ECOPETROL S.A. (Form: 20-F, Received: 04/01/2020 06:06:43)

As filed with the Securities and Exchange Commission on March 31, 2020

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, 2019

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
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.

x 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 x 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.

x 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).

x 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 x

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 which basis of accounting the registrant has used to prepare the financial statements included in this filing:

¨ U.S. GAAP

x 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 x No

Annual Report on Form 20-F 2019

Table of Contents

					Page
1.	Introduction				1
	1.1	About This Annual Report			1
	1.2	Forward-looking Statements			1
	1.3	Selected Financial and Operating Data			2
2.	Strategy and Market Overview				4
	2.1	Our Corporate Strategy			5
		2.1.1	Business Plan		5
		2.1.2	2020 Investment Plan		7
3.	Business Overview				8
	3.1	Our History			8
	3.2	Our Corporate Structure			9
	3.3	Our Business			10
	3.4	Exploration and Production			10
		3.4.1	Exploration Activities		11
			3.4.1.1	Exploration Activities in Colombia	12
			3.4.1.2	Exploration Activities Outside Colombia	13
		3.4.2	Production Activities		15
			3.4.2.1	Production Activities in Colombia	15
			3.4.2.2	Production Activities Outside Colombia	24
			3.4.2.3	Marketing of Crude Oil and Natural Gas	27
		3.4.3	Reserves		28
		3.4.4	Joint Venture and Other Contractual Arrangements		36
	3.5	Transportation and Logistics			40
		3.5.1	Transportation Activities		40
			3.5.1.1	Pipelines	42
			3.5.1.2	Export and Import Facilities	44
		3.5.2	Other Transportation Facilities		44
		3.5.3	Marketing of Transportation Services		45

3.6	Refining and Petrochemicals			47
	3.6.1	Refining		47
		3.6.1.1	Barrancabermeja Refinery	47
		3.6.1.2	Cartagena Refinery	48
		3.6.1.3	Esenttia S.A.	50
		3.6.1.4	Biofuels	50
	3.6.2	Marketing and Supply of Refined Products		51
3.7	Research and Development; Intellectual Property			51
3.8	Applicable Laws and Regulations			52
	3.8.1	Regulation of Exploration and Production Activities		52
		3.8.1.1	Business Regulation	52
	3.8.2	Regulation of Transportation Activities		55
	3.8.3	Regulation of Refining and Petrochemical Activities		56
		3.8.3.1	Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels	57
		3.8.3.2	Regulation Concerning Production and Prices	57
		3.8.3.3	Regulation of Biofuel and Related Activities	59
	3.8.4	Regulation of the Natural Gas Market		59
3.9	Environmental, Social and Governance (ESG) Strategies and Initiatives			61
	3.9.1	HSE		61
		3.9.1.1	Ecopetrol S.A.	61
		3.9.1.2	Cenit	69
		3.9.1.3	Cartagena Refinery	69
	3.9.2	Corporate Responsibility		70
	3.9.3	Environmental Sustainability		71
		3.9.3.1	Environmental Practices	71
	3.9.4	Energy Initiatives		72
3.10	Related Party and Intercompany Transactions			73
3.11	Insurance			77
3.12	Human Resources/Labor Relations			80
	3.12.1	Employees		80
	3.12.2	Collective Bargaining Arrangements		82

4.	Financial Review				83
	4.1	Factors Affecting Our Operating Results			83
	4.2	Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results			85
		4.2.1	Taxes		85
		4.2.2	Exchange Rate Variation		88
		4.2.3	Effects of Inflation		90
		4.2.4	Effects of Crude Oil and Refined Products Prices		90
	4.3	Accounting Policies			90
	4.4	Critical Accounting Judgments and Estimates			91
	4.5	Operating Results			91
		4.5.1	Consolidated Results of Operations		91
			4.5.1.1	Total Revenues	92
			4.5.1.2	Cost of Sales	93
			4.5.1.3	Operating Expenses before Impairment of Non-Current Assets Effects	95
			4.5.1.4	Impairment of Non-Current Assets	96
			4.5.1.5	Finance Results, Net	97
			4.5.1.6	Income Tax	98
			4.5.1.7	Net Income (Loss) Attributable to Owners of Ecopetrol	98
			4.5.1.8	Segment Performance and Analysis	99
			4.5.1.9	Exploration and Production Segment Results	100
			4.5.1.10	Transportation and Logistics Segment Results	103
			4.5.1.11	Refining and Petrochemicals Segment Results	104
	4.6	Liquidity and Capital Resources			105
		4.6.1	Review of Cash Flows		105
		4.6.2	Capital Expenditures		106
		4.6.3	Dividends		106
	4.7	Summary of Differences between Internal Reporting (Colombian IFRS and IFRS)			107
	4.8	Financial Indebtedness and Other Contractual Obligations			108
	4.9	Off Balance Sheet Arrangements			109
	4.10	Trend Analysis and Sensitivity Analysis			110

iii

5.	Risk Review			112
	5.1	Risk Factors		112
		5.1.1	Risks Related to Our Business	112
		5.1.2	Risks Related to Colombia’s Political and Regional Environment	123
		5.1.3	Legal and Regulatory Risks	126
		5.1.4	Risks Related to Our ADSs	128
		5.1.5	Risks Related to the Controlling Shareholder	130
	5.2	Risk Management		131
		5.2.1	Managing Risk through Our Internal Control System	131
		5.2.2	Managing Information Security and Cybersecurity	132
		5.2.3	Managing Financial Risk	132
	5.3	Legal Proceedings and Related Matters		135
6.	Shareholder Information			142
	6.1	Shareholders’ General Assembly		142
	6.2	Dividend Policy		142
	6.3	Market and Market Prices		143
	6.4	Description of Ecopetrol Registered Debt Securities		144
	6.5	Description of Ecopetrol ADRs		144
	6.6	Taxation		146
		6.6.1	Colombian Tax Considerations	146
		6.6.2	U.S. Federal Income Tax Consequences	150
	6.7	Exchange Controls and Limitations		153
	6.8	Exchange Rates		154
	6.9	Major Shareholders		154
	6.10	Enforcement of Civil Liabilities		154

7.	Corporate Governance			156
	7.1	Bylaws		157
	7.2	Code of Ethics and Conduct		160
	7.3	Board of Directors		160
		7.3.1	Board Practices	163
		7.3.2	Board Committees	164
	7.4	Compliance with NYSE Listing Rules		166
	7.5	Management		167
	7.6	Compensation of Directors and Management		171
	7.7	Share Ownership of Directors and Executive Officers		171
	7.8	Controls and Procedures		172
8.	Financial Statements			174
9.	Signature Page			175
10.	Exhibits			176
11.	Cross-reference to Form 20-F			178

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;

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 health events, 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	2019			2018			2017			2016			2015
Oil and gas production (mboed)		725.1			720.4			715.1			717.9			760.7
Proved oil and gas reserves (Mmboe)⁽¹⁾		1,893			1,727			1,659			1,598			1,849
Exploratory Wells⁽²⁾		20			17			20			6			5
Refinery Through-put (bpd)⁽³⁾		375,754			375,666			347,483			332,751			234,861
1P Reserves replacement ratio		169	%		129	%		126	%		(7	)%		6	%

(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, Reficar, Apiay and Orito refineries. Reficar operations were shut down in March 2014 for the expansion and modernization plan. The new crude unit began start-up process in October 2015. During 2016, Reficar was undergoing the unit startup phase and commenced full operation in July 2016. The refinery’s global performance testing was successfully completed in the fourth quarter of 2017, resulting in the start of the refinery’s optimization and continuous operation stage. During 2018, Reficar continued its optimization phase.

Financial Information

International Financial Reporting Standards (IFRS)

(Expressed in millions of Colombian Pesos, except for the net income per share and net operating income per share, which are expressed in Colombian Pesos)

Table 2 – Selected Financial Data

Financial Information	2019		2018		2017		2016		2015
Revenue		71,488,512		68,603,872		55,954,228		48,485,561		52,347,271
Operating income		21,027,158		22,458,414		16,171,855		8,904,548		2,131,165
Net income (loss) attributable to Ecopetrol’s shareholders		13,744,011		11,381,386		7,178,539		2,447,881		(7,193,859	)
Net operating income per share		511		546		393		217		51.8
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
Earnings (loss) per share (basic and diluted)		334		277		175		59.5		(175.0	)
Total assets		133,890,296		124,643,498		117,847,412		118,958,977		123,588,190

Total equity		58,231,628		57,107,780		48,215,699		43,560,501		43,100,963
Subscribed and paid-in capital		25,040,067		25,040,067		25,040,067		25,040,067		25,040,068
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		180		314		89		23		-
Total liabilities		75,658,668		67,535,718		69,631,713		75,398,476		80,487,227

Our consolidated financial statements for the years ended December 31, 2015, 2016, 2017, 2018 and 2019 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 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$3,282 per US$1.00, which corresponds to the Tasa Representativa Promedio del Mercado (TRM), or Average Representative Market Exchange Rate, for 2019. Such conversion should not be construed as a representation that the Colombian Peso amounts correspond to, or have been or could be converted into, U.S. dollars at that rate or any other rate. On March 27, 2020, the Representative Market Exchange Rate was COP$3,996 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.

Strategy and Market Overview

The US-China trade war escalated in 2019 and increased average tariffs between the two nations (U.S. tariffs to China rose from 12.0% to 21.0%, and Chinese tariffs to the U.S. from 16.5% to 21.1% in each case from 2018 to 2019), affecting global confidence. Global industrial production entered a downturn, and world trade stagnated with most countries worldwide recording a slowdown in the growth of their economies. In 2019, these factors led to a 0.75 million barrels of oil equivalent per day (mmboepd) growth in oil demand, the lowest growth rate since 2012 when demand increased by 0.60 mmboepd.

World oil supply remained stable in 2019. While the supply of those outside the Organization of the Petroleum Exporting Countries (OPEC) increased by 1.94 mmboepd in 2019, mainly due to higher production in the U.S. (1.62 mmboepd) and Brazil (0.23 mmboepd), the supply from OPEC countries fell by 2.10 mmboepd. In addition to production declines in Saudi Arabia, the decrease in total OPEC output was largely driven by falling production in Venezuela and Iran due, in part, to U.S. sanctions. Crude oil production in Venezuela averaged 0.82 mmboepd in 2019, a decline of 0.57 mmboepd as compared to 2018. In 2019, Iranian crude oil production decreased by 1.21 mmboepd as compared to 2018.

In conclusion, global oil markets were roughly balanced in 2019, as global oil supply declined slightly, and global oil consumption grew at the smallest rate since 2009. However, market pessimism increased in 2019 largely due to trade war fears and a global slowdown, pushing down the price of oil. Brent averaged US$64/Bl in 2019, down from a 2018 average of US$72/Bl.

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

Source: EIA: Short term Energy Outlook

During 2020, international reference prices have been impacted due to the disagreement on production cuts between the Organization of the Petroleum Exporting Countries (OPEC) and Russia, global and regional economic and political developments in the OPEC, and its capacity and decision to increase production levels to gain market share.

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 could continue to influence 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. According to the National Administrative Department of Statistics (DANE for its Spanish acronym), during 2019 Colombia’s GDP grew by 3.3% in real terms, as compared to 2018. The sectors with the greatest growth rates were retail, financial services, and public administration, which had the largest contribution to national GDP. On the other hand, construction had the worst performance.

Local sales of liquid fuels (LPG, diesel, jet and gasoline) increased by 4% in 2019, boosted by increased demand for gasoline and diesel.

Natural gas demand in Colombia decreased by 1.7% in 2019 as compared to 2018 due to lower demand from natural gas fired power plants.

2.1

Our Corporate Strategy

2.1.1

Business Plan

The Ecopetrol Group’s 2020 - 2022 Business Plan (the Plan) is aligned with the strategic priorities of achieving profitable and sustainable growth, using strict capital discipline and cash flow protection, taking into consideration the challenges posed by energy transition, climate change, respect for the environment and biodiversity, the protection and responsible use of water, and the inclusion of an innovation and technology component, leveraging the integrated value generation for the Group.

The Plan includes investments between US$13 and US$17 billion, most of which will be invested in Colombia, aimed at continuing reserves and production growth, the search and development of investment opportunities to leverage portfolio diversification, and ensuring the continuity of the operations. Furthermore, the Plan provides for increased operational sustainability with specific goals of decarbonization, increased use of renewable energy and digital transformation. The Plan is based on a Brent price of US$57/Bl.

Investments in growth (58%) are focused on continuing the profitable development of existing assets and addressing the transition to gas. Investments in operational continuity (26%) are aimed at preserving the value of the assets and providing reliability and integrity to the operation, and the remaining (16%) of investments will boost innovation and technology and decarbonization goals.

Some of the most relevant operational goals of the Plan are expected to: (i) reach organic production levels of between 745 - 800 thousand barrels of oil equivalent per day, (ii) maintain the replacement rate of organic reserves above 100%, without price effect, (iii) realize throughput between 370 - 420 thousand barrels per day for the integrated refining system, (iv) achieve between 1.10 - 1.25 million barrels per day of volumes transported, in line with the expected country’s production and demand for liquid fuels, (v) reduce emissions between 1.8 and 2.0 million metric tons of carbon dioxide equivalent (MmtCO2e) in 2020 and (vi) install approximately 300 Megawatts of renewable energy sources.

Upstream

The Plan allocates 83% of total investments to the upstream segment, prioritizing the development of the Group’s position in strategic assets such as the Piedemonte and Rubiales fields as well as others in the Middle Magdalena Valley and key regions such as Brazil and the Permian Basin. Furthermore, the maturation and development of improved recovery activities will continue. The Plan allocates 72% of upstream investments on projects in Colombia while the remainder will be invested in further developing the Group's international operations.

In terms of exploration, the Plan provides for drilling more than 30 exploratory wells located in the most relevant basins, focused mostly in Colombia and implementing an important seismic survey program. Additionally, the Group expects to continue with the evaluation and development of the offshore gas discoveries made in the Colombian Caribbean through investments totaling US$200 million.

In relation to unconventional reservoirs, the maturation of the initiatives associated with the Comprehensive Research Pilot Project (Proyectos Piloto de Investigación Integral or PPII as per its Spanish acronym) in the Middle Magdalena Valley Basin will continue, and development activities in the Permian Basin in Texas increase.

Downstream

The Plan allocates 11% of investments to the downstream segment, focusing on the use and optimization of the current infrastructure. To this end, we plan to conduct major maintenance and technological updates at the Cartagena and Barrancabermeja refineries as well as implement the Cartagena Refinery’s Original Crude Unit interconnection project. We also plan to expand the Esenttia plant by 70 thousand tons of polypropylene per year. A gross refining margin of between US$10 - US$15 per barrel is expected, with periods of significant volatility.

In an effort to move forward with the production of cleaner fuels for the country, the investments made during the 2020 - 2022 period will consolidate the quality of domestic diesel to between 10 to 15 ppm of sulphur and reduce the sulphur in gasoline to a maximum of 50 ppm. Moreover, we anticipate initiating a project designed to reach levels below 10 ppm in both fuels in the medium term. We already report this quality level for domestic diesel, including the diesel used by mass transport systems such as Transmilenio in Bogotá.

Midstream

The Plan includes allocating 5% of investments to this segment, focused on improving efficiency and synergies in the transportation system as well as capturing investment opportunities in multi-purpose pipelines associated with the increase in domestic fuel demand. To this end, we foresee investments totaling US$300 million. This segment is expected to continue to be an important cash generator.

Technology and Innovation

In terms of technology, our efforts will focus on realizing the feasibility of enhanced oil recovery and unconventional hydrocarbons projects in an effective, environmentally and socially sustainable manner, increasing flexibility and logistical efficiency for the transportation of heavy crudes and increasing energy efficiency, among others. Additionally, we plan to complete the ten key projects on our digital agenda that seek to maximize production, improve the commercialization and refining margin, and digitize financial management.

Emission reduction and water management

In line with the 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, the Plan allocates between US$320 and US$430 million for investments in projects that help reduce carbon emissions between 200 and 400 kilotons of carbon dioxide equivalents (KtCO2e), in order to reach an annual reduction of between 1.8 and 2.0 million of tons of carbon dioxide equivalents (MtCO2e) in 2022.

In order to enhance integrated water management, wastewater reuse, water security and water governance, the Plan allocates investments of between US$100 and US$150 million in wastewater treatment and final water disposal wells and to provide potable water and sanitation to 900,000 in 40 prioritized municipalities.

Social and Environmental Investment

The Plan expects to allocate between US$350 and US$400 million in funds to our socio-environmental program, designed to help close socioeconomic gaps in Colombia and boost sustainable community development and wellbeing. The priority areas for the socio-environmental investment program are public and community infrastructure, public services, education, sports and health, rural development and business entrepreneurship.

The Plan seeks to maintain leveraging metrics in line with the Company’s investment grade rating and competitive vis-à-vis industry peers.

The Plan emphasizes Ecopetrol's commitment to a safe and sustainable operation, while protecting the environment and the communities in the areas where it operates, and ensuring the satisfaction of its employees, conditions that will help create shared prosperity and constructive dialogue with all its stakeholders.

2.1.2

2020 Investment Plan

In November 2019, the Board of Directors approved between US$4.5 and US$5.5 billion for the 2020 investment plan at US$57/Bl Brent. The Ecopetrol Group plans to produce between 745 and 760 thousand barrels of oil equivalent per day during 2020. Ecopetrol expects to allocate 78% percent of these investments to projects in Colombia and the remainder to positioning and developing the Ecopetrol Group’s operations in the United States, Mexico and Brazil.

On March 16, 2020, Ecopetrol announced a set of actions to address current challenging market conditions, which have resulted, among other matters, in a 60% decline in the Brent crude price as compared to the end of 2019, due to external shocks including the strong increase in the supply of oil and the spread of COVID-19. These measures are part of a phased intervention plan that aims for the Company to adapt in a timely and orderly manner to changing market conditions.

The first stage of this plan includes the following actions:

Effective immediately, a COP$2 trillion cutback in costs and expenses to strengthen Ecopetrol’s competitiveness, including austerity measures, prioritization of operational and administrative activities, and control over operational expenses, such as travel restrictions, sponsorships and involvement in events, among others.

ii.

Implementation of new commercial strategies to maximize the value of the crudes and products sold by the Ecopetrol Group.

iii.

A US$1.2 billion decrease in the 2020 investment plan so that the new range of the investment plan is now US$3.3 - 4.3 billion. The measures adopted aim to intervene in investment opportunities in the early stages, seeking to preserve production and cash flow and maintain the integrity and reliability of investments, including social investment commitments already made.

iv.

Regarding the Earnings Distribution Proposal reported to the market on March 2, 2020, the Board of Directors proposed a new payment scheme consisting of the following: a first payment of 100% of the dividend to minority shareholders and 14% of the dividend to the majority shareholder, to be made on April 23, 2020, and the payment of the remaining 86% of the dividend to the majority shareholder to be disbursed during the second half of 2020.

The production target for 2020 set forth above remains unchanged as of phase one, between 745 - 760 mboed. See the section entitled Trend Analysis and Sensitivity Analysis—Trend Analysis for further information.

Ecopetrol will continue to monitor market developments to determine the need to launch subsequent stages of the intervention plan, seeking to optimize the balance between decisive responses under current market conditions and preservation the Company's long-term value.

The table below sets forth the details of the initial investment plan per business segment announced in November 2019 (which has now been modified as described above):

Table 3 – 2020 Investment Plan ⁽¹⁾

Business Segment	*% Percentage ⁽²⁾*
Exploration		14	%
Production		66	%
Midstream		7	%
Downstream		11	%
Other		2	%
TOTAL		100	%

(1)

This 2020 Investment Plan was modified by the intervention measures announced by Ecopetrol on March 16, 2020 as described above.

(2)

Percentage over the upper range.

Exploration

In exploration, investment has been allocated mainly to the evaluation and appraisal of discoveries and ongoing exploration activity of Ecopetrol S.A. (approximately 35%), Hocol S.A. (Hocol) (approximately 9%), Ecopetrol America LLC (approximately 2%), ECP Hidrocarburos Mexico (approximately 7%) and Ecopetrol Brazil (approximately 47%).

Production

In the production segment, investment has been allocated mainly to the development of production projects of Ecopetrol S.A. (approximately 75%) primarily at Castilla, Rubiales, Chichimene, Llanito, Casabe, Piedemonte and Caño Sur fields. In addition, Ecopetrol plans to spend approximately 19% of the funds allocated in the production investment plan in the Permian project as described below. Ecopetrol also has allocated funds for its affiliates and subsidiaries as follows: approximately 2% for the development, operation and maintenance of fields of Ecopetrol America LLC in the U.S. Gulf of Mexico and approximately 4% to Hocol.

Midstream

In the midstream segment, resources have been allocated to improve system and operational integrity. The segment seeks to strengthen its profitability by means of higher transported volumes through oil and multi-purpose pipelines and better operating results. These investments are expected to optimize future operating costs due to equipment upgrades and performance improvement.

Downstream

In the downstream segment, investment has been primarily allocated to the Barrancabermeja and Cartagena refineries through initiatives aimed at optimizing maintenance costs, enhancing integrity management, and improving the quality of diesel and gasoline. The segment is seeking a higher efficiency in operations in order to maximize the value of the existing assets.

Environmental, Social and Governance (ESG) and Digital Transformation

Ecopetrol expects to invest US$150 million in energy transition and carbon emission reduction in 2020. The Plan includes funding for the medium-term socio-environmental investment program, with an expected investment of between US$350 and US$400 million for the upcoming three years, aimed at helping close socioeconomic gaps in Colombia and boosting sustainable community development and wellbeing.

To strengthen the digital transformation, Ecopetrol expects to allocate US$91 million in 2020 toward capturing benefits associated with artificial intelligence, blockchain and bot technologies, among others. Ecopetrol expects to invest an additional US$35 million in leveraging new innovation processes, including creating strategic alliances and innovation ecosystems.

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 public stock-holding corporation, one hundred percent state-owned, and continued the development of exploration and production activities in a competitive basis with autonomy over our 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. As of March 23, 2018, pursuant to our amended bylaws, the duration of the Company is 100 years.

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. Starting in August 2010, our ADSs began trading on the Toronto Stock Exchange (TSX) under the symbol “ECP.” On February 17, 2016, we announced our application for voluntary delisting from the TSX. On March 25, 2016, our ADR’s were officially delisted from the TSX. On December 7, 2017, we applied to the Alberta Securities Commission and the Ontario Securities Commission to cease our reporting requirements, due to our delisting process. On September 4, 2018, we announced that effective August 29, 2018, we had ceased to be a reporting issuer in each of the provinces of Alberta and Ontario and hence were no longer a reporting issuer in any jurisdiction in Canada. Accordingly, Ecopetrol no longer has any disclosure obligations in Canada.

3.2

Our Corporate Structure

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

Our subsidiaries, Refinería de Cartagena S.A.S. (Reficar or Cartagena Refinery), Cenit Transporte y Logistica 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. Our subsidiaries are either directly owned by us or indirectly owned by us through one or more of our other subsidiaries. As of December 31, 2019, we have seven directly owned and 22 indirectly owned subsidiaries.

During 2019, the following changes were made to the Ecopetrol Group’s structure:

We formed a joint venture (JV) with Occidental Petroleum Corp for the development of unconventional reservoirs in approximately 97,000 acres in the Midland Basin, within the Permian Basin, Texas, by which we acquired 49% of Rodeo Midland Basin LLC (Rodeo). We have joint control over Rodeo, and, for that reason, we recognize the proportionate share of the assets, liabilities, revenues and expenses associated with Rodeo. The information we present throughout this annual report with respect to Rodeo represents such proportionate share. To develop the JV, we incorporated two new companies: (i) Ecopetrol Permian LLC, dedicated to the exploration, development and production of unconventional resources, and (ii) Ecopetrol USA Inc., which purpose is the exploration and exploitation of hydrocarbons. It also converted Ecopetrol America Inc. into Ecopetrol America LLC, which will continue to focus on US GoM operations.

ii.

We incorporated two service companies in México: Topili Servicios Administrativos - Sociedad de Responsabilidad Limitada de Capital Variable and Kalixpan Servicios Técnicos - Sociedad de Responsabilidad Limitada de Capital Variable.

iii.

We became the controlling shareholder of Inversiones de Gases de Colombia S.A. (“Invercolsa”), due to the decision of the Colombian Supreme Court of Justice that returned 145 million ordinary shares of this company to Ecopetrol, thus increasing our equity interest from 43.35% to 51.88%.

iv.

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, which will allow them to organize financial, administrative and operational aspects to preserve their sustainability. Those entities are not material subsidiaries and therefore these processes are not expected to have a material adverse effect on Ecopetrol’s results of operations or financial condition.

Graph 2 – Ecopetrol Corporate Structure

The stock ownership percentage listed refers to Ecopetrol S.A.’s direct and indirect participation. 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

Our Business

We are a vertically integrated oil and gas company with presence primarily in Colombia and with activities in Peru, Brazil, Mexico and the U.S. The Nation currently owns 88.49% of our voting capital stock. We are among the world’s largest public companies, ranking 300 on the Forbes Global 2000 Ranking - 2019. We play a key role in the local Colombian hydrocarbon market.

3.4

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, 2019, 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.

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

3.4.1

Exploration Activities

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

Graph 3- Sedimentary basins where Ecopetrol executes exploration activities

During 2019, the exploration strategy was directed at leveraging our goal on three working fronts: onshore Colombia, offshore Caribbean, and strengthening and diversifying our exploration overseas.

3.4.1.1

Exploration Activities in Colombia

The Ecopetrol Group was awarded ten exploration blocks by the National Hydrocarbons Agency (ANH) during the 2019 bidding round process. Three of these were awarded to Ecopetrol S.A, the Gua-Off 10 Block located in the Colombian Caribbean offshore and two blocks in the Llanos Basin. The remaining seven blocks were awarded to our subsidiary Hocol.

During 2019, Ecopetrol and its subsidiaries drilled nineteen (19) wells in Colombia, of which fifteen (15) were exploratory (A3/A2) and four (4) appraisal wells (A1) in Colombia. Seven (7) wells were successful, nine (9) were plugged and abandoned, and three (3) were under evaluation as of December 31, 2019. This activity was concentrated mainly in the following basins: Llanos, Lower Magdalena Valley, Middle Magdalena Valley, Upper Magdalena Valley and Piedemonte.

The following table sets forth, for the periods indicated, the number of gross and net productive and dry 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,

2019

2018

2017

(number of wells)

COLOMBIA

Ecopetrol S.A.

Gross Exploratory Wells

Owned and operated by Ecopetrol

Productive

1.0

–

Dry⁽¹⁾

1.0

–

1.0

Total

2.0

–

1.0

Operated by Partner in Joint Venture

Productive

4.0

5.0

3.0

Dry

1.0

2.0

Total

5.0

6.0

5.0

Operated by Ecopetrol in Joint Venture

Productive

–

Dry

–

1.0

Total

–

1.0

Net Exploratory Wells⁽²⁾

Productive

2.8

1.9

1.5

Dry

1.4

0.3

2.3

Total

4.2

2.2

3.8

Sole Risk

Productive

1.0

–

Dry

5.0

2.0

–

Total

6.0

2.0

–

ECAS

Gross Exploratory Wells

Productive

–

Dry

–

1.0

Total

–

1.0

Net Exploratory Wells

Productive

2.8

–

Dry

1.4

–

0.5

Total

4.2

–

0.5

Equion

Gross Exploratory Wells

Productive

–

Dry

–

Total

–

Hocol

Gross Exploratory Wells

Productive

1.0

–

Dry

2.0

4.0

1.0

Total

3.0

5.0

1.0

Net Exploratory Wells

Productive

0.5

1.0

–

Dry

2.0

3.2

1.0

Total

2.5

4.2

1.0

(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)

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

Ecopetrol drilled seven (7) successful wells in Colombia in 2019 (i) Jaspe-8, where Ecopetrol holds a 30% working interest, and Frontera as the operator holds the remaining 70% working interest at the Quifa Block, (ii) Andina Norte-1, where Ecopetrol holds a 50% working interest, and Parex Resources as the operator holds the remaining 50% working interest at the Capachos Block, (iii) Boranda-2 ST1, where Ecopetrol holds a 50% working interest, and Parex Resources as the operator holds the remaining 50% working interest at the Playon Block, (iv) Cosecha CW-01-ST, where Ecopetrol holds a 30% working interest, and Occidental Petroleum Corporation as the operator holds the remaining 70% working interest at the Cosecha Block, (v) Boranda-3 where Ecopetrol holds a 50% working interest, and Parex Resources as the operator holds the remaining 50% working interest at the Playon Block, (vi) Flamencos-1 operated by Ecopetrol who holds a 100% working interest in the VMM Block, and (vii) Bullerengue-3, where Ecopetrol holds a 50% working interest through its subsidiary Hocol, and Lewis as the operator holds the remaining 50% working interest at the Sinú San Jacinto Block.

Seismic

In Colombia, we acquired a total of 2,000 km² of 3D seismic offshore in the Col-5 Block, and through our joint venture partner, Parex Resources, 174 km² of 3D seismic onshore which were acquired in the Fortuna field.

Furthermore, Ecopetrol purchased four additional 3D seismic surveys for a total of 1,370 km² in the Eastern Plains (Llanos Orientales) and Putumayo basin to improve technical understanding of these prolific basins.

3.4.1.2

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 operational expertise and technology.

Ecopetrol Óleo e Gás do Brasil Ltda. has secured an agreement with Shell Brasil Petróleo Ltda. to acquire 30% of the interests, rights and obligations in two areas of the Santos basin, offshore in Brazil, to pursue Pre-Salt play. One of these blocks includes the Gato do Mato discovery. Under this agreement, Shell will reduce its stake from 80% to 50% and continue as operator, while the French company Total will retain the remaining 20%.

Moreover, during the 252 Gulf of Mexico lease sale our subsidiary Ecopetrol America LLC acquired a 31.5% working interest in the MC 904 block located in the Gulf of Mexico of the United States, in consortium with Fieldwood Energy as the operator with a 58.94% working interest, and Talos Energy with a 9.56% working interest. Also, in 2019 Ecopetrol and its partners successfully drilled the Esox-1 well in the MC 627 block in the Gulf of Mexico, where Ecopetrol America LLC holds a 21.43% working interest, Hess Corporation as the operator holds a 57.14% working interest, and Chevron holds the remaining 21.43% working interest. The well is currently being tested, and results, so far, seem promising.

Additionally, Ecopetrol Hidrocarburos Mexico Inc. is executing the exploration plan for Block 6. The following table sets forth information on our exploratory drilling for the periods indicated.

Table 5 – Exploratory Drilling Outside Colombia

For the year ended December 31,

2019

2018

2017

(number of wells)

INTERNATIONAL

Ecopetrol America LLC

Gross Exploratory Wells

Productive

1.0

–

Dry⁽¹⁾

–

2.0

Total

1.0

–

2.0

Net Exploratory Wells⁽²⁾⁽³⁾

Productive

0.2

–

Dry

0.0

–

0.6

Total

0.2

–

0.6

Ecopetrol Óleo e Gás do Brasil Ltda.

Gross Exploratory Wells

–

Productive

–

Dry

–

Total

–

Net Exploratory Wells

Productive

–

Dry

–

Total

–

Ecopetrol Germany

Gross Exploratory Wells

–

Productive

–

Dry

–

Total

–

Net Exploratory Wells

Productive

–

Dry

–

Total

–

Savia Perú

Gross Exploratory Wells

–

Productive

–

Dry

–

Total

–

Net Exploratory Wells

Productive

–

Dry

–

Total

–

(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)

Net exploratory wells are calculated according to our percentage of ownership in these wells.

(3)

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

Seismic

Our subsidiary, Ecopetrol Brazil, invested in new 3D seismic data obtaining 12,314 Km² to mainly evaluate the Pre-Salt bidding rounds in the Santos and Campos basins (Transfer of Rights, Round 16 and Round 6). In addition, it purchased 2,660 Km of 2D seismic to fill information gaps and 12,000 Km of 2D seismic to carry out the regional studies.

Ecopetrol Hidrocarburos Mexico Inc. acquired the license for 88,015 km² of 3D seismic from the Campeche program for a period of 24 months.

3.4.2

Production Activities

Our consolidated average production was 725 thousand barrels of oil equivalent per day (boepd) in 2019, an increase of approximately 4.7 thousand boepd as compared to 2018. This growth was primarily due to the positive results in the Akacias, Yarigui, Caño Sur, Rubiales, and Chichimene fields, the greater commercialization of gas, mostly from the Cupiagua and Floreña fields and the entry into operation of the Cupiagua LPG Plant.

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,
	2019						2018						2017
	Oil		Gas⁽¹⁾		Total		Oil		Gas⁽¹⁾		Total		Oil		Gas⁽¹⁾		Total
	(thousand boepd)
Total production in Colombia⁽²⁾		576.6		130.5		707.1		578.4		125		703.4		577.3		121.6		698.9
Total International production⁽³⁾		15		3.0		18		14.1		2.9		17.0		13.6		2.6		16.2
Total production of Ecopetrol Group (Gross)		591.6		133.5		725.1		592.5		127.9		720.4		590.9		124.2		715.1

Total production of Ecopetrol Group for presentation of reserves⁽⁴⁾		528.9		133.7		662.6		524.3		129.8		654.1		515.1		126.9		642.0

(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. Includes royalties

(3)

Total International production corresponds to Rodeo Midland Basin 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), Rodeo Midland Basin 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.

3.4.2.1

Production Activities in Colombia

3.4.2.1.1

Ecopetrol S.A.’s Production Activities in Colombia

For the year ended December 31, 2019, Ecopetrol S.A. was the largest participant in the Colombian hydrocarbons industry, accounting for approximately 62% of crude oil production and 62% of natural gas production (according to calculations made by Ecopetrol based on information from the Ministry of Mines and Energy). Also during 2019, Ecopetrol S.A. carried out development drilling mainly in the Eastern and Orinoquia regions, drilling 571 development wells (298 of those through direct operations and 273 through joint ventures).

Ecopetrol S.A. manages its production operations through a regional organization. Our operating assets are distributed in the following vice-presidencies:

Central Region: comprising 25 fields with active production in 2019.

Orinoquía Region: comprising 19 fields with active production in 2019.

Southern Region: comprising 33 fields with active production in 2019.

Eastern Region: comprising 2 fields with active production in 2019.

Piedemonte Region: comprising 6 fields with active production in 2019.

A sixth vice-Presidency, the Vice-Presidency of Associated Operations, is responsible for all of the production activities in which a partner is involved, regardless of the location of such activities in Colombia. This Vice- Presidency is comprised of 123 fields with active production in 2019. On February 10, 2020, a new Vice-Presidency of Gas was created in order to lead and execute the Ecopetrol Group’s integrated natural gas strategy.

The map below shows the locations of Ecopetrol S.A.’s operations with production information for each of our administrative regions described in the following paragraphs.

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 548.0 mbod in 2019, 0.7 mbod lower than in 2018, which represents a year-to-year decrease of 0.1%.

The following chart summarizes Ecopetrol S.A.’s average daily crude oil production in Colombia by region, prior to deducting royalties, for the periods indicated.

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

	For the year ended December 31,
	2019		2018		2017
	(thousand bpd)
Central Region
1) La Cira – Infantas		25.9		28.1		22.6
2) Casabe		13.2		13.9		15.9
3) Yarigui		17.9		14.4		14.5
4) Other		15.9		17.3		18.5
Total Central Region		72.9		73.7		71.5
Orinoquía Region
1) Castilla		114.1		113.9		114.1
2) Chichimene		69.1		67.7		70.5
3) CPO-09⁽²⁾		10.9		4.5		3.1
4) Cupiagua		7.2		8.3		9.6
5) Apiay⁽²⁾		7.3		7.6		8.5
6) Other		12.9		13.4		12.7
Total Orinoquía Region		221.5		215.4		218.5
Eastern Region
1) Rubiales		119.3		119.5		118.7
2) Caño Sur		4.5		3.2		1.4
Total Eastern Region		123.8		122.7		120.1
Southern Region
1) San Francisco		6.2		6.0		6.2
2) Huila Area⁽¹⁾		3.8		3.5		3.1
3) Tello		3.4		3.6		3.9
4) Other		10.4		11.7		12.2
Total Southern Region		23.8		24.8		25.4
Associated Operations
1) Piedemonte⁽²⁾		18.3		21.2		19.9
2) Quifa		20.5		21.2		18.8
3) Caño Limon		25.7		25.3		22.2
4) Nare⁽²⁾		10.9		12.0		13.4
5) Other		30.6		32.4		35.2
Total Associated Operations		106.0		112.1		109.5
Total average daily crude oil production Ecopetrol S.A. (Colombia)		548.0		548.7		545.0

(1)

Huila Area: some assets were reclassified and are reported under Other in the Southern Region.

(2)

In respect of our annual reports on form 20-F for the years ended December 31, 2018 and 2017, the the CPO-09, Apiay, Pidemonte and Nare Fields were included in “other” in years 2018 and 2017, whereas for this annual report, these fields are reported separately, and the figures for 2017 and 2018 have been adjusted.

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

	2019 (mbod)		Year-on-Year ∆ (%)			2018 (mbod)		Year-on- Year ∆ (%)			2017 (mbod)
Light		36.5		(10.3	)%		40.7		(4.0	)%		42.4
Medium		150.3		(2.7	)%		154.4		1.8	%		151.6
Heavy		361.2		2.1	%		353.6		0.7	%		351.0
Total		548.0					548.7					545.0

Ecopetrol S.A.’s crude oil production during 2019 was approximately 34% light and medium crudes and 66% heavy crudes. In 2018, approximately 36% of the crude oil production consisted of light and medium crudes, and 64% consisted of heavy crudes. In 2017, approximately 36% of the crude oil production consisted of light and medium crudes, and 64% consisted of heavy crudes.

Natural Gas Production

In 2019, the average daily production of natural gas by Ecopetrol S.A. (excluding its subsidiaries) reached 116.75 mboed, including natural gas liquids (NGLs), corresponding to a 3.8% increase in comparison to 2018 production.

We have three main natural gas production fields: Guajira, Cusiana and Cupiagua. On November 22, 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields. The fields were operated by Chevron through the Guajira Association Contract (57% Ecopetrol and 43% Chevron). Under the terms of the agreement, Hocol will acquire Chevron's stake and will take the position of operator. The transaction is subject to approval by the Colombian Superintendence of Industry and Commerce.

Of our total natural gas production during the year ended December 31, 2019, approximately 15% was supplied from the Guajira field, 31% from the Cusiana field, 31% from the Cupiagua field and the remaining 23% from other fields.

On October 29, 2019 the new Liquefied Petroleum Gas (LPG) plant of the Cupiagua field began operations. This plant is expected to produce between 7,000 and 8,000 LPG barrels per day. The plant produces LPG and other products such as natural gas liquids (NGL) and penthane (C5), which are used as a diluent of the heavy crudes produced in fields such as Castilla, Rubiales, Chichimene, CPO-09, Quifa and Caño Sur.

The following table sets forth Ecopetrol S.A.’s average daily natural gas production in Colombia, including NGLs, prior to deducting royalties, for the years ended on December 31, 2019, 2018 and 2017.

