pillar system” which manages and assigns funds in accordance with age, the condition of the affiliates, among others, as well as changes to pension schemes applicable to women), a bill for a labor reform (for more information related to the labor reform see Risk Review – Risk Factors – Risks Related to Our Business) and the bill for the National Development Plan. As of the date of this annual report, it is unclear how these bills could affect the Colombian economy or our business.

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With respect to Brazil, for the year ended December 31, 2022, revenues derived from our consolidated subsidiaries in this country represented 3% of our total revenues. Brazilian markets have experienced heightened volatility due the uncertainties from ongoing investigations on money laundering and corruption conducted by the Brazilian Federal Police and the Office of the Brazilian Federal Prosecutor, including the Lava Jato investigation. These investigations adversely affected the Brazilian economy and political scenario. We have no control over and cannot predict whether the ongoing investigations or allegations will result in further political and economic instability, or if new allegations against government officials and/or companies will arise in the future. During the first round of the Brazilian presidential elections held on October 2, 2022, former President Luiz Inácio Lula da Silva received 48.40% of the votes and Mr. Bolsonaro obtained 43.23% of the votes. A run-off election was held on October 30, 2022 and Mr. Lula da Silva was elected with 50.90% of the total votes, and took office on January 1, 2023. Changes in economic or other policies by Mr. Lula da Silva’s administration could negatively affect our industry in general, or our Brazilian subsidiaries’ results of operations, in particular.

With respect to Peru, for the year ended December 31, 2021, revenues derived from our consolidated subsidiaries in this country represented 2% of our total revenues. Peru’s most recent general presidential elections took place in April 2021. Following a run-off between the two top contenders on June 6, 2021, Pedro Castillo was elected as Peru’s president. On December 7, 2022, Mr. Castillo announced his intention to dissolve the Peruvian Congress and to intervene, among others, the Peruvian judicial branch and Superior Court. Mr. Castillo’s actions were deemed to constitute an attempted coup, which led to his destitution and arrest. Mr. Castillo was succeeded by his then vice-president, Dina Boluarte. Following Mr. Castillo’s destitution, a wave of protests in support of Mr. Castillo erupted across the country, which led President Boluarte to declare a state of emergency across several regions in Peru on December 12, 2022 and call for congressional approval of a bill to permit early elections in 2024. As of the date of this annual report, the bill for early congressional elections was initially approved by the Peruvian Congress but is pending a second round of approval as it would require a possible amendment to the Peruvian Constitution. These events have further increased the environment of political uncertainty in Peru, and gave way to further discussions about a possible reform of the Peruvian Constitution, which is based on free market, contractual liberty, and minimal governmental intervention in the economy. There is uncertainty as to whether President Boluarte will obtain the required qualified majorities in order to modify the Peruvian Constitution. We cannot assure that policies against free market and minimal intervention of the government in the Peruvian economy will not be taken by the 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, 2022, revenues derived from our consolidated subsidiaries in this country represented 2% of our total revenues. In 2019, following social unrest and protests, the Chilean government called for a constitutional assembly to reform the Chilean constitution. In May 2021, the Chilean government established a constitutional assembly to write a new constitution, which was rejected by 61.86% of the votes cast on a referendum that took place on September 4, 2022. Though the Chilean congress has started work on setting parameters for how to start over on a new constitution, the old constitution will remain in effect in the meantime. We cannot predict when or whether a new constitution will be approved, or the impact it may have on the regulatory framework governing our subsidiaries’ operations. Furthermore, in December 2021, Chile elected a new President, Gabriel Boric, who took office on March 11, 2022. Mr. Boric is part of a coalition made up of several political parties from the Chilean left wing and we cannot predict what policies will be adopted by Mr. Boric’s government and whether those policies would have a negative impact on the Chilean economy or our industry sector in Chile or our Chilean subsidiaries’ business and financial performance.

We cannot provide any assurances that political or social developments in Colombia, Peru, Brazil, or Chile over which we have no control, will not have an adverse effect on our respective economic situations and will not 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. This could have a material adverse effect on our business, results of operations, financial condition.

Our business operations and financial condition could be negatively affected by the COVID-19 pandemic or other pandemic diseases and health events.

Pandemic diseases and other health events, such as COVID-19, 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. While different variants of COVID-19 continue to spread, the pace of contagion and related disruptions appear to have stabilized; however, to the extent any such variants become dominant or a new wave of worldwide infections recurs, any 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.

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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.

New more severe variants of COVID-19 could emerge going forward, endangering the economic outlook. COVID-19 outbreak resulted in increased volatility in local and international markets and economic indicators, such as exchange rates, interest rates, credit spreads and commodity prices. Any shocks related to new variants or unexpected movements in these market factors could result in financial losses in our investment portfolio.

Other effects of a new wave of the COVID-19 pandemic or another pandemic may include increased unemployment, high inflation, a reduction in household income, reduction in government revenues, increased government expenditures and a deterioration of our and Colombia’s financial position. A sharp decrease in demand for oil and its derivatives due to the economic slowdown caused by the COVID-19 pandemic or any other pandemic, in turn, may have a negative effect on the prices of oil and gas, which may also have a negative impact in the Colombian economy and our financial position. We are unable to predict the response of international actors in the face of a new wave of the COVID-19 pandemic or another pandemic, including, for example, whether OPEC+ countries would cooperate in oil production, whether the US would sell more oil from its Strategic Petroleum Reserve, whether the US would ease sanctions on Venezuela or Iran, or whether China would decide to reactivate its zero-covid policy, as well as the corresponding spillover effects of these actions on the global economy.

From a macroeconomic point of view, the COVID-19 pandemic had a negative impact on Colombia with GDP decreasing by 7.0% in 2020. In 2021, Colombia’s GDP increased by 10.6%, surpassing 2019 levels. In 2022, Colombia’s GDP increased by 7.5%. The main industries that were affected by the COVID-19 pandemic were construction, transportation, hospitality, real estate, and food services. The aforementioned sectors, excluding construction, had a solid recovery in 2021 and 2022, even exceeding 2019 levels. However, the employment level has not fully recovered as compared to pre-pandemic levels. The unemployment rate was 11.2% in 2022, 13.7% in 2021 and 16.1% in 2020.

The Colombian Government declared a status of health emergency in the country, as a result of the COVID-19 pandemic, and such declaration remained valid from March 2020 to June 30, 2022, the date on which said measure was definitively lifted. As of February 9, 2023, Colombia had 6,358,068 confirmed cases of COVID-19, 6,181,727 recovered cases and 142,576 deaths.

Furthermore, although as of January 26, 2023, 97% of Ecopetrol’s workers had completed their vaccination scheme against COVID-19, and 74% had received boosters in addition to their completed vaccination schemes, our operations remain susceptible to the impact of the COVID-19 vaccination programs, coverage and immunity achieved, the severity and duration of another outbreak, and the actions by national and international government authorities to contain the pandemic and minimize its impact, among other things.

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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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 criminal bands known as Bacrim. From time to time, guerrillas target crude oil and multi-purpose pipelines, including the Oleoducto Transandino, Caño Limón - Coveñas and Oleoducto Bicentenario pipelines, and other related infrastructure disrupting our activities and those of our business partners.

During 2022, the attacks against our pipeline infrastructure decreased by 27% in relation to 2021 (30 attacks in 2022 compared with 41 attacks in 2021). Nonetheless, the attacks especially affected infrastructure located in the Norte de Santander, Santander, Arauca, and Nariño departments, and the Caño Limón – Coveñas and Transandino pipelines. As a result, there was a deferred production of 115 barrels directly related to these attacks in 2022, as compared to 2,154 barrels in 2021. As of March 10, 2023, there were 6 attacks against our pipeline infrastructure.

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 2022 was approximately COP 151,630.5 million (USD 31.5 million using a COP 4,810.2/1.00 US exchange rate as of December 31, 2022). During 2022 we also experienced 4 attacks to our production infrastructure in Santander, specifically on the Serpentina 77B oil-water transfer line, 4” transfer line of dehydrator LC 3a K2+258 and 10” line of injection trunk from PIA5 to PIA3, 6” line of the 703 network that goes out to Serpentine 52 to station 7 and 8” gas line from LCI-01. In respect of the production infrastructure, the direct cost of repairs due to guerrilla attacks in 2022 was approximately COP 30.7 million (USD 6.4 million using a COP 4,810.2/1.00 USD exchange rate as of December 31, 2022).

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. Associated with the above, the theft of crude oil has increased from approximately 3,081 bod in 2021 to 3,344 bod in 2022. This situation is directly related to the increase of illicit activities, such as those relating to illegal crops, mining and smuggling, as well as the presence of guerilla dissidents and other illegal groups in the areas of influence of the main crude transportation systems, such as Caño Limón – Coveñas System (Catatumbo and Norte de Santander) and the Trasandino System (Tumaco and Nariño). Furthermore, the theft of refined products is mainly related to the presence of common crime that illegally markets these products, presenting losses of approximately 10.5 bod and 24.6 bod in the years ended December 31, 2022 and 2021, respectively.

In May and June 2021, Colombia experienced a significant public order situation with prolonged social unrest related to a proposed tax reform that was subsequently withdrawn. During the year, there were situations of public order in different regions of the country caused by the presence and consolidation of illegal armed groups in the form of attacks, thefts, sabotages and damages.

The social protests resulted in blockades of the country’s main roads and isolated incidents against certain of our infrastructure, which in turn momentarily adversely affected the operations of our upstream, midstream, and downstream and sales and marketing segments, leading to decreases in our crude oil and refined products production and transported volumes, the Barrancabermeja refinery’s throughput and demand for fuels. Despite the impact on our operations in the upstream, midstream, and downstream and sales and marketing segments, we adjusted our logistics to minimize the impact on the distribution of fuels to the different regions of Colombia, implemented strategies to maintain operations and maintained a fluid dialogue with the communities where it operates.

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.

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On November 30, 2016, the Colombian Congress approved a peace agreement between the Colombian Government and the FARC. Since then, the Colombian Government has advanced in the process of gradually integrating many of the FARC members into civilian and political life. Despite of these efforts, in August 2019 some former leaders of this guerilla left the process and announced the resumption of hostilities.

On December 31 of 2022, President Gustavo Petro announced a bilateral ceasefire, starting on January 1, 2023 until June 30, 2023, initially with five illegal armed organizations: ELN, Segunda Marquetalia, Estado Mayor Central, Autodefensas Gaitanistas de Colombia (AGC) and the Sierra Nevada illegal group. In March 2023, the second round of the dialogue between the Colombian Government and the ELN ended, and the third round is expected to take place in the upcoming months in Havana, Cuba. As of the date of this annual report, peace dialogues are being held with the different armed groups to achieve human security, through the definitive solution of the armed conflict in Colombia. Furthermore, also in March 2023, President Gustavo Petro announced the start of a peace process with the FARC dissidents, who did not align to the peace agreement signed in 2016.

Therefore, it is expected that some guerilla groups may continue their illegal and terrorist activities, including attacks on our infrastructure, as well as disputes with other illegal armed groups for territorial control, resulting in a deterioration of Colombia’s national security and our assets, which consequently may negatively impact our operating results.

There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries.

There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries. However, it is important to mention that in recent months, since August 2022, diplomatic relations have been reestablished with the Government of Venezuela and the new government of Colombia, and this situation allows to generate greater cooperation actions to resolve situations at the border. Ecopetrol is aware of and at all times complies with any U.S. sanctions administered by the Office of Foreign Assets Control of the U.S. Department of the Treasury (“OFAC”).

Although continuity in political relations is expected, the result of these relations remains uncertain, therefore, it is possible that impacts on border towns and cities related to migration and border operations could again occur and therefore, could negatively affect Colombia´s economy, social issues and overall security situation.

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 to 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. Additionally, the uncertainty of Colombia’s economic recovery due to the COVID-19 pandemic could have an impact on our results.

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 government intervention and policies.

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5.2.3

Legal and Regulatory Risks

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, 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, 2022, Ecopetrol S.A. recorded COP 24.41 trillion in accounts receivable due from FEPC and Cartagena Refinery recorded COP 1.9 trillion 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).

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 with environmental laws.

We are also subject to control and monitoring by the regional autonomous corporations (CAR for its Spanish acronym), 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 Spanish acronym), 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.

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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 upstream 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 electric power 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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In 2021, the Colombian Government enacted the Climate Action Law (Law 2169) 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. As a response to this, we have also committed to achieve zero net carbon emissions by 2050 (scopes 1 and 2), with some projects already implemented or under investigation and by 2030, seeking to reduce our CO2e emissions by 25% as compared to the prior baseline established in 2019. 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, tax credits, carbon offsets among others) or meet other stakeholders’ expectations with respect to such plans, 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 green 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.

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) 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 company’s climate goals, increasing costs and negatively impacting financial and operational results.

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.

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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 August 2022, the MHCP submitted a tax reform bill to Congress proposing changes to the Colombian tax regime. The tax reform bill was sanctioned by President Petro as Law 2277 of 2022 on December 13, 2022, and became effective starting January 1, 2023. The law is expected to increase tax collection to approximately COP 20 trillion by the end of 2023 (approximately 3% of the country GDP). 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), (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% will apply when the Brent price reaches USD 65.43, USD 73.17 and USD 79.92, respectively, according to ANH Resolution No. 0181 (revenues from the sale of natural gas are not subject to this surtax) (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.

For a description of taxes affecting our results of operations and financial condition in 2022, 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.

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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, 2022, Ecopetrol S.A. was a party to 6,595 legal proceedings relating to civil, criminal, administrative, environmental, tax, constitutional, arbitration and labor claims, of which 4,720 were filed against us in the Colombian courts and arbitration tribunals and of which 358 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.

5.2.4

Risks Related to Our ADSs

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 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.

Colombian law is not clear about the need to request proxies from existing shareholders. Thus, holders of our ADSs may not become aware of some matters in time to instruct the Depositary to vote their shares.

The Deposit Agreement provides holders of our ADSs with the right to instruct the Depositary to vote common shares separately. However, holders of our ADRs should be aware that in Colombia, it is uncertain whether a depositary must vote all common shares of a Colombian corporation in an American Depositary Receipt, or ADR, program in the same manner as a single block or may vote them separately. Accordingly, if either the custodian or the Depositary are not able 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.

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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 DCIP-83 issued by the Colombian Central Bank among others), regulates the manner 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.

Colombian residents 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.

We are a mixed economy company organized under the laws of Colombia. In addition, most of the members of our Board of Directors (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.

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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. In particular, 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.

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 with 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, 2022, the Colombian Stock Exchange (Bolsa de Valores de Colombia or “BVC” for its Spanish acronym) had a market capitalization of approximately COP 331,595 billion (USD 77.9 billion using the closing rate for 2022), a 10.46% decrease when compared with the amount at the end of 2021. By comparison, the New York Stock Exchange (the “NYSE”) had a market capitalization of USD 32.9 trillion as of December 31, 2022, and a daily trading volume of approximately USD 167.5 billion in 2022.

As of December 31, 2022, our shares represented the highest market capitalization of the BVC accounting for 15.30% of the total MSCI COLCAP index.

Our subsidiaries listed on the Colombian Stock Exchange (“BVC” for its Spanish acronym) such as ISA, are also exposed to these risks. As of December 31, 2022, ISA’s shares accounting for 11.92% 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.

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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, the SFC and the BVC. 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.

5.2.5

Risks Related to the Controlling Shareholder

Our controlling shareholder’s interests may differ, from time to time, from those of certain minority shareholders, or that 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 expenditures 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 and financial condition. 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 Vice-Presidency of Compliance and its Corporate Integrated Risk Office, in 2022 Ecopetrol S.A. continued 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 is based on the risk management which 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:

(i)

Risk Assessment Methodology: In order to properly prioritize mitigation, treatment and monitoring efforts of risk management at the process level, a standardized methodology was established to assess inherent and residual risk levels. The risk level (Very High, High, Medium, Low or None) is obtained from the combination of the risks (impacts) and the probability of occurrence of those consequences. According with the level of risk, action plans for management and mitigation are defined.

(ii)

Mitigation Plans: Each year, by performing the stages of the risk management cycle, we define and implement mitigation plans in order 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.

(iii)

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 in order to avoid risk materialization.

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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:

(i)

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 the 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 in our 2022 Enterprise Risk Map on our website.

(ii)

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.

(iii)

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), Enterprise Risk Management (COSO 2017) and our ethics and compliance rules, with the aim of establishing an integrated 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), 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 performs preventive monitoring in selected 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. This component has been designed and implemented across the organization, with a two-level focus: Enterprise Risk and Processes Risks.

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 in order 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.

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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, as part of its long-term strategy “Energy that Transforms” and in line with its TESG agenda, expects to invest approximately COP 2.3 trillion in 2023 in projects for comprehensive water management, decarbonization, fuel quality, among others. Additionally, we have set a shadow price on carbon at 20 USD/TCO2 in 2022, 30 USD/TCO2 from 2025, and 40 USD/TCO2 from 2030 onwards, which will be used to assess and evaluate current and future projects and investments. See section Strategy and Market Overview—Our Corporate Strategy—2040 Strategy: Energy that Transforms for detailed information on our strategy and carbon shadow price.

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. These analyses are being updated and refined reflecting changes that we anticipate for the years to come and that are aligned with the IEA’s latest scenarios. We have assumed a peak oil scenario (globally in the late 2020s and in Colombia between the 2030s and 2040s), to reflect ambitious actions and goals in the decarbonization path and to seize the opportunities of the transition. Additionally, in 2022, we evaluated transition risks associated with market risks (crude oil and natural gas demand) and regulatory risks (related to carbon pricing and offsetting) under three IEA’s World Energy Outlook 2022 scenarios: (i) Net Zero Emissions (NZE), (ii) Announced Pledges Scenario (APS), and (iii) Stated Policies Scenario (STEPS), to analyze the resilience of our long-term strategy. On September 2022, we presented our second specialized report on climate change management following the recommendations of the Task Force on Climate-Related Financial Disclosures (TCFD) highlighting progress in strengthening climate-related risk and opportunity management processes through discussions on governance, strategy, risks and metrics and targets. Our climate risk strategy is also being aligned with the recommendations of the TCFD and includes the addition of a new climate-related risk to our 2022 enterprise risks, in respect of inadequate management of climate change and water.

5.3.3

Managing Information Security and Cybersecurity

Ecopetrol S.A. has a dedicated management team focused on information security issues such as risk analysis, treatment of information, safe information management practices and classification of critical business information, control systems compliance and effectiveness of available information security technologies, all of which are articulated with the ERM system at the enterprise level. The Cybersecurity unit is part of the Digital Vice-Presidency, reporting to senior management and to the Company’s Board of Directors.

Ecopetrol S.A. has included cybersecurity risk as one of the key enterprise risks. Based on that, a working group formed in 2014, coordinated by the cybersecurity area with the participation of industrial control systems and information technology specialists, has been understanding the new challenges of cybersecurity risk, developing activities to identify and protect critical digital assets.

During 2019, Ecopetrol S.A., as a NOC (National Oil Company), provided updates to the Cyber Defense Command Unit (an entity under the control of the Colombian Ministry of Defense) regarding the inventory of its critical cybernetic infrastructure that was included in the classified catalogue of national critical cybernetic infrastructure. No such updates were required or provided in any of 2020, 2021 and 2022.

Our cybersecurity team established a plan to continue the incorporation of cybersecurity practices to enhance the awareness about these risks at an operational level and adjust current information security practices considering the cyber-threat context. Likewise, as a result of this process, we are currently continuing the incorporation of elements relative to management of the cyber security threat, including proper configuration of storage devices, overall control of information security, policies and procedures that address trading information security, control mechanisms for remote work, specialized monitoring and cyber threat services, vulnerability management, cyber incident response management and cybersecurity insurance coverage, among others.

Ecopetrol S.A. has a Security Operations Center (SOC) service, in order to enhance the ability to foresee and identify trends in attacks in Ecopetrol S.A.’s information technology infrastructure and to monitor our reputation on the internet. During 2022, we kept the capacities of the SOC up and running, expanding the scope of services to Operational Technology (OT) digital assets, conducting red team exercises and improving our monitoring coverage. While there were cyber-attacks during 2022, every event reported was controlled and there were no material effects on processes, equipment, products, services, relationships with customers or suppliers, competitive conditions or critical information. Ecopetrol S.A. does not have any current proceedings that relate to cyber breaches.

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Furthermore, during 2022, the internal audit department conducted audits on cybersecurity processes following up on our prior enhancement plans. As a result of the aforementioned, an action plan was developed during 2022 with main objectives to strengthen identification of threats, access to management and improve certain technical components of our cybersecurity program. Ecopetrol S.A. has continuously updated its cybersecurity policies and response procedures for cyber incidents, which was tested in several wargame exercises that covered all business segments and their subsidiaries.

During 2021 and 2022, in response to the requirements arising from the COVID-19 pandemic, Ecopetrol S.A. kept its cybersecurity risk profile and its cybersecurity strategy updated, by continuing to ensure connectivity for remote work and the alignment to the cloud migration for critical applications. Likewise, Ecopetrol S.A. continued to strengthen its capabilities to monitor and respond to malicious activities.

Ecopetrol S.A. uses the ONG-C2M2 (Oil & Gas - Cybersecurity Capability Maturity Model) as a framework to manage its cybersecurity maturity and to establish its Cybersecurity Program and its Cybersecurity Management System, implementing practices and capabilities those covers the following domains: Risk Management, Asset Change and Configuration Management, Identity and Access Management, Threat and Vulnerability Management, Situational Awareness, Information Sharing and Communications, Event and Incident Response - Continuity of Operations, Supply Chain and External Dependencies Management, Workforce Management and Cybersecurity Program Management.

Ecopetrol S.A. has also strengthened its cybersecurity capabilities in 2022 by continuing to incorporate “Zero Trust” foundational practices and a set of advanced protection controls for critical information in order to reduce the level of cyber risk in the business units.

Increasing cultural awareness in terms of cyber security was another key initiative that continued during 2022, in which three management pillars stand out: i) training (developing new skills), ii) promotion and adoption of change processes, and iii) communication (promoting the understanding and support for new behaviors).

Finally, in order to continue strengthening our cybersecurity strategy between 2023 and 2025, a quantitative cybersecurity risk model is being applied, which will help define our business cybersecurity and cyberdefense program, and which includes the following priority fronts for the coming years: business operation protection, supply chain protection, critical data flows, privacy management, strengthening cybersecurity culture, operational efficiency and technological evolution.

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 taking into account that part of our financial exposure under 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 upstream, midstream, downstream, and electric power 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 2022, Ecopetrol S.A. executed strategic and 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 of physical barrels. We do not use derivative financial instruments for speculative or profit-generating purposes. In Ecopetrol S.A. a total of 12 million barrels were the subject of strategic hedges oriented to mitigate the impact of low prices in the cash flow; additionally, a total of 3.3 million barrels were the subject of strategic hedges oriented to secure the value promise of Permian. A total of 35.4 million barrels were the subject of tactical hedges oriented at mitigating risks associated with storage marketing strategies, anticipated purchases of raw materials, crude oil imports, supply to refineries, international sales delivered at the destination port and maritime freights.

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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, 2022, our U.S. dollar-denominated total debt amounted to USD 22.3 billion principal, which we recognize in our consolidated financial statements at its amortized cost, which corresponds to the present value of cash flows, discounted at the effective interest rate. Out of this total, a USD 16.3 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, 2022, increased 21.1% on a year-to-year basis, in contrast to the 0.2% increase of the total debt expressed in U.S. dollars.

Taking previous considerations into account, we seek to identify and manage currency risk in a comprehensive manner, using an integrated analysis of natural hedges in order to benefit from the correlation between income or investments in a foreign operation and debt denominated in foreign currency. We adopted hedge accounting 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 5.4 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 – 2023. During the second half of 2021, Ecopetrol S.A. hedged a new portion of the dollar-denominated debt against future revenues in an amount of USD 3.7 billion, and during 2021 Ecopetrol S.A. hedged USD 4.9 billion with its foreign investments and future revenues. Likewise, during 2022 Ecopetrol S.A. hedged a new portion of the dollar-denominated debt against future revenues in an amount of USD 0.6 billion and during 2022 Ecopetrol S.A. hedged USD 0.75 billion with its foreign investments and future revenues.

As of December 31, 2022, the outstanding value of the natural accounting hedges was USD 14.2 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.

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 as a result of the issuances of floating rate debt linked to LIBOR, DTF, CPI, IBR, IPCA, CDI, TJLP, TAB and SOFR (with a participation of 8.33%, 0.34%, 4.21%, 0.58%, 3.60%, 2.30%, 0.44%, 0.38% and 5.71% respectively, of the nominal debt balance as of December 31, 2022). Thus, volatility in interest rates may affect the fair value of and cash flows related to our investments and floating rate debt. In 2022, 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.

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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 have to 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 22.2 to our consolidated financial statements.

Regarding liquidity risk, Ecopetrol S.A. forecasts and monitors its cash position on a daily basis in order 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 reviews cash evolution, availability and forecasts under different 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 in order to mitigate our exposure with 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 in order to mitigate the impacts in our financial statements as a result of the fluctuation of risk factors, such as commodity prices, exchange rate, interest rate 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.

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, but which at all times must be a minimum of investment grade 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. will 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.

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5.4

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 believe will 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, 2022, Ecopetrol S.A. was a party to 6,595 legal proceedings relating to civil, criminal, administrative, environmental, tax, constitutional, arbitration and labor claims, out of which 4,720 were filed against us in the Colombian courts and arbitration tribunals, of which 358 had an accrual provision. We allocate sufficient amounts of 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.

A class action lawsuit has been filed against Ecopetrol S.A. and against employees of the company, and the First Administrative Court 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) has 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, and we are still awaiting a ruling in the first instance.

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, The Company’s Board of Directors in December 2011 approved the participation of Ecopetrol S.A. in the project as part of the support of its contingency plans and the relationship with its 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 billion. According to the agreement Ecopetrol S.A. will be in charge of the construction of the aforementioned infrastructure. As of the date of this annual report, the construction projects continue their progress. Their statuses are 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, functional tests are undergoing and overall process is of 97%.

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.

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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 in order 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 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.

As of the date of this annual report, the claims have decreased to COP 7.2 trillion, as a result of the reconsideration of the amount initially claimed.

As of the date of this annual report, a first instance judgment is pending.

Salgar-Cartago Multi-purpose Pipeline Spill

On December 23, 2011 our Salgar-Cartago pipeline ruptured. Internal and external experts believe this incident occurred as a result of creep movement of soil caused by severe weather conditions, causing the soil surrounding the pipeline to exert strong pressure on the pipeline and rupture it. As of the date of this annual report, there are three lawsuits related to this incident with possible damages of approximately COP 6.95 billion.

Class Action of the AWA Indigenous Community

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. The parties are currently waiting for the evidentiary stage to start.

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 reestablishment 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. As of the date of this annual report, a compliance agreement hearing was still pending.

Consultation Process with Afro-Wilches

On April 21, 2022, the First Section of the Administrative Court of Barrancabermeja – Santander ordered Ecopetrol S.A., the National Authority for Environmental Licenses (ANLA, for its Spanish acronym) and the Ministry of the Interior to carry out a consultation process with the Afro-Colombian Corporation of Puerto Wilches – Afro Wilches in connection with the Comprehensive Research Pilot Projects (PPII for its Spanish acronym) Kalé and Platero projects. The ruling was appealed by Ecopetrol S.A, ANLA and the Ministry of the Interior, among others. On June 2, 2022, the Administrative Court of Santander revoked the ruling of the First Section of the Administrative Court of Barrancabermeja – Santander.

Foncoeco

On March 18, 2019, Ecopetrol S.A. received judicial notice of a lawsuit filed by the Fund of Workers and Former Workers of Ecopetrol for Participation in Utilities (“Foncoeco”) on behalf of workers and former workers alleging that between 1997 and 2017 the company allocated part of its profits for the wellbeing of their workers. The plaintiffs considered that they had the right to receive those profits up to COP 3,157,461,510,000. This lawsuit is similar the one that was ruled in favor of Ecopetrol S.A. in 2011.

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The final arguments and sentencing hearing were held on March 2, 2022, in which a first instance ruling was issued in favor of Ecopetrol, which was confirmed by the Superior Court of Bogotá in June 29, 2022. Foncoeco filed an appeal before the Supreme Court which is in its admission stage.

Environmental Administrative Proceedings

As of December 2022, Ecopetrol S.A. was part of 193 environmental administrative proceedings, of which 174 were initiated before 2021 and 19 during 2022. It is not possible for us to determine whether the pending proceedings could have a material effect on Ecopetrol S.A. During 2022, 21 proceedings were concluded, in 3 of them we were subject to monetary fines through resolution 1816 of 2022, for an aggregate amount of COP 3,114,533,402, resolution 2458 of 2020 for an aggregate amount of COP 35,702,100, and resolution 881 of 2022, for an aggregate amount of COP 1,308,660,854.

Reficar Investigations

Reficar is a wholly owned subsidiary of Ecopetrol. 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 generally 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 use or 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 disciplines individuals for 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 aforementioned state entities:

1.	The Office of the Comptroller General’s investigations and proceedings.

1.1

Because of the modifications 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 budget for services, labor and materials. As required, Reficar executed an action plan addressing the 36 findings. See section on The Attorney General’s Office Investigations below, which describes the Attorney General’s Office pronouncement on December 10, 2021, in relation to the 36 findings.

1.2

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 related to the six companies involved in the Project, including former members of Ecopetrol S.A.’s Board of Directors, former members of Reficar’s Board of Directors, former employees of Ecopetrol S.A., and former employees of Reficar, as well as Chicago Bridge & Iron Company N.V., CBI - Chicago Bridge & Iron company (CB&I) Americas Ltd., Chicago Bridge & Iron Company CB&I UK Limited, CBI Colombiana S.A., Foster Wheeler USA Corporation and Process Consultants Inc.

These investigations were conducted based on the Office of the Comptroller General’s theory 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.

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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 of the Project’s budget and the second one is related to the modifications 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, as well as against (ii) CBI - Chicago Bridge & Iron company (CB&I) Americas Ltd., Chicago Bridge & Iron Company CB&I UK Limited, CBI Colombiana S.A., Foster Wheeler USA Corporation and Process Consultants Inc, and the following insurance companies, Compañía Aseguradora de Fianzas 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 issued a decision 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 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. Charges are related among others, with: (i) having approved additions to the Project’s capital expenditures, 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 The Attorney General’s Office Investigations below, which describes the Attorney General’s Office pronouncement 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.

1.2.2.

In the second proceeding, on February 3, 2022, the Intersectoral Delegate Comptroller’s Office closed the proceedings, with a decision in favor of the individuals that were under investigation.

1.3.

The Office of the Comptroller General also ordered the commencement of an 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 (three former presidents and five former financial vice presidents, one of whom is Ecopetrol S.A.’s current CFO) are under investigation. The Office of the Comptroller General is reviewing the supporting documentation provided related to financial cost destination, among others. Currently there is no allegation related to acts of corruption, bribery or fraud.

While the content and status of this proceeding remain confidential, Reficar and several of its employees have cooperated with and provided the information required by the Office of the Comptroller General in charge of leading the proceedings.

As of the date of this annual report, both Ecopetrol and Reficar have no liability under these proceedings.

1.4.

From 2017 until 2022 the Office of the Comptroller General has performed special and financial audits to Reficar and has issued final reports, in which it concluded that, in its opinion, Reficar’s financial statements from 2016 to 2021 do not reasonably represent the entity’s financial position as of the end of each year. This situation originates in the difference in interpretations, of Reficar and of the Comptroller General, concerning the applicable accounting principles. Historically, Reficar’s external independent auditors have issued unqualified opinions on Reficar’s financial statements during and after the Project. As of the date of this annual report, such auditors have not informed Reficar that there has been any change to their opinions to the financial statements. As of the date of this annual report, to the best of Ecopetrol’s knowledge, the financial statements continue to fairly represent the financial and operational condition of the Company in all material aspects and its internal controls remain 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.

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2.	The Attorney General’s Office investigations:

Reficar was officially informed that the Attorney General’s Office had initiated four investigations related to the Project. As of the date of this annual report, all four investigations have been closed.

2.1.

Regarding the first of these investigations, on September 12, 2017, the Attorney General’s Office indicted certain former members of Reficar’s Board of Directors, as well as certain former officers of Reficar. The charges were related to the failure to fulfill some of their duties as administrators and/or for acting “ultra vires” in the exercise of their functions against: (i) Javier Genaro Gutiérrez (Ecopetrol CEO, 2007-2015); (ii) Felipe Laverde (Reficar General Counsel, 2009-March 2017); (iii) Pedro Rosales (Ecopetrol Downstream Executive Vice President, 2008-2015); (iv) Diana Constanza Calixto (Ecopetrol Head of the Corporate Finance Unit, 2009-2014), (v) Orlando José Cabrales (Reficar CEO, 2009-2012) and (vi) Reyes Reinoso Yánez (Reficar CEO, 2012-2016). The Attorney General’s Office closed the case against the rest of the certain former members of Reficar’s Board of Directors and the rest of the certain former officers of Reficar.

On January 17, 2020, the Attorney General’s Office issued its judgment against Reyes Reinoso Yánez for acting “ultra vires” in the exercise of his functions promoting a special billing procedure without the due diligence required to protect Reficar’s resources. As for the other four individuals initially investigated, they were acquitted of the charges. Mr. Reinoso submitted an appeal against the decision.

On June 29, 2021, the appeal against the first instance ruling was resolved, declaring the disciplinary motion in favor of Reyes Reinoso Yánez and the other individuals that were under investigation. With this ruling, the process was formally closed.

2.2.

In the second investigation, on October 21, 2020, the Attorney General’s Office issued its judgment against a former employee of Reficar, Nicolas Isaksson Palacios, related to the failure to fulfill some of his duties for acting “ultra vires” in the exercise of his functions. The Attorney General’s Office closed the case against the rest of the former members of Reficar’s Board of Directors and the other Reficar employees.

On October 31, 2022, the Attorney General’s Office dismissed the process pursuant to the applicable statute of limitation.

2.3.

On May 4, 2021, the Attorney General’s Office closed the third proceeding related to the increase of the budget of the Project, against former members of the Board of Directors and former employees of Ecopetrol considering, amongst others: (i) that the capital expenditure modifications that were approved during the execution of the Project were necessary and that the public servants who approved them acted in accordance with their duties, (ii) that the costs and schedule presented to Reficar by CB&I were wrong, and (iii) if the capital expenditure modifications had not been approved, the mega-project could not have been completed.

2.4.

On December 10, 2021, the Attorney General’s Office closed the fourth proceeding related to the findings included in the final report of the Project special audit carried out by the Office of the Comptroller General in 2016. The process was formally closed pursuant to the applicable statute of limitation.

As of the date of this annual report, there have been no allegations related to acts of corruption, bribery or fraud.

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 Attorney General’s Office processes.

3.	The Prosecutor’s Office investigations:

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The Prosecutor’s Office has been conducting the following legal proceedings in which Ecopetrol S.A. has been recognized as a victim:

3.1

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 (CBI Executive Project Director); (vi) Phillip Asherman (CBI 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 has already made public the factual basis for such charges, which is based on the theory that: (i) executing a cost reimbursable engineering, procurement and construction contract (EPC) and not a lump sum agreement favored CBI interests, and (ii) executing special invoicing procedures (MOA –Memorandum of Agreement and PIP –Project Invoicing Procedure) with CBI allowed the payments of unreasonable amounts not duly verified by the Joint Venture Foster Wheeler USA Corporation and Process Consultant Inc (FPJVC). The defense attorneys have not yet had an opportunity to present their case against such facts in a court of law.

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.

As of the date of this annual report, the preparatory hearing for the oral trial is still ongoing. No member of Ecopetrol’s current management team, nor the current Boards of Directors of Ecopetrol or Reficar are subject to this process.

3.2

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 EPC contract. The defense attorneys have not yet had an opportunity to present their case against such facts in a court of law.

As of the date of this annual report, the preparatory hearing for the oral trial is still 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.

3.3

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 has already made public the factual basis of the charges, which is based on the theory that hiring FPJVC as the PMC of the Project through a sole source process violated the objective selection principle.

On October 13, 2021, the preparatory hearing concluded and oral arguments took place from February 7 to April 5, 2022.

On May 9, 2022, proceedings concluded, and 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 submitted an appeal. The appeal is pending a decision from the District Criminal Court of Bogotá.

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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.

3.4

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 December 2023, due to the application of a plea agreement (principio de oportunidad).

4.	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 is the claimant in the ICC arbitration and seeks 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 USD116 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.

In January 2020, McDermott International Inc., 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 has implemented actions to protect its interests and is being advised by a group of experts with whom it will continue 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 provides 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 will not be subject to estimation in the Bankruptcy Court, and the stay will not be violated if the parties discuss logistical items with the International Chamber of Commerce tribunal or each other. The order reserves 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 International Inc. 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.

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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 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.

Until the Tribunal renders its final decision (which is still pending as of the date of this annual report), the outcome of this arbitration is unknown.

Bioenergy Special Audit

The Office of the Comptroller General, in exercise of its fiscal monitoring duties and authority as set forth in Article 267 of the Political Constitution, has undertaken audits of the performance of the Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S. investments.

On February 6, 2017, the Office of the Comptroller General initiated a Special Intervention (Special Audit) in order to evaluate the use of public funds in the project carried out by Bioenergy Zona Franca S.A.S. and Bioenergy S.A.S. On July 10, 2017 the Office of the Comptroller General issued its final report with 15 findings related to: (i) acquisition, lease payments and the use of agricultural lands, (ii) loss of profits due to the project’s delay; and (iii) execution of contracts related with the building, commissioning and start-up of the industrial plant and the agricultural component of the project. On December 28, 2018, Bioenergy completed all of the activities set forth in the remediation plan to address the 15 findings.

As a result of some of the findings, the Office of the Comptroller General opened several actions of fiscal liability (proceso de responsabilidad fiscal) against former members of Bioenergy’s administration and third-party companies.

In 2018, the Office of the Comptroller General initiated a financial audit of Bioenergy’s financial statements for the year ended December 31, 2018. On May 21, 2019, the Comptroller General delivered its financial audit final report, issuing: (i) an unqualified opinion on Bioenergy’s financial statements, (ii) an efficient and effective internal control process opinion, and (iii) a reasonable opinion, since the budget was prepared and executed, in all relevant matters, according to Bioenergy’s budgeting internal regulation. Finally, the Office of the Comptroller General determined three findings related to: (i) plots of land pending to legalize, (ii) ethanol imports and (iii) the leasing agreement of the Casa Roja plot of Land. On December 31, 2020, Bioenergy completed all of the activities set forth in the remediation plan to address the three findings.

In 2019, the Office of the Comptroller General initiated and ended a compliance audit of Bioenergy S.A.S for the period starting July 1, 2017 to May 31, 2019. The Comptroller General notified Bioenergy on February 4, 2020 its compliance audit final report determining seven findings related to: (i) agricultural lands productivity, (ii) income and expenses from rental payments of subleased agricultural lands, (iii) balanced scorecard results for 2017-2018, (iv) update of laboratory procedures, (v) transport contract number 0029-17 settlement, (vi) document handling and (vii) Campo Victoria plot of Land. Bioenergy filed the remediation plan on February 25, 2020.

Until June 24, 2020, when the Superintendence of Companies of Colombia gave the order to start the Bioenergy’s liquidation proceeding, Bioenergy S.A.S. completed activities as scheduled in the remediation plan according to the June 30, 2020 deadline. Any pending activities related to the aforementioned remediation plan, are in charge of the liquidator appointed by the Superintendence of Companies of Colombia in Bioenergy’s liquidation proceeding.

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During 2021, such judicial liquidation proceeding continued under surveillance and instruction of the Superintendence of Companies of Colombia, in compliance of the applicable law. On December 15, 2021, the adjudication hearing for both companies (Bioenergy SAS and Bioenergy Zona Franca SAS) was started by Superintendence of Companies of Colombia, continued on March 4, 2022, and was completed on March 9, 2022 with the approval of (i) the Adjudication Agreement of Bioenergy SAS; and (ii) the Reorganization Agreement of Bioenergy Zona Franca SAS respectively.

On December 16, 2021, a reorganization agreement of Bioenergy Zona Franca SAS was filed in the Superintendence of Companies of Colombia, with favorable vote of 75% of the creditors, to be authorized by such Superintendence. On January 24, 2022, Superintendence of Companies of Colombia authorized the continuity of the activities and corporate purpose of Bioenergy Zona Franca SAS until April 2022.

After the fulfillment of the agreement for the administrative liquidation of Bioenergy and the agreement regarding Bioenergy Zona Franca, neither Ecopetrol S.A. nor any of its affiliates will be considered shareholders of the aforementioned companies. Therefore, legal contingencies associated to those companies are now limited.

Interconexión Eléctrica S.A.

On July 21, 2021, Ecopetrol S.A. was served as defendant within a public action (acción popular). The acción popular was filed before the First Section of the Administrative Court of Cundinamarca (the “Cundinamarca Court”) by Fundación Defensa de la Información Legal y Oportunidad – Dilo Colombia (“Fundación Dilo”) This action invokes three collective rights (public funds, antitrust and public ethical behavior) and demands their protection. According to the law, the courts may order a wide range of remedies to protect such rights, provided it determines they were violated. The complaint sought, among other things, to prevent the MHCP from selling its ownership stake in ISA to Ecopetrol S.A. unless a competitive bid was undertaken. Accordingly, Fundación Dilo as plaintiff requested preliminary injunctive relief to suspend all actions aimed to close the Acquisition. On July 28, 2021, Ecopetrol S.A. filed a statement in opposition to the request for preliminary injunctive relief and, on August 6, 2021, formally filed its response to the acción popular. In its responses, Ecopetrol S.A. opposed the injunctive relief and the acción popular on the grounds that the claim has no legal basis. In its statement, Ecopetrol S.A. presented the technical, financial, and legal arguments that show that Fundación Dilo did not comply with the legal requirements for said preliminary injunctive relief measure to be granted. In addition, Ecopetrol S.A. argued that the potential sale of the Nation’s ownership in ISA does not contravene the Colombian legal regime. Furthermore, the consummation of the Acquisition is expected to generate benefits to both the Nation and Ecopetrol S.A., and does not threaten or contravene any of the collective rights invoked by the claimant. The MHCP also filed a similar response. On September 13, 2021, the Cundinamarca Court rejected the plaintiff’s request for interim relief and scheduled a settlement hearing, which took place on September 28, 2021. The parties did not reach an agreement at the settlement hearing. On February 3, 2022, the Cundinamarca Court issued a first instance ruling, rejecting all claims. The plaintiff did not file an appeal within the required period of time and on March 23, 2022, Ecopetrol requested the Cundinamarca Court to issue a final judicial decision giving effect to its decision from February 3, 2022. On May 9, 2022, the Cundinamarca Court issued the final judicial decision, which effectively concluded and closed the public action by Fundación Dilo.

Similarly, on January 28, 2022, the Administrative Court of Antioquia (“Antioquia Court”) admitted a new public action (acción popular) filed by Jaime Aristizábal Tobón, acting as president of the National Union of Electric Interconnection Workers S.A. (SINTRAISA, for its Spanish acronym), Samuel Guillermo Roldán Escobar as president and legal representative of the Energy Industry Workers Union (SINTRAE, for its Spanish acronym), and Gonzalo Álvarez Henao, as representative of the Civic Movement of Medellín and the Metropolitan Area, against Ecopetrol S.A. and the MHCP. The plaintiffs consider that, with the transfer of ISA’s shares to Ecopetrol, the defendants violated the collective rights to administrative morality and public property. On February 17, 2022, the Antioquia Court declared all actions under this process void and rejected the lawsuit determining that the decision in the popular action process brought on by Fundacion Dilo had a res judicata effect. As the plaintiff did not file an appeal within the required period of time, on March 23, 2022, Ecopetrol requested the Antioquia Court to issue a deed of execution regarding its February 17, 2022 decision and declaring that such decision is enforceable from April 29 of 2022.

If there is an order to unwind the Acquisition while Ecopetrol S.A. is the owner of the ISA shares acquired from the MHCP, a court may order Ecopetrol S.A. to return the ISA shares to the MHCP and the MHCP would have to reimburse Ecopetrol S.A. the purchase price paid for such shares. Such reimbursement may be subject to delays and the MHCP may not have the ability to reimburse such purchase price.

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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 Business Group had significant influence but 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 General Comptroller (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 General Comptroller’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 Comptroller General’s Office investigation names two current members of senior management—the Chief Operating Officer of Ecopetrol, and the Chief Executive Officer of Cenit S.A., 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. To the best of Ecopetrol knowledge, there are no allegations related to acts of corruption, bribery or fraud.

Partial nullity lawsuit of Decree 1142 of 2021

On September 23, 2021, the Ministry of the Interior issued Decree 1142, which modified Decree 1821 of 2020, Sole Regulatory Decree of the General Royalties System. 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. On September 2, 2022, Ecopetrol filed a claim requesting the annulment of Article 3.1.1.2.1 of this Decree, considering it illegal.

6.	Shareholder Information

6.1

Shareholders’ General Assembly

Our Shareholders’ General Assembly will be held on March 30, 2023 and the following matters will be discussed, among others:

●

The plan for distribution of the Company’s profits, which establishes the distribution of an ordinary dividend per share of COP 487.00 and an extraordinary dividend per share of COP 106.00, for a total dividend of COP 593.00 per share, is as follows: payment of dividends to minority shareholders to be made in three equal installments on April 27, 2023, September 28, 2023 and December 21, 2023; and the payment to the majority shareholder, to be made during the course of the 2023, by offsetting the dividends to be paid against the accounts receivable from the FEPC.

●

The establishment of an occasional reserve of COP 7,665,757,580,9029 in order to support Ecopetrol S.A.’s financial sustainability and flexibility in the execution of its strategy.

●

Election of the external auditor for the remainder of the 2021-2025 period and definition of his compensation.

●

Election of members of the board of directors for the remained of the 2021-2025 period.

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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. 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 30, 2022, our shareholders at the ordinary General Shareholders’ Assembly approved an ordinary dividend of 59.8% of our net income for the fiscal year ended December 31, 2021 amounting to COP 9,991,356 million, or COP 243 per share, and an extraordinary dividend of 9.1% of our net income for the abovementioned fiscal year, amounting to COP 1,521,317 million, or COP 37 per share; both based on the number of outstanding shares as of December 31, 2021. The payment will be made on April 21, 2022 to our minority shareholders and no later than September 30, 2022 to the majority shareholder.

On June 17, 2022, our shareholders at an extraordinary General Shareholders’ Assembly, approved: (i) to extend the deadline for the payment of dividends to the Nation, originally approved in the General Shareholders’ Assembly of March 30, 2022, from September 30 to October 31, 2022, and (ii) to distribute the Company's occasional reserve that had been approved in the General Shareholder’s Assembly held on March 30, as an extraordinary dividend of COP 168. The payment of the dividend for minority shareholders was made in a single payment on June 30, 2022, and for the majority shareholder, the total dividend payment was offset against the accounts receivable from the FEPC.

On March 26, 2021, our shareholders at the ordinary General Shareholders’ Assembly approved an ordinary dividend of 41.41% of our net income for the fiscal year ended December 31, 2020 amounting to COP 698,984 million, or COP 17 per share, based on the number of outstanding shares as of December 31, 2020. The payment date was made on April 22, 2021 to 100% of our shareholders.

On March 27, 2020, our shareholders at the ordinary General Shareholders’ Assembly approved an ordinary dividend of 56% of our net income for the fiscal year ended December 31, 2019. At the Extraordinary General Shareholders’ Meeting held on December 16, 2019, the Company’s Shareholders approved the following: i) the change in the destination of the Company’s occasional reserve that had been constituted in the General Shareholders’ Meeting held on March 29, 2019 and ii) its subsequent distribution as an extraordinary dividend of 89 Colombian pesos (COP 89) per share.

Ecopetrol S.A. S.A. is required to have legal reserves equal to 50% of its subscribed capital. If the legal reserves are less than 50% of subscribed capital, we will contribute 10% of net income to our legal reserves every year until our legal reserves meet the required level.

See section Financial Review—Liquidity and Capital Resources—Dividends.

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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 the relevant stockbrokers 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, in order 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 324.39 as of December 31, 2022) 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:

●

Transfers between shareholders who are considered to be the same beneficial owner;

●

Transfer of shares owned by financial institutions, under supervision of the SFC, that are in a liquidation process;

●

Repurchases of shares by the issuer;

●

Property delivered in lieu of payment, or payment of money or other valuable property, different than the amount owed or demanded, in exchange for the payment of the debt;

●

Transfer of shares made by the Nation or the Financial Institutions Warranty Fund (Fondo de Garantías de Instituciones Financieras) or FOGAFIN;

●

Transfer of shares issued abroad by Colombian companies, provided they take place outside Colombia;

●

Transfer of shares issued by foreign companies, offered through a public offering in Colombia, provided that they take place outside Colombia;

●

Transfers made by the Central Counterparty Risk Chamber, in accordance with the provisions of paragraph 2 of Article 2.13.1.1.1. of this Decree; and

●

Any other transaction specifically authorized by the SFC to take place outside the BVC.

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.

6.4

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:

5.875% Notes due 2023

4.125% Notes due 2025

5.375% Notes due 2026

6.875% Notes due 2030

4.625% Notes due 2031

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8.875% Notes due 2033

7.375% Notes due 2043

5.875% Notes due 2045

5.875% Bonds due 2051

Please refer to Exhibits 4.10, 4.11, 4.12, 4.13, 4.14, 4.15, 4.16, 4.17, 4.18, 4.19 and 4.20 to this Annual Report for the information relating to these debt securities required by Item 12.A of Form 20-F.

