As filed with the Securities and Exchange Commission on April 8, 2021

 

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

 

FORM 20-F
ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

For the fiscal year ended December 31, 2020

 

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. (571) 234 4000

 

 

 

Lina María Contreras Mora

Investor Relations Officer
investors@ecopetrol.com.co
Tel. (571) 234 5190
Carrera 13 N.36-24 Piso 7
Bogota, 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
6.875% Notes due 2030   EC30   New York Stock Exchange
5.375% Notes due 2026   EC26   New York Stock Exchange
7.375% Notes due 2043   EC43   New York Stock Exchange
5.875% Notes due 2045   EC45   New York Stock Exchange

 

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

 

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

 

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.

 

41,116,694,690 Ecopetrol common shares, par value COP$ 609 per share

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 

☒ Yes  ☐ No

 

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

 

☐ Yes  ☒ No

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

 

☒ 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.

 

☒ Yes  ☐ No

 

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

 

 

 


 

Annual Report on Form 20-F 2020

Table of Contents

 

1. Introduction     4
  1.1 About This Annual Report 4
  1.2 Forward-looking Statements 4
  1.3 Selected Financial and Operating Data 5
2. Strategy and Market Overview 7
  2.1 Our Corporate Strategy 8
    2.1.1 2021 – 2023 Business Plan 8
      2.1.1.1 Energy Transition 10
    2.1.2 2021 Investment Plan 11
  2.2. Unconventional Energy Sources 11
3. Business Overview   12
  3.1 Our History   12
  3.2 Our Corporate Structure 12
  3.3 Recent Developments 13
  3.4 Our Business   14
  3.5 Exploration and Production 14
    3.5.1 Exploration Activities 15
      3.5.1.1 Exploration Activities in Colombia 15
      3.5.1.2 Exploration Activities Outside Colombia 17
    3.5.2 Production Activities 19
      3.5.2.1 Production Activities in Colombia 19
        3.5.2.1.1 Ecopetrol S.A.’s Production Activities in Colombia 19
        3.5.2.1.2 Ecopetrol S.A.’s Affiliates and Subsidiaries’ Production Activities in Colombia 26
      3.5.2.2 Production Activities Outside Colombia 29
      3.5.2.3 Marketing of Crude Oil and Natural Gas 33
    3.5.3 Reserves 34
    3.5.4 Joint Venture and Other Contractual Arrangements 43
  3.6 Transportation and Logistics 47
    3.6.1 Transportation Activities 47
      3.6.1.1 Pipelines 50
      3.6.1.2 Export and Import Facilities 52
    3.6.2 Other Transportation Facilities 52
    3.6.3 Marketing of Transportation Services 53
  3.7 Refining and Petrochemicals 56
    3.7.1 Refining 56
      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 59
      3.7.1.5 Biofuels 59
    3.7.2 Marketing and Supply of Refined Products 59
  3.8 Research and Development; Intellectual Property 59
  3.9 Applicable Laws and Regulations 60
    3.9.1 Regulation of Exploration and Production Activities 60
      3.9.1.1 Business Regulation 60
        3.9.1.1.1 Environmental Licensing and Prior Consultation 63
        3.9.1.1.2 Royalties 65
    3.9.2 Regulation of Transportation Activities 65
    3.9.3 Regulation of Refining and Petrochemical Activities 67
      3.9.3.1 Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels 67
      3.9.3.2 Regulation Concerning Production and Prices 68

 

      3.9.3.3 Regulation of Biofuel and Related Activities 70
    3.9.4 Regulation of the Natural Gas Market 70
    3.9.5 Regulation of the Electric Energy Commercialization Activity 71
    3.9.6 Regulation of the Electricity Self-Generation Activity 72
  3.10 Technology, Environment, Social and Governance (TESG) Strategies and Initiatives 73
    3.10.2 Energy Initiatives 76
    3.10.3 HSE 77
      3.10.3.1 Ecopetrol S.A. 77
      3.10.3.2 Cenit 83
      3.10.3.3 Cartagena Refinery 83
  3.11 Related Party and Intercompany Transactions 83
  3.12 Insurance 89
  3.13 Human Resources/Labor Relations 91
    3.13.1 Employees 91
    3.13.2 Collective Bargaining Arrangements 93
4. Financial Review 94
  4.1 Factors Affecting Our Operating Results 95
  4.2 Effect of the COVID-19 Pandemic on our 2020 Results 96
  4.3 Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results 98
    4.3.1 Taxes 98
    4.3.2 Exchange Rate Variation 101
    4.3.3 Effects of Inflation 103
    4.3.4 Effects of Crude Oil and Refined Product Prices 103
  4.4 Accounting Policies 103
  4.5 Critical Accounting Judgments and Estimates 103
  4.6 Operating Results 104
    4.6.1 Consolidated Results of Operations 104
      4.6.1.1 Total Revenues 104
      4.6.1.2 Cost of Sales 106
      4.6.1.3 Operating Expenses before Impairment of Non-Current Assets Effects 107
      4.6.1.4 Impairment of Non-Current Assets 109
      4.6.1.5 Finance Results, Net 110
      4.6.1.6 Income Tax 111
      4.6.1.7 Net Income (Loss) Attributable to Owners of Ecopetrol 111
      4.6.1.8 Segment Performance and Analysis 111
      4.6.1.9 Exploration and Production Segment Results 113
      4.6.1.10 Transportation and Logistics Segment Results 116
      4.6.1.11 Refining and Petrochemicals Segment Results 117
  4.7 Liquidity and Capital Resources 119
    4.7.1 Review of Cash Flows 119
    4.7.2 Capital Expenditures 120
    4.7.3 Dividends 120
  4.8 Summary of Differences between Internal Reporting (Colombian IFRS and IFRS) 121
  4.9 Financial Indebtedness and Other Contractual Obligations 123
  4.10 Off Balance Sheet Arrangements 124
  4.11 Trend Analysis and Sensitivity Analysis 124
5. Risk Review   126
  5.1 Risk Factor Summary 126
  5.2 Risk Factors 128
    5.2.1 Risks Related to Our Business 128
    5.2.2 Risks Related to Colombia’s Political and Regional Environment 142
    5.2.3 Legal and Regulatory Risks 145
    5.2.4 Risks Related to Our ADSs 148
    5.2.5 Risks Related to the Controlling Shareholder 150
  5.3 Risk Management 151
    5.3.1 Integrated Risk Management System and Internal Control System 151

ii

 

    5.3.2 Managing Low Carbon Economy and Climate Change Risks 152
    5.3.3 Managing Information Security and Cybersecurity 153
    5.3.4 Managing Financial Risk 154
  5.4 Legal Proceedings and Related Matters 156
6. Shareholder Information 164
  6.1 Shareholders’ General Assembly 164
  6.2 Dividend Policy 164
  6.3 Market and Market Prices 165
  6.4 Description of Ecopetrol Registered Debt Securities 166
  6.5 Description of Ecopetrol ADRs 166
  6.6 Taxation 167
    6.6.1 Colombian Tax Considerations 167
    6.6.2 U.S. Federal Income Tax Consequences 172
  6.7 Exchange Controls and Limitations 174
  6.8 Exchange Rates 176
  6.9 Major Shareholders 176
  6.10 Enforcement of Civil Liabilities 176
7. Corporate Governance 177
  7.1 Bylaws 179
  7.2 Code of Ethics and Conduct 182
  7.3 Board of Directors 183
    7.3.1 Board Practices 186
    7.3.2 Board Committees 186
  7.4 Compliance with NYSE Listing Rules 188
  7.5 Management 190
  7.6 Compensation of Directors and Management 193
  7.7 Share Ownership of Directors and Executive Officers 194
  7.8 Controls and Procedures 194
8. Financial Statements 197
9. Signature Page 198
10. Exhibits 199
11. Cross-reference to Form 20-F 201

iii

 

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. (This URL is intended to be an inactive textual reference only. It is not intended to be an active hyperlink to our website. The information on our website, which might be accessible through a hyperlink resulting from this 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”, 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 governmental agencies responsible for regulating our business.

 

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”, “predicts”, “prognosticate”, “project”, “target”, “achieve” and “intend”, among other similar expressions, are understood as forward-looking statements. We have made forward-looking statements that address, among other things:

 

• our exploration and production activities, including drilling;

 

• import and export activities;

 

• our liquidity, cash flow, and sources of funding;

 

• 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.

 

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 crude oil and other commodity prices, refining margins and prevailing exchange rates;

 

• competition;

 

• our ability to obtain financing;

4

 

• 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;

 

• 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, military operations, terrorist acts, wars or embargoes;

 

• regulatory developments, including regulations related to climate change;

 

• receipt 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 the forward-looking statements.

 

1.3 Selected Financial and Operating Data

 

The following table sets forth, for the periods and at the dates indicated, our selected historical financial and certain key operating data. The selected financial data has been derived from and should be read in conjunction with, and is qualified in its entirety by reference to, our consolidated audited financial statements, presented in Colombian Pesos.

 

Table 1 – Selected Operating Data

 

Operating Information   2020     2019     2018     2017     2016  
Oil and gas production (mboed)     697.0       725.1       720.4       715.1       717.9  
Proved oil and gas reserves (mmboe)(1)     1,770       1,893       1,727       1,659       1,598  
Exploratory wells(2)     18       20       17       20       6  
Refinery throughput (bpd)(3)     322,038       375,754       375,444       347,483       332,751  
1P Reserves replacement ratio     48 %     169 %     129 %     126 %     (7 )%

 

 

(1) Proved oil and gas reserves include natural gas royalties and exclude crude oil royalties.
(2) Gross exploratory wells.
(3) Refinery throughput includes the Barrancabermeja, Cartagena, Apiay and Orito refineries.

5

 

Financial Information

International Financial Reporting Standards (IFRS)

(Expressed in millions of Colombian Pesos, except for the net income per share, net operating income per share and dividends declared per share, which are expressed in Colombian Pesos, and common shares and weighted average shares outstanding, which are expressed as number)

 

Table 2 – Selected Financial Data

 

Financial Information   2020     2019     2018     2017     2016  
Revenue     50,223,393       71,488,512       68,603,872       55,954,228       48,485,561  
Operating income     7,181,765       21,027,158       22,458,414       16,171,855       8,904,548  
Net income (loss) attributable to Ecopetrol’s shareholders     1,586,677       13,744,011       11,381,386       7,178,539       2,447,881  
Net operating income per share     175       511       546       393       217  
Weighted average number of shares outstanding     41,116,694,690       41,116,694,690       41,116,694,690       41,116,694,690       41,116,694,690  
Net income per share (basic and diluted)     39       334       277       175       59.5  
Total assets     137,694,169       133,890,296       124,643,498       117,847,412       118,958,977  
                                         
Total equity     53,499,363       58,231,628       57,107,780       48,215,699       43,560,501  
Subscribed and paid-in capital     25,040,067       25,040,067       25,040,067       25,040,067       25,040,067  
Number of common shares     41,116,694,690       41,116,694,690       41,116,694,690       41,116,694,690       41,116,694,690  
Dividends declared per share     17       180       314       89       23  
Total liabilities     84,194,806       75,658,668       67,535,718       69,631,713       75,398,476  

 

Our consolidated financial statements for the years ended December 31, 2016, 2017, 2018, 2019 and 2020 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 and IFRS.

 

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 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.

 

As indicated in IFRS 10 “Consolidated Financial Statements,” we must present our financial information on a consolidated basis as if we were a single entity, combining the financial statements of Ecopetrol S.A. and its subsidiaries line by line, adding assets, liabilities, shareholder’s equity, revenues and expenses of similar nature, removing the reciprocal items among companies that are members of the Ecopetrol Group (Ecopetrol Group or EG) and recognizing non-controlling interest. We present our operating information on a consolidated basis in accordance with IFRS.

 

In this annual report, references to “US$” or “U.S. dollars” are to United States dollars and references to “COP$” “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$3,691.27 per US$1.00, which corresponds to the average Tasa Representativa del Mercado (TRM), or Representative Market Exchange Rate, for 2020. 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 April 5, 2021, the Representative Market Exchange Rate was COP$3,679 per US$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.

6

 

 

2. Strategy and Market Overview

 

Containment measures and economic disruptions related to the COVID-19 outbreak led to a slowdown in production and mobility worldwide, producing a significant drop in global demand for oil in 2020. Demand contracted for most refined products (especially jet fuel and gasoline), which brought the Brent price to US$20/Bl by the end of April 2020. Although demand recovered throughout the second half of the year, it did not reach pre-COVID-19 pandemic levels. The U.S. Energy Information Administration (EIA) estimates that demand contracted by 9.0 mmbd as compared to 2019, the largest annual decline registered in EIA data since 1980. 

 

Oil supply slowly reacted to low prices. Moreover, a price war between Saudi Arabia and Russia in March and April further delayed the supply response. However, the Organization of the Petroleum Exporting Countries (OPEC) and its allies (including Russia) agreed to a supply cut at the end of April 2020. This, in conjunction with the drop in United States production, was key in balancing the oil market. In total, supply was reduced by 6.4 mmbd in 2020, of which OPEC’s share was 4.1 mmbd, the US’s share was 0.9 mmbd and the remaining 1.4 mmbd was contributed by others.

 

The drop in demand resulted in an increase in inventory and a decline in price during the first half of 2020. During much of the second half of the year, reduced oil production from the 14 OPEC member countries and ten of the world’s major non-OPEC oil-exporting nations, including Russia (OPEC+) and the United States, along with a rising oil consumption, caused inventory to fall, driving Brent prices to a monthly average of US$ 50/Bl in December 2020.

 

Graph 1 – Supply/Demand Balance vs ICE Brent Price Evolution

 

 

Source: EIA: Short Term Report (January 2021)

7

 

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 performance of Colombia’s gross domestic product (GDP) is one of the main drivers of fuel consumption in Colombia. According to the National Administrative Department of Statistics (DANE for its acronym in Spanish), in 2020 Colombia’s GDP fell 6.8% in real terms, as compared to 2019. The main reason for this contraction was derived from the COVID-19 pandemic and from the measures taken by the Colombian government to stop the spread of the virus, which included, among other measures, mandatory lockdowns and work slowdowns in certain industries. These measures particularly affected the construction, transportation, and mining industries, whereas the agriculture, financial services and real estate industries were still able to post positive growth rates along 2020. Within this context, local sales of liquid fuels decreased by 19.9% during 2020, primarily due to lower diesel and gasoline demand.

 

Natural gas demand in Colombia decreased by 1.4% in 2020 compared with 2019, due to lower demand from the industrial sector and refineries. In 2020, the natural gas market was challenged from the supply side itself, primarily due to the decrease in demand needs due to the COVID-19 pandemic, the latter generated several blockades and quarantines in different countries leading to a decrease in natural gas requirements for electricity generation as in the industrial sector. Additionally, it faced the harshness of the hurricane season in the Gulf of Mexico, which also forced the suspension of the mobilization of LNG ships, causing some terminals to suspend their operations. During the months of May to July, natural gas prices for Hubs such as TTF and JKF reached similar ranges to the ones of Henry Hub, placing them in ranges between US$1.43 – US$ 2.38 million British thermal unit (MMbtu). However, these same markers showed a significant recovery by the end of 2020, primarily due to the commencement of the winter season, leading to the production of natural gas from the Gulf of Mexico turning to serve the Asian market.

 

2.1 Our Corporate Strategy

 

2.1.1 2021 – 2023 Business Plan

 

The Ecopetrol Group’s Organic Business Plan (the “Business Plan”) for the 2021-2023 period, is aimed at restoring the Ecopetrol Group’s growth trajectory post COVID-19, increasing competitiveness, laying the foundations of energy transition and going deeper into the Technology, Environment, Social and Governance (TESG) agenda through positive social and environmental impact in the territories where we operate. The Business Plan also seeks to maintain the effective response of the Ecopetrol Group to uncertain economic and environmental conditions, ensure the financial sustainability of the Ecopetrol Group and keep the value promise to stakeholders in the medium and long terms. The organic investment included in the Business Plan is expected to be financed mainly with internal cash generation. The Brent price assumptions under the Business Plan are as follows: US$ 45/Bl in 2021, US$ 50/Bl in 2022 and US$ 54/Bl in 2023.

 

The Business Plan features an organic investment between US$ 12 billion and US$ 15 billion for the three-year period, mainly focused in Colombia, and seeks to ensure capital allocation towards incorporation of more competitive reserves and resources within a new scenario of oil and gas prices, competitive positioning in the energy transition (such as gas, decarbonization, short-cycle hydrocarbons and the incorporation of renewable energies), reliability investments necessary for a responsible and sustainable operation, and strategic technologies and social investment for the future of the Ecopetrol Group.

 

76% of the investments are expected to be allocated towards growth opportunities aimed at continuing the exploration and profitable development of existing assets and accelerating adaptation to the energy transition, with investments focused on the continuation of the enhanced recovery programs and the growth of the gas value chain. The remaining 24% of investments are expected to be allocated to operational continuity, seeking to preserve the value of the assets and bring reliability and integrity to the Ecopetrol Group’s consolidated operations.

 

The most relevant operational goals of the Business Plan are the following: (i) to reach production levels between 700 and 710 thousand barrels of oil equivalent per day in 2021, with a growth trajectory that allows the Ecopetrol Group to reach production levels of approximately 750 thousand barrels of oil equivalent per day by 2023; (ii) to reach a joint throughput at the Barrancabermeja and Cartagena refineries of between 340 and 365 thousand barrels per day in 2021, with a growth path that allows reaching a joint throughput at such refineries of approximately 420 thousand barrels per day by 2023 in an expected scenario of recovery in demand and refining margins, as well as the interconnection of the crude plants at the Cartagena refinery; and (iii) to reach transported volumes of over one million barrels per day – in line with the evolution of the production and demand for liquid fuels in the country.

8

 

Upstream

 

In terms of the upstream segment, the Business Plan allocates an investment range of between US$ 9 billion and US$ 11 billion. The Business Plan maintains the growth of this segment as a strategic objective, with a focus on accelerating the progression of resources and reserves, through exploration, drilling and enhanced recovery.

 

Of the aforementioned resources, (i) 69% is expected to be be allocated in production activities, including the Rubiales, Castilla, Piedemonte and the Middle Magdalena Valley fields, with a continued focus on maturity and development of improved recovery activities, (ii) 22% is expected to be allocated internationally, where the main focus areas will be Brazil and the Permian Basin in the United States and (iii) 9% of the resources are expected to be allocated in exploration activities, with an expected drilling of more than 40 wells located in the basins of greater materiality, with emphasis on the Llanos Orientales, Middle Magdalena Valley, Lower Magdalena Valley and Sinú-San Jacinto areas.

 

In terms of unconventional reservoirs, the Ecopetrol Group will continue the development process for the initiatives associated to the Comprehensive Research Pilot Projects (PPII for its Spanish acronym) in the Middle Magdalena valley basin in Colombia, and well as increasing development activities in the Permian Basin in Texas.

 

Regarding the growth of the natural gas chain (one of the Ecopetrol Group’s strategic pillars), between 9% and 10% of the investment called for by the Business Plan is expected to be allocated towards the development of Piedemonte and other sources of gas in the Middle Magdalena Valley, Guajira and the Sinú-San Jacinto basin areas in Colombia. Additionally, the Business Plan calls for investments for the evaluation and development of the largest offshore gas discoveries in the Colombian Caribbean.

 

The Business Plan foresees the achievement of reserves replacement ratio greater than 100% after 2022. However, such goal is subject to revision based on the evolution of both the Business Plan and market conditions.

 

Midstream

 

In terms of the midstream segment, the Business Plan allocates an investment of between US$ 780 million and US$ 960 million, mainly aimed at strengthening the integrity and reliability of the infrastructure, prioritizing resources for the growth of the multi-pipeline business, while advancing in increasing flexibility and efficiency in logistics for the evacuation of heavy crude and the growth of the pipeline infrastructure. These investments are also expected to enable future operating costs optimization by upgrading equipment and improving its performance.

 

Downstream

 

In terms of the downstream segment, the Business Plan allocates an investment between US$ 1.2 billion and US$ 1.4 billion focused on ensuring (i) the integrity and competitiveness of existing assets, and (ii) compliance with the fuel quality path. Regulatory compliance investments and major maintenance investment are expected to be made a part of the compliance with the life cycle of the plants in the Cartagena and Barrancabermeja refineries. The expected investments also call for the execution of the final phase of the interconnection project of the crude plants of the Cartagena refinery in an aggregate amount of approximately US$ 77 million, which is expected to commence operations in 2022.

 

In order to advance with the production of cleaner fuels for the country, investments in the 2021-2023 period are expected to make possible to guarantee sustained internal quality of diesel of between 10 and 15 ppm of sulfur, and to bring gasoline to a maximum of 50 ppm of sulfur across Colombia.

 

Commercial Strategy

 

The Business Plan maintains the Ecopetrol Group’s strategy of diversifying clients and destinations, with an important emphasis on the independent refining sector in China, while maintaining an active participation in the refining market of the United States. The foregoing is expected to be leveraged on our operational flexibility at ports, a stable quality of our crude oil and optimization of logistics.

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TESG

 

In terms of TESG, the Business Plan allocates approximately COP$ 1.7 trillion for the 2020-2024 period for social and environmental investment, aimed at closing social gaps and promoting the development and well-being of the communities where the Ecopetrol Group operates, with strategic projects expected in infrastructure, public services, education, sports and health, inclusive rural development and entrepreneurship and business development. Additionally, support will continue to be provided with resources in order to meet the COVID-19 pandemic needs of the communities and areas where the Ecopetrol Group operates.

 

Between US$ 100 million and US$ 150 million are expected to be allocated to the development of the Ecopetrol Group’s digital strategy, in order to capture benefits related to artificial intelligence technologies, block chain and bots, among others. Furthermore, we expect to invest between US$70 million and US$110 million in projects to increase the recovery factor, energy transition and strategic studies on water issues and new materials.

 

In connection with the Ecopetrol Group’s energy transition strategy, the Business Plan allocates investments of more than US$600 million in initiatives focused on the decarbonization agenda, among which stand out solar, wind and geothermal energy projects, followed by energy efficiency and fuel quality projects, among others. Similarly, in March 2021, intermediate and long-term emissions reduction goals and achievement plan were defined in line with the Ecopetrol Group’s growth strategy.

 

In 2021, the Ecopetrol Group also expects to consolidate its evaluation of opportunities associated with the hydrogen value chain and will seek to materialize partnerships in international agreements and with governments to identify business opportunities.

 

For more information on the TESG agenda see section entitled Technology, Environment, Social and Governance (TESG) Strategies and Initiatives.

 

2.1.1.1 Energy Transition

 

To acknowledge the risks and opportunities that transitioning to a low carbon economy implies for the Ecopetrol Group, we have defined four lines of action, including the aforementioned, to face the energy transition, as described below:

 

(i) Continue strengthening the competitiveness of the oil and gas business: The Ecopetrol Group plans to gain resilience in the oil and gas portfolio, which is expected to continue to be our core activities until the peak in oil demand is reached, while increasing its commitment to new businesses resilient to the energy transition.

 

(ii) Diversification of our business portfolio into low-carbon businesses: The Ecopetrol Group is exploring new business opportunities in the electricity value chain specifically in the energy transmission market as well as other potential future low-carbon businesses such as green hydrogen, carbon capture, utilization and storage (CCUS), nature-based solutions, among others, as long as that they meet the Ecopetrol Group’s growth, cash protection, and capital discipline criteria.

 

(iii) Achievement of decarbonization targets: Focused on accelerating and prioritizing energy efficiencies and reductions in carbon emissions the Ecopetrol Group plans on achieving the decarbonization goals mentioned in the section entitled Technology, Environment, Social and Governance (TESG) Strategies and Initiatives. Such targets are aligned with the Ecopetrol Group’s objectives of reducing the carbon emissions associated with its operations, as well as reducing the vulnerability of its operation and infrastructure to climate change.

 

(iv) Achievement of sustainability through the TESG strategy: The Ecopetrol Group’s TESG strategy places a clear focus on climate change (including decarbonization targets), water management, and territorial development as well as biodiversity, circular economy, health, safety and environmental (HSE) practices and diversity, leveraged on technology as a key enabler.

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Oil and gas companies are evaluating options to reposition themselves along the energy value chain in new business segments aligned with the market trends towards decarbonization and electrification, such as renewable generation, commercialization, and services to end customers, among others. It is Ecopetrol’s view that the need to connect and integrate multiple points and types of generation will reinforce the role of transmission as an indispensable actor in the energy value chain, and a required enabler of the growth of clean generation and electrification.

 

Our announced interest in acquiring a 51.4% stake in Interconexión Eléctrica S.A. (ISA) is part of this strategy as it would allow us to achieve a relevant position in a strategic sector for the energy transition. Through a single transaction, we would position ourselves in a key link in the electricity business with clear prospects for future growth. For more information on this potential transaction see the section entitled Business Overview-Recent Developments.

 

2.1.2 2021 Investment Plan

 

In December 2020, the Board of Directors approved between US$ 3.5 billion and US$ 4.0 billion for the 2021 investment plan at US$ 45/Bl Brent. The Ecopetrol Group plans to produce between 700 and 710 thousand barrels of oil equivalent per day during 2021. The Ecopetrol Group expects to allocate 80% percent of these investments to projects in Colombia and the remainder to the positioning and development of the Ecopetrol Group’s operations in the United States and Brazil.

 

The table below sets forth the details of the investment plan per business segment announced in December 2020:

 

Table 3 – 2021 Investment Plan

 

Business Segment   % Percentage(1)  
Exploration     6 %
Production     71 %
Midstream     7 %
Downstream     11 %
Other     5 %
TOTAL     100 %

 

 

(1) Percentage over the upper range.

 

2.2. Unconventional Energy Sources

 

Ecopetrol’s strategy for unconventional resources is based on the significant acreage position it has in the Middle Magdalena Basin in Colombia. In September 2019, the Colombian Council of State authorized the execution of the PPII to do the research on the eventual effects of using unconventional technology and made mandatory recommendations in respect of the pilot stage. However, a final decision on the development of unconventional reservoirs will not be issued until the government has evaluated the PPII results.

 

On February 28, 2020, the Ministry of Mines and Energy issued Decree 328 providing the general guidelines for developing PPII on unconventional reservoirs. Furthermore, on December 24, 2020, Ecopetrol signed a contract with the Agencia Nacional de Hidrocarburos - National Hydrocarbons Agency (the “ANH”) in respect of a pilot program in the Middle Magdalena Basin pursuant to which the potential environmental and social impacts are to be evaluated and the multi-stage hydraulic fracturing in horizontal wells concept is to be assessed.

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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 oldest Colombian oil field, 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 Agencia Nacional de Hidrocarburos - National Hydrocarbons Agency (the ANH) 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 in a competitive basis with autonomy over business decisions. Since 2006, according to Law 1118, we have been evolving 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 November 2007, when our common shares were listed on the Colombian Stock Exchange. Our American Depository Shares (ADSs) were listed on the New York Stock Exchange in 2008.

 

3.2 Our Corporate Structure

 

We operate in the following business segments: (i) Exploration and Production; (ii) Transportation and Logistics; (iii) Refining, Petrochemicals and Biofuels; and (iv) Sales and Marketing.

 

Our subsidiaries, Refinería de Cartagena S.A.S. (Reficar or Cartagena Refinery), Cenit Transporte y Logística de Hidrocarburos S.A.S. (Cenit) and Oleoducto Central S.A. (Ocensa) are significant subsidiaries, as such term is defined under SEC Regulation S-X.

 

We have a number of directly and indirectly held subsidiaries both in Colombia and abroad. As of December 31, 2020, we have eight directly owned and 19 indirectly owned subsidiaries.

 

During 2020, the following changes were made to the Ecopetrol Group’s structure:

 

  (i) On March 10, 2020, Bioenergy and Bioenergy Zona Franca S.A.S, were admitted to reorganization processes by the Superintendence of Companies under Law 1116 of 2006. The reorganization ended on June 24, 2020, with the applicable regulatory authority ordering the judicial liquidation processes for both companies. Furthermore, as these entities were not material subsidiaries and are not currently under our control, these processes did not have a material adverse effect on Ecopetrol’s results of operations or financial condition. For further information see section Risk Review—Legal Proceedings and Related Matters.

  

(i) On December 18, 2020, the liquidation process of ECP Germany Oil and Gas GmbH was completed, with no material adverse effect on Ecopetrol’s consolidated results.

 

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Graph 2 – Ecopetrol’s Corporate Structure(1)

 

 

The stock ownership percentage listed refers to Ecopetrol S.A.’s direct and indirect participation as of December 31, 2020. The data in this structure shows neither the whole ownership nor its decimal figures, so they will be used only for information purposes.

 

Exhibit 8.1 to this annual report identifies our principal operating subsidiaries, their respective countries of incorporation, and our percentage ownership in each (both directly and indirectly through other subsidiaries).

 

3.3 Recent Developments

 

Sale of Ecopetrol’s stake in Offshore International Group

 

On January 19, 2021, Ecopetrol signed a Share Purchase Agreement with De Jong Capital LLC, through one of its subsidiaries as buyer, pursuant to which Ecopetrol sold its 50% ownership interest in Offshore International Group (OIG). This divestment was the result of a competitive process between a number of bidders, jointly carried out by Ecopetrol and its partner, in respect of the sale of 100% of the capital stock of OIG.

 

Non-binding offer to acquire 51.4% of ISA’s outstanding shares

 

On January 27, 2021, Ecopetrol announced its interest in acquiring 51.4% of the outstanding shares of ISA, currently owned by the Colombian Ministery of Finance and Public Credit (MHCP by its Spanish acronym). Ecopetrol is pursuing this transaction with a view that an equity stake in ISA can materially increase its exposure to global trends in electrification and decarbonization, provide access to growth opportunities and improve its risk profile by adding stable cash flows to the Ecopetrol Group’s revenue composition. The transaction is expected to be funded through a combination of equity to be issued, in which the MHCP would maintain at least 80% of Ecopetrol's share ownership, cash from operations and/or other financing alternatives available to Ecopetrol. To the extent we decide to finance the ISA acquisition through an equity offering, we are analyzing whether to offer preemptive or similar rights to our existing shareholders.

 

ISA operates and maintains transmission networks in Colombia, Peru, Bolivia, Brazil and Chile, among others, and participates through its subsidiaries in the toll-road business, telecommunications and management of real-time systems. Based on its public reports as filed with the Superintendencia Financiera de Colombia (the “SFC”), ISA’s consolidated operational revenues and net income for 2020 totaled COP 10.2 trillion and COP 2.1 trillion, respectively; and its total assets were COP 54.0 trillion as of December 31, 2020. As of March 31, 2021, ISA’s market capitalization as reported on the Colombian Stock Exchange (BVC) was COP 24.9 trillion.

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On February 12, 2021, Ecopetrol and the MHCP signed an exclusivity agreement through which the parties will carry out non-binding preliminary conversations on the terms and conditions of the potential transaction. The exclusivity period is initially scheduled to end on June 30, 2021 unless extended by mutual agreement of the parties. During this period, Ecopetrol will carry out a detailed due diligence of ISA and the MHCP has agreed to negotiate exclusively with Ecopetrol.

 

Although the Colombian Government, through the MHCP, is the majority shareholder of both ISA and Ecopetrol, and will be acting as seller in the proposed transaction for Ecopetrol’s acquisition of ISA's shares, the transaction has been structured and negotiations will be carried out on an arm's length basis, with seller and buyer independent from each other. Ecopetrol and the Colombian Government will each engage their own financial and legal counsel for purposes of carrying out this transaction. In addition, for purposes of determining ISA's valuation, Ecopetrol has engaged two experienced investment banking firms. Ecopetrol intends to engage a separate independent advisor to deliver a fairness opinion related to ISA’s valuation and Ecopetrol’s final purchase price proposal. Moreover, the Board of Directors of Ecopetrol, which is composed by a majority of independent members, retains full oversight and autonomous decision rights over Ecopetrol’s interest in the transaction.

 

In line with the aforementioned, on March 25, 2021, the Ecopetrol Group’s Board of Directors approved the establishment of a Special Committee that will act as a temporary mechanism to evaluate the valuation of ISA, the price range and/or the price of the potential transaction and make the necessary recommendations to the Board of Directors. The committee will be comprised of the following independent members of Ecopetrol’s Board of Directors:

 

• Carlos Gustavo Cano

 

• Sergio Restrepo

 

• Esteban Piedrahita

 

• Santiago Perdomo, who will chair the committee

 

For information on the regulation of the electricity sector in Colombia, see section Applicable Laws and Regulations—Regulation of the Electric Energy Commercialization Activity and Regulation of the Electricity Self-Generation Activity.

 

The potential acquisition of a percentage of ISA’s shares would be subject to the approval of the Ecopetrol´s Board of Directors. Likewise, the required authorizations from regulatory and supervisory entities in Colombia and other countries in which ISA has operations are being evaluated.

 

3.4 Our Business

 

We are a vertically integrated oil and gas company with presence primarily in Colombia and with activities in the U.S., Brazil and Mexico. The Nation currently owns 88.49% of our voting capital stock. We are among the world’s largest public companies, ranking 313 on the Forbes Global 2000 Ranking – 2020, and the largest Colombian company in this ranking. We play a key role in the local Colombian hydrocarbon market.

 

3.5 Exploration 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, 2020, we were the largest operator and the largest producer of crude oil and natural gas in Colombia, maintaining the largest acreage exploration position in Colombia.

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Unless otherwise stated, all figures are given before deducting royalties.

 

3.5.1 Exploration Activities

 

Under our Business Plan, Ecopetrol is aiming to incorporate resources in high reward projects concentrated in: (i) near field exploratory activity, (ii) underexplored onshore basins in Colombia, such as Putumayo and Piedemonte, (iii) offshore Colombia, and (iv) international areas such as offshore Brazil in Pre-salt Santos and the U.S. Gulf of Mexico.

 

Graph 3 – Sedimentary basins where Ecopetrol executes exploration activities

 

 

During 2020, the exploration strategy was directed at leveraging our goal on three working fronts: onshore Colombia, offshore Caribbean, and strengthening our exploration overseas.

 

3.5.1.1 Exploration Activities in Colombia

 

During 2020, Ecopetrol and its subsidiaries drilled sixteen (16) wells in Colombia, of which ten (10) were exploratory and six (6) were appraisal wells. As of December 31, 2020, two (2) wells were successful, five (5) were plugged and abandoned, and nine (9) were under evaluation. This activity was concentrated mainly in the following basins: Llanos, Lower Magdalena Valley, Middle Magdalena Valley, Upper Magdalena Valley and Sinú San Jacinto.

 

In 2020, Ecopetrol participated in the drilling of two (2) successful wells in Colombia:

 

(i) the Cayena-1 ST1 well, drilled at sole risk by our partner Parex Resources in the Fortuna Association contract (where Ecopetrol holds a 20% working interest and Parex Resources, as the operator, holds the remaining 80% working interest); and

 

(ii) the Arrecife-3 well, where Ecopetrol holds a 100% working interest, through its subsidiary Hocol, at the VIM 8 Block.

 

Furthermore, during 2020 the Merecumbé-1 well was tested and declared successful after showing gas production in the Chengue Formation. This well was drilled by Lewis Energy in partnership with our subsidiary Hocol in 2019. As of the date of this annual report, this well is closed and under evaluation.

 

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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 our joint venture partners, and the exploratory wells drilled by third parties pursuant to sole risk contracts with us.

 

Table 4 – Exploratory Drilling in Colombia

 

    For the year ended December 31,  
    2020     2019     2018  
    (Number of wells)  
COLOMBIA                  
Ecopetrol S.A                        
Gross exploratory wells                        
Owned and operated by Ecopetrol                        
Productive     -       1.0       -  
Dry(1)     2.0       1.0       -  
Under Evaluation(2)(3)     1.0       -       -  
Total     3.0       2.0       -  
Operated by a partner in Joint Venture                        
Productive     -       4.0       5.0  
Dry(1)     -       1.0       1.0  
Under Evaluation(2)     1.0       1.0       3.0  
Total     1.0       6.0       9.0  
Operated by Ecopetrol in Joint Venture                        
Productive     -       -       -  
Dry(1)     -       -       -  
Under Evaluation(2)     2.0       -       1.0  
Total     2.0       -       1.0  
Net Exploratory Wells(4)                        
Productive     -       2.8       1.9  
Dry(1)     2.0       1.4       0.3  
Under Evaluation(2)     2.5       0.4       2.0  
Total     4.5       4.6       4.2  
Sole Risk                        
Productive     1.0       1.0       -  
Dry(1)     1.0       5.0       2.0  
Under Evaluation(2)(5)     3.0       -       -  
Total     5.0       6.0       2.0  
Hocol                        
Gross Exploratory Wells                        
Productive     1.0       1.0       1.0  
Dry(1)     2.0       2.0       4.0  
Under Evaluation(2)     2.0       2.0       -  
Total     5.0       5.0       5.0  
Net Exploratory Wells(4)                        
Productive     1.0       0.5       1.0  
Dry(1)     2.0       2.0       3.2  
Under Evaluation(2)     1.0       1.0       -  
Total     4.0       3.5       4.2  

 

 

(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) The Flamencos-2 well was classified as “under evaluation” for the year ended December 31, 2020. However, as of January 2021, it has been declared successful.
(4) Net exploratory wells were calculated according to our percentage of ownership in these wells.
(5) The El Niño-1 well was classified as “under evaluation” for the year ended December 31, 2020. However, as of January 2021, it has been declared successful.

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As a result of our divestment strategy, Hocol transferred 50% of its interest to Lewis Energy for the exploration of natural gas in a frontier play in the Perdices block. Additionally, the Agencia Nacional de Hidrocarburos approved the transfer of our 50% working interest in the COL-5, Purple Angel and Fuerte Sur blocks, where the Gorgon and Kronos gas discoveries are located, to Shell. With the arrival of a new operator with deep-water offshore experience, offshore drilling will recommence with an appraisal well, Gorgon-2, in December 2021. The appraisal well will be drilled in a 2,400 meters water depth, with an expected total depth of 4,543 meters. In case of success, additional drilling is to follow, with the expectations of accelerating the development of this material gas discovery.

 

Seismic

 

In Colombia, Ecopetrol purchased 273 km2 of 3D seismic and 1,328 km of 2D seismic surveys in the Llanos, Middle Magdalena Valley and Upper Magdalena Valley basins, with the objective of improving our geological understanding of these prolific basins.

 

3.5.1.2 Exploration Activities Outside Colombia

 

Our international exploration strategy aims to expand and renew our exploration portfolio in basins with long term potential, dilute our risks and improve the possibility of increasing our reserves. Some key aspects of this strategy include participating in bidding rounds to secure blocks available for exploration and entering into joint ventures with international and regional oil companies that contribute with operational expertise and technology.

 

In 2020, Ecopetrol America LLC signed a cross-assignment with Chevron, through which new blocks in the US Gulf of Mexico were acquired and participation in other blocks was transferred to Chevron. As a result, Ecopetrol America LLC was able to diversify its portfolio while reducing risk and capital exposure.

 

On June 12, 2020, Ecopetrol Óleo e Gás do Brasil Ltda. officially entered the Gato do Mato discovery in the Brazilian Pre-Salt, located in the BM-S-54 and Sul de Gato do Mato blocks, where Ecopetrol holds a 30% working interest, Total holds a 20% working interest and Shell as the operator holds the remaining 50% working interest. The Gato do Mato-4 appraisal well was drilled and was declared successful.

 

In the pre-salt of the Santos Basin, Ecopetrol Óleo e Gás do Brasil Ltda. also drilled, together with its partners Shell (as operator) and Chevron, the Saturno-1 well, which was declared a dry hole. Further technical evaluations are being carried out during 2021 to decide the path forward with regards to remaining potential in the Saturno exploration block.

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

 

Table 5 – Exploratory Drilling Outside Colombia

 

    For the year ended December 31,  
    2020     2019     2018  
    (Number of wells)  
UNITED STATES                        
Ecopetrol America LLC                        
Gross exploratory wells                        
Productive     -       1.0       -  
Dry(1)     -       -       -  
Under Evaluation(2)     -       -       -  
Total     -       1.0       -  
Net Exploratory Wells(3)(4)                        
Productive     -       0.2       -  
Dry(1)     -       -       -  
Under Evaluation(2)     -       -       -  
Total     -       0.2       -  
BRAZIL                        
Ecopetrol Óleo e Gás do Brasil Ltda.                        
Gross exploratory wells                        
Productive(5)     1.0       -       -  
Dry(1)     1.0       -       -  
Under Evaluation(2)     -       -       -  
Total     2.0       -       -  
Net Exploratory Wells(3)(4)                        
Productive     0.3       -       -  
Dry(1)     0.1       -       -  
Under Evaluation(2)     -       -       -  
Total     0.4       -       -  

 

 

(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.
(5) Gato do Mato-4 appraisal well was drilled before Ecopetrol Brasil formal entrance into the joint venture with Shell, while pending the governmental authorities’ approval. Therefore, the well expenditure was part of the acquisition cost under the sale and purchase agreement executed between Ecopetrol Brasil and Shell Brasil Petróleo Ltda. Due to that, the Gato do Mato-4 well cost was recorded as “acquisition cost” in the 2020 financial statements of of Ecopetrol Brasil.

 

Seismic

 

Our subsidiary, Ecopetrol America LLC, purchased 2,423 km2 of 3D seismic data to evaluate the exploratory potential of 77 U.S. Gulf of Mexico blocks, and to further evaluate the discovery made with the Esox-1 well drilled in 2019.

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3.5.2 Production Activities

 

In 2020, our consolidated average production was 697 thousand barrels of oil equivalent per day (boepd), a decrease of 28 thousand boepd as compared to 2019. This was primarily due to the following factors: (i) the effects of the COVID-19 pandemic, which caused a significant reduction in oil and gas demand, (ii) the drop in oil prices which led to a slowdown in activity and investment, and (iii) public order issues caused by the slowdown in the economy, impacting our operations in different regions. The aforementioned situations were reflected in the temporary closure of some wells, negatively affecting the production of some fields. However, as of the date of this annual report, all affected wells have been reactivated.

 

The following table summarizes the results of our oil and gas production activities for the periods indicated:

 

Table 6 – Ecopetrol Group’s Oil and Gas Production

 

    For the year ended December 31,  
    2020     2019     2018  
    Oil     Gas(1)     Total     Oil     Gas(1)     Total     Oil     Gas(1)     Total  
    (Thousand boepd)  
Total gross production in Colombia(2)     537.4       138.1       675.5       576.6       130.5       707.1       578.4       125.0       703.4  
Total international gross production(3)     17.4       4.2       21.5       15.0       3.0       18.0       14.1       2.9       17.0  
Total gross production of Ecopetrol Group     554.7       142.3       697.0       591.6       133.5       725.1       592.5       127.9       720.4  
                                                                         
Total production of Ecopetrol Group for presentation of reserves(4)     508.5       138.8       647.3       528.9       133.7       662.6       524.3       129.8       654.1  

 

 

(1) Conversion between million cubic feet per day (mcfpd) and boepd is performed at 5,700 mcfpd to 1 boepd.
(2) Total production in Colombia corresponds to Ecopetrol S.A., Hocol and 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, Savia Perú S.A. (Peru), 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, which is inmaterial.

 

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, 2020, Ecopetrol S.A. was the largest participant in the Colombian hydrocarbons industry, accounting for approximately 66.1% of crude oil production and 55.6% of natural gas production (calculations based on information from the Ministry of Mines and Energy). During 2020, Ecopetrol S.A. completed the drilling of 201 development wells, mainly in the Central and Orinoquía regions (156 through direct operations and 45 through associated companies).

 

Ecopetrol S.A. manages its production operations through a regional organization, which comprises a total of 79 oil fields with active production in 2020:

 

• Central Region

 

• Orinoquía Region

 

• Andina Oriente Region (resulting from the integrations of the former Oriente and South regions)

 

• Piedemonte Region

19

 

Additionally, we operate 104 fields with active production through Associated Operations with different partners.

 

In February 2020, the Vice-Presidency of Gas was created in order to lead and execute the Ecopetrol Group’s integrated gas strategy.

 

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

 

Graph 4 – Ecopetrol S.A. Operations in Colombia

 

 

Note: Associated Operations are conducted through a countrywide Vice-presidency of Associated Operations.

 

Crude Oil Production

 

The average daily production of crude oil in Colombia by Ecopetrol S.A. (excluding its subsidiaries), was 516 mbod in 2020, 32 mbod lower than in 2019, which represents a year-to-year decrease of 6%.

 

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.

20

 

Table 7 – Ecopetrol S.A.’s Average Daily Crude Oil Production in Colombia by Region

 

    For the year ended December 31,  
    2020     2019     2018  
    (Thousand bpd)  
Central Region                        
La Cira – Infantas     19.51       25.90       28.10  
Casabe     13.11       13.20       13.90  
Yarigui     18.90       17.90       14.40  
Other     16.95       15.90       17.30  
Total Central Region     68.47       72.90       73.70  
Orinoquía Region                        
Castilla     112.22       114.10       113.90  
Chichimene     68.80       69.10       67.70  
CPO-09     5.25       10.90       4.50  
Apiay     6.33       7.30       7.60  
Other     7.16       5.60       4.40  
Total Orinoquía Region     199.76       207.00       198.10  
Piedemonte Region                        
Floreña(1)(2)     25.54       22.70       25.90  
Cupiagua(3)     6.22       7.20       8.30  
Cusiana(3)     2.13       3.10       4.00  
Total Piedemonte Region     33.90       33.00       38.20  
Andina Oriente Region(4)                        
Rubiales     106.27       119.30       119.50  
Caño Sur     5.06       4.50       3.20  
San Francisco     4.05       6.20       6.00  
Huila Area     5.55       3.80       3.50  
Tello     4.33       3.40       3.60  
Other     7.50       10.40       11.70  
Total Andina Oriente Region     132.77       147.60       147.50  
Associated Operations                        
Quifa     14.73       20.50       21.20  
Caño Limon     24.14       25.70       25.30  
Nare     9.53       10.90       12.00  
Floreña(1)(2)     2.62       -       -  
Other     30.15       30.40       32.70  
Total Associated Operations     81.17       87.50       91.20  
Total average daily crude oil production Ecopetrol S.A. (Colombia)     516.03       548.00       548.70  

  

 

(1) The Piedemonte fields changed their name to the Floreña fields as of December 2020.
(2) The Floreña fields were included in Associated Operations until February 2020, when the association contract with Equión ended. Starting in March 2020, these fields are reported under the Piedemonte Region.
(3) In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana fields were included in the Orinoquía Region, whereas for the year ended December 31, 2020, these fields are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.
(4) In July 2020, the former Southern and Eastern regions joined to form the Andina region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.

 

Table 8 – Ecopetrol S.A. Production per Type of Crude

 

      2020
(Mbod) 		    Year-on-Year
∆ (%) 		    2019
(Mbod) 		    Year-on-Year
∆ (%) 		    2018
(Mbod) 		 
Light       39.0       6.8 %     36.5       (10.3 )%     40.7  
Medium       140.6       (6.5 )%     150.3       (2.7 )%     154.4  
Heavy       336.4       (6.9 )%     361.2       2.1 %     353.6  
Total       516.0       (5.8 )%     548.0       (0.1 )%     548.7  

 

Ecopetrol S.A.’s crude oil production in Colombia during 2020 was approximately 35% light and medium crudes and 65% heavy crudes. In 2019, approximately 34% of the crude oil production consisted of light and medium crudes, and 66% consisted of heavy crudes. In 2018, approximately 36% of the crude oil production consisted of light and medium crudes, and 64% consisted of heavy crudes.

21

 

Natural Gas Production

 

In 2020, the average daily production of natural gas by Ecopetrol S.A. (excluding its subsidiaries) reached 121.82 mboed, including natural gas liquids (NGLs), corresponding to a 4.3% increase compared to 2019 production. This production was supplied from the following fields: Cupiagua (35%), Cusiana (24%), Floreña (18%), Guajira (11%), and the remaining 12% from other fields.

 

By the end of December 31, 2020, the Liquefied Petroleum Gas (LPG) plant of the Cupiagua field produced 7,500 LGP barrels per day. The plant produces LPG and other products such as natural gas liquids (NGL) and penthane (C5).

 

Starting May 2020, our subsidiary Hocol took in the position of operator of the Chevron’s stake in the Chuchupa and Ballena fields, following the approval of the transaction by the Superintendence of Industry and Commerce of Colombia in November 2019.

 

Table 9 – Ecopetrol S.A.’s Average Daily Natural Gas Production in Colombia

 

    For the year ended December 31,  
    2020     2019     2018  
    Thousand bpd     mmcfpd     Thousand bpd     mmcfpd     Thousand bpd     mmcfpd  
Central Region                                                
La Cira – Infantas     0.10       0.57       0.12       0.68       0.16       0.91  
Provincia     1.48       4.84       1.58       4.96       1.96       7.30  
Yarigui     0.42       2.41       0.43       2.45       0.42       2.39  
Gibraltar     5.71       29.12       6.25       31.86       6.87       34.94  
Other     2.00       10.42       1.68       8.84       1.86       10.20  
Total Central Region     9.71       47.36       10.06       48.79       11.27       55.75  
Orinoquía Region                                                
Apiay     0.32       -       0.29       -       0.49       -  
Other     0.58       -       0.64       -       0.25       -  
Total Orinoquía Region     0.90       -       0.93       -       0.74       -  
Piedemonte Region                                                
Floreña(1)(2)     22.22       109.93       1.95       8.72       2.06       9.41  
Cupiagua(3)     42.68       194.99       36.45       196.08       26.97       153.73  
Cusiana(3)     29.57       136.63       35.72       164.67       34.73       159.83  
Total Piedemonte Region     94.47       441.55       74.12       369.47       63.76       322.96  
Andina Oriente Region(4)                                                
Huila Area     0.19       0.34       0.09       0.40       0.13       0.68  
Tello     0.08       0.47       0.07       0.40       0.11       0.63  
Other     0.19       0.53       0.25       0.23       0.25       0.23  
Total Andina Oriente Region     0.46       1.34       0.41       1.03       0.49       1.54  
Associated Operations                                                
Guajira     12.80       72.92       17.92       102.14       23.02       131.21  
Floreña(1)(2)     2.15       9.91       12.50       57.51       12.20       55.46  
Other     1.33       5.37       0.82       3.48       1.01       4.50  
Total Associated Operations     16.28       88.20       31.24       163.13       36.23       191.18  
Total Natural Gas Production (Colombia)     121.82       578.45       116.76       582.43       112.49       571.43  

 

 

(1) The Piedemonte fields change their name to the Floreña fields as of December 2020.
(2) The Floreña fields were included in Associated Operations until February 2020, when the association contract with Equión ended. Starting in March 2020, these fields are reported under the Piedemonte Region.
(3) In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana fields were included in the Orinoquía Region, whereas for the year ended December 31, 2020, these fields are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.
(4) In July 2020, the former Southern and Eastern regions joined to form the Andina region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.

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 Company’s sales of natural gas liquids represented less than 1% of the Company’s consolidated sales for the periods presented in this annual report.

22

 

Projects to Increase Recovery Factor

 

In 2020, Ecopetrol continued the implementation of secondary and tertiary recovery programs to improve the fields’ recovery factor. By the end of 2020, the fields with secondary and tertiary recovery programs contributed with 36% of the daily production of the Ecopetrol Group, underpinned by the good results obtained from the water injection expansion projects in the Chichimene, Castilla and Llanito fields.

 

The recovery programs increased proven reserves by 113 million boe with an investment of approximately US$ 345 million executed throughout the year. Of 42 recovery projects, 34 correspond to secondary recovery and eight to tertiary recovery.

 

Development Wells

 

The following table sets forth the number of gross and net development wells drilled in Colombia, both solely by Ecopetrol S.A. and with its associates, that reached total depth for the years ended December 31, 2020, 2019 and 2018.

 

Table 10 – Ecopetrol S.A.’s Gross and Net Development Wells in Colombia(1)

 

    For the year ended December 31,  
    2020     2019     2018  
   

Productive

Wells

    Dry
Wells 		    Productive
Wells 		    Dry
Wells 		    Productive
Wells 		    Dry
Wells 		 
Central Region                                                
Gross development wells owned and operated by Ecopetrol     51.0       -       84.0       1.0       12.0       -  
Orinoquía Region                                                
Gross development wells owned and operated by Ecopetrol     32.0       -       87.0       2.0       77.0       -  
Andina Oriente Region(2)                                                
Gross development wells owned and operated by Ecopetrol     73.0       -       124.0       -       134.0       4.0  
Piedemonte Region(3)                                                
Gross development wells owned and operated by Ecopetrol     -       -       -       -       -       -  
Total gross development wells owned and operated in Colombia     156.0       -       295.0       3.0       223.0       4.0  
Associated Operations                                                
Gross development wells in joint ventures     45.0       -       268.0       5.0       311.0       4.0  
Net development wells(4)     29.0       -       137.0       2.6       148.7       1.8  
Total gross development wells in joint ventures Ecopetrol S.A. in Colombia     45       -       268.0       5.0       311.0       4.0  
Total net development wells in joint ventures Ecopetrol S.A. in Colombia(4)     29.0       -       137.0       2.6       148.7       1.8  
Total gross development wells Ecopetrol S.A. in Colombia     201       -       563.0       8.0       534.0       8.0  
Total net development wells Ecopetrol S.A. in Colombia(4)     185.0       -       432.0       5.6       370.7       5.8  

 

 
(1) Includes only wells that were drilled and completed.
(2) In July 2020, the former Southern and Eastern regions joined and formed the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.
(3) In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and the Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.
(4) 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.

23

 

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, 2020.

 

Table 11 – Ecopetrol S.A.’s Gross and Net In Process Wells

 

    For the year ended December 31, 2020  
    Drilled but
not
completed 		    Mobilization     Being
drilled 		    Being
completed 		 
    (Number of wells)  
COLOMBIA    
Central Region                                
Gross in process wells owned and operated by Ecopetrol     7.0       -       4.0       8.0  
Orinoqula Region                                
Gross in process wells owned and operated by Ecopetrol     -       -       -       -  
Andina Oriente Region(1)                                
Gross in process wells owned and operated by Ecopetrol     1.0       1.0       2.0       -  
Piedemonte Region(2)                                
Gross in process wells owned and operated by Ecopetrol     -       -       -       -  
Total gross in process wells owned and operated in Colombia     8.0       1.0       6.0       8.0  
Associated Operations                                
Gross in process wells in joint ventures     8.0       -       1.0       -  
Net in process wells(3)     6.2       -       1.0       -  
Total gross in process wells in joint ventures Ecopetrol S.A.     8.0       -       1.0       -  
Total net in process wells in joint ventures Ecopetrol S.A.(3)     6.2       -       1.0       -  
Total gross in process wells Ecopetrol S.A. in Colombia     16.0       1.0       7.0       8.0  
Total net in process wells Ecopetrol S.A. in Colombia(3)     14.2       1.0       7.0       8.0  

 

 
(1) In July 2020, the former Southern and Eastern regions joined to form the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.
(2) In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and the Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.
(3) 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.

24

 

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, 2020.

 

Table 12 – Ecopetrol SA.’s Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production in Colombia

 

    As of December 31, 2020  
    Developed     Undeveloped  
    Gross     Net     Gross     Net  
    (Acres)  
Ecopetrol S.A.     471,969       371,489       4,633,683       3,443,517  

 

Gross and Net Productive Wells

 

The following table sets forth Ecopetrol S.A.’s total gross and net productive wells by region as of December 31, 2020.

 

Table 13 – Ecopetrol S.A.’s Gross and Net Productive Wells by Region(1)

 

    For the year ended December 31, 2020  
    Crude Oil(2)     Natural Gas(3)  
    Gross     Net(4)     Gross     Net(4)  
    (Number of wells)  
COLOMBIA                        
Central Region     2,049       1,548       4.0       4.0  
Orinoquía Region     996       985       -       -  
Andina Oriente Region(5)     1,087       1,034       8.0       8.0  
Piedemonte Region(6)     58       58       17.0       17.0  
Associated Operations Region     2,711       1,473       34.0       16.0  
Total     6,901       5,098       63.0       45.0  

 

 
(1) Includes only wells that were drilled and completed.
(2) 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.
(3) Natural gas wells are those in which operations are directed only toward the production of commercial gas.
(4) Net productive wells are calculated by multiplying gross productive wells by our ownership percentage.
(5) In July 2020, the former Southern and Eastern regions joined and formed the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.
(6) In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020.

25

 

3.5.2.1.2 Ecopetrol S.A.’s Affiliates and Subsidiaries’ Production Activities in Colombia

 

In 2020, the subsidiaries’ production in Colombia came from Hocol and Equión. During the year, the production obtained from these two companies was 37.6 thousand boepd, which represents 5.4% 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 14 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Crude Oil Production(1)

 

    For the year ended December 31,  
    2020     2019     2018  
    (Thousand bpd)  
COLOMBIA                        
Hocol                        
Joint venture operation     1.06       2.00       2.30  
Direct operation     19.14       18.80       18.40  
Total Hocol     20.20       20.80       20.70  
Equion(1)                        
Joint venture operation     -       -       -  
Direct operation     1.13       7.90       9.00  
Total Equion     1.13       7.90       9.00  
Production Tests     -       -       -  
Total Average Daily Crude Oil Production     21.33       28.70       29.70  

 

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

 

The 86% decrease in Equion’s production in 2020, as compared to 2019, was mainly due to the termination of the Piedemonte’s association contract in February 2020.

 

Natural Gas Production

 

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

 

Table 15 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Natural Gas Production

 

    For the year ended December 31,  
    2020     2019     2018  
    Thousand
bpd 		    mmcfpd     Thousand
bpd 		    mmcfpd     Thousand
bpd 		    mmcfpd  
COLOMBIA                                                
Hocol                                                
Joint venture operation     2.18       12.43       2.00       11.40       1.60       9.10  
Direct operation(1)     13.24       75.48       6.70       38.20       5.90       33.60  
Total Hocol     15.42       87.91       8.70       49.60       7.50       42.80  
Equion(2)                                                
Joint venture operation     -       -       -       -       0.20       1.10  
Direct operation     0.86       4.10       5.00       23.29       4.80       22.34  
Total Equion     0.86       4.10       5.00       23.29       5.00       23.44  
Production Tests     -       -       -       -       -       -  
Total Average Daily Gas Production (Subsidiaries in Colombia)     16.28       92.01       13.70       72.89       12.50       66.24  

 

 

 

(1) In November 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields and took the position of operator, this represents the increase in production related to direct operation.
(2) Equion fields were in operation until February 2020.

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 Company’s sales of natural gas liquids represented less than 1% of the Company’s consolidated sales for the periods presented in this annual report.

26

 

Development Wells

 

The following table sets forth the number of gross and net development wells drilled exclusively by our subsidiaries and in their joint ventures in Colombia for the periods indicated.

 

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

 

    For the year ended December 31,  
    2020     2019     2018  
    Productive
Wells 		    Dry
Wells 		    Productive
Wells 		    Dry
Wells 		    Productive
Wells 		    Dry
Wells 		 
    (Number of wells)  
Hocol                                    
Gross development wells owned and operated by Hocol     24.0       -       21.0       2.0       12.0       -  
Gross development wells in joint ventures     -       -       2.0       -       2.0       -  
Net development wells(2)     24.0       -       22.0       2.0       13.0       -  
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     24.0       -       21.0       2.0       12.0       -  
Total gross development wells in joint ventures in Colombia     -       -       2.0       -       2.0       -  
Total net development wells (Subsidiaries in Colombia)(2)     24.0       -       22.0       2.0       13.0       -  

 

 

(1) Includes only wells that were drilled and completed.
(2) 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.
(3) Equion fields were in operation until February 2020.

Note: There were no dry wells in our Colombian subsidiaries’ operations for the year ended December 31, 2018 and December 31, 2020.

27

 

Table 17 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net In Process Wells(1)

 

    For the year ended December 31, 2020  
    Drilled but
not
completed 		    Mobilization     Being
drilled 		    Being
completed 		 
    (Number of wells)  
Hocol                        
Gross in process wells owned and operated by Hocol     -       1.0       -       1.0  
Gross in process wells in joint ventures     -       -       -       -  
Net in process wells(1)     -       1.0       -       1.0  
Equión(2)                                
Gross in process wells owned and operated by Equión     -       -       -       -  
Gross in process wells in joint ventures     -       -       -       -  
Net in process wells(1)     -       -       -       -  
Total gross in process wells owned and operated in Colombia     -       1.0       -       1.0  
Total gross in process wells in joint ventures in Colombia     -       -       -       -  
Total net in process wells (Subsidiaries in Colombia)     -       1.0       -       1.0  

 

 

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

 

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, 2020.

 

Table 18 – Ecopetrol S.A.’s Subsidiaries in Colombia Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production

 

      As of December 31, 2020  
      Developed     Undeveloped  
      Gross     Net     Gross     Net  
      (Acres)  
Hocol(1)       62,774       37,608       3,005       2,967  
Equión(2)       -       -       -       -  
Total       62,774       37,608       3,005       2,967  

 

 

(1) In November 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields and took the position of operator since May 2020, this represents the increase in acreage related to Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production.
(2) Equion fields were in operation until February 2020.

28

 

 

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, 2020.

 

Table 19 – Undeveloped Production Acreage as of December 31, 2020 by Expiration Year

 

    For the year ended December 31,  
    2021     2022     2023     2024     2025 and beyond  
    Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net  
    (Acres)  
COLOMBIA                                                            
Ecopetrol S.A.     -       -       -       -       -       -       -       -       551,999       321,721  
Hocol     -       -       -       -       -       -       -       -       -       -  
Equión(1)     -       -       -       -       -       -       -       -       -       -  
Total Colombia     -       -       -       -       -       -       -       -       551,999       321,721  
PERÚ                                                                                
Savia Perú(2)     -       -       -       -       57,671       28,836       -       -       -       -  
Total Perú     -       -       -       -       57,671       28,836       -       -       -       -  
UNITED STATES OF AMERICA                                                                                
Ecopetrol America LLC     -       -       -       -       -       -       -       -       -       -  
Ecopetrol Permian LLC     -       -       -       -       -       -       -       -       -       -  
Total United States of America     -       -       -       -       -       -       -       -       -       -  

 

 

(1) Equion fields were in operation until February 2020.
(2) Savia’s fields will end operation in November 2023 when the contract expires.

 

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, 2020.

 

Table 20 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Productive Wells(1)(2)

 

    For the year ended December 31, 2020  
    Crude Oil     Natural Gas  
    Gross     Net(3)     Gross     Net(3)  
    (Number of wells)  
Hocol(4)     279.0       240.0       52.0       34.0  
Equión(5)     -       -       -       -  
Total (Subsidiaries in Colombia)     279.0       240.0       52.0       34.0  

 

 

(1) Information in the table above reflects productive wells that directly contribute to hydrocarbons production and therefore excludes wells used for injection, disposal, water abstraction or other similar activities. We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. Natural gas wells are those in which operations are directed only towards production of commercial gas.
(2) Includes only wells that were drilled and completed.
(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) In November 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields and took the position of operator since May 2020, this represents the increase in the increase in Gross and Net Productive Natural Gas Wells.
(5) Equion fields were in operation until February 2020.

 

3.5.2.2 Production Activities Outside Colombia

 

In 2020, the subsidiaries’ production outside Colombia came from Ecopetrol America LLC, Ecopetrol Permian LLC and Savia. In 2020, the production obtained from these three companies was 21.4 thousand boepd, which represents 3.1% of the Ecopetrol Group’s total production.

29

 

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 21 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Crude Oil Production(1)

 

    For the year ended December 31,  
    2020     2019     2018  
    (Thousand bpd)  
PERÚ                        
Savia Perú(1)     3.11       3.50       3.90  
UNITED STATES OF AMERICA                        
Ecopetrol America LLC     10.41       11.40       10.20  
Ecopetrol Permian LLC     3.85       0.10       -  
Total average daily crude oil production (International)     17.37       15.00       14.10  

 

 

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

 

Table 22 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Natural Gas Production

 

    For the year ended December 31,  
    2020     2019     2018  
    Thousand
bpd 		    mmcfpd     Thousand
bpd 		    mmcfpd     Thousand
bpd 		    mmcfpd  
PERÚ                                    
Savia Perú(1)     0.91       2.44       0.90       3.99       1.10       2.90  
UNITED STATES OF AMERICA                                                
Ecopetrol America LLC     1.78       10.15       1.80       10.26       1.80       10.30  
Ecopetrol Permian LLC     1.46       3.26       -       -       -       -  
Total average daily natural gas production (International)     4.15       15.85       2.70       14.30       2.90       13.10  

 

 

(1) In January 2021 Ecopetrol S.A. divested its 50% equity share in Savia Peru 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 Company’s sales of natural gas liquids represented less than 1% of the Company’s consolidated sales for the periods presented in this annual report.

 

30

 

 

Development Wells

 

The following table sets forth the number of gross and net development wells outside Colombia, drilled exclusively by us and in joint ventures for the periods indicated.

 

Table 23 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Development Wells(1)

 

    For the year ended December 31,  
    2020     2019     2018  
Number of wells   Productive
Wells 		    Dry
Wells 		    Productive
Wells 		    Dry
Wells 		    Productive
Wells 		    Dry
Wells 		 
PERÚ                                    
Savia Peru(2)                                    
Gross development wells     -       -       -       -       -       -  
Net development wells(3)     -       -       -       -       -       -  
UNITED STATES OF AMERICA                                                
Ecopetrol America LLC                                                
Gross development wells     -       -       2.0       -       1.0       -  
Net development wells(3)     -       -       0.5       -       0.3       -  
Ecopetrol Permian LLC(4)                                                
Gross development wells     18.0       -       6.0       -       -       -  
Net development wells(3)     8.8       -       2.0       -       -       -  
Total gross wells (International)     18.0       -       8.0       -       1.0       -  
Total net wells (International)(3)     8.8       -       2.5       -       0.3       -  

 

 

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

(2) In January 2021 Ecopetrol divested its 50% equity share in Savia Peru 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 Corp (OXY). Non-operated wells are not included because they are not considered material. Wells operated by others are not included because Ecopetrol’s share is not material.

 

Table 24 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net In Process Wells

 

    For the year ended December 31, 2020  
    Drilled but
not
completed 		    Mobilization     Being
drilled 		    Being
completed 		 
    (Number of wells)  
PERÚ                        
Savia Perú(1)                        
Gross in process wells     -       -       -       -  
Net in process wells(2)     -       -       -       -  
UNITED STATES OF AMERICA                                
Ecopetrol America LLC                                
Gross in process wells     -       -       -       -  
Net in process wells(2)     -       -       -       -  
Ecopetrol Permian LLC(3)                                
Gross in process wells     18.0       2.0       2.0       3.0  
Net in process wells(2)     8.8       1.0       1.0       1.5  
Total gross in process wells (International)     18.0       2.0       2.0       3.0  
Total net in process wells (International)(2)     8.8       1.0       1.0       1.5  

 

 

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

(2) 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.

(3) Includes only wells under direct operation by OXY. Non -operated wells are not included because they are not material.

31

 

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, 2020.

 

Table 25 – 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, 2020  
    Developed     Undeveloped  
    Gross     Net     Gross     Net  
    (Acres)  
PERÚ                        
Savia Perú(1)     79,575       39,787       57,671       28,836  
UNITED STATES OF AMERICA                                
Ecopetrol America LLC     55,440       14,479       23,040       6,566  
Ecopetrol Permian LLC     65,358       47,825       1,498       258  
Total (International)     200,373       102,091       82,209       35,660  

 

 

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

 

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, 2020.

 

Table 26 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Productive Wells(1)(2)

 

    For the year ended
December 31, 2020 		 
    Crude Oil  
    Gross     Net(3)  
    (Number of wells)  
PERÚ            
Savia Perú(4)     599.0       299.5  
UNITED STATES OF AMERICA                
Ecopetrol America LLC     16.0       3.9  
Ecopetrol Permian LLC(5)     22.0       10.8  
Total (International)     637.0       314.2  

 

 

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

(2) Information in the table above reflects productive wells that directly contribute to hydrocarbons production and therefore excludes wells used for injection, disposal, water abstraction or other similar activities. We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. Natural gas wells are those in which operations are directed only towards production of commercial gas.

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

(5) Includes only wells drilled and completed under direct operation by Occidental Petroleum Corp (OXY). Non-operated wells are not included because they are not material.

32

 

3.5.2.3 Marketing of Crude Oil and Natural Gas

 

In 2020, Ecopetrol sold 883 mboed, out of which 425 mboed represented sales of crude oil (48%), 87 mboed of natural gas (10%) and 371 mboed of fuels and petrochemicals (42%).

 

Crude Oil Export Sales

 

In 2020, crude oil export sales increased by 13 mboed compared to 2019, mainly due to the greater availability of crude oil, supported by our sales and marketing strategy in response to lower crude oil runs at the refineries, which in turn was primarily due to a decrease in the domestic demand for fuels and refined products. Ecopetrol’s crude oil export sales are traded both in the spot and contract markets, primarily to refiners in the United States and Asia.

 

The Castilla blend is the main type of crude oil for export sales, with 371 mboed sold during 2020 (a 89% share of the crude oil basket) followed by Vasconia with 24 mboed (a 6% share of the crude oil basket), the domestic crudes sold by Ecopetrol America LLC with 8 mboed, (a 2% share of the crude oil basket), and Mares blend with 7 mboed (a 2% share of the crude oil basket).

 

Ecopetrol places its exports in markets that provide the best value for its crudes. In 2020, Asia was the main destination, representing 49% of crude oil exports, closely followed by the United States with 43%. The expansion of refining capacity in countries like China as well as the fast recovery in crude demand of key refining hubs in Asia after lockdown measures to curb the spread of the COVID-19 pandemic were eased in Asia have supported the increase of crude oil flows from Colombia to Asia.

 

Moreover, volatility in the production of regional competitors has given refiners in the United States, India and other markets an incentive to diversify their supply sources, which in turn has opened opportunities for Colombian producers. Our crude basket realization price decreased by US$ 24/Bl year over year due to market conditions stemming from the effects of the COVID-19 pandemic mentioned above.

 

Crude Oil Purchase Contracts

 

Ecopetrol has signed several crude oil purchase contracts with third parties and business partners. Ecopetrol also purchases the country’s crude oil royalties from the National Hydrocarbons Agency. These crudes are processed in Ecopetrol’s 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, 2020, 2019 and 2018.

 

Table 27 – Ecopetrol Consolidated Crude Oil Purchases

 

    For the year ended December 31,  
    2020     2019     2018  
    (Million barrels)  
Crude oil purchased from ANH royalties     31.0       35.4       37.6  
Crude oil purchased from third parties     34.0       30.0       20.7  
Crude oil imported from third parties     5.6       9.1       14.0  

33

 

During 2020, part of Ecopetrol’s 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 2020, Ecopetrol decreased the imports of diluent by 32% (17 mbod) compared to 2019, due to the use of domestic produced naphtha. Diluent is used to transport heavy crudes through the pipeline system.

 

Natural Gas Sales

 

Ecopetrol sells 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.

 

Ecopetrol’s natural gas sales and self-consumption increased by 2% (2.9 mboed) compared to 2019, due to higher production primarily as a result of Hocol’s acquisition of Chevron’s interest in the Guajira association contract.

 

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 28 – Ecopetrol Consolidated Natural Gas Delivery Commitments

 

    For the year ended December 31,  
    2021     2022     2023     2024  
    (gbtud)  
Volume for sales third parties     503.3       483.3       420.9       311.1  
Volume for self-consumption     188.2       169.4       160.9       157.1  
Volume for intercompany sales     89.4       18.5       18.5       16.8  
Total Commitments     780.9       671.2       600.3       485.0  

 

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 2020. 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, 2020, are based on the average prices 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.

 

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

34

 

 

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, 2020, 2019 and 2018.

 

Table 29 – Net Proved Developed Reserves

 

    Colombia     North
America 		    South
America
excluding
Colombia 		    Total  
Net Proved Developed oil reserves in million barrels oil equivalent                                
At December 31, 2020(1)     757.4       16.3       2.3       776.0  
At December 31, 2019     832.0       12.0       3.8       848.0  
At December 31, 2018     814.0       13.0       5.0       832.0  
Net Proved Developed NGL reserves in million barrels oil equivalent                                
At December 31, 2020     57.0       1.1       0.4       58.0  
At December 31, 2019     49.0       0.1       0.5       50.0  
At December 31, 2018     50.5       -       0.6       51.1  
Net Proved Developed gas reserves in billion standard cubic feet                                
At December 31, 2020(2)     2,617.0       15.0       4.4       2,636.4  
At December 31, 2019     2,645.0       11.0       7.0       2,662.0  
At December 31, 2018     2,865.5       10.0       7.0       2,882.5  
Net Proved Developed oil, NGL and gas reserves in million barrels oil equivalent                                
At December 31, 2020     1,273.3       20.0       3.5       1,296.8  
At December 31, 2019     1,345.0       14.0       6.0       1,365.0  
At December 31, 2018     1,368.0       14.0       7.0       1,389.0  

 

 

(1) Oil Reserves included 14 million barrels of Fuel Oil.

(2) Gas Reserves included 411 bcf of Fuel Gas.

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 means that the determination of the property rights to the quantities of natural gas we produce is based on the total volume produced without deductions on account of royalties. The main producing gas fields are Cupiagua, Pauto, Cusiana, Chuchupa and Gibraltar.

 

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. Cenit provides transportation services for the entire Ecopetrol Group and we fully consolidate Cenit 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 2018, 2019 and 2020 annual reports, we have used our real transportation costs, rather than the regular tariffs set by the Ministry of Mines and Energy.

35

 

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 30 – Proved Oil, NGL and Natural Gas Reserves for 2020

 

    Oil (mmb)     NGL (mmb)     Natural Gas
(bcf) 		    Total Oil
and Gas
(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(1)     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(1)     -       -       -       -  
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  

 

 

(1) The reserves in South America include participation in Savia Peru, where we sold our interest on January 19, 2021.

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 17 million barrels of fuel oil, 381 billion standard cubic feet of fuel gas within our natural gas results and 517 billion cubic feet of royalties, as of December 31, 2019.

 

Table 31 – Proved Oil, NGL and Natural Gas Reserves for 2019

 

    Oil (mmb)     NGL (mmb)     Natural Gas
(bcf) 		    Total Oil
and Gas
(mmboe) 		 
PROVED DEVELOPED RESERVES                                
Colombia     832.0       49.0       2,645.0       1,345.0  
International                                
North America     12.0       0.1       11.0       14.0  
South America     3.8       0.5       7.0       6.0  
TOTAL PROVED DEVELOPED RESERVES     847.8       50.0       2,662.0       1,365.0  
PROVED UNDEVELOPED RESERVES                                
Colombia     306.0       28.0       111.0       353.0  
International                                
North America     123.0       29.0       133.0       175.0  
South America     -       -       -       -  
TOTAL PROVED UNDEVELOPED RESERVES     429.0       57.0       244.0       529.0  
TOTAL PROVED RESERVES     1,277.0       107.0       2,906.0       1,893.0  

 

 

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.

36

 

The following table summarizes our proved oil, NGL and natural gas reserves, which includes 16 million barrels of fuel oil, 327 billion standard cubic feet of fuel gas within our natural gas results and 534 billion cubic feet of royalties, as of December 31, 2018.

 

Table 32 – Proved Oil, NGL and Natural Gas Reserves for 2018

 

    Oil (mmb)     NGL (mmb)     Natural Gas
(bcf) 		    Total Oil
and Gas
(mmboe) 		 
PROVED DEVELOPED RESERVES                                
Colombia     814.0       50.5       2,866.0       1,368.0  
International                                
North America     13.0       -       10.0       14.0  
South America     5.0       0.5       7.0       7.0  
TOTAL PROVED DEVELOPED RESERVES     832.0       51.0       2,883.0       1,389.0  
PROVED UNDEVELOPED RESERVES                                
Colombia     285.0       22.0       113.0       327.0  
International                                
North America     10.0       -       6.0       11.0  
South America     -       -       -       -  
TOTAL PROVED UNDEVELOPED RESERVES     295.0       22.0       119.0       338.0  
TOTAL PROVED RESERVES     1,127.0       73.0       3,002.0       1,727.0  

 

 

Note: The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.

 

Changes in Proved Reserves

 

Table 33 – Changes in Proved Reserves

 

    For the year ended December 31,  
    2020     2019     2018  
    (Mmboe)  
Revisions of previous estimates     (71.5 )     83.0       120.5  
Improved Recovery     113.1       94.0       129.1  
Extensions and discoveries     42.7       67.0       57.4  
Purchases     29.9       164.0       -  
Sales     (1.0 )     -       -  
Total reserves additions     113.2       408.0       307.0  
Production     (236.3 )     (242.0 )     (239.0 )
Net change in proved reserves     (123.0 )     166.0       68.0  

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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 2020, 2019 and 2018.

 

The reserves replacement ratio for 2020 was 48% compared to 169% in 2019 and 129% in 2018.

 

The average replacement ratio for the last three years was 115%.

 

Table 34 – Reserves Replacement Ratio (Including Purchases and Sales)

 

      For the year ended December 31,  
      2020     2019     2018  
Annual       48 %     169 %     129 %
Three-year average       115 %     140 %     83 %

 

Revisions of Previous Estimates

 

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.

 

In 2019, revisions increased reserves by 83 million boe, mainly as a result of:

 

(i) An increase of 33 million boe due to improved reservoir performance in the Rubiales field and continuous development with drilling activities.

 

(ii) An increase of 36 million boe in reserves due to the review of the curve type of new development activities according to updated new wells results in the Caño Sur field and additional gas processing plant capacity to extract NGL in the Cupiagua field.

 

(iii) An increase of 14 million boe in reserves, due to better production performance mainly in the Akacias, Caño Limón and Chichimene fields.

 

Nonetheless, due to the decrease in oil price compared to the Brent reference price used in the reserve estimation process at $63 per barrel in 2019 (as compared to $72 per barrel in 2018), the Company removed volumes of total proved reserves in the amount of 19 million boe, which have become uneconomical. This impact was partially offset by improved reservoir performance and new projects in several fields.

 

In 2018, revisions increased reserves by 121 million boe, mainly as a result of:

 

(i) An increase of 87 million boe due to the continuous development of the Rubiales, Chichimene and Quifa fields, of which a 68 million boe increase in reserves is due to improved reservoir performance in the Rubiales field.

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(ii) An increase 14 million boe increase in reserves due to development activities in the Bonanza and Ocelote fields.

 

(iii) An increase of 19.8 million boe, due to other development activities and good well performance in other fields.

 

Improved Recovery

 

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

 

In 2019, improved recovery increased reserves by 94 million boe. An increase of 25 million boe was associated with new proved areas under water flooding in the Chichimene and Akacias fields. Furthermore, the continued development of water flooding projects at existing wells in the Castilla, Chichimene, Yarigui, La Cira-Infantas fields accounted for a 45 million boe increase. The remaining 26%, or 24 million boe, increase was due primarily to water injection reservoir responses at various fields.

 

In 2018, improved recovery increased reserves by 129 million boe. The additions were associated with new proved areas under water flooding in the Chichimene, Castilla, La Cira-Infantas, Apiay, Suria, Yarigui, Casabe and Dina Cretaceo fields (86 million boe increase). In addition, the new steam injection project at the Teca-Cocorná field accounted for a 19 million boe increase in reserves. The remaining 19%, or 24 million boe, increase was due primarily to water injection reservoir responses at various fields.

 

On average, improved recovery has added 112 million boe each year over the last three years.

 

Extensions and Discoveries

 

The following table sets forth the change in the Company’s proved reserves attributed to extensions and discoveries in millions of boe for the periods indicated.

 

Table 35 – Changes in Proved Reserves Attributed to Extensions and Discoveries

 

    For the year ended December 31,  
    2020     2019     2018  
    (Mmboe)  
Extensions and discoveries                        
Total change     42.7       67.0       57.4  
Proved Undeveloped Reserves Change     14.6       34.0       39.9  
Change from unproved to proved developed reserves     28.0       33.0       17.5  


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 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). The Company’s extensions and discoveries during 2019 amounted to 67 million boe primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Quifa, Suria, Tisquirama, Cupiagua Sur, Castilla and Garzas fields (accounting for 55 million boe). The remaining 12 million boe corresponded to smaller changes in 26 fields with variations between 0.01 to 2.1 million boe.

39

 

The Company’s extensions and discoveries during 2018 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, Castilla, Cupiagua, Pauto and Caño Sur fields (accounting for 45 million boe) and newly discovered fields and reservoirs (accounting for 12 million boe). The remaining 9 million boe corresponded to smaller changes in several other fields.

 

Purchases

 

Starting May 2020, Hocol S.A. 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 S.A., 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.

 

In 2019, Ecopetrol S.A. through its wholly owned subsidiary, Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC, a company whose economic activity is directed towards the execution of a joint development plan under the joint venture between Ecopetrol and Occidental Petroleum Corp, announced on July 31, 2019, which represented 164 million boe. Through this joint venture, the Company and Occidental Petroleum Corp are pursuing development of unconventional reservoirs in approximately 97,000 acres of the Permian Basin in Texas. For the acquisition and closing of the transaction, Ecopetrol S.A. made an initial payment of approximately US $876.5 million dollars. As of December 31, 2020, Ecopetrol had paid a total of US$ 121.8 million of the initial US$ 750 million carry obligation.

 

There were no purchases or acquisitions in 2018.

 

Sales

 

Pursuant to a public auction process carried out by Ecopetrol and Hocol in December 2020, 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. We are now pending approval of such sale from the ANH, a process that typically takes 18 months. Based on that timing, we do not expect the formal approval to be received until July 2022.

 

Development of reserves

 

As of December 31, 2020, our total proved undeveloped oil and gas reserves amounted to 473 million boe, 69% of which is related to development activities at the Rubiales, Castilla and Chichimene fields in Colombia, among others, and 31% of which is related to development activities in North American fields.

 

Ecopetrol’s year-end development plans are 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 the external certification agent.

 

As of December 31, 2019, our total proved undeveloped oil and gas reserves amounted to 529 million boe, 46% of which is related to development activities in the Rubiales, Castilla, Caño Sur Chichimene, Teca, Akacias and Pauto fields and 31% of which is related to development of unconventional reservoirs of the U.S. Permian Basin in Texas. The remaining 23% comes from activities at several other fields.

 

In 2019, Ecopetrol’s 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 went beyond the five years due to the limitations in water handling in the facilities. These exemptions were reviewed and approved by the external certification agent.

40

 

As of December 31, 2018, our total proved undeveloped oil and gas reserves amounted to 338 million boe, 21% of which is related to new drilling activities in the Rubiales field, 41% is related to development activities in the Castilla, Caño Sur, Chichimene, Quifa, Cupiagua and Yarigui fields and 22% of which is related to the new development activities in the Teca, Pauto, Bonanza and Ryberg fields. The remaining 16% comes from activities at several other fields.

 

In 2018, the development plan of Rubiales and Caño Sur Field went beyond 5 years due to the limitations in water handling in the facilities and Ryberg offshore field. These exemptions were reviewed by the external certification agent.

 

Our proved undeveloped reserves represent 27% of our total proved reserves as of December 31, 2020, 28% as of December 31, 2019, and 20% as of December 31, 2018.

 

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

 

Table 36 – Developed and Undeveloped Proved Reserves

 

    Oil (mmb)     NGL (mmb)     Natural Gas
(bcf) 		    Total Oil
and Gas
(mmboe) 		 
2020 Proved Reserves                                
Developed     776       58       2,636       1,297  
Undeveloped     396       27       285       473  
2019 Proved Reserves                                
Developed     848       50       2,662       1,365  
Undeveloped     429       57       244       529  
2018 Proved Reserves                                
Developed     832       51       2,882       1,389  
Undeveloped     295       23       119       338  

 

Of the total amount of proved undeveloped reserves that Ecopetrol 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 14% is associated with development execution in fields, such as the Ocelote field, among others. The amount of investments made during 2020 to convert proved undeveloped reserves to proved developed reserves was US$353 million.

 

Of the total amount of proved undeveloped reserves that Ecopetrol had at the end of 2018 (338 million boe), we converted approximately 89 million boe, or 26%, to proven developed reserves during 2019. Approximately 75% of the total conversion is primarily associated with the development of crude oil and gas projects in the Castilla, Rubiales, Chichimene and Yarigui fields (67 million boe), while the remaining 25% is associated with development execution in other fields such as the Suria, Casabe, Quifa, Caño Sur and Ocelote fields, among others. The amount of investments made during 2019 to convert proved undeveloped reserves to proved developed reserves was US$791 million.

 

Of the total amount of proved undeveloped reserves that Ecopetrol had at the end of 2017 (287 million boe), we converted approximately 84 million boe, or 29%, to proven developed reserves during 2018. Approximately 69% of the total conversion is primarily associated with the development of crude oil and gas projects in the Castilla, Rubiales and Chichimene fields (58 million boe), while the remaining 31% is associated with development execution in other fields such as the Ocelote, La Cira-Infantas, Caño Sur and K2 fields, among others. The amount of investments made during 2018 to convert proved undeveloped reserves to proved developed reserves was US$841 million.

41

 

Changes in Undeveloped Proved Reserves

 

The following table reflects the main changes in undeveloped proved reserves as of December 31, 2020, 2019 and 2018.

 

Table 37 – Changes in Undeveloped Proved Reserves

 

    For the year ended December 31,  
    2020     2019     2018  
    (Mmboe)  
Consolidated companies                        
Revisions of previous estimates     (46.3 )     43.0       28.4  
Improved Recovery     45.9       40.0       67.1  
Extensions and discoveries     14.6       34.0       39.9  
Purchases     -       163.0       -  
Proved undeveloped converted to proved developed     (69.4 )     (89.0 )     (83.7 )
Net change in unproved reserves     (55.2 )     190.0       51.7  

 

 

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.

 

Undeveloped Proved converted to Developed Proved: Of the total amount of undeveloped proved reserves that Ecopetrol had at the end of 2019 (529 million boe), we converted approximately 69 million boe, or 13%, to developed proved reserves during 2020. Approximately 86% of the total conversion was primarily associated with the development of crude oil and gas projects in Ecopetrol S.A Fields as Castilla, Rubiales and Cupiagua fields, among others and 14% was associated with development execution in fields where our subsidiaries are operating.

 

All the explanations that were included in Changes in Proved Reserves apply for this section.

 

Reserves Process

 

Ecopetrol’s reserves process is coordinated by Fidel Antonio Delgado Loría the Corporate Resources and Reserves Manager. Mr. Delgado Loría is a Petroleum Engineer with over 19 years of experience in the upstream sector of production business in Ecopetrol and other companies in the industry in Colombia and Venezuela. He received his engineering degree from Universidad Central de Venezuela. He reports to the Upstream Chief Financial Officer. In addition, the Ecopetrol 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, Netherland, Sewell & Associates, Inc., Ryder Scott Company, and Sproule International Limited, in compliance with the definitions of the Society of Petroleum Engineers and the applicable SEC rules. According to our corporate policy, we report the reserves values obtained from the external engineers, even if they are lower than our expected reserves.

 

The reserves estimation process ends when the Corporate Reserves Manager consolidates the results and together, with the Development Vice-President and the Upstream Chief Financial Officer, presents the outcome to the Reserves Committee, which comprises the Ecopetrol Group’s CEO, CFO and the Vice-President of Development and Production, 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 aforementioned external independent engineering consultants have estimated and certified Ecopetrol’s proved reserves as of December 31, 2020. These external engineers estimated 99% of our estimated net proved reserves for the year ended December 31, 2020, 2019 and 2018. The reserves reports of the external engineers are included as exhibits to this annual report.

42

 

Ecopetrol’s 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.

 

The following table reflects the estimated proved reserves of oil and gas as of December 31, 2018 through 2020, and the changes therein.

 

Table 38 – Estimated Proved Reserves of Oil and Gas

 

    Colombia     North
America 		    South
America
excluding
Colombia 		    Total  
Consolidated Companies   Net proved oil, NGL and gas reserves in mmboe  
At December 31, 2018     1,695.0       25.0       7.2       1,727.2  
Revisions     78.4       4.3       0.2       83.0  
Improved Recovery     94.3       -       -       94.0  
Extensions and Discoveries     66.0       0.7       -       67.0  
Purchases     -       164.0       -       164.0  
Production     (236.0 )     (4.2 )     (1.4 )     (242.0 )
At December 31, 2019     1,698.0       189.7       5.6       1,893.0  
Revisions     (49.8 )     (20.8 )     (0.9 )     (71.5 )
Improved Recovery     113.1       -       -       113.1  
Extensions and Discoveries     40.8       1.8       -       42.7  
Purchases     29.9       -       -       29.9  
Sales     (1.0 )     -       -       (1.0 )
Production     (229.6 )     (5.6 )     (1.2 )     (236.3 )
At December 31, 2020     1,601.1       165.1       3.5       1,770.2  

 

 

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 the sections Financial Review—Trend Analysis and Sensitivity Analysis and Risk Review—Risk Factors.

 

3.5.4 Joint Venture and Other Contractual Arrangements

 

We conduct our exploration and production 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, 2020.

 

Association Contract

 

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 E&P contracts and Special Contracts (Casabe, La Cira and Teca-Cocorná fields) which are described below, are the most significant in terms of our production and proved reserves.

43

 

Under association contracts, the exploratory risk is assumed entirely 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 economically viable. All major decisions of this committee must be made unanimously by the parties.

 

The maximum term of an association contract is 28 years. The first six years of the contract are for the exploratory phase, which are extendible for 1 or 2 more years at the partner’s request. The remaining time is for the exploitation phase.

 

Incremental Production Contract

 

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 Ecopetrol’s 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 Contract for Exploration and Exploitation of “La Cira-Infantas” Area, “Teca Cocorná” Area; and a Services and Technical Collaboration Contract for the “Casabe” field.

44

 

Joint Venture Contracts 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 fields and the Teca-Corcorná field 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 Venture Contracts, 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 contract term is divided in three phases. The first phase lasts 180 days, the second 730 days and the third phase lasts up to the economical limit of the field.

 

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 contract term is divided in two phases. The first phase lasts three years, extendable 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.

 

Services and Technical Collaboration Contract “Casabe”

 

The purpose of the contract executed between Ecopetrol S.A. and Schlumberger Surenco S.A. on April 26, 2004, was the evaluation, design and execution of work programs specifically with the purpose of increasing the value in the Casabe field by means of hydrocarbon exploration and production activities to obtain incremental production, application of new technologies, application of techniques for deposits management and operational costs reduction. Ecopetrol S.A. was the operator and Schlumberger Surenco S.A. kept the right of first option regarding the activities to be executed in the area of interest.