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

	For the year ended December 31,
	2019		2018		2017
	(thousand boepd)
COLOMBIA
Central Region
1) La Cira – Infantas		0.12		0.16		0.15
2) Provincia		1.58		1.96		2.41
3) Yarigui		0.43		0.42		0.48
4) Gibraltar		6.25		6.87		7.16
5) Other		1.68		1.86		2.02
Total Central Region		10.06		11.27		12.22
Orinoquía Region
1) Cupiagua		36.45		26.97		25.29
2) Cusiana		35.72		34.73		31.97
3) Other		2.87		2.80		2.44
Total Orinoquía Region		75.04		64.50		59.70
Southern Region
1) Huila Area⁽¹⁾		0.09		0.13		0.10
2) Tello		0.07		0.11		0.22
3) Other		0.25		0.25		0.40
Total Southern Region		0.41		0.49		0.72
Associated Operations
1) Guajira		17.92		23.02		27.09
2) Piedemonte⁽²⁾		12.50		12.20		9.70
3) Other		0.82		1.01		1.59
Total Associated Operations		31.24		36.23		38.38
Total Natural Gas Production (Colombia)		116.75		112.49		111.02

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

(1)

In the Southern Region, some assets that were previously part of the Huila area were reclassified as Other.

(2)

In respect of our annual reports on form 20-F for the years ended December 31, 2018 and 2017, the Pidemonte and Nare Fields were included in “other” in years 2018 and 2017, whereas for this annual report, these fields are reported separately, and the figures for 2017 and 2018 have been adjusted.

Projects to Increase Recovery Factor

Ecopetrol continues to invest in its recovery factor program in order to increase reserves and production. In 2019, the recovery factor program increased proven reserves by 94 million boe.

In 2019, secondary and tertiary recovery technologies contributed 219 mboed or 30% of the Ecopetrol Group’s total daily production, mainly from 30 fields, as compared to 29 fields in 2018. The fields that reported better results in injection efficiency and oil production correspond to both gas injection in Cupiagua, Cusiana and Pauto fields and water injection in La Cira, Yariguí, Chichimene and Casabe fields. Regarding both polymer injection and steamflood, there are currently projects under execution that are expected to have production results in the coming quarters.

US$62 million was invested in the execution of 46 studies and eight pilots to reduce uncertainties, and mature these opportunities into projects in the medium and long-term. These pilots under assessment had a daily production of approximately 15 mboed.

During 2019, 17 fields had projects in execution in respect of secondary and tertiary recovery, with an investment close to US$730 million. Additionally, final investment decisions were taken for 11 new recovery projects, and 16 recovery projects are being structured based on the results of their correspondent pilots.

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 joint ventures that reached total depth for the years ended December 31, 2019, 2018 and 2017.

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

	For the year ended December 31,
	2019		2018		2017
	(number of wells)
COLOMBIA
Central Region
Gross wells owned and operated by Ecopetrol		85		12		–
Orinoquía Region
Gross wells owned and operated by Ecopetrol		89		77		56
Southern Region
Gross wells owned and operated by Ecopetrol		2		19		–
Eastern Region
Gross wells owned and operated by Ecopetrol		122		118		143
Total gross wells owned and operated by Ecopetrol S.A. in Colombia		298		226		199
Associated Operations
Gross wells in joint ventures		273		302		276
Net wells⁽¹⁾		139.6		144.2		97
Total gross wells in joint ventures Ecopetrol S.A. in Colombia		273		302		276
Total net wells in joint ventures Ecopetrol S.A. in Colombia⁽¹⁾		139.6		144.2		97
Total gross wells Ecopetrol S.A. in Colombia		571		528		475
Total net wells Ecopetrol S.A. in Colombia⁽¹⁾		437.6		370.2		296

(1)

Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations.

Production Acreage

The following table sets forth Ecopetrol S.A.’s developed and undeveloped gross and net acreage of crude oil and natural gas production in Colombia for the year ended December 31, 2019.

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

Production Acreage as of December 31, 2019 (acres)

Developed

Undeveloped

Gross

Net

Gross

Net

Ecopetrol S.A.

463,396

358,798

4,642,257

3,412,923

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, 2019.

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

	As of December 31, 2019 (number of wells)
	Crude Oil⁽¹⁾				Natural Gas⁽²⁾
	Gross		Net⁽³⁾		Gross		Net⁽³⁾
COLOMBIA
Ecopetrol S.A.
Central region		2,089		1,585		6		6
Orinoquía region		1,012		997		17		16
Southern region		518		463		8		8
Eastern Region		680		680		0		0
Region of Associated Operations		2,794		1,402		38		18
Total (Ecopetrol S.A.)		7,093		5,127		69		48

Note: The above table reflects the productive wells that directly contribute to hydrocarbon production and therefore excludes wells used for injection, disposal, water abstraction, or other similar activities.

(1)

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.

(2)

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

(3)

Calculation of net productive wells is calculated by multiplying gross productive wells by our ownership percentage.

3.4.2.1.2

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

Crude Oil Production

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

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

	For the year ended December 31,
	2019		2018		2017
	(thousand bpd)
Hocol
Joint venture operation		2.0		2.3		2.3
Direct operation		18.8		18.4		19.4
Total Hocol		20.8		20.7		21.7
Equion
Joint venture operation		-		–		0.1
Direct operation		7.9		9.0		10.5
Total Equion		7.9		9.0		10.6
Production Tests		-		–		–
Total Average Daily Crude Oil Production (Subsidiaries in Colombia)		28.7		29.7		32.3

The 12% decrease in Equion’s production in 2019, as compared to 2018, was mainly due to the natural production decline of our fields.

Natural Gas Production

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

Table 14 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Natural Gas Production

	For the year ended December 31,
	2019		2018		2017
	(thousand boepd)⁽¹⁾
Hocol
Joint venture operation		2.0		1.6		0.6
Direct operation		6.7		5.9		5.2
Total Hocol		8.7		7.5		5.8
Equion
Joint venture operation		-		0.2		0.2
Direct operation		5.0		4.8		4.6
Total Equion		5.0		5.0		4.8
Production Tests		-		–		–
Total Natural Gas Production (Subsidiaries in Colombia)		13.7		12.5		10.6

(1)

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

Development Wells

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

Table 15 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Development Wells

	For the year ended December 31,
	2019		2018		2017
	(number of wells)
Hocol
Gross wells owned and operated by Hocol		23		12		17
Gross wells in joint ventures		2		2		–
Net wells⁽¹⁾		24		13		17
Equion
Gross wells owned and operated by Equion⁽²⁾		–		–		–
Gross wells in joint ventures		–		–		1
Net wells⁽¹⁾		–		–		–
Total gross wells owned and operated in Colombia		23		12		17
Total gross wells in joint ventures in Colombia		2		2		1
Total net wells (Subsidiaries in Colombia)		24		13		17

(1)

Net wells correspond to the sum of wells owned and operated by our subsidiaries and their ownership percentage of wells owned in joint ventures with their partners.

(2)

Even though for the last three years Equion has operated every well, Equion has not owned any well 100%; rather Equion has drilled wells in joint venture with Ecopetrol. Therefore, after a careful review of the categories, all Equion data was moved from gross wells owned and operated by Equion to gross wells in joint ventures. However, the number of wells remains the same.

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, 2019.

Table 16 – Ecopetrol S.A.’s Subsidiaries in Colombia Developed and Undeveloped Gross and
Net Acreage of Crude Oil and Natural Gas Production

	Production acreage as of December 31, 2019
	Developed				Undeveloped
	Gross		Net		Gross		Net
	(in acres)
Hocol		23,211		21,576		794		765
Equion		16,300		4,104		54,666		12,162
Total (Subsidiaries in Colombia)		39,511		25,680		55,460		12,927

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, 2019.

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

	For the year ended December 31, 2019
	Crude Oil				Natural Gas
	Gross		Net		Gross		Net
	(number of wells)
Hocol		316		274.8		25		23.5
Equion		15		8		15		8
Total (Subsidiaries in Colombia)		331		282.8		40		31.5

(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.

3.4.2.2

Production Activities Outside Colombia

The Ecopetrol Group’s production outside of Colombia comes from Ecopetrol America LLC (73.3%), Rodeo (0.7%) and of its share in the Peruvian company Savia (26%). In 2019, the production obtained from these three companies was 17.7 mboed, which represents 2.5% of the total production of the Ecopetrol Group.

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

	For the year ended December 31,
	2019		2018		2017
	(thousand bpd)
Savia Perú		3.5		3.9		3.9	⁽¹⁾
Ecopetrol America LLC		11.4		10.2		9.2
Rodeo Midland Basin LLC⁽²⁾		0.1		N.A.		N.A.
Total average daily crude oil production (International)		15		14.1		13.1

(1)

In 2017, Savia’s crude oil production included NGLs. In preparing our 2018 operational information, those NGLs were reclassified into our 2017 natural gas production.

(2)

In 2019, Ecopetrol S.A., through its wholly-owned subsidiary Ecopetrol Permian LLC, acquired 49% of Rodeo Midland Basin LLC.

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

	For the year ended December 31,
	2019		2018		2017
	(thousand boepd)
Savia Perú		0.9		1.1		1.1	⁽¹⁾
Ecopetrol America LLC		1.8		1.8		2.0
Rodeo Midland Basin LLC⁽²⁾		0.0		N.A.		N.A.
Total average daily natural gas production (International)		2.7		2.9		3.1

(1)

In 2017, Savia’s crude oil production included NGLs. In preparing our 2018 operational information, those NGLs were reclassified into our 2017 natural gas production.

(2)

In 2019, Ecopetrol S.A. through its wholly owned subsidiary, Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC.

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

	For the year ended December 31,
	2019		2018		2017
	(number of wells)
Savia Perú
Gross wells		-		-		-
Net wells⁽²⁾		-		-		-
Ecopetrol America LLC		-		-		-
Gross wells		2		1		2
Net wells⁽²⁾		0.5		0.3		0.4
Rodeo Midland Basin LLC⁽³⁾
Gross wells		6		N.A.		N.A.
Net wells		2.0		N.A.		N.A.
Total gross wells (International)		8		1		2
Total net wells (International)		2.5		0.3		0.4

(1)

(2)

Net wells correspond to the sum of wells entirely owned by us or our subsidiaries and our ownership percentage of wells owned in joint ventures with our partners.

(3)

In 2019, Ecopetrol S.A. through its wholly-owned subsidiary Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC.

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, 2019.

Table 21 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Developed and Undeveloped Gross and
Net Acreage of Crude Oil and Natural Gas Production

	Production acreage as of December 31, 2019
	Developed				Undeveloped
	Gross		Net		Gross		Net
	(in acres)
Savia Perú		79,575		39,788		57,671		28,836
Ecopetrol America LLC.⁽¹⁾		49,680		13,243		23,040		6,566
Rodeo Midland Basin LLC⁽²⁾		62,034		47,746		4,737		816
Total (International)		191,289		100,777		85,448		36,218

(1)

Production and acreage from Ecopetrol America LLC is related to the K2, Dalmatian and Gunflint field blocks in the Gulf of Mexico. For K2, there are four blocks in the production stage. For Dalmatian, there are two blocks in the production stage. For Gunflint, there are five blocks in the production stage, of which one is producing.

(2)

In 2019, Ecopetrol S.A. through its wholly-owned subsidiary Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC. Acres spaced or assigned to productive wells. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells.

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, 2019.

Table 22 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Productive Wells

	As of December 31, 2019
	Crude Oil
	Gross		Net
	(number of wells)
INTERNATIONAL
Savia Perú		601		300
Ecopetrol America LLC		13		3.3
Rodeo Midland Basin LLC		6		2.0
Total (International)		620		305.3

3.4.2.3

Marketing of Crude Oil and Natural Gas

In 2019, Ecopetrol sold 928 mboed, out of which 412 mboed represented sales of crude oil (44%), 81 mboed of natural gas (9%) and 435 mboed of fuels and petrochemicals (47%).

Crude Oil Export Sales

Crude oil export sales in 2019 increased by 13 mboed compared to 2018, mainly due to higher production and an effective commercial strategy of domestic purchases of crude from third parties. 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 367 mboed sold during 2019 (a 91% share of our crude oil basket) followed by the domestic crudes sold by Ecopetrol America LLC with 10 mboed, (a 2.5% share in our crude oil basket), Mares blend with 9 mbopd (a 2.2% share of our crude oil basket), and Apiay Blend with 7 mboed (a 1.8% share of our crude oil basket).

Ecopetrol places its exports in markets that provide the best value for its crudes. In 2019, Asia was the main destination, representing 46.3% of crude oil exports, closely followed by the United States with 42%. The expansion of refining capacity in countries like China has supported the increase of crude oil flows from Colombia to Asia. Moreover, volatility in the production of regional competitors has given US refiners an incentive to diversify their supply sources, which in turn has opened opportunities for Colombian producers. Ecopetrol’s crude basket discount versus ICE Brent price was on average US$ 5.6/Bl. Our crude basket increased by US$ 2.9/Bl year over year due to market conditions and our commercial strategy focused on markets with higher value.

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 Hydrocarbon Agency (ANH). This oil is 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, 2019, 2018 and 2017.

Table 23 – Ecopetrol Consolidated Crude Oil Purchases

	For the year ended December 31,
	2019		2018		2017
	(million barrels)
Ecopetrol Group
Crude oil purchased from ANH royalties		35.4		37.6		40.3
Crude oil purchased from third parties		30.0		20.7		16.7
Crude oil imported from third parties		9.1		14.0		24.8

During 2019, 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 should allow us to capture enhanced margins.

Import of Diluents

In 2019, Ecopetrol increased the imports of diluent by 1.2 % (0.6 mbpd) compared to 2018 due to higher production. Diluent is used to transport our 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 3.0% (2.7 mboepd) compared to 2018, due to higher production.

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 24 – Ecopetrol Consolidated Natural Gas Delivery Commitments

	For the year ended December 31,
	2020		2021		2022		2023
	(gbtud)
Volume for sales third parties		586.9		554.8		377.9		325.1
Volume for self-consumption		207.7		226.8		235.7		238.9
Total Commitments		794.6		781.6		613.6		564.0

Data was updated based on current contracts of Ecopetrol S.A. and the official report made to the Ministry of Mines and Energy in 2019.

3.4.3

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, 2019, 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 Equion and Hocol’s assets in Colombia.

Estimated Net Proved Reserves

The following table sets forth our estimated net proved developed reserves of crude oil and gas by region for the years ended December 31, 2019, 2018 and 2017.

Table 25 – Net Proved Developed Reserves

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, 2017		747		10		6		763
At December 31, 2018		814		13		5		832
At December 31, 2019		832		12		3.8		848
Net Proved Developed NGL reserves in million barrels oil equivalent
At December 31, 2017		54.6		-		0.8		55.4
At December 31, 2018		50.5		-		0.6		51.1
At December 31, 2019		49		0.12		0.5		50
Net Proved Developed gas reserves in billion standard cubic feet
At December 31, 2017		3,143		10		5		3,158
At December 31, 2018		2,865.5		10		7		2,882.5
At December 31, 2019		2,645		11		7		2,662
Net Proved Developed oil, NGL and gas reserves in million barrels oil equivalent
At December 31, 2017		1,353		11		8		1,372
At December 31, 2018		1,368		14		7		1,389
At December 31, 2019		1,345		14		6		1,365

Gas Reserves included 381 bcf of Fuel Gas

Oil Reserves included 17 million barrels of Fuel Oil

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 Bonga.

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 2017, 2018 and 2019 annual reports, we have used our real transportation costs, rather than the regular tariffs set by the Ministry of Mines and Energy.

The following table summarizes our proved oil, NGL and natural gas reserves, which includes 17 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 26 – Proved Oil, NGL and Natural Gas Reserves for 2019

Reserves Category	Oil (million barrels)		NGL (million barrels)		Natural Gas (bcf)		Total Oil and Gas (Mmboe)
PROVED DEVELOPED RESERVES
Total (Colombia)		832		49		2,645		1,345
International:
North America		12		0.12		11		14
South America		3.8		0.5		7.0		6.0
TOTAL PROVED DEVELOPED RESERVES		848		50		2,662		1,365
PROVED UNDEVELOPED RESERVES
Total (Colombia)		306		28		111		353
International:
North America		123		29		133		175
South America		-		-		-		-
TOTAL PROVED UNDEVELOPED RESERVES		429		57		244		529
TOTAL PROVED RESERVES		1,277		107		2,906		1,893

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

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

The following table summarizes our proved oil, NGL and natural gas reserves, which includes 16 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 27 – Proved Oil, NGL and Natural Gas Reserves for 2018

Reserves Category	Oil (million barrels)		NGL (million barrels)		Natural Gas (bcf)		Total Oil and Gas (Mmboe)
PROVED DEVELOPED RESERVES
Total (Colombia)		814		50.5		2,866		1,368
International:
North America		13		-		10		14
South America		5		0.5		7		7
TOTAL PROVED DEVELOPED RESERVES		832		51		2,883		1,389
PROVED UNDEVELOPED RESERVES
Total (Colombia)		285		22		113		327
International:
North America		10		-		6		11
South America		-		-		-		-
TOTAL PROVED UNDEVELOPED RESERVES		295		22		119		338
TOTAL PROVED RESERVES		1,127		73		3,002		1,727

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 304 billion standard cubic feet of fuel gas within our natural gas results and 562 billion cubic feet of royalties, as of December 31, 2017.

Table 28 – Proved Oil, NGL and Natural Gas Reserves for 2017

Reserves Category	Oil (million barrels)		NGL (million barrels)		Natural Gas (bcf)		Total Oil and Gas (Mmboe)
PROVED DEVELOPED RESERVES
Total (Colombia)		747		54.6		3,143		1,353
International:
North America		10		-		10		11
South America		6		0.8		5		8
TOTAL PROVED DEVELOPED RESERVES		763		55.4		3,158		1,372
PROVED UNDEVELOPED RESERVES
Total (Colombia)		247		19		93		282
International:
North America		4		-		3		5
South America		-		-		-		-
TOTAL PROVED UNDEVELOPED RESERVES		251		19		96		287
TOTAL PROVED RESERVES		1,014		74		3,253		1,659

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

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 2019, 2018 and 2017.

Changes in Proved Reserves

Table 29 – Changes in Proved Reserves

	As of December 31,
	2019			2018			2017
Consolidated Company (million barrels oil equivalent)
Revisions of previous estimates		83			120.5			174
Improved Recovery		94			129.1			73
Extensions and discoveries		67			57.4			44
Purchases		164			-			4
Total reserves additions		408			307			295
Production		(242	)		(239	)		(234	)
Net change in proved reserves		166			68			61

The reserves replacement ratio for 2019 was 1.69 barrels compared to 1.29 barrels in 2018 and 1.26 barrels in 2017. The average replacement ratio for the last three years was 1.4 barrels.

Table 30 – Reserves Replacement Ratio (including purchase and sales)

	As of December 31,
	2019		2018		2017
Annual		1.69		1.29		1.26
Three year average		1.4		0.83		0.42

Revisions of Previous Estimates

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 review of the curve type of new development activities according to new wells results in the Caño Sur field and additional gas processing plant capacity to extract NGL in the Cupiagua field.

(iii)

The remaining 17% (or 14 million boe) increase in reserves, was due to varying increases and decreases from other fields.

In 2018, revisions increased reserves by 120 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.

(ii)

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

(iii)

The remaining 16%, or 19.8 million boe, increase in reserves was due to varying increases and decreases from other fields.

In 2017, revisions increased reserves by 175 million boe, mainly as a result of:

(i)

An increase of 49 million boe due to the continuous development of the Castilla, Chichimene, Rubiales, Caño Sur and Akacias fields of which a 32 million boe increase in reserves is due to the new development projects in the Caño Sur and Akacias fields, and a 17 million boe increase in reserves is due to development activities and improved reservoir performance in the Chichimene, Castilla and Rubiales fields.

(ii)

An increase of 23 million boe due to improved natural gas sales in the Cupiagua and Pauto fields, which in turn was due to better performance and improved output of such fields. Additionally, new gas and NGL projects in the Cupiagua Sur field led to a 27 million boe increase in reserves. Revisions in the Nutria, Llanito, Tibu, Casabe and Cohembi fields as a result of drilling activities and better production performance accounted for a 23 million boe increase in reserves.

(iii)

The remaining 30%, or 52 million boe, increase in reserves was due to varying increases and decreases from other fields.

Improved Recovery

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.

In 2017, improved recovery increased reserves by 73 million boe. The additions were associated with new proved areas under water flooding in the Chichimene and Castilla fields (47 million boe increase). The continued development of water flooding projects at existing wells in the Tibú, La Cira, Infantas, Casabe and Guando SW fields, accounting for a 24 million boe increase. The remaining 3%, or 2 million boe, increase was due primarily to water injection pilots in the Apiay and Palogrande fields.

On average, improved recovery has added 98.7 million boe each year over the last three years.

Extensions and Discoveries

Extensions and discoveries during 2019 amounted to 67 million boe primarily due to extensions of proved acreage mainly from activities in new proved areas in the Rubiales, Quifa, Suria, Tisquirama, Castilla and Garza’s fields, which accounted for 35 million of the total of 67 million boe from extensions of proved acreage. The remaining 32 million boe corresponds to smaller changes in several other fields.

Extensions and discoveries during 2018 amounted to 57 million boe primarily due to extensions of proved acreage mainly from activities in new proved areas in the Rubiales, Castilla, Cupiagua, Pauto and Caño Sur fields, which accounted for 45 million boe and newly discovered fields and reservoirs accounted for 12 million boe. The remaining 9 million boe corresponds to smaller changes in several other fields.

Extensions and discoveries during 2017 amounted to 44 million boe primarily due to extensions of proved acreage mainly from activities in new proved areas in the Rubiales, Castilla, Pauto, Cajua and Arrayan fields, which accounted for 39 million boe of the total of 44 million boe from extensions of proved acreage. The remaining 5 million boe corresponds to smaller changes in several other fields.

Purchases

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 will be 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 will pursue 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.

There were no purchases or acquisitions in 2018.

Ecopetrol S.A.’s purchases of minerals in 2017 included the acquisition of an additional participation of 11.6% in the K2 Field by Ecopetrol America LLC which represented 4 million boe.

Development of reserves

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.

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 5 years due to the limitations in water handling in the facilities. This exemption was reviewed and approved by the external certification agent.

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.

As of December 31, 2017, our total proved undeveloped oil and gas reserves amounted to 287 million boe, 24% of which is related to the drilling activities in the Castilla field, 11% is related to gas sale projects in the Pauto and Cupiagua fields and 42% of which is related to the development activities in the Rubiales, Caño Sur, Chichimene, Yarigui, Tibu, Nutria, Palagua and Quifa fields. The Moriche, Ocelote, Akacias, Dina, Casabe, Llanito, La Cira and Cajua fields collectively accounted for 11% of total proved undeveloped oil and gas reserves with the remaining 12% from several other fields.

Our proved undeveloped reserves represent 28% of our total proved reserves as of December 31, 2019, 20% as of December 31, 2018 and 17% as of December 31, 2017.

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

Table 31 – Developed and Undeveloped Proved Reserves

	Oil		NGL		Gas		Total
Proved Reserves as of December 31,	Mmbls		Mmbls		Bcf		Mmboe
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
2017 proved reserves
Developed		763		55		3,158		1,372
Undeveloped		251		19		96		287

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.

Of the total amount of proved undeveloped reserves that Ecopetrol had at the end of 2016 (269.3 million boe), we converted approximately 53 million boe, or 20%, to proven developed reserves during 2017 (286.6 million boe), primarily associated with the development of crude oil and gas projects in the Castilla, Rubiales, Pauto, Quifa, La Cira Infantas and K2 fields. These projects accounted for approximately 89% of the total conversion while the remaining 11% is associated with development execution in other fields such as the Chichimene and Ocelote fields, among others. The amount of investments made during 2017 to convert proved undeveloped reserves to proved developed reserves was US$494 million.

Changes in Undeveloped Proved Reserves

The following table reflects the main changes in undeveloped proved reserves as of December 31, 2019, 2018 and 2017.

Table 32 – Changes in Undeveloped Proved Reserves

	As of December 31,
Consolidated Companies (million barrels oil equivalent)	2019			2018			2017
Revisions of previous estimates		43			28.4			9
Improved recovery		40			67.1			36
Extensions and discoveries		34			39.9			25
Purchases		163			-			-
Proved Undeveloped converted to Proved Developed		(89	)		(83.7	)		(53	)
Net change in unproved reserves		190			51.7			17

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

Rounded figures

Reserve Process

Ecopetrol’s reserves process is coordinated by the Corporate Reserves Manager, a highly experienced engineer, who reports to the Upstream Chief Financial Officer. The Ecopetrol reserves group is comprised of reserves coordinators who are geologist and petroleum engineers, each with more than ten years of experience in reservoir characterization, field development, estimation and reporting of reserves and who support and interact with the specialists involved in the estimation and reporting process, following an established procedure with its corresponding internal controls. As in previous years, the reserves are estimated and certified by recognized external independent engineers (this year consisting of Ryder Scott Company, Gaffney, Cline & Associates, Sproule International Limited, Netherland Sewell & Associates, Inc. and DeGolyer and MacNaughton) 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 Group’s CEO, the Group’s CFO and the Vice-President of Development and Production. 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.

Petroleum engineering consultants Ryder Scott Company, Gaffney, Cline & Associates, Sproule International Limited, Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton have estimated and certified Ecopetrol’s proved reserves as of December 31, 2019. These external engineers estimated 99% of our estimated net proved reserves for the year ended December 31, 2019, 2018 and 2017. The reserves reports of the external engineers are included as exhibits to this annual report.

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, the estimates should not be interpreted as being 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, 2017 through 2019, and the changes therein.

Table 33 – Estimated Proved Reserves of Oil and Gas

Consolidated companies	Colombia			North America			South America excluding Colombia			Total
	Net proved oil, NGL and gas reserves in Mmboe
At December 31, 2017		1,635			16			8.2			1,659.2
Revisions		114			5.8			1			120.8
Improved Recovery		129			-			-			129
Extensions and discoveries		50			7			-			57
Production		(233	)		(3.8	)		(2	)		(238.8	)
At December 31, 2018		1,695			25			7.2			1,727.2
Revisions		78.4			4.3			0.2			83
Improved Recovery		94.3			-			-			94
Extensions and discoveries		66			0.7			-			67
Purchases		-			164			-			164
Production		(236	)		(4.2	)		(1.4	)		(242	)
At December 31, 2019		1,698			189.7			6			1,893

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.

Rounded figures

3.4.4

Joint Venture and Other Contractual Arrangements

We conduct our exploration and production business through a variety of types of contractual arrangements with the Colombian government or with third parties. Below is a general description of the main type of contractual arrangement to which we were a party as of December 31, 2019.

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.

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, and 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.

Risk Production Contract for Discovered Undeveloped and Inactive Fields (First Round 2003)

We have entered into risk production contracts for discovered undeveloped fields to promote exploration by private companies of both undeveloped and inactive fields. Under these contracts, the contracting party assumes all costs and expenses for the development and operation of a field in exchange for a percentage interest in the field’s production as specified in the contract. This type of contract has a ten-year term calculated from its date of execution: one year for the evaluation period and a maximum of nine years for the development period. Some of these contracts have subsequently been extended beyond their original term. Currently, Ecopetrol does not have any contract under this type of contractual arrangement.

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.

Joint Venture Contracts for Exploration and Exploitation of “La Cira-Infantas” Area and of “Teca-Cocorná” Area

These contracts between Ecopetrol S.A. and Occidental Andina LLC, 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 field 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 Occidental Andina LLC. Ecopetrol S.A. provides financial resources and the preferential rights of use for the existing infrastructure in that zone and Occidental Andina LLC 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’s term is divided in three phases. The first phase lasts 180 days, the second 730 days and the third up to the economical limit.

The incremental production, after deduction of the royalties, is owned 52% by Ecopetrol S.A. and 48% by Occidental Andina LLC. 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’s term is divided in two phases. The first phase lasts three years, extendable for up to an additional year, the second 20 years counted as from the initiation for the second phase 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 Occidental Andina LLC. 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, is 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. is the operator and Schlumberger Surenco S.A. keeps the right of first option regarding the activities to be executed in the area of interest.

Both parties can invest in all the activities seeking to evaluate, obtain and incorporate incremental value in the area of interest. Such activities are developed directly by the parties or via contractors (Ecopetrol) or subcontractors (Schlumberger). Amounts expended pursuant to the contract are 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. commit 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 Management 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 National Hydrocarbons Agency (ANH) and its Contracts

The National Hydrocarbon Agency (Agencia Nacional de Hidrocarburos or ANH as per its Spanish acronym) 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).

Pursuant to the first stage of this contractual model, the ANH only receives a percentage of oil revenues in two cases:

when the international oil prices rise beyond a specified price, 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.

Under all E&P contracts executed since ANH’s 2008 bidding round, the ANH receives a percentage of the production from the beginning of the contract, upon the commencement of the production phase, and not only in the extension phase of the contract 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) and the superficiary canon. It also has a right to use of the subsoil from the beginning of the contract, calculated based on the area of the field during the exploration stage and based on the production during the evaluation and production stage.

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.

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.

3.5

Transportation and Logistics

3.5.1

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.

Graph 5 – Map of Oil Pipelines

Graph 6 – Map of Multi-purpose Pipeline

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

Table 34 – Volumes of Crude Oil and Refined Products Transported

	For the year ended December 31,
	2019		2018		2017
	(thousand bpd)
Crude oil transport⁽¹⁾		877.7		836.2		823.3
Refined products transport⁽²⁾		275.3		273.4		268.2
Total		1,153.0		1,109.6		1,091.5

(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.

The volume of crude oil transported by Cenit’s main systems and those of its subsidiaries increased in 2019 by 5% compared to the previous year. This increase was mainly the result of (i) increased oil production at the national level, including production by third parties, (ii) commercial strategies at the Monterrey facilities which facilitated the transport of oil previously transported outside of our infrastructure, (iii) transportation of crude from the Acordionero oil field, and iv) increased crude oil transport demand from the Barrancabermeja refinery. Of the total volume of crude transported by oil pipeline, approximately 78.1% belonged to the Ecopetrol Group.

The volume of refined products transported by Cenit increased by 0.7% in 2019 mainly due to growth of demand from the frontier with Venezuela and higher volumes in the Cartagena – Baranoa pipeline, which more than offset lower volumes in the Galan – Sebastopol pipeline, which in turn was due to programed maintenance at the Barrancabermeja refinery and the import of refined products through the Buenaventura port. Of the total volume of refined products transported in multi-purpose pipelines during the year, 32.9% belonged to the Ecopetrol Group.

Transportation Capacity

Our main crude oil pipeline systems’ operating capacity decreased from 1,497 thousand bpd in 2018 to 1,486 thousand bpd in 2019 primarily due to scheduled maintenance. Our main multi-purpose pipeline transportation capacity increased from 510 thousand bpd in 2018 to 511 thousand bpd in 2019.

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).

3.5.1.1

Pipelines

As of December 31, 2019, 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 82% of the oil pipeline shipping capacity in Colombia. By December 31, 2019, our network of crude oil and multi-purpose pipelines was approximately 9,106 kilometers in length. The transportation network consists of approximately 5,367 kilometers of main crude terminals and oil pipeline networks connecting various fields to the Barrancabermeja refinery and Reficar, 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 refinery and from Reficar to major distribution points. Out of the 5,367 kilometers of crude oil pipelines, owned by us, 3,155 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, 2019.

Table 35 – Our Main Pipelines

Pipeline	Kilometers		Capacity (mbd)			Product Transported	Origin	Destination	Indirect Ownership Percentage
Caño Limón-Coveñas		771		250		Crude Oil	Caño Limón	Coveñas		100.00	%
Oleoducto de Alto Magdalena (OAM)		391		110		Crude Oil	Tenay	Vasconia		95.8	%
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)		260		314	⁽²⁾	Crude Oil	East fields	Monterrey Cusiana		65.00	%
Oleoducto Bicentenario de Colombia		230		110	⁽³⁾	Crude Oil	Araguaney	Banadia		55.97	%

(1)

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

Cupiagua-Cusiana (segment zero): 198 mbd

Cusiana-El Porvenir (segment one): 745 mbd

Vasconia-Coveñas (segment three): 550 mbd

(2)

Transportation capacity for this pipeline is measured by using crude oil viscosity of 690 cStk (30° C).

(3)

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

As of December 31, 2019 we owned 74 stations, 40 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, 2019, we had a nominal storage capacity associated with the transportation network of 16.4 million barrels of crude oil and 4.8 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 bpd at 300 cSt of diluted crude oil from the Chichimene and Castilla fields to the Monterrey pumping station and the transportation of 45,000 bpd 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 is currently in the commissioning process.

Chinchina – Pereira product pipeline realignment

The main objective of the Chinchina-Pereira project was to move the product pipeline infrastructure away from densely populated areas. The realignment of the pipeline increased the reliability and safety of the transportation of refined products to the western region of Colombia by avoiding geotechnically active areas. The pipeline is 55 kilometers long.

The refined product pipeline Salgar - Cartago - Yumbo realignment between the towns Chinchiná and Pereira passes through the municipalities of Santa Rosa de Cabal and Marsella. The project was commissioned and inaugurated during September 2019.

Replacement of El Porvenir Station Pumping Units

During 2019, Ocensa completed the replacement of five internal combustion pumping units with electrical energy engines and the installation of an electrical power generation plant with a 6 MW gas turbine. The startup of the project reduces Ocensa’s CO2 emission to 44,000 tons of CO2 equivalent per year, which represents about 15% of Ocensa’s total operations gas emissions. The project has also resulted in savings in operation and maintenance costs of US$9.8 million between 2018 and 2019.

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.

3.5.1.2

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 1.62 million bpd for crude oil. Our import capacity of refined products and crude oil reached 0.19 million bpd and 0.33 million bpd, 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 11.8 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 5.8 million barrels.

3.5.2

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 2019, 27.0 million barrels of crude oil and refined products were transported by tanker trucks, and 10.34 million barrels of refined products were transported by barges, particularly using the Magdalena River, connecting Barrancabermeja with Barranquilla and Cartagena.

3.5.3

Marketing of Transportation Services

Cenit and its subsidiaries’ main line of business is the crude oil pipeline transport (76.7% of revenues), followed by the refined products pipeline transport (14.4% of revenues) and ports and related services (4.4% 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 73.3% of this business segment’s revenues in 2019. Transportation services for crude oil provided to Ecopetrol S.A. represented 61.3% 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 40.1% of refined products pipeline transport revenues in 2019, principally due to the transport of naphtha, diesel and gasoline. Cenit also has 15 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 Distribuidora Andina.

Deregulated businesses, such as ports and crude-loading facilities, represent a smaller portion of Cenit’s revenue (4.4% in 2019). 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 on 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.

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.

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).

As of the date of this annual report, Bicentenario continues evaluating its options under the Transport Agreements and the Shareholders Agreement (Acuerdo Marco de Inversión) in order to guarantee the compensation, indemnification or other restitution deriving from the alleged early termination of said agreements and any other contractual breaches by the Carriers.

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

During 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.

During 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 on March and June 2019, respectively.

As of the date of this annual report, arbitrators have been designated by the parties for the aforementioned proceedings.

3.6

Refining and Petrochemicals

3.6.1

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. Ecopetrol S.A. operates this refinery and also owns and operates 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 36 – Average Daily Installed and Actual Refinery Capacity

	For the year ended December 31,
	2019							2018							2017
	Capacity		Through-put		% Use			Capacity		Through-put		% Use			Capacity		Through-put		% Use
	(bpd)		(bpd)		(bpd)			(bpd)		(bpd)		(bpd)			(bpd)		(bpd)		(bpd)
Barrancabermeja		250,000		218,612		87	%		250,000		221,946		89	%		250,000		209,838		84	%
Reficar⁽¹⁾		150,000		155,049		103	%		150,000		151,331		101	%		150,000		135,700		90	%
Apiay		2,500		779		31	%		2,500		939		38	%		2,500		997		40	%
Orito		2,300		1,314		57	%		2,300		1,228		53	%		2,500		948		38	%
Total		404,800		375,754		93	%		404,800		375,444		93	%		405,000		347,483		86	%

(1)

Reficar’s operations were fully stabilized during the second half of 2017.

3.6.1.1

Barrancabermeja Refinery

The Barrancabermeja refinery supplies approximately 51.6% 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 37 – Production of Refined Products from the Barrancabermeja Refinery

	For the year ended December 31,
	2019			2018			2017
	(bpd)
LPG, Propylene and Butane		10,114			11,813			10,712
Gasoline Fuels and Naphtha		64,063			58,623			56,047
Diesel		57,469			58,305			56,090
Jet Fuel and Kerosene		24,320			23,604			20,421
Fuel Oil		32,009			36,636			38,217
Lube Base Oils and Waxes		797			729			609
Aromatics and Solvents		2,652			3,106			2,847
Asphalts and Aromatic Tar		29,593			31,104			26,468
Polyethylene, Sulphur and Sulphuric Acid		1,139			1,479			1,509
Total		222,156			225,399			212,920
Difference between Inventory of Intermediate Product		(703	)		(1,018	)		(405	)
Total Production		221,453			224,381			212,515

In 2019, total production from the Barrancabermeja refinery decreased by 1.3% mainly due to the impact of the scheduled maintenance of the diesel hydrotreating unit.

We own and operate four petrochemical plants and one paraffin and lube plant located within the Barrancabermeja refinery. In 2019, we produced 33,309 tons of low-density polyethylene, a decrease of 31.3% compared to the production of 48,468 tons in 2018. This decrease was primarily due to maintenance performed on the Turboexpander unit. We produced 657.9 mboe of aromatics (benzene, toluene, xylene, orthoxylene, heavy aromatics and cyclohexane), a 26.4% decrease as compared with the production of 894 mboe of aromatics in 2018. The decrease was mainly the result of scheduled planned maintenance of the Aromatic unit.

The gross refining margin decreased from US$11.8 per barrel in 2018 to US$10.6 per barrel in 2019, primarily due to lower product prices and higher crude price spreads for the refinery feed slate. The average conversion index for the Barrancabermeja refinery was 86.8% in 2019 and 84.6% in 2018. This increase was primarily due to higher yields of valuable products and lower fuel oil yields.

3.6.1.2

Cartagena Refinery

The following table sets forth the production of refined products from the Cartagena Refinery for the periods indicated.

Table 38 – Production of Refined Products from the Cartagena Refinery

	For the year ended December 31,
	2019		2018		2017
	(bpd)
LPG, Propylene and Butane		4,255		4,227		6,791
Gasoline Fuels and Naphta		49,904		51,703		43,728
Diesel		79,069		76,833		60,467
Jet Fuel and Kerosene		9,331		8,057		6,700
Fuel Oil		3,660		4,671		10,150
Sulphur		585		581		446
Total		146,804		146,072		128,282
Difference between Inventory of Intermediate Products		2,262		39		3,916
Total Production⁽¹⁾		149,066		146,111		132,198
Petcoke (Metric tons)		922,460		984,558		704,073

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

	For the year ended December 31,
	2019		2018		2017
	(bpd)
Imports
Motor Fuels		521		-		212
Diesel		-		-		–
Jet Fuel and Kerosene		-		466		847
Alkylate		-		-		–
LPG and Butane		990		739		618
Total Imports		1,511		1,205		1,677

During 2019, the Cartagena Refinery imported products in order to achieve the planned input of the Alkylation Unit and to cover the North Coast sales demand primarily due to an unscheduled operational event at this unit in the third quarter of the year.

	For the year ended December 31,
	2019		2018		2017
	(bpd)
Sales
Motor Fuels		49,865		52,126		44,051
Diesel		77,981		78,007		60,289
Jet Fuel and Kerosene		9,063		8,082		7,489
Fuel Oil		3,713		4,704		7,528
Other Products		22,435		19,942		27,099
Total Sales		163,057		162,861		146,456

During its stabilization period in the second half of 2017, the Cartagena Refinery completed individual unit performance tests (for 100% of units), and the Global Performance Test on December 5, 2017.