6.5

Description of Ecopetrol ADRs

Fees and Charges That a Holder of Our ADSs May Have to Pay, Either Directly or Indirectly

JPMorgan Chase Bank, N.A., our Depositary, 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:

●

A fee of USD 0.05 or less per ADS for any cash distribution made pursuant to the Deposit Agreement;

●

A fee for the distribution of securities (or the sale of securities in connection with a distribution), such fee being in an amount equal to the fee for the execution and delivery of ADSs which would have been charged as a result of the deposit of such securities (treating all such securities as if they were common shares) but which securities or the net cash proceeds from the sale thereof are instead distributed by the Depositary to those holders of ADRs entitled thereto;

●

An aggregate fee of up to USD 0.05 per ADS per calendar year (or portion thereof) for services performed by the Depositary in administering the ADRs (which fee may be charged on a periodic basis during each calendar year and shall be assessed against holders of ADRs as of the record date or record dates set by the Depositary during each calendar year and shall be payable in the manner described in the next succeeding provision);

●

A fee for the reimbursement of such fees, charges and expenses as are incurred by the Depositary and/or any of the Depositary’s agents (including, without limitation, the custodian and expenses incurred on behalf of holders of ADRs in connection with compliance with foreign exchange control regulations or any law or regulation relating to foreign investment) in connection with the servicing of our common shares or other Deposited Securities, the sale of securities (including, without limitation, Deposited Securities) and the delivery of Deposited Securities or otherwise in connection with the Depositary’s or its custodian’s compliance with applicable law, rule or regulation (which fees and charges shall be assessed on a proportionate basis against registered holders of ADRs as of the record date or dates set by the Depositary and shall be payable at the sole discretion of the Depositary by billing such holders of ADRs or by deducting such charge from one or more cash dividends or other cash distributions);

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●

Stock transfer or other taxes and other governmental charges;

●

SWIFT, cable, telex and facsimile transmission and delivery charges incurred at the request of a holder of ADRs;

●

Transfer or registration fees for the registration of transfer of Deposited Securities on any applicable register in connection with the deposit or withdrawal of Deposited Securities; and

●

In connection with the conversion of foreign currency into U.S. dollars, the Depositary shall deduct out of such foreign currency the fees, expenses and other charges charged by it or the Depositary’s agent (which may be a division, branch or affiliate) so appointed in connection with such conversion. The Depositary and/or the Depositary’s agent may act as principal for such conversion of foreign currency. Such charges may at any time and from time to time be changed by agreement between us and the Depositary.

●

We will pay all other charges and expenses of the Depositary and any agent of the Depositary (except the custodian) pursuant to agreements from time to time between us and the Depositary. The fees described above may be amended from time to time.

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 2020, reimbursements were made in the amount of approximately USD 2,020,472. In 2021, reimbursements were made in the amount of approximately USD 1,411,363. In 2022, reimbursements were made in the amount of approximately USD 1,200,000.

Other

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. Until 2018, foreign residents deriving income through a permanent establishment were subject to Colombian income tax on the Colombian source income attributable to their permanent establishment only. As of 2019, foreign tax residents deriving income through a permanent establishment will be subject to Colombian income tax on their global source income attributable to their permanent establishment 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.

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As mentioned above, Law 1819 of 2016 created a new dividends tax that applies on all dividend distributions to Colombian individuals or to any type of non-resident shareholder, absent any specific treaty or exception, regardless that dividends are paid from taxed or untaxed profits. According to the aforementioned law, dividend payments made to foreign shareholders out of profits accrued at the corporate level as of 2017 were subject to a 5% withholding. That rate was subsequently modified by Law 1943 of 2018, which increased it to 7.5% and extended dividend taxation to intercompany dividends between Colombian resident companies (with certain exceptions).

From fiscal year 2022 onwards, a withholding tax on dividends paid applies as follows:

(i)

Dividends paid to non-resident shareholders: (i) a 10% 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 an additional 10% dividend tax after applying the initial 35% withholding tax rate (i.e., 41.5% in 2022).

(ii)

For Colombian individuals: dividend income in excess of 300 UVT are taxed at a 10% rate, in respect of profits taxed at the corporate level; and 31% withholding tax rate on dividends distributed from profits not taxed at the corporate level, plus an additional 10% dividend tax after applying the initial 35% withholding tax rate.

From fiscal year 2023 onwards, dividend taxation will be as follows:

(i)

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.

(ii)

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.

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 to be a Colombian resident when he/she meets any of the following criteria:

(i)

He/she remains in Colombia continuously or discontinuously for more than 183 calendar days within any given 365-consecutive-day term;

(ii)

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

(iii)

He/she is a Colombian national and:

Has a spouse or permanent companion, or dependent children, who are tax residents in Colombia, or

50% or more of his or her total income is Colombian source income, or

50% or more of his or her assets are managed in Colombia, or

50% or more of his or her assets are deemed to be located or possessed in Colombia, or

Has failed to provide proof of residency in another country (different from Colombia) upon previous official request by the Colombian tax office, or

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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 meet any of the following requirements will not be deemed as tax residents:

(i)

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.

(ii)

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:

(i)

It has its place of effective management, in Colombia during the corresponding year or taxable period;

(ii)

It has its main domicile in the Colombian territory; or

(iii)

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. As noted above, until 2018 permanent establishments were considered Colombian taxpayers in connection with their Colombian source income. As of fiscal year 2019, foreign residents deriving income through a Colombian permanent establishment are subject to Colombian income tax on the worldwide income attributable to the Colombian permanent establishment. 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. 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

Dividends

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. For fiscal years 2017 and 2018, a withholding tax on dividends was triggered for dividends paid to non-resident shareholders. Withholding tax rates on dividends were as follows: (i) a 5% dividend tax for dividends distributed out of profits already taxed at the company’s level; (ii) 35% withholding tax rate for dividends distributed out of profits that were not taxed at the company’s level, plus a 10% dividend tax rate after having applied and deducted the initial 35% withholding. Note that dividends paid to non-resident shareholders out of profits taxed at the corporate level until December 31, 2016, are not subject to the aforementioned 10% dividend tax or any other income tax. As of 2021, the withholding tax rates applicable to dividends paid to resident companies and non-resident shareholders (companies and individuals) are: i) a 7,5% or 10% tax on dividends, as applicable, 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); and (ii) 35% withholding tax rate on dividends distributed from profits not taxed at the corporate level, plus an additional 7.5% or 10%, as applicable, dividend tax after applying the initial 35% withholding tax rate.

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 10% dividend tax applies on the balance of dividends to be distributed to

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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.

Dividends

As a general 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 and, as of 2022, is as follows:

(i)

Dividends paid to non-resident shareholders: (i) a 10% dividend tax on dividends distributed from profits taxed at the corporate level (except that dividends paid to nonresident 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 an additional 10% dividend tax after applying the initial 35% withholding tax rate (i.e., 41.5% in 2022).

(ii)

Dividends paid to Colombian companies: (i) a 7.5% dividend tax on dividends distributed from taxed profits, or (ii) a 35% withholding tax on dividends distributed from untaxed profits, plus an additional 7.5% dividend tax on the balance of the dividend amount after the initial 35% withholding.

(iii)

For Colombian resident individuals: dividend income in excess of 300 UVT is taxed at a rate of 10%, for fiscal years 2021 onwards 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 10% dividend tax after applying the initial 35% withholding tax rate.

From fiscal year 2023 onwards, dividend taxation will be as follows:

(i)

(ii)

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

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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.

Variation, Inflation and the Price of Oil on our Results—Taxes—Taxes.

In addition to the above, the new dividend tax will apply at a 5% rate over dividends distributed from profits taxed at the corporate level. This treatment was modified by Law 1943 of 2018 and Law 2010 of 2019 (7.5% in 2019 and 10% from 2020 onwards). See section Financial Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results—Taxes.

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% 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% 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:

(i)

The gain or loss arising therefrom will be the difference between the sale price and the tax basis of the shares. As a general rule, the tax basis of shares is equal to the price paid for such shares (i.e., cost of acquisition).

(ii)

The applicable tax rate and the withholding tax rate have to be determined on a 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 10%; otherwise, profits will qualify as ordinary income, subject to a 33% income tax for fiscal year 2021 (2022 onwards – 35%).

Tax Treatment of Non-Residents Who Purchase Ecopetrol’s Shares in the BVC Market and Exchange Them for ADSs

Dividends

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.

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

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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

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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 2021 taxable 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 2022 taxable year⁴. 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. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to which holders of ADSs or common shares and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to treat dividends as qualified for tax reporting purposes. Because such procedures have not yet been issued, it is not clear whether we will be able to comply with them. 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. U.S. Holders who do not elect to claim a credit for any foreign income taxes paid during the taxable year may instead, at such U.S. Holder’s election, deduct otherwise creditable 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 Internal Revenue Service (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 a corporation or other 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. 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.

6.7

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 purposed 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,

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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).

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.

6.8

Exchange Rates

On March 27, 2023, the Representative Market Exchange Rate was COP 4,741.76 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.

6.9

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 February 28, 2023:

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Table 69 – Major Shareholders


	As of February 28, 2023
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
Total	41,116,694,690	100.00

(1)	Includes 1,600 shares owned by other state entities.

All our common shares have identical voting rights.

As of February 17, 2023, the registration date of our annual general shareholders’ meeting, 2.66 % or 1,094,709,060 of our common shares were held of record in the form of American Depository Shares, we had 42 registered holders, and 23,116 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 5-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 affect 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 procedural system 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. SAA15-10392, of October 1, 2015, issued by the Colombian Superior Council of the Judiciary (Consejo Superior de la Judicatura), as follows:

●

A treaty exists between Colombia and the country where the judgment was granted relating to the recognition and enforcement of foreign judgments or, in the absence of such treaty, there is reciprocity in the recognition of foreign judgments between the courts of the relevant jurisdiction and the courts of Colombia;

●

The foreign judgment does not relate to “in rem rights” vested in assets located in Colombia at the time the lawsuit was filed;

●

The foreign judgment does not contravene or conflict with Colombian laws relating to public order other than those governing judicial procedures;

●

The foreign judgment, in accordance with the laws of the country where it was rendered, is final and is not subject to appeal;

●

A duly legalized copy of the judgment (together with an official translation into Spanish if the judgment is issued in a foreign language) has been presented to the Supreme Court of Colombia;

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●

The foreign judgment does not refer to any matter upon which Colombian courts have exclusive jurisdiction;

●

No proceeding is pending in Colombia with respect to the same cause of action, and no final judgment has been awarded in any proceeding in Colombia on the same subject matter and between the same parties;

●

In the proceeding commenced in the foreign court that issued the judgment, the defendant was served in accordance with the laws of such jurisdiction and in a manner reasonably designated to give the defendant an opportunity to defend against the action; and

●

The legal requirements pertaining to the exequatur proceedings have been observed.

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 when it has been proven that either a U.S. court has enforced a Colombian judgment or that a 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.

7.	Corporate Governance

Since 2004, Ecopetrol S.A. has voluntarily adopted transparency, governance and control practices to facilitate corporate governance in order to generate confidence among stakeholders and ensure the sustainability of its business. The corporate governance practices at Ecopetrol S.A. aim to:

●

Promote all stakeholders transparency, objectivity and competitiveness;

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Add value to the company and attract investors;

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Protect shareholders, investors and stakeholders’ rights;

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Encourage financial markets confidence; and

●

Accomplish the highest corporate governance standards.

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, the organization and management of the Ecopetrol Group’s operations is evolving into three business lines:(i) Hydrocarbons, (ii) Low Emission Solutions and (iii) Transmission and Roads. For each business line, the objective and focus

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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 Low Emissions Solutions business, led by Ecopetrol’s Vice President of Low Emissions Solutions, 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.

Ecopetrol as Corporate Governance Benchmark

Ecopetrol’s commitment to its various stakeholders and the implementation of the best corporate governance standards has been recognized by certain independent third parties.

In October 2022, S&P’s Global Rating released its assessment of Ecopetrol S.A.’s 2021 results for the Dow Jones Sustainability Index (“DJSI”), which analyzes the organization’s short-term exposure to ESG risks and opportunities and its ability to anticipate and adapt to long-term disruptors. Ecopetrol participated in the DJSI evaluation process for the third consecutive year, achieving a score a top score as compared to other companies in the oil and gas sector. In particular, in the governance and economic dimension “G”, Ecopetrol’s score increased as compared to 2021 results, placing it among the best performing companies of similar size in its industry.

In 2022, Ecopetrol received the National Association of Public Utilities and Communications Companies Award (Asociación Nacional de Empresas de Servicios Públicos y Comunicaciones or ANDESCO for its acronym in Spanish) in corporate governance for its project “Strengthening the Corporate Governance Model of the Ecopetrol Group” through which we sought to incorporate best corporate governance practices from 2018 to 2019 in the following areas (i) board of director practices; (ii) decision-making model and attributions, (iii) senior management committee support and (iv) relationship model and interaction of Ecopetrol as parent company with its subsidiaries.

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 a strategy enabler 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.

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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:

(i)

Boards of Directors: Ecopetrol and Subsidiaries

Promote best management practices in 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.

(ii)

Senior Management Committees

Establish the structure of the Senior Management Committees (operating, monitoring and improvement mechanisms).

Optimize Ecopetrol senior management time.

(iii)

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.

(iv)

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.

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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Composition of Board of Directors: including in its list of candidates a Representative for the hydrocarbon producing departments where Ecopetrol operates and a Representative for the minority shareholders, who will be chosen by the 10 shareholders with the largest stock participations. Ecopetrol has adopted the practice of having a majority of independent members (5 out of 9). From 2019 to October 2022 the Board had one (1) non-independent Director. The current Board of Directors is composed of seven (7) independent members and two (2) non-independent members.

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Dividend policy: guaranteeing the right of each shareholder to receive his pro rata dividends in accordance with Colombian law.

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Issues not included in the agenda of extraordinary meetings of the General Shareholders Assembly: permitting a vote on those initiatives submitted by one or more shareholders representing at least 2% of the subscribed shares of the company.

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Asset disposal: ensuring that any asset disposal of an amount equal or higher than 15% of the stock exchange capitalization of Ecopetrol S.A. is discussed and decided by the General Shareholders’ Assembly and that the Nation will only vote affirmatively if the vote of minority shareholders is equal to or exceeds 2% of the shares subscribed by shareholders other than the Nation.

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 and 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, and Deed No. 9184 of May 11, 2022 issued by the Notary Twenty Nine of Bogotá. An English translation of the amended bylaws is included as Exhibit 1.1 to this annual report.

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’ Meeting

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 on the Sunday previous to the meeting, must be published at Ecopetrol S.A.’s website www.ecopetrol.com.co.

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 by shareholders holding at least 5% of the outstanding shares, or when unforeseen or urgent needs of the Company require it. An Extraordinary Shareholders’ Meeting should be called no later than 15 calendar days prior to the date of the meeting. The only exception is when the Law requires a greater time between the summons and the meeting. Such notice to 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.

For both the ordinary and extraordinary meetings, the quorum required is a plural number of shareholders representing 50% plus one of the subscribed shareholders entitled to vote. Decisions are approved with 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;

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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;

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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 2022 annual shareholders’ meeting was held in-person at the Corferias (Centro Internacional de Negocios y Exposiciones) adhering to strict biosafety protocols. Additionally, we implemented a digital voting process for the first time and, to guarantee the rights of the shareholders, we allowed in-person appointments for shareholders to exercise their right to inspect our books and documents. For the 2022 meeting, there were 3,333 on-site participants and 3,670 viewers through social media platforms.

During the meeting 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 243 and an extraordinary dividend per share of COP 37, for a total dividend of COP 280 per share, as follows: a payment of 100% of the dividend to minority shareholders to be made on April 21, 2022 and the payment to the majority shareholder, made on September 30, 2022, following the recommendations from the CONPES.

●

The establishment of an occasional reserve of COP 8.9 trillion in order to support Ecopetrol S.A.’s financial sustainability and flexibility in the execution of its strategy.

●

The legal assistance program for members of the Board of Directors of Ecopetrol S.A.

●

Amendment of our bylaws.

Additionally, Ecopetrol held two extraordinary General Shareholder’s Meetings on June 17 and October 24, 2022. The following matters were approved (i) the amendment of the dividend payment schedule for the majority shareholder and the partial distribution of occasional reserve as an extraordinary dividend of COP 168 per share and (ii) the appointment of the Board of Directors as follows:

●

Non-Independent Directors: Mónica de Greiff Lindo and Gonzalo Hernández Jiménez.

●

Independent Directors: Gabriel Mauricio Cabrera Galvis, Carlos Gustavo Cano Sanz, Saúl Kattan Cohen, Sandra Ospina Arango, Luis Santiago Perdomo Maldonado, Esteban Piedrahíta Uribe and Sergio Restrepo Isaza.

Our 2023 Shareholders’ General Assembly will be held on March 30, 2023 and the following matters will be discussed, among others:

The establishment of an occasional reserve of COP 7,665,757,580,9029 in order to support Ecopetrol S.A.’s financial sustainability and flexibility in the execution of its strategy.

Election of the external auditor for the remainder of the 2021-2025 period and definition of his compensation.

Election of members of the board of directors for the remained of the 2021-2025 period.

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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 or not 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 5-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 with 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.

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 when so requested by a plurality of shareholders holding at least 5% of the total number of outstanding shares. Such requests shall be made in writing and must clearly indicate the purpose of the meeting.

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 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.

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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 hecho relevante. Any transfer of shares equal 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 in order 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

Our Code of Ethics and Conduct considers, as ethical principles of the organization, the integrity, responsibility, respect and commitment to life. Our Code of Ethics and Conduct also states that we must comply with the provisions contained in the applicable national and international laws in the countries where we have operations, including the U.S. and Colombia.

In our Code, we define the guidelines for the following aspects: conflict of interest; ethical conflict; prohibition of bribery, other forms of corruption and violations of the FCPA; integrity in accounting; prevention of money laundering and financing of terrorism; gifts, amenities and hospitalities; protection and use of resources; information management; security and confidentiality; prohibition of insider trading and use of inside information, environmental policy, social responsibility, respect for human rights and rejection of discrimination, antitrust and anticompetitive practices and sexual harassment in the workplace; whistleblowing channel; and examples of ethical behaviors. As part of the Ethics guidelines of Ecopetrol, facilitation payments, political contributions and donations, diversion of money from social investment activities or sponsorships towards political activities or other than the purposes established by the Company and lobbying are prohibited.

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Our Code of Ethics and Conduct applies to our Board of Directors, our Chief Executive Officer, our Chief Financial Officer, principal accounting officer, persons performing similar functions, to all of the other employees of the company and its affiliates and all individuals or legal entities that have any relationship with it, including beneficiaries, shareholders, contractors, suppliers, agents, partners, customers, allies (included joint ventures) and suppliers, in addition to the personnel and companies that the contractors engage for the execution of the agreed activities.

All our agreements with suppliers or third parties include a provision relating to compliance with applicable anti-bribery and anti-corruption regulations. These agreements also require our suppliers and third parties to accept our Code of Ethics and Conduct and our compliance manuals.

Our Code of Ethics and Conduct is available on our website.

7.3

Board of Directors

The current Board of Directors was elected at the Extraordinary Shareholders Meeting held on October 24, 2022. The elected Board of Directors named Saúl Kattan Cohen as Chairman and Mauricio Cabrera Galvis as Vice Chairman.

The current Board of Directors is composed as follows:

Non-independent members:

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Gonzalo Hernandez Jimenez

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Monica de Greiff Lindo

Independent members:

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Gabriel Mauricio Cabrera Galvis

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Saul Kattan Cohen

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Luis Santiago Perdomo Maldonado

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Sergio Restrepo Isaza (as financial accounting expert)

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Esteban Piedrahita Uribe

●

Sandra Ospina Arango (nominated by the hydrocarbon producing departments)

●

Carlos Gustavo Cano Sanz (nominated by the minority shareholders with largest shareholding)

The information below sets forth the names and business experience of each of the Directors elected at the General Shareholders Ordinary Meeting held on October 24, 2022:

Gonzalo Hernandez Jiménez currently holds the position of Technical Vice Minister of Finance and Public Credit and Professor of the Advanced Macroeconomics course at Universidad Javeriana. He is also a member of the Boards of Directors of the Administrator of Resources of the General System of Social Security in Health (ADRES, for its Spanish acronym), Financiera de Desarrollo Nacional S.A. and Grupo Bicentenario S.A.S. 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 is a non-independent member of Ecopetrol’s Board of Directors since October 24, 2022.

Mr. Hernandez Jimenez 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;

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(vi) the energy industry, and (vii) government affairs and public policy. As a member of Ecopetrol’s Board of Directors, he is periodically trained in ethics, compliance and risk management matters.

Monica 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 and One Young World. She holds a bachelor´s degree in law, a graduate degree in Administrative Law, and a PhD in Jurisprudence all from Universidad del Rosario in Bogotá. She served as Ambassador to Kenya, permanent representative to the United Nations for Environment and Habitat, CEO of the Bogotá Chamber of Commerce and of the Grupo Energía Bogotá, as well as District Secretary of Economic Development of Bogotá. She is a former 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 has been a non-independent member of Ecopetrol’s Board of Directors since October 24, 2022.

Ms. de Greiff Lindo has expertise in: (i) the energy industry; (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. As a member of Ecopetrol’s Board of Directors, she is periodically trained in ethics, compliance and risk management matters.

Gabriel Mauricio Cabrera Galvis works on investment banking and financial consulting activities as the Director of the firm Cabrera & Bedoya, Banqueros de Inversión. He is a current member of the Boards of Directors of the Asociación para la Promoción de las Artes (PROARTES), Lloreda S.A., and the Financiera de Desarrollo Nacional S.A. He has also served as President of the Banco de Occidente and Fundación FES, Dean of the Faculty of Economics of the Universidad Externado, General Director of Public Credit at the Ministry of Finance and Public Credit Head of the Global Planning Unit of the National Planning Department and Technical Vice President, Director of the Economics Department and researcher at the Asociación Bancaria de Colombia. He is also a former director of Clínica DIME S.A., Fabricato S.A., Grupo de Energía de Bogotá, Empresa de Teléfonos de Bogotá, Propal, Banco de Bogotá, ISA, Carbocol, Astorga S.A., Giros y Finanzas C.F.C., Incorbank S.A. and Ecopetrol S.A. (from 2017 to 2019). He holds a B.A. degree in Philosophy from the Pontificia Universidad Javeriana and a Master’s degree in Economics from Universidad de los Andes and is a Ph.D. candidate at the London School of Economics. He has authored various books on economic policies and articles on monetary exchange policy and fiscal policy. He has been an independent member of Ecopetrol’s Board of Directors since October 24, 2022, and he is the current Vice-Chairman of the Board and President of its Remuneration, Nomination and Culture Committee.

Mr. Cabrera Galvis has expertise in: (i) the energy industry; (ii) administration, senior management, and leadership; (iii) government affairs and/or public policy; (iv) financial and securities markets; (v) human resources and talent development; (vi) legal and corporate governance; and (vii) business strategy and project management. As a member of Ecopetrol’s Board of Directors, he is periodically trained in ethics, compliance and risk management matters.

Saul Kattan Cohen is the current President of the firm SK Consulting Partners Corp. and the liquidator of the companies of Grupo Transtel. He is currently an alternate member of the Board of Directors of Tikva S.A. He has served as President of Empresa de Telecomunicaciones de Bogotá, NFCGC Investments and Blockbuster Video Colombia and was a Financial and Economic Researcher at Colombia’s central bank (Banco de la República). He has been a member of several Boards of Directors, including Colombia Móvil (TIGO), Empresa de Energía de Bogotá, Contact Center Americas, Colvatel, Skynet, Kokoriko and Pepe Ganga. He holds a bachelor’s degree in Economics from the Universidad de los Andes in Bogotá, attended the Executive Management Program at the Instituto de Alta Dirección Empresarial (INALDE) in Bogotá and the Advanced Management Program at the Wharton Business School at the University of Pennsylvania. He has been an independent member of Ecopetrol’s Board of Directors since October 24, 2022, he is the current Chairman of the Board and President of its Technology and Innovation Committee.

Mr. Kattan Cohen has expertise in: (i) administration, senior management and leadership;( ii) government affairs and public policy; (iii) financial and securities markets; (iv) business risk management; (v) human resources and talent development; (vi) legal affairs and corporate governance; (vii) technology and innovation; (viii) cybersecurity; and (ix) business strategy and project management. As a member of Ecopetrol’s Board of Directors, he is periodically trained in ethics, compliance and risk management matters.

Luis Santiago Perdomo Maldonado has over 40 years of experience in the Colombian banking industry. He has held senior management positions, including that of CEO of Banco Colpatria, part of the Scotiabank Group. He has been a member of several Boards of Directors in Colombian and Latin American companies in various economic sectors including finance, mining and agriculture, in organizations

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such as Banco Latinoamericano de Comercio Exterior (Bladex), Scotiabank Peru, Asociación Bancaria de Colombia, Deceval, Asociación Nacional de Empresarios de Colombia (ANDI) and Asociación Nacional de Instituciones Financieras (ANIF). He is also a Founding Member of the Colombian Institute of Corporate Governance, and served as Managing Director of Grupo Mercantil Colpatria S.A. He has been a member of the Boards of Directors of Colegio de Estudios Superiores de Administración (CESA), Fundación de Cirugía Reconstructiva (CIREC) and the Plenary Council of Gimnasio Moderno. He has also collaborated with the Fundación Universitaria Minuto de Dios. He holds a degree in Business Administration from the Colegio de Estudios Superiores de Administración (CESA). He is currently a member of the Board of Directors of Mineros S.A. and serves as an independent Director of the Board of Directors of Ecopetrol S.A. since April 2019. He is currently the President of the Board’s Business Committee.

Mr. Perdomo Maldonado has experience in: (i) administration, senior management and leadership; (ii) finance and securities markets; (iii) legal affairs and corporate governance; (iv) sustainability; (v) business strategy and project management; (vi) business risk management; (vii) human resources and talent development; (viii) technology and innovation; (ix) health, safety and/or environment; (x) cybersecurity; and (xi) energy industry. As a member of Ecopetrol’s Board of Directors, he is periodically trained in ethics, compliance, and risk management matters.

Sergio Restrepo Isaza served as Vice President of Capital Markets and Executive Vice President of Corporate Development at Grupo Bancolombia. He began his professional career at Corporación Financiera Corfinsura, where he served as CEO, Vice President of Investment Banking and Investment and International Vice President. He has been a member of several Boards of Directors including Cementos Argos, Compañía Nacional de Chocolates, Conavi, Asobancaria, Bolsa de Valores de Colombia, Conglomerado Financiero Internacional Banagrícola S.A., Suramericana Asset management SUAM, Consorcio Financiero and several others in the community sector. He holds a degree in Business Administration from EAFIT University in Medellin, Colombia, and an MBA from Stanford University in California. He has extensive experience in audit and risk matters, and has served as member of several audit and risk committees in different companies, where he played an active role in the analysis of financial information and was also responsible for investor relations. He is currently partner at Exponencial Banca de Inversión S.A.S., member and Chairperson of the Board of Directors of Grupo BIOS S.A.S., a member of the Board of Directors of Odinsa S.A. and Mineros S.A. He is an expert in financial, auditing and business risk matters and has been an independent Director of the Board of Directors of Ecopetrol S.A. since April 2019. He is the President of the Audit and Risk Committee of the Board of Directors.

Mr. Restrepo Isaza has experience in: (i) administration, senior management, and leadership; (ii) finance and securities markets; (iii) human resources and talent development; (iv) business strategy and project management; and (v) legal affairs and corporate governance. As for corporate governance matters, Mr. Restrepo Isaza has attended courses on this subject at the International Finance Corporation and at the Universidad Católica de Chile. As a member of Ecopetrol´s Board of Directors, Mr. Restrepo Isaza is periodically trained in ethics, compliance, and risk management matters.

Esteban Piedrahíta Uribe previously held the positions of Chairperson of the Chamber of Commerce of Cali, General Director at Departamento de Planeación Nacional, Advisor to the President and then Senior Specialist at the Inter-American Development Bank, Economic Editor of Semana magazine, General Manager of Endriven Colombia/Gas Meridional S.A.S. E.S.P., member of the Advisory Council of Fundación Panthera, among others. He holds a degree in Economics from Harvard University and a master’s degree in Philosophy and History of Science from the London School of Economics and Political Science. He is currently the Dean of Icesi University and member of the Boards of Directors of Cementos Argos S.A, Compañía de Seguros Bolívar S.A. and Seguros Comerciales Bolívar S.A. He is also a member of the Board of Trustees of Fundación Sidoc and Centro Internacional de Entrenamiento e Investigaciones Médicas (CIDEIM), and has been an independent Director of the Board of Directors of Ecopetrol S.A. since April 2019 and President of the Corporate Governance and Sustainability Committee.

Mr. Piedrahíta Uribe has experience in: (i) the energy industry; (ii) energy transition; (iii) administration, senior management and leadership; (iv) government affairs and public policy; (v) business strategy and project management; and (vi) legal affairs and/or corporate governance. In addition to the positions, Mr. Piedrahíta Uribe also has experience in: (i) finance and securities markets, having worked as Investment Banker with Salomon Brothers in New York and Estrategias Corporativas in Bogotá; and (ii) climate change and sustainability, having served as independent member of the Investment Committee of the MGM Sustainable Energy Fund (MSEF) I and II. In respect of technology and innovation, Mr. Piedrahíta Uribe founded two internet companies: Laciudad.com and Zoom Media Group and participated in Massachusetts Institute of Technology’s program “Massachusetts Institute of Digital Business Strategy: Harnessing Our Digital Future”. As a member of Ecopetrol’s Board of Directors, Mr. Piedrahíta Uribe is periodically trained in ethics, compliance, and risk management matters.

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Sandra Ospina Arango has 31 years of experience in the energy industry. She has co-led projects and initiatives for the development and upgrading of national electricity systems; participated in formulating regulations and standards for the future development of smart grids and renewable energies, and in shared-value initiatives between the State, academia and industry, supporting innovation and regional entrepreneurship. She is an Electrical Engineer, licensed in Physical-Mathematics from the Universidad del Valle. She holds a graduate studies degree in Energy Transmission and Distribution and a Master’s degree in Energy Generation from the aforementioned university. She is a current Professor of the Master’s in Engineering at Universidad del Valle and participates of projects on I+D+I (Research, Development and Innovation, for its Spanish acronym) at Universidad del Valle, pursues a Ph.D. in Electrical and Electronic Engineering at the same University and leads the Smart Grid Group of the Regional Energy Integration Commission (CIER, for its Spanish acronym) – Latin America. Throughout the past years she has served in management positions at Celsia Colombia S.A. E.S.P. and has been a member of various steering committees in the energy sector for various entities. She has been an independent member of Ecopetrol’s Board of Directors since October 24, 2022 and is the current President of the Board’s HSE Committee.

Ms. Ospina Arango has expertise in: (i) energy industry and energy transition; (ii) administration, senior management and leadership; (iii) government affairs and public policy; (iv) finance 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/or environment; (x) sustainability; (xi) cybersecurity; and (xii) 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.

Carlos Gustavo Cano Sanz holds a degree in Economics from Universidad de los Andes in Bogotá, a Master’s degree from Lancaster University in England, a postgraduate degree in Government, Business and International Economics from Harvard University in Boston, and a postgraduate degree from the Instituto de Alta Dirección Empresarial (INALDE) in Bogotá. He has been Chairperson of the Federación Nacional de Arroceros (FEDEARROZ), Chairperson of the Sociedad de Agricultores de Colombia (SAC), founder and Chairperson of Corporación Colombia Internacional (CCI), Chairperson of Caja Agraria and Chairperson of El Espectador (newspaper). He was the Minister of Agriculture from 2002 to 2005, and Director of Banco de la República from 2005 to 2017. He is currently a Professor at Universidad de los Andes, member of the Advisory Committee for Agriculture at Bancolombia, of the Advisory Council for Colombia of The Nature Conservancy (TNC) and hence has expertise in energy transition, climate change and water and wastewater management and member of the Board of Directors of Inversiones Minka S.A.S. His latest published book is “Mi paso por el Banco: Desaprendiendo y aprendiendo” published by Banco de la República and Universidad de Ibagué in March 2020. Additionally, since March 31, 2017, he is an independent Director of the Board of Directors of Ecopetrol S.A., nominated by the minority shareholders with the largest shareholding in Ecopetrol. He served as Vice Chairperson of said Board of Directors and President of its Business Committee until October 2022.

Mr. Cano Sanz has experience in: (i) administration, senior management and leadership; (ii) government affairs and public policy; (iii) finance and securities markets; (iv) human resources and talent development; (v) business strategy and project management; (vi) human development in the territories, having served as specialist in the Regional and Urban Development Unit of the National Planning Department, and as Minister of Agriculture and Rural Development; and (vii) sustainability. He has published various works related to sustainability issues, including: “La sostenibilidad del desarrollo hecha encíclica”, “Desarrollo Sostenible, impuesto al carbono y pago de servicios ecosistémicos: el caso de la Amazonia”, “La economía del cambio climático y la opción Amazónica”, “La economía del cambio climático” and “Economía y Agua”. As a member of Ecopetrol’s Board of Directors, Mr. Cano Sanz is periodically trained in ethics, compliance, and risk management matters.

In our Shareholders’ General Assembly to be held on March 30, 2023, our shareholders will elect the members of the board of directors for the remainder of the 2021-2025 period.

The current members of the Board that would not continue for the remainder of the 2021-2025 period would be Luis Santiago Perdomo Maldonado, Sergio Restrepo Isaza and Carlos Gustavo Cano Sanz. In this regard, three new candidates have been formally nominated to integrate the Board of Directors of the Company:

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Claudia González is a lawyer from the Universidad del Rosario with a specialization in financial legislation from the Universidad de los Andes. She served as a member of the Board of Directors of Ecopetrol from March 2018 to March 2019. She is currently the Executive President of the Asociación Colombiana de Corredores de Seguros or “ACOAS,” an association that represents insurance brokers. She served as Legal Secretary of the Presidency of the Republic, Secretary General of the Ministry of Finance and Public Credit, Secretary General of the Ministry of Mines and Energy, Secretary General of the Administrative Department of Security (DAS), National Administrative and Financial Director of the Attorney General's Office and Deputy Director of Programming for the Central Sector of the National Planning Department (DNP).

Ms. Gonzalez has been a member of the board of directors of various companies including Gecelca, Fiduprevisora S.A., Central de Inversiones S.A. (CISA), Sociedad de Activos Especiales S.A.S. (SAE), Coljuegos, Unidad de Gestión Pensional y Parafiscales (UGPP), Urrá S.A. ESP and Ecopetrol S.A. She currently serves on the board of directors of Fiduprevisora S.A. Given her professional background, she has experience in: (i) the energy industry; (ii) the energy transition; (iii) administration, senior management, and leadership; (iv) government affairs and/or public policy; (v) business risk management; (vi) human resources and talent development; and (vii) legal affairs and corporate governance.

Luis Alberto Zuleta 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, a university professor and a columnist. He has also been a member of the board 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 and a member of the governing board of Fundación Social.

Mr. Zuleta currently serves in the following committees: financial and audit committee of the manufacturing company Grupo Crystal S.A.S., financial committee of ICETEX and the risk committee of Protección S.A. Additionally, he is a member of the board of directors of the not-for-profit Fundación Pro Niñez Gabriel Herrera Rogelis.

Juan José Echavarría is a management engineer from the School of Mines, Universidad Nacional de Colombia, completed a non-degree program in Economics at Harvard University, was awarded a master’s degree in economics from Boston University and holds 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 is currently an Associate Researcher at Fedesarrollo and a dedicated university professor. Previously, he served as general manager and member of the board director of the Colombian 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 of the 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 was nominated to Ecopetrol’s Board of Directors by the minority shareholders with the second largest shareholding (after the Nation) in Ecopetrol. He is currently a member of the board of directors of the not-for-profit Alejandro Angel Escobar Foundation. Given his professional background, he has experience 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.

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7.3.1

Board Practices

Our Board of Directors is composed of nine members and is responsible for, among other things, establishing our general business policies. The majority of the Board of Directors must be independent and must be elected pursuant to the criteria set out in paragraph two, Article 44, Law 964, 2005, and 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 two seats in the Board of Directors, the name of one individual jointly proposed by departments that produce hydrocarbons and one individual jointly proposed by the ten minority shareholders with the highest equity participation. According to Colombian law, 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 October 24, 2022. During the General Shareholder’s Meeting of 2023, shareholders will elect directors for the remainder of the 2021-2025 period.

Our CEO is appointed by the Board of Directors and will have at least two 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 web page or in an alternative media vehicle.

The remuneration of our Directors is set exclusively by the shareholders at the General Shareholders Assembly. Directors are compensated 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. In the practice a consensus decision making operates in the Board.

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) to promote the attraction of human talent and (iv) to ensure the long-term stability and sustainability of the Ecopetrol Group’s strategy.

The policy regulates the capacities, obligations, and requirements for the nomination and election of the board members in order 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 complements the Corporate Governance Code and the internal regulations of (i) the General Shareholders’ Meeting, (ii) the Board of Directors, (iii) the Corporate Governance and Sustainability Committee, (iv) the Competence Matrix of the members of the Board of Directors, and (v) Ecopetrol’s Decisions and Attributions Matrix.

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Gender diversity

Furthermore, 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.

Part of this commitment is reflected in the appointment of women on the boards of directors of the Ecopetrol Group, with an increased participation from 22% in 2021 to 24% in 2022. In 2022, 80 of the 327 positions on the boards of directors of the Group’s companies were held by women.

7.3.2

Board Committees

Pursuant to our bylaws, our Board of Directors has the ability to constitute the committees it considers necessary. The Board of Directors currently has six committees (audit and risk committee, corporate governance and sustainability committee, remuneration, appointments and culture committee, business committee, 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 chairman 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.

During 2021, within the context of the ISA acquisition from the Ministry of Finance and Public Credit in ISA, the Board of Directors established a temporary Special Committee that analyzed the valuation of ISA, the price range and/or the price of the transaction. The Special Committee was comprised of independent members and made the necessary recommendations to the Board of Directors to evaluate the acquisition. The Special Committee met for the last time in August 2021.

Table 70 – Composition of committees of the Board of Directors since October 27, 2022


Audit and Risk Committee	Remuneration, Nomination and Culture Committee
Sergio Restrepo Isaza	Gabriel Mauricio Cabrera Galvis
(President and Financial Accounting Expert)	(President)

Carlos Gustavo Cano Sanz	Mónica de Greiff Lindo
Luis Santiago Perdomo Maldonado	Saul Kattan Cohen

Corporate Governance and Sustainability Committee	New Business Committee
Esteban Piedrahita Uribe	Luis Santiago Perdomo Maldonado
(President)	(President)

	Carlos Gustavo Cano Sanz
	Esteban Piedrahita Uribe
Carlos Gustavo Cano Sanz	Gonzalo Hernández Jiménez
Gabriel Mauricio Cabrera Galvis	Gabriel Mauricio Cabrera Galvis
Gonzalo Hernández Jiménez	Sandra Ospina Arango
Mónica de Greiff Lindo	Saul Kattan Cohen
	Sergio Restrepo Isaza

HSE Committee	Technology and Innovation Committee
Sandra Ospina Arango	Saul Kattan Cohen
(President)	(President)

Mónica de Greiff Lindo Sergio Restrepo Isaza	Esteban Piedrahita Uribe Sandra Ospina Arango Luis Santiago Perdomo Maldonado

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Audit and Risk Committee

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 is in charge of guaranteeing the design, implementation and supervision of our internal control over financial reporting. It also ratifies the annual hydrocarbons reserves report and provides support for our Board on 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 Sergio Restrepo Isaza 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, appointments and culture committee, which must be comprised of at least three members, including at least one independent director, 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.

Corporate Governance and Sustainability Committee

Our corporate governance and sustainability committee, which must be comprised of at least three members, including at least one independent director, 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 makes recommendations related to the Ecopetrol Group’s sustainability agenda and TESG topics.

Business Committee

Our business committee, which must be comprised of at least five members, including at least one independent Director, 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.

HSE Committee (Health, Safety and Environment)

Our 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.

Technology and Innovation Committee

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. Starting in 2020, the Technology & Innovation Committee also reviewed TESG-related topics.

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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 seven independent Directors and two non-independent Directors.
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 does not meet without 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.
Audit and Risk Committee
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.

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NYSE Standards		Our Corporate Governance Practices
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

Management

The following presents information concerning our executive officers and senior management. Unless otherwise noted, the majority of these individuals are Colombian citizens.

Executive Officers

Felipe Bayón Pardo has served as the Chief Executive Officer of Ecopetrol S.A. since 2017. He has over 31 years of experience in the energy industry and has led the Ecopetrol Group’s transformation and energy transition processes, its TESG (Technology, Environmental, Social and Governance) strategy, and the positioning of the company in strategic basins in the United States, Brazil and Mexico. Mr. Bayón joined Ecopetrol S.A. in February 2016 as Chief Operating Officer, overseeing the upstream, midstream, downstream, projects and marketing operations, as well as the research and innovation areas. Prior to his tenure at Ecopetrol, he worked for more than 20 years at BP plc, most recently as Senior Vice-President of BP America and Head of Global Deepwater Response. From 2005 to 2010, he was the Regional President of BP Southern Cone (South America). He began his career in 1991 at Hocol (Shell) in Colombia. He holds a degree in mechanical engineering from Universidad de los Andes. On January 26, 2023, Ecopetrol S.A. announced that Felipe Bayón Pardo will step down as Chief Executive Officer of the Company on March 31, 2023, and the selection process and appointment of the new Chief Executive Officer is ongoing. On March 24, 2023, the Board of Directors appointed Alberto Consuegra Granger as interim CEO of Ecopetrol S.A. effective from April 1, 2023, and until the date on which the successor to Felipe Bayón Pardo is appointed.

Alberto Consuegra Granger has served as Chief Operating Officer of Ecopetrol S.A. since March 1, 2019. Prior to this role, he was interim CEO of Cenit S.A.S., Ecopetrol S.A.’s midstream subsidiary, since February 2018 and Vice-President of Supply and Services of Ecopetrol S.A. since August 2016. Mr. Consuegra holds a degree in civil engineering from the Universidad de Cartagena and a master’s degree in pavements and construction management from Texas A&M University. Before joining Ecopetrol S.A., he was Vice-President of Exploration and Production at Equion Energia Limited, where he also served as the Vice-President for Projects and Production between 2011 and 2016. Mr. Consuegra began his professional career in 1984 at Morrison Knudsen International as a contract coordinator during the construction of the Cerrejón project. In 1993, he joined Ecopetrol S.A., working in the Projects Group, and then went to BP Exploration, where he worked for 16 years, first as a contract coordinator, then as procurement and contract manager, then human resource manager for the Andean area, and finally as leader of the Colombian Performance Unit until end of 2010. On March 24, 2023, its Board of Directors appointed Alberto Consuegra Granger as interim CEO of Ecopetrol S.A. effective from April 1, 2023, and until the date on which the successor to Felipe Bayón Pardo, who will lead the Company until March 31, as informed to the market, is appointed.

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Jaime Caballero Uribe has served as the Chief Financial Officer of Ecopetrol S.A. since August 2018. Mr. Caballero has over 25 years of international experience in the energy sector. He joined the Ecopetrol Group in 2016 and was the Chief Financial Officer for the downstream segment prior to his appointment as the Ecopetrol Group’s CFO. Previously, his experience includes 17 years at BP, where he held leadership positions in North and South America, Africa and Europe, and most recently as Regional CFO for Brazil, Uruguay, Colombia and Venezuela. Mr. Caballero holds a law degree from Universidad de los Andes, an MBA in energy business from Fundação Getulio Vargas (Rio de Janeiro) and has completed executive programs in advanced financial management from Duke University and the Wharton School of Business.

Management Team

Jorge Elman Osorio Franco has served as Vice-President for the upstream segment since June 1, 2022, Prior to his position, he served as the Development and Production Vice-President of Ecopetrol S.A. from March 2019 to May 2022, Regional Development and Production Vice-President from June 2017 to February 2019. Mr. Osorio holds a degree in chemical engineering from Universidad Nacional of Colombia, graduated from the Operations Academy of the Massachusetts Institute of Technology (MIT) in Boston, United States, where he continues attending several trainings. He has over 34 years of experience in Engineering, Projects and Operations in the Oil and Gas industry. He spent 24 years of his career at BP, where he served as Senior Operations Manager in Major Projects in Indonesia, Operations Excellence Director at Atlantic LNG in Trinidad & Tobago, and Technical Director for Colombia and Venezuela, among other leadership positions.

Pedro Fernando Manrique Gutierrez was appointed as the Commercial and Marketing Vice President of the Ecopetrol Group in April of 2017. He is also a member of the Ecopetrol Trading Asia Pte Ltda board of directors. He holds a bachelor’s degree in Electrical Engineering from the Industrial University of Santander, holds a Master’s degree in Industrial and Systems Engineering from the University of Florida in the United States where he was a Fulbright Scholar and an MBA from the IE Business School in Madrid, Spain. He has 33 years of experience in the oil and gas industry and previously spent 15 years in the upstream business with Chevron Petroleum Company in different locations and his last assignment was as the Commercial and Business Planning Manager for Chevron Latin America where he also served as a member of the Leadership Team for Chevron Latin America. During his career he also worked with Enron Energy Services as a Risk Manager and as a Business Development Manager at Enron International based in Houston, Texas.

Héctor Manosalva Rojas has served as CEO of Cenit S.A.S., Ecopetrol S.A.’s midstream subsidiary since March 1, 2019. He joined Ecopetrol S.A. in 1986 and prior to his appointment as CEO of Cenit, he served as Vice-President for Development and Production since July 2014. Over the course of his career at Ecopetrol S.A., Mr. Manosalva has held various positions, including Executive Vice-President for Production and Exploration, Vice-President of Production, Production Manager of the Central Region, President of Colombia’s Advisor for Safety and Security of National Energy Infrastructure, Director of HSE and Corporate Social Responsibility, Production Manager of the Southern Region and Head of the Production Planning Division. Mr. Manosalva holds a degree in petroleum engineering from the Universidad de America (Bogotá) and postgraduate degrees in Finance at the Universidad EAFIT and Executive Management from Universidad de los Andes. Currently, he is pursuing the Berkeley Executive Education Program: Senior Management and Innovation at Berkeley University of California.

Nicolás Azcuénaga Ramírez, is the Corporate Vice-President for Strategy and Business Development of the Ecopetrol Group since November 2021. Since May 2021, he was responsible for leading for Ecopetrol the transaction to buy the MHCP’s 51.4% stake in ISA which represented a transformational transaction for Ecopetrol S.A. and a robust response to the energy transition challenge. Previously, Mr. Azcuénaga was the CFO for upstream subsidiaries, accountable for the finance function of seven upstream subsidiaries in five countries. Prior to joining Ecopetrol S.A. Mr. Azcuénaga worked for BP as Business Manager for Brazil and Uruguay, Deputy Transition Manager for Southern Gas Assets and Business Manager in Aberdeen, U.K., and a range of financial, JV management and business development roles in Colombia. Mr. Azcuénaga is an international executive, with over 20 years of experience across a range of commercial, finance, business development and leadership roles, experienced managing complex joint ventures and negotiations, risks, and delivering value creation opportunities. Mr. Azcuénaga has served in several boards of directors and is a current board member of Rodeo Midland Basin USA, Intervial Chile and Innovaflora Group in Spain. Mr. Azcuénaga holds a B.A. in Management from CESA University Business School with emphasis in finance and projects evaluation. In addition, he holds a diploma on anti-money laundering from Manchester University & International Compliance Association.

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Yeimy Báez has served as the Ecopetrol Group Low Emissions Solutions Vice-President, responsible for leading the strategy to develop natural gas, LPG, biogas and hydrogen, which being clean energy sources are fundamental for energy transition and closing social gaps in Colombia developing and encouraging its widespread and affordable access. She has over 20 years of experience in the oil and gas industry, where she successfully fulfilled a broad range of technical, commercial, strategic and financial roles; including as the Corporate Manager of Financial Planning and Business Performance in Ecopetrol S.A. She holds a degree in Petroleum Engineering from the Industrial University of Santander, an MBA degree from Externado University of Colombia and is highly skillful in Project Management (PMP certified). Prior to her current assignment, she served for recognized players in the industry such as Equion, BP and Weatherford.

Mauricio Jaramillo Galvis has served as Vice-President of Health, Safety and Environment (HSE) since January 2020. Mr. Jaramillo has 26 years of experience in the oil and gas private sector in Colombia and Latin America. He has been appointed to several leadership roles as Vice-President of HSE of BP Colombia, Vice-President of HSE and Engineering at the Andean Unit of BP, Vice-President of Corporate Affairs and HSE, and Vice-President of Human Resources and Sustainability at Equion, among others. Mr. Jaramillo holds an MD from Universidad Javeriana, a specialization in Occupational Health and Safety from Universidad El Bosque and a degree from the Operations Academy at MIT.

Walter Fabián Canova has served as Vice-President of Refining and Industrial Processes since April 16, 2020. Since joining the Ecopetrol Group in March 2017, first as Operations Vice-President and later General Manager for the Cartagena refinery, Mr. Canova has been part of the Ecopetrol Group transformation process. Mr. Canova has almost 30 years of experience in the public and private oil and gas sector, mainly in refining and logistic with a strong focus on strategy and operations. He holds a degree in Chemical Engineer from Universidad Nacional del Litoral, Argentina, completed post-graduate studies in Project Management and Management Program at North Caroline and Houston Universities, and an MBA at Universidad de Belgrano, in Argentina. Prior to joining Ecopetrol S.A., he has worked in several refineries and headquarters for companies such as ExxonMobil, Axion Energy and Puma Energy, where he held positions such as Operations Manager, Project Manager and General Manager.

Fernán Ignacio Bejarano Arias has served as Vice-President of Legal Affairs and General Counsel at Ecopetrol S.A. since March 2016. Mr. Bejarano Arias holds a bachelor’s degree in law from Universidad Javeriana in Bogotá and an LLM from American University in Washington D.C. In his more than thirty years of professional experience, he has been a partner at the law firms of Estudios Palacios Lleras S.A, Bejarano Cárdenas y Ospina y Asociados Ltda and OPEBSA Compañía de Abogados S.A.S. and has worked for several years in important positions in the public sector, such as the Vice-Minister of Foreign Affairs, Secretary of the Monetary Board, Secretary of the Board of Directors of the Banco de la República (Colombian Central Bank), Office of Legal Affairs Counselor at the Presidency of the Republic of Colombia, and Vice-President of Legal Affairs and General Counsel at Corporación Financiera Colombiana. Mr. Bejarano Arias is a professor at the Faculty of Law of the Universidad Javeriana and has been an arbitrator before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce.