 

Both parties could invest in all the activities seeking to evaluate, obtain and incorporate incremental value in the area of interest. Such activities were developed directly by the parties or via contractors (Ecopetrol) or subcontractors (Schlumberger). Amounts expended pursuant to the contract were reimbursed depending on the incremental value (monthly valuation in US$ of the results obtained from the execution of the work programs) created through the contract and the activities executed thereunder.

 

Both Ecopetrol S.A. and Schlumberger Surenco S.A. committed to assume full responsibility for damages and/or losses suffered by their respective personnel and goods in development of the contract, regardless of the cause. The maximum authority is the Executive Committee.

 

The contract had an initial term of 10 years and was amended several times to include an additional term of six years for which a new business was structured. The contract ended in April 2020 and is currently in liquidation.

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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 beginning on January 1, 2004. Decree Law 1760 of 2003 states, “The Empresa Colombiana de Petróleos, Ecopetrol, is split, its organic structure is modified, and the Agencia Nacional de Hidrocarburos and the Sociedad Promotora de Energía de Colombia S.A. are created.” 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 the rights or obligations of Ecopetrol or other parties with respect to contracts in existence before January 1, 2004 when the ANH was created and therefore Ecopetrol retains the authority to execute agreements with respect to all areas that it held prior to that date.

 

Below, we include a brief description of each type of contract that we have entered into with the ANH:

 

Technical Evaluation Agreement

 

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 (Technical Evaluation Agreement or 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 Contract

 

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” (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).

 

Under all E&P contracts executed since ANH’s 2008 bidding round, the ANH receives a percentage of the production share, upon the commencement of the production phase, and not only in the extension phase of the contract (additional production share) as mentioned in the previous paragraph. In addition, ANH has economic rights when the price of oil exceeds a reference price set in the contract (high price fee) as well as the surface fee based on the hectares of the assigned area of the contract (both with and without production).

 

E&P contracts have three phases: (i) an exploration period, which term is 6 years counted from the effective date, renewable for two additional years, (ii) an evaluation period of two years, assuming a discovery is made, to determine the commercial potential of the discovery and (iii) a production period, which is, with respect to each production field, 24 years plus any extensions, which are counted from the date of declaration of commerciality of the corresponding field. The abovementioned terms have been modified during ANH’s 2014 bidding round for unconventional and offshore reservoirs to an exploration period of nine years and a 30-year production period. As per the new model E&P contract published by the ANH on June 29, 2018, the term of the evaluation period for offshore contracts entered into as of 2019 will be three, five or seven years, depending on the depth of the water where the discovery is located.

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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 were 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 ANH covering fields directly operated by Ecopetrol S.A. Under these agreements ANH recognizes the exclusive right of Ecopetrol S.A. to explore and exploit the hydrocarbons property of the Nation that are obtained in the areas they cover, until resource depletion or until Ecopetrol S.A. returns the area to the Nation through the ANH.

 

These agreements also provide the conditions under which Ecopetrol S.A. is able to assign, partially or completely, its rights and duties thereunder to third parties.

 

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

 

(GRAPHIC)

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Graph 6 – Map of Multi-purpose Pipeline

 

(GRAPHIC)

 

The table below sets forth the volumes of crude oil and refined products transported through the crude oil pipelines and multi-purpose pipelines owned by us.

 

Table 39 – Volumes of Crude Oil and Refined Products Transported

 

    For the year ended December 31,  
    2020     2019     2018  
    (thousand bpd)  
Crude oil transport(1)     785.6       877.7       836.2  
Refined products transport(2)     231.5       275.3       273.4  
Total     1,017.1       1,153.0       1,109.6  

 

 

(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.

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The volume of crude oil transported by Cenit’s main systems and those of its subsidiaries decreased by 10.5% in 2020 compared to the previous year. This decrease was mainly the result of (i) lower production levels, primarily due to low crude oil prices in the international markets (ii) a decrease in crude oil demand, primarily due to the lockdowns instituted around the world in response to the COVID-19 pandemic, which in turn resulted in lower transported volumes to the refineries and (iii) slow recovery rates at production fields, primarily due to market uncertainty and lower consumption. Of the total volume of crude transported by oil pipelines, approximately 82.3% belonged to the Ecopetrol Group.

 

The volume of refined products transported by Cenit decreased by 15.9% in 2020 compared to the previous year, mainly due to the impact caused by the different sanitary measures taken by the Colombian government to control the spread of COVID-19. More specifically, measures such as lockdowns and mobility restrictions that led to a decrease in demand for refined products and hence reduced wholesalers’ needs to transport such products through Cenit’s pipelines. Of the total volume of refined products transported by multi-purpose pipelines in 2020, 35.7% belonged to the Ecopetrol Group.

 

Transportation Capacity

 

Our main crude oil pipeline systems’ operating capacity decreased from 1,486 kbd in 2019 to 1,469 kbd in 2020 primarily due to scheduled maintenance. Our main multi-purpose pipeline transportation capacity increased from 511 kbd in 2019 to 519 kbd in 2020.

 

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, 2020, 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 81% of the oil pipeline shipping capacity in Colombia. By December 31, 2020, our network of crude oil and multi-purpose pipelines was approximately 9,127 kilometers in length. The transportation network consists of approximately 5,387 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 5,378 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.

 

The following table sets forth our main pipelines in which we own an indirect interest as of December 31, 2020.

 

Table 40 – Our Main Pipelines

 

Pipeline   Kilometers     Capacity
(kbd) 		    Product
Transported 		  Origin   Destination   Indirect
Ownership Percentage 		 
Caño Limón-Coveñas     774       250     Crude Oil   Caño Limón   Coveñas     100.00 %
Oleoducto de Alto Magdalena (OAM)     391       102     Crude Oil   Tenay   Vasconia     95.80 %
Oleoducto de Colombia (ODC)     483       236     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       296     Crude Oil   East fields   Monterrey Cusiana     65.00 %
Oleoducto Bicentenario de Colombia(3)     230       110     Crude Oil   Araguaney   Banadia     55.97 %

 

 

(1) Ocensa has four segments with different capacities. 745 kbd refers to the capacity of segment two (El Porvenir-Vasconia). The capacity of the other segments are as follows:

a. Cupiagua-Cusiana (segment zero): 198 kbd

b. Cusiana-El Porvenir (segment one): 745 kbd

c. Vasconia-Coveñas (segment three): 550 kbd

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

(3) Represents the contractual crude oil transportation capacity for the pipeline currently in operation.

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As of December 31, 2020, 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, 2020, we had a nominal storage capacity associated with the transportation network of 16.7 million barrels of crude oil and 4.7 million barrels of refined products. We do not own any tankers.

 

Pipeline Projects

 

San Fernando – Monterrey

 

The San Fernando – Monterrey project objectives and scope include ensuring the ability to transport 300,000 barrels per day at 300 cSt of diluted crude oil from the Chichimene and Castilla fields to the Monterrey pumping station and the transportation of 45,000 barrels per day of diluent (naphtha) between the Apiay station and the Castilla and Chichimene fields. The project foresees the construction of a new 30” 119-km crude oil pipeline, a new pumping station to include reception, storage and dilution facilities, the conversion of the existing pipeline of 10” between the Castilla II plant and the Apiay station, and the construction of a new 10” pipeline between Chichimene and San Fernando fields in order to transport diluent (naphtha) from the Apiay station to the San Fernando plant.

 

In 2018, the project completed the maximum pumping test, in accordance with the operational system parameter and owner’s requirements; as a result, the main functional services of the project were validated. The construction, startup phase and commissioning of all systems were completed in January 2018. The system is able to transport crude oil at 750 cSt between the San Fernando and Apiay stations. During 2019, 17 kms of the 30” oil pipeline infrastructure designed to bypass the Apiay station were under construction. The project was commissioned in April 2020. The commissioning of this project resulted in the reduction of 13,430 tons of CO2 emissions for the year and it reduced our energy and drag reducing agent (DRA) consumption by approximately 30%.

 

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 kbd 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 kbd to 155 kbd. The project is currently under construction and it is expected to be in operation by November 2021.

 

Replacement of Tanker Loading Unit TLU - Coveñas

 

In 2019, Ocensa invested US$ 32.8 million in offshore infrastructure as a part of the investment plan signed with the Infrastructure National Agency (ANI), which allows Ocensa to continue operating in a public area of the Morrosquillo Gulf, loading tankers with a capacity of up to 2 million barrels of crude oil. Investments during 2019 consisted of the following: the acquisition of a new, more efficient CALM Turret Buoy and PLEM (Pipeline End Manifold), which will improve the loading times of the tankers; the acquisition of two fiber optic systems, one of which communicates the TLU-2 with land and the other monitors the deformations of the submarine pipeline caused by sea currents; the maintenance of a string of floating hoses; the improvement of the inland transport and handling system; and the completion of integrity works such as inspections of the underwater pipeline, which lead to the repair of four welded joins of 42” and the stabilization of the last 72 meters of the seabed of the offshore pipeline.

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In 2020, Ocensa invested US$ 9.1 million in offshore infrastructure according to an updated investment plan signed with the ANI on December 4, 2019. The new CALM Turret buoy and 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.

 

The maintenance of floating marine hoses and the integrity works of the subsea pipeline was performed according to the plan.

 

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 2019, the engineering for the project was completed and the execution phase was approved.

 

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.

 

Vasconia Energy Recovery (RECVA)

 

Given that 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. The project is expected to be commissioned at the end of June 2021.

 

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 1.87 million barrels per day for crude oil. Our import capacity of refined products and crude oil reached 0.61 million barrels per day and 0.14 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 that are capable of storing 9.58 million barrels. Our docks used for import and export of refined products can load tankers of 70 thousand DWT. Additionally, these facilities have storage capacity of up to 1.1 million barrels.

 

3.6.2 Other Transportation Facilities

 

We have entered into transportation agreements with tanker truck and barge companies in order 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 because of capacity limitation is transported by barges. During 2020, 18.4 million barrels of crude oil and refined products were transported by tanker trucks, and 5.7 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 (76.9% of revenues), followed by the refined products pipeline transport (14.26% of revenues) and ports and related services (4.25% 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 Comisión de Regulación de Energía y Gas (CREG).

 

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, Trafigura, Mansarovar, Metapetroleum and Gran Tierra, who collectively represented 74.94% of this business segment’s revenues in 2020. Transportation services for crude oil provided to Ecopetrol S.A. represented 87.32% of this business segment’s crude oil transport revenues.

 

Cenit also transports refined products. Its main client for this service is Ecopetrol S.A., which accounted for 44.92% of refined products pipeline transport revenues in 2020, mainly due to the transport of naphtha, diesel, and gasoline. Cenit also has 31 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 (4.25% in 2020). 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

 

Oleoducto Bicentenario de Colombia S.A.S.

 

During July 2018, the carriers Frontera Energy Colombia Corp. (Frontera), Canacol Energy Colombia S.A.S. (Canacol) and Vetra Exploración y Producción Colombia S.A.S. (Vetra and, together with Frontera and Canacol, the Carriers) sent letters to Oleoducto Bicentenario de Colombia S.A.S. (Bicentenario) alleging there were early termination rights under the Ship-or-Pay Transport Agreements entered by each of them and Bicentenario in 2012 (the Transport Agreements). Bicentenario has rejected the terms of the letters, noting that there is no option for early termination and reiterating to the Carriers that the Transport Agreements are current and therefore the Carriers must fulfill their obligations under the Transport Agreements in a timely fashion. Under Bicentenario’s understanding that the Transport Agreements remain current and that the Carriers are in violation of their obligations under such agreements, Bicentenario declared the Carriers delinquent because of their failure to pay for transport service under the aforementioned agreements. Consequently, Bicentenario executed the standby letters of credit posted as guarantee for the Transport Agreements. On October 19, 2018, Bicentenario notified Frontera of the existence of a “Dispute” pursuant to Clause 20 of the respective Transport Agreement and moved to the party dispute settlement stage as provided for in such clause. Such discussions ended without an agreement on December 19, 2018. On January 28, 2019, Bicentenario filed an Arbitration Claim against Frontera in accordance with the arbitration clause of the Transportation Agreement to claim any compensation, indemnification or other restitution deriving from the alleged early termination of said agreements.

 

Similarly, on November 1, 2018, Bicentenario notified Vetra and Canacol of the existence of a “Dispute” pursuant to Clause 20 of the respective Transport Agreement and moved to the party dispute settlement stage as provided for in each such respective clause. Such discussions ended without agreement in March 2019.

 

On June 14, 2019, and June 26, 2019, Bicentenario filed arbitration claims against Vetra and Canacol, respectively, in accordance with the arbitration clause of the Transportation Agreement to claim any compensation, indemnification or other restitution deriving from the alleged early termination of said agreements.

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As part of the litigation strategy of Bicentenario, the above-mentioned claims were withdrawn, and new claims were filed, as explained below:

 

On November 12, 2019, Bicentenario filed an arbitration claim against Frontera, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 119448), in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).

 

On December 10, 2019, Bicentenario filed an arbitration claim against Vetra, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120089) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).

 

On December 26, 2019, Bicentenario filed an arbitration claim against Canacol, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120179) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).

 

On December 3, 2019, Bicentenario also filed an arbitration claim against its shareholders Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp., Canacol and Vetra under clause 23(d) of the Acuerdo Marco de Inversión before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 119872) contending that since Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp. Canacol and Vetra did not perform the actions requested by Bicentenario necessary to support the indebtedness of the Bicentenario Project, they are in breach of the Acuerdo Marco de Inversión and therefore must compensate and indemnify Bicentenario due to their unlawful conduct. This arbitration claim was withdrawn by Bicentenario on October 22, 2020, in order to present its claims on the arbitration described in the following paragraph.

 

On December 3, 2019, Frontera, Pacific OBC Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp. filed an international arbitration request against Bicentenario and Cenit under Commerce (Case No. 120488) to resolve the disputes between the parties concerning: (i) the alleged dividends due by Bicentenario, (ii) the alleged abuse of Cenit as the majority shareholder of Bicentenario, (iii) the termination of the Transportation Agreements and (iv) the tariffs dispute with Cenit.

 

On January 10, 2020, Bicentenario filed an arbitration claim against Canacol under the storage agreement (contrato de almacenamiento terminal coveñas) before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120386) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the storage agreement up to the end of the Ship or Pay term (2024). See the section Business Overview—Marketing of Transportation Services—Bicentenario, CENIT and Frontera Settlement Agreement.

 

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

 

In July 2018, the carriers Frontera, Vetra and Canacol (carriers) sent notifications to Cenit Transporte y Logística de Hidrocarburos SAS (Cenit) alleging they were exercising their early termination right under the Ship-or-Pay Crude Oil Transport Agreements (SoP agreements) entered among each of them and Cenit for the transportation of crude oil through the Caño Limón – Coveñas pipeline (owned by Cenit).

 

In response to the alleged termination of SoP Agreements, CENIT issued letters stating its position and that the alleged event which would have given the carriers early termination rights had not occurred as provided for in Clause 13.3 and other clauses of the aforementioned SoP agreements. In the same letters, CENIT stated that it would continue invoicing and charging for the transport services as stipulated in the SoP agreements, since they remain in force, and therefore, Carriers must fulfill their contractual obligations.

 

In November 2018, CENIT filed an arbitration claim against Frontera Energy Group claiming that SoP Agreements are in full force and effect and that Frontera is obliged to comply with their terms and conditions. In similar terms, arbitration claims were also filed against Vetra and Canacol in March and June 2019, respectively. See the section Business Overview—Marketing of Transportation Services—Bicentenario, CENIT and Frontera Settlement Agreement.

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Bicentenario, CENIT and Frontera Settlement Agreement

 

On November 17, 2020, CENIT 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, will resolve all the disputes pending among them, related to the Caño Limón – Coveñas pipeline, and will terminate all the pending arbitration proceedings related to such disputes. This transaction eliminates any uncertainty related to the potential outcomes of the disputes, thus protecting the interests of all the parties and those of their stakeholders and create new business opportunities for the parties involved. The settlement arrangement includes 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 and Caño Limón – Coveñas pipelines. Frontera will also enter into new transportation contracts with CENIT and Bicentenario. The new ship or pay commitment is projected to be approximately 3,900 bbls/day, based on the current oil price, for a term of five years subject to adjustments, at a current rate of US$ 11.5/bl. Frontera will not have to make payments for oil it may have to ship through alternate pipelines. These contracts will 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 will transfer to Cenit its 43.03% of the outstanding shares of Bicentenario, and will transfer to Bicentenario its participation in the Bicentenario pipeline line fill. The arrangement is conditional upon certain regulatory approvals, including approval of the settlement arrangement as a conciliation under Colombian law, which requires 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. Once all approvals are obtained and the parties perform all their obligations under the agreement, the Ecopetrol Group’s stake in Bicentenario will be 100%. As of the date of this annual report, the final approval by the Administrative Tribunal of Cundinamarca was pending.

 

Bicentenario, Cenit and Canacol Settlement Agreement

 

On October 30, 2020, Cenit and Canacol reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes 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 Caño Limón – Coveñas pipelines. On November 18, 2020, the competent arbitration tribunal approved the settlement agreement entered into by Cenit and Canacol, according to which Canacol was obliged to transfer all its outstanding shares in Bicentenario to Cenit. Additionally, as part of the settlement, Canacol entered into new transportation contracts with Cenit. These contracts will allow Cenit to obtain payment of certain amounts included in the settlement, during the term of the contracts. Furthermore, on March 8, 2021, Bicentenario and Canacol reached an agreement to settle all their aforementioned disputes. The agreement established a formula that seeks to end all contractual obligation disputes between the parties and settle all the outstanding obligations between the companies. As of the date of this annual report, approval of the settlement agreement between Bicentenario and Canacol is still pending.

 

Bicentenario, Cenit and Vetra Settlement Agreement

 

On November 23, 2020, Cenit and Vetra reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes 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 Caño Limón – Coveñas pipelines. On February 18, 2021, the competent arbitration tribunal approved the settlement agreement entered into by Cenit and Vetra, according to which Vetra is obliged to transfer all its outstanding shares in Bicentenario to Cenit and to make a cash payment for the remaining balance of the amounts included in the settlement. Furthermore, on January 13, 2021, Bicentenario and Vetra reached an agreement to settle all their aforementioned disputes. The agreement established a formula that seeks to end all contractual obligations between the parties and settle all the outstanding obligations between the companies. As of the date of this annual report, approval of the settlement agreement between Bicentenario and Vetra is still pending.

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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 Reficar, 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 the majority of 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 41 – Average Daily Installed and Actual Refinery Capacity

 

      For the year ended December 31,  
      2020     2019     2018  
      Capacity     Throughput     Use     Capacity     Throughput     Use     Capacity     Throughput     Use  
      (bpd)     (bpd)     (%)     (bpd)     (bpd)     (%)     (bpd)     (bpd)     (%)  
Barrancabermeja       250,000       179,210       72 %     250,000       218,612       87 %     250,000       221,946       89 %
Reficar       150,000       140,866       94 %     150,000       155,049       103 %     150,000       151,331       101 %
Apiay       2,500       887       35 %     2,500       779       31 %     2,500       939       38 %
Orito       2,300       1,074       47 %     2,300       1,314       57 %     2,300       1,228       53 %
Total       404,800       322,038       80 %     404,800       375,754       93 %     404,800       375,444       93 %

 

3.7.1.1 Barrancabermeja Refinery

 

The Barrancabermeja refinery supplies approximately 51.9% of the fuels consumed in Colombia 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 42 – Production of Refined Products from the Barrancabermeja Refinery

 

    For the year ended December 31,  
    2020     2019     2018  
    (bpd)  
LPG, Propylene and Butane     9,101       10,114       11,813  
Gasoline Fuels and Naphtha     50,167       64,063       58,623  
Diesel     54,261       57,469       58,305  
Jet Fuel and Kerosene     11,910       24,320       23,604  
Fuel Oil     25,112       32,009       36,636  
Lube Base Oils and Waxes     577       797       729  
Aromatics and Solvents     2,274       2,652       3,106  
Asphalts and Aromatic Tar     27,018       29,593       31,104  
Polyethylene, Sulphur and Sulphuric Acid     856       1,139       1,479  
Total     181,276       222,156       225,399  
Difference between Inventory of Intermediate Product     1,046       (703 )     (1,018 )
Total Production     182,322       221,453       224,381  

 

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In 2020, total production from the Barrancabermeja refinery decreased by 17.7% compared with 2019 mainly due to a contraction in the demand for fuels and petrochemical products caused by mobility restrictions imposed at the national level due to the health emergency caused by the COVID-19 pandemic.

 

We own and operate four petrochemical plants and one paraffin and lube plant located within the Barrancabermeja refinery. In 2020, we produced 20,945 tons of low-density polyethylene, a decrease of 37.1% compared to the production of 33,309 tons in 2019. This decrease was primarily due to the impact on the operation of ethylene production in the cracking units as a result of a lower demand for gasoline due to the health emergency caused by the COVID-19 pandemic. We produced 551.1 mboe of aromatics (benzene, toluene, xylene, orthoxylene, heavy aromatics and cyclohexane), a 16.2% decrease as compared with the production of 657.9 mboe of aromatics in 2019. The decrease was mainly the result of the decrease in demand by our national clients given a decrease in their activity, which in turn was due to mobility and work restrictions imposed at the national level due to the health emergency caused by the COVID-19 pandemic.

 

The gross refining margin decreased from US$ 10.6/Bl in 2019 to US$ 9.1/Bl in 2020, primarily due to the lower positive differential in product prices versus the Brent price, and the higher cost of the crude oil basket. The average conversion index for the Barrancabermeja refinery was 87.6% in 2020 and 86.8% in 2019. This increase was primarily due to a better quality of the diet and higher deliveries of asphalt compared to the crude load of 2019.

 

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 43 – Production of Refined Products from the Cartagena Refinery

 

    For the year ended December 31,  
    2020     2019     2018  
    (bdp)  
LPG, Propylene and Butane     3,321       4,255       4,227  
Gasoline Fuels and Naphtha     43,259       49,904       51,703  
Diesel     72,170       79,069       76,833  
Jet Fuel and Kerosene     7,424       9,331       8,057  
Fuel Oil     2,375       3,660       4,671  
Sulphur     466       585       581  
Total     129,015       146,804       146,072  
Difference between Inventory of Intermediate Product     5,318       2,262       39  
Total Production(1)     134,333       149,066       146,111  
Petcoke (Metric Tons)     828,931       922,460       984,558  

 

 
(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 44 – Imports and Sales of Refined Products from the Cartagena Refinery

 

    For the year ended December 31,  
    2020     2019     2018  
    (bpd)  
Imports                  
Motor Fuels     -       521       -  
Jet Fuel and Kerosene     -       -       466  
LPG and Butane     1,132       990       739  
Total Imports     1,132       1,511       1,205  

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During 2020, the Cartagena refinery imported butane in order to achieve the planned feed of the Butamer Unit and to increase the production of alkylate.

 

    For the year ended December 31,  
    2020     2019     2018  
    (bdp)  
Sales                  
Motor Fuels     43,979       49,865       52,126  
Diesel     73,188       77,981       78,007  
Jet Fuel and Kerosene     7,394       9,063       8,082  
Fuel Oil     2,552       3,713       4,704  
Other Products     24,275       22,435       19,942  
Total Sales     151,388       163,057       162,861  

 

Total sales decreased from US$3,904 million in 2019 to US$2,399 million in 2020. A total of 51.6 million barrels of crude were processed in 2020 compared to 56.6 million barrels of crude processed in 2019. Exports to international markets represented 43.66% of total sales (US$1,047 million).

 

The Cartagena refinery’s 2020 figures already reflect the operation of all units. The gross refining margin decreased to US$6.6/Bl in 2020 from US$9.2/Bl in 2019 mainly due to the reduction of product demand as consequence of the COVID-19 public health emergency and the Russia-Saudi Arabia oil price war. Throughput decreased during 2020, from an average of 155 mbd in 2019 to 141 mbd in 2020.

 

3.7.1.3 Esenttia S.A.

 

During 2020, Esenttia’s production totaled 490 thousand tons of petrochemical products, a 6.5% increase compared to the 460 thousand tons produced in 2019, primarily due to effective articulation of the supply chain and the ability of Esenttia to maintain its work schedule in in safe conditions given the COVID-19 pandemic. Average capacity increased by 10 thousand tons in 2020, primarily due to the expansion of the extruder capacity and the installation of a second desorber, investments that improved efficiency and reliability in plant performance. The total contribution margin in 2020 (including the contribution of polypropylene, polyethylene and masterbatches) was 3% lower than in 2019 (from US$ 242 per ton in 2019 to US$ 235 per ton in 2020), even in adverse market conditions caused by the COVID-19 pandemic.

 

Table 45 – Operating Capacity of Esenttia

 

    For the year ended December 31,  
    2020     2019     2018  
    (Metric Tons)  
Average capacity     480,000       470,000       470,000  
Throughput     489,627       459,737       447,290  
% Use     102 %     98 %     95 %

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3.7.1.4 Invercolsa

 

During 2020, Inversiones de Gases de Colombia S.A. (Invercolsa), registered 1.26 million users of natural gas, a slight increase of 3% compared to the 1.22 million users of natural gas in 2019, due to the contraction of residential natural gas installations given the COVID-19 pandemic. In 2020, Invercolsa continued to integrate its operations into the Ecopetrol Group, in connection with the increase in stake completed by Ecopetrol in November 2019. Invercolsa embraced an HSE culture and leadership model based on Ecopetrol Group’s practices.

 

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 theoretical capacity of 100,000 tons per year of biodiesel.

 

On March 10, 2020, Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S were admitted to reorganization processes by the Superintendence of Companies of Colombia under Law 1116 of 2006. The reorganization process ended on June 24, 2020, with applicable regulatory authority ordering the start of the liquidation process of both companies. For more information, see the section Risk Review—Legal Proceedings and Related Matters.

 

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 decreased by 53 mboed, 17% lower as compared to 2019. This decrease is primarily the result of the mandatory lockdowns imposed by the Colombian national government in order to curb the spread of the COVID-19 pandemic, which in turn led to sales of middle distillates and gasoline.

 

During 2020, 3.5 million barrels of diesel and 2.5 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 Ecopetrol to maintain the share of the national market. In the same way, 5.1 million barrels of diluent produced by Reficar were used to transport crude reducing diluent imports. In addition, Ecopetrol imported petrochemicals in order to complement the national supply, generating additional sales of lubricating bases, polyethylene, hexanes and others.

 

Exports of products decreased by 9% compared to 2019, 8 mboed from Reficar and 5 mboed from Ecopetrol, primarily due to lower crude oil runs at the refineries.

 

3.8 Research and Development; Intellectual Property

 

Our innovation and technology center is the Colombian Petroleum Institute (ICP for its Spanish acronym), established in 1985 and located in Piedecuesta, Santander. Technology and innovation as a key lever of our TESG strategy, are essential to our efforts to add value to our business segments through the development of proprietary technologies and competitive advantages and the adaptation of third-party technologies to our processes, and for embracing the low carbon energy transition.

 

Our research, technology development and innovation efforts are focused on four main pillars: (i) extending the technical limits for reserves growth, (ii) increasing the efficiency and sustainability of our operations, (iii) preparing the corporation for decarbonization and energy transition, and (iv) increasing the digitalization of our company. The scope of the Colombian Petroleum Institute activities covers all of our value chain segments: exploration, production, refining, transportation and sales and marketing, as well as environmental sustainability and asset integrity.

 

We will monitor the progress of technological advances that could enable us to increase the share of low emissions hydrogen in our refining and petrochemical processes. As water is a fundamental resource, our efforts will also include a technology–enabled water management program that encompasses the conservation, recycling, reuse and valorization of production water streams. Finally, we are also exploring avenues for the production of high performance, materials from petroleum molecules, for advanced non-combustion applications.

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Each year Ecopetrol presents to the Colombian National Council for Tax Benefits (Consejo Nacional de Beneficios Tributarios, or CNBT) its research, technology development projects and innovation initiatives, in order to obtain certifications for its science and technology investments. The CNBT certifies eligible science and technology investments, which are deductible from income tax upon execution; and Ecopetrol applies the tax benefit.

 

Our intangible assets are preserved through a technological value-generation process and an intellectual property protection process, which include the consolidation of trade secrets, patents, copyrights, trademarks, industrial designs, and publications in specialized journals. Ecopetrol has filed 266 patent applications in the last 15 years, 19 of them in 2020. Our most recent patent applications include innovative technologies, such as (i) a device for the coalescence of oil droplets dispersed in industrial wastewaters, (ii) synthesis and formulation of a nanofluid based on polymer-coated silica nanoparticles for the modification of relative permeability, (iii) a three dimensional superhydrophobic foam and its preparation method, and (iv) an online inspection tool for the efficient detection and classification of damages in transportation pipelines.

 

In 2020, the Colombian authorities granted us 8 new patents all in Colombia. We currently hold 101 patents in Colombia, the United States, Mexico, Russia, Peru, Venezuela, Ecuador, Brazil, Nigeria, Indonesia, India and Malaysia.

 

In 2020, Ecopetrol S.A. licensed 10 of its technologies to private companies for manufacturing, marketing commercialization and technical support including 5 to a North American company for tackling oil theft in pipelines.

 

We currently have 52 technologies licensed to Colombian and multi-national companies.

 

3.9 Applicable Laws and Regulations

 

3.9.1 Regulation of Exploration and Production Activities

 

3.9.1.1 Business Regulation

 

Pursuant to the Colombian Constitution, the Nation is the exclusive owner of minerals and non-renewable resources located in the subsoil and has full authority to determine the rights to be held and royalties or compensation to be paid by investors for the exploration or production of any hydrocarbon reserves. The Ministry of Mines and Energy 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, refinement, 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 Resolution 40048 of 2015, 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, 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 Ministry of Mines and Energy, 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 Ministry of Mines and Energy 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 in development of the mandate of Decree 3004 setting the technical conditions, requirements and procedures for the exploration and exploitation of unconventional fields. Resolution 90341 of 2014 is currently suspended by order of the Council of State, as a precautionary measure in the analysis of a legal action filed by the Universidad del Norte. This precautionary measure covers both the Decree 3004 of December 26, 2013 and Resolution N° 90341 of March 27, 2014, related to 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, amends 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.

 

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. The main measures established by this agreement are the following:

 

i. The extension of terms and deadlines for the execution of activities related to investments in exploration and evaluation phases and for the declaration of commercial discoveries;

 

ii. The establishment of procedures to transfer investments in exploration programs between allocated areas; and

 

iii. The leveling of the contractual terms of offshore contracts entered before 2014 to the ones included in the contracts executed as a result of the 2014 Colombian Round.

 

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.

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Agreement 002 of 2017, 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.

 

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 National 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 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. 2 (Agreement No. 2) opened a Permanent Competitive Bidding Procedure (PPAA), which aims to select, among previously qualified proponents on equal terms, the most favorable offers to allocate the areas previously determined, demarcated 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. 19 of November 4, 2020.

 

The Agreement 02 of 2017 was partially modified by agreement 03 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 in 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 of the right of option of improvement by the initial proponent 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 01 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 02 of 2017.

 

Agreement 02 of April 7, 2020 of the ANH regulates temporary measures to strengthen the hydrocarbon sector due to the effects generated by the fall in international oil prices. This agreement takes into account what is regulated by Decree 417 of 2020, where the Government declared the State of Economic, Social and Ecological Emergency throughout the national territory, and tlhe declaration by the World Health Organization (WHO) of the outbreak of COVID-19 as a global pandemic. Among the legal measures enacted were: (i) the extension of terms and deadlines in the contracts signed with the ANH; (ii) exceptions to the requirements established in Agreement 01 of 2020 mentioned above, which considers the status of the international oil prices; (iii) possibility of allocating resources from the Benefit Programs to the Communities “PBC” to strengthen measures applied by the Government to face the crisis; and (iv) reduction of contractual guarantees, complying with the requirements established there.

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Agreement 06 of September 11, 2020 of the ANH added Agreement 18 of 2004, Agreement 04 of 2005, Agreement 21 of 2006, and Agreement 2 of 2017 to incorporate into the Contracting Regulations for the Exploration and Exploitation of Hydrocarbons, the contractual elements that allow entities to carry out PPII on hydrocarbons in unconventional reservoirs (YNC) with the use of the Multistage Hydraulic Fracturing with Horizontal Drilling (FHPH) technique.

 

Through Resolution 0613 of September 14, 2020, the ANH opened a competitive process for the development of Research Projects in Unconventional Reservoirs by the use of the FHPH technique.

 

A first round was carried out between September 14, 2020 and November 25, 2020, allocating one area to Ecopetrol S.A. Therefore, by means of Resolution 0802 of November 25, 2020, the ANH awarded a Special Contract for Research Projects (CEPI) to Ecopetrol S.A. This contract will allow Ecopetrol, to execute activities in the interest of investigation, clarifying and exploring the feasibility of the hydraulic fracturing procedure for the exploration and exploitation of hydrocarbons in unconventional reservoirs in Colombia. The name of the contract is KALÉ and is located in Puerto Wilches (Department of Santander). As of the date of this annual report, the second round had commenced and was concluded in March 2021.

 

Temporary regulation for the Comprehensive Research Pilot Projects (PPII)

 

Ecopetrol has actively participated in the formulation of specific regulation for the implementation of the PPII. The regulatory framework includes:

 

• Resolution 40185 of 2020 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. Regulations for the selection of contractors for CEPIs (Special Contract for Pilot Projects).

 

As of the date of this annual report, additional items of the PPII regulatory framework are being discussed with the Colombian Governement pursuant to which we have made comments. In particular, the Colombian Government and the oil & gas industry are waiting for the final versions of the regulatory framework for pilot evaluation criteria, radioactive materials monitoring, health base lines and evaluation variables.

 

3.9.1.1.1 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 the serious deterioration of renewable natural resources, or that may have the capacity of materially modifying the physical environment.

 

The National Authority on Environmental Licensing (ANLA), created by means of Decree 3573 of 2011, is the authority responsible for evaluating the applications and issuing the environmental licenses for oil & gas-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 the prior 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 individuals may request information regarding the activities of the project and their potential impacts. They may also request to undertake an environmental hearing so as to obtain information of the project subject to environmental licensing.

 

On May 26, 2015, the Ministry of Environment and Sustainable Development (MESD) issued Decree 1076, which compiles most of Colombian regulations in force regarding environment and sustainable development.

 

The environmental license encompasses all of 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 have the capacity of materially modifying the physical environment. The license shall define specific conditions under which the beneficiary of the license may undertake such project or activity. The procedure to obtain an environmental license begins when the company files an Environmental Impact Study (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), according to Decree 2106 of 2019. When the project or activity requires permits for the use of forestry species that are banned, these should be included in the environmental license process. 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 (PMA).

 

The environmental licensing procedure in Colombia is set forth 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 determine the viability of the project, the procedure may take between 165 and 265 business days, depending on whether the applicant is required to file additional information. The actual procedure incorporates an oral hearing between the ANLA and the applicant in order to evaluate the information provided in the license application and whether it is necessary or not to request additional information about the proposed project. The ANLA will have no other opportunities to request additional information after this hearing.

 

The environmental licensing process for activities in unconventional reservoirs is that of 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, on unconventional hydrocarbon reservoirs using the FHPH technique.

 

The Ministry of Environment and Sustainable Development (MESD) is also responsible for issuing regulation and establishing climate change policies for different sectors in Colombia. The Ecopetrol Group comply with all applicable regulations. In particular, MESD is responsible for issuing regulation regarding Law 1931 of 2018 (Climate Change Law), which outlines provisions for the establishment of a National Program of Greenhouse Gas (GHG) Tradable Emission Quotas (PNCTE for its Spanish acronym). The PNCTE is expected to enter into force in 2022. The MEDS is also responsible for the National Emission Reductions Registry (RENARE for its Spanish acronym), in which companies must register verified GHG emission reductions. RENARE is expected to start operating in 2021. As part of our continuous monitoring of climate change requirements, we also identified ongoing regulatory processes related to the reduction of fugitive emissions and routine flaring, led by the Ministry of Energy and Mines. A company that does not comply with the applicable environmental laws and regulations, does not execute the corresponding Environmental Management Plans (PMA) 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. 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.

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3.9.1.1.2 Royalties

 

In Colombia, the Nation is the owner of minerals and non-renewable resources located in the subsurface, including hydrocarbons. Thus, companies engaged in exploration and production of hydrocarbons, such as Ecopetrol, must pay 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 Article 16 Law 756 of 2002, and Article 29 of the 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.

 

Regarding natural gas, in accordance with Resolution 877 of 2013, as amended by Resolution 640 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.

 

3.9.2 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 Comisión de Regulación de Energía y Gas (CREG as per its Spanish acronym).

 

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) must be open to third-party use on the basis of equal access to all.

 

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. 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 a public interest activity under Colombian laws.

 

Transportation systems, classified as crude oil pipelines and refined product 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 licenses and local permits awarded by the Ministry of Mines and Energy, the MESD and regional environmental authorities, respectively.

 

Crude oil transport

 

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 access 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 transport its crude oil royalties. However, for both private and public access pipelines, the ANH must pay the tariff for the pipeline use to transport its percentage of production.

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The Ministry of Mines and Energy is responsible for reviewing and approving the design of and tracks for crude oil pipelines and establishing transport 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 transport 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 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 2020, the MME started a consulting process to carry out a study with the purpose of reviewing, adjusting, and updating the crude oil tariff setting methodology. The scope of the study requires the contractor to prepare a document proposing changes to the current methodology and analyze whether it would be possible to implement the proposed methodology once the current tariff period (2019-2023), determined by Resolution 72146 of 2014 has been finalized. The results of such study will be analyzed and discussed between all the stakeholders prior to the enforcement of any changes.

 

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 transport services to third parties pursuant to a mechanism established under that decree.

 

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

 

Refined products and liquefied petroleum gas transport

 

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.

 

The applicable framework regarding LGP transportation was established by CREG Resolution 092 of 2009 (amended by Resolution 153 of 2014), which, among other issues, sets forth: (i) the obligation of the owners and operators of transportations infrastructure to guarantee access to their infrastructure to other market agents, as long as they pay the fees regulated by CREG; (ii) the general obligations applicable to LGP transporters; (iii) the requirements applicable to the LGP transportation agreement; and (iv) establishes the non-discrimination principle regarding the access to the national transportation infrastructure.

 

In January 2021, CREG presented a new draft resolution 232 of 2020, which establishes the Regulations for Transportation by multipurpose pipeline. The draft resolution was open to comments from the public and the oil and gas industry until February 26, 2021. The main objectives of the proposed regulation are: (i) to ensure free access to the transportation system without discrimination; (ii) offer optimal conditions in the operation and provision of the public transport service. In 2021, CREG also plans to define the methodology for calculating transportation rates for multipurpose pipelines.

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In February 2021, CREG issued resolution 004 of 2021.Through this resolution CREG defined the Weighted Average Cost of Capital (WACC) methodology that will be applicable to the different activities that this entity 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 will be 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. As required by article 87 of Law 142 of 1994, regulatory agencies may modify the tariff methodologies every five (5) years. As of the date of this annual report, the tariff methodology had not yet been issued.

 

3.9.3 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 State. 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.

 

In 2008, Law 1205, 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, Ecopetrol has been producing and selling diesel and gasoline that comply with the requirements of the aforementioned law.

 

Since 1995, under Resolution number 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 40619 of June 30, 2017 as amended by Resolution 40575 of 2019, which extended the validity period. Ecopetrol has been complying with this regulation and working with governmental entities in order to improve air quality in the most critical areas in Colombia.

 

3.9.3.1 Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels

 

Wholesale marketing, transport, 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 Ecopetrol’s 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 Ecopetrol, which is meant to be marketed for the provision of public utilities, shall be the result of competitive procedures.

 

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.

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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.

 

3.9.3.2 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 current gasoline engine, 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 current gasoline, diesel and biofuels between the storage plant and the fuel service station.

 

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

 

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.

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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 Income 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 Income and the International Parity Price, when the second is greater than the first on the date of issuance of the sales invoice, multiplied by the volume of fuel sold).

 

The event that generates the contribution is the sale in Colombia of gasoline or diesel by the refiners and/or importers to the wholesale distributor of fuels, according to the price set by the Ministry of Mines and Energy, however, if the importer is at the same time a wholesale distributor, the triggering event shall be the withdrawal of the product to be sold. The taxpayer responsible for the contribution is the refiner and/or importer and the active subject is the Nation. The tax base corresponds to the positive difference between the sum of the Differentials of Participation and the sum of the Differentials of Compensation.

 

The Ministry of Mines and Energy calculates the contribution through the liquidation of the Net Position of each refiner or importer with respect to the FEPC based on the report that the refiners and/or importers submit. If the sum of the Differentials of Participation is greater than the sum of the Differentials of Compensation and the contribution is caused, the Ministry of Mines and Energy will order the refiner or the importer to pay the contribution to the National Treasury within the 30 days following the execution of the liquidation resolution.

 

Subsequently, Law 1837 of 2017 (Article 16) provided that the remaining resources that were in the Ecopetrol’s 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). 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.

 

The Ministry of Mines and Energy issued Resolution 31435 of 2020, which contains the settlement of our Net Positions corresponding to: (i) the fourth quarter of 2019 and (ii) the first and the second quarter of 2020. In this Resolution, Ecopetrol was ordered to transfer COP$50,131,065,625.67 to the DGCPTN. Also, by means of Resolution 31434 and for the same periods, the Ministry ordered Refinería de Cartagena S.A.S. to transfer COP157,942,973,442.41 to the DGCPTN.

 

Law 1955 of 2019 authorizes the Ministry of Finance, as administrator of the FEPC, 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.

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3.9.3.3 Regulation of Biofuel and Related Activities

 

The sale and distribution of biofuels 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.

 

The sale and distribution of biofuels 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.

 

3.9.4 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 by the market, but some agreements still have to conform to the regulated formula. CREG issued Resolutions 185 (for transportation) and 186 (for supply) of 2020, which jointly replace 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, 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. Ecopetrol is authorized to participate as a seller in the primary market as a natural gas producer and as a buyer in the secondary market when Ecopetrol requires natural gas from other producers for its 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. Ecopetrol is also able to resell available natural gas transportation capacity into the secondary market as a non-regulated consumer.

 

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 to be 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 to 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 agreement with a warranty of uninterrupted provision 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 first 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 agreements determined by CREG 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); and (ii) permit the sale of natural gas from small fields (capacity under 30 million CFPD) pursuant to contracts that fulfill certain regulatory requirements but whose form is not prescribed by law.

 

3.9.5 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 electric energy market (“MEM”, for its Spanish acronym) 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., one subsidiary of Ecopetrol, 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 the regulations and the rights and duties of the agents. The main income of commercialization agents comes from the variable and fixed components of the unit cost tariff formula described in CREG Resolution 119 of 2007, as modified by CREG Resolutions 191 of 2014 and 030 of 2018. The variable component considers:

 

• 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 ASIC 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,

 

• 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, and

 

• 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 by CREG Resolutions 116 of 1998, 019 of 2006 and 184 of 2015).

 

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 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.

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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 National Interconnected System (“SIN” for its Spanish acronym) 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 Regional Transmission Systems (STR for its Spanish acronym), 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. 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 STN 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.

 

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.

 

The rules set forth by CREG Resolution 095 of 2007 Article 2 are applicable to Ecopetrol and, as of the date of this annual report, we are in compliance with all such requirements.

 

3.9.6 Regulation of the Electricity Self-Generation Activity

 

Law 1715 of 2014 regulates the integration of non-conventional renewable energies to the National Interconnected System. 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.

 

Based on Law 1715 of 2014, Decree 2469 of 2014, as currently compiled by Section 4 of Decree 1073 of 2015, 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.

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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 Mining and Energy Planning Unit (“UPME”) and the remuneration of surplus energy. Note that, as determined by Resolution UPME 281 of 2018, 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 030 of 2018.

 

CREG Resolution 024 of 2015 (modified by CREG Resolution 140 of 2017) sets conditions for surplus sales of an AGGE, connection and metering conditions, and back-up and energy supply conditions. Specifically, this resolution determines that AGGE must follow the general connection rules to the SIN for a generation plant, that they must have a remote telemetry system, and that they must have a back-up power purchase agreement, among others.

 

CREG Resolution 030 of 2018 establishes the connection conditions for AGPE, surplus sales conditions, metering conditions and energy commercialization rules for AGPE. Note that CREG published CREG Resolution 002 of 2021, by means of which it published a project resolution in which it modifies the regulation for AGPE regarding the connection measurement, and surplus trade rules.

 

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 Ecopetrol’s self-generation projects. As of the date of this annual report, Ecopetrol complies 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.

 

3.10 Technology, Environment, Social and Governance (TESG) Strategies and Initiatives

 

Ecopetrol has a long-standing commitment to positively contribute in terms of economic, social, and environmental development, and grounds its behavior on a solid corporate governance, a business conduct based on values ​​and ethical principles, with transparency at its core. This work has been led in collaboration with our stakeholders through initiatives and strategies that have been framed in corporate responsibility and sustainability. The Company has strengthened its metrics and reporting of environmental, social and governance (ESG) issues in line with international standards.

 

Furthermore, Ecopetrol has identified that Technology (T), leveraged on applied innovation and the revolution brought about by digital transformation, is a key catalyst to accelerate and achieve in a timely manner the necessary changes to face ESG challenges. This is the new concept of TESG. The convergence between TESG and Ecopetrol’s corporate strategy marks a milestone that will change the future of the Company, where its transformation into an energy company is leveraged by technology. With this, we validate our commitment to be a Company that moves towards value creation in a sustainable future.

 

During 2020, Ecopetrol reviewed its environmental, social and governance (ESG) taxonomy, considering shifts in international trends related to these. One of the main findings of the project was that sustainability needs to be addressed from a technology standpoint that allows for the implementation of innovative solutions to current and future challenges in an accelerated and exponential way. The TESG strategy integrates technology to environmental, social, economic and governance issues, allowing for innovative solutions to have accelerated implementations and timely scalability, and is one of the four lines of action of our energy transition plan (See the section entitled Strategy and Market Overview—Our Corporate Strategy—2021 – 2023 Business Plan—Energy Transition).

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This strategy is based on a materiality analysis, which allowed the identification of 28 TESG topics that have or could have a significant impact (positive or negative) on our ability to generate value in the short, medium and long term and/or a significant relevance to stakeholders. Based on this analysis, Ecopetrol identified materiality as a dynamic and recurring process that is expected to be constantly reviewed. Moreover, although Ecopetrol manages all 28 TESG topics using four distinct categories (exceptional, outstanding, differentiated and compliance), in its disclosures, Ecopetrol will prioritize the following, based on their materiality:

 

Ecopetrol’s Material Topics

 

•       Climate Change •      Circular Economy
•       Water Management •      Air Quality
•       Regional Development •      Fuel Quality
•       Health and Safety •      Use of energy and alternative sources
•       Biodiversity and Ecosystem Services •      Prevention and management of incidents by operations
•       Talent attraction, development and retention •      Prevention and management of incidents causes by third parties

 

During 2020, we reviewed and updated our seven stakeholder groups (as defined below), given that their expectations and perceptions are considered within the materiality analysis. The methodology used for this update was based on the application of the AA1000 standard. Its purpose is to responsibly manage relationships with our key stakeholders, which leverages decision-making and strategic vision, resulting in long-term value creation.

 

Ecopetrol’s seven key stakeholder Groups are: (i) associates and partners, (ii) investors, (iii) clients, (iv) suppliers, contractors and their employees, (v) employees, retirees and their beneficiaries, (vi) state, and (vii) society and community.

 

As in previous years, during 2020 the Corporate Responsibility Area consulted the perceptions and expectations of our seven stakeholder groups with respect to the 28 TESG topics and corporate responsibility attributes. The results obtained for corporate responsibility in 2020 (84%) represent an improvement of 2% over the results obtained in 2019 (82%).

 

We also remain committed to improving our information disclosure standards by following international best practices. In particular, during 2020, and early 2021, the Company decided to begin the adoption of the Sustainability Accounting Standards Board (SASB), the recommendations of the Taskforce on Climate-related Financial Disclosures (TCFD), and the Stakeholder Capitalism Metrics (SCM) into our stakeholders’ reports.

 

During 2020, the environmental management strategy of Ecopetrol S.A. included the following components:

 

i. Environmental Viability: this strategy concentrates on the planning, execution and submission of environmental impact assessments to national and regional authorities in order to obtain licenses and permits for project execution. Adequate project planning allows projects to pursue impact prevention and minimization through the mitigation hierarchy approach, ensuring the sustainability of operations and systematic relationships with stakeholders.

 

ii. Climate Change: this strategy aims to decrease our carbon emissions and manage climate-related risks and opportunities, through the implementation of four strategic action lines:

 

Mitigation: reducing our greenhouse gas emissions (GHG) and creating carbon offset alternatives as part of a comprehensive decarbonization plan;

 

Vulnerability and Adaptation: reducing the risks and impacts to our operations posed by climate variability and change;

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Research and Technology: investing on research and development to reduce our GHG emissions through low carbon technologies; and

 

Involvement in Policymaking: advising and influencing government policies on climate change.

 

Our decarbonization plan has four components: (i) GHG emissions inventory verification, (ii) development and implementation of an emissions reduction portfolio, (iii) design and implementation of an offset portfolio of natural climate solutions, and (iv) development of a net zero emissions roadmap.

 

As part of Ecopetrol S.A.’s efforts to contribute to the Sustainable Development Goals and the Paris Agreement, on March 25, 2021, Ecopetrol announced its plan to achieve net zero carbon emissions by 2050 (scopes 1 & 2), in line with its commitment to mitigate climate change and further the energy transition and the TESG agenda.

 

By 2030, Ecopetrol seeks to reduce its 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, Ecopetrol will seek to reduce 50% of its 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.

 

The development of the goals proposed are a part of the Ecopetrol Group’s Corporate Strategy and energy transition roadmap. Progress on these goals is expected to be reported periodically in line with Company’s earnings results.

 

Ecopetrol continues to implement its emissions reduction portfolio, which includes specific programs and targets in relation to renewable energies, elimination of routine flaring, energy efficiency and reduction of fugitive emissions and venting. In 2020, we achieved a reduction of 199,847 tons of CO2e from projects implemented during that year. Ecopetrol has achieved a total accumulated reduction of 8,472,766 tons of CO2e during the 2010-2020 period, of which 1,756,163 tons of CO2e have already been verified by a third party.

 

iii. Sustainable production system and biodiversity: Ecopetrol’s 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 are described below.

 

i. Prevention and mitigation of biodiversity impacts:

 

• Updated biodiversity information for decision making and resilience analysis.

 

• Incorporate the impact of 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 and generate additional biodiversity and social co-benefits.

 

• Conserving biodiversity and ecosystem services

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iv. Circular Economy: the circular economy model of Ecopetrol was structured in alignment with the National Circular Economy Strategy declared by the Ministry of Environment and Sustainable Development in 2019. This strategy defined the concept of circular economy as “production and consumption systems that promote efficiency in the use of materials, water and energy, taking into account ecosystem resilience, circular use of material flows through implementation of technological innovation, partnerships and collaborations between actors, and promotion of business models that respond to the fundamentals of sustainable development.”

 

In this sense, the main goal of the circular economy model is to incorporate the concept into management processes in order to promote economic growth, improve competitiveness, and mitigate risks related to environment and price volatility in raw materials. The model’s five components are (i) efficient use of resources and new businesses, (ii) improvement and development of products and services, (iii) standards and public policy, (iv) territory management towards circularity, and (v) corporate culture.

 

The circular initiatives portfolio includes 333 initiatives: out of which 230 are being developed directly by Ecopetrol S.A., 97 by the Ecopetrol Group, and 6 by industrial symbiosis

 

v. Water Management: this strategy aims to incorporate water management efficiency into the organization’s value chain, as a key element in project decision-making. Based on a sustainability framework, we aim to reduce environmental impacts and water-related conflicts, as well as incorporate water security stewardship initiatives in accordance with the following areas: (i) operational efficiency in water management; (ii) sustainability and water security in the environment; and (iii) water planning and governance. This strategy is aligned with the 2010 National Water Resources Policy, the 2018-2022 National Development Plan, the Green Growth Mission and the UN 2030 Sustainable Development Goals.

 

Ecopetrol is also committed to improving the quality of the fuels it supplies in order to contribute to a better air quality for Colombians and comply with fuel quality regulations. Taking advantage of being an integrated company, after April 2018, we reduced the sulphur content in our diesel B2 (98% fossil and 2% biodiesel) to under 25 ppm. In particular, in 2020, the diesel and the gasoline that we distributed in Colombia had an average of 9.9 ppm and 84.9 ppm of Sulphur, respectively, below the current local regulations of 50 ppm in diesel and 300 ppm in gasoline.

 

Further information can be found in Ecopetrol’s 2020 Sustainability Report which is available on our website at: www.ecopetrol.com.co.

 

3.10.2 Energy Initiatives

 

Ecopetrol has been undertaking significant efforts to make efficient and rational use of energy resources in its production processes and to reduce energy consumption, costs and carbon dioxide emissions. We focus on efficiency, reliability, optimization and energy diversification.

 

Production

 

Further, during 2020, Ecopetrol’s production segment had an average monthly energy consumption of 402 GWhm (gigawatts per hour per month) for its direct operation, from which 66% was provided through self-generation and the remaining 34% with non-regulated energy purchased from the National Transmission System.

 

Transport

 

In January 2021, Ecopetrol started the construction of a second solar complex, San Fernando, in order to supply renewable energy to its transport and production operations. This second solar farm will have an installed capacity of 59 MW, which will add up, along with the current capacity of the Castilla Solar Farm (21 MW), a total capacity of 80 MW of solar generation in the Castillas’ solar farm. The San Fernando solar farm will supply part of the energy required by the San Fernando transport station and the Castilla field.

 

In 2021, the Ecopetrol Group will begin the development of six new photovoltaic projects for 45 MW that are expected to boost Colombia’s energy transition and that will be added to the San Fernando and Castilla solar farms.

 

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In terms of wind generation, we have identified prospects on the Atlantic Coast and Huila. Furthermore, the wind measurement activity was awarded in the Casablanca lot adjacent to the Cartagena Refinery, which began in January 2021.

 

Refining

 

During 2020, the Barrancabermeja refinery’s average monthly energy consumption was 53 GWhm (gigawatts per hour per month), provided through self-generation. The Cartagena Refinery’s average monthly energy consumption was 58 GWhm (gigawatts per hour per month), provided through self-generation.

 

3.10.3 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.

 

3.10.3.1 Ecopetrol S.A.

 

One of the principles that guides Ecopetrol is the commitment to its 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 (HSE) practices.

 

The results of the HSE performance in 2020, compared with the prior year, were:

 

• A reduction in the Total Recordable Incidents Frequency (TRIF) from 0.59 in 2019 to 0.43 in 2020. The TRIF represents the number of employee or contractor injuries that require minimum medical treatment for every million hours worked, including fatalities

 

• A 67% decrease in road accidents, due to improvements in real-time monitoring of drivers’ safety habits, an increase in control check points for tracking tankers and awareness campaigns for drivers

 

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

 

• 5 process safety incidents in 2020, from 4 incidents in 2019;

 

• A 38% decrease in the number of incidents involving employee or contractor injuries that require medical treatment, restricted work or lost days

 

• The severity of occupational incidents remained constant in 2020 compared to 2019 with three fatalities recorded in both years; and

 

• A decrease of 12% in the amount of oil spilled. In 2020, 125 barrels were spilled as compared to 142 barrels in 2019.

 

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.

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Total Recordable Incidents Frequency – Employees and Contractors

 

Ecopetrol S.A. places an important emphasis on understanding, monitoring and controlling the impacts on workers and contractors.

 

TRIF has improved from 2.96 incidents per million hours worked in 2012 to 0.43 in 2020. In 2020, 46 recordable cases occurred, where 15% led to restricted work, 9% required medical treatment and 76% led to lost days. Additionally, we had a 38% decrease in the number of occupational incidents compared to 2019, however, with decreased work hours in 2020.

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Graph 7 – Total Recordable Incident 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. and the Vice-Presidency of Transport and Logistics, 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 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 National Authority for Environmental Licenses (ANLA), are part of the risk management procedures of the territories where we operate.

 

The emergency and contingency plans, which have been developed from a risk and consequence analysis, cover the preparedness, response and recovery phases and include the following elements:

 

• Identification of emergency and disaster scenarios

 

• Definition and implementation of strategies and procedures for responding to spills, fires, explosions, events involving hazardous materials, events affecting people, and natural events.

 

• Workers training and education programs

 

• Definition and implementation of resources, equipment and tools

 

• Emergency evacuation drills

 

• Definition of activation mechanisms and early warning system to communities

 

• Implemented common command and control model called Incident Command System, which allows for organized and objective-oriented decision making

 

• Cooperation and coordination schemes defined and formalized through mutual aid plans

 

• Operational information and communications available to evaluate and carry out a situational analysis of the evolution of emergencies

 

• Performance evaluations

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Ecopetrol continuously implements training programs for all personnel involved in emergency or contingency response plans. In the last four years, 13,457 trainings have taken place to improve our employees’ skills. During 2019 and 2020, 7,033 training were carried out as shown in the table below:

 

Graph 8 – Trained personnel

 

 

Performance improvement has been achieved through the execution of the 36 emergency and contingency plans.

 

Frequency of process safety incidents

 

Our Process Safety Management (PSM) strategy is to: first, define high-risk processes; second, prioritize intervention in high-risk processes; and third, apply all PSM elements in the prioritized high-risk processes.

 

Loss of primary containment is the number of unplanned or uncontrolled releases of oil, gas or other hazardous materials.

 

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 2020, there were 0.05 Tier 1 process safety incidents per million hours worked, an increase from the 0.03 recorded in 2019.

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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. and the Vice-Presidency of Transport and Logistics classified according to the criteria in API-754 Tier 1, but does not include Ecopetrol S.A.’s subsidiaries.

 

Environmental Incidents

 

In 2020, Ecopetrol S.A. recorded 4 environmental incidents, compared with 6 in 2019 and 11 in 2018. The volume of oil spills was 125 in 2020, a decrease from 142 barrels in 2019 and a decrease from 710.26 barrels in 2018.

 

Lisama 158/La Fortuna Incident

 

On March 2, 2018, a seepage of water and traces of crude oil occurred near the Lisama 158 well, located in the village of La Fortuna, in the Middle Magdalena Valley of Colombia. Ecopetrol activated its contingency plan to contain the spill. As of March 30, 2018, the Lisama 158 well was sealed and stopped flowing.

 

Ecopetrol’s internal investigation concluded that there were four concurrent critical factors leading to the incident and that in the absence of any of them, the incident would not have occurred.

 

Corrective and mitigation actions implemented by Ecopetrol

 

In due course, Ecopetrol carried out all the social, environmental and technical actions to fully attend the event and mitigate other damages and manage the incident, in compliance with the obligations contained in Law 1523 of 2012, Presidential Decree 321 of 1999 and the contingency plan of the Lisama Well.

 

After closing the event and abandoning of the well, Ecopetrol continues to implement environmental recovery actions, in accordance with the orders given by and in coordination with the environmental authorities. Likewise, voluntary social investments have been fulfilled.

 

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 was informed that the National Environmental Licensing Authority (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 to Ecopetrol in an amount of COP$5.155 million. In the course of said administrative process, the ANLA exonerated Ecopetrol from liability for some charges, due to the fact that ANLA evidenced that Ecopetrol had activated its contingency plan and implemented the corresponding actions. It also mentioned that Ecopetrol’s environmental control actions were taken in an appropriate manner. Nonetheless, it decided to impose the fine, because the ANLA considered that the actions were not taken in a timely manner and because, it considered that Ecopetrol did not adopt and implement the necessary actions to correct the mechanic failures in the well, in order to prevent the environmental damage. On February 11, 2020, Ecopetrol filed a reconsideration appeal before ANLA requesting the reversal of this decision. On February 9, 2021, through Resolution 290, the decision of the ANLA was announced and reduced the fine to COP$ 3,863,918,267. The file is now closed by the environmental authority.

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

 

An initial suspension order against those Ecopetrol 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 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.

 

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. As of the date of this annual report the court has not scheduled a hearing date. On September 25, 2020, Ecopetrol informed Mapfre Seguros Generales de Colombia S.A. that it was seeking to invoke guarantee coverage by the guarantors.

 

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 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 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.

 

On March 22, 2018, Ecopetrol made a claim to MAPFRE SEGUROS GENERALES DE COLOMBIA S.A., based on its Control of Well Policy and received the US$19 million in October 2019. Thereafter, as a result of the third party liability policy claim objection, Ecopetrol has taken the relevant actions to obtain the guarantee coverage of guarantors. On February 27, 2020, Ecopetrol filed a lawsuit against “MAPRE SEGUROS GENERALES DE COLOMBIA S.A.” to obtain recognition and payment of COP$ 128,807,833,685 based on civil liability. The court is analyzing the lawsuit.

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3.10.3.2 Cenit

 

Cenit established its own HSE Management System based on Decree 1072 of 2015 in 2017, and this was implemented during 2018. Cenit is also leading the definition of standard HSE key process indicators (KPIs) for all of the midstream subsidiaries to be able to measure the transportation business as a whole and share the lessons learned and best practices within the industry. Cenit consolidated the 2019 KPIs and agreed upon the goals for 2020 for the transportation business to obtain the results for each subsidiary and for the entire group. Local and field operations have been mainly conducted under Ecopetrol’s HSE model and guidelines, but from early 2021 Cenit controls all transportation activities under its own HSE model and guidelines.

 

3.10.3.3 Cartagena Refinery

 

In 2020, approximately 5,179,195 man-hours were employed conducting Reficar’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 Reficar’s TRIF for 2018, 2019 and 2020, which includes Ecopetrol Operation and Maintenance (O&M), Reficar and subcontractors. The table presents statistics related to operating and maintenance activities. Reficar has not reported fatalities during the period 2010 – 2020.

 

Table 46 – Performance Indicators

 

    For the year ended December 31,  
Metric   2020     2019     2018  
Man-hours     5,179,195       6,538,295       6,779,729  
Recordable accidents     1       1       12  
Total recordable incidents frequency (TRIF)*     0.19       0.15       1.77  
Environmental Incidents (EI)     -       -       -  
Process Safety Incidents (PSI)     -       -       -  

 

 

* These risks were associated with normal operations.

 

3.11 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.

 

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:

 

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 on the basis of 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 in 2010 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.

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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 became the successor of Hocol, of a ship-or-pay transportation agreement for 17,500 barrels per day, thus increasing Ecopetrol’s contracted capacity in the P135 Project to 87,500 barrels per day.

 

On July 1, 2017, with the consent of Ecopetrol 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 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, and executed (i) settlement agreements with those who accepted Ocensa’s offer and (ii) the corresponding amendments to the transportation agreements.

 

In 2020, payments made by Ecopetrol S.A. under these two agreements amounted to US$ 1,099.85 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. In 2018, Ecopetrol S.A. received an aggregate sum of US$ 5.25 million under the contract. On December 1, 2018, the parties agreed to extend the term of the agreements for one year until November 30, 2019. On December 1, 2019, the parties agreed to extend the term of the agreements for two years until December 1, 2021. In 2020, Ecopetrol S.A. received an aggregate sum of US$ 3.67 million under the contract.

 

Ocensa has entered into the following agreements, among others, with some of our other subsidiaries:

 

In March 1995, Equión and Santiago Oil Company entered into agreements for the transportation of crude oil through the Oleoducto Central S.A. (Ocensa) pipeline. In November 2012, Equión and Santiago Oil Company transferred, by means of various transactions, its shares (24.8%) and transportation rights (19.8%) holdings in the Ocensa pipeline to wholly owned subsidiaries of Ecopetrol S.A. (51%) and Talisman (49%). Equión and Santiago Oil Company kept 5% of transportation rights in Ocensa. In 2014, the transportation fees billed by Ocensa were: Equión (US$ 44.4 million), Santiago Oil Company (US$ 3.8 million) and Hocol (US$ 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. On May 23, 2013, another amendment was executed that modified the terms by which the payments of invoices should be made. In 2020, Equión paid Ocensa US$ 0.26 million. Hocol paid Ocensa, as assignee of transportation rights from original shippers, US$ 30.30 million in 2020.

 

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 MME Tariff had been set in 2011 for a four-year term, with a yearly adjustment based on the consumer price index. In 2020, payments made by Ecopetrol S.A. under this agreement amounted to US$140 million.

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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 directly or by third-party contractors hired by Ecopetrol 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, 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 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. Pursuant to the terms of this agreement, ODC paid approximately US$ 4.36 million in 2020.

 

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. Pursuant to the terms of this agreement, ODC paid Ecopetrol S.A. approximately US$0.86 million in 2020.

 

In September 1999, a joint operation agreement was signed for the TLU-3 Coveñas buoy between Ocensa, ODC and Ecopetrol. Pursuant to the terms of this agreement, ODC paid approximately US$1.96 million in 2020. 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.

 

ODC has entered into the following agreements with some of our other subsidiaries:

 

Between March 1992 and January 1993, Hocol, Equión 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 2020, the transportation fees billed by ODC were: Equión (US$ 0.71 million) and Hocol (US$ 0.66 million).

 

Oleoducto de los Llanos Orientales (ODL)

 

Ecopetrol S.A. has entered into the following agreements, among others, with its 65%-owned subsidiary, ODL:

 

In March 2009, Ecopetrol S.A. entered into a ship-or-pay agreement with ODL that establishes a financing tariff used to pay ODL’s indebtedness to Grupo Aval for five years. This agreement was superseded by a new contract executed in May 2010, with a seven-year term, to reflect new conditions agreed with Grupo Aval. In August 2013, this contract was amended, providing a new term of seven years, including a two-year grace period, and an interest rate of DTF + 2.5%. This financing tariff is collected through a trust fund, which in turn is responsible for making the debt service payments to Grupo Aval. Under this agreement, ODL has committed to transport 75,000 bpd during the initial two-year grace period of the facility and 90,000 bpd during the remaining years, including the new term. Ecopetrol S.A. is responsible for 65% of this capacity. Payments by Ecopetrol S.A. under this contract were COP$ 63.87 billion in 2020.

 

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 expires 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 2020. This agreement was extended under the “ship-and-pay” conditions until December 2021. Payments by Ecopetrol S.A. under this contract were COP$ 678.4 billion in 2020.

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In March 2010, Ecopetrol S.A. entered into a pipeline operating and maintenance agreement with ODL. This agreement had an original five-year term and was amended in 2015 to extend the term another ten years, adjusting certain conditions. In January 2017, this agreement was partially assigned by Ecopetrol to Cenit, due to matters related to the management of plants and pipeline assets. In August 2017, the maintenance obligations were partially assigned by Ecopetrol to a third party. In October 2017 and February 2018, the name of the contract, some technical definitions and the annexes of the contract were updated and certain Ecopetrol’s obligations were removed, in line with the partial assignment. In March 2020 the agreement was finished by the term of the contract and the new one was assigned to a third party. Pursuant to the terms of this agreement, ODL paid to Ecopetrol S.A. COP$ 2.17 billion, plus applicable taxes, in 2020. In addition, pursuant to the partial assignment ODL paid to Cenit COP$ 0.05 billion, plus applicable taxes, in 2020; this agreement terminated in March 2020, and the operation was assigned to a third party.

 

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$ 7.68 billion plus applicable taxes in 2020.

 

Oleoducto Bicentenario de Colombia S.A.S.

 

Ecopetrol S.A. has entered into the following agreements, among others, with its 55.97% 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. In November 2018, the agreement was amended to remove the restriction on the number of contingent services during 2018. In March 2019, the agreement was amended to extend the term to provide the “contingent service” until June 21, 2019. In June 2019, the agreement was amended to extend the term to provide the “contingent service” until September 21, 2019. In September 2019, the agreement was amended to extend the term to provide the “contingent service” until December 21, 2019. In October 2019, the agreement was amended to remove the restriction on the number of contingent services during 2019. In December 2019, the agreement was amended to extend the term to provide the “contingent service” until June 21, 2020. In June 2020 and December 2020, the agreement was amended to extend the term for six months to provide the “contingent service” until June 21, 2021. Pursuant to the terms of these agreements, in 2020, Ecopetrol and Hocol paid COP$ 626.77 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. Pursuant to the terms of this agreement, Ecopetrol and Hocol paid to Bicentenario COP$ 39.0 billion, plus applicable taxes, in 2020.

 

In August 2012, Ecopetrol S.A. entered into an Operation and Maintenance agreement for the Araguaney – Banadia pipeline system. The duration of this agreement is 15 years. This agreement was partially assigned in January 2017 by Ecopetrol to Cenit due to matters related to the management of plants and pipeline assets. In July 2018 Oleoducto Bicentenario and Cenit signed a settlement agreement to recognize costs related to this contract. The scope of the contract assigned by Ecopetrol to Cenit was finished by the mutual agreement of the parties (Bicentenario and Cenit) in March 2020. Pursuant to the terms of those agreements, Bicentenario paid to Cenit COP$ 0.05 billion, plus applicable taxes, in 2020.

 

In November 2017, the maintenance obligations of the transportation system (from the first agreement mentioned in the preceding paragraph) were partially assigned to a third party. During December 2017, the agreement with Ecopetrol was modified to exclude from its scope the Araguaney and Banadía Stations’ maintenance. In November 2018, the pipeline maintenance obligations were extended until April 2019. In April 2019, the pipeline maintenance obligations were extended until July 2019. In July 2019, the pipeline maintenance obligations were extended until October 2019. In October 2019, the pipeline maintenance scope was substituted by technical supervision and in July 2020, the technical supervision scope was terminated by mutual agreement of the parties. However, the operational scope of the contract is still valid. Pursuant to the terms of this agreement, Bicentenario paid to Ecopetrol S.A. COP$ 5.83 billion, plus applicable taxes, in 2020.

 

Ecodiesel

 

Ecopetrol S.A. (Ecopetrol) entered into a supply agreement for the Barrancabermeja refinery, with Ecodiesel Colombia S.A. (Ecodiesel), a company in which Ecopetrol has a 50% equity interest. The current agreement began on January 25, 2018. Pursuant to the terms of this agreement, Ecodiesel must deliver to Ecopetrol and Ecopetrol must in turn purchase 48,100 barrels of Ecodiesel’s biodiesel production each month. Payments vary depending on the purchased volumes and the prices of biodiesel. This agreement expires on January 31, 2021. In 2020 a total of COP$ 283.4 billion was paid under this contract. In April 2020, Ecopetrol made a spot purchase to Ecodiesel for consumption in the Port of Buenaventura for COP$ 0.4 billion. A new agreement began on February 1, 2020 for the delivery of 50,880 barrels of Ecodiesel’s biodiesel production each month. The new agreement will be active until January 31, 2026.

 

Additionally, Ecopetrol, as Reficar’s legal agent, signed another supply agreement with Ecodiesel on October 2, 2019 that was valid until September 30, 2020 and pursuant to which Ecopetrol agreed to buy up to 156,000 barrels of biodiesel for a year from Ecodiesel. A total of COP$ 46.4 billion was paid under this contract. On October 1, 2020, Ecopetrol and Ecodiesel signed another supply agreement for the supply of biodiesel to Reficar that is valid until September 30, 2023. Pursuant to the terms of this agreement, Ecodiesel must deliver to Reficar, and Reficar must in turn purchase 10,400 barrels of Ecodiesel’s biodiesel production each month. In the fourth quarter of 2020, Reficar paid a total of COP$ 19.6 billion to Ecodiesel under this agreement.

 

In 2020, Ecopetrol bought COP$ 283.8 billion worth of biodiesel from Ecodiesel for its own consumption and COP$ 66 billion worth of biodiesel for Reficar’s consumption.

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Savia Peru 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 US$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 US$57 million through the disbursement period ended on December 31, 2017. On December 11, 2019, Ecopetrol 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 is US$28.3 million under the loan agreement. Korea National Oil Corporation (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 sold its 50% ownership interest in OIG. Korea National Oil Corporation (KNOC) also sold its participation on OIG (the remaining 50%) to De Jong Capital LLC, under the same terms and conditions as Ecopetrol.

 

On the same date, Ecopetrol 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. As of the date of this annual report, Savia Peru owed US$ 26.8 million to Ecopetrol under this loan agreement.

 

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);

 

• Properties and other assets;

 

• Rendering and receiving services;

 

• Leasing assets;

 

• Depositing and borrowing money; and

 

• Using public utilities.

 

In addition, we have an agreement with the ANH (National Hydrocarbons Agency) 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 and the ANH that reflects our export sales prices (crudes and products), a quality adjustment for API gravity and sulphur content, transportation rates from the wellhead to the Coveñas or Tumaco ports and a marketing fee. We sell the physical product purchased from the ANH as part of our ordinary business.

 

For the years ended December 31, 2020, 2019 and 2018, we purchased the following volumes of crude oil from the ANH corresponding to royalties paid in kind by oil producers in Colombia: 31.0 million barrels, 35.4 million barrels and 37.6 million barrels, respectively. The contract between the ANH and us was extended until October 31, 2022. See the 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 is a state-owned enterprise and the Nation’s control of Ecopetrol results from the fact that it is one of our shareholders and owns more than a majority of our common shares. Neither Ecopetrol 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.

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3.12 Insurance

 

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 of our affiliated and subsidiary companies.

 

As a proactive strategy to deal with the hardening conditions of the worldwide reinsurance market for the last three years, in July 2020, Ecopetrol became a member of the OIL Pool. OIL is an energy industry mutual insurance company based in Hamilton, Bermuda, established since 1972. This organization operates on the basis of 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. OIL insures assets worldwide for a total value over US$3trillion. Its credit rating is A (S&P) and A2 (Moody's). Currently, 61 companies in the world are members of OIL.

 

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

 

i. Category A: Coverage through the OIL pool 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 and the companies covered, along with limits and coverage details.

 

Table 47 – Category A: Coverages through the Oil Pool and Reinsurance and Insurance Market for the Downstream Segment

 

    Limit (eel / agg)(1)     Deductible     Ecopetrol              
US$ Millions   Onshore     Offshore     Onshore     Offshore     Downstream     Reficar     Esenttia  
Policies                                          
Property all risk     2,200       N/A       5       N/A       X       X       X  
Sabotage and terrorism     600       N/A       0.5       N/A       X       X       X  

 

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

Note: Due to its liquidation, Bioenergy was not included in the renewal of Ecopetrol’s corporate insurance program for 2021.

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Table 48 – Category A: Coverages through the Oil Pool and Reinsurance and Insurance market for the Upstrem segment

 

    Limit (eel / agg)(1)   Deductible   Ecopetrol                          
US$ Millions   Onshore   Offshore   Onshore   Offshore   Upstream   Equión   Hocol   Santiago Oil   ECP America   Permian   ECP Costa Afuera  
Policies                                              
Property all risk(2)     400     N/A     1.0     N/A     X     X     X   X   X     X   X  
Sabotage and terrorism     400     N/A     0.5     N/A     X     X     X   X   N/A     X   N/A  
Control of wells(3)     250 / 75     800 / 300     1.0     5 / 6     X     X     X   N/A   X     X   N/A  

 

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

(2) US$250 million Property All Risk but US$400 million Maximum Loss limit and in the aggregate in respect of earthquakes.

(3) Onshore: Drilling US$250 million; Production US$75 million for any well. // Offshore: Drilling US$800 million; Production US$300 million for any well

 

Table 49 – Category B: Transversal Coverages through the Traditional Insurance and Reinsurance Market for the Downstream, Upstream and Midstream Segments

 

US$ Millions Limit
(eel / agg)(1) 		Deductible Ecopetrol Reficar Esenttia Esenttia MB Equión Hocol Santiago Oil ECP America Permian Brazil ECP Costa Afuera Cenit Ocensa ODL OBC ODC      Invercolsa  
Policies        
Third party liability 500 10.0 X X X X X X X X X X X X X X X  X   N/A  
Crime 35 0.5 X X X X X X X X X X X N/A N/A N/A N/A  N/A   X  
Directors & Officers 65 Various X X X X X X X X X X X X X X X  X   X  
Cargo 75 3% dispatch X X N/A N/A N/A X N/A N/A N/A N/A N/A N/A N/A N/A N/A  N/A      N/A  
Charterers 750 0.02 X X N/A N/A N/A X N/A N/A N/A N/A N/A N/A N/A N/A N/A  N/A    N/A  
Cyber(2) 25 / 150 Various X X X X X X X X X X X X X X X  X   X  

  

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

(2) Coverage under section one (buyback for property) only applies to Ecopetrol S.A. whereas coverage under Sections two to nine apply to Ecopetrol and its downstream, midstream and upstream 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.

 

Ecopetrol’s midstream subsidiaries continue having an independent program for their oil transportation companies (including crime and directors & officers policies).

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Table 50 – Midstream Program

 

    Limit (eel / agg)(1)     Deductible                                
US$ Millions   Onshore     Offshore     Onshore     Offshore     Cenit     Ocensa     ODL     OBC     ODC  
Policies                                                      
Property all risk(2)     200       200       0.250       0.50       X       X       X       X       X  
Sabotage and terrorism(3)     70       30       0.075       0.15       X       X       X       X       X  
Third party liability     100       100       0.100       0.50       X       X       X       X       X  
Directors & Officers(4)     75               -               X       X       X       X       X  
Crime     50               0.175               X       X       X       X       X  

 

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

(2) US$200 million each company and an aggregated excess shared limit of US$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.

(4) Aggregate limit of US$75 million word wide coverage. Deductible only for coverage No.2 in the USA.

 

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.

 

With respect to 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.

 

With respect to onshore operations in the U.S., Ecopetrol 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 Human Resources/Labor Relations

 

3.13.1 Employees

 

As of December 31, 2020, the Ecopetrol Group had 13,977 employees, a decrease of 7.8% compared to 2019. This decrease was primarily due to the Bioenergy liquidation, the early retirement plan offered to a group of employees, resignations and termination of temporary contracts. Most of our employees are located in Colombia.

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The table below presents the breakdown of Ecopetrol employees according to the business segments where they work, and the personnel of our subsidiaries for the years ended December 31, 2020, 2019 and 2018.

 

Table 51 – Ecopetrol Group’s Employees

 

    For the year ended December 31,  
    2020     2019     2018  
    (Number of employees)  
Ecopetrol S.A.                        
Exploration and Production                        
Exploration     208       227       215  
Production     2,271       2,324       2,258  
Others     712       501       758  
Total Exploration and Production     3,191       3,052       3,231  
Downstream     -       -       -  
Refining     2,526       2,661       2,696  
Marketing     145       145       136  
Others     38       37       74  
Total Downstream     2,709       2,843       2,906  
Transport     802       860       798  
Others     820       796       351  
Total Operations     7,522       7,551       7,286  
Corporate     2,248       2,536       2,417  
Total Ecopetrol S.A.     9,770       10,087       9,703  
Ecopetrol America LLC.     47       66       68  
Ecopetrol Permian LLC.     16       -       -  
Ecopetrol USA     29       -       -  
Bioenergy S.A.S.     -       478       441  
Bioenergy Zona Franca S.A.S.     -       287       279  
Hocol S.A.     346       249       221  
Equión Energía Limited     38       242       284  
Oleoducto Central S.A.     283       288       275  
Oleoducto de Colombia S.A.     15       7       3  
Oleoducto de los Llanos S.A.     77       79       75  
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.     98       143       153  
Ecopetrol Óleo e Gás do Brasil Ltda.     35       31       16  
Esenttia S.A.     417       412       428  
Esenttia MB     41       46       -  
Cenit Transporte y Logistica de Hidrocarburos S.A.S.     511       366       282  
Invercolsa     2,247       2,371       -  
Ecopetrol Energía S.A. E.S.P     7       5       -  
TOTAL     13,977       15,157       12,228  

 

As of December 31, 2020, the subsidiaries Kalixpan Servicios Técnicos, S. de R.L. de C.V., Topili Servicios Administrativos S. de R.L. de C.V., Ecopetrol Capital AG and Black Gold RE did not have direct employees.

 

Loans and investment on 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 2020, Ecopetrol S.A. has extended 833 housing loans for a total of COP$ 209.6 billion and 1,411 general-purpose loans for a total of COP$ 15.3 billion. In 2020, Ecopetrol S.A. also provided on-site and external training and development, which totaled to COP$ 15.9 billion, and it extended a total of COP$ 186.5 billion in subsidies for education.

 

We have not provided loans (including housing loans), extended or maintained credit lines, arranged for the extension of credit by third parties, materially modified or renewed an extension of credit lines, in the form of a personal loan to or for any of our executive officers since our ADSs were registered under the Exchange Act.

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Ecopetrol does not offer credits to any of its executive officers.

 

Labor Regulation

 

In accordance with Article 123 of the Colombian Constitution and the 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 behavior is subject to the rules to those who handle public interests and goods and could be held liable for their illegal actions and omissions pursuant to the following regimes: (i) disciplinary (Law 734 of 2002), (ii) criminal or (iii) civil.

 

Declaration of Culture

 

In 2020, Ecopetrol updated its Declaration of Culture, which contains the six principles that guide our operation: (i) Life First, (ii) Collaboration, (iii) Ethics & Transparency, (iv) Innovation, (v) Excellence and (vi) Leadership.

 

3.13.2 Collective Bargaining Arrangements

 

Ecopetrol S.A.

 

A collective bargaining agreement with some labor unions governs labor relations between Ecopetrol and its unionized workers, which amounted to 4,933 employees as of December 31, 2020. The agreement also governs our labor relations with other 2,777 non-unionized employees who, according to current labor legislation, are beneficiaries of the collective bargaining agreement.

 

We currently have eleven industry-wide labor unions and nine company labor unions:

 

• Unión Sindical Obrera de la Industria del Petróleo — USO (industry labor union);

 

• Asociación de Trabajadores, Directivos, Profesionales y Técnicos de las Empresas de la Rama de Actividad Económica del Recurso Natural del Petróleo, los combustibles y sus Derivados— ADECO (industry labor union);

 

• Sindicato Nacional de Trabajadores de Empresas Operadoras, Contratistas, Subcontratistas de Servicios y Actividades de la Industria Petrolera, Petroquímica y Similares — SINDISPETROL (industry labor union);

 

• Unión de Trabajadores de la Industria Petrolera y Energética de Colombia – UTIPEC, former UTEN (industry labor union);

 

• Sindicato Nacional de Trabajadores de la Industria de los Hidrocarburos – SINATRINHI (industry labor union);

 

• Asociación Sindical de Trabajadores de la Industria de Hidrocarburos de Colombia - ASINTRAHC, (industry labor union);

 

• Sindicato Nacional de Trabajadores de Mantenimiento de la Industria del Petróleo, Gas y Carbón - SINTRAMANPETROL (industry labor union);

 

• Unión Sindical de Trabajadores del Sector Energético – USTRASEN (industry labor union)

 

• Sindicato de Trabajadores de la Industria Minero Energética – SINTRAMEN (industry labor union)

 

• Unión Sindical de los Trabajadores de Oleoductos y Poliductos - USOLEODUCTOS (industry labor union)

 

• Asociación Sindical de Trabajadores de la Industria del Petróleo - ASINPE (industry labor union)

 

• Asociación de Profesionales de Ecopetrol — ASPEC (company labor union);

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• Asociación Sindical de Empleados de Ecopetrol – ASOPETROL (company labor union);

 

• Asociación Sindical de Trabajadores de Ecopetrol – TRASINE (company labor union);

 

• Asociación Sindical de Trabajadores de Ecopetrol – ASTECO (company labor union);

 

• Sindicato de Trabajadores Petroleros de Ecopetrol – SINPECO (company labor union);

 

• Sindicato de Profesionales de Ecopetrol S.A. – SINPROECOP (company labor union);

 

• Asociación de Profesionales y Tecnólogos Empleados de ECOPETROL S.A. – APROTECO (company labor union).

 

• Asociación Sindical de Trabajadores de la Industria del Petróleo e Hidrocarburos de Ecopetrol S.A. ASTIPHEC (company labor union); and

 

• Sindicato de Trabajadores de Ecopetrol S.A. SINTRAECO (company labor union).

 

In 2020, 50.3% of Ecopetrol’s employees were affiliated with one of the above trade union organizations. As of the same date and in accordance with the governing legal provisions, the current Collective Bargaining Agreement (described below) applied to 78.3% of Ecopetrol S.A.’s total workers, out of which 28% were workers who were not affiliated with any Trade Union Organization but were beneficiaries of the Collective Bargaining Agreement by extension under Article 471 numeral 1 of the Substantive Labor Code.

 

Ecopetrol S.A.’s relations with unions are based on a permanent dialogue and communication sessions where different matters are discussed in order to solve and prevent any labor conflict.

 

Our current collective bargaining agreement has been in effect since July 1, 2018 and has a term of four and half years, expiring on December 31, 2022. The collective bargaining agreement included an increase in salaries at an annual rate of the local consumer price index (CPI) +1.21% for the remainder of 2018 and CPI +1.70% every year for the remainder of its duration. The agreement covers health, food, loans and transportation, among other benefits for workers, within reasonable criteria. It also includes union guarantees and addresses regulatory issues.

 

During 2020, the agreements contained in the Collective Labor Convention 2018 – 2022 were performed, as were other agreements signed in the framework of the collective bargaining agreement process. In addition, a number of areas of dialogue with trade unions were advanced and different issues pertaining to their interest were addressed. A total of 425 meetings were scheduled.

 

The Company manages compliance with trade unions rights with respect to the discount of trade union dues, permits and trade union guarantees. It also fully observes the rules governing aspects such as trade union law and other rights related to freedom of association.

 

4. Financial Review

 

Our consolidated financial statements for the years ended December 31, 2018, 2019 and 2020 were prepared in accordance with IFRS.

 

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.

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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) the reduced demand levels for crude oil and its derivative products, and (iii) volumes, product mix, exchange rate, and our operational performance. 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 do also. 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. 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. 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 Trend Analysis and Sensitivity Analysis—Trend 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 and natural gas that we make from third parties and the ANH.

 

We sell crude oil and natural gas in the local and the international markets. We also process crude oil at the Barrancabermeja and Reficar 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 48.4% of our total revenues, on average, for the past three years.

 

International sales and prices

 

Our international sales represented 51.6% 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 an excess of 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 finalize or revert back, 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, because the 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$787,466 million in 2020.

 

On September 30, 2020, Law 2056 of 2020, (“Through which the organization and operation of the general system of royalties is regulated”), was issued. Article 18 of this law broadened the definition of incremental production to all production from fields where additional investments have been made to increase the recovery factor. In this sense, the total production of these fields 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.

 

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 and the ANH that reflects our export sales prices (crudes oil and products), a quality adjustment for API gravity and sulphur content, transportation rates from the wellhead to the Coveñas or Tumaco ports and a marketing fee. 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 October 31, 2022.

 

Since 2016, we have imported crude oil for Reficar feedstock when such imports result in better operational or economic performance of the Ecopetrol Group.

 

4.2 Effect of the COVID-19 Pandemic on our 2020 Results

 

The Covid-19 outbreak was first reported in late 2019 in China. Subsequently, taking into account the level of expansion, the World Health Organization (WHO) declared the outbreak as a pandemic on March 11, 2020. Said status is maintained to the date of this annual report. 

 

Many countries have undertaken various public health measures to control the spread of COVID-19, including mandatory quarantines, forced economic shutdowns and travel restrictions, as well as economic measures to mitigate the impacts of such public health policies on their respective national economy.

 

On March 17, 2020, the Colombian Government, through Legislative Decree 417 of 2020, declared a 30-day state of national emergency in light of the health and economic crisis caused by the outbreak of COVID-19. On May 6, 2020, through Legislative Decree 637 of 2020, the Colombian Government declared a state of emergency for an additional 30 days. The Government has implemented various economic and public health measures to address the crisis. See “Risk Factors – Risks Related to Colombia’s Political and Regional Environment."

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The COVID-19 pandemic has also caused significant volatility in financial and commodity markets around the world. While governments have announced aid packages to the most affected people and taken macroeconomic measures to face the crisis, the COVID-19 pandemic has disrupted economies worldwide. See “Risk Factors – Risks Related to Our Business – Our business operations could be disrupted by the Coronavirus or other pandemic disease and health events for further information on the effects of the coronavirus pandemic and – Risks Related to Colombia’s Political and Regional Environment – The worldwide economic effects of the outbreak and economic shutdown caused by the COVID-19 pandemic is adversely affecting Colombia’s economy, and the impact could be material.”

 

This situation has had a significant impact on the oil industry. Most specifically, travel bans imposed by several countries and established quarantine measures reduced demand levels for oil and its derivative products in 2020. Ecopetrol’s operations were affected by this situation and as a consequence, some plants in our refineries and some of our wells were temporarily closed due to low demand and prices and the measures taken to contain the spread of COVID-19 in workers and contractors. In this context, Ecopetrol took the following actions during 2020 to face the impacts of the COVID-19 pandemic:

 
  • Ecopetrol’s Board of Directors was permanently at the forefront of the crisis caused by Covid-19. Throughout the year, the Board of Directors held a total of 15 extraordinary sessions to direct Ecopetrol with opportunity and expeditiousness in taking measures to counteract the impacts derived from this crisis. In addition, Ecopetrol issued the “Declaration of Contingency Operation” in March 2020 and activated the equipment, plans and actions required to prevent infections, respond to new challenges in the Ecopetrol’s Group operations and enact special containment measures.

 

  • Cuts in costs and expenses, including austerity measures, prioritization of operational and administrative activities, and control over operational expenses, such as travel restrictions, sponsorships and participation in events, among others. These measures contributed to the total unit cost for the year 2020 which was approximately USD$ 27/bl, a decrease of 23% compared to the total unit cost for 2019.

 

• Disbursements under credit lines in the aggregate amount of USD$665 million, as well as an issuance of external public debt bonds in the international capital markets in the aggregate amount of USD$2 billion.

 

• Publication of a new organic investment plan for Ecopetrol Group approved by the Board of Directors on July 17, 2020 considering: (i) a detailed review of the Ecopetrol Group’s portfolio, (ii) progress in the interventions carried out, and (iii) the gradual recovery of economic activity.

 

• Allocated resources of COP$85,387 million in connection with humanitarian aid and other initiatives to strengthen the Colombian health system to address the COVID-19 pandemic.