During the initial phase of the refinery optimization process, in the first half of 2018, the maximum charge capacity of several of the Cartagena Refinery plants were tested and provided the following results: (i) the Delayed Coking unit, reaching a maximum feed of 46,088 bpd versus a nominal capacity of 45,000 bpd, (ii) the crude unit, reaching 166,607 bpd versus a nominal capacity of 150,000 bpd and (iii) the hydrocracking unit reaching 38,204 bpd versus a nominal capacity of 35,000 bpd.

In August 2018 a test was run using 100% domestic crude during nine days, achieving an average throughput of 164 mbd. In September 2018, the highest average throughput per month of 161 mbd was achieved since the refinery’s commissioning.

Finally, the fluid catalytic cracking unit reached 43,515 bpd versus a nominal capacity of 40,000 bpd after coupling and putting the turbo expander into operation.

The gross refining margin, decreased from US$11.0 per barrel in 2018 to US$9.2 in 2019 mainly due to lower product prices and higher crude price spreads across international markets. Throughput increased during 2019, from an average of 151 mbd in 2018 to 155 mbd in 2019. The Cartagena Refinery’s 2019 figures already reflect the operation of all units.

Total sales have decreased as compared to 2018, US$4,129 million in 2018 versus US$3,904 million in 2019, mainly due to trends in the international market behavior characterized by lower product prices. A total of 56.6 million barrels of crude were processed in 2019 compared to 55.3 million barrels of crude processed in 2018. Exports to international markets represented 46% of total sales (US$1,800 million).

Financing

On December 30, 2011, with the approval from the Colombian Ministry of Finance and Public Credit, Reficar executed a US$3.5 billion project finance to partially fund the expansion and modernization of the Cartagena Refinery, loans with tenors of 14 and 16 years from Commercial Banks and Export Credit Agency Facilities, respectively. The aggregate amount drawn under these finance agreements totaled US$3,497 million. These credit agreements included a mechanism by which Reficar can exit the facility by transferring the debt to the Ecopetrol parent level by either (i) the occurrence of a mandatory debt assumption event or (ii) a voluntary debt assumption.

During 2017, Reficar received capital injections of US$269 million to cover project capital expenditures, start-up costs, one-off stabilization costs of the new refinery and the debt service payments due on June 20, 2017. The amount requested by Reficar under the Construction Support Agreement was US$97 million. The amount requested by Reficar under the Debt Service Guarantee Agreement was US$172 million. There was no need to request additional contributions under the Debt Service Guarantee to cover the debt service payment due on December 2017.

The principal amount repaid by Reficar during 2016 was US$269 million and during 2017 was US$130 million. Interest payments during 2016 and 2017 were US$87 million and US$42 million, respectively.

As part of Ecopetrol Group’s strategy to optimize its capital structure, on December 13, 2017, with the approval of the senior lenders and the Colombian Ministry of Finance and Public Credit, Ecopetrol S.A. voluntarily assumed Reficar’s senior debt. As of the date of the voluntary assumption, Reficar owed the senior lenders a principal amount of US$2,666 million (in nominal terms).

In order to finalize the implementation of Ecopetrol Group’s strategy to optimize its capital structure, the following capital injections were undertaken by Ecopetrol on December 13, 2017, increasing its shareholding participation in Reficar from 75.96% to 99.34%:

As a result of the voluntary debt assumption, Reficar assumed an account payable in the amount of US$2,596 million (book value for Reficar’s senior debt under IFRS) in favor of Ecopetrol. As a shareholder, Ecopetrol requested that such account be repaid with Reficar shares.

ii.

Ecopetrol requested that the existing subordinated COP-denominated loan it granted to Reficar in the amount of $1,522,760 million (book value as of December 13, 2017) be repaid with new Reficar shares.

iii.

Additionally, on December 7, 2018, the direct shareholding participation of Ecopetrol S.A. in Reficar increased from 75.96% to 99.34%, after additional contributions of paid-in capital.

3.6.1.3

Esenttia S.A.

During 2019, Esenttia’s production totaled 460 thousand tons of petrochemical products, a 3% increase compared to the 447 thousand tons produced in 2018, primarily due to greater supply of the required raw material due to conditions in the American market. The total contribution margin in 2019 (including the contribution of polypropylene, polyethylene and masterbatches) was 27% higher than in 2018, an increase from US$191 per ton in 2018 to US$242 per ton in 2019. The increase in contribution margin was primarily due to higher inventory levels of the required raw material allowing for a reduction in costs.

Table 40 – Operating Capacity of Esenttia

	For the year ended December 31,
	2019			2018			2017
	(Metric Tons)
Average capacity		470,000			470,000			470,000
Throughput		459,737			447,290			440,632
% Use		98	%		95	%		94	%

3.6.1.4

Biofuels

We have investments in two biofuel companies: (i) Bioenergy S.A.S., in which we own indirectly 99.61% of the shares, that in 2017 began the operation of an ethanol plant with nominal capacity of 480,000 liters/day, and (ii) 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.

Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S. were admitted to this reorganization process mainly due to lower than expected agricultural productivity and a deterioration in market conditions that make the current level of debt unsustainable. By this process, they will seek to establish agreements with their main creditors as well as liquidity alternatives to maintain the viability of the companies.

3.6.2

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, natural gas and petrochemical products, among others.

Domestic sales of products increased by 7.9 mboepd, an increase of 2.6% compared to 2018. This increase is primarily the result of: (i) a 4.3%, or 6.5 mboepd, increase in middle distillates sales mainly due to higher economic growth in general, change in the bio-fuel blend percent and higher airplane transportation demand by passengers; (ii) a 5%, or 5.5 mboepd, increase in gasoline primarily as a result of higher economic growth and increased demand in the border region, given the decrease in the supply of Venezuelan gasoline; and (iii) a 77%, or 6.5 mboepd, decrease in fuel oil sales primarily as a result of lower production in order to generate products with higher value.

During 2019, 3.4 million barrels of diesel and 3.8 million barrels of gasoline produced by Reficar 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, 1.2 million barrels of diluent produce 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 increased by 5.9% compared to 2018, 6.4 mboepd from Reficar and -0.2 mboepd from Ecopetrol, primarily due to (i) a 39%, or 13 mboepd increase in exports of diesel and (ii) a 35%, or 8.3 mboepd decrease in gasoline exports.

3.7

Research and Development; Intellectual Property

Our innovation and technology center is the Colombian Petroleum Institute, established in 1985 and located in Bucaramanga, Santander. In 2019, research and development expenses were US$50.1 million, compared to US$40.7 million in 2018. Technology and innovation 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.

Our research, technology development and innovation efforts are focused on four main strategies: extending the technical limits for reserves growth; increasing the efficiency and sustainability of our operations preparing the corporation for decarbonization and the energy transition; and 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 commercialization, as well as environmental sustainability and asset integrity.

By 2030, our goal is to achieve a 20% reduction of our equivalent carbon dioxide emissions through energy efficiency projects, abatement of fugitive methane emissions, zero routine gas flaring in our operations, and carbon capture, utilization and storage (CCUS). We are diversifying the sources of energy for our operations by deploying a portfolio of renewables, including solar, wind and possibly geothermal resources. We will also monitor the progress of technological advances that could enable the use of green hydrogen in our refining and petrochemical processes. As water is a fundamental resource, our efforts will also include a water management program that encompasses the conservation, recycling, reuse and valorization of production water streams. Finally, we will also explore the production of high performance, non-combustible materials from petroleum molecules.

Each year Ecopetrol presents to the Colombian Institute for the Development of Science and Technology (Instituto Colombiano para el Desarrollo de la Ciencia y la Tecnología, or COLCIENCIAS) its research, technology development projects and innovation initiatives, in order to obtain certifications for its science and technology investments. COLCIENCIAS certifies science and technology investments, which are deductible from income tax upon execution; and Ecopetrol applies the tax benefit. In 2019, we obtained US$1.38 million in science-and-technology-related tax benefits certified by COLCIENCIAS.

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 247 patent applications in the last years, 23 of them in 2019. Our most recent patent applications include innovative technologies, such as (i) a method obtaining carbon quantum dots from petroleum molecules and its applications, (ii) a process for obtaining a transportable hydrocarbon blend composed of heavy crudes and non-conventional diluents, (iii) a downhole diluent injection process and its monitoring and control scheme for the recovery of extra heavy oil.

In 2019, Ecopetrol declared two industrial secrets that strengthen its competitive advantages in heavy oil processing and flow assurance; and in offshore exploration, specifically in the Colombian sector of the Caribbean Sea. The Colombian and international authorities granted us eight new patents—seven in Colombia and one in India. We currently hold 93 patents in Colombia, the United States, Mexico, Russia, Peru, Venezuela, Ecuador, Brazil, Nigeria, Indonesia, India and Malaysia.

In 2019, Ecopetrol S.A. licensed six of its technologies to private companies for manufacturing, marketing commercialization and technical support. We currently have 46 technologies licensed to Colombian and multi-national companies.

3.8

Applicable Laws and Regulations

3.8.1

Regulation of Exploration and Production Activities

3.8.1.1

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.

Decree 3004 of 2013, 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. 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.

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:

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.

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.

As mentioned above, 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 so-called Comprehensive Research Pilot Projects (PPII).”

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.

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 and execution of contracts.

As result of the first cycle of the PPAA, the ANH offered 18 continental areas and two offshore areas. As part of the second cycle, the ANH allocated 14 onshore blocks.

Resolution 078 of 2019, as issued by the ANH, approved the terms of reference and the model of the contract for the “permanent bidding procedure.” 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.

3.8.1.1.1

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 on 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 activities.

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 undertake a public consultation process with those communities before initiating such projects or activities. This consultation process is a prerequisite for obtaining the required environmental licenses.

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 the majority 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 Ministry of Environment and Sustainable Development (MESD) is also responsible for establishing guidelines regarding climate change policies for the hydrocarbon sector in Colombia. We comply with those guidelines. At present, MESD has not proposed any specific steps for the implementation of the Kyoto Protocol or the Paris Agreement, as they relate to our operations. We are continuously monitoring climate change requirements that could be applicable to us. A company that does not comply with the applicable environmental laws and regulations, does not execute the Environmental Management Plan (PMA) approved by the environmental authority or ignores the requirements imposed by an environmental license may be subject to an administrative proceeding initiated 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.

3.8.1.1.2

Royalties

In Colombia, the Nation is the owner of minerals and non-renewable resources located in the subsoil, including hydrocarbons. Thus, companies engaged in exploration and production of hydrocarbons, such as Ecopetrol, must pay to the National Hydrocarbons Agency (ANH), as representative of the National 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.

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.

3.8.2

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 Ministry of Environment and Sustainable Development 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.

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 31332 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 tariff methodology that has been in place since 2014, providing more regulatory stability for the Midstream companies through June 2023.

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 of 2009 (amended by Resolution 152 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 August 2017 CREG prepared a draft resolution 113 of 2017, which has not been issued. It introduces a new framework for the transportation regulation of liquefied petroleum gas and refined products. The draft resolution was open for observations from the general public and the oil and gas industry until January 12, 2018. CREG is also in the process of defining the transportation regulation and the rate calculation method for refined products. The primary goals and components of the proposed regulation are: (i) to ensure access to the transport systems for liquid fuels and the LPG pipeline systems without discrimination; (ii) to promote the timely expansion of the transport system in line with the needs of the market; (iii) to promote competition and prevent restrictive practices; (iv) to separate the operations of refining and transport; and (v) to ensure the efficient and continuous operation of transport systems. As of the date of this annual report, the above mentioned resolution has not been issued.

3.8.3

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.

3.8.3.1

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, 019 of 2015, and 034, 063, 064 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, 095 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.

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.

3.8.3.2

Regulation Concerning Production and Prices

According to the Decree - Law 4130 of 2011 and Decree 1260 of 2013, CREG is in charge of 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.

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). 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 Resolutions 31536 and 31538 of 2018 which contain the settlement of our Net Positions corresponding to: (i) the period between December 29 and 31, 2016 and the first and second quarters of 2017, and (ii) the third and fourth quarters of 2017. In those resolutions the FEPC was ordered to transfer COP $729,729,493,450.88 and COP $1,183,672,269,819.52 to Ecopetrol, respectively.

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 (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. The Ministry of Mines and Energy calculated the net positions corresponding to the year 2018 (Resolutions 31093 of 2019, 31219 of 2019 and 31227 of 2019), which totaled COP$3,137,557,402,233.94. The Ministry of Mines and Energy calculated the Net Positions corresponding to the year 2019 (Resolutions 31254 of 2019 and 31271 of 2019), which totaled COP$1,298,416,657,817.56.

3.8.3.3

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.

3.8.4

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 Resolution 114 of 2017, partially amended by CREG Resolution 21 of 2019 which adjusted commercial aspects of the wholesale natural gas market in Colombia and compiled CREG Resolution 089 of 2013 and its amendments. 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.

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).

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 114 of 2017: (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

Environmental, Social and Governance (ESG) Strategies and Initiatives

3.9.1

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.

3.9.1.1

Ecopetrol S.A.

One of the principles that guides Ecopetrol is the commitment to employees and the development of those 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 2019, compared with the prior year, were:

A reduction in the Total Recordable Incidents Frequency (TRIF), which represents the number of employee or contractor injuries that require minimum medical treatment for every million hours worked, including fatalities, from 0.63 incidents per million hours worked in 2018 to 0.59 in 2019; an improvement compared with the 2.96 recorded in 2012;

A 22% 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;

We improved our process safety performance, to 0.03 in 2019 from 0.05 in 2018, also an improvement compared with the 0.11 recorded in 2012;

An 8% increase in the number of incidents involving employee or contractor injuries that require medical treatment, restricted work or lost days;

An increase greater than 65% in the severity of occupational incidents due to three fatalities recorded in 2019; and

A decrease greater than 400% in the amount of oil spilled. In 2019, 142 barrels were spilled as compared to 710 barrels in 2018.

We have several programs in place aimed at increasing the safety of our industrial processes and minimizing the number of occupational accidents and other major incidents. Our HSE management model is based on key focus areas that are aligned with our integrated management system.

Total Recordable Incidents Frequency – Employees and Contractors

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

TRIF has improved from 2.96 incidents per million hours worked in 2012 to 0.59 in 2019. In 2019, 74 recordable cases occurred, where 31% led to restricted work, 11% required medical treatment and 58% led to lost days. Additionally, we had an 8% increase in the number of occupational incidents compared to 2018, however, with increased work hours in 2019.

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

All of our operational areas have preparedness and emergency response plans, each in accordance with Colombian legal requirements and our new internal guidelines for emergency management.

Our preparedness and emergency response plans have been developed based on our analysis of risk scenarios, the estimated consequences of these events and the implementation of strategies to be followed in response to each scenario. These contingency plans have the approval of the ANLA.

The objectives of our contingency plans are to:

Protect the health and safety of our workers, contractors and the communities in which we operate; and

Prevent oil spills and leaks of harmful substances in offshore and onshore areas, fires and explosions and mitigate environmental impacts.

Our contingency plan includes, among others:

Procedures for the containment of oil and other harmful substances, as well as procedures to safeguard the safety of affected communities, the environment and the personnel involved in such containment actions; and

Strategies for responding to emergencies located outside of our facilities and mutual aid emergency plans, including actions developed with local environmental authorities, the local community and other organizations for containment and recovery of spilled product, cleaning and recovery of affected areas, monitoring of the environmental effects and, if the spill or leak has an operational source, compensation for local communities and other affected persons.

Further, through our training programs, we are upgrading the skills of our fire brigade, ensuring the reliability of firefighting and emergency equipment and working on improving our performance during emergency drills. In 2019, about 85% of the fire brigade completed the training program.

In offshore operations, the operator has the responsibility of designing and implementing plans and strategies aligned with international best practices that cover various emergency response scenarios.

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 2019, there were 0.03 Tier 1 process safety incidents per million hours worked, an improvement from the 0.05 recorded in 2018.

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

Graph 8 – 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 2019, Ecopetrol S.A. recorded 6 environmental incidents, compared with 11 in 2018 and 14 in 2017. The volume of oil spills was 142 barrels in 2019, a decrease from 710.26 barrels in 2018 and an increase from 50.7 barrels in 2017. The decrease compared to 2018 in the numbers of environmental incidents was the result an improvement of the equipment and maintenance systems monitoring.

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. It is estimated that between March 12 and March 15, 550 barrels of crude, mixed with mud and rainwater, seeped into the streams of La Lizama and Caño Muerto. 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.

The four critical factors were the following:

A reservoir in natural overpressure conditions (4,850 PSI). During a well intervention in November 2017, a section of a working string fell to the bottom causing the rupture of the “blanking plug”, which served the purpose of preventing reservoir fluids from reaching the wellhead.

ii.

The rupture or failure of the “blanking plug” produced a flow of unexpected fluids that required the injection of fluids at a pressure of 1,250 PSI, which in turn could have generated the loss of the mechanical integrity in the casing of 9 5/8” affected by wear.

iii.

Presence of a natural system of geological faults in the area, which in addition to the other factors, allowed well fluids to migrate to the surface.

iv.

Time of exposure of the upper formations to the over-pressure of the reservoir, which contributed to the emergence of fluids in a farm near the well, a mixture of water, mud, crude oil and gas.

Corrective and mitigation actions implemented by Ecopetrol

With respect to the actions performed by Ecopetrol to address, mitigate other damages and manage the incident, in compliance of the obligations contained in Law 1523 of 2012, Presidential Decree 321 of 1999 and the contingency plan for the Lisama Well, Ecopetrol did the following:

Implementation of control and containment procedures to slow the spread of the spill and keep it contained.

ii.

Activities to protect the life and health of the surrounding communities.

iii.

Monitoring of the following resources: water, air and land.

iv.

Activities to protect and preserve fauna and flora in the area of influence and.

Operational attention and verification of the causes which led to the incident.

In terms of response to the incident, Ecopetrol coordinated actions and additional mitigation activities with several Colombian governmental authorities, including: the municipalities of Barrancabermeja, San Vicente de Chucurí and Puerto Wilches, the Department of Santander, the Environmental Regional Autonomous Authority of Santander, the Environmental Police of Barrancabermeja, the National Licensing Authority, the Colombian Red Cross, the Civil Defense, the Ministry Public, the Hydrocarbons National Authority, the Ministry of Environment and Sustainable Development, the Institute of Hydrology, Meteorology and Environmental Studies and, the Colombian Public Defender Office.

In addition, for the preparation and performance of the Environmental Recovery Plan (PRA) which Ecopetrol proposed and filed before the environmental authorities, Ecopetrol had the support of the Biological Resources Investigation Institute Alexander Von Humboldt (pursuant to which a contract was entered into between the aforementioned parties). Furthermore, to ensure the attention and management of wildlife actually and potentially affected by the incident, Ecopetrol had the support and advice of Cabildo Verde Sabana de Torres, a non-governmental agency.

Additionally, the government of Colombia, through the Ministry of Environment and Sustainable Development, requested an independent audit review from a group of environmental and humanitarian experts, composed by the Joint UNEP/OCHA Environment Unit (JEU) and the activation of the UNDAC mechanism of the United Nations Office for the Coordination of Humanitarian Affairs. The aforementioned experts delivered a report that included a set of conclusions and recommendations which were accepted and included by Ecopetrol within the guidelines of its Environmental Recovery Plan (PRA).

The following are the most important milestones which were carried out by Ecopetrol in response to the incident:

Since April 8, 2018, Ecopetrol intervened the Lisama Well with a snubbing unit (specialized unit which handles pressure), with the purpose to verify the integrity of the casing, the cement used for the casing and to seal off the area where the spill was occurring. These activities finalized successfully on May 8, of 2018, when the Lisama Well was finally plugged with a double seal of cement.

On May 27, 2018, after ensuring that the activities described above were successfully performed to control the spill, the 63 families (approximately 177 individuals) which were directly affected by the spill returned to their homes.

On June 2, 2018, the technical abandonment of the Lisama Well initiated, a process which ended on the July 11, 2018.

On October 19, 2018 and in compliance to Resolution 1767 of 2006, Ecopetrol filed before the ANLA the Environmental Recovery Plan (PRA), a plan to perform several activities to ensure the recovery of affected natural resources (water, air and land) plus fauna and flora was prepared, including the following aspects:

Components of intervention:

Activities to recover the biotic environment.

ii.

Activities to recover the abiotic environment.

iii.

Socio-economical activities.

iv.

Follow up activities.

Intervention strategies:

Water: Recovery of affected water bodies.

ii.

Land: Dismantling of the protection and defense mechanisms in place and reconfiguration and land suitability procedures on the site of the spill.

iii.

Flora: Following up and monitoring of regeneration regarding sapling and pole stage (brinzal y latizal) specimens; following up and monitoring of affected specimens; recovery of vegetation in place; recovery of the riparian vegetation of the gorge La Lizama and La Muerte canyon; incorporation of tree nurseries for the riparian vegetation recovery.

iv.

Fauna: Activities to manage wildlife specimens affected.

Social and Economic: Information and awareness campaigns.

vi.

Monitoring: Supervising and following up procedures of natural recovery.

Additionally, Ecopetrol has been reporting the advances achieved of the Environmental Recovery Plan (PRA) to all competent authorities.

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.

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. The Company´s employees currently being investigated are:

Felipe Bayón (CEO and former Chief Operating Officer)

ii.

Héctor Manosalva Rojas (former Vice-President of Development and Production)

iii.

Ricardo Ernesto Coral Lucero (former Vice-President of the Central Region)

iv.

Oscar Ferney Rincón (Development and Production Operations Manager of the De Mares region)

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:

Seven writs of protection (injunctive actions) seeking the protection of fundamental rights have been ruled in favor of Ecopetrol.

In addition, there are two additional 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.

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 Tribunal of Santander (competent judge) issued an interim measure whereby the latter ordered different authorities and Ecopetrol to perform different 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 Tribunal 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.

Ecopetrol has taken the relevant actions to obtain the guarantee coverage of guarantors.

3.9.1.2

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 are mainly conducted under Ecopetrol’s HSE model and guidelines.

3.9.1.3

Cartagena Refinery

In 2019, approximately 6,538,295 man-hours were employed conducting Reficar’s business activities. Our HSE performance indicators for Process Safety Incident (PSI) and Environmental Incident (EI) were well within our established expectations, and Total Recordable Incidents Frequency (TRIF) performance improved in 2019 as compared to 2018.

The following table covers Reficar’s TRIF for 2017, 2018 and 2019, which include 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 – 2019.

Table 41 – Performance Indicators

METRIC	2019		2018		2017
Man-hours		6,538,295		6,779,729		7,495,531
Recordable accidents		1		12		9
Total recordable incidents frequency (TRIF)*		0.15		1.77		1.2
Environmental Incidents (EI)		0		0		0
Process Safety Incidents (PSI)		0		0		0.13

* These risks were associated with normal operations.

The results of other related performance indicators during 2019 were:

Lost Time Injury Incidents: 1 incident,

ii.

Medical Treatment Injury: 0 incidents;

iii.

Restricted Work Incidents: 0 incidents,

iv.

Environmental Incidents: 0; and

Process Safety Incidents: 0.

3.9.2

Corporate Responsibility

Ecopetrol’s mission is to build a better future, which is profitable and sustainable with a healthy, clean and safe operation (clean barrels); to ensure operational excellence and transparency in each of our actions, and to build mutually beneficial relationships with stakeholders. This business statement is complemented by our definition of a “Higher Purpose” that synthesizes Ecopetrol’s reason for being: “We are the energy that transforms Colombia”.

Corporate Responsibility is a crosscutting theme that has an impact throughout the organization and its operations. The Corporate Responsibility framework has three pillars as described below:

Corporate Integrity: focuses on ensuring consistency and coherence between what the Company says, promises and practices.

Human Rights: seeks to ensure the promotion and respect of Human Rights, based on the United Nations Guiding Principles (UNGP).

Sustainable Development Agenda: Ecopetrol identifies, reviews and manages its non-financial material issues in a continuous review process that also seeks to establish long-term goals that contribute to the Company’s sustainability. Likewise, the Company plans to work with its stakeholder groups to fulfill five of the United Nations Sustainable Development Goals (SDGs).

As in previous years, during 2019 the Corporate Responsibility Area consulted the perceptions and expectations of our seven stakeholder groups (shareholders and investors; associates and partners; clients; contractors and its employees; employees and pensioners; community and local government; and national government) with respect to eleven attributes (i.e. compliance with made commitments, ethical and transparent behavior, responsibility with the community, the environment and Human Rights, among others).

On average, 82% of respondents rated these attributes in the two highest options on the scale. This represents an improvement of 9% to the result obtained in 2018 (73%). Of particular note, are the improvements in results obtained in the community and local government and associates and partners stakeholder groups.

3.9.3

Environmental Sustainability

3.9.3.1

Environmental Practices

Ecopetrol S.A.

During 2019, the environmental management strategy of Ecopetrol included the following components:

Environmental Viability: this strategy concentrates on obtaining environmental licenses and permits as well as adequate land management that ensures the sustainability of operations through timely prevention efforts and management of environmental impacts, constant and systematic relationships with stakeholders and participation in the sustainable development of the territories in which we operate.

ii.

Climate Change: this strategy aims to decrease our carbon emissions and reduce the vulnerability of our operations and our facilities to the effects of climate change through the implementation of four strategic action lines:

Mitigation: reducing our carbon dioxide emissions and creating carbon offset alternatives;

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

Research and Technology: reducing our greenhouse gas emissions through action on research and development, process optimization, implementation of energy efficient strategies, carbon capture and sequestration and diversification into low-carbon energy sources; and

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

In line with Ecopetrol’s Climate Change Strategy, we are prioritizing three areas: 1) updating our emissions inventory, 2) developing greenhouse gas reduction projects in various operating areas and 3) defining the compensation portfolio through nature based solutions.

As part of our efforts to contribute towards preserving the environment, in 2019, we declared our commitment to reduce carbon dioxide emissions by 20% by 2030 and to reduce the operation’s vulnerability to climate change. This decrease has been ongoing for several years. In 2019, we achieved a reduction of 380,603 tons of CO2e, for a cumulative decrease of 1.6 million tons of CO2 equivalent from our direct operations through the implementation of energy efficiency projects, the reduction of routine flaring in Chichimene and the use of renewable energy, among others. We also verified a reduction of 1,068,394 tons of CO2e in previous years through a third party certification.

iii.

Sustainable productive projects and biodiversity: this strategy has as its main objective the adequate management of biodiversity and ecosystem services, aiming to work for the welfare of communities. It has four major areas of work: (i) baselines, resilience analysis and biodiversity in project planning and operations, (ii) landscape-scale interventions in priority areas, (iii) compensation and conservation of ecosystems and (iv) solutions based on nature and sustainable use of biodiversity.

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 resilience of ecosystems, 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 this concept into management processes in order to promote economic growth, improve competitiveness, and mitigate risks related to environment and price volatility in raw materials, in the medium term. 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) culture.

Integrated Management of Water Resources: This strategy aims to “incorporate efficient water management into the organization’s value chain, as an enabler of projects and operations, seeking company sustainability, the reduction of environmental impacts and water-related conflicts, and water security in the environment,” based on 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 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 December 2019, the diesel and the gasoline that we distributed in Colombia had an average of 10.9 ppm and 95.3 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 2019 Sustainability Report which is available on our website at: www.ecopetrol.com.co

3.9.4

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.

Refining

During 2019, the Barrancabermeja refinery’s average monthly energy consumption was 58.7 GWhm (gigawatts per hour per month), provided through self-generation. The Cartagena Refinery’s average monthly energy consumption was 63.8 GWhm (gigawatts per hour per month), provided through self-generation.

Production

In October 2019, our first solar complex, “Parque Solar Castilla,” began operations. This plant has a capacity of 21 MW and will prevent the emission of more than 154 thousand tons of CO2. The Castilla solar farm is the largest self-generation plant with non-conventional renewable sources in Colombia and it is expected to supply part of the energy required by the Castilla field.

Further, during 2019, Ecopetrol S.A.’s production segment had an average monthly energy consumption of 389.8 GWhm (gigawatts per hour per month) for its direct operation, from which 70% was provided through self-generation and the remaining 30% with non-regulated energy purchased from the National Transmission System.

The cost of power transmission and the cost of operation and maintenance for the self-generation centers of the Rubiales field were reduced through the renegotiation of the energy transmission contract.

Transport

In 2020, Ecopetrol expects to begin the construction of a second solar complex, San Fernando, in order to supply renewable energy to its transport and production operations. This second farm will have an installed capacity of 50 MW.

3.10

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 30 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 2015 Ecopetrol received a temporary release of capacity from Vitol of 24,000 barrels per day for segment I and II and 14,000 barrels per day for segment III.

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 2019, payments made by Ecopetrol S.A. under these two agreements amounted to US$1,193.37 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. In 2019, Ecopetrol S.A. received an aggregate sum of US$4.62 million under the contract. On December 1, 2019, the parties agreed to extend the term of the agreements for two years until December 1, 2021.

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

In March 1995, Equion and Santiago Oil Company entered into agreements for the transportation of crude oil through the Oleoducto Central S.A. (Ocensa) pipeline. In November 2012, Equion 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%). Equion and Santiago Oil Company kept 5% of transportation rights in Ocensa. In 2014, the transportation fees billed by Ocensa were: Equion (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 2019, Equion paid Ocensa US$3.07 million and Santiago Oil Company US$0.25 million, in each case for transportation fees. Hocol paid Ocensa, as assignee of transportation rights from original shippers, US$28.73 million in 2019.

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 2019, payments made by Ecopetrol S.A. under this agreement amounted to US$89.6 million.

In August 1992, an operation and maintenance agreement was signed for the Vasconia and Coveñas terminals both property of ODC. The duration of this agreement is indefinite, but can be terminated by any party upon six months’ notice. The initial contract included services rendered by Ecopetrol 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. Pursuant to the terms of this agreement, ODC paid approximately US$4.0 million in 2019.

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$12.2 million in 2019.

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$5.6 million in 2019. 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, Equion and Santiago Oil Company each entered into agreements with ODC for the transportation of crude oil through the Vasconia-Coveñas pipeline. The term of each of these agreements is indefinite. As of January 2013, the applicable tariff is the one set by the Ministry of Mines and Energy. In 2019, the transportation fees billed by ODC were: Equion (US$1.0 million), Santiago Oil Company (US$0.002 million) and Hocol (US$0.58 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$90.3 billion in 2019.

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. Payments by Ecopetrol S.A. under this contract were COP$808.7 billion in 2019.

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, Pursuant to the terms of this agreement, ODL paid to Ecopetrol S.A. COP$6.56 billion, plus applicable taxes, in 2019. In addition, pursuant to the partial assignment ODL paid to Cenit COP$0.82 billion, plus applicable taxes, in 2019.

In 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. In 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$7.8 billion plus applicable taxes in 2019.

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. Pursuant to the terms of these agreements, in 2019, Ecopetrol and Hocol paid COP$839.7 billion to Bicentenario S.A.

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$27.4 billion, plus applicable taxes, in 2019.

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. Pursuant to the terms of those agreements, Bicentenario paid to Cenit COP$0.93 billion, plus applicable taxes, in 2019.

In November 2017, the maintenance obligations of the transportation system were partially assigned to Cenit S.A.S. During December 2017 the agreement 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. While this agreement has now been terminated, pursuant to the terms of this agreement, Bicentenario paid to Ecopetrol S.A. COP$8.8 billion, plus applicable taxes, in 2019.

Ecodiesel

Ecopetrol S.A. entered into a supply agreement with Ecodiesel Colombia S.A. (Ecodiesel), a company in which Ecopetrol S.A. 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 S.A. and Ecopetrol S.A. 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 2019 a total of COP$270 billion was paid under this contract.

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 April 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.

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 Hydrocarbon 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, 2019, 2018 and 2017, we purchased the following volumes of crude oil from the ANH corresponding to royalties paid in kind by oil producers in Colombia: 35.4 million barrels, 37.6 million barrels and 40.3 million barrels, respectively. The contract between the ANH and us was extended until April 30, 2020. 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.

3.11

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.

There are three corporate insurance programs covering Ecopetrol S.A. and its subsidiaries. In the text and tables below, we set forth our insurance programs and the companies covered, along with limits and coverage details.

Group 1- Downstream Program: This insurance program provides coverage for downstream (assets and operations) of Ecopetrol S.A. and all of its subsidiaries in excess of their local insurance programs, when applicable. Coverage includes all physical damage and sabotage and terrorism, which were designed to cover downstream operations.

Table 42 – Group 1 Downstream Program (figures in US$ millions)

Limit (eel/agg)⁽¹⁾

Deductible

Ecopetrol

Policies

Onshore

Off shore

On shore

Off shore

Downstream

Reficar

Bioenergy

Esenttia

Property all risk

3.200

N/A

Sabotage and terrorism

600

N/A

0.5

N/A

(1)

Eel: each and every loss. Agg: Aggregate

Group 2 – Upstream Program: This program provides coverage for upstream (assets and operations) of Ecopetrol’s interests and all of its upstream subsidiaries. Coverage includes all physical damage, sabotage and terrorism and control of wells.

Table 43 – Group 2 Upstream Program (figures in US$ millions)

Limit (eel/agg)⁽¹⁾

Deductible

Ecopetrol

Santiago

ECP

ECP Costa

Policies

Onshore

Offshore

Onshore

Offshore

Upstream

Equion

Hocol

Oil

America

Brazil

Afuera

Property all risk

400

⁽²⁾

N/A

0.5

N/A

Sabotage and terrorism

N/A

0.5

N/A

Control of Wells

350 / 75

⁽³⁾

800 / 300

0.25

5/6

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)

Drilling: US$350 million; Production: US$75 million for any well.

Group 3 – Transversal Program: This program provides coverage for downstream, upstream and midstream operations of Ecopetrol and all of its subsidiaries in excess of their local insurance programs. Coverage includes general liability, directors and officers, cargo, crime, charterers’ liability and cyber-attack insurance.

Table 44 – Group 3 Transversal Program (figures in US$ millions)

Limit (eel/agg)⁽¹⁾

Policies

Limit
(eel/agg)⁽¹⁾

Deductible

Ecopetrol

Reficar

Esenttia

Bioenergy

Equion

Hocol

Santiago
Oil

ECP
America

Brazil

Cenit

Ocensa

ODL

OBC

ODC

Third Party Liability

500

Various

Crime

30/60

Various

N/A

Directors & Officers

Various

Cargo

3% dispatch

N/A

Charterers

750

0.02

N/A

Cybers

25/200

Various

N/A

(1)

Eel: each and every loss. Agg: Aggregate.

Our third-party liability insurance policies cover 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 (Cenit, Ocensa, ODL, Bicentenario Pipeline and ODC) have an independent program for its oil transportation companies (including crime and directors & officers policies).

Table 45 – Midstream Program (figures in US$ millions)

Limit (eel/agg)⁽¹⁾

Deductible

Onshore

Offshore

Onshore

Offshore

Cenit

Ocensa

ODL

OBC

ODC

Policies

Property all risk

200⁽²⁾

0.25

0.5

Sabotage and terrorism⁽³⁾

0.075

0.5

Third Party Liability

100

0.35

D&O

100⁽⁴⁾

0.05

Crime

0.1

(1)

Eel: each and every loss. Agg: Aggregate.

(2)

US$200 million each company and an aggregated excess shared limit of US$1.000 million (aggregate for the policy period).

(3)

Does not include Caño Limón – Coveñas (CLC) and Oleoducto Transandino (OTA) systems owned by Cenit.

(4)

Aggregate limit of US$100 million and 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. For the other insurance lines, stand-alone policies have been analyzed to start coverage in 2020.

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. Additional policies are requested from the insurers as they are needed.

3.12

Human Resources/Labor Relations

3.12.1

Employees

As of December 31, 2019, the Ecopetrol Group had 15,157 employees, an increase of 23.95% from 2018. This increase was primarily due to the inclusion of Invercolsa and its subsidiaries’ employees within the consolidated results of the Ecopetrol Group. Most of our employees are located in Colombia. 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, 2019, 2018 and 2017.

Table 46 –Ecopetrol Group’s Employees

	As of December 31,
	2019		2018		2017
	(number of employees)
Ecopetrol S.A.
Exploration and Production
Exploration		227		215		197
Production		2,324		2,258		2,141
Others		501		758		639
Total Exploration and Production		3,052		3,231		2,977
Downstream
Refining		2,661		2,696		2,669
Marketing		145		136		132
Others		37		74		67
Total Downstream		2,843		2,906		2,868
Transport		860		798		817
Others		796		351		330
Total Operations		7,551		7,286		6,992
Corporate		2,536		2,417		2,290
TOTAL ECOPETROL S.A.		10,087		9,703		9,282

	As of December 31,
	2019		2018		2017
	(number of employees)
Ecopetrol America LLC.		66		68		70
Bioenergy S.A.S.		478		441		358
Bioenergy Zona Franca S.A.S.		287		279		316
Hocol S.A.		249		221		205
Equion Energía Limited		242		284		298
Oleoducto Central S.A.		288		275		290
Oleoducto de Colombia S.A.		7		3		1
Oleoducto de los Llanos S.A.		79		75		68
Oleoducto Bicentenario de Colombia S.A.S.		0		0		0
Ecopetrol del Perú S.A.		0		0		0
Ecopetrol Costa Afuera de Colombia S.A.S.		0		0		6
Refinería de Cartagena S.A.S.		143		153		185
Ecopetrol Óleo e Gás do Brasil Ltda.		31		16		16
Polipropileno del Caribe S.A. (now Esenttia S.A.)		458		428		417
Cenit Transporte y Logistica de Hidrocarburos S.A.S.		366		282		217
Invercolsa		2,371		n/a		n/a
Ecopetrol Energía S.A. E.S.P		5		0		0
TOTAL		15,157		12,228		11,729

The number of Polipropileno del Caribe S.A. (now Esenttia S.A.) employees reported in 2017 was re-stated to include Esenttia Masterbach’s employees. Essentia Masterbach is a subsidiary of Esenttia S.A.

As of December 31, 2019, the subsidiaries Ecopetrol USA Inc, Ecopetrol Permian LLC, 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 Glod 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 2019, Ecopetrol S.A. has extended 1,248 housing loans for a total of COP$292 billion and 2,527 general-purpose loans for a total of COP$25.9 billion. In 2019, Ecopetrol S.A. also provided on-site and external training and development, which totaled to COP$38.9 billion, and it extended a total of COP$171.7 billion in subsidies for education.

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

There are no executive officers with loans from Ecopetrol.

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.

3.12.2

Collective Bargaining Arrangements

Ecopetrol S.A.

A collective bargaining agreement between us and our main labor unions governs labor relations with our unionized employees, which amounted to 5,131 employees as of January 1, 2020. The agreement also governs our labor relations with other 2,836 non-unionized employees who, according to current labor legislation, are beneficiaries of the collective bargaining agreement.

We currently have ten 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);

Asociación Sindical de Trabajadores de la Industria del Petróleo – ASTIP (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)

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

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); and

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 2019, 50.9% 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 79.0% of Ecopetrol S.A.’s total workers. Out of that 79.0%, 28.1% 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 2019, 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 249 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.

Financial Review

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

Our consolidated financial statements were consolidated line by line and all transactions and significant balances between affiliates 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 international prices of crude oil, international prices for refined products and local prices for natural gas, as well as sales 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 segment. 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 product prices in the international market, change in environmental regulations, 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 market. We also process crude oil at Barrancabermeja and Reficar 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 linked to international benchmarks. Local sales represent 49% of our total revenues, on average, for the past three years.

International Sales and Prices

Our foreign sales represented 51% 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 linked to international benchmarks primarily 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.

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$614,336 million in 2019.

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 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 us was extended until April 30, 2020.