María Paula Camacho has 24 years of experience within the Ecopetrol Group. She has served as Legal Manager for M&A and Corporate affairs for Ecopetrol since 2021 and as of August 18, 2022, she was appointed interim Vice President of Corporate Affairs and Secretary General for two months, after which she was ratified in the position. As Vice President of Corporate Affairs and Secretary General, she leads the corporate affairs of the Company which include acting as the Company’s secretary for the Board of Directors and the Shareholders’ meetings, as well as heading the corporate governance initiatives for the Ecopetrol Group, the Company’s corporate responsibility guidelines and reporting, corporate communications, and institutional relations. Ms. Camacho has practiced law in Colombia and has extensive experience as Secretary General, head of legal departments, communications and corporate responsibility. Ms. Camacho holds a law degree from Pontificia Universidad Javeriana and a post-graduate degree in commercial law from Panthéon-Assas University Paris II.

María Juliana Alban Durán has served as Compliance Vice-President and Compliance Officer since July 2015. Ms. Alban holds a law degree from Universidad Sergio Arboleda with a specialization in commercial and financial Law from the same institution and has completed an executive program in strategic management of regulatory and enforcement agencies at Harvard’s Kennedy School of Government and an executive program in Leadership Decision Making from the same institution. Beginning in 2007, Ms. Alban previously worked in the Attorney General’s Office (Procuraduría General de la Nación) as Attorney General for State Contracts, General Secretary and Chief of Legal Office, among other positions within the institution.

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Alejandro Arango López has served as Vice-President of Human Resources at Ecopetrol S.A. since October 2014. He has more than 20 years of professional experience in different countries and has worked as Vice-President of Human Resources at Banco Santander in Colombia and as Human Resources Director of the Consumer Finance Division, Strategy Division and Cards Division at Banco Santander in Spain. Mr. Arango has also served as Human Resources Director for the Asia Pacific region at Banco Santander in Hong Kong and as Global Human Resources Division T&O, among others. Mr. Arango holds a degree in strategic marketing from CESA School of Business, a bachelor’s degree in theology from the Universidad Hochschule Sankt Georgen (Frankfurt) and a bachelor’s degree in philosophy from Javeriana University. As of January 23, 2023, Mr. Arango López has been exclusively dedicated to lead the collective bargaining process on behalf of the Company. Natalia Morales Gamble, who currently serves as Excellence and Administrative Head of the HSE Vice-Presidency, has been in charge of the other functions of the Human Resources Vice-Presidency.

Natalia Morales Gamble is the acting Vice-President of Human Resources. She is an environmental engineer from Universidad de los Andes, with a specialization in Environmental Law from Universidad del Rosario and a Master in Sustainable Development and Corporate Responsibility from Escuela Organización Industrial de Madrid. She has 18 years of experience in the energy and hydrocarbon sector, in the areas of human resources management, sustainability, HSEQ, business risk and technology. She has worked in different companies in the O&G sector in management positions such as Frontera Energy, Equion Energía and BP Colombia. She has extensive experience in the creation and implementation of management models, organizational culture transformation, management systems and strategies in HSEQ, corporate responsibility and human talent.

Diana Escobar Hoyos has served as Vice-President of Sustainable Development since September 2020. Ms. Escobar is a lawyer from Universidad Pontificia Bolivariana who specialized in Human Rights and International Humanitarian Law at University of Antioquia, with complementary studies in sustainable development and renewable energy. Ms. Escobar has worked as Deputy Commissioner for Legality and Coexistence in the Office of High Commissioner for Peace at Presidency of the Republic, coordinator of programs for economic reintegration of population in social risk in the Mayor’s Office of Medellín, consultant in sustainable development for sectors such as agricultural and retail, resource manager in non-governmental entities and external consultant at the Inter-American Development Bank.

Jaime Pineda Durán has been appointed as Vice President of Supply and Services as of January 10, 2023. Prior to this appointment, he was Procurement and Supply Chain Manager at Ecopetrol S.A. He joined Ecopetrol in 1989 as a Legal Advisor, and has served 22 years at the Vice-Presidency of Legal Affairs and 11 years in the procurement and supply chain areas. Mr. Pineda has held leadership positions such as District Legal Adviser, Head of the Legal Coordination for Procurement, Head of the Supply and Services Legal Advice Unit, Director of the Internal Control Office, Director of Supply of Goods and Services, Strategic Supply Director, Head of the Supply Excellence Department, where he led the transformation of the Company’s procurement and supply chain operating model. Mr. Pineda has over 33 years of relevant experience in the Oil and Gas industry as a lawyer and supply chain executive. He has also been a professor in several universities. He holds a bachelor’s degree in Law from Universidad Autónoma de Bucaramanga and has vast experience in contract law.

Ernesto Gutiérrez de Piñeres has served as Vice-President of Science, Technology and Innovation. Mr. Gutierrez de Piñeres is a Systems Engineer and Information Systems Management Specialist from Barranquilla’s Universidad del Norte. He holds an Executive MBA from Los Andes University. He has more than 23 years of experience as Director and Manager of information technology areas in different multinational companies in multiple industry sectors, leading and developing high-performance teams in Colombia, the United States, Central and South America. Mr. Gutierrez de Piñeres is an executive with experience in transforming technology areas into business partners and generators of value for organizations through innovation, knowledge, team development and technology strategies that leverage corporate strategy and competitive business.

With his leadership, Mr. Gutierrez de Piñeres has launched the digital reinvention process of the company focused on technology and innovation as catalysts of corporate goals to face energy transition challenges.

None of our Directors, Executive Officers or members of senior management has any familial 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, compensation for Directors’ attendance at meetings of the Board of Directors and/or committee meetings increased from the equivalent of four to six minimum monthly wage salaries, which totals approximately COP 6.96 million for 2023 and COP 6 million for 2022. See Note 31.1 to our consolidated financial statements for more details.

During 2022, the total compensation paid to our Directors amounted to COP 3.582 million and the remuneration paid to executive officers and senior management active amounted to COP 27,359 million. This includes amounts paid to certain of our executive officers and senior management pursuant to a bonus plan under which such persons are entitled to receive variable compensation based on our company results for each full year. The variable compensation ranges from 0% to 150% of each person’s base compensation based on our company performance.

None of the current members of our management team are eligible to receive pension and retirement benefits from us. As of December 31, 2022, there was no amount recorded to provide pension and retirement benefits. To align the interests of management and our overall strategy, climate change, water and energy transition related metrics are now included in the variable compensation program of senior management. In 2022, 50% of the variable compensation was tied to TESG targets, which included metrics related to climate, renewable energies, and milestones related to the gas and hydrogen strategy.

Implementation of the Long-Term Incentive Plan

Companies have increasingly incorporated incentive compensation plans into their compensation structures, in line with good international practices, driving exceptional and sustainable results to meet stakeholder expectations. Long-Term Incentives Plans (ILPs, by the Spanish acronym) are intended to generate incremental value for shareholders based on the Company’s proposed objectives and goals, by offering senior management a compensation mechanism in line with the achievement of those strategic objectives and align incentives for the beneficiary leaders with the Company’s achievement of such strategic objectives.

Ecopetrol’s general ILP Plan is 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 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 are aligned with the corporate strategy and business plan. These objectives are updated periodically and are in effect for a three-year term. The metrics and objectives help guide the company in achieving its long-term objectives and goals. They are regularly monitored to ensure that the company stays on track and is making progress towards meeting its strategic goals. As of the date of this annual report, there are three ILP plans in effect: (i) for the 2020-2022 period, for which the objectives are concentrated on generating operating cash flow (“OCF”), reducing GHG emissions, and the replacement of reserves (“RRR”); (ii) for the 2021-2023 period, for which the objectives are OCF, RRR, and energy transition, a metric that includes GHG reduction targets and diversification into low-emission businesses; and (iii) for the 2022-2024 period, for which the objectives are related to FCO crude oil production and energy transition, a metric that includes GHG reduction targets.

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 Ecopetrol’s subsidiaries.

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7.7

Share Ownership of Directors and Executive Officers

No individual Director or executive officer beneficially owns more than 1% of our outstanding shares.

The following executive officers and directors own shares of Ecopetrol S.A.:

Table 71 – Executive Officers and Directors owning Ecopetrol’s shares


Executive Officer	Number of shares⁽¹⁾	% Ownership
Felipe Bayón Pardo	8,418	0.00002	%
Jaime Eduardo Caballero Uribe	30,000	0.00007	%

(1)	As of January 31, 2023.

Under Colombian law, all of our shareholders have the same economic privileges and voting rights.

7.8

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, 2022, 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, 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.

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As of the year ended December 31, 2022, 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.”

Based on the assessment performed, management concluded that our internal control over financial reporting was effective as of December 31, 2022.

The effectiveness of our internal control over financial reporting has been audited by Ernst & Young Audit 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 years ended December 31, 2022, 2021 and 2020 were audited by Ernst & Young Audit S.A.S. The following table sets forth the fees billed to us by Ernst & Young Audit S.A.S. during the fiscal years ended December 31, 2022 and 2021.

Table 72 – Fees Billed to us by Ernst & Young Audit S.A.S.


	For the year ended December 31,
COP Millions, excluding 19% Value Added Tax	2022	2021
Audit fees	23,835	21,044
Audit-related fees	—	12
Tax fees	83	—
All other fees	109	88
Total	24,027	21,144

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 in 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 during the year ended December 31, 2022, that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

Attestation Report of the Registered Public Accounting Firm

Ernst & Young Audit 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.

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8. Financial Statements

Index

Report of Independent Registered Public Accounting Firm (Ernst & Young Audit SAS, Auditor Firm ID 1522)		1

Report of Independent Registered Public Accounting Firm (Ernst & Young Audit SAS, Auditor Firm ID 1522)		4

Consolidated statement of financial position		6

Consolidated statement of profit or loss		7

Consolidated statement of comprehensive income		8

Consolidated statement of changes in equity		9

Consolidated statement of cash flows		11

1.	Reporting entity	12

2.	Basis for presentation	12

3.	Significant estimates and accounting judgments	18

4.	Accounting policies	21

5.	New standards and regulatory changes	41

6.	Cash and cash equivalents	43

7.	Trade and other receivables	45

8.	Inventories	46

9.	Other financial assets	46

10.	Taxes	49

11.	Other assets	58

12.	Business combinations	60

13.	Investments in associates and joint ventures	61

14.	Property, plant, and equipment	64

15.	Natural and environmental resources	65

16.	Right-of-use assets	68

17.	Intangible assets	69

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18.	Impairment of non-current assets	70

19.	Goodwill	76

20.	Loans and borrowings	77

21.	Trade and other payables	80

22.	Provisions for employees’ benefits	80

23.	Accrued liabilities and provisions	85

24.	Equity	92

25.	Revenue from contracts with customers	95

26.	Cost of sales	99

27.	Administrative, operations and project expenses	99

28.	Other operating (expenses) income	100

29.	Financial result	101

30.	Risk management	101

31.	Related parties	109

32.	Joint operations	111

33.	Information by segments	113

34.	Supplemental information on oil and gas producing activities (unaudited)	120

35.	Subsequent and relevant events	125

Exhibit 1 – Consolidated subsidiaries, associates, and joint ventures		126

Exhibit 2 – Conditions of the most significant debt		132

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Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Ecopetrol S.A.

Opinion on the Financial Statements

We have audited the accompanying consolidated statements of financial position of Ecopetrol S.A. (the Company) as of December 31, 2022 and 2021, 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, 2022, and the related notes and financial statement schedules listed in exhibits 1 and 2 (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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have 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, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 29, 2023 expressed an unqualified opinion thereon.

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 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.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Ernst& Young Audit S.A.S.	Ernst & Young Audit S.A.S.	Ernst & Young Audit S.A.S.	Ernst & Young Audit S.A.S.
Bogotá D.C.	Medellín – Antioquia	Cali – Valle del Cauca	Barranquilla - Atlántico
Carrera 11 No 98 - 07	Carrera 43A No. 3 Sur-130	Avenida 4 Norte No. 6N – 61	Calle 77B No 59 – 61
Edificio Pijao Green Office	Edificio Milla de Oro	Edificio Siglo XXI	Edificio Centro Empresarial
Tercer Piso	Torre 1 – Piso 14	Oficina 502	Las Américas II Oficina 311
Tel. +57 (601) 484 7000	Tel: +57 (604) 369 8400	Tel: +57 (602) 485 6280	Tel: +57 (605) 385 2201

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		Estimation of fair value amount of long-lived assets in the Cartagena refinery
Description of the Matter		As described in notes 4.13 and 18.2 of the consolidated financial statements, management assesses, at each reporting date, whether there is an indication that long-lived assets may be impaired. If any indication exists, or when annual impairment testing for a Cash Generating Unit (CGU) is required, management estimates the CGU’s recoverable amount. A CGU’s recoverable amount is the higher of a CGU’s fair value less costs of disposal and its value in use. When the carrying amount of a CGU exceeds its recoverable amount, the CGU is considered impaired and is written down to its recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the CGU’s recoverable amount since the last impairment loss was recognized. In 2022, the Company recognized a reversal of impairment loss in the Cartagena refinery (the CGU) of COP $1,107,101. Auditing management’s estimate related to the determination of the CGU’s recoverable amount was complex and required the involvement of specialists due to the highly judgmental nature of the assumptions used in the model for estimating the CGU´s recoverable amount. In particular, the estimation to determine the recoverable amount was sensitive to significant assumptions, such as changes in the discount rate (weighted average cost of capital) and refining margins, which are affected by expectations about future market or economic conditions such as the sales prices of refined products and crude oil purchase prices.
How We Addressed the Matter in Our Audit		We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company’s process to determine the recoverable amount of the CGU, including controls over management’s review of the methodology used to development such estimates, the projected financial information and the significant assumptions described above. Our audit procedures included, among others, assessing the methodology used and testing the significant assumptions described above, as well as the underlying data used by the Company by comparing the significant assumptions used by management to current industry and economic trends. Additionally, we assessed the reasonableness of the Company´s projections by comparing them to actual results and comparable trends of the industry, and also tested the clerical accuracy of such projections. We also involved our specialists to assist us in the assessment of the discount rate (weighted average cost of capital), forward prices for oil and refined products, and projected financial information used in management’s estimate. Furthermore, we evaluated the related disclosures in the consolidated financial statements.
		The impact of the estimation of oil and gas reserves in the determination of depreciation, depletion and amortization and impairment of long-lived assets

F-2

A member firm of Ernst & Young Global Limited

Table of Contents

Description of the Matter

As described in notes 3.1 and 3.2 to the consolidated financial statements, the oil and gas reserves estimates used in the calculation of depreciation, depletion and amortization (DD&A), and in the determination of future cash flows used in the impairment analyses of long-lived assets. The risk is the inappropriate recognition of reserves that impacts these accounting estimates.

The estimation of oil and gas reserves used to calculate the DD&A and perform the impairment analyses is a complex process and requires professional judgement. Management uses specialized firms (hereinafter “specialists”) when estimating the reserves, which are determined based on engineering assumptions and methods, contractual arrangements, and economic factors. Estimates of oil and gas reserves depend upon a number of variable factors and key assumptions, including: historical production, contractual arrangements, operating and capital costs to be incurred, oil and gas prices, among others.

Auditing these accounting estimates was complex, because of the inherent technical engineering nature of the reserves estimation process, which requires the use of specialists in the performance of the assessment, including in the determining the reasonableness of management’s key assumptions previously identified.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company’s process to calculate the DD&A and to perform its impairment analyses, including management’s controls over the completeness and the accuracy of the financial data provided to the specialists for use in estimating oil and gas reserves used to develop such estimates.

To evaluate the estimated quantity of oil and gas reserves used in the calculation of DD&A (proved reserves) and impairment, we obtained the reports from external specialists hired by management and evaluated the competency and objectivity of the external specialists and management´s qualified persons responsible for overseeing the preparation of the reserve estimates by the specialists through the consideration of their professional qualifications, experience and their use of accepted industry practices.

In addition, we evaluated the completeness and accuracy of the financial data and inputs described above, which were used by the specialists in estimating oil and gas reserves by agreeing them to the cash flows used in impairment analyses and the final reserves balance used to the DD&A estimation. For reserves, verifying that reserve movements were in compliance with SEC regulations; evaluating management’s estimation of the point at which the operating cash flow from a project becomes negative (the economic limit); evaluating the completeness and accuracy of the inputs used by management in estimating the oil and gas reserves by agreeing the inputs to source documentation; performing back-testing of historical data to identify indications of estimation bias over time. We also tested the mathematical accuracy of the DD&A computations and reviewed the model of impairment analyses of long-lived assets by assessing the consistency between the estimation of oil and gas reserves prepared by the specialists with volumes of reserves included in the projected financial information, among other procedures.

Additionally, we evaluated the related disclosures in the consolidated financial statements.

Ernst & Young Audit S.A.S.

We have served as the Company’s auditor since 2016.

Bogotá, Colombia

March 29, 2023

F-3

A member firm of Ernst & Young Global Limited

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Ecopetrol S.A.

Opinion on Internal Control over Financial Reporting

We have audited Ecopetrol S.A.’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), (the COSO criteria). In our opinion, Ecopetrol S.A. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Company as of December 31, 2022 and 2021, 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, 2022, and the related notes and financial statement schedules listed in exhibits 1 and 2 and our report dated March 29, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

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. 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.

Ernst& Young Audit S.A.S.	Ernst & Young Audit S.A.S.	Ernst & Young Audit S.A.S.	Ernst & Young Audit S.A.S.
Bogotá D.C.	Medellín – Antioquia	Cali – Valle del Cauca	Barranquilla - Atlántico
Carrera 11 No 98 - 07	Carrera 43A No. 3 Sur-130	Avenida 4 Norte No. 6N – 61	Calle 77B No 59 – 61
Edificio Pijao Green Office	Edificio Milla de Oro	Edificio Siglo XXI	Edificio Centro Empresarial
Tercer Piso	Torre 1 – Piso 14	Oficina 502	Las Américas II Oficina 311
Tel. +57 (601) 484 7000	Tel: +57 (604) 369 8400	Tel: +57 (602) 485 6280	Tel: +57 (605) 385 2201

F-4

Table of Contents

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.

Bogotá, Colombia

March 29, 2023

F-5

A member firm of Ernst & Young Global Limited

Table of Contents

Ecopetrol S.A.

Consolidated statement of financial position

(In millions of Colombian pesos)


		As of December 31,
	Note	2022	2021
Assets
Current assets
Cash and cash equivalents	6	15,401,058	14,549,906
Trade and other receivables	7	39,224,999	18,448,882
Inventories	8	11,880,034	8,398,212
Other financial assets	9	1,162,127	1,627,150
Current tax assets	10	6,784,392	6,273,802
Other assets	11	2,778,480	2,333,091
		77,231,090	51,631,043
Assets held for sale		45,755	64,704
Total current assets		77,276,845	51,695,747
Non–current assets
Trade and other receivables	7	32,155,205	24,159,716
Other financial assets	9	1,563,744	1,307,584
Investment in associates and joint ventures	13	9,496,600	8,357,186
Property, plant, and equipment	14	100,997,498	90,076,526
Natural and environmental resources	15	42,323,610	35,909,844
Right-of-use assets	16	627,813	496,678
Intangible assets	17	18,146,605	15,508,516
Non-current tax assets	10	13,401,050	9,030,132
Goodwill	19	5,350,114	4,686,324
Other assets	11	1,453,347	1,198,363
Total non–current assets		225,515,586	190,730,869
Total assets		302,792,431	242,426,616
Liabilities
Current liabilities
Loans and borrowings	20	22,198,583	9,206,283
Trade and other payables	21	19,937,704	13,568,231
Provisions for employee benefits	22	2,753,697	2,296,253
Current tax liabilities	10	7,630,901	2,152,104
Accrued liabilities and provisions	23	1,533,136	1,590,118
Other liabilities		2,728,317	1,409,534
		56,782,338	30,222,523
Liabilities related to non-current assets held for sale		—	26,208
Total current liabilities		56,782,338	30,248,731
Non–current liabilities
Loans and borrowings	20	92,936,256	85,854,645
Trade and other payables	21	57,056	70,607
Provisions for employee benefits	22	10,211,542	9,082,792
Non-current tax liabilities	10	15,275,644	12,124,520
Accrued liabilities and provisions	23	11,223,358	12,642,089
Other liabilities		2,403,148	1,819,460
Total non–current liabilities		132,107,004	121,594,113
Total liabilities		188,889,342	151,842,844
Equity
Subscribed and paid in capital	24.1	25,040,067	25,040,067
Additional paid in capital	24.2	6,607,699	6,607,699
Reserves	24.3	8,898,633	10,624,229
Other comprehensive income	24.5	15,796,719	11,357,894
Retained earnings		29,811,809	14,859,658
Equity attributable to owners of parent		86,154,927	68,489,547
Non–controlling interest		27,748,162	22,094,225
Total equity		113,903,089	90,583,772
Total liabilities and equity		302,792,431	242,426,616

F-6

Table of Contents

Ecopetrol S.A.

Consolidated statement of profit or loss

(In millions of Colombian pesos, except for basic and diluted earnings per share, which are expressed in Colombian pesos)


		For the years ended December 31,
	Note	2022	2021	2020
Sales revenue	25	159,611,078	91,881,204	50,223,393
Cost of sales	26	(89,458,148)	(55,581,776)	(37,567,472)
Gross profit		70,152,930	36,299,428	12,655,921
Administrative expenses	27	(4,335,695)	(3,342,069)	(3,373,150)
Operations and project expenses	27	(4,743,628)	(3,153,557)	(2,586,016)
Impairment of non-current assets	18	(287,999)	(33,351)	(633,156)
Other operating (expenses) income	28	(555,855)	(72,744)	1,118,166
Operating income		60,229,753	29,697,707	7,181,765
Financial results	29
Finance income		1,317,145	403,592	1,101,430
Finance expenses		(8,027,252)	(4,431,648)	(3,929,791)
Foreign exchange (loss) gain		(124,650)	330,002	346,774
		(6,834,757)	(3,698,054)	(2,481,587)
Share of profits of associates and joint ventures	13	768,422	426,164	76,336
Profit before income tax expense		54,163,418	26,425,817	4,776,514
Income tax expense	10	(18,963,938)	(8,795,263)	(2,038,661)
Net profit for the year		35,199,480	17,630,554	2,737,853
Net profit attributable to:
Owners of parent		31,604,781	15,649,143	1,586,677
Non–controlling interest		3,594,699	1,981,411	1,151,176
		35,199,480	17,630,554	2,737,853
Basic and diluted earnings per share	24.6	768.7	380.60	38.59

F-7

Table of Contents

Ecopetrol S.A.

Consolidated statement of comprehensive income

(In millions of Colombian pesos)



		For the years ended December 31,
	Note	2022	2021	2020

Net profit for the year		35,199,480	17,630,554	2,737,853
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	30.3	(1,528,749)	(808,777)	(722)
Hedge of a net investment in a foreign operation	30.4	(4,987,735)	(2,871,410)	(364,343)
Cash flow hedge with derivative instruments		117,913	(135,666)	55,072
Financial instruments measured at fair value		829	830	406
Foreign currency translation		15,960,722	5,970,719	1,569,590
Sale of joint ventures	29	—	(361,728)	—
		9,562,980	1,793,968	1,260,003
Other comprehensive income that will not to be reclassified to profit or loss in subsequent periods -net of taxes:
Remeasurement (loss) gain on defined benefit plans	22.1	(668,254)	1,777,157	96,221
		(668,254)	1,777,157	96,221
Other comprehensive income for the year, net of tax		8,894,726	3,571,125	1,356,224
Total comprehensive income for the year, net of tax		44,094,206	21,201,679	4,094,077
Comprehensive income attributable to:
Owners of parent		36,043,606	19,059,975	2,887,080
Non–controlling interest		8,050,600	2,141,704	1,206,997
		44,094,206	21,201,679	4,094,077

F-8

Table of Contents

Ecopetrol S.A.

Consolidated statement of changes in equity

(In millions of Colombian pesos)


		Attributable to owners of parent
		Subscribed	Additional		Other			Non–
		and paid–	paid–in		comprehensive	Retained		controlling	Total
	Note	in capital	capital	Reserves	income	earnings	Total	interest	equity
Balance as of January 1, 2022		25,040,067	6,607,699	10,624,229	11,357,894	14,859,658	68,489,547	22,094,225	90,583,772
Adoption of new standards	5.1	—	—	—	—	42,054	42,054	—	42,054
Balance as of January 1, 2022, after adoption		25,040,067	6,607,699	10,624,229	11,357,894	14,901,712	68,531,601	22,094,225	90,625,826
Net profit		—	—	—	—	31,604,781	31,604,781	3,594,699	35,199,480
Release of reserves	24.3	—	—	(5,886,441)	—	5,886,441	—	—	—
Dividends declared	24.4	—	—	(6,907,605)	—	(11,512,675)	(18,420,280)	(2,073,000)	(20,493,280)
Business combination	12	—	—	—	—	—	—	(238,839)	(238,839)
Equity restitution		—	—	—	—	—	—	(84,824)	(84,824)
Appropriation of reserves, net:
Legal	24.3	—	—	1,669,468	—	(1,669,468)	—	—	—
Fiscal and statutory reserves	24.3	—	—	509,082	—	(509,082)	—	—	—
Occasional	24.3	—	—	8,889,900	—	(8,889,900)	—	—	—
Other comprehensive income:
(Loss) gain on hedging instruments:
Cash flow hedge for future exports		—	—	—	(1,528,749)	—	(1,528,749)	—	(1,528,749)
Hedge of a net investment in a foreign operation		—	—	—	(4,854,805)	—	(4,854,805)	(132,930)	(4,987,735)
Cash flow hedge with derivative instruments		—	—	—	62,792	—	62,792	55,121	117,913
Financial instruments measured at fair value		—	—	—	942	—	942	(113)	829
Foreign currency translation		—	—	—	11,572,728	—	11,572,728	4,387,994	15,960,722
Remeasurement loss on defined benefit plans		—	—	—	(814,083)	—	(814,083)	145,829	(668,254)
Balance as of December 31, 2022		25,040,067	6,607,699	8,898,633	15,796,719	29,811,809	86,154,927	27,748,162	113,903,089


		Attributable to owners of parent
		Subscribed	Additional		Other			Non–
		and paid–	paid–in		comprehensive	Retained		controlling	Total
	Note	in capital	capital	Reserves	income	earnings	Total	interest	equity
Balance as of December 31, 2020		25,040,067	6,607,699	9,635,136	7,947,062	669,900	49,899,864	3,599,499	53,499,363
Net profit		—	—	—	—	15,649,143	15,649,143	1,981,411	17,630,554
Release of reserves	24.3	—	—	(5,066,156)	—	5,066,156	—	—	—
Dividends declared	24.4	—	—	—	—	(698,984)	(698,984)	(2,008,840)	(2,707,824)
Business combination	12	—	—	—	—	—	—	18,973,080	18,973,080
Change in participation in subsidiaries		—	—	—	—	228,692	228,692	(596,394)	(367,702)
Equity restitution		—	—	—	—	—	—	(14,824)	(14,824)
Appropriation of reserves, net:
Legal	24.3	—	—	168,808	—	(168,808)	—	—	—
Fiscal and statutory reserves	24.3	—	—	509,082	—	(509,082)	—	—	—
Occasional	24.3	—	—	5,377,359	—	(5,377,359)	—	—	—
Other comprehensive income:
(Loss) gain on hedging instruments:
Cash flow hedge for future exports		—	—	—	(808,777)	—	(808,777)	—	(808,777)
Hedge of a net investment in a foreign operation		—	—	—	(2,869,539)	—	(2,869,539)	(1,871)	(2,871,410)
Cash flow hedge with derivative instruments		—	—	—	(105,048)	—	(105,048)	(30,618)	(135,666)
Financial instruments measured at fair value		—	—	—	431	—	431	399	830
Foreign currency translation		—	—	—	5,811,782	—	5,811,782	158,937	5,970,719
Sale of joint ventures	29	—	—	—	(361,728)	—	(361,728)	—	(361,728)
Remeasurement gains on defined benefit plans		—	—	—	1,743,711	—	1,743,711	33,446	1,777,157
Balance as of December 31, 2021		25,040,067	6,607,699	10,624,229	11,357,894	14,859,658	68,489,547	22,094,225	90,583,772

F-9

Table of Contents

Ecopetrol S.A.

Consolidated statement of changes in equity

(In millions of Colombian pesos)


		Attributable to owners of parent
		Subscribed	Additional		Other			Non–
		and paid–	paid–in		comprehensive	Retained		controlling	Total
	Note	in capital	capital	Reserves	income	earnings	Total	interest	equity
Balance as of December 31, 2019		25,040,067	6,607,699	3,784,658	6,646,660	12,334,706	54,413,790	3,817,838	58,231,628
Net profit		—	—	-	—	1,586,677	1,586,677	1,151,176	2,737,853
Release of reserves	24.3	—	—	(540,826)	—	540,826	—	—	—
Dividends declared		—	—	—	—	(7,401,005)	(7,401,005)	(1,425,586)	(8,826,591)
Change in participation in subsidiaries		—	—	—	—	—	—	249	249
Appropriation of reserves, net:
Legal		—	—	1,325,148	—	(1,325,148)	—	—	—
Fiscal and statutory reserves		—	—	509,082	—	(509,082)	—	—	—
Occasional		—	—	4,557,074	—	(4,557,074)	—	—	—
Other comprehensive income:
(Loss) gain on hedging instruments:
Cash flow hedge for future exports		—	—	—	(722)	—	(722)	—	(722)
Hedge of a net investment in a foreign operation		—	—	—	(364,343)	—	(364,343)	—	(364,343)
Cash flow hedge with derivative Instruments		—	—	—	40,443	—	40,443	14,629	55,072
Financial instruments measured at fair value		—	—	—	211	—	211	195	406
Foreign currency translation		—	—	—	1,528,592	—	1,528,592	40,998	1,569,590
Remeasurement gains on defined benefit plans		—	—	—	96,221	—	96,221	—	96,221
Balance as of December 31, 2020		25,040,067	6,607,699	9,635,136	7,947,062	669,900	49,899,864	3,599,499	53,499,363

F-10

Table of Contents

Ecopetrol S.A.

Consolidated statement of cash flows

(In millions of Colombian pesos)


		For the years ended December 31,
	Note	2022	2021	2020
Cash flow in operating activities:
Net profit for the period		35,199,480	17,630,554	2,737,853
Adjustments to reconcile the net profit to net cash provided by operating activities:
Income tax expense	10	18,963,938	8,795,263	2,038,661
Depreciation, depletion, and amortization	14,15,16,17	12,128,991	10,159,922	9,324,538
Loss (gain) foreign exchange, net	29	124,650	31,726	(346,774)
Realization of other comprehensive income from the sale of a joint venture	29	—	(361,728)	—
Finance cost of loans and borrowings	29	5,517,417	3,095,224	2,384,342
Finance cost of post–employment benefits and abandonment costs	29	2,003,687	1,043,728	872,987
Write off of exploratory assets and dry wells	15	1,032,164	486,408	448,132
Loss on disposal of non–current assets		379,985	61,846	246,317
Gain on revaluation of assets in Guajira association	28	—	—	(1,284,372)
Gain on acquisition of participations and interests	28	—	—	(86,026)
Gain on loss of control	28	—	—	(65,695)
Impairment loss of current assets	28	101,871	83,773	34,416
Impairment loss of non-current assets	18	287,999	33,351	633,156
Gain on fair value adjustment of financial assets		(77,082)	(7,431)	(43,948)
Loss on hedging transactions with derivatives		(553)	19,485	—
Share of profit of associates and joint ventures	13	(768,422)	(426,164)	(76,336)
Net gain on the sale of assets held for sale		(279,635)	(3,840)	(5,635)
Hedge ineffectiveness	30.3	6,625	24,496	9,779
Realized loss on foreign exchange cash flow hedges	25	1,143,287	249,978	193,374
Movements in provisions	23	715,831	714,839	412,609
Net change in operational assets and liabilities:
Trade and other receivables		(28,471,881)	(9,457,451)	678,349
Inventories		(2,831,729)	(2,980,134)	716,077
Trade and other payables		3,690,068	3,117,982	(2,550,411)
Tax assets and liabilities		(3,100,744)	(2,448,882)	(1,256,889)
Provisions for employee benefits		(355,645)	(222,356)	465,062
Provisions and contingencies		(1,004,167)	(878,576)	(442,794)
Other assets and liabilities		589,729	(523,090)	(392,843)
		44,995,864	28,238,923	14,643,929
Income tax paid		(8,761,294)	(5,702,902)	(5,457,225)
Net cash provided by operating activities		36,234,570	22,536,021	9,186,704
Cash flow in investing activities:
Investment in joint ventures	13	(329,377)	(44,735)	—
Acquisition of subsidiaries, net of acquired cash		—	(8,951,587)	—
Investment in property, plant, and equipment	14	(8,767,716)	(6,117,588)	(5,032,317)
Investment in natural and environmental resources	15	(11,962,544)	(6,733,028)	(5,994,462)
Acquisitions of intangibles	17	(1,147,510)	(444,346)	(90,082)
Proceeds from sales of other financial assets		1,301,394	1,282,903	2,107,856
Interests received	29	965,952	266,116	299,246
Dividends received	13	1,471,134	206,048	157,241
Proceeds from sales of non-current assets		373,634	17,986	23,713
Net cash used in investment activities		(18,095,033)	(20,518,231)	(8,528,805)
Cash flow in financing activities:
Proceeds from borrowings	20.1	16,844,029	24,666,792	13,805,403
Repayment of borrowings	20.1	(16,409,494)	(11,267,540)	(5,003,885)
Interest payments		(5,492,251)	(3,333,555)	(2,345,683)
Lease payments	16	(434,555)	(336,030)	(350,539)
Payment of restitution of equity to minority shareholders		(84,824)	—	—
Dividends paid	24.4	(13,356,947)	(2,771,287)	(8,734,351)
Net cash (used) provided in financing activities		(18,934,042)	6,958,380	(2,629,055)
Exchange difference in cash and cash equivalents		1,645,657	491,428	(22,294)
Net increase (decrease) in cash and cash equivalents		851,152	9,467,598	(1,993,450)
Cash and cash equivalents at the beginning of the year		14,549,906	5,082,308	7,075,758
Cash and cash equivalent at the end of the year	6	15,401,058	14,549,906	5,082,308

F-11

Table of Contents

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

1.	Reporting entity

Ecopetrol S.A. is a mixed economy company, with a commercial nature, formed in 1948 in Bogotá – Colombia, headquarters of the Ecopetrol Business Group (collectively called “Ecopetrol Business 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 electric power 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

2.1

Statement of compliance and authorization of financial statements

The consolidated financial statements of Ecopetrol and its subsidiaries as of December 31, 2022, and 2021 and for each of the three years in the period ended December 31, 2022, have been prepared in accordance with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB).

Accounting policies 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 on March 29, 2023.

2.2Reclassifications

For presentation purposes, the Ecopetrol Business Group reclassified some items in the comparative figures as of December 31, 2021 and 2020. They had no impact on the items of the statement of financial position, profits and losses, comprehensive income, changes in equity, or cash flows. The reclassifications are presented in notes 10 – Taxes and 24.5 - Other comprehensive income attributable to owners of parent.

2.3Basis for consolidation

The consolidated financial statements were prepared by consolidating all companies set out in Exhibits 1 and 2, which are those over which Ecopetrol exercises direct or indirect control. Control is achieved when the Ecopetrol Business Group:

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has power over the investee (including rights to manage relevant activities);

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is exposed, or has the rights, to variable returns from its involvement with the investee; and

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has the ability to use its power to affect its operational returns. This instance occurs when the Ecopetrol Business Group has less than a majority of the voting rights of an investee, and it still has the power over the investee to provide it with the practical ability to direct the relevant activities of the investee unilaterally. The Ecopetrol Business Group considers all relevant facts and circumstances in assessing whether or not the Company’s voting rights in an investee are sufficient or not to give it power, including:

the percentage of the Ecopetrol Business Group’s voting rights relative to the size and apportionment of the shares of other vote holders;

potential voting rights held by the Ecopetrol Business Group, other vote holders or other parties;

rights arising from other contractual arrangements; and

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

any additional facts and circumstances that indicate that the Ecopetrol Business 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 Business 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, 2022, were prepared on the basis that the Ecopetrol Business Group will continue to operate as a going concern bases.

Significant changes in consolidation:

2022

Ecopetrol US Trading LLC

In November 2022, the indirect subsidiary Ecopetrol US Trading LLC was incorporated. This company is domiciled in Delaware, United States of America, its main corporate purpose is the international commercialization of refined, petrochemical, crude oil, and natural gas of Ecopetrol Business Group and third parties. Ecopetrol US Trading LLC is a direct subsidiary of Ecopetrol USA Inc.

Gasoducto de Oriente S.A.

On July 12, 2022, the liquidation of the Gasoducto de Oriente S.A. took place in the Chamber of Commerce of Bogotá. It was a subsidiary of Inversiones de Gases de Colombia S.A.

Conexión Kimal Lo Aguirre

In July 2022, ISA Inversiones Chile incorporated the Joint Venture Conexión Kimal Lo Aguirre, together with Transelec and China Southern Power Grid International (CSG) as shareholders. This company will build and operate the Kimal-Lo Aguirre project in Chile awarded in 2021.

2021

Acquisition of Interconexión Eléctrica S.A. E.S.P.

On August 20, 2021, the Ecopetrol acquired control of Interconexión Eléctrica S.A. E.S.P. (ISA), thus obtaining control of the company. See Note 12 – Business combinations.

ISA is a Multi-Latin business group with operations in the electric power transmission, toll roads concessions, and telecommunications businesses, through 50 subsidiaries, 11 joint ventures and 1 associate, in 6 countries in South and Central America. See the subsidiaries in Exhibit 1.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

New companies in Singapore

On July, 2021, the subsidiaries Ecopetrol Singapore Pte. Ltd. and Ecopetrol Trading Asia Pte Ltd. were incorporated in Singapore. Ecopetrol Singapore Pte. Ltd. owns 100% of the share capital of Ecopetrol Trading Asia Pte Ltd., whose main purpose is the international commercialization of crude and refined products of the Company to clients in Asia. Both companies are domiciled in Singapore.

2020

ECP Oil and Gas Germany GmbH

December 11, 2022, the subsidiary ECP Oil and Gas Germany GmbH completed its liquidation.

Bioenergy S.A.S and Bioenergy Zona Franca S.A.S.

On June 24, 2020, the Superintendence of Companies issued the liquidation orders decreeing on the termination of the reorganization process and the opening of the judicial liquidation process of Bioenergy S.A.S and Bioenergy Zona Franca S.A.S. The latter process will be carried out according to the law on business insolvency – Act 1116/2006, and under the direction of the aforementioned Superintendence. Consequently, as of this date Ecopetrol Business Group lost control over these companies and have not been consolidated since then. As a result, reduction of net assets was recognized due to the loss of control with a gain on the results of the Business Group for $65,570.

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 period, 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 Business 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.

2.5Functional and presentation currency

The consolidated financial statements are presented in Colombian Pesos, which is the Ecopetrol’s functional currency. For each Ecopetrol Business Group entity, its functional currency is determined based of the main economic environment where it operates.

The statements of profit or loss, and cash flows of subsidiaries with functional currencies different from Ecopetrol’s functional currency 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 part of a foreign operation, the cumulative translation adjustment related to the foreign operation is reclassified to profit or loss.

The consolidated financial statements are presented in Colombian pesos rounded up to the closest million unit (COP$ 000,000) except when otherwise indicated.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

2.6Foreign currency

Transactions in foreign currencies are initially recorded by the Ecopetrol Business 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 or net investment in a foreign operation hedge, 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.

2.7Classification of assets and liabilities as current and non–current

The Ecopetrol Business 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:

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It is expected to be realized or intended to be sold or consumed (or expected to be settled, in the case of liabilities) in the ordinary course of business;

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Held mainly for the purpose of trading;

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Expected to be realized (or to be settled, in the case of liabilities) within twelve months after the reporting period; or

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In the case of the assets, it is cash or a cash equivalent, unless the exchange of such asset or liability is restricted or to be used to settle a liability at least twelve months after the reporting period; or

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In the case of a liability, there is no unconditional right to defer settlement of the liability until at least twelve months after the reporting period.

Other assets and liabilities are classified as non–current.

Deferred tax assets and liabilities are classified as non–current assets and liabilities.

2.8Earnings per share

Basic earnings per share is calculated by dividing the profit for the year attributable to equity holders of Ecopetrol, the parent company, by the weighted average number of ordinary shares outstanding during the year. There is no potential dilution of shares.

2.9Conflict between Russia and Ukraine

The increase in prices has had both positive and negative impacts on the Business Group. On one hand, the rise in the average price of ICE Brent has increased revenues from the sale of our crudes, and higher prices of diesel, gasoline, jet fuel, and other refined products have been favorable for the 2022 financial results of Cartagena and Barrancabermeja refineries. However, the increase in prices has also had a negative effect for the Business Group, including the weakening of the Group´s crude oil differential versus Brent.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

To mitigate this, Ecopetrol Business Group has worked in improving the positioning of its crude oil and diversifying the destination markets. In addition, the high prices have affected the Business Group purchases of crude oil and products, which are used as inputs and raw materials for production processes as well as to meet the growing national demand for fuels. Lastly, higher energy costs, coupled with the international logistics crisis, have generated pressures on the operating costs and project execution timelines. Ecopetrol Business Group maintains a close and constant monitoring of various Russia-Ukraine related factors that could impact the 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 monitoring the potential changes in demand, geopolitical risks, and regulatory changes that could affect the operations.

2.10Considerations on climate change and energy transition

2.10.1Strategic aspects of Ecopetrol Business Group

On February 8, 2022, Ecopetrol communicated to the market its 2040 long-term strategy, called “Energy that Transforms”, which comprehensively responds to current environmental, social and governance challenges, maintaining the focus on generating sustainable value for all your interest groups. Its objective is to consolidate an agile and dynamic organization that adapts in a timely manner to the changes facing the energy industry, the challenges of a world that advances in the generation and use of clean energy, traveling a path of opportunities for growth and leadership in the Americas.

“Energy that Transforms” positions Ecopetrol Business Group as an integrated energy Group, which participates in all the links of the hydrocarbon chain and in linear infrastructure, both in energy transmission and road concessions, and hopes to continue diversifying into businesses that allow it to continue to reduce its carbon footprint and advance in meeting its goal of being a company with zero net carbon emissions by 2050 (scopes 1 and 2). The strategy is supported by four strategic pillars: (i) Grow with the Energy Transition, (ii) Generate Value with Sustainability, (iii) Cutting-Edge Knowledge and (iv) Competitive Returns.

Within the first three pillars described in the strategy, the following actions associated with the energy transition and climate change were included:

Grow with the energy transition

On average, between USD $5,200 and USD $6,000 million will be invested annually by 2040. Between 2022 and 2024, organic investments will range between USD $17,000 and USD $20,000 million. In line with international best practices, the valuations of these investments in exploration and production projects incorporate a cost of greenhouse gas emissions under the internal CO2 price methodology, with a price curve that starts at $20 USD/ TonCO2e today and amounts to $40 USD/TonCO2e from 2030.

Gas, as a fundamental source of energy in the energy transition, the 2022-2024 Plan includes investments in projects for more than USD $1,800 million. In the long term, it is expected to grow in its own production, seek new marketing options and venture into regasification and storage.

Investments will be made for USD $2,600 million (15% of the total investments of the Business Group), mainly concentrated in Brazil (42%) and Colombia (25%), in addition to Peru and Chile. In this way, the continuity of ISA’s 2030 Strategic Plan is guaranteed. This is how diversification towards low-emission businesses in the long term contemplates: (i) between 2019 (base year) and 2030, investment of USD $8.3 billion in current businesses and geographies and USD $2.2 billion in new geographies and (ii) achieving a participation of non-conventional renewable energies between 25% and 40% in the self-generation matrix by 2040.

The foregoing will be supported by, in addition to ISA, the gradual foray into emerging businesses aligned with new global trends, such as the production of low-carbon hydrogen as an energy source, the capture, use and storage of (CCUS) and Natural Climate Solutions (NCS), to mitigate the effects of climate change. Over the next three years, more than USD $200 million will be invested in green hydrogen projects in the Cartagena and Barrancabermeja refineries, and in CO2 capture projects through emerging technologies such as CCUS and SNC projects.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Generate value with sosTECnibilidad (sustainability + technology)

The 2022 - 2024 Plan (without ISA) includes investments of more than USD $1,400 million in projects for circular water management, decarbonization, energy efficiency, use of energy and alternative sources, improvement in the quality of fuels, and studies and pilots of green and blue hydrogen for applications in refineries and mobility.

In this sense, the Plan has a clear focus on supporting the energy transition strategy, including the incorporation of renewable energy sources for self-consumption, taking advantage of wind, solar and geothermal energy technologies, strengthening socio-environmental investment programs, deepening digital transformation and acceleration of the development and implementation of technologies to optimize operations throughout the chain.

On the other hand, the long-term objectives include for environmental matters, achieve (i) a 25% reduction in GHG emissions by 2030 compared to 2019 (scopes 1 and 2), (ii) zero emissions CO2 equivalent emissions by 2050 (scopes 1 and 2), (iii) zero routine flaring by 2030, (vi) water neutral by 2045 (zero discharges, 66% reduction in water collection and offsetting 34% of residual water consumption). In terms of social component, it is expected to promote the generation of about 230,000 new non-oil jobs by 2040 and contribute to the education of 2 million young colombians. As a sign of this commitment, Ecopetrol Business Group will seek to continue improving its position among public companies globally within the Dow Jones Sustainability Index.

Cutting edge knowledge

This pillar seeks to develop the necessary capacities for sosTECnibilidad (sustainability + technology), through a comprehensive science, technology, and innovation (CT+i) strategy to contribute to diversification, increase clean energy, decarbonize operations, and enhance human talent.

As part of the goals of the 2022-2024 Plan, more than USD $240 million will be allocated to innovation, technology, and digital transformation projects, which include technologies for the management of produced water as a profitable and sustainable resource and a study for the capture of CO2 in natural sinks.

2.10.2General organic investment plan

In line with the Strategy, on December 9, 2022, Ecopetrol S.A. informed the market of the approval of the general organic investment plan for 2023, which includes the following relevant elements in terms of the energy transition and climate:

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Nearly 23% of the plan is aimed at cementing diversification into new low-emission businesses, which includes investments in hydrogen production, renewable energy, carbon capture, and electricity transmission, leveraging diversification at the Ecopetrol Business Group scale.

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The plan seeks to reduce about 400,000 tons of CO2e emissions and incorporate about 900 MW of renewable energy and more than 50,000 tons of green hydrogen by 2025.

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The commitment to self-sufficiency in gas includes investments between COP $3.6 billion and COP $4.1 billion for exploration and production projects in the Piedemonte Llanero, the Continental Caribbean and Offshore. The plan aims the creation of, at least, two new regional energy communities and about 107,000 new gas-connected homes.

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Nearly COP $5.4 trillion are allocated to the electricity transmission business with the objective of enabling more than 6,000 kilometers of new transmission lines for non-conventional renewable energies by 2025.

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In accordance with the sosTECnibilidad (sustainability + technology) objectives of the strategy, the plan includes investments close to COP $2.3 trillion in decarbonization projects, integrated water management, and improvement of fuel quality, among others.

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Social investment resources for regional development and community well-being amount to COP $472 billion focused on road infrastructure, education, and access to public services such as water and gas.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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More than COP $405 billion will be allocated to science, technology, and innovation projects, essential to leverage business development and catalyze advances in technologies for the energy transition.

3.Significant estimates and accounting judgments

The preparation of the consolidated financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts of assets, liabilities, sales revenues, costs, and commitments recognized in the financial statements and the accompanying disclosures. The Ecopetrol Business 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 required a material adjustment to the carrying amount of assets or liabilities affected in future periods. Changes in estimates are adjusted prospectively in the period in which the estimate is revised.

In the process of applying the Ecopetrol Business 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:

3.1Oil and gas reserves

Hydrocarbon reserves are estimates of the amounts of hydrocarbons that can be economically and legally extracted from the Ecopetrol Business 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 geological, technical, and economic factothers, including projections of future production rates, 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 periods.

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 proven developed reserves may affect the carrying amounts of exploration and production assets, natural resources and environment, goodwill, liabilities for dismantling and depreciation, depletion, and amortization. With all other variables remaining unchanged, a decrease in estimated proven reserves would increase, prospectively, depreciation, depletion, and amortization costs, while an increase in 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, depletion, and amortization, is presented in Notes 14 and 15.

3.2Impairment (recovery) of non-current assets

Ecopetrol Business Group Management uses its professional judgment in assessing the existence of evidence of an impairment loss or reversal, based on internal and external factors.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

When an indicator of impairment loss or reversal of impairment of prior period impairment exists, the Ecopetrol Business 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, taxes, and costs; (2) useful life of assets; (3) future prices, (4) discount rate, which is reviewed annually, and is determined as the weighted average cost of capital (WACC), and (5) changes in regulation. Specifically, for crude oil and gas assets, the following are also included: (6) estimation of volumes and market value of oil and natural gas reserves and (7) 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 periods 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 periods.

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 period impairment amounts.

3.3Exploration and evaluation costs

The application of the Ecopetrol Business 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 Business 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 drilling success level 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 period. The expenses for dry wells are included in operating activities in the consolidated statement of cash flows.

3.4Determination 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 non-current assets for more information.

3.5Abandonment and dismantling costs of fields and other facilities

According to environmental and oil regulations, the Ecopetrol Business 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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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. Ecopetrol Business Group considers that the abandonment and dismantling costs are reasonable, based on the experience of the Ecopetrol Business 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 financial statements. See Note 4.14 - Provisions and contingent liabilities (Obligation to withdraw assets).

3.6Pension 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.

3.7Goodwill impairment

In December of each year, the Ecopetrol Business 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. Ecopetrol Business 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.

3.8Litigation

The Ecopetrol Business 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 financial statements.

This analysis, which may require considerable judgment, includes the assessment of current legal proceedings brought against the Ecopetrol Business Group and claims not yet initiated. A provision is recognized when the Ecopetrol Business Group 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.

3.9Taxes

Calculation of the income tax provision requires interpretation of tax law in the jurisdictions where the Ecopetrol Business Group operates. Significant judgment is required to determine estimates for income tax on taxable profits and to evaluate the recoverability of deferred tax assets, which are based on the ability to generate sufficient taxable income during the periods in which such deferred taxes could be used or deduct.