 

• The execution by Ecopetrol S.A. of 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 of crude oil. A total of 30 million barrels (mmbls) were the subject of strategic hedges oriented at protecting the Ecopetrol´s income and cash flow, limiting losses, covering production costs and avoiding potential closures of production fields. A total of 21.7 million barrels (mmbls) were the subject of tactical hedges oriented at mitigating risks associated with storage marketing strategies, anticipated purchases of raw materials, supply to refineries, international sales delivered at the destination port and exports of heavy fuel oil.

 

• Recognition of impairment expenses at the end of December 31, 2020 in the aggregate amount of COP$633,156 million, after adjusting some of the assumptions used (prices and discount rates) in the impairment evaluation carried out as of December 31, 2019, recognizing the impact on the Ecopetrol Group’s main long-term assets (some productive assets in the exploration and production segment and in the Cartagena refinery).

 

These measures were aimed at ensuring the sustainability of the Ecopetrol Group’s business in an environment of low prices, prioritizing cash-generating opportunities with better equilibrium prices, maintaining growth dynamics with a focus on the execution of strategic asset development plans, and in asset value preservation through investments to gain reliability, integrity and continuity to the current operation in refineries, transportation systems and production fields. Similarly, these actions are covered by Ecopetrol’s risk management policies and procedures.

 

In terms of Ecopetrol’s results of operations as of and for the year ended December 31, 2020, the most significant impacts were the following: (i) a reduction in revenues, especially due to the contraction in demand and a decrease in the international Brent price partially offset with the higher exchange rate, (ii) an increase in financial costs due to an increase in debt, a decrease in valuation to fair value and lower yields of the securities portfolio, which in turn were as a result of low market rates, (iii) recognition of impairment at the end of the year as described above, and (iv) an increase in our depreciation expenses, partly generated by the update of the Ecopetrol’s reserve balance.

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As a result of the measures taken, the constant monitoring of the COVID-19 pandemic, the ongoing vaccination programs and the evolution of the Ecopetrol Group’s results, while we cannot offer any assurances, as of the date of this annual report, Ecopetrol does not believe that the COVID-19 pandemic will have a significant impact on the Ecopetrol Group in the long-term.

 

Nonetheless, the Ecopetrol Group will continue to monitor the evolution of the COVID-19 pandemic and the market to determine the need to implement subsequent stages of the COVID-19 intervention plan and will continuously review impairment indicators on long-lived assets and on investments in companies.

 

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, (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.

 

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.

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Additionally, in December 2018, the Colombian Congress adopted Law 1943, which introduced the following key changes to the Colombian tax system, applicable beginning in 2019, including the following aspects:

 

The corporate income tax rates were set to be reduced gradually from 33% to 30% as follows: 33% in 2019, 32% in 2020, 31% in 2021 and 30% from 2022 onward.

 

The presumptive income tax rate was reduced to 1.5% for fiscal year 2019.

 

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 year 2018 and 2019 the newly enacted dividends tax applies as follows:

 

i. For non-resident shareholders:  (i) a 5% dividend tax for dividends paid out of profits that were accrued as of January 1, 2017 and a 7.5% dividend tax for dividends paid out of profits that accrued as of January 1, 2019 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 35% withholding tax rate 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, 5% dividend tax after applying the initial 35% withholding tax rate and a 33% withholding tax rate 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, 2019, plus an additional, 7.5% dividend tax after applying the initial 33% withholding tax rate; and (iv) a 35% withholding tax rate on dividends distributed from profits not taxed at the corporate if the dividend is paid out of profits that accrued until December 31, 2016.

 

ii. For Colombian individuals: for fiscal year 2018, dividends paid were taxed at 5% if they were between 600 and 1,000 Tax Value Unit (UVT or Unidad de Valor Tributario for its Spanish acronym) and 10% if they were greater than 1,000 UVT. For fiscal year 2019, dividends paid were taxed at 15% if they were greater than 300 UVT.

 

Dividends paid to local corporations during 2018 were not subject to any income tax, provided that such dividends were taxed at the corporate level. For fiscal year 2019 and 2020, these dividends were taxed at 7.5%.

 

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% and vehicles 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.

 

Carbon tax accrues on the carbon content of fossil fuels used for combustion. The rate will be COP$ 16,422 and COP$ 17,211 per ton of CO2, for fiscal year 2019 and 2020, respectively.

 

For additional information see Note 10.2.4 of our consolidated financial statements.

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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.

 

In December 2019, the Colombian Congress adopted Law 2010, which introduced the following key changes to the Colombian tax system, among others:

 

The corporate income tax rates will be gradually reduced from 32% to 30% as follows: 32% in 2020, 31% in 2021 and 30% in 2022 onward.

 

The presumptive income tax rate will be reduced to 0.5% for fiscal year 2020 and to 0% from 2021 onward.

 

The creation of a “normalization tax” 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.

 

As of 2020, 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 2020, 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 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) 32% withholding tax rate on dividends distributed from profits not taxed at the corporate level (31% for 2021 and 30% as of 2022), plus an additional 10% dividend tax after applying the initial 32% withholding tax rate (i.e., 38.8% in 2020).

 

ii. Dividends paid to Colombian companies: (i) a 7.5% dividend tax on dividends distributed from taxed profits, or (ii) a 32% withholding tax on dividends distributed from non-taxed profits (31% on 2021 and 30% as from 2022), plus an additional 7.5% dividend tax on the balance of the dividend amount after the initial 32% withholding.

 

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

 

Part A: Applicable Taxpayers

 

Resident individuals with assets located in Colombia and abroad.

 

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 due from Colombian entities, mining or oil rights and/or 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.

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Part B: Tax Accrual Rules

 

The wealth tax at a rate of 1%, on January 1 of each fiscal year 2020 and 2021. The taxable base is the taxpayer’s net equity on each of the accrual dates (gross equity less liabilities and certain exclusions, including a portion of the value of the dwelling house and 50% of the goods repatriated to normalization). In any case, the taxable base for fiscal year 2021 may not vary by more than 25% of the prior year’s inflation.

 

Thin capitalization: A 2:1 debt-to-equity ratio determines the amount of deductible interests on loans with related parties.

 

Law 2010 maintains the tax regime for profits derived from indirect transfer of Colombian assets.

 

As of 2020, the transfer (or disposal) of real estate whose value is higher than 29,800 UVT (approximately COP$918,436,000) will no longer be subject to the real estate consumption (excise) tax (formerly applied at 2%). This tax was specifically repealed by the Constitutional Court and was not re-introduced by Congress in Law 2010.

 

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$1,068,210,000,000) by 2020, 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.

 

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.

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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.

 

During 2020, the Colombian Peso depreciated on average 12.46% against the U.S. dollar. During 2019 and 2018, the Colombian Peso depreciated on average 11.02% and 0.2%, respectively, against the U.S. dollar. Additionally, as of December 31, 2020, December 31, 2019 and December 31, 2018, the Colombian Peso/U.S. dollar exchange rate had depreciated 4.74%, 0.84% and 8.91% respectively from the rate a year earlier.

 

In 2020, our consolidated debt in foreign currency increased by a total of US$2,420 million as Ecopetrol S.A. entered into committed credit lines in an aggregate principal amount of US$665 million and issued an SEC-registered bond in an aggregate amount of US$2,000 million. In 2019, our consolidated debt in foreign currency decreased by a total of US$159 million mainly as a result of amortization of foreign currency capital expenditures. In 2018, our consolidated debt in foreign currency decreased by a total of US$2,123 million mainly as a result of prepayments of local and foreign currency of US$2,446 million and amortization of foreign currency capital expenditures.

 

As of December 31, 2020, our U.S. dollar denominated total debt was US$12,728 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, US$12,598 million are in Ecopetrol S.A.’s balance sheet, whose functional currency is the Colombian Peso. Therefore, when the Colombian Peso depreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate loss. In contrast, when the Colombian Peso appreciates against the U.S. dollar, Ecopetrol S.A. has an exchange rate gain. Some of the Ecopetrol Group’s companies have the U.S. dollar as their functional currency and are not exposed to a material exchange rate risk resulting from fluctuations in the Colombian Peso against the U.S. dollar. When the financial statements of the Ecopetrol Group are consolidated, the exchange rate differential of the subsidiaries’ assets and liabilities whose functional currency is the U.S. dollar is recognized directly in equity, as part of other comprehensive income.

 

Since 2015, Ecopetrol S.A. 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 67.9% (US$8,549 million) of Ecopetrol S.A.’s debt in U.S. dollars, as of December 31, 2020, was designated as a hedge. 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, 2020, the Ecopetrol Group’s companies have the equivalent of a net U.S. dollar liability position of US$1,424 million after the implementation of the natural hedging previously mentioned above, minimizing the effect of exchange rate fluctuations in their results for the year.

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4.3.3 Effects of Inflation

 

The average annual rate of inflation in Colombia for the past ten years is 3.70%. It decreased in 2020 as compared to 2019. As measured by the general consumer price index, average annual inflation in Colombia for the years ended December 31, 2020, 2019 and 2018 was 1.61%, 3.80% and 3.18%, respectively. The decrease in inflation in 2020 is mainly due to the COVID-19 pandemic, which created an abrupt supply and demand shock on Colombian CPI, particularly as a result of weak demand, significant excess productive capacity, a very tight labor market and price relief measures.

 

Cost inflation in the prices of goods, raw materials, debt interest expenses denominated in local currency indexed to inflation and services for operation of oil and gas producing assets can 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 2020 was US$43.2 per barrel as compared to US$64.2 per barrel in 2019 and US$71.7 per barrel in 2018. See section Strategy and Market Overview for more information.

 

Ecopetrol’s average crude oil basket price was US$34.4 per barrel in 2020, as compared to US$58.6 per barrel in 2019 and US$63.2 per barrel in 2018. The decrease of US$24.2 per barrel in 2020 as compared to 2019 was mainly due to the decrease in the international Brent price and a weaker spread between the price of heavy crude oil versus the Brent price, which was partially offset by proactive sales and marketing management towards the diversification of clients and destinations, with sales of our Castilla and Vasconia blend crudes to South Korea, customers reactivation in India and Spain, and a sustained market share in the United States Gulf of Mexico and China.

 

In addition, Ecopetrol’s average product basket price was US$49.2 in 2020, US$69.8 in 2019, and US$77.30 in 2018. The decrease of US$20.6 per barrel in 2020 as compared to 2019 was primarily the result of a decrease in the international Brent price, partially offset by (i) an increase in our sales volumes at the beginning of the year at higher prices and (ii) our active commercial management that allowed us to export the production surpluses, which in turn were the result of a decrease in domestic demand, largely for gasoline, diesel and jet fuel as a result of the effects of the COVID-19 pandemic.

 

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 Operating Results—Consolidated Results of Operations—Impairment of Non-Current assets, Segment Performance and Analysis and Note 18 to our consolidated financial statements.

 

4.4 Accounting Policies

 

Our consolidated financial statements for the years ended December 31, 2020, 2019 and 2018 were prepared in accordance with IFRS. The detail of the accounting policies is described in Note 4 to our consolidated financial statements.

 

We adopted IFRS 16 – Leases as from January 1, 2019. Also, we adopted IFRS 9 – Financial Instruments and IFRS 15 – Renevue fron Contracts and Customers as from January 1, 2018. The adoption of such standards did not generate a material impact in our results. 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.

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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, 2020, 2019 and 2018.

 

Table 52 – Consolidated Income Statement

 

Income Statement   For the year ended December 31,     % Change  
(COP$ Million)   2020     2019     2018     2020/2019     2019/2018  
Revenue     50,223,393       71,488,512       68,603,872       (29.7 )     4.2  
Cost of sales     37,567,472       44,972,360       41,184,379       (16.5 )     9.2  
Gross Profit     12,655,921       26,516,152       27,419,493       (52.3 )     (3.3 )
Operating expenses     4,841,000       3,726,557       4,592,445       29.9       (18.9 )
Impairment (recovery) of non-current assets, net     633,156       1,762,437       368,634       (64.1 )     378.1  
Operating Income     7,181,765       21,027,158       22,458,414       (65.8 )     (6.4 )
Finance results, net     (2,481,587 )     (1,670,494 )     (2,010,375 )     48.6       (16.9 )
Share of profit in associates and joint ventures     76,336       366,904       165,836       (79.2 )     121.2  
Income before income tax     4,776,514       19,723,568       20,613,875       (75.8 )     (4.3 )
Income tax expense     (2,038,661 )     (4,718,413 )     (8,258,485 )     (56.8 )     (42.9 )
Net Income     2,737,853       15,005,155       12,355,390       (81.8 )     21.4  
Net income attributable to:                                        
Company’s shareholders     1,586,677       13,744,011       11,381,386       (88.5 )     20.8  
Non-controlling interest     1,151,176       1,261,144       974,004       (8.7 )     29.5  
Net Income     2,737,853       15,005,155       12,355,390       (81.8 )     21.4  

 

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, 2020, 2019 and 2018. An explanation of how we classify our operations into business segments is included in section 4.6.1.8 below.

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Table 53 – Third-Party Revenues by Business Segment

 

    2020     2019     2018     Change Sales Revenues
(%) 		 
Revenue by segment   Volume
(barrels equivalent) 		    Average price US$/barrels     Sales revenues (COP$ Million)     Volume
(barrels equivalent) 		    Average price US$/barrels     Sales revenues (COP$ Million)     Volume
(barrels equivalent) 		    Average price US$/barrels     Sales revenues (COP$ Million)     2020/2019     2019/2018  
Local Crude oil   2,208,356     28.6     230,520     2,232,087     48.6     356,857     2,919,416     60.8     550,479     (35.4 )   (35.2 )
Foreign Crude oil   153,185,623     34.4     19,498,553     147,692,547     58.7     28,461,601     143,208,235     63.2     26,898,737     (31.5 )   5.8  
Natural gas local   31,391,611     24.5     2,845,155     28,798,105     23.8     2,256,123     28,065,889     22.5     1,885,846     26.1     19.6  
Foreign natural gas   554,742     8.6     17,231     506,556     16.6     27,255     530,945     17.7     27,899     (36.8 )   (2.3 )
Other income(1)   5,409,528     -     263,466     3,788,550     -     193,282     3,216,650     -     749,939     36.3     (74.2 )
Exploration and production sales   192,749,860     -     22,854,925     183,017,845     -     31,295,118     177,941,135     -     30,112,900     (27.0 )   3.9  
Local refined products   90,659,046     54.1     17,745,376     111,095,596     74.5     27,170,498     108,781,359     81.9     26,354,549     (34.7 )   3.1  
Foreign refined products   39,668,072     42.4     6,165,364     44,007,684     62.3     8,977,662     41,577,284     68.6     8,485,932     (31.3 )   5.8  
Foreign Crude Oil   -     -     29     289,289     62.6     61,995     -     -     -     (100.0 )   100.0  
Other income(1)   -     -     894,118     -     -     183,315     -     -     107,467     387.7     70.6  
Refining and petrochemicals(2)   130,327,118     -     24,804,887     155,392,569     -     36,393,470     150,358,643     -     34,947,948     (31.8 )   4.1  
Transportation services   -     -     2,563,581     -     -     3,799,924     -     -     3,543,024     (32.5 )   7.3  
Transportation and logistics   -     -     2,563,581     -     -     3,799,924     -     -     3,543,024     (32.5 )   7.3  
Total sales   323,076,978     -     50,223,393     338,410,414     -     71,488,512     328,299,778     -     68,603,872     (29.7 )   4.2  
Crude Oil   155,393,979     34.4     19,729,102     150,213,923     58.6     28,880,453     146,127,651     63.2     27,449,216     (31.7 )   5.2  
Natural gas   31,946,353     24.3     2,862,386     29,304,661     23.7     2,283,378     28,596,834     22.4     1,913,745     25.4     19.3  
Refined products   135,736,646     49.2     24,174,206     158,891,830     69.8     36,341,442     153,575,293     77.3     35,590,420     (33.5 )   2.1  
Transportation services and others   -     -     3,457,699     -     -     3,983,239           -     3,650,491     (13.2 )   9.1  
Total sales   323,076,978     -     50,223,393     338,410,414     -     71,488,512     328,299,778     -     68,603,872     (29.7 )   4.2  

 

 

(1) 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.
(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.

 

In 2020, total revenues decreased by 29.7% as compared to 2019, primarily as a result of: (i) a COP$21,330,388 million decrease in revenues mainly due to a 41.3%, or US$24.2 per barrel, decrease of our average crude oil basket price and a 29.5%, or US$20.6 per barrel decrease of our average refined products basket price, which in case in turn was primarily the result of the decrease in the international crude oil and product reference prices, (ii) a COP$4,246,388 million decrease in revenues attributable to the decrease in our sales volume (as further explained below) and (iii) a COP$723,744 decrease in revenues attributable to a decrease in the service revenue of our transportations and logistics segment, which in turn was primarily due to a decrease in transported volumes. These decreases were partially offset by a COP$5,035,401 million increase in revenues resulting from a 12.46% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$3,282.39/US$1.00 in 2019 to an average exchange rate of COP$3,691.27/US$1.00 in 2020, resulting in an increase in revenue from exports.

 

The decrease of our sales volume in 2020 as compared to 2019 was the result of a 14.6%, or 23.2 mbe, decrease in refined products volumes, which in turn was primarily due to the contraction in demand caused by the COVID-19 pandemic. This decrease was partially offset by (i) a 3.4%, or 5.2 mbpe, increase in our crude sales volume which was resulting from higher availability associated with lower throughput at our refineries and (ii) a 9.0%, or 2.6 mbe, increase in natural gas sales volume due to Hocol’s acquisition of 100% of Chevron Petroleum Company’s participation in the Guajira association contract (which corresponds to 43% of the total contract) and the entry into operation of the Cupiagua LPG plant.

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In 2019, total revenues increased by 4.2% as compared to 2018, primarily as a result of: (i) a COP$5,951,875 million increase resulting from the 11.02% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$2,956.55/US$1.00 in 2018 to an average exchange rate of COP$3,282.39/US$1.00 in 2019, resulting in an increase in sales revenue from exports, (ii) a COP$2,322,792 million revenue increase attributable to the increase in our sales volume explained below and (iii) a COP$292,590 increase in services revenue from our transportations and logistics segment, primarily due to an increase in transported volumes. This increase was partially offset by: the 7.3%, or US$4.6 per barrel, decrease of our average crude oil basket price, which in turn was primarily the result of the lower performance of the Brent crude benchmark price, and the 9.7%, or US$7.5 per barrel decrease of our average refined products basket price, which in turn was primarily the result of the lower result of the international product prices performance, mainly in gasoline, naphtha and fuel oil prices, in spite of better diesel crack due to IMO 2020.

 

The increase of our sales volume in 2019 as compared to 2018 was the result of: (i) the 2.8%, or 4.1 mbpe, increase in our crude sales volume which was primarily the result of higher crude exports to Asia and the US Gulf Coast as a result of the Company’s commercial strategy, higher production level and an increase of purchases, (ii) the 3.5%, or 5.3 mbe, increase in refined products volumes due to an increase in consumption in border areas, which in turn was primarily due to a decrease in imports of Venezuelan products, a change in the biodiesel blend, an increased demand for jet fuel by the aviation industry and an increase in exports of diesel due to better realization price in the international markets and (iii) the 2.5%, or 0.7 mbe, increase in natural gas sales volume, primarily due to the incorporation of new fields and marketing processes during 2019.

 

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 2020 was COP$37,567,472 million, representing a COP$7,404,888 million or 16.5% decrease as compared to 2019, primarily as a result of the following factors:

 

• A COP$8,857,293 million decrease in the purchase costs of crude oil, natural gas and refined products, which were purchased for sales or for refining, resulting from (i) lower average purchase prices by COP$7,178,744 million due to the decrease in international benchmark prices for crude oil and refined products and (ii) a COP$3,339,573 million decrease in volumes purchased primarily due to lower national demand for products, which in turn was due to the lockdown measures taken by the Colombian Government to control the COVID-19 pandemic, a decrease in our imports of diluent given the decrease in our crude production and a decrease in our imports of crude oil, which in turn was due to the decrease of activity of our refineries. This decrease was partially offset by a COP$1,661,024 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$545,907 million decrease in maintenance and contracted services, associated with the optimization plan performed during 2020, a renegotiation of rates and lower activity in general.

 

• A COP$30,862 million decrease in other minor items.

 

The factors mentioned above were partially offset by: (i) a COP$1,333,903 million increase in our consumption of inventories given a greater consumption of refined products and the effect of lower prices and (ii) a COP$695,271 million increase in depreciation, amortization and depletion expenses primarily due to a higher level of capital investment and the devaluation of the average exchange rate of the Colombian Peso against the U.S. dollar in subsidiaries with the US dollar as their functional currency (which was partially offset by a lower depreciation rate associated with decreased levels of production).

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Cost of sales in 2019 was COP$44,972,360 million, representing a COP$3,787,981 million or 9.2% increase as compared to 2018, primarily as a result of the following factors:

 

(i) A COP$2,197,539 million increase in the purchase costs of crude oil, natural gas and refined products, which were purchased for sales and, in the case of crude oil, for refining, which was primarily the result of (i) lower average purchase prices due to the COP$2,894,955 million decrease in international benchmark prices for crude oil, natural gas and refined products, (ii) a COP$2,702,726 million increase in volumes purchased, primarily to ensure domestic supply of diesel and new contracts of domestic crude and (iii) a COP$2,389,768 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.

 

(ii) A COP$685,059 million increase in depreciation, amortization and depletion expenses primarily due to (i) an increase in our level of capital expenditures and (ii) higher production levels associated with the results of our drilling campaign. The above mentioned was partially offset by a decrease in depreciation expenses due to higher hydrocarbon proved developed reserves in 2019 as compared to 2018.

 

(iii) A COP$626,779 million increase in maintenance, contracted services and energy, associated with increased operating activity, incremental production costs, entry into operation of new wells, greater share in fields, higher electrical power rates, among others.

 

(iv) A COP$210,764 million increase in labor costs, which is primarily the result of: (i) the recognition of employee benefits under the new collective bargaining agreement, (ii) a salary increase in 2019 and (iii) an increase in the number of employees.

 

(v) A COP$470,960 million increase in taxes and contributions, primarily due to: (i) higher taxes assumed mainly for VAT on gasoline and ACPM that went from being taxed at the general rate of 19% to 5%, thus limiting the VAT discount on goods and services purchased and (ii) greater economic rights to the ANH due to the production reactivation of the CP09 field.

 

(vi) A COP$87,063 million increase in other minor items.

 

The factors mentioned above were partially offset by a COP$490,183 million decrease in our consumption of inventories given our strategy to supply products in the country.

 

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$4,841,000 million in 2020, a COP$1,114,443 million or 29.9% increase as compared to 2019, mainly as a result of the following factors (see Notes 27 and 28) to our consolidated financial statements for more detail):

 

• A COP$806,730 million increase in labor expenses was mainly due to (i) the recognition of the voluntary retirement plan of 421 people in 2020, which despite the current increase in expenses, is expected to result in approximately COP 0.4 trillion in future cash savings, and (ii) the salary increase in 2020 as compared to 2019.

 

• A COP$283,373 million increase in general expenses mainly due to (i) the recognition of the fixed costs of some plants at the Barrancabermeja refinery that temporarily suspended their production during the Covid-19 pandemic, and (ii) expenses incurred in connection with humanitarian aid and other initiatives to strengthen the Colombian health system to address the COVID-19 pandemic.

 

  • A COP$224,239 million decrease in other income primarily due to an income recognized in 2019 associated to a favorable litigation related to the fill-up of the line in the transportation segment and compensation received in 2019 relating to certain environmental events and no similar events occurred in 2020.

 

• A COP$115,626 million increase in other operating expenses mainly by the write-off of assets that were recognized as projects in progress, due to the completion of economic feasibility studies.

 

• A COP$80,313 million increase in other minor items.

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These results were partially offset by:

 

  • A higher positive effect of COP$321,473 million from profit on acquisition of participations and interests resulting from the (i) Hocol’s acquisition in 2020 of 100% of Chevron Petroleum Company’s participation in the Guajira association contract, which generated (a) COP$1,284,372 million at Ecopetrol, a revaluation gain of the assets that Hocol already had in the Guajira association and (b) COP$86,025 million at Hocol, a gain as its acquisition of the remaining 43% stake was considered a bargain purchase, and (ii) the effect of the increase in Invercolsa’s valuation recognized in 2019 when we became their controlling shareholder which was not present in 2020.

  

• A COP$74,365 million decrease in exploratory expenses mainly as a result of lower drilling in 2020 and less seismeic reprocessing.

 

Operating expenses, which include selling, general and administrative expenses before impairment of non-current assets amounted to COP$3,726,557 million in 2019, a COP$865,888 million or 18.9% decrease as compared to 2018, mainly as a result of the following factors: (see Notes 27 and 28 to our consolidated financial statements for more detail).

 

(i) A COP$1,060,989 million increase in other income, with no cash impact, mainly from the difference between the fair value and book value of Invercolsa. As a result of the ruling issued by the Colombian Supreme Court of Justice in 2019, we increased our shareholding in Invercolsa from 43.35% to 51.88%, which in addition with another aspects represents a change in control of that entity; therefore, Invercolsa became our subsidiary rather than an affiliate, and we began to fully consolidate Invercolsa into our consolidated financial statements from November 2019. According to IFRS “Business combinations,” the acquisition of Invercolsa was recognized at fair value.

 

(ii) A COP$623,927 million decrease in exploratory expenses mainly as a result of the recognition of spending on exploratory activity at Ecopetrol America’s León 1 and 2 wells in 2018.

 

This decrease was partially offset by:

 

(i) A COP$229,330 million increase in general expenses mainly due to (i) the negative impact on our midstream segment of attacks by third parties and illegal valves, and (ii) an increase in our social investment made, especially the connection of the Middle Magdalena - Guillermo Gaviria Bridge trunk road in Barrancabermeja.

 

(ii) A COP$183,211 million increase in labor expenses associated with the benefits agreed to as part of the new collective bargaining agreement we entered into in 2018 and an increase in the number of employees.

 

(iii) A COP$192,875 million increase in depreciation and amortization mainly related to retirement cost of three fields without reserves.

 

(iv) A COP$59,460 million increase in taxes mainly in the industry and trade tax (associated with higher revenues) and tax on financial transactions (associated with higher cash disbursements throughout the year).

 

(v) A COP$154,152 million increase in other minor items.

 

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.

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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, 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. (See Notes 3.2, 4.12 and 18 to our consolidated financial statements for more detail).

 

In 2020, we recognized impairment losses of non-current assets of COP$633,156 million as compared to impairment losses of COP$1,762,437 million in 2019 and COP$368,634 million in 2018. 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 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.

 

The 2019 impairment loss, net of non-current assets of COP$1,762,437, corresponds to the net result of:

 

(i) An impairment of non-current assets in the exploration and production segment primarily due to the decrease in estimations of short-term hydrocarbon price outlook, in spite of the incorporation of new reserves and technical and operational information variables and lower discount rate.

 

(ii) An impairment of non-current assets in the transportation and logistics segment, primarily associated with the south generating unit, comprised of Puerto Tumaco and the TransAndino Pipeline (OTA), and the north generating unit, comprised of the Caño Limón – Coveñas Pipeline, which was especially affected by damages to its infrastructure attributed to attacks by third-parties.

 

(iii) A reversal of impairment of non-current assets in the refining and petrochemicals segment, primarily related to the net effect of i) a reversal of impairment of the Cartagena Refinery due to a lower discount rate associated with external market factors, ii) an impairment loss in Bioenergy primarily due to the decrease in availability of cane, partially offset by an improvement in the projection of the realization price of ethanol and a decrease in the discount rate and iii) an impairment loss associated with the modernization plan for the Barrancabermeja refinery, considering the state of the technical alternatives analysis of possible future increases in conversion.

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As mentioned above, in 2018, Ecopetrol recognized impairment losses, net of non-current assets of COP$368,634 million, which corresponds to the net result of:

 

(i) An impairment of non-current assets in the refining and petrochemicals segment, primarily due to adjustments in market expectations with respect to the impact of implementation of IMO regulations on projected margins for Reficar’s refined products, (ii) a decrease in the short-term outlook for the ethanol prices given a global over-supply of ethanol, (iii) downward updates to Bioenergy’s near-term agricultural outputs and (iv) an increase in the discount rate used for Reficar and Bioenergy, reflecting updated macroeconomic conditions. These negative impacts were partially offset by the commencement of the stabilization period at both Reficar and Bioenergy as well as tax benefits associated with Law 1942, 2018.

 

(ii) An impairment of non-current assets in the transportation and logistics segment, primarily the result of a decrease in the forecast of the volume to be transported by the southern transportation unit and an increase in investment needs to mitigate the operative risk of our transportation systems.

 

(iii) A reversal of impairment of non-current assets in the exploration and production segment primarily due to an improved short- term hydrocarbon price outlook, incorporation of new reserves and technical and operational information variables.

 

For more information regarding impairment by segment, see the 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$2,481,587 million in 2020 as compared to a loss of COP$1,670,494 million in 2019. This increase in loss was mainly due to:

 

(i) A COP$489,852 million increase in interest expenses, primarily as a result of the increase in the Ecopetrol Group’s financial debt in 2020 given that Ecopetrol S.A. entered into committed credit lines in an aggregate principal amount of US$665 million in committed credit lines and issued an SEC-registered bond in an aggregate amount of US$2,000 million and the negative effect of the devaluation of the Colombian peso against the US dollar in 2020 had on our foreign currency debt.

 

(ii) A COP$327,194 million decrease in valuation to fair value and lower yields of the securities portfolio, as a result of low market rates and a lower average cash position in 2020 as compared to 2019.

 

(iii) A COP$147,458 million decrease in financial income related to retroactive dividends and interest received by us in respect of Invercolsa’s profits in 2019, before we acquired control of this entity in November 2019.

 

(iv) A COP$152,724 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.

 

This increase was partially offset by the positive impact resulting from the strong appreciation of the Colombian Peso against the U.S. dollar in the last quarter of 2020 had on our U.S. dollar net liability position. In 2020, our exchange rate gain was COP$346,774 million, as compared to a gain of COP$40,639 million in 2019.

 

Finance results, net, amounted to a loss of COP$1,670,494 million in 2019 as compared to a loss of COP$2,010,375 million in 2018. This decrease in loss was mainly due to:

 

• A COP$504,924 million decrease in interest expenses, primarily as a result of prepayments of debt in 2018 which generated interest savings in 2019.

 

• A COP$147,458 million increase in financial income related to retroactive dividends plus interest received by us in respect of Invercolsa’s profits, which were declared during the time the legal proceeding was underway, associated with the increase in equity interest granted to us as a result of the favorable ruling.

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This decrease was partially offset by:

 

• the negative impact resulting from the 0.8% depreciation of the Colombian Peso against the U.S. dollar on our U.S. dollar net debt position. In 2019, our exchange rate gain was COP$40,639 million, as compared to a gain of COP$372,223 million in 2018.

 

• A COP$19,083 million increase in losses related to other minor financial items.

 

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

 

4.6.1.6 Income Tax

 

Income taxes amounted to and COP$2,038,661 million in 2020, COP$4,718,413 million in 2019 and COP$8,258,485 million in 2018. The above is equivalent to an effective tax rate of 42.7%, 23.9% and 40.1% in 2020, 2019 and 2018, respectively.

 

The increase in the effective tax rate from 2019 to 2020 was mainly due to: (i) the recognition of a deferred tax asset in the amount of COP$1,550,152 in 2019 as a result of the expectation to recover the historical tax losses of Ecopetrol America that were not recognized up until that time , and (ii) higher losses in the Ecopetrol Group’s companies that are taxed under a special regime. This increase was partially offset by Ecopetrol S.A.’s presumptive income in 2020 being taxed at a lower nominal rate.

 

The decrease in the effective tax rate from 2018 to 2019 was mainly due to the following: i) the agreement signed with Oxy in the U.S. Permian Basin as described elsewhere in this annual report, due to which the Company expects that sufficient future taxable income will be generated in its subsidiaries located in the United States to deduct the historical tax losses of Ecopetrol America. Under IFRS regulations, we are allowed to create a deferred tax receivable in the amount of COP$1,550,152 million, which will gradually offset against the tax charge on future taxable profits generated; ii) the accounting recognition of the market value of our increased equity interest in Invercolsa did not generate a tax charge as it did not constitute non-fiscal revenue and iii) a 4% decrease in the nominal tax rate established by the Colombian Financing Law (Ley de Financiamiento).

 

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 2020, net income attributable to owners of Ecopetrol was COP$1,586,677. In 2019, net income attributable to owners of Ecopetrol was COP$13,744,011, whereas in 2018 net income attributable to owners of Ecopetrol was COP$11,381,386 million.

 

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 and Transportation and Logistics. See the section Business Overview for a description of each segment.

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The following tables present our revenues and net income by business segment for the years ended December 31, 2020, 2019 and 2018:

 

Table 54 – Revenues by Business Segment

 

    For the year ended December 31,     % Change  
    2020     2019     2018     2020/2019     2019/2018  
    (COP$ Million)  
Exploration and Production     36,839,997       52,667,990       50,372,764       (30.1 )     4.6  
Third parties     22,854,925       31,295,118       30,112,900       (27.0 )     3.9  
Local crude oil     230,520       356,857       550,479       (35.4 )     (35.2 )
Foreign crude oil     19,498,553       28,461,601       26,898,737       (31.5 )     5.8  
Local natural gas     2,845,155       2,256,123       1,885,846       26.1       19.6  
Foreign natural gas     17,231       27,255       27,899       (36.8 )     (2.3 )
Other income     263,466       193,282       749,939       36.3       (74.2 )
Inter-segment net operating revenues     13,985,072       21,372,872       20,259,864       (34.6 )     5.5  
Refining and Petrochemicals     26,104,351       38,770,806       37,011,373       (32.7 )     4.8  
Third parties     24,804,887       36,393,470       34,947,948       (31.8 )     4.1  
Local refined products     17,745,376       27,170,498       26,354,549       (34.7 )     3.1  
Foreign refined products     6,165,364       8,977,662       8,485,932       (31.3 )     5.8  
Foreign crude oil     29       61,995       -       (100.0 )     100.0  
Other income(1)     894,118       183,315       107,467       387.7       70.6  
Inter-segment net operating revenues     1,299,464       2,377,336       2,063,425       (45.3 )     15.2  
Transportation and Logistics     12,194,440       13,070,736       11,354,167       (6.7 )     15.1  
Third parties     2,563,581       3,799,924       3,543,024       (32.5 )     7.3  
Inter-segment net operating revenues     9,630,859       9,270,812       7,811,143       3.9       18.7  
Eliminations of consolidations     (24,915,395 )     (33,021,020 )     (30,134,432 )     (24.5 )     9.6  
Total revenues     50,223,393       71,488,512       68,603,872       (29.7 )     4.2  

 

(1) 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.

 

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

 

Table 55 – Operating and Net Income by Business Segment

 

    For the year ended December 31,     % Change  
    2020     2019     2018     2020/2019     2019/2018  
    (COP$ Million)  
Exploration and Production                                        
Operating Income     1,149,291       11,601,485       15,899,337       (90.0 )     (27.0 )
Net income attributable to owners     (139,279 )     9,382,129       9,930,519       (101.0 )     (6.0 )
Refining and Petrochemicals                                        
Operating Income     (2,185,511 )     1,142,204       (757,793 )     (291.0 )     (251.0 )
Net income attributable to owners     (2,848,511 )     117,708       (1,973,075 )     (2,520.0 )     (106.0 )
Transportation and Logistics                                        
Operating Income     8,218,724       8,366,747       7,317,513       (2.0 )     14.0  
Net income attributable to owners     4,574,800       4,244,860       3,424,234       8.0       24.0  
Eliminations in consolidation                                        
Operating Income     (739 )     (83,278 )     (643 )     (99.0 )     12,851.0  
Net income attributable to owners     (333 )     (686 )     (292 )     (51.0 )     135.0  
Ecopetrol consolidated                                        
Operating Income     7,181,765       21,027,158       22,458,414       (66.0 )     (6.0 )
Net income attributable to owners     1,586,677       13,744,011       11,381,386       (88.0 )     21.0  

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4.6.1.9 Exploration and Production Segment Results

 

In 2020, exploration and production segment sales were COP$36,839,997 million, compared to COP$52,667,990 million in 2019. In 2020, our segment sales decreased by 30.1% as compared with 2019 mainly as a result of:

 

(i) The 27.0% decrease in sales of crude oil to third parties in 2020 as compared to 2019 primarily due to: (i) a decrease in the price of our crude oil basket of US$21.0 per barrel, (ii) an increased spread in our crude oil basket versus the Brent price, (iii) lower production levels, primarily due to lower demand as a result of the mobility restrictions and lockdown that were imposed throughout the year because of the COVID-19 pandemic and impacts due to public order issues. This decrease was partially offset by (i) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in revenue recorded in U.S. dollars, (ii) an increase in crude oil sales of 5.2 mmbls, which in turn was primarily related to an increase in availability associated with lower throughput at our refineries, (iii) an increase in natural gas sales of 2.6 mmbls, which in turn was primarily due to Hocol’s acquisition of 100% of Chevron Petroleum Company’s participation in the Guajira association contract (which corresponds to 43% of the total contract), positive results of our United States Permian operations, the reversion of the Pauto and Floreña fields from Equión to Ecopetrol and the start-up of the Cupiagua LPG Plant.

 

(ii) The 34.6% decrease in inter-segment revenues in 2020 as compared to 2019 mainly due to: (i) the decrease in the price of our crude oil basket and a worsening spread as compared to the Brent price and (ii) lower refineries throughputs due to the global contraction in demand as a result of the COVID-19 pandemic. This decrease was partially offset by the impact of the depreciation of the Colombian Peso against the U.S dollar.

 

In 2019, exploration and production segment sales were COP$52,667,990 million, compared to COP$50,372,764 million in 2018. In 2019, our segment sales increased by 4.6% as compared with 2018 mainly as a result of:

 

(i) Increased sales of crude oil to third parties, which increased by 3.9% in 2019 as compared to 2018 primarily due to: (i) an increase in local and exports sales of crude oil (4.1 mmbls) mainly due to higher crude exports to Asia and the US Gulf Coast as a result of the Company’s commercial strategy, a higher production level and an increase of purchases to third parties, (ii) an increase in sales of natural gas (0.7 mmbls) due to greater demand, (iii) an increased spread in our crude oil basket versus the Brent price and (iii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars. This increase was partially offset by the decrease in the price of our crude oil basket of US$4.6 per barrel.

 

(ii) Increased inter-segment revenues, which increased by 5.5% in 2019 as compared to 2018 mainly due to: i) higher production volumes as a result of drilling campaigns and purchases to third parties, emphasized deliveries of crude oil in order to supply Reficar and Barrancabermeja in order to replace imported crudes and (ii) the depreciation of the Colombian Peso against the U.S dollar. This increase was partially offset by the decrease in the price of our crude oil basket in spite of better spreads as compared to the Brent price.

 

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.

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In 2020, the cost of sales for this segment decreased by 9.5% as compared with 2019 due to the net effect of:

 

(i) Fixed costs decreasing by 1.1%, or COP$108,644 million, in 2020 as compared to 2019 mainly due to the optimization plan adopted by the Ecopetrol Group which was reflected in fewer contracted services, lower process materials usage and lower general costs. This decrease was partially offset by higher fixed transportation costs, primarily due to the depreciation of Colombian Peso against U.S dollar.

 

(ii) Variable costs decreasing by 12.5%, or COP$ 3,356,802 million in 2020 as compared to 2019, as a result of (i) the decrease in the price of our crude oil basket resulting in a lower cost of oil, (ii) a decrease in volume of naphtha purchased for dilution as a consequence of lower production of heavy oil and (iii) non-execution of reversal cycles in the Bicentenario pipeline and lower transported volume. The latter was partially offset by (i) an increase in crude oil volume purchases due to a strategy that enabled further optimization of the supply chain, (ii) the decrease in the price of our crude oil basket that impacted the inventory valuation and (iii) higher energy purchases given operative issues in our self-generating plants.

 

In 2019, the cost of sales for this segment increased by 12.8% as compared with 2018, due to the net effect of:

 

(i) Fixed costs increasing by 8.1%, or COP$716,252 million, in 2019 as compared to 2018, mainly due to: (i) an increase in planned maintenance, higher tariffs and the depreciation of the Colombian Peso against the U.S dollar and (ii) higher labor costs due the recognition of salary increases and benefits for employees under our new collective bargaining agreement along with an increase in the number of employees.

 

(ii) Variable costs increasing by 14.6%, or COP$3,418,429 million, in 2019 as compared to 2018, as a result of (i) an increase of purchases of crude oil due to the strategy, which enables further optimization of the supply chain, (ii) higher transportation costs due to the use of alternative oil pipelines to transport crude oil given attacks against the Caño Limón - Coveñas pipeline and an increase in tariffs, (iii) an increase in natural gas royalties due to higher production, (iv) an increase in depreciation and amortization mainly due to increased investment levels which in turn were primarily due to positive results from the drilling campaign and the improvement in the asset recovery factor and (v) an increase in electricity cost related to higher tariffs.

 

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 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.

 

In 2019, operating expenses before impairment of non-current assets decreased by 10.3% as compared to 2018 primarily as a net result of: (i) a decrease in exploratory expenses mainly as a result of the recognition of spending on exploratory activity at Ecopetrol America’s León 1 and 2 wells in 2018, (ii) an increase in depreciation and amortization related to retirement costs of three fields without reserves, (iii) an increase in social investments made by the Company, (iv) higher taxes mainly the industry and trade tax due to a sales increase and (v) an increase in the level of seismic acquisition compared to 2018, with the COL5 and Saturn programs in Brazil.

 

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.

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There was an impairment of non-current assets recognized in the exploration and production segment in 2019, totaling COP$1,982,044 billion in 2019 as compared to the net reversal of COP$785,940 million in 2018. The impairment loss in this segment in 2019 was mainly due to (i) a decrease in the price projection of our crude oil and ii) an increase in net book value as a result of higher asset short-term retirement obligations.

 

Because of all the above, the segment recorded a net loss attributable to owners of Ecopetrol of COP$139,279 million in 2020 as compared to net income attributable to owners of Ecopetrol of COP$9,382,129 million in 2019 and net income attributable to owners of Ecopetrol of COP$9,930,519 million in 2018.

 

Lifting and Production Costs

 

The aggregate average production cost, on a Colombian Peso basis, decreased to COP$ 28,634 per boe during 2020 from COP$ 29,275 per boe during 2019. This decrease was primarily due to:

 

(i) A decrease in activity, mainly in subsoil and surface maintenance, primarily due to the restrictions driven by the COVID-19 pandemic.

 

(ii) A decrease in costs related to support services in line with the decrease in our operating activity and a decrease in supplies used in the production process.

 

(iii) An increase in the cost of energy, primarily due to the use of more costly thermal generation and an increase in our purchases from the national interconnected system; partially offset by our new energy self-generation strategies, which led to a reduction in diesel, fuel oil and residual distillate energy costs.

 

(iv) A decrease in costs related to optimizations in maintenance contracts and others, which allowed us to have better rates and discounts in operation contracts.

 

On a dollar basis, the aggregate average production cost decreased to US$ 7.75 per boe in 2020 from US$8.92 per boe in 2019 primarily due to a 12.46% depreciation of the Colombian Peso against the U.S. dollar in 2020.

 

The aggregate average lifting cost, on a Colombian Peso basis, decreased to COP$ 27,555 per boe during 2020 from COP$28,100 per boe during 2019, primarily due to:

 

(i) A decrease in activity, mainly in subsoil and surface maintenance, primarily due to the restrictions driven by the COVID-19 pandemic.

 

(ii) A decrease in costs related to support services in line with the decrease in our operating activity and a decrease in supplies used in the production process.

 

(iii) An increase in the cost of energy, primarily due to the use of more costly thermal generation and an increase in our purchases from the national interconnected system; partially offset by our new energy self-generation strategies, which led to a reduction in diesel, fuel oil and residual distillate energy costs.

 

(iv) A decrease in costs related to optimizations in maintenance contracts and others, which allowed us to have better rates and discounts in operation contracts.

 

(v) A decrease in property production volumes compared to 2019 of 6.7 mbed per day.

 

On a dollar basis, the aggregate average lifting cost decreased to US$ 7.46 per boe in 2020 from US$8.56 per boe in 2019 due to a 12.46% depreciation of the Colombian Peso against the U.S. dollar in 2020.

 

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, 2020, 2019 and 2018.

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Table 56 – Crude Oil and Natural Gas Average Prices and Costs

 

    2020     2019     2018  
Crude Oil Average Sales Price (US$ per barrel)(1)     34.4       58.6       63.2  
Crude Oil Average Sales Price (COP$ per barrel)(1)     126,962       192,262       187,845  
Natural Gas Average Sales Price (US$ per barrel equivalent)     4.3       4.2       3.9  
Natural Gas Average Sales Price (COP$ per barrel equivalent)(2)     15,719       13,670       11,741  
Aggregate Average Unit Production Costs (US$ per boe)(3)     7.75       8.92       9.40  
Aggregate Average Unit Production Cost (COP$ per boe)(3)     28,634       29,275       27,782  
Aggregate Average Lifting Costs (US$ per boe)(4)(5)(6)     7.46       8.56       8.66  
Aggregate Average Lifting Costs (COP$ per boe)(4)(5)(6)     27,555       28,100       25,614  

 

 

(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 2020, our transportation and logistics segment sales were COP$12,194,440 million compared to COP$13,070,736 million in 2019. The 6.7% decrease in 2020 as compared with 2019 was mainly due to: (i) lower volumes of crude oil transported through our pipelines which was primarily due to a decrease of oil production at the national level, including production by third parties, (ii) a decrease in the volumes of refined products transported mainly due to lower demand as a result of the mobility restrictions and quarantines that were imposed throughout the year in order to combat the of the COVID-19 pandemic, (iii) the impact of IFRS 15 in revenue recognition from contracts with customers given that during 2020 the revenue associated with our ship or pay contracts in the Bicentenario and Caño Limón- Coveñas pipelines were not recognized due to the ongoing legal process we were under with some of their shippers (See Note 23.3 to our consolidated financial statements for more details) and (iv) a decrease in our sales of services due to zero reversal cycles through the Bicentenario pipeline during the year as result of a stable operation of the Caño Limón - Coveñas pipeline throughout 2020. This decrease was partially offset by the positive effect on our U.S. dollar-indexed transportation fees resulting from the depreciation of the Colombian peso against the U.S. dollar, previously mentioned.

 

In 2019, our transportation and logistics segment sales were COP$13,070,736 million compared to COP$11,354,167 million in 2018. The 15.1% increase in 2019 as compared with 2018 was mainly due to: (i) higher volumes of crude oil transported through our pipelines which was primarily due to an increase of oil production at the national level, including production by third parties, (ii) reversal cycles through the Bicentenario pipeline, (iii) commercial strategies implemented for industrial services such as oil dilution, unloading facilities at the Monterrey facility that enabled the transport of oil previously transported outside of our infrastructure and oil injection at Ayacucho, (iv) an increase in the volume of refined products transported mainly due to growth of the border zone demand and higher volumes in the Cartagena - Baranoa pipeline and, (v) the positive effect on our U.S. dollar-indexed transportation fees resulting from the depreciation of the Colombian peso against the U.S. dollar.

 

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.

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The cost of sales amounted to COP$3,381,357 in 2020 as compared to COP$3,738,194 million in 2019. The cost of sales for this segment decreased by 9.5% in 2020 as compared with 2019 mainly due to (i) a decrease in costs associated with lower transported volumes, (ii) lower fixed costs mainly as a result of contract renegotiations, (iii) a decrease in depreciation as a result of an adjustment in the useful life of some of our transportations systems, and (iv) a decrease in costs related to the rescheduling of maintenance activities throughout the year, which in turn was primarily due to the effects of the COVID-19 pandemic.

 

The cost of sales amounted to COP$3,738,194 million in 2019 as compared to COP$3,402,087 million in 2018. The cost of sales for this segment increased by 9.9% in 2019 as compared with 2018 mainly due to (i) an increase in costs associated with higher transported volumes, (ii) an increased consumption of materials, supplies and depreciation resulting from an adjustment in the useful life of some of our transportations systems, and (iii) higher electricity market prices.

 

In 2020, operating expenses before the impairment of non-current assets increased by 27.6% as compared to 2019 due to: (i) an increase in labor expenses given that certain of the segment’s employees chose to take the voluntary retirement plan we offered in 2020 and (ii) an extraordinary income recognized in 2019 associated to a favorable litigation related to Ocensa’s line filled and no similar income in 2020. This increase was partially offset by a decrease in the expenses associated to the remediation of the damages caused by terrorist attacks and illicit taps into our transportation infrastructure.

 

In 2019, operating expenses before the impairment of non-current assets increased by 57.8% as compared to 2018 due to the expenses associated to the remediation of the damages caused by terrorist attacks and illicit taps in our transportation infrastructure. This increase was partially offset by the favorable ruling in the arbitration claim regarding Ocensa’s line filled with Equión and Santiago.

 

The reversal of impairment of non-current assets recognized in the segment in 2020, totaled COP$341,065 million as compared to impairment losses of non-current assets of COP$232,556 million in 2019. This reversal in the impairment of this segment was primarily by 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 Banadia- Ayacucho pipeline, part of the Caño Limon- Coveñas system.

 

The impairment losses of non-current assets recognized in the segment in 2019, totaled COP$232,556 million in 2019 as compared to impairment losses of non-current assets of COP$169,870 million in 2018. The increase in the impairment loss of this segment was primarily the result of a decrease in the forecast of the volume to be transported by the southern cash generating unit, Transandino pipeline and the impact of the terrorist attacks that took place in the Banadia- Ayacucho portion of the Caño Limon- Coveñas pipeline.

 

The segment recorded net income attributable to owners of Ecopetrol of COP$4,574,800 million in 2020 as compared to net income of COP$4,244,860 million in 2019 and COP$3,424,234 million in 2018.

 

4.6.1.11 Refining and Petrochemicals Segment Results

 

In 2020, the refining and petrochemical segment sales were COP$26,104,351 million compared to COP$38,770,806 million in 2019. In 2020, sales of refined products and petrochemicals decreased by 32.7% as compared with 2019, mainly due to (i) a decrease of our volumes of gasoline and diesel sales due to a drastic worldwide drop in demand as a result of the COVID-19 pandemic and (ii) lower prices of the product basket given external market factors. This decrease was partially offset by: (i) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars, (ii) higher volumes of polypropylene produced by Esenttia and the strengthening of its international margins and (iii) the consolidation of Invercolsa into our consolidated results of operations as form November 2019.

 

In 2019, the refining and petrochemical segment sales were COP$38,770,806 million compared to COP$37,011,373 million in 2018. In 2019, sales of refined products and petrochemicals increased by 4.6% as compared with 2018, mainly due to (i) an increase of our diesel exports due to their improved economic performance in the international market and (ii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars. This increase was partially offset by lower prices of our refined product basket and the weakening of international fuel prices.

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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$25,825,555 million in 2020, compared to COP$37,856,219 million in 2019 and COP$35,658,753 million in 2018.

 

In 2020, the cost of sales for this segment decreased 31.8% as compared with 2019, principally due to (i) decreased in volume purchases of crude oil for use by our refineries primarily due to lower throughput, which in turn was caused by the COVID-19 pandemic (ii) lower average purchase prices, (iii) a decrease in diesel imports associated with the lower demand caused by COVID-19 national lockdowns and (iii) the inclusion of a higher percentage of domestic crude in the Cartagena refinery, which resulted in a more cost-effective crude slate.

 

In 2019, the cost of sales for this segment increased 6.2% as compared with 2018, principally due to (i) increased purchases of crude oil for use by our Cartagena refinery primarily due to higher throughput and higher feedstock costs due to the appreciation of our crude as compared to Brent, (ii) an increase in diesel imports associated with first quarter operational events in the Barrancabermeja refinery as well as increased purchases of products to reduce the sulphur content of fuels for the local market. 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 2020, operating expenses before the impairment of non-current assets increased by 649% as compared to 2019, mainly due to: (i) an increase in income as a result of our recognition of the Invercolsa’s valuation in 2019 once we became their controlling shareholder and no similar recognition in 2020, (ii) recognition of the fixed cost of plants temporarily halted at the Barrancabermeja refinery given the COVID-19 pandemic and decrease in product demand, (iii) the consolidation of Invercolsa during the entire year of 2020 versus two months in 2019 and (iv) higher labor expenses due certain of the segment’s employees choosing to accept the voluntary retirement plan in Ecopetrol, previously mentioned.

 

In 2019, operating expenses before the impairment of non-current assets decreased by 80.1% as compared to 2018, mainly due to the gain of COP$1,048,924 recognized when we obtained control of Invercolsa in November 2019.

 

In 2020, we recognized an impairment loss of non-current assets in this segment totaling COP$781,528 million, as compared to a reversal of impairment of COP$452,163 million in 2019. The impairment loss we observed in 2020 is primarily the result of (i) an impairment loss of COP $440,525 million attributable to the Cartagena refinery, which in turn was mainly due to lower refining margins; and (ii) an impairment loss of COP $341,000 million attributable to the Barrancabermeja Refinery Modernization Plan, taking into account progress in the technical analysis of the project.

 

In 2019, we recognized a reversal of impairment of non-current assets in this segment totaling COP$452,163 million, as compared to impairment losses of COP$984,704 million in 2018. The reversal we observed in 2019 is primarily the result of net effect between i) a reversal of impairment of the Cartagena Refinery was mainly due to a lower discount rate associated with external market factors, ii) an impairment loss in Bioenergy which was generated primarily due to the decrease in availability of sugar cane, partially offset by an improvement in the projection of the realization price of ethanol and a decrease in the discount rate, and iii) an impairment loss associated with the modernization plan for the Barrancabermeja refinery, considering the state of the technical alternatives analysis of possible future increases in conversion.

 

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.

 

The refining and petrochemicals segment recorded net loss attributable to owners of Ecopetrol of COP$2,848,511 million in in 2020 compared to a net income of COP$117,708 million in 2019 and a net loss of COP$1,973,075 million in 2018.

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4.7 Liquidity and Capital Resources

 

Our principal sources of liquidity in 2020 were: (i) cash flows from our operations amounting to COP$9,186,704 million, (ii) cash flow from financing activities, mainly from the proceeds from new issuances of debt instruments, net of related payments of principal and interest, which totaled COP$6,455,835 million and (iii) cash flows from net sales of securities investment portfolio amounting to COP$2,107,856 million.

 

Our main uses of cash in 2020 were: (i) COP$11,116,861 million in capital expenditures, which included investments in property, plant and equipment, natural and environmental resources and intangibles, (ii) dividend payments amounting to COP$8,734,351 million, which included dividends of COP$7,369,499 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to the non-controlling shareholders of our subsidiaries totaling COP$1,364,852 million, and (iii) COP$350,539 million in lease payments. For more information regarding our debt, see the section Financial Review—Financial Indebtedness and Other Contractual Obligations.

 

4.7.1 Review of Cash Flows

 

Cash from operating activities

 

Net cash provided by operating activities decreased by 66.8% in 2020 as compared to 2019, mainly as a result of:

 

  i) A 45.4% decrease in our operating income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to (i) lower sales volumes associated with the decrease in demand and weighted average sale prices which in turn primarily reflects the effects of the COVID-19 pandemic as previously discussed, and (ii) expenses in 2020, such as the voluntary retirement plan we offered certain of our employees and aid granted to support Colombian Government efforts to mitigate the health and other social impacts of the COVID-19 pandemic. This decrease was partially offset by (i) lower operational costs given the decrease in our activity levels generally, (ii) new businesses integrated into the Ecopetrol Group’s consolidated results, such as Invercolsa and Permian, and our increased participation in the Guajira association contract and iii) good results of our performance of subsidiaries that are not sensitive to the Brent price, such as Esenttia and Cenit.

  

ii) Higher working capital expenditures needs mainly due to the decrease in operating activity generated by the COVID-19 pandemic, which derived into lower accounts payable with suppliers and an increase in tax assets give that income tax advances did not offset charged taxes as Ecopetrol S.A. will be taxed at the presumptive income tax rate given its decreased income results for 2020. The factor mentioned was partially offset by a decrease in accounts receivable and inventories, which in turn was due to the decrease in sales.

 

Net cash provided by operating activities increased by 23.3% in 2019 as compared to 2018, mainly as a result of:

 

i) A 2.8% increase in our operating income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to i) higher levels of hydrocarbon production, ii) a record refining throughput of 374 mbd, similar to that of 2018, despite major scheduled maintenance for our units, iii) a solid performance of the midstream segment, which guaranteed operational continuity despite third-party damages to its infrastructure, iv) a successful commercial management that enabled us to materialize better oil spreads vs the Brent price and v) a favorable COP peso/U.S. dollar devaluation environment. This increase was partially offset by lower international crude and product prices.

 

ii) Lower working capital expenditures needs mainly due to a decrease in accounts receivable from the FEPC and a lower payment in advance of the capital gains tax.

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Cash used in investing activities

 

In 2020, net cash used in investing activities decreased by 15.0% as compared to 2019, mainly as a result of (i) a 20.5% decrease in investments in capital expenditures, mainly due to the work restrictions implemented to contain the cases of contagion of COVID-19 (under the concept of operational vital minimum), that was reflected in temporary closure of some wells and negatively affected our production. All the above primarily affected our capital expenditures in the Rubiales, Caño Sur, Casabe, Sur and Recetor assets as well as the Cartagena refinery, (ii) blockages by the communities in the Rubiales, Apiay and Tibu fields, and (iii) a decrease in our securities investment levels in order to conserve liquidity given the lower generation of cash from the operations.

 

In 2019, net cash used in investing activities increased by 15.1% as compared to 2018, mainly as a result of (i) a 65.2% increase in investments in capital expenditures, mainly due to a drilling campaign which was concentrated in the Castilla, Rubiales, Chichimene, Suria, Casabe, Yariguí-Cantagallo and La Cira-Infantas fields and inorganic investment from international agreements such as the strategic alliance with OXY in the US Permian basin. This increase was partially offset by a decrease in our investment portfolio to support our capital expenditures and dividends received from affiliates.

 

Cash used in financing activities

 

Net cash used in financing activities decreased by 84.7% in 2020, as compared to 2019, due to (i) an increase in cash from borrowings, net of related payments of principal and interest, of COP$6,455,835 million as compared to a decrease of COP$3,002,977 million in 2019, which in turn primarily reflects Ecopetrol S.A. entering into committed credit lines in an aggregate principal amount of US$665 million and issuing an SEC-registered bond in an aggregate amount of US$2,000 million in 2020, (ii) a COP$5,132,678 decrease in dividend payments in 2020 as compared to 2019.

 

Net cash used in financing activities increased by 8.7% in 2019, as compared to 2018, due to (i) an increase in dividend payments to the shareholders of Ecopetrol (COP$12,910,611 million) and in dividend payments made by certain of our subsidiaries to their non-controlling shareholders (COP$956,418 million), (ii) payments of local and foreign currency-denominated loans totaling COP$3,002,977 million and (iii) COP$300,326 million in lease payments.

 

4.7.2 Capital Expenditures

 

Our consolidated capital expenditures in 2020, 2019 and 2018 were COP$11,116,861 million, COP$13,979,141 million and COP$8,460,426 million, respectively. These investments were distributed by business segment on average, for the past three years as follows: 83.5% for the exploration and production segment, 8.1% for refining and petrochemicals and 8.4% for the transportation and logistics segment. See Note 33.3 to our consolidated financial statements for more detail about capital expenditures by segment.

 

Our investment plan approved for 2021 is a range of between US$3,500 million and US$4,000 million. See the section entitled Strategy and Market Overview—2021 Investment Plan for further information and implicit Brent prices.

 

The resources required for the investment plan can be funded through internal cash generation and cash surpluses existing at the beginning of the year.

 

4.7.3 Dividends

 

On March 26, 2021, our shareholders at the ordinary General Shareholders Assembly approved a distribution of ordinary dividends 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 will be April 22, 2021 for 100% of shareholders.

 

In 2020, we paid dividends of COP$7,369,499 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$1,364,852 million.

 

In 2019, we paid dividends of COP$12,910,611 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$956,418 million.

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In 2018, we paid dividends of COP$3,659,373 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$768,328 million.

 

4.8 Summary of Differences between Internal Reporting (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, 2020, 2019 and 2018, in accordance with Colombian IFRS and IFRS:

 

Table 57 – Consolidated Net Income and Equity

 

    For the year ended December 31,     % Change  
    2020     2019     2018     2020/2019     2019/2018  
    (COP$ Million)  
Net income attributable to owners of Ecopetrol (IFRS)     1,586,677       13,744,011       11,381,386       (88.5 )     20.8  
Cash flow hedge for future company exports     (122,375 )     (419,275 )     (471,314 )     (70.8 )     (11.0 )
Exchange rate effects on tax bases – Deferred tax     223,775       (73,253 )     646,333       (405.5 )     (111.3 )
Net income Attributable to owners of Ecopetrol (Colombian IFRS)     1,688,077       13,251,483       11,556,405       (87.3 )     14.7  
Net Equity (IFRS)     53,499,363       58,231,628       57,107,780       (8.1 )     2.0  
Cash flow hedge for future company exports     -       (10,099 )     (20,792 )     (100.0 )     (51.4 )
Exchange rate effects on tax bases – Deferred tax     2,319,907       2,122,593       2,217,450       (9.3 )     (4.3 )
Net Equity (Colombian IFRS)     55,819,270       60,344,122       59,304,438       (7.5 )     1.8  

 

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 Ecopetrol’s foreign currency debt, Ecopetrol’s Board of Directors approved a cash flow hedge for future crude oil exports. According to IAS 39 – Financial Instruments, Ecopetrol implemented this hedge beginning on October 1, 2015, the date on which it 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, Ecopetrol applied cash flow hedge accounting from January 1, 2015 in its financial statements under Colombian IFRS.

 

As a result of this accounting policy difference, for the year ended December 31, 2020, our net income as reported under IFRS was COP$122,375 million higher than our net income as reported under Colombian IFRS.

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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.

 

Ecopetrol’s 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, 2020, our net income attributable to owners of Ecopetrol as reported under IFRS was COP$223,775 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$12,435 million in 2020, COP$14,865 million in 2019 and COP$22,030 million in 2018 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$12,091 million in 2020, COP$12,630 million in 2019 and COP$11,316 million in 2018 in connection with our associates and joint ventures whose functional currency is the U.S. dollar.

 

As a result of these accounting policy differences described above, 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. For the year ended December 31, 2019, we reported net income attributable to the owners of Ecopetrol under IFRS of COP$13,744,011 million as opposed to a net income attributable to the owners of Ecopetrol of COP$13,251,483 million reported under Colombian IFRS for the same period. For the year ended December 31, 2018, these same accounting differences led us to report net income attributable to the owners of Ecopetrol under IFRS of COP$11,381,386 million as opposed to a net income attributable to the owners of Ecopetrol of COP$11,556,405 million reported under Colombian IFRS for the same period.

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4.9 Financial Indebtedness and Other Contractual Obligations

 

As of December 31, 2020, we had outstanding consolidated indebtedness of COP$44.5 trillion, which corresponded primarily to the following long-term transactions:

 

Table 58 – Consolidated Financial Indebtedness

 

Company   Type   Initial Date   Original Amount   Maturity     Interest Rate     Amortization  
Ecopetrol S.A.   Bonds   September 18, 2013   US$ 1,300 million     September 18, 2023       5.875 %     Bullet  
        September 18, 2013   US$ 850 million     September 18, 2043       7.375 %     Bullet  
        May 28, 2014   US$ 2,000 million     May 28, 2045       5.875 %     Bullet  
        September 16, 2014   US$ 1,200 million     January 16, 2025       4.125 %     Bullet  
        June 26, 2015   US$ 1,500 million     June 26, 2026       5.357 %     Bullet  
        June 15, 2016*   US$ 500 million     September 18, 2023       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  
        April 29, 2020   US$ 2,000 million     April 29, 2030       6.875 %     Bullet  
    Bank Loans   December 30, 2011**   US$ 440 million     December 20, 2025       Floating       Semi-annual  
        April 15, 2020   US$ 665 million     September 20, 2023       Floating       Semi-annual  
    ECAs   December 30, 2011**   US$ 2,650 million     December 20, 2027       Fixed       Semi-annual  
        December 30, 2011**   US$ 100 million     December 20, 2027       Floating       Semi-annual  
        December 30, 2011**   US$ 97 million     December 20, 2027       Fixed       Semi-annual  
        December 30, 2011**   US$ 210 million     December 20, 2027       Floating       Semi-annual  
Invercolsa & Subsidiaries   Bank Loans   Various   US$ 377,202 million     Various       Fixed       Fixed  
    Leases   Various   US$ 4,471 million     Various       Floating       Various  
Ocensa   Bond   July 14, 2020   US$ 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 billion     November 4, 2032       Floating       Monthly  

 

 

* Reopening of bond due to 2023.
** Debt originally obtained by Reficar 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 on such bank loan. It was listed as US$321 million and the correct amount as listed in the table above is US$440 million.

 

The Colombian Superintendence of Finance, through Resolution 1379 of October 10, 2019, authorized the renewal of the term of the Issuance and Placement Program of Internal Debt Bonds and Commercial Papers of the Company for three (3) additional years, until October 10, 2022.

 

Further, the Ministry of Finance and Public Credit of Colombia, through Resolution 0600 of February 18, 2020, authorized the Company to structure the issuance and placement of bonds in the international capital markets for up to two billion US dollars (US$2,000,000,000).

 

These authorizations themselves do not constitute an approval for the issuance of securities or any financing transaction.

 

The short and long term debt transactions executed in 2020 were as follows:

 

• Between March and April 2020, Ecopetrol 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 US$ 221.5 million, respectively (totalling COP$ 1.7 trillion according to the COP$/US$ exchange rate as of the day of execution of each transaction). All loans were prepaid on September 2020.
• On April 15, 2020, Bank of Nova Scotia and Mizuho Bank disbursed an aggregate amount of US$ 665 million (COP$ 2.3 trillion according to the COP$/US$ exchange rate as of December 31, 2020) under a committed credit facility due on September 2023.
• On April 24, 2020, Ecopetrol S.A issued 6.875% Notes due 2030 in an aggregate amount of US$ 2 billion (COP$ 6.9 trillion according to the COP$/US$ 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 US$ 500 million (COP$ 1.7 trillion according to the COP$/US$ exchange rate as of December 31, 2020) in an SEC-registered transaction. 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.

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Ecopetrol did not incur any short-term or long-term bank loans or bonds in 2019.

 

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, 2020.

 

Table 59 – Our Contractual Obligations

 

    Payments due by period  
COP$ Millions   Total     Less than
1 year 		    1 to 3
years 		    3 to 5
years 		    More than
5 years 		 
Employee Benefit Plan     33,222,962       1,450,763       3,017,049       3,130,406       25,624,744  
Contract Service Obligations     16,030,925       5,155,544       3,024,772       4,057,953       3,792,655  
Operating Lease Obligations     211,661       155,862       37,506       14,550       3,742  
Natural Gas Supply Agreements     12,157,544       5,027,100       3,429,898       2,678,858       1,021,688  
Purchase Obligations     2,663,077       843,285       576,356       660,593       582,843  
Energy Supply Agreements     1,496,929       4,598       90,733       233,353       1,168,245  
Capital Expenditures     13,573,859       3,806,896       5,566,521       2,178,127       2,022,316  
Build, Operate, Maintain and Transfer Contracts (BOMT)     469,712       81,101       139,646       107,041       141,925  
Capital (Finance) Lease Obligations     308,125       34,891       63,571       59,798       149,865  
Financial Sector Debt     9,499,662       1,324,669       5,133,819       2,339,691       701,483  
Bonds     34,635,738       -       6,379,460       4,080,000       24,176,278  
Total     124,270,194       17,884,709       27,459,331       19,540,370       59,385,784  

 

 

Note: For the presentation of the contractual obligations in this annual report, contractual obligations beyond the current year represent the expected amount to be committed by us according to our framework contracts. Previously, we were reporting our obligations beyond the current year based on individual orders instead of framework contracts. The implementation of this methodology has resulted in a material increase of our commitments from what was previously reported.

 

4.10 Off Balance Sheet Arrangements

 

As of December 31, 2020, we did not have off-balance sheet arrangements of the type that is required to be disclosed under Item 5.E of Form 20-F.

 

4.11 Trend Analysis and Sensitivity Analysis

 

Ecopetrol updated its Business Plan on February 23, 2021. See the section entitled Strategy and Market Overview—Our Corporate Strategy—2021 – 2023 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, 2020, considering ICE Brent crude oil prices that reasonably reflect management’s view of crude oil prices given prevailing market conditions, and management portfolio costs.

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Table 60 – Sensitivity Analysis of Reserves

 

COP$ Millions   Oil and
NGL (mmb) 		    Natural Gas
(bcf) 		    Total Oil
and Gas
(mmboe) 		 
Reserves as of December 31, 2020     1,068.0       2,466.0       1,501.0  
Sensitivity Scenario     1,167.0       2,509.0       1,607.0  
Difference (mmb)     99.0       43.0       106.0  
Difference (%)     0.09       0.02       0.07  

 

 

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 US$ 46 per barrel in 2021, between US$ 55 and US$ 58 per barrel in the period 2022-2025, and between US$61 and US$68 onwards, and costs of management portfolio.

 

The base scenario on which our sensitivity analysis is made corresponds to 85% of our oil, NGL and natural gas reserves, as of December 31, 2020, 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.

 

Sensitivity Analysis of our Results

 

The following table provides information about the sensitivity of our results as of December 31, 2020, due to variations of US$1 in the price of ICE Brent crude and of 1% in the COP$/US$ exchange rate.

 

Table 61 – Sensitivity Analysis of our Results

 

COP$ Million   Income
Statement
2020 		    Income
Statement
Case ICE
Brent(1)  
+US$1 		    Difference
Between
Real 2020
and Case
ICE Brent 		    Income
Statement
Case
TRM(2)  
+1% 		    Difference
Between
Real 2020
and Case
TRM 		 
Revenue     50,223.39       51,298.64       1,075.25       50,710.48       487.09  
Cost of sales     37,567.47       37,963.58       396.11       37,727.33       159.86  
Gross Income     12,655.92       13,335.06       679.14       12,983.15       327.23  
Operating expenses     4,841.00       4,841.00       -       4,841.00       -  
Impairment of non-current assets     633.16       633.16       -       633.16       -  
Operating income     7,181.76       7,860.90       679.14       7,508.99       327.23  
Finance results, net     (2,481.59 )     (2,481.59 )     -       (2,481.59 )     -  
Share of profit of associates and joint ventures     76.34       76.34       -       76.34       -  
Income before income tax     4,776.51       5,455.65       679.14       5,103.74       327.23  
Income Tax     (2,038.66 )     (2,328.52 )     (289.86 )     (2,178.32 )     (139.66 )
Net Income     2,737.85       3,127.13       389.28       2,925.42       187.57  

 

 

(1) ICE Brent = US$43 per barrel
(2) Exchange rate (TRM) = COP$ 3,693/US$ 1.00

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Assumptions for the Sensitivity Analysis of our Results

 

Our sensitivity analysis is based on the Consolidated Statement of Profit or Loss for 2020, as presented elsewhere in this annual report.

 

The sensitivity of the ICE Brent price index is in reference to an increase of US$1 per barrel of crude oil in the average ICE Brent reference price based on a 366-day year for 2020. Prices assumed correspond to realized prices for crude oil, natural gas and refined products for 2020, 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 2020. Prices are the realized prices of crude oil, natural gas and refined products in 2020 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 2020).

 

The income tax for each of our sensitivity analyses (price of ICE Brent and COP$/US$ exchange rate) is estimated using the effective corporate tax rate of 43% for 2020.

 

This sensitivity analysis keeps everything constant. In the case of significant variations of the ICE Brent price, Ecopetrol will perform interventions in its operating expenditures.

 

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 62

 

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

 

5. Risk Review

 

5.1 Risk Factor Summary

 

The following is a summary of the principal risks we face:

 

1. Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time.
2. Achieving our long-term growth depends on our ability to execute our strategic plan— specifically, the discovery and/or successful development of additional reserves and our capacity to adapt our business to the transition to a low carbon economy and climate change.
3. Our business depends substantially on international prices for crude oil and refined products.
4. Changes in the Colombian Peso/U.S. dollar exchange rate could have an adverse effect on our financial condition and results of operations.
5. 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.
6. 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.
7. 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.

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8. We are exposed to the credit, political and regulatory risks of our customers.
9. Our ability to access the credit and equity capital markets on favorable terms to obtain funding to finance our operations or refinance our debt maturities.
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.
12. Our current and planned investments and exploration activities 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.
14. Our performance could be negatively affected by the lack of skilled employees to execute our business strategy.
15. If the strategic plans associated to natural gas and NGL failed 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.
18. Our business operations and financial condition could be negatively affected by the COVID-19 or other pandemic diseases and health incidents.
19. Our operations, including our activities in areas classified as indigenous reserves and Afro-Colombian lands, are subject to opposition from members of various communities.
20. We have made significant investments in acquisitions and divestments and we may not realize the expected value.
21. We might be required to provide financial support to our subsidiaries in Colombia or abroad.
22. Ongoing Colombian State control entities investigations regarding our subsidiary Reficar and our former subsidiary Bioenergy could adversely affect us.
23. Our results may be affected by the performance of our suppliers, our business partners or their third-party service providers.
24. Our insurance policies do not cover all liabilities and may not be available for all risks.
25. 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
26. A failure in our information technology systems or cyber security attacks may adversely affect our financial results.
27. We are exposed to behaviors incompatible with our ethics and compliance standards.
28. The reliability and capacity of national power supply systems may affect or limit the continuity of our operations or limit growth.
29. Rising water production levels may affect or constrain our crude oil production.

 

Risks Related to Colombia’s Political and Regional Environment

 

30. The worldwide economic effects of the outbreak and economic shutdown caused by the COVID-19 pandemic is adversely affecting Colombia’s economy, and the impact could be material.
31. The Colombian government could seize or expropriate Ecopetrol’s 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.
33. Despite the peace agreement between the Colombian government and the FARC and the peace negotiation process attempts with the National Liberation Army (the ELN), some illegal and terrorist activities of guerrilla groups or their members may continue.
34. There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries.

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35. The investment climate in Colombia, may be less stable than the prevailing economic conditions and investment climate in developed countries.
36. Our operations might be affected by rising climate change and energy transition concerns.
37. 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.

 

Legal and Regulatory Risks

38. Our operations are subject to extensive regulation.
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 ADSs holders may be subject to restrictions 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. ADRs 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.

 

Risks Related to the Controlling Shareholder

50. Our controlling shareholder’s interests may be different from those of certain minority shareholders.

 

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, 2020, 2019 and 2018, 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 US$ 72.2/Bl in 2018, US$ 63/Bl in 2019 and US$ 43/Bl in 2020. In 2020, the Company recognized a decrease in oil and gas proven reserves of 6.5% as compared to 2019, to 1,770 mmboe in 2020 from 1,893 mmboe in 2019. In 2019, the Company recognized an increase in oil and gas proven reserves of 9.6% as compared to 2018, to 1,893 mmboe in 2019 from 1,727 mmboe in 2018. For more information, see the section Business Overview—Exploration and Production—Reserves.

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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.

 

In 2020, Ecopetrol recognized impairment losses of non-current assets of COP$ 633,156 million which corresponds to the net result of:

 

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

 

• An impairment of non-current assets in the refining and petrochemicals segment, primarily related to the lower refining margins at the Cartagena Refinery and the Barrancabermeja Refinery Modernization Plan, considering the progress in technical analysis of the project.

 

• A reversal of impairment of non-current assets in the transportation and logistics segment, 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 Caño Limón-Coveñas system.

 

Any significant change in estimates 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, 2020. Based on these calculations, assuming an average price per barrel of ICE Brent price of US$ 46/Bl in 2021, US$ 55/Bl and US$ 58/Bl between 2022 and 2025, and between US$ 61/Bl and US$ 68/Bl onwards, Ecopetrol could recognize an increase in oil and gas proved reserves of approximately 7%. This analysis takes into account Ecopetrol’s 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 the 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 strategic plan — specifically, the discovery and/or successful development of additional reserves and our capacity to adapt our business to the transition to a low carbon economy and climate change.

 

Our long-term growth objectives depend largely on our ability to develop the reserves recovery potential associated with existing fields and to discover and/or acquire new reserves, and in turn develop them successfully. Our exploration activities expose us to the 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.

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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. Additionally, our strategy envisioned the exploration and development of unconventional reservoirs in Colombia, by using fracking technology. See the section Strategy and Market Overview—2021 – 2023 Business Plan. However, the implementation of this strategy depends, among others, on the final outcome of the regulatory framework under implementation by the Colombian Government, the environmental license required for the PPII, and the results of the scientific information to be collected.

 

If we are unable to achieve expected recovery factors in our existing fields, or successfully discover and develop additional reserves, or if we do not acquire properties having proved reserves, 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.

 

Furthermore, we are subject to risks related to the transition to a low carbon economy and to climate change. In terms of our physical risks, these are related to the exposure we have to Colombia’s current climate conditions that might affect water availability and increase the exposure 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 because of climate change. Extreme weather events could result in damages to our assets and negatively affect our operations and financial condition.

 

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 carbon tax in place since 2017, the implementation of an emissions trading system (ETS) expected to be implemented in 2022, the updated nationally determined contribution (NDC), and the oil & gas industry’s climate change plan that includes new national mitigation and adaptation measures. These changes could lead to increases in our costs and investments in the short term (Ecopetrol has 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 the Company in the short term). See the section Legal and Regulatory Risks - Our operations might be affected by rising climate change and energy transition regulatory developments.

 

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. As of the date of this annual report, the index has been applied to our upstream segment assets with the stranded risk evaluation still being developed in our midstream and downstream segments. Our analysis resulted in no stranded assets in our upstream segment, with the assets with the highest risk of becoming stranded being just initiating their development (either still in the exploratory stage or having just commenced production). 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 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.

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See the section Strategy and Market Overview—Our Corporate Strategy for a discussion of our strategic plan.

 

Our business depends substantially on international prices for crude oil and refined products. The prices for these products are volatile; a sharp decrease could adversely affect our business prospects and results of operations.

 

In 2020, approximately 94% of the revenues came from sales of crude oil, natural gas and refined products and 90% 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 Organization of the Petroleum Exporting Countries (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 addition, due to the disagreement on production cuts between the Organization of the Petroleum Exporting Countries (OPEC) and Russia, the OPEC and its capacity and decision to increase production levels to gain market share have impacted the international reference prices in the past.

 

The continuing spread of the coronavirus disease (COVID-19) continues to lead to periods of instability in the global economy, which in turn could continue to cause instability in crude oil, NGL, and gas demand and oil, NGL, and gas prices. Additionally, the level of global oil inventories caused by the COVID-19 pandemic has created surpluses for oil and may result in the cost of exploring for, developing, producing and transporting oil to go up due to surpluses created by the pandemic. The COVID-19 pandemic may further impact the prices of crude oil, natural gas and refined products as expectations about future commodity prices become unpredictable due to the inability to forecast the duration scope of impact of the pandemic. See Our business operations could be disrupted by the COVID-19 or other pandemic disease and health events for further information on the effects of the coronavirus pandemic.

 

When crude oil, refined products and natural gas prices are low, we earn less revenue and we generate lower cash flow and less income. Conversely, when crude oil, refined product and natural gas prices are high, we earn more and generate a larger amount of cash and net income. During 2020, our crude oil basket price was US$ 34.4/Bl versus US$ 58.6/Bl in 2019, the refined product basket price was US$ 49.2/Bl versus US$ 69.8/Bl in 2019; and the natural gas price was US$ 24.3 per barrel equivalent in 2020 versus US$ 23.7 per barrel equivalent in 2019. 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.

 

In 2020, we had an impairment of non-current assets of COP$633,156 million, as compared to COP$1,762,437 million in 2019 and COP$368,634 million in 2018. These impairments are an accounting effect that does not involve any inflow of resources and they are susceptible to reversion when the fair value of the asset is above its book value. For additional information about this impairment charges, see the section Financial Review—Operating Results—Consolidated Results of Operations—Impairment of Non-Current Assets and Note 18 to our consolidated financial statements.

 

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.

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Changes in the Colombian Peso/U.S. dollar exchange rate could have an adverse effect on our financial condition and results of operations given the amount of U.S. dollar denominated debt held by the company and the fact that most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars.

 

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, 2020, our U.S. dollar-denominated total aggregate principal amount was US$ 12.3 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, an aggregate principal amount of US$ 11.8 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 12.46% in 2020, 10.98% in 2019 and 0.18% in 2018. Additionally, as of December 31, 2020, the Colombian Peso depreciated 4.74%; as of December 31, 2019, the Colombian Peso depreciated 0.84%; and as of December 31, 2018, the Colombian Peso depreciated 8.91%, in each case from year-end exchange in the previous year. In addition, given the effect of COVID-19 on the world’s economies, the performance of the interest rate in the U.S., different global growth perspectives, commercial and political tensions in the biggest world 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. Given that markets are dealing with a great deal of uncertainty, it is expected that U.S. dollar movements will remain difficult to forecast.

 

A future depreciation 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.

 

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, Mexico 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.

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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 exploration, production, refining and transportation activities 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), blockages in the communities in which we operate, 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, blow-outs, surface cratering, pipeline failures, theft and damage to our transportation infrastructure, sabotage, terrorist attacks and criminal activities.

 

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 in order 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 the projects we may decide to undertake.

 

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.

 

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 the section Business Overview—Exploration and Production for a summary of our current deep-water drilling activities.

 

We are exposed to the credit, political and regulatory risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

 

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.

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The combination of decreasing cash flows as a result of declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities 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 ability to access the credit markets as well as the debt and equity capital markets on favorable terms to obtain funding to finance our operations or refinance our debt maturities may be limited due to the deterioration of these markets, any change to our credit ratings and the authorizations we need before incurring any financial indebtedness or executing any equity offering.

 

A new financial crisis, volatility in prices in the oil and gas sector, the potential impacts on demand of further lockdowns or outbreaks of COVID-19, the lack of consensus among OPEC+ members, the political uncertainty in the region, the discovery of corruption by governments and private companies in emerging markets and further geopolitical disruptions in the Middle East, which could involve developed countries, and 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 could make it more difficult for us and our subsidiaries to access international and local capital markets and finance our operations and potentially refinance our debt maturities on terms acceptable to us. These conditions, along with 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 ESG considerations in our operation and management, and addressing risks related to climate change; considering further the evolving restrictions to invest in pure fossil fuels companies announced by certain investors worldwide.

 

Access to credit and capital markets is also dependent on our credit ratings, which are mainly determined by our financial and operational strength, oil and gas market conditions 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 April 3, 2020, Fitch Ratings downgraded our credit rating from BBB to BBB- as a consequence of our direct linkage of the company to the sovereign rating downgrade of the Republic of Colombia. On March 26, 2020, S&P revised our outlook to negative and affirmed our stand-alone credit rating in bbb-. On July 31, 2020, Moody’s confirmed our long-term international rating at Baa3, with a stable outlook. We cannot offer any assurance that our credit rating will continue.

 

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 Superintendency of Colombia. Likewise, our equity offerings must abide to 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 Superintendency 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.

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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. If market interest rates increase, our financing expenses may increase, which could have an adverse effect on our results of operations and financial condition.

 

As of December 31, 2020, approximately 13.62%, or a principal of US$ 1.8 billion (COP$ 6.1 trillion, using a COP$ 3,432.50/1.00 US exchange rate as of December 31, 2020), of our total indebtedness consisted of floating rate debt. If market interest rates rise, our financing expenses will increase, which could have an adverse effect on 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 capital projects or inorganic acquisitions, the prevailing interest rates and spreads at any specific time could be less favorable in terms of cost when compared to our previous financing transactions, which could adversely affect our financial condition and results of operations.

 

Our 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 July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. Similarly, it is not possible to predict whether LIBOR will continue to be viewed as an acceptable market benchmark, what rate or rates may become acceptable alternatives to LIBOR, or what effect these changes in views or alternatives may have on financial markets for LIBOR-linked financial instruments. As of December 31, 2020, 8.3% of our long-term nominal debt was subject to floating interest rates that used LIBOR as the benchmark. Although we expect to adapt such contracts as developments relating to a LIBOR replacement arise, currently, we 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 exploration activities outside Colombia are exposed to political and economic risks.

 

We began exploration activities outside Colombia in 2006 through our Brazilian subsidiary, Ecopetrol Óleo e Gás do Brasil Ltda. We operate through business partners, subsidiaries or affiliates outside Colombia. We currently have investments, joint ventures and subsidiaries incorporated in Peru, Brazil, Mexico, Bermuda, Panama, the Cayman Islands, Switzerland, Spain, the United Kingdom and the United States, and we are analyzing investments in other countries. In connection with making investments, we are and will be subject to risks related to economic and political conditions and governmental economic actions. We cannot predict the positions of foreign governments relating to the oil and gas industry, 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, 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, fluctuation of local currencies against the Colombian Peso, the nationalization of oil and gas reserves, increases in export and income tax rates for crude oil and oil products, 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, or cause us to incur additional costs or delay the timeline of our projects.

 

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 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 in our adaptation 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 transition to a new low carbon economy and address climate change, we face the risk that our progress may be curtailed due to the high cost of low-carbon and water management technologies. In the case of our enhanced oil recovery program, we not only depend on the successful selection, adaptation, demonstration and deployment of appropriate technologies but also in the reservoir response to the application of these recovery technologies.

 

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 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 the capacities of management at all levels of the organization and develop the skills they need to find the solutions to implement climate-resilient initiatives and to achieve our decarbonization goals.

 

If the strategic plans associated to natural gas and NGL failed 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 January 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.

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Additionally, we are currently 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 Ecopetrol 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 and results of operations could be impacted.

 

We depend on others for the construction and availability of natural gas transportation infrastructure for the transport of our gas, which may limit our ability to develop new or existing fields or lead to the deterioration of related assets and may not allow us to recover the cost of capital invested in natural gas discoveries.

 

Ecopetrol S.A. can only hold up to 25% of the equity of any natural gas transportation company according to Article 5 of CREG Resolution 057 of 1996 (except for transportation assets acquired before this Resolution). Therefore, there can be no assurance that the transportation infrastructure necessary to transport natural gas from the fields to distribution points and our customers will be built by third parties or that if built there will be sufficient capacity available to us for the exploitation of new natural gas discoveries or the development of existing fields due to the non-financial closure of transport projects or lack of signed contracts with transporters. The failure to commercially exploit new or existing discoveries may result in impairment of the related assets and our inability to recover the capital expenditures invested to make these natural gas discoveries.

 

Our operations could be affected by reactions of labor unions, social organizations, communities and contractors to Colombia’s political and social environment, environmental and climate change concerns and organizational changes.

 

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, which could have an adverse effect on our operations and financial condition.

 

On July 1, 2018, a new collective bargaining agreement became effective for a term of four and half years, expiring on December 31, 2022. We cannot assure you that we will not experience strikes or labor unrest in the future.

 

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.

 

The effects of climate variability and climate change, such as the increase in the frequency and intensity of climate phenomena such as “La Niña” and “El Niño”, intensify the risk of natural disaster occurrence, such as floods, landslides, water availability, wild fires, droughts, increased temperature and rising sea and river levels, among others, which may affect our business operations.

 

In Colombia, the “El Niño” climate phenomenon is characterized by (i) a lack of rainfall, which may drastically decrease surface waterbodies flows, affecting both freshwater withdrawals required for operations 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.

 

Furthermore, the “La Niña” climate phenomenon is characterized by increased rainfall, which can generate (i) landslides that threaten pipeline infrastructure and increase the risk of ruptures that may cause hydrocarbon spills and limit road transportation and (ii) flooding, which could limit operations in our production fields and facilities.

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These risks could result in property damage, loss in production, loss of revenue, loss of life, pollution and harm to the environment, 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.

 

Our business operations and financial condition could be negatively affected by the COVID-19 or other pandemic diseases and health events.

 

Pandemic diseases and health events, such as COVID-19, have the potential to negatively impact economic activities in many countries, including the countries in which we operate or have trade links, with consequent adverse effects on our customers and business.

 

In particular, the timeline and potential magnitude of the COVID-19 outbreak still remain unknown. The persistence and variation of the virus could continue to more broadly affect the Colombian and global economy, including our business and operations, because of its impact on the demand for oil and gas. For example, the outbreak of coronavirus has resulted in a widespread health crisis that has adversely affected the economies and financial markets of many countries, resulting in an economic downturn that affected our operating results in 2020. In addition, the effects of COVID-19 and concerns regarding its global spread have recently negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility, impacted the revenues we receive for oil and natural gas, and has materially and adversely affected the demand for and marketability of our production, and is anticipated to continue to adversely affect the same for the foreseeable future. As the potential impact from COVID-19 is difficult to predict, the extent to which it will negatively affect our operating results, or the duration of any potential business disruption is uncertain. The magnitude and duration of any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control.

 

In terms of the impact on Ecopetrol, the disagreement on production cuts between the Organization of the Petroleum Exporting Countries (OPEC) and Russia since the beginning of March 2020 through April, 2020, followed by the decision of Saudi Arabia to reduce its sale oil prices and increase its production to gain market share, negatively impacted the international reference prices for crude oil and refined products in 2020. Furthermore, as a result of the COVID-19 pandemic and measures put in place to slow its spread, including the imposition of quarantines and medical screenings, travel restrictions and the suspension of certain activities, we have seen and expect to continue to see substantial uncertainty in macro-economic conditions with regards to lower prices and demand for oil, gas and related products. These recent global developments resulted in a significant drop in Brent crude prices during 2020 as compared to 2019. As our business depends substantially on international prices for crude oil and refined products, while we were able to recuperate some of the losses suffered during the second quarter of 2020, the sharp decrease in oil prices in 2020 negatively impact our results of operations and business prospects for the year ended December 31, 2020 as compared to the year ended December 31, 2010. In particular, our consolidated gross profit, consolidated operating income, and consolidated net income for 2020 decreased by 52.3%, 65.8% and 81.8%, respectively, as compared to the same line items in 2019. Our operating results were affected mainly by (i) decreases in international prices of crude oil, international prices for refined products and local prices for natural gas, (ii) the reduced demand levels for crude oil and its derivative products, and (iii) decreases in sales volumes, product mix and exchange rate volatility.