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

4.2.1

Taxes

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

A unified income tax rate was set at 33% for 2018.

An income tax surtax for profits above COP$800 million was set at 4% for 2018.

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 will be 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 will be 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.

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:

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, 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$15,000 per ton of CO2.

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

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

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:

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%.

A wealth tax was created to apply for fiscal years 2020 and 2021. Tax accrues for the following taxpayers (Part A below) whose net equity as of January 1, 2020 was equal to or greater than COP$5,000,000,000:

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.

Part B: Tax Accrual Rules

The wealth tax will accrue 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:

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

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 will be 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.

4.2.2

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 Ecopetrol Group companies whose functional currency is the Colombian Peso. The conversion effect from U.S. dollar to Colombian Peso is mainly due to local sales and exports of crude oil, natural gas and refined products whose prices are based on benchmarks quoted in U.S. dollars. Therefore, they are exposed to foreign currency exchange risk on revenues, capital expenditures and financial instruments that are denominated in a currency other than its functional currency.

Fluctuations in the U.S. dollar-Colombian Peso exchange rate have effects on our consolidated financial statements. As crude oil is priced in U.S. dollars, fluctuations in the exchange rate of the Colombian Peso against the U.S. dollar may have a significant impact on revenues, cost, monetary assets and liabilities held in foreign currency.

An appreciation of the Colombian Peso has a negative impact on our results of operations because our revenues from exports of crude oil, natural gas and refined products are primarily expressed in U.S. dollars. Costs of imported products and contracted services expressed in U.S. dollars will also be lower when expressed in Colombian Pesos, but on balance, our operating income in Colombian Pesos tends to decline when the Colombian Peso appreciates, other factors being equal. The appreciation of the Colombian Peso against the U.S. dollar also decreases the debt service requirements of our Companies with the Colombian Peso as their functional currency, 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, interest costs, and operating income, all tend to increase.

During 2019 and 2018, the Colombian Peso depreciated on average 11.02% and 0.2% against the U.S. dollar. During 2017, the Colombian Peso appreciated on average 3.35% against the U.S. dollar. Additionally, as of December 31, 2019 and December 31, 2018, the Colombian Peso/U.S. dollar exchange rate had depreciated 0.84% and 8.91% respectively from the rate a year earlier. In contrast, as of December 31, 2017, the Colombian Peso/U.S. dollar exchange rate appreciated 0.56% from the rate a year earlier.

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. In 2017, our consolidated debt in foreign currency decreased by a total of US$2,582 million mainly as a result of prepayments of foreign currency denominated loans of US$2,400 million and amortization of foreign currency capital expenditures.

As of December 31, 2019, our U.S. dollar denominated total debt was US$10,308 million, which we recognize in our 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, US$10,244 million relates 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. has an exchange rate gain. Some of the Ecopetrol Group 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. On the asset side, when the financial statements of the 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 71.6% (US$7,331 million) of Ecopetrol S.A.’s debt in U.S. dollars, as of December 31, 2019, 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, 2019, Ecopetrol Group companies have the equivalent of a net U.S. dollar liability position of US$371 million after the implementation of the natural hedging previously mentioned above, neutralizing the effect of exchange rate fluctuations in their results for the year.

4.2.3

Effects of Inflation

The average annual rate of inflation in Colombia for the past ten years is 3.85%. It increased in 2019 as compared to 2018. As measured by the general consumer price index, average annual inflation in Colombia for the years ended December 31, 2019, 2018 and 2017 was 3.80%, 3.18%, and 4.09%, respectively. The increase in inflation in 2019 is mainly due to the “El Niño” weather phenomenon, the indirect tax increase, the devaluation of the Colombian peso against the dollar and demand pressures. Cost inflation in the prices of goods, raw materials, interest cost of debt 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.

4.2.4

Effects of Crude Oil and Refined Product Prices

The average price of ICE Brent crude in 2019 was US$64.2 as compared to US$71.7 per barrel in 2018 and US$54.7 per barrel in 2017. See section Strategy and Market Overview.

Ecopetrol’s average crude oil basket price relative to ICE Brent reported a discount of US$5.6 per barrel in 2019, a lower discount than the US$8.50 in 2018 and US$6.90 in 2017 due to: (i) a better valuation of our heavy crudes primarily due to a decrease in Canadian and Venezuelan supply (ii) our knowledge of the refining market for heavy and intermediate crudes, (iii) the ability to identify and capture opportunities in the United States and Asia, and (iv) the incorporation of new refinery customers in those markets. Our average price crude oil basket was US$58.6 per barrel in 2019 as compared to US$63.2 per barrel in 2018 and US$47.8 per barrel in 2017, which represents a decrease of US$4.6 per barrel in 2019 compared to 2018.

In addition, Ecopetrol’s average products basket price relative to ICE Brent reported a discount of US$5.6, US$5.6 and US$7.9 per barrel in 2019, 2018 and 2017. In 2019, the spread in the refined product basket versus the Brent price remained the same as that of 2018. This was largely due to better asphalt sales prices and the behavior of diesel crack that partially offset weak gasoline prices. Furthermore, there was a positive price effect due to the composition of the basket as more valuable products were sold in 2019 as compared to 2018.

In the Operating Results section below, we present the impact of the price increase 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 17 to our consolidated financial statements.

In addition, as described in Section 2.1.2 Strategy and Market Overview—2020 Investment Plan above, on March 16, 2020, Ecopetrol announced a set of actions to address current challenging market conditions, which have resulted, among other matters, in a 60% decline in the Brent crude price as compared to the end of 2019, due to external shocks including the strong increase in the supply of oil and the spread of COVID-19. See the section entitled Trend Analysis and Sensitivity Analysis—Trend Analysis for further information.

4.3

Accounting Policies

Our consolidated financial statements for the years ended December 31, 2019, 2018 and 2017 were prepared in accordance with IFRS. The detail of the accounting policies is described in Note 4 to our consolidated financial statements.

From January 1, 2019, we were required to adopt IFRS 16 – Leases and from January 1, 2018, we were required to adopt IFRS 9 – Financial Instruments and IFRS 15 – Operating income. Our financial statements as of and for the years ended December 31, 2019 and 2018, reflect the adoption of these new standards, which 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 Group to our consolidated financial statements included in this annual report.

4.4

Critical Accounting Judgments and Estimates

Critical accounting policies are those policies that require us to exercise judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations. The accounting judgments and estimates we make in these contexts require us to calculate variables and make assumptions about matters that are highly uncertain. In each case, if we had made other estimates, or if changes in the estimates occur from period to period, our financial condition and results of operations could be materially affected.

See Note 4 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 changed or different estimates would not be material to our financial presentation.

4.5

Operating Results

The following discussion is based on information contained in our audited consolidated financial statements and should be read in conjunction therewith.

4.5.1

Consolidated Results of Operations

The following table sets forth components of our income statement for the years ended December 31, 2019, 2018 and 2017.

Table 47 – Consolidated Income Statement

Income Statement	For the Years ended December 31,									% Change
(Colombian Pesos in millions)	2019			2018			2017			2019/2018			2018/2017
Revenue		71,488,512			68,603,872			55,954,228			4.2			22.6
Cost of sales		44,972,360			41,184,379			36,908,325			9.2			11.6
Gross Profit		26,516,152			27,419,493			19,045,903			(3.3	)		44.0
Operating expenses		3,726,557			4,592,445			4,185,186			(18.9	)		9.7
Impairment (recovery) of non-current assets, net		1,762,437			368,634			(1,311,138	)		378.1			(128.1	)
Operating Income		21,027,158			22,458,414			16,171,855			(6.4	)		38.9
Finance results, net		(1,670,494	)		(2,010,375	)		(2,495,731	)		(16.9	)		(19.4	)
Share of profit of companies		366,904			165,836			93,538			121.2			77.3
Income before income tax		19,723,568			20,613,875			13,769,662			(4.3	)		49.7
Income tax		(4,718,413	)		(8,258,485	)		(5,800,268	)		(42.9	)		42.4
Net Income		15,005,155			12,355,390			7,969,394			21.4			55.0
Net income attributable to:
Company’s shareholders		13,744,011			11,381,386			7,178,539			20.8			58.5
Non-controlling interest		1,261,144			974,004			790,855			29.5			23.2
Net Income		15,005,155			12,355,390			7,969,394			21.4			55.0

4.5.1.1

Total Revenues

The following table sets forth our principal sources of third-party revenues by business segment for the years ended December 31, 2019, 2018 and 2017. An explanation of how we classify our operations into business segments is included in section 4.5.1.8 below.

Table 48 – Third-Party Revenues by Business Segment

	2019						2018						2017						Change Sales Revenues (%)
Revenue by segment	Volume (barrels equivalent)		Average price US dollars/ barrels		Sales revenues (Colombian Pesos in millions)		Volume (barrels equivalent)		Average price US dollars / barrels		Sales revenues (Colombian Pesos in millions)		Volume (barrels equivalent)		Average price US dollars / barrels		Sales revenues (Colombian Pesos in millions)		2019/2018			2018/2017
Local Crude oil		2,232,087		48,6		356,857		2,919,416		60.8		550,479		6,629,362		46.5		909,871		(35.2	)		(39.5	)
Foreign Crude oil		147,692,547		58,7		28,461,601		143,208,235		63.2		26,898,737		151,619,346		47.8		21,426,666		5.8			25.5
Natural gas local		28,798,105		23,8		2,256,123		28,065,889		22.5		1,885,846		26,998,537		22.8		1,815,754		19.6			3.9
Foreign natural gas		506,556		16,6		27,255		530,945		17.7		27,899		618,022		17.7		32,303		(2.3	)		(13.6	)
Other income⁽¹⁾		3,788,550		-		193,282		3,216,650		-		749,939		3,412,568				819,726		(74.2	)		(8.5	)
Exploration and production sales		183,017,845				31,295,118		177,941,135				30,112,900		189,277,835				25,004,320		3.9			20.4
Local refined products		111,095,596		74,5		27,170,498		108,781,359		81.9		26,354,549		106,891,163		67.2		21,187,091		3.1			24.4
Foreign refined products		44,007,684		62,3		8,977,662		41,577,284		68.6		8,485,932		38,268,394		53.2		6,005,556		5.8			41.3
Foreign Crude Oil		289,289		62.6		61,995		-		-		-		341,366		53.0		52,397		100.0			(100.0	)
Residential gas ⁽²⁾		145,068		100.8		49,420		-		-		-		-		-		-		100.0			-
Other income⁽¹⁾		-		-		133,895		-		-		107,467		-				98,315		24.6			9.3
Refining and petrochemicals		155,537,637				36,393,470		150,358,643				34,947,948		145,500,923				27,343,359		4.1			27.8
Transportation services		-				3,799,924		-				3,543,024		-				3,606,549		7.3			(1.8	)
Transportation and logistics		-		-		3,799,924		-		-		3,543,024		-		-		3,606,549		7.3			(1.8	)
Total sales		338,555,482				71,488,512		328,299,778				68,603,872		334,778,758				55,954,228		4.2			22.6
Crude Oil		150,213,923		58,6		28,880,453		146,127,651		63.2		27,449,216		158,590,074		47.8		22,388,934		5.2			22.6
Natural gas		29,304,661		23,7		2,283,378		28,596,834		22.4		1,913,745		27,616,559		22.7		1,848,057		19.3			3.6
Residential gas⁽²⁾		145,068		100,8		49,420		-		-		-		-		-		-		100.0			-
Refined products		158,891,830		69,8		36,341,442		153,575,293		77.3		35,590,420		148,572,125		62.7		28,012,373		2.1			27.1
Transportation services and others		-				3,933,819		-				3,650,491		-				3,704,864		7.8			(1.5	)
Total sales		338,555,482				71,488,512		328,299,778				68,603,872		334,778,758				55,954,228		4.2			22.6

(1)

In the case of the exploration and production segment, other income corresponds to services and sales of refined products (mainly LPG and asphalt) allocated to our exploration and production segment. In the case of the refining and petrochemicals segment, other income corresponds to industrial services.

(2)

As a result of the ruling issued by the Colombian Supreme Court of Justice in October 2019, we increased our shareholding in Invercolsa from 43.35% to 51.88%, which represents a change in control of that entity; therefore, Invercolsa has become our subsidiary rather than an affiliate, and we consolidate Invercolsa into our consolidated financial statements as of such date. Invercolsa is involved in the commercialization, distribution and transport of natural gas and LPG. The detail of this transaction is described in Notes 2 and 12 to out consolidated financial statements.

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 volumes transported. 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.

In 2018, total revenues increased by 22.6% as compared to 2017, primarily as a result of: (i) a COP$12,898,392 million increase in revenues mainly due to the 32.2%, or US$15.4 per barrel increase of our average crude oil basket price, which in turn was primarily the result of the better performance of the Brent crude benchmark price and the 23.3%, or US$14.6 per barrel increase, of our average refined products basket price, which in turn was primarily due to strengthening of diesel prices, and (ii) the 0.2% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$2,951.15 /US$1.00 in 2017 to an average exchange rate of COP$2,956.55/US$1.00 in 2018, resulting in an increase in sales revenue from exports, which represented an increase of COP$297,937 million. This increase was partially offset by: (i) a COP$407,261 million revenue decrease attributable to the decrease in our sales volume explained below and (ii) a COP$139,424 decrease in services revenue from our transportations and logistics segment, primarily due to the resolution of the disagreement regarding the P135 Project tariffs leading to lower tariffs, which was partially offset by higher volumes transported through the San Fernando – Apiay system and the expansion of the P135 Project.

The decrease of our sales volume in 2018 as compared to 2017 was the result of (i) the 7.9%, or 12.5 mbe, decrease in our crude sales volume was primarily the result of lower crude exports due to a greater allocation of domestic crudes to supply Reficar in order to replace imports. This decrease was partially offset by (i) the 3.4%, or 5.0 mbe, increase in refined products volumes due to greater refining throughput and (ii) the 3.5%, or 1.0 mbe, increase in natural gas sales volume, primarily due to greater demand and active incremental sales.

4.5.1.2

Cost of Sales

Our cost of sales was principally affected by the factors described below. See Note 25 to our consolidated financial statements for more detail.

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:

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.

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.

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.

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.

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.

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.

Cost of sales in 2018 was COP$41,184,379 million, representing a COP$4,276,054 million or 11.6% increase as compared to 2017, primarily as a result of the following factors:

A COP$3,225,596 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) higher average purchase prices due to the COP$5,359,427 million increase in international benchmark prices for crude oil, natural gas and refined products, (ii) a COP$59,117 million increase in natural gas purchase volume, primarily to ensure the supply to our refineries during periods of ongoing maintenance in our natural gas production fields and (iii) a COP$52,233 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. This increase was partially offset by (i) a COP$1,478,718 million decrease in crude oil volumes purchased due to lower imports of light crude used by Reficar that were replaced by our own crude volumes and (ii) a COP$766,463 million decrease in products purchase volume, primarily medium distillates and gasolines, primarily due to higher production at Barrancabermeja and Reficar in order to supply the local market.

A COP$700,715 million increase in maintenance cost and contracted services, primarily due to: (i) additional costs for community management and well integrity and (ii) services contracted for water treatment, workover campaigns, surface maintenance, as well as costs associated with higher production and the increase in the throughput of our refineries.

A COP$477,829 million increase in inventory consumption associated with higher level of sales volumes in 2018 compared to 2017.

A COP$290,590 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 4.4% salary increase in 2018 and (iii) an increase in the number of employees.

A COP$177,158 million increase in the cost of processing materials and operating supplies due to an increase in our operational activities.

The factors mentioned above were partially offset by:

A COP$512,341 million decrease in depreciation, amortization and depletion charges due to (i) an increase in hydrocarbon proved developed reserves in 2018 as compared to 2017, which in turn led to a decrease in depreciation expenses. This decrease was partially offset by (i) higher production levels associated with the results of our drilling campaign, and (ii) increase in our level of capital expenditures.

A COP$83,493 million decrease in other minor items.

The factors mentioned above were partially offset by a COP$231,222 million increase in inventories and an increase in unit costs associated with the increase of the Brent price of crude oils and products.

4.5.1.3

Operating Expenses before Impairment of Non-Current Assets Effects

Operating expenses and selling, general and administrative expenses before taking into account the 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 26 and 27 to our consolidated financial statements for more detail).

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 October 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 as of such date. According to IFRS “Business combinations,” the investment in Invercolsa must be recognized at fair value.

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:

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 Magdalena Medio - Guillermo Gaviria Bridge trunk road in Barrancabermeja.

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.

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

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).

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

Operating expenses and selling, general and administrative expenses before taking into account the impairment of non-current assets amounted to COP$4,592,445 million in 2018, a COP$407,259 million or 9.7% increase as compared to 2017, mainly as a result of the following factors (see Notes 25 and 26 to our consolidated financial statements for more detail).

A COP$463,160 million decrease in other income due to the acquisition of an additional 11.6% interest at the K2 field in the Gulf of Mexico, which generated a gain due to the increase in the book value of the asset above the price paid for the additional interest. This non-cash gain is the result of the fair value valuation of the interest acquired, reflecting a price increase between the date of the deal and the price outlook by the end of 2017, among other factors.

A COP$188,304 million increase in general expenses due to the negative impact in our midstream segment of attacks by third parties and higher expenses incurred in respect of environmental incidents in our upstream segment.

A COP$133,828 million decrease in other income due to the sale of the following fields in 2017: Sogamoso, Río Zulia, Río de Oro and Puerto Barco, Santana, Nancy Maxine Burdine and Valdivia Almagro.

A COP$45,439 million increase in exploratory expenses as a result of a (i) higher seismic activity and (ii) the recognition of spending on exploratory activity mainly at the León 1, León 2, Bonifacio, Huron and Payero wells in 2018.

This increase was partially offset by:

A COP$214,563 million decrease in taxes mainly due to the elimination of the wealth tax since 2018.

A COP$72,318 million decrease in expenses related to our gas pipeline availability BOMT contracts with Transgas that terminated in August 2017.

A COP$136,591 million decrease in other minor items, particularly a reversal of a provision we had set aside in respect of the tariff dispute we were having in connection with the P135 Project

Each of our operating segments bears the costs and expenses incurred for product use and marketing and each segment assumes administrative expenses and all non-operational transactions related to its activity. Discussion of operating expenses by business segment is included in the section Financial Review—Operating Results—Consolidated Results of Operations—Segment Performance and Analysis.

4.5.1.4

Impairment of Non-Current Assets

The impairment of our non-current assets includes expenses (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 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 volumes transported. (See Notes 3.2, 4.12 and 17 to our consolidated financial statements for more detail).

In 2019, we recognized impairment losses of non-current assets of COP$1,762,437 as compared to impairment losses of non-current assets of COP$368,634 million in 2018 and a COP$1,311,138 million net reversal of impairment of non-current assets in 2017. 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 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 2019 impairment loss, net of non-current assets of COP$1,762,437, corresponds to the net result of:

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.

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.

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.

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:

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.

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.

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.

The partial reversal of the impairment recorded in 2017 is primarily the result of an improved hydrocarbon prices outlook, incorporation of new reserves, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, favorable refining margins outlook, market conditions affecting the discount rate and technical operational capacity, among other factors.

For more information regarding impairment by segment, see the section Financial Review—Operating Results—Consolidated Results of Operations—Segment Performance and Analysis.

4.5.1.5

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$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.

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.

Finance results, net, amounted to a loss of COP$2,010,375 million in 2018 as compared to a loss of COP$2,495,731 million in 2017. This decrease in loss was mainly due to:

The positive impact resulting from the 8.9% depreciation of the Colombian Peso against the U.S. dollar on our U.S. dollar net asset position. In 2018, our exchange rate gain was COP$372,223 million, as compared to a gain of COP$5,514 million in 2017.

A COP$84,265 million decrease in financial costs related to long term obligations mainly due to a lower interest rate on our asset retirement obligation.

A COP$13,420 million increase in interest expenses, primarily the result of premiums paid in respect of prepayments of debt in 2018 which will generate interest savings in the first half of 2019, which was partially offset by lower interest expenses given (i) use of cash surpluses to pre-pay foreign currency-denominated loans totaling US$2,006 million and local loans totaling the equivalent of US$440 million in 2018 and (iii) a decrease in interest on local currency-denominated loans with a lower interest rate indexed to the Consumer Price Index (CPI).

A COP$47,802 million increase in losses related to other minor financial items.

For more details on our financial income and expenses see Note 28 to our consolidated financial statements for more details.

4.5.1.6

Income Tax

Income taxes amounted to COP$4,718,413 million in 2019, COP$8,258,485 million in 2018 and COP$5,800,268 million in 2017. The above is equivalent to an effective tax rate of 23.9%, 40.1% and 42.1% in 2019, 2018 and 2017, respectively.

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).

The decrease in the effective tax rate from 2017 to 2018 was mainly due to: (i) the positive impact of Law 1943, 2018 that led to higher deferred asset taxes, primarily at Reficar and Bioenergy, given the lower presumptive income rate of 0% starting in 2021, which will allow them to offset higher tax losses from previous years; (ii) the 300 basis points nominal tax decrease as a consequence of the 2016 tax reform; and (iii) an increase in the contribution of our income from Reficar, which is taxed at a lower nominal rate of 15%. This decrease was partially offset by (i) a non-deductible expense effect, primarily due to exploratory activity at Ecopetrol América Inc.’s León 1 and 2 wells and (ii) exchange rate effects on tax bases for companies with the U.S. dollar as their functional currency but with profit or tax losses in Colombian pesos, which required them to recognize a deferred taxes according to IAS 12.41 between the carrying amount 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 December 31, 2018.

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

4.5.1.7

Net Income (Loss) Attributable to Owners of Ecopetrol

As a result of the foregoing, in 2019, net income attributable to owners of Ecopetrol was COP$13,744,011. In 2018, net income attributable to owners of Ecopetrol was COP$11,381,386 million whereas, in 2017, net income attributable to owners of Ecopetrol was COP$7,178,539 million.

4.5.1.8

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.

The following tables present our revenues and net income by business segment for the years ended December 31, 2019, 2018 and 2017:

Table 49 – Revenues by Business Segment

	Year ended December 31,									% Change
	2019			2018			2017			2019/2018			2018/2017
	(Colombian Pesos in millions)
Exploration and Production		52,667,990			50,372,764			36,494,934			4.6			38.0
Third parties		31,295,118			30,112,900			25,004,320			3.9			20.4
Local crude oil		356,857			550,479			909,871			(35.2	)		(39.5	)
Foreign crude oil		28,461,601			26,898,737			21,426,666			5.8			25.5
Local natural gas		2,256,123			1,885,846			1,815,754			19.6			3.9
Foreign natural gas		27,255			27,899			32,303			(2.3	)		(13.6	)
Other income		193,282			749,939			819,726			(74.2	)		(8.5	)
Inter-segment net operating revenues		21,372,872			20,259,864			11,490,614			5.5			76.3
Refining and Petrochemicals		38,770,806			37,011,373			28,644,016			4.8			29.2
Third parties		36,393,470			34,947,948			27,343,359			4.1			27.8
Local refined products		27,170,498			26,354,549			21,187,091			3.1			24.4
Foreign refined products		8,977,662			8,485,932			6,005,556			5.8			41.3
Foreign crude oil		61,995			-			52,397			100.0			(100.0	)
Natural gas local		49,420			-			-			100.0			-
Other income		133,895			107,467			98,315			24.6			9.3
Inter-segment net operating revenues		2,377,336			2,063,425			1,300,657			15.2			58.6
Transportation and Logistics		13,070,736			11,354,167			10,598,064			15.1			7.1
Third parties		3,799,924			3,543,024			3,606,549			7.3			(1.8	)
Inter-segment net operating revenues		9,270,812			7,811,143			6,991,515			18.7			11.7
Eliminations of consolidations		(33,021,020	)		(30,134,432	)		(19,782,786	)		9.6			52.3
Total revenues		71,488,512			68,603,872			55,954,228			4.2			22.6

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 50 – Operating and Net Income by Business Segment

	Year ended December 31,									% change
	2019			2018			2017			2019/2018			2018/2017
	(Colombian Pesos in millions)
Exploration and Production
Operating Income		11,601,485			15,899,337			8,061,484			(27	)		97
Net income attributable to owners		9,382,129			9,930,519			3,820,501			(6	)		160
Refining and Petrochemicals
Operating Income		1,142,204			(757,793	)		1,362,934			(251	)		(156	)
Net income attributable to owners		117,708			(1,973,075	)		358,859			(106	)		(650	)
Transportation and Logistics
Operating Income		8,366,747			7,317,513			6,748,047			14			8
Net income attributable to owners		4,244,860			3,424,234			2,999,978			24			14
Eliminations in consolidation
Operating Income		(83,278	)		(643	)		(610	)		12,851			5
Net income attributable to owners		(686	)		(292	)		(799	)		135			(63	)
Ecopetrol consolidated
Operating Income		21,027,158			22,458,414			16,171,855			(6	)		39
Net income attributable to owners		13,744,011			11,381,386			7,178,539			21			59

4.5.1.9

Exploration and Production Segment Results

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:

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.

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.

In 2018, exploration and production segment sales were COP$50,372,764 million, compared to COP$36,494,934 million in 2017. In 2018, our segment sales increased by 38.0% as compared with 2017 mainly as a result of:

Increased sales of crude oil to third parties, which increased by 20.4% in 2018 as compared to 2017 primarily due to: (i) an increase in the price of our crude oil basket of US$15.4 per barrel, (ii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars, (iii) an increase of 1.0 mmboe in sales of natural gas mainly due to greater demand and management of incremental sales. This increase was partially offset by the decrease in local and exports sales of crude oil (12.1 mmbls) mainly due to an increase in the use of local crude by Reficar and Barrancabermeja for their operations.

Increased inter-segment revenues, which increased by 76.3% in 2018 as compared to 2017 mainly due to: i) higher production volumes as a result of drilling campaigns, emphasized deliveries of crude oil in order to supply Reficar and Barrancabermeja in order to replace imported crudes and ii) an increase in the price of our crude oil basket due to the better performance of the Brent crude benchmark prices.

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 in the exploration and production segment. In addition, this segment’s costs are impacted by the purchases of crude oil from ANH and third parties, naphtha for dilution and transportation services.

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

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.

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.

100

In 2018, the cost of sales for this segment increased by 22.5% as compared with 2017, due to the net effect of:

Fixed costs increasing by 10.1%, or COP$815,784 million, in 2018 as compared to 2017, mainly due to (i) an increase in contracted services mainly due to the reactivation of the activity at the CPO-09 Block, an environmental audit contract primarily at the Rubiales and Cira-Teca fields, as well as water treatment expenses at the Magdalena Medio and Meta fields, (ii) an increase in maintenance and operating materials due to greater well preventive interventions, mainly in assets of the Central and Orinoquía Regional Vice-Presidencies, as well as an increase in maintenance in the K2 field for corrosion management, and (iii) 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.

Variable costs increasing by 28.0%, or COP$5,113,316 million, in 2018 as compared to 2017, as a result of (i) an increase of purchases of crude oil due to the increase in international benchmark prices, (ii) higher transportation costs due to the use of alternative oil pipelines to transport crude oil given attacks against the Caño Limón - Coveñas pipeline, (iii) an increase in operating activity costs such us electricity, process materials and services contracted associated with higher production. This increase was partially offset by lower depreciation and amortization mainly due of an increase in hydrocarbon proved developed reserves in 2018 as compared to 2017, which led to a decrease in depreciation expenses.

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.

In 2018, operating expenses before impairment of non-current assets increased by 30.9% as compared to 2017, primarily as a result of (i) the bargain purchase in our acquisition of an additional stake in the K2 field in 2017, (ii) the sale of the following fields in 2017: Sogamoso, Río Zulia, Río de Oro and Puerto Barco, Santana, Nancy Maxine Burdine and Valdivia Almagro, (iii) the recognition of exploratory activity at Ecopetrol America LLC’s León 1 and 2 wells and Hocol’s Bonifacio, Hurón and Payero wells in 2018, (iv) an increase in operation expenses related to the Lizama’s well environmental incident that occurred in the first half of 2018. This increase was partially offset by (i) the elimination of the wealth tax since 2018 and (ii) a decrease in exploratory activity at the Kronos-1, Parmer-1, Warrior 2, Lunera-1, Brama-1, Molusco-1, Godric, Dumbo and Pollera wells recognized in 2017.

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.

The net reversal of impairment of non-current assets recognized in the exploration and production segment in 2018, which totaled COP$785,940 million in 2018 as compared to COP$183,718 million in 2017, increased by 327.8% as compared to 2017 mainly due to due to the incorporation of new reserves, improved short-term hydrocarbon price outlook and improvements in technical operational capacity.

The segment recorded net income attributable to owners of Ecopetrol of COP$9,382,129 million in 2019 as compared to net income attributable to owners of Ecopetrol of COP$9,930,519 million in 2018 and net income attributable to owners of Ecopetrol of COP$3,820,501 million in 2017.

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Lifting and Production Costs

The aggregate average production cost, on a Colombian Peso basis, increased to COP$29,275 per boe during 2019 from COP$27,782 per boe during 2018. The aggregate average lifting cost, on a Colombian Peso basis, increased to COP$28,100 per boe during 2019 from COP$25,614 per boe during 2018. These increases are primarily due to:

An increase in energy costs due to (i) higher prices in unit gas cost, (ii) an increase in the energy rate due to the impact of a lower supply of hydraulic energy, an increase in production and an increase in our injection of water barrels and (iii) an increase in the number of drilled wells, partially offset by (iv) energy matrix efficiencies.

An increase in subsoil maintenance due to the increase in the cost per intervention, in line with (i) an increase in the number of interventions of greater complexity, (ii) an increase in tariffs mainly due to the depreciation of the Colombian peso against the U.S. dollar and higher labor costs and (iii) higher costs of operation mainly due to a salary adjustment and an increase in the number of employees.

An increase in contracted association services due to increased production volumes of crude oil and associated water.

On a dollar basis, the aggregate average production cost decreased to US$8.92 per boe in 2019 from US$9.40 per boe in 2018 primarily due to a 0.11% depreciation of the Colombian Peso against the U.S. dollar in 2019. Production volumes also increased compared to 2018 by 5.4 mboed.

On a dollar basis, the aggregate average lifting cost, decreased to US$8.56 per boe in 2019 from US$8.66 per boe in 2018 also due to a 0.11% depreciation of the Colombian Peso against the U.S. dollar in 2019.

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 in our production process or the output that we sell 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, 2019, 2018 and 2017.

Table 51 – Crude Oil and Natural Gas Average Prices and Costs

	2019		2018		2017
Crude Oil Average Sales Price (U.S. dollars per barrel)⁽¹⁾		58.6		63.2		47.8
Crude Oil Average Sales Price (COP$ per barrel)⁽¹⁾		192,262		187,845		141,175
Natural Gas Average Sales Price (U.S. dollars per barrel equivalent)		23.7		22.4		22.7
Natural Gas Average Sales Price (COP$ per barrel equivalent)		79,605		66,922		66,919
Aggregate Average Unit Production Costs (U.S. dollars per boe)⁽²⁾		8.92		9.40		8.02
Aggregate Average Unit Production Cost (COP$ per boe)⁽²⁾		29,275		27,782		23,684
Aggregate Average Lifting Costs (U.S. dollars per boe)^(3)(4)(5)		8.56		8.66		7.65
Aggregate Average Lifting Costs (COP$ per boe)^{(3)(4) (5)}		28,100		25,614		22,585

(1)

Corresponds to our average sales price on a consolidated basis.

(2)

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.

(3)

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.

(4)

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.

(5)

As a result of the evaluation of control over companies under IFRS, Ecopetrol does not consolidate Savia Perú and Equion.

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4.5.1.10

Transportation and Logistics Segment Results

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.

In 2018, our transportation and logistics segment sales were COP$11,354,167 million compared to COP$10,598,064 million in 2017. The 7.1% increase in 2018 as compared with 2017 was mainly due to (i) higher volumes of crude oil transported by our pipelines which was primarily due to reversal cycles through the Bicentenario pipeline, the startup of the San Fernando-Apiay System and the expansion of the P135 Project, (ii) an increase in the volume of refined products transported mainly due to the increase in production at Barrancabermeja and Reficar, (iii) the positive effect on our U.S. dollar-indexed transportation fees resulting from the depreciation of the Colombian peso against the U.S. dollar. This increase was partially offset by a decrease in revenue due to the resolution of the disagreement regarding the P135 Project tariffs, leading to lower tariffs.

The cost of sales for our transportation and logistics segment is mainly related to: (i) project costs associated with the maintenance of transportation networks and (ii) operating costs related to these systems, including the costs of labor, energy, fuels and lubricants and others.

The cost of sales amounted to COP$3,738,194 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 volumes transported, (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.

The cost of sales amounted to COP$3,402,087 million in 2018 as compared to COP$3,271,835 million in 2017. The cost of sales for this segment increased by 4.0% in 2018 as compared with 2017 mainly due to (i) an increase in costs associated with higher volumes transported, primarily due to the reasons described above and (ii) increased consumption of materials, supplies and depreciation resulting from the start of the San Fernando – Apiay system at Cenit since January 2018 and the expansion of the P135 Project since July 2017.

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 Equion and Santiago. See Business Overview - Related Party and Intercompany Transactions.

In 2018, operating expenses before the impairment of non-current assets decreased by 27.1% as compared to 2017 due to: (i) a reversal of a provision we had set aside in respect of tariff dispute we were having in connection with the P135 Project and (ii) the elimination of wealth tax since 2018. This decrease was partially offset by higher expenses associated with attacks on our infrastructure by third parties.

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 impairment losses of non-current assets recognized in the segment in 2018, totaled COP$169,870 million in 2018 as compared to an impairment recovery of COP$59,455 million in 2017. The difference in impairment from a reversal in 2017 to a loss in 2018 was primarily the result of a decrease in the forecast of the volume to be transported by the southern cash generating unit and an increase in investment needs to mitigate the operative risk of our transportation systems.

The segment recorded net income attributable to owners of Ecopetrol of COP$4,244,860 million in 2019 as compared to net income of COP$3,424,234 million in 2018 and COP$2,999,978 million in 2017.

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4.5.1.11

Refining and Petrochemicals Segment Results

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.

In 2018, the refining and petrochemical segment sales were COP$37,011,373 million compared to COP$28,644,016 million in 2017. In 2018, sales of refined products and petrochemicals increased by 29.2% as compared with 2017, mainly due to: (i) an increase in our average products basket price due to the increase in international prices and (ii) increased sales volumes, primarily of medium distillates, and gasoline in Colombia and international markets, due to higher refining throughput and positive operating performance at our refineries.

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$37,856,219 million in 2019, compared to COP$35,658,753 million in 2018 and COP$26,855,395 million in 2017.

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 2018, the cost of sales for this segment increased 32.8% as compared with 2017, principally due to (i) an increase in purchase of crude oil at higher international benchmark prices, (ii) higher volume purchase of crude oil for use by our refineries due to higher throughput, (iii) an increase in cost of transportation associated with higher production in our refineries. This increase was partially offset by: (i) lower imports of products primarily medium distillates and gasolines as a result of higher production at Barrancabermeja and Reficar refineries and (ii) lower imports of light crude used at the Cartagena Refinery as a result of the substitution of such crude, which resulted in a more cost-effective crude slate for the Refinery.

In 2019, operating expenses before the impairment of non-current assets decreased by 80.1% as compared to 2018, mainly due to the difference between the fair value and book value of Invercolsa of COP$1,048,924 as noted in section Financial Review – Operating Results – Consolidated Results of Operations - Operating Expenses before Impairment of Non-Current Assets Effects. We decided to place Invercolsa into the downstream segment because it is standard industry practice to include both crude oil refining and natural gas processing and purification in this segment.

In 2018, operating expenses before the impairment of non-current assets decreased by 24.6% as compared to 2017, due to stabilization expenses of the Cartagena Refinery which was reflected in lower maintenance expenses, contracted services and general expenses.

In 2019, we recognized a reversal of impairment of non-current assets in this segment totalling 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.

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The impairment losses of non-current assets recognized in the segment in 2018, which totaled COP$984,704 million in 2018, as compared to a net reversal of impairment of COP$1,067,965 million in 2017, is primarily the result of: (i) adjustments in market expectations with respect to the impact of implementation of IMO regulation on projected margins for the Cartagena Refinery’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.

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 income attributable to owners of Ecopetrol of COP$117,708 million in 2019 compared to a net loss of COP$1,973,075 million in 2018, and a net income to owners of Ecopetrol of COP$358,859 million in 2017.

4.6

Liquidity and Capital Resources

Our principal source of liquidity in 2019 was cash flows from our operations amounting to COP$27,711,767 million.

Our main uses of cash in 2019 were (i) COP$13,979,141 million in capital expenditures, which included investments in property, plant and equipment, natural and environmental resources and intangibles, (ii) dividend payments amounting to COP$13,867,029 million, which included dividends of COP$12,910,611 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to the non-controlling shareholders of our subsidiaries totaling COP$956,418 million, iii) COP$3,002,977 million related to amortizations of capital and debt interest payments and iv) COP$300,326 million in lease payments.

For more information regarding our debt, see the section Financial Review—Financial Indebtedness and Other Contractual Obligations.

4.6.1

Review of Cash Flows

Cash from operating activities

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

A 2.8% increase in our operational 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.

Net cash provided by operating activities increased by 32.4% in 2018 as compared to 2017, mainly as a result of a 31.9% increase in our operational income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to (i) higher hydrocarbon production levels, (ii) an increase in our refining throughput, (iii) our continued strategy of replacing imports of crude oil and refined products with domestic production, (iv) the commencement of operations of the San Fernando – Apiay project and expansion of the P135 Project in our the midstream segment, (v) cost efficiencies from our transformation plan and (vi) a favorable price environment. This increase was partially offset by higher working capital needs mainly due to an increase in accounts receivable from the FEPC and the payment in advance of the capital gains tax due in 2019 pursuant to Decree 2146, 2018.

105

Cash used in investing activities

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.

In 2018, net cash used in investing activities increased by 98.9% as compared to 2017, mainly as a result of: (i) a 38.5% increase in investments in capital expenditures, which was driven mainly by drilling in the Castilla and La Cira-Infantas fields and the B3 module of the Rubiales field and (ii) a 249.4% increase in our investment portfolio as a result of excess liquidity.

Cash used in financing activities

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.

Net cash used in financing activities increased by 23.7% in 2018, as compared to 2017, due to (i) prepayments of local and foreign currency-denominated loans totaling the equivalent of US$2,446 million as compared to US$2,400 million in prepayments of foreign currency-denominated loans made in 2017 and (ii) an increase in dividend payments to the shareholders of Ecopetrol of COP$2,713,712 million and in dividend payments made by certain of our subsidiaries to their non-controlling shareholders of COP$209,342 million.

4.6.2

Capital Expenditures

Our consolidated capital expenditures in 2019, 2018 and 2017 were COP$13,979,141 million, COP$8,460,426 million and COP$6,107,506 million, respectively. These investments were distributed by business segment on average, for the past three years as follows: 85.7% for the exploration and production segment, 3.7% for refining and petrochemicals and 10.6% for the transportation and logistics segment. See Note 32.3 to our consolidated financial statements for more detail about capital expenditures by segment.

Our investment plan approved for 2020 is a range of between US$3,300 million and US$4,300 million. See the section entitled Strategy and Market Overview—2020 Investment Plan for further information.

The resources required for the investment plan can be funded through internal cash generation with no need to raise additional net financing.