To the extent that future cash flows and taxable income differ significantly from the estimates, the Ecopetrol Business Group’s ability to realize the deferred tax assets recorded could be affected.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Furthermore, changes in tax rules could limit the capacity of the Ecopetrol Business 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.

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 Business 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.

3.10Hedge 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 Business Group periodically monitors the alignment between its hedge instruments and its risk management policy.

3.11Provision for significant maintenance and replacement

Ecopetrol Business Group has contractual obligations under its road and electric power transmission concession agreements to provide the replacement and maintenance activities. The amount of the provision is based on qualitative and quantitative analyzes made by Ecopetrol Business Group’s maintenance area and an estimate of disbursements for major maintenance and replacements, which considers the current market prices of the components to be replaced at the time to recognize the provision.

3.12Traffic projections for road concessions

The revenue for the services provided under the road concessions related to certain contracts, which are accounted under 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 projections among other variables according to the concession.

3.13Electric power transmission concessions agreements

Ecopetrol Business Group operates energy transmission concessions in Colombia, Peru, Chile, Bolivia, and Brazil under public service concession agreements in which the grantor controls or regulates the services provided by the concessionaire, to whom they are provided, and at what price.

3.14Business combination

According to IFRS 3, Business combinations, applying the acquisition method implies to identify the assets acquired and liabilities assumed and measure them at fair value on the acquisition date, subject to certain exceptions. For each kind of asset or liability, fair value methodologies are applied considering the observable inputs and elements described in IFRS 13 – Fair value measurement.

4.Accounting policies

4.1Financial 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.

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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 trade receivables, other receivables, and financial assets held–to–maturity are measured subsequently measured at amortized cost using the effective interest method.

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, supposing that the market participants act in their economic best 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.

Ecopetrol Business 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:

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Level 1: Quoted (unadjusted) market prices in active markets for identical assets or liabilities. The fair value of the Ecopetrol Business Group’s marketable securities with a quoted market price is based on Level 1 inputs.

●

Level 2: Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observed. Level 2 inputs include prices of similar assets, prices obtained through quotations made by stockbrokers, and prices that can be substantially corroborated with other observable data with the same contractual terms.

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.

●

Level 3: Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable. The Ecopetrol Business Group does not use Level–3 inputs for the measurement of financial assets and liabilities. The Ecopetrol Business Group may use Level–3 inputs for the calculation the recoverable amount of certain non–financial assets for the purpose of impairment testing.

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 period. 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. This methodology is also applied to the instrument’s measurement related to the concession financial assets.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Impairment

The Ecopetrol Business Group evaluates if there is objective evidence that a financial asset or group of financial assets are impaired. Financial assets are evaluated for the impairment indicators at the end of each reporting period. Financial assets are considered impaired when there is objective evidence that, because of one or more events that occurred after initial recognition, the estimated future cash flows of the asset have been affected. For financial assets measured at amortized cost, the amount of the impairment loss recognized is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the financial asset’s original effective interest rate.

4.1.1

Cash and cash equivalents

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.

Restricted cash is a monetary resource with the objective of allocating it to specific and previously determined purposes.

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 Business Group has applied the practical expedient, Ecopetrol Business 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 Business Group has applied the practical expedient are measured at the transaction price determined under IFRS 15.

Ecopetrol Business Group classifies its financial assets in the following categories:

Financial assets measured at fair value through profit or loss

Financial assets are held for trading and financial assets designated at the time of the initial recognition at fair value through profit or loss. Financial assets are classified as held for trading if they are acquired to be sold or repurchased in the short term. They are recognized at their fair value and losses or profits arising at the time of re–measurement are recognized in the statement of profit or loss.

Financial assets measured at fair value with changes in other comprehensive income

These are equity instruments of other non–controlled and non–strategic companies not allowing for any type of control or significant influence thereon and where the Ecopetrol Business Group’s Management does not intend to negotiate with them in the short term. These financial instruments are recorded at their fair value, and unrealized gains or losses are recognized in other comprehensive income.

Financial assets at amortized cost

This category is the most relevant to Ecopetrol Business Group. The Group’s financial assets at amortized cost includes trade receivables, other receivables, loans, and borrowings.

Loans and receivables are non–derivative financial assets with fixed or determinable payments that are not quoted in an active market. Loans and receivables, including trade and other receivables, are measured initially at fair value and then at amortized cost using the effective interest rate method, less impairment.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Loans to employees are initially recorded using the present value of the future cash flows, discounted at the current market rate for similar loans. If the interest rate is less than the current market rate, fair value will be less than the amount of the loan. This difference is recorded as a benefit to employees.

Ecopetrol Business Group measures financial assets at amortized cost if both of the following conditions are met:

●	The asset is held within a business model with the objective to hold financial assets to collect contractual cash flows.

●	The contractual terms of the asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

Financial assets at amortized cost are subsequently measured using the effective interest method and are subject to impairment analysis. Gains and losses are recognized in profit or loss when the asset is derecognized, modified, or impaired.

Derecognition of financial assets

The Ecopetrol Business 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 Business Group does neither transfer nor retain substantially all the risks and benefits of the asset or transfer control of the asset, the Ecopetrol Business Group continues to recognize the transferred asset, to the extent of its continuing participation, and it also recognizes the associated liability.

4.1.3Financial liabilities

Financial liabilities correspond to the financing obtained by the Ecopetrol Business Group through bank credit facilities and bonds, accounts payables 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 EIR. The EIR amortization is included as finance costs in the statement of profit or loss.

Accounts payable to suppliers and creditors are short–term financial liabilities recorded at nominal value since it does not significantly differ from fair value.

Derecognition

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

Financial instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Changes in the fair value of derivatives are recognized as gains or losses in the statement of profit or loss, except for the effective portion of cash flow hedges, which is recognized in other comprehensive income and later reclassified to profit or loss when the hedge item affects profit or loss.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Changes in fair value of derivative contracts, which do not qualify or are not designated as hedges, including forward contracts for the purchase and sale of commodities under negotiation for physical delivery or receipt of the commodity are recorded in profit or loss.

Derivatives embedded in the host contract are accounted for as separate derivatives at fair value if their economic characteristics and risks are not closely related to those of the host contracts and the host contracts are not held for trading or designated at fair value through profit or loss. These embedded derivatives are measured at fair value with changes in fair value recognized in profit or loss.

4.1.5Hedging operations

For purposes of hedge accounting, hedges are classified as:

●	Cash flow hedges: hedges of the exposure to variability in cash flows attributable to a particular risk associated with all, or a component of, a recognized asset or liability or a highly probable forecast transaction, and that could affect profit or loss.

●	Hedges of net investments in foreign operations.

●	Fair value hedges: hedges of the exposure to changes in fair value of a recognized asset or liability or an unrecognized firm commitment, or a component of any such item, that is attributable to a particular risk and that could affect profit or loss.

At the inception of a hedge relationship, Ecopetrol Business 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 periods for which they were designated.

4.1.5.1

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.

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 transaction subsequently results in the recognition of a non-financial item, the amount accumulated in equity is removed from the separate component of equity and included in the initial cost or other carrying amount of the hedged 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 initially hedged transaction will occur.

Ecopetrol Business Group designates certain loans as a hedging instrument for its exposure to exchange rate risk in future crude oil exports. Additionally, Ecopetrol Business 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.

4.1.5.2Hedge of net investment in a foreign operation

Hedges of a net investment in a foreign operation, including a hedge of a monetary item that is accounted for as part of the net investment, 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.

Ecopetrol Business Group allocates 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 30.4.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

4.1.5.3Fair value hedge

The gain or loss on the hedging instrument shall be 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.

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. However, if the hedged item is an equity instrument for which an entity has elected to present changes in fair value in other comprehensive income, those amounts shall remain in other comprehensive income.

4.2Inventories

Inventories are recorded at the lower of cost and net realizable value.

Inventories mainly comprise crude oil, fuels and petrochemicals, and consumable inventories (spares and supplies).

The cost of crude oil is the production costs, including transportation costs.

The cost of other inventories 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.

Consumable inventories (spares and supplies) are recognized as inventory and then charged to expense, maintenance, or project to the extent that such items are consumed.

Ecopetrol Business Group estimates the net realizable value of inventories at the end of the period. 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 original write-down, so that the new carrying amount will always be the lower of the cost and the revised net realizable value.

4.3Investments in associates and joint ventures

4.3.1Investments in associates

An associate is an entity over which the Ecopetrol Business 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 Business Group holds an equity interest with voting rights of 20% to 50%. See Exhibit 1 – 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 Business 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 Business Group’s share of the results of operations of the associate is recognized in the consolidated statement of profit or loss. Any change is recognized in other comprehensive income of the Ecopetrol Business Group.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

After application of the equity method, the Ecopetrol Business Group determines if it is necessary to recognize an impairment on its investment in its associate. The Ecopetrol Business Group determines whether there is objective evidence that the investment is impaired. If there is such evidence, the amount of the impairment is calculated as the difference between the recoverable amount and the carrying value, and then the impairment is recognized in the consolidated profit or loss statement.

When necessary, the Ecopetrol Business Group adjusts the accounting policies of associates to ensure consistency with the policies adopted by the Ecopetrol Business Group. Additionally, the equity method of these companies is measured on their most recent financial statements.

4.3.2

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.

4.4Joint operations

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 Ecopetrol Business 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 the operator 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 Ecopetrol Business Group participates as a non–operator partner, it recognizes the assets, liabilities, sales revenues, cost of sales, and expenses based on the operator partner’s report. When Ecopetrol Business Group is the direct operator of joint venture contract, it recognizes its percentage of assets, liabilities, sales revenues, costs, and expenses, based on the participation of each partner in the items corresponding to assets, liabilities, sales revenues, costs, and expenses.

When the Ecopetrol Business 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. Any transaction cost related to the acquisition or increased share in the joint operation that constitutes a business combination is recognized in the consolidated statement of profit or loss.

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.

4.5Non–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.

4.6Property, plant, and equipment

Recognition and measurement

Property, plant, and equipment are stated at cost less accumulated depreciation and accumulated impairment losses. Tangible components related to natural and environmental resources are part of property, plant, and equipment.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The initial cost of an assets 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 item.

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 Ecopetrol Business Group expects to use during more than one period are recognized as property, plant, and equipment.

Any gain or loss arising from the disposal of a property, plant, and equipment is recognized in profit or loss of the period.

Subsequent disbursements

Subsequent disbursements correspond to all payments to be made on existing assets 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 an asset 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 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 period in which it was executed. Depreciation of an asset starts when it is ready to be used.

Useful lives are determined based on the period over which an asset is expected to be available for use, physical exhaustion, technical or commercial obsolescence and legal limits or restrictions over the use of the asset.

The estimated useful life of assets fluctuates in the following ranges:


Plant and equipment	10 – 55 years
Pipelines, networks, and lines	10 – 63 years
Buildings	10 – 100 years
Other	3 – 35 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 if appropriate.

4.7Natural and environmental resources

Recognition and measurement

Ecopetrol Business 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 the evaluation of mineral resources.

Exploration costs

Acquisition and exploration costs are recorded as exploration and evaluation assets until the determination of whether the exploration drilling is successful or not; if determined to be unsuccessful, all costs incurred are recognized as expenses in the statement of profit or loss.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 charged as assets until it is determined if they are commercially viable; otherwise, they are expensed in the consolidated statement of profit or loss as dry wells expense. 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 reclassified to the natural and environmental resources account after being assessed for impairment.

All capitalized costs are subjected to technical and commercial revisions at least once a year to confirm the evaluation and exploration efforts continue the fields; otherwise, these costs are written off through to profit or loss.

Exploration costs are net of the revenues obtained from the sale of crude oil during the extensive testing period, net of cost of sales since they are considered necessary to complete the asset.

Development costs

Development costs correspond to those costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing. When a project is approved for development, the corresponding capitalized acquisition and exploration costs are classified as natural and environmental resources and costs 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 is 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 estimation includes plugging and abandonment costs, facility dismantling and environmental recovery of areas and wells. Changes arising in new abandonment liability estimations and environmental remediation are capitalized in the carrying amount of the related 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 amortization factor of future economic benefits over the useful life of the asset. Depreciation/depletion rates are reviewed annually, based on reserves reports and the impact of any changes is recognized prospectively in the financial statements.

Reserves are independently estimated by internationally recognized external consultants and approved by Ecopetrol’s Board of Directors. Proved 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.

Impairment

Assets associated to exploration, evaluation and production are subject to review for possible impairment in their carrying amount. See Notes 3.2 — Impairment of non-current assets and 4.13 — Impairment of non–current assets.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

4.8Capitalization of borrowing costs

Borrowing costs related to the acquisition, construction or production of a qualifying asset that requires a substantial period 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 item will flow to the Ecopetrol Business Group and costs can be measured reliably. Other borrowing costs are recognized as financial costs. Projects that have been suspended but that the Ecopetrol Business Group intends to continue to pursue their development in the future, are not considered qualifying assets for the purpose of capitalization of borrowing costs.

4.9Intangible assets

Intangible assets with a defined useful life, 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 method are revised at the end of each reporting period; any change in estimates is recognized on a prospective basis.

The disbursements related to research activities are recognized as expense as incurred.

Easements

Easements are rights obtained for the use part of land for the installation of a transmission line. This implies restrictions on the use of the land by the owner and authorizations to Ecopetrol Business 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 Ecopetrol Business 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. Easements have an indefinite useful life, so they are not amortized and are reviewed annually for impairment.

4.10

Concessions

Ecopetrol Business 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.

Concessions that meet the above criteria are recorded according IFRIC 12 - Concession Agreements of services.

Ecopetrol Business Group’s assets that were built to operate concessions where the grantor has no residual interest in the infrastructure and the Group has no obligation to return the assets are recognized under IFRS 16 - Leases. In these cases, the construction of the infrastructure is a service provided to the grantor, different from the operation and maintenance service. Revenue from services is measured and recorded in accordance with IFRS 15 – Revenue from Contracts with Customers and IFRS 9 – Financial Instruments, depending on the asset model.

Concessions in which the Ecopetrol Business Group does not have a contractual right to receive money or another financial asset from the grantor but has the right to charge users in exchange for the services provided, are recognized under the intangible asset model.

The detail of each type of concession by country is disclosed in Note 25.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Intangible asset model

Considering IFRIC 12, concessions in which Ecopetrol Business Group does not have a contractual right to receive cash or another financial asset from the grantor but has the right to charge users in exchange for the services provided, are recognized under the intangible asset model. The costs incurred by Ecopetrol Business Group for the construction of the concession infrastructure are on a straight-line basis over the term of the concession period. Revenue from construction or improvement services is recognized according to the level of completion of the construction, based on the costs actually incurred, including at construction margin.

The operation and maintenance costs related to the concession are recognized in the statement of profit or loss once the infrastructure of the concession is ready for its use and Ecopetrol Business Group receives from the grantor the right to receive a fee for the services. Revenues are recognized based on the services provided as established in the concession agreements.

Infrastructure expansions are recognized as intangible asset 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.

Financial asset model

Concessions in which Ecopetrol Business 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 financial asset model. In this model the financial asset is classified as a financial asset concession, according to IFRS 9 – Financial Instruments, and it will be represented as current and non-current concessions in the financial position of Ecopetrol Business Group. This asset accrues interest using the effective interest rate method (see Note 4.1).

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.

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). After initial recognition goodwill is measured at cost less any accumulated impairment loss, which cannot be reversed in subsequent periods according to IAS 36. Goodwill is not amortized but tested for impairment annually.

4.12Leases

As of January 1, 2019, the Ecopetrol Business Group adopted IFRS 16, “Leases” applying the modified retrospective scope.

At the beginning of a contract, Ecopetrol Business Group assesses whether a contract is, or contains, a lease. This situation arises if the contract transfers the right to control the use of an identified asset for a period in exchange for a consideration. To assess whether a contract conveys the right to control an identified asset, the regulations of IFRS 16 are used.

Ecopetrol Business Group applies the guidance of IFRS 16 – Leases on concessions contracts that do not meet the criteria of the guidance of IFRIC 12.

Ecopetrol Business Group as a lessee

On the commencement date of the lease, Ecopetrol Business Group recognizes lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying asset during the lease term. The interest expense on the lease liability and the depreciation expense on the right-of-use asset are recognized separately.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

In subsequent recognition, Ecopetrol Business Group makes a remeasurement of the lease obligation 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 obligation will be recognized as an adjustment to the asset for the right of use.

Ecopetrol Business Group as a lessor

Ecopetrol Business 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 operational.

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.

Right-of-use assets

The Ecopetrol Business 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. The cost of right-of-use assets includes the amount of lease liabilities recognized, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received.

Lease liabilities

At the commencement date of the lease, the Ecopetrol Business Group recognizes lease liabilities measured at the present value of the lease payments to be made during the term of the lease. The lease payments include fixed payments (including in-substance fixed payments) less any lease incentives receivable, variable lease payments that depend on an index or a rate, and amounts expected to be paid under residual value guarantees. Variable payments that do not depend on an index or rate are recognized as expenses in the period in which an event or condition indicates that the payment will occur.

To calculate the present value of the lease payments, the Ecopetrol Business Group uses the incremental borrowing rate on the lease’s commencement date. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments or a change in the assessment of an option to purchase the underlying asset.

Current leases and low-value asset leases

The Ecopetrol Business 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 (short-term leases), and lease contracts for which the underlying asset is of low value (low-value assets).

Joint Operating Agreements (JOA)

In JOA agreements, the Ecopetrol Business Group assesses whether it controls the use of the asset. If the Ecopetrol Business Group, as the operator, controls the use of the asset, it recognizes the entire right-of-use and lease liability in the financial statements. If it is the JOA who controls, it is analyzed whether the contract meets the characteristics of a sublease, and in that case each party must recognize the right of use in proportion to their participation. Ecopetrol Business Group recognizes 100% of the right-of-use in joint venture agreements in which the Groups is the operator.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

4.13Impairment of non–current assets

In order to evaluate if any non-current assets are impaired, Ecopetrol Business 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 Business Group, for the Transportation segment, each pipeline system is considered an independent CGU, and for the Electric power 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 or 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 before taxes 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.

Fair value less costs of disposal, as described above, is compared to valuation multiples and quoted prices of shares in companies comparable to Ecopetrol Business 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 periods. 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.

The carrying amount of non–current assets reclassified as assets held–for–sale is compared to its fair value less costs of disposal. No other provision for depreciation, depletion, or amortization is recorded if the fair value less costs of sale is lower than the carrying amount.

For the case of concessions, Ecopetrol Business 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 Business 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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

If the effect of the temporary 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. When the discount is recognized, the increase in the provision 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 Ecopetrol Business Group uses all available information to determine a reasonable estimate of their respective cost.

Contingent liabilities are not recognized but are subject to disclosure in the explanatory notes when an outflow of resources is possible; including those whose amounts cannot be estimated.

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 should 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 period in which the obligation originates, a provision is recognized when there is enough information available to make the best estimation.

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 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 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 in results for the period as a financial expense.

4.15

Income tax and other taxes

Income tax expense is comprised of income tax payable for the period and the effect of deferred taxes in each period.

Current income taxes are recognized in income 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 Business 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 periods, 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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

4.15.2Deferred income tax

Deferred tax is provided using the liability method for temporary 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 Business 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.

The carrying amount of a deferred tax asset is subject to review at the end of each reporting period, and it is reduced to the extent 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, or in respect of the taxes on the possible future distribution of accumulated profits of subsidiaries or investments accounted for by the equity method, if at the time of the distribution it may be controlled by Ecopetrol and it is probable that the retained earnings will be reinvested by the Ecopetrol Business Group companies and, therefore, will not be distributed to the Group.

4.15.3Other taxes

The Ecopetrol Business 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.

4.16Employee benefits

Salaries and benefits for Ecopetrol Business 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 periods other than the probationary period.

Ecopetrol belonged to the special pension regime under which pension liabilities are Ecopetrol’s responsibility and not pension fund’s responsibility. However, Law 797 of January 29, 2003, and Legislative Act 001 of 2005 determined that Ecopetrol will no longer belong to the said regime and that from that point on employees would be part of the General Pension Regime. Consequently, pension obligations related to employees pensioned until July 31, 2010, are still Ecopetrol’s responsibility. Employees are entitled to such pension bonus if they worked with Ecopetrol prior to January 29, 2003, but whose labor agreement expired without renewal before that date.

All labor benefits of employees who joined Ecopetrol before 1990 are Ecopetrol’s responsibility, without the involvement of any social security entity or institution. Service cost for the employee and his/her relatives registered with Ecopetrol is determined by means of a mortality table, prepared based on facts occurring during the year.

For employees who joined Ecopetrol after the Act 50 of 1990 went in effect, Ecopetrol makes periodic contributions for severance payments, pensions, and labor risks to the respective funds.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

In 2008, Ecopetrol partially settled the value corresponding to monthly pension payments from its pension liabilities, transferring such liabilities and their underlying amounts to autonomous pension funds (PAP, for its acronym in Spanish). The funds transferred, and returns on those funds, cannot be redirected, nor can they be returned to the Ecopetrol Business Group, until all of the pension obligations have been fulfilled. The settled obligation covers allowances and pension bonds payments, with health and education remaining Ecopetrol’s responsibility.

Employee benefits are divided into four groups comprised as follows:

a)	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 period in which the employees have rendered 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 Business 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.

b)	Post–employment defined benefit plans:

In the defined benefits plan, the Ecopetrol Business Group provides 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:

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Pensions

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Pension bonds

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Health

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Educational plan

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Retroactive severances

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 period.

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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 period (current service cost) and the amount resulting from a new benefit plan. Plan amendments corresponds 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.

(a)	Others long-term benefits

Others long–term benefits include the five–year term bonus which 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 Business 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.

(b)	Termination benefits

Termination benefits are recognized only when a detailed plan exists and there is no possibility to withdraw the offer. The Ecopetrol Business 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.

4.17Revenue from contracts with customers

The Ecopetrol Business 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, and 3) sales of refined and petrochemical products, and biofuels, and 4) transmission of energy power and toll roads concessions. 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 Business Group expects to receive in exchange for those goods or services.

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, pipe or by another delivery method, thus fulfilling the Ecopetrol Business Group’s performance obligations to its customers.

For some natural gas supply contracts with a replacement period, 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 hydrocarbons transport

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. Ecopetrol Business Group companies are principal in providing these services.

Ship/ Take-or-Pay contracts for the sale of refined products, storage and transport specify minimum quantities of products or services for which a customer will pay, even if the latter does not receive them or use them (“deficient quantities”). Although the Ecopetrol Business Group expects customers to recover all deficient quantities to which they are contractually entitled, any load revenue received related to temporary shortfalls that will be offset in a future period will be deferred and that amount recognized as revenue in the event any of the following scenarios occurs:

The customer exercises its right to deficient volumes or services, or

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The possibility is remote that the customer will exercise its right to deficient volumes or services.

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. 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.

In other cases, Ecopetrol Business 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, Ecopetrol Business 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 period, 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.

Electric power transmission and toll roads concessions

This group 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 (4) telecommunications services.

The recognition of revenue from electric power transmission services occurs according to the performance obligations based on the conditions of the contracts that include requirements established by the electricity market regulators in the countries in which Ecopetrol Business Group operates. This is generally achieved when the performance obligations agreed with the regulatory entities are executed, considering the period 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.

For service concession agreements, Ecopetrol Business Group measures the revenue in accordance with IFRIC 12 at the fair value of the consideration received or receivable, considering the payment defined in the contracts.

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Recognize revenues and costs for project construction services in results for the period, according to the percentage completion method of the projects at the reporting date, which includes an estimated profit margin determined based on the macroeconomic characteristics and the conditions of the project, and the weighting of the estimated receivable cash flows related to the estimated cash flows of the construction.

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Recognize revenues and costs for operation and maintenance services of third-party facilities in the profit or loss statement for the period, as the service is provided, based on the performance obligations established in the contracts.

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Recognize the financial returns of concession agreements classified as financial assets in the statement of profit or loss for the period using the effective interest rate method.

The business model developed under electric power transmission concession agreement, associated with the obligation to build, and implement the electric power transmission infrastructure and is classified under the asset according to IFRS 15 – Revenue from contracts with customers. The asset is recognized while the obligation to build and implement the infrastructure is satisfied, and revenue is recognized over the life of the project.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Significant financing component

Payments received from customers are generally short term (except for revenue of concessions). Using the practical expedient in IFRS 15, Ecopetrol Business 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 as amortized cost, defining the future cash flows, and applying and discount rate, according to IFRS 9 – Financial Instruments.

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 Business Group makes its best estimate of the transaction price that reflects the goods and services transferred to customers.

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 Business 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 Business Group.

4.18Costs and expenses

Costs and expenses are presented according to their nature; 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 financial 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), e) dividends derived from equity instruments measured at fair value with changes in other comprehensive income.

4.20Information by business segment

Ecopetrol Business Group presents the information related to its business segments in its consolidated financial statements in accordance with paragraph 4 of IFRS 8 – Operation segments.

The operations of the Ecopetrol Business Group are performed through four business segments: 1) Exploration and Production, 2) Transport and Logistics, 3) Refining, Petrochemical and Biofuels, and 4) Electric Power Transmission and Toll Roads Concessions.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Segments are determined based on Ecopetrol Business 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 Business 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.

b)	Transport and logistics: This segment includes sales revenue and costs associated with the transport and distribution of hydrocarbons and derivative products in operation.

Refining, petrochemicals, and biofuels: 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.

Electric power transmission and toll roads concessions: This segment includes activities of supplying electric power transmission services, design, development, construction, operation, and maintenance of road and energy infrastructure projects. Revenues come from the supplying of these services to domestic and foreign clients (mainly Latin America). This segment also includes the supplying of information technology and telecommunications services.

See information by segments in Note 33.

4.21Business combinations

The Ecopetrol Business 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. Ecopetrol Business 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 acquirer will recognize separately the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree.

The company that acts as buyer will recognize the goodwill generated as an asset on the acquisition date, measured as the difference between (i) the sum of the consideration transferred, the amount of any non-controlling interest, and the fair values on the date of acquisition of the shareholding in the acquiree, and (ii) the net amount of the acquisition date of the identifiable assets acquired and the liabilities assumed.

The cost of an acquisition is measured as the aggregate of the consideration transferred, which is measured at acquisition date fair value, and the amount of any non-controlling interests in the acquiree. For each business combination, the Ecopetrol Business Group elects whether to measure the non-controlling interests in the acquiree at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition-related costs are expensed as incurred and included in administrative expenses.

The Ecopetrol Business Group determines that it has acquired a business when the acquired set of activities and assets include an input and a substantive process that together significantly contribute to the ability to create outputs. The acquired process is considered substantive if it is critical to the ability to continue producing outputs, and the inputs acquired include an organized workforce with the necessary skills, knowledge, or experience to perform that process or it significantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay in the ability to continue producing outputs.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

When Ecopetrol Business Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date.

Goodwill is initially measured at cost (being the excess of the aggregate of the consideration transferred and the amount recognized for non-controlling interests and any previous interest held over the net identifiable assets acquired and liabilities assumed). If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Ecopetrol Business Group re-assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognized at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognized in profit or loss.

After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of Ecopetrol Business Group’s cash-generating units that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Where goodwill has been allocated to a cash-generating unit (CGU) and part of the operation within that unit is disposed of, the goodwill associated with the disposed operation is included in the carrying amount of the operation when determining the gain or loss on disposal. Goodwill disposed in these circumstances is measured based on the relative values of the disposed operation and the portion of the cash-generating unit retained.

5.New standards and regulatory changes

5.1New standards adopted by Ecopetrol Business Group, effective as of January 1, 2022

Ecopetrol Business Group applied for the first-time certain standards and amendments, which are effective for annual periods beginning on or after January 1, 2022. It has not early adopted any other standards, interpretations or amendments that have been issued and not yet effective as of the date of this report:

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IAS 16 – Property, plant, and equipment: amendment that expresses the prohibition of deducting from the cost of property, plant, and equipment the value of sales of items produced, while the company prepares the asset for its intended use. As of January 1, 2022, Ecopetrol Business Group adopted for the first time the Amendment IAS 16 “Property, Plant and Equipment - Proceeds before intended use” in a mandatory manner, the nature and effects of these changes are mentioned below:

In May 2020, the International Accounting Standards Committee - IASB issued amendments to IAS 16 - Property, Plant and Equipment referring to the part of proceeds before intended use, in terms of:

The sales obtained from the elements produced during the installation and start-up process of the asset, that is, products obtained in the project stage or extensive tests, are recognized in the results of the period as revenue.

The costs associated with the production of products obtained in the project stage or extensive tests sold according to IAS 2 are also recognized in the result of the period.

The amount of revenue and costs related to the sale of products obtained in the project stage or extensive tests is disclosed in the notes to the consolidated financial statements, detailing in which items of the Financial Statement they are included.

In the oil and gas sector, this amendment has effects on the treatment of the sale to third parties of extensive oil field tests, which are sales of crude oil or gas from a well under development before entering the market in full production.

Retroactive application only affected for property, plant, and equipment, and natural and environmental resources accounts that were in the construction stage at the beginning of the earliest period presented in the consolidated financial statements in which the Ecopetrol Business Group adopted the standard, that is, on January 1, 2021. The impact of the adoption of this standard was as follows:

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

An increase of $48,173 (See Note 15) and $18,013 (See Note 14) in the Exploration and evaluation account within Natural and environmental resources and property, plant, and equipment balance sheet line items, respectively, with a corresponding increase in retained earnings.

An effect of $24,132 (See Note 10) due to the reversal of the deferred tax liability arising from the temporary difference between the tax basis and accounting basis prior to the adoption of the amendment and a corresponding effect in retained earnings.

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IAS 37 – Provisions, contingent assets, and liabilities: in which it details what costs an entity must include when determining whether a contract is onerous. The amendments apply a directly related cost approach. The costs that relate directly to a contract to provide goods or services include both incremental costs (e.g., the costs of direct labor and materials) and an allocation of costs directly related to contract activities (e.g., depreciation of equipment used to fulfil the contract as well as costs of contract management and supervision). General and administrative costs do not relate directly to a contract and are excluded unless they are explicitly chargeable to the counterparty under the contract. This amendment had no impact on the annual consolidated financial statements of Ecopetrol Business Group.

●

Cycle of annual improvements 2018 – 2020 involving adjustments to IFRS 1 - subsidiary as first-time adopter, IAS 41 - taxes on fair value measurements, IFRS 16 - lease incentives and IFRS 9 - charges in the 10% test for the derecognition of financial liabilities, which clarifies the charges that an entity includes when evaluating whether the terms of a new or modified financial liability are materially different from the terms of the original financial liability. This amendment had no impact on the annual consolidated financial statements of Ecopetrol Business Group.

New standards adopted by Ecopetrol Business Group, effective as of January 1, 2021 (Reform to the benchmark interest rate) and 2020 (Amendments to IFRS 3, IFRS 7, IFRS 9, IAS 39, IAS 1, IFRS 16 Covid-19, IAS 8 and revised conceptual framework for Financial Reporting), did not have a significant impact on the financial statements as of December 31, 2021, and 2020.

5.2 New standards issued but not yet adopted

The IASB issued amendments to the following standards, with an effective date on January 1, 2023, or later periods:

●

Amendment to IAS 1 - Classifications of liabilities as current or non-current, modifies the requirement to classify a liability as current, by establishing that a liability is classified as current when it does not have the right at the end of the reporting period to defer the liquidation of the liability during, at least, the twelve months following the date of the reporting period. This amendment will be effective as of January 1, 2023. On October 31, 2022, IASB published an amendment on non-current liabilities with agreed conditions and modified the effective date of January 2024.

●	Amendments to IAS 1 – Presentation of financial statements. Companies must disclose material information about their accounting policies and apply the concept of materiality to accounting policy disclosures. The amendments clarify the following points:

The word “significant” is changed to “material or relative importance”.

The accounting policies that must be disclosed in the notes to the financial statements are clarified, “an entity will disclose information about its material or relative importance accounting policies.”

It is clarified when an accounting policy is considered material or relatively important.

Adds the following paragraph: “Information on accounting policies that focuses on how an entity has applied the requirements of IFRS to its own circumstances provides specific information about the entity that is more useful to users of financial statements than standardized information or information that only doubles or summarizes the requirements of IFRS standards”.

●

Amendments to IAS 8 – Accounting Policies, Changes in Accounting Estimates and Errors. They clarify how companies should distinguish changes in accounting policies from changes in accounting estimates. The amendment was published by the IASB in February 2021 and clearly defines an accounting estimate to distinguish it from an accounting policy: “Accounting estimates are monetary amounts, in financial statements, that are subject to measurement uncertainty”.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

It mentions “an accounting policy could require that elements of the financial statements be measured in a way that entails measurement uncertainty—that is, the accounting policy could require that these elements be measured by monetary amounts that cannot be directly observed and they must be estimated. In this case, an entity develops an accounting estimate to achieve the objective established by the accounting policy.

●	Amendments to IAS 12 Deferred taxes related to assets and liabilities that are recognized in a single transaction. The purpose of the amendments is to reduce diversity in the reporting of deferred taxes on leases and decommissioning obligations.

The amendment allows the recognition of a deferred tax liability or asset that has arisen in a transaction that is not a business combination, in the initial recognition of an asset or liability that, at the time of the transaction, does not give rise to taxable temporary differences and deductibles in the same amount.

●

Modifications to IFRS 1: The amendment permits a subsidiary that elects to apply paragraph D16(a) of IFRS 1 to measure cumulative translation differences using the amounts reported in the parent’s consolidated financial statements, based on the parent’s date of transition to IFRS, if no adjustments were made for consolidation procedures and for the effects of the business combination in which the parent acquired the subsidiary. This amendment is also applied to an associate or joint venture that elects to apply paragraph D16(a) of IFRS 1.

●

IFRS 3 – Business combinations: in which they update a reference from the standard to the Conceptual Framework. The amendments add an exception to the recognition principle of IFRS 3 to avoid the issue of potential ‘day 2’ gains or losses arising for liabilities and contingent liabilities that would be within the scope of IAS 37 Provisions, Contingent Liabilities and Contingent Assets or IFRIC 21 Levies, if incurred separately. The exception requires entities to apply the criteria in IAS 37 or IFRIC 21, respectively, instead of the Conceptual Framework, to determine whether a present obligation exists at the acquisition date. At the same time, the amendments add a new paragraph to IFRS 3 to clarify that contingent assets do not qualify for recognition at the acquisition date.

●

Modifications to IFRS 9, IAS 39, and IFRS 7: Reform of reference interest rates. The amendments provide several exemptions that apply to all hedging relationships that are directly affected by the interest rate benchmark reform. A hedging relationship is affected if the reform gives rise to uncertainty about the timing and/or amount of the cash flows based on benchmarks of the hedged item or hedging instrument.

Although the standard has already entered into force, the companies have not made the changes in the current debt contracts and continue to apply the LIBOR rate for interest calculations since the 3 and 6-month LIBOR dollar reference rates will remain in effect until on June 30, 2023, according to the Financial Conduct Authority (FAC).

●

IFRS 17 - Insurance Contracts, 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. The standard’s general model requires that insurance contract liabilities be measured using current weighted probability estimates of future cash flows, a risk adjustment, and a contractual service margin that represents the expected gain from fulfilling the contracts. The effects of changes in the estimates of future cash flows and the risk adjustment related to future services are recognized during the period in which the services are rendered and not immediately in profit loss statement.

IFRS 17 replaces IFRS 4 - Insurance Contracts and will be effective for the subsidiaries Black Gold Re and Linear Systems Re Ltd for the financial reporting period beginning January 1, 2023. The standard has not yet been approved by Colombia and it is expected that in the course of 2023 it will be adopted by the country allowing Ecopetrol Business Group to adopt it in line with the international standard. The assessment of the impact of IFRS 17 is in an implementation phase and a significant effect on the Group’s consolidated financial statements is not expected given that most of the insurance contracts are short-term and would be managed by the PPA methodology - Simplified allocation of premiums.

6.Cash and cash equivalents

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	2022	2021
Banks	9,491,029	11,080,569
Short–term investments	5,907,785	3,467,859
Cash	2,244	1,478
	15,401,058	14,549,906

As of December 31, 2022, the balance of cash and cash equivalents includes 1) restricted cash flow of Interconexión Eléctrica S.A. E.S.P. for $1,987,409 ($1,039,024 as of December 31, 2021), based on financing contracts and maintained, mainly, to guarantee debt service and 2) restricted cash flow mainly of Oleoducto Bicentenario for $79,870 ($71,979 as of December 31, 2021). Both will be used in the next 12 months exclusively for the payment of principal and interest on loans.

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, 2022, was 8.5% (2021 – 2.6%).

The following table reflects the credit quality of banks in which Ecopetrol Business Group has deposits and check accounts, and issuers of investments included in cash and cash equivalents:


Rating	2022	2021
AAA	5,356,966	3,892,694
F1	1,458,524	1,177,581
A	919,903	1,224,990
A-2	749,912	—
A-1	731,424	1,294,164
AA	675,596	526,127
A3	647,316	3,049
BRC1+	606,052	2,172,603
A+	543,260	—
A-	477,059	—
F1+	466,031	2,383,713
BB	463,681	106,070
BBB	425,485	1,277,357
A2	197,917	—
A1	192,594	1,032
Baa1	93,157	—
B	16,753	14,674
Aaa	10,276	27,621
AAAmmf	5,508	—
Caa3	4,385	—
Ba1	3,083	—
BRC1	1,201	1,671
CCC	1,160	4,872
AAAf	714	19,481
P-2	—	370,582
Aa3	—	11,239
C	—	6,615
Other	1,353,101	33,771
	15,401,058	14,549,906

See credit risk policy in Note 30.7.

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Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

7.Trade and other receivables


	2022	2021
Current
Fuel Price stabilization fund (1)	26,296,870	7,824,788
Concessions (2)	5,194,909	3,370,644
Customers
Domestic	3,268,944	2,917,305
Foreign	3,065,207	3,222,837
Accounts receivable from employees	115,922	106,547
Related parties (Note 31)	110,408	9,355
Industrial services	70,762	32,096
Other	1,101,977	965,310
	39,224,999	18,448,882

Non–current
Concessions (2)	28,647,390	21,259,519
Customers
Foreign	185,331	36,965
Domestic	72,985	178,552
Accounts receivable from employees	498,415	534,051
Related parties (Note 31)	335	335
Other (3)	2,750,749	2,150,294
	32,155,205	24,159,716

(1)

Corresponds to the application of Resolution 180522 of March 29, 2010, and other regulations that modify and add it (Decree 1880 of 2014 and Decree 1068 of 2015), which establishes the procedure to recognize the subsidy for refiners and importers of motor gasoline current and ACPM, and the methodology for calculating the net position (value generated between the parity price and the regulated price, which can be positive or negative).

For 2022, the increase in accounts receivable was mainly generated by the increase in international reference indicators. During 2022, the Ministry of Finance and Public Credit paid COP$18,262,487 to the Ecopetrol Business Group as follows;

●

Payments to Reficar for $6,114,489 in cash and $719,834 through Colombian sovereign bonds - TES (this operation did not generate cash flows), corresponding to the liquidation of the second half of 2021 and the first, second, and third quarter of 2022, and,

●

Payments to Ecopetrol for $4,639,779 in cash and $6,788,385 through offsetting with dividends payable to the Ministry of Finance and Public Credit, this operation did not generate cash flows and its effect implies an increase in the variation in working capital in the cash flow statement of the Ecopetrol Business Group. The payment corresponds to the liquidation of the second half of 2021 and the first quarter of 2022.

The Ecopetrol Business Group and the National Government continue to work together and are committed to seeking alternatives to settle the balance as of December 31, 2022, during 2023.

(2)	Includes electric power transportation concessions and roads.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(3)

Corresponds mainly to accounts receivable from the Government of Brazil for employee benefits governed by Law 4819 of 1958 to ISA CTEEP, and crude loan agreements of the Business Group for transportation systems. The balance of these accounts receivable is $2,481,530 (2021: $1,772,101) and the related provision for expected losses established, included in the provision line for expected credit losses, is $475,936 (2021: $368,299), representing a net book value of $2,005,594 (2021: $1,403,802). The administration monitors the progress and developments related to the legal aspect of the matter and continuously evaluates the possible impacts on its consolidated financial statements.

The book value of trade and other receivables approximates their fair value.

The changes in the allowance for doubtful accounts for the year ended December 31, 2022, 2021 and 2020 are as follows:


	2022	2021	2020
Opening balance	(750,191)	(291,144)	(282,791)
Additions (reversal), net	(46,690)	2,665	(15,082)
Effect of business combination	—	(474,654)	—
Effect of change of control in subsidiaries	—	—	5,517
Currency translation	(131,270)	4,794	(1,271)
Accounts receivable write–off and uses	22,033	8,148	2,483
Closing balance	(906,118)	(750,191)	(291,144)

8.Inventories

The inventories balance is presented net of the allowance for inventory losses.


	2022	2021
Crude oil (1)	5,971,109	3,305,965
Fuels and petrochemicals (2)	3,241,154	2,845,486
Materials for goods production	2,667,771	2,246,761
	11,880,034	8,398,212

(1)

The variation is mainly due to a higher level of inventories in transit and connected for delivery in January 2023, and recovery of indicators (Brent reference).

(2)

The variation is mainly due to the receipt of fuel imports to accomplish with the national demand for fuels.

The following are the changes of the allowances for losses for the years ended December 31, 2022, 2021 and 2020:


	2022	2021	2020
Opening balance	(127,662)	(109,549)	(131,526)
Additions	(18,236)	(58,437)	(9,748)
Increase due to business combination	—	(2,837)	—
Foreign currency translation	(3,591)	(1,449)	(122)
Effect of change of control in subsidiaries	—	—	20,075
Other (1)	20,692	44,610	11,772
Closing balance	(128,797)	(127,662)	(109,549)

(1)

It mainly includes uses.

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. The amount recorded for this in 2022 was $133,164 (2021 - $23,785; 2020 - $9,017).

9.Other financial assets

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	2022	2021
Assets measured at fair value
Investment Portfolio – Foreign currency	1,056,385	1,172,718
Investments in equity securities and trust funds (1)	875,335	606,624
Investment Portfolio – Local currency	761,687	759,892
Assets measured at fair value through other comprehensive income	3,583	2,789
Hedging instruments (2)	311	17,449
	2,697,301	2,559,472
Assets measured at amortized cost (3)	28,570	375,262
	2,725,871	2,934,734

Current	1,162,127	1,627,150
Non–current	1,563,744	1,307,584
	2,725,871	2,934,734

(1)

They include deposits in trusts companies and restricted funds in Brazil, Peru, Chile, and Colombia.

(2)

As of December 31, 2022, corresponds to swap contracts to hedge commodity price risk and forwards contracts to hedge exchange rate risk.

(3)

Includes investments with maturities greater than 90 days, in Chile and Colombia.

The average return of the investment portfolio in Colombian pesos (local currency) and U.S. dollars (foreign currency) were 4.3% (2021 – 2.23%) and 13.11% (2021 – 0.1%), respectively.

Changes in fair value are recognized in financial results (Note 29).

9.1Restrictions

As of December 31, 2022 and 2021, there were restricted funds for $328,283 and $138,688 respectively, which have specific destinations for projects in Brazil, Peru, Chile, and Colombia.

9.2Maturity


	2022	2021
Up to 1 year	1,162,127	1,627,150
1 – 2 years	673,169	434,372
2 – 5 years	452,417	786,760
> 5 years	438,158	86,452
	2,725,871	2,934,734

9.3Fair value

The following is the balance of other financial assets by fair value hierarchy level as of December 31, 2022, and 2021:


	2022	2021
Level 1	1,892,486	834,057
Level 2	804,815	1,725,415
	2,697,301	2,559,472

There were no transfers between hierarchy levels for the years ended December 31, 2022, and 2021.

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Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

9.4Credit rating

The following table reflects the credit quality of the issuers of other financial assets:


	2022	2021
BB	1,051,042	7,412
BB+	898,072	954,212
Ba1	388,743	—
AAA	40,369	1,158,794
Ba2	16,227	—
A	14,702	12,204
A3	9,918	—
F3	4,457	8,990
BBB	4,153	7,112
F1+	29	319,253
B	—	158,814
A-1	—	119,461
BRC1+	—	75,068
A+	—	42,821
AA+	—	6,075
Other	298,159	64,518
	2,725,871	2,934,734

See credit risk policy in Note 30.7.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

10.Taxes

10.1Current and non-current tax assets and liabilities


	2022	2021
Current tax assets
Income tax (1)	279,457	1,739,542
VAT refund (2)	4,725,281	3,108,175
Other taxes (3)	1,779,654	1,426,085
	6,784,392	6,273,802
Non-current tax assets
Deferred tax assets (4)	13,392,480	9,024,858
Income tax credits	8,570	5,274
	13,401,050	9,030,132

Current tax liabilities
Income tax payable (5)	6,617,468	1,298,524
Industry and commerce tax (6)	346,958	247,966
Value added tax	206,341	157,452
National tax and surcharge on gasoline	181,490	192,665
Carbon tax	77,721	66,006
Other taxes (7)	200,923	189,491
	7,630,901	2,152,104

Non-current tax liabilities
Deferred tax liabilities (8)	13,479,336	10,850,463
Income tax payable	90,897	65,130
Income tax (9)	1,705,411	1,208,927
	15,275,644	12,124,520

(1)	The variation corresponds mainly to the use of the balance in favor of the 2021 income tax return, of Ecopetrol S.A.

(2)

It corresponds mainly to the balance in favor of the value added tax (VAT) in Ecopetrol S.A. for $4,165,563, Esenttia S.A. for $252,977, ISA Group for $189,538, and other companies for $50,305, among others, and a favorable balance in the industry and commerce tax in Ecopetrol S.A. for $57,543, and Cenit for $8,887, and other companies for $468.

(3)	It includes the potential tax credit of the VAT paid in the acquisition of real productive fixed assets, in accordance with the section 258-1 of the Colombia Tax Code. Additionally, it includes advances and self-withholdings of territorial taxes.

(4)	Mainly corresponds to the loans payable in dollar of Ecopetrol Business Group, that increased due to the currency devaluation in 2022 (21%), and the increase in debt levels.

(5)

The increase between the prior year mainly corresponds to the better results obtained in the year by Ecopetrol S.A., due to the growth of revenue given the increase in the average prices of the basket of crude oil, natural gas, and products, and the higher revenue obtained by the midstream segment, and the increase in the tax rate (35% in 2022 vs. 31% in 2021), among others.

(6)	The increase between the prior year mainly corresponds to the higher income obtained by Ecopetrol Business Group.

(7)	The variation mainly corresponds to the increase in royalties’ payments, transport tax, among others, due to the improved results in the fiscal year 2022.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(8)

The variation mainly corresponds to the temporary differences related to IAS 12.41 and the deferred tax of ISA, represented by the changes related to the contractual asset CPC 47 and the deferral of income in accordance with Law 12,973/2014 in Companhia de Transmissao de Energia Eletrica Paulista (CTEEP), the application of additional depreciation shifts, effect of the exchange difference of international bonds and actuarial liabilities in ISA and among others.

(9)	Mainly corresponds to the contributions payable by the ISA group of PIS, CONFIS of CTEEP and subsidiaries located in Brazil.

10.2Income tax

In accordance with Law 2010/2019 and Law 2155/2021, the tax provisions applicable in Colombia for taxable years 2021 and 2022, are the following:

●

The income tax rate applicable to national companies and foreign entities will be 31% for the year 2021 and 35% for the fiscal year 2022. Law 2155 of 2021 increased the income tax rate from 31% to 35% from the year 2022.

●

For the year 2021, the presumptive income rate was 0% of the taxpayer's net equity from the immediately 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 will continue to be 15% during the term of said contract. This is the case of Refinería de Cartagena S.A.S. (“Reficar”) until 2023 and Esenttia Masterbatch Ltda. ("Esenttia MB") until 2028.

●

For fiscal years 2021 and 2022, Ecopetrol Business Group had subsidiaries that were subject to a 31% and 35%, respectively, income tax rate, subsidiaries located in free trade zones that were subject to a 15% income tax rate depending upon whether they complied with the Legal Stability Contract (LSA) rules and other subsidiaries in Brazil, Chile, Perú, USA, that were subject to 34%, 27%, 29.5%, 21%, respectively, and other companies that were subject to statutory income tax rates applicable in countries where they are incorporated.

●

The tax depreciation percentages are adjusted based on the table established in Article 137 of the Colombian Tax Code. On the other hand, oil investments amortization 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, exploratory drilling, among others, are capitalizable until the technical feasibility and commercial viability of extracting the resource are determined.

●

The cost of acquisition of exploration rights, geology and geophysics (G&G), exploratory drilling, among others, is capitalized for tax purposes until the technical and commercial feasibilities of extracting the resource are achieved.

●

Variations 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 have signed a legal stability contract, and included within it the article that they contemplated that tax losses did not have an expiration date.

Related to income tax in other countries in which the Business Group operates, the following are the main aspects to consider:

Peru

●

Current income tax rate is 29.5% on the taxable income after deducting the employes participation, which is calculated with a rate of 5% or 10% on the taxable income.

●

Dividends and other forms of profit distribution are subject 5% income tax rate.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

●

From 2021, the financial expenses deduction is limited to 30% of tax Ebitda.

●

Intra-group services deduction is allowed for low value-added services to the extent that the deductible amount does not exceed expenses and costs plus a 5% margin.

Brazil

●

Legal entities income tax and Social Contribution on Liquid Profits are federal taxes that affect the income of the legal entity in its real or presumed profit.

●

Real profit: Tax is determined based on the results for each period, establishing the taxable base considering the accounting profit and performing the depurations determined in tax legislation. All income and returns on capital are included in the calculation base. The 34% rate is applied to the taxable base of liquid profit.

●

Presumed profit: it is a simplified form taxation for the calculation base. Applies to legal entities that have gross income up to BRL $78 million in the immediately preceding year. In this system, the tax base is determined by applying the rate of 8%, 12% or 32% to gross income (the rate to be applied depends on the activity carried out by the taxpayer) and the rate of 34% is applied to the result.