 

For the year ended December 31, 2020, we also recognized impairment losses of non-current assets of COP$ 633,156 million, which corresponds to the net result of:

 

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

 

• An impairment of non-current assets in the refining and petrochemicals segment, primarily related to the lower refining margins at the Cartagena Refinery and the Barrancabermeja Refinery Modernization Plan, considering the progress in technical analysis of the project.

 

• A reversal of impairment of non-current assets in the transportation and logistics segment, primarily as a result of a recovery in the 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.

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At this point, we cannot forecast the duration of the effects of COVID-19 on our business or when international prices for crude oil and refined products will stabilize. Our future business results will be affected by the extent and duration of these conditions and the effectiveness of responsive actions that we and others take, including (i) our actions to reduce capital and operating expenses, (ii) in respect of oil supply, any cooperation between OPEC member countries, and (iii) in respect of COVID-19, the impact of vaccination programs, coverage and immunity achieved, the severity and duration of the outbreak, and the actions by national and international government authorities to contain the pandemic and minimize its impact, among other things. We will continue to monitor market developments and evaluate the impacts of decreased demand on our production levels as well as impacts on project development and future production.

 

See Note 2.8 to our consolidated financial statements for further information.

 

Our operations, including our activities in areas classified as indigenous reserves and Afro-Colombian lands, are 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. In order 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.

 

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. 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.

 

We have made significant investments in acquisitions and divestments and we may not realize the expected value.

 

We have acquired interests in several companies in Colombia and abroad and in 2019 entered into a joint venture with Oxy in the U.S. Permian Basin. See the section Business Overview—Our Corporate Structure. Obtaining the expected benefits of the acquisitions will depend, in part, on our ability to (i) obtain the expected results of operations and financial condition from these acquisitions, (ii) manage different sets of assets and operations and integrate distinct corporate cultures, (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 as well as all other risks affecting the oil and gas industry. These efforts may not succeed. Our failure to successfully obtain the expected results from our acquisitions could adversely affect our financial condition and results of operations. Also, the acquisitions may be subject of review by administrative control entities in Colombia, which could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations.

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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 of the date of this annual report, there is not a clear position of the new United States’ administration regarding policies concerning Colombia. Moreover, from the original executive orders signed by President Biden related to climate change, there is a 60 day suspension to issue, extend or amend federal leases or drilling permits on federal land, while a task force conducts an environmental study. This order does not affect operations that were already on going or under drilling permits issued prior the order, but we cannot assure there will be no further executive orders that may adversely affect our U.S. operations. These executive orders also established additional task force groups to review changes in fiscal and regulatory policies, which may include changes in royalty rates, minimum bids and lease terms for federal land. Ecopetrol´s investments in the United States include federal land (Gulf of Mexico), therefore there is uncertainty in terms of how any future regulatory changes by the Biden administration will affect such leases.

 

In addition, as a result of strategic reassessments of our core operations and portfolio management analysis, we have executed partial or total divestments in our current businesses and the sale price in these transactions might not have been enough to realize the original expected value or to recover the investments the company has made. These transactions may also be subject to review by administrative control entities in Colombia, which could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations.

 

We might be required to provide financial support to our subsidiaries in Colombia or abroad.

 

Although currently Ecopetrol is not the sponsor and has not provided guarantees to third parties to support the financing activities of any of its 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.

 

Ongoing Colombian State control entities investigations regarding our subsidiary Reficar and our former subsidiary Bioenergy could adversely affect us.

 

Ecopetrol, Bioenergy and Reficar’s employees are generally subject to the control and supervision of the Colombian State control entities. See section Risk Review—Legal Proceedings and Related Matters for additional information. The investigations concerning Reficar and Bioenergy, as well as other at Ecopetrol, that are described in section Risk Review—Legal Proceedings and Related Matters remain ongoing. While we are cooperating fully with both cases, adverse developments in connection with these investigations, including any expansion of the scope of the investigations, could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations.

 

In connection with this investigation or any other investigation carried out by any other authority, there can be no assurance that we will not incur in additional costs and expenses or expose us or our employees to sanctions and lawsuits, any of which could adversely impact our reputation and, in turn, could have adverse effects on our financial condition and results of operations. See section 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.

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Our results may be affected by the performance of our suppliers, our business partners or their 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 we will not be found liable 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, including through a decrease in limits and coverages, which could affect future decisions expected to be made by such directors and officers and could lead to an adverse effect on our financial condition and results of operations.

 

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 new low 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 & 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, we can not yet assure that these trend 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.

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During 2020, 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.

 

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 business, we are subject to the risk that our employees, contractors, or any person having relations with us may misappropriate our assets, manipulate our assets or information or engage in money laundering or the financing of terrorism, for such person’s personal or business advantage. Our systems for identifying and monitoring these risks may not be effective to fully mitigate them in all situations. Such acts may result in material financial losses or reputational harm to 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 2020 was 7,097 GWh/year, of which 68% was supplied through self-generation, and the remaining 32% through power grid. Our demand is 10% of the total energy demand in Colombia. Our self-generation is subject to fuel and solar availability. In addition, several producing fields are connected to the national transmission system and depend on its expansion and reliability to keep steady production levels. The national electricity market is volatile due to changes in hydrology and availability of fuels (natural gas, diesel etc.), bringing uncertainty to prices. If energy were to become unavailable or difficult to obtain, our results of operation and financial condition could be adversely affected.

 

Rising water production levels may affect or constrain our crude oil production.

 

During 2020, the Ecopetrol Group produced approximately 16.3 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’s Political and Regional Environment

 

This section discusses potential risks related to our extensive operations in Colombia.

 

The worldwide economic effects of the outbreak and economic shutdown caused by the COVID-19 pandemic is adversely affecting Colombia’s economy, and the impact could be material.

 

The COVID-19 pandemic is currently having an adverse impact on the world economy. Many countries have undertaken various public health measures to control the spread of COVID-19, including mandatory quarantines, forced economic shutdowns and travel restrictions, as well as economic measures to mitigate the impacts of such public health policies on their respective national economy. As of March 31, 2021, Colombia had 2,406,377 confirmed cases of COVID-19, 2,285,515 recovered cases and 63,422 deaths.

 

On March 17, 2020, the Government, through Legislative Decree 417 of 2020, declared a 30 day state of national emergency in light of the health and economic crisis caused by the outbreak of COVID-19. On May 6, 2020, through Legislative Decree 637 of 2020, the Government declared a state of emergency for an additional 30 days. The Government has implemented various economic and public health measures to address the crisis, including (i) mandatory shelter in place orders; (ii) border closure for all non-citizens and non-residents; (iii) short term and low interest loans for all types of agricultural producers; (iv) payroll subsidies for companies and credit lines for different sectors of the economy; (iv) closure of all schools and universities; (v) incentivizing working from home and a mandatory work from home order for 80% of Government employees; (vi) actions by the Banco de la Republica, including reductions of its interest rate by 250 basis points in 2020, the provision of non-delivery forwards in the amount of up to U.S. $1 billion and supplying liquidity auctions up to COP$ 20 trillion; (vii) suspension of increases in utility tariffs; (viii) reduction in the prices of gasoline; (ix) changes to the general budget and measures to render more flexible certain procedures to enable the Government to access the credit markets; and (x) increased COVID-19 testing of up to 15,000 per day, among others. The efficacy of certain of these measures cannot yet be evaluated, and their duration and effect remain uncertain. On December 18, 2020, the Government announced that the country had purchased 40 million doses of COVID-19 vaccines, composed of 10 million doses from Pfizer Inc., 10 million doses from AstraZeneca and 20 million doses from the multilateral Covax agreement. Vaccination began in February 2021 and will have 5 phases, prioritizing those at higher risk, such as health workers and citizens over 80 years old.

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From a macroeconomic point of view, the COVID-19 pandemic had a negative impact on Colombia in 2020 with GDP decreasing by 6.8% for the year ended December 31, 2020 as compared to the year ended December 31, 2019. The main industries that lead to this decrease were construction, transportation, and accommodation, real estate and food services. Economic stagnation, the depreciation of the Colombian Peso, contraction and decreased income levels and increased unemployment levels could result in a pronounced period of economic slowdown in Colombia, which could lead to a further decrease in oil and gas demand and hence could continue to negatively impact our business and financial condition. Furthermore, the COVID-19 outbreak has also resulted in 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. Any shocks or unexpected movements in these market factors could result in financial losses in our investment portfolio.

 

If the economic and public health crisis caused by the COVID-19 outbreak continues and the Government’s measures are not effective, the economic performance of the country may suffer further than already anticipated, as a result of adverse effects on commerce, transportation and foreign investment, among other things, and thus may potentially adversely affect Ecopetrol’s ability to service its debt, including the bonds. The effects of the COVID-19 pandemic and the economic shutdown may also include an increase in unemployment, a reduction in household income, reduction in Government revenues, increased Government expenditures and a deterioration of Ecopetrol’s and Colombia’s financial position. The sharply lower demand for oil and its derivatives due to decreased demand as a result of the COVID-19 pandemic in turn resulted in lower and more volatile price of oil and gas, which has also negatively affected the Colombian economy and the financial position of Ecopetrol. The Government has projected negative GDP growth of 6.8% for 2020, the first recession in Colombia in over two decades.

 

The COVID-19 pandemic, any additional wave or resurgence and/or new pandemic may also have the effect of heightening the other risks described herein, such as those relating to economic, social and political developments in Colombia and its credit ratings. Consequently, the current COVID-19 pandemic and its potential impact on the global economy may require Colombia to enact additional changes to existing regulations or implement more stringent regulations, which may further adversely impact the Republic’s economy, the prices of, and Colombia’s ability to make payments on, its outstanding securities or other indebtedness.

 

The Colombian government could seize or expropriate Ecopetrol’s 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 2020, the attacks against our pipeline infrastructure decreased by 29% in relation to 2019 (51 attacks in 2020 compared with 72 attacks in 2019). Nonetheless, the attacks especially affected the infrastructure located in the Norte de Santander, Arauca and Nariño departments and the Caño Limón - Coveñas and Transandino pipelines. There was no deferred production directly related to these attacks in 2020 as compared to a deferred production of 660,052 barrels in 2019. Throughout the first quarter of 2021, there were 12 attacks against our pipeline infrastructure.

 

Guerilla attacks have resulted in unscheduled shutdowns of our transportation systems in order 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 2020 was approximately COP$213,300 million (US$62.147 million, using a COP$3,432.50/1.00 US exchange rate as of December 31, 2020). During 2020 we also experienced one particular attack to our production infrastructure in Casanare, specifically on the transfer line parallel to the Liria well that, while not affecting people or the environment, resulted in in a dent.

 

During 2018, attacks resulted in the unavailability of our Caño Limón-Coveñas pipeline which led certain of our customers to request the early termination of their transport agreements. While we have reached preliminary settlement agreements with our customers in respect of these disputes, such agreements are subject to regulatory approvals. See Note 23.3 to our consolidated financial statements for further information.

 

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 1,808 bod in 2019 to approximately 2,744 bod in 2020, representing for Ecopetrol and its partners a consolidated loss of COP$367,515 million for the year ended December 31, 2020 (US$107,069 million, using COP$3,432.50/US$1.00 exchange rate as of December 31, 2020) and COP$ 241,840 million for the year ended December 31, 2019. This situation is directly related to the increase of illicit crops, presence of guerilla dissidents and other illegal groups in the areas of influence of the main crude transportation systems, such as as Caño Limón – Coveñas System (Catatumbo and Norte de Santander) and the Trasandino System (Tumaco and Nariño). Furthermore, the theft of refined products is related to the presence of common crime that illegally markets these products, presenting losses of approximately 24 bod and 37 bod in the years ended December 31, 2020 and 2019, respectively.

 

These activities and their possible escalation and the effects associated with them have had, and may have in the future, a negative impact on the Colombian economy or on us, which may affect our customers, employees, assets or the environment, with resulting containment, clean-up and repair expenses.

 

Despite the peace agreement between the Colombian government and the FARC and the peace negotiation process attempts with the National Liberation Army (the ELN), some illegal and terrorist activities of guerrilla groups or their members may continue.

 

On November 30, 2016, the Colombian Congress approved a peace agreement between the Colombian government and the Revolutionary Armed Forces of Colombia, or FARC. Since then, the Colombian government has advanced in the process of gradually integrating many of the FARC members into civilian and political life. In spite of these efforts, in August 2019 some former leaders of this guerilla left the process and announced the resumption of hostilities.

 

Likewise, the National Liberation Army, or ELN, guerrilla group, has increased its actions against the Colombian security forces and the critical infrastructure of the Nation, which we believe is an attempt to show its presence and influence in some regions and put pressure to resume peace negotiations that were interrupted since January 2019, as a result of the terrorist attacks carried out by the ELN. The Colombian Government proclaims that the continuity of the dialogues depends on the cessation of terrorist activities and the release of hostages by this group. It is expected that attacks against critical infrastructure will continue until a new bilateral ceasefire can be agreed upon.

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Therefore, it is expected that some guerilla groups, such as the ELN, may continue their illegal and terrorist activities, including attacks on our infrastructure, 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.

 

In particular, the economic, political and social crisis in Venezuela is having a severe impact on Colombia’s economy and social situation. This situation could affect the countries’ diplomatic relations, impact border towns and cities, accelerate Venezuelan migration flow into Colombia, affect our borderline operations and therefore may have a negative impact on Colombia’s economy and general security situation as well as in our operating results.

 

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.

 

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 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. 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.

 

5.2.3 Legal and Regulatory Risks

 

This section discusses potential legal and regulatory risks to Ecopetrol, including the risk of having to comply with new laws and regulations.

 

Our operations are subject to extensive regulation.

 

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.

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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 National Authority on Environmental License or 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), 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 as per 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 Prior Consultation.

 

Environmental regulation has become more stringent in Colombia in recent years. As a result, our operating costs have increased in order 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 in order to allocate funds to environmental compliance. We are also exposed to delays in obtaining environmental licenses from ANLA, which can lead to cost overruns or to changes in our investment plans. These additional costs may have a negative impact on the profitability of the projects we intend to undertake or may make them economically unattractive, in turn having a negative impact on our results of operations and financial condition.

 

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 business 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.

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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.

 

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. For instance, as of December 2020 Colombia announced an ambition goal to reduce carbon emissions by 51% by 2030 as part of its Nationally Determined Contribution (NDC). This national commitment is considered in Ecopetrol’s ongoing review of its objectives on emission reductions.

 

Furthermore, in addition to the carbon tax that Colombia imposed for fuel consumption, of approximately US$5 per ton of CO2, in 2022 we expect a National Program of Tradable Quotas of (PNCTE), a type of Emissions Trading System (ETS) to enter into force. Additionally, the Colombian government is planning a regulation on reduction of routine flaring and fugitive emissions. While we expect these to be in line with our current decarbonization policy for the identification, measurement, and correction of fugitive emissions and vents, we can offer no assurance that we will meet the new regulations or that the new regulations will not need to increased costs. Any of the two mentioned effects could negatively impact our financial condition and results of operations.

 

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 2018, pursuant to Law 1943, the Colombian Congress enacted a tax reform (the Financing Law), which became effective as of January 1, 2019 and modified the Colombian income tax regime. This Law 1943 was declared unconstitutional as of January 1, 2020 but continued to have full effect until December 31, 2019. 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 along with some changes to tax legislation.

 

For a description of taxes affecting our results of operations and financial condition in 2019, 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 non-taxed 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.

 

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, 2020, Ecopetrol S.A. was a party to 5.361 legal proceedings relating to civil, criminal, administrative, environmental, tax, labor claims, of which 3.641 were filed against us in the Colombian courts and arbitration tribunals and of which 234 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 22 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 December 29, 2017, 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 ADSs holders may be subject to restrictions on foreign investment in Colombia.

 

Colombia’s International Investment Statute (the set of rules and regulations which govern the foreign exchange market and the transactions thereto, which include Decree 1068 of 2015, Resolution 1 of 2018 and External Circular DCIN 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 foreign exchange market intermediaries 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 Superintendence of Finance. 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 handle their investment by means of the procedures set forth in section 7.4.1 of the External Regulation of the Circular DCIN-83 of the Colombian Central Bank.

 

In the future, the Government, the Colombian Congress or the Colombian Central Bank may amend Colombia’s International Investment Statute or the foreign investment rules, which could result in more restrictive rules and could negatively affect trading of our ADSs.

 

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, especially if the foreign investment is not duly registered before the Colombian Central Bank. Also, currently Colombia has a floating exchange rate system that might be subject to change in the future. See section Shareholder Information—Exchange Controls and Limitations.

 

Holders of our ADSs may not be able to effect service of process on us, our directors or executive officers within the United States, which may limit your recovery in any foreign judgment you obtain against us.

 

We are a mixed economy company organized under the laws of Colombia. In addition, most of the members of our Board of Directors (Directors) and executive officers reside outside the United States. All or a substantial portion of our assets and the assets of these persons are located outside of the United States. As a result, it may not be possible for ADSs holders to effect service of process within the United States upon us or these persons or to enforce judgments against us or them in U.S. courts obtained in such courts predicated upon the civil liability provisions of the U.S. federal securities laws. Colombian courts determine whether to enforce a U.S. judgment predicated on the U.S. securities laws through a procedural system known as exequatur. For a description of these limitations, see section Shareholder Information—Enforcement of Civil Liabilities.

 

The protections afforded to minority shareholders in Colombia are different from those in the United States, and may be difficult to enforce.

 

Under Colombian law, the protections afforded to minority shareholders are different from those in the United States. 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.

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ADRs do not have the same tax treatment as other equity investments in Colombia.

 

Although ADRs represent Ecopetrol’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 obtained, 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 and can be more volatile than other securities markets in the United States. As of December 31, 2020, the Colombian Stock Exchange (BVC) had a market capitalization of approximately COP$365,657 billion (US$105 billion using the closing rate for 2020), a 16% decrease when compared with the amount at the end of 2019, a daily average trading volume of approximately COP$122,752 million (US$33 million, using the average exchange rate for 2020), a 14% decrease when compared with the volume in 2019. By comparison, the New York Stock Exchange (the NYSE) had a market capitalization of US$32.6 trillion as of December 31, 2020, and a daily trading volume of approximately US$182.7 billion in 2020.

 

As of December 31, 2020, our shares represented the highest market capitalization of the BVC accounting for 11% of the total COLCAP index, which reflects the price volatility of the 20 most-liquid stocks.

 

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, the ability of investors in our ADSs to sell them at the desired price and time could be substantially limited.

 

We are not required to disclose as much information to investors as a U.S. issuer is required to disclose.

 

We are subject to the reporting requirements set by Law 964 of 2005, the Superintendence of Finance and the BVC - (Colombian Stock Exchange). 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 be different from those of certain minority shareholders.

 

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.

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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, thereby negatively affecting our prospects, results of operations and financial condition. See the section Shareholder Information—Dividend Policy.

 

Additionally, our controlling shareholder may undertake projects, approve decisions 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.

 

5.3 Risk Management

 

5.3.1 Integrated Risk Management System and Internal Control System

 

Under the leadership of the Vice-Presidency of Compliance, in 2020 Ecopetrol S.A. strengthened 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, in order 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, Ecopetrol has 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.

 

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: These are those 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 Ecopetrol´s strategy. Emerging risks are selected from those trends, and they are included in the enterprise risks as a new risk or as a cause of existing enterprise risk. Further information can be found in Ecopetrol’s 2020 Enterprise Risk Map which is available on our website at:

https://www.ecopetrol.com.co/wps/portal/Home/es/NuestraEmpresa/%C3%89tica%20y%20Transparencia/GestionDeRiesgos.

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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.

 

ii. Processes Risks: These are those 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: These are those risks that are at an operational level of detail and occur in our day-to-day activities and tasks.

 

Ecopetrol has also continued consolidating its 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.

 

Ecopetrol has 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 of the Company’s objectives relating to operations, strategy, reporting and compliance, through the appropriate risks management and ensuring the effectiveness of its controls and the scope of which includes its 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.

 

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 energy transition and decarbonization activities, expects to invest approximately US$ 600 million in the next three years in projects that aim to meet our mitigation targets. Additionally, Ecopetrol has set a shadow price on carbon at US$ 20/TCO2 in 2021, 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 the section entitled Business Overview—Environmental, Social and Governance (ESG) Strategies and Initiatives—Environmental sustainability 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 for ensuring long-term value creation, Ecopetrol has been conducting energy transition scenario analysis since 2018. These analyses are being updated and refined reflecting two elements: i) the acceleration of the transition in recent years given a reduction of costs of electrification and renewables earlier than expected, accompanied by increasing oil price volatility and decreased investment appetite in the hydrocarbon sector; and ii) decrease in the demand for oil & gas brought by the COVID-19 pandemic. We have assumed a peak oil scenario (globally in the late 2020s and in Colombia between the 2030s and 2040s), to reflect more ambitious actions and goals in the decarbonization path and to seize the opportunities of the transition. Our climate risk strategy is being aligned with the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD) and includes the addition of a new climate-related risk to our 2020 enterprise risks, in respect of inadequate management of climate change and water. This risk complements the risk of not responding to the new low carbon economy.

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See the section entitled Strategy and Market Overview—Our Corporate Strategy for more details about our energy transition roadmap.

 

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. In 2020, no such updates were provided.

 

Ecopetrol’s 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 Ecopetrol’s reputation on the internet. During 2020, Ecopetrol strengthened the SOC by incorporating updated capabilities, expanding the scope of services to Operational Technology (OT) digital assets, conducting redteam exercises and improving monitoring coverage. While there were cyber-attacks during 2020, every event 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.

 

Furthermore, during 2020, 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 adopted in 2020. The primary goal of the plan was to reinforce our cybersecurity culture and refine certain technical components of our cybersecurity program. Ecopetrol S.A. also recently updated its cybersecurity policies and cyber incidents response procedure which was tested in several wargames exercises covering all business segments and their subsidiaries.

 

During the first quarter of 2020, in response to the requirements derived from the COVID-19 pandemic, Ecopetrol S.A. updated its cybersecurity risk profile and its cybersecurity strategy, which now covers ensuring connectivity for teleworking, remote work and articulation with the migration into the cloud for critical applications and all of the Ecopetrol Group companies. Likewise, Ecopetrol S.A. strengthened its capabilities to monitor and response against malicious activities.

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Ecopetrol 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.

 

Finally, in order to update the cybersecurity strategy for 2021 to 2023, Ecopetrol S.A. formulated an approach to strengthen its cybersecurity program, in which the Cybersecurity Capability Maturity Model (C2M2) framework will be complemented with zero trust practices and a set of advanced protection controls for critical information (military grade), with focus on the reduction of cyber risk level in business units and the increase of the cultural awareness in cybersecurity terms.

 

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 and downstream segments) and either export crude oil at international market prices or sell refined products at prices that are correlated to international market prices. During 2020, 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. A total of 30 million barrels (mmbls) were the subject of strategic hedges oriented at protecting the Ecopetrol’s income and cash flow, limiting losses, covering production costs and avoiding potential closures of production fields; for this purpose. A total of 21.7 million barrels (mmbls) were the subject of tactical hedges oriented at mitigating risks associated with storage marketing strategies, anticipated purchases of raw materials, supply to refineries, international sales delivered at the destination port and exports of heavy fuel oil.

 

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, 2020, our U.S. dollar-denominated total debt principal was US$12.3 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 US$11.8 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 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.

 

Taking previous considerations into account, Ecopetrol seeks 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 incomes or investments in a foreign operation and debt denominated in foreign currency. The Company adopted hedge accounting as part of its risk management strategy, using two types of natural hedges with its 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, the Company 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, on October 2015, US$ 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. In June 2016, Ecopetrol continued its hedge accounting strategy, using the natural hedge between some of its foreign investments and its dollar-denominated debt in an amount of US$5.2 billion. Likewise, in November 2019 Ecopetrol hedged a new portion of the dollar-denominated debt against its new investment in the U.S. Permian Basin in an amount of US$0.93 billion and during 2020 Ecopetrol hedged US$1.22 billion with its foreign investments.

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As of December 31, 2020, the outstanding value of the natural accounting hedges was US$8.5 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 recognized directly in equity, as part of other comprehensive income. In addition, the Company entered into financial derivative instruments in order to mitigate the impact of exchange rate volatility on its financial statements by selling US dollars in order to fulfil Colombian peso denominated debt obligations.

 

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, which means that an appreciation of the Colombian peso against the U.S. dollar could generate a loss if companies whose functional currency is the Colombian peso have an active net 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 if companies whose functional currency is the Colombian peso have a net active position in U.S. dollars or a loss if they have a net liability position in U.S. dollars. 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). With the adoption of hedge accounting, the effect of volatility of foreign exchange rate on the effective hedged portion of the debt is recognized directly in equity, as part of other comprehensive income. Our hedge management strategy is completely focused on our accounting, reason why the ultimate effect will only be determined when the hedge operations come to an end.

 

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 and IBR (with a participation of 8.3%, 1.8%, 2.5% and 1.0%, respectively, of the nominal debt balance as of December 31, 2020). Thus, volatility in interest rates may affect the fair value of and cash flows related to our investments and floating rate debt. In 2020, our analysis of credit risk events and global financial markets drove us to decide not to hedge interest rate risk. Nevertheless, our capital markets office continuously monitors the performance of interest rates and the effect of interest rates on our financial statements.

 

The trust funds linked to Ecopetrol S.A.’s pension obligations (PAP for its acronym in Spanish) are also exposed to changes in interest rates, as they include fixed- and floating-rate instruments that are mark 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 the Decree 1833 of 2016 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 Plan assets to our consolidated financial statements.

 

Regarding liquidity risk, Ecopetrol 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.

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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 Ecopetrol’s 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.

 

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, 2020, Ecopetrol S.A. was a party to 5,361 legal proceedings relating to civil, criminal, administrative, environmental, tax and labor claims, of which 3,641 were filed against us in the Colombian courts and arbitration tribunals, of which 234 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.

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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 probatory stage.

 

The Regional Environmental authority of Norte de Santander, or Corporación Autónoma Regional de la Frontera Nororiental (CORPONOR) has filed a lawsuit against Ecopetrol at 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 legal counsel filed 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. Currently this lawsuit is in the evidentiary stage. In July 2020 the evidentiary stage closed and we are awaiting a ruling in the first instance.

 

Ecopetrol and national and local authorities convened 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 in the project as part of the strengthening of its contingency plans and its relationship with its stakeholders. On November 10, 2017, the relevant parties entered into an agreement with the purpose of building the alternative water supply at a cost of approximately COP$385 billion. According to the agreement Ecopetrol will be in charge of the construction of the above-mentioned infrastructure. As of the date of this annual report, Ecopetrol has awarded two construction contracts. For the initial segment of the project and a second construction contract for a subsequent segment is soon to be awarded. The corresponding auditing contract has also been awarded.

 

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 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 filed a motion requesting the judge to require the claimants to amend their claim to more precisely set forth the facts and evidence it believes establishes Ecopetrol’s liability.

 

On March 3, 2015, Ecopetrol 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 conciliatory hearing was held in order to seek an agreement, but it failed.

 

In January 2018, a judicial order was issued to commence the evidence gathering process, 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 briefs. As of the date of this annual report the case remained pending.

 

As of the date of this annual report, the claims have decreased to COP$7.3 trillion, as a result of the reconsideration of the amount initially requested and the inclusion of new claimants in the process.

 

PetroTiger

 

As highlighted in previous 20-F and 6-K filings, on January 6, 2014, the United States Department of Justice (DOJ) announced the unsealing of charges against two former co-chief executive officers (CEOs) and the former general counsel of PetroTiger Ltd. (PetroTiger), alleging, among other things, violations of the U.S. Foreign Corrupt Practices Act (FCPA) and conspiracy to commit violations of the FCPA and money laundering in connection with payments made to an Ecopetrol employee. By the time of the DOJ announcement, that employee no longer worked at the Company. The DOJ alleged the payments were made to secure Ecopetrol’s approval for PetroTiger’s entry into an oil services contract with Mansarovar Energy Colombia Ltd. Ecopetrol participated in the Mansarovar project as non-operating partner in a joint operating agreement. Also on January 6, 2014, the DOJ announced that the general counsel of PetroTiger had pled guilty on November 8, 2013, to one count of conspiracy to violate the FCPA and to commit wire fraud. One of the charged former co-CEOs pleaded guilty on February 18, 2014, to the same charge. On May 9, 2014, the DOJ charged the other former co-CEO with conspiracy to violate the anti-bribery provisions of the FCPA, conspiracy to commit wire fraud, conspiracy to launder money, and substantive FCPA anti-bribery and money laundering violations. On June 15, 2015, that co-CEO pleaded guilty to conspiracy to violate the FCPA.

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After the DOJ unsealed its charges on January 6, 2014, Ecopetrol filed a complaint the same month, jointly with the Transparency Secretariat of the Presidency of the Republic, to Colombia’s Attorney General’s office requesting the investigation of individuals who may have been involved in the wrongdoing related to the Mansarovar contract. Colombian authorities initiated a proceeding related to PetroTiger, and on March 11, 2015, arrested four current Ecopetrol employees and two former Ecopetrol employees related to their investigation of the Mansarovar project and five other contracts involving PetroTiger and Ecopetrol. To date, four investigations of the control entities continue in course. During 2017 and 2018 to date, Colombian authorities have resolved an appeal confirming the conviction of a former Ecopetrol employee and another person involved in the case but not linked with Ecopetrol. Likewise, two other appeals are in progress, one of them submitted by Ecopetrol and the Prosecutor’s Office in a case in which a former Ecopetrol employee was acquitted, and the other submitted by the defense attorney of a former Ecopetrol employee in a case in which the employee pleaded guilty.

 

Ecopetrol has responded to information requests from the DOJ and Colombian authorities in connection with their investigations of PetroTiger. Ecopetrol has been designated with the formal status of victim in the local Colombian proceedings. It has terminated the employment of the four charged individuals who were Ecopetrol employees at the time of the arrests. Ecopetrol has concluded an internal investigation and has not identified any new issues relating to PetroTiger.

 

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 four 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 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 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.

 

The foregoing implies that Ecopetrol, along with the National Agency for Legal Defense of the State (Agencia Nacional de Defensa Jurídica del Estado or ANDJE) and CENIT, need to recalculate the amount of the claims based on the decision of the Administrative Court of Cundinamarca.

 

Although the plaintiffs did not clearly determine the amount of their claims, Ecopetrol 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. However, based on the November 14, 2020 decision, Ecopetrol, ANDJE and CENIT, need to recalculate the amount of the claims.

 

As of the date of this annual report, the court has not yet set a hearing date.

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Foncoeco

 

On March 18, 2019, Ecopetrol received judicial notice of a lawsuit filed by workers and former workers seeking if 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 on behalf of Ecopetrol in 2011.

 

The lawsuit is in the evidentiary stage and on February 10, 2021, a hearing will be held to collect evidence, hear the parties’ final closing briefs and the court will issue the final ruling.

 

Environmental Administrative Proceedings

 

As of December 2020, Ecopetrol S.A. was party to 211 environmental administrative proceedings, of which 185 were initiated before 2020 and 26 during 2020. It is not possible for us to determine whether the pending proceedings could have a material effect on Ecopetrol. During 2020, 50 proceedings were concluded, in two of them we were subject to monetary fines through resolution 0710-0667 of 2020, in the aggregate amount of COP $265.836.101 and resolution 0052 of 2020, in the aggregate amount of COP$5.155.203.368, with the latter pending a final decision by the Environmental Authority.

 

Reficar Investigations

 

Reficar is a wholly owned subsidiary of Ecopetrol. 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 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 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 resources 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 potential crimes 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 Reficar’s expansion and modernization project (the Project), the Office of the Comptroller General initiated a special audit investigation of the Project in 2016 and delivered 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, on January 18, 2017, Reficar submitted an action plan addressing the 36 findings in the following areas: (i) contract management, (ii) supervision of engineering standards contracted with third parties, and (iii) documentation of the control, reporting and monitoring mechanisms of subcontracts.

 

1.2 As a result of the findings described above, on March 10, 2017, the Office of the Comptroller General opened actions for financial responsibility (proceso de responsabilidad fiscal) against 36 individuals and the six companies involved in the Project, including former members of Ecopetrol’s Board of Directors, former members of Reficar’s Board of Directors, former employees of Ecopetrol, 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.

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These actions were initiated based on the Office of the Comptroller General’s theory that lower than expected profitability at Reficar could have been caused by (i) modifications to the schedule and, (ii) the increase of the budget for the Project.

 

On June 5, 2018, the Office of the Comptroller General split the initial proceeding in two. 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.

 

Regarding the first proceeding, on June 5, 2018, the Office of the Comptroller General issued charges for financial responsibility (proceso de responsabilidad fiscal) against (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. Therefore, as of the date of this annual report, no current or former member of Ecopetrol’s Board of Directors was charged in the first proceeding related to the increase in the Project’s budget.

 

As of the date of this annual report, no charges have been issued in the second proceeding related to the modifications in the Project’s schedule.

 

While the content and status of the proceedings remains confidential, we can report that Reficar and several of its employees have cooperated with and provided the information required by the department of 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.

 

1.3 From 2017 until 2020 the Office of the Comptroller General has performed special financial audits in Reficar and has delivered final reports, in which it concluded that, in its opinion, Reficar’s financial statements from 2016 to 2019 do not reasonably represent the entity’s financial position as of the end of each year. This situation originates in the different interpretation, by Reficar and the Comptroller General, of the applicable accounting principles. Historically, Reficar’s external independent auditors have issued unqualified opinions on Reficar’s financial statements during and after the expansion and modernization project of the refinery. 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.

 

2. The Attorney General’s Office investigations:

 

Reficar has been officially informed that the Attorney General’s Office currently has four ongoing investigations related to the Project.

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Regarding one of these four investigations, on September 12, 2017, the Attorney General’s Office issued a list of charges against 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 Yanes (Reficar CEO, 2012-2016). The Attorney General’s Office closed the case against the rest of the members of Reficar’s Board of Directors and the rest of the former officers of Reficar.

 

On January 17, 2020 the Attorney General’s Office issued its judgment against Reyes Reinoso Yanes 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 filed an appeal against the decision and is awaiting resolution.

 

In another 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.

 

The specific content and status of the remaining two ongoing investigations remains confidential.

 

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 part of the Attorney General’s Office proceedings.

 

3. The Prosecutor’s Office investigations:

 

The Prosecutor’s Office has been conducting the following legal proceedings in which Ecopetrol 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 Yanes (Reficar CEO, 2012-2016); (iii) Felipe Laverde Concha (Reficar General Counsel, 2009-March 2017); (iv) Pedro Alfonso Rosales Navarro (Ecopetrol 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.

 

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 CEO, 2007-2015), Reyes Reinoso Yánez (Reficar CEO, 2012-2016), Pedro Alfonso Rosales Navarro (Ecopetrol Downstream Executive Vice President, 2008-2015), and Diana Constanza Calixto Hernández (Ecopetrol Head of the Corporate Finance Unit, 2009-2014). The arraignment hearing took place on August 5, 2019.

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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.

 

On January 27, 2020, during the indictment hearing, Ecopetrol and Reficar were recognized as victims.

 

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. The defense attorneys have not yet had an opportunity to present their case against such facts in a court of law.

 

Ecopetrol and Reficar have cooperated closely and extensively with the control entities in furthering their investigations and will continue to monitor the status and development of these investigations.

 

As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar and the current employees are not part of the above proceedings. None of the legal proceedings described in this paragraph are related with bribery charges.

 

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.

 

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 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 US$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 US$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 US$116 million and COP$387,558 million. On March 16, 2018, CB&I submitted its Exhaustive Statement of Counterclaim further increasing its claims to approximately US$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, US$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 Defence to Counterclaim increasing its claims to approximately US$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 US$137 million.

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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 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 the International Chamber of Commerce tribunal, 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 also 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 lifted on the arbitration was lifted on July 1, 2020.

 

On May 6, 2020, the Superintendence of Corporations 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. Until the Tribunal renders its final decision, 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.

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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) incomes 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 process, 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 process.

 

6. Shareholder Information

 

6.1 Shareholders’ General Assembly

 

Our Shareholders’ General Assembly was held on March 26, 2021 and the following matters were approved:

 

• The plan for distribution of the Company’s profits, which establishes the distribution of an ordinary dividend per share of seventeen Colombian pesos (COP$ 17), is as follows: a payment of 100% of the dividend to minority shareholders and the majority shareholder, to be made on April 22, 2021.
• The occasional reserve of COP$ 5.4 trillion in order to support the financial sustainability and flexibility of the Company in the development of its strategy.
• Amendment of our bylaws. For further information please see the section Corporate Governance—Bylaws.

 

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 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 will be April 22, 2021 for 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.

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On March 29, 2019, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 60% of our net income or COP$169 per share (within the dividend policy of 40% and 60% of net income), for the fiscal year ended December 31, 2018 and an extraordinary dividend of 20% of our net income or COP$56 per share, given our strong operational and robust cash position in 2018, for a total dividend per share of COP$225. On March 23, 2018, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 55% of our net income for the fiscal year ended December 31, 2017. On March 31, 2017, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 40% of our net income before the impairment of non-current assets (net of taxes) for the fiscal year ended December 31, 2016. See section Financial Review—Liquidity and Capital Resources—Dividends.

 

Ecopetrol 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.

 

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 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$ 275.0626 as of December 31, 2020) 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 Superintendence of Finance, 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 Superintendence of Finance to take place outside the BVC.

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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 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

7.375% Notes due 2043

5.875% Notes due 2045

 

Please refer to Exhibits 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, US$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 US$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 US$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);

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• 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);

 

• 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 2018, reimbursements were made in the amount of approximately US$2,062,050 for expenses related to investor relations activities. In 2019, reimbursements were made in the amount of approximately US$2,458,847. In 2020, reimbursements were made in the amount of approximately US$ 2,020,472.

 

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.

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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 (hereinafter “CTC”). For more information related to the Colombian dividends tax regime, see Risk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Information.

 

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 non-taxed 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 2019 onwards, a withholding tax on dividends paid applies as follows:

 

i. For resident companies and non-resident shareholders (companies and individuals): (i) a 10% dividend (7.5% for fiscal year 2019) 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); and (ii) 32% (33% for fiscal year 2019) withholding tax rate on dividends distributed from profits not taxed at the corporate level (31% for 2021 and 30% as of 2022), plus an additional 10% (7.5% for fiscal year 2019) dividend tax after applying the initial 32% withholding tax rate (i.e., 38.8% in 2020 = $100 *32% = $32, plus $68 * 10% = $6.8).

 

ii. For Colombian individuals: dividend income in excess of 300 UVT are taxed at a 15% and 10% rate, for fiscal years 2019 and 2020 (2021 onwards), respectively.

 

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

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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
• 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 5% 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 5% dividend tax or any other income tax. As of 2019, the withholding tax rates applicable to dividends paid to resident companies and non-resident shareholders (companies and individuals) are: (i) a 7.5% 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); and (ii) 33% withholding tax rate on dividends distributed from profits not taxed at the corporate level (32% for 2020, 31% for 2021 and 30% as of 2022), plus an additional 7.5% (10% from 2020 onward) dividend tax after applying the initial 33% (32%, 31% or 30%) withholding tax rate.

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Furthermore 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 5% dividend tax (7.5% in 2019 and 10% from 2020 onwards) applies on the balance of dividends to be distributed to the shareholder investing through an FFAA, or on the gross amount in such cases the dividend is paid out of profits that were subject to taxation at the corporate level. These foreign shareholders subject to this withholding tax are not required to file an income tax return in Colombia.

 

Taxation of Capital Gains from the Sale of ADSs

 

Capital gains obtained from the sale of ADSs by non-Colombian entities, Colombian individuals who are non-residents in Colombia and foreign non-resident individuals, are not subject to income tax in Colombia, as such sale does not generate Colombian-source income to the extent that the ADSs are not deemed to be sourced in Colombia. If the holder of the ADSs who is a non-resident entity, a Colombian individual who is not a resident in Colombia or a foreign non-resident individual, decides to surrender the ADSs and withdraw the underlying common shares, it is arguable that such transaction does not generate a capital gain subject to income tax in Colombia. However, different interpretations may be adopted by the Colombian Tax Authorities on this matter.

 

Tax Treatment in Colombia of a Non-Colombian Entity and a Non-Resident Individual of Colombia Who Purchases Ecopetrol’s Shares in Colombia’s Securities Market

 

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 as of 2020 was modified 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) 32% withholding tax rate on dividends distributed from profits not taxed at the corporate level (31% for 2021 and 30% as of 2022), plus an additional 10% dividend tax after applying the initial 32% withholding tax rate (i.e., 38.8% in 2020).

 

ii. Dividends paid to Colombian companies: (i) a 7.5% dividend tax on dividends distributed from taxed profits, or (ii) a 32% withholding tax on dividends distributed from non-taxed profits (31% on 2021 and 30% as from 2022), plus an additional 7.5% dividend tax on the balance of the dividend amount after the initial 32% withholding.

 

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

 

Non-resident entities or non-resident individuals whose investment qualifies as portfolio investment (i.e., investing through a FFAA), will be taxed upon distribution by means of the withholding tax mechanism. In this case withholding will apply at 25% on dividends that are distributed by the Colombian entity are not taxed at the corporate level. Pursuant to Article 18-1 of the Colombian Tax Code, assuming that the dividends cannot be attributed to a permanent establishment in Colombia belonging to the shareholder. These foreign shareholders subject to this withholding tax are not required to file an income tax return in Colombia, nevertheless those rules would not apply to foreign investments whereby the final beneficiary is a tax resident in Colombia who has control over such investments. This treatment was modified by Law 1943/2018 and Law 2010/2019. See section Financial Review—Effect of Taxes, Exchange Rate.

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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—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 years 2018 and 2019 (2020 – 32%; 2021 – 31%; 2022 onwards – 30%).

 

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 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.

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6.6.2 U.S. Federal Income Tax Consequences

 

This summary describes the principal U.S. federal income tax consequences of the ownership and disposition of common shares or ADSs, but it does not purport to be a comprehensive description of all of the U.S. tax consequences that may be relevant to a decision to hold or dispose of common shares or ADSs. This summary applies only to purchasers of common shares or ADSs who will hold the common shares or ADSs as capital assets for U.S. federal income tax purposes and does not apply to special classes of holders such as dealers in securities or currencies, holders whose functional currency is not the U.S. dollar, holders of 10% or more of our shares (taking into account shares held directly or through depositary arrangements) by vote or by value, tax-exempt organizations, financial institutions, holders liable for the alternative minimum tax, securities traders who elect to account for their investment in common shares or ADSs on a mark-to-market basis, partnerships or other pass-through entities or arrangements and investors therein, insurance companies, U.S. expatriates, persons that purchase or sell common shares or ADSs as part of a wash sale for tax purposes, and persons holding common shares or ADSs in a hedging transaction or as part of a straddle, conversion or other integrated transaction for U.S. federal income tax purposes. The statements regarding U.S. tax law set forth in this summary are based on the Internal Revenue Code of 1986, as amended, the “Code,” its legislative history, existing and proposed U.S. Treasury regulations, published rulings and court decisions, all as in force on the date of this annual report, and changes to such law subsequent to the date of this annual report may affect the tax consequences described herein (possibly with retroactive effect). This summary is also based in part on the representations of the Depositary and the assumption that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms.

 

Each holder is encouraged to consult such holder’s tax advisor concerning the overall tax consequences to it, including the consequences under laws other than U.S. federal income tax laws, of an investment in common shares or ADSs. In this discussion, references to a “U.S. Holder” are to a beneficial owner of a common share or an ADS that is for U.S. federal income tax purposes (1) an individual citizen or resident of the United States, (2) a corporation, or any other entity taxable as a corporation, organized under the laws of the United States, any state thereof or the District of Columbia, (3) an estate whose income is subject to U.S. federal income tax regardless of its source, or (4) a trust if (i) a United States court can exercise primary supervision over the trust’s administration and one or more United States persons are authorized to control all substantial decisions of the trust or (ii) it has in effect a valid election under applicable U.S. Treasury regulations to be treated as a U.S. person.

 

For U.S. federal income tax purposes, holders of ADSs generally will be treated as owners of the common shares represented by such ADSs.

 

This discussion does not address any aspect of U.S. federal taxation other than U.S. federal income taxation (such as the estate and gift tax or the Medicare tax on net investment income). Holders of common shares or ADSs should consult their own tax advisor regarding the U.S. federal, state and local and other tax consequences of owning and disposing of common shares and ADSs in their particular circumstances.

 

Distributions on Common Shares or ADSs

 

A distribution to U.S. Holders made by us of cash or property with respect to common shares or ADSs generally will be treated as a dividend for U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Distributions in excess of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, will be treated first as a tax-free return of capital reducing such U.S. Holder’s adjusted tax basis in the common shares or ADSs. Any distribution in excess of such adjusted tax basis will be treated as capital gain and will be either long-term or short-term capital gain depending upon whether the U.S. Holder held the common shares or ADSs for more than one year. Distributions of additional common shares or ADSs to U.S. Holders that are part of a pro rata distribution to all of our shareholders generally will not be subject to U.S. federal income tax. We do not maintain calculations of our earnings and profits under U.S. federal income tax principles, and, therefore, except as described in the previous sentence, U.S. Holders should expect that any distributions generally will be reported as dividends for U.S. federal income tax purposes. As used below, the term “dividend” means a distribution that constitutes a dividend for U.S. federal income tax purposes. The amount of any distribution will include the amount of any Colombian tax withheld on the amount distributed, and the amount of a distribution paid in Colombian Pesos will be measured by reference to the exchange rate for converting Colombian Pesos into U.S. dollars in effect on the date the distribution is received by the Depositary (or by a U.S. Holder in the case of a holder of common shares) regardless of whether the payment is in fact converted into U.S. dollars. If the Depositary (or U.S. Holder in the case of a holder of common shares) does not convert such Colombian Pesos into U.S. dollars on the date it receives them, generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend payment is included in income to the date the payment is converted into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income (as discussed below). The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.

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If you are a non-corporate U.S. Holder, dividends that constitute qualified dividend income will be taxable to you at the preferential rates applicable to long-term capital gains, provided that you meet certain holding requirements. Dividends paid on the ADSs will be treated as qualified dividend income if (1) the ADSs are readily tradable on an established securities market in the United States and (2) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a passive foreign investment company (PFIC). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States, as long as they are so listed. Based on our audited financial statements and relevant market and shareholder data, we believe that we were not treated as a PFIC for U.S. federal income tax purposes with respect to our 2020 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 2021 taxable year. However, this conclusion is a factual determination that is made annually and thus may be subject to change. Based on existing guidance, it is not clear whether dividends received with respect to the common shares will be treated as qualified dividends. 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 will be entitled, subject to a number of complex limitations and conditions, to claim a U.S. foreign tax credit in respect of any Colombian income taxes withheld on dividends received on common shares or ADSs. U.S. Holders who do not elect to claim a credit for any foreign income taxes paid during the taxable year may instead claim a deduction in respect of such Colombian income taxes, provided the U.S. Holder elects to deduct (rather than credit) all foreign income taxes for that year. Dividends received with respect to the common shares or ADSs will be treated as foreign source income, subject to various classifications and other limitations. For the purposes of the U.S. foreign tax credit limitations, the dividends paid with respect to our common shares or ADSs generally will constitute “passive category income” for most U.S. Holders. The rules relating to computing foreign tax credits or deducting foreign income taxes are extremely complex, and U.S. Holders are urged to consult their own independent tax advisers 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.

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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.

 

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

 

Payments in foreign currency with respect to certain foreign exchange transactions including international investments between Colombian residents and non-Colombian residents must be conducted through the foreign exchange market. Therefore, any foreign currency income or expense under the ADRs must be completed through the appropriate channels of the foreign exchange market. Transactions conducted through the foreign exchange market are made at market rates freely negotiated with authorized foreign exchange intermediaries (local banks, financial corporations, administrators and others) or using a bank accounts opened abroad and registered as compensation account 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.

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Foreign portfolio investments must be made through authorized foreign exchange investment management companies. Only brokerage firms, trust companies and investment management companies, subject to the inspection and supervision of the Superintendence of Finance, are allowed to make investments in the local Colombian 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 and foreign exchange purposes.

 

Colombian law provides that the Colombian Central Bank may intervene in the foreign exchange market at its own discretion at any time (i.e., it may limit the remittance of dividends whenever the international reserves fall below an amount equal to three months of imports). Additionally, from time to time, the Colombian government introduces amendments to the International Investment Statute. Hence, we cannot assure you that the Colombian Central Bank will not intervene in the future imposing restrictions to the free convertibility system currently applicable in Colombia. See section Risk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Environment.

 

Registration of Foreign Investment Represented in Underlying Shares

 

Colombia’s International Investment Statute and the regulations issued by the Colombian Central Bank, which have been amended from time to time through related 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 mandate 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 (yearly or monthly, depending on the type of information).

 

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 financial sanctions.

 

Notwithstanding the regulations described above, foreign investors who acquire ADRs are not required to directly register this investment with Colombian authorities. 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 must register these operations with the Colombian authorities and comply with applicable regulations through its Colombian brokerage firm.

 

In 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.

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6.8 Exchange Rates

 

On April 5, 2021, the Representative Market Exchange Rate was COP$ 3,679 per US$1.00. The Federal Reserve Bank of New York does not report a noon-buying rate for Colombian Pesos. The Superintendence of Finance 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 Superintendence of Finance 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 at March 31, 2021:

 

Table 63 – Major Shareholders

 

    As of March 31, 2021  
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 16, 2021, the registration date of our annual general shareholders’ meeting, 1.39% of our common shares were held of record in the form of American Depository Shares, we had 38 registered holders, and 13,048 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.

 

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. PSAA15-10392, 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 that were located in Colombia at the time the suit was filed;

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• 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;
• 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 is 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 be collected 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.:

 

• Promote and guarantee all stakeholders transparency, objectivity and competitiveness;
• Add value to the company and attract investors;
• Protect shareholders, investors and stakeholders’ rights;
• Encourage financial markets confidence; and
• Accomplish the highest corporate governance standards.

 

Corporate Governance System

 

Corporate governance is the system of rules and practices that govern the decision-making process 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.

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Our model is structured based on the law, international standards, good practices and the strategy of the Ecopetrol Group, in order to ensure 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 and the Ecopetrol Group companies.

 

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
a. Promote best management practices in the Boards of Ecopetrol and in the other Ecopetrol Group’s companies.
b. Ensure alignment of the strategy under the Ecopetrol Group’s management by segments.

 

ii. Senior Management Committees
a. Establish the structure of the Senior Management Committees (operating, monitoring and improvement mechanisms).
b. Optimize Ecopetrol senior management time.

 

iii. Matrix of Decisions and Attributions
a. Define the key or more relevant decisions of the Ecopetrol Group.
b. Establish which governing bodies are responsible for making key decisions.
c. Define how these decisions are made.

 

iv. Relationship Model
a. Establish the way in which the areas within the Ecopetrol Group’s scope are related to the Ecopetrol Group’s companies.
b. Capture the Ecopetrol Group’s synergies.
c. Manage articulation through management or administration by segments.

 

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:

 

• Composition of Board of Directors: including in its list of candidates a Representative for hydrocarbon producing departments operated by Ecopetrol and a Representative for the minority shareholders, who will be chosen by the 10 shareholders with the largest stock participations. According to corporate governance practices recommended by the OECD, an organization to which Colombia has been a member since 2018, the Government implemented the practice of eliminating the participation of Directors with a ministerial level in the company’s Board of Directors. Therefore, in 2019 the Government nominated one (1) non-independent Director without ministerial rank. The current Board of Directors is composed by eight (8) independent members and one (1) non-independent member.

 

• Dividend policy: guaranteeing the right of each shareholder to receive his pro rata dividends in accordance with Colombian law.

 

• 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 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. In addition, the bylaws were amended in the ordinary meeting of the General Shareholders Assembly held on March 26, 2021. The text of the amended bylaws is yet to be recorded in public deed and registered before the mercantile registry, which in Colombia corresponds to the Chamber of Commerce. 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 the 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 30 calendar days prior to the date on which the meeting will take place and 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. 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.

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Decisions made at ordinary and extraordinary shareholders’ meeting must be approved by a plural number of shareholders representing the majority of the shares present. Colombian law requires higher majorities in the following cases:

 

• The vote of at least 70% of the shares present and entitled to vote at the ordinary shareholders’ meeting is required to approve the issuance of stock not subject to preemptive rights;

 

• The vote of at least 78% of the shares represented entitled to vote is required to approve the distribution of the annual net profits. In the absence of this special majority, at least 50% of the net profits must be distributed. If the sum of all legal reserves (statutory, legal and optional) exceeds the amount of the outstanding capital, the Company must distribute at least 70% of the annual net profits;

 

• The vote of at least 80% of the shares represented is required to approve the payment of dividends in shares; and

 

• The vote of 100% of the outstanding and issued shares is required to replace a vacancy on the Board of Directors without applying the electoral quotient system.

 

Shareholders may be represented by proxies, provided that the proxy: (i) is in writing (faxes and electronic documents are valid), (ii) specifies the name of the representative, (iii) specifies the date or time of the meeting for which the proxy is given and (iv) includes other information specified by the applicable law. Proxies granted abroad do not require legalization or an apostille.

 

During our ordinary annual shareholders’ meeting, our employees and Directors are only allowed to represent their own shares, unless they act as legal representatives.

 

In 2020, due to the exceptional situation arising from the COVID-19 pandemic, our annual shareholders’ meeting was held virtually for the first time. However, our shareholders were able to follow the meeting through our website and the live broadcast on the National Institutional Channel. We had 2,198 connections via streaming and 134,058 viewers through the National Institutional Channel.

 

To facilitate the correct representation of its shareholders, Ecopetrol, after review and authorization by the Financial Superintendence of Colombia and the Superintendence of Corporations, provided a digital proxy system through which our shareholders were represented by attorneys provided by the Company, and enabled them to submit their voting decisions. The instructions for the use of this system, the list of proxies, and the forms, were available on our website.

 

Our 2021 annual shareholders’ meeting was held in the same way. Additionally, to guarantee the active participation and rights of the shareholders, the Company provided channels for the submission of proposals that were included in the agenda and a virtual and in-person system to inspect our books and documents. For the 2021 meeting, there were 2,388 connections via streaming and 122,630 viewers through the National Institutional Channel.

 

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.

 

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;

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• 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 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 selected 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 selected by the ten largest minority shareholders. The minority shareholders’ right to select 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 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 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.

 

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.

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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 Superintendence of Finance. 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 two (2) years and may be reelected consecutively for two (2) periods, and it may once again be hired after one (1) period away from the position.

 

7.2 Code of Ethics and Conduct

 

Our recently updated 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.

 

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.

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Our Code of Ethics and Conduct is available on our website at:

https://www.ecopetrol.com.co/wps/portal/Home/en/Ourcompany/Ethics%2C%20Transparency%20and%20Compliance%20Program/Code%20of%20Ethics%20and%20Conduct%20of%20the%20Ecopetrol%20Business%20Group

 

7.3 Board of Directors

 

The current Board of Directors was elected at the General Shareholders Ordinary Meeting held on March 26, 2021, for a two-year term beginning on April 9, 2021.

 

The current Board of Directors is composed as follows:

 

Non-independent member:

 

• Germán Eduardo Quintero Rojas.

 

Independent members:

 

• Cecilia María Vélez White
• Luis Guillermo Echeverri Vélez
• Juan Emilio Posada Echeverri
• Sergio Restrepo Isaza (as financial-accounting expert)
• Luis Santiago Perdomo Maldonado
• Esteban Piedrahita Uribe
• Hernando Ramírez Plazas (nominated by the oil producing departments in which Ecopetrol operates)
• Carlos Gustavo Cano Sanz (nominated by ten (10) minority shareholders with major 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 March 26, 2021 for a two-year term beginning on April 9, 2021:

 

Germán Eduardo Quintero Rojas has served as General Director of Fogafin, President of the National Hydrocarbons Agency, Secretary General of of the Ministry of Mines and Energy, Interior and Finance and Public Credit, as well as Secretary General and Advisor to the Ministry of Commerce, Industry and Tourism, and Advisor to the Secretary General of the Office of the President of the Republic of Colombia. He has also served as Director General and Secretary General of Acción Fiduciaria S.A. and Head of the Legal Office of the Ministry of Finance of Public Credit, among other positions in the public and private sectors. He is an attorney with a degree from Sergio Arboleda University, and studies in Administrative Law from Javeriana University. He also carried out studies for a doctorate in an administrative law program from San Pablo CEU University of Madrid, where he was a doctorate candidate. He was a member of the drafting commission of the current Code of Administrative Procedures and Administrative Litigation. He has been a member of several top-level national Boards of Directors, highlighting his directorship in Ecopetrol (2019-January 2021) and the Financiera de Desarrollo Nacional (FDN) as well as his service as Chairperson of the Boards of Directors of Bancoldex S.A., Gecelca S.A. E.S.P., Urrá S.A. and Cisa, among others. He is a current Director of the Board of Directors of FDN and is Legal Secretary to the Office of the President of the Republic. Mr. Quintero is a non-independent member of the Board of Directors of Ecopetrol S.A.

 

Cecilia María Vélez White has extensive professional experience, having occupied the following positions in the public sector: Minister of Education of Colombia, Secretary of Education of Bogota, Minister Counselor for Economic Affairs at the Embassy of Colombia in the United Kingdom, Deputy Director and Head of the Territorial Development Unit at the National Planning Department, Head of Planning of the Urban Development Fund at Banco Central Hipotecario, and Deputy Director of Planning at Banco de la República (National Central Bank). She has served as Dean of Universidad Jorge Tadeo Lozano and was Visiting Professor at the Graduate School of Education at the same University. She studied Economics at Universidad de Antioquia from 1972-1976 and received her degree from Universidad Jorge Tadeo Lozano in 1977. She also holds a Master’s degree in Economics from the University of Louvain in Belgium and was a Fellow at the Special Urban and Regional Studies program (SPURS) at Massachusetts Institute of Technology (MIT) in Boston. She is currently a member of several Boards of Directors and Advisory Boards, including: Suramericana de Seguros, Fedesarrollo, Eafit, Fundación Luker, United Way, and Empresarios por la Educación. She assists on the Advisory Board of the Harvard Ministerial Leadership Program and provides advisory and consulting services. Mrs. Vélez is an independent Director of the Board of Directors of Ecopetrol S.A.

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Luis Guillermo Echeverri Vélez has over 30 years of experience in the development, marketing, stimulation and performance of international business, exports and imports and in the preparation and implementation of public and corporate policies, the development and implementation of conventional projects as well as those relating to information technology, strategic planning, financing of public and private projects and the obtainment of funds and resources. His professional practice includes experience as an international business advisor. He served as Executive Director of the Inter-American Development Bank, the Inter-American Investment Corporation and the Multilateral Investment Fund on behalf of the Governments of Colombia, Peru, and Ecuador. He was Director and Founder of various companies and large projects between 2000 and 2010. He served as Commercial Attaché in Colombia´s Diplomatic Mission to the US and Director of the Regional Office of Proexport (now ProColombia) in Miami. Mr. Echeverri is an attorney with a degree from Universidad Pontificia Bolivariana de Medellín and also holds a Master in Agricultural Economics from Cornell University in New York. In his position as international business advisor, he has successfully directed business initiatives as well as change, innovation, methodological and technological implementation processes in various companies and organizations. He successfully managed the presidential campaign of Iván Duque Márquez, present President of the Republic of Colombia. Currently, Mr. Echeverri is President of the Asociación Primero Colombia, a nonprofit think tank dedicated to promoting democratic values and youth leadership; former Chairperson and member of the Board of Directors of the Chamber of Commerce of Bogotá and member of the Board of Directors of Telefónica, Pragma and Colmédica. He serves as an independent Director and Chairperson of the Board of Directors of Ecopetrol S.A.

 

Juan Emilio Posada Echeverri has been a Board Member and Advisory Council Member for many public and private, both profit and nonprofit organizations in the areas of infrastructure, air transportation, hospitality, national defense, banking, insurance, securities brokerage, telecommunications, technology, media, education, children’s rights, chambers of commerce and business associations, as well as in a Latin American youth orchestra and a national competitiveness program, in which he led the private portion of the initiative. He has held senior management positions at Billiton M & T (then a subsidiary of Royal Dutch Shell Group) in the Netherlands as well as Banco Cafetero in New York and Miami, where he also served as International Vice President and was responsible for its subsidiaries and investments in seven countries. Founder, Executive Chairperson and CEO of Grupo Fast S.A. and Fast Colombia S.A.S. - VivaAir (formerly VivaColombia, the first low cost airline in Colombia); Founder and CEO of Stratis Ltda. (infrastructure projects); Corporate Director of Synergy Aerospace; CEO of Avianca Airlines, Alianza Summa (Avianca-Aces-Sam) and Aces Airlines; CEO of Puerto Brisa, a deep water mega-port in Colombia; Executive Chairperson of Táximo Ltd, Chairperson of Direktio and Fundación Plan; Director of Allianz Life and Allianz General in Colombia; Board member of Avianca Holding and Sociedad Hotelera Tequendama (seven hotels in Colombia), Plan International (Brazil) and member of the Nominating and Governance Committee of Plan International’s Global Assembly, as well as, a member of the Advisory Councils of Grupo Empresarial del Sector Defensa (GESED), Disán (international fertilizer and chemical products trading company), Flores de la Campiña (producer and exporter of fresh flowers), YPO Gold Colombia (global CEO network), NT3 (real estate project developers), Polymath Ventures, AMROP-Top Management and the Orchestra of the Americas (Washington D. C.). He has been actively involved in fourth industrial revolution ventures and a middle-class housing construction firm. He holds a degree in Business Administration from EAFIT University in Medellin, Colombia, an MBA in International Business and Finance from Pace University in New York graduating with honors in international academic excellence, and a degree in International Finance Law from the London School of Economics. Due to his experience in audit and risk matters, he has been called upon to participate in the finance and audit committees of several different Boards of Directors, including that of the Banco Nacional del Comercio, Corredores Asociados (a stock brokerage firm in Colombia), and is held in high regard by the financial sector in general. He has received numerous awards such as the Cruz de Boyacá, Grado Gran Cruz, EY’s 2016 Emerging Entrepreneur Award, multiple medals from the Colombian Armed Forces and 10 Best Junior Chamber of Commerce Executives, among others. The companies under his leadership have also received awards and recognitions in service and quality, such as the Portafolio Award for Service, and recognitions from Fenalco Antioquia, Cotelco and the Government of Antioquia. Currently, he has a consulting agreement with the International Cooperation Agency, United Nations Development Program (UNDP), is a member of the Board of Directors of Financiera de Desarrollo Nacional (FDN) and of Sociedad de Acueducto de Alcantarillado y Aseo de Barranquilla S.A. E.S.P. and is an independent Director of the Board of Directors of Ecopetrol S.A.

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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 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, having served as member of several audit and risk committees during in different companies his time in the financial sector, where he played an active role in the analysis of financial information and was also responsible for investor relations. Currently he is 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. Mineros S.A. and Consorcio Financiero. He is an expert in financial, auditing and business risk matters and an independent Director of the Board of Directors of Ecopetrol S.A.

 

Luis Santiago Perdomo Maldonado has over 40 years of experience in the Colombian banking industry, having 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 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 serves as CEO of Grupo Mercantil Colpatria S.A. He has been a member of the Boards of Directors of Colegio de Estudios Superiores (CESA), Fundación de Cirugía Reconstructiva (CIREC) and the Plenary Council of Gimnasio Moderno, as well as having 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.

 

Esteban Piedrahíta Uribe is currently Chairperson of the Chamber of Commerce of Cali. He previously held the positions of 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 and General Manager of Endriven Colombia/Gas Meridional S.A.S. E.S.P., among others. He has been a member of the Boards of Directors of Banco Agrario, Carvajal Educación and Alianza Valores, and a member of the Advisory Council for Colombia at The Nature Conservancy. 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 a member of the Boards of Directors of Fedesarollo, Cementos Argos, Centro de Eventos Valle del Pacífico, and of the Advisory Council of the Fundación Panthera, and is an independent Director of the Board of Directors of Ecopetrol S.A.

 

Hernando Ramírez Plazas has been the Dean of the School of Engineering, Academic Vice-Rector, Rector and Professor at Universidad Sucolombiana. He worked at the National Institute of Health and the Ministry of Health and served as external evaluator of Colciencias in technological development and innovation projects in the area of natural gas. He also participated as a trainer in gas issues for the production staff at Canacol Energy. He holds a degree in Chemical Engineering from the Universidad Nacional de Colombia, a master’s degree in Public Health from the same university and a Specialist degree in Gas Engineering from the Universidad de Zulia (Venezuela). Currently, he is an independent Director of the Board of Directors of Ecopetrol S.A. nominated by the Hydrocarbon Producing Departments since March 23, 2018.

 

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 Minister of Agriculture in the administration of President Álvaro Uribe, between August 7, 2002 and February 3, 2005, and Director of Banco de la República between February 4, 2005 and January 31, 2017. He is currently a Professor at Universidad de los Andes, member of the Board of Trustees of Universidad EAFIT in Medellín, of the Advisory Committee for Agriculture at Bancolombia, of the Advisory Council for Colombia of The Nature Conservancy (TNC) and of the Board of Directors of Minka S.A.S. 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, Vice Chairperson of said Board of Directors and Chairperson of its Business Committee. His latest published book is “Mi paso por el Banco: Desaprendiendo y aprendiendo” published by Banco de la República and Universidad de Ibagué on March 2020.

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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, our majority shareholder must include, in its list of candidates 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 filled either by person or by position, (ii) at least three members appointed for a specific period must be nominated for the following period, and (iii) beginning in 2019, Directors will be elected for a two-year term. Currently, we have one Director appointed by his position without Ministerial rank. Our current Directors were elected at the General Shareholders Assembly held on March 26, 2021. Members of the Board may be reelected indefinitely.

 

Our CEO is appointed by the Board of Directors and will have at least two alternates. The CEO is elected for a two-year term, may be reelected indefinitely and freely removed prior to the expiration of his term. In accordance with our bylaws, the Board of Directors must evaluate the annual performance of the CEO, and such results must be published in Ecopetrol’s web page or in an alternative media vehicle.

 

The compensation 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 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.

 

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 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.

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Table 64 – Composition of committees of the Board of Directors as of March 26, 2021*

 

Audit and Risk Committee

 

Remuneration, Appointments and Culture Committee

Sergio Restrepo Isaza
(President and Financial Accounting Expert) 		  Juan Emilio Posada Echeverri
(President)
Hernando Ramírez Plazas   Santiago Perdomo Maldonado
Santiago Perdomo Maldonado   Germán Eduardo Quintero Rojas**
Juan Emilio Posada Echeverri   Esteban Piedrahita Uribe
    Orlando Ayala Lozano
     

Corporate Governance and Sustainability Committee*

 

New Business Committee

Esteban Piedrahita Uribe
(President) 		  Carlos Gustavo Cano Sanz
(President)
Orlando Ayala Lozano***   Hernando Ramírez Plazas
Carlos Gustavo Cano Sanz   Sergio Restrepo Isaza
Juan Emilio Posada Echeverri   Juan Emilio Posada Echeverri
Luis Guillermo Echeverri Vélez   Esteban Piedrahita Uribe
     

HSE Committee

 

Technology and Innovation Committee

Hernado Ramírez Plazas
(President) 		  Luis Guillermo Echeverri
(President)
Carlos Gustavo Cano Sanz   Orlando Ayala Lozano***
Germán Eduardo Quintero Rojas**   Germán Eduardo Quintero Rojas**
    Sergio Restrepo Isaza
    Carlos Gustavo Cano Sanz
    Santiago Perdomo Maldonado

 

 
* The composition may be modified after this annual report in accordance with the election of the Board of Directors at the General Shareholders Ordinary Meeting on March 26, 2021.
** Member of this Committee since April 2019 until January 12, 2021. He was elected again at the General Shareholders Ordinary Meeting on March 26, 2021.
*** Not elected to the Board of Directors at the General Shareholders’ Ordinary Meeting on March 26, 2021. Replacement will be elected to the Committee after this annual report.

 

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, environment 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.

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Remuneration, Appointments 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 compensation of our executive officers and employees, and within the framework of the Ecopetrol Group’s strategy, oversee 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, 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.

 

New Business Committee

 

Our new 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 business 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 starting 2020.

 

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 eight independent Directors and one non-independent Director without Ministerial rank.

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NYSE Standards

 

Our Corporate Governance Practices

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. Except for our audit and risk committee, our Board of Directors does not meet 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.
     

Compensation Committee

   
A compensation 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 compensation committee composed entirely of independent directors. Pursuant to our board charter, this committee shall be composed of a majority of independent Directors.
     

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 must have an audit committee that satisfies the requirements of Law 964 of 2005, including its minimum number of members, independence criteria and audit related duties. Our audit and risk committee is composed entirely of independent Directors, and the committee meets the requirements of Law 964 of 2005 and Rule 10A-3 under the Exchange Act.
     

Equity Compensation Plans

   
Equity compensation plans and all material revisions thereto require shareholder approval, subject to limited exemptions. §§303A.08 and 312.03.   Under Colombian law, no similar right to vote on equity compensation plans and material revisions thereto is given to shareholders. We do not give our shareholders the right to vote on equity compensation plans and material revisions thereto.
     

Listed companies must adopt and disclose corporate governance guidelines. §303A.09.

 

The Superintendence of Finance 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.

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NYSE Standards

 

Our Corporate Governance Practices

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 Bayon Pardo has served as the Chief Executive Officer of Ecopetrol since 2017. Prior to this, Mr. Bayón served as Chief Operating Officer of Ecopetrol since February 2016, overseeing the upstream, midstream, downstream, technology, projects and marketing operations, as well as the research and innovation areas. With over 29 years of experience in the oil and gas industry, Mr. Bayón has led Ecopetrol’s transformation process, TESG strategy and he has managed to position Ecopetrol in strategic basins in the United States, Brazil and Mexico. For more than 20 years, he worked 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), and, prior to 2005, he worked in BP’s headquarters as Chief of Staff to the Upstream CEO and Head of the Executive Office for Exploration and Production. He began his career in 1995 in BP Colombia, as a Project Engineer, where he held various positions until becoming Vice-President of Operations in Colombia. Prior to this, he worked for Shell.

 

Alberto Consuegra Granger has served as Chief Operating Officer of Ecopetrol since March 1, 2019. Prior to this role, he was interim CEO of Cenit S.A.S., Ecopetrol’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, he was Vice-President of Exploration and Production at Equión 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 Cerrejon 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.

 

Jaime Caballero Uribe has served as the Chief Financial Officer of Ecopetrol since August 2018. Mr. Caballero has over 20 years of international experience in the oil and gas 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 (Bogotá), 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 the Development and Production Vice-President of Ecopetrol since March 1, 2019. Prior to his current assignment, he served as Regional Development and Production Vice-President from June 2017 to February 2019. He holds a degree in chemical engineering from the National University of Colombia and has over 31 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 Operations Manager, Senior Operations Manager in Major Projects, Technical Director and Operations Excellence Director, among other leadership positions including managerial positions in Colombia, Trinidad & Tobago and Indonesia.

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Jorge Arturo Calvache Archila has served as Vice-President of Exploration since February 1, 2019. He has more than 35 years of experience. He has served in companies such as Shell and Hocol, where he led exploration projects in the Netherlands, the United States and Colombia. Mr. Calvache holds a degree in geology from Universidad Nacional, post-graduate studies in geophysics from the same university, and studied management at the Universidad de Los Andes.

 

Jurgen Gerardo Loeber Rojas has served as the Projects & Engineering Vice-President of Ecopetrol since May 2016. Mr. Loeber holds a degree in business administration from the Universidad del Norte and a specialization in project management. He joined the Army Corps of Engineers as reserve officer and reached the rank of captain. He has over 30 years of experience in the oil and gas industry. He began his career in 1985 in Exxon as financial analyst. From 1992 to 2001, he worked for BP in various countries as project manager, construction manager and project control engineer. For the last 10 years, he worked at Equión Limited (formerly BP Exploration Colombia) as Project Director. From 2001 to 2006, he was Project Director for Wood Group Colombia.

 

Pedro Fernando Manrique Gutierrez has served as the Commercial and Marketing Vice President of Ecopetrol since April 2017. He is also a member of the Cartagena refinery, Cenit and Invercolsa’s board of directors. He holds a bachelor’s degree in electrical engineering from the Industrial University of Santander, 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 30 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, with his last assignment being 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 has also worked at Enron Energy Services as a Risk Manager and at Enron International as a Business Development Manager, each based in Houston, Texas.

 

Héctor Manosalva Rojas has served as CEO of Cenit S.A.S., Ecopetrol’s midstream subsidiary, since March 1, 2019. He joined Ecopetrol 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, 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 at the Universidad de los Andes.

 

Juan Manuel Rojas Payán has served as Corporate Vice-President for Strategy and Business Development since August 2018. Prior to his appointment, he served as Corporate Manager for New Business since 2016. He graduated with a degree in Economics from Universidad de los Andes and holds a master’s degree in Public Policy from Harvard University and a master’s degree in Economics from Universidad de los Andes. Previously he was Vice-Minister of Mines and Energy, Chief Executive Officer of Bridas Corporation, Manager of New Business at Pan American Energy, and Director of Energy at Sideco Americana/Socma, among other positions. He has been a member of the boards of directors of different utilities companies in various countries, a petrochemical company, and of oil and gas companies in Latin America. In addition, he worked as a consultant for the energy industry in Asia, Africa and Latin America. In the academic field, he has been professor of the master of public policy program at the University Torcuato di Tella in Argentina and the professor of history of economic thought at the University of the Andes in Colombia.

 

Yeimy Báez has served as Gas Vice-President since March 2020. In this position, Ms. Báez is responsible for leading, strengthening and executing an integrated strategy to develop natural gas, LPG, biogas and hydrogen, which being clean energy sources are fundamental for energy transition and the Ecopetrol Group’s sustainability. She has over 17 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. She holds a degree in Petroleum Engineering from the Industrial University of Santander, an MBA degree from Externado of Colombia University and is highly-skillful in Project Management (PMP certified). Prior to her current assignment, she served for recognized players in the industry such as Equión, BP and Weatherford.

191

 

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 Equión, 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 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, 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 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.

 

Mónica Jiménez González has served as Secretary General of Ecopetrol S.A. since July 2016. Monica leads the corporate affairs of the company which includes heading the corporate governance initiatives for Ecopetrol and its group of companies, the company’s Corporate Responsibility programs, and Ecopetrol’s corporate communications. Ms. Jiménez holds a law degree from University of the Andes (Bogotá) and has practiced as a foreign lawyer in Canada. She worked as a lawyer in a boutique law firm that specialized in international law and then in a major Canadian law firm in Vancouver, BC. Ms. Jimenez has practiced in Colombia and Canada on matters related to corporate social responsibility (ESG), corporate law and international arbitration. She holds a post-graduate degree in Civil and State Responsibility from the Universidad Externado de Colombia and a Master of Science in Development Studies from the London School of Economics and Political Science. She has extensive experience as counsel and tribunal secretary in commercial and investment arbitrations under the rules of the ICC, ICSID and UNCITRAL. Ms. Jimenez is also a Member of the International Court of Arbitration of the International Chamber of Commerce (ICC).

 

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. 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.

 

Alejandro Arango Lopez 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.

192

 

Andres Eduardo Mantilla Zarate has served as the Director of the Colombian Petroleum Institute of Ecopetrol (ICP), the technology development and innovation center of the company, since September 2013. He holds a degree in Petroleum Engineering from Universidad Industrial de Santander, Colombia, a Master of Science degree in Petroleum Engineering from Stanford University, and a Ph.D. in Geophysics from Stanford University. His professional work includes the leadership and management of the teams for development, demonstration and implementation of energy and environmental technologies. In the last three years, he has reoriented the ICP efforts towards the exploration and development of technological solutions to take advantage of the energy transition, adapt and mitigate climate change, protect and strengthen biodiversity, and the protection and responsible use of water. He had previously worked for Ecopetrol holding various positions between 1994 and 2006. Before rejoining Ecopetrol in 2013, he worked for BP Colombia, Marathon Oil Company and Maersk Oil. During his professional career, he has had exposure to exploration and production projects and the evaluation of new ventures in Colombia, the Gulf of Mexico, the North Sea, West Africa, South America and the Middle East.

 

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.

 

Carlos Andrés Santos Nieto has served as Vice-President of Supply and Services since July 23, 2018. Prior to his appointment as Vice-President of Supply and Services, he was Procurement and Supply Chain Manager at Ecopetrol. Mr. Santos is an economist from Universidad Externado de Colombia and holds a postgraduate degree in international economics from the same institution and a college diploma course in advanced negotiations from Universidad CESA, and has completed other negotiations training provided by BP in Colombia, Alaska and London. Prior to joining the Company, he served as Offshore Business Unit General Manager in Coremar Group and Procurement & Supply Chain Manager Drilling, Wells, Subsurface and Offshore in Equión Energia Limited (Former BP Exploration Colombia). He also served as Latin America Procurement Sourcing Manager for Merck Sharp & Dohme and Procurement & Supply Chain Manager Specialist for Quala Colombia S.A. He has held various positions within BP as PSCM Drilling & Wells Category Lead, Iraq SPU in London, PSCM Market Intelligence Lead & Deflation Project Lead in Alaska, PSCM Specialist D&W in Alaska, PSCM Specialist O&M in Colombia, PSCM Commercial Analyst in Colombia and PSCM Specialist Business Support in Colombia.

 

Ernesto Gutiérrez de Piñeres has served as Digital Vice-President since October 2018. Mr. Gutierrez de Piñeres is a Systems Engineer and Information Systems Management Specialist from University of Norte de Barranquilla, and holds an Executive MBA from Los Andes University. He has more than 19 years of experience as Director and Manager (CIO) of information technology areas in different multinational companies on multiple industry sectors, leading and developing high performance teams in Colombia, USA, 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 the organizations through technology-based innovation, team development and technology strategies that leverage corporate strategy and competitive business.

 

None of our Directors, Executive Officers or members of senior management has any familial relationship with any Director, Executive Officer or member of senior management.

 

7.6 Compensation of Directors and Management

 

Based on a resolution adopted at our annual shareholders’ meeting in 2012, compensation for Directors’ attendance in person 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$5.4 million for 2021 and COP$5.2 million for 2020. See Note 31.1 to our consolidated financial statements for more details.

193

 

During 2020, the total compensation paid to our Directors, executive officers and senior management active amounted to COP$24.07 billion. This includes amounts paid to certain of our Directors, executive officers and senior management pursuant to a bonus plan under which such persons are entitled to receive contingent compensation based on our company results for each full year. The contingent compensation ranges from 0% to 150% of each person’s base compensation based on our company performance.

 

None of the members of our management team are eligible to receive pension and retirement benefits from us. The total amount recorded as of December 31, 2020 to provide pension and retirement benefits amounted to COP$13,413 million.

 

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 own shares of Ecopetrol:

 

Table 65 – Executive Officers 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 %
Cecilia María Vélez White     59,833       0.00015 %

 

 
(1) As of March 31, 2021.

 

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, 2020, 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.

194

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, effective control over financial reporting cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projection of any evaluation of the effectiveness of the internal controls to future periods is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

 

As of the year ended December 31, 2020, 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 the end of the period covered by this annual report.

 

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, 2020, 2019 and 2018 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, 2020 and December 31, 2019.

 

Table 66 – Fees Billed to us by Ernst & Young Audit S.A.S.

 

    For the year ended December 31,  
COP Millions, excluding 19% Value Added Tax   2020     2019  
Audit fees     12,864       10,343  
Audit-related fees     -       -  
Tax fees     -       -  
All other fees     -       -  
Total     12,864       10,343  

 

Audit Fees. The audit fees listed in the table above are the aggregated fees billed by Ernst & Young Audit S.A.S. 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.

 

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, 2020 that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

195

 

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.

 

Significant Changes

 

For a description of significant events since December 31, 2020, please see Note 34 to our consolidated financial statements.

 

196

 

 

8. Financial Statements

 

Ecopetrol S.A.

Consolidated Financial Statements

At December 31, 2020 and 2019 and for three years ended December 31, 2020, 2019 and 2018

 

197

 

 

Index
Report of Independent Registered Public Accounting Firm F-2
   
Report of Independent Registered Public Accounting Firm F-6
   
Consolidated statement of financial position F-8
   
Consolidated statement of profit or loss F-9
   
Consolidated statement of comprehensive income F-10
   
Consolidated statement of changes in equity F-11
   
Consolidated statement of cash flows F-13

 

1. Reporting entity F-14
     
2. Basis for presentation F-14
     
3. Significant estimates and accounting judgments F-19
     
4. Accounting policies F-23
     
5. New standards and regulatory changes F-39
     
6. Cash and cash equivalents F-40
     
7. Trade and other receivables, net F-42
     
8. Inventories, net F-43
     
9. Other financial assets F-43
     
10. Taxes F-45
     
11. Other assets F-53
     
12. Business combinations F-54
     
13. Investments in associates and joint ventures F-56
     
14. Property, plant and equipment F-59
     
15. Natural and environmental resources F-61
     
16. Right-of-use assets F-64
     
17. Intangible assets F-64
     
18. Impairment of non-current assets F-65
     
19. Goodwill F-71
     
20. Loans and borrowings F-72
     
21. Trade and other payables F-75
     
22. Provisions for employees’ benefits F-76
     
23. Accrued liabilities and provisions F-80
     
24. Equity F-88
     
25. Sales revenue from contracts with customers F-90
     
26. Cost of sales F-91
     
27. Administrative, operations and project expenses F-92
     
28. Other operating income (expenses), net F-92
     
29. Financial result, net F-93
     
30. Risk management F-93
     
31. Related parties F-99
     
32. Joint operations F-102
     
33. Information by segments F-104
     
34. Subsequent events F-111
     
35. Supplemental information on oil and gas producing activities (unaudited) F-112

 

Exhibit 1 – Consolidated subsidiaries, associates and joint ventures F-116
   
Exhibit 2 – Conditions of the most significant debt F-119

 

F-1 

 

 

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, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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, 2020, 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 April 8, 2021 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.

 

F-2 

 

 

 

 

 

 

Estimation of fair value amount of long-lived assets in the Cartagena refinery

 

Description of

the Matter

 

As described in notes 4.12 and 18 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 an asset is required, management estimates the asset’s recoverable amount. An asset’s recoverable amount is the higher of an asset’s or Cash Generating Unit (CGU’s) fair value less costs of disposal and its value in use. When the carrying amount of an asset or CGU exceeds its recoverable amount, the asset 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 asset’s or CGU’s recoverable amount since the last impairment loss was recognized. In 2020, the Company recognized an impairment charge in the Cartagena refinery of COP $ 418,803.

 

Auditing management’s estimate related to the determination of the assets’ or 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 asset´s recoverable amount. In particular, the estimation to determine the recoverable amount was sensitive to significant assumptions, such as changes in the weighted average cost of capital, sales price of refined products, refining margins and the level of operational expenditures, which are affected by expectations about future market or economic conditions.

 

  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 CGUs, including controls over management’s review of the significant assumptions described above, projected financial information and methodology used to develop such estimates.

 

Our audit procedures included, among others, assessing methodologies and testing the significant assumptions described above and 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 internal business plans, and also tested the clerical accuracy of such projections.

 

We also involved our valuation specialists to assist us in the review of the weighted average cost of capital and projected financial information used in management’s estimate and to perform a sensitivity analysis to evaluate the change in the recoverable amount that would result from changes in the underlying assumptions.

 

Furthermore, we evaluated the disclosure of this matter in Note 18 to the consolidated financial statements.

 

F-3 

 

 

      Determination of depreciation, depletion and amortization and impairment of long-lived assets
 

 

Description of the Matter

 

 

As described in notes 3.1 and 3.2 to the consolidated financial statements, the computation of the units-of-production method, which is used in the determination of depreciation, depletion and amortization (DD&A) of property, plant and equipment related to exploration and production and natural and environmental resources, as well as in the determination of future cash flows used in the impairment analysis of long-lived assets, is dependent upon the estimation related to oil and gas reserves.

 

 

The estimation of oil and gas reserves used to calculate the DD&A and perform the impairment analysis is a complex process and requires professional judgement. Management uses external independent engineers (hereinafter “specialists”) when estimating the reserves, which are determined based on geological, technical and economic factors. Estimates of oil and gas reserves depend upon a number of variable factors and key assumptions, including, quantities of oil and gas that are expected to be recovered, the timing of the recovery, production levels, operating and capital costs to be incurred, sales price, among others.

 

Auditing the Company’s DD&A and impairment calculation 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 analysis, 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 and methodology used to develop such estimates.

 

To evaluate the estimated quantity of oil and gas reserves expected to be recovered used to calculate the DD&A and in the impairment calculation, 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 DD&A and cash flows used in impairment analysis. For proved undeveloped reserves, we evaluated management’s development plan for compliance with the SEC rule that undrilled locations are scheduled to be drilled within five years, unless specific circumstances justify a longer time, by assessing consistency of the development projections with the Company’s drill plan and the availability of capital relative to the drill plan. We also tested the mathematical accuracy of the DD&A computations and reviewed the model of impairment analysis 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.

 

Furthermore, we evaluated the disclosure of this matter in Notes 35.4 and 35.5 to the consolidated financial statements.

 

F-4 

 

 

      Recoverability of deferred tax assets
 

 

Description of the Matter

 

 

As described in notes 4.14.2 and 10.2 to the consolidated financial statements, on December 31, 2020, the Company had deferred tax assets arising from net operating losses carryforwards (NOLs) of approximately COP $ 7,673,912. The NOLs were generated primarily by Ecopetrol USA Inc. and Refinería de Cartagena S.A.S. Deferred tax assets are subject to review at the end of each reporting period, and are reduced to their realizable amounts, to the extent it is no longer probable that sufficient taxable profit will be realized in the future.

       
 

 

 

 

 

 

How We Addressed the Matter in Our Audit

 

Auditing management’s assessment of the realizability of deferred tax assets involved complex auditor judgment because management’s estimate of realizability is based on assessing the probability, timing and sufficiency of future taxable profits, expected reversals of taxable temporary differences and available tax planning opportunities that will create future taxable profits; these projections are sensitive because they can be affected by variabilities in management’s projections and future market and economic conditions.

 

We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company’s process to determine the realizability of deferred tax assets, including controls over management’s projections of future taxable income, scheduled analysis of the future reversal of existing taxable temporary differences and the identification of available tax planning opportunities.

 

Among other audit procedures performed, we involved our valuation and tax professionals to assist on the review of significant assumptions used in the projections of future taxable income by jurisdiction. We also tested the completeness and accuracy of the underlying data used in such projections. We evaluated the reasonableness of such projections by comparing future taxable income to actual results obtained in prior periods, as well as evaluating management’s consideration of current industry and economic trends and evaluating whether changes to the Company’s business model and other factors would significantly affect the projected financial information.

 

In addition, with the assistance of our tax professionals, we assessed the application of the tax laws, including the Company's future tax planning opportunities and tested the Company´s scheduling of the timing and amount of reversal of taxable temporary differences.

 

We also evaluated the related disclosures in the consolidated financial statements.

 

/s/ Ernst & Young Audit S.A.S.  
We have served as the Company’s auditor since 2016.  
Bogota, Colombia  
April 8, 2021  

 

F-5 

 

 

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.’ internal control over financial reporting as of December 31, 2020, 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, 2020, 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, 2020 and 2019, 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, 2020, and the related notes and financial statement schedules listed in exhibits 1 and 2 and our report dated April 8, 2021 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.

 

F-6 

 

 

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.

 

/s/ Ernst & Young Audit S.A.S.  
Bogotá, Colombia  
April 8, 2021  

 

F-7 

 

 

Ecopetrol S.A.

 

Consolidated statement of financial position

(In millions of Colombian pesos)

 

          As of December 31,  
    Note     2020     2019  
Assets                        
Current assets                        
Cash and cash equivalents     6       5,082,308       7,075,758  
Trade and other receivables, net     7       4,819,092       5,700,334  
Inventories, net     8       5,053,960       5,658,099  
Other financial assets     9       2,194,651       1,624,018  
Current tax assets     10       3,976,295       1,518,807  
Other assets     11       1,664,036       1,778,978  
              22,790,342       23,355,994  
Assets held for sale             44,032       8,467  
Total current assets             22,834,374       23,364,461  
Non–current assets                        
Investment in associates and joint ventures     13       3,174,628       3,245,072  
Trade and other receivables, net     7       676,607       786,796  
Property, plant and equipment     14       66,508,338       64,214,822  
Natural and environmental resources     15       31,934,159       29,072,798  
Right-of-use assets     16       377,886       456,225  
Intangible assets     17       555,043       483,098  
Non-current tax assets     10       8,071,733       6,809,347  
Other financial assets     9       877,008       3,355,274  
Goodwill     19       1,594,279       1,159,922  
Other assets     11       1,090,114       942,481  
Total non–current assets             114,859,795       110,525,835  
Total assets             137,694,169       133,890,296  
Liabilities                        
Current liabilities                        
Loans and borrowings     20       4,923,346       5,012,173  
Trade and other payables     21       8,449,041       10,689,246  
Provisions for employee benefits     22       2,022,137       1,929,087  
Current tax liabilities     10       1,243,883       2,570,779  
Accrued liabilities and provisions     23       1,221,109       789,297  
Other liabilities             391,771       751,717  
              18,251,287       21,742,299  
Liabilities related to non-current assets held for sale             31,156       -  
Total current liabilities             18,282,443       21,742,299  
Non–current liabilities                        
Loans and borrowings     20       41,808,408       33,226,966  
Trade and other payables     21       21,064       24,445  
Provisions for employee benefits     22       10,401,530       9,551,977  
Non current tax liabilities     10       1,866,054       1,399,374  
Accrued liabilities and provisions     23       11,206,621       9,128,991  
Other liabilities             608,686       584,616  
Total non–current liabilities             65,912,363       53,916,369  
Total liabilities             84,194,806       75,658,668  
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       9,635,136       3,784,658  
Other comprehensive income     24.5       7,947,062       6,646,660  
Retained earnings             669,900       12,334,706  
Equity attributable to owners of parent             49,899,864       54,413,790  
Non–controlling interest             3,599,499       3,817,838  
Total equity             53,499,363       58,231,628  
Total liabilities and equity             137,694,169       133,890,296  

 

F-8 

 

 

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     2020     2019     2018  
Sales revenue     25       50,223,393       71,488,512       68,603,872  
Cost of sales     26       (37,567,472 )     (44,972,360 )     (41,184,379 )
Gross profit             12,655,921       26,516,152       27,419,493  
Administrative expenses     27       (3,373,150 )     (2,151,599 )     (1,653,858 )
Operations and project expenses     27       (2,586,016 )     (2,631,754 )     (2,903,132 )
Impairment loss of non–current assets, net     18       (633,156 )     (1,762,437 )     (368,634 )
Other operating income (expenses), net     28       1,118,166       1,056,796       (35,455 )
Operating income             7,181,765       21,027,158       22,458,414  
Financial results, net     29                          
Finance income             1,101,430       1,623,336       1,129,563  
Finance expenses             (3,929,791 )     (3,334,469 )     (3,512,161 )
Foreign exchange gain, net             346,774       40,639       372,223  
              (2,481,587 )     (1,670,494 )     (2,010,375 )
Share of profits of associates and joint ventures     13       76,336       366,904       165,836  
Profit before income tax expense             4,776,514       19,723,568       20,613,875  
Income tax expense     10       (2,038,661 )     (4,718,413 )     (8,258,485 )
Net profit for the year             2,737,853       15,005,155       12,355,390  
Net profit attributable to:                                
Owners of parent             1,586,677       13,744,011       11,381,386  
Non–controlling interest             1,151,176       1,261,144       974,004  
              2,737,853       15,005,155       12,355,390  
Basic and diluted earnings per share     24.6       38.6       334.3       276.8  

 

F-9 

 

 

Ecopetrol S.A.