4.6.3

Dividends

On March 27, 2020, our shareholders at the ordinary General Shareholders Assembly approved a distribution of ordinary dividends for the fiscal year ended December 31, 2019 amounting to COP$ 7,401,005 million, or COP$180 per share, based on the number of outstanding shares as of December 31, 2019. The payment dates will be April 23, 2020 (100% to minority shareholders / 14% to the majority shareholder), and during the second half of 2020 the remaining 86% to the majority shareholder.

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.

In 2018, we paid dividends for the fiscal year ended December 31, 2017 amounting to 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.

In 2017, we paid dividends for the fiscal year ended December 31, 2016 amounting to COP$945,661 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$558,986 million.

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4.7

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, 2019, 2018 and 2017, in accordance with Colombian IFRS and IFRS:

Table 52 – Consolidated Net Income and Equity

	For the year ended December 31,									% Change
	2019			2018			2017			2019/2018			2018/2017
	(Colombian Pesos in millions)
Net income attributable to owners of Ecopetrol (IFRS)		13,744,011			11,381,386			7,178,539			20.8			58.5
Cash flow hedge for future company exports		(419,275	)		(471,314	)		(366,048	)		(11.0	)		28.8
Exchange rate effects on tax bases – Deferred tax		(73,253	)		646,333			(192,079	)		(111.3	)		(436.5	)
Net income Attributable to owners of Ecopetrol (Colombian IFRS)		13,251,483			11,556,405			6,620,412			14.7			74.6
Net Equity (IFRS)		58,231,628			57,107,780			48,215,699			2.0			18.4
Cash flow hedge for future company exports		(10,099	)		(20,792	)		(29,258	)		(51.4	)		(28.9	)
Exchange rate effects on tax bases – Deferred tax		2,122,593			2,217,450			1,594,864			(4.3	)		39.0
Net Equity (Colombian IFRS)		60,344,122			59,304,438			49,781,305			1.8			19.1

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, 2019, our net income as reported under IFRS was COP$419,275 million higher than our net income as reported under Colombian IFRS.

Exchange rate effects on tax bases – Deferred tax. According to IAS 12.41, companies with a U.S. dollar functional currency and profit or tax loss in Colombian Pesos are required to recognize deferred taxes attributable to the difference between the carrying amounts of non-monetary assets in their financial statements and their respective tax bases converted from Colombian Pesos to U.S. dollars using the exchange rate on the closing date. The effect of the temporary difference is charged to profit and losses without a cash outflow expected in the future. Under local accounting principles (The General Accounting Office opinion No. 20162000000781 dated January 18, 2016), the result attributable to the aforementioned difference in accounting policies does not generate any deferred taxes.

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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, 2019, our net income attributable to owners of Ecopetrol as reported under IFRS was COP$73,253 million higher 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$14,865 million in 2019, COP$22,030 million in 2018 and COP$61,893 million in 2017 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$12,630 in 2019, COP$11,316 million in 2018 and COP$60,748 million in 2017 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, 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. For the year ended December 31, 2017, these same accounting differences led us to report net income attributable to the owners of Ecopetrol under IFRS of COP$7,148,539 million as opposed to a net income attributable to the owners of Ecopetrol of COP$6,620,412 million reported under Colombian IFRS for the same period.

4.8

Financial Indebtedness and Other Contractual Obligations

As of December 31, 2019, we had outstanding consolidated indebtedness of COP$36 trillion, which corresponded primarily to the following long-term transactions:

Table 53 – 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

5.375%

Bullet

June 15, 2016

US$500 million

September 18, 2023

5.875%

Bullet

December 1, 2010

COP$479,900 million

December 1, 2020

Floating

Bullet

December 1, 2010

COP$284,300 million

December 1, 2040

Floating

Bullet

August 27, 2013

COP$168,600 million

August 27, 2023

Floating

Bullet

August 27, 2013

COP$347,500 million

August 27, 2028

Floating

Bullet

August 27, 2013

COP$262,950 million

August 27, 2043

Floating

Bullet

Bank Loans

December 30, 2011

US$321 million

December 20, 2025

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

Ocensa

Bond

May 7, 2014

US$500 million

May 7, 2021

4.000%

Bullet

Oleoducto Bicentenario

Bank Loan

July 5, 2012

COP$2.1 trillion

July 5, 2024

Floating

Quarterly

ODL

Bank Loan

August 1, 2013

COP$800 billion

August 1, 2020

Floating

Quarterly

Reopening of bond due to 2023.

Debt originally obtained by Reficar for the Refinery modernization and voluntarily assumed by Ecopetrol.

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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.

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, 2019.

Table 54 – Our Contractual Obligations

COP$ in millions	Payments due by period
Contractual obligations	Total		Less than 1 year		1 to 3 years		3 to 5 years		More than 5 years
Employee Benefit Plan		29,814,647		1,326,347		2,744,022		2,845,377		22,898,901
Contract Service Obligations		23,942,962		5,962,450		8,077,571		4,488,763		5,414,178
Operating Lease Obligations		410,126		255,187		51,373		20,253		83,312
Natural Gas Supply Agreements		3,439,765		3,258,259		3,184		0		178,322
Purchase Obligations		1,552,454		895,001		377,878		45,793		233,783
Energy Supply Agreements		1,106,008		59,585		146,358		16,175		883,890
Capital Expenditures		14,368,402		4,688,138		4,083,070		3,601,107		1,996,088
Build, Operate, Maintain and Transfer Contracts (BOMT)		325,539		32,647		66,276		67,609		159,007
Capital (Finance) Lease Obligations		766,391		95,673		151,674		120,713		398,331
Financial Sector Debt		8,220,705		1,371,546		2,529,532		2,733,243		1,586,384
Bonds		27,844,279		556,113		1,578,675		6,202,348		19,507,143
Total		111,791,278		18,500,946		19,809,613		20,141,381		53,339,339

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.

4.9

Off Balance Sheet Arrangements

As of December 31, 2019, 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.

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4.10

Trend Analysis and Sensitivity Analysis

Trend Analysis

Ecopetrol updated its Business Plan on February 26, 2020. See the section entitled Strategy and Market Overview—Our Corporate Strategy—Business Plan for a discussion of the trends recognized in the development of that plan.

As described in the section entitled Strategy and Market Overview—2020 Investment Plan above, on March 16, 2020, Ecopetrol announced a set of actions to address current challenging market conditions, which have resulted, among other matters, in a 60% decline in the Brent crude price as compared to the end of 2019, due to external shocks including the strong increase in the supply of oil and the spread of COVID-19.

These measures are part of an intervention plan that seeks to have the Ecopetrol Group adapt in a timely and orderly manner to changing market conditions. The first stage of this plan includes the following actions:

Effective immediately, a COP$2 trillion cutback in costs and expenses to strengthen the Ecopetrol’s competitiveness, including austerity measures, prioritization of operational and administrative activities, and control over operational expenses, such as travel restrictions, sponsorships and involvement in events, among others.

ii.

Implementation of new commercial strategies to maximize the value of the crudes and products sold by the Ecopetrol Group.

iii.

iv.

The production target for 2020 set forth above remains unchanged as of phase one, between 745 - 760 mboed.

Furthermore, the economies of all the countries where the Ecopetrol Group is located are currently experiencing negative economic consequences from the COVID-19 pandemic including, a significant drop in worldwide stock prices, decreasing oil prices, rise in unemployment, decreasing interest rates, liquidity concerns and devalued currencies. There is concern that the United States and other developed countries will fall into a recession in the near term, which will negatively impact the Colombian economy. Any such continued macroeconomic downturn could have a material adverse effect on our results of operations and business condition.

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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, 2019, taking into account ICE Brent crude oil prices that reasonably reflect management’s view of crude oil prices given prevailing market conditions, which particularly consider, amongst various factors, long-term projections of independent experts in the oil and gas market such as IHS, Platts and Wood Mackenzie.

Table 55 – Sensitivity Analysis of Reserves

	Oil and NGL (million barrels)			Natural Gas (bcf)		Total Oil and Gas (Mmboe)
Reserves as of December 31, 2019		1,163.8			2,306.4		1,568.5
Sensitivity Scenario		1,159.4			2,309.4		1,564.6
Difference (million barrels)		(4.4	)		3.0		(3.9	)
Difference (%)		(0.4	)		0.1		(0.2	)

The conversion rate used is 5,700 cf = 1 boe.

Assumptions for the Sensitivity Analysis of Reserves

The sensitivity of the ICE Brent price of US$40 per barrel in 2020, US$50 per barrel in 2021 and between US$53 and US$72 onwards, and costs of management portfolio.

The base scenario on which our sensitivity analysis is made corresponds to 83% of our oil, NGL and natural gas reserves, as of December 31, 2019, 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, 2019, due to variations of US$1 in the price of ICE Brent crude and of 1% in the COP$/US$ exchange rate.

Table 56 – Results of Reserves’ Sensitivity Analysis

	Income Statement 2019			Income Statement Case ICE Brent⁽¹⁾+ US$1			Difference Between Real 2019 and Case ICE Brent			Income Statement Case TRM⁽²⁾- 1%			Difference Between Real 2019 and Case TRM
	(COP$ in billions)
Revenue		71,488.51			72,502.72			1,014.21			72,185.51			697.00
Cost of sales		44,972.36			45,376.30			403.94			45,218.97			246.61
Gross Income		26,516.15			27,126.42			610.27			26,966.54			450.39
Operating expenses		3,726.56			3,726.56			-			3,726.56			-
Impairment of non-current assets		1,762.44			1,762.44			-			1,762.44			-
Operating income		21,027.15			21,637.42			610.27			21,477.54			450.39
Finance results, net		(1,670.49	)		(1,670.49	)		-			(1,670.49	)		-
Share of profit of associates and joint ventures		366.90			366.90			-			366.90			-
Income before income tax		19,723.56			20,333.83			610.27			20,173.95			450.39
Income Tax		(4,718.41	)		(4,864.41	)		(145.99	)		(4,826.16	)		(107.75	)
Net Income		15,005.15			15,469.43			464.27			15,347.79			342.64

(1)

ICE Brent = US$64 per barrel

(2)

Exchange rate (TRM) = COP$3.281/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 2019, 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 365-day year for 2019. Prices assumed correspond to realized prices for crude oil, natural gas and refined products for 2019, 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 2019. Prices are the realized prices of crude oil, natural gas and refined products in 2019 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 2019).

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 24% for 2019.

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 57

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

Risk Review

5.1

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.

5.1.1

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.

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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, 2019, 2018 and 2017, 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 period was US$54.93 per barrel in 2017, US$72.20 per barrel in 2018 and US$63 per barrel in 2019. In 2018, the Company recognized an increase in oil and gas proven reserves of 4% as compared to 2017, to 1,727 mmboe in 2018 from 1,659 mmboe in 2017. 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.

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 capital cost (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 2019, Ecopetrol recognized impairment losses of non-current assets of COP$1,762,437 million which corresponds to the net result of:

A reversal of impairment of non-current assets in the refining and petrochemicals segment, primarily related to 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.

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, 2019. Based on these calculations, assuming an average price per barrel of ICE Brent price of US$40 per barrel in 2020, US$50 per barrel in 2021, and between US$53 and US$72 onwards, Ecopetrol could recognize a decrease in oil and gas proved reserves of approximately 0.2%. 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.

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Achieving our long-term growth depends on our ability to execute our strategic plan — specifically, the discovery and/or successful development of additional reserves.

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.

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—Business Plan. However, the implementation of this strategy depends, among others, on the final outcome of the regulatory framework affecting this technology currently being defined in Colombia, obtaining the requisite environmental license required for the exploratory phase (including the Integral Pilot Research Projects –PPII) to begin and the results of the PPII.

In February 2019, a commission of experts appointed by the Colombian government submitted its non-binding recommendation to advance in the pilot testing phase with the previous necessary steps to assure effective monitoring, control and communication of the pilot program development to stakeholders. In September 2019, the State Council authorized the execution of the Integral Pilot Research Projects (PPII) only to investigate the eventual effects of using fracking technology. However, we cannot assure you that unconventional reservoirs in Colombia will be able to be exploited.

On February 28, 2020, the Ministry of Mines and Energy issued Decree 328 that rules the general guidelines for the development of PPII on unconventional reservoirs by using fracking technology. Further regulations are required to advance in the PPII implementation.

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.

In addition, our business growth and sustainability depend on our ability to manage the capital investments and operate efficiently, in accordance with the corporate strategy guidelines.

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 2019, in Ecopetrol, approximately 95% of the revenues came from sales of crude oil, natural gas and refined products and 91% 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, 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, 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 since the beginning of March, the OPEC and its capacity and decision to increase production levels to gain market share have impacted the international reference prices.

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Currently, the spread of the coronavirus disease (COVID-19) generates uncertainty about a possible slowdown of the global economy, which in turn could cause a decrease in crude oil, NGL, and gas demand and oil, NGL, and gas prices. See 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.

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 2019, our crude oil basket price was US$58.6 per barrel versus US$63.2 per barrel in 2018, the refined product basket price was US$69.8 per barrel versus US$77.3 per barrel in 2018; and the natural gas price was US$24.1 per barrel equivalent in 2019 versus US$22.4 per barrel equivalent in 2018. 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 2019, we had an impairment of non-current assets of COP$1,762,437 million, as compared to the COP$368,634 million impairment of non-current assets in 2018 and the COP$1,311,138 million net reversal of the impairment of non-current assets in 2017. 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 17 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.

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, 2019 our U.S. dollar-denominated total aggregate principal amount was US$9.9 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$9.4 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 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 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 Company adopted hedge accounting as part of its risk management strategy, using two types of natural hedges with its U.S. dollar 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. As a result of the implementation of both hedges, US$7.3 billion of Ecopetrol S.A.’s debt in U.S. dollars as of December 31, 2019, 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.

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The U.S. dollar/Colombian Peso exchange rate has fluctuated during the last several years. On average, the Colombian Peso appreciated 3.35% in 2017, depreciated 0.18% in 2018, and depreciated 10.98% in 2019. Additionally, as of December 31, 2019, the Colombian Peso depreciated 0.84%; as of December 31, 2018, the Colombian Peso depreciated 8.91%, and as of December 31, 2017, the Colombian Peso appreciated 0.56%, in each case from year-end exchange in the previous year. In addition, given the performance of the interest rate in the U.S., different global growth perspectives, Presidential elections in the United States in 2020, 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 29.1 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.

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, natural disasters, 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.

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Our involvement in deep-water drilling either as direct operator or in conjunction with our business partners involves risks and costs, which may be out of our control.

Our deep-water drilling activities present severe risks, such as the risk of spills, explosions on platforms and drilling operations, and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings. As a result, more stringent government regulation may result in increased costs and longer exploration and development timeframes for our deep-water drilling operations and consequently could adversely affect our results of operations and financial condition. Heightened risks and costs associated with deep-water drilling may have a negative effect on our results of operations and financial condition and in our reputation.

See 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.

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 29.2 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 and capital markets on favorable terms to obtain funding to 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.

A new financial crisis, volatility in prices in the oil and gas sector (as what is currently being experienced with the significant drop of the price of Brent crude in 2020 year to date), the spread in protectionist policies in the United States, China and Europe, 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, which in turn could worsen risk perception with respect to the emerging markets, or the occurrence of any of the risks described in the section Risk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Environment 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. 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 our ratings as our rating is capped by the rating of the Republic of Colombia and the implicit support that can potentially be provided to the Company. On May 27, 2019, Fitch Ratings revised our outlook to negative from stable, as a consequence of the adjustment made to the Colombia´s Sovereign Rating Outlook. On June 27, 2019, S&P upgraded our stand-alone credit rating to bbb- from bb+ and maintained our long-term corporate credit rating at BBB- and our outlook at stable. On July 29, 2019, Moody’s confirmed our long-term international rating at Baa3, with a stable outlook. On December 3, 2019, Fitch Ratings maintained our credit rating at BBB with negative outlook and our stand-alone rating at bbb. We cannot offer any assurance that our credit rating will continue.

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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, the Government, through the Ministry of Finance and Public Credit and the favorable opinion of the National Planning Department, must authorize all indebtedness of state-owned entities and government-controlled companies through a majority equity stake. Consequently, excluding our foreign subsidiaries or those subsidiaries in which we hold minority interest, most of our indebtedness must be previously authorized by the Colombian Ministry of Finance and Public Credit and the National Planning Department. As such, our indebtedness is subject to the Government’s time frames and policies, and we cannot guarantee that such authorizations would be granted in a timely fashion or granted at all.

We may be exposed to increases in interest rates, thereby increasing our financial costs.

We may incur debt locally and in the international capital markets and, consequently, may be affected by changes in prevailing interest rates. 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, 2019, approximately 14.18%, or a principal of US$1.5 billion (COP$5.1 trillion, using a COP$3.277,14/1.00 US exchange rate as of December 31, 2019), 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 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.

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.

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Our future performance depends on the successful selection, development and deployment of new technologies and the knowledge to operate 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 for 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. 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 a deficiency in leadership capacity and lack of key skilled employees.

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 can be negatively affected by a deficiency in leadership capacity and a lack of key skilled employees that can execute our business strategy with competency, creativity and determination.

Our operations may not be able to keep pace with the increasing domestic demand for natural gas.

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), under a medium forecasted demand scenario there would be a natural gas deficit in Colombia as of January 2024.

Considering the CREG Resolution 114 of 2017, 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. Hence, Ecopetrol will not be able to keep or increase its market participation unless the Company increases its natural gas reserves as local demand grows.

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, delays in the completion of projects relating to our production facilities or the acceleration of the decline in our gas production, among other reasons, we may be required to compensate our customers for our failure to supply natural gas.

Delays in the start of new projects could result in penalties imposed on us by our clients. We pay penalties due to delays in the start of new projects in 2019. We cannot assure that in the future we will not be subject to additional monetary fines which can in turn affect our financial condition and results of operations.

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. 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.

For example, we have developed natural gas reserves in the Cusiana and Cupiagua fields, but transportation capacity to deliver gas from these fields is currently limited. Although there are projects under development that will eliminate this limitation, we can offer no assurance that they will prove successful.

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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.

We are exposed to several risks that may partially interrupt our activities. They include fires or explosions, natural disasters, criminal acts and acts of terror, malfunction of pipelines and emission of toxic substances.

Also, the effects of climate variability and climate change could create impacts and losses in any part of our business operations, for instance, as the result of increase in the intensity of the “La Niña” and “El Niño” climate phenomena, causing floods and drought periods, increased temperature and rising sea and river levels.

The “El Niño” climate phenomenon is characterized by (i) a lack of rainfall, which limits the amount of water necessary for the development of various activities of the company, (ii) increased temperatures, which could have a direct impact on our worker’s health given an increased occurrence of heat waves and the increased occurrence of epidemics and diseases and (iii) potential negative impact on energy supply. 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.

As a result, our activities could be significantly affected. These risks could result in property damage, 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 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 could be disrupted by the Coronavirus or other pandemic diseases and health events.

Pandemic diseases and health events, such as the recent outbreak of the novel strain of coronavirus infection (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.

The ongoing outbreak of COVID-19 was first reported on December 31, 2019 in Wuhan, Hubei Province, China. From Wuhan, the disease spread rapidly to other parts of China as well as other countries, including Colombia and the United States, growing into a global pandemic. Since the outbreak began, countries have responded by taking various measures including imposing quarantines and medical screenings, restricting travel, limiting public gatherings and suspending certain activities. In addition, concerns related to COVID-19 have negatively impacted global financial markets and the demand for crude oil and refining products, resulting, among others, in the fall of oil prices, a trend which may continue. There are other broad and continuing concerns related to the potential effects of COVID-19 on international trade (including supply chains and export levels), travel, employee productivity, securities markets, and other economic activities that may have a destabilizing effect on financial markets and economic activity.

On March 17, 2020, the Colombian government declared a State of Economic, Social and Ecological Emergency to contain the dissemination of COVID-19 and mitigate the risks associated with the pandemic. In the exercise of its powers, the Colombian government is entitled to implement extraordinary measures that might affect ongoing business operations. We cannot assure that such measures will not adversely affect our business. Furthermore, in the case of a forced shutdown involving any of the companies comprising the Ecopetrol Group, our contractors, suppliers, customers and other business partners, we may be unable to meet certain of our business obligations for an unknown period of time, which could adversely affect our business, financial condition and results of operations.

See Note 33 to our consolidated financial statements for further information.

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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 the previous consultation process, set forth by Colombian law. These consultation processes are part of the administrative procedures for obtaining environmental licenses to start our projects, works or activities in areas belonging to 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.

Our activities are subject to opposition, including protests by various communities, and even in areas in which the previous consultation process does not apply. Recently, through popular consultation, some communities have voted against the development of extractive industry projects. Any such similar situation may affect our future projects.

In recent years, indigenous communities have 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 opposed to our operations or that such communities will participate in consultation processes if available. We may be exposed to similar delays due to opposition from local communities in other countries where we carry out our activities.

We have made significant investments in acquisitions and we may not realize the expected value.

We have acquired interests in several companies in Colombia and abroad and have most recently 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.

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 if 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.

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 financing guarantees to 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 or results.

Any situation that could affect the operations of our subsidiaries, or make them financially non-viable, particularly for those that recently entered into operations, such as Bioenergy, 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.

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, which will allow them to organize financial, administrative and operational aspects to preserve their sustainability. Those entities are not material subsidiaries and therefore these processes are not expected to have a material adverse effect on our consolidated results of operations and financial condition. Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S. were admitted to this reorganization process mainly due to lower than expected agricultural productivity and a deterioration in market conditions that make their current level of debt unsustainable. By these processes, they will seek to establish agreements with their main creditors as well as liquidity alternatives to maintain their viability.

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Ongoing Colombian State control entities investigations regarding our subsidiaries Reficar and 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.

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.

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 any of them, 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 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.

A failure in our information technology systems or cyber security attacks may adversely affect our financial results.

We depend on the reliability and security of our information technology systems to conduct certain exploration, development and production activities, process financial records and operating data and communicate with our employees and business partners, and for many other activities related to our business. Our information technology systems may fail or have other significant shortcomings due to operational system flaws or employee misuse, tampering or manipulation. In addition, we may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

During 2019, our internal cyber security systems identified and contained cyber security attacks such as malware, phishing and denial of service. In total, we had four 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.

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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 2019 was 7,502 GWh/year, of which 71% was supplied through self-generation, and the remaining 29% through power grid. Our demand is 10% of the total energy demand in Colombia.

Our self-generation is subject to fuel 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 2019, Ecopetrol Group produced approximately 16.5 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.

5.1.2

Risks Related to Colombia’s Political and Regional Environment

This section discusses potential risks related to our extensive operations in Colombia.

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.

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 2019, the attacks against our pipeline infrastructure decreased by 31.4% in relation to 2018 (105 attacks in 2018 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. The attacks against oil pipelines located in Putumayo department restarted in 2019 for the first time since 2015, with five attacks. This lead to an increase in deferred production to 660,052 barrels in 2019 from 11,102 barrels in 2018, mainly due to social problems in the area impacted by the third party attacks, principally in the Arauca department.

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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 2019 was approximately COP$236,059 million (US$72.03 million, using a COP$3.277,14/1.00 US exchange rate as of December 31, 2019). During the first three months of 2020, there have been 18 attacks against the infrastructure of the Caño Limón Coveñas and Transandino pipelines. Additionally, these attacks have resulted in certain of our customers requesting the early termination of their transport agreements. We are currently disputing such terminations. See Note 22.4 to our consolidated financial statements for further information.

Likewise, the theft of refined products and crude oil, resulting from security issues, may impact our operating and financial results in the future. Theft of refined products increased from approximately 21 bod in 2018 to approximately 37 bod in 2019. Theft of crude oil increased from approximately 1,324 bod in 2018 to approximately 1,808 bod in 2019.

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 maintains 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.

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.

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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 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. 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.

Our operations might be affected by rising climate change and energy transition concerns

Due to worldwide agreements addressing the concern for increased of global temperatures, companies have had to take actions in order to respond and counteract the effects of their operations regarding climate change.

Governments have also created additional legal and regulatory measures, such as increased restrictions of greenhouse gas (also “GHG”) emissions that could prompt more stringent domestic regulations related to climate change, with potential impact on project delays, new costs of production, and future investments and operational plans.

The Colombian government currently imposes a carbon tax on fuel consumption (approximately COP$5/ton of CO2e). The Climate Change Law (1931/18) will mandate the implementation of a national cap and trade system, which could potentially increment the price of carbon. In addition, we see growing pressure from investors towards companies in order to lower carbon footprints and establish a credible energy transition pathway linked to a near net zero carbon scenario, which could in turn increase our costs of operation.

Additionally, our operations could be exposed to climate variability and climate changes, which could potentially materialize in water shortages, floods, fires, storms and hurricanes, rising sea levels, among other natural occurrences, which could potentially lead to a materially adverse effect on our results of operation and financial condition.

Colombian political and economic conditions have a direct impact on our business and may have a material adverse effect on us.

Colombia’s economic policies may have direct impact on our Company as well as market conditions, the prices of securities and our ability to access national and international capital markets. Our financial condition and results of operations may be adversely affected by the following factors, among others, and the Government’s response to such factors: exchange rate movements; inflation; exchange control policies; price instability; interest rates; liquidity of domestic capital and lending markets; tax policy; regulatory policy for the oil and gas industry, including pricing policy; and other political, diplomatic, social and economic developments in or affecting Colombia.

Uncertainty over whether the Government will implement changes in policy or regulations that may affect any of the factors mentioned above or other factors in the future may lead to economic uncertainty in Colombia and increase the volatility of the Colombian securities market and securities issued abroad by Colombian companies. Any changes in the ruling government, oil and gas or investment regulations and policies or a shift in political attitudes in Colombia are beyond our control.

Developments and the perception of risk in other countries, especially emerging market countries, may adversely affect the market price of Colombian securities, including our ADSs.

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Securities issued by Colombian companies may be affected by economic and market conditions in other countries, including other Latin American and emerging market countries. Although economic conditions in Latin American countries and in other emerging market countries may differ significantly from economic conditions in Colombia, investors’ reactions to developments in these other countries may have an adverse effect on the market value of securities of Colombian issuers and our ability to access capital markets.

Due to past financial crises in several emerging market countries (such as the Asian financial crisis of 1997, the Russian financial crisis of 1998 and the Argentinean financial crisis of 2001), the world financial crisis of 2008 and the recent sovereign debt crises in certain European countries, investors may view investments in emerging markets with heightened caution. In the past, as a result of crises in other countries, flows of investments into Colombia have been reduced. Crises in other countries, especially in emerging market countries, may hamper investor enthusiasm for securities of Colombian issuers. If Latin America experiences a new slow-down or if the price for securities of Latin American issuers falls, the price for our ADSs could follow this trend and could be adversely affected, as could our ability to access domestic or international capital markets.

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 imposed and subsequently eliminated additional taxes such as the Income Tax for Equality (CREE) and the wealth tax, and 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, dividends paid to non-resident shareholders are subject to a withholding tax. Until 2018, the withholding tax rates applicable to dividends paid to non-resident shareholders were: (i) a 5% dividend tax on dividends distributed from profits taxed at the corporate level, with certain exceptions; and (ii) a 35% withholding tax rate on dividends distributed from profits not taxed at the corporate level plus an additional 5% dividend tax after applying the initial 35% withholding tax rate. As per Law 2010, the withholding tax rates applicable to dividends paid to non-resident shareholders are: (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); and (ii) dividends paid out of untaxed profits at the corporate level are subject to an equalization tax (statutory 32% rate for 2020, 31% for 2021 and 30% as of 2022) and, the remainder, to a 10% dividend tax (i.e., 38.8% in 2020). Tax treaty rules might also apply on dividend distributions when a shareholder is a resident in a country that has executed a tax treaty with Colombia and reduce or eliminate the applicable taxes if the applicable requirements are met.

5.1.3

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 Environmental License National Agency 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 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.

Under certain of our credit agreements, we are under an obligation to comply with international environmental standards established by our lenders or by multilateral institutions. Failure to comply with such environmental standards could result in an event of default under the relevant credit agreements that we, or our subsidiaries, have entered into, which would affect our financial condition.

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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, 2019, Ecopetrol S.A. was a party to 4,988 legal proceedings relating to civil, criminal, administrative, environmental, tax, labor claims, of which 3,445 were filed against us in the Colombian courts and arbitration tribunals and of which 266 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 21 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.

5.1.4

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 register 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. 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 you 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, 2019, the Colombian Stock Exchange (BVC) had a market capitalization of approximately COP$436,786 billion (US$133.28 billion using the closing rate for 2019), a 29% increase when compared with the amount at the end of 2018, a daily average trading volume of approximately COP$142,796 million (US$43.50 million, using the average exchange rate for 2019), a 3% decrease when compared with the volume in 2018. By comparison, the New York Stock Exchange (the NYSE) had a market capitalization of US$30.9 trillion as of December 31, 2019, and a daily trading volume of approximately US$135.8 billion in 2019.

As of December 31, 2019, our shares represented the highest market capitalization of the BVC accounting for 14.70% 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.

5.1.5

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.

Our controlling shareholder may propose 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.

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5.2

Risk Management

5.2.1

Managing Risk through Our Internal Control System

Under the leadership of the Vice-Presidency of Compliance, Ecopetrol S.A. consolidated 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.

The main purpose of the Ecopetrol S.A.’s Internal Control System 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. The system performance is systematically monitored by the Board of Directors.

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 risk management component of our Internal Control System is in charge of identifying 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.

Enterprise Risks: Are those risks that are directly associated with the business strategy plan of the Company and are systematically monitored by the Management Committee. 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: 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.

Our risk management approach is based on the risk management cycle, consisting in five main stages: planning, identifying, evaluating, treatment and monitoring risks, as well as communication across all stages. This cycle is supported in three pillars of risk management: culture, organizational structure and normative and management tools.

Three of our most important tools within the risk management component are:

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 consequences (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.

Ecopetrol has also defined guidelines and implemented an Internal Control System, 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.

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5.2.2

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.

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 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) the inventory of its critical cybernetic infrastructure that was included in the classified catalogue of national critical cybernetic infrastructure.

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 policies, specialized monitoring and control mechanisms, vulnerability management and cybersecurity insurance coverage, among others.

Ecopetrol S.A. has a Security Operations Center 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.

While there were cyber-attacks during 2019, 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 cybersecurity issues.

Furthermore, during 2019, the internal audit department conducted an audit on cybersecurity processes following up on our prior enhancement plans. As a result of this audit, the action plan was updated to be implemented in 2020. The primary goal of the plan is to reinforce our cybersecurity strategy and refine certain technical components of our cybersecurity program.

Ecopetrol updated its cybersecurity risk profile and its cybersecurity strategy defining the management’s scope, which now covers information technologies and the companies of the Ecopetrol Group. The Cybersecurity unit is part of the Digital Vice-presidency, reporting to senior management.

Ecopetrol used the ONG-C2M2 (Oil & Gas - Cybersecurity Capability Maturity Model) as a framework to manage its cybersecurity maturity and to establish its Cybersecurity Program. Ecopetrol also recently updated its cybersecurity policies and cyber incidents response procedure which was tested in three wargames exercises.

5.2.3

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 the second half of 2019, Ecopetrol S.A. executed 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.

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Currency risk arises in our operations given the fact that most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars. Therefore when the Colombian Peso depreciates against the U.S. dollar, our revenues converted into Colombian Pesos increase. Conversely, when the Colombian Peso appreciates against the U.S. dollar, our revenues decrease. On the other hand, imported goods, oil services and the debt, which is mainly denominated in U.S. dollars, become less expensive when the Colombian Peso appreciates against the U.S. dollar and more expensive when the Colombian Peso depreciates against the U.S. dollar.

As of December 31, 2019 our U.S. dollar-denominated total debt principal was US$9.9 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$9.4 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 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. In addition, the risk management strategy of 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 1, 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. On June 8, 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, on November 12, 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. As of December 31, 2019, the outstanding value of the natural accounting hedges was US$7.3billion. 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 29.1 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. Nevertheless, it is important to bear in mind that for Ecopetrol S.A.’s cash flow, the effect of the Colombian peso appreciation against the U.S. dollar is positive given the fact that we habitually convert our income in foreign currency to Colombian pesos.

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 4.2%, 4.2%, 4.9% and 0.9%, respectively, of the nominal debt balance as of December 31, 2019). Thus, volatility in interest rates may affect the fair value of and cash flows related to our investments and floating rate debt. In 2019, 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) 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 21.2 Plan assets to our consolidated financial statements.

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Finally, counterparty risk is the potential probability that a borrower or counterparty defaults on any obligation. In our case, we are exposed to this risk as we invest in different financial instruments and receive letters of credit in order to mitigate our exposure with our commercial counterparties. We manage this risk by monitoring and analyzing the counterparty’s creditworthiness, stock price behavior, spreads on credit default swaps, probability of default, among others.

Hedging guidelines for Ecopetrol S.A. and its subsidiaries

Ecopetrol S.A.’s management established new 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 are generally limited to investments of our excess cash 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 U.S. government or Colombian government, without regard to the ratings assigned to such securities. In Ecopetrol S.A.’s Colombian Peso portfolio, it must invest our excess cash 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. In addition, Ecopetrol S.A. may also invest in securities issued or guaranteed by the Colombian government without rating restrictions.

On December 2018, Ecopetrol S.A.’s management approved an update to the investment guidelines applicable for both U.S. Dollars and Colombian Pesos, that has been effective since January 1, 2019. The guidelines were updated in light of the following: the current reality of the financial markets, alignment with the practices of comparable companies in the oil sector, the Ecopetrol Group’s current corporate structure and the need to have a larger investment universe with the objective of generating higher returns on resources with an acceptable level of risk. The primary changes are:

Both the Ecopetrol S.A. 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 short and long term limits by issuer and issuance based on internal analyzes and external risk ratings.

Additionally, the portfolios in U.S. Dollar and Colombian Peso of Ecopetrol S.A. will be segmented in the tranches determined by Ecopetrol S.A.’s management, meeting the Company’s working capital and liquidity needs, benchmarks and cash flow projections.

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5.3

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, 2019, Ecopetrol S.A. was a party to 4,988 legal proceedings relating to civil, criminal, administrative, environmental, tax and labor claims, of which 3,445 were filed against us in the Colombian courts and arbitration tribunals, of which 266 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 22 to our consolidated financial statements included in this annual report for a discussion of our legal proceedings.

Caño Limón – Coveñas Crude Oil Pipeline Spill

On December 11, 2011, the Caño Limón - Coveñas oil pipeline ruptured and caused the spill of approximately 3,267 barrels of crude oil into the Iscala creek, which connects with the Pamplonita River that provides water to the city of Cúcuta. The incident did not cause any fatalities or injuries.

A class action lawsuit has been filed against Ecopetrol S.A. and against employees of the company, and the First Administrative Court has jurisdiction to conduct the case, which is in the 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.

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 one construction contract. 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 Tribunal accepted another 1,208 informal traders and fishermen as claimants.

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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.

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 six lawsuits related to this incident with possible damages of approximately COP$7.47 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.

Although the plaintiffs did not clearly determine the amount of their claims, Ecopetrol and the National Agency for Legal Defense (Agencia Nacional de Defensa Jurídica del Estado or ANDJE) have initially calculated the amount to be up to COP$358,201,371,800.

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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.

Environmental Administrative Proceedings

As of December 2019, Ecopetrol S.A. was party to 243 environmental administrative proceedings, of which 218 were initiated before 2019, and 25 during 2019. It is not possible for us to determine whether the pending proceedings could have a material effect on Ecopetrol. During 2019, nine proceedings were concluded, in four of them we were subject to monetary fines through resolution 200.36-19.0649 of 2019, resolution 199, September 20, 2019, resolution DGL 0366 May 20, 2019 and resolution DGL 0534, August 2, 2019 in the aggregate amount of COP$2 billion.

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:

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.

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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 current employee of Ecopetrol, and former employees of Reficar, as well as against (ii) 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, 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 January 2017, the Office of the Comptroller General initiated a special audit in Reficar and delivered a final report to Reficar on July 12, 2017. In this report the Office of the Comptroller General concluded that, in their opinion, Reficar’s 2016 Financial Statements do not reasonably represent, in all important aspects, the entity’s financial position as of December 31, 2016.

On February 2, 2018, the Legal Accounts Commission of the National House of Representatives of the Republic of Colombia informed Reficar that the House of Representatives decided, through Resolution No. 2713 on December 3, 2017, that it would not close the General Budget and Treasury Account and the National Balance Sheet for the 2016 fiscal year, since the 2016 Financial Statements of several state entities, among them Reficar, had received a negative opinion from the Office of the Comptroller General. Pursuant to Resolution No. 2713, Colombian control entities were ordered to initiate the corresponding disciplinary, fiscal and/or criminal investigations.

1.4

In December 2017, the Office of the Comptroller General initiated a special audit in Reficar and submitted a final report to Reficar on May 18, 2018. In this report the Office of the Comptroller General concluded that, in their opinion, Reficar’s 2017 Financial Statements do not reasonably represent, in all important aspects, the entity’s financial position as of December 31, 2017.

On February 6, 2019, the Legal Accounts Commission of the National House of Representatives of the Republic of Colombia informed Reficar that the House of Representatives decided, through Resolution No. 3135 on December 18, 2018, that it would not close the General Budget and Treasury Account and the National Balance Sheet for the 2017 fiscal year, since the 2017 Financial Statements of several state entities, among them Reficar, had received a negative opinion from the Office of the Comptroller General. Pursuant to Resolution No. 3135, Colombian control entities were ordered to initiate the corresponding disciplinary, fiscal and/or criminal investigations.

1.5

On January 2019, the Office of the Comptroller General initiated a financial audit in Reficar and delivered a final report to Reficar on May 20, 2019.

On November 26, 2019, the Legal Accounts Commission of the National House of Representatives of the Republic of Colombia informed Reficar that the House of Representatives had decided, through Resolution No. 2898, that it would not close the General Budget and Treasury Account and the National Balance Sheet for the 2018 fiscal year, since the 2018 Financial Statements of several state entities, among them Reficar, had received a negative opinion from the Office of the Comptroller General. Pursuant to Resolution No. 2898, Colombian control entities were ordered to initiate the corresponding disciplinary, fiscal and/or criminal investigations.

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1.6

On January 2020, the Office of the Comptroller General initiated a financial audit in Reficar. The final report is expected to be delivered to Reficar in May 2020.

In respect of the special audits mentioned in sections 1.3, 1.4, 1.5 and 1.6 above, as of the date of this annual report, Reficar has no knowledge of any procedural actions carried out by any of the Colombian control entities regarding the disciplinary, fiscal and/or criminal investigations ordered by Resolution No. 2713, Resolution No. 3135 or Resolution No. 2898.

Reficar’s external auditors issued an unqualified opinion on Reficar’s financial position as of December 31, 2016, 2017, 2018 and 2019. As of the date of this annual report, such auditors have not informed Reficar that there has been any change to their opinion.

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.

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.

The specific content and status of the remaining three 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.

The Prosecutor’s Office investigations:

The Prosecutor’s Office has been conducting the following legal proceedings:

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, 2018.

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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.

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.

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 their employees are not part of the Prosecutor’s Office 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.

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.

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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.

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.

The oral hearing was scheduled to begin in April 2020, but the arbitration was stayed, as described below. After the hearing, the Tribunal will analyze the parties’ arguments to render its final decision on Reficar’s and CB&I’s claims. Until the Tribunal renders its final decision, the outcome of this arbitration is unknown.

On January 21, 2020, Comet II B.V., the successor in interest to Chicago Bridge & Iron Company N.V., commenced a bankruptcy case under title 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.

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, lifting the stay on August 30, 2020 provides sufficient time to commence hearings on or after December 7, 2020.

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. 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.

Moreover, 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 issued its financial audit final report with six 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, 2019, Bioenergy completed four of the activities set forth in the remediation plan. Completion of the two remaining items are pending but expected to be completed within the allotted time period.