Statute of limitations of tax returns

In Colombia, the income tax returns of the taxable years 2011, 2014, 2015, 2016, 2017, 2018, 2019, 2020 and 2021 and income tax for equality - CREE - of the taxable years 2014, 2015, and 2016 can still be reviewed by the tax authorities. The management of Ecopetrol Business 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. Returns filed by taxpayers that have made transactions, subject to the transfer pricing regulations, have a five-year (5) statute of limitations, for the tax returns that are filed as of January 1, 2020. For the other countries where there are subsidiaries of the Ecopetrol Business Group, the statute of limitations time will depend on the local regulations in each country.

Income tax expense


	2022	2021	2020
Current income tax (1)	16,791,619	6,975,549	2,861,606
Deferred income tax (2)	2,813,817	1,939,567	(791,824)
Deferred income tax – rate change (3)	(658,919)	(28,993)	—
Adjustments to prior years’ current and deferred tax(4)	17,421	(90,860)	(31,121)
Income tax expenses	18,963,938	8,795,263	2,038,661

(1)

The increase between 2022 and 2021 by $9,816,070 corresponds mainly to the better results obtained in the year in Ecopetrol S.A., generated by the growth of revenue given the increase in the average prices of the crude basket oil, natural gas, and products, and the higher revenue obtained by the midstream segment, and the increase in the tax rate (35% in 2022 vs. 31% in 2021), among others.

(2)

The variation between 2022 and 2021 by $874,250 corresponds mainly to the effect of the exchange rate on loans denominated in foreign currencies of Ecopetrol S.A. and Refinería de Cartagena, to the adjustment of the calculation of deferred tax for capital gains, from 10% to 15%, associated with the disinvestment of the share of Ecopetrol S.A. in the opportunity called Roger project, among others.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(3)	The variation between 2022 and 2021 by ($656,926) corresponds mainly to the effect of the Law 2277 of 2022, that established an additional point on the income tax rate of 5%, 10%, or 15% as of the year 2023 and following years.

(4)	The variation between 2022 and 2021 by $108,281 corresponds mainly to the difference between the provision and the income tax return for fiscal year 2021 filed in 2022.

Reconciliation of the income tax expenses

The reconciliation between the income tax expense and the current tax applicable to the Ecopetrol Business Group is as follows:


	2022		2021		2020
Net income before income tax	54,163,418		26,425,817		4,776,514
Statutory rate (Colombia)	35.0	%	31.0	%	32.0	%
Income tax at statutory rate	18,957,196		8,192,003		1,528,484
Effective tax rate reconciliation items:
Adjustment - IAS 12.41	1,946,269		1,194,065		247,358
Non–deductible expenses	448,433		387,407		29,649
Reversal of deferred tax recognized in prior years	—		—		245,508
Rate differential adjustment	(670,080)		(304,176)		14,974
Non–taxable income	(739,243)		(517,483)		(35,471)
Prior years’ taxes	17,421		(90,860)		(31,121)
Foreign currency translation and exchange difference	(82,028)		(149,035)		59,852
Tax discounts and tax credit	(184,054)		(173,154)		(20,572)
Others	(71,057)		285,489		—
Effect of tax reform	(658,919)		(28,993)		—
Income tax calculated	18,963,938		8,795,263		2,038,661
Effective tax rate	35.0	%	33.3	%	42.7	%
Current	16,801,363		6,940,660		2,583,832
Deferred	2,162,575		1,854,603		(545,171)
	18,963,938		8,795,263		2,038,661

The effective tax rate as of December 31, 2022 is 35.0% (2021 – 33.3%); The variation of 1.7% compared to the previous period is mainly due to: a) the profit increase, b) the effect of the companies of the Group with profit that have a nominal tax rate different from the parent company (Refineria de Cartagena - $476,772, Ecopetrol Capital AG - $71,563, Esenttia MB - $67,942, Ecopetrol USA - $168,374, Ecopetrol Permian - $243,809 and others - $133,178), c) to the effect of the Law 2277 of 2022, that established an additional point on the income tax rate of 5%, 10%, or 15% as of the year 2023 and following years in Ecopetrol S.A. and Hocol, d) the greater distribution of capital pledges in Companhia de Transmissão de Energía Elétrica Paulista (CTEEP), e) the effect of the incorporating ISA in Ecopetrol Business Group and f) the update of the occasional profit tax associated with the divestment of Ecopetrol S.A. share in the opportunity called the Roger project, among others.

Deferred income tax


	2022	2021
Deferred tax assets (1)	13,392,480	9,024,858
Deferred tax liabilities (2)	(13,479,336)	(10,850,463)
Net deferred income tax	(86,856)	(1,825,605)

(1)	Mainly corresponds to the loans payable in dollar of Ecopetrol Business Group, that increased due to the currency devaluation in 2022 (21%), and the increase in debt levels of the Business Group.

(2)	The variation mainly corresponds to the deferred tax of ISA, represented by the deferral of income and the application of accelerated depreciation amounts in Companhia de Transmissao de Energia Eletrica Paulista (CTEEP).

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The detail of deferred tax assets and liabilities is as follows:


	2022	2021
Deferred tax assets (liabilities)
Loans(1)	8,707,743	3,385,388
Loss carry forwards (2)	6,497,845	6,122,243
Provisions (3)	3,712,239	4,029,550
Employee benefits (4)	963,558	1,378,161
Accounts payable	54,611	13,774
Presumptive income tax excesses (5)	—	180,563
Goodwill (6)	(604,350)	(405,973)
Other (7)	(3,499,216)	(3,050,013)
Accounts receivable (8)	(4,558,699)	(4,029,534)
Property plant and equipment and Natural and environmental resources (9)	(11,360,587)	(9,449,764)
	(86,856)	(1,825,605)

(1)	Corresponds mainly to the effect in the foreign exchange rate (21%) in the fiscal year 2022 and the increase in debt levels of the Business Group.

(2)	In 2022, a deferred tax asset for tax losses carryforwards was recognized for $6,497,845 (2021 - $6,122,243) in the following companies:

Tax losses that do not expire: Ecopetrol USA for $339,950 (2021 - $765,914); Refinería de Cartagena for $1,871,732 (2021 - $2,027,433); and ISA Group companies in Chile for $35,806 (2021 - $20,818).

Tax losses that expire in 12 years in Invercolsa for $17,524 (2021 - $14,626).

Tax losses that expire in 20 years from the date they were recognized by Ecopetrol USA Inc. for $1,887,805 (2021 - $1,591,781).

Tax losses expiring in 2025 of Ruta de la Araucanía and Transamerican for $111,273 (2021 - $137,289); 2027, Ruta Costera for $84,964 (2021 - $17,953); 2030 from Internexa Chile for $16,062 (2021 - $12,931); 2029 of Ruta del Maipó for $1,000,632 (2021 - $763,272); 2040 from ISA Interchile for $1,104,625 (2021 - $756,410); and 2044 Ruta del Loa for $27,472 (2021 - $13,816).

(3)Corresponds to non-deductible accounting provisions, mainly the asset retirement obligation (ARO) provision.

(4)	Corresponds to update of the actuarial calculations for health, pensions and bonds, education, and other long-term benefits to employee.

(5)	In 2021, Refineria de Cartagena recognized deferred tax assets by COP$180,563

(6)

According to Colombian tax law until the fiscal year 2016, goodwill was subject to amortization for fiscal proposes, while under IFRS it is only allowed to be subject to impairment tests, a difference that results in a deferred tax liability, variances related to translation adjustment from the year.

(7)

The variation corresponds mainly to: a) the balance of regulatory security works and payment of pre-existing infrastructure of the concessionaires in Chile and in Companhia de Transmissão de Energía Elétrica Paulista (CTEEP) for the provision associated with law 4819 pension benefits, b) the total deferred tax liability of ISA's consolidated, mainly in Ruta del Maipo due to the readjustment of the financial asset and c) the effect of business combination (ISA).

(8)	The variation mainly corresponds to the deferred tax of ISA, represented by the deferral of income and the application of accelerated depreciation amounts in Companhia de Transmissao de Energia Eletrica Paulista (CTEEP).

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(9)

For tax purposes, natural and environmental resources, and property, plant, and equipment have a useful life and a depreciation and amortization methodology different from those determined under international accounting standards, mainly in ISA Colombia and Transmantaro considering their accelerated depreciation in 2022.

Each legal entity of the Ecopetrol Business 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 jurisdictions and tax authorities.

The movements of deferred income tax for the years as of December 31, 2022, 2021 and 2020 are as follows:


	2022	2021	2020
Opening balance	(1,825,605)	6,034,706	5,480,516
Deferred tax recognized in profit or loss	(2,162,575)	(1,854,603)	545,171
Increase due to business combination	96,767	(7,877,297)	(383,346)
Deferred tax recognized in other comprehensive income (a)	4,769,474	1,535,151	89,526
Other	(24,132)	(35,033)	—
Foreign currency translation	(940,785)	371,471	302,839
Closing balance	(86,856)	(1,825,605)	6,034,706

(a)The following is the detail of the income tax recorded in other comprehensive income:


December 31. 2022	Pre–tax	Deferred tax	After tax
Actuarial valuation gains (losses) (Note 22.1)	1,254,514	(586,260)	668,254
Cash flow hedging for future crude oil exports (Note 30.3)	3,167,351	(1,638,602)	1,528,749
Hedge of a net investment in a foreign operation (Note 30.4)	7,526,124	(2,538,389)	4,987,735
Hedge with derivative instruments	(111,690)	(6,223)	(117,913)
	11,836,299	(4,769,474)	7,066,825


December 31. 2021	Pre–tax	Deferred tax	After tax
Actuarial valuation gains (losses) (Note 22.1)	(2,456,667)	679,510	(1,777,157)
Cash flow hedging for future crude oil exports (Note 30.3)	1,259,269	(450,492)	808,777
Hedge of a net investment in a foreign operation (Note 30.4)	4,579,758	(1,708,348)	2,871,410
Hedge with derivative instruments	191,487	(55,821)	135,666
	3,573,847	(1,535,151)	2,038,696


December 31. 2020	Pre-tax	Deferred tax	After tax
Actuarial valuation gains (losses) (Note 22.1)	(137,459)	41,238	(96,221)
Cash flow hedging for future crude oil exports (Note 30.3)	(1,186)	1,908	722
Hedge of a net investment in a foreign operation (Note 30.4)	520,490	(156,147)	364,343
Hedge with derivative instruments	(78,547)	23,475	(55,072)
	303,298	(89,526)	213,772

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Deferred tax assets not recognized

Deferred tax assets related to tax loss carryforwards incurred by the subsidiaries of ISA Group: Ruta del Bosque (Chile) for $102,864 (2021 – $35,511), Ruta del Maule (Chile) for $43,702 (2021 - $27,404), ISA Inversiones Chile Ltda for $84,816, Ruta Costera (Colombia) for $391 (2021 - $932), ISA Intervial Colombia for $564 (2021 - 541), Proyecto de Infrastructura del Perú for $1,143, ISA Capital do Brasil for $20,216 (2021 - $15,983), ISA Investimentos Brasil for $883, Internexa Brasil Operadora de Telecomunicações for $101,525 (2021 - $69,358), Internexa Participações (Brasil) for $2,913 (2021 – 2,121) and ISA Bolivia for $4,142 (2021 – 1,831), 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 the short term.

If Ecopetrol Business Group had been able to recognize the unrecognized deferred tax asset, the profit for the year ended December 31, 2022, would have increased by $363,158 ($153,681).

With respect to the additional income surtax, deferred tax assets corresponding to the estimated surcharge for the years 2026 and following are not recognized because there is no certainty about the proportion of the deferred that will be recovered in each of these years.

Deferred tax liabilities not recognized

As of December 31, 2022, in connection with paragraph 39 of IAS 12 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. (Base: $-25,966,564 Tax: $-3,894,985) and other group companies (Base: $-8,891,965 Tax: $-1,333,795).

Dividends received in the year 2022 were untaxed. The Company expects this same treatment for the dividends it receives in 2023.

Uncertain tax positions - IFRIC 23

Ecopetrol Business 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 Business Group considers that uncertain tax positions include 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 Business Group will continue to monitor new tax regulations and ruling issued by the tax authority and other entities.

10.3.Other taxes

Dividend taxes

Starting on 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 7.5% (10% as of 2023, 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 7.5% withholding will apply to the value of the dividend once decreased with the income tax (35% for the year 2022).

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The non-taxed dividends that the Ecopetrol Business 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.

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.

Ecopetrol Business Group submitted in 2022 the transfer pricing information for 2021 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 2022, 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 2021 will be required, which imply changes in the income provision of the same year.

Law 2010 of December 27, 2019 - Colombia

In October 2019 the Constitutional Court declared Law 1943 of 2018 (Tax Reform of 2018) due to procedural defects in its approval in Congress. The Court said that the effect of its pronouncement would be applicable as of January 1, 2020, therefore Law 1943 was applicable in its entirety until December 31, 2019. The Constitutional Court granted the executive the possibility of presenting a new legislative project for the 2020 period, as a result, the Government presented a bill that was sanctioned and materialized in Law 2010 of December 27, 2019. In general terms, specific modifications were presented, such as the following:

Income tax rate applicable for taxable year 2020 and following years:


Year	General Rate*
2020	32	%
2021	31	%

(*) Applicable rate for Colombian companies, permanent establishments, and foreign entities.

The undercapitalization rule contained in article 118-1 of Colombia Tax Code, had been modified by Law 1943/2018. In this sense, as of 2019, the undercapitalization rule will only be applicable with respect to interest generated in the acquisition of debts contracted, directly or indirectly, with national or foreign economic associates. Likewise, the capital-debt ratio was modified to 2:1 (previously it was 3:1) with which not only may interest generated on debts acquired with related parties be deducted when the average total amount of such debts does not exceed two (2) times the net worth of the taxpayer determined as of December 31 of the immediately preceding taxable year.

Value Added Tax

The VAT already paid by the user of the free zone are 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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 compensation of tax losses, and (v) the term of the finality will be 5 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 ($24). 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.

Law 2155 of September 14, 2021 - Colombia

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 2022 was 30% and the discount of the Industry and Commerce Tax was 100%.

Audit benefit: For the fiscal years 2022 and 2023, this Law reduce 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).

Tax reform Law 2277 of December 13, 2022

The most relevant aspects of this reform in the Business Group’s taxes.

Additional rate to the income tax rate: An additional rate is established for those companies that carry out the activity 0610 – Crude oil extraction.

An additional rate will be calculated taking as a 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 at constant values. On these, the percentiles that give rise to the surcharge rate are determined as indicated below:

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

< percentile 30	0%
> = percentile 30 and < percentile 45	5%
> = percentile 45 and < percentile 60	10%
> = percentile 60	15%

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.

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.

Effective head office of management: It will be understood that the effective headquarters of management of a company or entity is the place where the commercial and management decisions necessary to carry out the activities of the company or entity are materially made on a day-to-day basis, that is, the places where the administrators of the company usually execute their responsibilities and the daily activities.

Research, technological development, or innovation investment discount: Investments in projects qualified by the National Council of Tax Benefits in Science and Technology in Innovation in Colombia will have the right to discount 30% of the value invested in said income tax projects in the taxable period 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 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.

11.Other assets

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	2022	2021
Current
Partners in joint operations	871,409	639,199
Prepaid expenses	693,341	549,456
Advanced payments to contractors and suppliers	679,829	591,990
Trust funds	507,163	527,520
Related parties (Note 31)	1,087	1,386
Other assets	25,651	23,540
	2,778,480	2,333,091
Non–current
Abandonment and pension funds	568,066	461,729
Employee benefits	342,143	229,969
Trust funds	184,464	176,781
Advanced payments and deposits	87,684	92,815
Judicial deposits and attachments	54,776	48,845
Other assets	216,214	188,224
	1,453,347	1,198,363

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

12.Business combinations

On August 20, 2021, the closing conditions of the Inter-Administrative Agreement signed on August 11 between Ecopetrol S.A. and the Ministry of Finance and Public Credit (“MHCP”) for the acquisition of 569,472,561 shares of Interconexión Eléctrica S.A. ESP (“ISA”) equivalent to 51.4% of the outstanding shares of this company and representing 100% of the ownership of the MHCP in said company were satisfactorily fulfilled.

Considering the final purchase price allocation on August 31, 2022, the fair value of the identifiable assets and liabilities of ISA as at the date of acquisition were:


		Fair Value
Assets
Cash and cash equivalents		4,983,234
Accounts receivable		27,487,774
Inventories		120,300
Other financial assets		1,093,941
Current tax assets		477,504
Other assets		682,445
Investments in subsidiaries and joint ventures		5,014,749
Properties, plant, and equipment		17,486,901
Right of use assets		230,207
Intangibles		13,903,491
Deferred tax assets		2,075,849
Total assets		73,556,395
Liabilities
Loans		27,203,432
Leases		255,503
Accounts payable		1,358,692
Employee Benefits		973,210
Tax liabilities		1,897,786
Provisions and contingencies		947,883
Other liabilities		1,708,349
Deferred tax liabilities		9,856,379
Total liabilities		44,201,234
Total identifiable net assets		29,355,161

Non-controlling interest		(18,734,241)
Goodwill derived from the acquisition		3,279,916
Consideration transferred		13,900,836

The net assets recognized in the consolidated financial statements as of December 31, 2021, were based on a provisional assessment of their fair value and could be adjusted in case of obtaining new information as referred to in paragraph 46 of IFRS 3. The valuation was not completed as of the date of approval of the 2021 financial statements by the Company’s Management.

In August 2022, the valuation was completed, considering the new information obtained to the acquisition date, and the fair value of the properties, plant, and equipment was $17,486,901, and intangibles $13,903,491, which presented a decrease of $153,557, and $422,988, respectively, over the provisional value. Those adjustments were not material thus the financial information as of December 2021 was not restated. As a result, there was a decrease in the deferred tax liability of $96,767 and a decrease in the non-controlling interest of $238,839. There was also a corresponding increase in goodwill of $240,939, resulting in $3,279,916 of total goodwill arising on the acquisition. The increased depreciation charge on the property, plant, and equipment, from the acquisition date to 31 December 2021 was also not material.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

From the date of acquisition, ISA contributed $4,113,198 of revenue and $1,108,202 (including non-controlling interest for $846,454) to net profit from continuing operations of the Group. If the combination had taken place at the beginning of 2021, the Group’s revenue from continuing operations would have been higher by $7,039,487, and the profit before tax from continuing operations would have been $2,096,511 (including non-controlling interest for $1,501,984). The goodwill of $3,279,916 comprises the fair value of expected synergies arising from acquisition.

13.Investments in associates and joint ventures

13.1Composition and movements


	2022	2021
Joint ventures
Interligação Elétrica do Madeira S.A.	1,871,142	1,374,483
Transmissora Aliança de Energia Elétrica S.A.	1,830,504	1,496,060
Equion Energía Limited	1,191,154	1,860,634
Interligação Elétrica Paraguaçu S.A.	614,112	412,526
Interligação Elétrica Garanhuns S.A.	571,328	363,498
Interligação Elétrica Ivaí S.A.	469,176	288,224
Interligação Elétrica Aimorés S.A.	411,495	278,408
Conexión Kimal Lo Aguirre S.A. (1)	169,230	—
Ecodiesel Colombia S.A.	54,614	64,019
Interconexión Eléctrica Colombia Panamá S.A.	20,516	8,737
Transnexa S.A. E.M.A.	8,545	8,545
Derivex S.A.	439	448
Parques de Rio	83	93
Interconexión Eléctrica Colombia Panamá S.A.S E.S.P.	4	4
	7,212,342	6,155,679
Less impairment:
Equion Energía Limited	(400,196)	(398,104)
Transnexa S.A. E.M.A.	(8,545)	(8,545)
	6,803,601	5,749,030
Associates
Gases del Caribe S.A. E.S.P.	1,495,341	1,515,838
ATP Tower Holdings	913,218	813,697
Gas Natural del Oriente S.A. E.S.P.	148,254	142,508
Gases de la Guajira S.A. E.S.P.	69,376	69,461
E2 Energía Eficiente S.A. E.S.P.	34,944	35,062
Extrucol S.A.	27,680	28,578
Serviport S.A.	9,399	9,399
Sociedad Portuaria Olefinas	4,186	3,012
	2,702,398	2,617,555
Less impairment: Serviport S.A.	(9,399)	(9,399)
	2,692,999	2,608,156
	9,496,600	8,357,186

(1)	In July 2022, ISA Inversiones Chile incorporated the company Conexion Kimal Lo Aguirre S.A. together with Transelec and China Southern Power Grid International (CSG). This company will build and operate the Kimal-Lo Aguirre project in Chile awarded in 2021.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following is the movement of investments in associates and joint ventures:

For the year ended December 31, 2022:


	Associates	Joint ventures	Total
Opening balance	2,608,156	5,749,030	8,357,186
Capital contributions	—	329,377	329,377
Effects of equity method through:
Profit or loss	126,329	642,093	768,422
Other comprehensive income	149,165	1,450,948	1,600,113
Dividends declared (1)	(190,651)	(1,365,755)	(1,556,406)
Impairment (Note 18)	—	(2,092)	(2,092)
Closing balance	2,692,999	6,803,601	9,496,600

(1)

During 2022, Ecopetrol Business Group received dividends of $1,471,134 from its investments Transmissora Aliança de Energia Elétrica S.A., Interligação Elétrica do Madeira S.A., Gas Natural del Oriente S.A. E.S.P, Gases del Caribe S.A. E.S.P., Extrucol S.A., Gases de la Guajira S.A. E.S.P. and E2 Energía Eficiente S.A. E.S.P.

For the year ended December 31, 2021:


	Associates	Joint ventures	Total
Opening balance	1,791,249	1,383,379	3,174,628
Capital contributions	—	44,735	44,735
Business combination (Note 12)	783,494	4,231,255	5,014,749
Effects of equity method through:
Profit or loss	193,367	232,797	426,164
Other comprehensive income	12,142	121,856	133,998
Dividends declared (1)	(171,238)	(177,870)	(349,108)
Impairment (Note 18)	(858)	(83,644)	(84,502)
Foreign currency translation	—	(3,478)	(3,478)
Closing balance	2,608,156	5,749,030	8,357,186

(1)

During 2021, the Group received dividends of $206,048 from Ecodiesel, Transmissora Aliança de Energia Elétrica S.A., Interligação Elétrica do Madeira S.A., Gas Natural del Oriente S.A. E.S.P, Gases del Caribe S.A. E.S.P., Extrucol S.A., Gases de la Guajira S.A. E.S.P. and E2 Energía Eficiente S.A. E.S.P.

For the year ended December 31, 2020:


	Associates	Joint ventures	Total
Opening balance	1,826,757	1,418,315	3,245,072
Effects of equity method through:
Profit or loss	114,779	(38,443)	76,336
Other comprehensive income	(2,923)	—	(2,923)
Dividends declared (1)	(148,665)	(9,017)	(157,682)
Impairment reversal (loss) (Note 18)	2,529	(69,041)	(66,512)
Foreign currency translation	(1,228)	81,565	80,337
Closing balance	1,791,249	1,383,379	3,174,628

(1)

During 2020, the Group received dividends of $157,241 from its investments.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

13.2Additional 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, 2021, and 2020:

2022

2021

Interligação

Transmissora

Equion

Interligação

Transmissora

Equion

Elétrica do

Aliança de

Energía

Elétrica do

Aliança de

Energía

Madeira

Energia Elétrica

Limited

Madeira

Energia Elétrica

Limited

Statement of financial position

Current assets

689,613

1,967,310

1,684,029

593,389

1,233,296

3,054,020

Non–current assets

5,890,932

12,351,913

27,943

4,432,664

8,985,539

3,850

Total assets

6,580,545

14,319,223

1,711,972

5,026,053

10,218,835

3,057,870

Current liabilities

376,203

753,445

41,336

325,049

711,592

62,157

Non–current liabilities

2,765,355

7,474,497

31,372

2,196,231

4,633,422

35,316

Total liabilities

3,141,558

8,227,942

72,708

2,521,280

5,345,014

97,473

Equity

3,438,987

6,091,281

1,639,264

2,504,773

4,873,821

2,960,397

Other complementary information

Cash and cash equivalents

200,091

700,313

52,370

207,703

128,256

106,858


	2022			2021
	Interligação	Transmissora	Equion	Interligação	Transmissora	Equion
	Elétrica do	Aliança de	Energía	Elétrica do	Aliança de	Energía
	Madeira	Energia Elétrica	Limited	Madeira	Energia Elétrica	Limited
Statement of profit or loss
Sales revenue	603,362	2,598,283	4,263	639,356	2,953,672	63,169
Costs	(20,098)	(410,106)	(23,726)	(18,021)	(450,666)	(45,201)
Other operating income (expenses), net	—	(198,835)	(945)	—	(117,526)	(8,553)
Financial (expenses) income	(88,991)	(606,837)	48,040	(129,094)	(562,549)	65,611
Income tax (expense)	(106,292)	(129,531)	23,151	(112,574)	(285,702)	(22,091)
Financial year results	387,981	1,252,974	50,783	379,667	1,537,229	52,935
Other comprehensive results	—	8,565	1,144,801	—	15,599	1,632,400
Other complementary information
Depreciation and amortization	881	20,551	47	3,708	15,076	399

This is a reconciliation of equity of the significant investments and the carrying amount of investments as of December 31:


	2022						2021
	Interligação		Transmissora		Equion		Interligação		Transmissora		Equion
	Elétrica do		Aliança de		Energía		Elétrica do		Aliança de		Energía
	Madeira		Energia Elétrica		Limited		Madeira		Energia Elétrica		Limited
Equity of the joint venture	3,438,987		6,091,281		1,639,264		2,504,773		4,873,821		2,960,397
% of Ecopetrol’s ownership	51	%	14.88	%	51	%	51	%	14.88	%	51	%
Ecopetrol’s ownership	1,753,883		906,382		836,025		1,277,434		725,185		1,509,802
Additional value of the investment	—		230,828		375,694		—		197,070		375,694
Impairment	—		—		(400,196)		—		—		(398,104)
Unrealized gain	—		—		(20,565)		—		—		(24,862)
Carrying amount of the investment	1,753,883		1,137,210		790,958		1,277,434		922,255		1,462,530

The information on assets, liabilities, and profit of the other associated companies and joint ventures is found in exhibits 1 and 2.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

14.Property, plant, and equipment


	Plant	Pipelines,
	and	networks,	Work in
	equipment	and lines	progress	Buildings	Lands	Other	Total
Cost
Balance as of December 31, 2021	57,452,843	55,402,633	10,566,114	9,660,227	4,800,297	3,018,660	140,900,774
Additions/capitalizations (1)	2,433,113	1,331,585	4,496,490	401,079	15,956	89,493	8,767,716
Abandonment cost update (Note 23)	(241,090)	(333,705)	—	(42,730)	—	(3,652)	(621,177)
Capitalized financial interests (2)	62,677	23,155	89,809	7,778	518	2,031	185,968
Exchange differences capitalized	366	135	524	45	3	12	1,085
Disposals	(669,531)	(471,119)	(18,057)	(41,606)	(480)	(50,169)	(1,250,962)
Decrease related to business combination (Note 12)	—	(176,451)	—	37,542	(14,648)	—	(153,557)
Effect of adopting new standards (3)	—	—	18,013	—	—	—	18,013
Foreign currency translation	7,200,073	3,665,015	336,968	635,557	393,059	228,227	12,458,899
Reclassifications/transfers (4)	(3,430,789)	846,520	(2,027,540)	4,696,173	4,364	(59,324)	29,404
Balance as of December 31, 2022	62,807,662	60,287,768	13,462,321	15,354,065	5,199,069	3,225,278	160,336,163

Accumulated depreciation and impairment losses
Balance as of December 31, 2021	(24,698,837)	(19,665,052)	(1,279,600)	(4,059,253)	(67,611)	(1,053,895)	(50,824,248)
Depreciation expense	(2,807,716)	(2,319,775)	—	(423,067)	—	(159,398)	(5,709,956)
Recovery (loss) impairment (Note 18)	504,960	(70,439)	(153,449)	84,478	22,248	11,420	399,218
Disposals	637,049	448,340	755	37,953	41	44,162	1,168,300
Foreign currency translation	(2,737,467)	(1,340,435)	(2,307)	(195,728)	(8,192)	(126,507)	(4,410,636)
Reclassifications/transfers (4)	1,588,122	76,853	16,561	(1,674,537)	—	31,658	38,657
Balance as of December 31, 2022	(27,513,889)	(22,870,508)	(1,418,040)	(6,230,154)	(53,514)	(1,252,560)	(59,338,665)
Balance as of December 31, 2021	32,754,006	35,737,581	9,286,514	5,600,974	4,732,686	1,964,765	90,076,526
Balance as of December 31, 2022	35,293,773	37,417,260	12,044,281	9,123,911	5,145,555	1,972,718	100,997,498

(1)

Mainly includes: i) Ecopetrol S.A. ongoing projects associated with the Caño Sur, Castilla, Chichimene, Cusiana and Rubiales fields, ii) Interconexión Eléctrica S.A. E.S.P projects in progress: UPME 05-2014 Interconexión Costa Caribe 500kV, the UPME 06-2018 project New El Rio 220 kV Substation, and associated transmission lines and the UPME 03-2014 Interconexión Noroccidental 230/500 kV project.

(2)

Financial interest is capitalized based on the weighted average rate of borrowing costs.

(3)

Corresponds to the effect of adopting the IAS 16 amendment in Hocol S.A. (Note 5.1).

(4)

Includes the activation of the interconnection of the crude plant of the Refinería de Cartagena S.A.S. (IPCC).

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	Plant	Pipelines,
	and	networks	Work in
	equipment	and lines	progress	Buildings	Lands	Other	Total
Cost
Balance as of December 31, 2020	51,088,781	37,141,694	7,514,228	8,412,469	4,112,826	2,692,461	110,962,459
Additions/capitalizations	1,958,132	1,657,967	1,854,907	434,438	4,965	207,179	6,117,588
Increase by business combination (Note 12)	184,303	14,860,422	1,521,181	557,224	395,828	121,500	17,640,458
Abandonment cost update (Note 23)	(182,172)	(104,101)	(1,673)	(3,494)	—	127	(291,313)
Capitalized financial interests (1)	53,740	29,435	29,209	12,491	160	6,129	131,164
Exchange differences capitalized	1,371	751	745	319	4	156	3,346
Disposals	(312,646)	(81,967)	(9,344)	(25,530)	(4,164)	(37,560)	(471,211)
Foreign currency translation	4,946,012	1,646,079	164,778	204,496	257,988	120,110	7,339,463
Transfers/reclassifications	(284,678)	252,353	(507,917)	67,814	32,690	(91,442)	(531,180)
Balance as of December 31, 2021	57,452,843	55,402,633	10,566,114	9,660,227	4,800,297	3,018,660	140,900,774
Accumulated depreciation and impairment losses
Balance as of December 31, 2020	(21,256,869)	(17,558,024)	(1,023,456)	(3,628,724)	(78,548)	(908,500)	(44,454,121)
Depreciation expense	(2,420,045)	(1,723,300)	-	(381,978)	-	(116,923)	(4,642,246)
Reversal (loss) of an impairment (Note 18)	24,888	(22,346)	(312,009)	12,790	16,403	(858)	(281,132)
Disposals	276,225	66,555	421	18,152	34	31,355	392,742
Foreign currency translation	(1,726,218)	(434,365)	(1,550)	(73,136)	(5,500)	(61,416)	(2,302,185)
Transfers/reclassifications	403,182	6,428	56,994	(6,357)	-	2,447	462,694
Balance as of December 31, 2021	(24,698,837)	(19,665,052)	(1,279,600)	(4,059,253)	(67,611)	(1,053,895)	(50,824,248)

Net balance as of December 31, 2020	29,831,912	19,583,670	6,490,772	4,783,745	4,034,278	1,783,961	66,508,338
Net balance as of December 31, 2021	32,754,006	35,737,581	9,286,514	5,600,974	4,732,686	1,964,765	90,076,526

(1)

Financial interest is capitalized based on the weighted average rate of loan costs. See Note 20 – Loans and financing.

15.Natural and environmental resources

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


			Exploration
	Oil	Asset retirement	and
	investments	cost	evaluation	Total
Cost
Balance as of December 31, 2021	76,229,481	8,172,698	7,212,305	91,614,484
Additions/capitalizations (1)	8,368,195	—	3,594,349	11,962,544
Abandonment cost update (Note 23)	—	(1,130,363)	21,524	(1,108,839)
Disposals (2)	(759,178)	(114,899)	(6,084)	(880,161)
Write off exploratory assets and dry wells (3)	(223,058)	—	(809,106)	(1,032,164)
Capitalized financial interests (4)	136,696	—	60,570	197,266
Exchange differences capitalized	798	—	353	1,151
Effect of adopting new standards (5)	—	—	48,173	48,173
Foreign currency translation	4,431,851	127,871	533,347	5,093,069
Transfers/reclassifications	153,686	49,596	(175,406)	27,876
Balance as of December 31, 2022	88,338,471	7,104,903	10,480,025	105,923,399

Accumulated depletion and impairment losses
Balance as of December 31, 2021	(51,316,344)	(4,230,674)	(157,622)	(55,704,640)
Depletion expense	(4,536,052)	(800,139)	—	(5,336,191)
(Loss) reversal of impairment (Note 18)	(632,179)	—	9,105	(623,074)
Disposals	421,036	96,489	11,793	529,318
Foreign currency translation	(2,354,611)	(82,927)	—	(2,437,538)
Transfers/reclassifications	35,677	(70,835)	7,494	(27,664)
Balance as of December 31, 2022	(58,382,473)	(5,088,086)	(129,230)	(63,599,789)
Net balance as of December 31, 2021	24,913,137	3,942,024	7,054,683	35,909,844
Net balance as of December 31, 2022	29,955,998	2,016,817	10,350,795	42,323,610

(1)

Mainly includes a) Ecopetrol Permian, for investments in drilling of wells and construction of facilities executed in Rodeo, b) Ecopetrol S.A., mainly in Caño Sur, Casabe, Castilla, Chichimene, Floreña, Rubiales fields, and Cupiagua and Uchuva exploratory wells, and c) Hocol S.A., mainly in Guarrojo, Cicuco, SSJN1, Guajira, VIM-8, SN15, YDSN-1, LLA-87 blocks.

(2)	Corresponds mainly to the withdrawal of Rygberg’s association contract in Ecopetrol América.

(3)	Mainly includes a) Saturno block in Ecopetrol Brazil related to the entry bond, b) dry wells in Hocol S.A.: Bololó, Pilonera, Pollera, and Chinchorro and unsuccessfulness of the Sinuano and Yoda B wells, c) Ecopetrol S.A., Boranda Norte 1 well, and d) Ecopetrol América, Starman well.

(4)	Financial interest is capitalized based on the weighted average rate of borrowing costs.

(5)	Corresponds to the effect of adopting the IAS 16 amendment (Nota 5.1)

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


		Asset	Exploration
	Oil	retirement	and
	investments	cost	evaluation	Total
Cost
Balance as of December 31, 2020	65,367,278	7,231,851	8,867,894	81,467,023
Additions/capitalizations (1)	4,032,780	60,618	2,639,630	6,733,028
Abandonment cost update (Note 23)	—	778,925	13,256	792,181
Disposals	(3,497)	(484)	(69,908)	(73,889)
Withdrawal of exploratory assets and dry wells (2)	—	—	(486,408)	(486,408)
Capitalized financial interests (3)	99,786	—	24,757	124,543
Exchange differences capitalized	2,546	—	632	3,178
Foreign currency translation	1,979,171	101,866	767,117	2,848,154
Transfers/reclassifications	4,751,417	(78)	(4,544,665)	206,674
Balance as of December 31, 2021	76,229,481	8,172,698	7,212,305	91,614,484
Accumulated depletion and impairment losses
Balance as of December 31, 2020	(46,106,147)	(2,981,449)	(445,268)	(49,532,864)
Depletion expense	(3,803,027)	(1,193,454)	—	(4,996,481)
Reversal of impairment (Note 18)	305,016	—	59,111	364,127
Disposals	500	—	31,214	31,714
Foreign currency translation	(1,401,121)	(41,610)	—	(1,442,731)
Transfers/reclassifications	(311,565)	(14,161)	197,321	(128,405)
Balance as of December 31, 2021	(51,316,344)	(4,230,674)	(157,622)	(55,704,640)
Net balance as of December 31, 2020	19,261,131	4,250,402	8,422,626	31,934,159
Net balance as of December 31, 2021	24,913,137	3,942,024	7,054,683	35,909,844

(1)

Includes: a) Ecopetrol Permian for investments made in the drilling of wells and construction of facilities executed in RODEO, b) Ecopetrol for the Llanito, Purple Angel, Casabe and Offshore Tayrona fields. and c) Hocol mainly in Mamey 3, Pintado, Pozo Toldado, SN-8, Rc7 Pozo Basari, Ocelote, SSJN1, VIM8 and Saman. d) Ecopetrol America for Rydber and K2 e) Ecopetrol Brazil for the Gato do Mato project.

(2)

Mainly includes the Moyote well by Ecopetrol México, Ecopetrol S.A. mainly the Aguas Blancas, Alqamari-1, Nafta-1, Lorito Este 1, Boranda Centro 1 and Chimuelo 1 wells, Hocol Chacha 2 well, Ecopetrol América the well Silverback #1 and Silverback #2 and by Ecopetrol Brasil Ceará. Additionally, Hocol includes exploration expenses.

(3)	Financial interests are capitalized based on the weighted average rate of loan costs. See Note 20 – Loans and borrowings.

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, 2022, 2021 and 2020:


	2022	2021	2020
Between 1 and 3 years (a)	48,206	—	—
Between 3 and 5 years (b)	—	—	319,368
More than 5 years (c)	650,767	651,040	589,604
Total suspended exploratory Wells	698,973	651,040	908,972
Number of projects exceeding 1 year	8	6	16
Wells under 1 year of suspended (d)	990	20,863	—

(a)	For 2022, the balance corresponds to Hocol: Bullerengue South West-1 and Merecumbe 1, which are under evaluation.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(b)	For 2020, the balance corresponds mainly to wells of Ecopetrol S.A.: Purple Angel and Gorgon.

(c)	For 2022 and 2021, it corresponds mainly to i) Ecopetrol S.A.: Orca 1, Purple Angel, and Gordon, which are under evaluation. For 2020, the exploratory wells correspond mainly to i) Ecopetrol S.A.: Orca 1, Luna-1, and Gala 1K.

(d)	For 2022, the balance corresponds to Ecopetrol: Magallanes. For 2021, the balance corresponds to Hocol: Merecumbe 1 -SSJN1 as of December 2021.

16.Right-of-use assets

The following is the movement of right-of-use assets for the years ended December 31, 2022 and 2021:


		Lands and	Plant and		Right-of-use	Lease
	Pipelines	buildings	equipment	Vehicles	assets	liabilities
Balance as of December 31, 2021	77,019	199,070	121,384	99,205	496,678	1,165,099
Additions	40,642	100,070	71,013	142,346	354,071	354,071
Amortization of the period	(24,751)	(61,814)	(60,359)	(102,198)	(249,122)	—
Remeasurements(1)	(114)	(24,524)	7,505	16,779	(354)	18,644
Impairment loss	—	(1,244)	(4,042)	(5,499)	(10,785)	—
Disposals	(4,701)	(2,696)	(23,010)	(215)	(30,622)	(31,957)
Finance cost	—	—	—	—	—	70,250
Repayment of borrowings and interests	—	—	—	—	—	(434,555)
Transfers	(584)	(108)	595	(43)	(140)	(1,877)
Exchange difference	8,723	35,304	6,448	17,612	68,087	72,671
Balance as of December 31, 2022	96,234	244,058	119,534	167,987	627,813	1,212,346

(1)	Corresponds mainly to updating rates and conditions in lease contracts.


		Lands and	Plant and		Right-of-use	Lease
	Pipelines	buildings	equipment	Vehicles	assets	liabilities
Balance as of December 31, 2020	—	93,472	133,939	150,475	377,886	1,055,198
Additions	22,871	22,190	10,037	20,319	75,417	75,417
Effect of business combinations (Note 12)	75,836	121,042	13,779	19,550	230,207	255,503
Amortization of the period	(6,897)	(39,109)	(61,186)	(86,830)	(194,022)	—
Remeasurements(1)	—	26,057	48,803	5,045	79,905	80,068
Impairment loss	—	(5,802)	(20,608)	(5,373)	(31,783)	—
Disposals	—	(14,540)	—	(98)	(14,638)	(64,726)
Finance cost	—	—	—	—	—	49,694
Repayment of borrowings and interests	—	—	—	—	—	(336,030)
Transfers	(214)	(11,676)	(363)	(1,134)	(13,387)	2,615
Exchange difference	(14,577)	7,436	(3,017)	(2,749)	(12,907)	47,360
Balance as of December 31, 2021	77,019	199,070	121,384	99,205	496,678	1,165,099

(1)	Corresponds mainly to updating rates and conditions in lease contracts.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

17.Intangible assets

The following is the movement of intangibles and their amortization and impairment for the years ended December 31, 2022, and 2021:


	Licensees and	Other	Concessions	Easements
	software	intangibles	and rights	(1)	Total
Cost
Balance as of December 31, 2021	1,118,811	940,080	13,503,441	1,733,379	17,295,711
Acquisitions	292,803	9,953	835,457	9,297	1,147,510
Effect of business combination (Note 12)	—	12,670	(117,270)	(318,388)	(422,988)
Disposals	(4,148)	—	(95,875)	(478)	(100,501)
Foreign currency translation	74,759	338,654	3,439,810	86,905	3,940,128
Transfers/reclassifications	30,389	(18,605)	2,518	126,729	141,031
Balance as of December 31, 2022	1,512,614	1,282,752	17,568,081	1,637,444	22,000,891

Accumulated amortization and impairment losses
Balance as of December 31, 2021	(689,817)	(153,292)	(878,125)	(65,961)	(1,787,195)
Amortization of the period	(138,544)	(30,282)	(658,457)	(6,439)	(833,722)
Losses for impairment	(1,785)	(15,323)	(34,022)	(133)	(51,263)
Disposals	3,283	—	95,875	425	99,583
Foreign currency translation	(58,215)	(243,909)	(919,328)	(109)	(1,221,561)
Transfers/reclassifications	918	(3,865)	—	(57,181)	(60,128)
Balance as of December 31, 2022	(884,160)	(446,671)	(2,394,057)	(129,398)	(3,854,286)

Net balance as of December 31, 2021	428,994	786,788	12,625,316	1,667,418	15,508,516
Net balance as of December 31, 2022	628,454	836,081	15,174,024	1,508,046	18,146,605

(1)

Easements are acquired rights for the passage of its operating assets, mainly electric power 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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	Licensees and	Other	Concessions	Easements
	software	intangibles	and rights	(2)	Total
Cost
Balance as of December 31, 2020	835,030	201,463	351,108	79,176	1,466,777
Acquisitions	140,263	11,456	275,736	16,891	444,346
Effect of business combination (1)	130,634	666,455	11,910,589	1,618,801	14,326,479
Disposals	(21,581)	(226)	(402)	(79)	(22,288)
Foreign currency translation	82,397	83,856	893,249	18,553	1,078,055
Transfers/reclassifications	(47,932)	(22,924)	73,161	37	2,342
Balance as of December 31, 2021	1,118,811	940,080	13,503,441	1,733,379	17,295,711

Accumulated amortization and impairment losses
Balance as of December 31, 2020	(607,871)	(67,299)	(173,799)	(62,765)	(911,734)
Amortization of the period	123,796	(19,780)	(427,989)	(3,200)	(327,173)
Losses for impairment	(57)	—	—	—	(57)
Disposals	21,313	56	—	41	21,410
Foreign currency translation	(55,695)	(66,333)	(447,697)	—	(569,725)
Transfers/reclassifications	(171,303)	64	171,360	(37)	84
Balance as of December 31, 2021	(689,817)	(153,292)	(878,125)	(65,961)	(1,787,195)

Net balance as of December 31, 2020	227,159	134,164	177,309	16,411	555,043
Net balance as of December 31, 2021	428,994	786,788	12,625,316	1,667,418	15,508,516

(1)

Corresponds to the balances recognized in the business combination, which mainly includes i) service concessions classified as intangible assets, according to IFRIC 12, in Peru, Bolivia, and Colombia, ii) rights to use infrastructure and intangible assets recognized through business combinations in Brazil and Peru, and iii) intangibles associated with economic benefits from contractual income.

(2)

Easements are acquired rights for the passage of its operating assets, mainly electric power transmission lines. These assets are acquired in perpetuity, so there is no set term or contractual limit, and the right is maintained over time.

18.Impairment of non-current assets

As mentioned in Note 4.13, each year the Ecopetrol Business Group assesses whether there is an indication that an asset or cash–generating unit may be impaired or if impairment losses recognized in previous periods should be reversed.

The impairment of non-current assets includes property, plant, and equipment, natural resources, investments in companies, goodwill, and other non–current assets. Ecopetrol Business 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, (e) the market and country risk assessments reflected in the discount rate, and (f) changes in domestic and international 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 profit or loss statement. Highly sensitive significant estimates affecting each business segments, among others include (a) in the exploration and production segment, variations of recoverable hydrocarbon estimates, changes in projected realization prices, and the discount rate, (b) in the refining segment, changes in finished products and crude oil prices, the discount rate, refining margins, changes in environmental regulations, cost structure, and the level of capital expenditures, (c) in the transport and logistics segment, changes in regulated tariffs and transported volumes, and (d) in electric power 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, moderate growth, among others.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

As described in Note 2.9, the behavior of the prices of crude oil and products during the year 2022 showed a recovery versus the price levels generated in 2021 and 2020, a situation that has an impact in the parameters established for the calculation of the impairment.

Based on the impairment tests conducted by the Ecopetrol Business Group, the following are the impairments or reversals for the years ended on December 31, 2022, 2021 and 2020:


Impairment (loss) reversal by segment	2022	2021	2020
Exploration and Production	(890,248)	438,020	(192,693)
Refining and Petrochemicals	1,096,021	(305,466)	(781,528)
Transport and Logistics	(406,229)	(165,901)	341,065
Electric power transmission and toll roads concessions	(87,543)	(4)	—
	(287,999)	(33,351)	(633,156)

Recognized in:
Property, plant, and equipment (Note 14)	399,218	(281,132)	(384,638)
Natural resources (Note 15)	(623,074)	364,127	(217,709)
Investment in joint ventures and associates (Note 13)	(2,092)	(84,502)	(66,512)
Right of use assets (Note 16)	(10,785)	(31,783)	35,874
Other non-current assets	(51,266)	(61)	(171)
	(287,999)	(33,351)	(633,156)

18.1Exploration and production

The impairment reversal of assets of the Exploration and Production segment for the years ended December 31 of 2022, 2021 and 2020 is the following:


	2022	2021	2020
Oilfields	(888,156)	521,664	(123,652)
Investment in joint ventures	(2,092)	(83,644)	(69,041)
	(890,248)	438,020	(192,693)

18.1.1

Oilfields

In 2022, an impairment expense was recognized, mainly the Cusiana, Llanito, Sur, Cicuco-Boquete, and Upia fields (mainly associated with a decrease in reserve volumes) and a recovery in Tibú, Oripaya, and Arrayán (mainly associated with the better projection of market prices and higher volumes of reserves).

In 2021, because of the new market variables, the incorporation of new reserves, price differentials versus the reference to Brent, available technical and operational information, there was a recovery of impairment recognized in previous years of the fields that operate in Colombia: Tibú, West B, South, Dina Cretaceous, Hobo, Underriver, La Hocha and Totare; and in the field K2 abroad. There also was an expense for impairment, mainly in the Oripaya, Arrayán, and Boranda fields.

An impairment expense was recognized in the year 2020 because of the economic context of the hydrocarbons sector, the behavior of market variables, price differentials versus the reference to Brent, technical and operational information available. This impairment was mainly recognized in fields that operate in Colombia: Occidente B, Sur, Teca, Tibú, La Hocha, and Espinal, and in the field K2 abroad. In addition, a recovery was recognized in Casabe, because of a significant increase in its reserves, as well as Provincia, Lisama and Orito.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following is the breakdown of oilfields impairment losses or reversals for the years ended December 31, 2022, 2021 and 2020:



	Carrying	Recoverable	Impairment
Cash generating units	amount	amount	reversal (loss)
Oil fields in Colombia
Reversal	3,540,732	5,563,724	250,306
Loss	4,870,976	3,732,514	(1,138,462)
			(888,156)

2021



	Carrying	Recoverable	Impairment
Cash generating units	amount	amount	reversal (loss)
Oil fields in Colombia
Reversal	11,216,641	17,575,851	499,599
Loss	239,046	136,698	(104,041)
Fields operated abroad
Reversal	1,142,593	1,306,219	126,106
			521,664

2020



	Carrying	Recoverable	Impairment
Cash generating units	amount	amount	reversal (loss)
Oil fields in Colombia
Reversal	24,845,238	61,224,928	1,019,395
Loss	2,439,799	1,423,561	(1,016,238)
Fields operated abroad
Loss	1,277,609	1,150,800	(126,809)
			(123,652)

The grouping of assets to determine the CGUs is consistent as compared to the prior periods.

The assumptions used to determine the recoverable amount include the following:

–

The fair value less costs of disposal of the Exploration and Production segment assets was determined based on cash flows after tax derived from the business plans approved by Ecopetrol Business Group’s Management, which are developed based on long–term macroeconomic policies and fundamental assumptions of supply and demand. The fair value hierarchy is 3.

–	Balance of oil and gas reserves, in addition to proven reserves; probable and possible reserves were also considered (See Note 34), adjusted by different risk factors.

–

The discount rate in real terms was determined as the weighted average cost of capital (WACC) and corresponds to a differential rate depending on the projected tax surcharge for each year, as follows: 7.34 % with tax surcharge of 0%, 7.14% with a tax surcharge of 5%, 6.93% with a tax surcharge of 10% and 6.73% with a tax surcharge of 15% (2021: 4.94%).

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

–

Oil price – Brent: Projections include USD$94.63/barrel for the first year, USD$82.56/barrel average for the medium term, and USD$79.17/barrel starting in 2034. In 2021, the assumptions made took a price of USD$75.72/barrel for the first year, USD$62.60/barrel average for the medium term and USD$61.89/barrel as of 2033. The projection of international crude oil prices is carried out by an independent agency specialized in Oil & Gas, which has been considering the current scenarios of the OPEC (Organization of Petroleum Exporting Countries) oil quota agreements and the balance between supply and demand in the short and long term for the industry.