 

Consolidated statement of comprehensive income

 

(In millions of Colombian pesos)

 

          For the years ended December 31,  
    Note     2020     2019     2018  
Net profit for the year                                
Other comprehensive income             2,737,853       15,005,155       12,355,390  
Other comprehensive income that may be reclassified to profit or loss in subsequent periods -net of taxes:                                
Unrealized gain (loss) on hedges:                                
Cash flow hedge for future exports     30.3       (722 )     238,331       (533,374 )
Hedge of a net investment in a foreign operation     30.4       (364,343 )     (61,267 )     (971,954 )
Cash flow hedge with derivative instruments             55,072       46,451       (52,174 )
Foreign currency translation             1,569,996       8,701       2,599,242  
              1,260,003       232,216       1,041,740  
Other comprehensive income that will not to be reclassified to profit or loss in subsequent periods -net of taxes:                                
Remeasurement gain (loss) on defined benefit plans     22.1       96,221       (1,799,829 )     (4,290 )
Other losses             -       (175,494 )     -  
              96,221       (1,975,323 )     (4,290 )
Other comprehensive income (loss) for the year, net of tax             1,356,224       (1,743,107 )     1,037,450  
Total comprehensive income for the year, net of tax             4,094,077       13,262,048       13,392,840  
                                 
Comprehensive income attributable to:                                
Owners of parent             2,887,080       11,502,149       12,363,132  
Non–controlling interest             1,206,997       1,759,899       1,029,708  
              4,094,077       13,262,048       13,392,840  

 

F-10 

 

 

Ecopetrol S.A.

 

Consolidated statement of changes in equity

 

(In millions of Colombian pesos)

 

          Attributable to owners of parent              
    Note     Subscribed and paid-in capital     Additional paid-in capital     Reserves     Other comprehensive income     Retained earnings     Total     Non-controlling interest     Total
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             -       -       (540,826 )     -       540,826       -       -       -  
Dividends declared     24.4       -       -       -       -       (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  
Foreign currency translation             -       -       -       1,528,803       -       1,528,803       41,193       1,569,996  
Remeasurement loss 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  

 

          Attributable to owners of parent              
    Note     Subscribed and paid-in capital     Additional paid-in capital     Reserves     Other comprehensive income     Retained earnings     Total     Non-controlling interest     Total
equity 		 
Balance as of December 31, 2018             25,040,067       6,607,699       5,138,895       8,380,761       9,970,492       55,137,914       1,969,866       57,107,780  
Net profit             -       -       -       -       13,744,011       13,744,011       1,261,144       15,005,155  
Release of reserves             -       -       (3,050,703 )     -       3,050,703       -       -       -  
Dividends declared     23.4       -       -       (3,659,386 )     -       (9,251,256 )     (12,910,642 )     (1,010,206 )     (13,920,848 )
Business combination     12       -       -       -       -       -       -       1,606,390       1,606,390  
Other movements             -       -       -       -       176,608       176,608       (350 )     176,258  
Appropriation of reserves, net:     23.3                                                                  
Legal             -       -       1,155,640       -       (1,155,640 )     -       -       -  
Fiscal and statutory reserves             -       -       509,082       -       (509,082 )     -       -       -  
Occasional             -       -       3,691,130       -       (3,691,130 )     -       -       -  
Other comprehensive income:                                                                        
Gain (loss) on hedging instruments:                                                                        
Cash flow hedge for future exports             -       -       -       238,331       -       238,331       -       238,331  
Hedge of a net investment in a foreign operation             -       -       -       (61,267 )     -       (61,267 )     -       (61,267 )
Cash flow hedge with derivative instruments             -       -       -       34,651       -       34,651       11,800       46,451  
Foreign currency translation             -       -       -       29,507       -       29,507       (20,806 )     8,701  
Remeasurement loss on defined benefit plans             -       -       -       (1,799,829 )     -       (1,799,829 )     -       (1,799,829 )
Other movements             -       -       -       (175,494 )     -       (175,494 )     -       (175,494 )
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  

 

F-11 

 

 

Ecopetrol S.A.

 

Consolidated statement of changes in equity

 

(In millions of Colombian pesos)

 

          Attributable to owners of parent              
    Note    

Subscribed

and paid-in capital

   

Additional

paid-in

capital

    Reserves    

Other

comprehensive

income

   

Retained

earnings

    Total    

Non-controlling

interest

   

Total

equity

 
Balance as of December 31, 2017             25,040,067       6,607,700       2,177,869       7,399,015       5,210,302       46,434,953       1,780,746       48,215,699  
Net profit             –       –       –       –       11,381,386       11,381,386       974,004       12,355,390  
Dividends declared     23.4       –       –       –       –       (3,659,386 )     (3,659,386 )     (840,626 )     (4,500,012 )
Appropriation of reserves, net             –       –       2,961,026       –       (2,961,026 )     –       –       –  
Other movements             –       (1 )     –       –       (784 )     (785 )     38       (747 )
Other comprehensive income:                                                                        
Gain (loss) on hedging instruments:                                                                        
Cash flow hedge for future exports             –       –       –       (533,374 )     –       (533,374 )     –       (533,374 )
Hedge of a net investment in a foreign operation             –       –       –       (971,954 )     –       (971,954 )     –       (971,954 )
Cash flow hedge with derivative instruments             –       –       –       (37,904 )     –       (37,904 )     (14,270 )     (52,174 )
Foreign currency translation             –       –       –       2,529,268       –       2,529,268       69,974       2,599,242  
Remeasurement loss on defined benefit plans             –       –       –       (4,290 )     –       (4,290 )     –       (4,290 )
Balance as of December 31, 2018             25,040,067       6,607,699       5,138,895       8,380,761       9,970,492       55,137,914       1,969,866       57,107,780  

 

F-12 

 

 

Ecopetrol S.A.

 

Consolidated statement of cash flows

 

(In millions of Colombian pesos)

 

          For the years ended December 31,  
    Note     2020     2019     2018  
Cash flow provided by operating activities:                                
Net profit for the period             2,737,853       15,005,155       12,355,390  

Adjustments to reconcile the net profit to net cash provided by

operating activities:

                               
Income tax expense     10       2,038,661       4,718,413       8,258,485  
Depreciation, depletion and amortization     14,15,16,17       9,324,538       8,582,783       7,704,850  
Foreign exchange income     29       (346,774 )     (40,639 )     (372,223 )
Finance cost of loans and borrowings     29       2,384,342       1,894,490       2,399,414  
Finance cost of post–employment benefits and abandonment costs     29       872,987       757,509       668,782  
Write off of exploratory assets and dry wells     15       448,132       340,271       898,924  
Loss on disposal of non–current assets             246,317       121,121       75,835  
Gain on revaluation of assets in Guajira association     28       (1,284,372 )     -       -  
(Gain) loss on acquisition of participations and interests     28       (86,026 )     (1,048,924 )     12,065  
Gain on loss of control     28       (65,695 )     -       -  
Impairment loss of short–term assets     28       34,416       90,441       136,044  
Impairment loss of non–current assets     18       633,156       1,762,437       368,634  
(Gain) loss on fair value adjustment of financial assets             (43,948 )     18,551       (92,906 )
Share of profit of associates and joint ventures     13       (76,336 )     (366,904 )     (165,836 )
Net gain on the sale of assets held for sale             (5,635 )     (2,846 )     -  
Hedge ineffectiveness     30.3       9,779       5,173       35,239  
Realized loss (gain) on foreign exchange cash flow hedges     25       193,374       386,773       (128,404 )
Net change in operational assets and liabilities:                                
Trade and other receivables             678,349       2,381,905       (2,039,161 )
Inventories             716,077       (597,552 )     (448,135 )
Trade and other payables             (2,550,411 )     1,389,064       1,355,175  
Tax assets and liabilities             (1,256,889 )     (1,409,334 )     (1,413,915 )
Provisions for employee benefits             465,062       (234,629 )     (181,060 )
Provisions and contingencies             (30,185 )     (253,043 )     (89,345 )
Other assets and liabilities             (392,843 )     (492,745 )     (218,542 )
              14,643,929       33,007,470       29,119,310  
Income tax paid             (5,457,225 )     (5,295,703 )     (6,650,116 )
Net cash provided by operating activities             9,186,704       27,711,767       22,469,194  
Cash flow used in investing activities:                                
Investment in property, plant and equipment     14       (5,032,317 )     (4,012,659 )     (3,302,929 )
Investment in natural and environmental resources     15       (5,994,462 )     (9,798,193 )     (5,051,828 )
Acquisitions of intangibles     17       (90,082 )     (168,289 )     (105,669 )
Sales (purchases) of other financial asset, net             2,107,856       3,117,549       (843,612 )
Interests received     29       299,246       481,674       383,624  
Dividends received     13       157,241       189,169       108,991  
Proceeds from sales of assets             23,713       154,780       92,620  
Net cash used in investment activities             (8,528,805 )     (10,035,969 )     (8,718,803 )
Cash flow used in financing activities:                                
Proceeds from borrowings     20       13,805,403       359,876       517,747  
Repayment of borrowings             (5,003,885 )     (1,596,630 )     (9,270,262 )
Interest payments             (2,345,683 )     (1,766,223 )     (2,610,562 )
Lease payments     16       (350,539 )     (300,326 )     -  
Dividends paid     21       (8,734,351 )     (13,867,029 )     (4,427,701 )
Net cash used in financing activities             (2,629,055 )     (17,170,332 )     (15,790,778 )
Exchange difference in cash and cash equivalents             (22,294 )     258,548       406,246  
Net (decrease) increase in cash and cash equivalents             (1,993,450 )     764,014       (1,634,141 )
Cash and cash equivalents at the beginning of the year             7,075,758       6,311,744       7,945,885  
Cash and cash equivalent at the end of the year     6       5,082,308       7,075,758       6,311,744  

 

F-13 

 

 

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. (“Ecopetrol”) is a mixed economy company, of a commercial nature, incorporated in 1948 in Bogotá – Colombia, and the parent company of the Ecopetrol Business Group. Its corporate purpose is to conduct commercial or industrial activities related to the exploration, exploitation, production, refining, transportation, storage, distribution and commercialization of hydrocarbons and their derivatives and products, directly or through its subsidiaries (collectively referred to as “Ecopetrol Business Group”).

 

11.51% of Ecopetrol shares are publicly traded on the New York and Colombian Stock Exchanges. The remaining shares (88.49% of total outstanding shares) are owned by the Colombian Ministry of Finance and Public Credit.

 

The address of the main office of Ecopetrol is Bogotá – Colombia, Carrera 13 No. 36 – 24.

 

2. Basis for presentation

 

2.1 Statement of compliance and authorization of financial statements

 

The consolidated financial statements of Ecopetrol and its subsidiaries as of December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018 have been prepared in accordance with International Financial Reporting Standards (IFRS), as issued by the International Accounting Standards Board (IASB).

 

Accounting policies described in Note 4 have been applied consistently in all years presented.

 

These consolidated financial statements were approved and authorized for issuance by the Board of Directors of Ecopetrol on April 8, 2021.

 

2.2 Basis for consolidation

 

The consolidated financial statements were prepared by consolidating all companies set out in Exhibit 1, which are those over which Ecopetrol exercises direct or indirect control. Control is achieved when the Ecopetrol Business Group:

 

  · has power over the investee (including rights to manage relevant activities);

 

  · is exposed, or has the rights, to variable returns from its involvement with the investee; and

 

  · 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:

 

  a) the percentage of the Ecopetrol Business Group’s voting rights relative to the size and apportionment of the shares of other vote holders;

 

  b) potential voting rights held by the Ecopetrol Business Group, other vote holders or other parties;

 

  c) rights arising from other contractual arrangements; and

 

  d) any additional facts and circumstances that indicate that the Ecopetrol 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.

 

F-14 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases.

 

All inter–company 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 following subsidiaries had changes in the Group:

 

2020

 

a) The liquidating agency for ECP Oil and Gas Germany GmbH submitted the report and the liquidation balance on December 11, 2020. Therefore, the company is no longer part of the Group from the date above on.
   
b) 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 SAS and Bioenergy Zona Franca SAS. 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. As a consequence, as of this date the Group does not have control over these companies and they are no longer part of the consolidated figures. As a result, reduction of net assets was recognized due to the loss of control with an impact on the results of the Business Group for COP$65,570. The Group does not recognize additional liabilities related to these companies. See Note 28.

 

2019

 

a)

In November 2019, Ecopetrol obtained an additional 8.53% ownership interest in Invercolsa, through the Supreme Court of Justice final ruling stating that Mr. Fernando Londoño’s attempt to acquire Invercolsa’s shares owned by Ecopetrol S.A. was not valid. As a result, Ecopetrol obtained control of Invercolsa, with a total ownership interest of 51.88%. No consideration was paid for the shares obtained as a result of the judicial ruling.

 

The subsidiaries that started being consolidated as a result of obtaining control of Invercolsa are as follows:

 

  · Inversiones de Gases de Colombia S.A., whose main corporate purpose is to hold investments in companies associated with activities in the energy sector; the exploration, exploitation, refining, transformation, transport, distribution and sale of hydrocarbons and their derivatives in the national territory; and to encourage the establishment of new companies and to hold shares or corporate interests therein.

 

  · Alcanos de Colombia S.A. E.S.P., whose main corporate purpose is to provide fuel gas to homes in Neiva and throughout Colombia; to construct and operate gas pipelines, distribution networks, regulation, measurement and compressor stations and any works undertaken necessary for the management and commercialization of public services.

 

  · Metrogas de Colombia S.A. E.S.P., whose main corporate purpose is to commercialize and distribute fuel gas; to explore, store, use, transport, refine, purchase, sell and distribute hydrocarbons and their derivatives in all their forms and representations.

 

  · Gases del Oriente S.A. E.S.P., whose main corporate purpose is to provide fuel gas to homes by distributing gas and performing all activities complementary to the provision thereof.

 

  · Promotora de Gases del Sur S.A. E.S.P., whose main corporate purpose is to promote the affiliation of national or foreign capital, public or private and to achieve the gas massification project in the Huila department, through a gas pipeline from the Neiva municipality to the Hobo municipality.

 

  · Gasoducto de Oriente S.A., whose main corporate purpose is to design and construct hydrocarbon production and treatment plants, such as gas pipelines, oil pipelines and others, as well as to invest in projects related thereto.

 

  · Combustibles Líquidos de Colombia S.A. E.S.P., whose main corporate purpose is to commercialize wholesale fuel gas, to distribute LPG to homes and to carry out complementary activities to this distribution, as well as to store, transport, package, distribute and sell LPG.

 

F-15 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

b) In July 2019, two companies were incorporated to enable the operation between Ecopetrol S.A. and Occidental Petroleum Corp. (OXY), whereby it was agreed to form a Joint Operation to execute a joint plan for the development of Unconventional Deposits in the Texas Permian Basin. The two companies incorporated were the following:

 

  · Ecopetrol USA Inc., whose corporate purpose is to participate in any lawful act or activity for which corporations may be organized under the General Corporation Law of Delaware.

 

  · Ecopetrol Permian LLC., whose corporate purpose is to carry out any or all lawful businesses for which limited liability companies can be organized in accordance with the Delaware Limited Liability Companies Act.

 

c) Two companies in Mexico were incorporated to provide administrative and technology services to Ecopetrol México. The two companies created were: Topili Servicios Administrativos S. de R.L. de C.V. and  Kalixpan Technical Services S. de R.L. de C.V.

 

2018

 

  · Ecopetrol Energía S.A.S. E.S.P: whose corporate purpose is to commercialize electric power for the Ecopetrol Business Group Ecopetrol holds a 99% direct interest in the subsidiary and an indirect interest of the remaining 1% through Andean Chemicals Ltd.

 

2.3 Basis of presentation

 

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 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.

 

2.4 Functional 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.A.’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 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 particular foreign operation is reclassified to profit or loss.

 

The financial statements are presented in Colombian pesos rounded up to the closest million unit (COP$000,000) except when otherwise indicated.

 

2.5 Foreign 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.

 

F-16 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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.

 

2.6 Classification 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:

 

  · 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;

 

  · Held mainly for the purpose of trading;

 

  · Expected to be realized (or to be settled, in the case of liabilities) within twelve months after the reporting period; or

 

  · 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

 

  · 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.

 

2.7 Earnings per share (basic and diluted)

 

Basic earnings per share is calculated by dividing the profit for the year attributable to equity holders of Ecopetrol S.A., the parent company, by the weighted average number of ordinary shares outstanding during the year. There is no potential dilution of shares.

 

2.8 Impact of Covid-19 on financial statements

 

The Covid-19 outbreak was first reported in late 2019 in China. Subsequently, taking into account the level of expansion, the World Health Organization (WHO) declared the outbreak as a pandemic on March 11, 2020. Said status is maintained to the date of this annual report.

 

Many countries have undertaken various public health measures to control the spread of COVID-19, including mandatory quarantines, forced economic shutdowns and travel restrictions, as well as economic measures to mitigate the impacts of such public health policies on their respective national economy.

 

The Covid-19 pandemic has also caused significant volatility in financial and commodity markets around the world. While governments have announced aid packages to the most affected people and taken macroeconomic measures to face the crisis, the COVID-19 pandemic has disrupted economies worldwide.

 

On March 17, 2020, Colombia Government, through Legislative Decree 417 of 2020, declared a 30 day state of national emergency in light of the health and economic crisis caused by the outbreak of COVID-19. On May 6, 2020, the Government declared a state of emergency for an additional 30 days. For the rest of 2020, the National Government and local authorities implemented sectored lockdowns, and partial closures of commerce and not essential economic activities according to the number of new cases of infected population and hospital capacity. The Government also has implemented other economic and public health measures to address the crisis, including (i) border closure for all non-citizens and non-residents; (ii) short term and low interest loans for all types of agricultural producers; (iii) payroll subsidies for companies and credit lines for different sectors of the economy; (iv) incentivizing working from home and a mandatory work from home order for 80% of Government employees and (v) reduction in the prices of gasoline, among others.

 

F-17 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

This situation has had a significant impact on the oil industry. Most specifically, travel bans imposed by several countries and established quarantine measures reduced demand levels for oil and its derivative products in 2020. Ecopetrol’s operations were affected by this situation and as a consequence, some plants in our refineries and some of our wells were temporarily closed due to low demand and prices and the measures taken to contain the spread of COVID-19 in workers and contractors. In this context, Ecopetrol took the following actions during 2020 to face the impacts of the pandemic: 

 

- Ecopetrol’s Board of Directors was permanently at the forefront of the crisis caused by Covid-19. Throughout the year, the Board held a total of 15 extraordinary sessions to direct Ecopetrol with opportunity and expeditiousness in taking measures to counteract the impacts derived from this crisis. In addition Ecopetrol issued the ‘Declaration of Contingency Operation’ in March 2020 and activated the equipment, plans and actions required to prevent infections, respond to new challenges in the operation and special containment measures.

 

- Cuts in costs and expenses, including austerity measures, prioritization of operational and administrative activities, and control over operational expenses, such as travel restrictions, sponsorships and participation in events, among others.

 

- Disbursements under credit lines in the aggregate amount of USD$665 million, as well as an issuance of external public debt bonds in the international capital markets in the aggregate amount of USD$2 billion. (Note 20).

 

- Publication of a new organic investment plan for Ecopetrol Group approved by the Board of Directors on July 17, 2020 considering: (i) a detailed review of the Ecopetrol Group’s portfolio, (ii) progress in the interventions carried out, and (iii) the gradual recovery of economic activity.

 

- Allocated resources by COP$85,387 million in connection with humanitarian aid and other initiatives to strengthen the Colombian health system to address the COVID-19 pandemic.

 

- The execution by Ecopetrol S.A. of 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 of crude oil. A total of 30 million barrels (mmbls) were the subject of strategic hedges oriented at protecting the Ecopetrol’s income and cash flow, limiting losses, covering production costs and avoiding potential closures of production fields. A total of 21.7 million barrels (mmbls) were the subject of tactical hedges oriented at mitigating risks associated with storage marketing strategies, anticipated purchases of raw materials, supply to refineries, international sales delivered at the destination port and exports of heavy fuel oil.

 

- Recognition of impairment expenses at the end of December 31, 2020 in the aggregate amount of COP$633,156 million, after adjusting and updating some of the assumptions used (prices and discount rates) to the circumstances and environment of the 2020, recognizing the impact on the Ecopetrol Group’s main long-term assets (some productive assets in the exploration and production segment and in the Refinería de Cartagena). (Note 18 - Impairment of non-current assets).

 

These measures were aimed at ensuring the sustainability of the Ecopetrol Group’s business in an environment of low prices, prioritizing cash-generating opportunities with better equilibrium prices, maintaining growth dynamics with a focus on the execution of strategic asset development plans, and in asset value preservation through investments to gain reliability, integrity and continuity to the current operation in refineries, transportation systems and production fields. Similarly, these actions are covered by Ecopetrol’s risk management policies and procedures. (Note 30).

 

In terms of Ecopetrol’s results of operations as of and for the year ended December 31, 2020, the most significant impacts were the following in: (i) a reduction in revenues (Note 25), especially due to the contraction in demand and a decrease in the international Brent price, partially offset with the higher exchange rate, (ii) an increase in financial costs due to an increase in debt (Note 29), a decrease in valuation to fair value and lower yields of the securities portfolio, which in turn were as a result of low market rates, (iii) recognition of impairment at the end of the year as described above (Note 18), and (iv) an increase in our depreciation expenses (Notes 14, 15, 16 and 17), partly generated by the update of the Ecopetrol’s reserve balance (Note 35).

 

As a result of the measures taken, the constant monitoring of the COVID-19 pandemic, the ongoing vaccination programs and the evolution of the Ecopetrol Group’s results, while we cannot offer any assurances, as of the date of this annual report, Ecopetrol does not believe that the Covid-19 pandemic will have a significant impact on the Ecopetrol Group in the long-term.

 

Nonetheless, the Ecopetrol Group will continue to monitor the evolution of the COVID-19 pandemic and the market to determine the need to implement subsequent stages of the COVID-19 intervention plan and will continuously review impairment indicators on long-lived assets and on investments in companies.

 

F-18 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

2.9 Reclassifications

 

For presentation purposes, the Group reclassifies some items in the comparative figures as of December 2019. This had no impact on the items in the statements of financial position, profit or loss, comprehensive income, changes in equity or cash flows.

 

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:

 

3.1 Oil and gas reserves

 

Hydrocarbon reserves are estimates of the amount 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 amount 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 estimations are prepared using geological, technical and economic factors, including projections of future production rates, oil prices, engineering data and duration and amount 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.

 

3.2 Impairment of non-current assets

 

Management uses its professional judgment in assessing the existence of evidence of an impairment loss or reversal, based on internal and external factors.

 

F-19 

 

 

Ecopetrol S.A.

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) estimation of the volumes and market value of oil and natural gas reserves; (2) production profiles for oilfields and the future production of refined and petrochemical products; (3) investments, taxes and future costs; (4) useful life of assets; (5) long–term prices; (6) the discount rate, which is revised annually and determined as the weighted average cost of capital (WACC); and (7) changes in environmental regulation. The recoverable amount is compared to the carrying amount of the asset, 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 (except over the goodwill), 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 price assumptions are estimated at current market conditions related to upstream. 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 risk and uncertainty. 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.

 

3.3 Exploration and evaluation costs

 

The application of the Ecopetrol Business Group’s accounting policy for exploration and evaluation costs requires judgment in order 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 in order to annually assess 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 is included in operating activities in the consolidated statement of cash flows.

 

3.4 Determination of cash generating units (CGU)

 

The allocation of assets in cash generating units requires significant judgment, as well as assessments regarding integration among assets, the existence of active markets, and similar exposure to market risk, shared infrastructure, and the way in which management monitors the operations. See Note 4.12 – Impairment of non-current assets for more information.

 

3.5 Abandonment 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.

 

F-20 

 

 

Ecopetrol S.A.

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. The 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 4.13 - Provisions and contingent liabilities (Obligation to withdraw assets).

 

3.6 Pension plan and other benefits

 

The determination of expenses, liabilities and adjustments relating to pension plans and other defined retirement benefits makes it necessary for management to use its judgment in the application of actuarial assumptions made in the actuarial calculation. The actuarial assumptions include estimates regarding future mortality, retirement, changes in compensation and discount rate in order 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.

 

3.7 Goodwill 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 impaired.

 

The determination of the recoverable amount is described in Note 4.12, and its calculation requires assumptions and estimates. The 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.

 

3.8 Litigation

 

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.

 

3.9 Taxes

 

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.

 

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.

 

F-21 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

3.10 Hedge 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.

 

F-22 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

4. Accounting policies

 

The accounting policies indicated below have been applied consistently for all the periods presented.

 

4.1 Financial instruments

 

A financial instrument is any contract that creates a financial asset for one 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.

 

Transaction costs that are directly attributable to the acquisition or issue of financial assets and financial liabilities (other than financial assets and financial liabilities at fair value through profit or loss) are added to or deducted from the fair value of the financial assets or financial liabilities, as appropriate, on initial recognition. Transaction costs directly attributable to the acquisition of financial assets or financial liabilities at fair value through profit or loss are recognized immediately 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, assuming that market participants act in their economic best interest.

 

A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset for its most profitable use or by selling it to another market participant that would use the asset in its highest and best use.

 

The Group uses valuation techniques that are appropriate for the circumstances and for which sufficient data are available 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 a whole, as follows:

 

  · 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. For other assets and liabilities, fair value estimations are generally based on the net present value of expected future cash.

 

  · 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.

 

F-23 

 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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.

 

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 to be impaired when there is objective evidence that, as a result 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.

 

4.1.2 Financial assets

 

The classification of financial assets at initial recognition depends on the financial asset’s contractual cash flow characteristics and the Group’s business model for managing them. With the exception of trade receivables that do not contain a significant financing component or for which the Ecopetrol Business Group has applied the practical expedient, the 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.

 

The Ecopetrol Business Group classifies its financial assets in the following categories:

 

  a) 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.

 

  b) 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 investments are recorded at their fair value and unrealized gains or losses are recognized in other comprehensive income.

 

  c) Financial assets at amortized cost

 

This category is the most relevant to the Group. The Group’s financial assets at amortized cost includes trade receivables, other receivables, loans to associates, and loans to employees.

 

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.

 

F-24 

 

 

Ecopetrol S.A.

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.

 

The 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 in order 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 (EIR) method and are subject to impairment analysis. Gains and losses are recognized in profit or loss when the asset is derecognized, modified or impaired.

 

De–recognition 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.

 

4.1.3 Financial liabilities

 

Financial liabilities correspond to the financing obtained by the Ecopetrol Business Group through bank credit facilities and bonds, accounts payable to suppliers and creditors.

 

Bonds and bank credit facilities (this is the category most relevant to the Group) 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 (EIR) method. The effective interest method amortization is included as a financial expense in the statement of profit or loss. Amortized cost is calculated by taking into account 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.

 

4.1.4 Derivative financial instruments and hedging activities

 

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.

 

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.

 

F-25 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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.

 

4.1.5 Hedging 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, the 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 designates long–term loans as hedging instruments for its exposure to the exchange risk in future oil exports. See Note 30.3 for further information.

 

4.1.5.2 Hedge 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 in a way similar 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 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 for further information.

 

4.1.5.3 Fair 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.

 

F-26 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

4.2 Inventories

 

Inventories are stated 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 required to bring a pipeline into working order, is treated as part of the related pipeline.

 

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 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.

 

4.3 Related parties

 

Related parties are considered those in which one party has the ability to control, or has joint control of the other, or exercises significant influence over the other party in making financial or operational decisions, or is a member of key management personnel (or close relative of a member). The Ecopetrol Business Group considers related parties to be associates, joint ventures, key management executives, entities managing resources for payment of employee post–employment benefit plans and Colombian government entities for the purposes of certain relevant transactions, such as the purchase of hydrocarbons and the fuel price stabilization fund (see Note 31 – Related parties).

 

4.3.1 Investments 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 I – Consolidated companies, associates and joint ventures for further details.

 

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 in other comprehensive income is recognized in other comprehensive income of the Ecopetrol Business Group.

 

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 its carrying value, and then the impairment is recognized in the consolidated statement of profit or loss.

 

F-27 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

When necessary, the Ecopetrol Business Group makes adjustments to 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.

 

4.4 Joint 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 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 participates as a non–operator partner, it recognizes the assets, liabilities, sales revenues, cost of sales and expenses based on the operator’s report. When Ecopetrol 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.

 

4.5 Non–current assets held for sale

 

Non–current assets are classified as held for sale if their carrying values will be recovered principally through a sale transaction rather than through continued use. Non–current assets are classified as held for sale only when the sale is highly probable within one year from the classification date and the asset (or group of assets) is available for immediate sale in its present condition. These assets are measured at the lower of their carrying amount and fair value less related costs of disposal.

 

4.6 Property, 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.

 

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 the entity expects to use during more than one period are recognized as property, plant and equipment.

 

F-28 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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 in order 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 – 40 years
Buildings   10 – 42 years
Other   3 – 35 years

 

Lands are recognized separately from buildings and facilities and it is not subject to depreciation.

 

Depreciation methods and useful lives are reviewed annually and adjusted if appropriate.

 

4.7 Natural and environmental resources

 

Recognition and measurement

 

Ecopetrol 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.

 

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 is no longer 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.

 

F-29 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

All capitalized costs are subjected to technical and commercial revisions at least once a year to confirm the evaluation and exploration efforts continue on 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 subsequent to 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, that is, at the prices and costs that apply at 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 4.12 — Impairment of non-current assets.

 

4.8 Capitalization of borrowing costs

 

Borrowing costs related to the acquisition, construction or production of a qualifying asset that requires a substantial period of time 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 finance 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.

 

F-30 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

4.9 Intangible 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 expensed as incurred.

 

4.10 Business combinations

 

The Group recognizes business combinations using the acquisition method. Identifiable assets acquired and liabilities assumed are initially measured at fair value on the acquisition date, subject to certain exceptions.

 

On the acquisition date, the acquirer will separately recognize the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree, and any goodwill or bargain purchase resulting from the acquisition.

 

The company that acted as buyer will recognize the goodwill generated as an asset on the acquisition date, measured as the difference between (i) the aggregate of the consideration transferred, the amount of any non-controlling interest and in a business combination achieved in stages the acquisition-date fair value of the acquirer’s previously held equity interest in the acquiree and (ii) the net amount on the acquisition date of the identifiable assets acquired and the liabilities assumed.

 

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.

 

The acquirer will identify the acquisition date as the date on which control of the acquiree is obtained.

 

The measurement period is the period after the acquisition date during which the acquirer can adjust the provisional amounts recognized in a business combination. The measurement period cannot exceed one year from the acquisition date.

 

During 2019 and 2020 the Group recognized transactions as business combinations (Note 12).

 

4.11 Leases

 

As of January 1, 2019, the Ecopetrol Business Group adopted IFRS 16, “Leases” (“IFRS 16”) applying the modified retrospective scope.

 

At the beginning of a contract, the 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 of time 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 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 recognised separately.

 

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, b) changes in future lease payments resulting from variations in an index or in the rate used for determine the payments. The amount of the remeasurement of the obligation will be recognized as an adjustment to the asset for the right of use.

 

F-31 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Ecopetrol Business Group as a lessor

 

Leases in which the Ecopetrol Business Group does not transfer substantially all the risks and rewards incidental to ownership of an asset are classified as operational. Rental income is recognized in the statement of profit or loss on a straight-line basis over the lease terms.

 

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.

 

In order 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.

 

Short-term 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 consolidated 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.

 

4.12 Impairment of non–current assets

 

In order to evaluate if any tangible or intangible assets are impaired, Ecopetrol compares its carrying amount with its recoverable amount at the end of each reporting period 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 and companies in this segment of the Ecopetrol Business Group and for the Transportation segment; each pipeline system is considered an independent CGU.

 

F-32 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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’s 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, in order to determine if it is reasonable.

 

When an impairment loss is recorded, future amortization expenses are calculated on the basis of 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.

 

4.13 Provisions and contingent liabilities

 

Provisions are recognized when the Ecopetrol Business Group has a current obligation (legal or constructive) as a result 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.

 

Future environmental decommissioning costs related to current or future operations, are accounted for as expenses or assets, as the case may be. Expenditures related to past operations that do not contribute to the obtaining of current or future benefits, are expensed as incurred.

 

The recognition of these provisions coincides with the identification of an obligation related to environmental remediation and Ecopetrol uses available information to determine a reasonable estimation of the related cost.

 

Provisions for which a negative outcome is assessed as possible are not recognized but are disclosed in the explanatory notes; including those for which the amount cannot be estimated.

 

If there is an expectation that the provision will be reimbursed, either in whole or in part, for example by virtue of an insurance contract, the amounts expected to be reimbursed are recognized as a separate asset only when such reimbursement is almost certain.

 

If the effect of the time value of money is significant, the provisions are discounted using the current market rate before taxes reflecting, as applicable, the liability specific risks. When recognizing the discount, the increase of the provision resulting from time elapsed is recognized as financial cost in the profit or loss statement.

 

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.

 

F-33 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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 consolidated 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.

 

4.14 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.

 

Income tax is paid by each legal entity and not on a consolidated basis.

 

4.14.1 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.

 

4.14.2 Deferred 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.

 

4.14.3 Other 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. For more details, see Note 10.

 

F-34 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

4.15 Employee benefits

 

Salaries and benefits for Ecopetrol’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.

 

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:

 

  · Pensions

  · Pension bonds

  · Health

  · Educational plan

  · Retroactive severances

 

F-35 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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 takes into account 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 particular country’s rate, the latest version of which is the RV08 mortality table published in resolution 1555 of October 2010. The future salary and pension increases are linked to the country’s future inflation rates. Note 22 – Provisions for employee benefits provides further details on key assumptions used.

 

The amounts recognized in the consolidated statement of profit or loss related to employees defined benefit plans are comprised mainly by service cost and the net financial expense. Service cost includes mainly the increase in present value of the benefit obligation during the 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.

 

4.16 Revenue from contracts with customers

 

The Ecopetrol Business Group’s business is based on three 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 products, petrochemicals and biofuels. 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 Group’s performance obligations to its customers.

 

F-36 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

For some natural gas supply contracts with a replacement period, a distinction is made between quantities of gas consumed and not consumed in order 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:

 

a) The customer exercises its right to deficient volumes or services, or

 

b) The possibility is remote that the customer will exercise its right to deficient volumes or services.

 

Refined 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 are recognized when the service is provided to the customer.

 

In other cases the, 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 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.

 

According to the risk profiles, the Ecopetrol Business Group manages advance payment systems for some of its customer contracts.

 

Significant financing component

 

Generally payments received from customers are short term. Using the practical expedient in IFRS 15, the 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.

 

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 will make its best estimate of the transaction price that reflects the goods and services transferred to customers.

 

Agreements signed with customers do not include variable considerations such as rebates, refunds or discounts.

 

F-37 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Non-cash considerations

 

Agreements signed in the Ecopetrol Business Group does not consider non-cash transactions.

 

Customer advances

 

These correspond to contractual obligations in which the Ecopetrol Business Group receives advances from customers. These advances by customers form part of the policies and risk assessment defined by the Business Group.

 

4.17 Costs 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.

 

4.18 Finance 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.

 

4.19 Information by business segment

 

Ecopetrol 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 three business segments: 1) Exploration and Production, 2) Transport and Logistics and 3) Refining, Petrochemical and Biofuels. Segments are determined based on 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 recorded and presented at market prices.

 

a) 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.

 

c) 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.

 

See information by segments in Note 33.

 

F-38 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

5. New standards and regulatory changes

 

5.1 New standards adopted by the Group, effective as of January 1, 2020

 

Ecopetrol applied certain standards and amendments which were effective for annual periods beginning on or after January 1, 2020. Ecopetrol has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective.

 

- Amendments to IFRS 3 - Definition of a business: clarifies that to be considered a business, an integrated set of activities and assets must include, at a minimum, an input and a substantive process that, together, significantly contribute to the ability to create output. Furthermore, it clarifies that a business can exist without including all of the inputs and processes needed to create outputs.

 

- Amendments to IFRS 7, IFRS 9 and IAS 39 - Reference interest rate reform: a number of exemptions are provided, which apply to all hedging relationships directly affected by changes in the reference interest rate indexes. A hedging relationship is affected if the change in ratios creates uncertainty about the timing and/or amount of cash flows from the hedged item or hedging instrument.

 

These modifications have no impact on the consolidated financial statements, as there is currently no interest rate coverage.

 

- Amendments to IAS 1 and IAS 8 - Definition of material: The new definition establishes that, “Information is material if its omission or distortion is expected to influence the decisions made by the main users of financial statements”. The amendments clarify that materiality will depend on the nature and/or magnitude of the information, either individually or in combination with other information, within the context of the financial statements. A misstatement of information is material if it can be reasonably expected to influence the decisions made by primary users.

 

These modifications have not had any impact on the consolidated financial statements.

 

- Revised Conceptual Framework for Financial Reporting: The IASB issued the revised Conceptual Framework in March 2018. It establishes a comprehensive set of concepts for financial reporting, standard setting, guidance for preparers in defining consistent accounting policies and assisting others to understand and interpret the standards. The Conceptual Framework includes several new concepts, provides updated definitions and recognition criteria for assets and liabilities, and clarifies some important concepts. Changes to the Conceptual Framework may affect the application of IFRS in situations where a standard does not apply to a particular transaction or event. For preparers developing accounting policies based on the Conceptual Framework, it is effective for annual periods beginning on or after January 1, 2020.

 

These modifications have not had an impact on the consolidated financial statements.

 

- Amendments to IFRS 16 Covid-19-related rental concessions: On May 28, 2020, the IASB issued the amendment to IFRS 16 - Covid-19-related rental concessions, which provides relief to tenants. As a practical solution, a tenant may choose not to assess whether a Covid-19-related rental concession from a landlord is a lease modification. A lessee who makes this choice accounts for any change in the lease payments resulting from the concession in the same way that it would account for the change under IFRS 16, if the change were not a modification of the lease. The amendment applies to annual reporting periods beginning on or after June 1, 2020. Early application is allowed.

 

This amendment was not applied given that the number of contracts that would be within its scope is reduced and – evaluating its impact at the business group level – it is not material. Consequently, each company will guarantee that the changes in the lease contracts under IFRS 16 comply with the current guidelines of the standard, which establishes that the modifications are recorded as a higher or lower value of the asset in use.

 

F-39 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

5.2 New standards issued by the IASB that will enter into force in future periods

 

The new amended standards and interpretations that are issued, but not yet effective, up to the date of issuance of the Group’s financial statements are disclosed below. Ecopetrol intends to adopt these new and amended standards and interpretations, if applicable, when they become effective.

 

Effective January 1, 2021:

 

- Reform to the reference interest rate - Phase 2: The amendments address issues that might affect financial reporting as a result of the reform of an interest rate benchmark, including the effects of changes to contractual cash flows or hedging relationships arising from the replacement of an interest rate benchmark with an alternative benchmark rate. The amendments provide practical relief from certain requirements in IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 relating to: (i) changes in the basis for determining contractual cash flows of financial assets, financial liabilities and lease liabilities; and (ii) hedge accounting.

 

Within the accounting analysis, Ecopetrol established that the contractual cash flows of financial assets or financial liabilities measured at amortized cost would change as a result of the interest rate reform. According to the standard, the contracts that change the basis for determining the contractual flows as a result of the interest rate reform should not have a recalculation in the IRR and therefore no accounting impact on the Income Statement applying paragraph B5.4.5 of IFRS 9. Monthly financial expenses will be measured at the new interest rate without implying a remeasurement in the rate that may affect the current cost of the financial asset and/or liability.

 

Effective as of January 1, 2022 with early adoption in 2021:

 

- IAS 16 - Property, plant and equipment: amendment which prohibits entities deducting from the cost of an item of property, plant and equipment, any proceeds from selling items produced while bringing that asset to the location and condition necessary for it to be capable of operating in the manner intended by management. Instead, an entity recognizes the proceeds from selling such items, and the costs of producing those items, in profit or loss.

 

The amendment is effective for annual reporting periods beginning on or after 1 January 2022 and must be applied retrospectively to items of property, plant and equipment made available for use on or after the beginning of the earliest period presented when the entity first applies the amendment.

 

Ecopetrol will apply the amendment with early adoption in 2021 subject to approval by decree as required in Colombia regulation.

 

- IFRS 3 - Business combinations: in which they update a reference from the standard to the Conceptual Framework.

 

- IAS 37 - Provisions, contingent liabilities and contingent assets: to specify which costs an entity needs to include when assessing whether a contract is onerous or loss-making.

 

Entry into force as of January 1, 2022 or later periods:

 

- 2018 - 2020 annual improvement cycle that involves adjustments to IFRS 1, IFRS 9, IAS 41 and IFRS 16.

 

The Company constantly monitors the new accounting standards, updates or amendments that the IASB issues, to validate their application and impacts on the Financial Statements.

 

6. Cash and cash equivalents

 

    2020     2019  
Banks     4,215,518       5,813,306  
Short–term investments (1)     866,606       1,262,105  
Cash     184       347  
      5,082,308       7,075,758  

 

F-40 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

(1) During the second quarter of 2020, resources were invested in funds in dollars as part of the issuance and placement of external public debt bonds carried out by Ecopetrol in April.

 

As of December 31, 2020, cash and cash equivalents balance included COP$11,682 (COP$85,286 as of December 31, 2019), of restricted cash to be used exclusively for the payment of loans principal and interest obtained by Oleoducto Bicentenario and Oleoducto de los Llanos. The use of short–term financial investments depends on the liquidity needs of the Ecopetrol Business Group.

 

The fair value of cash and cash equivalents approximates their book value due to their short–term nature.

 

The return on cash and cash equivalents for the years ended December 31, 2020 and 2019 were 2.2% and 3.2%, respectively.

 

The following table reflects the credit quality of issuers of investments included in cash and cash equivalents:

 

Rating   2020     2019  
AAA     2,578,090       3,851,656  
F1+     1,286,310       244,547  
A-1     851,394       1,244,462  
F1     207,773       -  
BRC1+     99,923       673,342  
AAAf     28,552       -  
F3     12,184       -  
A     4,319       167,404  
BRC1     2,336       -  
AAAmmf     2,162       -  
Aaa     1,431       -  
AA     546       229,473  
BBB     121       569,514  
AA-     22       -  
A-2     -       89,996  
BB     -       43  
Baa2     -       10  
Other     7,145       5,311  
      5,082,308       7,075,758  

 

See credit risk policy in Note 30.7.

 

F-41 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

7. Trade and other receivables, net

 

    2020     2019  
Current                
Customers                
Foreign     2,021,070       2,759,993  
Domestic     1,913,106       2,015,517  
Fuel price stabilization fund (1)     319,927       256,303  
Related parties (Note 31)     105,048       27,449  
Accounts receivable from employees     97,723       95,693  
Industrial services     39,651       47,691  
Other (2)     322,567       497,688  
      4,819,092       5,700,334  
                 
Non–current                
Accounts receivable from employees     474,693       508,588  
Domestic customers     51,955       52,819  
Related parties (Note 31)     -       93,657  
Other (2)     149,959       131,732  
      676,607       786,796  

 

(1) Corresponds to the application of Colombian Resolution 180522 of March 29, 2010 and other regulations that modify and add to it (Decree 1880 of 2014 and Decree 1068 of 2015), which establish the procedure to recognize the subsidy for refiners and importers of current motor gasoline and diesel, and the methodology for calculating the net position (the value arising from the differences between the parity price and the regulated price, which can be positive or negative). During 2020, the Group paid COP$208,074 from the stabilization fund as follows: Ecopetrol COP$50,131 and Reficar COP$157,943 for the fourth quarter 2019 and the first half of 2020. For the second half of 2020, the fuel price stabilization fund represented an account receivable for the Group.
(2) It mainly corresponds to crude oil loan agreements for transportation systems.

 

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, 2020, 2019 and 2018 are as follows:

 

    2020     2019     2018  
Opening balance     282,791       268,654       170,016  
Additions, net     16,253       14,158       107,725  
Effect of change of control in subsidiaries (Note 28)     (5,517 )     -       -  
Accounts receivable write–off and uses     (2,383 )     (21 )     (9,087 )
Closing balance     291,144       282,791       268,654  

 

F-42 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

8. Inventories, net

 

    2020     2019  
Crude oil     1,719,426       1,965,022  
Fuels and petrochemicals     1,407,297       1,876,247  
Materials for the production of goods     1,927,237       1,816,830  
      5,053,960       5,658,099  

 

The following are the changes of the allowances for losses for the years ended December 31, 2020, 2019 and 2018:

 

    2020     2019     2018  
Opening balance     (131,526 )     (86,938 )     (194,507 )
(Additions) reversals, net     (9,748 )     (44,191 )     115,778  
Foreign currency translation     (122 )     371       (9,717 )
Effect of change of control in subsidiaries (Note 28)     20,075       -       -  
Uses, transfers and reclassifications (1)     11,772       (768 )     1,508  
Closing balance     (109,549 )     (131,526 )     (86,938 )

 

(1) It mainly includes the update of the provision in joint operations.

 

Crude oil, fuel and petrochemicals inventories are adjusted to the lowest between the cost and the net realizable value, as a result of fluctuations in international crude oil prices. The amount recorded for this in 2020 was COP$9,017 (2019 - COP$9,759).

 

9. Other financial assets

 

    2020     2019  
Assets measured at fair value through profit or loss                
Investment Portfolio – Local currency     474,535       1,630,149  
Investment Portfolio – Foreign currency     2,494,124       3,340,908  
      2,968,659       4,971,057  
Assets measured at fair value through other comprehensive income     732       -  
Assets measured at amortized cost     3,391       3,367  
Hedging instruments     98,877       4,868  
      3,071,659       4,979,292  
                 
                 
Current     2,194,651       1,624,018  
Non–current     877,008       3,355,274  
      3,071,659       4,979,292  

 

The average return of the investment portfolio in Colombian pesos and U.S. dollars were approximately 5.6% (2019 – 5.4%) and approximately 2.3% (2019 – 3.6%), respectively.

 

Changes in fair value are recognized in financial results (Note 28).

 

9.1 Restrictions

 

As of December 31, 2020 and 2019, there were no investments with restricted use.

 

F-43 

 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

9.2 Maturity

 

    2020     2019  
Up to 1 year     2,194,651       1,624,018  
1 – 2 years     101,216       983,571  
2 – 5 years     573,420       1,791,549  
> 5 years     202,372       580,154  
      3,071,659       4,979,292  

 

9.3 Fair value

 

The following is the balance of other financial assets by fair value hierarchy level as of December 31, 2020 and 2019:

 

    2020     2019  
Level 1     5,273       472,547  
Level 2     3,062,995       4,503,378  
      3,068,268       4,975,925  

 

There were no transfers between hierarchy levels for the years ended December 31, 2020 and 2019.

 

The securities comprising Group’s portfolio are valued on a daily basis according to the instructions issued by the Financial Superintendence of Colombia. To this end, the information provided by authorized entities is used, which includes data from active markets. For cases in which market data is not available, other directly or indirectly observable data is used.

 

For U.S. dollar–denominated investments, fair value is based on information released by Bloomberg, while for investments denominated in Colombian pesos, fair value is provided by Precia, an entity authorized by the Financial Superintendence of Colombia to provide this service.

 

Within the investment valuation hierarchy process, other relevant aspects are taken into account, such as the issuer’s rating, investment rating and the risk analysis of the issuer performed by the Ecopetrol Business Group.

 

9.4 Credit rating

 

The following table reflects the credit quality of the issuers of other financial assets measured at fair value through profit or loss:

 

    2020     2019  
A-1     1,107,777       -  
BBB-     758,472       -  
F1+     551,626       350,325  
AAA     353,939       2,707,019  
A-3     127,861       -  
A+     60,692       712,934  
F1     43,839       -  
AA-     21,263       186,325  
A     21,179       186,222  
AA     7,759       477,423  
AA+     5,332       155,012  
A1     -       18,168  
BBB     -       159,968  
Rating not available     876       -  
Other     11,044       25,896  
      3,071,659       4,979,292  

 

See credit risk policy in Note 30.8.

 

F-44 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

10. Taxes

 

10.1 Current and Non-current tax assets and liabilities

 

    2020     2019  
Current tax assets                
Income tax (1)     1,823,027       190,605  
Credit tax balance (2)     1,311,693       614,005  
Other taxes (3)     841,575       714,197  
      3,976,295       1,518,807  
Non-current tax assets                
Deferred tax assets     7,673,912       6,809,347  
Income tax credits (4)     397,821       -  
      8,071,733       6,809,347  
                 
Current tax liabilities                
Income tax payable (5)     811,197       1,967,353  
Industry and commerce tax     161,813       195,776  
National tax and surcharge on gasoline     137,710       145,569  
Carbon tax     64,091       54,586  
Value added tax     5,607       33,098  
Other taxes (6)     63,465       174,397  
      1,243,883       2,570,779  
                 
Non-current tax liabilities                
Deferred tax liabilities     1,639,206       1,328,831  
Income tax payable (7)     226,848       70,543  
      1,866,054       1,399,374  

 

(1) Given the payment for self-withholdings during the year, credit for foreign tax paid, credit for 50% of the industry and commerce paid, and VAT credit for acquisition of real productive fixed assets, a favorable balance is generated for the term.

 

(2) Corresponds mainly to the Ecopetrol´s value added tax (VAT) and industry and commerce tax in favour.

 

(3) Includes the VAT credit derived from the acquisition of real productive fixed assets, following Article 95 of Law 2010 of 2019 and municipal advance payments and self-withholdings.

 

(4) Corresponds to the effective VAT credit paid on the acquisition of real productive fixed assets, which, given the limitations established by law, will be used in future income tax returns.

 

(5) In addition to the income tax recognized as a current liability, it includes the short-term portion of the liability of “works for taxes” related to Ecopetrol and Cenit, the income tax payment mechanism for 2017, established in Law 1819 of 2016 for COP$94,185 and COP$39,379 respectively.

 

(6) It mainly includes royalties, transport tax among others.

 

(7) The advance payment mechanism of “works for taxes” is regulated by article 238 of Law 1819 of 2016 - Tax reform, which established it as a form of payment in respect of income tax payable for the years 2017, 2018 and 2019. In compliance therewith, in May 2018, 2019 and 2020, the Group’s companies recognized an asset and a liability for the value of the projects designated for each fiscal year.

 

F-45 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

10.2 Income tax

 

In accordance with Law 2010/2019 (Tax Reform) the tax provisions applicable to individual companies in Colombia for the taxable year 2020 are the following:

 

- The income tax rate applicable to national companies and foreign entities will be 32% for the year 2020, 31% for the year 2021 and 30% for the year 2022 and subsequent years.

 

- For the years 2019 and 2020, the presumptive income rate will be 1.5% and 0.5%, respectively, of the taxpayer's net equity from the immediately previous year. From 2021 the applicable tax rate will be 0%.

 

- 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”) and Esenttia Masterbatch Ltda. ("Esenttia MB").

 

- For fiscal year 2020, the Group had subsidiaries that were subject to a 32% income tax rate, subsidiaries located in free trade zones that were subject to a 15% income tax rate depending upon whether or not they complied with the LSA rules and other subsidiaries 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 Law 1819 of 2016. On the other hand, oil investments amortization will be calculated based on the technical production units as it is recorded for accounting purposes.

 

- 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.

 

- Tax losses generated as of January 1, 2017 may be offset against ordinary net income obtained in the following 12 taxable years.

 

- Following the Article 290 of Law 1819 of 2016, any excess between estimated income reported and CREE that has not yet been offset may be offset in accordance to the formula provided for this purpose in said article and subject to the term established in Article 189 of the Colombian Tax Code.

 

Statute of limitations of tax returns

 

By general rule, the statute of limitations for the income tax return corresponds to 3 years counted as 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 statute of limitations, for the tax returns that are filed as of January 1, 2020.

 

For tax returns with favorable balances, the statute of limitations will be 3 years as of the filing date of the request for refunds or offsetting.

 

For tax returns in which tax losses are carried forward, the statute of limitations will be 6 years (5 years from 2020) counted as of their filing date.

 

With respect to tax returns where tax losses are calculated, the statute of limitations will be 12 years and if the losses are carried forward within the last 2 years of the 12–year period, the statute of limitations will be extended up to 3 additional years from the year of offsetting.

 

The income tax returns of the taxable years 2011, 2012, 2014, 2015, 2016, 2017, 2018 and 2019 and income tax for equality - CREE - of the taxable years 2014, 2015, and 2016 of Group Companies are subject to acceptance and review by the tax authorities.

 

F-46 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Income tax expense

 

    2020     2019     2018  
Current income tax (1)     2,861,606       7,117,040       7,539,093  
Deferred income tax (2)     (791,824 )     (2,365,108 )     783,136  
Adjustments to prior years’ current and deferred tax     (31,121 )     (33,519 )     (63,744 )
Income tax expenses     2,038,661       4,718,413       8,258,485  

 

(1) The variation mainly corresponds to the difference between the bases for determining the tax (COP$4,776,521 in 2020 and COP$19,723,568 in 2019), due to the decrease of the profit.

 

(2) Includes COP$383,346 of tax related to the acquisition Chevron´s stake in the Guajira Association contract (Note 12). Additionally, the deferred tax from tax losses, presumptive income excesses, asset retirement obligation update, among others. This tax was calculated on temporary differences, using the current tax rates at the time of recovery or use.

 

Reconciliation of the income tax expenses

 

The reconciliation between the income tax expense and the current tax applicable to the Ecopetrol Business Group in Colombia is as follows:

 

    2020     2019     2018  
Net income before income tax     4,776,514       19,723,568       20,613,875  
Statutory rate     32.0 %     33.0 %     37.0 %
Income tax at statutory rate     1,528,484       6,508,777       7,627,134  
 Effective tax rate reconciliation items:                        
Non–deductible expenses     289,043       295,550       379,633  
Reversal of deferred tax recognized in prior years     245,508       -       -  
Rate differential adjustment     14,974       132,888       172,352  
Impairment of non-current assets     -       57,646       (128,461 )
Variation in equity accounting method in Invercolsa     7,002       (2,943 )     -  
Non–taxable income (1)     (35,471 )     (524,658 )     (119,963 )
Prior years’ taxes (2)     (50,159 )     (33,519 )     (63,744 )
Foreign currency translation and exchange difference     59,852       (54,319 )     751,210  
Tax discounts and tax credit     (20,572 )     (110,857 )     -  
Ecopetrol U.S.A. adjustment income tax (3)     -       (1,550,152 )     -  
Effect of tax reform     -       -       (359,676 )
Income tax calculated     2,038,661       4,718,413       8,258,485  
 Effective tax rate     42.7 %     23.9 %     40.1 %
                         
Current     2,583,832       7,127,492       7,416,038  
Deferred (4)     (545,171 )     (2,409,079 )     842,447  
      2,038,661       4,718,413       8,258,485  

 

(1) It includes mainly the non-taxable dividends.

 

(2) It includes the update effect of 2020 deferred tax compared to 2019 for COP$19,038.

 

(3) In 2019, two companies, Ecopetrol USA Inc. and Ecopetrol Permian, were incorporated e in the United States for the development of the unconventional hydrocarbons business. US tax regulations business reorganizations (IRC Section 368 (a) (1) (F)) makes it possible to offset tax losses occurring in previous years with future income tax returns. Because the results of Ecopetrol America LLC and Ecopetrol Permian LLC will be consolidated into Ecopetrol USA Inc.’s financial statements, it will be responsible for the payment of taxes in the United States. The International Accounting Standard - IAS 12 establishes when a company has strong evidence that will allow it to offset the tax losses, it is possible to calculate a deferred tax asset. Additionally, the tax projections with the entry into operation of Ecopetrol Permian, allow to infer that it will generate enough income to recover the losses of previous years, therefore the recognition of deferred tax asset is feasible.

 

(4) Includes COP$383,346 that corresponds to deferred tax liability of Guajira association (Note 12).

  

F-47 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

The effective tax rate as of December 31, 2020, is 42.7% (2019 - 23.9%). The increase from the previous year is mainly due to: a) the decrease in projected profit at the end of each year, b) the limitation in the use of the tax credits, c) the effect of the adjustment for exchange differences in the companies of the business group that are dollar functional currency, d) the effect of the adjustment of Permian in 2019 and e) the effect of the companies of the group with losses that have a nominal rate different from the parent company.

 

Deferred income tax

 

    2020     2019  
Deferred tax assets     7,673,912       6,809,347  
Deferred tax liabilities     (1,639,206 )     (1,328,831 )
Net deferred income tax     6,034,706       5,480,516  

 

The detail of deferred tax assets and liabilities is as follows:

 

    2020     2019  
Deferred tax assets (liabilities)                
Loss carry forwards (1)     4,478,606       2,550,816  
Provisions (2)     3,187,850       2,404,032  
Employee benefits (3)     1,874,242       1,875,872  
Accounts payable (4)     (10,626 )     711,503  
Loans and borrowings     846,019       920,203  
Accounts receivable     183,843       139,410  
Excess presumptive income     61,722       298,273  
Other     47,269       (15,189 )
Goodwill (5)     (366,346 )     (363,968 )
Property plant and equipment and Natural and environmental resources (6)     (4,267,873 )     (3,040,436 )
      6,034,706       5,480,516  

 

(1) In 2020, a deferred tax asset for tax losses carryforwards was recognized in the following companies: Ecopetrol USA Inc. (COP$1,663,411), Refinería de Cartagena (COP$1,601,570) and Ecopetrol S.A. (COP$1,189,973).

 

(2) Corresponds to non-deductible accounting provisions, mainly the asset retirement obligation (ARO) provision.

 

(3) Actuarial calculations for health, pensions and bonds, education and other long-term benefits to employees.

 

(4) The variation corresponds to the change in the methodology for the deferred tax in the estimated liabilities.

 

(5) According to Colombian tax law, goodwill is subject to amortization, while under IFRS it is not amortized but such goodwill is subject to impairment tests, and any difference results in a deferred tax liability.

 

(6) For tax purposes, natural and environmental resources and property, plant and equipment have a useful life and a methodology for calculating depreciation and amortization different from those determined under international accounting standards. This item includes the amount of the capital gains of 10% tax rate applicable to the lands. The main variation is related to the income tax rate variation from 31% to 30%.

 

F-48 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Deferred tax details are as follows:

 

    Loss
carry
forwards 		    Provisions     Employee benefits     Accounts payable     Loans and borrowings     Excess
presumptive
income 		 
As of December 31, 2018     1,002,062       1,994,762       1,161,860       365,646       827,452       (37,638 )
Profit or loss     1,548,754       409,270       (57,343 )     345,857       92,751       335,911  
OCI     -       -       771,355       -       -       -  
As of December 31, 2019     2,550,816       2,404,032       1,875,872       711,503       920,203       298,273  
Profit or loss     1,927,790       783,818       39,608       (722,129 )     (74,184 )     (236,551 )
Increase due to business combinations (Guajira association)     -       -       -       -       -       -  
OCI     -       -       (41,238 )     -       -       -  
As of December 31, 2020     4,478,606       3,187,850       1,874,242       (10,626 )     846,019       61,722  

 

    PPE and
Natural
resources 		    Goodwill     Accounts receivable     Others     Total  
As of December 31, 2018     (2,304,140 )     (404,394 )     79,591       (143,717 )     2,541,484  
Profit or loss     (736,296 )     40,426       59,819       341,053       2,380,202  
OCI     -       -       -       (114,520 )     656,835  
Increase in shareholding in Invercolsa     -       -       -       (98,005 )     (98,005 )
As of December 31. 2019     (3,040,436 )     (363,968 )     139,410       (15,189 )     5,480,516  
Profit or loss     (844,091 )     (2,378 )     44,433       (68,306 )     848,010  
Increase due to business combinations
(Guajira association – Note 12) 		    (383,346 )     -       -       -       (383,346 )
OCI     -       -       -       130,764       89,526  
As of December 31, 2020     (4,267,873 )     (366,346 )     183,843       47,269       6,034,706  

  

Deferred tax assets recognized

 

Deferred tax assets recognized in the consolidated financial statements as of December 31, 2020 and 2019 amounted to COP$7,673,912 and COP$6,809,347, respectively and is mainly comprised of the items included in detail of deferred tax assets and liabilities.

 

Deferred tax assets for tax loss carryforwards and excesses of presumptive income tax amounted to COP$4,540,328 and COP$2,849,087 as of December 31, 2020 and 2019 respectively, and is mainly comprised of:

 

  · Tax losses carryforwards that do not expire corresponding to Refinería de Cartagena (COP$8,007,852) and Ecopetrol USA (USD $404 million - COP$1,386,730), amount to COP$9,394,582 (2019 - COP$6,385,989) that generates deferred taxes of COP$1,601,570 (2019 - COP$1,052,848), and COP$306,172 (2019 - COP$182,977), respectively.

 

  ·

Tax losses carryforwards that expire in 20 years from the year in which they were incurred corresponding to Ecopetrol USA amounting to COP$6,532,048 (2019 - COP$6,144,400) (USD $1,904 million) and correspond to deferred tax assets of COP$1,357,239 (2019 - COP$1,288,249).

 

  · Tax losses carryforwards that expire in the following 12 years counted as from the year they were incurred corresponding to Ecopetrol S.A. amounting to COP$3,953,551 resulting in a deferred tax assets of COP$1,189,973.

 

Additionally, as of December 31, 2020 the excess of presumptive income amounted to COP$199,103 resulting in a deferred tax asset of COP$61,722 in Ecopetrol S.A.

 

F-49 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

The Ecopetrol Business Group recognizes deferred tax assets to the extent that it is probable that they will be realized against available sources of income, including projections of future taxable income. In accordance to the tax rules regulation applicable until December 31, 2016, excess of presumptive income and excess minimum base excesses before 2017 incurred in the income tax and income tax for equity equality - (CREE, as its acronym in Spanish) respectively, may be offset with the ordinary taxable income in the following five (5) years, using for this purpose, the formula established in numeral 6th, of Article 290 of Law 1819/2016.

 

The tax loss carryforwards of Ecopetrol USA generated between 2008 and 2017, expire in 20 years from the year in which they were incurred. The tax loss carryforwards generated starting January 1, 2018 have no expiration date and its use is limited to 80% of taxable income.

 

The movements of deferred income tax for the years as of December 31, 2020, 2019 and 2018 are as follows:

 

    2020     2019     2018  
Opening balance     5,480,516       2,541,484       2,682,881  
Deferred tax recognized in profit or loss     928,517       2,409,079       (842,447 )
Increase due to business combination     (383,346 )     (98,005 )     -  
Deferred tax recognized in other comprehensive income (a)     89,526       656,835       666,767  
Foreign currency translation     (80,507 )     (28,877 )     34,283  
Closing balance     6,034,706       5,480,516       2,541,484  

 

  (a) The following is the detail of the income tax recorded in other comprehensive income:

 

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  

 

December 31. 2019   Pre–tax     Deferred tax     After tax  
Actuarial valuation gains (losses) (Note 22.1)     2,571,184       (771,355 )     1,799,829  
Cash flow hedging for future crude oil exports (Note 30.3)     (356,339 )     118,008       (238,331 )
Hedge of a net investment in a foreign operation (Note 30.4)     87,524       (26,257 )     61,267  
Hedge with derivatives instruments     (69,220 )     22,769       (46,451 )
      2,233,149       (656,835 )     1,576,314  

 

December 31. 2018   Pre–tax     Deferred tax     After tax  
Actuarial valuation gains (losses) (Note 22.1)     (29,249 )     33,539       4,290  
Cash flow hedging for future crude oil exports (Note 30.3)     797,658       (264,284 )     533,374  
Hedge of a net investment in a foreign operation (Note 30.4)     1,382,278       (410,324 )     971,954  
Hedge with derivatives instruments     77,872       (25,698 )     52,174  
      2,228,559       (666,767 )     1,561,792  

 

Deferred tax assets not recognized

 

Deferred tax assets related to the tax loss carryforwards incurred by the subsidiaries Andean Chemicals Ltd and Ecopetrol Costa Afuera S.A.S. in the amount of COP$1,912 and COP$71,305, respectively, excess of presumptive income of Hocol Petroleum Company, and Reficar in the amount of COP$245,508, were not recognized, as the Management considered that it is not probable that these deferred tax assets will be recoverable in the foreseeable future.

 

If the Ecopetrol Business Group had recognized this deferred tax asset, the profit for the year ending December 31, 2020 would have increased by COP$247,420.

 

F-50 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Deferred tax assets (liabilities) not recognized

 

As of December 31, 2020, by application of the exception indicated in IAS 12, paragraph 39, the deferred tax asset was not recognized on the difference between the accounting and tax basis associated with investments in Ecopetrol subsidiaries and joint ventures (Base: COP$812,673 - Tax: COP$81,267). 

 

Income tax provisions and contingent liabilities

 

The income tax returns for taxable years 2011, 2012, 2014, 2015, 2016, 2017, 2018 and 2019 and CREE tax returns for taxable years 2014, 2015, and 2016 of Group companies are subject to acceptance and review by part of the tax authorities. The management of the Group companies considers that the amounts recorded as tax liabilities are sufficient and are supported by current regulations, doctrine and jurisprudence to address any claim that may be established with respect to such years.

 

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.

 

10.2.1. Dividend taxes

 

Dividends related to profits generated from the year ended December 31, 2017; dividends will be subject to withholding at a rate of 10% for 2020 (7.5% in 2019). Further, if the earnings against which the dividends are distributed were not subject to corporate tax, these dividends are taxable by the income tax applicable during the distribution period (for 2019 the rate is 33%). In this scenario, the 7.5% tax on dividends will be applicable to the distributed amount, once it is reduced by the 32% in 2020 (33% in 2019) income tax rate.

 

The non-taxed dividends that the Company will receive will not be subject to withholding tax due to the express provision of the regulation that establishes the dividends that are distributed within the business groups duly registered with the Chamber of Commerce and decentralized entities; they will not be subject to withholding tax for this concept.

 

10.2.2. Transfer prices

 

According to the Colombian tax law, income taxpayers who enter into transactions with related parties or related parties located in foreign jurisdictions and in free trade zones or with residents located in jurisdictions considered tax havens, are obliged to determine their ordinary and extraordinary income for purposes of the income tax, its costs and deductions, considering for these operations the arm's length principle.

 

Ecopetrol filed in 2020 its transfer pricing informative return for the 2019 taxable year, and its corresponding supporting documentation, as well as the country-by-country report and the master file for the same year, following the current tax law.

 

For fiscal year 2020, related-party transactions in foreign jurisdictions, as well as the business conditions under which said operations were carried out and the general structure did not vary significantly with respect to the previous year. For this reason, these transactions were carried out in accordance with the arm's length principle. It is estimated that there will be no need for adjustments derived from the analysis of transfer prices for 2020, which imply changes in the income provision of the taxable year 2020.

 

F-51 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

10.2.3. Value Added Tax (VAT)

 

Law 2010/2019 established that VAT paid on the import, creation, construction or acquisition of real productive fixed assets, may be treated as a tax credit for income tax purposes. This VAT cannot be assumed simultaneously as a cost or expense in the income tax and is not allowed to be discounted from the VAT return.

 

10.2.4. Tax reform

 

The Government issued the Law 2010/2019, which makes numerous changes to the Colombian tax rules. The Tax Reform reduces the corporate income tax (CIT) rate from 33% in 2019 to 32% for 2020, 31% for 2021 and 30% for 2022 and onwards.

 

The presumptive income tax rate (i.e., an alternative tax based on a percentage of the net equity of the last year) is reduced from 1.5% to 0.5% in 2020 and 0% for 2021 and onwards.

 

The thin capitalization rule ratio is modified from 3:1 (which includes all debt that generates interest with local and foreign entities, related or unrelated) to a 2:1 ratio that only considers debt transactions involving related local and foreign parties (including back-to-back transactions involving foreign third parties).

 

Tax on dividends

 

As of January 1, 2020, the Tax Reform establishes a 7.5% dividend tax on distributions between Colombian companies. The tax will be charged only on the first distribution of dividends between Colombian entities and may be credited against the dividend tax due once the ultimate Colombian company makes a distribution to its shareholders (nonresident shareholders (entities or individuals) or to Colombian individual residents). The dividend tax on local distributions does not apply if the Colombian companies are part of a registered economic group, or the distribution is to a Colombian entity qualifying for the new Colombian holding company (CHC) regime.

 

Normalization tax

 

The Tax Reform establishes a tax amnesty to “normalize” (i) unreported assets; or (ii) nonexistent liabilities that were included on a tax return. The amnesty will apply only for 2020 (September 25, 2020 is the due date for filing the normalization tax). The applicable tax rate is 15% of the value of the unreported assets or nonexistent liabilities.

 

Value Added Tax

 

Law 2010 of 2019 established that VAT paid on the import, construction or acquisition of real productive fixed assets may be deducted from taxable income. This VAT cannot be reported simultaneously as a cost and expense in the income tax return nor will it be discounted from the sales tax.

 

Concerning VAT, changes have been made to the list of goods and services excluded from VAT as set forth in Articles 424, 426 and 476 of the Tax Code, adding Article 437 to the Tax Code, with regard to guidelines on compliance with formal duties concerning VAT by service providers abroad, and it has been noted that VAT withholding may be up to 50% of the tax amount, subject to regulation by the National Government. The VAT rate remains at 19%.

 

Tax procedures

 

With regards to procedure, changes have been made: (i) withholding tax returns which, being considered ineffective, will be enforceable, (ii) electronic notification of administrative acts; (iii) payment of the entire amount covered by a statement for objections to avoid late interest at the current rate plus two points; and (iv) elimination of the extension of the status of limitations to three (3) additional years due to tax losses offset and (v) a five-year status of limitations for those taxpayers who must comply with the transfer pricing regime.

 

Additionally, an audit benefit was included for fiscal years 2020 to 2021. Under this benefit, the income tax returns that reflect an increase in the net income tax of at least 30%, or 20% over the net income tax of the immediately preceding year, shall be considered firm for six (6) or twelve (12) months, respectively after the date of 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.

 

F-52 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

The above benefit does not apply to: (i) taxpayers who have access to tax benefits due to their location in a specified geographic region; (ii) if it is demonstrated that the withholding taxes reported are non-existent; (iii) if the net income tax is less than 71 UVT (COP$2,5 for fiscal year 2020). The reduced status of limitation stated is not applicable for withholding tax returns and VAT retuns, which shall follow the general tax rules.

 

11. Other assets

 

    2020     2019  
Current                
Partners in joint operations (1)     534,145       921,983  
Advanced payments to contractors and suppliers     503,698       360,781  
Prepaid expenses     369,979       272,007  
Trust funds (2)     218,158       144,798  
Related parties (Note 31)     7,093       57,016  
Other assets     30,963       22,393  
      1,664,036       1,778,978  
Non–current                
Abandonment and pension funds (3)     405,376       445,457  
Trust funds (4)     338,067       171,008  
Employee benefits     221,658       220,998  
Advanced payments and deposits     54,392       56,027  
Judicial deposits and attachments     42,672       40,317  
Other assets     27,949       8,674  
      1,090,114       942,481  

 

(1) Corresponds to the net amount of cash calls and cutbacks generated in relation to the operations carried out with partners through Exploration and Production (E&P) contracts, Technical Evaluations (TEA) contracts and agreements entered in to with the National Hydrocarbons Agency (ANH), as well as through association contracts and other types of contracts.

 

(2) It mainly includes the deposits related to Guajira Association's abandonment fund.

 

  (3) Mainly corresponds to Ecopetrol’s share in trusts established to support costs of abandonment of wells and dismantling of facilities, as well as the payment of future retirement pensions in some association contracts.
     
  (4) Mainly includes the resources invested in fiduciary commissions destined to “works for taxes”, mechanism of payment of the income tax of 2019 and 2020, constituted in compliance with article 238 of Law 1819 of 2016 - Tax reform.

 

F-53 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

12. Business combinations

 

12.1 Additional interest in Invercolsa

 

On November 29, 2019, Ecopetrol acquired an additional interest of 8.53% in Invercolsa (See Note 2.2 Basis of consolidation) obtaining control of Invercolsa and resulting in a total ownership interest of 51.88%.

 

In 2020 Ecopetrol finalized the fair value of separately identified assets and liabilities acquired, that resulted in an adjustment of COP$434,357 from Property, Plant and Equipment and Natural Resources to Goodwill (Note 19).

 

12.2 Guajira association contract

 

On November 22, 2019, Hocol S.A. – a 100% subsidiary of Ecopetrol Corporate Group – signed a Purchase Agreement and Sale of Assets with “Chevron” in order to acquire the entire stake owned by the latter in the Guajira Association (43% of the association contract) and its position as operator. The remaining 57% stake in this association belongs to Ecopetrol S.A. The transaction was subject to the approval of the Superintendence of Industry and Commerce (SIC), which was made official on April 2, 2020, through resolution 12785/2020. As established in the agreement, the start of the operation by Hocol would be the first business day of the month following the date of this approval, i.e. May 1, 2020. Therefore, this is the acquisition date for accounting recognition purposes.

 

The transaction price was determined based on a fixed reference value as of January 1, 2019 plus or minus price adjustments that relied directly on variables associated with the Guajira asset between January 1, 2019 and May 1, 2020. The clauses of the purchase agreement indicate that there is a 180-day term to finish adjusting the differences arising from the movement on the assets acquired and the liabilities assumed. During the review and approval process to determine the final price, Chevron and Hocol signed an agreement to extend the deadline for the closing of the transaction, which is expected to end during the first half of 2021. These deadlines are in regulatory compliance.

 

Ecopetrol and Hocol measured the assets acquired and the liabilities assumed in proportion to their participation in accordance with the provisions of IFRS 11 - Joint agreements and IFRS 3 - Business combinations.

 

For Ecopetrol, this transaction is configured as an acquisition in stages. Fair value was determined using the income approach applying the discounted cash flow methodology. The fair values of property, plant and equipment, natural and environmental resources and deferred tax have been determined based on the information available and following the guidelines of IFRS 3. Therefore, they may have adjustments associated with working capital, in compliance with the clauses of the purchase agreement and the guidelines defined in IFRS 3.

 

The table below summarizes the amounts recognized for the assets acquired and the liabilities assumed at the acquisition date:

 

    Ecopetrol     Hocol     Total  
Assets                        
Accounts receivable     -       19,545       19,545  
Property, plant and equipment     829,121       361,426       1,190,547  
Natural resources     615,642       214,852       830,494  
Right-of-use asset     -       206       206  
Other assets (1)     113,107       145,660       258,767  
      1,557,870       741,689       2,299,559  
Liabilities                        
Accounts payable     (585 )     (20,342 )     (20,927 )
Deferred tax     (383,346 )     (38,611 )     (421,957 )
Provisions     (37,798 )     (34,234 )     (72,032 )
Other liabilities (2)     (34,455 )     (102,487 )     (136,942 )
      (456,184 )     (195,674 )     (651,858 )
Fair value of net assets     1,101,686       546,015       1,647,701  

 

(1) The other assets mainly include the abandonment fund.

 

(2) The other liabilities mainly include the abandonment and pension obligations and customer advances.

 

F-54 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

The effect on operating results as of December 31, 2020 is summarized below:

 

    Ecopetrol     Hocol     Total  
Fair value of the net assets     1,101,686       546,015       1,647,701  
Book value of net assets     (200,660 )     -       (200,660 )
Consideration paid     -       (454,630 )     (454,630 )
Foreign currency translation     -       (5,359 )     (5,359 )
(=) Net profit from the acquisition      901,026       86,026       987,052  
                         
Recognized in:                        
Property, plant and equipment (Note 14)     720,670       361,426       1,082,096  
Natural and environmental resources (Note 15)     563,546       214,852       778,398  
Intangibles (Note 17)     156       -       156  
Accounts receivable     -       19,545       19,545  
Right-of-use asset     -       206       206  
Other assets     -       145,660       145,660  
Accounts payable     -       (20,342 )     (20,342 )
Deferred tax     -       (38,611 )     (38,611 )
Provisions     -       (34,234 )     (34,234 )
Other liabilities     -       (102,487 )     (102,487 )
Consideration paid     -       (454,630 )     (454,630 )
Foreign currency translation     -       (5,359 )     (5,359 )
Subtotal     1,284,372       86,026       1,370,398  
                         
                         
Profit on acquisition before deferred tax (Note 28)     1,284,372       86,026       1,370,398  
(-) Deferred tax expense (Note 10)     (383,346 )     -       (383,346 )
Net profit from the acquisition after deferred tax     901,026       86,026       987,052  

 

Costs related to the acquisition of $19,898 million were excluded from the pre-existing participation and were recognized as operating expenses in the period.

 

Effects on the Ecopetrol Group's results

 

Ecopetrol Group's income includes COP$238,955 related to the acquisition of the Guajira association, while the profit for the year increased by COP$161,423.

 

If this business combination took place on January 1, 2020, the Group's income would have an amount of COP$50,308,407, while the profit for the year would be COP$2,766,398. Management considers that these figures represent an approximate measure of the performance on an annualized basis and provide a benchmark for comparison for future periods.

 

In determining the Group's anticipated income and profits, if the Guajira association had been acquired at the beginning of the current reporting period, management would have calculated the depreciation of property, plant and equipment and natural resources acquired on the basis of its fair value in the initial recognition for the business combination instead of the carrying amounts recognized in the financial statements prior to the acquisition.

 

F-55 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

13. Investments in associates and joint ventures

 

The details on the participations, economic activity, address, area of operations and financial information of the investments in joint ventures and associates can be found in Exhibit 1.

 

  13.1 Composition and movements

 

    2020     2019  
Investment in joint ventures                
Equion Energía Limited     1,642,735       1,515,067  
Offshore International Group     613,258       709,871  
Ecodiesel Colombia S.A.     51,672       46,095  
      2,307,665       2,271,033  
Less impairment:                
Equion Energía Limited     (314,460 )     (322,388 )
Offshore International Group (1)     (609,826 )     (530,330 )
      1,383,379       1,418,315  
Investments in associates                
Gases del Caribe S.A. E.S.P.     1,512,629       1,527,911  
Gas Natural del Oriente S.A. E.S.P.     143,893       166,685  
Gases de la Guajira S.A. E.S.P.     69,518       68,608  
E2 Energía Eficiente S.A. E.S.P.     35,614       28,501  
Extrucol S.A.     26,996       32,847  
Sociedad Colombiana de Servicios Portuarios S.A. - Serviport S.A.     8,541       11,070  
Sociedad Portuaria Olefinas y Derivados     2,599       2,205  
      1,799,790       1,837,827  
Less impairment: Serviport S.A.     (8,541 )     (11,070 )
      1,791,249       1,826,757  
      3,174,628       3,245,072  

 

(1) The movement includes COP$2,527 related to foreign currency translation, recognized in Equity.

 

The following is the movement of investments in associates and joint ventures:

 

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 COP$157,241 (2019 - COP$189,169) from its investments.

 

F-56 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

For the year ended December 31, 2019:

 

    Associates     Joint ventures     Total  
Opening balance     244,662       1,599,674       1,844,336  
Effects of equity method through:                        
Profit or loss     109,538       257,366       366,904  
Other comprehensive income     (174,991 )     4,531       (170,460 )
Dividends declared     (75,674 )     (4,192 )     (79,866 )
Impairment reversal (loss) (Note 18)     142       (318,962 )     (318,820 )
Foreign currency translation and other movements (1)     1,723,080       (120,102 )     1,602,978  
Closing balance     1,826,757       1,418,315       3,245,072  

 

(1) Invercolsa S.A. became a subsidiary as of November 29, 2019, thus the direct investments of Invercolsa in Gases del Caribe S.A. E.S.P., Gas Natural del Oriente S.A. E.S.P., Gases de la Guajira S.A. E.S.P., Extrucol S.A., E2 Energía Eficiente S.A. E.S.P., became direct investments of the Group as of the consolidation.

 

For the year ended December 31, 2018:

 

    Associates     Joint ventures     Total  
Opening balance     225,178       1,105,282       1,330,460  
Effects of equity method through:                        
Profit or loss     105,908       59,928       165,836  
Other comprehensive income     1,731       135,831       137,562  
Dividends declared     (86,847 )     (3,503 )     (90,350 )
Impairment (loss) reversal (Note 18)     (1,308 )     302,136       300,828  
Closing balance     244,662       1,599,674       1,844,336  

 

13.2 Additional information about associates and joint ventures

 

The following is the breakdown of assets, liabilities and results of the two main investments in associates and joint ventures, Equion Energía Limited and the Offshore International Group, as of December 31, 2020 and 2019:

 

    2020     2019  
    Equion Energía Limited     Offshore International Group     Equion Energía Limited     Offshore International Group  
Statement of financial position                                
Current assets     2,616,813       266,240       2,530,453       284,591  
Non–current assets     13,538       1,302,555       95,384       1,481,680  
Total assets     2,630,351       1,568,795       2,625,837       1,766,271  
Current liabilities     81,259       154,086       315,002       310,561  
Non–current liabilities     49,773       871,089       76,768       718,863  
Total liabilities     131,032       1,025,175       391,770       1,029,424  
Equity     2,499,319       543,620       2,234,067       736,847  
Other complementary information                                
Cash and cash equivalents     36,601       110,622       188,820       48,752  

 

F-57 

 

  

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    2020     2019     2018  
    Equion
Energía
Limited 		    Offshore
International
Group 		    Equion
Energía
Limited 		    Offshore
International
Group 		    Equion
Energía
Limited 		    Offshore
International
Group 		 
Statement of profit or loss                                                
Sales revenue     257,066       325,812       1,285,891       529,167       1,490,177       653,054  
Costs     (127,672 )     (364,750 )     (671,179 )     (690,484 )     (755,656 )     (585,192 )
Other operating income (expenses), net     60,852       (234,597 )     (624 )     (64,115 )     29,136       (353,010 )
Financial (expenses) income     (1,090)       (24,034 )     (3,660 )     (31,288 )     (3,659 )     (21,227 )
Income tax     (45,137 )     59,818       (214,048 )     208,473       (338,487 )     (16,594 )
Financial year results     144,019       (237,751 )     396,380       (48,247 )     421,511       (322,969 )
Other comprehensive results     1,223,990       -       1,102,757       —       1,095,090       —  
                                                 
Other complementary information                                                
Depreciation and amortization     41,536       205,243       404,482       226,654       511,615       243,601  

 

This is a reconciliation of equity of the significant investments and the carrying amount of investments as of December 31:

 

    2020     2019  
    Equion
Energía
Limited 		    Offshore
International
Group 		    Equion
Energía
Limited 		    Offshore
International
Group 		 
Equity of the joint venture     2,499,319       543,620       2,234,067       736,847  
% of Ecopetrol’s ownership     51 %     50 %     51 %     50 %
Ecopetrol’s ownership     1,274,654       271,811       1,139,374       368,424  
Additional value of the investment     375,693       341,447       375,693       341,447  
Impairment     (314,460 )     (609,826 )     (322,388 )     (530,330 )
Unrealized gain     (7,612 )     -       -       -  
Carrying amount of the investment     1,328,275       3,432       1,192,679       179,541  

 

F-58 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

14. Property, plant and equipment

 

    Plant
and
equipment 		    Pipelines,
networks
and lines 		    Work in
progress(1) 		    Buildings     Lands     Other     Total  
Cost                                          
Balance as of December 31, 2019     47,995,471       36,370,647       6,259,654       8,157,945       4,054,538       2,660,232       105,498,487  
Additions/capitalizations (1)     1,625,316       1,179,602       1,573,469       390,731       18,705       244,494       5,032,317  
Increase in abandonment costs (Note 23)     181,318       15,035       -       3,885       -       3,126       203,364  
Capitalized financial interests (2)     42,052       31,511       38,756       14,965       753       8,324       136,361  
Exchange differences capitalized     1,338       1,002       1,233       476       24       265       4,338  
Disposals     (491,677 )     (84,184 )     (79,077 )     (16,390 )     (10,155 )     (85,785 )     (767,268 ) 
Effect of control loss in subsidiaries (3)     (298,570 )     (592,885 )     (775 )     (266,526 )     (60,341 )     (144,189 )     (1,363,286 ) 
Adjustment on fair value for business combination  (Note 12)     547,965       44,538       -       54,413       -       73,754       720,670  
Foreign currency translation     1,336,351       478,103       19,804       59,107       73,181       29,876       1,996,422  
Transfers (4)     149,217       (301,675 )     (298,836 )     13,863       36,121       (97,636 )     (498,946 ) 
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  
                                                         
Accumulated depreciation and impairment losses                                                        
Balance as of December 31, 2019     (19,035,642 )     (16,635,110 )     (1,114,366 )     (3,456,254 )     (80,682 )     (961,611 )     (41,283,665 )
Depreciation expense     (2,296,176 )     (1,634,545 )     -       (341,052 )     -       (113,207 )     (4,384,980 )
Reversal (loss) of an impairment (Note 18)     (368,754 )     329,743       (327,751 )     (18,074 )     8,799       (8,601 )     (384,638 )
Disposals     443,259       75,150       3,492       14,279       11       82,310       618,501  
Effect of control loss in subsidiaries (3)     266,825       403,095       262       221,708       30,669       108,081       1,030,640  
Foreign currency translation     (306,506 )     (155,927 )     959       (13,707 )     3,403       (9,738 )     (481,516 )
Transfers/reclassifications     40,125       59,570       413,948       (35,624 )     (40,748 )     (5,734 )     431,537  
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 )
                                                         
                                                         
Net balance as of December 31, 2019     28,959,829       19,735,537       5,145,288       4,701,691       3,973,856       1,698,621       64,214,822  
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  

 

(1) Includes capitalizations for the acquisition of Guajira association by Hocol for a value of COP$361,426 (See Note 12).
(2) Financial interests are capitalized based on the weighted average rate of borrowing costs. See Note 20 - Loans and borrowings.
(3) See effects of control loss in subsidiaries in Note 28.

 

F-59 

 

 

Ecopetrol S.A.

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 (1)     Buildings     Lands     Other     Total  
Cost                                                        
Balance as of December 31, 2018     46,474,369       34,349,283       4,624,703       7,852,278       3,984,576       2,845,802       100,131,011  
Additions / capitalizations     804,570       765,994       2,097,378       243,039       20,098       81,580       4,012,659  
Increase by business combinations     123,436       1,118,178       44,876       9,062       22,924       20,471       1,338,947  
Increase in abandonment costs     148,764       102,402       -       1,248       -       4,337       256,751  
Capitalized financial interests (2)     77,627       32,630       12,831       15,800       1,033       2,389       142,310  
Exchange differences capitalized     4,208       1,769       696       857       56       130       7,716  
Disposals     (500,876 )     (165,936 )     (78,399 )     (24,050 )     (354 )     (71,309 )     (840,924 )
Foreign currency translation     244,666       84,357       2,691       10,757       12,869       6,369       361,709  
Transfers     618,707       81,970       (445,122 )     48,954       13,336       (229,537 )     88,308  
Balance as of December 31, 2019     47,995,471       36,370,647       6,259,654       8,157,945       4,054,538       2,660,232       105,498,487  
Accumulated depreciation and impairment losses                                                        
Balance as of December 31, 2018     (17,985,416 )     (14,777,790 )     (497,441 )     (3,122,523 )     (34,302 )     (913,556 )     (37,331,028 )
Depreciation expense     (2,001,116 )     (1,634,783 )     -       (326,512 )     -       (122,153 )     (4,084,564 )
Reversal (loss) of an impairment
(Note 18) 		    519,835       (113,860 )     (626,878 )     (87,338 )     (35,533 )     (29,349 )     (373,123 )
Disposals     481,384       116,769       -       17,807       -       91,541       707,501  
Foreign currency translation     (103,365 )     (36,341 )     -       (3,656 )     -       (3,323 )     (146,685 )
Transfers/reclassifications     53,036       (189,105 )     9,953       65,968       (10,847 )     15,229       (55,766 )
Balance as of December 31, 2019     (19,035,642 )     (16,635,110 )     (1,114,366 )     (3,456,254 )     (80,682 )     (961,611 )     (41,283,665 )
Net balance as of December 31, 2018     28,488,953       19,571,493       4,127,262       4,729,755       3,950,274       1,932,246       62,799,983  
Net balance as of December 31, 2019     28,959,829       19,735,537       5,145,288       4,701,691       3,973,856       1,698,621       64,214,822  

 

(1) The balance of work in progress as of December 31, 2019 include mainly: Modernization of the Barranca and Cartagena refineries, Castilla facilities and works in the Colombian Petroleum Institute (ICP, by its acronym in Spanish).

 

(2) Financial interests are capitalized based on the weighted average rate of borrowing costs. See Note 20 - Loans and borrowings.