Finally, 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 issued its compliance audit final report with 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.

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Shareholder Information

6.1

Shareholders’ General Assembly

Our Shareholders’ General Assembly was held on March 27, 2020 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 180 Colombian pesos (COP$180), is as follows: a first payment of 100% of the dividend to minority shareholders and 14% of the dividend to the majority shareholder, to be made on April 23, 2020, and the payment of the remaining 86% of the dividend to the majority shareholder to be disbursed during the second half of 2020.

The occasional reserve of COP$4,557,074 million 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 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.

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.

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6.3

Market and Market Prices

On August 2010, our ADSs began trading on the Toronto Stock Exchange (TSX) under the symbol “ECP.” On February 17, 2016, we announced the application for voluntary delisting from the Toronto Stock Exchange following the Board of Directors’ decision to delist from the TSX. The decision was based on the Board of Director’s assessment of the limited trading activity of our ADRs in Canada, a liquid market for our ADRs on the NYSE and for our ordinary shares on the local Colombian Stock Exchange (Bolsa de Valores de Colombia), among other factors. The time and administrative efforts associated with maintaining the listing of the ADRs on the TSX were also taken into account. On March 2, 2016, our ADR’s were officially delisted from the TSX. On December 7, 2017, we applied to the Alberta Securities Commission and the Ontario Securities Commission to cease our reporting requirements, due to our delisting process. On September 4, 2018, we announced that effective August 29, 2018, we had ceased to be a reporting issuer in each of the provinces of Alberta and Ontario and hence were no longer a reporting issuer in any jurisdiction in Canada. Accordingly, Ecopetrol no longer has any disclosure obligations in Canada. The ADRs have continued to trade on the NYSE and the ordinary shares have continued to trade in the Colombian stock market. Therefore, the Company continues to be subject to United States, as well as Colombian, reporting and corporate governance obligations.

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$270.7132 as of December 31, 2019) 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.

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.

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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 Tank of New York Mellon, as trustee:

5.875% Notes due 2023

4.125% Notes due 2025

5.375% Notes due 2026

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 and 4.19 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;

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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);

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 2017, reimbursements were made in the amount of approximately US$2,220,290 for expenses related to investor relations activities. 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.

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.

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6.6

Taxation

6.6.1

Colombian Tax Considerations

The following is a general description of the Colombian tax considerations for investments in common shares in Colombia or for the purchase of ADSs, in a foreign securities market. This description is based on applicable law in effect as of the date of this annual report is issued, which may be subject to changes.

Prospective purchasers of common shares or ADSs should consult their own tax advisors for a detailed analysis of the tax consequences in Colombia, resulting from the acquisition, ownership and disposition of common shares or ADSs.

General Rules

Colombian entities and individuals who are deemed to be residents within the Colombian national territory for Colombian tax purposes are subject to Colombian income tax on their worldwide income. Foreign entities and individuals who are not deemed to be residents in Colombia, are subject to income tax in Colombia only with respect to their Colombian-source income, which is generally defined as income obtained from (i) the rendering of services inside Colombian territory, (ii) the exploitation of tangible and intangible assets in Colombia, and (iii) the sale of tangible or intangible assets that are located inside Colombian territory at the time of the sale. 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:

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.

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For Colombian tax purposes, an individual is considered to be a Colombian resident when he/she meets any of the following criteria:

He/she remains in Colombia continuously or discontinuously for more than 183 calendar days within any given 365-consecutive-day term;

ii.

He/she is related to the Colombian government’s foreign service or to individuals who are in the Colombian government’s foreign service and who, by virtue of the Vienna Conventions on diplomatic and consular relations, are exempted from taxes during the time of their service; or

iii.

He/she is a Colombian national and:

Has a spouse or permanent companion, or dependent children, who are tax residents in Colombia, or

50% or more of his or her total income is Colombian source income, or

50% or more of his or her assets are managed in Colombia, or

50% or more of his or her assets are deemed to be located or possessed in Colombia, or

Has failed to provide proof of residency in another country (different from Colombia) upon previous official request by the Colombian tax office, or

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:

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:

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.

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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.

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.

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The dividend tax regime as of 2020 was modified as follows:

ii.

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.

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%).

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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.

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.

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Distributions on Common Shares or ADSs

A distribution to U.S. Holders made by us of cash or property with respect to common shares or ADSs generally will be treated as a dividend for U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Distributions in excess of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, will be treated first as a tax-free return of capital reducing such U.S. Holder’s adjusted tax basis in the common shares or ADSs. Any distribution in excess of such adjusted tax basis will be treated as capital gain and will be either long-term or short-term capital gain depending upon whether the U.S. Holder held the common shares or ADSs for more than one year. Distributions of additional common shares or ADSs to U.S. Holders that are part of a pro rata distribution to all of our shareholders generally will not be subject to U.S. federal income tax. We do not maintain calculations of our earnings and profits under U.S. federal income tax principles, and, therefore, except as described in the previous sentence, U.S. Holders should expect that any distributions generally will be reported as dividends for U.S. federal income tax purposes. As used below, the term “dividend” means a distribution that constitutes a dividend for U.S. federal income tax purposes.

The amount of any distribution will include the amount of any Colombian tax withheld on the amount distributed, and the amount of a distribution paid in Colombian Pesos will be measured by reference to the exchange rate for converting Colombian Pesos into U.S. dollars in effect on the date the distribution is received by the Depositary (or by a U.S. Holder in the case of a holder of common shares) regardless of whether the payment is in fact converted into U.S. dollars. If the Depositary (or U.S. Holder in the case of a holder of common shares) does not convert such Colombian Pesos into U.S. dollars on the date it receives them, generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend payment is included in income to the date the payment is converted into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income (as discussed below). The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.

If you are a non-corporate U.S. Holder, dividends that constitute qualified dividend income will be taxable to you at the preferential rates applicable to long-term capital gains, provided that you meet certain holding requirements. Dividends paid on the ADSs will be treated as qualified dividend income if (1) the ADSs are readily tradable on an established securities market in the United States and (2) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a passive foreign investment company (PFIC). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States, as long as they are so listed. Based on our audited financial statements and relevant market and shareholder data, we believe that we were not treated as a PFIC for U.S. federal income tax purposes with respect to our 2019 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 2020 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.

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Sale, Exchange or Other Taxable Dispositions of Common Shares or ADSs

A U.S. Holder generally will recognize capital gain or loss upon the sale, exchange or other taxable disposition of common shares or ADSs in an amount equal to the difference between the U.S. dollar value of the amount realized on the sale, exchange or other taxable disposition of the common shares or ADSs and the U.S. Holder’s adjusted tax basis, determined in U.S. dollars, in the common shares or ADSs. Any gain or loss will be long-term capital gain or loss if the common shares or ADSs have been held for more than one year. Certain non-corporate U.S. Holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. The deductibility of capital losses is subject to limitations under the Code.

If you are a U.S. Holder of common shares or ADSs, the initial tax basis of your common shares or ADSs will be the U.S. dollar value of the Colombian Peso-denominated purchase price determined on the date of purchase. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis U.S. Holder, or, if it elects, an accrual basis U.S. Holder, will determine the dollar value of the cost of such common shares or ADSs by translating the amount paid at the spot rate of exchange on the settlement date of the purchase. Such an election by an accrual basis U.S. Holder must be applied consistently from year to year and cannot be revoked without the consent of the Internal Revenue Service (IRS). If you convert U.S. dollars to Colombian Pesos and immediately use that currency to purchase common shares or ADSs, such conversion generally will not result in taxable gain or loss to you.

With respect to the sale or exchange of common shares or ADSs, the amount realized generally will be the U.S. dollar value of the payment received determined on (1) the date of receipt of payment in the case of a cash basis U.S. Holder and (2) the date of disposition in the case of an accrual basis U.S. Holder. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis taxpayer, or, if it elects, an accrual basis taxpayer, will determine the U.S. dollar value of the amount realized by translating the amount received at the spot rate of exchange on the settlement date of the sale.

Deposits and withdrawals of common shares in exchange for ADSs, and of ADSs for common shares, generally will not result in the realization of gain or loss for U.S. federal income tax purposes.

Backup Withholding and Information Reporting

In general, dividends on common shares or ADSs, and payments of the proceeds of a sale, exchange or other taxable disposition of common shares or ADSs, paid within the United States, by a U.S. payer through certain U.S.-related financial intermediaries to a U.S. Holder are subject to information reporting and may be subject to backup withholding at a current rate of 24%, unless the holder (1) establishes that it is a corporation or other exempt recipient or (2) with respect to backup withholding, provides an accurate taxpayer identification number and certifies that it is a U.S. person and that no loss of exemption from backup withholding has occurred.

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.

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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). Since September 25, 1999, the Colombian foreign exchange regime is structured under the system of free flotation of the exchange rate, whereby market forces determine the level of exchange rate from time to time.

Foreign portfolio investments must be made through authorized foreign exchange investment management companies. 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 March 27, 2020, the Representative Market Exchange Rate was COP$ 3,996 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, 2020:

Table 58 – Major Shareholders

	At March 31, 2020
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 20, 2020, the registration date of our annual general shareholders’ meeting, 2.15% of our common shares were held of record in the form of American Depository Shares, we had 38 registered holders, and 14,522 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;

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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;

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.

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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.

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:

Boards of Directors: Ecopetrol and Subsidiaries

Promote best management practices in the Boards of Ecopetrol and in the other Ecopetrol Group companies.

Ensure alignment of the strategy under the Group’s management by segments.

ii.

Senior Management Committees

Establish the structure of the Senior Management Committees (operating, monitoring and improvement mechanisms).

Optimize Ecopetrol senior management time.

iii.

Matrix of Decisions and Attributions

Define the key or more relevant decisions of the Ecopetrol Group.

Establish which governing bodies are responsible for making key decisions.

Define how these decisions are made.

iv.

Relationship Model

Establish the way in which the areas within the Ecopetrol Group’s scope are related to the Group’s companies.

Capture the Ecopetrol Group synergies.

Manage articulation through management or administration by segments.

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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 National 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 National 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.

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. In addition, the bylaws were amended in the ordinary meeting of the General Shareholders Assembly held on March 27, 2020. 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.

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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.

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.

Preference Rights and Restrictions Attaching to Our Shares

There are only ordinary shares, and these carry no special rights or restrictions (ordinary shares). Our shareholders do not have any type of preemptive rights.

Under Commercial Colombian law, our shareholders have the following economic privileges and voting rights:

to participate and vote on the decisions of the General Shareholders Assembly;

to receive dividends based on the financial performance of the Company in proportion to their share ownership;

to transfer and sell shares according to our bylaws and Colombian law;

to inspect corporate books and records with 15 business days prior to the ordinary shareholders’ meeting where the year-end financial statements are to be approved;

upon liquidation, to receive a proportional amount of the corporate assets after the payment of external liabilities; and

to sell the shares, known as right of withdrawal (derecho de retiro), if a corporate restructuring affects the economic or voting rights of the shareholders in the terms and conditions established under Colombian law.

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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 agreement that gives us competitive and economic advantages over our competitors, or in respect of any document related to intellectual property. Shareholders also have the right to propose good corporate governance recommendations to the office for the protection of investors.

Others. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may propose recommendations to our Board of Directors pertaining to the management of our Company. Any shareholder may file a written petition to our Board of Directors to investigate corporate governance violations that the shareholder believes to have been committed.

Amendments to Rights and Restrictions to Shares

We have only one class of stock and it has no special rights or restrictions (ordinary shares). Our shareholders do not have any type of preemptive rights. The rights given to our shareholders by law are described in our bylaws and may only be modified through an amendment to the law.

The additional rights given to our minority shareholders in our bylaws and corporate governance code may only be modified through an amendment of those internal documents.

Limitations on the Rights to Hold Securities

There are no limitations in our bylaws or Colombian law on the rights of Colombian residents or foreign investors to own the shares of our Company, or on the right to hold or exercise voting rights with respect to those shares, except in cases of legal representation.

Restrictions on Change of Control Mergers, Spin-offs or Transformations of the Company

Under Colombian law and our bylaws, the General Shareholders Assembly has full authority to approve any mergers, spin-offs or transformations, subject to compliance of applicable law. Corporate restructurings are subject to the requirement that the Nation must hold a minimum of 80% of our common stock in any issuance of stock pursuant to Law 1118 of 2006.

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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 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 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 and security; social responsibility and respect for human rights; whistleblowing channel; and examples of ethical behaviors. As part of the Ethics guidelines of Ecopetrol, facilitation payments, political contributions 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 and suppliers, in addition to the personnel and companies that the contractors engage for the execution of the agreed activities.

All of our agreements with suppliers or third parties include a provision relating to compliance with applicable anti-bribery and anti-corruption regulations. These agreements also require our suppliers and third parties to accept our Code of Ethics and Conduct and our compliance manuals.

Our Code of Ethics and Conduct is available on our website at:

https://www.ecopetrol.com.co/wps/portal/web_es/ecopetrol-web/corporate-responsibility/ethics-and-compliance/code-of-ethics

7.3

Board of Directors

The current Board of Directors was elected at the General Shareholders Ordinary Meeting held on March 29, 2019, for a two-year term beginning on April 10, 2019.

The current Board of Directors is composed as follows:

Non-independent member:

General Secretary for the Ministry of Finance and Public Credit, currently Germán Eduardo Quintero Rojas.

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Independent members:

Orlando Ayala Lozano

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 (postulated by the oil producing departments in which Ecopetrol operates)

Carlos Gustavo Cano Sanz (postulated 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 29, 2019 for a two-year term beginning on April 10, 2019:

Germán Eduardo Quintero Rojas (44) has served as Managing Director of Fogafin, President of the National Hydrocarbons Agency, General Secretary and Advisor to the Ministry of Trade, Industry and Tourism, and General Secretary of the Ministry of Mines and Energy. He has been an advisor to the General Secretary of the Office of the President of the Republic of Colombia, General Secretary of the Ministry of Internal Affairs, General Director and General Secretary of Acción Fiduciaria S.A., and Head of the Legal Office of the Ministry of Finance and Public Credit. Mr. Quintero is a lawyer from Sergio Arboleda University, having studied administrative law and received a degree from Javeriana Pontifical 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. To date, he is a member of the board of directors at Financiera de Desarrollo Nacional (FDN) and Gecelca S.A. E.S.P. Currently, as the General Secretary of the Ministry of Finance and Public Credit, Mr. Quintero is a non-independent member of Ecopetrol’s Board of Directors.

Orlando Ayala Lozano (63) has 40 years of experience in the global technology industry, 25 years of which he spent working for Microsoft in Seattle, Washington, where he served in a number of managerial positions, including Vice President for the Intercontinental Region where he covered all countries in the southern hemisphere, Executive World Vice President for Sales, Marketing and Support, and World President for Emerging Markets. Before joining Microsoft, he worked for NCR Corp., where he held the position of Sales Director for NCR Mexico and Senior Product Manager in Dayton, Ohio. His studied information systems administration at Jorge Tadeo Lozano University in Bogotá in 1981, and received a Doctorate Honoris Causa granted by the same university in 1998, where he is member of the Management Board. Mr. Ayala was honored by the Antioquia newspaper El Colombiano with its 18th annual “Exemplary Colombian Citizen Living Abroad” award in 2013. Mr. Ayala is currently an independent director of the Executive Council of Centene Corp. (CNC). Currently, Mr. Ayala serves as an independent member of Ecopetrol’s Board of Directors and also serves as an international consultant and speaker on matters of leadership and technology trends.

Luis Guillermo Echeverri Vélez (62) has over 20 years of experience in the development, marketing, promotion and conducting of international business, imports and exports, the formulation and implementation of public and corporate policies, the development and implementation of conventional projects and information technology ventures, strategic planning, the financing of public and private projects and raising cooperation funds. 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 served as Commercial Attaché in Colombia’s diplomatic mission to the US and as Director of Proexport’s Miami Regional Office. Mr. Echeverri is an attorney who graduated from the Bolivarian Pontifical University of Medellín and earned a Master’s degree in Agricultural Economics from Cornell University, New York. Mr. Echeverri is an advisor in international businesses and has successfully led business initiatives and processes involving change and methodological and technological innovation and implementation in companies of various sizes and large organizations. He is currently serving as President of Primero Colombia Association, a non-governmental association dedicated to the promotion of democratic values and young leadership, Chairman of the Board of Directors of the Chamber of Commerce of Bogota, and a member of the Boards of Directors of Telefonica and Pragma. Currently, Mr. Echeverri is Chairman and independent member of Ecopetrol’s Board of Directors.

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Juan Emilio Posada Echeverri (61) has been the CEO of several large companies and is currently both a professional board member and an entrepreneur. He has sat on the boards of companies in the fields of insurance, air travel, hotels, infrastructure, telecoms, banks, technology start-ups, trading companies, trade associations, international and domestic chambers of commerce and local and international non-governmental associations. He was also the Founder, Chairman, Executive Chairman 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-in-Chief of Synergy Aerospace. Mr. Posada is also a member of the board of Avianca Holdings and was formerly the CEO of Avianca Airlines, Alianza Summa (Avianca-Aces-Sam) and Aces airlines. Mr. Posada currently serves as Executive Chairman of Táximo Ltd., Chairman of Direktio and Fundacion Plan, director of Allianz Life and Allianz General in Colombia, Sociedad Hotelera Tequendama (seven hotels in Colombia), Plan International (Brazil) and a member of the nominations and governance committee of the Global Assembly of Plan International. Mr. Posada holds a degree in Business Administration from EAFIT University in Medellin, Colombia, an MBA from Pace University in New York and a degree in International Financial Law from the London School of Economics. His experience in audit and risks has been acquired through his time on the finance and audit committees of the boards of directors at different companies and at the Banco Nacional del Comercio, Corredores Asociados (a securities brokerage house in Colombia), among other activities. He is also a member of the advisory councils of Grupo Empresarial del Sector Defensa (GESED), Disán (international fertilizer and chemicals trading company), Flores de la Campiña (producer and exporter of fresh flowers), of YPO Gold Colombia (global network of CEO’s) and NT3 (developers of real estate projects of which he is also a founder), Polymath Ventures, AMROP-Top Management and the Orchestra of the Americas. Currently, Mr. Posada serves as an independent member of Ecopetrol’s Board of Directors.

Sergio Restrepo Isaza (58) served in the Bancolombia Group as Vice President for Capital Markets and Executive Vice President for Corporate Development. He initiated his professional career at Corporación Financiera Corfinsura, where he held the positions of Company President, Vice President for Investment Banking and Vice President for Investments and International. He also served in several boards 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. Mr. Restrepo graduated with a degree in Business Administration from EAFIT University of Medellín, with a master’s degree in Business Administration from Stanford University in California. He has extensive experience in the areas of audit and risk, and during his time in the financial sector, he was a member of the finance and audit committees of the boards of directors at different companies where he took a very active role in the analysis of financial statements and was in charge of the investor’s relations of many of these companies. He is currently a partner at Exponencial Banca de Inversión S.A.S., a member and Chairman of the Board of directors of the BIOS SAS Group, and a member of the boards of directors of Odinsa S.A. and Consorcio Financiero. Currently, Mr. Restrepo serves as an independent member of Ecopetrol’s Board of Directors.

Santiago Perdomo Maldonado (62) has over 30 years of senior management experience in the Colombian banking industry, including as President of Banco Colpatria, Scotiabank Group. He has been a member of various boards of directors at Colombian and Latin American companies in a range of economic sectors, such as finance and mining and agriculture, including Bladex, Deceval, CESA, the Asociación Nacional de Empresarios de Colombia (ANDI), and the Asociación Nacional de Instituciones Financieras (ANIF), and he was a founding member of the Colombian Institute of Corporate Governance. Mr. Perdomo holds a degree in business administration from the CESA School of Advanced Studies in Administration. He is currently the Executive Director of the Colpatria Group and Mineros S.A. Currently, Mr. Perdomo serves as an independent member of Ecopetrol’s Board of Directors.

Esteban Piedrahita Uribe (48) is President of the Commerce Chamber of Cali and previously served as General Director of Colombia’s National Planning Department, advisor to the President and Senior Specialist at the Inter-American Development Bank and Economics Editor of the Semana’s magazine, among other positions. He has served on the boards of directors of Banco Agrario, Metrocali, Amalfi S.A. Carvajal Educación and Alianza Valores. Mr. Piedrahita graduated with a degree in economics from Harvard University and earned a master’s degree in philosophy and history of science from the London School of Economics and Political Science. Mr. Piedrahita is currently a member of the Boards of Directors of Cementos Argos and Centro de Eventos Valle del Pacífico, a member of the Board of Fedesarrollo and the Advisory Council of Panthera Foundation in Colombia, and he previously served on the local Advisory Council of The Nature Conservancy. Currently, Mr. Piedrahita serves as an independent member of Ecopetrol’s Board of Directors.

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Hernando Ramírez Plazas (66) has held positions at Universidad Surcolombiana as Dean of the Faculty of Engineering, Academic Vice-Principal, Principal, and Professor. He has worked at the National Institute of Health and at the Ministry of Health. He had a role as an external evaluator for Colciencias in technology development and innovation projects in the area of natural gas. Additionally, he has acted as a trainer in gas issues for production personnel at Canacol Energy Inc., and he currently provides professional services to Comfamiliar Huila. Mr. Ramirez is a chemical engineer who graduated from the Universidad Nacional de Colombia, with a master’s degree in public health from the same university, and a specialization in gas engineering from the Universidad de Zulia (Venezuela).

Carlos Gustavo Cano Sanz (73) has been President of the Colombian Agriculture Association (SAC), Founder and Director of Corporación Colombia Internacional (CCI), President of the Agrarian Bank, and President of the newspaper El Espectador. He was the Minister of Agriculture between August 7, 2002 and February 3, 2005 and the Co-Director of Banco de la República between February 4, 2005 and January 31, 2017. He is an Economist from the Universidad de los Andes in Bogotá with a master’s degree in economics from the University of Lancaster in England and a postgraduate degree in government, business and international economics from Harvard University in Boston and undertook further postgraduate studies at the Instituto de Alta Dirección Empresarial (INALDE) of Bogotá. He currently teaches in the Master of Corporate Finance program at CESA University and in the Business School at Universidad de los Andes. He is a member of the Superior Council of the EAFIT University of Medellín, the Consultative Committee for Agriculture of Bancolombia. Mr. Cano has served as an independent Director in Ecopetrol’s Board of Directors, since March 31, 2017.

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 29, 2019. 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.

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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, compensation and nomination 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.

Table 59 – Composition of committees of the Board of Directors as of March 31, 2020

Audit and Risk Committee		Compensation and Nomination 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		Luis Guillermo Echeverri
(President)		(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

This Committee met for the first time on September 12, 2019.

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Audit and Risk Committee

Our audit and risk committee, which must be comprised of at least three members, all of them independent Directors, is our highest internal control body and provides support to our Board of Directors on risk, accounting and financial matters. It is in charge of guaranteeing the design, implementation and supervision of our internal control over financial reporting. It also ratifies the annual hydrocarbons reserves report and provides support for our Board on analyzing topics related to financial matters, risks, control 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.

Compensation and Nomination Committee

Our compensation and nomination 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.

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, makes proposals to our Board of Directors to ensure and supervise the fulfillment of our good corporate governance and sustainability practices in accordance with our corporate governance code.

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 in respect of the monitoring and management of risks associated with the health and safety of our employees, contractors and partners, as well as the performance of the Ecopetrol Group’s environmental management.

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 in respect of the technological and digital transformation, as well as the cultural change that Ecopetrol is going through in order to transform Ecopetrol into a leading company in the use of technology and digital innovation in the hydrocarbons sector.

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7.4

Compliance with NYSE Listing Rules

The following is a summary of the significant differences between our corporate governance practices and those required for U.S. companies under the NYSE listing standards.

NYSE Standards		Our Corporate Governance Practices
*Director Independence*
The majority of the board of directors must be independent. §303A.01. “Controlled companies,” which would include Ecopetrol if we were a U.S. issuer, are exempt from this requirement. A controlled company is one in which more than 50% of the voting power is held by an individual, group or another company, rather than the public. §303A.00.		Pursuant to our bylaws, the majority of the Board of Directors must be independent. As of the date of this annual report, we have eight independent Directors and one non-independent Director without Ministerial rank.

*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.

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NYSE Standards		Our Corporate Governance Practices
*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.

*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 (54) has served as the Chief Executive Officer of Ecopetrol since September 2017. Prior to being appointed Chief Executive Officer, Mr. Bayón served as Chief Operating Officer of Ecopetrol from February 2016, overseeing the upstream, midstream, downstream, technology, engineering, projects and marketing operations, as well as the research and innovation areas. Mr. Bayon holds a degree in mechanical engineering from Universidad de Los Andes (Bogotá, Colombia). He has over 27 years of experience in the oil and gas industry. 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 (60) 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 Equion Energia Limited, where he also served as the Vice-President for Projects and Production between 2011 and 2016. Mr. Consuegra began his professional career in 1984 at Morrison Knudsen International as a contract coordinator during the construction of the 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.

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Jaime Caballero Uribe (45) 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 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 (58) 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.

Jorge Arturo Calvache Archila (59) has served as Vice-President of Exploration since February 1, 2019. He has more than 30 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, a master’s degree in geophysics from the same university, and studied management at the Universidad de Los Andes.

Rubén Darío Moreno Rojas (54) has served as Vice-President of Transport Operations and Maintenance since March 1, 2019. Prior to his appointment as Vice-President of Transport Operations and Maintenance, he had served as deputy Vice-President of Transport Operations and Maintenance since April 2018. He has a 30-year career at Ecopetrol S.A., where he has held several managerial positions in the Vice-Presidency of Transportation including Operations Manager, Technical Superintendent, Head of Maintenance and Head of Operations. Mr. Moreno holds a degree in electronic engineering from the Universidad Antonio Nariño and an executive MBA from the Universidad la Sabana.

Jurgen Gerardo Loeber Rojas (62) 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 Equion Limited (formerly BP Exploration Colombia) as Project Director. From 2001 to 2006, he was Project Director for Wood Group Colombia.

Pedro Fernando Manrique Gutierrez (55) has served as the Commercial and Marketing Vice President of Ecopetrol since April 2017. Mr. Manrique is also a member of the boards of directors of Reficar, Cenit and Invercolsa. 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 29 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 (57) 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.

168

Juan Manuel Rojas Payán (48) has served as Vice-President for Strategy and New Business 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 pistory of economic thought at the University of the Andes in Colombia.

Orlando Díaz (64) has served as Vice-President of Transformation since June 2019. Prior to his current assignment, he served as Barrancabermeja Refinery’s General Manager since 1986. He holds a degree in chemical engineering from Universidad Industrial de Santander and executive MBA from Universidad de los Andes. As General Manager, he implemented transformation strategies focused on the integral development of people from the perspectives of their technical and human competences, while directing the incorporation into the operation of modern concepts of management and leadership. In addition, Mr. Diaz executed initiatives related to innovation, creativity and collective leadership that allowed the Barrancabermeja Refinery to improve its economic margins and the reliability and availability of the facilities. Currently, Mr. Diaz leads the incorporation of agile methodologies to accelerate the implementation of our main business strategies.

Yeimy Báez (40) has served as Gas Vice-President since March 2020. In this position, Ms. Báez will be responsible for leading, strengthening and executing an integrated strategy to develop gas, which being a clean energy source, is fundamental for energy transition and Ecopetrol Group’s sustainability. She has over 16 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 Equion, BP and Weatherford; her achievements include a decisive leadership in the strategic portfolio management in Ecopetrol, leveraging disciplined and rigorous investment decisions as well as the design of the 3-year business plan.

Mauricio Jaramillo Galvis has served as Vice-President of Health, Safety and Environment (HSE) since January 2020. Mr Jaramillo has 25 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 Strategic Planning 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 a master’s degree 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 (53) will serve as Vice-President of Refining and Industrial Processes starting 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 (64) 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 Finaciera Colombiana. Mr. Bejarano Arias has been 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.

169

Mónica Jiménez González (44) has served as Secretary General of Ecopetrol S.A. since July 2016. 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, cross-border transactions, and corporate law. 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 (44) 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. 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 others.

Alejandro Arango Lopez (60) has served as Vice-President of Human Resources at Ecopetrol S.A. since October 2014. He has more than 20 years of professional experience around the world 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.

Andres Eduardo Mantilla Zarate (49) has served as the Director of the Colombian Petroleum Institute of Ecopetrol, the technology development 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 oil and gas technology development, demonstration and implementation teams. 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.

Isabel Cristina Ampudia Rendón (52) has served as interim Vice-President of Sustainable Development at Ecopetrol since February 2020. She is an agronomist - zootechnist from the Universidad Nacional de Colombia and holds a master’s degree in political studies from Universidad Javeriana, an MBA from the Universidad del Valle. She is also a specialist in public management for social development at Alcalá de Henares University of Spain. She has worked as Coordinator at the National Center for Territorial Advice of the National Federation of Coffee Growers in the Departamental Committee of Coffee Growers of Valle del Cauca (Colombia), as Project Director at the Corporation for Development and Peace of Valle del Cauca, as National Director of the National Network of Regional Programs of Peace and Development, and as Executive Director of the Association of Petroleum Foundations. She has also worked in the academic arena, teaching at recognized universities in Colombia.

Carlos Andrés Santos Nieto (42) has served as Vice-President of Supply and Services since August 7, 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 Equion 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.

170

Ernesto Gutiérrez de Piñeres (46) 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$5.2 million for 2020 and COP$5.0 million for 2019. See Note 30.1 to our consolidated financial statements for more details.

During 2019, the total compensation paid to our Directors, executive officers and senior management active amounted to COP$26.52 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.

Only three members of our management team are eligible to receive pension and retirement benefits from us. The total amount recorded as of December 31, 2019 to provide pension and retirement benefits amounted to COP$18,740 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 60 – Executive Officers owning Ecopetrol’s shares

Executive Officer	Shares⁽¹⁾		%
Felipe Bayón Pardo		8,418		0.00002	%
Jaime Eduardo Caballero Uribe		30,000		0.00007	%

(1)

As of March 25, 2020.

Under Colombian law, all of our shareholders have the same economic privileges and voting rights.

171

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, 2019, we evaluated the design and effectiveness of our financial disclosure controls and procedures under the supervision and participation of our management, including our Chief Executive Officer and Chief Financial Officer. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even if effective, disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of the end of the period covered by this annual report, our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in the reports that we file and submit under the Securities Exchange Act of 1934 is recorded, summarized and reported as and when required and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15(d)-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and monitored by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles, and it includes those policies and procedures that: i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets; ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorization of our management and directors; and iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, effective control over financial reporting cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projection of any evaluation of the effectiveness of the internal controls to future periods is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

As of the year ended December 31, 2019, our management conducted an assessment of the effectiveness of our internal control over financial reporting in accordance with the criteria established in the publication “Internal Control – Integrated Framework (2013),” issued by the Committee of the Sponsoring Organizations of the Treadway Commission, as well as the rules set by the SEC in its Final Rule “Management’s Report on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports.”

Consistent with the guidance issued by the Securities and Exchange Commission that an assessment of recently acquired businesses may be omitted from management’s annual report on internal control over financial reporting in the year of acquisition, management excluded the assessment of the effectiveness of internal control over financial reporting of Inversiones de Gases de Colombia S.A. and its subsidiaries (“Invercolsa”). Invercolsa, which is included in the 2019 consolidated financial statements of the Company, represented 0.8% of total and net assets as of December 31, 2019, and 0.1% and 0.2% of revenues and net income, respectively, for the year then ended. More details regarding Invercolsa’s acquisition can be found in note 12 of our 2019 consolidated financial statements.

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.

172

Audit and Non-Audit Fees

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

Table 61 – Fees Billed to us by Ernst & Young Audit S.A.S.

	As of December 31,
	2019		2018
	(in millions of Colombian Pesos, excluding 19% value added tax)
Audit fees		10,343		11,742
Audit-related fees		–		19
Tax fees		–		71
All other fees		–		–
Total		10,343		11,832

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.

Audit-related Fees. The audit-related fees listed in the table above are the fees billed by Ernst & Young Audit S.A.S. in connection with their agreed-upon procedures of our variable compensation bonus system and its review procedures in connection with the offering document related to the SEC-registered bonds we reopened in 2016.

Tax Fees. For 2018 the tax fees listed in the table above correspond to a conceptual analysis for a subsidiary about the tax consequences associated with new or proposed legislation based on the economic models prepared by the subsidiary.

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, 2019 that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

Attestation Report of the Registered Public Accounting Firm

Ernst & Young Audit S.A.S.’s attestation report on our internal control over financial reporting is included in their audit report accompanying our consolidated financial statements. See Report of Independent Registered Public Accounting Firm to the consolidated financial statements.

Significant Changes

For a description of significant events since December 31, 2019, please see Note 33 to our consolidated financial statements.

173

Financial Statements

Ecopetrol S.A.
Consolidated Financial Statements
At December 31, 2019 and 2018 and for three years ended December 31, 2019, 2018 and 2017

174

Index

Report of Independent Registered Public Accounting Firm – Financial Statements		F-2
Report of Independent Registered Public Accounting Firm – Internal Control over Financial Reporting		F-5
Consolidated statement of financial position		F-7
Consolidated statement of profit or loss		F-8
Consolidated statement of comprehensive income		F-9
Consolidated statement of changes in equity		F-10
Consolidated statement of cash flows		F-12
1.	Reporting entity	F-13
2.	Basis for presentation	F-13
3.	Significant estimates and accounting judgments	F-16
4.	Accounting policies	F-20
5.	New standards and regulatory changes	F-36
6.	Cash and cash equivalents	F-38
7.	Trade and other receivables, net	F-38
8.	Inventories, net	F-39
9.	Other financial assets	F-39
10.	Taxes	F-41
11.	Other assets	F-49
12.	Business combinations	F-50
13.	Investments in associates and joint ventures	F-52
14.	Property, plant and equipment	F-55
15.	Natural and environmental resources	F-57
16.	Intangible assets	F-60
17.	Impairment of non-current assets	F-61
18.	Goodwill	F-66
19.	Loans and borrowings	F-67
20.	Trade and other payables	F-70
21.	Provisions for employees’ benefits	F-70
22.	Accrued liabilities and provisions	F-75
23.	Equity	F-84
24.	Sales revenue from contracts with customers	F-86
25.	Cost of sales	F-87
26.	Administrative, operations and project expenses	F-88
27.	Other operating income (expenses), net	F-88
28.	Financial result, net	F-89
29.	Risk management	F-89
30.	Related parties	F-96
31.	Joint operations	F-99
32.	Information by segments	F-101
33.	Subsequent events	F-109
34.	Supplemental information on oil and gas producing activities (unaudited)	F-110
Exhibit 1 – Consolidated subsidiaries, associates and joint ventures		F-114
Exhibit 2 – Conditions of the most significant loans		F-117

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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 31, 2020 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 recoverable amount of long-lived assets in the Cartagena refinery

Description of

the Matter

As described in notes 4.12 and 17 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’s (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 2019, the Company reversed a previously recognized impairment loss in the Cartagena refinery of COP $911,597 million.

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 processes to determine the recoverable amount of the CGUs, including controls over management’s review of the significant assumptions described above.

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 performed a sensitivity analysis to evaluate the change in the recoverable amount that would result from changes in the underlying assumptions; we assessed the accuracy of the Company´s projections by comparing them to actual operating results and recalculated management's estimate projected model. 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.

F-3

Determination of depreciation, depletion and amortization and impairment of long-lived assets

Description of the Matter

As described in note 3.1 and 3.2 to the consolidated financial statements, the computation of the units-of-production method, 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 analyses of long-lived assets, uses the estimation related to oil and gas reserves. The estimation of oil and gas reserves is a Complex process and requires professional judgement.

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 and operating and capital costs to be incurred, sales price, among others.

Auditing the Company’s DD&A and impairment calculation was especially 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 of the process, evaluated the design, and tested the operating effectiveness of controls over the Company’s process to calculate 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.

Our audit procedures included, among others, evaluating the professional qualifications as of the individuals responsible for overseeing the preparation of the reserve estimates by the specialists. We also assessed the qualification and competence of the specialists engaged by the Company to develop these estimates. In addition, we evaluated the completeness and accuracy of the financial data and inputs described above used by the specialists in estimating oil and gas reserves by agreeing them to source documentation. 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.

/s/ Ernst & Young Audit S.A.S.

We have served as the Company’s auditor since 2016.

Bogota, Colombia

March 31, 2020

F-4

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, 2019, 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, 2019, based on the COSO criteria.

As indicated in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Inversiones de Gases de Colombia S.A. and its subsidiaries (“Invercolsa”), which is included in the 2019 consolidated financial statements of the Company and constituted 0.8% of total and net assets as of December 31, 2019 and 0.1% and 0.2% of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Invercolsa.

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, 2019 and 2018, 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, 2019, and the related notes and the financial statement schedules listed in exhibits 1 and 2 and our report dated March 31, 2020 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-5

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

March 31, 2020

F-6

Ecopetrol S.A.

Consolidated statement of financial position

(In millions of Colombian pesos)

		As of December 31,
	Note	2019		2018
Assets
Current assets
Cash and cash equivalents	6		7,075,758		6,311,744
Trade and other receivables, net	7		5,700,334		8,194,243
Inventories, net	8		5,658,099		5,100,407
Other financial assets	9		1,624,018		5,321,098
Current tax assets	10		1,518,807		1,031,307
Other assets	11		1,778,978		1,020,428
			23,355,994		26,979,227
Assets held for sale			8,467		51,385
Total current assets			23,364,461		27,030,612
Non–current assets
Trade and other receivables, net	7		786,796		755,574
Investment in associates and joint ventures	13		3,245,072		1,844,336
Property, plant and equipment	14		64,214,822		62,799,983
Natural and environmental resources	15		29,072,798		23,075,450
Right-of-use assets	5.1		456,225		—
Intangible assets	16		483,098		410,747
Deferred tax assets	10		6,809,347		3,879,427
Other financial assets	9		3,355,274		2,826,717
Goodwill	18		1,159,922		1,159,922
Other assets	11		942,481		860,730
Total non–current assets			110,525,835		97,612,886
Total assets			133,890,296		124,643,498
Liabilities
Current liabilities
Loans and borrowings	19		5,012,173		4,019,927
Trade and other payables	20		10,689,246		8,945,790
Provisions for employee benefits	21		1,929,087		1,816,882
Current tax liabilities	10		2,570,779		1,751,300
Accrued liabilities and provisions	22		789,297		814,409
Other liabilities			751,717		476,314
Total current liabilities			21,742,299		17,824,622
Non–current liabilities
Loans and borrowings	19		33,226,966		34,042,718
Trade and other payables	20		24,445		30,522
Provisions for employee benefits	21		9,551,977		6,789,669
Deferred tax liabilities	10		1,328,831		1,337,943
Non current tax liabilities	10		70,543		—
Accrued liabilities and provisions	22		9,128,991		6,939,603
Other liabilities			584,616		570,641
Total non–current liabilities			53,916,369		49,711,096
Total liabilities			75,658,668		67,535,718
Equity
Subscribed and paid in capital	23.1		25,040,067		25,040,067
Additional paid in capital	23.2		6,607,699		6,607,699
Reserves	23.3		3,784,658		5,138,895
Other comprehensive income			6,646,660		8,380,761
Retained earnings			12,334,706		9,970,492
Equity attributable to owners of parent			54,413,790		55,137,914
Non–controlling interest			3,817,838		1,969,866
Total equity			58,231,628		57,107,780
Total liabilities and equity			133,890,296		124,643,498

F-7

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	2019			2018			2017
Sales revenue	24		71,488,512			68,603,872			55,954,228
Cost of sales	25		(44,972,360	)		(41,184,379	)		(36,908,325	)
Gross profit			26,516,152			27,419,493			19,045,903
Administrative expenses	26		(2,151,599	)		(1,653,858	)		(1,764,524	)
Operations and project expenses	26		(2,631,754	)		(2,903,132	)		(2,926,065	)
(Impairment loss) reversal of impairment loss of non-current assets, net	17		(1,762,437	)		(368,634	)		1,311,138
Other operating income (expenses), net	27		1,056,796			(35,455	)		505,403
Operating income			21,027,158			22,458,414			16,171,855
Financial results, net	28
Finance income			1,623,336			1,129,563			1,159,356
Finance expenses			(3,334,469	)		(3,512,161	)		(3,660,601	)
Foreign exchange gain			40,639			372,223			5,514
			(1,670,494	)		(2,010,375	)		(2,495,731	)
Share of profits of associates and joint ventures	13		366,904			165,836			93,538
Profit before income tax expense			19,723,568			20,613,875			13,769,662
Income tax expense	10		(4,718,413	)		(8,258,485	)		(5,800,268	)
Net profit for the year			15,005,155			12,355,390			7,969,394
Net profit attributable to:
Owners of parent			13,744,011			11,381,386			7,178,539
Non–controlling interest			1,261,144			974,004			790,855
			15,005,155			12,355,390			7,969,394
Basic and diluted earnings per share	23.6		334.3			276.8			174.6

F-8

Ecopetrol S.A.