18.1.2Investments in joint ventures

Investments in joint ventures in the Exploration and Production segment are recorded using the equity method of accounting. Ecopetrol Business group evaluates if there is any objective evidence that indicate that the fair value of such investments has impaired in the period, especially those for which goodwill has been recorded.

As a result, Ecopetrol Business Group recognized a loss or reversal of impairment on the carrying value as of December 31, as follows:


	2022	2021	2020
Equion Energía Limited	(2,092)	(83,644)	7,928
Offshore International Group	—	—	(76,969)
	(2,092)	(83,644)	(69,041)

In 2022, an impairment expense was recognized on the investment in Equion, mainly due to the increase in the discount rate, as well as the sale of the Alto Magdalena Pipeline (OAM) at a lower value than expected.

In 2021, an impairment expense was recognized on the investment in Equion, mainly from the consideration of the fair value of the sale transaction of the El Morro Araguaney Pipeline.

There was a recovery in 2020 on the investment in Equion mainly originated by the update of the transport rates through pipelines. Additionally, an impairment loss was recognized on the investment in Offshore International Group considering the fair value of the sale transaction. The significant assumptions used to determine the recoverable amount of these investments are consistent with those described in the previous section, except for the use of a discount rate in real terms in 2020 for Offshore International Group of 5.79% (2019 – 8.50%).

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

18.2Refining and Petrochemical

Ecopetrol Business Group recognized a loss or reversal of impairment on the carrying value as of December 31, as follows:


	2022	2021	2020
Refinería de Cartagena S.A.S.	1,096,024	34,650	(440,525)
Invercolsa S.A.	(3)	(97)	(3)
Refinería de Barrancabermeja (projects)	—	(340,019)	(341,000)
	1,096,021	(305,466)	(781,528)

The following is the Cash Generating Units impairment or reversals in the refining and petrochemical segment for the years ended December 31, 2022, 2021 and 2020:

2022


	Carrying	Recoverable	Impairment
Cash–generating units	amount	amount	reversal (loss)
Refinería de Cartagena S.A.S.	31,750,957	32,846,981	1,096,024
Invercolsa S.A.	276	273	(3)
			1,096,021

2021


	Carrying	Recoverable	Impairment
Cash–generating units	amount	amount	reversal (loss)
Refinería de Cartagena S.A.S.	26,808,008	26,842,658	34,650
Invercolsa S.A.	292	195	(97)
Refinería de Barrancabermeja (projects)	340,019	—	(340,019)
			(305,466)

2020



	Carrying	Recoverable	Impairment
Cash–generating units	amount	amount	loss
Refinería de Cartagena S.A.S.	24,041,174	23,600,649	(440,525)
Invercolsa S.A.	276	273	(3)
Refinería de Barrancabermeja (projects)	676,334	335,334	(341,000)
			(781,528)

The grouping of assets to determine the CGUs is consistent with prior periods.

18.2.1

Refinería de Cartagena S.A.S.

The recoverable amount of the Refinería de Cartagena was calculated based on its fair value less costs of disposal, which is higher than its value in continued use. The fair value less costs of disposal of the Refinería de Cartagena was determined based on cash flows after taxes that are derived from business plans approved by the Ecopetrol Business Group’s Management, which are developed based on market prices provided by a third-party expert, which considers long–term macroeconomic variables and fundamental supply and demand assumptions for crude oil and refined products. The fair value hierarchy is 3.

Refinería de Cartagena, supported by best practices, has reviewed the current considerations in market trends and has considered the implications of climate change within the estimate of the recoverable value, for which it incorporated the following aspects:

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

●

SosTecnibilidad (Technology + Sustainability) Capex: Reficar’s investment plan, aligned with the strategy of the Ecopetrol Business Group, includes investments focused on the implementation of new technologies that allow the current operation of the refinery to be conditioned in line with the country’s fuel demands and the entry into new markets such as petrochemicals.

●

Estimation horizon: Reficar has revised the estimation of the valuation horizon in the FMV exercise, going from a probable operating horizon of 94 to 70 years. Thus, considering possible impacts from decarbonization in the long term.

The significant assumptions to determine the recoverable amount included (i) a gross refining margin determined by crude oil feedstock and products price outlook provided by an independent third-party expert; (ii) a real discount rate (after tax) of 7.6% (2021-5.3% and 2020–5.1%), determined under WACC methodology. Other no significant assumptions are i) current conditions or benefits, or similar, as an industrial user of goods and services of the free trade zone and during the validity of the license; (ii) level of costs and long–term operating expenses in line with international refinery standards of similar configuration and conversion capacity; (iii) refinery throughput and production; and (iv) level of continued investment.

It is important to mention that the refining business is highly sensitive to the volatility of the margins and the macroeconomic variables implicit in the determination of the discount rate, therefore, any change in these assumptions could potentially result in significant variations in the determination of impairment losses or reversal amounts.

In 2022, there is a reversal of impairment of $1,107,101 mainly due to i) favorable market conditions, ii) high differentials of distilled products sustained in the short term due to conjunctural impacts of the Ukraine-Russia crisis, and iii) differential in national crudes allow diet optimization. Additionally, an expense is presented for impairment in office-type containers because of the appraisals made to these and surpluses from the expansion project for $11,077.

The impairment reversal of impairment for 2021 is mainly due to: i) favorable market conditions, ii) the recovery in product spreads, especially gasoline and middle distillates, and iii) growth in fuel demand.

The impairment expense for 2020 was mainly derived from lower refining margins associated with external factors associated with the COVID-19 pandemic. On the other hand, Management endured operational improvements that compensate to a certain extent for the effects of macroeconomic variables.

18.2.2Refinería de Barrancabermeja

As of December 31, 2022, qualitative assessment of the assets associated with the refining segment were executed, including the Barrancabermeja Refinery Modernization Project. As a result, there are no indicator of impairment loss or recovery.

As of December 31, 2021, because an update analysis for the Barrancabermeja Refinery Modernization Project, an impairment expense of $340,019 was recognized, produced mainly by engineering work executed according to the evaluations and the context of the industry during the year.

An impairment expense of $341,000 was recognized as of December 31, 2020, because of the update of the analysis for the Barrancabermeja Refinery Modernization Project, in relation to engineering work based on the evaluations carried out and the current context of the industry.

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 value included: i) the tariffs regulated by the Ministry of Mines and Energy and the Energy and Gas Regulation Commission - CREG, ii) the actual discount rate used in the valuation was 4.73% (2021 – 2.95% and 2020 - 3.17%) and iii) transport volume projections based on the financial plan and the long-term volumetric transport program.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

For 2022, the volumetric projection up to 2040 shows a decrease in crude oil exploratory prospects in the southern and northern fields of Colombia because of contractual uncertainties and socio-environmental viability, which represented an impairment loss for the CGUs by 2022 of Cenit Transporte y Logística S.A.S. in the South, North, and Yaguará-Tenay for $405,357, and Oleoducto de Colombia S.A. for $872.

In 2021, an impairment expense was recognized for the Southern Cash Generating Unit, the estimate of the impaired value was $160,653, corresponding to the total value of the asset. In addition, an impairment loss of $2,845 was established for the Yaguará-Tenay system, which corresponds to 39% of the value of the asset. Finally, the segment recognized an additional impairment loss of $2,545 as a result of the sale of a turbo-generator during the year and a recovery in other non-current assets of $142. The recognition of impairment is due to volumetric variation and rates.

In 2020, Cenit recognized an impairment recovery of $341,065, related to the South CGU, which includes Tumaco Port and the TransAndino Pipeline (OTA, by its acronym in Spanish) and the North CGU, which includes the section Banadia - Ayacucho, and it is part of the Caño Limón Pipeline, due to volumetric recovery and changes in tariffs. The fair value of these CGUs is $7,049,007 and their book value is $2,153,631.

18.4Energy transmission and roads

According to the impairment test, as of December 31, 2022, 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 assets of Internexa Brasil and Internexa Argentina, which showed impairment indicators. Each of these operations constitute an independent Cash Generating Unit (CGU) and impairment tests were performed for each CGU.

As of December 31, 2022, an impairment loss of $87,543 was recognized, which $85,568 corresponds to Internexa Brasil, due to updating the business plan that reflects a decline in revenues and operating profit margins, and $1,975 from Internexa Argentina, due to cost capital increase.

To determine the recoverable amount, the Company used the discounted free cash flow methodology, based on revenue projections, operating costs, capital investments, and operational taxes.

Internexa Brasil

Discount rate: WACC 12.35% in local currency (BRL). The WACC is made up of a cost of equity (Ke) of 11.58%, and a cost of debt (Kd) of 12.35%. The growth rate in perpetuity was 1% of real growth (long-term inflation plus 1 percentage point), equivalent to 4.31% per year.

Business assumptions: The estimate of the recoverable amount was based on the generation of the annual operating cash, through the projection of ordinary revenue, operating costs, capital investments and company taxes.

Internexa Argentina

Discount rate: WACC in dollars of 19.75%. Composed of a Ke of 19.75% and Kd 0% (the company has no financial debt). A gradient of 5.27% was used for the estimation of perpetuity.

19.Goodwill

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	2022	2021
Interconexión Eléctrica S.A. E.S.P.	3,755,835	3,092,045
Oleoducto Central S.A.S.	683,496	683,496
Hocol Petroleum Ltd.	537,598	537,598
Invercolsa S.A.	434,357	434,357
Andean Chemical Ltd	127,812	127,812
Esenttia S.A.	108,137	108,137
	5,647,235	4,983,445
Less impairment Hocol Petroleum Ltd.	(297,121)	(297,121)
	5,350,114	4,686,324

Related to goodwill impairment analysis in ISA, the estimate of the recoverable amount for Energy CGU was based on the value in use, which is calculated using a discounted cash flow model projected according to the term of contracts. The principal assumptions were the generation of the annual operating cash, through the projection of ordinary revenue, operating costs, capital investments, and company taxes.

20.Loans and borrowings

20.1

Composition of loans and borrowings


	Weighted average effective
	interest rate as of December 31				2022	2021
	2022		2021
Local currency
Bonds	9.8	%	9.1	%	4,965,653	4,941,024
Syndicated loan	11.5	%	5.4	%	388,518	600,452
Lease liabilities (1)	8.0	%	6.3	%	844,734	823,922
Commercial loan	10.3	%	7.8	%	1,782,944	1,516,377
					7,981,849	7,881,775
Foreign currency
Bonds (2)	6.0	%	5.7	%	82,432,647	66,603,695
Commercial and syndicated loans	4.6	%	3.5	%	23,537,675	18,750,580
Loans from related parties (Note 31)	5.9	%	0.3	%	815,056	1,483,701
Lease liabilities (1)	6.0	%	6.0	%	367,612	341,177
					107,152,990	87,179,153
					115,134,839	95,060,928
Current					22,198,583	9,206,283
Non–current					92,936,256	85,854,645
					115,134,839	95,060,928

(1)

Corresponds to present value of the payments to be made during the term of the operative lease contracts of pipelines, tanks, property, and vehicles, recognized by the implementation of IFRS 16 – Leases (See Note 16).

(2)

Corresponds to the increase in the exchange rate by $829 per dollar and the movements in debt during the period.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

During 2022, loans and borrowings for $16,844,029 were acquired mainly in Ecopetrol S.A. for $11,429,785 given, i) the disbursement of a financing line for $5,384,315 (USD$1,200 million) for the advance payment of the credit contracted in the acquisition of ISA, ii) 1B club deal operations, acquisition of treasury credits and drafts financed in the fourth quarter of 2022 for an approximate amount of USD $1,120 million, and iii) short-term financing with the company BNP Paribas for $625,944 (USD $160 million), and Interconexión Eléctrica S.A. E.S.P. for $5,331,221, which mainly includes i) the international issuance of corporate bonds for $2,063,735 in the subsidiary Transmantaro-CTM for the repurchase of its 2023 international bond and ii) the disbursement of credits to cover investment plans and projects in Brazil, Peru, and Chile.

As a consequence of Ecopetrol Business Group strategy related to the integral management of debt and financing of the maturities of 2023, during 2022 payments were made for $16,409,494; mainly in Ecopetrol S.A. for $10,071,064 and Interconexión Eléctrica S.A. E.S.P. for $5,101,656.

20.2Fair value of loans

The fair value of loans and borrowings is $106,509,947 and $99,258,034 as of December 31, 2022, and 2021, respectively.

20.3Maturity of loans and borrowings

The following are the maturities of loans and borrowing as of December 31, 2022:


	Up to 1
	year (1)	1 – 5 years	5-10 years	> 10 years	Total
Local currency
Bonds	579,032	1,262,971	1,559,593	1,564,057	4,965,653
Syndicated loan	254,165	134,353	—	—	388,518
Lease liabilities	150,872	384,661	308,493	708	844,734
Commercial loans	311,721	689,835	631,100	150,288	1,782,944
	1,295,790	2,471,820	2,499,186	1,715,053	7,981,849
Foreign currency
Bonds	12,235,174	25,336,179	23,223,393	21,637,901	82,432,647
Commercial and syndicated loans	7,726,416	15,054,954	547,092	209,213	23,537,675
Lease liabilities	126,147	206,474	34,991	—	367,612
Loans from related parties	815,056	—	—	—	815,056
	20,902,793	40,597,607	23,805,476	21,847,114	107,152,990
	22,198,583	43,069,427	26,304,662	23,562,167	115,134,839

(1)Includes short-term credit and the current portion of long-term debt, as applicable.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following are the maturities of loans and borrowing as of December 31, 2021:


	Up to 1
	year (1)	1 – 5 years	5–10 years	> 10 years	Total
Local currency
Bonds	290,858	1,152,829	1,423,909	2,073,428	4,941,024
Syndicated loan	239,597	360,855	—	—	600,452
Lease liabilities	188,477	340,283	283,070	12,092	823,922
Commercial loans	170,758	539,693	595,307	210,619	1,516,377
	889,690	2,393,660	2,302,286	2,296,139	7,881,775
Foreign currency
Bonds	3,275,138	27,550,698	17,515,876	18,261,983	66,603,695
Commercial loans	3,457,708	14,792,560	303,012	197,300	18,750,580
Lease liabilities	100,046	205,617	35,514	—	341,177
Loans from related parties	1,483,701	—	—	—	1,483,701
	8,316,593	42,548,875	17,854,402	18,459,283	87,179,153
	9,206,283	44,942,535	20,156,688	20,755,422	95,060,928

(1)	Includes short–term credit and the current portion of long–term debt, as applicable.

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, 2022 and 2021:


	2022	2021
Local currency
Fixed rate	1,844,086	1,239,723
Floating rate	6,137,763	6,642,052
	7,981,849	7,881,775
Foreign currency
Fixed rate	82,850,932	69,427,014
Floating rate	24,302,058	17,752,139
	107,152,990	87,179,153
	115,134,839	95,060,928

The interest on the bonds in national currency is indexed to the CPI (Consumer Price Index) and bank loans and variable rate leasing in Colombian pesos are indexed to the DTF (Fixed Term Deposits) and IBR (Banking Reference Indicator), plus a differential. Interest on loans in foreign currency is calculated based on the LIBOR rate plus a spread and the interests of the other types of debt are at a fixed rate.

20.5Loans designated as hedging instrument

As of December 31, 2022, Ecopetrol Business Group designated USD$14,512 million (2021 - USD13,287 million) of foreign currency debt as a hedging instrument, of which USD$8,940 million is used to hedge the net investment in foreign operations with the US dollar as their functional currency, and USD$5,572 million is used to hedge the cash flows of future crude oil exports. See Notes 30.3 and 30.4.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

20.6Guarantees and covenants

As of December 31, 2022, 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 $23,670,968, mainly in i) Chile for $17,676,320 in ISA Intervial, Ruta de la Araucaria, Ruta del Maipo, Ruta del Loa, and ISA Interchile, b) Brazil in ISA CTEEP for $3,315,648, and c) Colombia on the Ruta Costera for $2,679,000.

The syndicated loan entered by Oleoducto Bicentenario requires that this subsidiary maintain an established relationship of leverage and solvency and cash flow / service to the debt.

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.

21.Trade and other payables


	2022	2021
Current
Suppliers	15,034,677	10,470,260
Withholding tax	1,896,128	717,720
Partners’ advances	1,164,197	1,060,349
Dividends payable (1)	392,346	58,668
Insurance and reinsurance	330,363	294,114
Deposits received from third parties	162,338	136,310
Agreements in transport contracts	115,526	33,883
Related parties (Note 31)	67,879	66,598
Hedging operations (2)	4,311	2,032
Various creditors	769,939	728,297
	19,937,704	13,568,231

Non - current
Suppliers	28,425	8,260
Deposits received from third parties	331	33
Various creditors	28,300	62,314
	57,056	70,607

(1)

Corresponds to dividends payable from Interconexión Eléctrica S.A. for $366,999 (2021: $53,976), Inversiones de Gases de Colombia S.A. for $21,680 (2021: $978), and Ecopetrol S.A. for $3,667 (2021: $3,714).

(2)

Corresponds to the balance payable for the liquidation of swap contracts acquired to hedge the price risk of export crude oil.

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

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	2022	2021
Post–employment benefits
Healthcare	8,140,648	6,636,809
Pension	2,073,562	2,159,530
Education	405,769	443,761
Bonds	399,114	320,833
Other plans (1)	115,136	91,476
Termination benefits – Voluntary retirement plan	772,133	746,585
	11,906,362	10,398,994
Social benefits and salaries	970,598	856,198
Other employee benefits	88,279	123,853
	12,965,239	11,379,045
Current	2,753,697	2,296,253
Non–current	10,211,542	9,082,792
	12,965,239	11,379,045

(1)

Includes benefits to employees for five years and layoffs.

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:


	Pension and bonds		Other		Total
	2022	2021	2022	2021	2022	2021
Liabilities for employee benefits
Opening balance	14,520,592	16,320,383	7,946,927	8,510,594	22,467,519	24,830,977
Effect of business combination	—	545,319	—	301,780	—	847,099
Current service cost	51,756	10,948	95,724	121,404	147,480	132,352
Past service cost (2)	—	3,545	114,162	125,783	114,162	129,328
Interest expense	953,146	867,644	530,482	485,494	1,483,628	1,353,138
Transferred benefits	—	—	—	(577)	—	(577)
Actuarial (gains) losses	(1,805,907)	(2,285,738)	1,361,808	(1,091,228)	(444,099)	(3,376,966)
Benefits paid	(981,486)	(931,051)	(608,184)	(506,323)	(1,589,670)	(1,437,374)
Foreign currency translation	102,047	(10,458)	24,105	—	126,152	(10,458)
Closing balance	12,840,148	14,520,592	9,465,024	7,946,927	22,305,172	22,467,519

Plan assets
Opening balance	12,040,229	13,157,729	28,296	15,236	12,068,525	13,172,965
Effect of business combination	—	—	—	11,004	—	11,004
Return on assets	802,711	691,584	1,819	367	804,530	691,951
Contributions to funds	—	—	125,788	504,511	125,788	504,511
Benefits paid	(961,931)	(924,924)	(125,129)	(502,340)	(1,087,060)	(1,427,264)
Actuarial (losses) gains	(1,513,537)	(884,160)	564	(482)	(1,512,973)	(884,642)
Closing balance	10,367,472	12,040,229	31,338	28,296	10,398,810	12,068,525
Net post–employment benefits liability	2,472,676	2,480,363	9,433,686	7,918,631	11,906,362	10,398,994

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following table shows the movement in profit and loss and in other comprehensive income as of December 31, 2022, 2021 and 2020:


	2022	2021	2020
Recognized in profit or loss
Interest expense	679,098	661,187	622,163
Current service cost	147,480	132,352	118,035
Past service cost	114,162	129,328	631,761
Remeasurements	—	(211)	—
	940,740	922,656	1,371,959
Recognized in other comprehensive income
Pension and pension bonds (1)	156,755	1,401,578	226,597
Healthcare (1)	(1,429,423)	991,050	(33,324)
Other	18,154	64,039	(55,814)
	(1,254,514)	2,456,667	137,459
Deferred tax	586,260	(679,510)	(41,238)
	(668,254)	1,777,157	96,221

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’s responsibility. The destination of trust resources and its yields cannot be changed or returned to the Ecopetrol Business Group until all pension obligations have been fulfilled.

The following is the composition of the plan assets of pension and pension bonds by type of investment as of December 31, 2022 and 2021:


	2022	2021
Other local currency	4,810,813	5,422,709
Bonds of private entities	1,674,431	2,393,322
Bonds issued by the national government	1,552,690	2,758,728
Other foreign currency	1,762,899	113,012
Variable yield	291,847	1,026,862
Other public bonds	201,508	302,254
Bonds of foreign entities	104,622	51,638
	10,398,810	12,068,525

53.76% (2021 –36.99%) of 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 46.24% (2021 – 63.01%) are classified as level 2.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following table reflects the credit ratings of the issuers and counterparties in assets held by the autonomous pension funds:


	2022	2021

AAA	4,138,043	7,183,658
Nación	3,319,858	2,871,610
AA+	312,303	455,875
BB+	267,961	78,216
AA	161,244	74,350
F1+	87,111	112,284
F1	83,684	—
BBB-	47,919	39,865
BRC1+	43,000	37,884
BBB+	30,331	40,928
A+	23,514	—
BAA2	20,880	—
BAA1	20,814	18,855
AA-	8,714	9,558
A	2,352	5,834
Other ratings	330,997	47,348
Rating not available	1,500,085	1,092,260
	10,398,810	12,068,525

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, 2022, and 2021:


2022	Pension		Bonds		Health		Education		Others (1)
Discount rate	6.2% - 14.7	%	9.00	%	8.7% - 14-7	%	6.3% - 14.8	%	7.4% - 14.5	%
Salary growth rate	4.5% - 5.5	%	N/A		4.5% - 5.5	%	N/A		4.5% - 4.7	%
Expected inflation rate	3.0% - 4.5	%	3.00	%	3.00	%	3.00	%	3.0% - 4.5	%
Pension growth rate	3.00	%	N/A		4.0% - 5.5	%	4.00	%	4.00	%
Cost trend
Short–term rate	N/A		N/A		6.33	%	4.00	%	N/A
Long–term rate	N/A		N/A		4.00	%	4.00	%	N/A


2021	Pension		Bonds		Health		Education		Others (1)
Discount rate	5.18% - 8.7	%	5.00% - 6.25	%	7.00% - 8.8	%	6.30% - 8.9	%	5.56% - 7.10	%
Salary growth rate	4.50	%	N/A		N/A		4.50	%	4.5% - 4.7	%
Expected inflation rate	3.0% - 4.0	%	3.00	%	3.00	%	3.00	%	3.00% - 4.00	%
Pension growth rate	3.0% - 3.5	%	N/A		N/A		N/A		3.50	%
Cost trend
Short–term rate	N/A		N/A		6.67	%	4.00	%	N/A
Long–term rate	N/A		N/A		4.00	%	4.00	%	4.70	%

N/A: Not applicable for this benefit.

(1)	Weighted average discount rate.

The cost trend is the projected increase for the initial year, which includes the expected inflation rate.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

22.4Maturity of benefit obligation

The cash flows required for payment of post–employment obligations of Ecopetrol S.A. and Cenit are the following:


Period	Pension and bonds	Other benefits	Total
2023	1,158,416	614,528	1,772,944
2024	1,187,807	645,419	1,833,226
2025	1,212,665	684,044	1,896,709
2026	1,225,740	718,026	1,943,766
2027	1,245,109	756,240	2,001,349
2028 y ss	6,380,585	4,323,885	10,704,470

22.5Sensitivity analysis

The following sensitivity analysis shows the effect of such possible changes on the obligation for defined benefits, while keeping the other assumptions constant, as of December 31, 2022:


	Pension	Bonds	Health	Education	Other
Discount rate
–50 basis points	12,000,383	1,076,007	8,472,198	396,973	900,711
+50 basis points	10,969,190	1,027,361	7,538,544	372,713	872,696
Inflation rate
–50 basis points	10,974,674	1,023,440	N/A	N/A	782,593
+50 basis points	12,057,329	1,079,923	N/A	N/A	803,403
Salary growth rate
–50 basis points	N/A	N/A	N/A	N/A	90,552
+50 basis points	N/A	N/A	N/A	N/A	96,723
Cost trend
–50 basis points	N/A	N/A	7,535,085	372,035	N/A
+50 basis points	N/A	N/A	8,478,117	397,599	N/A

N/A: Not applicable for this benefit.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

23.Accrued liabilities and provisions


	Asset		Environmental
	retirement		contingencies and
	obligation	Litigation	others	Total
Balance as of December 31, 2021	11,890,319	703,966	1,637,922	14,232,207
Abandonment costs update	(1,730,016)	—	—	(1,730,016)
Additions	93,704	153,786	468,341	715,831
Uses	(607,769)	(41,773)	(354,625)	(1,004,167)
Financial costs	333,688	10,293	17,322	361,303
Foreign currency translation	186,215	81,894	42,085	310,194
Reversal of provision for sale of assets (1)	(188,540)	—	—	(188,540)
Transfers	28,427	(9,915)	41,170	59,682
Balance as of December 31, 2022	10,006,028	898,251	1,852,215	12,756,494
Current	946,675	94,375	492,086	1,533,136
Non-current	9,059,353	803,876	1,360,129	11,223,358
	10,006,028	898,251	1,852,215	12,756,494

(1)

Corresponding to the abandonment provision associated with the assets related to the participation of Ecopetrol S.A. in Asociación Casanare, Estero, Garcero, Orocué and Corocora (CEGOC), which were sold to Perenco Oil and Gas Colombia. This trade closed on August 26, 2022.


	Asset		Environmental
	retirement		contingencies and
	obligation	Litigation	others	Total
Balance as of December 31, 2020	11,239,325	118,139	1,070,266	12,427,730
Abandonment costs update	500,868	—	—	500,868
Effect of business combination (Note 12)	—	329,123	618,760	947,883
Additions	242,435	261,785	210,619	714,839
Uses	(548,133)	(13,453)	(334,922)	(896,508)
Financial costs	292,329	3,925	7,272	303,526
Foreign currency translation	152,212	4,466	34,774	191,452
Transfers	11,283	(19)	31,153	42,417
Balance as of December 31, 2021	11,890,319	703,966	1,637,922	14,232,207
Current	1,041,674	59,843	488,601	1,590,118
Non-current	10,848,645	644,123	1,149,321	12,642,089
	11,890,319	703,966	1,637,922	14,232,207

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	Asset		Environmental
	retirement		contingencies and
	obligation	Litigation	others	Total
Balance as of December 31, 2019	8,835,420	137,429	945,439	9,918,288
Increase in abandonment costs	2,307,453	—	—	2,307,453
Additions	143,320	32,108	237,181	412,609
Uses	(291,793)	(31,709)	(106,448)	(429,950)
Financial costs	258,464	—	—	258,464
Effect of control loss in subsidiaries (Note 28)	(23,874)	(20,117)	—	(43,991)
Adjustment on fair value for business combination	31,137	—	—	31,137
Foreign currency translation	37,239	428	5,476	43,143
Transfers	(58,041)	—	(11,382)	(69,423)
Balance as of December 31, 2020	11,239,325	118,139	1,070,266	12,427,730
Current	949,638	46,844	224,627	1,221,109
Non-current	10,289,687	71,295	845,639	11,206,621
	11,239,325	118,139	1,070,266	12,427,730

23.1Asset retirement obligation

The estimated liability for asset retirement obligation costs corresponds to the future obligation that the Ecopetrol Business Group to restore environmental conditions to a level similar to that existing 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 Business 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, 2022, were Exploration and Production 5.30% (2021 – 2.89%), Refining and Petrochemicals 6.36% (2021 - 4.21%), and Transportation and Logistics 5.58% (2021 - 3.14%).

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

23.2Litigations

The following table details the main litigations recognized in the statement of financial position as of December 31, whose loss expectations are probable and could imply an outflow of resources:


	2022	2021
Second instance rulings unfavorable to the interests of Ecopetrol, related to public works contributions, for which they have a unified sentence and that could be subject to collection by the tax authority	223,439	203,160
CTEEP Regulatory Contingency: Billing Eletrobras – RBNI Corresponds to the collection action filed by Eletrobras against ISA CTEEP requesting the return of the value charged in excess by the company as part of the payment of the compensation resulting from the extension of Concession Contract No. 059/2001 under Law No. 12,783/201, relating to NI facilities (new investments) that had been transferred to the company by Eletrobras.	40,692	27,993
Tax contingency: Property and Urban Land Tax (IPTU) CTEEP: corresponds to processes related to the collection of Property Tax (IPTU) in several municipalities of the State of São Paulo and recognizes a provision to cover processes.	23,691	—
Unfavorable first instance ruling for Ecopetrol in the process of direct fixing for the damages associated with the hydrocarbon spill that occurred in Guaduas, Vereda Raizal and Cajón, in the property called “La Floresta” in May 2004.	14,245	—
Administrative processes of a sanctioning type issued by PRONATEL and OSIPTEL Internexa Peru: Procedure for failure to pay contributions during the years 2010 to 2022 for the usufruct contracts with Telefónica del Perú and associated fines.	11,675	—
Damages to third parties due to hydrocarbon easement in a building near the Cartagena Refinery.	11,019	11,019
Lost profits because of an open competition for the management of a set of assets transferred to a trust company.	5,774	5,774

23.2Environmental contingencies and others

These correspond to contingencies for environmental incidents and obligations related to environmental compensation and mandatory investment of 1% for the use of, exploitation of or effect on natural resources imposed by national, regional, and local environmental authorities. Mandatory investment of 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 2019 and article 321 of Law 1955 of 2019 in relation to the projects that Ecopetrol Business Group develops in Colombia.

The Colombian Government through the Ministry of Environment and Sustainable Development, issued in December 2016 and in January 2017 the Decrees 2099 and 075, which modify the Single Regulatory Decree of the environment and sustainable development sector, Decree 1076 of 2015, related to the mandatory investment for the use of water taken directly from natural sources. The decrees included modifications and guidelines regarding the geographical scope for the execution of the activities for the fulfillment of the obligation, investment lines and the calculation of the base of liquidation of the obligations. Likewise, June 30, 2017, was defined as the maximum date to modify the Investment Plans that are in execution.

In 2019, Law 1955/2020 was issued, which in its article 321 unifies the basis for the settlement of this obligation and requires updating the investment obligations of 1% to present value. Ecopetrol Business Group carried out the recertification of the settlement base and the acceptance of the percentage of updating of the investment values of 1% in more than 90 environmental licenses, generating a lower provision for this obligation. Currently, ANLA’s pronouncements are being received in relation to article 321 of Law 1955, some through official letters and others through resolutions. Ecopetrol Business Group has filed an appeal for reconsideration with ANLA in most cases, which are under review by this authority.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

23.3Contingencies

Refinería de Cartagena S.A.S.

Arbitration tribunal:

On March 8, 2016, Reficar 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 Reficar and CB&I for the expansion of the Cartagena Refinery in Cartagena, Colombia. Reficar is the Claimant in the ICC arbitration and seeks 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 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, Reficar 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 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, Chicago Bridge & Iron Company filed a response to Reficar’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 Reficar’s claim.

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.

In relation to this matter, as of December 31, 2020, there is a balance of approximately USD $ 122 million, in invoices paid by Reficar to CB&I, under the PIP and MOA Agreements of the EPC contract, whose supports provided to date by CB&I do not show acceptance by AMEC Foster Wheeler - PCIB.

In January 2020, McDermott International Inc. – 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 has taken actions to protect its interests and has 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.

On January 21, 2020, Comet II BV, the successor in interest to Chicago Bridge & Iron Company NV, commenced bankruptcy case under title 11 of the United States Code in the United States 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 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 or August 30, 2020.- whichever would occur first. On June 30, 2020, McDermott International Inc. notified the occurrence of the effective date of the reorganization plan, for which the suspension of arbitration was lifted on July 1, 2020.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

On May 6, 2020, the Superintendence of Companies ordered the judicial liquidation of CBI Colombiana SA, one of the defendants in the CB&I arbitration. On October 22, 2020, Reficar requested its recognition as a creditor of CBI Colombiana SA, up to the maximum amount of its claims in the arbitration. On January 15, 2021, the liquidator of CBI Colombiana SA 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 Court ordered the submission of post-hearing briefs for October 15 and November 5, 2021. Likewise, the Court summoned the parties to a hearing on closing arguments for November 18, and 19, 2021.

On August 16, 2021, the parties requested the Court to modify the procedural calendar, consisting of slightly altering the dates of presentation of the post-hearing briefs. On August 26, 2021, the Court granted the request of the parties, so the post-hearing briefs were presented on October 22 and November 10, 2021. The closing arguments hearing was held in a single session on November 18, 2021, and the session scheduled for November 19, 2021, was dispensed with.

Subsequently, on December 20, 2021, Refinería de Cartagena presented its memorial for costs in the Arbitration against CB&I. Until the Court issues its final decision, the result of this arbitration is unknown.

Investigations of control entities – Reficar

Reficar is a wholly owned subsidiary of Ecopetrol S.A. According to Colombian regulations, Ecopetrol’s and Reficar’s employees are considered public servants, and as such can be held liable for negligent use or management of public resources. In this context, given that Ecopetrol S.A. is majority owned by the Colombian Government and Reficar is a wholly owned subsidiary of Ecopetrol, Ecopetrol and Reficar administer public resources.

As a result, Ecopetrol S.A. and Reficar employees are generally subject to the control and supervision of the following control entities, among others:

1.Office of the Comptroller General (Contraloría General de la República – CGR):

Financial Audit for the 2021 period

The CGR executed a financial audit of Refinería de Cartagena between January 17 and May 31, 2022.

In the Final Audit Report, two issues of an administrative nature are established, and it is indicated that (i) the budget execution is reasonable, since the budget was prepared and executed in accordance with the applicable regulations, (ii) the internal financial control was efficient, since it is adequate and effective controls according to the risks that are inherent to the different processes, procedures and activities during the 2021 period, and (iii) that the accounting opinion is negative, since the CGR considered that the financial statements “do not reasonably present all the important aspects, the financial situation as of December 31, 2021”, due to the discovery of higher values in the property, plant, and equipment account, due to the alleged overestimation in 2.9 trillion pesos of this accounting account.

Considering the above, the CGR did not terminate the fiscal account for the 2021 term.

Compliance audit

The CGR executed a compliance audit of the Refinería de Cartagena between July 18 and December 6, 2022, with the following objectives: (i) Evaluate the execution and results of the Cartagena Crude Plant Interconnection Project (“IPCC Project”) ), and (ii) Monitor the progress of the improvement plan for the finding “greater values recognized in property, plant, and equipment”.

The Final Audit Report establishes 6 administrative findings, indicating that: (i) the result of the combined risk and fraud assessment is low, (ii) the concept of compliance with the regulations applicable to the IPPC Project is unreserved, and (iii) after reviewing the activity of the improvement plan, the CGR considers that it does not “rectify the condition of the issue”.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Fiscal responsibility processes

PRF-2018-00684-PRF-017-2018

Due to the late entry into operation that generated lost profits, the CGR is executing an independent process in which various requirements have been met.

Through Order 167 of February 3, 2022, the CGR archived the process due to the non-existence of damage, and the non-accreditation of injury to public property, mainly due to force majeure due to the labor abnormality and the winter wave that occurred.

PRF-80011-2018-33300

Through Order No. 1328 of August 24^th, 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 (three former presidents and five former financial vice-presidents) are investigated.

According to the press release, the CGR attributes the alleged damage to unidentified expenses associated with the Project, amounting to US$9,240,927 from the period June to December 2015 and US$12,447,618 from the periods 2016 to 2018; and 268.71 MUSD that, being approved and entered the refinery budget, do not show what was executed within the Project.

At present, the process is pending imputation or archiving.

In this process, the Cartagena Refinery was considered an affected entity by the CGR.

-PRF-2017-01208 Contract 5210733.

On November 7, 2017, the CGR began the Fiscal Responsibility Process, related to contract 5210733, whose purpose is to provide the “Comprehensive maintenance service for tanks and vessels for Refinería de Cartagena S.A. and the Nestor Pineda Terminal of Ecopetrol S.A.”.

On March 20, 2022, the CGR confirmed that Refinería de Cartagena was considered an affected entity within this process.

On June 30, 2022, the CGR issued the filing order for this process.

It is clarified that the Refinería de Cartagena was not the subject of the proceedings, and workers of the Company were not linked to the process.

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, workers of the Chicago Bridge and Iron Company (CB&I) and the Statutory Auditor of Refinería de Cartagena 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. In this process, Refinería de Cartagena and Ecopetrol S.A. were officially recognized as victims.

On November 25, 2019, the trial preparatory hearing was installed and is currently taking place.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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, for the crimes of aggravated unfair administration, and obtaining a false public document. In this process, Refinería de Cartagena and Ecopetrol S.A. were officially recognized as victims.

On November 18, 2019, the preparatory trial hearing was installed, and it is currently being developed.

Proceeding 3 – 110016000101201800134 – Subscription of contract PMC - Foster Wheeler

This process is being carried out against two ex-employees of Refinería de Cartagena who acted as ex-president on property and ex-president in charge, for the crime of entering into a contract without legal requirements. In this process, Refinería de Cartagena and Ecopetrol S.A. were officially recognized as victims.

On August 18, 2022, a sentence was handed down imposing the minimum penalty for the crime charged, equivalent to 64 months in prison and a fine of (66.66) SMLMV. On August 25, 2022, the defenders of the defendants supported the appeal briefs, and the parties were notified to rule.

Proceeding 4 - 110016000000201702546 – Principle of opportunity

This process is being executed against an ex-employee of the Refinería de Cartagena, for charges related to crimes against the public administration, and illegal interest in the execution of contracts.

The criminal action is suspended until December 2023, due to the application of the principle of opportunity.

3.Office of the Attorney (Procuraduría General de la Nación - PCG)

There are six (6) disciplinary actions carried out by the PGN, which are in stages of a reserved nature.

The Company was aware of one (1) action associated with the Project that was archived, as follows:

-IUS 2012-332368 – IUC D-2017-981346

By Order dated October 21, 2020, the PGN issued an indictment against an ex-employee of Refinería de Cartagena for the commission of a very serious offense as a very serious fault for the preparation of the PIP. In the same decision, the investigation was closed against seven people, including former workers and former members of the Board of Directors of Refinería de Cartagena, considering that they did not commit disciplinary offenses.

On October 31, 2022, the PGN issued a filing order since the phenomenon of the prescription of disciplinary action was configured.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

23.5Detail of contingent liabilities

The following is a summary of the main contingent liabilities that have not been recognized in the statement of financial position as, according to the evaluations made by internal and external advisors of the Ecopetrol Business Group, the expectation of loss is not probable as of December 31, 2022, and 2021:


	2022		2021
	Number of		Number of
Type of process	processes	Proceedings	processes	Proceedings
Constitutional	122	642,057	86	1,336,966
Ordinary administrative	147	2,590,089	146	1,867,591
Labor	625	68,194	788	87,175
Civil	59	761,090	58	13,148
Penal	—	—	1	—
	953	4,061,430	1,079	3,304,880

23.6Details of contingent assets

The following is a breakdown of the Ecopetrol Business Group’s principal contingent assets, where the associated contingent gain is likely, but not certain:


	2022		2021
	Number of		Number of
Type of process	processes	Proceedings	processes	Proceedings
Ordinary administrative	87	687,332	62	217,550
Arbitration	—	—	1	78,600
Civil	211	30,717	188	23,258
Penal	98	2,453	72	55,385
Labor	406	15,696	185	4,714
Constitutional	10	—	4	—
	812	736,198	512	379,507

24.Equity

24.1

Subscribed and paid–in capital

Ecopetrol’s authorized capital amounts to $36,540,000, and is comprised of 60,000,000,000 ordinary shares, of which 41,116,694,690 are outstanding, and 11.51% (4,731,906,273 shares) are held privately and 88.49% (36,384,788,417 shares) are held by the Colombian Government. The value of the reserve shares amounts to $11,499,933 comprised of 18,883,305,310 shares. As of December 31, 2022, and 2021, subscribed and paid–in capital amounts to COP$25,040,067. There are no potentially dilutive shares.

24.2Additional paid–in capital

Additional paid–in capital mainly corresponds to: (i) share premium from the Ecopetrol Business Group’s capitalization in 2007, for $4,457,997, (ii) share premium from the sale of shares awarded in the second capitalization, which took place in September 2011, of $2,118,468, iii) a $31,377 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).

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24.3Equity reserves

The following is the composition of the Ecopetrol Business Group’s reserves as of December 31, 2022, and 2021:


	2022	2021
Legal reserve	6,407,256	4,737,788
Fiscal and statutory reserves	509,082	509,082
Occasional reserves	1,982,295	5,377,359
	8,898,633	10,624,229

The General Shareholders’ Meeting of Ecopetrol S.A., held on March 30, 2022, approved the 2021 profit distribution project and the establishment of a reserve for $8,889,900, to support the financial sustainability of the Company and flexibility in the development of your strategy. The Extraordinary General Assembly of June 17, 2022, approved the modification of the destination of a part of the occasional reserve to distribute it as an extraordinary dividend for $6,907,605.

The movement of equity reserves is the following for the years ended December 31, 2022, and 2021:


	2022	2021
Opening balance	10,624,229	9,635,136
Release of reserves	(5,886,441)	(5,066,156)
Allocation to reserves	11,068,450	6,055,249
Dividends declared	(6,907,605)	—
Closing balance	8,898,633	10,624,229

24.4Retained earnings and dividends

Ecopetrol Business Group distributes dividends based on its financial statements prepared under International Financial Reporting Standards accepted in Colombia (NCIF, as its acronym in Spanish).

The Ordinary General Assembly of Shareholders of Ecopetrol S.A., held on March 30, 2022, approved the profit distribution project for fiscal year 2021 and defined the distribution of dividends in the amount of $11,512,675 (distribution during 2021: $698,984).The due date for the payments of the ordinary and extraordinary dividends to the minority shareholders was April 21, 2022, and, throughout 2022, in the case of the majority shareholder.

Additionally, the Extraordinary General Assembly of Ecopetrol S.A. of June 17, 2022, approved the modification of the destination of a part of the occasional reserve to distribute it as an extraordinary dividend for $6,907,605. The payment was made in June 2022, for minority shareholders in a single payment, and for the majority shareholder, the entirety of this dividend was offset with the receivable account related to the Fuel Price Stabilization Fund, therefore, did not imply a cash outflow.

Dividends were paid as follows:


	2022	2021	2020
Ecopetrol S.A.	11,622,778	696,387	7,369,498
Oleoducto Central S.A. - Ocensa	752,530	682,615	959,949
Interconexión Eléctrica S.A. ESP	572,260	790,532	—
Invercolsa S.A.	179,202	150,333	148,941
Oleoducto de los Llanos Orientales S.A. - ODL	138,939	147,056	166,589
Oleoducto de Colombia S.A. - ODC	91,238	86,594	89,374
Oleoducto Bicentenario de Colombia S.A.S. - OBC	—	217,770	—
Total	13,356,947	2,771,287	8,734,351

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(Figures expressed in millions of Colombian pesos, unless otherwise stated)

24.5Other comprehensive income attributable to owners of parent

The following is the composition of the other comprehensive income attributable to the shareholders of the parent, Ecopetrol, net of tax:


	2022	2021	2020
Foreign currency translation	28,816,983	17,244,255	11,794,201
Hedge of a net investment in a foreign operation	(9,219,271)	(4,364,466)	(1,494,927)
Actuarial gain on defined benefit plans	(1,331,361)	(517,278)	(2,260,989)
Cash flow hedges for future exports	(2,473,999)	(945,250)	(136,473)
Cash flow hedge with derivative instruments	1,290	(61,502)	43,546
Others	3,077	2,135	1,704
	15,796,719	11,357,894	7,947,062

24.6Earnings per share


	2022		2021		2020
Profit attributable to Ecopetrol’s shareholders		31,604,781		15,649,143		1,586,677
Weighted average number of outstanding shares		41,116,694,690		41,116,694,690		41,116,694,690
Net basic earnings per share (Colombian pesos)	COP$	768.7	COP$	380.60	COP$	38.59

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25.Revenue from contracts with customers


	2022	2021	2020
National sales
Mid–distillates (1)	39,182,510	17,140,327	8,860,588
Gasoline and turbo fuels (1)	27,620,199	15,475,370	6,768,046
Natural gas (2)	4,162,876	3,200,069	2,845,155
Services	3,601,681	3,065,988	2,859,559
Electric power transmission services (3)	2,595,505	728,467	—
Plastic and rubber	1,568,816	1,642,035	865,204
LPG and propane	1,094,332	926,231	375,775
Asphalts	897,200	611,051	526,100
Fuel gas service	860,102	734,666	671,570
Crude oil	375,790	193,476	230,520
Roads and Construction Services (3)	355,737	107,179	—
Aromatics	343,792	247,387	155,740
Polyethylene	302,630	320,466	138,035
Fuel oil	9,213	23,799	37,001
Other income gas contracts	1,940	2,879	32,190
Other products	679,183	402,828	322,232
Cash flow hedges (4)	—	(8)	—
	83,651,506	44,822,210	24,687,715
Foreign sales
Crude oil (2)	56,651,753	34,868,421	20,086,173
Electric power transmission services (3)	5,114,783	1,827,622	—
Roads and Construction Services (3)	4,676,822	1,241,144	—
Fuel oil	4,348,312	2,288,977	1,044,811
Diesel	2,324,861	3,867,937	3,164,068
Plastic and rubber	2,036,201	2,092,379	1,302,131
LPG and propane	339,837	116,960	18,943
Natural gas	254,054	71,529	17,231
Gasoline and turbo fuels	157,685	—	179,257
Cash flow hedges (4)	(1,578,246)	(349,884)	(857,347)
Other products (5)	1,633,510	1,033,909	580,411
	75,959,572	47,058,994	25,535,678
	159,611,078	91,881,204	50,223,393

(1)

Corresponds to the application of Decree 180522 of March 29, 2010, and other standards that modify and add (Decree 1880 of 2014 and Decree 1068 of 2015), which establishes the procedure to recognize the subsidy for refiners and importers of ordinary motor gasoline and ACPM, and the methodology for calculating the net position (value generated between the parity price and the regulated price, which can be positive or negative). As of December 31, 2022, the value recognized by price differential corresponds to $36,532,743 (2021 $11,335,453; 2020 ($142,723)).

(2)

With the implementation of the IAS 16 Amendment on the management of the sale of products obtained in the project stage or extensive tests mandatory as of January 1, 2022, Ecopetrol Business Group recognizes as of that date, the income received from the product of the sale of hydrocarbons in the stage prior to their declaration of commerciality of the oil fields. The cost related to these revenues is disclosed in Note 26 – Cost of sales. As of December 2022, the value recognized for extensive tests is as follows: natural gas for national sales $44,962 and crude oil for foreign sales $141,242.

(3)	Corresponds to the revenue related to the electric power transmission contracts and toll roads concessions of Interconexión Eléctrica S.A. E.S.P. See Note 4.17 – Revenue from contracts with customers.

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(4)	Includes accumulated as of December 31 the result of i) hedges for future exports (Note 30.3) for ($1,143,287) (2021: ($249,978); 2020: ($193,374)) and ii) operations with derivative financial instruments for ($434,959) (2021: ($99,914); 2020: ($663,973)).

(5)	Includes revenue from telecommunications services provided by Interconexión Eléctrica S.A. E.S.P. and the sale of diesel, asphalt, and other products.

Sales by geographic areas


	2022	%		2021	%		2020	%
Colombia	83,651,506	52.4	%	44,822,210	48.8	%	24,687,715	49.2	%
Asia	22,547,997	14.1	%	20,355,063	22.2	%	9,497,498	18.9	%
United States	27,120,783	17.0	%	16,025,083	17.4	%	11,365,218	22.6	%
South America and others	13,609,587	8.5	%	5,727,355	6.2	%	1,296,370	2.6	%
Central America and the Caribbean	9,841,202	6.2	%	3,503,618	3.8	%	2,581,644	5.1	%
Europe	2,840,003	1.8	%	1,447,875	1.6	%	794,948	1.6	%
	159,611,078	100	%	91,881,204	100	%	50,223,393	100	%

Concentration of customers

During 2022, Organización Terpel S.A. represented 9% of sales revenue for the period (2021 – 11% and 2020 – 15%); no other customer represented more than 10% of total sales. There is no risk of the Ecopetrol Business Group’s financial situation being affected by a potential loss of the client. The commercial relationship with this customer 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 and Colombia.

The main concessions are the following:

Concessions in Colombia

Intelligent Network Systems, through a business collaboration agreement entered into with UNE EPM Telecomunicaciones S.A. and Consorcio ITS, executes the addendum number 5 of the Inter-administrative Agreement 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)”, in which the payment consists in the right to participate in the resources received from the penalty fees collected through the photodetection system within the municipality.

This contract is within the scope of IFRIC 12 under the intangible model, because the Municipality of Medellín, as the grantor, controls what services the operator must provide with the infrastructure, who must be charged, and at what price. In addition, the Municipality of Medellín controls, through ownership of the right of use, any significant residual interest in the infrastructure at the end of its useful life.

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Notes to the consolidated financial statements

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Ruta Costera

Under the public-private partnership scheme, considering the terms of Law 1508 of 2012, and from the act of awarding the Public Tender VJ-VE-IP-LP-0011-2013, issued by the National Infrastructure Agency (ANI), through Resolution No. 862 of July 2, 2014, on September 10, 2014, the ANI and the concessionaire signed the Concession Contract No. 004 of 204. The purpose is to “execute 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 contract is within the scope of IFRIC 12 under the financial asset model for investment in construction (construction services). The concession receives income from the following sources of compensation: ANI contributions, tolls collections and revenues from commercial exploitation. If the concessionaire does not achieve the expected revenue from toll collection, the grantor (ANI) will recognize and pay the concessionaire the collection differential in years 8, 13 and 18, contractually denominated as present value of the reference month of toll collection. The revenue guarantees represent an unconditional contractual right to receive cash or other financial assets for construction services provided. The contractually guaranteed payment is a specific and determinable amount.

As of December 31, 2021, a progress of 97.24% was obtained for Functional Unit 3 and 99.94% for Functional Unit 6, achieving a consolidated progress of the project of 99.91% and commissioning of the entire road corridor.