 

F-60 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

15. Natural and environmental resources

 

    Oil
investments 		    Asset
retirement cost 		    Exploration and
evaluation 		    Total  
Cost                              
Balance as of December 31, 2019     59,822,566       5,036,884     8,362,719       73,222,169  
Additions/capitalizations (1)     3,659,270       123,446     2,211,746       5,994,462  
Increase in abandonment costs  (Note 23)     -       2,075,992     28,097       2,104,089  
Disposals     (1,806 )     260     (223,805 )     (225,351 )
Withdrawal of exploratory assets and dry wells (2)     -       -     (448,132 )     (448,132 )
Capitalized financial interests     111,140       -     -       111,140  
Exchange differences capitalized     3,535       -     -       3,535  
Adjustment at fair value for business combinations (Note 12)     563,546       -     -       563,546  
Foreign currency translation     440,978       23,353     (138,809 )     325,522  
Transfers     768,049       (28,084 )   (923,922 )     (183,957 ) 
Balance as of December 31, 2020     65,367,278       7,231,851     8,867,894       81,467,023  
                               
Accumulated amortization and impairment losses                              
Balance as of December 31, 2019     (41,993,097 )     (2,156,274 )   -       (44,149,371 )
Depletion expense     (3,810,349 )     (831,909 )   -       (4,642,258 )
Reversal (loss) of impairment (Note 18)     116,403       -     (334,112 )     (217,709 )
Disposals     213       (40 )   93,975       94,148  
Foreign currency translation     (310,894 )     (14,546 )   -       (325,440 )
Transfers     (108,423 )     21,320     (205,131 )     (292,234 )
Balance as of December 31, 2020     (46,106,147 )     (2,981,449 )   (445,268 )     (49,532,864 )
                               
Net balance as of December 31, 2019     17,829,469       2,880,610     8,362,719       29,072,798  
Net balance as of December 31, 2020     19,261,131       4,250,402     8,422,626       31,934,159  
                                       

(1) Includes capitalizations for the acquisition of Guajira association by Hocol for a value of COP$214,852 (See Note 12).

 

(2) Includes dry wells: 1) Ecopetrol: Nafta 1, Caronte, Alqamari, Boranda Sur and Coyote; 2) Hocol: Obiwan and 3) Ecopetrol Brasil: a well of Saturno. Additionally, exploration costs of Ecopetrol America are included.

 

F-61 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    Oil
investments 		    Asset
retirement cost 		    Exploration and
evaluation 		    Total  
Cost                                
Balance as of December 31, 2018     53,936,041       2,919,146       4,806,000       61,661,187  
Additions/capitalizations (1)     5,144,295       166,431       4,487,467       9,798,193  
Increase (decrease) in abandonment costs     5,703       1,965,309       (38,835 )     1,932,177  
Disposals     (84,052 )     (9,253 )     (142,127 )     (235,432 )
Withdrawal of exploratory assets and dry wells (2)     —       —       (340,271 )     (340,271 )
Capitalized financial interests (3)     94,995       —       10,834       105,829  
Exchange differences capitalized     5,150       —       587       5,737  
Foreign currency translation     68,793       (3,004 )     (112,917 )     (47,128 )
Transfers     651,641       (1,745 )     (308,019 )     341,877  
Balance as of December 31, 2019     59,822,566       5,036,884       8,362,719       73,222,169  
                                 
Accumulated amortization and impairment losses                                
Balance as of December 31, 2018     (36,806,667 )     (1,779,070 )     —       (38,585,737 )
Depletion expense     (3,836,479 )     (383,360 )     —       (4,219,839 )
Impairment loss (Note 18)     (1,017,061 )     —       —       (1,017,061 )
Disposals     83,667       8,511       —       92,178  
Foreign currency translation     (61,862 )     (2,256 )     —       (64,118 )
Transfers     (354,695 )     (99 )     —       (354,794 )
Balance as of December 31, 2019     (41,993,097 )     (2,156,274 )     —       (44,149,371 )
                                 
Net balance as of December 31, 2018     17,129,374       1,140,076       4,806,000       23,075,450  
Net balance as of December 31, 2019     17,829,469       2,880,610       8,362,719       29,072,798  

 

(1) The main capitalizations correspond to the development of assets in the Permian basin.

 

(2) Includes dry wells: 1) Ecopetrol: Tibirita, Provenza 1, La Cira 7000 and Ávila 1; 2) Ecopetrol America LLC: Warrior and Molerusa and 3) Hocol: Mamey West and Venganza Oeste.

 

(3) Borrowing costs are capitalized at the weighted average rate of borrowing costs. See Note 20 - Loans and borrowings.

 

F-62 

 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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, 2020, 2019 and 2018:

 

    2020     2019     2018  
Between 1 and 3 years (a)     -       361,700       496,871  
Between 3 and 5 years (b)     319,368       132,021       375,371  
More than 5 years (c)     589,604       441,389       273,764  
Total suspended exploratory wells     908,972       935,110       1,146,006  
Number of projects exceeding 1 year     16       30       24  
Wells under 1 year of suspension     -       —       9,511  

 

(a) As of December 2019, suspended exploratory wells correspond to Ecopetrol: Caronte, Purple Angel and Gorgon. As of December 2018, suspended exploratory wells correspond to Ecopetrol: Purple Angel, Caronte and discovery wells of Ecopetrol America Inc: Warrior 1.

 

(b) For 2020, the balance corresponds mainly to wells of Ecopetrol: Purple Angel and Gorgon. For 2019, the balance corresponds mainly to wells of Ecopetrol S.A.: Luna-1 and Gala 1K and discovery wells of Ecopetrol America Inc: Warrior 1. For 2018, the balance corresponds mainly to wells of Ecopetrol S.A.: Orca1, Tiribita 1A and Tiribita 3, which are under evaluation.

 

(c) Correspond mainly to i) Ecopetrol S.A.: Orca 1, Luna-1 and Gala 1K, which are under evaluation; and ii) Offshore International Group, temporarily abandoned for future production plans.

 

F-63 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

16. Right-of-use assets

 

The following is the movement of right-of-use assets for the years ended December 31, 2020 and 2019:

 

    Lands and
buildings 		    Plant and
equipment 		    Vehicles     Right-of-use
assets 		    Subleases     Lease
liabilities 		 
Balance as of December 31, 2019     218,513       97,264       140,448       456,225       29,436       1,290,954  
Additions     41,303       14,618       32,582       88,503       -       88,503  
Amortization of the period     (52,200 )     (29,038 )     (98,726 )     (179,964 )     -       -  
Remeasurements     (41,907 )     33,686       69,255       61,034       -       76,799  
Impairment loss     312       29,718       5,844       35,874       -       -  
Disposals     (13,343 )     (4,321 )     -       (17,664 )     -       (28,916 )
Effect of control loss in subsidiaries     (61,044 )     (7,432 )     -       (68,476 )     (29,436 )     (102,671 )
Finance cost     -       -       -       -       -       64,988  
Repayment of borrowings and interests     -       -       -       -       -       (350,539 )
Exchange difference     1,838       (556 )     1,072       2,354       -       16,080  
Balance as of December 31, 2020     93,472       133,939       150,475       377,886       -       1,055,198  

 

(1) See effects of control loss in subsidiaries in Note 28.

 

    Lands and
buildings 		    Plant and
equipment 		    Vehicles     Right-of-use
assets 		    Subleases     Lease
liabilities 		 
Balance as of December 31, 2018     -       -       -       -       -       797,889  
IFRS 16 implementation (January 1st)     236,519       78,412       145,704       460,635       29,610       490,245  
Additions     26,252       123,341       74,900       224,493       -       224,493  
Amortization of the period     (43,759 )     (66,831 )     (64,764 )     (175,354 )     -       -  
Impairment loss (Note 18)     (495 )     (37,601 )     (15,392 )     (53,488 )     -       -  
Disposals     (4 )     (57 )     -       (61 )     -       (50 )
Finance cost     -       -       -       -       3,302       76,139  
Repayment of borrowings and interests     -       -       -       -       (3,476 )     (300,326 )
Exchange difference     -       -       -       -       -       2,564  
Balance as of December 31, 2019     218,513       97,264       140,448       456,225       29,436       1,290,954  

 

17. Intangible assets

 

The following is the movement of intangibles and their amortization and impairment for the years ended December 31, 2020 and 2019:

 

    Licenses and
software 		    Other
intangibles 		    Total  
Cost                        
Balance as of December 31, 2019     994,599       285,247       1,279,846  
Acquisitions     43,817       46,265       90,082  
Foreign currency translation     12,569       5,072       17,641  
Effect of control loss in subsidiaries (Note 28)     (10,584 )     -       (10,584 )
Disposals     (5,430 )     -       (5,430 )
Adjustment on fair value for business combination (Note 12)     156       -       156  
Transfers     30,892       64,174       95,066  
Balance as of December 31, 2020     1,066,019       400,758       1,466,777  
Accumulated amortization                        
Balance as of December 31, 2019     (692,217 )     (104,531 )     (796,748 )
Amortization of the period     (93,907 )     (23,429 )     (117,336 )
Recovery -losses for impairment (Note 18)     (176 )     5       (171 )
Disposals     5,558       11       5,569  
Effect of control loss in subsidiaries (Note 28)     9,877       -       9,877  
Foreign currency translation     (8,689 )     (65 )     (8,754 )
Transfers     (2,116 )     (2,055 )     (4,171 )
Balance as of December 31, 2020     (781,670 )     (130,064 )     (911,734 )
Net balance as of December 31, 2019     302,382       180,716       483,098  
Net balance as of December 31, 2020     284,349       270,694       555,043  
Useful life     <5 years       <7 years          

 

F-64 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    Licenses and
software 		    Other
intangibles 		    Total  
Cost                        
Balance as of December 31, 2018     1,015,720       197,283       1,213,003  
Acquisitions     48,064       120,225       168,289  
Disposals     (114,187 )     (1,041 )     (115,228 )
Foreign currency translation     3,477       (3,946 )     (469 )
Exchange differences capitalized     —       (14 )     (14 )
Transfers     41,525       (27,260 )     14,265  
Balance as of December 31, 2019     994,599       285,247       1,279,846  
Accumulated amortization                        
Balance as of December 31, 2018     (712,329 )     (89,927 )     (802,256 )
Amortization of the period     (88,044 )     (14,982 )     (103,026 )
Reversal of impairment loss (Note 18)     53       2       55  
Disposals     114,143       1,041       115,184  
Foreign currency translation     (2,333 )     (33 )     (2,366 )
Transfers/reclassifications     (3,707 )     (632 )     (4,339 )
Balance as of December 31, 2019     (692,217 )     (104,531 )     (796,748 )
    Net balance as of December 31, 2018     303,391       107,356       410,747  
Net balance as of December 31, 2019     302,382       180,716       483,098  
Useful life     <5 years       <7 years          

 

18. Impairment of non-current assets

 

As mentioned in Note 4.12, 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 (except for goodwill impairment losses).

 

The Impairment of non-current assets includes property, plant and equipment and natural resources, investments in companies, goodwill and other non–current assets. The Ecopetrol Business Group is exposed to future risks derived mainly from variations in: (i) the estimate of future oil prices, (ii) refining margins and profitability, (iii) cost profile, (iv) investments and maintenance expenses, (v) amounts of recoverable reserves, (vi) market and country risk assessments reflected in the discount rate and (vii) 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 (other than goodwill impairment losses) in the profit or loss. Highly sensitive significant estimates affecting each business segments, among others include: (i) in the exploration and production segment, variations of recoverable hydrocarbon estimates, changes in projected realization prices and the discount rate; (ii) 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; and (iii) in the transport and logistics segment, changes in regulated tariffs and transported volumes.

 

As described in Note 2.8, the 2020 Covid-19 pandemic generated a significant impact on the world’s economy and consequently on the oil industry – hand in hand with significant volatility in the financial and commodity markets of all the world. This situation has been improving in recent months, as a result of the reopening of different sectors of the economy and the advancement of vaccination programs.

 

F-65 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Based on the impairment tests conducted by the Ecopetrol Business Group, the following are the impairment or reversals for the years ended on December 31, 2020, 2019 and 2018:

 

Impairment (loss) reversal by segment   2020     2019     2018  
Exploration and Production     (192,693 )     (1,982,044 )     785,940  
Refining and Petrochemicals     (781,528 )     452,163       (984,704 )
Transport and Logistics     341,065       (232,556 )     (169,870 )
      (633,156 )     (1,762,437 )     (368,634 )
                         
Recognized in:                        
Property, plant and equipment (Note 14)     (384,638 )     (373,123 )     (1,083,285 )
Natural resources (Note 15)     (217,709 )     (1,017,061 )     414,102  
Investment in joint ventures and associates (Note 13)     (66,512 )     (318,820 )     300,828  
Right of use assets (Note 16)     35,874       (53,488 )     -  
Intangibles (Note 17)     (171 )     55       (279 )
      (633,156 )     (1,762,437 )     (368,634 )

 

18.1 Exploration and production

 

The impairment reversal of assets of the Exploration and Production segment for the years ended December 31 of 2020, 2019 and 2018 is the following:

 

    2020     2019     2018  
Oilfields     (123,652 )     (1,663,082 )     483,803  
Investment in joint ventures     (69,041 )     (318,962 )     302,136  
Other     —       —       1  
      (192,693 )     (1,982,044 )     785,940  

 

F-66 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

18.1.1 Oilfields

 

An impairment expense was recognized in the year 2020 as a result of the current 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, as a consequence of a significant increase in its reserves, as well as Provincia, Lisama and Orito.

 

In 2019, as a result of the current hydrocarbons sector’s economic context, the behavior of the market variables, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, available technical and operational information, there was an impairment loss in the oilfields that operate in Colombia mainly Tibú, Casabe, Provincia, Underriver, La Hocha y Andalucía and the oilfield operated abroad K2.

 

In 2018, based on new market variables, incorporation of new reserves, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, available technical and operational information, there was a partial reversal of an impairment recognized in previous years for the oil fields that operate in Colombia Casabe, Provincia, Underriver, Tisquirama and Orito and in fields operated abroad Gunflint and K2, and an impairment mainly in Tibú and Dina Norte fields.

 

The following is the breakdown of oilfields impairment losses or reversals for the years ended December 31, 2020, 2019 and 2018:

 

2020

 

 Cash generating units   Carrying
amount 		    Recoverable
amount 		    Impairment (loss)
reversal 		 
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 )

 

2019

 

Cash generating units   Carrying
amount 		    Recoverable
amount 		    Impairment (loss)
reversal 		 
Oil fields in Colombia                        
Reversal     3,842,819       6,047,345       74,577  
Loss     4,992,462       3,322,284       (1,673,258 )
Fields operated abroad                        
Reversal     200,910       539,785       4,391  
Loss     68,792       —       (68,792 )
                      (1,663,082 )

 

2018

 

Cash generating units   Carrying
amount 		    Recoverable
amount 		    Impairment (loss)
reversal 		 
Oil fields in Colombia                        
Reversal     19,156,326       50,462,080       689,665  
Loss     764,808       405,421       (359,387 )
Fields operated abroad                        
Reversal     1,810,618       2,719,086       157,709  
Loss     184,375       180,191       (4,184 )
                      483,803  

 

F-67 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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 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 real discount rate (after tax) determined as the average weighted cost of capital (WACC) and it corresponds to 3.67% (2019 - 6.31% and 2018–7.46%).

 

  – Oil price – Brent: the forecasts include USD$46.36/barrel for the first year, USD$57.00/barrel for the medium term and USD$67.77/barrel for the long term. In 2019, the assumptions taken USD$55.61/barrel for the first year, USD$56.50/barrel for the medium term and USD$71.6/barrel as of the year 2030. In 2018, the assumptions taken USD$81.4/barrel for 2018, USD$67.6/barrel average for the next six years and USD$71.4/barrel as of 2030. International oil price projections were carried out by an independent agency specializing in oil and gas, taking into account the current scenarios of oil quota agreements of the OPEC (Organization of Petroleum Exporting Countries) and the impact of the changes in specifications issued by the international agreement to prevent pollution by ships (Marpol) as of the year 2020 on crude and fuels with high sulfur content.

 

18.1.2 Investments in joint ventures

 

Investments in joint ventures in the Exploration and Production segment are recorded using the equity method of accounting. Ecopetrol evaluates if there is any objective evidence that indicate that the fair value of such investments has deteriorated in the period, especially those for which goodwill has been recorded.

 

As a result, Ecopetrol recognized an (impairment loss) or reversal of impairment on the carrying value as of December 31, as follows:

 

    2020     2019     2018  
Equion Energía Limited     7,928       (134,753 )     108,791  
Offshore International Group     (76,969 )     (184,209 )     193,345  
      (69,041 )     (318,962 )     302,136  

 

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% and 2018 – 8.92%).

 

There was a recovery in 2020 on the investment in Equion mainly originated by the update of the transport rates through pipelines where Ecopetrol has a shareholding, and an impairment loss was recorded on the investment in Offshore International Group considering the fair value of the sale transaction.

 

In 2019, an impairment loss for both. Offshore International Group and Equion Energía Limited was recorded, due to current market variables, decreasing international crude oil prices, conservative position over projects and increasing costs.

 

In 2018, the market showed an improvement in the crude oil and gas production forecast. Operational performance and technical evolution have contributed to strengthening future cash flows that, in turn, contributed to the reversal of the impairment charged recognized in previous years for Offshore International Group and Equion Energy.

 

F-68 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

18.2 Refining and Petrochemical

 

The following is the Cash Generating Units impairment or reversals in the refining and petrochemical segment for the years ended December 31, 2020, 2019 and 2018:

 

2020

 

 

Cash–generating units

  Carrying
amount 		   

Recoverable

amount

    Impairment loss  
Refinería de Cartagena     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 )

 

2019

 

 

Cash–generating units

  Carrying
amount 		   

Recoverable

amount

    Impairment (loss)
reversal 		 
Refinería de Cartagena     22,292,788       23,204,385       911,597  
Bioenergy     575,331       340,991       (234,340 )
Refinería de Barrancabermeja (projects)     901,517       676,423       (225,094 )
                      452,163  

 

2018

 

 

Cash–generating units

  Carrying
amount 		   

Recoverable

amount

    Impairment loss  
Refinería de Cartagena     23,411,058       22,640,761       (770,297 )
Bioenergy     774,343       560,882       (213,461 )
Other     946       —       (946 )
                      (984,704 )

 

The grouping of assets to determine the CGUs is consistent with prior periods.

 

18.2.1 Refinería de Cartagena

 

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.

 

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 5.10% (2019-6.23% and 2018-6.48%), determined under WACC methodology; (iii) 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; (iv) level of costs and long–term operating expenses in line with international refinery standards of similar configuration and conversion capacity; (v) refinery throughput and production; and (vi) 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.

 

F-69 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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.

 

The reversal of impairment recorded for 2019, is mainly related to macroeconomic assumptions changes which decreased the discount rate used to value the assets; this is explained by the decreasing risk and the Company’s cost of the debt. Together, operational management and financial results allowed the support of operational improvements included in the forecast that compensate in some measure the effects related to the impact that the MARPOL regulation will have on the margins’ forecast of refined products and the crude oil basket price discounts. The results of 2019 were impacted by a higher knowledge of the Refinery capabilities and efficient operational management.

 

The impairment recorded for 2018 is explained by: i) an adjustment in market expectations in relation to the impact that the implementation of the MARPOL regulation will have on margins of refined products, ii) the differential of light and heavy crudes that serve as raw material; and iii) fundamental macroeconomic changes that increased the discount rate used for the valuation of Reficar's assets, mainly associated with the increase in the risk-free rate and higher market risk premiums. Improvements in operational and commercial inputs associated to the refinery optimization as well as the tax effects of the “Tax reform” (tax reform) partially offset the effects of the macroeconomic variables.

 

18.2.2 Bioenergy

 

Starting June 24, 2020, Bioenergy entered the mandatory liquidation process. Therefore, as of this date the Group does not have control over Bioenergy and it is no longer a part of the consolidated figures.

 

An impairment expense was recorded in 2019 in the amount of $234,340. This value was mainly generated by changes in operating variables, changes in the projection of operating flows and the need for greater resources, mainly due to the results of the renewal of older cane plantations. An impairment loss was observed in 2018 mainly due to the updating of the project entry dates, the stabilization process of the industrial plant and the updating of operating variables.

 

The recoverable amount of Bioenergy for 2019 and 2018 was calculated based on the fair value less the costs of disposal level, which is greater than the value in use and corresponds to the future cash flows discounted after taxes on profit. The fair value hierarchy is 3.

 

The significant assumptions used to determine the recoverable amount included: (a) forecast of ethanol prices based on projections made by Group specialists and (b) a 6.03% discount rate in real terms (2018 – 6.97%) determined under the WACC methodology.

 

  18.2.3 Refinería de Barrancabermeja

 

An impairment expense of COP$341,000 was recognized as of December 31, 2020 as a result 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.

 

During 2019, a loss of COP$225,094 was recorded, primarily related to engineered works for the integral development of the Refinería de Barrancabermeja Modernization Project, mainly due to the advance in the technical analysis of options to the eventual improvement of the conversion of the Refinery. Once the project is reactive, Ecopetrol will evaluate whether it could reverse any impairment loss recorded in the previous years.

 

During 2018, the Refinería de Barrancabermeja Modernization Project, which is currently suspended, was evaluated and there were no indications that implied the recognition of additional impairment.

 

F-70 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

18.3 Transport 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 3.17% (2019 - 4.88% and 2018 - 5.60%) and iii) transport volume projections based on the end of year results for 2020 and the long-term volumetric transport program.

 

In 2020, Cenit recognized an impairment recovery of COP$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 COP$7,049,007 and their book value is COP$2,153,631.

 

In 2019, we recorded an impairment loss of COP$232,556, mainly related to the cash–generating unit of the South COP$106,983, by Puerto de Tumaco and the TransAndino Pipeline (OTA), which means an impairment loss of 100% of the book value; and the cash-generating unit of the North COP$125,140; both include the right-of-use assets. This impairment loss was generated mainly by decreased volume transport to determine the income forecast and the lower efficiency costs.

 

In 2018, the main impairment recorded was COP$167,917, corresponding to the systems of the Southern Cash Generating Unit (CGU), composed of the Tumaco Port and the TransAndino Pipeline (OTA) and its afferent pipelines, the Mansoyá - Orito Pipeline (OMO), San Miguel - Orito (OSO), and Churuyaco- Orito (OCHO). This value was generated mainly by a decrease in the volume projections for the southern systems, and an increase in the need for maintenance capex to reduce the operational risk of the transport systems.

 

19. Goodwill

 

    2020     2019  
Oleoducto Central S.A.     683,496       683,496  
Hocol Petroleum Ltd.     537,598       537,598  
Invercolsa S.A. (1)     434,357       -  
Andean Chemical Ltd     127,812       127,812  
Propilco S.A.     108,137       108,137  
      1,891,400       1,457,043  
Less impairment Hocol Petroleum Ltd.     (297,121 )     (297,121 )
      1,594,279       1,159,922  

 

(1) Corresponds to the value recognized by updating the fair value of Invercolsa S.A. (Note 12).

 

As of December 31, 2020 and 2019, the Ecopetrol Business Group assessed the recoverability of the carrying value of goodwill generated in the acquisition of subsidiaries. The recoverable amount was determined based on the realization value less costs of disposal using the present value of future cash flows for each of the companies acquired with goodwill. The source of information used the financial projections of each company derived from the business plans approved by management, which were developed based on long-term macroeconomic factors such as price curves and margins and fundamental assumptions of supply and demand. As a result of the analysis, the Ecopetrol Business Group did not recognize any goodwill impairment for these periods.

 

F-71 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

20. Loans and borrowings

 

  20.1 Composition of loans and borrowings

 

   

Weighted average effective

interest rate as of December 31

    2020     2019  
    2020     2019              
Local currency                                
Bonds     6.4 %     8.7 %     1,084,461       1,567,598  
Syndicated loan     5.6 %     8.0 %     811,079       1,115,874  
Lease liabilities (1)     6.6 %     7.2 %     836,489       1,039,303  
Commercial loan     6.3 %     8.3 %     312,408       737,032  
                      3,044,437       4,459,807  
Foreign currency                                
Bonds (2)     6.0 %     5.9 %     33,944,548       25,832,740  
Commercial loan (3)     3.6 %     4.1 %     8,247,014       6,586,538  
Loans from related parties (Note 31)     0.8 %     2.4 %     1,277,046       1,108,403  
Lease liabilities (1)     6.1 %     6.2 %     218,709       251,651  
                      43,687,317       33,779,332  
                      46,731,754       38,239,139  
Current                     4,923,346       5,012,173  
Non–current                     41,808,408       33,226,966  
                      46,731,754       38,239,139  

 

(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.

 

(2) On April 29, 2020, Ecopetrol issued and placed external public debt bonds for an amount of USD$2,000 million, with a 10-year term and a coupon rate of 6.875%.

 

(3) Includes contingent credit line for USD$665 million with international banking (Scotiabank and Mizuho Bank).

 

In 2020, financial obligations were acquired for a total amount of COP$13,805,403 (2019 – COP$359,876 and 2018 – COP$517,747) as part of the market risk mitigation strategy (Note 30).

 

  20.2 Fair value of loans

 

The fair value of loans and borrowings is COP$52,721,790 and COP$43,261,792 as of December 31, 2020 and 2019, respectively.

 

For fair value measurement, local currency bonds were valued using Precia reference prices, while bonds in U.S. dollars were valued using Bloomberg. With regard to the other financial obligations for which there is no market benchmark, a discount to present value technique was used. These rates incorporate market risk through some benchmarks (Libor, FTD) and the Ecopetrol Business Group’s credit risk (spread).

 

F-72 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

  20.3 Maturity of loans and borrowings

 

The following are the maturities of loans and borrowing as of December 31, 2020:

 

    Up to 1
year (1) 		    1 - 5 years     5-10 years     > 10 years     Total  
Local currency                                        
Bonds     65,829       354,081       370,900       293,651       1,084,461  
Syndicated loan     242,660       568,419       -       -       811,079  
Financial leasing     167,059       418,938       211,233       39,259       836,489  
Other     106,410       205,998       -       -       312,408  
      581,958       1,547,436       582,133       332,910       3,044,437  
Foreign currency                                        
Bonds     1,905,325       14,692,852       12,109,859       5,236,512       33,944,548  
Commercial loans     1,098,593       6,563,863       584,558       -       8,247,014  
Loans from related parties     1,277,046       -       -       -       1,277,046  
Financial leasing     60,424       149,381       8,904       -       218,709  
      4,341,388       21,406,096       12,703,321       5,236,512       43,687,317  
      4,923,346       22,953,532       13,285,454       5,569,422       46,731,754  

 

(1) Includes short–term credit and the current portion of long–term debt, as applicable.

 

The following are the maturities of loans and borrowing as of December 31, 2019:

 

    Up to 1
Year (1) 		    1 - 5 years     5-10 years     > 10 years     Total  
Local currency                                        
Bonds     571,969       403,996       358,976       232,657       1,567,598  
Syndicated loan     361,545       754,329       —       —       1,115,874  
Financial leasing     179,448       559,337       235,791       64,727       1,039,303  
Other     218,375       343,049       121,679       53,929       737,032  
      1,331,337       2,060,711       716,446       351,313       4,459,807  
Foreign currency                                        
Bonds     1,386,032       13,873,755       5,574,713       4,998,240       25,832,740  
Commercial loans     1,129,117       4,163,624       1,253,446       40,351       6,586,538  
Loans from related parties     1,108,403       —       —       —       1,108,403  
Financial leasing     57,284       175,962       18,405       —       251,651  
      3,680,836       18,213,341       6,846,564       5,038,591       33,779,332  
      5,012,173       20,274,052       7,563,010       5,389,904       38,239,139  

 

  (1) Includes short–term credit and the current portion of long–term debt, as applicable.

 

F-73 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

  20.4 Breakdown 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, 2020 and 2019:

 

    2020     2019  
Local currency                
Fixed rate     523,870       598,802  
Floating rate     2,520,567       3,861,005  
      3,044,437       4,459,807  
Foreign currency                
Fixed rate     38,706,328       31,087,439  
Floating rate     4,980,989       2,691,893  
      43,687,317       33,779,332  
      46,731,754       38,239,139  

 

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.

 

  20.5 Loans designated as hedging instrument

 

As of December 31, 2020, Ecopetrol S.A. designated USD$8,549 million (2019 – USD$7,331 million) of foreign currency debt as a hedging instrument, of which USD$7,249 million is used to hedge the net investment in foreign operations with the US dollar as their functional currency, and USD$1,300 million is used to hedge the cash flows of future crude oil exports. See Note 30 – Risk management.

 

  20.6 Guarantees and covenants

 

Financing obtained directly by Ecopetrol S.A. in capital markets has no guarantees granted or financial covenant restrictions.

 

The following is a summary of certain restrictions contained in certain other loan instruments of Ecopetrol Business Group. As of Dec 31, 2020 the covenants, loans and payments have been fulfilled.

 

  – The loan entered into by Oleoducto de los Llanos was guaranteed with the economic rights of the ship–or–pay transportation agreements with Frontera Energy Corp and also includes certain restrictions regarding capital contributions and asset disposal. In August 2020, the payment of the last installment of the syndicated loan was made, thus ending the syndicated loan agreement signed with Grupo Aval.

 

  – The syndicated loan entered into by Oleoducto Bicentenario requires that this subsidiary maintain an established relationship of leverage and solvency and cash flow / service to the debt.

 

F-74 

 

  

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

20.7 Movement of net financial debt

 

The following is the movement of net financial debt as of December 31, 2020, 2019 and 2018:

 

    Cash and
equivalents 		    Other financial
assets 		    Loans and
borrowings 		    Net financial
debt 		 
Balance as of December 31, 2018     6,311,744       8,147,815       (38,062,645 )     (23,603,086 )
Cash flow     505,466       (3,117,549 )     3,303,303       691,220  
Exchange difference:                                
Recognized in profit or loss     258,548       182,396       (151,518 )     289,426  
Recognized in other comprehensive income     -       -       (53,911 )     (53,911 )
Financial cost registered to projects     -       -       (261,592 )     (261,592 )
Financial income (expense) recognized in profit or loss     -       (18,551 )     (1,894,490 )     (1,913,041 )
Foreign currency translation     -       (204,441 )     (14,627 )     (219,068 )
Other movements that do not generate cash flow (1)     -       (10,378 )     (1,103,659 )     (1,114,037 )
Balance as of December 31, 2019     7,075,758       4,979,292       (38,239,139 )     (26,184,089 )
Cash flow     (1,971,156 )     (2,107,856 )     (6,105,296 )     (10,184,308 )
Exchange difference:                                
Recognized in profit or loss     (22,294 )     38,701       747,744       764,151  
Recognized in other comprehensive income     -       -       (722,458 )     (722,458 )
Financial cost registered to projects     -       -       (255,372 )     (255,372 )
Financial income (expense) recognized in profit or loss     -       43,948       (2,386,537 )     (2,342,589 )
Foreign currency translation     -       42,529       (175,885 )     (133,356 )
Effect of loss of control in subordinates     -       -       528,981       528,981  
Other movements that do not generate cash flow     -       75,045       (123,792 )     (48,747 )
Balance as of December 31, 2020     5,082,308       3,071,659       (46,731,754 )     (38,577,787 )

 

(1) Corresponds mainly to the recognition of right-of-use assets and lease liabilities due to the initial adoption of IFRS 16 - Leases as of January 1, 2019.

 

21. Trade and other payables

 

    2020     2019  
Suppliers     6,491,909       8,115,015  
Partners’ advances     497,898       925,761  
Withholding tax     462,429       673,204  
Insurance and reinsurance     240,803       136,041  
Dividends payable (1)     223,571       157,181  
Deposits received from third parties     85,545       44,826  
Related parties (Note 31)     72,316       187,616  
Agreements in transport contracts (2)     37,941       71,239  
Hedging operations     6,405       -  
Various creditors     351,288       402,808  
      8,470,105       10,713,691  
Current     8,449,041       10,689,246  
Non - current     21,064       24,445  
      8,470,105       10,713,691  

 

(1) During 2020, the Group paid dividends to its shareholders in the amount of COP$8,734,351 (2019 – COP$13,867,029 and 2018 – COP$4,427,701) net of withholdings when applicable.

 

(2) Corresponds to the value of the debt for agreements in the pipelines transportation contracts, calculated in the volumetric compensation for quality and other inventory management agreements.

 

The carrying amount of trade accounts and other accounts payable approximates their fair value due to their short–term nature.

 

F-75 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

22. Provisions for employees’ benefits

 

    2020     2019  
Post–employment benefits                
Healthcare     7,193,527       6,908,799  
Pension     2,819,985       2,853,718  
Education     485,792       458,441  
Bonds     342,669       352,917  
Other plans     102,632       98,729  
Termination benefits – Voluntary retirement plan (1)     713,407       124,186  
      11,658,012       10,796,790  
Social benefits and salaries     674,080       587,596  
Other employee benefits     91,575       96,678  
      12,423,667       11,481,064  
                 
Current     2,022,137       1,929,087  
Non–current     10,401,530       9,551,977  
      12,423,667       11,481,064  

 

(1) Includes for 2020 an obligation for a new voluntary retirement plan, on which Ecopetrol made offers to a part of its workers during the year. This plan was approved at the end of 2019 by the Company's Board of Directors (Note 22.6).

 

  22.1 Post–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, 2020 and 2019:

 

    Pension and bonds (1)     Other     Total  
    2020     2019     2020     2019     2020     2019  
Liabilities for employee benefits                                                
Opening balance     15,916,472       14,131,943       7,593,171       6,212,118       23,509,643       20,344,061  
Current service cost     -       -       118,035       76,478       118,035       76,478  
Past service cost (2)     -       -       631,761       -       631,761       -  
Interest expense     882,785       920,622       439,682       418,553       1,322,467       1,339,175  
Actuarial gains     418,187       1,755,300       87,311       1,273,409       505,498       3,028,709  
Benefits paid     (897,061 )     (891,393 )     (359,366 )     (387,387 )     (1,256,427 )     (1,278,780 )
Closing balance     16,320,383       15,916,472       8,510,594       7,593,171       24,830,977       23,509,643  
                                                 
Plan assets                                                
Opening balance     12,709,838       12,348,557       3,015       3,954       12,712,853       12,352,511  
Return on assets     700,168       801,065       136       217       700,304       801,282  
Contributions to funds     -       -       370,090       83,071       370,090       83,071  
Benefits paid     (897,061 )     (891,393 )     (358,199 )     (84,243 )     (1,255,260 )     (975,636 )
Actuarial gains     644,784       451,609       194       16       644,978       451,625  
Closing balance     13,157,729       12,709,838       15,236       3,015       13,172,965       12,712,853  
Net post–employment benefits liability     3,162,654       3,206,634       8,495,358       7,590,156       11,658,012       10,796,790  

 

(1) There is no cost for the pension and pension plans service, due to the fact that the beneficiaries were retired as of July 31, 2010.

 

(2) It includes the new voluntary retirement plan.

 

F-76 

 

 

Ecopetrol S.A.

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, 2020, 2019 and 2018:

 

    2020     2019     2018  
Recognized in profit or loss                        
Interest expense. net     622,163       537,893       485,842  
Current service cost     118,035       76,478       77,373  
Past service cost     —       —       50,489  
Remedies     —       10,213       503  
      740,198       624,584       614,207  
Recognized in other comprehensive income                        
Pension and pension bonds     226,597       (1,303,693 )     1,003  
Healthcare     (33,324 )     (1,268,379 )     (17,356 )
Education and severance     (55,693 )     922       45,509  
Termination benefits – Voluntary retirement plan     (121 )     (34 )     93  
      137,459       (2,571,184 )     29,249  
Deferred tax     (41,238 )     771,355       (33,539 )
      96,221       (1,799,829 )     (4,290 )

 

22.2 Plan assets

 

Plan assets are resources held by pension trusts for payment of pension obligations. Payments for health and education post–employment benefits is 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, 2020 and 2019:

 

    2020     2019  
Bonds issued by the national government     4,958,612       4,301,961  
Bonds of private entities     3,177,531       3,122,630  
Other foreign currency     1,992,800       870,859  
Other local currency     1,502,349       1,899,787  
Other public bonds     777,562       1,082,815  
Variable yield     679,448       823,977  
Bonds of foreign entities     84,663       610,824  
      13,172,965       12,712,853  

 

23.3% (2019 – 26.6%) 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 76.7% (2019 – 73.4%) are classified as level 2.

 

The fair value of level 2 plan assets is calculated using prices quoted in the assets’ market. The Ecopetrol Business Group obtains these prices through reliable financial data providers recognized in Colombia or abroad depending on the investment.

 

For the securities issued in local currency, the fair value of plan assets is calculated using information published by Precia, a price supplier authorized by the Financial Superintendence of Colombia. According to its methodology, prices are calculated based on market information on the valuation date or estimated from historical inputs according to the criteria established for the calculation of each of the prices.

 

The average price is calculated based on the most representative market of the transactions carried out through electronic platforms approved and supervised by the regulator.

 

On the other hand, the estimated price is calculated for investments that do not reflect enough information to estimate an average market price, replicating the quoted prices for similar assets or prices obtained through quotes from brokers. This estimated price is also given by Precia as a result of the application of robust methodologies approved by the financial regulator and widely used by the financial sector.

 

F-77 

 

 

Ecopetrol S.A.

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:

 

    2020     2019  
Nation     5,102,222       4,448,221  
AAA     4,369,805       5,138,279  
AA+     570,716       837,009  
BBB-     458,273       455,201  
BBB     201,163       319,514  
AA     134,454       6,679  
F1+     61,192       56,728  
BRC1+     52,296       68,313  
A3     11,633       17,267  
BBB+     10,328       22,113  
AA-     4,014       16,067  
BAA3     -       219,830  
SP1+     -       84,933  
A-1+     -       78,156  
BAA1     -       15,538  
A     5,307       11,841  
Other credit ratings     297,048       30,129  
Not available ratings     1,894,514       887,035  
      13,172,965       12,712,853  

 

See credit risk policy in Note 30.8.

 

22.3 Actuarial 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, 2020 and 2019:

 

2020   Pension     Bonds     Health     Education     Other benefits (1)  
Discount rate     5.50 %     4.75 %     6.00 %     5.00 %     4.09 %
Salary growth rate     N/A       N/A       N/A       N/A       4.70 %
Expected inflation rate     3.00 %     3.00 %     3.00 %     3.00 %     3.00 %
Pension growth rate     3.00 %     N/A       N/A       N/A       N/A  
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 %     N/A  

 

F-78 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

2019   Pension     Bonds     Health     Education     Other benefits (1)  
Discount rate     5.75 %     5.25 %     6.00 %     5.50 %     4.83 %
Salary growth rate     N/A       N/A       N/A       N/A       5.50% / 4.70  
Expected inflation rate     3.00 %     3.00 %     3.00 %     3.00 %     3.00 %
Pension growth rate     3.00 %     N/A       N/A       N/A       N/A  
Cost trend                                        
Short–term rate     N/A       N/A       7.00 %     4.00 %     N/A  
Long–term rate     N/A       N/A       4.00 %     4.00 %     N/A  

 

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.

 

The mortality table used for the calculations was that of ‘Valid Annuitant’ for men and women based on the experience gained for the period 2005–2008 of the Colombian Social Security Institute.

 

22.4 Maturity of benefit obligation

 

The cash flows required for payment of post–employment obligations are the following:

 

Period     Pension and bonds     Other benefits     Total  
  2021       967,810       482,953       1,450,763  
  2022       996,869       493,791       1,490,660  
  2023       1,019,379       507,009       1,526,388  
  2024       1,034,972       511,627       1,546,599  
  2025       1,069,252       514,556       1,583,808  
  2026 and thereafter       5,607,391       2,602,556       8,209,947  

 

22.5 Sensitivity 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, 2020:

 

    Pension     Bonds     Health     Education     Other benefits  
Discount rate                                        
–50 basis points     16,139,465       1,147,350       7,798,461       515,004       846,709  
+50 basis points     14,368,856       1,072,868       6,715,899       464,394       812,726  
Inflation rate                                        
–50 basis points     14,314,193       1,072,094       N/A       N/A       717,069  
+50 basis points     16,193,316       1,147,825       N/A       N/A       740,501  
Salary growth rate                                        
–50 basis points     N/A       N/A       N/A       N/A       96,530  
+50 basis points     N/A       N/A       N/A       N/A       105,392  
Cost trend                                        
–50 basis points     N/A       N/A       6,720,777       464,319       N/A  
+50 basis points     N/A       N/A       6,720,777       514,849       N/A  

 

F-79 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

22.6 Voluntary retirement plan

 

In October 2019, the Ecopetrol’s Board of Directors approved a new employee retirement plan that included four categories of retirements from January 2020 until December 2023: compliance of the work cycle (pension), Retirement Plan A (rent), Retirement Plan B (Bonus) and improved compensation. As for December 31, 2019, the Ecopetrol Business Group has not recognize a provision related to this plan, since it will be understood as an obligation at the time the Company offers the plan and each employee voluntarily accepts their retirement by taking advantage of any of the mentioned categories. In May 2020, Ecopetrol started offering this retirement plan, to which 421 workers have applied.

 

In August 2016, the Ecopetrol offered a voluntary retirement plan, which as of December 31, 2020 was used by 125 workers (2019 – 132) who met certain requirements. This plan includes benefits such as monthly income, education and health benefits until the date on which the employee is granted their retirement pension.

 

As of December 31, 2020, the amount of the net obligation associated with voluntary retirement plans is $713,407 (2019 - $124,186).

 

23. Accrued liabilities and provisions

 

    Asset
retirement
obligation 		    Litigation     Environmental
contingencies and
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  

 

    Asset
retirement
obligation 		    Litigation     Environmental
contingencies and
others 		    Total  
                         
Balance as of December 31, 2018     6,719,275       127,945       906,792       7,754,012  
Increase in abandonment costs     2,188,928       —       —       2,188,928  
Additions     112,486       58,913       90,854       262,253  
Uses     (410,191 )     (45,342 )     (59,755 )     (515,288 )
Financial costs     226,803       —       3       226,806  
Foreign currency translation     (5,240 )     79       1,211       (3,950 )
Transfers     3,359       (4,166 )     6,334       5,527  
Balance as of December 31, 2019     8,835,420       137,429       945,439       9,918,288  
Current     589,411       28,662       171,224       789,297  
Non-current     8,246,009       108,767       774,215       9,128,991  
      8,835,420       137,429       945,439       9,918,288  

 

F-80 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    Asset
retirement
obligation 		    Litigation     Environmental
contingencies and
others 		    Total  
Balance as of December 31, 2017     5,527,324       182,966       827,159       6,537,449  
Increase in abandonment costs     1,062,280       —       —       1,062,280  
Additions     71,015       61,851       174,780       307,646  
Uses     (182,130 )     (114,647 )     (100,215 )     (396,992 )
Financial costs     186,518       —       —       186,518  
Foreign currency translation     54,610       (2,368 )     10,983       63,225  
Transfers     (342 )     143       (5,915 )     (6,114 )
Balance as of December 31, 2018     6,719,275       127,945       906,792       7,754,012  
Current     549,678       88,623       176,108       814,409  
Non-current     6,169,597       39,322       730,684       6,939,603  
      6,719,275       127,945       906,792       7,754,012  

 

23.1 Asset 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 3.5 – Abandonment and dismantling costs of fields and other facilities. 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, taking into account the temporariness and risks of this obligation. The discount rates used in the estimate of the obligation as of December 31, 2020 were: Exploration and Production 2.65% (2019 – 3.01%), Transportation and Logistics 2.71% (2019 – 2.61%) and Refining and Petrochemicals 3.67% (2019- 3.94%). The increase in the provision in 2020 was generated due to the fall in discount rates, directly associated with the decrease in macroeconomic variables impacted by Covid-19.

 

23.2 Environmental 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 2018 and article 321 of Law 1955 of 2019 in relation to the projects that Ecopetrol 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.

 

In 2017, the main changes established by these decrees were related to the areas and lines of investment and the basis for settlement of the obligations. Similarly, June 30, 2017 was declared the maximum date to modify investment plans that were underway. On June 30, 2017, Ecopetrol filed with the National Environmental Licensing Authority (ANLA) certain investment plans to meet the 1% mandatory investment based on the new decrees, relative to investment lines, maintaining the settlement base of Decree 1900.

 

In 2019, Law 1955/2019 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 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 has filed an appeal for reconsideration with ANLA in most cases, which are under review by this authority.

 

F-81 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

23.3 Contingencies

 

Oleoducto Bicentenario de Colombia S.A.S.

 

During July 2018, the carriers Frontera Energy Colombia Corp. (Frontera), Canacol Energy Colombia S.A.S. (Canacol) and Vetra Exploración y Producción Colombia S.A.S. (Vetra and, together with Frontera and Canacol, the Carriers) sent letters to Oleoducto Bicentenario de Colombia S.A.S. (Bicentenario) alleging there were early termination rights under the Ship-or-Pay Transport Agreements entered by each of them and Bicentenario in 2012 (the Transport Agreements). Bicentenario has rejected the terms of the letters, noting that there is no option for early termination and reiterating to the Carriers that the Transport Agreements are current and therefore the Carriers must fulfill their obligations under the Transport Agreements in a timely fashion.

 

Under Bicentenario’s understanding that the Transport Agreements remain current and that the Carriers are in violation of their obligations under such agreements, Bicentenario declared the Carriers delinquent because of their failure to pay for transport service under the aforementioned agreements. Consequently, Bicentenario executed the standby letters of credit posted as guarantee for the Transport Agreements.

 

On October 19, 2018, Bicentenario notified Frontera of the existence of a “Dispute” pursuant to Clause 20 of the respective Transport Agreement and moved to the party dispute settlement stage as provided for in such clause. Such discussions ended without an agreement on December 19, 2018. On January 28, 2019, Bicentenario filed an Arbitration Claim against Frontera in accordance with the arbitration clause of the Transportation Agreement to claim any compensation, indemnification or other restitution deriving from the alleged early termination of said agreements. Similarly, on November 1, 2018, Bicentenario notified Vetra and Canacol of the existence of a “Dispute” pursuant to Clause 20 of the respective Transport Agreement and moved to the party dispute settlement stage as provided for in each such respective clause. Such discussions ended without agreement on March, 2019.

 

See section Bicentenario, Cenit and Frontera Settlement Agreement below for further developments on the disputes.

 

Cenit Transporte y Logística de Hidrocarburos S.A.S. (“Cenit”)

 

On November 2018, Cenit filed an arbitration claim against Frontera Energy Group (“Frontera”) claiming that the Ship or Pay Agreements of the Caño Limón - Coveñas pipeline, which termination was alleged by Frontera, are in full force and effect and that Frontera is obliged to comply with their terms and conditions, including a dispute regarding the payment of transportation fees applicable to such agreements. Cenit considers that the amounts owed by Frontera for this concept as of December 31, 2020, are $ 334,583.

 

The abovementioned fees dispute was at the root of the opposition manifested by Frontera Group against the application of the fees defined by the Ministry of Mines and Energy for the period 2015-2019. The rate differential amounts to $ 114,075 which was placed by Frontera in a trust fund, whilst the balance of the debt according to Cenit’s accounting records on the same date are $ 99,734, thus evidencing that the amounts receivable are funded.

 

Frontera has not paid the component of the fee related to the abandonment fund to which Cenit considers they are entitled by virtue of the application of resolutions 31480 and 31661 issued by the Ministry of Mines and Energy. Frontera Energy Group owed $ 9,663 in connection therewith.

 

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, will resolve all the disputes pending among them, related to the Caño Limón – Coveñas pipeline, and will terminate all the pending arbitration proceedings related to such disputes. This transaction eliminates any uncertainty related to the potential outcomes of the disputes, thus protecting the interests of all the parties and those of their stakeholders and create new business opportunities for the parties involved. The settlement arrangement includes 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 and Caño Limón – Coveñas pipelines. Frontera will also enter into new transportation contracts with Cenit and Bicentenario. Frontera will transfer to Cenit its 43.03% stake in Bicentenario´s shareholdings.

 

F-82 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

The new ship or pay commitment is projected to be approximately 3,900 bbls/day, based on the current oil price, for a term of five years subject to adjustments, at a current fee of $11.5/bbl. Frontera will not have to make payments for oil it may have to ship through alternate pipelines. These contracts will allow Cenit and Bicentenario to obtain payment of certain amounts included in the settlement, during the term of the contracts. The arrangement is conditional upon certain regulatory approvals, including approval of the settlement arrangement as a conciliation under Colombian law, which requires 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. As of the date of this annual report the final approval by the Administrative Tribunal of Cundinamarca was pending.

 

Bicentenario, Cenit and Canacol Settlement Agreement

 

On October 30, 2020 Cenit and Canacol reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes 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 Caño Limón – Coveñas pipelines. On November 18, 2020 the competent arbitration tribunal approved the conciliation agreement entered into by Cenit and Canacol, according to which Canacol was obliged to transfer all its outstanding shares in Bicentenario to Cenit. Additionally, as part of the settlement, Canacol entered into new transportation contracts with Cenit. These contracts will allow Cenit to obtain payment of certain amounts included in the settlement, during the term of the contracts. On the other hand, on March 8, 2021 Bicentenario and Canacol reached an agreement to settle all their aforementioned disputes. The agreement established a formula that seeks to end all contractual obligation disputes between the parties and settle all the outstanding obligations between the companies. (Approval of the conciliation between Bicentenario and Canacol is still pending as of the date of this annual report).

 

Bicentenario, Cenit and Vetra Settlement Agreement

 

On November 23, 2020, Cenit and Vetra reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes 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 Caño Limón – Coveñas pipelines. On February 18, 2021 the competent arbitration tribunal approved the conciliation agreement entered into by Cenit and Vetra, according to which Vetra is obliged to transfer all its outstanding shares in Bicentenario to Cenit and to make a cash payment for the remaining balance of the amounts included in the settlement. On the other hand, on January 13, 2021 Bicentenario and Vetra reached an agreement to settle all their aforementioned disputes. The agreement established a formula that seeks to end all contractual obligations between the parties and settle all the outstanding obligations between the companies. (Approval of the conciliation between Bicentenario and Vetra is still pending as of the date of this annual report).

 

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.

 

F-83 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

On June 28, 2019, CB&I submitted its Reply to the Non-Exhaustive Statement of Defence 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 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.

 

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. The outcome of the arbitration remains uncertain until such time as the arbitration ruling is issued.

 

23.4 Investigations of control entities – Reficar

 

Reficar is a wholly owned subsidiary of Ecopetrol. 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 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 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 resources 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.

 

F-84 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

The Prosecutor’s Office (Fiscalía General de la Nación) investigates potential crimes 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 Reficar’s expansion and modernization project (the Project), the Office of the Comptroller General initiated a special audit investigation of the Project in 2016 and delivered 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, on January 18, 2017, Reficar submitted an action plan addressing the 36 findings in the following areas: (i) contract management, (ii) supervision of engineering standards contracted with third parties, and (iii) documentation of the control, reporting and monitoring mechanisms of subcontracts.

 

1.2 As a result of the findings described above, on March 10, 2017, the Office of the Comptroller General opened actions for financial responsibility (proceso de responsabilidad fiscal) against 36 individuals and the six companies involved in the Project, including former members of Ecopetrol’s Board of Directors, former members of Reficar’s Board of Directors, former employees of Ecopetrol, 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 actions were initiated based on the Office of the Comptroller General’s theory that lower than expected profitability at Reficar could have been caused by (i) modifications to the schedule and, (ii) the increase of the budget for the Project.

 

On June 5, 2018, the Office of the Comptroller General split the initial proceeding in two. 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.

 

Regarding the first proceeding, on June 5, 2018, the Office of the Comptroller General issued charges for financial responsibility (proceso de responsabilidad fiscal) against (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. Therefore, as of the date of this annual report, no current or former member of Ecopetrol’s Board of Directors was charged in the first proceeding related to the increase in the Project’s budget.

 

As of the date of this annual report, no charges have been issued in the second proceeding related to the modifications in the Project’s schedule.

 

While the content and status of the proceedings remains confidential, we can report that Reficar and several of its employees have cooperated with and provided the information required by the department of 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.

 

1.3 In 2017, 2018, 2019, 2020 and 2021 the Office of the Comptroller General initiated a special/financial audit in Reficar and delivered a final report. In this report the Office of the Comptroller General concluded that, in their opinion, Reficar’s Financial Statements do not reasonably represent, the entity’s financial position. This situation originates in the different interpretation, by Reficar and the Comptroller General, of the applicable accounting laws. Reficar has used all the legal mechanism to enforce its position.

 

F-85 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

As of the date of this annual report, considering the best Group’s knowledge, Reficar’s 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 former and current Boards of Directors of Ecopetrol and Reficar are not part of the Comptroller General proceedings.

 

2. The Attorney General’s Office investigations:

 

Reficar has been officially informed that the Attorney General’s Office currently has four ongoing investigations related to the Project.

 

Regarding one of these four investigations, on September 12, 2017, the Attorney General’s Office issued a list of charges against 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 Yanes (Reficar CEO, 2012-2016). The Attorney General’s Office closed the case against the rest of the members of Reficar’s Board of Directors and the rest of the former officers of Reficar.

 

On January 17, 2020 the Attorney General’s Office issued its judgment against Reyes Reinoso Yanes 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 filed an appeal against the decision and is awaiting resolution.

 

In another 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 other Reficar employee.

 

The specific content and status of the remaining two ongoing investigations remains confidential.

 

As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar are not part of the Attorney General’s Office proceedings.

 

3. The Prosecutor’s Office investigations:

 

The Prosecutor’s Office has been conducting the following legal proceedings in which Ecopetrol 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 Yanes (Reficar CEO, 2012-2016); (iii) Felipe Laverde Concha (Reficar General Counsel, 2009-March 2017); (iv) Pedro Alfonso Rosales Navarro (Ecopetrol 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.

 

F-86 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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.

 

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 CEO, 2007-2015), Reyes Reinoso Yánez (Reficar CEO, 2012-2016), Pedro Alfonso Rosales Navarro (Ecopetrol Downstream Executive Vice President, 2008-2015), and Diana Constanza Calixto Hernández (Ecopetrol Head of the Corporate Finance Unit, 2009-2014). The arraignment hearing took place on August 5, 2019 and 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.

 

3.3 On June 12, 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). Ecopetrol and Reficar were recognized as victims.

 

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. The defense attorneys have not yet had an opportunity to present their case against such facts in a court of law.

 

Ecopetrol and Reficar have cooperated closely and extensively with the control entities in furthering their investigations and will continue to monitor the status and development of these investigations.

 

As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar and the current employees are not part of the above proceedings. None of the legal proceedings described in this paragraph are related with bribery charges.

 

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.

 

  23.5 Legal proceedings not recognized

 

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, 2020 and 2019:

 

    2020     2019  
Type of process   Number of
 processes 		    Proceedings     Number of
processes 		    Proceedings  
 Constitutional action     20       15,810,719       16       15,689,778  
 Ordinary administrative     156       714,606       162       781,686  
 Ordinary labor     659       54,030       614       51,029  
 Ordinary civil     54       6,363       54       17,956  
 Executive administrative     2       11,951       1       28  
 Special labor     15       3,106       13       720  
 Penal     2       595       1       595  
 Action of protection     234       47       112       10  
 Executive civil     1       -       1       -  
      1,143       16,601,417       974       16,541,802  

 

F-87 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

23.6 Details 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:

 

    2020     2019  
Type of process   Number of
 processes 		    Proceedings     Number of
 processes 		    Proceedings  
 Ordinary administrative     99       402,380       37       384,215  
 Arbitration     2       138,386       1       67,232  
 Ordinary civil     114       82,572       75       86,363  
 Penal     149       61,466       156       60,177  
 Executive civil     57       5,299       61       4,912  
 Ordinary labor     48       3,129       50       3,295  
 Executive administrative     10       2,450       11       4,028  
 Special labor     84       426       57       307  
 Action of protection     5       -       4       -  
      568       696,108       452       610,529  

 

24. Equity

 

The main components of equity are detailed below:

 

24.1 Subscribed and paid–in capital

 

Ecopetrol’s authorized capital amounts to COP$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 COP$11,499,933 comprised of 18,883,305,310 shares. As of December 31, 2020 and 2019, subscribed and paid–in capital amounts to COP$25,040,067. There are no potentially dilutive shares.

 

24.2 Additional paid–in capital

 

Additional paid–in capital mainly corresponds to: (i) share premium from the Ecopetrol Business Group’s capitalization in 2007, for COP$4,457,997, (ii) share premium from the sale of shares awarded in the second capitalization, which took place in September 2011, of COP$2,118,468, iii) a COP$31,377 share premium from the placement of shares on the secondary market, arising from the calling of guarantees from debtors in arrears, according to the provisions of Article 397 of the Code of Commerce, and (iv) additional paid–in capital receivables for COP$(143).

 

24.3 Equity reserves

 

The following is the composition of the Ecopetrol Business Group’s reserves as of December 31, 2020 and 2019:

 

    2020     2019  
Legal reserve     4,568,980       3,243,832  
Fiscal and statutory reserves     509,082       509,082  
Occasional reserves (1)     4,557,074       31,744  
      9,635,136       3,784,658  

 

(1)     Ecopetrol's General Shareholders' Meeting, held on March 27, 2020, approved the 2019 profit distribution project and set up a reserve of 4,557,074 in order to support the Company's financial sustainability and flexibility in development of its strategy.

 

F-88 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

The movement of equity reserves is the following for the years ended December 31, 2020 and 2019:

 

    2020     2019  
Opening balance     3,784,658       5,138,895  
Release of reserves     (540,826 )     (3,050,703 )
Allocation to reserves     6,391,304       5,355,852  
Dividends declared     -       (3,659,386 )
Closing balance     9,635,136       3,784,658  

 

24.4 Retained earnings and dividends

 

The Ecopetrol Business Group distributes dividends based on its separate annual financial statements, prepared under International Financial Reporting Standards accepted in Colombia (NCIF, by its acronym in Spanish).

 

The General Assembly of Shareholders of Ecopetrol S.A. held on March 27, 2020, decreed dividends on the 2019 profit for COP$7,401,005 (2019 – COP$9,251,256). A total of 100% of decreed dividends was paid during 2020 and 2019.

 

On March 26, 2021, the ordinary General Shareholders Assembly approved a distribution of ordinary dividends 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. The payment date will be April 22, 2021 for 100% of shareholders.

 

24.5 Other 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 S.A., net of tax:

 

    2020     2019     2018  
Foreign currency translation     11,794,201       10,265,398       10,235,891  
Cash flow hedge with derivative instruments     44,132       3,689       (30,962 )
Cash flow hedges for future exports     (136,470 )     (135,748 )     (374,079 )
Actuarial gain on defined benefit plans     (2,260,989 )     (2,357,210 )     (557,381 )
Hedge of a net investment in a foreign operation     (1,494,926 )     (1,130,583 )     (1,069,316 )
Others     1,114       1,114       176,608  
      7,947,062       6,646,660       8,380,761  

 

24.6 Earnings per share

 

    2020     2019     2018  
Profit attributable to Ecopetrol’s shareholders             1,586,677               13,744,011               11,381,386  
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$       38.6       COP$       334.3       COP$       276.8  

 

F-89 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

25. Sales revenue from contracts with customers

 

    2020     2019     2018  
National sales                        
Mid–distillates (1)     8,860,588       15,041,883       14,039,638  
Gasoline and turbo fuels (1)     6,768,046       9,658,180       9,334,939  
Services     2,859,559       4,115,626       3,531,404  
Natural gas     2,845,155       2,256,123       1,885,846  
Plastic and rubber     865,204       834,133       899,410  
Fuel gas service     671,570       72,249       -  
Asphalts     526,100       544,200       335,426  
LPG and propane     375,775       372,916       574,639  
Crude oil     230,520       356,857       550,479  
Aromatics     155,740       228,552       282,545  
Polyethylene     138,035       192,436       270,887  
Fuel oil     37,001       97,907       509,482  
Other income gas contracts (2)     32,190       102,845       156,031  
Other products     322,232       431,201       651,874  
      24,687,715       34,305,108       33,022,600  
Foreign sales                        
Crude oil (3)     19,498,582       28,523,596       26,898,737  
Diesel     3,164,068       4,391,798       3,050,839  
Plastic and rubber     1,302,131       1,249,189       1,308,685  
Fuel oil (4)     968,429       1,870,929       2,053,594  
Gasoline and turbo fuels     179,257       1,085,392       1,782,194  
LPG and propane     18,943       13,591       20,212  
Natural gas     17,231       27,255       27,899  
Cash flow hedge for future exports – Reclassification to
profit or loss (Note 30.3) 		    (193,374 )     (386,773 )     128,404  
Other products     580,411       408,427       310,708  
      25,535,678       37,183,404       35,581,272  
      50,223,393       71,488,512       68,603,872  

 

(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, 2020, the value recognized by price differential corresponds to COP$142,723 (2019 COP$1,785,277; 2018 COP$3,835,533). See Note 4.16 – Sales revenue recognition from contracts with customers.

 

(2) Corresponds to the income on the participation in the profits of gas sales, according to the agreement signed between Ecopetrol and Hocol (considering the assets purchase agreement signed with Chevron to acquire the stake owned by the latter in the Guajira Association as of May 1, 2020), for the extension of the association contract for the exploitation of gas in La Guajira. Prior to this acquisition, the agreement was signed between Ecopetrol and Chevron since 2004.

 

(3) Includes hedges with derivative instruments for COP$(587,591).

 

(4) Includes hedges with derivative instruments for COP$(76,382).

 

F-90 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Sales by geographic areas

 

    2020     %     2019     %     2018     %  
Colombia     24,687,715       49.2 %     34,305,108       48.0 %     33,022,600       48.1 %
United States     11,365,218       22.6 %     17,371,173       24.3 %     14,765,674       21.5 %
Asia     9,497,498       18.9 %     13,529,151       18.9 %     12,271,225       17.9 %
Central America and the Caribbean     2,581,644       5.1 %     3,472,665       4.9 %     4,449,033       6.6 %
South America and others     1,296,370       2.6 %     1,502,815       2.1 %     2,968,038       4.3 %
Europe     794,948       1.6 %     1,307,600       1.8 %     1,127,302       1.6 %
      50,223,393       100 %     71,488,512       100 %     68,603,872       100 %

 

Concentration of customers

 

During 2020, Organización Terpel S.A. represented 15.0% of sales revenue for the period (2019 – 16.0% and 2018 – 14.0%); 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.

 

26. Cost of sales

 

    2020   2019   2018
Variable costs            
Imported products (1)   7,592,489   12,639,710   11,809,529
Depreciation amortization and depletion   6,069,903   5,523,306   5,064,518
Purchases of crude in association and concession   4,281,661   5,466,496   3,820,746
Purchases of hydrocarbons – ANH (2)   2,798,432   5,437,177   5,667,567
Electric energy   1,098,621   829,543   662,297
Hydrocarbon transport services   874,632   821,654   696,964
Taxes and economic rights   841,443   788,924   441,207
Process materials   827,464   1,016,617   968,884
Purchases of other products and gas   598,015   584,507   632,509
Services contracted in associations   269,637   267,778   260,207
Others (3)   657,634   (676,269)   (186,087)
    25,909,931   32,699,443   29,838,341
Fixed costs            
Depreciation and amortization   2,930,120   2,781,446   2,555,176
Labor costs   2,299,761   2,316,567   2,105,803
Maintenance   2,257,370   2,497,002   2,260,984
Services contracted   1,623,375   1,841,009   1,796,354
Services contracted in associations   1,121,010   1,211,510   1,040,221
Taxes and contributions   593,041   516,933   393,690
Materials and operating supplies   508,037   574,678   565,601
Hydrocarbon transport services   253,752   268,572   261,237
General costs   71,075   265,200   366,972
    11,657,541   12,272,917   11,346,038
    37,567,472   44,972,360   41,184,379

 

  (1) Imported products correspond mainly to diesel and diluent to facilitate the transport of heavy crude oil.

 

  (2) Corresponds to purchases of crude oil by Ecopetrol from the National Hydrocarbons Agency (ANH, by its acronym in Spanish) derived from national production, both of the Ecopetrol Business Group’s direct operations and of third parties.

 

  (3) Corresponds mainly to: i) the valuation of the inventory, product of the costing process, ii) the valuation at Net Realizable Value, and iii) the agreements of inventories by transport and iv) capitalizable costs to projects.

 

F-91 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

27. Administrative, operations and project expenses

 

    2020     2019     2018  
Administrative expenses                        
Labor expenses (1)     (1,658,613 )     (759,324 )     (662,258 )
General expenses (2)     (1,424,348 )     (1,140,975 )     (911,645 )
Depreciation and amortization     (229,792 )     (202,547 )     (40,838 )
Taxes     (60,397 )     (48,753 )     (39,117 )
      (3,373,150 )     (2,151,599 )     (1,653,858 )
Operations and project expenses                        
Exploration costs     (689,087 )     (763,452 )     (1,387,379 )
Commissions fees freights and services     (656,432 )     (558,370 )     (466,862 )
Taxes     (428,608 )     (483,330 )     (433,506 )
Labor expenses     (309,972 )     (402,531 )     (316,386 )
Fee for regulatory entities     (142,695 )     (94,785 )     (98,794 )
Depreciation and amortization     (83,909 )     (60,952 )     (44,318 )
Maintenance     (78,181 )     (56,333 )     (50,846 )
Right-of-use assets amortization     (10,814 )     (14,532 )     -  
Others     (186,318 )     (197,469 )     (105,041 )
      (2,586,016 )     (2,631,754 )     (2,903,132 )

 

(1) Includes for 2020 recognition of the new voluntary retirement plan for 421 workers.

 

(2) Recognition of plants without temporary production given the health situation.

 

28. Other operating income (expenses), net

 

    2020     2019     2018  
Gain on revaluation of assets in Guajira association (1)     1,284,372       -       -  
Gain (loss) on acquisition of participations and interests (1)     86,026       1,048,924       (12,065 )
Loss on sale of assets     (263,647 )     (148,021 )     (93,601 )
Expense for legal provisions     (139,978 )     (98,020 )     (68,398 )
Impairment loss of short–term assets     (34,416 )     (90,441 )     (105,692 )
Gain on loss of control (2)     65,695       -       -  
Other income     120,114       344,354       244,301  
      1,118,166       1,056,796       (35,455 )

 

(1) Results in the acquisition of La Guajira: Ecopetrol COP$1,284,372 and Hocol COP$86,026. For Ecopetrol 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. (Note 12 – Business combinations).

 

(2) Recognition 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. COP$65,570 (Note 2.2). Liquidation process of ECP Oil and Gas Germany GmbH COP$125.

 

F-92 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

29. Financial result, net

 

    2020     2019     2018  
Finance income                        
Results from financial assets and others     665,310       975,245       745,571  
Yields and interests     299,246       481,674       383,624  
Gain on derivatives valuation     108,838       -       -  
Dividends (1)     44       117,260       -  
Gain on sale of equity instruments     -       -       368  
Other financial income     27,992       49,157       -  
      1,101,430       1,623,336       1,129,563  
Finance expenses                        
Interest (2)     (2,384,342 )     (1,894,490 )     (2,399,414 )
Financial cost of other liabilities (3)     (872,987 )     (757,509 )     (668,782 )
Results from financial assets     (473,598 )     (638,767 )     (381,445 )
Other financial expenses     (198,864 )     (43,703 )     (62,520 )
      (3,929,791 )     (3,334,469 )     (3,512,161 )
Foreign exchange gain net     346,774       40,639       372,223  
Financial result net     (2,481,587 )     (1,670,494 )     (2,010,375 )

 

  (1) In 2007, Arrendadora Financiera Internacional Bolivariana (AFIB) and Ecopetrol S.A. signed an agreement to constitute a trust fund, in which Invercolsa deposited dividends corresponding to 8.53% of the participation in dispute, regarding the shares acquired by Fernando Londoño. In 2019, as a result of the sentence of the Supreme Court of Justice, Ecopetrol received the amount of dividends that were in that trust.

 

  (2) As of December 31, 2020, borrowing costs for the financing of developing natural resources and property, plant and equipment of COP$247,501 (2019 – COP$248,139 and 2018 – COP$200,833) were capitalized.

 

  (3) Includes the financial expense of the asset retirement obligations and the liabilities for post–employment benefits.

 

30. Risk management

 

30.1 Exchange 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. The impact of exchange rate fluctuations, especially the Colombian peso/U.S. dollar exchange rate, has been material considering events presented during 2020 such as the disagreement between the members of the Organization of Petroleum Exporting Countries (OPEP) and Russia to maintain the cuts in production and the effects of the Covid-19 pandemic.

 

As of December 31, 2020, the Colombian peso depreciated 4.7%, going from a closing rate as of December 31, 2019 of COP$3,277.14 to COP$3,432.5 pesos per dollar.

 

When the Colombian peso depreciates, export earnings, when converted to pesos, increase, and imports and external debt service become more expensive.

 

The balance of financial assets and liabilities denominated in foreign currency for the years ended December 31, is presented in the following table:

 

(in USD$Million)   2020     2019  
Cash and cash equivalents     197       114  
Other financial assets     1,164       1,468  
Trade receivables and payables, net     203       81  
Loans and borrowings     (11,814 )     (9,429 )
Other assets and liabilities, net     277       64  
Net liability position     (9,973 )     (7,702 )

 

F-93 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Of the total net position, USD$(10,158) million correspond to net liabilities of companies with the Colombian peso as its functional currency, of which USD$(8,549) correspond to loans used as hedging instruments whose valuation is recognized in other comprehensive income, the exchange rate difference valuation of the remaining net liabilities for USD$(1,609) million affect the profit or loss. Likewise, USD$(185) million of the net position correspond to monetary assets and liabilities of Group companies with a functional currency different from the Colombian peso, whose valuation is recognized in profit or loss.

 

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, 2020:

 

Scenario / Variation in
the exchange rate 		    Effect on income
before taxes (+/–) 		    Effect on other
comprehensive income (+/–) 		 
  1%       (48,866 )     (293,457 )
  5%       (244,330 )     (1,467,286 )

 

30.3 Cash flow hedge for future exports

 

In order to present on financial statements the effect of the natural hedge between exports and debt, and considering that the exchange rate risk materializes when the exports are made, on October 1, 2015, the Board of Directors designated the amount of USD$5,440 million of Ecopetrol’s foreign currency debt as a hedge instrument of future revenue from crude oil exports, for the period 2015–2023 in accordance with IFRS 9 – Financial instruments.

 

The following is the movement of foreign currency debt designated as a non–derivative hedging instrument for the years ended December 31, 2020 and 2019:

 

(USD$Million)   2020     2019  
Hedging instrument at the beginning of the period     1,300       1,300  
Reassignment of hedging instruments     1,230       5,551  
Realization of exports     (1,230 )     (5,551 )
Hedging instrument at the end of the period     1,300       1,300  

 

The following is the movement in other comprehensive income for the years ended December 31, 2020, 2019 and 2018:

 

    2020     2019     2018  
Opening balance     (135,748 )     (374,079 )     159,295  
Exchange difference     (201,967 )     (35,607 )     (704,871 )
Reclassification to profit or loss     193,374       386,773       (128,404 )
Ineffectiveness     9,779       5,173       35,617  
Deferred income tax     (1,908 )     (118,008 )     264,284  
Closing balance     (136,470 )     (135,748 )     (374,079 )

 

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  
2021     (71,358 )     21,408       (49,950 )
2022     (71,358 )     21,408       (49,950 )
2023     (52,245 )     15,675       (36,570 )
      (194,961 )     58,491       (136,470 )

 

F-94 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

30.4 Hedge 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 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$5.2 billion. During 2019 and 2020 Ecopetrol S.A. expanded this hedge for USD$2,049 million to include in the designation the investments in Ecopetrol Permian LLC and Ecopetrol Brasil and add a greater amount in Reficar. The total hedged value as of December 31, 2020 is USD$7,249 million.

 

The following is the movement in other comprehensive income for the years ended December 31:

 

    2020     2019     2018  
Opening balance     1,130,583       1,069,316       97,362  
Exchange difference     520,490       87,524       1,381,900  
Ineffectiveness     —       —       378  
Deferred income tax     (156,147 )     (26,257 )     (410,324 )
Closing balance     1,494,926       1,130,583       1,069,316  

 

30.5 Hedging with financial derivatives

 

In 2020, Ecopetrol carries out forward non-delivery operations for the sale of dollars in order to mitigate the volatility of the exchange rate in the cash flow required for the Company's operations. As of December 31, 2020, the Group has open positions for COP$91,305.

 

The impact on the profit or loss as of December 31, 2020 due to the settlement of these hedges generated a loss of COP$62,911 (2019 - COP$60,740) and the amount recognized in the other comprehensive income was a profit of COP$51,486 (2019 - COP$43,141).

 

30.6 Commodity price risk

 

The price risk of raw materials is associated with the Group’s operations, both exports and imports of crude oil, natural gas and refined products. In order 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 Group (with operations in the exploration and production, transportation and logistics and refining segments) and carries out both crude exports at international market prices and sales of refined products at prices correlated with international prices.

 

The 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 Group’s consolidated financial statements from the volatility of market variables in a given period of time, to protect income and thus cash flow. On the other hand, tactical hedges allow to capture value in trading operations and Asset Backed Trading (ABT), thereby mitigating the market risk of specific operations.

 

F-95 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

The following is the detail of the operations during 2020:

 

1) Strategic hedges

 

The operations were oriented to specifically protect income and cash flow, limit losses, cover production costs and avoid potential closures of production fields (Apiay, Caño Sur and Chichimene), and therefore a possible acceleration in the decline of the basic curve. For this purpose, hedges for about 30 million barrels (MMBLS) were managed.

 

The operations carried out during 2020 were managed considering the analysis, approval, monitoring and compliance processes as defined in current policies and procedures, achieving the objectives defined for the hedge. In addition, these operations were classified as effective in accordance with IFRS standards. The benefit of these contracts was USD$42.7 million.

 

2) Tactical hedges

 

The commitments in physical spots and term contracts in the commercialization activity represent an exposure to the price risk of commodities, in particular 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 commercialization activity carried out by Ecopetrol, in order to maximize value capture, Ecopetrol can concentrate the risk exposure in terms of time and/or indicator that differs from the Company’s natural price risk profile.

 

Swaps operations for 18 MMBLS to mitigate risks associated with storage marketing strategies, anticipated purchases of raw materials, supply to refineries and international sales delivered at the destination port expired last year. Such strategies – together with their hedge – allowed to get benefits of around USD$15 million.

 

Similarly, hedges on exports of heavy fuel oil were made in 2020 corresponding to 3.7 MMBLS; this operation allowed to guarantee profits in the mount of USD$25.5 million.

 

As of the date of this report, the Group has in its asset a swap position of COP$7,572 and a forward position of COP$91,305 (Note 9). These derivative operations are recognized under cash flow hedge accounting.

 

30.7 Credit risk

 

Credit risk is the risk that the Ecopetrol Business Group may suffer financial losses as a consequence 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, and transport services, the Ecopetrol Business Group may be exposed to credit risk in the event that 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.

 

F-96 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

An aging analysis of the accounts receivable portfolio in arrears, but not impaired, as of December 31, 2020 and 2019 is as follows:

 

    2020     2019  
Less than 3 months overdue     56,144       243,893  
Between 3 and 6 months overdue     1,270       136,700  
More than 6 months overdue     301,858       267,525  
      359,272       648,118  

 

Credit risk in financial assets

 

Following the promulgation of Decree 1525 of 2008, which provides general rules on investments for public entities, Ecopetrol’s management established guidelines for its investment portfolios. These guidelines determine that investments in Ecopetrol’s U.S. dollar portfolios are generally limited to investments of cash excess in fixed–income securities issued by entities rated A or higher in the long term and A1/P1/F1 or higher in the short term (international scale) by Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings.

 

In addition, Ecopetrol S.A. 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 without qualification restrictions.

 

In order to diversify the risk in the Colombian Peso portfolio, Ecopetrol does not invest more than 10% of the cash excess in one specific issuer. In the case of the U.S. dollar portfolio, Ecopetrol 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 – Provisions for employees’ benefits.

 

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, 2020, 16% (2019, 17% and 2018, 17%) 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 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’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 have to follow the same regime as the regular obligatory pension funds in their moderate portfolio.

 

F-97 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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 profit

or loss (+/–)

    Effect on Other
Comprehensive 
Income (+/–) 		 
    Financial
Assets 		    Financial
Liabilities 		    Plan Assets  
+100 basis points     (25,878 )     60,577       (557,002 )
–100 basis points     25,878       (59,459 )     557,901  

 

A sensitivity analysis of discount rates on pension plan assets and liabilities is disclosed in Note 22 – Provisions for employees’ benefits.

 

30.9 Liquidity risk

 

The ability to access credit and capital markets to obtain resources for the investment plan execution for the Business Group may be limited due to adverse changes in market conditions. A global financial crisis could worsen risk perception in emerging markets.

 

Events that could affect the political and regional environment of Colombia may make it difficult for our subsidiaries to access the capital markets. These conditions, together with potential significant losses in the financial services sector and changes in credit risk assessments, may make it difficult to obtain resources on favorable terms. As a result, the Ecopetrol Business Group may be forced to review the conditions of the investment plan (as necessary), 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, 2020. The amounts disclosed in the table are the contractual undiscounted cash flows. The payments in foreign currency were restated taking a constant exchange rate of COP$3,432.50 per U.S. dollar:

 

    Up to 1 year     1–5 years     5–10 years     > 10 years     Total  
Loans (payment of principal and interest)     3,585,623       33,051,812       17,701,887       13,750,003       68,089,325  
Trade and other payables     8,449,041       21,064       —       —       8,470,105  
Total     12,034,664       33,072,876       17,701,887       13,750,003       76,559,430  

 

30.10 Capital 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 that support an investment grade credit rating profile.

 

The following is the leverage ratio as of December 31, 2020 and 2019:

 

    2020     2019  
Loans and borrowings (Note 20)     46,731,754       38,239,139  
Cash and cash equivalents (Note 6)     (5,082,308 )     (7,075,758 )
Other financial assets (Note 9)     (3,071,659 )     (4,979,292 )
Net financial debt     38,577,787       26,184,089  
Equity (Note 24)     53,499,363       58,231,628  
Leverage (1)     41.90%       31.02%  

 

  (1) Leverage = Net financial debt / (Net financial debt + Equity)

 

The movement of the net financial debt is detailed in Note 20.7.

 

F-98 

 

 

Ecopetrol S.A.

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, 2020 and 2019 are as follows:

 

  Accounts
receivable 		  Accounts
receivable
– Loans 		  Other
assets 		  Accounts
payable 		  Loans   Other
liabilities 		 
Joint Ventures                        
Equion Energía Limited (1) 1,950   -   7,093   32,335   1,277,046   1,663  
Ecodiesel Colombia S.A. 1,345   -   -   35,632   -   1  
Offshore International Group Inc (2) -   97,300   -   -   -   -  
Associates                        
Gas Natural del Oriente S.A. E.S.P. -   -   -   1,858   -   -  
Extrucol S.A. -   -   -   279   -   -  
E2 Energía Eficiente S.A. E.S.P. 4,453   -   -   1,264   -   -  
Serviport S.A. -   -   -   948   -   -  
Balance as of December 31, 2020 7,748   97,300   7,093   72,316   1,277,046   1,664  
Current 7,748   97,300   7,093   72,316   1,277,046   1,664  
Non–current -   -   -   -   -   -  
  7,748   97,300   7,093   72,316   1,277,046   1,664  
  (Nota 7)   (Nota 7)   (Nota 11)   (Nota 21)   (Nota 20)      

 

    Accounts
receivable 		    Accounts
receivable
– Loans 		    Other
assets 		    Accounts
payable 		    Loans     Other
liabilities 		 
Joint Ventures                                                
Equion Energía Limited(1)     25,333       —       57,016       153,501       1,108,403       794  
Ecodiesel Colombia S.A.     2,116       —       —       29,447       —       1  
Offshore International Group Inc.(2)     —       93,657       —       —       —       —  
Associates                                                
Serviport S.A.     —       —       —       4,668       —       —  
Balance as of December 31, 2019     27,449       93,657       57,016       187,616       1,108,403       795  
Current     27,449       —       57,016       187,616       1,108,403       795  
Non–current     —       93,657       —       —       —       —  
      27,449       93,657       57,016       187,616       1,108,403       795  
      (Note 7)       (Note 7)       (Note 11)       (Note 21)       (Note 20)          

 

Loans:

 

(1) Resources deposited by Equion in Ecopetrol Capital AG.

 

Accounts receivable – Loans:

 

  (2) Offshore International Group: Loan granted by Ecopetrol S.A. for USD$57 million in 2016, with an interest rate of 4.99% payable semiannually from 2017 and maturing in 2021. The balance in nominal value of this loan as of December 31, 2020 is USD$28 million (2019 – USD$28 million).

 

F-99 

 

 

Ecopetrol S.A.

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:

 

    2020     2019     2018  
    Sales and
services 		    Purchases
and others 		    Sales and
services 		    Purchases
and others 		    Sales and
services 		    Purchases
and others 		 
Joint Ventures                                                
Equion Energía Limited     27,595       356,872       317,382       569,105       67,002       846,284  
Ecodiesel Colombia S.A     8,268       346,201       8,614       280,649       6,860       267,498  
Offshore International Group     4,461       —       3,245       —       2,386       —  
      40,324       703,073       329,241       849,754       76,248       1,113,782  

 

Associates                                                
E2 Energía Eficiente S.A. E.S.P.     49,860       2,849       —       —       —       —  
Gas Natural del Oriente S.A. E.S.P.     —       26,141       —       —       —       —  
Extrucol S.A.     —       1,162       —       —       —       —  
      90,184       733,225       329,241       849,754       76,248       1,113,782  

 

31.1 Directors 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 2020 for fees to members of the Board of Directors amounted to COP$3,102 (2019 - COP$1,847).

 

The total compensation paid to Directors as of December 31, 2020, amounted to COP$24,068 (2019 – COP$22,632 and 2018 – COP$21,580). Directors are not eligible to receive pension and retirement benefits. The total amount reserved as of December 31, 2020, to provide pension and retirement benefits to the eligible executive officers amounted to COP$13,413 (2019 – COP$18,740 and 2018 – COP$5,491).

 

As of December 31, 2020, 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
Orlando Díaz   <1% outstanding shares
Jorge Calvache   <1% outstanding shares

 

31.2 Post–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).

 

These trust companies will manage the pension resources for a period of five years (2016-2021) and as compensation they receive remuneration with fixed and variable components, the latter are settled on the gross yields of the portfolios and charged to the resources managed.

 

F-100 

 

 

Ecopetrol S.A.

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 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, Ecopetrol purchases the crude oil that the ANH receives from producers in Colombia at the prices set in accordance with a 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 and the ANH ended on October 30, 2020 and a new one began with effect from November 1, 2020 to October 31, 2022.

 

From December 2013 the Ecopetrol Business Group commercialized, on behalf of the ANH, the natural gas received by the latter in kind from producers. Since January 2014, ANH has received royalties in cash for the production of natural gas.

 

The purchase value of oil and gas from ANH is detailed in Note 26 – Cost of sales.

 

Additionally Ecopetrol, like other oil and gas companies, takes part in “rounds” for the allocation of exploration blocks in Colombia without implying special treatment for Ecopetrol on count of it being an entity whose majority shareholder is the Colombian Government.

 

(b) Price differential

 

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 - Sales revenue from contracts with customers and in Note 7 - Trade and other receivables, net.

 

(c) National Tax and Customs Direction

 

Ecopetrol, 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. For more information, see Note 10 – Taxes.

 

(d) Comptroller General of the Republic

 

Ecopetrol, 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 does not have any other kind of association or commercial relationship with this entity.

 

F-101 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

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 2020 are as follows:

 

32.1 Contracts in which Ecopetrol is not the operator

 

Partners   Contract   Type   %
Participation 		    Geographic area of operations
Occidental de Colombia LLC   Chipirón         30-41 %    
Occidental Andina LLC   Cosecha   Production     30 %   Colombia
    Cravo Norte         55 %    
    Rondón         50 %    
Mansarovar Energy Colombia Ltd   Nare   Production     50 %   Colombia
Frontera Energy Colombia Corp.   Quifa   Production     40 %   Colombia
    Casanare         74.40 %    
    Corocora         83.91 %    
Perenco Colombia Limited   Estero   Production     95.98 %   Colombia
    Garcero         91.22 %    
    Orocúe         86.47 %    
ONGC Videsh Limited Sucursal Colombiana   Ronda Caribe RC-10   Exploration     50 %   Offshore Caribe Norte
Petrobras, Repsol & Statoil   Tayrona   Exploration     50 %   Offshore Caribe Norte
Shell EP Offshore Ventures Limited   Fuerte Sur                
    Purple Angel   Exploration     50 %   Offshore Caribe Norte
    Col-5                
Shell   Saturno         10 %    
    Sul de Gato do Mato   Exploration     30 %   Brazil
    Gato do Mato         30 %    
BP Energy   Pau Brasil   Exploration     20 %   Brazil
Chevron   CE-M-715_R11   Exploration     50 %   Brazil
Lewis   SSJN1   Exploration     50 %   Colombia
    Mana         30 %    
Interoil Colombia   Ambrosia   Production     30 %   Colombia
    Rio Opia         30 %    
Canacol   Rancho Hermoso-Mirador   Production     100 %   Colombia
    Rancho Hermoso -Otras formaciones         70 %    
    Llanos 86         50 %    
    Llanos 87         50 %    
Geopark   Llanos 104   Exploration     50 %   Colombia
    Llanos 123         50 %    
    Llanos 124         50 %    
Fieldwood - Gunflint   Gunflint   Production     32 %   Gulf of Mexico
Murphy Oil -   Dalmatian   Production     30 %   Gulf of Mexico
Oxy (Anadarko) - K2   K2   Production     21 %   Gulf of Mexico
Shell   Deep Rydberg/Aleatico   Exploration     29 %   Gulf of Mexico
HESS   ESOX   Production     21 %   Gulf of Mexico
Pemex Exploración y Producción   Bloque 8   Exploration     50 %   Gulf of Mexico
PC Carigali Mexico Operation SA   Bloque 6   Exploration     50 %   Gulf of Mexico
Talos   Palmer   Exploration     30 %   Gulf of Mexico
OXY (Anadarko)   Warrior   Exploration     30 %   Gulf of Mexico
Occidental Petroleum Company   Rodeo Midland Basin   Production     49 %   Permian Texas U.S.

 

F-102 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

32.2 Contracts in which Ecopetrol is the operator

 

Partners   Contract   Type   % Participation    

Geographic area of

operations

    VMM29              
ExxonMobil Exploration Colombia   CR2   Exploration     50 %   Colombia
    C62                
Repsol Colombia oil &gas  limited   CPO9   Exploration     55 %   Colombia
ONGC Videsh Limited Sucursal Colombia   RC9   Exploration     50 %   Colombia
CPVEN E&P Corp Sucursal Colombia   VMM32   Exploration     51 %   Colombia
Shell Exploration and Production   CR4   Exploration     50 %   Colombia
SK Innovation Co Ltd.   San Jacinto   Exploration     70 %   Colombia
Repsol Exploración Colombia S.A.   Catleya   Exploration     50 %   Colombia
Emerald Energy PLC Suc. Colombia   Cardon   Exploration     50 %   Colombia
Parex Resources Colombia Ltd.   ORC401 CRC-2004-01   Exploration     50 %   Colombia
Repsol Colombia Oil & Gas Limited   CPO9 - Akacias   Production     55 %   Colombia
Occidental Andina LLC   La Cira Infantas   Production     58 %   Colombia
    Teca         76 %    
Ramshorn International Limited   Guariquies I   Production     50 %   Colombia
Perenco Oil And Gas   San Jacinto Rio Paez   Production     68 %   Colombia
Cepsa Colombia                    
Total Colombia   Mundo Nuevo   Exploration     15 %   Colombia
Talisman Oil & Gas                    
Equion Energia Limited                    
Emerald Energy   Oleoducto Alto Magdalena   OAM     45 %   Colombia
Frontera Energy                    
Lewis   Clarinero   Exploration     50 %   Colombia
Talisman Oil & Gas   Niscota   Production     20 %   Colombia
Total Colombie                    
ONGC   RC-9   Exploration     50 %   Colombia

  

32.3 Relevant operations during the period

 

During 2020 the following relevant events were presented in the joint operations contracts:

 

1) On February 7, 2020, Ecopetrol and Shell EP Offshore Ventures Limited (“Shell”) signed an agreement through which Shell will acquire a 50% stake in the Fuerte Sur blocks, Purple Angel and COL-5, located in deep waters of the Colombian Caribbean, where the discovery of a new gas province was made with the Kronos (2015), Purple Angel and Gorgon (2017) wells. Following the commercial agreement, Shell will take over the operation of the blocks and a delimiting well will be drilled in the area at the end of 2021 and the first production test will be carried out, once the respective approvals from the authorities are fulfilled. This transaction was concluded on December the 23rd, 2020.

 

F-103 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

33. Information by segments

 

A description of the Ecopetrol Business Group’s business segments is in Note 4.19 – 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 are 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.