Consolidated statement of comprehensive income

(In millions of Colombian pesos)

		For the years ended December 31,
	Note	2019			2018			2017
Net profit for the year			15,005,155			12,355,390			7,969,394

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	29.1.2		238,331			(533,374	)		(84,837	)
Hedge of a net investment in a foreign operation	29.1.3		(61,267	)		(971,954	)		57,997
Cash flow hedge with derivative instruments			46,451			(52,174	)		35,768
Unrealized loss on equity instruments measured at fair value			—			—			(7,828	)
Foreign currency translation			8,701			2,599,242			(257,147	)
			232,216			1,041,740			(256,047	)
Other comprehensive income that will not to be reclassified to profit or loss in subsequent periods -net of taxes:
Remeasurement loss on defined benefit plans	21.1		(1,799,829	)		(4,290	)		(1,548,043	)
Other gains (losses)			(175,494	)		—			(11,817	)
			(1,975,323	)		(4,290	)		(1,559,860	)
Other comprehensive income -loss for the year, net of tax			(1,743,107	)		1,037,450			(1,815,907	)
Total comprehensive income for the year, net of tax			13,262,048			13,392,840			6,153,487

Comprehensive income attributable to:
Owners of parent			11,502,149			12,363,132			5,353,778
Non–controlling interest			1,759,899			1,029,708			799,709
			13,262,048			13,392,840			6,153,487

F-9

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, 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 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

		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-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, 2016			25,040,067		6,607,699		1,558,844		9,222,710			(402,462	)		42,026,858			1,533,643			43,560,501
Net profit			—		—		—		—			7,178,539			7,178,539			790,855			7,969,394
Dividends declared	23.4		—		—		—		—			(945,684	)		(945,684	)		(551,494	)		(1,497,178	)
Appropriation of reserves, net			—		—		619,025		—			(619,025	)		—			—			—
Other movements			—		1		—		2			(1,066	)		(1,063	)		(48	)		(1,111	)
Other comprehensive income:
Gain (loss) on hedging instruments
Cash flow hedge for future exports			—		—		—		(84,837	)		—			(84,837	)		—			(84,837	)
Hedge of a net investment in a foreign operation			—		—		—		57,997			—			57,997			—			57,997
Cash flow hedge with derivative instruments			—		—		—		25,984			—			25,984			9,784			35,768
Loss on equity instruments measured at fair value			—		—		—		(7,828	)		—			(7,828	)		—			(7,828	)
Foreign currency translation			—		—		—		(255,153	)		—			(255,153	)		(1,994	)		(257,147	)
Remeasurement loss on defined benefit plans			—		—		—		(1,548,043	)		—			(1,548,043	)		—			(1,548,043	)
Other movements			—		—		—		(11,817	)		—			(11,817	)		—			(11,817	)
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

F-11

Ecopetrol S.A.

Consolidated statement of cash flows

(In millions of Colombian pesos)

		For the years ended December 31,
	Note	2019			2018			2017
Cash flow provided by operating activities:
Net profit for the period			15,005,155			12,355,390			7,969,394
Adjustments to reconcile the net profit to net cash provided by operating activities:
Income tax expense	10		4,718,413			8,258,485			5,800,268
Depreciation, depletion and amortization	5.1, 14,15,16		8,582,783			7,704,850			8,281,347
Foreign exchange income	28		(40,639	)		(372,223	)		(5,514	)
Finance cost of loans and borrowings	28		1,894,490			2,399,414			2,385,994
Finance cost of post–employment benefits and abandonment costs	28		757,509			668,782			753,047
Withdrawal of exploratory assets and dry wells	15		340,271			898,924			898,264
Loss on disposal of non–current assets			121,121			75,835			26,686
(Gain) loss on acquisition of participations	27		(1,048,924	)		12,065			(451,095	)
Loss on impairment of short–term assets	27		90,441			136,044			30,600
Impairment loss (reversal) of non-current assets	17		1,762,437			368,634			(1,311,138	)
Loss (gain) on fair value adjustment of financial assets			18,551			(92,906	)		(104,706	)
Share of profit of associates and joint ventures			(366,904	)		(165,836	)		(93,538	)
Net gain on the sale of assets held for sale			(2,846	)		—			(166,389	)
Gain on sale of equity instruments measured at fair value						—			(13,236	)
Hedge ineffectiveness			5,173			35,239			8,918
Realized loss (gain) on foreign exchange cash flow hedges	24		386,773			(128,404	)		(160,772	)
Net change in operational assets and liabilities:
Trade and other receivables			2,381,905			(2,039,161	)		(2,189,473	)
Inventories			(597,552	)		(448,135	)		(323,626	)
Trade and other payables			1,389,064			1,355,175			21,417
Tax assets and liabilities			(1,409,334	)		(1,413,915	)		(493,533	)
Provisions for employee benefits			(234,629	)		(181,060	)		(227,384	)
Provisions and contingencies			(253,043	)		(89,345	)		104,135
Other assets and liabilities			(492,745	)		(218,542	)		451,263
			33,007,470			29,119,310			21,190,929
Income tax paid			(5,295,703	)		(6,650,116	)		(4,217,303	)
Net cash provided by operating activities			27,711,767			22,469,194			16,973,626
Cash flow from investing activities:
Investment in property, plant and equipment	14		(4,012,659	)		(3,302,929	)		(2,363,283	)
Investment in natural and environmental resources	15		(9,798,193	)		(5,051,828	)		(3,426,405	)
Acquisitions of intangibles	16		(168,289	)		(105,669	)		(175,868	)
Acquisition of interests in joint operations			—			—			(141,950	)
Sales (purchases) of other financial asset, net			3,117,549			(843,612	)		564,754
Interests received			481,674			383,624			405,562
Dividends received			189,169			108,991			270,136
Proceeds from sales of assets held for sale			—			—			159,041
Proceeds from sales of equity instruments measured at fair value			—			—			56,930
Proceeds from sales of property, plant and equipment			154,780			92,620			267,324
Net cash used in investment activities			(10,035,969	)		(8,718,803	)		(4,383,759	)
Cash flow used in financing activities:
Proceeds from borrowings			359,876			517,747			444,827
Repayment of borrowings			(1,596,630	)		(9,270,262	)		(9,007,340	)
Interest payments			(1,766,223	)		(2,610,562	)		(2,696,979	)
Lease payments	5.1		(300,326	)		—			—
Dividends paid			(13,867,029	)		(4,427,701	)		(1,504,647	)
Net cash used in financing activities			(17,170,332	)		(15,790,778	)		(12,764,139	)
Exchange difference in cash and cash equivalents			258,548			406,246			(290,310	)
Net increase (decrease) in cash and cash equivalents			764,014			(1,634,141	)		(464,582	)
Cash and cash equivalents at the beginning of the year			6,311,744			7,945,885			8,410,467
Cash and cash equivalent at the end of the year	6		7,075,758			6,311,744			7,945,885

Non-cash transactions
Recognition of right-of-use assets and lease liabilities	5.1		685,128			—			—
Fair value for change in participation in Invercolsa	12		2,932,110			—			—

F-12

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017 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 March 31, 2020.

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:

the percentage of the Ecopetrol Business Group’s voting rights relative to the size and apportionment of the shares of other vote holders;

potential voting rights held by the Ecopetrol Business Group, other vote holders or other parties;

rights arising from other contractual arrangements; and

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-13

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 were incorporated in the years indicated:

2019

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. See Note 12

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-14

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

Two companies in Mexico were incorporated to provide administrative and technology services to Ecopetrol Mexico. 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.

2017

Esenttia Resinas del Perú SAC: a wholly–owned subsidiary whose corporate purpose is to commercialize polypropylene resins and master batches in Peru.

ECP Hidrocarburos México S.A. de CV: a wholly–owned subsidiary, engaged in operating oil contracts in Mexico, starting with blocks 6 and 8 of Round 2.1 in shallow waters.

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.

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.

F-15

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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.

F-16

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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

Assets impairment

Management uses its professional judgment in assessing the existence of evidence of an impairment loss or reversal, based on internal and external factors.

When an indicator of impairment loss or reversal of impairment of prior 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 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. 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.

F-17

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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–financial 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 and transportation facilities, which include the cost of plugging and abandoning wells, dismantling facilities, and environmental remediation in the affected areas.

Estimated abandonment and dismantling costs are recorded at the time of the installation of the assets and are reviewed annually.

The calculations for these estimations are complex and involve significant judgments by Management. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing, extent and amount of expenditure may also change, for example, in response to changes in internal cost projections, changes in reserve estimates, future inflation rates and discount rates. The Ecopetrol 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.

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.

F-18

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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-19

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

Equity investments available for sale that do not have a market quotation price and for which fair value cannot be reliably measured are measured at cost less any impairment identified at the end of each reporting period.

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.

F-20

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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:

Financial assets measured at fair value through profit or loss

Financial assets are held for trading and financial assets designated at the time of the initial recognition at fair value through profit or loss. Financial assets are classified as held for trading if they are acquired to be sold or repurchased in the short term. They are recognized at their fair value and losses or profits arising at the time of re–measurement are recognized in the statement of profit or loss.

Financial assets measured at fair value with changes in other comprehensive income

These are equity instruments of other non–controlled and non–strategic companies not allowing for any type of control or significant influence thereon and where the Ecopetrol Business Group’s management does not intend to negotiate with them in the short term. These investments are recorded at their fair value and unrealized gains or losses are recognized in other comprehensive income.

F-21

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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. 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.

F-22

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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 accumulated in OCI are accounted for, depending on the nature of the underlying hedged transaction. 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.

F-23

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Ecopetrol designates long–term loans as hedging instruments for its exposure to the exchange risk in future oil exports. See Note 28 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 28 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.

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 30 – Related parties).

F-24

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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 records 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 contracts, it records 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 recorded 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.

F-25

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 operation, 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.

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.

F-26

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The estimated useful life of assets fluctuates in the following ranges:

Plant and equipment	11 – 60 years
Pipelines, networks and lines	11 – 50 years
Buildings	11 – 50 years
Other	6 – 40 years

Land is recorded 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 consolidated 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.

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.

F-27

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 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 — Asset impairment (reversal) and 4.12 — Impairment of non–financial 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.

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 in relation to research activities are expensed as incurred.

4.10

Goodwill

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. Goodwill is not amortized but tested for impairment annually.

F-28

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

4.11

Leases

As of January 1, 2019, the Group applied IFRS 16 – Leases. See Note 5.1.

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.

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. 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.

F-29

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

The carrying amount of the provision is reviewed and adjusted annually considering changes in the assumptions used for its estimation, using a rate that reflects the risk specific to the liability. 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.

F-30

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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.

F-31

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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:

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.

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

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.

F-32

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 20 – 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.

F-33

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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 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, petrochemicals and biofuels, 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 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 for Ecopetrol.

F-34

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

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.

F-35

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Exploration and production: This segment includes activities related to the exploration and production of oil and gas. Revenues are derived from sales of oil and natural gas at market prices to other segments and to third parties (domestic and foreign distributors). Costs include costs incurred in production. Expenses include all exploration costs that are not capitalized.

Transport and logistics: This segment includes sales revenue and costs associated with the transport and distribution of hydrocarbons and derivative products in operation.

Refining, petrochemicals and biofuels: This segment mainly includes activities performed at the Barrancabermeja and Cartagena refineries, where crude oil from production fields is refined or processed. 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 32.

New standards and regulatory changes

5.1

New standards adopted by the Group, effective as of January 1, 2019

IFRS 16 - Leases

As of January 1, 2019, the Ecopetrol Business Group adopted IFRS 16, “Leases” (“IFRS 16”). The effects of the adoption of IFRS 16 are described below:

IFRS 16 was issued in January 2016 and supersedes IAS 17 “Leases,” IFRIC 4 “Determining whether an Arrangement Contains a Lease” (“IFRIC 4”), SIC-15 “Operating leases – Incentives” and SIC-27 “Evaluating the Substance of Transactions in the Legal Form of a Lease.” IFRS 16 sets the principles of recognition, measurement, presentation and disclosure of leases and requires lessees to record all their leases under a balance sheet registration model similar to the recording of financial leases under IAS 17. The standard includes two practical expedients for lessees: leases of low-value assets and short-term leases (those with lease terms of 12 months or less). On the commencement date of the lease, a lessee is required to recognize a liability corresponding to the total lease payments and a right-of-use asset which is an asset representing the lessee’s right-of-use of the leased asset during the lease term. The lessees is required to separately recognize interest expense on the lease liability and the depreciation expense on the right-of-use asset.

The Ecopetrol Business Group elected to use the transition practical expedient not to reassess whether a contract is, or contains, a lease at January 1, 2019. Instead, the Group applied the standard only to contracts that were previously identified as leases under IAS 17 and IFRIC 4.

Effect of adoption

The Ecopetrol Business Group adopted IFRS 16, using the modified retrospective method of adoption. The Ecopetrol Business Group recognised right-of-use assets and subleases for COP$490,245 as of January 1, 2019, and a corresponding lease liability for the same amount. Therefore, there was no effect in retained earnings upon initial application.

Summary of the new accounting policies

Definition of a lease

Prior to the application of IFRS 16, the Ecopetrol Business Group assessed at contract inception whether a contract is, or contained, a lease in accordance with IFRIC 4. Upon application of IFRS 16, the Ecopetrol Business Group assesses whether a contract is, or contains, a lease by determining whether it conveys the right-of-use of an asset (the underlying asset) for a period of time in exchange for 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, the 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.

F-36

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 recognised, 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 recognised 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).

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 recognised in the statement of profit or loss on a straight-line basis over the lease terms.

Other leases are classified as finance leases, and the Ecopetrol Business Group records an account receivable, for an amount equal to the net investment in the lease.

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. In addition, the Ecopetrol Business Group assesses whether, due to the contractual characteristics of the lease, each of the parties to the joint arrangement need to account for their respective interests in the joint arrangement.

Amounts recognized in the consolidated statement of financial position and in consolidated statement of profit or loss:

The book values of the right-of-use assets, the lease liabilities and the movements for the period are detailed below:

	Right-of-use assets
	Lands and buildings			Plant and equipment			Vehicles			Right-of-use assets			Sublease			Lease liabilities
Balance as of December 31, 2018 (1)		—			—			—			—			—			797,889
IFRS 16 adoption (January 1, 2019)		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		(44,254	)		(50,944	)		(80,156	)		(175,354	)		—			—
Impairment loss		—			(53,488	)		—			(53,488	)		—			—
Disposals		(4	)		(57	)		—			(61	)		—			(50	)
Finance cost		—			—			—			—			3,302			76,139
Repayment of borrowings		—			—			—			—			(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

(1)

Corresponds to the balance recognized by the Group as a financial lease under IAS 17.

The right-of-use assets are tested for impairment.

F-37

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Cash and cash equivalents

	2019		2018
Banks		5,813,306		4,511,078
Short–term investments		1,262,105		1,799,597
Cash		347		1,069
		7,075,758		6,311,744

As of December 31, 2019, cash and cash equivalents balance included COP$85,286 (COP$92,331 as of December 31, 2018), 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, 2019 and 2018 were 3.2% and 3%, respectively.

The following table reflects the credit quality of issuers of investments included in cash and cash equivalents:

Rating	2019		2018
AAA		3,851,656		3,092,236
A-1		1,244,462		512,757
BRC1+		673,342		470,623
BBB		569,514		1,305,037
F1+		244,547		222,454
AA		229,473		107,520
A		167,404		—
A-2		89,996		147,186
BB		43		—
Baa2		10		—
A1		—		394,696
F1		—		48,566
Other		5,311		10,669
		7,075,758		6,311,744

See credit risk policy in Note 29.2.2

Trade and other receivables, net

	2019		2018
Current
Customers
Foreign		2,759,993		2,404,531
Domestic		2,015,517		1,512,821
Fuel price stabilization fund (1)		256,303		3,828,691
Accounts receivable from employees		95,693		78,459
Industrial services		47,691		154,152
Related parties (Note 30)		27,449		23,480
Other		497,688		192,109
		5,700,334		8,194,243

Non–current
Accounts receivable from employees		508,588		470,609
Related parties (Note 30)		93,657		117,824
Domestic customers		52,819		—
Other		131,732		167,141
		786,796		755,574

F-38

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(1)

Corresponds to the application of 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 2019, the Group received COP$5,359,869 from the stabilization fund as follows: Ecopetrol received COP$4,435,974 and Reficar received COP$923,895 for the year 2018 and the first three quarters of 2019.

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, 2019, 2018 and 2017 are as follows:

	2019			2018			2017
Opening balance		268,654			170,016			144,329
Additions, net		14,158			107,725			35,229
Accounts receivable write–off and uses		(21	)		(9,087	)		(9,542	)
Closing balance		282,791			268,654			170,016

Inventories, net

	2019		2018
Crude oil		1,965,022		1,958,572
Fuels and petrochemicals		1,876,247		1,524,548
Materials for the production of goods		1,816,830		1,617,287
		5,658,099		5,100,407

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 2019 was COP$9,759 (2018 - COP$30,252).

The following are the changes of the allowances for losses for the years ended December 31, 2019, 2018 and 2017:

	2019			2018			2017
Opening balance		(86,938	)		(194,507	)		(265,435	)
(Reversals) additions, net		(44,191	)		115,778			(9,134	)
Foreign currency translation		371			(9,717	)		4,266
Uses		(768	)		1,508			75,796
Closing balance		(131,526	)		(86,938	)		(194,507	)

Other financial assets

	2019		2018
Assets measured at fair value through profit or loss
Investment Portfolio – Local currency		1,630,149		3,389,869
Investment Portfolio – Foreign currency		3,340,908		4,754,369
		4,971,057		8,144,238
Assets measured at amortized cost		3,367		3,577
Hedging instruments		4,868		—
		4,979,292		8,147,815


Current		1,624,018		5,321,098
Non–current		3,355,274		2,826,717
		4,979,292		8,147,815

F-39

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The average return of the investment portfolio in Colombian pesos and U.S. dollars were approximately 5.4% (2018 – 5.4%) and approximately 3.6% (2018 – 2.1%), respectively.

Changes in fair value are recognized in financial results (Note 28).

9.1

Restrictions

As of December 31, 2019 and 2018, there were no investments with restricted use.

9.2

Maturity

	2019		2018
Up to 1 year		1,624,018		5,321,098
1 – 2 years		983,571		1,847,241
2 – 5 years		1,791,549		823,425
> 5 years		580,154		156,051
		4,979,292		8,147,815

9.3

Fair value

The following is the balance of other financial assets by fair value hierarchy level as of December 31, 2019 and 2018:

	2019		2018
Level 1		472,547		372,636
Level 2		4,503,378		7,771,602
		4,975,925		8,144,238

There were no transfers between hierarchy levels for the years ended December 31, 2019 and 2018.

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:

	2019		2018
AAA		2,707,019		3,105,894
A+		712,934		161,160
AA		477,423		15,430
F1+		350,325		353,175
AA-		186,325		455,584
A		186,222		80,334
BBB		159,968		—
AA+		155,012		193,747
BRC1+		—		611,905
BBB+		—		18,731
A1		18,168		3,148,043
Other		17,661		235
		4,971,057		8,144,238

See credit risk policy in Note 29.2.2.

F-40

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

10.

Taxes

10.1

Current tax assets and liabilities

	2019		2018
Current tax assets
Other taxes (1)		714,197		211,558
Income tax (2)		190,605		765,399
Credit tax balance (3)		614,005		54,350
		1,518,807		1,031,307
Current tax liabilities
Income tax (2)		1,967,353		1,065,688
Tax of industry and commerce		195,776		174,207
National tax and surcharge on gasoline		145,569		141,408
Carbon tax		54,586		48,520
Value added tax		33,098		168,185
Other taxes (4)		174,397		153,292
		2,570,779		1,751,300

Non-current tax liabilities (5)		70,543		—

(1)

It includes the potential tax discount for VAT incurred in the acquisition of real productive fixed assets, in accordance with article 83 of Law 1943 of 2018 – Tax reform, and territorial tax advances.

(2)

It mainly corresponds to the 2019 income tax provision, net of self-withholdings, balances in favor (refunds), advances tax payments filed in the statement of the immediately preceding year.

(3)

VAT balance in favor, among others.

(4)

It includes royalties, transport tax, among others.

(5)

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 and 2018. In compliance therewith, in May 2018 and 2019, the Group’s companies recognized an asset and a liability for the value of the projects designated for each fiscal year.

10.2

Income tax

The Constitutional Court judged Law 1943 of 2018 (Tax reform) to be unconstitutional and established that this decision would take effect as of January 1, 2020. However, the this law must be followed for the fiscal year 2019. Below is indicated the tax effects applicable in Colombia for 2019:

The income tax rate applicable to national companies, foreign companies with permanent establishments and foreign entities will be 33%.

The income tax rate for the 2018 tax year was 33% with a surcharge of 4% applicable on net income exceeding COP$800 million.

The income tax for tax free trade zone users will be 20%. The tax rate of companies located in a free trade zone with a legal stability agreement is 15% during term of the said agreement.

The presumptive income rate will decrease from 3.5% to 1.5% from 2018. Tax losses accumulated until December 31, 2016 that have not been compensated, may be carried forward in accordance to the formula provided in the article 290 of Law 1819/2016.

F-41

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

For fiscal year 2019, the Ecopetrol Business Group had subsidiaries that were subject to a 33% income tax rate, subsidiaries in free trade zones that were subject to a 15% or 20% income tax rate depending upon whether or not they complied with the CEJ rules and other subsidiaries that were subject to statutory income tax rates in the countries in which they were incorporated.

Depreciation and amortization methods and annual percentages are limited to those established in the tax rule and depends on the type of asset. For example, machinery and equipment depreciate at 10%, infrastructure (including pipelines) at 2.22% and vehicles and computers at 20%, among others. Additionally, oil investments can be amortized using the units-of-production method.

The cost of acquisition of exploration rights, geology and geophysics (G&G), exploratory drilling, etc., is capitalized for tax purposes until the technical and commercial feasibility of extracting the resource is achieved.

Tax losses may be offset against ordinary net income obtained in the following twelve taxable years.

In accordance with 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 with the formula provided for this purpose in said article and subject to the term established in Article 189 of the Tax Code.

In 2019, the National Government issued Law 2010, which modified certain substantive aspects of the Tax law. (See more detail in Note 10.2.4. Tax reform).

Statute of limitations on review of tax returns

By general rule, the statute of limitations for the income tax return is three (3) years from the deadline to timely file the return as of the date of expiration or as of the filing date, when these have been filed extemporaneously. Returns filed by taxpayers that have made transactions subject to the transfer pricing regulations have a statute of limitations of six years.

For tax returns in which tax losses are either originated or carried forward, the statute of limitations will be 12 years counted as of their filing dates.

Income tax expense

	2019			2018			2017
Current income tax		7,117,040			7,539,093			5,108,549
Deferred income tax		(2,365,108	)		783,136			472,772
Adjustments to prior years’ current and deferred tax		(33,519	)		(63,744	)		218,947
Income tax expenses		4,718,413			8,258,485			5,800,268

F-42

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Reconciliation of the income tax expenses

The reconciliation between the income tax expenses and the tax determined based on the statutory tax rate applicable to the Ecopetrol Business Group in Colombia is as follows:

	2019			2018*			2017*
Net income before income tax		19,723,568			20,613,875			13,769,662
Statutory rate		33%			37%			40%
Income tax at statutory rate		6,508,777			7,627,134			5,507,865
ETR reconciliation items:
Non–deductible expenses		295,550			379,633			271,414
Rate differential adjustment		132,888			172,352			186,588
Impairment of non–financial assets		57,646			(128,461	)		(175,750	)
Increase in shareholding in Invercolsa		(2,943	)		—			—
Non–taxable income		(524,658	)		(119,963	)		(107,881	)
Prior years’ taxes		(33,520	)		(63,744	)		218,947
Foreign currency translation and exchange difference		(54,318	)		751,210			(186,787	)
Tax discounts and tax credit		(110,857	)		—			—
Ecopetrol U.S.A. deferred tax		(1,550,152	)		—			—
Effect of tax reform		—			(359,676	)		—
Non–deductible wealth tax		—			—			85,872
Income tax calculated		4,718,413			8,258,485			5,800,268


Current		7,127,492			7,416,038			5,076,692
Deferred		(2,409,079	)		842,447			723,576
		4,718,413			8,258,485			5,800,268

*Information from the years 2018 and 2017 were reclassified for purposes of comparability with 2019.

(1)

In 2019, two companies, Ecopetrol USA Inc. and Ecopetrol Permian, were created 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. As of December 2018, Ecopetrol America Inc generated tax losses of USD $2,067 million and in 2019 it estimates these will increase to USD$107 million. 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. IAS 12 establishes when a Company has strong evidence that will allow it to offset for deferred tax losses, it is possible to establish a deferred tax asset. The forecasts as of 2020 in the United States with the entry into operation of Ecopetrol Permian, allow for the reasonable expectation that taxable profits required to recover the losses of previous years will be generated; therefore, the recognition of the deferred tax asset is feasible.

The effective tax rate for the year ended December 31, 2019 was 23.9% (2018 - 40.1%). The decrease from the previous year is mainly due to: a) the effect of the deferred tax assets not recognized of Ecopetrol USA and Permian, b) a reduction of the nominal tax rate by 4 bps, (33% in 2019 as compared to 37% in 2018), c) the use of the 50% tax discount in the industry and commerce tax, d) the appreciation of Ecopetrol’s increased interest in Invercolsa, and, e) the application of the Tax reform for estimating the deferred tax balances; among others.

F-43

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Deferred income tax

	2019			2018
Deferred tax assets		6,809,347			3,879,427
Deferred tax liabilities		(1,328,831	)		(1,337,943	)
Net deferred income tax		5,480,516			2,541,484

The detail of deferred tax assets and liabilities is as follows:

	2019			2018
Deferred tax assets (liabilities)
Loss carryforwards (1)		2,849,087			1,002,062
Provisions (2)		2,404,032			1,994,762
Employee benefits (3)		1,875,872			1,161,860
Accounts payable		1,631,706			1,193,098
Accounts receivable		139,410			79,591
Excess presumptive income		64,249			(37,638	)
Right-of-use assets		(33,592	)		—
Investments and hedging		(45,844	)		(143,717	)
Goodwill (4)		(363,968	)		(404,394	)
Property plant and equipment and Natural and environmental resources (5)		(3,040,436	)		(2,304,140	)
		5,480,516			2,541,484

(1)

In 2019, a deferred tax asset for loss carryforwards were recognized in the following companies: Ecopetrol USA Inc for COP$1,497,966, Refinería de Cartagena for COP$1,052,848 and Bioenergy for COP$64,343 and the excess of presumptive income over net ordinary income of Refinería de Cartagena and Bioenergy for COP$228,569 and COP$5,361 respectively.

(2)

Corresponds to non-deductible accruals, mainly the provision for asset retirement obligation (ARO).

(3)

Actuarial calculations for health, retirement pensions, education, pension bonds and other benefits to long–term employees.

(4)

According to Colombian tax law, goodwill is amortizable, while under IFRS it is not amortized but such goodwill is subject to impairment tests and any difference results in a deferred tax liability.

(5)

For fiscal 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 tax for occasional gains of 10% to the land. The main variation corresponds to the decrease in the income tax rate from 33% to 30%.

F-44

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:

PPE and
Natural
resources Provisions Employee
benefits Loss carry
forwards Accounts
payable

As of December 31, 2017 (1,006,299 ) 1,840,988 1,373,561 611,766 208,618

Profit or loss (1,297,841 ) 153,774 (178,160 ) 390,296 984,480

OCI — — (33,541 ) — —

As of December 31, 2018 (2,304,140 ) 1,994,762 1,161,860 1,002,062 1,193,098

Profit or loss (736,296 ) 409,270 (57,343 ) 1,847,025 438,608

OCI — — 771,355 — —

As of December 31, 2019 (3,040,436 ) 2,404,032 1,875,872 2,849,087 1,631,706

Accounts
receivable Goodwill Right-of-use
assets Others Total

As of December 31, 2017 94,864 (408,932 ) — (31,685 ) 2,682,881

Profit or loss (15,273 ) 4,538 — (884,261 ) (842,447 )

OCI — — — 734,591 701,050

As of December 31. 2018 79,591 (404,394 ) — (181,355 ) 2,541,484

Profit or loss 59,819 40,426 (33,592 ) 441,162 2,409,079

OCI — — — (143,397 ) 627,958

Increase in Invercolsa shareholding — — — (98,005 ) (98,005 )

As of December 31, 2019 139,410 (363,968 ) (33,592 ) 18,405 5,480,516

The Ecopetrol Business Group offsets deferred taxes assets and liabilities only if it has a legally enforceable right to offset current tax liabilities and assets; and, to the extent they relate to income taxes in the same tax jurisdiction and the same tax authority.

Deferred tax assets recognized

Deferred tax assets recognized in the consolidated financial statements as of December 31, 2019 and 2018 amounted to COP$6,809,347 and COP$3,879,427, 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 amounted to COP$2,849,087 as of December 31, 2019 and is mainly comprised of:

Tax losses carryforwards that do not expire corresponding to Refinería de Cartagena, Bioenergy and Ecopetrol USA amount to COP$6,385,989 and correspond to deferred tax assets of COP$1,052,848, COP$64,343 and COP$182,977, respectively.

Tax loss carryforwards that expire in 20 years from the year in which they were generated corresponding to Ecopetrol USA amounting to COP$6,144,400 (USD $1,904 million) and correspond to deferred tax assets of COP$1,288,249.

Additionally, as of December 31, 2019 the excess of presumptive income amounted to COP$1,332,854 that generates a deferred tax assets of COP$228,569 in Refinería de Cartagena, COP$5,361 in Bioenergy and COP$22,590 in Ecopetrol USA. As of December 31, 2018, deferred tax assets have been recognized for an amount of COP$1,002,063 related to excesses of presumptive income and the accumulated tax losses of Refinería de Cartagena amount to COP$948,671 and Bioenergy Zona Franca S.A.S. amount to COP$53,392, as management expects these amounts will be realized in future periods.

The Ecopetrol Business Group recognizes deferred tax assets based on tax projections and the elimination of presumptive income from the year 2021, as contemplated in Law 2010/2019.

Refinería de Cartagena, Bioenergy, Ecopetrol Costa Afuera (“ECAS”), Ecopetrol USA, Permian and Andean Chemicals Ltd (“Andean”) have accumulated tax losses for a net amount of COP$12,402,061 as of December 2019 and COP$4,292,418 as of December 2018.

In accordance with the tax rules regulation applicable until December 31, 2016, excess presumptive income and minimum base excesses generated before 2017 in income and supplementary taxes and in income tax for equity equality - (CREE, as its acronym in Spanish) respectively, may be compensated with the ordinary taxable income in the following five years, using for this purpose, the formula established in number 6, of article 290 of law 1819/ of 2016. The tax loss carryforwards of Ecopetrol USA generated between 2008 and 2017, expire in 20 years from the year in which they were generated. The tax loss carryforwards generated starting January 1, 2018 have no expiration date and its use is limited to 80% of taxable income.

F-45

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Deferred tax assets not recognized

Deferred tax assets related to the tax loss carryforwards generated by the subsidiaries Bioenergy S.A. Ecopetrol Costa Afuera and Andean Chemicals Ltd in the amount of COP$105,592, and excess of presumptive income of Bioenergy SA, Ecopetrol Costa Afuera, Hocol Petroleum Company, Andean in the amount of COP$74,481, were not recognized, as Management believes it is not likely that these deferred tax assets will be recoverable in the short term.

If the Ecopetrol Business Group had recognized this deferred tax asset, the profit for the year ending December 31, 2019 would have increased by COP$180,073.

The movements of deferred income tax for the years ended December 31, 2019, 2018 and 2017 are as follows:

	2019			2018			2017
Opening balance		2,541,484			2,682,881			2,608,311
Deferred tax recognized in profit or loss		2,409,079			(842,447	)		(723,576	)
Increase due to business combination (Invercolsa)		(98,005	)		—			—
Deferred tax recognized in other comprehensive income (a)		627,958			701,050			798,146
Closing balance		5,480,516			2,541,484			2,682,881

(a)

The following is the detail of the income tax recorded in other comprehensive income:

December 31. 2019	Pre–tax			Deferred tax			After tax
Actuarial valuation gains (losses) (Note 21.1)		2,571,184			(771,355	)		1,799,829
Cash flow hedging for future crude oil exports (Note 29.1.2)		(356,339	)		118,008			(238,331	)
Hedge of a net investment in a foreign operation (Note 29.1.3)		87,524			(26,257	)		61,267
Hedge with derivative instruments		(69,220	)		22,769			(46,451	)
Other		—			28,877			28,877
		2,233,149			(627,958	)		1,605,191

December 31. 2018	Pre–tax			Deferred tax			After tax
Actuarial valuation gains (losses) (Note 21.1)		(29,249	)		33,539			4,290
Cash flow hedging for future crude oil exports (Note 29.1.2)		797,658			(264,284	)		533,374
Hedge of a net investment in a foreign operation (Note 29.1.3)		1,382,278			(410,324	)		971,954
Hedge with derivative instruments		77,872			(25,698	)		52,174
Other		925			(34,283	)		(33,358	)
		2,229,484			(701,050	)		1,528,434

December 31. 2017	Pre–tax			Deferred tax			After tax
Actuarial valuation gains (losses) (Note 21.1)		2,310,512			(762,469	)		1,548,043
Cash flow hedging for future crude oil exports (Note 29.1.2)		167,458			(82,622	)		84,836
Hedge of a net investment in a foreign operation (Note 29.1.3)		(86,563	)		28,566			(57,997	)
Hedge with derivative instruments		(53,385	)		17,617			(35,768	)
Other		6,649			762			7,411
		2,344,671			(798,146	)		1,546,525

F-46

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, 2019, deferred tax assets are not recognized on the difference between the accounting and tax basis associated with investments in subsidiaries and joint ventures of Ecopetrol (Base: COP$507,161 - Tax: COP$50,716), as the Ecopetrol Business Group does not have any intention of selling any of these investments in the foreseeable future.

Income tax provisions and contingent liabilities

Income tax returns for the 2011, 2012, 2014, 2015, 2016, 2017 and 2018 tax years and the CREE for the 2014, 2015, and 2016 tax years of the Group’s companies are subject to acceptance and review by the tax authorities. The management of the Group's companies considers whether the amounts accounted for as liabilities for taxes payable are sufficient and supported by current regulations, doctrine and jurisprudence to meet any claim that may be established with respect to these years. The Company's strategy is to avoid making fiscal decisions resulting in aggressive or risky positions that may call into question its tax returns.

Uncertain tax positions - IFRIC 23

The Ecopetrol Business Group’s strategy is to avoid making aggressive tax decisions that may cause questioning of its tax returns, in order to minimize the risk of possible challenge by the tax authorities.

Regarding uncertain 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 rate above 75% has been established, which has been calculated based on current regulations and official interpretations.

In accordance with the aforementioned standard, the Ecopetrol Group considers that uncertain tax positions included in its determination of income tax payable will not affect results if the success rate is above 75%. Notwithstanding, the Ecopetrol Business Group will continue to monitor new regulations and doctrine 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 7.5% (5% in 2018). 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 33% (35% in 2018) 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 the retention at the source for this concept.

There are no effects on income tax related to dividend payments made by the Company to its shareholders during 2019 and 2018.

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 and supplementary tax, its costs and deductions, considering for these operations the arm's length principle.

Ecopetrol submitted its transfer pricing informative return for the 2018 taxable year and its corresponding supporting documentation, as well as the country-by-country report and the master file for the year 2018, in accordance with current tax law.

For fiscal year 2019, 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, it is possible to infer that 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 2019, which imply changes in the income provision of the taxable year 2019.

F-47

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 1943/2018 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 nor will it be discounted from the sales tax.

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, training, 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%.

F-48

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Tax procedures

With regards to procedure, changes have been made: (i) declarations for withholding at source which, that being inefficient, will be enforceable, (ii) electronic notification of administrative actions; (iii) payment of the entire amount covered by a statement of objections to avoid delinquent interest at the current rate plus two points; and (iv) elimination of the extension of enforcement to three (3) additional years to offset tax losses, and the period for taxpayers who must comply with the transfer pricing regime is reduced to five (5) years.

Additionally, an audit benefit was included for fiscal years 2020 to 2021. Under this benefit, private settlement by taxpayers of income tax and supplements that increase net income tax by a minimum 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.

The above benefit does not apply to: (i) taxpayers who enjoy tax benefits due to their location in a specified geographic region; (ii) if it is demonstrated that declared withholdings at source are non-existent; (iii) if the net income tax is less than 71 UVT (COP$2,528,097 for fiscal year 2020). The deadline stipulated in this law does not extend to declarations of withholdings at source nor to the sales tax, which shall be established by the general regulation.

11.

Other assets

	2019		2018
Current
Partners in joint operations (1)		921,983		519,460
Advanced payments to contractors and suppliers		360,781		221,767
Prepaid expenses		272,007		191,168
Trust funds (2)		144,798		—
Related parties (Note 30)		57,016		19,214
Other assets		22,393		68,819
		1,778,978		1,020,428
Non–current
Abandonment and pension funds (3)		445,457		392,084
Employee benefits		220,998		213,645
Trust funds (2)		171,008		147,471
Advanced payments and deposits		56,027		61,556
Judicial deposits and attachments		40,317		43,137
Other assets		8,674		2,837
		942,481		860,730

(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)

Mainly includes the resources invested in fiduciary commissions destined to “works for taxes”, mechanism of payment of the income tax of 2017 and 2018, constituted in compliance with article 238 of Law 1819 of 2016 - Tax reform.

(3)

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.

F-49

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

12.

Business combinations

On November 29, 2019, Ecopetrol obtain 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%.

Upon obtaining control of Invercolsa, the Ecopetrol Business Group accounted for the transaction as a business combination and started consolidating Invercolsa (including its subsidiaries and associated companies) on the date control was obtained. The previously held interest in Invercolsa, which was accounted for under the equity method, was remeasured at fair value on such the date.

The acquisition of controlling interest did not require the payment of any consideration and was recorded using the acquisition method of accounting.