Concessions in Brazil

For concession contracts in Brazil to supply public electric power transmission services, the operator has the right in the contractual asset while the concessionaire complies with the obligation to build and implement the transmission infrastructure, recognizing revenues throughout the time of the project. At the end of the concession, the assets linked to it will be reverted, determining and calculating the compensation to be recognized by the operator.

The concession contracts of ISA CTEEP and TAESA were analyzed and classified in accordance with IFRS 15 - Revenue from contracts with customers within the contractual asset model as of the 1st of January 2018.

The value of the contractual asset of the electric power transmission concessionaires is formed by the present value of their future cash flows, which are determined at the beginning of the concession or in its extension and is revalued in the Periodic Tariff Review.

The cash flows are defined based on the remuneration that the concessionaires receive for supplying the public transmission service to the users, Receita Anual Permitida (RAP). These resources amortize the investments made in the transmission infrastructure. Any investments that are not amortized (reversed assets) generate the right to compensation from the grantor, equivalent to the additional remuneration of the entire transmission infrastructure at the end of the concession contract. This flow of future collections is updated for inflation (IPCA/IGPM) and remunerated by a discount rate that represents the financial component of the business defined at the beginning of each project.

During the stage of the execution of the construction of the work, the concessionaire has the right to the consideration in accordance with the fulfillment of the completion of the work and the performance obligations, and not only with the time used for the construction. The revenue is recognized for the value of the expenses incurred in the formation of the asset plus a construction margin.

Construction and remuneration revenues from concession assets are subject to deferral of the cumulative Social Integration Program and the Contribution for the Financing of Social Security (Cofins), recognized as deferred taxes (non-current liabilities).

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Concessions in Chile

Road concession contracts for the supplying the public service of road infrastructure in Chile, may consider traffic risk or guaranteed total income according to a revenue distribution mechanism or a present value of revenue, which in the latter cases, allow the total revenue of the concession to be collected in a guaranteed way in 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 there is a traffic risk, that is, whether its revenue is guaranteed or not and whether it is enough to pay for the investment. 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. In the other hand, if the contract establishes income and compensation guarantee mechanisms, it is recognized as a financial asset. This 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 Peru

Due to the terms and conditions contained in the concession contracts in Peru to provide public electricity transmission services, similar in their legal terms and in the rights and obligations with the Government, the model that applies to the concession contracts for the public energy transmission service in ISA REP, ISA Perú, and Consocio Transmantaro is the intangible asset model. It applies when the services provided by the operator are paid by the users or when the grantor does not unconditionally guarantee the collection of accounts receivable, and represents the right granted by the Peruvian State to charge users of the energy transmission service. This right is not an unconditional right to receive cash.

Concessions in Bolivia

Like the type of contracts in Peru, in those of concession to provide public energy services in Bolivia, the unconditional receipt of cash by the operator is not guaranteed, assuming the credit risk associated with the collection of amounts invoiced, which would mean that the company cannot recover the entire 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 assignor has no obligation to pay for the construction services received and, in this sense, the model that adjusts to the contractual conditions and framed by IFRIC 12 is the intangible asset model.

Committed investments

ISA and its companies have committed investments of $22.4 billion pending execution in the 2023-2030 period. These investments correspond to the balance pending execution of contracts already awarded, and to estimated needs for reinforcements and expansions of existing infrastructure and replacement of assets. These investments include 100% of the projects of the controlled companies and the capital contributions in the companies with shared control, which are estimated to be necessary to fund the portion corresponding to capital of the committed investments.

The 60% of the investment will be executed in the 2023-2025 period and 40% between 2026 and 2030. Ninety percent of the investment will be concentrated in the energy transmission business, 5% in roads and the remaining 5% in telecommunications. 55% of the committed investment will be executed in Brazil, where ISA CTEEP and subsidiaries will continue to work on the projects awarded in past tenders, and on the plan to reinforce and improve the transmission network.

In Colombia, 25% of the investment will be executed, mainly associated with energy transmission projects from UPME calls, connections, and asset replacement.

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The 14% of the committed investment will be developed in Chile, of which one third corresponds to the road business, and the remaining capex, to energy transmission. Six percent of the committed investment will be made in Peru, Argentina, and Bolivia.

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


	2022	2021	2020
Variable costs
Imported products (1)	31,230,405	16,944,375	7,592,489
Purchases of crude in association and concession	16,223,628	10,015,898	4,281,661
Purchases of hydrocarbons – ANH (2)	9,219,215	5,611,153	2,798,432
Depreciation amortization and depletion	6,774,770	6,328,144	6,069,903
Electric energy	1,540,452	1,087,269	1,098,621
Taxes and economic rights	1,510,265	1,125,761	841,443
Process materials	1,260,608	906,500	827,464
Purchases of other products and gas	1,244,765	811,024	598,015
Hydrocarbon transport services	1,219,818	917,552	874,632
Services contracted in associations	311,107	267,934	269,637
Extensive tests (3)	71,304	—	—
Others (4)	(2,426,118)	(3,009,700)	657,634
	68,180,219	41,005,910	25,909,931
Fixed costs
Depreciation and amortization	4,635,601	3,270,735	2,930,120
Maintenance	3,771,137	2,637,857	2,257,370
Labor costs	3,436,167	2,596,947	2,299,761
Construction services	2,802,486	732,723	—
Services contracted	2,870,890	2,023,277	1,623,375
Services contracted in associations	1,566,562	1,286,291	1,121,010
Taxes and contributions	914,455	1,060,123	593,041
Materials and operating supplies	684,679	561,182	508,037
Hydrocarbon transport services	179,082	57,855	253,752
General costs	416,870	348,876	71,075
	21,277,929	14,575,866	11,657,541
	89,458,148	55,581,776	37,567,472

(1)	Imported products correspond mainly to mid-distillates and gasolines. The variation corresponds to the higher national demand of these products, considering the maintenance programmed for the refineries for 2022, and diluent to facilitate the transport of heavy crude oil.

(2)	Corresponds to purchases of crude oil by Ecopetrol Business Group from the National Hydrocarbons Agency (ANH, by its acronym in Spanish) derived from national production.

(3)

Corresponds to the cost related to revenue from the sale of hydrocarbons (Note 25 - Revenue from contracts with customers), obtained in exploration stage or extensive tests prior to the declaration of commerciality of the oil fields. This recognition is the result of the application of the IAS 16 Amendment, mandatory as of January 1, 2022.

(4)	Corresponds to i) result of the process of use and valuation of core inventories, ii) measurement at net realizable value, and iii) other capitalizable charges to projects.

27.Administrative, operative, and project expenses

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	2022	2021	2020
Administrative expenses
General expenses	(2,040,773)	(1,638,129)	(1,424,348)
Labor expenses (1)	(1,663,464)	(1,264,319)	(1,658,613)
Taxes	(57,944)	(52,889)	(60,397)
Depreciation and amortization	(573,514)	(386,732)	(229,792)
	(4,335,695)	(3,342,069)	(3,373,150)
Operations and project expenses
Exploration costs	(1,512,268)	(959,562)	(689,087)
Commissions fees freights and services	(1,326,184)	(686,156)	(656,432)
Taxes	(781,181)	(515,848)	(428,608)
Labor expenses	(363,838)	(312,791)	(309,972)
Fee for regulatory entities	(192,094)	(139,158)	(142,695)
Maintenance	(162,383)	(156,412)	(78,181)
Depreciation and amortization (2)	(145,106)	(174,311)	(94,723)
Others	(260,574)	(209,319)	(186,318)
	(4,743,628)	(3,153,557)	(2,586,016)

28.Other operating (expenses) income


	2022	2021	2020
Expense for legal provisions	(516,288)	(650,926)	(139,978)
Loss on sale of assets (1)	(86,954)	(123,342)	(263,647)
Impairment loss of current assets	(101,871)	(83,773)	(34,416)
Gain on revaluation of assets in Guajira association (2)	—	—	1,284,372
Gain on acquisition of participations and interests (2)	—	—	86,026
Gain on loss of control in subsidiaries (3)	—	—	65,695
Other income (4)	149,258	785,297	120,114
	(555,855)	(72,744)	1,118,166

(1)

It mainly corresponds to the end of Rygberg’s association contract in Ecopetrol America, and the profit on the sale of the total participation of Ecopetrol S.A. in the Casanare, Estero, Garcero, Orocué and Corocora Association (CEGOC). This sale of fields was made to its partner Perenco Oil and Gas Colombia.

(2)	Results in the acquisition of Guajira in 2020: Ecopetrol S.A. $1,284,372 and Hocol $86,026. For Ecopetrol S.A. it corresponds to the revaluation of the assets that it already had in the Guajira association and for Hocol it corresponds to the Bargain obtained from the acquisition of the 43% stake.

(3)	Recognition in 2020 of the disposal of net assets due to the loss of control due to the opening of the judicial liquidation process of Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S. $65,570 and liquidation process of ECP Oil and Gas Germany GmbH COP$125.

(4)	For 2021, it mainly corresponds to the compensation received by Cenit Transporte y Logística de Hidrocarburos and Oleoducto Bicentenario de Colombia, because of the approval of the conciliation agreement with the Frontera Group.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

29.Financial result


	2022	2021	2020
Finance income
Yields and interests	965,952	266,116	299,246
Results from financial assets	178,212	108,640	665,310
Gain (loss) on derivatives valuation	18,099	(406)	—
Dividends	70	27	44
Gain on derivatives liquidation	—	10,695	108,838
Other financial income	154,812	18,520	27,992
	1,317,145	403,592	1,101,430
Finance expenses
Interest	(5,517,417)	(3,095,224)	(2,384,342)
Financial cost of other liabilities (1)	(2,003,687)	(1,043,728)	(872,987)
Results from financial assets	(152,355)	(101,973)	(473,598)
Other financial expenses	(353,793)	(190,723)	(198,864)
	(8,027,252)	(4,431,648)	(3,929,791)
Foreign exchange gain
(Loss) gain from exchange difference	(124,650)	(31,726)	346,774
Gain from realization of other comprehensive income on sale of joint ventures (2)	—	361,728	—
	(124,650)	330,002	346,774
Financial result	(6,834,757)	(3,698,054)	(2,481,587)

(1)

Includes the financial expense of the asset retirement obligations and the liabilities for post–employment benefits.

(2)

On January 19, 2021, through the signing of the share purchase agreement (Share Purchase Agreement) with one of the subsidiaries of De Jong Capital LLC., in its capacity as buyer, Ecopetrol S.A. formalized the sale of all the shares in the company Offshore International Group (OIG), in which it had a participation equivalent to 50%. This operation generated the following impacts on the results of the period: profit from the sale of assets for $4,923 and the realization of other comprehensive income for $361,728.

30.Risk management

30.1Exchange rate risk

The Ecopetrol Business 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, 2022, the Colombian peso depreciated 20.82%, going from a closing rate as of December 31, 2021, of COP$3,981.16 to COP$4,810.20 pesos per dollar.

When the Colombian peso depreciates, export earnings, when converted to pesos, increase, and imports and external debt service become more expensive.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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)	2022	2021
Cash and cash equivalents	615	388
Other financial assets	955	408
Trade receivables and payables, net	(392)	423
Loans and borrowings	(16,113)	(15,514)
Other assets and liabilities, net	202	702
Net liability position	(14,733)	(13,593)

Of the total net position, USD$(14,566) million correspond to net liabilities of companies with Colombian peso functional currency, of which USD$(14,512) correspond to loans used as hedging instruments whose valuation is recognized in other comprehensive income, the exchange difference valuation of the remaining net liabilities for USD$54 million affects the statement of profit and loss. Likewise, USD$(167) 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 1% and 5% 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, 2022:


Scenario / Variation in	Effect on income	Effect in other
the exchange rates	before taxes +/–	comprehensive income +/–
1%	10,618	698,068
5%	53,092	3,490,342

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 designated the sum of USD$5,440 million of Ecopetrol’s debt as a hedging instrument for its future revenues from crude oil exports, for the period 2015 – 2023. As of December 31, 2022, the current balance of this hedging corresponds to USD$1,300 million.

During the years 2022 and 2021, USD$4,272 million were designated as a hedging instrument for future income from the export of crude oil, for the period 2022-2030; in accordance with IFRS 9 – Financial instruments.

The following is the movement of this non-derivative hedging instrument:


(US$Million)	2022	2021
Hedging instrument at the beginning of the period	4,972	1,300
Reassignment of hedging instruments	1,879	675
Realization of exports	(1,879)	(675)
Designation of new coverage	600	3,672
Hedging instrument at the end of the period	5,572	4,972

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following is the movement in other comprehensive income for the years ended December 31, 2022, 2021 and 2020:


	2022	2021	2020
Opening balance	(945,250)	(136,473)	(135,751)
Exchange difference	(4,317,263)	(1,533,743)	(201,967)
Reclassification to profit or loss	1,143,287	249,978	193,374
Ineffectiveness	6,625	24,496	9,779
Deferred income tax	1,638,602	450,492	(1,908)
Closing balance	(2,473,999)	(945,250)	(136,473)

The expected reclassification of the cumulative exchange difference from other comprehensive income to the profit or loss is as follows:


Year	Before taxes	Taxes	After taxes
2023	1,910,677	(887,863)	1,022,814
2024	884,199	(410,875)	473,324
2025	878,587	(408,267)	470,320
2026	864,459	(401,702)	462,757
2027	26,104	(12,130)	13,974
2028	25,561	(11,878)	13,683
2029	24,526	(11,397)	13,129
2030	7,468	(3,470)	3,998
	4,621,581	(2,147,582)	2,473,999

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 Business 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 Business Group’s U.S. dollar denominated debt as the hedging instrument.

Ecopetrol Business Group designated as the hedged item the net investments in Oleoducto Central S.A. (Ocensa), Ecopetrol América LLC., Hocol Petroleum Ltd, (HPL) and Refinería de Cartagena S.A.S. (Reficar) and as a hedging instrument a portion of its debt denominated in US dollars, in a total amount equivalent to USD$5,200 million.

During 2019 and 2020 Ecopetrol S.A. expanded this hedge to include investments in Ecopetrol Permian LLC and Ecopetrol Brazil in the designation. At the close of December 31, 2020, the amount of the hedge amounted to USD$7,249 million.

During 2021 Ecopetrol Business Group expanded this hedge for USD$1,229 million to add a greater amount of designation for Refinería de Cartagena. In 2021, also capital payments of USD$270 million were made (June USD$163 and December USD$107 million). The total hedged balance as of December 31, 2021, is USD$8,208 million.

During 2022, an expansion for USD$750 million was carried out to add a greater amount in Permian and principal payments of the debt for USD$325 million were made. The total balance covered as of December 31, 2022, is USD$8,633 million.

Additionally, ISA Colombia made a net investment hedge on the investments in the companies REP, ISA Perú, CTM and PDI for a value of USD$307 million. The hedging instrument corresponds to a green international bond issued on November 26, 2021.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following is the movement in other comprehensive income attributable to owners of parent for the years ended December 31:


	2022	2021	2020
Opening balance	4,366,336	1,494,926	1,130,583
Exchange difference	7,526,124	4,579,758	520,490
Deferred income tax	(2,538,389)	(1,708,348)	(156,147)
Closing balance	9,354,071	4,366,336	1,494,926

30.5Hedging with financial derivatives

The ISA Group has hedges with derivative financial instruments – CCS (Cross Currency Swaps) and IRS (Interest Rate Swap) to hedge exchange rates. These hedges are recognized as cash flow hedges.


Company	Derivative instrument	2022	2021
Red de Energía del Perú (1)	Cross currency swap	48,195	106,333
Intervial Chile (2)	Cross currency swap	77,229	30,769
Ruta del Maipo (3)	Cross currency swap	—	11,042
		125,424	148,144

(1)

The company designated these derivative instruments as cash flow hedges, to mitigate exposure to exchange rate volatility of interest payments in Peruvian sol of the First Issue Series A and First Issue Series B of the Third Corporate Bond Program, considering that its functional currency is the US dollar.

(2)

In 2021, a UF currency hedging operation was subscribed as a debt strategy in Chilean pesos.

(3)

The subsidiary has a cross currency swap as a hedging instrument, the purpose of which is to reduce exposure to changes in future cash flows due to changes in the exchange rate that affect the bond held by the entity in US dollars and the UF variation due to future flows from toll collections.

30.6Commodity price risk

The price risk of raw materials is associated with Ecopetrol Business Group’s operations, both exports and imports of crude oil, natural gas, and refined products. To mitigate this risk, the 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.

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.

Ecopetrol Business Group has a policy for the execution of (strategic and tactical) hedges and implemented processes, procedures, and controls for their management:

●

The main purpose of the strategic hedging program is to protect the separate and consolidated financial statements against the volatility of market variables in each period, protect income and thus cash flow. During 2022, a hedging plan was executed to protect the box against low price scenarios below the budget base price, in this sense, put options were purchased. As of December 31, 2022, there was no balance of these financial instruments on the balance sheet.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

●

On the other hand, tactical hedges allow capturing value in trading operations and Asset Backed Trading (ABT), mitigating the market risk of specific operations. In the trading activity, the commitments in spot and forward physical contracts imply an exposure to commodity price risk, particularly the risk associated with the volatility of the price of crude oil and refined products. Although said exposure is part of the natural risk of the production, refining and marketing activity carried out by the Business group, sometimes marketing, to maximize value capture, can concentrate risk exposure in terms of term and/or or indicator that differs from the Company’s natural price risk profile. As of the date of this report, Ecopetrol S.A. recognizes a total net liability position in Swaps for $28,519 (2021: liability $34,395) and Ecopetrol Trading Asia PTE. LTD a total active net position in Swaps for $6,544. The constitution of these operations with derivatives is recognized under cash flow hedge accounting.

30.7

Credit risk

Credit risk is the risk that the Ecopetrol Business 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 selling process of crude oil, gas, refined products and petrochemicals, transport services, energy transmission, roads and telecommunications, the Ecopetrol Business Group may be exposed to credit risk if customers fail to fulfill their payment obligations. The Ecopetrol Business Group’s risk management strategy has designed mechanisms and procedures that aim to minimize such events, thus safeguarding the Ecopetrol Business Group’s cash flow.

The Ecopetrol Business Group performs a continuous analysis of the financial strength of its counterparties, by classifying them according to their risk level and financial guarantees in the event of a default of payments. Similarly, the Ecopetrol Business 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.

For the receivables that are considered exposed to credit risk, Ecopetrol Business Group make individual analysis of each customer’s situation to determine the value of impairment to recognize in financial statements. The Ecopetrol Business 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, 2022, and 2021 is as follows:


	2022	2021
Less than 3 months overdue	171,896	332,249
Between 3 and 6 months overdue	67,985	7,103
More than 6 months overdue	456,046	4,418
	695,927	343,770

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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

In addition, Ecopetrol Business 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’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 Company 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, Ecopetrol Business Group does not invest more than 10% of the cash excess in one specific issuer. In the case of the U.S. dollar portfolio, Ecopetrol Business 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 Business Group has investments in fixed and floating–rate instruments and has issued floating rate debt linked to LIBOR, DTF, and CPI interest rates. Thus, interest rate volatility may affect the fair value and cash flows of the Ecopetrol Business Group’s investments and the financial expense of floating rate loans and financing.

As of December 31, 2022, 26.4% (2021, 25.7% and 2020, 16%) of the Ecopetrol Business 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.

Ecopetrol Business 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 Ecopetrol Business 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 mark to 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 Business 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	Financial
	Assets *	Liabilities	Plan Assets
+100 basis points	(57,833)	842,534	(346,784)
–100 basis points	57,833	(887,053)	352,209

(*)This sensitivity was executed for portfolios of Ecopetrol S.A. and Black Gold Re. These are the most relevant of the Ecopetrol Business Group.

A sensitivity analysis of discount rates on pension plan assets and liabilities is disclosed in Note 22 – Provisions for employees’ benefits.

30.9Liquidity risk

The ability to access credit and capital markets to obtain resources for the investment plan execution for Ecopetrol Business Group may be limited due to adverse changes in market conditions. A global financial crisis could worsen risk perception in emerging markets.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 Business Group may be forced to review the conditions of the investment plan, or access financial markets under unfavorable terms, thereby negatively affecting the Ecopetrol Business Group’s results of operations and financial results.

Liquidity risk is managed in accordance with the Ecopetrol Business Group’s policies aimed at ensuring that enough cash flows to comply with the Ecopetrol Business 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, 2022. 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$4,810.20 per U.S. dollar:


	Up to 1 year	1–5 years	5–10 years	> 10 years	Total
Loans (payment of principal and interest)	22,915,877	58,620,843	39,406,585	49,615,059	170,558,364
Trade and other payables	19,937,704	62,647	—	—	20,000,351
	42,853,581	58,683,490	39,406,585	49,615,059	190,558,715

30.10Risk and opportunities related to climate

Ecopetrol Business Group made progress in the process of identifying and assessing physical and transition climate risks, considering short, medium, and long-term climate scenarios. Physical and transition risks are often seen as opposites. The greatest transition risks are associated with more aggressive reduction policies, while physical risks increase due to extreme weather events in lax policy scenarios that deviate from the objectives of the Paris Agreement. The IEA (International Energy Agency), the IPCC (Intergovernmental Panel on Climate Change) and the SSP (Shared Socio-economic Pathway) have developed multiple future climate scenarios that capture a series of policy decisions and climate outcomes.

●

Physical risks: related to the Business Group’s exposure and vulnerability to the impacts of climate change and climate variability, which could affect the availability of water and increase the exposure of assets to possible damages and operational disruptions.

For the case of Ecopetrol S.A., the Company executed the analysis and the identification of seven (7) physical risks related to chronic threats (drought and thermal stress) and acute threats (precipitation, coastal flooding, fluvial flooding, fires, and winds) at 95 points associated with the company’s main assets. The modeling was carried out through Cervest's EarthScan platform, using the following IPCC scenarios: (i) scenario aligned with the objective of the Paris Agreement (SSP1-RCP2.6), (ii) scenario peak emissions in 2040 (SSP2- RCP4.5), and (iii) business as usual scenario (SSP5- RCP8.5). EarthScan uses regional climate models with diverse data sets to analyze the physical vulnerability of assets, relative to the potential impact of climate hazards. The probability and severity of climatic events are estimated up to 2100.

Ecopetrol S.A. also has an analysis of vulnerability for climate variability scenarios associated with the “El Niño” phenomena and its opposite phase “La Niña”. The frequency and intensity of these phenomena have been increasing in Colombia.

●

Transition risk: related to the challenges that the company has identified to move towards a low-carbon, sustainable and competitive operation. The following are the identified risks:

Regulatory risk, associated with regulatory changes that may directly affect the Business Group in the short and medium term. Among the regulatory changes, the following can be highlighted: (i) new information requirements for the application or modification of current and future licenses (GHG emissions, vulnerability and climate risks analysis, adaptation measures, among others), of which Ecopetrol Business Group could not have the information available, (ii) new regulations for the detection and repair of leaks, flaring, and venting of gas, (iii) disclosure requirements on

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

environmental and social matters by the Financial Superintendence of Colombia, (iv) greater limitations on the use of offsetting to meet decarbonization goals, among others.

Legal risk, associated with the negative reactions and lawsuits against the climate action of the company.

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 Ecopetrol Business Group of not being able to meet market demand and of not advancing effectively in the development of these products and the impact in the costs due to the change in carbon prices.

Reputational risk, associated with the impossibility of responding in a timely way to the expectations and demand of investors and other interest groups to establish ambitious objectives regarding climate change, which would affect the image of Ecopetrol Business 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.

Ecopetrol S.A. defined a modeling exercise that prioritized market and regulatory risk, for the upstream segment, using the following analysis routes: (i) quantification of the impact on revenues derived from a changing demand for hydrocarbons, (ii) quantification of the impact in costs due to changes in carbon prices, and (iii) quantification of the financial repercussions derived from higher abatement costs associated with limitations on the use of offsets. The model used the International Energy Agency WEO 2022 scenarios: (i) Net Zero Emissions (NZE), (ii) Announced Pledges Scenario (APS), and (iii) Stated Policies Scenario (STEPS). The portfolio's resilience was evaluated by comparing the net present value of future cash flows from the IEA scenarios with the net present value of Ecopetrol's base case. In both cases, the hypotheses associated with the analysis routes were applied. The foregoing will be subject to review and assessment to establish the potential impact on the financial and strategic planning of the company.

The opportunities derive from the analysis of risks associated with the climate, the review of the energy transition scenarios, the implementation of the decarbonization plan and the alignment with the 2040 strategy. Opportunities have been identified related to the diversification of the traditional business, the incorporation into the portfolio of sustainable and low-emission businesses, the diversification in energy power and infrastructure markets, and the strengthening of energy efficiency and renewable energies.

30.11Capital management

The main objective of the capital management of the Ecopetrol Business 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:


	2022		2021
Loans and borrowings (Note 20)	115,134,839		95,060,928
Cash and cash equivalents (Note 6)	(15,401,058)		(14,549,906)
Other financial assets (Note 9)	(2,725,871)		(2,934,734)
Net financial debt	97,007,910		77,576,288
Equity (Note 24)	113,903,089		90,583,772
Leverage (1)	45.99	%	46.13	%

(1)Net financial debt / (Net financial debt + Equity)

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

31.Related parties

Balances with associates and joint ventures as of December 31, 2022, and 2021 are as follows:


		Accounts
	Accounts	receivable	Other	Accounts		Other
	receivable	– Loans	assets	payable	Loans	liabilities
Joint Ventures
Equion Energy Limited (1)	127	—	1,087	2,004	815,056	2,698
Ecodiesel Colombia S.A.	13,155	—	—	53,821	—	3
Interligação Elétrica do Madeira S.A.	89,505	—	—	—	—	—
Interligação Elétrica Garanhuns S.A.	—	40	—	—	—	—
Interligação Elétrica Ivaí S.A.	—	182	—	—	—	—
Derivex S.A.	—	335	—	—	—	—
Associates
Gas Natural del Oriente S.A. E.S.P.	—	—	—	7,048	—	—
Extrucol S.A.	2	—	—	854	—	—
E2 Energía Eficiente S.A. E.S.P.	7,397	—	—	4,152	—	—
Balance as of December 31, 2022	110,186	557	1,087	67,879	815,056	2,701
Current	110,186	222	1,087	67,879	815,056	2,701
Non–current	—	335	—	—	—	—
	110,186	557	1,087	67,879	815,056	2,701
	(Note 7)	(Note 7)	(Note 11)	(Note 21)	(Note 20)


		Accounts
	Accounts	receivable	Other	Accounts		Other
	receivable	– Loans	assets	payable	Loans	liabilities
Joint Ventures
Equion Energy Limited (1)	925	—	1,386	12,997	1,483,701	233
Ecodiesel Colombia S.A.	1,521	—	—	46,452	—	—
Interligação Elétrica Garanhuns S.A.	—	28	—	—	—	—
Interligação Elétrica Paraguaçu S.A.	—	28	—	—	—	—
Interligação Elétrica Aimorés S.A.	—	28	—	—	—	—
Interligação Elétrica Ivaí S.A.	—	28	—	—	—	—
Derivex S.A.	—	335	—	—	—	—
Associates
Gas Natural del Oriente S.A. E.S.P.	—	—	—	5,211	—	—
Extrucol S.A.	—	—	—	283	—	—
E2 Energía Eficiente S.A. E.S.P.	6,797	—	—	1,655	—	—
Balance as of December 31, 2021	9,243	447	1,386	66,598	1,483,701	233
Current	9,243	112	1,386	66,598	1,483,701	233
Non–current	—	335	—	—	—	—
	9,243	447	1,386	66,598	1,483,701	233
	(Note 7)	(Note 7)	(Note 11)	(Note 21)	(Note 20)

Loans:

(1)	Resources deposited by Equion in Ecopetrol Capital AG.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The main transactions with related parties as of December 31 are detailed as follows:


	2022		2021		2020
	Sales and	Purchases	Sales and	Purchases	Sales and	Purchases
	services	and others	services	and others	services	and others
Joint Ventures
Equion Energy Limited	33	23,845	13,996	149,046	27,595	356,872
Ecodiesel Colombia S.A.	21,234	619,286	35,825	442,373	8,268	346,201
Offshore International Group	—	—	—	—	4,461	—
	21,267	643,131	49,821	591,419	40,324	703,073
Associates
Gas Natural del Oriente S.A. E.S.P.	—	53,994	—	27,175	—	26,141
Extrucol S.A.	20	3,411	—	2,354	—	1,162
E2 Energía Eficiente S.A. E.S.P.	90,117	7,908	60,159	6,976	49,860	2,849
	90,137	65,313	60,159	36,505	49,860	30,152
	111,404	708,444	109,980	627,924	90,184	733,225

31.1Directors and key management personnel

In accordance with the approval given by the shareholders’ meeting 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 of 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 2022 for fees to members of the Board of Directors amounted to $3,582 (2021 - $3,757).

The total compensation paid to Executive Officers and Senior Managers as of December 31, 2022, amounted to $27,359 (2021 – $27,735 ). Executive Officers and Senior Managers are not eligible to receive pension and retirement benefits.

As of December 31, 2022, key management officers owned less than 1% of the outstanding shares of Ecopetrol S.A. as follows:


Key management personnel		% Shares
Felipe Bayón		<1% outstanding shares
Jaime Caballero		<1% outstanding shares

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 November 2016, the entities that manage the resources are: Fiduciaria Bancolombia, Fiduciaria de Occidente, and Consorcio Ecopetrol PACC (formed by Fiduciaria La Previsora, Fiduciaria Bancoldex, Fiduagraria, and Fiduciaria Central).

As of 2022, and after a rigorous selection and asset allocation process, the new trust companies that manage the funds related to the pension obligations are Fiduciaria BBVA, Fiduciaria Bogotá, and the Ecopetrol PACC 2021 Consortium, defined by Fiduprevisora, Fiducoldex, FiduAgraria, and Fiducentral.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

By nature of the business, the Business Group purchases the crude oil that the ANH receives from producers in Colombia at the prices set in accordance with an established formula, which reflects the sale prices (crude oils and products), adjusted for API gravity quality, sulfur content, transportation rates to the export ports, refining process cost and a commercialization rate (when apply). The contract between Ecopetrol S.A. and the ANH ended on October 30, 2020, and a new one began with effect from November 1, 2020, to October 31, 2022.

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.

Ecopetrol Business 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

Ecopetrol Business 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. Ecopetrol Business Group does not have any other kind of association or commercial relationship with this entity.

32.Joint operations

The Ecopetrol Business Group carries out exploration and production operations through Exploration and Production (E&P) Contracts, Technical Evaluation (TEA) Contracts and Agreements signed with the National Hydrocarbons Agency or ANH, as well as through Partnership Contracts and other types of contracts.

The main joint operations in 2022 are as follows:

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

32.1Contracts in which Ecopetrol Business Group is not the operator


			%	Geographic area of
Partners	Contract	Type	Participation	operations
	Chipirón		30-41%
SierraCol Energy Arauca, LLC	Cosecha	Production	30%	Colombia
	Cravo Norte		55%
	Rondón		50%
Frontera Energy Colombia Corp	Quifa	Production	40%	Colombia
Union Temporal Ismocol Joshi Parko	CPI Palagua	Production	Variable
			Between 70% and 80%	Colombia
			According amendment
Parex Resources Colombia LTD	Capachos LLA-122	Production Exploration	50%	Colombia
	E&P COL 1		40%
Anadarko Colombia Company (OXY)	E&P COL 2	Exploration	40%	Offshore North Caribe
	E&P COL 6		40%
	E&P COL 7		40%
Petrobras	Tayrona	Exploration	55.60%	Offshore North Caribe
	Fuerte Sur		50%
Shell EP Offshore ventures Limited	Purple Angel	Exploration	50%	Offshore North Caribe
	Col-5		50%
	Mana		30%
Interoil Colombia	Rio Opia	Production	30%	Colombia
	Ambrosia		30%
	Llanos 86		50%
	Llanos 87		50%
Geopark Colombia SAS	Llanos 104	Exploration	50%	Colombia
	Llanos 123		50%
	Llanos 124		50%
	SSJN1	Production	50%
	Perdices		50%
Lewis Energy Colombia	VIM-42	Exploration	50%	Colombia
	SSJN3-1		50%
	Clarinero		50%
Maurel & Prom Colombia B.V.	SSJN9	Exploration	50%	North Colombia
Quarter North Energy	Gunflint	Production	32%	Gulf of Mexico
Murphy Exploration and Production Company – USA	Dalmatian	Production	30%	Gulf of Mexico
OXY (Anadarko) - K2	K2	Production	21%	Gulf of Mexico
HESS	ESOX	Production	21%	Gulf of Mexico
	S-M-1709		30%
	S-M-1908		30%
Shell	S-M-1601		30%
	S-M-1713	Exploration	30%	Brazil
	S-M-1817		30%
	S-M-1599		30%
	S-M-1910		30%
	Saturno		10%
	Sul de Gato do Mato		30%
	BM-S-54		30%
BP Energy	Pau Brasil	Exploration	20%	Brazil
Chevron	CE-M-715	Exploration	50%	Brazil
	PAMA-M-187		30%
	PAMA-M-188		30%
Petrobras	PAMA-M-222	Exploration	30%	Brazil
	PAMA-M-223		30%
	BM-C-44		38%
	BM-S-74		13%
Anadarko	BM-C-29	Exploration	50%	Brazil
Repsol	BM-ES-29	Exploration	30%	Brazil
ONGC	BM-S-73	Exploration	13%	Brazil
	BM-S-63		30%
Vanco	BM-S-71	Exploration	30%	Brazil
	BM-S-72		30%
Occidental Midland Basin, LLC (Oxy)	Rodeo Midland Basin	Production	49%	Midland, Texas, USA
Pemex Exploration y Production	Bloque 8	Exploration	50%	Gulf of Mexico
PC Carigali Mexico Operation SA	Bloque 6	Exploration	50%	Gulf of Mexico

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

32.2Contracts in which Ecopetrol Business Group is the operator


			%	Geographic area of
Partners	Contract	Type	Participation	operations
	VMM29	Exploration	50%	Colombia
	CR2		50%
ExxonMobil Exploration Colombia	C62		50%
	KALE		100%
Repsol Colombia SA	CPO9	Exploration	55%	Colombia
ONGC Videsh Limited Sucursal Colombia	RC9	Exploration	50%	Colombia
CPVEN E&P Corp Sucursal Colombia	VMM32	Exploration	51%	Colombia
SK Innovation Co Ltd.	San Jacinto	Exploration	70%	Colombia
Repsol Exploration Colombia S.A.	Catleya	Exploration	50%	Colombia
Emerald Energy PLC Suc. Colombia	Cardon	Exploration	50%	Colombia
Parex Resourses Colombia Ltd.	ORC401 CRC-2004-01	Exploration	50%	Colombia
Repsol Colombia Oil & Gas Limited	CPO9 – Akacias	Production	55%	Colombia
SierraCol Energy Arauca, LLC	La Cira Infantas	Production	52%+PAP	Colombia
	Teca		100% Basic 60% incremental
Total Colombie	Niscota**	Exploration	20%	Colombia
Talisman Oil & Gas
Emerald Energy	Oleoducto Alto Magdalena	Production	45%	Colombia
Frontera Energy
Perenco Oil And Gas	San Jacinto Rio Paez	Production	68%	Colombia
Cepsa Colombia
	SSJN1	Production	50%	Colombia
	Perdices		50%	Colombia
Lewis Energy Colombia	VIM-42	Exploration	50%	Colombia
	SSJN3-1		50%	Colombia
	Clarinero		50%	Colombia
Maurel & Prom Colombia B.V.	CPO17	Exploration	50%	Colombia

**Fields in abandonment process.

The Company acquires investment commitments at the moment of receiving the exploration and/or exploitation rights of a determined area by the competent authority. As of December 31, 2022, investment commitments with the ANH reach USD $805.6 million (2021 - USD $739.9 million).

Ecopetrol Permian LLC has commitments related to the five-year business plan in the Permian Basin under the Rodeo Midland Basin LLC formation agreement, which may be modified annually by contract members, and Ecopetrol América LLC commitments derived from the joint operations in the Gulf of Mexico through authorizations for expenditures (AFEs) for projects of both a capital nature and operating expenses.

33.Information by segments

A description of the Ecopetrol Business Group’s business segments is in Note 4.20 - Information by business segment.

The following segment information is reported based on the information used by the Board of Directors as the top body to make strategic and operational decisions of these business segments. The performance of the segments is based primarily on an analysis of income, costs, expenses, and results for the period generated by each segment which are regularly monitored.

The information disclosed in each segment is presented net of transactions between the Ecopetrol Business Group companies.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

33.1Statement of profit or loss

Below are the consolidated statements of profit or loss by segment for the years ended December 31, 2022, 2021 and 2020:


	For the year ended on December 31, 2022
				Electric
				power
				transmission
	Exploration		Transport	and toll
	and	Refining and	and	roads
	Production	Petrochemicals	Logistics	concessions	Eliminations	Total
Third–party sales	60,719,903	82,728,875	2,807,031	13,355,269	—	159,611,078
Inter–segment sales	30,300,562	6,450,072	11,148,961	2,237	(47,901,832)	—
Revenue from contracts with customers	91,020,465	89,178,947	13,955,992	13,357,506	(47,901,832)	159,611,078
Variable cost	(34,649,988)	(76,341,169)	(720,247)	—	43,531,185	(68,180,219)
Fixed cost	(12,099,432)	(3,990,829)	(3,172,963)	(5,854,832)	3,840,127	(21,277,929)
Cost of sales	(46,749,420)	(80,331,998)	(3,893,210)	(5,854,832)	47,371,312	(89,458,148)
Gross profit	44,271,045	8,846,949	10,062,782	7,502,674	(530,520)	70,152,930
Administrative expenses	(2,489,557)	(823,349)	(499,801)	(965,314)	442,326	(4,335,695)
Operation and project expenses	(3,221,678)	(1,387,064)	(327,952)	—	193,066	(4,743,628)
Impairment of non–current assets	(890,248)	1,096,021	(406,229)	(87,543)	—	(287,999)
Other operating income and expenses net	(310,628)	(37,959)	(96,239)	(104,664)	(6,365)	(555,855)
Operating income	37,358,934	7,694,598	8,732,561	6,345,153	98,507	60,229,753
Financial result net
Financial income	1,011,182	89,173	157,264	577,743	(518,217)	1,317,145
Financial expenses	(2,894,636)	(1,381,682)	(287,889)	(3,883,596)	420,551	(8,027,252)
Foreign exchange gain (loss) net	(44,302)	(289,105)	10,080	198,677	—	(124,650)
	(1,927,756)	(1,581,614)	(120,545)	(3,107,176)	(97,666)	(6,834,757)
Share of profits of associates and joint ventures	30,197	222,460	—	515,746	19	768,422
Income before tax	35,461,375	6,335,444	8,612,016	3,753,723	860	54,163,418
Income tax	(13,829,885)	(1,464,380)	(2,962,021)	(707,652)	—	(18,963,938)
Net profit (loss) for the period	21,631,490	4,871,064	5,649,995	3,046,071	860	35,199,480
Profit (loss) attributable to:
Group owners of parent	21,761,164	4,686,009	4,483,060	673,688	860	31,604,781
Non–controlling interest	(129,674)	185,055	1,166,935	2,372,383	—	3,594,699
	21,631,490	4,871,064	5,649,995	3,046,071	860	35,199,480
Supplementary information
Depreciation depletion and amortization	7,304,525	1,960,399	1,448,626	1,415,441	—	12,128,991

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	For the year ended on December 31, 2021
				Electric
				power
				transmission
				and toll
	Exploration	Refining and	Transport and	roads
	and Production	Petrochemicals	Logistics	concessions	Eliminations	Total
Third–party sales	38,552,572	46,658,196	2,557,238	4,113,198	—	91,881,204
Inter–segment sales	24,696,380	4,318,189	9,601,228	—	(38,615,797)	—
Revenue from contracts with customers	63,248,952	50,976,385	12,158,466	4,113,198	(38,615,797)	91,881,204
Variable cost	(30,473,145)	(44,860,928)	(531,361)	—	34,859,524	(41,005,910)
Fixed cost	(9,861,987)	(3,674,460)	(2,728,948)	(1,817,491)	3,507,020	(14,575,866)
Cost of sales	(40,335,132)	(48,535,388)	(3,260,309)	(1,817,491)	38,366,544	(55,581,776)
Gross profit	22,913,820	2,440,997	8,898,157	2,295,707	(249,253)	36,299,428

Administrative expenses	(1,987,817)	(784,214)	(457,217)	(322,939)	210,118	(3,342,069)
Operation and project expenses	(1,882,686)	(944,616)	(404,264)	(460)	78,469	(3,153,557)
Impairment of non–current assets	438,020	(305,466)	(165,901)	(4)	—	(33,351)
Other operating income and expenses net	(617,893)	10,749	591,829	(51,267)	(6,162)	(72,744)
Operating income (expenses)	18,863,444	417,450	8,462,604	1,921,037	33,172	29,697,707
Financial result net
Financial income	517,629	24,313	76,453	89,267	(304,070)	403,592
Financial expenses	(2,410,906)	(1,151,255)	(250,816)	(886,420)	267,749	(4,431,648)
Foreign exchange gain (loss) net	(219,747)	(132,734)	381,964	300,519	—	330,002
	(2,113,024)	(1,259,676)	207,601	(496,634)	(36,321)	(3,698,054)
Share of profits of associates and joint ventures	9,610	200,998	858	214,698	—	426,164
Income before tax	16,760,030	(641,228)	8,671,063	1,639,101	(3,149)	26,425,817
Income tax	(5,019,540)	(383,562)	(2,925,390)	(466,771)	—	(8,795,263)
Net profit (loss) for the period	11,740,490	(1,024,790)	5,745,673	1,172,330	(3,149)	17,630,554
Profit (loss) attributable to:
Group owners of parent	11,829,119	(1,198,619)	4,635,354	386,438	(3,149)	15,649,143
Non–controlling interest	(88,629)	173,829	1,110,319	785,892	—	1,981,411
	11,740,490	(1,024,790)	5,745,673	1,172,330	(3,149)	17,630,554
Supplementary information
Depreciation depletion and amortization	6,844,910	1,640,940	1,211,642	462,430	—	10,159,922

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	For the year ended on December 31, 2020
	Exploration and	Refining and	Transport
	Production	Petrochemicals	and Logistics	Eliminations	Total
Third–party sales	22,854,925	24,804,887	2,563,581	—	50,223,393
Inter–segment sales	13,985,072	1,299,464	9,630,859	(24,915,395)	—
Revenue from contracts with customers	36,839,997	26,104,351	12,194,440	(24,915,395)	50,223,393
Fixed costs	(9,479,317)	(3,427,211)	(2,813,856)	4,062,843	(11,657,541)
Variable costs	(23,429,102)	(22,398,344)	(567,501)	20,485,016	(25,909,931)
Cost of sales	(32,908,419)	(25,825,555)	(3,381,357)	24,547,859	(37,567,472)
Gross profit	3,931,578	278,796	8,813,083	(367,536)	12,655,921

Administrative expenses	(2,163,198)	(936,175)	(533,594)	259,817	(3,373,150)
Operation and project expenses	(1,511,510)	(781,309)	(403,657)	110,460	(2,586,016)
Impairment of non–current assets	(192,693)	(781,528)	341,065	—	(633,156)
Other operating income and expenses net	1,085,114	34,705	1,827	(3,480)	1,118,166
Operating income (expenses)	1,149,291	(2,185,511)	8,218,724	(739)	7,181,765
Financial result net
Financial income	1,177,712	67,832	125,677	(269,791)	1,101,430
Financial expenses	(2,896,060)	(914,534)	(389,394)	270,197	(3,929,791)
Foreign exchange gain (loss) net	360,409	(447,880)	434,245	—	346,774
	(1,357,939)	(1,294,582)	170,528	406	(2,481,587)
Share of profits of associates and joint ventures	(53,037)	131,462	(2,089)	—	76,336
Income before tax	(261,685)	(3,348,631)	8,387,163	(333)	4,776,514
Income tax	43,569	614,269	(2,696,499)	—	(2,038,661)
Net profit (loss) for the period	(218,116)	(2,734,362)	5,690,664	(333)	2,737,853
Profit (loss) attributable to:
Group owners of parent	(139,279)	(2,848,511)	4,574,800	(333)	1,586,677
Non–controlling interest	(78,837)	114,149	1,115,864	—	1,151,176
	(218,116)	(2,734,362)	5,690,664	(333)	2,737,853
Supplementary information
Depreciation depletion and amortization	6,445,812	1,599,780	1,278,946	—	9,324,538

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

33.2Sales by product

The sales by product for each segment are detailed below for the years ended December 31, 2022, 2021 and 2020:


	For the year ended on December 31, 2022
				Electric power
				transmission
				and toll
	Exploration and	Refining and	Transport and	roads
	Production	Petrochemicals	Logistics	concessions	Eliminations	Total
Local sales
Mid–distillates	—	39,217,618	—	—	(35,108)	39,182,510
Gasoline and turbo fuels	—	32,022,556	—	—	(4,402,357)	27,620,199
Natural gas	5,250,577	—	—	—	(1,087,701)	4,162,876
Services	450,322	746,500	13,955,992	296,216	(11,847,349)	3,601,681
Electric power transmission services	—	—	—	2,595,505	—	2,595,505
Plastic and rubber	—	1,568,816	—	—	—	1,568,816
LPG and propane	739,323	385,178	—	—	(30,169)	1,094,332
Asphalts	47,224	849,976	—	—	—	897,200
Fuel gas service	—	869,101	—	—	(8,999)	860,102
Crude oil	28,725,485	491,440	—	—	(28,841,135)	375,790
Roads and Construction services	—	—	—	355,737	—	355,737
Aromatics	—	343,792	—	—	—	343,792
Polyethylene	—	302,630	—	—	—	302,630
Fuel oil	2,663	6,550	—	—	—	9,213
Other income gas contracts	1,940	—	—	—	—	1,940
Other products	20,204	2,164,882	—	—	(1,505,903)	679,183
	35,237,738	78,969,039	13,955,992	3,247,458	(47,758,721)	83,651,506
Foreign sales
Crude oil	56,701,497	92,147	—	—	(141,891)	56,651,753
Electric power transmission services	—	—	—	5,114,783	—	5,114,783
Roads and Construction Services	—	—	—	4,676,822	—	4,676,822
Fuel oil	—	4,348,312	—	—	—	4,348,312
Diesel	—	2,324,861	—	—	—	2,324,861
Plastic and rubber	—	2,036,201	—	—	—	2,036,201
LPG and propane	339,837	—	—	—	—	339,837
Natural gas	254,054	—	—	—	—	254,054
Gasoline and turbo fuels	—	157,685	—	—	—	157,685
Other products	35,113	1,281,174	—	318,443	(1,220)	1,633,510
Cash flow hedging	(1,547,774)	(30,472)	—	—	—	(1,578,246)
	55,782,727	10,209,908	—	10,110,048	(143,111)	75,959,572
	91,020,465	89,178,947	13,955,992	13,357,506	(47,901,832)	159,611,078

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	For the year ended on December 31, 2021
				Electric power
				transmission
				and toll
	Exploration and	Refining and	Transport and	roads
	Production	Petrochemicals	Logistics	concessions	Eliminations	Total
Local sales
Mid–distillates	—	17,166,812	—	—	(26,485)	17,140,327
Gasoline and turbo fuels	—	17,931,469	—	—	(2,456,099)	15,475,370
Natural gas	4,077,691	—	—	—	(877,622)	3,200,069
Services	132,060	659,088	12,158,466	120,795	(10,004,421)	3,065,988
Plastic and rubber	—	1,642,035	—	—	—	1,642,035
LPG and propane	618,218	332,542	—	—	(24,529)	926,231
Fuel gas service	—	742,212	—	—	(7,546)	734,666
Electric power transmission services	—	—	—	728,467	—	728,467
Asphalts	25,178	585,873	—	—	—	611,051
Polyethylene	—	320,466	—	—	—	320,466
Aromatics	—	247,387	—	—	—	247,387
Crude oil	23,619,491	—	—	—	(23,426,015)	193,476
Roads and Construction Services	—	—	—	107,179	—	107,179
Fuel oil	10,838	12,961	—	—	—	23,799
Other income gas contracts	2,879	—	—	—	—	2,879
Other products	35,213	2,160,653	—	—	(1,793,038)	402,828
Cash flow hedges	—	(8)	—	—	—	(8)
	28,521,568	41,801,490	12,158,466	956,441	(38,615,755)	44,822,210
Foreign sales
Crude oil	34,868,421	—	—	—	—	34,868,421
Diesel	—	3,867,937	—	—	—	3,867,937
Fuel oil	—	2,288,977	—	—	—	2,288,977
Plastic and rubber	—	2,092,379	—	—	—	2,092,379
Electric power transmission services	—	—	—	1,827,622	—	1,827,622
Roads and Construction Services	—	—	—	1,241,144	—	1,241,144
LPG and propane	116,960	—	—	—	—	116,960
Natural gas	71,529	—	—	—	—	71,529
Other products	20,365	925,595	—	87,991	(42)	1,033,909
Cash flow hedges	(349,891)	7	—	—	—	(349,884)
	34,727,384	9,174,895	—	3,156,757	(42)	47,058,994
	63,248,952	50,976,385	12,158,466	4,113,198	(38,615,797)	91,881,204

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


	For the year ended on December 31, 2020
	Exploration and	Refining and	Transport
	Production	Petrochemicals	and Logistics	Eliminations	Total
Local sales
Mid–distillates	—	8,871,938	—	(11,350)	8,860,588
Gasoline and turbo fuels	6,739	7,880,124	—	(1,118,817)	6,768,046
Services	116,485	268,081	12,194,384	(9,719,391)	2,859,559
Natural gas	3,683,018	—	—	(837,863)	2,845,155
Plastic and rubber	—	865,204	—	—	865,204
Fuel gas service	—	678,396	—	(6,826)	671,570
Asphalts	27,043	499,057	—	—	526,100
LPG and propane	249,533	133,525	—	(7,283)	375,775
Crude oil	13,250,275	—	—	(13,019,755)	230,520
Aromatics	—	155,740	—	—	155,740
Polyethylene	—	138,035	—	—	138,035
Fuel oil	7,758	29,243	—	—	37,001
Other income gas contracts	32,190	—	—	—	32,190
Other products	19,556	417,889	—	(115,213)	322,232
	17,392,597	19,937,232	12,194,384	(24,836,498)	24,687,715
Foreign sales
Crude oil	20,165,489	29	—	(79,345)	20,086,173
Diesel	—	3,164,068	—	—	3,164,068
Fuel oil	—	1,044,811	—	—	1,044,811
Plastic and rubber	—	1,302,131	—	—	1,302,131
LPG and propane	18,943	—	—	—	18,943
Natural gas	17,231	—	—	—	17,231
Gasolines and turbo fuels	—	179,257	—	—	179,257
Other products	26,702	553,206	56	447	580,411
Cash flow hedges	(780,965)	(76,382)	—	—	(857,347)
	19,447,400	6,167,120	56	(78,898)	25,535,678
	36,839,997	26,104,352	12,194,440	(24,915,396)	50,223,393

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

33.3Capital expenditures by segments

The following are the investments amounts made by each segment for the years ended December 31, 2022, 2021 and 2020:


				Electric
				power
				transmission
	Exploration	Refining and	Transport and	and toll roads
2022	and Production	Petrochemicals	Logistics	concessions	Total
Property, plant, and equipment (Note 14)	4,461,244	928,843	2,424,428	953,201	8,767,716
Natural and environmental resources (Note 15)	11,962,544	—	—	—	11,962,544
Intangibles (Note 17)	145,532	32,832	89,463	879,683	1,147,510
	16,569,320	961,675	2,513,891	1,832,884	21,877,770


				Electric
				power
				transmission
	Exploration	Refining and	Transport and	and toll roads
2021	and Production	Petrochemicals	Logistics	concessions	Total
Property, plant, and equipment (Note 14)	2,633,119	1,845,618	1,344,654	294,197	6,117,588
Natural and environmental resources (Note 15)	6,733,028	—	—	—	6,733,028
Intangibles (Note 17)	106,490	22,685	47,236	267,935	444,346
	9,472,637	1,868,303	1,391,890	562,132	13,294,962


	Exploration	Refining and	Transport and
2020	and Production	Petrochemicals	Logistics	Total
Property, plant, and equipment (Note 14)	2,866,600	1,329,181	836,536	5,032,317
Natural and environmental resources (Note 15)	5,994,462	—	—	5,994,462
Intangibles (Note 17)	41,002	8,771	40,309	90,082
	8,902,064	1,337,952	876,845	11,116,861

34.Supplemental information on oil and gas producing activities (unaudited)

The information in this note is referred to as “unaudited” as a means of clarifying that it is not covered by the audit opinion of the independent registered public accounting firm that has audited and reported on the “Consolidated Financial Statements.”