 

33.1 Statement of profit or loss

 

Below are the consolidated statements of profit or loss by segment for the years ended December 31, 2020, 2019 and 2018:

 

    For the year ended on December 31, 2020  
    Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport
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 )     —  
Total sales revenue     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 )     4,062,842       (11,657,542 )
Variable costs     (23,429,102 )     (22,398,344 )     (567,501 )     20,485,017       (25,909,930 )
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  

 

F-104 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    For the year ended on December 31, 2019  
    Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport and
Logistics 		    Eliminations     Total  
Third–party sales     31,295,118       36,393,470       3,799,924       —       71,488,512  
Inter–segment sales     21,372,872       2,377,336       9,270,812       (33,021,020 )     —  
Total sales revenue     52,667,990       38,770,806       13,070,736       (33,021,020 )     71,488,512  
Fixed costs     (9,587,961 )     (3,523,948 )     (3,039,452 )     3,878,443       (12,272,918 )
Variable costs     (26,785,904 )     (34,332,271 )     (698,742 )     29,117,475       (32,699,442 )
Cost of sales     (36,373,865 )     (37,856,219 )     (3,738,194 )     32,995,918       (44,972,360 )
Gross profit     16,294,125       914,587       9,332,542       (25,102 )     26,516,152  
                                         
Administrative expenses     (1,284,560 )     (496,155 )     (372,942 )     2,058       (2,151,599 )
Operation and project expenses     (1,475,710 )     (743,378 )     (434,904 )     22,238       (2,631,754 )
Impairment of non–current assets     (1,982,044 )     452,163       (232,556 )     —       (1,762,437 )
Other operating income and expenses net     49,673       1,014,988       74,607       (82,472 )     1,056,796  
Operating income (expenses)     11,601,484       1,142,205       8,366,747       (83,278 )     21,027,158  
Financial result net                                        
Financial income     1,440,440       229,297       273,613       (320,014 )     1,623,336  
Financial expenses     (2,311,133 )     (996,790 )     (306,878 )     280,332       (3,334,469 )
Foreign exchange gain (loss) net     287,286       (179,936 )     (66,711 )     —       40,639  
      (583,407 )     (947,429 )     (99,976 )     (39,682 )     (1,670,494 )
Share of profits of associates and joint ventures     227,401       17,091       138       122,274       366,904  
Income before tax     11,245,478       211,867       8,266,909       (686 )     19,723,568  
Income tax     (1,925,798 )     (83,504 )     (2,709,111 )     —       (4,718,413 )
Net profit (loss) for the period     9,319,680       128,363       5,557,798       (686 )     15,005,155  
Profit (loss) attributable to:                                        
Group owners of parent     9,382,129       117,708       4,244,860       (686 )     13,744,011  
Non–controlling interest     (62,449 )     10,655       1,312,938       —       1,261,144  
      9,319,680       128,363       5,557,798       (686 )     15,005,155  
Supplementary information                                        
Depreciation depletion and amortization     5,892,822       1,398,948       1,291,013       —       8,582,783  

 

F-105 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    For the year ended on December 31, 2018  
    Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport
and
Logistics 		    Eliminations     Total  
Third–party sales     30,112,900       34,947,948       3,543,024       —       68,603,872  
Inter–segment sales     20,259,864       2,063,425       7,811,143       (30,134,432 )     —  
Total sales revenue     50,372,764       37,011,373       11,354,167       (30,134,432 )     68,603,872  
Fixed costs     (8,871,709 )     (3,204,791 )     (2,805,516 )     3,535,979       (11,346,037 )
Variable costs     (23,367,475 )     (32,453,962 )     (596,571 )     26,579,666       (29,838,342 )
Cost of sales     (32,239,184 )     (35,658,753 )     (3,402,087 )     30,115,645       (41,184,379 )
Gross profit     18,133,580       1,352,620       7,952,080       (18,787 )     27,419,493  
                                         
Administrative expenses     (889,293 )     (443,880 )     (320,498 )     (187 )     (1,653,858 )
Operation and project expenses     (1,993,054 )     (668,177 )     (263,104 )     21,203       (2,903,132 )
Impairment of non–current assets     785,940       (984,704 )     (169,870 )     —       (368,634 )
Other operating income and expenses, net     (137,836 )     (13,652 )     118,905       (2,872 )     (35,455 )
Operating income (expenses)     15,899,337       (757,793 )     7,317,513       (643 )     22,458,414  
Financial result, net                                        
Financial income     1,099,893       147,689       110,898       (228,917 )     1,129,563  
Financial expenses     (2,038,312 )     (1,295,528 )     (407,589 )     229,268       (3,512,161 )
Foreign exchange gain (loss), net     868,479       (517,410 )     21,154       —       372,223  
      (69,940 )     (1,665,249 )     (275,537 )     351       (2,010,375 )
Share of profits of associates and joint ventures     135,265       27,730       2,841       —       165,836  
Income before tax     15,964,662       (2,395,312 )     7,044,817       (292 )     20,613,875  
Income tax     (6,096,591 )     420,224       (2,582,118 )     —       (8,258,485 )
Net profit (loss) for the period     9,868,071       (1,975,088 )     4,462,699       (292 )     12,355,390  
Profit (loss) attributable to:                                        
Group owners of parent     9,930,519       (1,973,075 )     3,424,234       (292 )     11,381,386  
Non–controlling interest     (62,448 )     (2,013 )     1,038,465       —       974,004  
      9,868,071       (1,975,088 )     4,462,699       (292 )     12,355,390  
Supplementary information                                        
Depreciation, depletion and amortization     5,248,364       1,307,216       1,149,270       —       7,704,850  

 

F-106 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

33.2 Sales by product

 

The sales by product for each segment are detailed below for the years ended December 31, 2020, 2019 and 2018:

 

    For the year ended on December 31, 2020  
    Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport
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     19,577,898       29       —       (79,345 )     19,498,582  
Diesel     —       3,164,068       —       —       3,164,068  
Plastic and rubber     —       1,302,131       —       —       1,302,131  
Fuel oil     —       968,429       —       —       968,429  
Gasoline and turbo fuels     —       179,257       —       —       179,257  
LPG and propane     18,943       —       —       —       18,943  
Natural gas     17,231       —       —       —       17,231  
Cash flow hedge for future exports – Reclassification to profit or loss (Note 30.3)     (193,374 )     —       —       —       (193,374 )
Other products     26,702       553,206       56       447       580,411  
      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  

 

F-107 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    For the year ended on December 31 2019  
    Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport
and Logistics 		    Eliminations     Total  
Local sales                                        
Mid–distillates     —       13,573,007       —       (31,251 )     13,541,756  
Gasoline and turbo fuel     —       11,269,797       —       (1,896,767 )     9,373,030  
Transport service     57,316       51,812       12,853,762       (9,133,788 )     3,829,102  
Natural gas     2,909,770       49,420       —       (653,647 )     2,305,543  
Plastic and rubber     —       760,301       —       —       760,301  
Asphalts     24,690       519,510       —       —       544,200  
LPG and propane     179,541       193,375       —       —       372,916  
Crude     21,056,104       —       —       (20,699,247 )     356,857  
Services     169,062       232,407       216,920       (309,036 )     309,353  
Aromatics     —       228,552       —       —       228,552  
Polyethylene     —       190,133       —       —       190,133  
Other income gas contracts     102,845       —       —       —       102,845  
Fuel oil     1,464       96,443       —       —       97,907  
Other products     25,215       779,407       —       (297,286 )     507,336  
      24,526,007       27,944,164       13,070,682       (33,021,022 )     32,519,831  
Recognition of price differential     —       1,785,277       —       —       1,785,277  
      24,526,007       29,729,441       13,070,682       (33,021,022 )     34,305,108  
Foreign sales                                        
Crude     28,461,601       61,995       —       —       28,523,596  
Diesel     —       4,391,798       —       —       4,391,798  
Fuel oil     —       1,870,929       —       —       1,870,929  
Plastic and rubber     —       1,200,668       —       —       1,200,668  
Gasoline and turbo fuels     —       1,085,392       —       —       1,085,392  
Natural gas     27,255       —       —       —       27,255  
LPG and propane     13,591       —       —       —       13,591  
Cash flow hedge for future exports –
reclassification to profit or loss 		    (386,773 )     —       —       —       (386,773 )
Other products     26,309       430,584       55       —       456,948  
      28,141,983       9,041,366       55       —       37,183,404  
      52,667,990       38,770,807       13,070,737       (33,021,022 )     71,488,512  

 

F-108 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    For the year ended on December 31, 2018  
    Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport
and
Logistics 		    Eliminations     Total  
Local sales                                        
Mid–distillates     725       11,662,476       —       (77,009 )     11,586,192  
Gasoline and turbo fuel     —       9,690,113       —       (1,737,261 )     7,952,852  
Transport service     37,279       36,321       11,089,012       (7,631,208 )     3,531,404  
Natural gas     2,535,658       —       —       (649,812 )     1,885,846  
Plastic and rubber     —       822,367       —       —       822,367  
Crude     20,142,527       —       —       (19,592,048 )     550,479  
LPG and propane     245,875       329,569       —       (805 )     574,639  
Fuel oil     20,391       489,091       —       —       509,482  
Asphats     26,406       309,020       —       —       335,426  
Aromatics     —       282,545       —       —       282,545  
Polyethylene     —       270,887       —       —       270,887  
Services     103,522       190,612       265,059       (319,783 )     239,410  
Other income gas contracts     156,031       —       —       —       156,031  
Other products     11,484       604,530       —       (126,507 )     489,507  
      23,279,898       24,687,531       11,354,071       (30,134,433 )     29,187,067  
Recognition of price differential     —       3,835,533       —       —       3,835,533  
      23,279,898       28,523,064       11,354,071       (30,134,433 )     33,022,600  
Foreign sales                                        
Crude     26,898,737       —       —       —       26,898,737  
Diesel     —       3,050,839       —       —       3,050,839  
Fuel oil     —       2,053,594       —       —       2,053,594  
Gasoline and turbo fuels     —       1,782,194       —       —       1,782,194  
Plastic and rubber     —       1,268,582       —       —       1,268,582  
Natural gas     27,899       —       —       —       27,899  
LPG and propane     20,212       —       —       —       20,212  
Cash flow hedge for future exports – Reclassification to profit or loss     128,404       —       —       —       128,404  
Other products     17,614       333,101       96       —       350,811  
      27,092,866       8,488,310       96       —       35,581,272  
      50,372,764       37,011,374       11,354,167       (30,134,433 )     68,603,872  

 

F-109 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

33.3 Capital expenditures by segments

 

The following are the investments amounts made by each segment for the years ended December 31, 2020, 2019 and 2018:

 

2020   Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport and
Logistics 		    Total  
Property, plant and equipment     2,866,600       1,329,181       836,536       5,032,317  
Natural and environmental resources     5,994,462       —       —       5,994,462  
Intangibles     41,002       8,771       40,309       90,082  
      8,902,064       1,337,952       876,845       11,116,861  

 

2019   Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport and
Logistics 		    Total  
Property, plant and equipment     2,151,194       497,512       1,363,953       4,012,659  
Natural and environmental resources     9,798,193       —       —       9,798,193  
Intangibles     25,775       20,569       121,945       168,289  
      11,975,162       518,081       1,485,898       13,979,141  

 

2018   Exploration
and
Production 		    Refining and
Petrochemicals 		    Transport and
Logistics 		    Total  
Property, plant and equipment     2,071,604       702,247       529,078       3,302,929  
Natural and environmental resources     5,051,828       —       —       5,051,828  
Intangibles     56,755       20,203       28,711       105,669  
      7,180,187       722,450       557,789       8,460,426  

 

F-110 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

34. Subsequent events

 

- Sale of stake in Offshore International Group

 

A Share Purchase Agreement was signed on January 19, 2021 with one of the subsidiaries of De Jong Capital LLC. Pursuant to which Ecopetrol sold the entire 50% stake it had in Offshore International Group (OIG).

 

- Non-binding offer to acquire participation in ISA

 

On January 27, 2021, Ecopetrol announced its interest in acquiring 51.4% of the outstanding shares of ISA, currently owned by the Colombian Government’s Ministerio de Hacienda y Credito Publico (MHCP). If the acquisition is consummated, Ecopetrol expects ISA to assist the Ecopetrol Group in increasing its exposure to new businesses aligned with global trends in electrification and decarbonization, which in turn could help leverage the Ecopetrol Group's profitable growth and improve its risk profile.

 

ISA operates and maintains a high voltage transmission network in Colombia, Peru, Bolivia, Brazil and Chile, among others, and participates through its subsidiaries in the toll-road business, telecommunications and management of real-time systems. Based on its public reports as filed with the Superintendencia Financiera de Colombia (the “SFC”), ISA’s consolidated revenues and net income for the third quarter of 2020 totaled COP 2.4 trillion and COP 483.8 billion, respectively; and its total assets were COP 52.3 trillion as of September 30, 2020. As of February 19, 2021, ISA’s market capitalization as reported on the Colombian Stock Exchange (BVC) was COP 25.5 trillion.

 

On February 12, 2021, Ecopetrol and the MHCP signed an exclusivity agreement through which the parties will carry out non-binding preliminary conversations on the terms and conditions of the potential transaction. The exclusivity period is initially scheduled to end on June 30, 2021 unless extended by mutual agreement of the parties. During this period, Ecopetrol will carry out due diligence activities on ISA and the MHCP has agreed to negotiate exclusively with Ecopetrol.

 

- New operating model for the transport segment

 

On February 1, 2021, Cenit assumed the integral operation of its infrastructure, directly executing the local and centralized operation of its hydrocarbon transport systems. With this change, Cenit also assumes the local operation of the Ocensa, Bicentenario and ODC (Oleoducto de Colombia) systems, and consolidates itself as the leader of Ecopetrol Group’s transport segment.

 

- WACC calculation methodology for liquid fuel transport

 

On February 8, 2021, the Energy and Gas Regulatory Commission (CREG) issued resolution 004 of 2021, whereby the Energy and Gas Regulatory Commission (CREG) establishes the WACC calculation methodology for activities regulated by CREG. Said activities include electric power distribution and transmission, and distribution and transportation of gas and liquid fuels. The discount rate for the transportation of liquid fuels through pipelines will be calculated and applied once the rate methodology for this activity is updated. In accordance with the CREG’s regulatory agenda, the methodology proposal is expected to be issued for comments during the second half of 2021 and the final document is expected to be published at the end of the year.

 

F-111 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

35. 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 2020, 2019 and 2018, and includes information related to the Ecopetrol Business Group’s consolidated subsidiaries, as well as its investments the joint ventures Equion Energía Limited and Offshore International Group. The oil and gas exploration and production activities of these two joint ventures are immaterial, as such the corresponding information has not been disclosed separately.

 

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.

 

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

 

    2020     2019     2018  
Natural and environmental properties     67,767,005       60,261,025       53,752,436  
Wells, equipment and facilities – property, plant and equipment     31,166,804       30,150,268       29,416,081  
Exploration and production projects     12,494,665       8,801,630       8,463,584  
Accumulated depreciation, depletion and amortization     (64,233,572 )     (60,346,094 )     (55,689,222 )
Net capitalized cost     47,194,902       38,866,829       35,942,879  

 

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 COP$3,936,494, COP$2,336,236 and COP$1,076,116 during 2020, 2019 and 2018, respectively.

 

35.2 Costs incurred in oil and gas exploration and developed activities

 

Costs incurred are summarized below and include both amounts expensed and capitalized in the corresponding period.

 

    2020     2019     2018  
Acquisition of proved properties (1)     507,907       2,668,960       —  
Acquisition of unproved properties (2)     1,274,660       261,231       81,295  
Exploration costs     1,340,898       640,556       1,197,946  
Development costs     7,367,020       8,084,283       6,346,276  
      10,490,485       11,655,030       7,625,517  

 

(1) 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. In July 2019, Ecopetrol S.A. and Occidental Petroleum Corp. (OXY) entered into a Joint Operation contract in order to execute a joint plan for the development of unconventional drilling in the Permian Basin in the state of Texas (USA).

 

(2) During 2020, Ecopetrol S.A. 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 Contract 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, 2019, 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 retains 10% of the interests of the block, while Shell (operator) and Chevron each retain 45% of the total.

 

F-112 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

35.3 Results of operations for oil and gas exploration and production activities

 

The Ecopetrol Business Group’s results of operations from oil and gas exploration and production activities for the years ended December 31, 2020, 2019 and 2018 are as follows:

 

    2020     2019     2018  
Net revenues                        
Sales     30,141,662       42,070,018       39,633,866  
Transfers     7,025,839       11,564,358       11,794,014  
      37,167,501       53,634,376       51,427,880  
Production costs(1)     12,753,880       9,336,387       8,337,413  
Depreciation, depletion and amortization(2)     6,393,506       6,049,543       5,591,774  
Other production costs(3)     14,005,669       21,550,907       18,918,275  
Exploration expenses(4)     689,204       763,562       1,387,463  
Other expenses(5)     2,227,481       4,163,241       1,036,983  
      36,069,740       41,863,640       35,271,908  
Income before income tax expense     1,097,761       11,770,736       16,155,972  
Income tax expense     (233,255 )     (2,107,363 )     (6,303,251 )
Results of operations for exploration and production activities     864,506       9,663,373       9,852,721  

 

(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 2020, 2019 and 2018 of COP$213,925, COP$198,394 and COP$187,340, respectively.

 

(2) In accordance with IAS 37, the expense related to asset retirement obligations that were recognized during 2020, 2019 and 2018 in depreciation, depletion and amortization, were COP$639,123, COP$272,147 and COP$180,193, 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 2020, 2019 and 2018, the Ecopetrol Business Group transferred approximately 18.9%, 21.6% and 22.9%, respectively, of its crude oil and gas production; (percentages based on the value sales in Colombian pesos) to intercompany business units. Those transfers were 45.9%, 51.5% and 51.8%, respectively, of crude oil and gas production volume (including Reficar).

 

The intercompany transfers were realized at market prices.

 

F-113 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

35.4 Reserve information

 

The Ecopetrol Business Group follows international standards for estimating, classifying and reporting reserves framed under SEC definitions. Corporate Reserve Management of Ecopetrol, Upstream Management and the Vice-Presidency of Development and Production, present the reserves balance to the Board of Directors for approval.

 

The reserves were estimated at a level of 99% by specialized firms: DeGolyer and MacNaughton, Ryder Scott Company, Gaffney Cline & Associates, Sproule International Limited and Netherland, Sewell & Associates, Inc. According to these certifications the reserves report complies with the content and guidelines set forth in Rule 4–10 of Regulation S–X issued by the United States SEC.

 

The following information relates to the net proven reserves owned by the Ecopetrol Business Group in 2020, 2019 and 2018, and corresponds to the official reserves statements prepared by the Ecopetrol Business Group:

 

    2020     2019     2018  
    Oil     Gas     Total     Oil     Gas     Total     Oil     Gas     Total  
    (Mbls)     (Gpc)     (Mbe)     (Mbls)     (Gpc)     (Mbe)     (Mbls)     (Gpc)     (Mbe)  
Proved reserves:                                                                        
Opening balance     1,384       2,906       1,894       1,200       3,002       1,727       1,088       3,254       1,659  
Revisions of previous estimates(1)     (81 )     51       (72 )     75       51       84       121       (4 )     121  
Improved recovery     100       74       113       94       3       94       128       4       129  
Purchases     -       171       30       142       126       164       —       —       —  
Extensions and discoveries     41       8       42       66       2       67       54       18       57  
Sales     (0.9 )     (0.3 )     (1 )     —       —       —       —       —       —  
Production     (186 )     (289 )     (236 )     (193 )     (278 )     (242 )     (191 )     (270 )     (239 )
Closing balance     1,257       2,921       1,770       1,384       2,906       1,894       1,200       3,002       1,727  
Proved developed reserves:                                                                        
Opening balance     898       2,662       1,365       883       2,882       1,389       818       3,158       1,372  
Closing balance     834       2,636       1,297       898       2,662       1,365       883       2,882       1,389  
Proved undeveloped reserves:                                                                        
Opening balance     486       244       529       317       119       338       270       96       287  
Closing balance     423       285       473       486       244       529       317       119       338  

 

Some values were rounded for presentation purposes.

 

(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.

 

35.5 Standardized measure of discounted future net cash flows relating to proved oil and gas quantities and changes therein

 

The standardized measure of discounted future net cash flows related to the above proved crude oil and natural gas reserves is calculated in accordance with the requirements of ASU 2010–03. Estimated future cash inflows from production under SEC requirements are computed by applying unweighted arithmetic average of the first–day–of–the–month for oil and gas price to year–end quantities of estimated net proved reserves, with cost factors based on those at the end of each year, currently enacted tax rates and a 10% annual discount factor. In our view, the information so calculated does not provide a reliable measure of future cash flows from proved reserves, nor does it permit a realistic comparison to be made of one entity with another because the assumptions used cannot reflect the varying circumstances within each entity. In addition, a substantial but unknown proportion of future real cash flows from oil and gas production activities is expected to derive from reserves which have already been discovered, but which cannot yet be regarded as proved.

 

F-114 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

    2020     2019     2018  
Future cash inflows     187,210,379       279,722,107       275,046,421  
Future costs                        
Production (1)     (85,989,384 )     (93,589,960 )     (90,176,326 )
Development     (28,752,131 )     (32,734,702 )     (21,945,453 )
Income taxes     (13,470,352 )     (37,077,231 )     (41,102,015 )
Future net cash flow     58,998,512       116,320,214       121,822,627  
10% discount factor     (18,568,308 )     (36,934,889 )     (35,518,187 )
Standardized measure of discounted net cash flows     40,430,204       79,385,325       86,304,440  

 

(1) Production future costs include the estimated costs related to assets retirement obligations in the amount of $12,545,574; $10,665,315 and $10,164,941 as of December 31, 2020, 2019, and 2018, respectively.

 

The following are the principal sources of change in the standardized measure of discounted net cash flows in 2020, 2019 and 2018:

 

    2020     2019     2018  
Net change in sales and transfer prices and in production cost (lifting) related to future production     (44,482,725 )     2,411,040       79,632,263  
Changes in estimated future development costs     (5,401,560 )     (12,627,361 )     (13,141,340 )
Sales and transfer of oil and gas produced, net of production costs     (24,413,621 )     (44,297,989 )     (43,090,467 )
Net change due to extensions, discoveries and improved recovery     3,134,469       7,061,712       8,496,249  
Net change due to purchase and sales of minerals in place     570,460       213,539       —  
Net change due to revisions in quantity estimates     (3,414,649 )     6,756,418       10,163,131  
Previously estimated development costs incurred during the period     7,943,239       23,200,357       12,505,421  
Accretion of discount     10,468,951       11,542,289       6,771,897  
Timing and other     567,027       (4,993,389 )     (13,633,228 )
Net change in income taxes     16,073,288       3,814,269       (12,616,331 )
Aggregate change in the standardized measure of discounted future net cash flows for the year     (38,955,121 )     (6,919,115 )     35,087,595  

 

F-115 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Exhibit 1 – Consolidated subsidiaries, associates and joint ventures

 

Consolidated subsidiary companies (1/2)

 

Company   Functional
currency 		  Ownership
interest
Ecopetrol 		    Activity   Country/
Domicile 		  Geographic
area of
operations 		  Equity     Profit
(loss) of
the year 		    Total
assets 		    Total
liabilities 		 
Refinería de Cartagena S.A.S.   U.S. dollar     100 %   Refining of hydrocarbons, commercialization and distribution of products   Colombia   Colombia     16,582,279       (1,688,830 )     27,321,381       10,739,102  
Cenit Transporte y Logística S.A.S. (*)   Colombian peso     100 %   Storage and transport by pipelines of hydrocarbons   Colombia   Colombia     16,310,718       4,696,705       18,303,490       1,992,772  
Ecopetrol Global Energy S.L.U   U.S. dollar     100 %   Investment vehicle   Spain   Spain     9,320,715       (434,773 )     9,321,078       363  
Ecopetrol USA Inc.   U.S. dollar     100 %   Exploration and exploitation of hydrocarbons   United States   United States     7,550,468       (294,497 )     7,552,294       1,826  
Ecopetrol Permian LLC.   U.S. dollar     100 %   Exploration and exploitation of hydrocarbons   United States   United States     3,566,413       (38,855 )     3,590,934       24,521  
Hocol Petroleum Limited   U.S. dollar     100 %   Investment vehicle   Bermuda   Bermuda     3,444,262       314,057       3,444,326       64  
Oleoducto Central S. A. - Ocensa   U.S. dollar     72.65 %   Transportation by crude oil pipelines   Colombia   Colombia     3,012,894       2,528,350       6,277,969       3,265,075  
Hocol S.A.   U.S. dollar     100 %   Exploration, exploitation and production of hydrocarbons   Cayman Islands   Colombia     2,376,723       300,828       3,877,096       1,500,373  
Ecopetrol América LLC.   U.S. dollar     100 %   Exploration and exploitation of hydrocarbons   United States   United States     2,320,615       (353,806 )     2,749,860       429,245  
Esenttia S.A.   U.S. dollar     100 %   Production and commercialization of polypropylene resin   Colombia   Colombia     1,870,802       263,126       2,445,757       574,955  
Ecopetrol Capital AG   U.S. dollar     100 %   Collection of surpluses from, and providing funds to, companies of the Ecopetrol Business Group.   Switzerland   Switzerland     1,872,129       176,999       7,482,055       5,609,926  
Ecopetrol Oleo é Gas do Brasil Ltda.   Brazilian real     100 %   Exploration and exploitation of hydrocarbons   Brazil   Brazil     1,657,410       (95,164 )     1,692,673       35,263  
Oleoducto Bicentenario de Colombia S.A.S.   Colombian peso     55.97 %   Transportation by crude oil pipelines   Colombia   Colombia     1,621,598       214,482       3,577,534       1,955,936  
Andean Chemicals Ltd.   U.S. dollar     100 %   Investment vehicle   Bermuda   Bermuda     1,268,047       (163,877 )     1,268,327       280  
Oleoducto de los Llanos Orientales S. A. - ODL   Colombian peso     65 %   Transportation by crude oil pipelines   Panama   Colombia     1,047,791       444,625       1,465,305       417,514  
Black Gold Re Ltd.   U.S. dollar     100 %   Reinsurer for companies of the Ecopetrol Business Group   Bermuda   Bermuda     837,693       54,412       1,079,572       241,879  

 

(*) Includes the effect of unrealized profits from transactions of companies in the transport and logistics segment.

 

F-116 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Consolidated subsidiaries (2/2)

 

Company   Functional
currency 		  Ownership
interest
Ecopetrol 		    Activity   Country/
Domicile 		  Geographic
area of
operations 		  Equity     Profit
(loss) of
the year 		    Total
assets 		    Total
liabilities 		 
Inversiones de Gases de Colombia S.A. Invercolsa S.A. y subsidiarias   Colombian peso     51.88 %   Holding with investments in natural gas and LPG transportation and distribution companies in Colombia   Colombia   Colombia     765,720       176,865       1,311,588       545,868  
Oleoducto de Colombia S.A. – ODC   Colombian peso     73 %   Transportation by crude oil pipelines   Colombia   Colombia     411,180       353,424       640,292       229,112  
Esenttia Masterbatch Ltda   Colombian peso     100 %   Manufacture of polypropylene compounds and masterbatches   Colombia   Colombia     322,511       166,911       401,404       78,893  
ECP Hidrocarburos de México S.A. de C.V.   U.S. dollar     100 %   Offshore exploration   Mexico   Mexico     59,279       (44,010 )     124,237       64,958  
Ecopetrol del Perú S.A.   U.S. dollar     100 %   Exploration and exploitation of hydrocarbons   Peru   Peru     53,003       305       55,202       2,199  
Bioenergy S.A.S. (1)   Colombian peso     99.61 %   Production of biofuels   Colombia   Colombia     26,508       (20,248 )     194,257       167,749  
Ecopetrol Costa Afuera S.A.S.   Colombian peso     100 %   Offshore exploration   Colombia   Colombia     13,356       1,148       32,017       18,661  
Ecopetrol Energía S.A.S E.S.P.   Colombian peso     100 %   Energy supply service   Colombia   Colombia     12,661       5,256       72,859       60,198  
Esenttia Resinas del Perú SAC   U.S. dollar     100 %   Commercialization polypropylene resins and masterbatches   Peru   Peru     6,275       1,319       39,833       33,558  
Topili Servicios Administrativos S de RL de CV   Mexican peso     100 %   Specialized management services   Mexico   Mexico     16       (35 )     20       4  
Kalixpan Servicios Técnicos S de RL de CV   Mexican peso     100 %   Specialized services related to oil and gas industry   Mexico   Mexico     20       (31 )     24       4  
Bioenergy Zona Franca S.A.S. (1)   Colombian peso     99.61 %   Production of biofuels   Colombia   Colombia     (92,416 )     (2,850 )     361,769       454,185  

 

F-117 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Associated companies and joint ventures

 

Company   Functional
currency 		  Ownership
interest
Ecopetrol 		    Activity   Country/
Domicile 		  Geographic
area of
operations 		  Equity     Profit
(loss) of
the year 		    Total
assets 		    Total
liabilities 		 
Joint ventures                                                        
Equion Energía Limited   U.S. dollar     51 %   Exploration, exploitation and production of hydrocarbons   United Kingdom   Colombia     2,499,319       167,727       2,630,351       131,032  
Offshore International Group Inc.   U.S. dollar     50 %   Exploration, exploitation and production of hydrocarbons   United States   Peru     543,621       (237,752 )     1,568,795       1,025,174  
Ecodiesel Colombia S.A. (2)   Colombian peso     50 %   Production, commercialization and distribution of biofuels and oleochemicals   Colombia   Colombia     103,344       29,188       167,801       64,457  
 Associates                                                        
Gases del Caribe S.A. E.S.P.   Colombian peso     25,40 %   Natural gas distribution and commercialization   Colombia   Colombia     489,367       278,329       2,132,231       1,642,864  
Gas Natural del Oriente S.A. E.S.P.   Colombian peso     17,91 %   Natural gas distribution and commercialization   Colombia   Colombia     111,181       52,956       202,644       91,463  
Gases de la Guajira S.A. E.S.P.   Colombian peso     5,36 %   Natural gas distribution and commercialization   Colombia   Colombia     55,265       18,128       170,937       115,672  
Colombiana de Extrusión S.A. -Extrucol S.A.   Colombian peso     18,16 %   Production of pipes and accessories in polyethylene   Colombia   Colombia     39,620       7,493       66,110       26,490  
E2 Energía Eficiente S. A. E.S.P.   Colombian peso     9,92 %   Energy services, supply, optimization, development, renewal and innovation of energy resources and infrastructure   Colombia   Colombia     28,802       4,062       93,736       64,934  
Serviport S.A. (3)   Colombian peso     49 %   Services for the support of loading and unloading of oil ships, supply of equipment, technical inspections and load measurements   Colombia   Colombia     17,430       568       45,457       28,027  
Sociedad Portuaria Olefinas y Derivados S.A. (2)   Colombian peso     50 %   Construction, use, maintenance and administration of port facilities, ports, private docks   Colombia   Colombia     4,432       562       8,196       3,764  

 

(1) Companies in liquidation process. See Note 2.2 Basis for consolidation.

 

(2) Information available as of November 30, 2020.

 

(3) Information available as of September 30, 2020, The investment is 100% impaired.

 

F-118 

 

 

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

 

Exhibit 2 – Conditions of the most significant debt

 

Type of debt   Company   Issue date   Maturity
date 		  Currency   Disbursement     Outstanding
balance
Dec 31,
2020 		    Outstanding
balance
Dec 31,
2019 		    Interest
rate 		  Amortization
plan 		  Payment of
 interest 		 
        Dec-10   Dec-40   COP     479,900       —       479,900     Floating   Bullet     Half-yearly  
        Dec-10   Dec-40   COP     284,300       284,300       284,300     Floating   Bullet     Half-yearly  
Bonds, domestic   Ecopetrol S.A.   Aug-13   Aug-23   COP     168,600       168,600       168,600     Floating   Bullet     Half-yearly  
currency       Aug -13   Aug-28   COP     347,500       347,500       347,500     Floating   Bullet     Half-yearly  
        Aug -13   Aug-43   COP     262,950       262,950       262,950     Floating   Bullet     Half-yearly  
Syndicated commercial loan, domestic currency   Oleoducto Bicentenario S.A.S   Jul-12   Jul-24   COP     2,100,000       800,450       999,950     Floating   Quarterly     Quarterly  
Syndicated commercial loan, domestic currency   Oleoducto de los Llanos Orientales S.A.   Aug -13   Aug-20   COP     800,000       —       96,000     Floating   Quarterly     Quarterly  
        Nov-20   Aug-25   COP     110,000       110,000       —     Floating   Half-yearly     Half-yearly  
Commercial loan   Inversiones de Gases de Colombia S.A. Invercolsa S.A. and subsidiaries   Aug-20   Aug-21   COP     50,000       43,000       —     Floating   Bullet     Quarterly  
        Sep-19   Jul-25   COP     70,912       21,681       70,912     Floating   Half-yearly     Half-yearly  
        Sep-13   Sep-23   USD     1,300       1,300       1,300     Fixed   Bullet     Half-yearly  
        Sep-13   Sep-43   USD     850       850       850     Fixed   Bullet     Half-yearly  
    Ecopetrol S.A.   May-14   May-45   USD     2,000       2,000       2,000     Fixed   Bullet     Half-yearly  
Bonds, foreign       Sep-14   May-25   USD     1,200       1,200       1,200     Fixed   Bullet     Half-yearly  
 currency       Jun-15   Jun-26   USD     1,500       1,500       1,500     Fixed   Bullet     Half-yearly  
        Jun-16   Sep-23   USD     500       500       500     Fixed   Bullet     Half-yearly  
        Apr-20   Apr-30   USD     2,000       2,000       2,000     Fixed   Bullet     Half-yearly  
    Oleoducto Central S.A. (1)   May-14   May-21   USD     500       500       500     Fixed   Bullet     Half-yearly  
        Jul-20   Jul-27   USD     500       500       500     Fixed   Bullet     Half-yearly  
Committed credit line   Ecopetrol S.A.   Apr-20   Sep-23   USD     665       665       —     Floating   Bullet     Half-yearly  
        Dec-17   Dec-27   USD     2,001       1,305       1,530     Fixed   Half-yearly     Half-yearly  
        Dec-17   Dec-27   USD     76       49       58     Floating   Half-yearly     Half-yearly  
International commercial loans (2)   Ecopetrol S.A.   Dec-17   Dec-27   USD     73       48       56     Fixed   Half-yearly     Half-yearly  
        Dec-17   Dec-27   USD     159       103       121     Floating   Half-yearly     Half-yearly  
        Dec-17   Dec-25   USD     359       257       288     Floating   Half-yearly     Half-yearly  

 

(1) This bond was redeemed early in 2020.

 

(2) Debt originally obtained by Reficar for the Refinery modernization and voluntarily assumed by Ecopetrol.

 

F-119 

 

 

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/ Jaime Caballero Uribe
    Name: Jaime Caballero Uribe
    Title: Acting Chief Executive Officer
     
  By: /s/ Sebastian Castañeda Arbelaez
    Name: Sebastian Castañeda Arbelaez
    Title: Acting Chief Financial Officer

 

Dated: April 8, 2021

 

198

 

 

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).
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   Natural Gas Transportation Agreement between Ecopetrol S.A. and Transportadora de Gas del Interior S.A. ESP, dated October 1, 2008 (incorporated by reference to Exhibit 4.3 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   Supplementary Agreement No. 1, dated December 5, 2008, to the Natural Gas Transportation Agreement between Ecopetrol S.A. and Transportadora de Gas del Interior S.A. ESP, dated October 1, 2008 (incorporated by reference to Exhibit 4.4 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   Supplementary Agreement No. 2, dated April 11, 2012, to the Natural Gas Transportation Agreement between Ecopetrol S.A. and Transportadora de Gas Internacional S.A. E.S.P., dated October 1, 2008 (incorporated by reference to Exhibit 4.5 on Form 20-F filed with the U.S. Securities and Exchange Commission on April 29, 2013 (File No. 001-34175)) (English Translation).
4.6   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).
4.7   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).
4.8   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).
4.9   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).
4.10   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).
4.11   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).

199

 

Exhibit
No.

 

Description

4.12   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).
4.13   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)).
4.14   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)).
4.15   Prospectus Supplement relating to Ecopetrol S.A.’s 5.875% Notes due 2023 (incorporated by reference to the Company’s Prospectus Supplement filed with the U.S. Securities and Exchange Commission on September 11, 2013 (File No. 333-190198)).
4.16   Prospectus Supplement relating to Ecopetrol S.A.’s 4.125% Notes due 2025, (incorporated by reference to the Company’s Prospectus Supplement filed with the U.S. Securities and Exchange Commission on September 9, 2014 (File No. 333-190198)).
4.17   Prospectus Supplement relating to Ecopetrol S.A.’s 5.375% Notes due 2026 (incorporated by reference to the Company’s Prospectus Supplement filed with the U.S. Securities and Exchange Commission on June 23, 2015 (File No. 333-190198)).
4.18   Prospectus Supplement relating to Ecopetrol S.A.’s 7.375% Notes due 2043 (incorporated by reference to the Company’s Prospectus Supplement filed with the U.S. Securities and Exchange Commission on September 11, 2013 (File No. 333-190198)).
4.19   Prospectus Supplement relating to Ecopetrol S.A.’s 5.875% Notes due 2045 (incorporated by reference to the Company’s Prospectus Supplement filed with the U.S. Securities and Exchange Commission on May 20, 2014 (File No. 333-190198)).
4.20   Prospectus Supplement relating to Ecopetrol S.A.’s 6.875% Notes due 2030 (incorporated by reference to the Company’s Prospectus Supplement filed with the U.S. Securities and Exchange Commission on April 27, 2020 (File No. 333-225381)).
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 LP.
23.3   Consent of Sproule International Limited.
23.4   Consent of DeGolyer and MacNaughton.
23.5   Consent of Gaffney, Cline & Associates.
23.6   Consent of Netherland, Sewell & Associates, Inc.
99.1   Third-Party Reserve Report of Ryder Scott Company, L.P.
99.2   Third-Party Reserve Report of Sproule International Limited.
99.3   Third-Party Reserve Report of DeGolyer and MacNaughton.
99.4   Third-Party Reserve Report of Gaffney, Cline & Associates.
99.5   Third-Party Reserve Report of Netherland, Sewell & Associates, Inc.
101.INS   XBRL Instance Document
101.SCH   XBRL Taxonomy Extension Schema Document
101.CAL   XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF   XBRL Taxonomy Extension Definition Linkbase Document
101.LAB   XBRL Taxonomy Extension Labels Linkbase Document
101.PRE   XBRL Taxonomy Extension Presentation Linkbase Document

 

200

 

 

11. Cross-reference to Form 20-F

 

      Sections
Item 1. Identity of Directors, Senior Management and Advisers   N/A
Item 2. Offer Statistics and Expected Timetable   N/A
Item 3. Key Information    
  A. Selected Financial Data   1.3
  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; 3.3 – 3.9; 4.6
  C. Organizational Structure   3.2
  D. Property, Plants and Equipment   3.4 – 3.6; 4.7.2; Notes 14, 15 and 16 to the consolidated financial statements
  E. Oil and Gas Disclosures   3.3 – 3.6; Notes 14, 15 and Supplemental information on Oil and Gas producing activities (unaudited by EY) to the consolidated financial statements
Item 4A. Unresolved Staff Comments   None
Item 5. Operating and Financial Review and Prospects    
  A. Operating Results   3.4 – 3.6; 4; 6.2; 6.3
  B. Liquidity and Capital Resources   2.1; 4.6; 4.8; Consolidated statements of cash flow and Notes 9, 19, 28 and 29.5 to the consolidated financial statements
  C. Research and development, Patents and Licenses, etc.   3.8; Note 16 to the consolidated financial statements
  D. Trend Information   4.11
  E. Off-Balance Sheet Arrangements   4.10
  F. Tabular Disclosure of Contractual Obligations   4.9
  G. Safe Harbor   1.2
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
Item 7. Major Shareholders and Related Party Transactions    
  A. Major Shareholders   6.9; 7.7
  B. Related Party Transactions   3.11; Note 30 to the consolidated financial statements
  C. Interests of Experts and Counsel   N/A
Item 8. Financial Information    
  A. Consolidated Statements and Other Financial Information   4; 6.2; 6.3; 8

201

 

      Sections
  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 – 4.14
  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
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 4.13-4.20
  B. Warrants and Rights   N/A
  C. Other Securities   N/A
  D. American Depositary Shares   6.5
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 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 17. Financial Statements   N/A
Item 18. Financial Statements   8
Item 19. Exhibits   10

202

 

 Exhibit 1.1

 

BYLAWS OF ECOPETROL S.A.

 

CHAPTER I: LEGAL NATURE, CORPORATE NAME, INCORPORATION, DOMICILE AND DURATION

 

ARTICLE ONE. LEGAL NATURE – CORPORATE NAME. - ECOPETROL S.A. is a corporation, of commercial nature, comprised of public and private shareholders, that carries out its corporate purpose in a competitive manner with private entities. Hereinafter and for the purposes of this document, it will be referred to as “Ecopetrol” or the “Company”.

 

As established by law, Ecopetrol is a mixed-economy company, from the national order, and assigned to the Ministry of Mines and Energy. All legal acts, agreements and actions required to carry out its corporate purpose are governed exclusively by the rules of private law, regardless of the percentage of the state shareholding in the Company's capital stock.

 

ARTICLE TWO. DOMICILE. - The main domicile of Ecopetrol is the city of Bogotá D.C. the Company may open subsidiaries, branch offices and agencies throughout the country and abroad.

 

ARTICLE THREE. DURATION. - The duration of the Company is one hundred (100) years as of its establishment.

 

CHAPTER II: CORPORATE PURPOSE

 

ARTICLE FOUR. CORPORATE PURPOSE. - The corporate purpose of Ecopetrol is to carry out, in Colombia or abroad, commercial and industrial activities related to the exploration, operation, refining, transportation, storage, distribution and marketing of hydrocarbons and their byproducts.

 

Additionally, the following activities are part of the corporate purpose of Ecopetrol:

 

1) Administration and management of all assets that were returned to the Government after the termination of the former De Mares Concession. Additionally, over such assets, Ecopetrol shall have, all the powers provided by Law.

 

2) Exploration and operation of hydrocarbons in oil areas or fields that, prior to January 1, 2004: a) were linked to executed agreements or, b) were being directly operated by Ecopetrol.

 

3) Exploration and operation of oil areas or fields assigned to Ecopetrol by the National Hydrocarbons Agency - ANH, or the entity acting as such.

 

4) Exploration and operation of hydrocarbons abroad, directly or through agreements entered into with third parties.

 

5) Export and import of hydrocarbons, its derivatives and their byproducts.

 

6) Production, processing, blending, transportation, storage, distribution and/or marketing (purchase and sale), and industrialization of hydrocarbons, their byproducts, and products owned by Ecopetrol or by third parties, domestic or imported.

 

7) Refining, processing, and any other type of industrial process or petrochemical of the hydrocarbons, its derivatives, similar products, in the grounds of the Company or of third parties.

 

8) Transportation and storage of hydrocarbons, their byproducts and similar, through transportation or storage systems.

 

9) Export and import of fuels and oxygenating components of vegetable origin.

 

10) Production, processing, mix, transportation, storage, distribution, and/or commercialization (purchase and sale) of fuels and vegetable-based oxygenating components, owned by the Company or from third parties, imported or domestic.

 

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11) Develop all of the activities required within the electric energy process, in order to generate energy that satisfies the Company’s own needs in all its business segments and, furthermore, sell its surplus and buy in case of shortages as a main source or as backup for its operations.

 

12) Design, construction, operation and maintenance of ports infrastructure for the export and import of hydrocarbons, and their byproducts or oxygenating components.

 

13) Construct, operate, administer, maintain, dispose and manage all infrastructure, facilities and property that is required to achieve the Company’s corporate purpose.

 

14) Establish and be part of all types of companies, including sole proprietorships, as well as open branches and agencies that are necessary for the proper implementation of its corporate purpose. The participation permitted by this clause may include involvement in companies whose activity differs from the one of the Company, provided that, in the opinion of the Board of Directors, this is appropriate for the implementation of the corporate purpose.

 

15) Concluding all kinds of credit and financing operations with financial entities or insurers.

 

16) Guarantee third-party obligations within the scope of its business and within the framework of its corporate purpose, with the prior authorization of its Board of Directors.

 

17) Securitizing assets and investments.

 

18) Temporarily or permanently invest cash surpluses and reserves in the capital markets, and underwrite bonds, purchase securities, equities, interests or rights, make deposits or engage in any type of investment and cash transaction with authorized financial entities.

 

19) Obtain and exploit industrial property rights on trademarks, drawings, insignia, patents for new technologies and products, results from research, and creations by the Company's competent units, as well as any other intangible property.

 

20) Training personnel in all specialties required for the proper implementation of the corporate purpose.

 

21) Participate in research, scientific or technological activities related to its corporate purpose, or to activities that are supplementary, related or useful thereto, as well as taking advantage of them and applying them technically and economically.

 

22) Carry out the above activities and any other investments, legal acts or related activities which are supplementary or useful for the implementation of its corporate purpose and activities in relation to hydrocarbons, their byproducts, refined products, similar, or products that are able to substitute those mentioned.

 

23) Participate in developing social programs for the community, in particular the community around sites where the Company has influence.

 

24) All other duties assigned by Law.

 

PARAGRAPH: Ecopetrol must accomplish its corporate purpose in a competitive manner, meeting criteria of economic and financial profitability in consideration of the market circumstances and the risks inherent to the industry, while also attending to the needs of the corporate group in which Ecopetrol is the parent company.

 

CHAPTER III:

CAPITAL, SHARES AND SHAREHOLDERS RIGHTS

 

ARTICLE FIVE. COMPANY CAPITAL. - The Company has an authorized share capital of thirty-six trillion five hundred forty thousand billion pesos legal tender ($36,540,000,000,000.00), divided into sixty billion (60,000,000,000) ordinary shares with a par value of six hundred nine pesos ($609) each, represented in accordance with the provisions of these Bylaws.

 

ARTICLE SIX. SHARE ISSUANCE. - Ecopetrol may issue shares within the authorized capital limit, in accordance with the limitations established by Law.

 

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ARTICLE SEVEN. SHAREHOLDER REGISTER. - The Company will keep a Stock Ledger that has been registered beforehand with the Chamber of Commerce of the main corporate domicile and this register will contain the names of the shareholders, the number of shares corresponding to each of them, the security or securities with their respective numbers and registration dates, the sales and transfers, pledges, usufructs, and judicial attachments and claims, as well as any other act subject to registration pursuant to the law. In the event that the shares are dematerialized, they will be represented by a macro security, which will be held in safekeeping and managed in the central securities depository, which will make annotations regarding the subscribers thereof and will keep the Stock Ledger. Shareholders may request a certificate through their direct depositor, which legitimizes them to exercise the rights inherent to their status.

 

The Company recognizes the person that appears registered in the Stock Ledger as the owner of shares, and only for the number of securities and under the conditions that are registered therein.

 

ARTICLE EIGHT. SECURITIES OR CERTIFICATES. - The shares of the Company may circulate in physical or dematerialized form.

 

a) Shares that circulate physically or in materialized form, will be represented by securities bearing the handwritten signature of the President and of the Secretary of the Company or whomever acts as such, and will be issued in a numeric and continuous series and must comply with all requirements pursuant to Article 401 of the Commerce Code, or the regulations that amend, replace or add to it.

 

Until the total amount per share has been paid in its entirety, only provisional securities will be issued to the subscribers. All provisional securities will be exchanged for permanent securities when the shares represented by them are fully paid. The securities may be issued for groups or lots of shares, or for each specific share.

 

The shareholders will be responsible for any taxes or fees imposed on the issuance of shares that circulate physically or in materialized form, as well as for those generated by transfers, transmission or changes regarding their ownership.

 

b) Certificates relating to the shares that are placed, transferred or taxed and that circulate in a dematerialized manner will be safeguarded and managed by a specialized entity or a Centralized Securities Depository with experience in this type of activity. The holders may request a certificate that guarantees the exercise of the rights inherent to the status of shareholder. The entity responsible for management will make the corresponding annotations regarding the subscribers of the shares and will keep the Shareholder Register. The content and characteristics of the certificates will be subject to the relevant legal requirements. Until the value of the shares has been fully paid, the Company may only issue provisional certificates.

 

The circulation, charges and other matters and operations related to the dematerialized shares will be governed by what is established in the laws applicable to dematerialized securities.

 

ARTICLE NINE. SHAREHOLDER DEFAULT. - When a shareholder fails to pay an installment on a due date for the shares it has subscribed, it cannot exercise the rights inherent to such shares. The Company, at the discretion of the Board of Directors, will proceed with the judicial collection or sell (at the expense of the defaulter and through a broker) the shares they have subscribed, or to allocate the amount received to the release of the number of shares corresponding to the installments paid, after deduction of twenty percent (20%) of such sums as compensation for the damage that will be presumed caused.

 

ARTICLE TEN. SHAREHOLDER RIGHTS. - All ordinary shares confer to the shareholder an equal right to the corporate assets and to the profits that are distributed, and each of them has the right to one vote in the deliberations of the General Shareholders Assembly, within the legal limitations.

 

3 

 

 

The shareholders of the Company, in addition to what is established by law, will enjoy the following rights and guarantees:

 

1) Participate in the deliberations of the General Shareholders Assembly and exercise their voting rights to make the decisions that correspond to the General Shareholders Assembly, including the appointment of bodies and individuals whom, in accordance with the law and these Bylaws, must be appointed by the shareholders and, if necessary, have effective mechanisms for representation in said Meetings.

 

2) Receive, as a dividend, a percentage of the profits of the Company in pro rata to the shares that the shareholder holds in the Company. Ecopetrol allocates the profits in accordance with the provisions set forth by law and these Bylaws.

 

3) Have access to the Company's public information in a timely and comprehensive manner, and freely inspect the books and other documents referred to in Articles 446 and 447 of the Commercial Code or the laws that modify, replace or add something to them, within fifteen (15) business days prior to the meeting of the General Shareholders Assembly in which the end-of-year financial statements are considered.

 

4) Request any information or clarifications they deem appropriate through the channels provided by the Company, such as the Shareholder and Investor Relations Office or whichever acts in its stead.

 

5) Receive by pro rata, part of the corporate assets at the time of liquidation, if applicable and, once the Company's external liabilities have been paid, in proportion to the shares they hold therein.

 

6) Be represented by a third party, as established by a written document in which they express the name of the party that will represent them and the scope of the mandate. The powers of representation for purposes of the General Shareholders Assembly must be subject to the provisions of Article 184 of the Commercial Code, or the regulations that amend, replace or add to it.

 

7) Transfer or dispose their shares, as established by law and these Bylaws.

 

8) Make recommendations on corporate governance to the Company, through written requests presented to the Shareholder and Investor Attention Office.

 

9) Request, with other shareholders, that a special Shareholders Assembly be held, in accordance with the provisions of Article 17 of these Bylaws.

 

10) Request authorization from the Shareholder and Investor Service Office to commission specialized audits, at their expense and under their responsibility, provided that such audit does not hinder the day-to-day operations of the Company, under the following terms:

 

a) Specialized audits may be carried out at any time and on the documents authorized by Article 447 of the Commercial Code, upon request of a plural number of shareholders representing at least five percent (5%) of the Company's subscribed shares.

 

b) Specialized audits may not cover documents that are confidential in nature, in accordance with the law, in particular Article 15 of the Constitution and Article 61 of the Commercial Code, as well as Letter g) of Article 4, Law 964 of 2005 and the regulations that govern, amend, replace or add to these.

 

c) Scientific, technical, economic, and statistic information shall not be subject to specialized audits either, in accordance with the applicable legislation. This shall also be the case for technical and scientific information regarding prospects for reservoirs, obtained directly by the Company or its partners, as well as the information derived from contracts that represent competitive advantages; this type of information will enjoy the commercial confidentiality set out by Colombian commercial law. In any case, specialized audits must deal with specific matters and cannot be conducted on industrial secrets or on matters whose confidentiality is protected by the legislation on intellectual property rights.

 

d) In no case, the specialized audits may imply impairment to managers’ autonomy, in accordance with legal and bylaw powers.

 

e) The working documents of the special auditor will subject to reserve and must be conserved for a time no less than five (5) years, as of the date of elaboration.

 

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f) The request to carry out specialized audits will be submitted in writing to the Shareholder and Investor Attention Service Office, stating the reasons why they are to be carried out, the facts and operations to be audited, and the duration. The persons hired to perform the specialized audits must be qualified professionals, recognized as such in accordance with the law, and they shall comply with the requirements set out by the law and these Bylaws for being a Statutory Auditor of the Company. The external auditor will be chosen in accordance with procedures that ensure their objective selection and independence.

 

g) The Shareholder and Investor Attention Service Office must process the request in question in an expeditious and efficient manner, facilitating the activities of the auditor, in coordination with the Company's units that must cooperate in order for the audit to be possible.

 

h) The results of the specialized audit will first be reported to the President of the Company, who has thirty (30) business days to comment. These results and the comments from the President will be shared with the Board of Directors and with the appropriate control and oversight administrative entities. In the event there is a breach of law, matters will be transferred to the competent authorities.

 

i) Investors may request specialized audits in accordance with the nature of its investment, taking into account the previous rules and as long as they own, at least individually or jointly, ten percent (10%) or more of the corresponding issuance of securities or values.

 

11) Submit proposals related to the proper progress of the Company to the Board of Directors, with other shareholders, provided that they represent at least five percent (5%) of the subscribed shares. The proposals must indicate the address and name of the person to whom the response to the request will be sent, and with whom the Board will act, if deemed necessary. In any case, the topics of such proposals may not be related to industrial secrets or information that is strategic to the Company's development. These requests must be submitted in writing to the Shareholder and Investor Service Office or the department that acts as such. In turn, this Office must submit them to the Board or to the relevant institutional committee for its examination and potential approval by the Board of Directors. In order to give answer to these requests, the Board of Directors must abstain from supplying information that is confidential or place Ecopetrol's business at risk, or affects the rights of third parties or that, if disclosed, may be used to the detriment of the Company.

 

12) When they deem that a rule of the Corporate Governance Code has been ignored or breached, they may contact the Company's Board of Directors in writing, stating the reasons and facts on which they base their claim, indicating their name, citizenship card number, address, telephone number and city, in order to guarantee that it will be possible to answer their request. The Secretary General, or the person acting as such, will send the above request to the Board of Directors. The Board will evaluate the request, give the response they consider, and take the necessary measures so that the relevant provisions are not breached. The Board of Directors may exercise this duty by appointing a committee to review such request.

 

13) Shareholders may exercise their exit rights in accordance with the terms and conditions established by law, and if such is the case, avail themselves with the conditions that the Nation will establish in the Declaration of the Majority Shareholder.

 

14) All rights granted by the law and these Bylaws.

 

PARAGRAPH ONE: FAIR TREATMENT TO SHAREHOLDERS AND INVESTORS. - In order to guarantee the full exercise of Shareholders rights and obligations that the Company has towards its investors and shareholders, the Company will give them equal treatment regarding requests, claims, and information, regardless of the value of their investment or the number of shares that they represent.

 

All shareholders of the Company will be treated fairly, considering that each shareholder has the same rights according to the number and class of shares held.

 

PARAGRAPH TWO: DISPUTE SETTLEMENT MECHANISMS. - Any disputes between the Company and its shareholders will be resolved by means of a direct settlement, which will start with the reception of the notification of disagreement. If no agreement is reached within sixty (60) business days, the parties can choose to resolve the disagreement either through the ordinary jurisdiction or through the Superintendence of Companies.

 

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ARTICLE ELEVEN. INDIVISIBILITY OF THE SHARES.- Shares will belong individually to the shareholders, as a result, when by any legal disposition or by agreement, one or more shares belong to a plural number of individuals, the Company will registry of the shares in favor of all joint owners, who must designate a common representative that will exercise the rights that correspond to them as Shareholders of the Company.

 

The appointment of this representative will be made in accordance with the provisions of Article 378 of the Commercial Code or the standard that amends or replaces it.

 

ARTICLE TWELVE. REPRESENTATION AND VOTE UNITY. - Each shareholder, whether an individual or legal entity, may only appoint a single representative to act before the General Shareholders Assembly, regardless of the number of shares held by it.

 

The representative or agent of a shareholder may not split the vote of their principal, which means that they are not allowed to vote with one or several shares held by the represented party in a certain sense or for certain individuals, and use other share(s) to vote differently or for other individuals. However, this individuality of the vote does not prevent a representative of several shareholders from voting in each case following the separate instructions issued by each shareholder, or each represented group or principal.

 

CHAPTER IV:

DIRECTION AND MANAGEMENT

 

ARTICLE THIRTEEN. CORPORATE BODIES.- The direction, management and representation of the Company will be the responsibility of the following main bodies:

 

a) General Shareholders Assembly.

 

b) Board of Directors, and

 

c) President, who provides General Legal Representation. However, the Company will also have other legal representatives.

 

PARAGRAPH: The Company will have a Secretary of the General Shareholders Assembly and a Secretary of the Board of Directors.

 

The Secretary, or whoever replaces him in his absolute or temporary absences, will be responsible for keeping the minute books and attesting before third parties regarding what is contained therein. This will be in addition to the duties set out in these Bylaws, the Regulations of the Company, and those assigned by the General Shareholders Assembly, the Board of Directors and the President.

 

The Secretary, or whoever replaces him in his absolute or temporary absences, will take special care to maintain the confidentiality that corresponds to the Company's books and documents according to the Law and commercial practices.

 

CHAPTER V:

GENERAL SHAREHOLDERS ASSEMBLY

 

ARTICLE FOURTEEN. COMPOSITION OF THE GENERAL SHAREHOLDERS ASSEMBLY.- The General Shareholders Assembly is comprised by the representatives of the shares with the necessary quorum, and under the terms prescribed in these Bylaws and in the law.

 

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ARTICLE FIFTEEN. DUTIES OF THE GENERAL SHAREHOLDERS ASSEMBLY.- The General Shareholders Assembly will exercise the following duties, both in ordinary meetings and in special meetings:

 

a) Appoint the person who will be the chair of the meeting.

 

b) Examine, approve or reject the end-of-year financial statements and the accounts that the Managers must submit.

 

c) Appoint and remove the members of the Board of Directors.

 

d) Appoint and remove the Statutory Auditor, and set their fees.

 

e) In accordance with the law, order the distribution of profits resulting from the financial statements, determining the amount of profits to be distributed, and the term and the methods for payment of the dividends. The General Shareholders Assembly may determine that the amounts available at any time for dividend distribution be fully or partially capitalized, and that their value be distributed in Company shares among the shareholders, pro rata with those held at the time of capitalization.

 

f) Define how the way to cancel loses if there were any to offset losses, if any.

 

g) Authorize the issuance and placement of shares in reserve, provided that this is done without being subject to the right of preference, likewise with the issuance of convertible bonds.

 

h) Authorize any issuance of preferred or dividend right shares and order the reduction or elimination of preferences.

 

i) Determine the reserves that must be established, in addition to statutory reserves.

 

j) Order the repurchase of own shares and their subsequent sale.

 

k) Adopt all measures required for compliance with these Bylaws or required in the interests of the Company.

 

l) Study and approve the amendments to the Bylaws, in accordance with the rules that govern the matter.

 

m) Approve the valuation of the contributions in goods received by the Company in payment for the subscription of shares, after the date of their issuance.

 

n) Consider and approve, as appropriate, the reports from the managers regarding the state of company business, as well as the report from the statutory auditor, as applicable.

 

o) Approve all mergers, spin-offs or transformations.

 

p) Approve authorized capital increases.

 

q) Issue its own regulations.

 

r) All others assigned by law or these Bylaws.

 

PARAGRAPH: The Nation undertakes, in accordance with its shareholding, that the disposal of assets of which its amount is equal to or greater than 15% of the market capitalization of Ecopetrol, will be discussed and decided within the General Shareholders Assembly, and the Nation may only vote in a favorable way if the vote of the minority shareholders is equal to or greater than 2% of the shares subscribed by shareholders other than the Nation.

 

Notwithstanding the foregoing, if the established majority referred to in this paragraph is not achieved, the Nation may request that a new Shareholders Assembly be held under the terms established in these Bylaws, and at said meeting such decisions may be taken with the majority provided in the Law or in these Bylaws.

 

ARTICLE SIXTEEN. ORDINARY MEETINGS. - The ordinary meetings of the General Shareholders Assembly will be held at the registered office of the company’s domicile within the first three months of each year, on the date and at the time indicated in the notice. The notice will be issued by the President thirty (30) calendar days prior to the scheduled date for the meeting, by publishing the notice on the Company's website www.ecopetrol.com.co, or whichever site takes its place, as well as in a print or digital newspaper with widespread circulation nationwide.

 

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In the ordinary meetings, the General Shareholders Assembly must deal with the following issues, in addition to those assigned by Law:

 

a) Examine the position of the Company.

 

b) Elect members of the Board of Directors and the Company’s auditor.

 

c) Determine the economic guidelines of the Company.

 

d) Analyze the accounts and financial statements for the last fiscal year.

 

e) Decide on the disposal and distribution of profits.

 

f) Approve all measures aimed at ensuring compliance with the corporate purpose.

 

PARAGRAPH ONE: Additionally, Ecopetrol will implement the following corporate governance best practices: (i) on the Sunday prior to the date of the ordinary meeting of the Shareholders Assembly, it will issue a reminder, by means of a notice published in a print or digital newspaper with widespread circulation nationwide, and on the website www.ecopetrol.com.co, or whichever site takes its place, regarding the date, time and place of the meeting, (ii) and at least three (3) calendar days prior to the date of the ordinary meeting it will use the website www.ecopetrol.com.co, or whichever site takes its place, to publish the agenda for the meeting of the Shareholders Assembly and the proposals from management.

 

PARAGRAPH TWO: If it is not duly summoned, the General Shareholders Assembly will be legally entitled to hold such meeting on the first business day of the month of April, at 10:00 a.m. at the offices of the main domicile where the Company's management operates.

 

ARTICLE SEVENTEEN. EXTRAORDINARY MEETINGS. - The General Shareholders Assembly may be called to extraordinary meetings when required on account of unforeseen or urgent needs of the Company, following notice from the President, the Board of Directors or the Statutory Auditor, such notice must include the agenda, date, time and place where it will take place.

 

Likewise, an extraordinary meeting maybe called by order or directly summoned by the Superintendent, or whomever has its duties, when so requested by a plural number of shareholders representing at least five percent (5%) of the total subscribed shares.

 

Calls to extraordinary meetings will be made by the President with fifteen (15) calendar days in advance of the date set for holding the meeting by means of a publication on the Company´s website of the announcement of the meeting, www.ecopetrol.com.co or whichever website functions in its places, as well as on a print or digital newspaper with widespread circulation nationwide.

 

The notice will indicate the matters on the Agenda to be considered by the General Shareholders Assembly in its extraordinary meeting.

 

PARAGRAPH: Additionally, Ecopetrol will implement the following corporate governance best practices: (i) on the Sunday prior to the date of the extraordinary meeting of the General Shareholders Assembly, it will issue a reminder, by means of a notice published in a newspaper of wide and national circulation, and on the website www.ecopetrol.com.co, or whichever site takes its place, regarding the agenda, date, time and place of the meeting, and (ii) at least three (3) calendar days prior to the date of the special meeting, it will use the website www.ecopetrol.com.co, or whichever site takes its place, to publish the agenda for the General Shareholders Assembly and the proposals from the management.

 

The Nation agrees to use its vote to support initiatives that are made in order to include additional issues to those mentioned in the agenda for the extraordinary meetings of the General Shareholders Assembly, provided that such initiatives are submitted by one or more shareholders representing at least two percent (2%) of the subscribed shares.

 

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ARTICLE EIGHTEEN. UNIVERSAL MEETINGS. - Notwithstanding the provisions of these Bylaws regarding the convening to ordinary and extraordinary meetings, the General Shareholders Assembly may meet, without prior notice, at any place, if there is a will to do so, when the totality of the subscribed shares is represented. It may deal with any matter, unless the law establishes otherwise.

 

ARTICLE NINETEEN. QUORUM.- The General Shareholders Assembly shall deliberate with a plural number of shareholders that represent, at least half plus one of the subscribed shares. Decisions will always be taken by the majority of votes present, unless the law establishes special majorities.

 

PARAGRAPH: If the General Shareholders Assembly is summoned to a meeting and it is not held due to a lack of quorum, a new meeting will be summoned and it will meet and decide validly with one or several shareholders, regardless of the number of shares represented. The new meeting must be held no sooner than ten (10) business days and no later than thirty (30) business days counted from the date set for the initial meeting. When the Shareholders Assembly gathers in an ordinary session in its own right on the first business day of the month of April, it may also validly deliberate and make decisions under the terms of this article.

 

CHAPTER VI:

BOARD OF DIRECTORS

 

ARTICLE TWENTY. BOARD OF DIRECTORS. - The Board of Directors of the Company will have nine (9) principal members with no alternates, who will be elected by the General Shareholders Assembly using the electoral quotient system, for periods of two (2) years, being possible that such members be re-elected for an indefinite period. The elected persons may not be replaced in partial elections without proceeding to a new election using the electoral quotient system, unless the vacancies are decided unanimously.

 

On the slate of candidates to be presented for consideration of the General Shareholders’ Assembly, at least three (3) current members will be included, with the exception of candidates in lines eight and nine, which will be postulated in accordance with Paragraph Two of this article.

 

The nomination and appointment to the Board of Directors of the Company shall be made in personal capacity. In any case, the member of the Board of Directors must observe his/her fiduciary duties as a director in the performance of his/her duties, regardless of the origin of his nomination.

 

If there is no new elections of Board members it will be understood that the appointment has been extended until a new appointment is made.

 

The Board of Directors will be subject to the inabilities and incompatibilities that the law may establish.

 

PARAGRAPH ONE: INDEPENDENT MEMBERS OF THE BOARD OF DIRECTORS. - The majority of the members of the Board of Directors shall be independent. The election of the independent members of the Board of Directors will be performed in accordance with the criteria provided in Paragraph Two of the Article 44 of Law 964 of 2005 and in accordance with the procedure established in Decree 3923 of 2006, or any provision that governs, amends, replaces or adds to these.

 

The members of the Board of Directors who are elected as independent, will commit in writing, upon accepting the position, to maintain their standing as independent members during the performance of their duties. If for any reason any Independent Board Member loses this condition, he/she must notify this situation in writing to the Secretary of the Board of Directors.

 

PARAGRAPH TWO: The Nation agrees that, in the meetings of the General Shareholders Assembly in which the members of the Board of Directors will be elected, the list of candidates that The Nation presents will include (for lines eight and nine) individuals proposed by the Hydrocarbon-Producing Departments in which Ecopetrol operates, and individuals proposed by the minority shareholders, as follows:

 

a) In applying the provisions of paragraph one, Article 5, Law 1118 of 2006, regarding line eight, the Nation's list of candidates for members of the Board of Directors shall include a person nominated by the Governors of the Hydrocarbon-Producing Departments operated by Ecopetrol. The name of the respective candidate must be chosen by the Governors of said Departments by simple majority, through a prior vote. The result of this must be sent to the Ministry of Finance and Public Credit no later than ten (10) days prior to when the respective meeting will be held. In the event that, for any reason, the name of the candidate is not submitted within the established timeframe, the Nation's list of candidates for members of the Board of Directors shall include one of the persons that has been designated by the Governors, who, in any case, must meet the requirements established in this paragraph.

 

Hydrocarbon-Producing Departments operated by Ecopetrol shall be understood according to Law 1530 of 2012, article 4, paragraph 1 or any law that additions, modify or replace this law.

 

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b) In line nine, the Nation's list of candidates for members of the Board of Directors shall include a person designated by the ten (10) minority shareholders with the largest shareholding. The name of the respective candidate must be chosen by simple majority, through a prior vote. The result of this must be sent to the Ministry of Finance and Public Credit no later than ten (10) days prior to when the respective meeting will be held. If such minority shareholders fail to reach an agreement, the Nation's list will include the person designated by the five (5) minority shareholders with the largest shareholding. If such shareholders do not reach an agreement prior to the date of the meeting in which the respective election is to be carried out, the Nation will be able to propose a candidate who must, in any case, meet the requirements established in this paragraph.

 

For the purpose of sections a) and b) of this paragraph, it shall be understood that the Nation's commitment to vote for candidates proposed by the minority shareholders of Ecopetrol and the Hydrocarbon-Producing Departments operated by Ecopetrol, shall be subject to the condition that each proposed candidate meets the following conditions:

 

(i) That the profiles conform to those defined for members of the Board of Directors of Ecopetrol, in accordance with the provisions set forth in these Bylaws.

 

(ii) The members comply with the requirements of an independent member, at least, in accordance with the definition of independence established in the paragraph of Article 44, Law 964 of 2005 or any provision that governs or amends it.

 

(iii) The Nation's agreement established in section b) of this article, shall no longer be valid at the moment in which the minority shareholders can, in accordance with their shareholding, appoint a member of the Board of Directors of Ecopetrol in their own right. The foregoing is without prejudice to the validity of the Declaration of the Nation, in its capacity as majority shareholder of Ecopetrol, signed on February 16, 2018.

 

PARAGRAPH THREE: The fees for members of the Board of Directors will be set by the General Shareholders Assembly and paid by the Company for attendance at the meetings of the Board of Directors and the Committees. This compensation shall be set in accordance with the nature of the Company, the responsibility inherent to the position and market guidelines. This information will be disclosed on the website www.ecopetrol.com.co, or whichever site takes its place.

 

PARAGRAPH FOUR: The members of the Board of Directors will be evaluated in accordance with the mechanism defined by the Board itself.

 

At each ordinary meeting, the Board of Directors shall provide the General Shareholders Assembly with a report on the operation of the Board of Directors, which shall take into account the attendance at the meetings of the Board and its Committees, performance and participation therein, and the results of the Board's assessment. The results of the assessments for the Board of Directors will be published on the Company's website www.ecopetrol.com.co, or whichever site takes its place.

 

PARAGRAPH FIVE: The rules on the appointment and functions of the Chairman of the Board of Directors and the Secretary are contemplated in the Internal Regulations of the Board of Directors that is published on the website of The Company www.ecopetrol.com.co.

 

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ARTICLE TWENTY-ONE. PROFILES OF THE MEMBERS OF THE BOARD OF DIRECTORS. - The members of the Board of Directors will be committed to the Company's corporate vision and must at least meet the following requirements: (i) have knowledge or international experience in the activities inherent to the Company's corporate purpose and/or have knowledge and experience in the field of industrial and/or commercial, financial, business risks, stock market, administrative, legal or related science activities, (ii) have more than 15 years of professional experience; (iii) enjoy a good reputation and be recognized for their professional competence and integrity, and (iv) not belonging simultaneously to more than five (5) boards of directors of corporations (Sociedades Anónimas), including Ecopetrol’s Board.

 

Gender, diversity and inclusion criteria will be taken into consideration when comprising the Board of Directors, and at least one (1) of the nine (9) members shall be a woman. Gender, diversity and inclusion criteria shall, in any case, be concurrent with the provisions set forth in this article regarding the profiles of the members of the Board of Directors.

 

TRANSITORY PARAGRAPH: The inclusion of at least one woman in the Board of Directors will apply as of 2023. The profiles of the members of the Board of Directors will be reviewed and updated by the Board of Directors or the institutional committee that the Board decides.

 

ARTICLE TWENTY-TWO. MEETINGS. - The Board of Directors will hold ordinary meetings at least eight (8) times a year at the offices of the Company or at the place indicated by it, on the date and time that it establishes and, in a special capacity, when summoned by itself, the President of Ecopetrol or its Board of Directors, the Statutory Auditor or two (2) of its members.

 

The summon to meetings, both ordinary and extraordinary, will be made by means of a communication sent to each of the members, at least five (5) calendar days in advance. Such communication may be sent through any suitable means, such as fax or email.

 

The deliberations of the Board of Directors may be suspended and then resumed as many times as decided by the majority of the members present at the meeting.

 

The Board of Directors shall elect its Chairperson and Vice Chair from its members, and their role will be to chair and direct the ordinary and extraordinary meetings of the Board of Directors and they shall be elected for periods of two (2) years. At the sessions in which both the Chairperson and Vice Chair are absent, the attendees may appoint the person who will chair the respective meeting from among their members.

 

The Secretary General, or their delegate, will act as secretary of the Board of Directors. In meetings where they are absent, attendees may appoint (from among its members) the person who will assume the duties of the Board's Secretary.

 

The President of the Company will attend the meetings of the Board of Directors, in which he will have voice but not vote. In no case may the President of be appointed as President of the Board of Directors.

 

PARAGRAPH ONE: QUORUM. - The Board of Directors shall deliberate with a number equal to or greater than five of its members. Decisions shall be made through a majority of the votes from the members present.

 

PARAGRAPH TWO: UNIVERSAL MEETINGS OF THE BOARD OF DIRECTORS.-The Board of Directors may meet validly at any date, time and place, without prior notice, when:

 

(i) All members of the Board of Directors are present.

 

(ii) They decide to declare the session as convened.

 

During the universal meetings, the Board of Directors may deal with any type of matter that relates to its duties, unless the law establishes otherwise.

 

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ARTICLE TWENTY-THREE. DUTIES. - The Board of Directors will have the following duties:

 

1) Appoint, evaluate and remove the President of Ecopetrol, approve his/her succession plan and set its compensation in accordance with the responsibility of the position and market guidelines.

 

2) Issue its own regulations.

 

3) Approve the succession policy for the members of the Board of Directors.

 

4) Organize and coordinate the succession process of its members, without prejudice to the power of the General Shareholders' Meeting regarding the appointment and removal of the members of the Board of Directors, so as to provide complete and relevant information on the candidates to be considered by the General Shareholders' Meeting, and ensure that the candidates meet the profile and comply with the requirements and conditions established for such purpose.

 

5) Authorize the following decisions or activities:

 

a) The incorporation, capital contribution or liquidation of all kind of companies, including sole proprietorships, direct subsidiaries and indirect subsidiaries, as well as the opening and closing of branches and agencies, both in Colombia and abroad, when it deems appropriate.

 

b) Participation with individuals or legal entities, national or foreign, governed by public or private law, in Colombia or abroad in the establishment of companies, partnerships, corporations and foundations that have an equal, similar, related or supplementary purpose, or a purpose that is necessary or useful to the implementation of the corporate purpose of Ecopetrol.

 

c) The acquisition of interests and rights in previously incorporated companies that have the same, similar, connected or complimentary purpose, and such acquisition is required because it is useful and it is appropriate for the proper development of the corporate purpose of Ecopetrol.

 

d) The disposal of shares, interests, contractual positions and rights in companies in which it has an interest.

 

e) Encumber, dispose of or limit the right of ownership over assets owned by Ecopetrol, other than hydrocarbons, their byproducts, and refined or petrochemical products according to the guidelines established by the Board of Directors.

 

6) Approve the Company’s budget and investment plan.

 

7) Examine and approve the reports that the President must submit on the work carried out by the Company.

 

8) Approve the annual reserve report and the 20F annual report.

 

9) Establish the criteria for determining size of personnel plant, the compensation policy, and approve the top-level organizational structure. For purposes of these Bylaws, those forming part of the first level dependencies shall be construed as those who, as part of their duties, report directly to the President.

 

10) Appoint and remove the employees who lead the first level areas of the Company.

 

11) Implement the decisions adopted by the General Shareholders Assembly related to the repurchase of shares of the Company.

 

12) Intervene in any activities for which the purpose, in its judgment, is to better pursue the Company’s activities through requests for reports from Company workers.

 

13) Propose to the General Shareholders’ Meeting the approval of reserve funds beyond the legal reserves.

 

14) When considered necessary, examine the Company’s documents and ledgers.

 

15) Together with the President of the Company, present for approval of the General Shareholders’ Meeting the Company’s management report, financial statements for each year, planned distribution of earnings and other documents stipulated in Article 446 of the Commercial Code and Law 222 of 1995, or in provisions that replace, regulate, amend or supplement them as set forth therein.

 

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16) Together with the President of the Company, present to the General Shareholders’ Meeting a special report expressing the closeness of existing economic relations between the parent company and its affiliates or subsidiaries, pursuant to Article 29 of Law 222 of 1995.

 

17) Fulfill the provisions of Article 447 of the Commercial Code or any provisions that regulate or amend it, on the right of inspection.

 

18) Serve as an advisory body for all matters that the President of the Company requires.

 

19) Approve the Code of Good Governance, Code of Ethics and their amendments.

 

20) Grant permits or licenses to the President of the Company, and appoint a person in charge in the event that the President's alternates are absent.

 

21) Adopt specific measures regarding the governance of the Company, its conduct and its information, in order to ensure respect for the rights of those who invest in its shares or any other securities that it issues, in accordance with the parameters set by market regulation bodies, while also ensuring the proper management of its affairs and public knowledge of its work.

 

22) Together with the President of the Company, submit a report to the General Shareholders Assembly describing the matters set forth in section 19 above.

 

23) Verify the effectiveness and transparency of the Company's accounting systems and submit regular reports to shareholders on the financial and governance position of the Company.

 

24) Ensure that Ecopetrol's economic relations with its shareholders (including the majority shareholder and its subsidiaries companies) fall within the limits and conditions established by law and regulations on the prevention, management and settlement of conflicts of interest established in these Bylaws and, in any case, under market conditions.

 

25) Establish the mechanisms necessary to ensure that when an Ecopetrol employee discloses (either to the Audit and Risks Committee of the Board of Directors or to their immediate superiors) information of which they have knowledge regarding a potential conflict of interest within the Company or irregularities regarding accounting or financial information, they will not suffer discrimination or negative consequences, and in general, will be protected from any retaliation resulting from this.

 

26) Request the President of the Company to hire the external advisors chosen by the Board of Directors, when deemed necessary in order to perform their duties, or as additional support for the Committees of the Board of Directors, in accordance with the terms and conditions established in the Internal Regulations of the Board of Directors.

 

27) Comply with the duties assigned to it by law in terms of the prevention and control of money laundering and terrorist financing laws that are valid and applicable, at a national and international level.

 

28) Regulate and implement the issuance and placement of shares and bonds convertible into shares. Likewise, authorize and implement the issuance and placement of non-convertible bonds in shares, as well as other debt securities that allow the financing of the Company. In any case, the Board of Directors may entrust the President of the Company with the approval of the subscription regulations, the prospectus of issuance and all other documents related to the issue and placement of securities.

 

29) Authorize the execution of loans and financing operations that have a term greater than one (1) year, from entities that are legally authorized for such purpose, as well as the granting of the guarantees that may be applicable.

 

30) Appoint and remove the legal representatives of the Company and their respective alternates.

 

31) Approve the granting of credits to Ecopetrol group of companies and third-party guarantees, both of which are to be carried out solely and exclusively within the Company's ordinary course of business and within the framework of its corporate purpose, in accordance with the provisions of these Bylaws.

 

32) Ensure the effectiveness of the internal control and risk management systems.

 

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33) The Board of Directors of the Company, in its capacity as the strategic guiding body, will have the following duties:

 

a) Approve the strategy and business plan for Ecopetrol group.

 

b) Approve the budget and investment plan for Ecopetrol group and issue the rules for their elaboration and execution.

 

c) Approve the consolidated objectives and targets Ecopetrol group.

 

d) Issue compensation guidelines for Ecopetrol and its subsidiaries companies.

 

e) Approve the consolidated financial statements.

 

f) Approve the guidelines for retaining, transferring and mitigating financial risks, including insurance for the Ecopetrol group.

 

g) Approve the new business of Ecopetrol group in accordance with the guidelines established by the Board of Directors and the internal regulations issued for this purpose.

 

h) Approve the corporate governance model applicable to Ecopetrol group.

 

34) All others assigned by Law and these Bylaws.

 

PARAGRAPH ONE: The Board of Directors may order the President to perform some of the functions assigned to it, except for those that by law expressly must be exercised by the Board of Directors.

 

PARAGRAPH TWO: The Board of Directors establish commissions for special work or studies within the Board itself.

 

ARTICLE TWENTY-FOUR. COMMITTEES OF THE BOARD OF DIRECTORS. - The Board of Directors may have institutional committees in accordance with the law, or those established by the Board itself, composed of members of the Board of Directors, appointed by the Board itself. At least one (1) member of each Committee shall be independent. The foregoing is without prejudice to the minimum number of independent members that the Audit and Risks Committee must comprise by law.

 

For its operation, in addition to the provisions of current regulations that are applicable, the Committees will have Internal Regulations that establish their objectives, duties and responsibilities.

 

CHAPTER VII:

GENERAL REGULATIONS FOR THE SHAREHOLDERS MEETING AND THE BOARD OF DIRECTORS

 

ARTICLE TWENTY-FIVE. MINUTES FOR PERSONAL ATTENDANCE MEETINGS. - The minutes must comply with the provisions of Articles 189 and 431 of the Commercial Code, as applicable, and with the regulations or circulars that govern, amend or replace these. The minutes will be registered when said formality is necessary by legal mandate.

 

ARTICLE TWENTY-SIX. REMOTE SESSIONS OF THE GENERAL SHAREHOLDERS’ MEETING AND BOARD OF DIRECTORS. - In addition to the in-person sessions regulated in other sections of these Bylaws, the General Shareholders’ Meeting or Board of Directors may meet remotely in accordance with Law 22 of 1995, or the rules that modify, add to or replace it.

 

ARTICLE TWENTY-SEVEN. DECISION-MAKING MECHANISM. - The General Shareholders Assembly or the Board of Directors shall take decisions when the shareholders or the directors express their voting decision in writing in accordance with Law 22 of 1995, or the rules that modify, add to or replace it.

 

ARTICLE TWENTY-EIGHT. MINUTES.- With regard to meetings where there is no personal attendance, or when there are decisions made through the mechanism established in the previous section, the corresponding minutes shall be prepared and recorded in the respective book in accordance with Law 22 of 1995, or the rules that modify, add to or replace it.

 

ARTICLE TWENTY-NINE. CONFLICT OF AUTHORITY. - Any doubt or conflict regarding the duties or authority of the Board of Directors and the President will always be settled in favor of the Board of Directors. Conflicts between the duties of the Board of Directors and the General Shareholders Assembly will be settled in favor of the General Shareholders Assembly.

 

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CHAPTER VIII:

THE PRESIDENT

 

ARTICLE THIRTY. PRESIDENT. - The management and General Legal Representation of Ecopetrol will be the responsibility of the President, who will be appointed by the Board of Directors.

 

The President shall be appointed for a two (2) year-term counted from its election, but may be re-elected for the same term more than once or removed freely from the position before expiration of the term. In cases where the Board does not appoint the President at the corresponding time, the previous President will continue to hold office until a new appointment is made. The election of the President will be carried out in accordance with criteria of suitability, knowledge, experience and leadership.

 

The Board of Directors must approve any change regarding the manner in which the President’s work shall be evaluated, and such change must be approved by of a simple majority. Once the respective amendment comes into effect, the Board of Directors' Secretary will communicate this to all managers and the new system will be disclosed to all interested citizens through the Shareholder and Investor Service Office and through Ecopetrol's website www.ecopetrol.com.co, or whichever site takes its place.

 

ARTICLE THIRTY-ONE. DUTIES OF THE PRESIDENT.-The President’s will have the following duties:

 

1) Execute the strategy and business plan approved by the Board of Directors.

 

2) Direct, coordinate, monitor, control and evaluate the execution and fulfillment of the objectives, duties, policies, plans, programs and projects inherent to the corporate purpose of Ecopetrol.

 

3) Adopt the decisions and determine the appropriate acts in order to fulfill the Company's corporate purpose and duties, within the limits set out by law and in the bylaws.

 

4) Implement the compensation policy, and present the Board of Directors with initiatives aimed at amending, supplementing or adjusting said policies.

 

5) Perform the evaluations of workers responsible for the first level dependencies of the Company, in accordance with the objectives established by the Board of Directors.

 

6) Execute and enforce all acts, operations, and authorizations comprised within the corporate purpose.

 

7) Together with the Board of Directors, present for approval of the General Shareholders’ Meeting the Company’s management report, certified financial statements for each fiscal year, planned distribution of earnings and other documents listed in Article 446 of the Commercial Code and Law 222 of 1995, or any provisions that replace, regulate, amend or supplement them, as set forth therein.

 

8) Together with the Board of Directors, present to the General Shareholders’ Meeting a special report expressing the closeness of economic relations existing between the parent company and its affiliates or subsidiaries, pursuant to Article 29 of Law 222 of 1995.

 

9) Fulfill the legal provisions concerning the right of inspection set forth in Article 447 of the Commercial Code or any standards that replace, regulate or amend it.

 

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10) Submit the following documents to the Board of Directors:

 

a) The budget and investment plan for the Company and its subsidiaries companies.

 

b) Amendments to the budget and investment plan, in accordance with the provisions set out by the rules for its preparation, issued by the Board of Directors.

 

c) A quarterly analysis of budget execution, supplemented by the corresponding test balances and the approximate calculation of profit and loss, as well as information on costs and prices for products in domestic and foreign markets.

 

d) Annually, the financial reports, the financial statements, a report on the progress of the Company, the status of new works or expansion, the results for the exploration, drilling and operations carried out by the Company and its contractors, the initiatives, work plans, and all instructions and suggestions aimed at the improvement and rationalization of the Company's industrial and administrative systems.

 

e) All other information requested by the Board of Directors for the fulfillment of the duties assigned to it.

 

11) Execute the Company’s budget and investment plan, consistent with the standards for its execution, as set by the Board of Directors.

 

12) Comply with and enforce the decisions of the Board of Directors.

 

13) Exercise the commercial and legal representation of Ecopetrol, without prejudice to the powers and rights conferred to the Legal Representatives for Judicial and Extrajudicial Affairs and the Legal Representative for the Provision of Goods and Services.

 

14) Approve the Company’s participation in national and international non-profit organizations that have the same corporate purpose as that of the Company, or a similar, connected, complimentary, necessary or useful corporate purpose for the Company.

 

15) Direct Ecopetrol's employment relations and appoint, remove and hire the Company's personnel in accordance with legal, regulatory and bylaw norms, and in compliance with the provisions of Section 4), Article 23 of these Bylaws.

 

16) Make proposals to the Board of Directors on the appointment or removal of employees from the first level dependencies and, if necessary, remove any of these employees and appoint a temporary replacement (this situation must be reported to the Board of Directors).

 

17) Represent the shares, participations or interests that Ecopetrol has in companies, partnerships, foundations, or any other type of association.

 

18) Summon the Board of Directors and the General Shareholders Assembly to ordinary and extraordinary meetings.

 

19) Present the Board of Directors with and ensure ongoing fulfillment of the specific measures regarding the governance of the Company, its conduct and its information, in order to ensure respect for the rights of those who invest in its shares or in any other securities it issues, while also ensuring proper management of its affairs and public knowledge of its work.

 

20) Treat all shareholders fairly.

 

21) Provide the market with timely, complete and accurate information about the Company's financial statements and its business and administrative conduct, without prejudice to the provisions of Articles 23 and 48, Law 222 of 1995, or the rules that replace or amend these.

 

22) Present a Code of Good Governance and a Code of Ethics to the Board of Directors for approval.

 

23) Avoid and reveal disclose potential conflicts of interest between them and the Company, or with shareholders, suppliers or contractors, reporting their existence to the members of the Board of Directors and, if applicable, to the General Shareholders Assembly, though refraining from deliberating or issuing their opinion on the contentious issue, according with the law and the procedure established within the Company.

 

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24) Establish and maintain the Company's Internal Control System.

 

25) Lead the Company's zero tolerance policy with respect to fraud, bribery, corruption, violations of the Foreign Corrupt Practices Act ("FCPA"), money laundering and financing of terrorism; the effective implementation and sustainability of the Compliance Program and fulfill the duties assigned to it by current and applicable regulations, with regard to the prevention and control of money laundering and the financing of terrorism.

 

26) Appoint the employees of the Company in the Boards of directors of the Companies in which Ecopetrol has a participation as a shareholder has participation in Colombia or abroad.

 

27) Execute and develop the corporate governance guidelines for Ecopetrol group.

 

28) Approve all new businesses of the Ecopetrol Group that are not responsibility of the Board of Directors, in accordance with the guidelines established by it and the provisions set forth in the internal regulations.

 

29) Encumber, transfer or limit the right of ownership over assets owned by Ecopetrol other than hydrocarbons, their derivatives and refined or petrochemical products in accordance with the guidelines established by the Board of Directors.

 

30) Perform all other duties established by Law.

 

PARAGRAPH: The President will organize the governance of the Company for which, without the authorization of another body, will be able to assign other workers and committees of the Company to carry out some of their functions, except those that by legal mandate, must be exercised directly by the President.

 

When for the development of the assigned faculties, the worker requires legal capacity in order to carry out agreements that are binding to the Company, the assignment of the President must be accompanied by the respective act of representation, which may be revoked at any time.

 

ARTICLE THIRTY-TWO. LEGAL REPRESENTATION OF THE COMPANY. - The President is the general legal representative of the Company, who will have the commercial and legal representation of Ecopetrol for all purposes and will have at least two (2) personal alternates who will replace him/her in the event of temporary, absolute or accidental absences, and will have identical powers. The alternates of the President will be appointed by the Board of Directors, for two-year periods and may be freely re-elected or removed at any time. When the Board of Directors does not appoint the alternates when needed, the previous ones will continue in their position until new appointments are made.

 

However, for more efficiency in the ordinary course of business, the Company will have, additionally, a Legal Representative for Judicial Affairs, and a Legal Representative for Purposes of the Supply of Goods and Services.

 

LEGAL REPRESENTATIVE FOR JUDICIAL AND OUT-OF-COURT AFFAIRS. - The Company will have one (1) legal representative for Judicial and Out-of-Court Affairs, who will have one (1) personal alternate who will replace it during its temporary, absolute or accidental absences, and such alternate will have identical powers.

 

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The legal representative for Judicial and Out-of-Court Affairs will represent the Company in the following matters: a) Receive all kinds of notifications regarding actions and administrative investigations and lawsuits filed or initiated against the Company in any kind of judicial, out-of-court, administrative or police action or proceedings. b) Represent the Company in all kind of judicial, administrative, police, arbitration or out-of-court proceedings, in which the Company is a party. For this purpose, the Legal Representative for Judicial and Out-of-Court Affairs or its alternate will be fully authorized to receive, withdraw, settle and conciliate on behalf of the Company. c) Respond on behalf of the Company, all kinds of judicial and out-of-court questions that may be directed to the Company. d) Represent the Company in all kinds of administrative actions initiated by or against it, before any administrative, police or judicial authority. e) Initiating and carrying out, on behalf of the Company, all kinds of requests, petitions or procedures before any administrative, police or judicial authority, including the power to file any appeal on behalf of the Company. f) Granting, on behalf of the Company, powers of attorney to the lawyers who will exercise representation and legal status in all kinds of judicial, police or administrative proceedings in which the Company is a party. For this purpose, the Representative or their alternate may confer powers of attorney to receive, withdraw, settle and conciliate on behalf of the Company. They may revoke the granted powers of attorney at any time.

 

The legal representative for Judicial and Out-of-Court Affairs and its alternate will be appointed by the Board of Directors for periods of two (2) years and may be re-elected indefinitely or freely removed at any time. The Legal Representative for Judicial and Out-of-Court Affairs and its alternate will continue in their positions until such time that the Board of Directors appoints another person in their place.

 

LEGAL REPRESENTATIVE FOR PURPOSES OF THE SUPPLY OF GOODS AND SERVICES. - The Company will have one Legal Representative for Purposes of the Supply of Goods and Services, who will have one (1) personal alternate who will replace it during their temporary, absolute or accidental absences, and such alternate shall have identical powers.

 

The Legal Representative for Purposes of the Supply of Goods and Services and its alternate will be appointed by the Board of Directors for periods of two (2) years and may be re-elected indefinitely or freely removed at any time. During their temporary, absolute or accidental absences, an alternate with identical power will replace them. The Legal Representative for Purposes of the Supply of Goods and Services and their alternate will continue in their positions until such time that the Board of Directors appoints another person in their place.