In accordance with the requirements of the United States Securities and Exchange Commission (SEC), Rule 4–10(a) of Regulation S–X, Release 33–8879, Accounting Standards Codification 932 and the ASU– 2010–03 “Oil and Gas reserve Estimation and Disclosures” rule, this section provides supplemental information on oil and gas exploration and producing activities of the Ecopetrol Business Group. The information included in sections (1) to (3) provides historical cost information pertaining to costs incurred in exploration, property acquisitions and development, capitalized costs, and results of operations. The information included in sections (4) and (5) presents information on Ecopetrol’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows.

The following information corresponds to Ecopetrol’s oil and gas producing activities as of December 31, 2022, 2021 and 2020, and includes information related to the Ecopetrol Business Group’s consolidated subsidiaries.

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

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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


	2022	2021	2020
Natural and environmental properties	90,284,366	79,385,151	67,767,005
Wells, equipment, and facilities – property, plant, and equipment	33,568,835	31,730,001	31,166,804
Exploration and production projects	16,451,284	11,474,682	12,494,665
Accumulated depreciation, depletion, and amortization	(79,744,788)	(70,739,885)	(64,233,572)
Net capitalized cost	60,559,697	51,849,949	47,194,902

It includes information of the Exploration and Production segment subsidiaries and joint ventures.

In accordance with IAS 37, costs capitalized to natural and environmental properties include provisions for asset retirement obligations of $1,979,749, $3,930,370, and $3,936,494 during 2022, 2021 and 2020, respectively.

34.2Costs incurred in oil and gas exploration and developed activities

Costs incurred are summarized below and include both amounts expensed and capitalized in the corresponding period.


	2022	2021	2020
Acquisition of proved properties (1)	141,928	—	507,907
Acquisition of unproved properties (2)	339,394	—	1,274,660
Exploration costs	3,322,055	1,793,549	1,340,898
Development costs	16,266,222	11,264,075	7,367,020
	20,069,599	13,057,624	10,490,485

(1)	For 2022, it corresponds to 49% of participation contract in Barnett, acquired by Ecopetrol Permian. For 2020, it corresponds mainly to the acquisition of the entire participation in the Guajira Association (43% of the association contract) by Hocol and its position as operator.

(2)

During 2022, Ecopetrol Óleo e Gás do Brasil Ltda have acquired and capitalized seven offshore blocks in the Santos Basin. The blocks are operated by Shell, which holds a 70% of participation in the assets, with a 30% of participation held by Ecopetrol Brasil.

During 2020, Ecopetrol Business Group through its subsidiary Ecopetrol Óleo e Gás do Brasil Ltda acquired 30% of the interests, rights and obligations in two areas that correspond to the BM-S-54 Concession Agrement and the Sul de Gato do Mato Shared Production Contract, located offshore in Santos basin of Brazil, in the discovery of hydrocarbons called “Gato do Mato”. Additionally, Ecopetrol Óleo e Gás do Brasil Ltda has recognized the billing related to activities of drilling during the year. On July 17, 2020, the Ministry of Mines and Energy of Brazil authorized the transfer of 10% of the Saturn block for USD$85 million, located in the Santos basin, to Ecopetrol Óleo e Gás do Brasil, this percentage of which Shell Brasil Petróleo Ltda and Chevron Brasil Óleo e Gas Ltda. were equal holders. In the new shareholding structure, Ecopetrol Óleo e Gás do Brasil retains 10% of the interests of the block, while Shell (operator) and Chevron each retain 45% of the total.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

34.3Results of operations for oil and gas exploration and production activities

The Ecopetrol Business Group’s results of operations from oil and gas exploration and production activities for the years ended December 31, 2022, 2021 and 2020 are as follows:


	2022	2021	2020
Net revenues
Sales	71,223,307	50,631,272	30,141,662
Transfers	19,797,158	12,617,680	7,025,839
	91,020,465	63,248,952	37,167,501
Production costs(1)	22,152,495	12,554,338	12,753,880
Depreciation, depletion, and amortization(2)	7,138,902	6,623,891	6,393,506
Other production costs(3)	20,741,550	21,156,904	14,005,669
Exploration expenses(4)	1,512,385	960,247	689,204
Other expenses(5)	5,399,726	3,090,128	2,227,481
	56,945,058	44,385,508	36,069,740
Income before income tax expense	34,075,407	18,863,444	1,097,761
Income tax expense	(13,026,271)	(5,652,743)	(233,255)
Results of operations for exploration and production activities	21,049,136	13,210,701	864,506

(1)

Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities including costs such as operating labor, materials, supplies, and fuel consumed in operations and the costs of operating natural gas liquids plants. In addition, they include expenses related to the asset retirement obligations that were recognized during 2022, 2021 and 2020 of $333,683, $292,329, and $213,925, respectively.

(2)	In accordance with IAS 37, the expense related to asset retirement obligations that were recognized during 2022, 2021 and 2020 in depreciation, depletion, and amortization, were $768,466, $887,725, and $639,123, respectively.

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

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

(5)	Corresponds to administration, marketing expenses, and impairment.

During 2022, 2021, and 2020, the Ecopetrol Business Group transferred approximately 21.8%, 19.9%, and 18.9%, respectively, of its crude oil and gas production; (percentages based on the value sales in Colombian pesos) to intercompany business units. Those transfers were 50.4%, 52.1% and 45.9%, respectively, of crude oil and gas production volume (including Refinería de Cartagena).

The intercompany transfers were realized at market prices.

34.4Reserve information

The Ecopetrol Business Group follows international standards for estimating, classifying, and reporting reserves framed under SEC definitions. Corporate Reserve Management of Ecopetrol Business Group, Upstream Management and the Vice-Presidency of Development and Production, present the reserves balance to the Board of Directors, which approved it in February 2023.

The reserves were estimated at a level of 99.8% by specialized firms: DeGolyer and MacNaughton, Ryder Scott Company, Gaffney Cline, and Sproule International Limited. 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.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following information relates to the net proven reserves owned by the Ecopetrol Business Group in 2022, 2021 and 2020, and corresponds to the official reserves statements prepared by the Ecopetrol Business Group:


	2022			2021			2020
	Oil	Gas	Total	Oil	Gas	Total	Oil	Gas	Total
	(Mbls)	(Gpc)	(Mbe)	(Mbls)	(Gpc)	(Mbe)	(Mbls)	(Gpc)	(Mbe)
Proved reserves:
Opening balance	1,449	3,151	2,002	1,257	2,921	1,770	1,384	2,906	1,894
Revisions of previous estimates (1)	81	(104)	63	240	431	315	(81)	51	(72)
Improved recovery	77	21	81	120	107	139	100	74	113
Purchases	39	50	48	—	—	—	—	171	30
Extensions and discoveries	52	33	57	12	—	12	41	8	42
Sales	—	—	—	(3)	(4)	(3)	(1)	—	(1)
Production	(183)	(323)	(240)	(177)	(304)	(231)	(186)	(289)	(236)
Closing balance	1,515	2,828	2,011	1,449	3,151	2,002	1,257	2,921	1,770
Proved developed reserves:
Opening balance	921	2,561	1,370	834	2,636	1,297	898	2,662	1,365
Closing balance	995	2,174	1,376	921	2,561	1,370	834	2,636	1,297
Proved undeveloped reserves:
Opening balance	528	590	632	423	285	473	486	244	529
Closing balance	520	654	635	528	590	632	423	285	473

Some values were rounded for presentation purposes.

Mbls = Million barrels

Gpc: Giga cubic feet

Mbe = Million barrels of oil equivalent

(1)

Represents changes in previous proved reserves, upward or downward, resulting from new information (except for an increase in a proved area), usually obtained from development drilling and production history or result from changes in economic factors.

For additional information about the changes in Proved Reserves and the process for estimating reserves, see section 3.1 – Oil and Gas Reserves.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

34.5Standardized measure of discounted future net cash flows relating to proved oil and gas quantities and changes therein

The standardized measure of discounted future net cash flows related to the above proved crude oil and natural gas reserves is calculated in accordance with the requirements of ASU 2010–03. Estimated future cash inflows from production under SEC requirements are computed by applying unweighted arithmetic average of the first day–of–the–month for oil and gas price to year–end quantities of estimated net proved reserves, with cost factors based on those at the end of each year, currently enacted tax rates and a 10% annual discount factor. In our view, the information so calculated does not provide a reliable measure of future cash flows from proved reserves, nor does it permit a realistic comparison to be made of one entity with another because the assumptions used cannot reflect the varying circumstances within each entity. In addition, a substantial but unknown proportion of future real cash flows from oil and gas production activities is expected to derive from reserves which have already been discovered, but which cannot yet be regarded as proved.


	2022	2021	2020
Future cash inflows	685,716,359	401,980,640	187,210,379
Future costs
Production (1)	(182,522,131)	(129,109,036)	(85,989,384)
Development	(58,332,264)	(38,451,863)	(28,752,131)
Income taxes	(201,912,509)	(69,053,224)	(13,470,352)
Future net cash flow	242,949,455	165,366,517	58,998,512
10% discount factor	(86,340,334)	(57,009,654)	(18,568,308)
Standardized measure of discounted net cash flows	156,609,121	108,356,863	40,430,204

(1)

Production future costs include the estimated costs related to assets retirement obligations in the amount of $23,234,408; $17,364,520, and $12,545,574 as of December 31, 2022, 2021, and 2020, respectively.

The following are the principal sources of change in the standardized measure of discounted net cash flows in 2022, 2021 and 2020:


	2022	2021	2020
Net change in sales and transfer prices and in production cost (lifting) related to future production	158,798,134	110,224,660	(44,482,725)
Changes in estimated future development costs	(52,166,780)	(22,011,659)	(5,401,560)
Sales and transfer of oil and gas produced net of production costs	(68,867,970)	(50,694,613)	(24,413,621)
Net change due to extensions, discoveries, and improved recovery	9,993,781	6,741,068	3,134,469
Net change due to purchase and sales of minerals in place	1,767,856	(13,419)	570,460
Net change due to revisions in quantity estimates	10,807,453	32,923,680	(3,414,649)
Previously estimated development costs incurred during the period	69,458,458	32,941,335	7,943,239
Accretion of discount	15,360,418	10,468,951	10,468,951
Timing and other	(11,990,359)	(16,636,925)	567,027
Net change in income taxes	(84,908,732)	(36,016,420)	16,073,288
Aggregate change in the standardized measure of discounted future net cash flows for the year	48,252,259	67,926,658	(38,955,121)

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

35.Subsequent and relevant events

●Issuance of bonds in the international market

Ecopetrol S.A. reported on January 10, 2023, that as part of its refinancing and financing strategy for the 2023 investment plan, it successfully placed External Public Debt Bonds in the international capital market, based on the authorization issued by the Ministry of the Treasury and Public Credit through Resolution 0054 of January 10, 2023, for USD2,000 million under the following conditions:


Term	10 years
Transaction date	January 10, 2023
Compliance date	January 13, 2023
Maturity	January 13, 2033
Face amount	US$2,000 million
Price	99.187
Yield	9.000%
Coupon rate	8.875%
Periodicity	Semiannual
Rating (Moody’s/S&P/Fitch)	Baa3 / BB+ / BB+

The allocation of the resources of the issuance is to make the prepayment of the balance of the credit authorized by resolution 1928 of August 13, 2021, obtained to finance the acquisition of 51.4% of Interconexión Eléctrica S.A. (ISA), and finance Ecopetrol’s 2023 organic investment plan and other non-investment expenses, including the refinancing of liabilities that mature in 2023.

●International bonds repurchase offer

On January 17, 2023, Ecopetrol S.A. reported that as part of its comprehensive debt management strategy and to mitigate refinancing risk, it launched a repurchase offer (tender offer) of its international bond maturing in September 2023. (issued in 2013), up to a principal amount of USD 1,000 million. The nominal amount outstanding of the mentioned bond is USD 1,800 million and it has a coupon rate of 5.875%.

On February 14, Ecopetrol S.A. reported the final results of the operation. According to the depository and information agent of the offer, on February 13, 2023, the total repurchased through the offer amounts to USD $978.5 million of the aggregate amount of the bonds. After the closing of the repurchase offer, a total of USD $821.4 million of the bond balance will remain outstanding.

●Felipe Bayón, President of Ecopetrol S.A., will lead the Company until March 31, 2023

On January 26, it was reported that Felipe Bayón Pardo will lead Ecopetrol S.A. until March 31, 2023. The selection and appointment process of the new president of Ecopetrol S.A. by the Board of Directors will be given based on a rigorous selection process, in accordance with the Succession Policy of the President of Ecopetrol S.A.

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Exhibit 1 – Consolidated subsidiaries, associates, and joint ventures


		Ownership				Geographic		Profit
	Functional	interest			Country/	area of		(loss) of	Total	Total
Company	currency	Ecopetrol		Activity	Domicile	operations	Equity	the year	assets	liabilities
Subsidiaries
Refinería de Cartagena S.A.S.	US Dollar	100	%	Refining of hydrocarbons, commercialization and distribution of products	Colombia	Colombia	27,050,693	2,871,807	43,624,345	16,573,652
Cenit transporte y logística de hidrocarburos S.A.S.	Colombian Peso	100	%	Storage and transport by pipelines of hydrocarbons	Colombia	Colombia	17,213,132	4,584,958	19,560,744	2,347,612
Ecopetrol Global Energy S.L.U.	US Dollar	100	%	Investment Vehicle	Spain	Spain	16,066,888	751,378	16,067,277	389
Oleoducto Central S.A.S - Ocensa	US Dollar	72.65	%	Transportation by crude oil pipelines	Colombia	Colombia	4,878,286	2,838,743	8,706,108	3,827,822
Hocol Petroleum Limited.	US Dollar	100	%	Investment Vehicle	Bermuda	Bermuda	5,215,029	605,044	5,215,238	209
Ecopetrol América LLC.	US Dollar	100	%	Exploration and exploitation of hydrocarbons	United States	United States	2,547,392	(154,690)	3,298,838	751,446
Hocol S.A.	US Dollar	100	%	Exploration and exploitation of hydrocarbons	Cayman Islands	Colombia	4,615,488	608,858	6,772,497	2,157,009
Esenttia S.A.	US Dollar	100	%	Production and commercialization of polypropylene resin	Colombia	Colombia	3,047,356	188,561	3,678,832	631,476
Ecopetrol Capital AG	US Dollar	100	%	Collection of surpluses from, and providing funds to, companies of Ecopetrol Business Group	Switzerland	Switzerland	3,196,506	255,926	11,473,594	8,277,088
Oleoducto Bicentenario de Colombia S.A.S.	Colombian Peso	100	%	Transportation by crude oil pipelines	Colombia	Colombia	1,349,368	218,102	2,249,766	900,398
Oleoducto de Colombia S. A. – ODC	Colombian Peso	73	%	Transportation by crude oil pipelines	Colombia	Colombia	486,729	426,614	787,802	301,073
Black Gold Re Ltd.	US Dollar	100	%	Reinsurer for companies of Ecopetrol Business Group	Bermuda	Bermuda	1,243,639	46,795	1,548,991	305,352
Andean Chemicals Ltd.	US Dollar	100	%	Investment Vehicle	Bermuda	Bermuda	2,162,912	119,383	2,163,316	404
Oleoducto de los Llanos Orientales S. A. - ODL	Colombian Peso	65	%	Transportation by crude oil pipelines	Panama	Colombia	824,251	515,817	1,414,330	590,079
Interconexión Eléctrica S.A. E.S.P	Colombian Peso	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.	Colombia	Latin-America	29,550,372	2,202,581	78,733,852	49,183,480

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Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


		Ownership				Geographic		Profit
	Functional	interest			Country/	area of		(loss) of	Total	Total
Company	currency	Ecopetrol		Activity	Domicile	operations	Equity	the year	assets	liabilities
Inversiones de Gases de Colombia S.A. Invercolsa S.A.	Colombian Peso	51.88	%	Holding with investments in natural gas and LPG transportation and distribution companies in Colombia	Colombia	Colombia	616,330	283,885	663,786	47,456
Alcanos de Colombia S.A. E.S.P. (1)	Colombian Peso	29.61	%	Residential public fuel gas service, construction and operation of gas pipelines, distribution networks, regulation, measurement, and compression stations.	Colombia	Colombia	393,197	131,102	814,660	421,463
Metrogas de Colombia S.A E.S.P. (1)	Colombian Peso	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.	Colombia	Colombia	67,772	17,047	136,167	68,395
Gases del Oriente S.A. E.S.P. (1)	Colombian Peso	48.50	%	Home public service of distribution of fuel gas and the development of all complementary activities to the supplying of said service.	Colombia	Colombia	123,247	44,925	216,319	93,072
Promotora de Gases del Sur S.A. E.S.P. (1)	Colombian Peso	31.44	%	Promote the linking of national or foreign capital, public or private, to achieve the gas massification project.	Colombia	Colombia	64,031	28,470	91,463	27,432
Combustibles Líquidos de Colombia S.A E.S.P. (1)	Colombian Peso	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.	Colombia	Colombia	60,408	1,444	84,213	23,805

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Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


		Ownership			Geographic		Profit
	Functional	interest		Country/	area of		(loss) of	Total	Total
Company	currency	Ecopetrol	Activity	Domicile	operations	Equity	the year	assets	liabilities
Ecopetrol USA Inc.	US Dollar	100%	Exploration and exploitation of hydrocarbons	United States	United States	13,849,664	1,235,087	13,872,872	23,208
Ecopetrol Permian LLC.	US Dollar	100%	Exploration and exploitation of hydrocarbons	United States	United States	8,999,442	1,357,066	9,875,481	876,039
Ecopetrol Oleo é Gas do Brazil Ltda.	Real	100%	Exploration and exploitation of hydrocarbons	Brazil	Brazil	2,093,147	(462,646)	2,313,440	220,293
Esenttia Masterbatch Ltda.	Colombian Peso	100%	Manufacture of polypropylene compounds and masterbatches	Colombia	Colombia	445,118	290,672	584,869	139,751
Ecopetrol del Perú S. A.	US Dollar	100%	Exploration and exploitation of hydrocarbons	Peru	Peru	71,668	(2,129)	75,229	3,561
ECP Hidrocarburos de México S.A. de C.V.	US Dollar	100%	Offshore exploration	Mexico	Mexico	52,677	(17,473)	59,826	7,149
Ecopetrol Costa Afuera S.A.S.	Colombian Peso	100%	Offshore exploration	Colombia	Colombia	12,964	(483)	13,130	166
Esenttia Resinas del Peru SAC	US Dollar	100%	Commercialization polypropylene resins and masterbatches	Peru	Peru	17,486	2,232	40,417	22,931
Topili Servicios Administrativos S de RL De CV.	Mexican Peso	100%	Specialized management services	Mexico	Mexico	5	(48)	25	20
Kalixpan Servicios Técnicos S de RL De CV.	Mexican Peso	100%	Specialized services related to oil and gas industry	Mexico	Mexico	53	(46)	58	5
Ecopetrol US Trading LLC	US Dollar	100%	International trading of crude oil and refined products	United States	United States	—	—	—	—
Ecopetrol Singapore PTE. LTD	Singapore dollar	100%	Holding company with investment in an international trading company for crude oil and refined products	Singapore	Asia	240,841	222,548	241,043	202
Ecopetrol Trading Asia PTE. LTD	Singapore dollar	100%	International trading of crude oil and refined products	Singapore	Asia	241,032	222,727	2,862,371	2,621,339

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Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Ownership

Geographic

Functional

interest

Country/

area of

Profit (loss) of

Total

Company

currency

Ecopetrol

Activity

Domicile

operations

Equity

the year

Total assets

liabilities

Associates

Serviport S.A. (2)

Colombian Peso

Services for the support
of loading and
unloading of oil ships,
supply of equipment,
technical inspections,
and load measurements

Colombia

16,589

(653)

38,776

22,187

Sociedad Portuaria Olefinas y Derivados S.A. (3)

Colombian Peso

Construction, use,
maintenance
and administration
of port facilities,
ports, private docks.

Colombia

5,362

1,323

8,940

3,578

Joint Ventures

Equion Energía Limited

US Dollar

Exploration and exploitation
of hydrocarbons

United Kingdom

Colombia

1,639,264

50,783

1,711,972

72,708

Ecodiesel Colombia S.A. (3)

Colombian Peso

Production, trading,
and distribution of
biofuels and oleochemicals

Colombia

109,229

77,729

248,791

139,562

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Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


		Ownership				Geographic		Profit
		interest			Country/	area of		(loss) of
Company	Functional currency	ISA		Activity	Domicile	operations	Equity	the year	Assets	Liabilities
Subsidiaries Interconexión Eléctrica S.A. ESP
Consorcio Transmantaro	US Dollar	60.00	%	Electric power	Peru	Peru	2,272,947	307,699	9,085,357	6,812,410
Interligação Eléctrica Evrecy	Brazilian real	35.82	%	Electric power	Brazil	Brazil	243,025	(48,856)	267,247	24,222
Fundo de Investimento Assis	Brazilian real	35.81	%	Autonomous Fund – Special Purpose Entity	Brazil	Brazil	37,107	7,562	37,107	—
Fundo de Investimento Barra Bonita Renda Fixa Referenciado	Brazilian real	35.73	%	Autonomous Fund – Special Purpose Entity	Brazil	Brazil	13,197	3,651	13,197	—
Fundo de Investimento Referenciado di Bandeirantes	Brazilian real	27.68	%	Autonomous Fund – Special Purpose Entity	Brazil	Brazil	250,436	29,441	250,436	—
Fundo de Investimento Xavantes Referenciado di	Brazilian real	17.54	%	Autonomous Fund – Special Purpose Entity	Brazil	Brazil	538,537	55,264	538,537	—
Interconexiones Viales	Chilean peso	65.00	%	Roads concessions	Chile	Chile	3,380	(2,935)	3,901	521
Interligação Elétrica Aguapeí	Brazilian real	35.82	%	Electric power	Brazil	Brazil	582,138	88,602	654,581	72,443
Interligação Elétrica Biguaçu	Brazilian real	35.82	%	Electric power	Brazil	Brazil	399,587	35,053	476,172	76,585
Interligação Elétrica De Minas Gerais	Brazilian real	35.82	%	Electric power	Brazil	Brazil	372,475	(27,636)	410,106	37,631
Interligação Elétrica Itapura	Brazilian real	35.82	%	Electric power	Brazil	Brazil	163,809	25,988	176,625	12,816
Interligação Elétrica Itaquerê	Brazilian real	35.82	%	Electric power	Brazil	Brazil	510,426	59,930	592,065	81,639
Interligação Elétrica Itaúnes	Brazilian real	35.82	%	Electric power	Brazil	Brazil	462,427	23,425	499,955	37,528
Interligação Elétrica Norte E Nordeste	Brazilian real	35.82	%	Electric power	Brazil	Brazil	338,101	38,685	485,124	147,023
Interligação Elétrica Pinheiros	Brazilian real	35.82	%	Electric power	Brazil	Brazil	56,620	62,687	69,231	12,611
Interligação Elétrica Riacho Grande	Brazilian real	35.82	%	Electric power	Brazil	Brazil	87,708	(721)	98,771	11,063
Interligação Elétrica Serra Do Japi	Brazilian real	35.82	%	Electric power	Brazil	Brazil	384,866	62,833	432,753	47,887
Interligação Elétrica Sul	Brazilian real	35.82	%	Electric power	Brazil	Brazil	204,438	12,193	232,392	27,954
Interligação Elétrica Tibagi	Brazilian real	35.82	%	Electric power	Brazil	Brazil	222,671	19,465	257,165	34,494
Internexa	Colombian peso	99.42	%	Telecommunications and ICT	Colombia	Colombia	125,935	(92,594)	607,744	481,809
Transamerican Telecomunication S.A.	US Dollar	99.42	%	Telecommunications and ICT	Argentina	Argentina	21,152	(3,278)	45,400	24,248
Internexa Brasil Operadora de Telecomunicações	Brazilian real	99.42	%	Telecommunications and ICT	Brazil	Brazil	28,195	(114,568)	253,014	224,819
Internexa Chile	Chilean peso	98.43	%	Telecommunications and ICT	Chile	Chile	34,332	7,098	100,853	66,521

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Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)


		Ownership				Geographic		Profit
		interest			Country/	area of		(loss) of
Company	Functional currency	ISA		Activity	Domicile	operations	Equity	the year	Assets	Liabilities
Subsidiaries Interconexión Eléctrica S.A. ESP
Interligação Elétrica JAGUAR 6 S.A.	Brazilian real	35.82	%	Electric power	Brazil	Brazil	224,245	1,775	237,516	13,271
Interligação Elétrica JAGUAR 8 S.A.	Brazilian real	35.82	%	Electric power	Brazil	Brazil	97,020	1,833	103,999	6,979
Interligação Elétrica JAGUAR 9 S.A.	Brazilian real	35.82	%	Electric power	Brazil	Brazil	388,824	7,930	432,420	43,596
Internexa Participações	Brazilian real	99.42	%	Investment Vehicle	Brazil	Brazil	23,221	(99,644)	24,430	1,209
Internexa Peru	US Dollar	99.42	%	Telecommunications and ICT	Peru	Peru	52,265	(4,307)	376,626	324,361
ISA Bolivia	US Dollar	100.00	%	Electric power	Bolivia	Bolivia	140,414	10,976	155,384	14,970
ISA Capital Do Brazil	Brazilian real	100.00	%	Investment Vehicle	Brazil	Brazil	5,373,693	650,721	5,606,854	233,161
ISA CTEEP	Brazilian real	35.82	%	Electric power	Brazil	Brazil	14,914,001	1,861,300	28,831,572	13,917,571
ISA Interchile	US Dollar	100.00	%	Electric power	Chile	Chile	1,493,203	(19,966)	7,374,469	5,881,266
ISA Intercolombia	Colombian peso	100.00	%	Electric power	Colombia	Colombia	130,626	47,481	357,192	226,566
ISA Intervial Chile	Chilean peso	100.00	%	Roads concessions	Chile	Chile	4,024,265	438,479	4,985,244	960,979
ISA Intervial Colombia	Colombian peso	100.00	%	Roads concessions	Colombia	Colombia	587	20	587	—
ISA Inversiones Chile	Chilean peso	100.00	%	Investment Vehicle	Chile	Chile	1,949,226	(9,385)	1,954,212	4,986
ISA Inversiones Chile Vías SpA	Chilean peso	100.00	%	Investment Vehicle	Chile	Chile	4,025,954	438,012	4,025,954	—
ISA Inversiones Costera Chile	Chilean peso	100.00	%	Investment Vehicle	Chile	Chile	(211,407)	(76,363)	612,824	824,231
ISA Inversiones Tolten	Chilean peso	100.00	%	Investment Vehicle	Chile	Chile	39	(9)	39	—
ISA Investimentos E Participações	Brazilian real	100.00	%	Investment Vehicle	Brazil	Brazil	1,152,834	163,525	1,152,949	115
ISA Peru	US Dollar	99.98	%	Electric power	Peru	Peru	240,254	34,518	1,159,668	919,414
ISA REP	US Dollar	60.00	%	Electric power	Peru	Peru	672,302	273,783	2,311,363	1,639,061
ISA Transelca	Colombian peso	100.00	%	Electric power	Colombia	Colombia	1,002,878	222,945	1,788,873	785,995
Linear Systems RE	US dollar	100.00	%	Other business	Bermudas	Bermudas	36,506	4,802	141,027	104,521
Proyectos de Infraestructura del Perú	US Dollar	100.00	%	Electric power	Peru	Peru	15,289	2,254	114,879	99,590
Ruta Costera	Colombian peso	100.00	%	Roads concessions	Colombia	Colombia	177,882	(11,404)	2,859,724	2,681,842
Ruta de La Araucanía	Chilean peso	100.00	%	Roads concessions	Chile	Chile	432,393	76,332	905,688	473,295
Ruta de Los Ríos	Chilean peso	75.00	%	Roads concessions	Chile	Chile	122,428	49,926	339,054	216,626
Ruta del Bosque	Chilean peso	100.00	%	Roads concessions	Chile	Chile	106,522	(23,361)	150,803	44,281
Ruta del Loa	Chilean peso	100.00	%	Roads concessions	Chile	Chile	324,504	50,506	1,121,725	797,221
Ruta del Maipo	Chilean peso	100.00	%	Roads concessions	Chile	Chile	2,831,192	355,286	8,869,327	6,038,135
Ruta del Maule	Chilean peso	100.00	%	Roads concessions	Chile	Chile	6,048	(4,561)	9,693	3,645
Sistemas Inteligentes en Red	Colombia peso	99.77	%	Other business	Colombia	Colombia	10,472	2,868	19,885	9,413
XM	Colombian peso	99.73	%	Electric power	Colombia	Colombia	45,336	10,873	306,304	260,968
Joint ventures Interconexión Eléctrica S.A. ESP
Interligação Elétrica do Madeira	Brazilian real	51.00	%	Electric power	Brazil	Brazil	3,438,987	387,981	6,580,545	3,141,558
Interligação Elétrica Garanhuns	Brazilian real	51.00	%	Electric power	Brazil	Brazil	985,789	161,864	1,369,603	383,814
Interligação Elétrica Paraguaçu	Brazilian real	50.00	%	Electric power	Brazil	Brazil	1,016,496	135,684	1,530,815	514,319
Interligação Elétrica Aimorés	Brazilian real	50.00	%	Electric power	Brazil	Brazil	671,186	110,769	1,014,426	343,240
Interligação Elétrica Ivaí	Brazilian real	50.00	%	Electric power	Brazil	Brazil	795,707	33,388	3,706,984	2,911,277
Transmissora Aliança de Energia Elétrica	Brazilian real	14.88	%	Electric power	Brazil	Brazil	6,091,281	1,252,974	14,319,223	8,227,942
Interconexión Eléctrica Colombia Panamá-Panamá	US Dollar	50.00	%	Electric power	Panama	Panama	38,132	(31,996)	40,480	2,348
Interconexión Eléctrica Colombia Panamá Colombia	Colombia peso	1.17	%	Electric power	Colombia	Colombia	267	(2)	268	1
Transnexa (4)	US Dollar	50.00	%	Transport and telecommunications	Ecuador	Ecuador	—	—	—	—
Derivex	Colombia peso	40.46	%	Manage the trading system for financial instruments derived from electricity	Colombia	Colombia	850	(873)	850	—
Parques del Río	Colombia peso	33.00	%	Roads	Colombia	Colombia	102	(30)	102	—
Conexión Kimal Lo Aguirre S.A.	Chilena peso	33.33	%	Electric power	Chile	Chile	507,690	776	631,392	123,702
Associates Interconexión Eléctrica S.A. ESP
ATP Tower Holdings	US Dollar	24.7	%	Transport and telecommunications	United States	United States	1,850,384	(219,990)	4,551,118	2,700,734

(1)

Indirect participation through Inversiones de Gases de Colombia S.A. Invercolsa S.A.

(2)

Information available as of September 30, 2022, the investment of is fully impaired.

F-131

Table of Contents

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(3)

Information available as of November 30, 2022.

(4)

Transnexa is in the liquidation process and its investment has been impaired in its entirety.

Exhibit 2 – Conditions of the most significant debt

Outstanding

balance

Interest

Amortization

Payment of

Type of debt

Company

Issue date

Maturity date

Currency

Disbursement

Dec 31, 2022

Dec 31, 2021

rate

plan

interest

Dec-10

Dec-40

284,300

Aug-13

Aug-23

168,600

Ecopetrol S.A.

Aug-13

Aug-28

COP

347,500

Floating

Bullet

Half-yearly

Aug-13

Aug-43

262,950

Dec-11

Dec-23

COP

180,000

Floating

Bullet

Half-yearly

Dec-11

Dec-41

COP

120,000

Floating

Bullet

Half-yearly

May-13

May-22

COP

120,000

—

120,000

Floating

Bullet

Quarterly

May-13

May-28

COP

100,000

Floating

Bullet

Quarterly

May-15

May-25

COP

100,000

Floating

Bullet

Quarterly

Bonds,

May-15

May-30

COP

120,000

Floating

Bullet

Quarterly

domestic

May-15

May-35

COP

280,000

Floating

Bullet

Quarterly

currency

Feb-16

Feb-24

COP

115,000

Floating

Bullet

Quarterly

Feb-16

Feb-28

COP

152,000

Floating

Bullet

Quarterly

Interconexión

Feb-16

Feb-41

COP

133,000

Floating

Bullet

Quarterly

Eléctrica S.A.

Apr-17

Apr-24

COP

260,780

Fixed

Bullet

Quarterly

E.S.P and

Apr-17

Apr-32

COP

196,300

Floating

Bullet

Quarterly

subsidiaries

Apr-17

Apr-42

COP

242,920

Floating

Bullet

Quarterly

Nov-17

Nov-25

COP

150,080

Fixed

Bullet

Quarterly

Nov-17

Nov-31

COP

120,100

Floating

Bullet

Quarterly

Nov-17

Nov-47

COP

229,820

Floating

Bullet

Quarterly

Jul-18

Jul-27

COP

156,500

Floating

Bullet

Quarterly

Jul-18

Jul-33

COP

142,063

Floating

Bullet

Quarterly

Jul-18

Jul-43

COP

201,437

Floating

Bullet

Quarterly

Aug-20

Aug-29

COP

160,000

Fixed

Bullet

Quarterly

Aug-20

Aug-40

UVR (1)

152,311

165,369

147,132

Fixed

Bullet

Annual

Jul-16

Jan-34

UVR (1)

353,434

440,777

341,416

Fixed

Half-yearly

Oct-11

Oct-26

COP

100,000

Floating

Bullet

Quarterly

F-132

Table of Contents

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Outstanding

Type of

Issue

Maturity

balance

Interest

Amortization

Payment of

debt

Company

date

Currency

Disbursement

Dec 31, 2022

Dec 31, 2021

rate

plan

interest

Sep-13

Sep-23

1,300

Sep-13

Sep-43

850

May-14

May-45

2,000

Sep-14

Jan-25

1,200

Ecopetrol S.A.

Jun-15

Jun-26

USD

1,500

Fixed

Bullet

Half-yearly

Nov-21

Nov-31

1,250

Nov-21

Nov-51

750

Jun-16

Sep-23

500

Apr-20

Apr-30

2,000

Oleoducto Central S.A.S.

Jul-20

Jul-27

USD

500

Fixed

Bullet

Half-yearly

Nov-21

Nov-33

330

Fixed

Half-yearly

Jul-16

Jan-34

151

143

151

Fixed

Half-yearly

Jan-11

Jan-26

Fixed

Bullet

Quarterly

Bonds,

Oct-12

Apr-31

Fixed

Bullet

Half-yearly

foreign

Feb-13

Feb23

Fixed

Bullet

Half-yearly

currency

May-13

May-23

450

600

450

Fixed

Bullet

Half-yearly

Apr-19

Apr-34

600

500

600

Fixed

Half-yearly

Mar-17

Feb24

Floating

Bullet

Annual

Interconexión

May-18

Apr-25

131

154

111

Floating

Bullet

Half-yearly

Eléctrica S.A.

Dec-19

Dec-29

Floating

Half-yearly

E.S.P and

Dec-20

Nov-28

USD

169

153

143

Floating

Half-yearly

subsidiaries

Dec-20

May-44

169

168

143

Floating

Half-yearly

Feb21

Jul-44

142

153

121

Floating

Half-yearly

May-21

May-24

253

230

215

Floating

Bullet

Oct-21

Oct-31

141

138

120

Floating

Bullet

Half-yearly

Oct-21

Oct-39

Floating

Half-yearly

Apr-22

Apr-29

134

—

Fixed

Half-yearly

Aug-18

Jun-25

234

238

213

Fixed

Half-yearly

Aug-18

Dec-30

242

407

220

Fixed

Half-yearly

Aug-18

Dec-24

Fixed

Half-yearly

Jun-19

Dec-30

201

207

183

Fixed

Half-yearly

Nov-22

Jun-50

Fixed

Half-yearly

Feb-21

Jun-50

—

Fixed

Half-yearly

Jul-21

Jun-56

1,200

Fixed

Bullet

Half-yearly

F-133

Table of Contents

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Outstanding

Issue

Maturity

balance

Interest

Amortization

Payment of

Type of debt

Company

date

Currency

Disbursement

Dec 31, 2022

Dec 31, 2021

rate

plan

interest

Sep-19

Sep-25

Fixed

Half-yearly

Jun-21

Jun-23

Fixed

Bullet

Feb16

Jul-24

Floating

Quarterly

Jan-14

Mar-29

Floating

Monthly

Jan-14

Jan-24

Fixed

Monthly

Aug-17

Mar-32

Floating

Monthly

Jan-11

May-26

—

Floating

Monthly

Nov-11

May-26

—

Floating

Monthly

Nov-11

May-26

—

Floating

Monthly

May-10

May-30

Fixed

Monthly

International

Interconexión

Mar-20

Aug-24

Floating

Quarterly

commercial

Eléctrica S.A.

Sep-12

Sep-23

USD

—

Fixed

Half-yearly

loans

E.S.P and

Oct-18

Mar-25

—

Floating

Monthly

subsidiaries

Sep-12

Sep-23

—

Fixed

Half-yearly

Sep-12

Sep-23

—

Fixed

Half-yearly

May-21

Mar-24

Fixed

Half-yearly

May-21

Mar-24

—

Fixed

Half-yearly

Sep-18

Jun-50

Fixed

Monthly

May-21

May-25

112

105

Fixed

Half-yearly

May-21

May-26

Fixed

Half-yearly

Jun-22

Jun-23

—

Fixed

Bullet

Dec-22

Nov-30

—

Floating

Half-yearly

Apr-22

Nov-26

—

Fixed

Bullet

Sep-22

Sep-32

—

Fixed

Half-yearly

Mar-22

Dec-41

—

Floating

Monthly

Dec-22

Dec-23

—

Floating

Quarterly

Sep-22

Mar-25

—

Floating

Half-yearly

Sep-22

Mar-25

—

Floating

Half-yearly

F-134

Table of Contents

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Outstanding

Issue

Maturity

balance

Interest

Amortization

Payment of

Type of debt

Company

date

Currency

Disbursement

Dec 31, 2022

Dec 31, 2021

rate

plan

interest

International

Dec-17

Dec-27

2,001

855

1,100

Fixed

commercial

Dec-17

Dec-27

Floating

loans -

Ecopetrol S.A.

Dec-17

Dec-27

USD

Fixed

Half-yearly

Refinería de

Dec-17

Dec-27

158

Floating

Cartagena

Dec-17

Dec-25

359

182

224

Floating

International commercial loan –ISA acquisition

Ecopetrol S.A.

Aug-21

Aug-23

USD

3,672

472

1,672

Floating

Half-yearly

Dec-16

Jan-28

COP

250,000

242,125

250,000

Floating

Half-yearly

Dec-16

Jan-34

COP

150,000

147,000

150,000

Floating

Half-yearly

Dec-16

Jan-34

COP

150,000

147,000

150,000

Floating

Half-yearly

Dec-16

Jan-34

UVR (1)

405,972

181,972

161,904

Fixed

Half-yearly

Domestic

Interconexión

Jul-18

Jul-35

COP

217,500

4,353

4,651

Floating

Half-yearly

commercial

Eléctrica S.A.

Oct-21

Oct-31

COP

158,050

Floating

Quarterly

loans

E.S.P and

Oct-21

Oct-28

COP

70,500

Floating

Quarterly

subsidiaries

Jun-17

Jun-24

COP

28,000

—

8,717

Floating

Quarterly

Aug-17

Aug-24

COP

32,000

—

23,863

Floating

Quarterly

Dec-17

Dec-24

COP

10,000

—

7,472

Floating

Quarterly

May-18

Nov-28

COP

59,467

50,971

59,467

Floating

Half-yearly

Nov-18

Nov-28

COP

23,000

19,714

23,000

Floating

Half-yearly

May-22

May-23

COP

14,422

—

Floating

Quarterly

Jun-22

Jun-27

COP

12,900

—

Floating

Quarterly

Ago-22

Ago-27

COP

51,085

—

Floating

Half-yearly

Committed credit line

Ecopetrol S.A.

Apr-20

Sep-23

USD

665

—

665

Floating

Bullet

Half-yearly

Domestic syndicated commercial loan

Oleoducto Bicentenario

Jul-12

Jul-24

COP

2,100,000

375,725

600,450

Floating

Quarterly

(1)UVR is “Unidad de Valor Real”, a national currency which reflects the inflation adjusted Colombian peso.

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9.	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.


	Ecopetrol S.A.

	By:	/s/ Felipe Bayón Pardo
	Name:	Felipe Bayón Pardo
	Title:	Chief Executive Officer


	By:	/s/ Jaime Caballero Uribe
	Name:	Jaime Caballero Uribe
	Title:	Chief Financial Officer

Dated: March 29, 2023

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10.Exhibits


Exhibit No.		Description
1.1		Amended and Restated Bylaws of Ecopetrol S.A., dated March 26, 2021 (English Translation).
2.1		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).
2.2		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).
4.1		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).
4.2		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).
4.3		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).
4.4		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).
4.5		Bicentenario Transport Contract between Oleoducto Bicentenario de Colombia S.A.S. and Ecopetrol S.A., dated June 20, 2012 incorporated by reference to Exhibit 4.9 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 25, 2014 (File No. 001-34175)) (English Translation).
4.6		Supplementary Agreement No. 2, dated March 28, 2014, to the Bicentenario Transport Contract between Oleoducto Bicentenario de Colombia S.A.S. and Ecopetrol S.A., dated June 20, 2012 (incorporated by reference to Exhibit 4.11 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 28, 2016 (File No. 001-34175)) (English Translation).
4.7		Supplementary Agreement No. 4, dated April 6, 2015, to the Bicentenario Transport Contract between Oleoducto Bicentenario de Colombia S.A.S. and Ecopetrol S.A., dated June 20, 2012 (incorporated by reference to Exhibit 4.12 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 28, 2016 (File No. 001-34175)) (English Translation).
4.8		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).
4.9		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).
4.10		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)).

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Table of Contents


Exhibit No.		Description
4.11		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)).
4.12		Prospectus Supplement relating to Ecopetrol S.A.’s 5.875% Notes due 2023 filed with the U.S. Securities and Exchange Commission on June 9, 2016 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on June 23, 2015 (File No. 333-190198)).
4.13		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 July 26, 2013 (File No. 333-190198)).
4.14		Prospectus Supplement relating to Ecopetrol S.A.’s 4.125% Notes due 2025 filed with the U.S. Securities and Exchange Commission on September 11, 2014, (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on July 26, 2013 (File No. 333-190198)).
4.15		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 July 26, 2013 (File No. 333-190198)).
4.16		Prospectus Supplement relating to Ecopetrol S.A.’s 5.375% Notes due 2026 filed with the U.S. Securities and Exchange Commission on June 25, 2015 (incorporated by reference to the Company’s Prospectus filed with the U.S. Securities and Exchange Commission on June 23, 2015 (File No. 333-190198)).
4.17		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 June 1, 2018 (File No. 333-225381)).
4.18		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 May 28, 2021 (File No. 333-256623)).
4.19		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 May 28, 2021 (File No. 333-256623)).
4.20		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 May 28, 2021 (File No. 333-256623)).
4.21		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 24, 2022 (File No. 001-34175) (English translation).
4.22		Loan Agreement among Ecopetrol S.A., as borrower, the lenders party thereto, Mizuho Bank, Ltd., as administrative agent, and BBVA Securities Inc., Banco Santander, S.A., JPMorgan Chase Bank, N.A., Mizuho Bank, Ltd., Sumitomo Mitsui Banking Corporation and The Bank of Nova Scotia, as joint lead arrangers and joint bookrunners, dated as of August 17, 2021 (incorporated by reference to Exhibit 4.21 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 24, 2022 (File No. 001-34175).
4.23		Loan Agreement among Ecopetrol, S.A., as Borrower (the “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.
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.
13.1		Section 906 Officer Certification.
23.1		Consent of Ernst & Young Audit S.A.S.
23.2		Consent of Ryder Scott Company, L.P.
23.3		Consent of DeGolyer and MacNaughton
23.4		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

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101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
101.LAB		XBRL Taxonomy Extension Labels Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

11. Cross-reference to Form 20-F


		Sections
Item 1.	Identity of Directors, Senior Management and Advisers	N/A
	A. Directors and Senior Management	N/A
	B. Advisers	N/A
	C. Auditors	N/A
Item 2.	Offer Statistics and Expected Timetable	N/A
	A. Offer Statistics	N/A
	B. Method and Expected Timetable	N/A
Item 3.	Key Information	N/A
	A.[Reserved]	N/A
	B. Capitalization and Indebtedness	N/A
	C. Reasons for the Offer and Use of Proceeds	N/A
	D. Risk Factors	5.2
Item 4.	Information on the Company	Note 1 to the consolidated financial statements
	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; 4.6, Notes 14, 15 and Supplemental information on Oil and Gas producing activities (unaudited by EY) to the consolidated financial statements
	C. Organizational Structure	3.2
	D. Property, Plants and Equipment	3.4 – 3.8; 4.7.2; Notes 14, 15 and 16 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; 6.2
	B. Liquidity and Capital Resources	2.1; 4.6; 4.8; Consolidated statements of cash flow and Notes 9, 19, 28 and 29 to the consolidated financial statements
	C. Research and development, Patents and Licenses, etc.	3.9; Note 16 to the consolidated financial statements
	D. Trend Information	4.11
	E. Critical Accounting Estimates	4.5
Item 6.	Directors, Senior Management and Employees
	A. Directors and Senior Management	7.3; 7.5
	B. Compensation	7.6; Notes 4, 21 and 30 to the consolidated financial statements
	C. Board Practices	7.3
	D. Employees	3.13
	E. Share Ownership	7.7
	F. Disclosure of a registrant's action to recover erroneously awarded compensationF	N/A
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	N/A

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Item 8.	Financial Information
	A. Consolidated Statements and Other Financial Information	4; 6.2; 6.3; 8
	B. Significant Changes	7.8; Note 33 to the consolidated financial statements
Item 9.	The Offer and Listing
	A. Offer and Listing Details	6.4, 6.5
	B. Plan of Distribution	N/A
	C. Markets	6.3
	D. Selling Shareholders	N/A
	E. Dilution	N/A
	F. Expenses of the Issue	N/A
Item 10.	Additional Information
	A. Share Capital	N/A
	B. Memorandum and Articles of Association	7.1
	C. Material Contracts	3.5.4; 4.9; Exhibits 4.1 – 4.09, 4.20 and 4.21
	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	N/A
	G. Statements by Experts	N/A
	H. Documents On Display	1.1
	I. Subsidiary Information	N/A
	J. Annual Report to Security Holders	N/A
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	4.10; 5.2.1; 5.2.4; 5.3.4; Note 29 to the consolidated financial statements
Item 12.	Description of Securities Other than Equity Securities
	A. Debt Securities	6.4; Exhibits 4.11–4.19
	B. Warrants and Rights	N/A
	C. Other Securities	N/A
	D. American Depositary Shares	6.5, Exhibit 2.1
Item 13.	Defaults, Dividend Arrearages and Delinquencies	None
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	None
Item 15.	Controls and Procedures	5.3; 7.8
Item 16.	[Reserved]
Item 16A.	Audit Committee Financial Expert	7.3.2
Item 16B.	Code of Ethics	7.2; 7.4
Item 16C.	Principal Accountant Fees and Services	7.8
Item 16D.	Exemptions from the Listing Standards for Audit Committees	N/A
Item 16E.	Purchases of Equity Securities by the Issuer and Affiliated Purchases	N/A
Item 16F.	Changes in Registrant’s Certifying Accountant	7.8
Item 16G.	Corporate Governance	7
Item 16H.	Mine Safety Disclosure	N/A
Item 16I.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	N/A
Item 17.	Financial Statements	N/A
Item 18.	Financial Statements	8
Item 19.	Exhibits	10

234