 

CHAPTER IX:

STATUTORY AUDITOR

 

ARTICLE THIRTY-THREE. STATUTORY AUDITOR. - The Company will have a Statutory Auditor along with their respective alternate, who will replace them during their absolute, temporary or accidental absences, both of whom shall be elected by the General Shareholders Assembly.

 

In terms of electing the people who are going to occupy the position of Statutory Auditor or their alternate, the Company may only elect individuals or legal entities duly registered in the Register for the Central Board of Accountants and who meet the requirements established in Law 43 of 1990 or in the standards that govern, amend or replace it, or whichever standards are applicable.

 

The election of the Statutory Auditor will be carried out based on an objective and transparent pre-selection carried out by the Audit and Risks Committee of the Board of Directors.

 

The Audit and Risks Committee of the Board of Directors will do the election of the External Auditor through an objective and transparent pre selection of candidates.

 

The Audit and Risks Committee of the Board of Directors will evaluate the candidates and present a recommendation to the General Shareholders Assembly, during which an order of eligibility will be established, based on criteria of experience, service, costs and knowledge of the sector.

 

The shareholders may propose additional candidates for Statutory Auditor to the Audit and Risks Committee, provided that their profiles comply with the provisions of the law and these Bylaws. They may also express any dissatisfaction with the current Statutory Auditor to the Shareholder and Investor Service Office, being the Audit and Risks Committee the one who will evaluate the case, so that it can be brought to the General Shareholders Assembly, which will make the decision on the matter.

 

PARAGRAPH ONE: In the event that the Statutory Auditor is a legal entity, it must appoint a public accountant to carry out the duties of statutory auditor so that the role can be performed personally, under the terms of Article 215 of the Commercial Code or the rules that replace or amend it. In the event that the person appointed is absent, the alternates will act in their place

 

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PARAGRAPH TWO: The Statutory Auditor will receive the payment indicated by the General Shareholders Assembly, in accordance with criteria such as suitability, professional experience in auditing similar companies, and market guidelines.

 

PARAGRAPH THREE: In accordance with the provisions of Article 206 of the Commerce Code, or the rules that replace or amend it, the Statutory Auditor's term will be equal to that of the Board of Directors, but in any case, they may be removed at any time by the General Shareholders Assembly through a vote representing half plus one of the shares present at the relevant meeting.

 

ARTICLE THIRTY-FOUR. DUTIES OF THE STATUTORY AUDITOR. - Without prejudice to the duties indicated by laws and regulations, the responsibilities of the Statutory Auditor are as follows:

 

1) Ensure that the transactions that are concluded or carried out on behalf of the Company comply with the requirements of these Bylaws, the decisions of the General Shareholders Assembly and the Board of Directors.

 

2) Examine all transactions, inventories, minutes, books, correspondence, account vouchers and business relating to the Company.

 

3) Verify the cash count on the occasions that the Statutory Auditor deems appropriate.

 

4) Verify of all the Company's securities, as well as the others that it has in safekeeping.

 

5) Inspect the assets of the Company and ensure that measures are taken for the conservation and security thereof.

 

6) Report (expressly and in writing) the irregularities noted in the Company's minutes of the Shareholders Assembly, the Audit and Risks Committee, the Board of Directors or the President, as appropriate.

 

7) Authorize the Company's financial statements by means of their signature.

 

8) Summon the General Shareholders Assembly to special meetings, in accordance with the provisions of Article 17 of these Bylaws.

 

9) Comply with the provisions of Article 447 of the Commerce Code or the legal provisions that govern or amend it.

 

10) Cooperate with the competent authority for the inspection and monitoring of the Company, and provide it with any reports that may be required or requested.

 

11) Act in the deliberations of the General Shareholders Assembly and those of the Board of Directors, when summoned to them, with the right to speak but not to vote.

 

12) Fulfill all other duties indicated by law and these Bylaws, as well as those that are entrusted to them by the Audit and Risks Committee and the General Shareholders Assembly (provided such duties are compatible with the law and Bylaws).

 

13) Ensure that management complies with the specific duties established by the monitoring bodies, especially those related to the duties of information and the Corporate Governance Code.

 

14) Report relevant findings to the Company's bodies, to the authorities and to the market, as appropriate.

 

15) Be aware of the complaints filed for breach of the rights of shareholders and investors, as well as the results of these investigations, which will be conveyed to the Board of Directors and made known to the General Shareholders Assembly.

 

16) Ensure that the Company's accounts and the minutes for sessions of the General Shareholders Assembly and the Board of Directors are kept regularly, and that the Company's correspondence and account vouchers are duly kept, issuing the necessary instructions for such purposes.

 

17) All others indicated in Article 207 of the Commerce Code or other legal provisions.

 

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PARAGRAPH ONE: The Statutory Auditor will not have the authority to intervene in Ecopetrol's administrative activities. They may only perform the administrative duties inherent to the role of Statutory Auditor.

 

PARAGRAPH TWO: In order to communicate the material findings, the Statutory Auditor must:

 

1) Report any irregularities that occur in Ecopetrol's operation and in the implementation of its business, in writing and in a timely manner, to the Board of Directors, the General Shareholders Assembly, the Audit and Risks Committee or the President, as appropriate in accordance with the competence of the body and the magnitude of the finding in the judgment of the Statutory Auditor.

 

2) Summon extraordinary meetings of the General Shareholders Assembly when necessary.

 

3) Inform the legal representative of securities holders, when deemed necessary, in the event there are debt securities.

 

PARAGRAPH THREE: On a permanent basis, management will use Ecopetrol's website www.ecopetrol.com.co or whichever site takes its place (available to the market and shareholders) to publish the latest report from the Statutory Auditor, together with its annexes and the details of the findings and qualifications presented.

 

ARTICLE THIRTY-FIVE. DISQUALIFICATIONS FOR THE POSITION OF STATUTORY AUDITOR.- In addition to the disqualifications and incompatibilities established in law, Ecopetrol's Statutory Auditor may not be anyone who has received income from the Company and/or its subsidiaries, where such income represents twenty-five percent (25%) or more of their latest annual income from the immediately preceding year, or persons who perform or exercise (in the Company and/or its subsidiaries companies, directly or through third parties) services other than those of Statutory Auditor, thereby compromising their independence for exercising the position. The Statutory Auditor will be appointed for periods of two (2) years and may be reelected consecutively for a total of 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.

 

CHAPTER X:

FINANCIAL STATEMENTS, PROFIT DISTRIBUTION, AND RESERVE FUNDS

 

ARTICLE THIRTY-SIX: FINANCIAL STATEMENTS. - On the thirty-first (31st) of December of each year the accounts will be closed and the financial statements of the Company will be produced.

 

ARTICLE THIRTY-SEVEN: FUTURE EXPENSES. - In order to calculate the income statement, funds must be appropriated in advance to cover future-but-certain expenses, such as company benefits, depreciation, amortization, and taxes, among others.

 

ARTICLE THIRTY- EIGHT. PROFITS. - Of the net profits calculated in accordance with Article 39 of these Bylaws, ten percent (10%) will be taken for the statutory reserve, until it is equal to half of the subscribed capital. When this limit is reached, the Company will not be obliged to continue carrying this ten percent (10%) to this account, unless the General Shareholders Assembly so provides. However, if it decreases, the same ten percent (10%) of the profits will be appropriated until the reserve once again reaches the limit of fifty percent (50%) of the subscribed capital.

 

ARTICLE THIRTY-NINE. DIVIDENDS.- For purposes of the distribution of profits as provided in Articles 155 and 454 of the Commercial Code or the rules that replace or amend them, net profits shall be considered as those resulting from the application of the following procedure:

 

1) The profits made by the Company are based on the real and reliable Financial Statements for each year, and from this value only the items corresponding to the following are subtracted: (i) Financing the losses from previous years that affect the capital, i.e. when as a consequence thereof the net equity is reduced below the subscribed capital (if any); (ii) The statutory reserve and bylaw-related reserves (if any), and (iii) Appropriations for the payment of income and ancillary taxes.

 

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2) Using the balance thus determined, the percentages to be distributed shall be applied in accordance with the provisions of the Law. This value shall be the minimum amount to be distributed as a dividend in each period.

 

3) The amounts resulting after having distributed the minimum dividends will be available so that the General Shareholders Assembly can establish incidental reserves or so that they can be distributed as dividends in addition to the minimum dividends established in number 2) above.

 

ARTICLE FOURTY. LOSSES.- Losses, if any, will be cancelled using the reserves allocated for that purpose and, failing that, using the legal reserve. Reserves whose purpose is to absorb certain losses cannot be used to cover other losses, unless the General Shareholders Assembly so decides. If the statutory reserve is insufficient to cancel the losses, the company’s profits for the following years will be applied to this end, until the loss is extinguished, and during such time it shall not be possible to allocate the profits differently. The meeting may adopt or order measures leading to the restoration of net equity when losses arise that have placed such equity below fifty percent (50%) of the subscribed capital of the Company, e.g. measures such as the sale of valued company assets, the reduction of subscribed capital (carried out in accordance with the law), or the issuance of new shares. Any of these measures must be taken within eighteen (18) months following the determination of the loss. Failing this, the Company must be dissolved.

 

CHAPTER XI:

DISSOLUTION AND LIQUIDATION

 

ARTICLE FORTY-ONE. DISSOLUTION.- The Company will only be dissolved due to the causes provided in Article 457 of the Commercial Code or the rules that replace or amend them.

 

ARTICLE FORTY-TWO. LIQUIDATION.- If the Company is dissolved, its liquidation will commence immediately. To this end, it should be taken into account that:

 

1) Excluding the event of an express legal exception, any act that deviates from this purpose will result in the unlimited, joint and several liability of the Liquidator or Liquidators and the Statutory Auditor who failed to intervene.

 

2) The following words must be added to the company name: UNDER LIQUIDATION. If this requirement is ignored, the Liquidator or Liquidators and the Statutory Auditor who failed to intervene shall be liable in an unlimited, joint and several manner for the damage and losses that may occur.

 

PARAGRAPH: In the event of liquidation, in-kind contributions will be returned to the person who provided them, in the corresponding proportion, once Article 240 of the Commercial Code and the other applicable legal provisions in such case have been applied.

 

ARTICLE FORTY-THREE. LIQUIDATOR.- The liquidation of the Company shall be performed by the person appointed by the General Shareholders Assembly and in accordance with Article 228 of the Commercial Code, or the provisions that supplement, govern or amend it. The Liquidator will execute any action under its exclusive liability.

 

ARTICLE FORTY-FOUR. POWERS OF THE LIQUIDATOR.- The President, in their capacity as liquidator, or the liquidators appointed by the General Shareholders Assembly, have the obligations and powers conferred to them by Articles 232, 233 and 238 of the Commercial Code.

 

ARTICLE FORTY-FIVE. POWERS OF THE GENERAL SHAREHOLDERS ASSEMBLY.- During the liquidation, the powers of the General Shareholders Assembly will remain as they were during the existence of the Company, with the only limitations being those that the liquidation status imposes.

 

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CHAPTER XII:

FINAL REGULATIONS

 

ARTICLE FORTY-SIX. TRANSPARENCY. - Ecopetrol group, its managers, employees and beneficiaries have expressly adopted a zero-tolerance policy against fraud, bribery, corruption, any violations to the FCPA, money laundering and terrorist financing. Furthermore, they manifestly reject any actions such as facilitation payments, political contributions and donations, and donations that do not comply with the requirements of the Colombian Constitution, lobbying activities and payments, anti-competitive and monopolistic practices, sexual harassment, discrimination in any form, and any behavior that may constitute a violation of the Colombian Constitution, local or foreign law, as applicable. Likewise, they reject all conducts infringing or not acknowledging the content of the Code of Ethics and the internal regulation. Based on this, the Company undertakes to:

 

1) Refrain from participating in events considered compliance risks (fraud, bribery, violations to FCPA, money laundering and terrorist financing).

 

2) Promote, maintain and strengthen the Compliance Program, the Internal Control System, the Integrated Risk System and an ethics and transparency culture in the Company to prevent and mitigate the materialization of compliance risks.

 

3) Have in place tools to identify the risks of the Company and that include means of control to mitigate such risks.

 

4) Reject and penalize behaviors involving the materialization of any of the risks set forth in this article.

 

5) Zero-tolerance of acts of favoritism or nepotism in selection processes or facilitation payments, political contributions and donations, and donations that do not comply with the requirements of the Colombian Constitution, lobbying activities and payments, anti-competitive and monopolistic practices.

 

6) Have in place adequate and confidential channels to receive and manage complaints, dilemmas and enquiries submitted by employees and people interested in the transparency of the Company.

 

7) Cooperate with national and foreign authorities in carrying out any inquiry and/or investigation involving Ecopetrol Group, its employees, contractors, suppliers, partners or allies.

 

8) Have within its organizational structure, an independent unit that ensures the adoption and management of the Compliance Program, the Internal Control System, and the Integrated Risk System and fosters its enforcement and articulation in Ecopetrol and the companies of Ecopetrol Group. This unit will have functional reporting to the Audit and Risks Committee of the Board of Directors.

 

ARTICLE FORTY-SEVEN. DUTIES AND RESPONSIBILITIES OF MANAGERS. - The duties and responsibilities of Ecopetrol will be those included in managers shall relate to those established in Article 23 of, Law 222 of 1995 and Article 200 of the Commerce Code, or in the legal provisions that govern, amend or replace these, or that are applicable.

 

ARTICLE FORTY-EIGHT. DUTY OF CONFIDENTIALITY. - The members of the Board of Directors and the employees of the Company have the duty to comply with the legal and internal guidelines regarding the protection and handling of confidential and reserved information, and may not make use of it for their own benefit or that of a third party, or for the purpose of causing any damage or harm to the Company or its shareholders. Therefore, they may not disclose to third parties the operations, plans or initiatives thereof, nor communicate of any technical procedure or the results of exploration or location of assets, or similar, and in general the activities of Ecopetrol, unless instructed or ordered by a competent government authority.

 

The use of privileged information for the negotiation of shares is rejected and prohibited. The Company's Administrators and employees must abide by the laws and internal regulations governing the matter.

 

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ARTICLE FORTY-NINE. DISQUALIFICATIONS AND INCOMPATIBILITIES.- The members of the Board of Directors and the employees of Ecopetrol will be subject to the inabilities and incompatibilities set out in the Political Constitution, the law, and the provisions contained in these Bylaws on such issues and on conflicts of interest, as well as the rules that govern, amend or replace these.

 

PARAGRAPH ONE: The foregoing does not prevent the members of the Board of Directors or employees at any level from acquiring the goods or services that the Company supplies to the public under conditions common to all those who request them.

 

PARAGRAPH TWO: Ecopetrol workers may be members of the boards of directors of the companies in which Ecopetrol holds an equity stake, which shall not imply a conflict of interest between that duty and the exercise of duties within the Company.

 

ARTICLE FIFTY. CONFLICTS OF INTEREST.- Among others, a conflict of interest shall be deemed to exist when:

 

a) There are opposing interests between a Manager or any employee of the Company and the interests of Ecopetrol, which may lead them to making decisions or acting for their own benefit or the benefit of third parties and to the detriment of the interests of the Company, or

 

b) When there is any circumstance that may diminish independence, fairness or objectivity in the actions of a Manager or any employee of Ecopetrol, and this may be detrimental to the interests of the Company.

 

For these purposes, Managers shall be construed as the persons defined as such in Article 22, Law 222 of 1995 or any rule that adds to, amends or replaces it.

 

PARAGRAPH TWO: DISCLOSURE OF CONFLICTS IN THE COMPANY.- The President members of the Board of Directors and all of Ecopetrol employees must disclose any conflict between their personal interests and the interests of Ecopetrol when dealing with its main shareholder and its subsidiaries companies, customers, suppliers, contractors and any person who conducts or intends to conduct business with the Company or with companies in which it has a shareholding or interests (direct or indirect).

 

PARAGRAPH THREE: MANAGEMENT OF CONFLICTS OF INTEREST.- In order to resolve situations involving conflicts of interest, the following procedure will be followed:

 

a) In the event that the conflict of interest involves an employee of the Company, other than Managers at the Company they must inform their line manager in writing so that the latter may decide on the matter, and if they deem that the conflict of interest exists, such line manager will appoint someone to replace the person involved in the conflict of interest.

 

b) In the event that the conflict of interest involves a Manager at Ecopetrol, matters shall proceed as provided in Section 7, Article 23, Law 222 of 1995 or the rules that may add to, amend or replace it.

 

ARTICLE FIFTY-ONE. ECOPETROL S.A. APPLICABLE LAW.- The legal system applicable to the Company will be that indicated in law, which, for the legal acts, agreements and actions necessary to manage and implement the corporate purpose, is exclusively Private Law.

 

ARTICLE FIFTY-TWO. CORPORATE GOVERNANCE.- Ecopetrol, its managers and employees undertake the obligation to comply with the corporate governance practices, which have been voluntarily adopted by the Company

 

ARTICLE FIFTY-THREE. SUPPLEMENTARY RULES.- In matters not provided for in these Bylaws, the relevant legal provisions shall apply.

 

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Exhibit 8.1

 

Subsidiaries of Ecopetrol S.A.

 

The following table sets forth our subsidiaries, their respective countries of incorporation, our percentage ownership in each (both directly and indirectly through other subsidiaries) at December 31, 2020.

 

COMPANY COUNTRY OF  INCORPORATION OWNERSHIP
ANDEAN CHEMICALS LIMITED Bermuda 100%
BLACK GOLD RE LIMITED Bermuda 100%
CENIT TRANSPORTE Y LOGÍSTICA DE HIDROCARBUROS S.A.S. Colombia 100%
ECOPETROL CAPITAL AG Switzerland 100%
ECOPETROL ENERGÍA SAS ESP * Colombia 100%
ECOPETROL GLOBAL ENERGY S.L.U. Spain 100%
EQUION ENERGÍA LIMITED United Kingdom 51%
HOCOL PETROLEUM LIMITED Bermuda 100%
INVERSIONES DE GASES DE COLOMBIA S.A. - Invercolsa S.A. Colombia 51.88%
REFINERIA DE CARTAGENA S.A.S * Colombia 100%
COLOMBIA PIPELINES LIMITED** United Kingdom 51%
ECOPETROL AMERICA LLC** United States 100%
ECOPETROL COSTA AFUERA COLOMBIA S.A.S.** Colombia 100%
ECOPETROL DEL PERU S.A.** Peru 100%
ECOPETROL OLEO & GAS DO BRASIL LTDA** Brazil 100%
ECOPETROL PERMIAN LLC ** United States 100%
ECOPETROL USA INC ** United States 100%
ECP Hidrocarburos de México ** Mexico 100%
ESENTTIA  MASTERBATCH LTDA** Colombia 100%
ESENTTIA RESINAS DEL PERU SAC** Peru 100%
ESENTTIA S.A. * Colombia 100%
HOCOL S.A.** Cayman Islands 100%
KALIXPAN SERVICIOS TÉCNICOS S. de r.l. de c.v ** Mexico 100%
OLEODUCTO BICENTENARIO DE COLOMBIA S.A.S.** Colombia 55.97%
OLEODUCTO CENTRAL S.A. - OCENSA** Colombia 72.65%
OLEODUCTO DE COLOMBIA S.A. - ODC ** Colombia 73%
OLEODUCTO DE LOS LLANOS ORIENTALES S.A.** Panama 65%
SANTIAGO OIL COMPANY** Cayman Islands 51%
TOPILI SERVICIOS ADMINISTRATIVOS de r.l. de c.v** Mexico 100%

 

*Direct and/or indirect participation.
**Solely indirect participation through subsidiaries or affiliates.

 

 

 

Exhibit 12.1

 

CERTIFICATION

 

I, Jaime Caballero Uribe, certify that:

 

  1. I have reviewed this annual report on Form 20-F of Ecopetrol S.A.;

 

  2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

  3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

 

  4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

 

  (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

 

  (c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  (d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

 

  5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

 

  (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

 

  (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

 

Dated: April 8, 2021

 

  By: /s/ Jaime Caballero Uribe
    Name: Jaime Caballero Uribe
    Title: Acting Chief Executive Officer

 

 

 

Exhibit 12.2

 

CERTIFICATION

 

I, Sebastian Castañeda Arbelaez, certify that:

 

  1. I have reviewed this annual report on Form 20-F of Ecopetrol S.A.;

 

  2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

  3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

 

  4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

 

  (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

  (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

 

  (c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

  (d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

 

  5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

 

  (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

 

  (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

 

Dated: April 8, 2021

 

  By: /s/ Sebastian Castañeda Arbelaez
    Name: Sebastian Castañeda Arbelaez
    Title: Acting Chief Financial Officer

 

 

 

Exhibit 13.1

 

Certification
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

 

Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), each of the undersigned officers of Ecopetrol S.A. (the “Company”), does hereby certify, to such officer’s knowledge, that:

 

The annual report on Form 20-F for the fiscal year ended December 31, 2020 (the “Form 20-F”) of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 20-F fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

Dated: April 8, 2021    
  By: /s/ Jaime Caballero Uribe
    Name: Jaime Caballero Uribe
    Title: Acting Chief Executive Officer
       
       
Dated: April 8, 2021      
  By: /s/ Sebastian Castañeda Arbelaez
    Name: Sebastian Castañeda Arbelaez
    Title: Acting Chief Financial Officer

 

 

 

Exhibit 23.1

 

Consent of Independent Registered Public Accounting Firm

 

We consent to the incorporation by reference in the Registration Statement (Form F-3 No. 333-225381) of Ecopetrol S.A. and in the related Prospectus of our reports dated April 08, 2021, with respect to the consolidated financial statements of Ecopetrol S.A., and the effectiveness of internal control over financial reporting of Ecopetrol S.A., included in this Annual Report (Form 20-F) for the year ended December 31, 2020.

 

 

/s/ Ernst & Young Audit S.A.S.  
   
Bogotá, Colombia  
   
April 08, 2021  

 

 

Exhibit 23.2

 

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

 

Ryder Scott Company, L.P. (“Ryder Scott”) consents to the references to our firm and our report dated February 10, 2021 (our “Report”) included in Ecopetrol S.A.’s annual report on Form 20-F for the year ended December 31, 2020 (the “Annual Report”), the inclusion of our Report as Exhibit 99.1 to the Annual Report and references to and information derived from our Report in the Annual Report, as well as to the incorporation by reference of the consent and our Report into Ecopetrol S.A.’s registration statement on Form F-3 filed with the United States Securities and Exchange Commission on June 1, 2018 (the “Registration Statement”). Ryder Scott further consents to the references to Ryder Scott as set forth in the Registration Statement under the heading “Experts”.

 

  /s/ RYDER SCOTT COMPANY, L.P.
   
  RYDER SCOTT COMPANY, L.P.
  TBPE Firm Registration No. F-1580

 

Houston, Texas

April 8, 2021

 

SUITE 2800, 350 7TH AVENUE, S.W.   CALGARY, ALBERTA T2P 3N9   TEL (403) 262-2799
633 17TH STREET, SUITE 1700   DENVER, COLORADO 80202   TEL (303) 339-8110

 

 

 

Exhibit 23.3

 

 

 

Ref.: 4377.110461

 

  April 7, 2021

 

Ecopetrol S.A

Calle 35 No. 7-21 Piso 1

Bogotá, D.C. Colombia

 

Re: Consent of Independent Petroleum Engineer

 

Dear Sirs:

 

We refer to our report, entitled “Evaluation of Certain P&NG Reserves of Hocol S.A. in Colombia (As of December 31, 2020)” dated February 5, 2021 (the “Report”).

 

We hereby consent to the references to Sproule International Limited (“Sproule”) and to the inclusion of and information derived from Sproule’s Report in Ecopetrol S.A.’s (“the Company”) annual report Form 20-F for the year ended December 31, 2020 (the “Annual Report”), the inclusion of our Report as Exhibit 99.2 to the Annual Report, as well as to the incorporation by reference of this consent and our Report into Ecopetrol S.A.’s registration statement on Form F-3 filed with the United States Securities and Exchange Commission on June 1, 2018 (“the Registration Statement”). We further consent to the references to Sproule International Limited as set forth in the Registration Statement under the heading “Experts”. Sproule’s reserves estimates for Colombia as prepared for Hocol S.A. and contained in the Annual Report have been combined with estimates of reserves prepared by other petroleum consultants and Sproule is therefore unable to verify the accuracy of the reserves estimates contained in the Annual Report other than those contained in the Report.

 

  Sincerely,
   
  SPROULE INTERNATIONAL LIMITED
  Alberta Permit to Practice number P06151
   
  /s/ Gary R. Finnis, P.Eng
  Gary R. Finnis, P.Eng
  Senior Manager, Engineering
  Date: Apr. 07, 2021                  Membership: 62965
   
  Gary Finnis, P.Eng
  Senior Manager

 

140 Fourth Avenue SW, Suite 900

Calgary, AB, Canada T2P 3N3

Sproule.com

T +1 403 294 5500 F +1 403 294 5590 TF +1 877 777 6135

 

 

Exhibit 23.4

 

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

 

April 8, 2021

 

Board of Directors

Ecopetrol S.A.

Calle 35 No. 7-21 Piso 1

Bogota, D.C. Colombia

 

Ladies and Gentlemen:

 

We hereby consent to the references to DeGolyer and MacNaughton and to the inclusion of and information derived from our report of third party dated February 12, 2021, containing our opinions regarding our estimates, as of December 31, 2020, of the proved oil, condensate, natural gas liquids, gas, and oil equivalent reserves of certain selected properties that Ecopetrol S.A. has represented it holds in Colombia and the United States as set forth under the headings “3. Business Overview–3.5 Exploration and Production–3.5.3 Reserves,” “8. Financial Statements,” and “10. Exhibits” and as Exhibit No. 99.3 in the Annual Report on Form 20-F of Ecopetrol S.A. for the year ended December 31, 2020 (the Annual Report), and to the incorporation by reference of this consent and our report of third party into Ecopetrol S.A.’s registration statement on Form F-3 filed with the United States Securities and Exchange Commission on June 1, 2018 (the Registration Statement). We further consent to the references to DeGolyer and MacNaughton as set forth in the Registration Statement under the heading “Experts,” provided, however, that we are necessarily unable to verify the accuracy of the reserves estimates contained in the Annual Report because our estimates of reserves have been combined with estimates of reserves prepared by other petroleum consultants.

 

  Very truly yours,
   
  /s/ DeGolyer and MacNaughton
  DeGOLYER and MacNAUGHTON
  Texas Registered Engineering Firm F-716

 

 

Exhibit 23.5

 

  Gaffney, Cline & Associates, Inc.
4425 Westway Park Blvd
Houston, TX 77041
 
Tel: +1 713 850 9955

 

March 29, 2021

 

Board of Directors

Ecopetrol S.A.

Carrera 13 No. 36 - 24

Bogotá, D.C.

Colombia

 

Dear Sirs,

 

Consent of Gaffney, Cline & Associates

 

As independent reserves engineers for Ecopetrol S.A. (Ecopetrol), Gaffney, Cline & Associates (GaffneyCline) hereby confirms that it has granted and not withdrawn its consent to (i) the references to GaffneyCline and to the inclusion of information contained in our third-party letter report entitled “SEC Proved Reserves Statement for Forty Nine Fields in Colombia in which Ecopetrol has an Interest, as of December 31, 2020”, dated February 16, 2021, prepared for Ecopetrol, and to the annexation of our report as an exhibit in Ecopetrol’s annual report on Form 20-F for the year ended December 31, 2020; and, (ii) incorporation by reference of this consent and our report into Ecopetrol S.A.’s registration statement on Form F-3 filed with the United States Securities and Exchange Commission on June 1, 2018 (the “Registration Statement”).

 

Yours sincerely,

     
  Gaffney, Cline & Associates  
     
 

/s/ Alejandro Giaquinta

 
  Project Manager  
  Alejandro Giaquinta, Principal Advisor  

 

 

 

Exhibit 23.6

 

 

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

 

We hereby consent to the inclusion in this Annual Report on Form 20-F of Ecopetrol S.A. for the year ended December 31, 2020 (the "Annual Report") of our report dated March 26, 2021, with respect to estimates of net reserves to the Ecopetrol S.A. interest, as of December 31, 2020 (our "Report") and to all references to our firm included in the Annual Report, as well as to the incorporation by reference of the consent and our Report into the Registration Statement on Form F-3 of Ecopetrol S.A., filed with the United States Securities and Exchange Commission on June 1, 2018 (the "Registration Statement").

 

  NETHERLAND, SEWELL & ASSOCIATES, INC.

 

By: /s/ C.H. (Scott) Rees III
  C.H. (Scott) Rees III, P.E.
    Chairman and Chief Executive Officer

 

Dallas, Texas

April 7, 2021

 

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

 

 

 

 

Exhibit 99.1

 

     

TBPE REGISTERED ENGINEERING FIRM F-1580

1100 LOUISIANA   SUITE 4600

HOUSTON, TEXAS 77002 -5294

FAX (713) 651-0849

TELEPHONE (713) 651 -9191

 

February 10, 2021

 

Ecopetrol

Cra. 13 No. 36-24

Edificio Principal, Piso 7 

Bogotá, D.C., Colombia 

 

Ladies and Gentlemen:

 

At the request of Ecopetrol, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves attributable to certain interests of Ecopetrol, as of December 31, 2020. The subject properties are located in the country of Colombia. The reserves were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 21, 2021 and presented herein, was prepared for public disclosure by Ecopetrol in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

 

The properties evaluated by Ryder Scott account for a portion of Ecopetrol’s total net proved reserves as of December 31, 2020. Based on information provided by Ecopetrol, the third party estimate conducted by Ryder Scott addresses 74 percent of the total proved developed net liquid hydrocarbon reserves and 66 percent of the total proved undeveloped net liquid hydrocarbon reserves of Ecopetrol. Ryder Scott evaluation also addresses 88 percent of the total proved developed net gas reserves and 56 percent of the total proved undeveloped net gas reserves of Ecopetrol.

 

The estimated reserves amounts presented in this report, as of December 31, 2020, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this 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. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

 

SUITE 2800, 350 7TH AVENUE, S.W. CALGARY, ALBERTA T2P 3N9 TEL (403) 262-2799
633 17TH STREET, SUITE 1700 DENVER, COLORADO 80202 TEL (303) 339-8110

 

  1  

 

 

Ecopetrol

February 10, 2021 

 

SEC PRICES PARAMETERS 

Estimated Net Reserves 

Attributable to Certain Interests of

Ecopetrol 

As of December 31, 2020

     

    Proved  
    Developed           Total  
    Producing     Non-Producing     Undeveloped     Proved  
Net Reserves                                
Oil/Condensate – Barrels     495,589,417       98,817,499       267,886,571       862,293,487  
Plant Products – Barrels     51,381,533       1,177,748       5,835,929       58,395,210  
Sales Gas – MMcf     2,104,130       973       123,522       2,228,625  
Fuel Oil - Barrels     5,690,553       173,988       6,286,688       12,151,229  
Fuel Gas - MMcf     308,678       8,855       37,120       354,653  

  

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels. The “sales” gas volumes are reported on an “as sold” basis expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In addition, at Ecopetrol’s request, the Fuel Gas and Fuel Oil volumes presented above are reported, but do not result in any sales or revenues to Ecopetrol’s interest. The net sales gas reserves volumes include certain gas royalty volumes owed to the host government that are treated as taxes to be paid in cash. 

 

Reserves Included in This Report

 

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

 

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe status categories.

 

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist.

 

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Ecopetrol’s request, this report addresses only the proved reserves attributable to the properties evaluated herein. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

2

 

 

Ecopetrol

February 10, 2021 

 

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

 

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

 

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal rights to produce or a revenue interest in such production unless evidence indicates that contract renewal is reasonably certain. Furthermore, properties in Colombia may be subjected to substantially varying contractual fiscal terms that affect the net revenue to Ecopetrol for the production of these volumes. The prices and economic return received for these net volumes can vary materially based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Ecopetrol the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Ecopetrol’s representations regarding such contractual information should be construed as a legal opinion on this matter.

 

This report includes certain volumes of proved reserves attributable to royalties owed to the host government that are treated as taxes to be paid in cash.

 

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Ecopetrol operates or has interests. Ecopetrol’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

 

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Ecopetrol owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

3

 

 

Ecopetrol

February 10, 2021 

 

Estimates of Reserves

 

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

 

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

 

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

 

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. Approximately 99 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through December 31, 2020 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Ecopetrol and were considered sufficient for the purpose thereof. The remaining 1 percent of the proved producing reserves were estimated by the volumetric method, analogy, or a combination of methods. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserves estimates was considered to be inappropriate.

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

4

 

 

Ecopetrol

February 10, 2021 

 

Approximately 100 percent of the proved developed non-producing and undeveloped reserves included herein were estimated by the volumetric method, analogy, or a combination of methods. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Ecopetrol that were available through December 31, 2020. The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

 

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

 

Ecopetrol has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Ecopetrol with respect to property interests, production and well tests from examined wells, normal direct costs of operating the wells or contract areas, other costs such as transportation and/or processing fees, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Ecopetrol. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

 

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations. 

 

Future Production Rates

 

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

 

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Ecopetrol. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

5

 

 

Ecopetrol

February 10, 2021 

 

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. 

 

Hydrocarbon Prices

 

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this 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. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

 

Ecopetrol furnished us with the above mentioned average prices in effect on December 31, 2020. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area(s) included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements. In cases where there are numerous contracts or price references within the same geographic area, the benchmark price is represented by the unweighted arithmetic average of the initial 12-month average first-day-of-the-month benchmark prices used.

 

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Ecopetrol. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Ecopetrol to determine these differentials.

 

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic areas and presented in accordance with SEC disclosure requirements for each of the geographic areas included in this report. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

6

 

 

Ecopetrol

February 10, 2021 

 
                  Average  
            Average     Proved  
        Price   Benchmark     Realized  
Geographic Area   Product   Reference   Price     Price  
    Oil/Condensate   Brent   $ 43.41/bbl   $ 35.39/bbl
Colombia   NGLs   Brent   $ 43.41/bbl   $ 27.59/bbl
    Gas   Gas Sales Agreement     $ 4.97/Mcf

 

 

The liquid price above, as provided by Ecopetrol, used the ICE Brent published by Bloomberg as reference. The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations. Liquid hydrocarbon reserves account for approximately 74 percent and gas reserves account for the remaining 26 percent of total future gross revenue from proved reserves. 

 

Costs

 

Operating costs for the contract areas and wells in this report were furnished by Ecopetrol and are based on the operating expense reports of Ecopetrol and include only those costs directly applicable to the contract areas or wells. The operating costs include a portion of general and administrative costs allocated directly to the contract areas and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Ecopetrol. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the contract areas or wells.

 

Development costs were furnished to us by Ecopetrol and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Ecopetrol were accepted without independent verification.

 

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Ecopetrol’s plans to develop these reserves as of December 31, 2020. The implementation of Ecopetrol’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Ecopetrol’s management. As the result of our inquiries during the course of preparing this report, Ecopetrol has informed us that the development activities included herein have been subjected to and received the internal approvals required by Ecopetrol’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Ecopetrol. Ecopetrol has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Ecopetrol has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While these plans could change from those under existing economic conditions as of December 31, 2020, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

7

 

 

Ecopetrol

February 10, 2021 

 

According to Item 1203 (d) of the SEC Regulations, an explanation should be included for the reasons “…why material amounts of proved undeveloped reserves remain undeveloped for five years or more after disclosure as proved undeveloped reserves.” A material amount of proved undeveloped reserves in this report is forecast to be developed beyond the five-year time frame. A five-year time frame for converting undeveloped reserves to developed reserves was adopted by the SEC, “unless specific circumstances justify a longer time frame.” In this report, Ryder Scott notes that there is an exception to the 5-year rule for the proved category in Rubiales field where proved undeveloped reserves were assigned beyond the 5-year limit. In the case of Rubiales, the field has facilities constraints in water handling capacity which require the scheduling of the entry of the new wells based on spare capacity of the plant. In our opinion, these facilities issues are considered a reasonable justification for an exception to the 5-year rule.

 

Current costs used by Ecopetrol were held constant throughout the life of the properties. 

 

Standards of Independence and Professional Qualification

 

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

 

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

 

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

 

We are independent petroleum engineers with respect to Ecopetrol. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

 

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

8

 

 

Ecopetrol

February 10, 2021 

 

Terms of Usage

 

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Ecopetrol.

 

Ecopetrol makes periodic filings on Form 20-F with the SEC under the 1934 Exchange Act. Furthermore, Ecopetrol has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 20-F is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form F-3 of Ecopetrol, of the references to our name, as well as to the references to our third party report for Ecopetrol, which appears in the December 31, 2020 annual report on Form 20-F of Ecopetrol. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Ecopetrol.

 

We have provided Ecopetrol with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Ecopetrol and the original signed report letter, the original signed report letter shall control and supersede the digital version.

 

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

 

  Very truly yours,  
     
  RYDER SCOTT COMPANY, L.P.  
  TBPE Firm Registration No. F-1580  
    

Mario A. Ballesteros, P.E.
TBPE License No. 107132
Managing Senior Vice President

 

 

MAB (FWZ)/pl 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

9

 

  

Professional Qualifications of Primary Technical Person

 

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mario A. Ballesteros was the primary technical person responsible for overseeing the independent estimation of reserves, future production and income to render the audit conclusions of the report presented herein.

 

Mr. Ballesteros, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President and also serves as an Engineering Group Leader responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Ballesteros served in a number of engineering positions with Chevron. For more information regarding Mr. Ballesteros geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

 

Mr. Ballesteros earned a Bachelor of Science degree in Mechanical Engineering in 1991 and a Masters of Petroleum Engineering degree in 1993 from the University of Tulsa. He also earned a Masters in Finance in 2000 from the Meta University in Colombia. He is a registered Professional Engineer in the State of Texas.

 

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Ballesteros fulfills. Mr. Ballesteros has attended formalized training and conferences including dedicated to the subject of the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register.

 

Based on his educational background, professional training and more than 21 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Ballesteros has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of June 2019.

  

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

10

 

 

PETROLEUM RESERVES DEFINITIONS

 

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) 

 

PREAMBLE

 

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

 

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

 

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

 

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

 

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

  1  

 

 

PETROLEUM RESERVES DEFINITIONS

 

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

 

Reserves do not include quantities of petroleum being held in inventory.

 

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories. 

 

RESERVES (SEC DEFINITIONS)

 

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

 

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). 

 

PROVED RESERVES (SEC DEFINITIONS)

 

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

 

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

(i) The area of the reservoir considered as proved includes:

 

(A) The area identified by drilling and limited by fluid contacts, if any, and

 

(B)  Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.  

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

2

 

 

PETROLEUM RESERVES DEFINITIONS

 

 

(ii)  In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii)  Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

(iv)   Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

(B)  The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v)  Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

  

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

3

 

 

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

 

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

 

and

 

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)
Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE) 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)
SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG) 

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)
EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE) 

 

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein). 

 

DEVELOPED RESERVES (SEC DEFINITIONS)

 

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

 

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i)  Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

(ii)  Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Developed Producing (SPE-PRMS Definitions)

 

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

 

Developed Producing Reserves

 

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. 

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

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PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES 

 

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

 

Developed Non-Producing

 

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

 

Shut-In

 

Shut-in Reserves are expected to be recovered from:

 

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

 

(2) wells which were shut-in for market conditions or pipeline connections; or

 

(3) wells not capable of production for mechanical reasons.

 

Behind-Pipe

 

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

 

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well. 

 

UNDEVELOPED RESERVES (SEC DEFINITIONS)

 

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

 

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

(i)   Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii)   Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

(iii)  Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.  

 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

 

2

 

 

Exhibit 99.2

 

 

 

  February 9, 2021

 

Ecopetrol S.A.

Cra. 13 No. 36-24

Edificio Principal, Piso 7

Bogotá, D.C., Colombia

 

Dear Sirs:

 

Sproule International Limited (“Sproule”) has been engaged by Hocol S.A (“Hocol” or the “Company”) to evaluate the proved, probable, and possible reserves in 9 blocks (16 fields) in Colombia, as of December 31, 2020, and to prepare a report as to its findings (the “Report”). The Report is compliant with the United States Securities Exchange Commission (SEC) definitions and disclosure guidelines. Hocol S.A. is a wholly owned subsidiary of Ecopetrol S.A. The Report, completed on February 5, 2021 and presented herein, was prepared for public disclosure by Ecopetrol S.A. in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

 

Ecopetrol S.A. has represented that the properties evaluated by Sproule for Hocol account for one (1) percent of Ecopetrol’s net total Barrel of Oil Equivalent (“BOE”) proved reserves as of December 31, 2020.

 

Estimates of Reserves

 

Reserves estimates included in this report are expressed as net oil reserves. Net oil reserves are defined as the portion of the gross reserves to be produced from the 9 blocks (16 fields) evaluated by Sproule after December 31, 2020 attributable to the interests owned by Ecopetrol after deducting all interests owned by others, including royalties in kind. As regulated by the ANH, all royalties associated to the properties reported herein were considered as a cash payment and not deducted from the net gas reserves.

 

140 Fourth Avenue SW, Suite 900

Calgary, AB, Canada T2P 3N3

Sproule.com

T +1 403 294 5500 F +1 403 294 5590 TF +1 877 777 6135

 

 

 

The reserves estimates for the properties contained herein were obtained using a variety of estimation methods: volumetric, performance, analogy or a combination of performance and volumetric methods. The following table summarizes the approximate percentage of the net reserves estimated by each of these methods.

 

Approximate Percent of Net Proved Reserves Estimated by Method
    Gas     Liquid Hydrocarbons  
Method   Developed     Undeveloped     Developed     Undeveloped  
Volumetric     0       0       0       0  
Performance     100       0       100       0  
Analogy     0       0       0       0  
Combination     0       100       0       100  

 

Sproule’s estimates of Ecopetrol S.A.’s net proved reserves, attributable to the properties contained in this report, were based on the definitions of proved reserves as promulgated by the SEC and are summarized as follows, expressed in millions of barrels (MMbbl) and millions of cubic feet (MMcf):

 

Estimates of Ecopetrol S.A.'s Net Reserves by Sproule

As of December 31, 2020

 
    Proved  
Net Remaining Reserves   Developed     Undeveloped     Total Proved  
Light and Medium Crude Oil (Mbbl)     8,080.4       5,107.8       13,188.2  
Conventional Natural Gas (Solution Gas) (MMcf)     3,178       0       3,178  
Gas Consumed in Operations (MMcf)     8,303       10,904       19,207  

 

Accuracy and Reliance on Data

 

All historical production, revenue and expense data, product prices, and other data that were obtained from the Company were accepted as represented, without further investigation by Sproule. According to the contract, the Company provided all the information required, such as the needed information and documents to ensure that Sproule would be able to complete the consulting services. Sproule is not responsible for the veracity and integrity of the information provided by the Company to execute the consultancy, which has been used in the generation of the evaluation results.

 

The accuracy of reserves estimates and associated economic analysis is, in part, a function of the quality and quantity of available data and of engineering and geological interpretation and judgment. Given the data provided at the time this letter was prepared, the estimates presented herein are considered reasonable. However, they should be accepted with the understanding that reservoir and financial performance subsequent to the date of the estimates may necessitate revision. These revisions may be material.

 

Sproule International Limited   - 2 -   February 9, 2021 

 

 

Maintenance, capital, abandonment, decommissioning and reclamation (“ADR”) cost estimates, as supplied by the Company, were accepted by Sproule as represented. No further investigation was undertaken by Sproule.

 

Evaluation Standards

 

This report has been prepared by Sproule using current geological and engineering knowledge, techniques and computer software. It has been prepared within the Code of Ethics of the Association of Professional Engineers and Geoscientists of Alberta (“APEGA”). This report was prepared in accordance with the guidelines and standards of the PRMS and the SEC regulations.

 

Hydrocarbon Prices

 

Constant prices were used in the economic evaluation and are based on the unweighted arithmetic average of the first-day-of-the month price for each of the 12 months preceding the effective date, as per SEC price parameters guidance. Hocol provided to Sproule the prices to be used in the evaluation. The benchmark prices used in this evaluation are as follows:

 

Oil:      
    Brent 43.41 USD/bbl
       
Gas:      
    Henry Hub 2.14 USD/MMBtu

 

Appropriate adjustments have been made to the constant oil prices to account for quality and transportation. These adjustments have been made and are presented at the field level.

 

Gas prices are based on gas sales contracts, and only applies to the sales gas volumes. A summary of the realized prices used in the evaluation was provided in the detailed final report.

 

Forward-Looking Statements

 

The evaluation process involves modeling to reasonably predict future outcomes. Inherent in the modeling process however are limitations which may indirectly affect the forecast of future events.

 

This report contains forward-looking statements including expectations of future production revenues and capital expenditures. Information concerning reserves may also be deemed to be forward-looking as estimates involve the implied assessment that the reserves described can be profitably produced in the future. These statements are based on current expectations that involve a number of risks and uncertainties, which could cause actual results to differ from those anticipated. These risks include, but are not limited to: the underlying risks of the oil and gas industry (i.e., corporate commitment, regulatory approval, operational risks in development, exploration and production); potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserves estimations; the uncertainty of estimates and projections relating to production; costs and expenses; health, safety and environmental factors; commodity prices; and exchange rate fluctuation.

 

Sproule International Limited   - 3 -   February 9, 2021 

 

 

Standards of Independence and Professional Qualifications

 

Sproule is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services in Canada and throughout the world since 1950. Our head office is located in Calgary, Alberta, Canada. In addition to having technical offices in Mexico City, Mexico, and The Hague, Netherlands, we also have commercial representation offices in Rio de Janeiro, Brazil.

 

Sproule does not have any financial interest, including stock ownership, in Ecopetrol S.A. The fees paid by the Company to Sproule, nor the award of the contract to complete this work, were not contingent on the results of the evaluation.

 

The professional qualifications of the technical person primarily responsible for reviewing and approving the reserves evaluation of the properties contained herein, are included as an attachment to this letter.

 

  Sincerely,
   
  SPROULE INTERNATIONAL LIMITED
  Alberta Permit to Practice number P06151
   
   
   
  /s/ Gary Finnis, P.Eng
  Gary Finnis, P.Eng
  Senior Manager
   
   

 

Sproule International Limited   - 4 -   February 9, 2021 

 

 

 

 

  February 9, 2021

 

Professional Qualifications of Primary Technical Person

 

The Conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Sproule International Limited. Gary R. Finnis was the primary technical person responsible for overseeing the independent estimation of reserves, future production and income to render the audit conclusions of the report presented herein.

 

Mr. Finnis, an employee of Sproule International Limited since 2003 is the Senior Manager, Engineering of Sproule and is also responsible for leading the development and execution of Sproule’s long term strategy and for driving process improvements and efficiencies in project management to optimize profitability.

 

Mr. Finnis earned a Bachelor of Science degree in Civil Engineering in 1998. He is a registered Professional Engineer and Responsible Member with the Association of Professional Engineers and Geoscientist of Alberta (APEGA), and the Society of Petroleum Engineers (SPE).

 

In addition to gaining experience and competency through prior work experience, APEGA requires a minimum amount of professional work hours, attendance at industry conferences, as well as professional development courses and seminars, and mentoring of junior staff in order to maintain Professional Engineer status.

 

Based on his educational background, professional training, and more then 18 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Finnis has attained the professional qualifications required as a Reserves Estimator and Reserves Auditor set fourth in the Petroleum Resources Management System (latest version June 2018).

 

  Sincerely,
  Sproule International Limited
  APEGA P06151
   
   
   
  /s/ Gary R. Finnis, P.Eng.
  Gary R. Finnis, P.Eng.
  Senior Manager, Engineering

140 Fourth Avenue SW, Suite 900

Calgary, AB, Canada T2P 3N3

Sproule.com

T +1 403 294 5500 F +1 403 294 5590 TF +1 877 777 6135

 

 

 

 

Exhibit 99.3

 

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

 

This is a digital representation of a DeGolyer and MacNaughton report.

 

This file is intended to be a manifestation of certain data in the subject report and as such are subject to the same conditions thereof. The information and data contained in this file may be subject to misinterpretation; therefore, the signed and bound copy of this report should be considered the only authoritative source of such information.

 

 

  1  

 

 

DEGOLYER AND MACNAUGHTON

5001 spring valley road

Suite 800 east

Dallas, texas 75244

 

February 12, 2021

 

Board of Directors

Ecopetrol S.A.

Calle 35 No. 7-21 Piso 1

Bogota, D.C.

Colombia

 

Ladies and Gentlemen:

 

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2020, of the extent of the estimated net proved hydrocarbon reserves of certain properties in Colombia and the United States in which Ecopetrol S.A. has represented it holds an interest. These interests are held by Ecopetrol S.A. and through its wholly owned subsidiaries Ecopetrol America LLC and Ecopetrol Permian LLC (collectively, “ECOPETROL”). This evaluation was completed on February 12, 2021. ECOPETROL has represented that these properties account for 17 percent on a net equivalent barrel basis of ECOPETROL’s net proved reserves as of December 31, 2020. ECOPETROL has also represented that these properties account for 14 percent of ECOPETROL’s total proved developed net liquid hydrocarbon (oil, condensate, and natural gas liquids (NGL)) reserves, 5 percent of its total proved developed net gas reserves, 32 percent of its total proved undeveloped net liquid reserves, and 38 percent of its total proved undeveloped net gas reserves. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by ECOPETROL.

 

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2020. Net reserves are defined as that portion of the gross reserves attributable to the interests held by ECOPETROL after deducting all interests held by others, including royalties paid in kind. ECOPETROL has advised that in September 2013, Resolución n° 877 was enacted by the government of Colombia, requiring that oil and condensate royalties be paid in kind and gas and NGL royalties be paid in cash. Based on this legislation, and at the request of ECOPETROL, royalties associated with gas and NGL reserves for the properties in Colombia have been considered as a cash payment and are therefore included in the net gas and NGL reserves estimated herein.

 

2

DeGolyer and MacNaughton

  

Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

 

Information used in the preparation of this report was obtained from ECOPETROL. In the preparation of this report we have relied, without independent verification, upon information furnished by ECOPETROL with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report.

 

Definition of Reserves

 

Petroleum reserves estimated in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

 

3

DeGolyer and MacNaughton

 

 

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

(i)    The area of the reservoir considered as proved includes:

 

(A)  The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii)   In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii)   Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

(iv)   Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(A)   Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

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(v)  Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

  

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i)    Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

(ii)   Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

(i)     Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii)   Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

 

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DeGolyer and MacNaughton

  

(iii)    Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

 

Methodology and Procedures

 

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

 

Based on the current stage of field development, production performance, the development plans provided by ECOPETROL, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves estimated herein were based on opportunities identified in the plan of development provided by ECOPETROL.

 

ECOPETROL has represented that its senior management is committed to the development plan provided by ECOPETROL and that ECOPETROL has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

 

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance methods were used to estimate OOIP and OGIP.

 

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Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

 

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report or the expiration date of the fiscal agreement, whichever occurs first.

  

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).

 

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

 

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DeGolyer and MacNaughton

 

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

 

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

 

Data provided by ECOPETROL from wells drilled through December 31, 2020, and made available for this evaluation have been used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through August, September, October, or November 2020. Estimated cumulative production, as of December 31, 2020, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 4 months.

  

Oil and condensate reserves estimated herein are to be recovered by normal field separation. Oil is reported herein as oil and fuel oil. Fuel oil is defined as that portion of the oil consumed in field operations. Oil includes fuel oil. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in millions of barrels (106bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

  

Gas quantities estimated herein are expressed as marketable gas, fuel gas, and sales gas. Marketable gas is defined as the total gas produced from the reservoir after reduction for shrinkage resulting from field separation; processing, including removal of the nonhydrocarbon gas to meet pipeline specifications; and flare and other losses but not from fuel usage. Fuel gas is defined as that portion of the gas consumed in field operations. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas quantities are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.7 pounds per square inch absolute (psia). Gas quantities included in this report are expressed in millions of cubic feet (106ft3).

 

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DeGolyer and MacNaughton

 

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

 

At the request of ECOPETROL, marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,700 cubic feet of gas per 1 barrel of oil equivalent.

 

Primary Economic Assumptions

 

This report has been prepared using initial prices, expenses, and costs provided by ECOPETROL in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein:

 

Oil, Condensate, and NGL Prices

 

ECOPETROL has represented that the oil, condensate, and NGL prices were based on a 12-month average price, calculated as the unweighted average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The volume-weighted average adjusted product prices attributable to the estimated proved reserves for the properties in Colombia evaluated herein were U.S.$36.49 per barrel for oil and condensate and U.S.$35.04 per barrel for NGL, based on a 12-month average Brent reference price of U.S.$43.41 per barrel. The volume-weighted average adjusted product prices attributable to the estimated proved reserves for the properties in the United States evaluated herein were U.S.$38.16 per barrel for oil and condensate and U.S.$6.72 per barrel for NGL, based on a 12-month average West Texas Intermediate reference price of U.S.$39.53 per barrel. ECOPETROL supplied differentials by field to the reference prices. These prices were held constant for the lives of the properties.

 

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DeGolyer and MacNaughton

 

Sales Gas Prices

 

ECOPETROL has represented that the sales gas prices for the properties in Colombia evaluated herein are defined by contractual agreements based on specific market conditions. The volume-weighted average adjusted product price attributable to the estimated proved reserves for the properties in Colombia evaluated herein was U.S.$2.13 per thousand cubic feet of gas. ECOPETROL has also represented that the sales gas prices for the properties in the United States evaluated herein were based on a Henry Hub reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. The sales gas prices were calculated for each property using differentials furnished by ECOPETROL to the Henry Hub reference price of U.S.$2.03 per million Btu and held constant thereafter. Btu factors provided by ECOPETROL were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves for the properties the United States evaluated herein was U.S.$0.80 per thousand cubic feet of gas. These prices were held constant for the lives of the properties.

 

Operating Expenses, Capital Costs, and Abandonment Costs

 

Estimates of operating expenses, provided by ECOPETROL and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2019 values, provided by ECOPETROL, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of the wells, and reclamation and restoration associated with the abandonment, were provided by ECOPETROL for all properties. Estimates of operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of the undeveloped reserves estimated herein.

 

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DeGolyer and MacNaughton

  

In our opinion, the information relating to estimated proved reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year and (ii) certain proved undeveloped reserves are scheduled for development more than 5 years in the future. The development plans provided by ECOPETROL for the properties evaluated herein include all development to be executed within 5 years of initial disclosure except for one well onshore Colombia and two wells offshore in the United States Gulf of Mexico. ECOPETROL has represented that these wells are part of ongoing development projects and that all remaining development investments for these three wells will be completed within 6 years from their initial disclosure. Based on these representations, reserves associated with these three wells were classified as proved.

 

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

 

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DeGolyer and MacNaughton

 

Summary of Conclusions

 

The estimated net proved reserves, as of December 31, 2020, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in millions of barrels (106bbl), millions of cubic feet (106ft3), and millions of barrels of oil equivalent (106boe):

 

          Estimated by DeGolyer and MacNaughton        
                Net Proved Reserves              
                as of December 31, 2020              
    Oil and           Marketable     Fuel     Sales     Oil  
    Condensate     NGL     Gas     Gas     Gas     Equivalent  
    (106bbl)     (106bbl)     (106ft3)     (106ft3)     (106ft3)     (106boe)  
Colombia                                                
Proved Developed     98.827       1.990       121,473.403       12,086.468       109,386.935       122.128  
Proved Undeveloped     6.629       0.000       2,301.209       1,733.330       567.879       7.032  
Colombia Total Proved     105.456       1.990       123,774.612       13,819.798       109,954.814       129.160  
United States                                                
Proved Developed     16.270       1.074       15,031.779       0.000       15,031.779       19.981  
Proved Undeveloped     105.835       20.971       105,107.419       0.000       105,107.419       145.246  
United States Total Proved     122.105       22.045       120,139.198       0.000       120,139.198       165.227  
Total Proved     227.561       24.035       243,913.810       13,819.798       230,094.012       294.388  

 

Notes:

1. Totals may vary due to rounding.
2. Marketable gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 5,700 cubic feet of gas per 1 barrel of oil equivalent, as provided by ECOPETROL.

3. Oil reserves estimated herein for the properties in Colombia include fuel oil. The estimated fuel oil contained in the oil reserves is 1.367 106bbl for proved developed reserves, 0.000 106bbl for proved undeveloped reserves, and 1.367 106bbl for total proved reserves.

 

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2020, estimated reserves.

 

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DeGolyer and MacNaughton

 

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in ECOPETROL. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of ECOPETROL. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

 

  Submitted,
   
   
  DeGOLYER and MacNAUGHTON
  Texas Registered Engineering Firm F-716

 

 

 Federico Dordoni, P.E.
Senior Vice President
DeGolyer and MacNaughton

 

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CERTIFICATE of QUALIFICATION

 

I, Federico Dordoni, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

 

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to ECOPETROL dated February 12, 2021, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

 

2. That I attended Buenos Aires Institute of Technology (ITBA) University, and that I graduated with a degree in Petroleum Engineering in the year 2004; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 16 years of experience in oil and gas reservoir studies and reserves evaluations.

 

 

 

Federico Dordoni, P.E.
Senior Vice President
DeGolyer and MacNaughton

 

 

 

 

 

Exhibit 99.4

 

 

 

 

 

 

  GaffneyCline
4425 Westway Park Blvd
Houston, TX 77041
 
Tel: +1 713 850 9955
www.gaffneycline.com

 

February 16, 2021

 

Fidel Delgado Doria

Gerente de Reservas

Ecopetrol S.A.

Calle 13 No. 36 -34

Bogotá, D.C.

Colombia

 

fidel.delgado@ecopetrol.com.com

 

Dear Fidel,

 

SEC Proved Reserves Statement

for Forty Nine Fields in which Ecopetrol has an Interest, Colombia as of December 31, 2020

Introduction

 

This Proved reserves statement has been prepared by Gaffney, Cline & Associates (GaffneyCline) and issued on February 16, 2021 at the request of Ecopetrol S.A. (Ecopetrol, or “the Client”), operator, participant operator, and interest participant in 49 fields in the Lower, Middle and Upper Magdalena Valley, Catatumbo, and Llanos Orientales Basins, Colombia.

 

This report is intended for use in conjunction with Ecopetrol’s December 31, 2020 filing obligations with the US Securities and Exchange Commission (SEC).

 

This report relates specifically and solely to the subject matter as defined in the scope of work in the Proposal for Services and is conditional upon the assumptions described herein. The report must be considered in its entirety and must only be used for the purpose for which it was intended.

 

GaffneyCline has prepared a reserves certification, as of December 31, 2020, of the hydrocarbon liquids and natural gas reserves of the fields indicated in the following Table 1.

 

 

 

Ecopetrol S.A. www.gaffneycline.com

 

 

 

 

 

 

Table 1: Assets and Fields Reviewed by GaffneyCline

 

AREA FIELD BASIN
     
ARRAYAN ARRAYAN Upper Magdalena Valley
     
BALCON BALCON Upper Magdalena Valley
     
CAGUAN ESPINO Upper Magdalena Valley
     
  RIO CEIBAS Upper Magdalena Valley
     
CAPACHOS ANDINA - ANDINA Llanos
  NORTE  
     
  CAPACHOS CENTRO Llanos
     
CARACARA CARACARA A Llanos
     
  CARACARA B Y C Llanos
     
  UNUMA Llanos
     
DINA BRISAS Upper Magdalena Valley
CRETACEO    
     
  CEBU Upper Magdalena Valley
     
  DINA CRETACEO Upper Magdalena Valley
     
  DINA NORTE Upper Magdalena Valley
     
  PALOGRANDE Upper Magdalena Valley
     
  PIJAO Upper Magdalena Valley
     
  TEMPRANILLO Upper Magdalena Valley
     
  TEMPRANILLO NORTE Upper Magdalena Valley
     
  TENAY Upper Magdalena Valley
     
HOBO YAGUARA Upper Magdalena Valley
     
JAGUAR ELIZITA Llanos
     
  PEGUITA Llanos
     
  PEGUITA II Llanos
     
  PEGUITA III Llanos
     
  PEGUITA SOUTH Llanos
  WEST  
     
LAS MONAS CORAZON Middle Magdalena Valley
     
LAS MONAS CORAZON WEST Middle Magdalena Valley
     
  LA SALINA Middle Magdalena Valley
     
  PAYOA Middle Magdalena Valley
     
LISAMA LISAMA Middle Magdalena Valley
     
  NUTRIA Middle Magdalena Valley
     
  TESORO Middle Magdalena Valley
     
NEIVA CPI DINA TERCIARIO Upper Magdalena Valley
     
ORIPAYA ORIPAYA Catatumbo
     
PROVINCIA AULLADOR Middle Magdalena Valley
     
  BONANZA Middle Magdalena Valley
     
  PROVINCIA Middle Magdalena Valley
     
SAN FRANCISCO SAN FRANCISCO Upper Magdalena Valley
     
SAN ROQUE SAN ROQUE Middle Magdalena Valley
     
TELLO - LA JAGUA LA JAGUA Upper Magdalena Valley
     
  TELLO Upper Magdalena Valley
     
TIBU TIBU Catatumbo
     
TISQUIRAMA TISQUIRAMA Middle Magdalena Valley
     
TISQUIRAMA ASO LOS ANGELES Middle Magdalena Valley
     
TISQUIRAMA ASO QUERUBIN Middle Magdalena Valley
     
TORO SENTADO RANCHO QUEMADO Llanos
     
  TORO SENTADO Llanos
     
  TORO SENTADO Llanos
  WEST  
     
VIGIA VIGIA Llanos
     
  VIGIA SUR Llanos
     
     

 

 

Ecopetrol S.A.

February 16, 2021

2

 

 

 

 

 

Summary and Conclusions

 

On the basis of technical and other information made available to GaffneyCline concerning these property units, GaffneyCline hereby provides the reserves statement in the following Table 2.

 

Table 2: Statement of Hydrocarbon Reserves Volumes

Forty-Nine Fields, Colombia

as of December 31, 2020

 

    Reserves Net to Ecopetrol’s Interest  
    Oil/Cond.     NGL’s     Gas     Fuel Gas  
Reserves   (MBbl)     (MBbl)     (BCF)     (BCF)  
Developed                                
Producing     40,649       2,072       37.662       20.283  
Non-Producing     4,733       172       1.177       1.552  
Undeveloped     4,614       275       5.790       0.282  
Total Proved     49,995       2,518       44.629       22.117  

 

Notes:

 

1. Oil and condensate reserves net to Ecopetrol’s interest represent volumes after the deduction of royalties, under the concessions that govern the assets, based on Ecopetrol’s working interest.

 

2. Gas and NGL reserves net to Ecopetrol’s working interest include gas and NGL royalty volumes that are required to be paid in cash according to Resolutions 877 and 351 from Agencia Nacional de Hidrocarburos (ANH) and the corresponding clarification note from ANH #20146240188522.

 

3. Net sales gas reserves exclude volumes consumed in operations (fuel gas), which are reported separately.

 

4. Fuel gas represents working interest volumes consumed in operations.

 

5. The above Reserves include production:

 

a. Until the economic limit when contracts are solely operated by Ecopetrol.

 

b. Beyond the end of the current license period in concession contracts that include an expiry date which are assumed to revert to Ecopetrol as the sole license holder at the expiry of the contract and, based on information provided by Ecopetrol, normally include a 12% increase in the royalty rate at contract expiry.

 

6. Totals may not exactly equal the sum of the individual entries because of rounding.

 

Hydrocarbon liquid volumes represent crude oil and condensate, natural gasoline, and NGL estimated to be recovered during field separation and plant processing and are reported in thousands (103) of stock tank barrels (MBbl). The volumes reported as gas represent expected gas sales and are reported in billions (109) of standard cubic feet at standard conditions (BCF). Standard conditions are defined as 14.7 psia and 60°F. There is no oil consumed as fuel in operations, so it is not reported. The sales gas volumes have been reduced for fuel usage consumed in operations (CiO) and shrinkage because of processing. Royalties due on oil production payable to the State have been deducted from reported net interest volumes. Royalties due on NGLs products, including sale gas, are not deducted; they are paid in cash.

 

 

Ecopetrol S.A.

February 16, 2021

3

 

 

 

I  

 

Gas reserves sales volumes are based on firm and existing gas contracts, or on the reasonable expectation of a contract or on the reasonable expectation that any such existing gas sales contracts will be renewed on similar terms in the future.

 

Ecopetrol has advised GaffneyCline that the Proved volumes included in this report represent 4% of the Ecopetrol’s total Proved reserves on an oil-equivalent basis. GaffneyCline is not in a position to verify this statement as it was not requested to review Ecopetrol’s other oil and gas assets.

 

Descriptions of the fields are included in the technical reports, which have been issued separately.

 

 

Ecopetrol S.A.

February 16, 2021

4

 

 

 

I  

 

Reserves Assessment

 

GaffneyCline’s estimate of reserves was based on data provided by Ecopetrol to GaffneyCline from September 2020 to December 2020, and includes such tests, procedures and adjustments as were considered necessary. Field data and information provided by Ecopetrol varies from field to field. All questions that arose during the course of the certification process were resolved to our satisfaction.

 

Technical information and comments related to the methodology followed to certify the reserves volumes for each of the fields is presented in separate individual field reports. As these reports are quite extensive and detailed, the significant points of the work performed are summarized below.

 

GaffneyCline performed procedures necessary to enable it to render an opinion on the appropriateness of the methodologies employed, adequacy and quality of the data relied on, depth and thoroughness of the reserves estimation process, classification and categorization of reserves appropriate to the relevant definitions used, and reasonableness of the estimates.

 

During this certification GaffneyCline used one or more of the following methods to assess the reserves: volumetric, performance or analogy, depending on the information available and the stage of development of the reservoir. Reserves volumes for existing wells were based on performance analysis (decline of production and behavior of appropriate fluid ratios). Reserves volumes for undrilled wells were based on established performance of analogous wells. Production forecasts were first prepared to reasonable technical limits and then truncated by the economic limit. Gross reserves and those net to Ecopetrol’s interests were verified on the basis of the fiscal and contractual terms applicable for each field.

 

To confirm estimates of petroleum initially in place, the structural and stratigraphic descriptions of the accumulations, various reservoir limits, petrophysical rock parameters and reservoir fluid properties were reviewed, checked for reasonableness and/or modified as appropriate based on information and data supplied by Ecopetrol. Reservoir and individual well performance were analyzed to assess the predominant reservoir drive mechanisms currently active in the fields and those expected to affect the future production performance.

 

The economic tests for the December 31, 2020 reserves volumes were based on prior twelve-month first-day-of-the-month average reference price for the Brent crude of US$ 43.41/Bbl, corrected for location and quality to a weighted average price of US$ 37.91/Bbl. Sales gas and plant product prices were advised by Ecopetrol according to existing contracts and/or regulations. The weighted average price of NGL products adjusted for location to determine proved reserves is US$ 24.27/Bbl. The weighted average sale gas price used to derive proved reserves is US$ 5.59/Mcf. No price escalation has been included, other than as provided for in existing contracts.

 

Future capital costs for operated and non-operated fields were provided by Ecopetrol. Recent historical operating expense data were used as the basis for operating cost projections. Neither capital not operating costs were escalated for inflation. GaffneyCline has found that sufficient capital investments and operating expenses have been projected to produce the estimated volumes.

 

 

Ecopetrol S.A.

February 16, 2021

5

 

 

 

I  

 

It is GaffneyCline’s opinion that the estimates of total remaining recoverable hydrocarbon liquid and gas volumes as of December 31, 2020 are, in the aggregate, reasonable and the reserves classification and categorization is appropriate and consistent with the SEC definitions and guidelines for reserves.

 

GaffneyCline is not aware of any potential changes in regulations applicable to these fields that could affect the ability of Ecopetrol to produce the estimated reserves. GaffneyCline concludes that the methodologies employed by the Client in the derivation of the estimates is appropriate, and that the quality of the data relied on, and the depth and thoroughness of the estimation process, are adequate.

 

 

Ecopetrol S.A.

February 16, 2021

6

 

 

 

I  

 

Basis of Opinion

 

This document reflects GaffneyCline’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client and/or obtained from other sources (e.g. public domain), the limited scope of engagement, and the time permitted to conduct the evaluation.

 

In line with those accepted standards, this document does not in any way constitute or make a guarantee or prediction of results, and no warranty is implied or expressed that actual outcome will conform to the outcomes presented herein. GaffneyCline has not independently verified any information provided by, or at the direction of, the Client and/or obtained from other sources (e.g., public domain), and has accepted the accuracy and completeness of this data. GaffneyCline has no reason to believe that any material facts have been withheld, but does not warrant that its inquiries have revealed all of the matters that a more extensive examination might otherwise disclose.

 

The opinions expressed herein are subject to and fully qualified by the generally accepted uncertainties associated with the interpretation of geoscience and engineering data and do not reflect the totality of circumstances, scenarios and information that could potentially affect decisions made by the report’s recipients and/or actual results. The opinions and statements contained in this report are made in good faith and in the belief that such opinions and statements are representative of prevailing physical and economic circumstances.

 

In the preparation of this report GaffneyCline has used definitions contained within Part 210 Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission (see Appendix I).

 

There are numerous uncertainties inherent in estimating reserves, and in projecting future production, development expenditures, operating expenses and cash flows. Oil and gas reserves assessments must be recognized as a subjective process of estimating subsurface accumulations of oil and gas that cannot be measured in an exact way. Estimates of oil and gas reserves prepared by other parties may differ, perhaps materially, from those contained within this report.

 

The accuracy of any reserves estimate is a function of the quality of the available data and of engineering and geological interpretation. Results of drilling, testing and production that post-date the preparation of the estimates may justify revisions, some or all of which may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered, and the timing and cost of those volumes that are recovered may vary from that assumed.

 

GaffneyCline has not undertaken a site visit and inspection because it was not included in the scope of work. As such, GaffneyCline is not in a position to comment on the operations or facilities in place, their appropriateness and condition, or whether they are in compliance with the regulations pertaining to such operations. Further, GaffneyCline is not in a position to comment on any aspect of health, safety, or environment of such operation.

 

 

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This report has been prepared based on GaffneyCline’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GaffneyCline is not in a position to attest to property title or rights, conditions of these rights (including environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).

 

Definition of Reserves

 

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce, or a revenue interest in, the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. All categories of reserves volumes quoted herein have been derived within the context of an economic limit test (ELT) assessment (pre-tax and exclusive of accumulated depreciation amounts) prior to any net present value (NPV) analysis.

 

This report has been prepared based on GaffneyCline’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties.

 

GaffneyCline is not aware of any carbon pricing impost or GHG emissions related to regulations that are applicable to the evaluation of the assets that are the subject of this report. GaffneyCline has also not included the impact of any potential carbon pricing scheme or regulatory compliance costs for GHG emissions that may be implemented in the future.

 

GaffneyCline is not in a position to attest to property title or rights, conditions of these rights (including environmental and abandonment obligations), or any necessary licenses and consents (including planning permission, financial interest relationships, or encumbrances thereon for any part of the appraised properties).

 

GaffneyCline is not aware of any potential changes in regulations applicable to these fields that could affect the ability of Ecopetrol to produce the estimated reserves.

 

Use of Net Present Values

 

It should be clearly noted that the estimates of discounted future net income (FNI, or pre-tax net present value) contained herein do not represent a GaffneyCline opinion as to the market value of the subject properties, nor any interest in them.

 

 

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In assessing a likely market value, it would be necessary to take into account a number of additional factors including reserves risk (i.e., that Proved and/or Probable and/or Possible reserves may not be realised within the anticipated timeframe for their exploitation); perceptions of economic and sovereign risk, including potential change in regulations; potential upside; other benefits, encumbrances or charges that may pertain to a particular interest; and, the competitive state of the market at the time. GaffneyCline has explicitly not taken such factors into account in deriving the FNIs presented herein.

 

Qualifications

 

In performing this study, GaffneyCline is not aware that any conflict of interest has existed. As an independent consultancy, GaffneyCline is providing impartial technical, commercial, and strategic advice within the energy sector. GaffneyCline’s remuneration was not in any way contingent on the contents of this report.

 

In the preparation of this document, GaffneyCline has maintained, and continues to maintain, a strict independent consultant-client relationship with Ecopetrol. Furthermore, the management and employees of GaffneyCline have no interest in any of the assets evaluated or related with the analysis performed as part of this report. The qualifications of the technical person primarily responsible for overseeing this estimate are provided in Appendix II.

 

Staff members who prepared this report hold appropriate professional and educational qualifications and have the necessary levels of experience and expertise to perform the work.

 

 

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Notice

 

This report was prepared for public disclosure in its entirety by Ecopetrol in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. Ecopetrol will obtain GaffneyCline’s prior written approval for any other use of any results, statements or opinions expressed to Ecopetrol in this report that are attributed to GaffneyCline.

 

Yours sincerely,

 

Gaffney, Cline & Associates

 

 

 

Project Manager

 

Alejandro Giaquinta, Principal Advisor

 

 

 

Reviewer

 

Rawdon J.H. Seager, Technical Director

 

Appendices

 

Appendix I SEC Reserves Definitions
   
Appendix II Technical Qualifications of Person Responsible for the Reserves Certification
   
Appendix III Glossary

 

 

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Appendix I

SEC Reserves Definitions

 

 

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U.S. SECURITIES AND EXCHANGE COMMISSION (SEC)

MODERNIZATION OF OIL AND GAS REPORTING1

 

Oil and Gas Reserves Definitions and Reporting

 

(a) Definitions

 

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

 

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

 

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

 

(ii) Same environment of deposition;

 

(iii) Similar geological structure; and

 

(iv) Same drive mechanism.

 

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

 

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

 

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

 

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

 

 

1 Extracted from 17 CFR Parts 210, 211, 229, and 249 [Release Nos. 33-8995; 34-59192; FR-78; File No. S7-15-08] RIN 3235-AK00].

 

 

 

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(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

 

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

 

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

 

(iv) Provide improved recovery systems.

 

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

 

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

(10)Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

 

(11)Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

 

 

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(12)Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in pail as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

 

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

 

(iii) Dry hole contributions and bottom hole contributions.

 

(iv) Costs of drilling and equipping exploratory wells.

 

(v) Costs of drilling exploratory-type stratigraphic test wells.

 

(13)Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

 

(14)Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

 

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

 

(16)Oil and gas producing activities.

 

(i) Oil and gas producing activities include:

 

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

 

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

 

 

 

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(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

 

(1) Lifting the oil and gas to the surface; and

 

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

 

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

 

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

 

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

 

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 

(ii) Oil and gas producing activities do not include:

 

(A) Transporting, refining, or marketing oil and gas;

 

(B) Processing of produced oil, gas or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

 

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

 

(D) Production of geothermal steam.

 

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

 

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(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

 

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

 

(18)Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

 

 

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(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

 

(19)Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

 

(20)Production costs.

 

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, they become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

(A) Costs of labor to operate the wells and related equipment and facilities.

 

(B) Repairs and maintenance.

 

(C) Materials, supplies, arid fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

 

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

 

(E) Severance taxes.

 

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

 

(21)Proved area. The part of a property to which proved reserves have been specifically attributed.

 

(22)Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

 

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(i) The area of the reservoir considered as proved includes:

 

(A) The area identified by drilling and limited by fluid contacts, if any, and

 

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

(23) Proved properties. Properties with proved reserves.

 

(24)Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

 

 

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(25)Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

 

(26)Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

 

(27)Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

(28)Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

 

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

 

(30)Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration.

 

 

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Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

 

(31)Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

(32)Unproved properties. Properties with no proved reserves.

 

 

 

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Appendix II

Technical Qualifications of Person Responsible for the
Reserves Certification

 

 

 

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Technical Qualifications of Person Primarily Responsible for the Reserves Certification

 

The reserves estimate of certain of Ecopetrol’s interests prepared by Gaffney, Cline & Associates (GaffneyCline), the results of which are presented in this report, was carried out by engineers and geoscientists under the direction of Mr. Alejandro Giaquinta.

 

Alejandro Giaquinta is a Principal Advisor with GaffneyCline in Argentina and is responsible for preparing reserves audits, certifications and field evaluations. He was responsible for overseeing the preparation of the reserves estimate of certain Ecopetrol interests.

 

Mr. Giaquinta has over 28 years of experience in the international oil and gas industry, with extensive experience in reservoir and petroleum engineer. He is qualified as a Reserves Auditor through having more than 20 years’ experience in petroleum engineering with estimation and evaluation of Reserves Information. He holds a Bachelor of Science degree in Petroleum Engineering from Universidad Nacional de Cuyo, Mendoza, Argentina, and a Master’s degree in Renewable Energy from Universidad del Rey Juan Carlos, Madrid, Spain.

 

Mr. Giaquinta is a member in good standing of the Society of Petroleum Engineers (SPE).

 

 

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Appendix III

Glossary

 

 

 

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% Percentage
1H05 First half (6 months) of 2005 (example)
2Q06 Second quarter (3 months) of 2006 (example)
2D Two dimensional
3D Three dimensional
4D Four dimensional
1P Proved Reserves
2P Proved plus Probable Reserves
3P Proved plus Probable plus Possible Reserves
ABEX Abandonment Expenditure
ACQ Annual Contract Quantity
oAPI Degrees API (American Petroleum Institute)
AAPG American Association of Petroleum Geologists
AVO Amplitude versus Offset
A$ Australian Dollars
B Billion (109)
Bbl Barrels
/Bbl per barrel
BBbl Billion Barrels
BHA Bottom Hole Assembly
BHC Bottom Hole Compensated
Bscf or Bcf Billion standard cubic feet
Bscfd or Bcfd Billion standard cubic feet per day
Bm3 Billion cubic metres
bcpd Barrels of condensate per day
BHP Bottom Hole Pressure
blpd Barrels of liquid per day
bpd Barrels per day
boe Barrels of oil equivalent @ xxx mcf/Bbl
boepd Barrels of oil equivalent per day @ xxx mcf/Bbl
BOP Blow Out Preventer
bopd Barrels oil per day
bwpd Barrels of water per day
BS&W Bottom sediment and water

 

 

 

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BTU British Thermal Units
bwpd Barrels water per day
CBM Coal Bed Methane
CiO Consumed in Operations
CO2 Carbon Dioxide
CAPEX Capital Expenditure
CCGT Combined Cycle Gas Turbine
cm centimetres
CMM Coal Mine Methane
CNG Compressed Natural Gas
Cp Centipoise (a measure of viscosity)
CSG Coal Seam Gas
CT Corporation Tax
D1BM Design 1 Build Many
DCQ Daily Contract Quantity
Deg C Degrees Celsius
Deg F Degrees Fahrenheit
DHI Direct Hydrocarbon Indicator
DLIS Digital Log Interchange Standard
DST Drill Stem Test
DWT Dead-weight ton
E&A Exploration & Appraisal
E&P Exploration and Production
EBIT Earnings before Interest and Tax
EBITDA Earnings before interest, tax, depreciation and amortisation
ECS Elemental Capture Spectroscopy
EI Entitlement Interest
EIA Environmental Impact Assessment
ELT Economic Limit Test
EMV Expected Monetary Value
EOR Enhanced Oil Recovery
EUR Estimated Ultimate Recovery
FDP Field Development Plan
FEED Front End Engineering and Design
FPSO Floating Production Storage and Offloading
FSO Floating Storage and Offloading

 

 

 

Ecopetrol S.A.

February 16, 2021

25

 

 

 

 

 

FWL Free Water Level
ft Foot/feet
Fx Foreign Exchange Rate
g gram
g/cc grams per cubic centimetre
gal gallon
gal/d gallons per day
G&A General and Administrative costs
GBP Pounds Sterling
GCoS Geological Chance of Success
GDT Gas Down to
GIIP Gas Initially In Place
GJ Gigajoules (one billion Joules)
GOC Gas Oil Contact
GOR Gas Oil Ratio
GRV Gross Rock Volumes
GTL Gas to Liquids
GWC Gas water contact
HDT Hydrocarbons Down to
HSE Health, Safety and Environment
HSFO High Sulphur Fuel Oil
HUT Hydrocarbons up to
H2S Hydrogen Sulphide
IOR Improved Oil Recovery
IPP Independent Power Producer
IRR Internal Rate of Return
J Joule (Metric measurement of energy) I kilojoule = 0.9478 BTU)
k Permeability
KB Kelly Bushing
KJ Kilojoules (one Thousand Joules)
kl Kilolitres
km Kilometres
km2 Square kilometres
kPa Thousands of Pascals (measurement of pressure)
KW Kilowatt
KWh Kilowatt hour
LAS Log ASCII Standard
LKG Lowest Known Gas

 

 

 

Ecopetrol S.A.

February 16, 2021

26

 

 

 

 

 

 

LKH Lowest Known Hydrocarbons
LKO Lowest Known Oil
LNG Liquefied Natural Gas
LoF Life of Field
LPG Liquefied Petroleum Gas
LTI Lost Time Injury
LWD Logging while drilling
m Metres
M Thousand
m3 Cubic metres
Mcf or Mscf Thousand standard cubic feet
MCM Management Committee Meeting
MMcf or MMscf Million standard cubic feet
m3/d Cubic metres per day
mD Measure of Permeability in millidarcies
MD Measured Depth
MDT Modular Dynamic Tester
Mean Arithmetic average of a set of numbers
Median Middle value in a set of values
MFT Multi Formation Tester
mg/l milligrams per litre
MJ Megajoules (One Million Joules)
Mm3 Thousand Cubic metres
Mm3/d Thousand Cubic metres per day
MM Million
MMm3 Million Cubic metres
MMm3/d Million Cubic metres per day
MMBbl Millions of barrels
MMBTU Millions of British Thermal Units
Mode Value that exists most frequently in a set of values = most likely
Mscfd Thousand standard cubic feet per day
MMscfd Million standard cubic feet per day
MW Megawatt
MWD Measuring While Drilling
MWh Megawatt  hour
mya Million years ago
NGL Natural Gas Liquids
N2 Nitrogen

 

 

 

Ecopetrol S.A.

February 16, 2021

27

 

 

 

 

 

NTG Net/Gross Ratio
NPV Net Present Value
OBM Oil Based Mud
OCM Operating Committee Meeting
ODT Oil-Down-To
OGIP Original Gas in Place
OIIP Oil Initially In Place
OOIP Original Oil in Place
OPEX Operating Expenditure
OWC Oil Water Contact
p.a. Per annum
Pa Pascals (metric measurement of pressure)
P&A Plugged and Abandoned
PDP Proved Developed Producing
Phie effective porosity
PI Productivity Index
PIIP Petroleum Initially In Place
PJ Petajoules (1015 Joules)
PSDM Post Stack Depth Migration
psi Pounds per square inch
psia Pounds per square inch absolute
psig Pounds per square inch gauge
PUD Proved Undeveloped
PVT Pressure, Volume and Temperature
P10 10% Probability
P50 50% Probability
P90 90% Probability
RF Recovery factor
RFT Repeat Formation Tester
RT Rotary Table
R/P Reserve to Production
Rw Resistivity of water
SCAL Special core analysis
cf or scf Standard Cubic Feet
cfd or scfd Standard Cubic Feet per day
scf/ton Standard cubic foot per ton
SL Straight line (for depreciation)
so Oil Saturation
SPM Single Point Mooring

 

 

Ecopetrol S.A.

February 16, 2021

28

 

 

 

 

 

 

SPE Society of Petroleum Engineers
SPEE Society of Petroleum Evaluation
SPS Subsea Production System
SS Subsea
stb Stock tank barrel
STOIIP Stock tank oil initially in place
Swi irreducible water saturation
sw Water Saturation
T Tonnes
TD Total Depth
Te Tonnes equivalent
THP Tubing Head Pressure
TJ Terajoules (1012 Joules)
Tscf or Tcf Trillion standard cubic feet
TCM Technical Committee Meeting
TOC Total Organic Carbon
TOP Take or Pay
Tpd Tonnes per day
TVD True Vertical Depth
TVDss True Vertical Depth Subsea
UFR Umbilical Flow Lines and Risers
USGS United States Geological Survey
US$ United States dollar
VLCC Very Large Crude Carrier
Vsh shale volume
VSP Vertical Seismic Profiling
WC Water Cut
WI Working Interest
WPC World Petroleum Council
WTI West Texas Intermediate
wt% Weight percent

 

 

Ecopetrol S.A.

February 16, 2021

29

 

 

 

Exhibit 99.5

 

 

March 26, 2021

 

Ecopetrol S.A. 

Cra. 13 No. 36-24

Edificio Principal, Piso 7

Bogotá, D.C. 

Colombia

 

Dear Ladies and Gentlemen:

 

In accordance with your request, we have estimated the proved developed reserves, as of December 31, 2020, to the Ecopetrol S.A. (Ecopetrol) interest in certain oil and gas properties located in Block Z-2B, Peru. This report is being provided to Ecopetrol under our engagement with Savia Perú S.A. (Savia), which owns a 100 percent working interest in the properties. It is our understanding that, as of December 31, 2020, Ecopetrol owned a 50 percent interest in Savia and that the proved reserves estimated in this report constituted approximately 0.2 percent of all proved reserves owned by Ecopetrol. It is also our understanding that Ecopetrol sold its interest on January 19, 2021. We completed our evaluation on or about January 22, 2021. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Ecopetrol's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

 

We estimate the net reserves to the Ecopetrol interest in these properties, as of December 31, 2020, to be:

 

          Net Reserves        
    Oil     NGL     Gas  
Category   (MBBL)     (MBBL)     (MMCF)  
Proved Developed Producing     2,212.0       367.3       4,428.0  
Proved Developed Non-Producing     131.7       0.0       0.0  
Total Proved Developed     2,343.7       367.3       4,428.0  

 

The oil volumes shown include crude oil and condensate. Natural gas liquids (NGL) volumes shown include liquefied petroleum gas and light aliphatic hydrocarbons (HAL acronym in Spanish), which is the C5+ fraction recovered at the Procesadora de Gas Pariñas S.A.C. (PGP) plant. Oil and NGL volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at contract temperature and pressure bases.

 

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2020, there are no undeveloped reserves for these properties. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves included herein have not been adjusted for risk. Reserves are limited to the license expiration date, which is November 30, 2023.

 

Oil and NGL prices used in this report are based on the 12-month unweighted arithmetic average of the first -day-of-the-month price for each month in the period January through December 2020. The average Brent Crude price of US$43.41 per barrel is adjusted for quality, transportation fees, and market differentials. Gas prices are based on contracts with Enel Generación Piura S.A. (ENEL), Gas Comprimido del Perú S.A. (GASCOP), and PGP, and are adjusted for energy content. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are US$43.41 per barrel of oil, US$42.87 per barrel of NGL, and US$1.736 per MCF of gas.

 

 

 

 

 

 

 

Operating costs used in this report are based on operating expense records of Savia, the operator of the properties. As requested, operating costs are limited to direct block-level costs and Savia's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs are not escalated for inflation.

 

Capital costs used in this report were provided by Savia and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for well services; acid stimulations; and maintenance of pipelines, production facilities, equipment and installations, and barges and boats. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation.

 

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include consideration of any costs due to such possible liability. We have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates include the effects of such contracts only to the extent that the associated fees are accounted for in the historical block-level accounting statements.

 

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Savia, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts used to prepare this report. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

 

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, petrophysical data, well test data, production data, wellbore completion information, historical price and cost information, gas contracts, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

 

The data used in our estimates were obtained from Savia, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the contractual rights to the properties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

2

 

 

 

 

  Sincerely,
   
  NETHERLAND, SEWELL & ASSOCIATES, INC.
  Texas Registered Engineering Firm F-2699
   
  By:  
    C.H. (Scott) Rees III, P.E.
    Chairman and Chief Executive Officer
   
  By:  
    Andres F. Castaño, P.E. 121698
    Vice President
   
   
  Date Signed: March 26, 2021

 

AFC:JCW

 

3

 

 

 

 

CERTIFICATE OF QUALIFICATION

 

I, Andres F. Castaño, Licensed Professional Engineer, 2100 Ross Avenue, Suite 2200, Dallas, Texas 75201, hereby certify:

 

I am an employee of Netherland, Sewell & Associates, Inc. in the position of Vice President.

 

I do not have, nor do I expect to receive, any direct or indirect interest in the securities of Ecopetrol S.A. or its subsidiaries.

 

I attended the University of Oklahoma and graduated in 2010 with a Master's Degree in Petroleum Engineering; I attended Universidad Nacional de Colombia and graduated in 2004 with a Bachelor's Degree in Petroleum Engineering; I am a Licensed Professional Engineer in the State of Texas, United States of America; and I have in excess of 15 years of experience in petroleum engineering studies and evaluations.

 

By:    
  Andres F. Castaño, P.E.   
  Vice President  
  Texas Registration No. 121698  

 

March 26, 2021 

Dallas, Texas, U.S.A.

 

4

 

 

 

 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

 

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

 

(2)  Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

 

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.

 

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

 

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

 

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

 

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

 

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Supplemental definitions from the 2018 Petroleum Resources Management System:

 

Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.

 

Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

 

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

 

Definitions

5

 

 

 

 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide improved recovery systems.

 

(8)  Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

 

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

 

(11)  Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

 

(12)  Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.

 

(13)  Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

 

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

 

(15)  Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

 

(16) Oil and gas producing activities.

 

(i) Oil and gas producing activities include:

 

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

 

Definitions

6

 

 

 

 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

 

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

 

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 

(ii) Oil and gas producing activities do not include:

 

(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D) Production of geothermal steam.

 

(17)  Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

 

(18)  Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

Definitions

7

 

 

 

 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

 

(19)  Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

 

(20) Production costs.

 

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

(A) Costs of labor to operate the wells and related equipment and facilities.
(B) Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E) Severance taxes.

 

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

 

(21)  Proved area. The part of a property to which proved reserves have been specifically attributed.

 

(22)  Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

(i) The area of the reservoir considered as proved includes:

 

(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
     
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

Definitions

8

 

 

 

 

DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

(23) Proved properties. Properties with proved reserves.

 

(24)  Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

 

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

 

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

 

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

 

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

 

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

 

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

 

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

     
a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

 

Definitions

 

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DEFINITIONS OF OIL AND GAS RESERVES 

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

 

(27)  Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

 

(28)  Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

 

(29)  Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

 

(30)  Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

 

(31)  Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

 

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

 

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

 

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

 

· The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
· The company's historical record at completing development of comparable long-term projects;
· The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
· The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
· The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

 

(32) Unproved properties. Properties with no proved reserves.

 

Definitions

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