The effect of the changes in the Ecopetrol Business Group ownership intrest in Invercolsa is summarized as follow:

(In COP$ millions)	2019

Increase in the ownership interest in Invercolsa at fair value		217,974
(+) Fair value of previously held interest on the date of acquisition of controlling interest		1,107,969
(=) Total fair value of investment in Invercolsa		1,325,943
(-) Carrying amount of previously held interest in Invercolsa		(277,019	)
Gain on acquisition acquisition of control of Invercolsa (Note 27)		1,048,924

The increase in the ownership interest in Invercolsa resulted in a gain recorded in profit or loss since no consideration was paid for such additional interest.

Revenue and profits included in the consolidated profit or loss statement upon consolidation of Invercolsa were COP$72,712 and COP$18,198 respectively. If the acquisition had occurred on January 1, 2019, management estimates that the consolidated revenue and net profit attributable to owners of the parent would have increased by COP$459,286 and COP$134,464, respectively.

Identifiable assets acquired and liabilities assumed

The table below summarizes the amounts recognized for the assets acquired and the liabilities assumed at the date of acquisition.

Item	Note		Amount COP$
Cash and cash equivalent				20,530
Current accounts receivable				195,225
Inventories				19,576
Current tax assets				10,704
Other assets				2,810
Investments in associates (1)				1,824,552
Trade accounts and other accounts receivables				52,820
Property, plant and equipment		14		1,338,947
Deferred tax assets				9,623
Other assets				807
Current loans and borrowings				(137,683	)
Trade accounts and other accounts payable				(58,423	)
Current provisions for employee benefits				(7,003	)
Current tax liabilities				(23,597	)
Provisions and contingencies				(8,576	)
Other liabilities				(13,650	)
Non – Current loans and borrowings				(186,923	)
Deferred tax liabilities				(107,629	)
Total net assets (2)				2,932,110

F-50

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(1)

The detail of the investments in associates measured at fair value on the date of acquisition is as follows:

Associate	COP$
Gases del Caribe S.A. E.S.P.		1,527,911
Gas Natural del Oriente S.A. E.S.P.		166,685
Gases de la Guajira S.A. E.S.P.		68,608
Extrucol S.A.		28,501
E2 Energía Eficiente S.A. E.S.P.		32,847
		1,824,552

(2)

These net assets correspond 100% to the Invercolsa Group, the fair value of the non-controlling interest on the date of acquisition was COP$1,606,390.

The fair values of property, plant and equipment, intangible assets and deferred tax have been provisionally determined and may be adjusted in accordance with measurement period included in IFRS 3 - Business combinations.

F-51

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

	2019			2018
Investment in joint ventures
Equion Energy Limited (1)		1,515,067			1,364,933
Offshore International Group		709,871			727,194
Ecodiesel Colombia S.A.		46,095			41,304
		2,271,033			2,133,431
Less impairment:
Equion Energy Limited		(322,388	)		(187,636	)
Offshore International Group		(530,330	)		(346,121	)
		1,418,315			1,599,674
Investments in associates
Gases del Caribe S.A. E.S.P.		1,527,911			—
Gas Natural del Oriente S.A. E.S.P.		166,685			—
Gases de la Guajira S.A. E.S.P.		68,608			—
Extrucol S.A.		28,501			—
E2 Energía Eficiente S.A. E.S.P.		32,847			—
Invercolsa S.A. (2)		—			243,294
Sociedad Colombiana de Servicios Portuarios S.A. - Serviport S.A.		11,070			11,212
Sociedad Portuaria Olefinas y Derivados		2,205			1,368
		1,837,827			255,874
Less impairment: Serviport S.A.		(11,070	)		(11,212	)
		1,826,757			244,662
		3,245,072			1,844,336

(1)

Equion Energía Limited: On December 14, 2007, Ecopetrol informed Equion of its decision not to extend the Santiago de las Atalayas, Tauramena, Recetor, Río Chitamena and Piedemonte association contracts, confirming their expiration dates on July 1, 2010, July 3, 2016, May 30, 2017, January 31, 2019 and February 29, 2020, respectively.

(2)

Invercolsa S.A. became a subsidiary as of November 29, 2019 (See Note 12), 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.

Equion Energía Limited and Ecopetrol fulfilled the Piedemonte association contract, as well as the delivery and receipt of the operations that are covered under the same. This process established five stages: i) analysis and start-up, ii) planning, iii) execution, iv) delivery and receipt and v) closing. As of December 31, 2019, the project was in the delivery and receipt stage. During the first months of 2020, the next steps have been followed: reach the final agreements, deliver the operations and formalize the contract termination act, which was signed on February 29, 2020 and where the agreements, indemnities, closing of issues, list of pending and inventory of information delivery were included.

F-52

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following is the movement of investments in associates and joint ventures:

For the year ended December 31, 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 17)		142			(318,962	)		(318,820	)
Foreign currency translation		1,723,080			(120,102	)		1,602,978
Closing balance		1,826,757			1,418,315			3,245,072

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 (Note 17)		(1,308	)		302,136			300,828
Closing balance		244,662			1,599,674			1,844,336

For the year ended December 31, 2017:

	Associates			Joint ventures			Total
Opening balance		249,537			1,303,157			1,552,694
Effects of equity method through:
Profit or loss		46,669			46,869			93,538
Other comprehensive income		—			(14,752	)		(14,752	)
Dividends declared		(61,124	)		(224,837	)		(285,961	)
Impairment (Note 17)		(9,904	)		(5,155	)		(15,059	)
Closing balance		225,178			1,105,282			1,330,460

F-53

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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 Energy Limited and the Offshore International Group, as of December 31, 2019 and 2018:

	2019				2018
	Equion Energy Limited		Offshore International Group		Equion Energy Limited		Offshore International Group
Statement of financial position
Current assets		2,530,453		284,591		2,083,614		354,959
Non–current assets		95,384		1,481,680		484,336		1,523,549
Total assets		2,625,837		1,766,271		2,567,950		1,878,508
Current liabilities		315,002		310,561		550,933		221,606
Non–current liabilities		76,768		718,863		77,331		885,410
Total liabilities		391,770		1,029,424		628,264		1,107,016
Equity		2,234,067		736,847		1,939,686		771,492
Other complementary information
Cash and cash equivalents		188,820		48,752		185,762		96,592
Current financial liabilities		—		—		3,176		95,633
Non–current financial liabilities		—		—		—		137,708

	2019						2018						2017
	Equion Energy Limited			Offshore International Group			Equion Energy Limited			Offshore International Group			Equion Energy Limited			Offshore International Group
Statement of profit or loss
Sales revenue		1,285,891			529,167			1,490,177			653,054			1,213,692			393,210
Costs		(671,179	)		(690,484	)		(755,656	)		(585,192	)		(793,999	)		(508,461	)
Administrative expenses and others		(624	)		(64,115	)		29,136			(353,010	)		12,188			(103,340	)
Financial (expenses) income		(3,660	)		(31,288	)		(3,659	)		(21,227	)		2,373			(20,264	)
Income tax		(214,048	)		208,473			(338,487	)		(16,594	)		(180,546	)		60,575
Financial year results		396,380			(48,247	)		421,511			(322,969	)		253,708			(178,280	)
Other comprehensive results		1,102,757			—			1,095,090			—			913,728			—

Other complementary information
Dividends paid to the Ecopetrol Business Group		—			—			—			—			217,075			—
Depreciation and amortization		404,482			226,654			511,615			243,601			557,970			232,953

F-54

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

This is a reconciliation of equity of the significant investments and the carrying amount of investments as of December 31:

	2019						2018
	Equion Energy Limited			Offshore International Group			Equion Energy Limited			Offshore International Group
Equity of the joint venture		2,234,067			736,847			1,939,686			771,492
% of Ecopetrol’s ownership		51%			50%			51%			50%
Ecopetrol’s ownership		1,139,374			368,424			989,240			385,746
Additional value of the investment		375,693			341,447			375,693			341,448
Impairment		(322,388	)		(530,330	)		(187,636	)		(346,121	)
Carrying amount of the investment		1,192,679			179,541			1,177,297			381,073

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, 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 (Note 12)		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 17)		519,835			(113,860	)		(626,878	)		(87,338	)		(35,533	)		(82,837	)		(426,611	)
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	)		68,717			(2,278	)
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 19 - Loans and borrowings.

Guarantees

The Esperanza 1 and 2 farms were pledged as a guarantee for the loan obtained by Bioenergy S.A.S. for the financing of the project (see Note 19.5 – Guarantees and covenants).

F-55

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

In accordance with the leasing contract between Bioenergy Zona Franca S.A. and Bancolombia for the construction of the industrial plant, it was established that the guarantee is the same plant.

	Plant and equipment			Pipelines, networks and lines			Work in progress(1)			Buildings			Lands			Other			Total
Cost
Balance as of December 31, 2017		42,561,894			32,000,049			3,866,318			7,618,586			3,839,355			2,806,696			92,692,898
Additions/capitalizations		1,196,520			944,797			993,817			147,005			14,909			5,881			3,302,929
Increase in abandonment costs		85,580			209,028			—			—			—			—			294,608
Capitalized financial interests (2)		48,351			34,399			14,853			14,350			6,703			5,316			123,972
Exchange differences capitalized		4,107			2,922			1,262			1,219			569			451			10,530
Disposals		(135,468	)		(112,171	)		(14,723	)		(11,997	)		(9,763	)		(56,734	)		(340,856	)
Foreign currency translation		2,324,744			849,868			32,585			100,091			124,903			55,983			3,488,174
Transfers (3)		388,641			420,391			(269,409	)		(16,976	)		7,900			28,209			558,756
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

Accumulated depreciation and impairment losses
Balance as of December 31, 2017		(14,779,973	)		(12,461,626	)		(553,420	)		(2,668,562	)		(39,522	)		(785,421	)		(31,288,524	)
Depreciation expense		(2,008,348	)		(1,465,429	)		—			(347,510	)		—			(123,792	)		(3,945,079	)
(Loss) reversal of an impairment (Nota 17)		(752,534	)		(311,080	)		55,979			(64,279	)		5,220			(16,591	)		(1,083,285	)
Disposals		116,225			84,217			—			8,996			—			40,957			250,395
Foreign currency translation		(677,901	)		(313,311	)		—			(27,782	)		—			(23,804	)		(1,042,798	)
Transfers (3)		117,115			(310,561	)		—			(23,386	)		—			(4,905	)		(221,737	)
Balance as of December 31, 2018		(17,985,416	)		(14,777,790	)		(497,441	)		(3,122,523	)		(34,302	)		(913,556	)		(37,331,028	)

Net balance as of December 31, 2017		27,781,921			19,538,423			3,312,898			4,950,024			3,799,833			2,021,275			61,404,374
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

(1)

The balance of work in progress as of December 31, 2018, mainly includes the works executed in production by facilities of the Castilla field, facilities in Cupiagua, air injection pilot facilities in the Chichimene field and secondary recovery of Yarigui, and in refining by the modernization project of Barrancabermeja.

(2)

Financial interests are capitalized based on the weighted average rate of borrowing costs. See Note 19 - Loans and financing.

(3)

Transfers corresponds mainly to: i) recognition of financial leasing contracts, ii) transfers from natural resources and the environment.

Guarantees

The Esperanza 1 and 2 farms were pledged as guarantee for the loan obtained by Bioenergy S.A.S. for the financing of the project (see Note 19.5 – Guarantees and covenants).

F-56

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, 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 17)		(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 19 - Loans and borrowings.

F-57

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(1)			Total
Cost
Balance as of December 31, 2017		50,183,858			2,215,263			4,508,808			56,907,929
Additions/capitalizations		3,579,982			(27,839	)		1,499,685			5,051,828
Acquisition of interests in joint operations (2)		(12,065	)		—			—			(12,065	)
Increase in abandonment costs		—			733,609			34,063			767,672
Disposals		(79	)		(2,080	)		(87,953	)		(90,112	)
Dry wells (3)		(1,563	)		—			(897,361	)		(898,924	)
Capitalized financial interests (4)		70,186			—			6,675			76,861
Exchange differences capitalized		5,961			—			567			6,528
Foreign currency translation		773,678			24,574			75,203			873,455
Transfers		(663,917	)		(24,381	)		(333,687	)		(1,021,985	)
Balance as of December 31, 2018		53,936,041			2,919,146			4,806,000			61,661,187

Accumulated amortization and impairment losses
Balance as of December 31, 2017		(34,014,963	)		(1,584,701	)		—			(35,599,664	)
Depletion expense		(3,471,803	)		(196,286	)		—			(3,668,089	)
Reversal (losses) of an impairment (Nota 17)		414,208			(106	)		—			414,102
Disposals		79			—			—			79
Foreign currency translation		(563,229	)		(19,080	)		—			(582,309	)
Transfers		829,041			21,103			—			850,144
Balance as of December 31, 2018		(36,806,667	)		(1,779,070	)		—			(38,585,737	)
Net balance as of December 31, 2017		16,168,895			630,562			4,508,808			21,308,265
Net balance as of December 31, 2018		17,129,374			1,140,076			4,806,000			23,075,450

(1)

The balance of oil investments in progress includes mainly investments made in the Purple Angel, Tayrona and unconventional hydrocarbons projects. In the developing fields, the most representative correspond to Castilla, Chichimene pilot and CPO09 re sanction.

(2)

Adjustment in the acquisition value of the participation of MCX Exploration USA LLC (see note 30.3).

(3)

Includes dry wells: 1) Ecopetrol America Inc: Leon 2) Hocol: Payero, Bonifacio, Pegaso-1 and Ocelote.

(4)

Borrowing costs are capitalized at the weighted average rate of borrowing costs. See Note 19 - Loans and financing.

F-58

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, 2019, 2018 and 2017:

	2019		2018		2017
Between 1 and 3 years (a)		361,700		496,871		600,767
Between 3 and 5 years (b)		132,021		375,371		791,261
More than 5 years (c)		441,389		273,764		250,219
Total suspended exploratory wells		935,110		1,146,006		1,642,247
Number of projects exceeding 1 year		30		24		24
Wells under 1 year of suspension		—		9,511		2,480

(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. As of December 31, 2017, suspended exploratory wells correspond mainly to discovery wells of Ecopetrol America Inc: Leon 2 and Warrior 1, which were under evaluation.

(b)

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, under evaluation; and ii) Offshore International Group, temporarily abandoned for future production plans.

F-59

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

16.

Intangible assets

The following is the movement of intangibles and their amortization and impairment for the years ended December 31, 2019 and 2018:

	Licenses and software			Other intangibles⁽¹⁾			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		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

	Licenses and software			Other intangibles⁽¹⁾			Total
Cost
Balance as of December 31, 2017		960,556			168,552			1,129,108
Acquisitions		69,442			36,227			105,669
Disposals		(46,007	)		(5,643	)		(51,650	)
Foreign currency translation		25,339			2,955			28,294
Transfers		6,390			(4,808	)		1,582
Balance as of December 31, 2018		1,015,720			197,283			1,213,003
Accumulated amortization
Balance as of December 31, 2017		(665,415	)		(83,467	)		(748,882	)
Amortization of the period		(75,818	)		(15,864	)		(91,682	)
Disposals		46,004			5,546			51,550
Foreign currency translation		(20,501	)		(184	)		(20,685	)
Transfers		3,401			4,042			7,443
Balance as of December 31, 2018		(712,329	)		(89,927	)		(802,256	)
Net balance as of December 31, 2017		295,141			85,085			380,226
Net balance as of December 31, 2018		303,391			107,356			410,747
Useful life		<5 years			<7 years

(1)

Corresponds mainly to easements.

F-60

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

17.

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–financial 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.

Based on the impairment tests conducted by the Ecopetrol Business Group, the following are the impairment (losses) or reversals for the years ended on December 31, 2019, 2018 and 2017:

Impairment (loss) reversal of impairment by segment	2019			2018			2017
Exploration and Production		(1,982,044	)		785,940			183,718
Refining and Petrochemicals		452,163			(984,704	)		1,067,965
Transport and Logistics		(232,556	)		(169,870	)		59,455
		(1,762,437	)		(368,634	)		1,311,138

Recognized in:
Property, plant and equipment (Note 14)		(426,611	)		(1,083,285	)		977,919
Natural resources (Note 15)		(1,017,061	)		414,102			376,934
Investment in joint ventures and associates (Note 13)		(318,820	)		300,828			(15,059	)
Other non–current assets		55			(279	)		(28,656	)
		(1,762,437	)		(368,634	)		1,311,138

17.1

Exploration and production

The impairment (loss) reversal of assets of the Exploration and Production segment for the years ended December 31 of 2019, 2018 and 2017 is as follows:

	2019			2018		2017
Oilfields		(1,663,082	)		483,803		188,873
Investment in joint ventures (Note 13)		(318,962	)		302,136		(5,155	)
Other		—			1		—
		(1,982,044	)		785,940		183,718

17.1.1

Oilfields

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.

F-61

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

In 2017, 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 CPO09, Casabe and Oripaya and in fields operated abroad Gunflint Dalmatian and K2, and an impairment in the Tibú, Underriver, Provincia and Orito fields, mainly.

The following is the breakdown of oilfields impairment losses or reversals for the years ended December 31, 2019, 2018 and 2017:

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	)
						(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

2017

Cash generating units	Carrying amount		Recoverable amount		Impairment (loss) reversal
Oil fields in Colombia
Loss		2,172,747		1,588,207		(584,540	)
Reversal		13,229,212		23,906,828		298,210
Fields operated abroad
Reversal		748,510		1,324,010		475,203
						188,873

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:

F-62

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

–

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, adjusted by different risk factors.

–

The real discount rate determined as the average weighted cost of capital (WACC) and it corresponds to 6.31% (2018–7.46% and 2017 – 8.17%).

–

Oil price – Brent: the forecasts include USD$55.61/barrel for the first year, USD$54.91/barrel for the medium term and USD$70.1/barrel for the long term. In 2018, the assumptions taken USD$81.4/barrel for the first year, USD$67.6/barrel for the medium term and USD$71.4/barrel as of the year 2030. In 2017, the assumptions taken USD$52.9/barrel for 2018, USD$72.5/barrel average for the next six years and USD$81.9/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.

17.1.2

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:

	2019			2018		2017
Equion Energy Limited		(134,753	)		108,791		(42,744	)
Offshore International Group		(184,209	)		193,345		37,589
		(318,962	)		302,136		(5,155	)

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 2019 for Offshore International Group of 8.50% (2018-8.92% and 2017 – 8.61%).

In 2019, an impairment loss for both. Offshore International Group and Equion Energy 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.

In 2017, because of new market variables, new reserves, price differentials against reference indicators and available technical and operational information, there was a reversal of an impairment recognized in previous years for Offshore International Group and Equion Energy.

F-63

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

17.2

Refining and Petrochemical

The Cash Generating Units with an (expense for) reversal of impairment in the Refining and Petrochemical Segment for the years ended December 31, 2019, 2018 and 2017 include:

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) reversal
Refinería de Cartagena		23,411,058		22,640,761		(770,297	)
Bioenergy		774,343		560,882		(213,461	)
Other		946		—		(946	)
						(984,704	)

2017

Cash–generating units	Carrying amount		Recoverable amount		(Impairment loss) reversal
Refinería de Cartagena		20,578,412		22,012,710		1,434,298
Refinería de Barrancabermeja (projects)		1,172,773		898,786		(273,987	)
Bioenergy		757,741		665,395		(92,346	)
						1,067,965

The grouping of assets to determine the CGUs is consistent with prior periods.

17.2.1

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) an actual discount rate of 6.23% which include a premium risk of 0.59% (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-64

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

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.

In 2017, we recorded a partial reversal of the impairment recorded in previous periods primarily as a result of: (a) an improved outlook in refining margins due to the ratification of the implementation of the International Convention for the Prevention of Pollution from Ships (Marpol) starting in 2020; (b) a lower discount rate resulting from the application of WACC methodology; and (c) operational and financial optimizations identified as part of the stabilization of the refinery.

17.2.2

Bioenergy

The recoverable amount of Bioenergy 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.

In 2019, we recorded an impairment loss of COP$234,340, due to changes in the operative variables, changes in the projection of the operational cash flows and the need for higher resources, mainly by the results of the renovation of older reeds.

In 2018, impairment is presented due to: i) a lower prospect of short-term ethanol prices, associated with imports from abroad in an environment of global over-supply of ethanol, ii) the updating of agricultural variables in the short term, iii) an increase in the discount rate used for the valuation in line with fundamentals of the market. These impacts were partially offset by the updating of operating variables associated with the stabilization and tax effects of the "Tax reform".

In 2017, we recorded an impairment loss mainly due to updating the dates of the start of operations of the project, the stabilization process of the industrial plant and the changes in the operational variables and ethanol prices.

17.2.3

Refinería de Barrancabermeja

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 revers 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.

During 2017, an impairment loss of COP$273,987 was recognized on the Refinería de Barrancabermeja, mainly related to the write off of certain management and financial capitalized balances associated with the suspension of the modernization project of the Refinery. This suspension is in response to capital discipline criteria implemented to ensure the growth and financial sustainability of Ecopetrol S.A. and the Ecopetrol Business Group in the adverse context that the hydrocarbons sector experienced in previous years. This project is being assessed within the Ecopetrol Business Group’s strategic plan therefore any impairment loss recognized in previous years may be subject to reversal.

F-65

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

17.3

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 4.88% (2018 - 5.60%) and iii) transport volume projections based on the end of year results for 2019 and the long-term volumetric transport program from 2020 onwards.

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.

In 2017, there was a reversal of an impairment for the Transportation and Logistics segment for COP$59,455, mainly in Oleoducto del Sur, which includes, among others, the Trans Andino Pipeline. The reversal was due to the inclusion of the Port of Tumaco in that generating unit.

18.

Goodwill

	2019			2018
Oleoducto Central S.A.		683,496			683,496
Hocol Petroleum Ltd.		537,598			537,598
Andean Chemical Ltd		127,812			127,812
Esenttia S.A.		108,137			108,137
		1,457,043			1,457,043
Less impairment Hocol Petroleum Ltd.		(297,121	)		(297,121	)
		1,159,922			1,159,922

As of December 31, 2019 and 2018, 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.

F-66

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

19.

Loans and borrowings

Exhibit 2 details the main conditions of the most significant loans of the Business Group.

19.1

Composition of loans and borrowings

The balances of the loans and financing, which are recorded at amortized cost, as of December 31, 2019 and 2018:

	Weighted average effective interest rate as of December 31				2019		2018
	2019		2018
Local currency
Bonds		8.7%		8.0%		1,567,598		1,568,034
Syndicated loan		8.0%		7.9%		1,115,874		1,439,590
Lease liabilities (1)		7.2%		—		1,039,303		591,153
Commercial loan		8.3%		7.6%		737,032		449,998
						4,459,807		4,048,775
Foreign currency
Bonds		5.9%		5.7%		25,832,740		25,599,996
Commercial loan		7.1%		4.4%		6,586,538		7,352,002
Loans from related parties (Note 30)		—		—		1,108,403		855,135
Lease liabilities (1)		6.2%		—		251,651		206,737
						33,779,332		34,013,870
						38,239,139		38,062,645
Current						5,012,173		4,019,927
Non–current						33,226,966		34,042,718
						38,239,139		38,062,645

(1)

Corresponds mainly 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. (see Note 5.1).

19.2

Maturity of loans and borrowings

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

F-67

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following are the maturities of loans and borrowing as of December 31, 2018:

	Up to 1 year (1)		1 - 5 years		5-10 years		> 10 years		Total
Local currency
Bonds		116,693		842,514		362,446		246,381		1,568,034
Syndicated loan		406,582		1,033,008		—		—		1,439,590
Commercial loans and other		120,069		491,781		270,920		158,381		1,041,151
		643,344		2,367,303		633,366		404,762		4,048,775
Foreign currency
Bonds		1,374,390		10,605,708		8,664,732		4,955,166		25,599,996
Commercial loans – Refinería de Cartagena		1,116,370		4,061,541		2,174,091		—		7,352,002
Other		885,823		136,574		39,475		—		1,061,872
		3,376,583		14,803,823		10,878,298		4,955,166		34,013,870
		4,019,927		17,171,126		11,511,664		5,359,928		38,062,645

(1)

Includes short–term credit and the current portion of long–term debt, as applicable.

19.3

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, 2019 and 2018:

	2019		2018
Local currency
Fixed rate		598,802		252,224
Floating rate		3,861,005		3,796,551
		4,459,807		4,048,775
Foreign currency
Fixed rate		31,087,439		31,432,667
Floating rate		2,691,893		2,581,203
		33,779,332		34,013,870
		38,239,139		38,062,645

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.

19.4

Loans designated as hedging instrument

As of December 31, 2019, Ecopetrol S.A. designated USD$7,331 million (2018 – USD$6,500 million) of foreign currency debt as a hedging instrument, of which USD$6,031 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 29 – Risk management.

19.5

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, 2019 the covenants, loans and payments have been fulfilled.

–

The loan entered into by Oleoducto de los Llanos is 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.

F-68

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

–

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.

–

The loan entered into by Bioenergy with Bancolombia is guaranteed with the La Esperanza 1 and 2 farms of COP$6,343.

19.6

Waiver

As for December 31, 2019, another waiver was granted to Ecopetrol’s subsidiaries:

–

Bancolombia granted a waiver to the lease agreements 120158 and 148090 of Bioenergy Zona Franca S.A.S. until June 2020 according to the need to manage short-term liquidity of the company.

19.7

Fair value of loans

The fair value of loans and borrowings is COP$43,261,792 and COP$38,305,674 as of December 31, 2019 and 2018, 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).

19.8

Movement of net financial debt

The following is the movement of net financial debt as of December 31, 2019, 2018 and 2017:

	Cash			Other			Loans			Net
	and			financial			and			financial
	equivalents			assets			borrowings			debt
Balance as of December 31, 2017		7,945,885			6,533,725			(43,547,835	)		(29,068,225	)
Cash flow		(2,040,386	)		843,612			11,363,077			10,166,303
Exchange difference:
Recognized in profit or loss		406,245			920,609			(816,840	)		510,014
Recognized in other comprehensive income		—			—			(2,165,569	)		(2,165,569	)
Financial cost registered to projects		—			—			(217,891	)		(217,891	)
Financial income (expense) recognized in profit or loss		—			92,906			(2,399,414	)		(2,306,508	)
Foreign currency translation		—			(245,958	)		(203,446	)		(449,404	)
Other movements that do not generate cash flow					2,921			(74,727	)		(71,806	)
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		—			(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	)

F-69

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

20.

Trade and other payables

	2019		2018
Suppliers		8,115,015		6,878,510
Partners’ advances		925,761		874,010
Withholding tax		673,204		246,867
Related parties (Note 30)		187,616		116,418
Dividends payable		157,181		84,657
Insurance and reinsurance		136,041		211,883
Agreements in transport contracts (1)		71,239		210,196
Deposits received from third parties		44,826		49,158
Various creditors		402,808		304,613
		10,713,691		8,976,312

Current		10,689,246		8,945,790
Non–current		24,445		30,522
		10,713,691		8,976,312

(1)

Corresponds to the value of debt from agreements in transport contracts of oil pipelines and poliducts, impacted by volumetric adjustments, 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.

21.

Provisions for employees’ benefits

	2019		2018
Post–employment benefits
Healthcare		6,908,799		5,507,784
Pension		2,853,718		1,452,322
Education		458,441		479,945
Bonds		352,917		331,064
Other plans		98,729		82,576
Termination benefits – Voluntary retirement plan		124,186		137,859
		10,796,790		7,991,550
Social benefits and salaries		587,596		521,802
Other employee benefits		96,678		93,199
		11,481,064		8,606,551

Current		1,929,087		1,816,882
Non–current		9,551,977		6,789,669
		11,481,064		8,606,551

F-70

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

21.1

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, 2019 and 2018:

	Pension and bonds (1)						Other						Total
	2019			2018			2019			2018			2019			2018
Liabilities for employee benefits
Opening balance		14,131,943			14,147,464			6,212,118			6,105,432			20,344,061			20,252,896
Current service cost		—			—			76,478			77,373			76,478			77,373
Past service cost		—			—			—			50,489			—			50,489
Interest expense		920,622			888,583			418,553			377,923			1,339,175			1,266,506
Actuarial (losses) gains		1,755,300			(56,655	)		1,273,409			(27,651	)		3,028,709			(84,306	)
Benefits paid		(891,393	)		(847,449	)		(387,387	)		(371,448	)		(1,278,780	)		(1,218,897	)
Closing balance		15,916,472			14,131,943			7,593,171			6,212,118			23,509,643			20,344,061

Plan assets
Opening balance		12,348,557			12,471,163			3,954			3,245			12,352,511			12,474,408
Return on assets		801,065			780,494			217			170			801,282			780,664
Contributions to funds		—			—			83,071			21,971			83,071			21,971
Benefits paid		(891,393	)		(847,449	)		(84,243	)		(21,526	)		(975,636	)		(868,975	)
Actuarial (losses) gains		451,609			(55,651	)		16			94			451,625			(55,557
Closing balance		12,709,838			12,348,557			3,015			3,954			12,712,853			12,352,511
Net post–employment benefits liability		3,206,634			1,783,386			7,590,156			6,208,164			10,796,790			7,991,550

(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.

The following table shows the movement in profit and loss and in other comprehensive income as of December 31, 2019, 2018 and 2017:

	2019			2018			2017
Recognized in profit or loss
Interest expense. net		537,893			485,842			373,522
Current service cost		76,478			77,373			52,164
Past service cost		—			50,489			—
Remedies		10,213			503			13,889
		624,584			614,207			439,575
Recognized in other comprehensive income
Pension and pension bonds		(1,303,693	)		1,003			(1,312,195	)
Healthcare		(1,268,379	)		(17,356	)		(794,535	)
Education and severance		922			45,509			(203,779	)
Termination benefits – Voluntary retirement plan		(34	)		93			(3	)
		(2,571,184	)		29,249			(2,310,512	)
Deferred tax		771,355			(33,539	)		762,469
		(1,799,829	)		(4,290	)		(1,548,043	)

F-71

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

21.2

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, 2019 and 2018:

	2019		2018
Bonds issued by the national government		4,301,961		4,307,972
Bonds of private entities		3,122,630		2,910,071
Other local currency		1,899,787		2,219,634
Other public bonds		1,082,815		1,014,663
Other foreign currency		870,859		691,658
Variable yield		823,977		653,828
Bonds of foreign entities		610,824		554,685
		12,712,853		12,352,511

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 73.4% are classified as level 2 (47.4% and 52.6% for 2018, respectively).

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-72

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:

	2019		2018
AAA		5,138,279		4,683,190
Nation		4,448,221		4,364,188
AA+		837,009		860,905
BBB-		455,201		426,743
BBB		319,514		193,579
BAA3		219,830		310,788
SP1+		84,933		—
A-1+		78,156		—
BRC1+		68,313		89,211
F1+		56,728		249,361
BBB+		22,113		86,040
A3		17,267		17,075
AA-		16,067		60,382
BAA1		15,538		21,395
AA		6,679		28,367
A		11,841		62,754
Other credit ratings		30,129		55,768
Not available ratings		887,035		842,765
		12,712,853		12,352,511

See credit risk policy in Note 29.2.

F-73

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

21.3

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, 2019 and 2018:

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

5.50% / 4.70

Expected inflation rate

3.00%

Pension growth rate

3.00%

N/A

Cost trend

Short–term rate

N/A

7.00%

4.00%

N/A

Long–term rate

N/A

4.00%

N/A

2018

Pension

Bonds

Health

Education

Other benefits (1)

Discount rate

6.75%

6.50%

7.00%

6.75%

5.87%

Salary growth rate

N/A

5.10% / 4.70

Expected inflation rate

3.00%

Pension growth rate

3.00%

N/A

Cost trend

Short–term rate

N/A

7.00%

4.00%

N/A

Long–term rate

N/A

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.

21.4

Maturity of benefit obligation

The cash flows required for payment of post–employment obligations are the following:

Period		Pension and bonds		Other benefits		Total
	2020		949,034		377,313		1,326,347
	2021		967,734		384,233		1,351,967
	2022		1,000,730		391,324		1,392,054
	2023		1,000,770		401,058		1,401,828
	2024		1,038,858		404,691		1,443,549
	2025 and thereafter		5,551,125		2,081,228		7,632,353

F-74

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

21.5

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, 2019:

Pension

Bonds

Health

Education

Other benefits

Discount rate

–50 basis points

15,765,778

1,098,700

7,464,162

478,697

231,732

+50 basis points

14,032,277

1,022,732

6,418,743

440,209

220,426

Inflation rate

–50 basis points

14,045,125

1,021,771

N/A

125,653

+50 basis points

15,744,316

1,099,381

N/A

128,775

Salary growth rate

–50 basis points

N/A

94,266

+50 basis points

N/A

103,434

Cost trend

–50 basis points

N/A

6,425,329

439,471

N/A

+50 basis points

N/A

7,452,021

478,793

N/A

21.6

Voluntary retirement plan

In October 2017, 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 August 2016, the Ecopetrol Business Group offered a voluntary retirement plan to 200 employees who met certain criteria. As of December 31, 2019, 132 employees were part of the plan, with a corresponding obligation of COP$124,186 (2018 – COP$137,859. This plan includes benefits such as monthly income, education and health benefits until the date on which the employee is granted their retirement pension.

22.

Accrued liabilities and provisions

	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-75

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

	Asset retirement obligation			Litigation			Environmental contingencies and others			Total
Balance as of December 31, 2016		5,064,660			209,932			643,278			5,917,870
Increase in abandonment costs		39,634			—			—			39,634
Additions (reversals)		110,587			(19,185	)		106,532			197,934
Uses		(66,469	)		(7,742	)		(19,613	)		(93,824	)
Financial costs		379,891			—			(367	)		379,524
Foreign currency translation		(979	)		(39	)		718			(300	)
Transfers (1)		—			—			96,611			96,611
Balance as of December 31, 2017		5,527,324			182,966			827,159			6,537,449
Current		199,824			159,881			199,123			558,828
Non–current		5,327,500			23,085			628,036			5,978,621
		5,527,324			182,966			827,159			6,537,449

(1)

Mainly includes transfers to liabilities associated with assets held for sale.

22.1

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, 2019 were: Exploration and Production 3.01% (2018 – 3.54%), Transportation and Logistics 2.61% (2018 – 3.69%) and Refining and Petrochemicals 3.94% (2018- 3.84%).

22.2

Litigation

The following is a summary of the main legal proceedings recognized in the consolidated statement of financial position, where the expectation of loss is probable and could imply an outflow of resources as of December 31, 2019 and 2018:

F-76

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Proceedings	2019		2018

Provision to execute contracts		93,992		93,992
Controversy for breach of contract with firms Consulting Group and Industrial Consulting SAS. with the Refinería de Cartagena and payment was made in 2019		—		15,541

22.3

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, 2018 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.

As of December 31, 2018, the provision for the 1% mandatory investment for the use of water was estimated based on the parameters established in Decree 1076 of 2015. The Ecopetrol Business Group is in the process of analyzing the impact of the applicability of the changes set out in the aforementioned decrees.

As of December 31, 2019, the Ecopetrol Business Group achieved a new certification of a settlement base and the acceptance of the percentage of the investment values’ update of 1% in compliance with article 321 of Law 1955 of 2019 generating a lower provision of this obligation.

22.4

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 the early termination rights under the Ship-or-Pay Transport Agreements entered by each of them and Bicentenario in 2012 (the “Transport Agreements”).

In accordance with the foregoing, the carriers have ceased to fulfill their obligations under said Transport Agreements. Bicentenario has rejected the terms of the letters, noting that there was 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 the tariff under the aforementioned agreements. Consequently, Bicentenario executed the standby letters of credit posted as guarantee for the Transport Agreements.

F-77

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Having exhausted the direct settlement stages with each carrier, Bicentenario withdrew the initially filed claims and filed arbitration claims against each of them as follows: (i) on November 12, 2019, Bicentenario filed a claim against Frontera under cover of the arbitration agreement contained in the Transport Agreement; (ii) on December 10, 2019, Bicentenario filed a claim against Vetra under the arbitration agreement contained in the Transport Agreement; and (iii) on December 26, 2019, Bicentenario filed a claim against Canacol under the arbitration agreement contained in the Transport Agreement. On December 3, 2019, Bicentenario also filed an arbitration claim against Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp., Canacol and Vetra under the Acuerdo Marco de Inversión before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce.

The four arbitration proceedings are ongoing.

Simultaneously, Bicentenario will continue to exercise its rights under the terms of the Transportation Agreements and its related agreements, to guarantee compliance and claim any compensation, indemnity or restitution arising from the alleged early termination of said agreements, together with other breaches.

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

Ship or pay transport agreements:

The clauses in the agreements signed with Frontera Energy Group with respect to the Caño Limón Coveñas Pipeline, and in particular clause 13.3 establish that, in the event of the suspension of services for reasons not attributable to any of the parties, for a period over 180 continuous calendar days, either party may request the early termination of the agreement.

Based on this, on July 12, 2018, CENIT received a communication from Frontera Energy Group, whereby the latter expressed its decision to exercise the provision set forth in clause 13.3 for each of the Transport Agreements signed with respect to the Caño Limón - Coveñas Pipeline, requesting their early termination. In relation to the foregoing, CENIT issued communication CEN-PRE-3451-2018-E dated July 17, 2018 whereby it stated that the grounds to exercise clause 13.3 of the agreements in question have not occurred; therefore, Frontera Energy Group cannot exercise its contractual right to early termination.

Included in that same communication, CENIT stated its intention to continue billing and charging the transportation services established in the aforementioned agreements, considering that they are still valid, therefore Frontera must comply with the obligations assumed therein.

In 2019, CENIT evaluated the revenue recognition principle in accordance with the criteria contained in IFRS 15, determining that it is not possible to recognize the income associated with this agreement in the amount of COP$163,852, notwithstanding the aforementioned, the contractual rights and obligations remain and therefore the controversy with the Frontera Energy Group continues.

As of December 31, 2019, the amounts owed by the Frontera Energy Group in relation to the case described above amount to COP$334,582.

F-78

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

22.5

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, 2019 and 2018:

	2019				2018
Type of process	Number of processes		Proceedings		Number of processes		Proceedings
Constitutional action		14		1,092,228		13		1,075,965
Ordinary administrative		160		780,150		149		701,080
Ordinary labor		593		49,055		652		76,744
Ordinary civil		52		16,269		54		15,875
Arbitration		0		0		1		10,608
Special labor		13		720		14		1,056
Penal		1		595		1		0
Executive administrative		1		28		2		40
Guardianship		112		10		105		0
Executive civil		1		0		2		1,281
		947		1,939,055		993		1,882,649

22.6

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:

	2019				2018
Type of process	Number of processes		Proceedings		Number of processes		Proceedings
Ordinary administrative		35		373,555		47		229,935
Ordinary civil		75		86,363		40		12,101
Arbitration		1		67,232		1		261,754
Penal		156		60,177		189		58,481
Executive civil		61		4,912		65		3,569
Executive administrative		11		4,028		15		4,286
Ordinary labor		50		3,295		51		6,086
Special labor		57		307		59		320
Guardianship		4		—		6		—
		450		599,869		473		576,532

F-79

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Refinería de Cartagena S.A.S

On May 25, 2016, CB&I filed its Answer to the Request for Arbitration and Counterclaim for approximately USD$106 million and COP$324,052 million. On June 27, 2016, Reficar filed its reply to CB&I’s counterclaim denying and disputing the declarations and relief requested by CB&I. On April 28, 2017, CB&I submitted its Statement of Counterclaim increasing its claims to approximately USD$116 million and COP$387,558 million. On March 16, 2018, CB&I submitted its Exhaustive Statement of Counterclaim further increasing its claims to approximately USD$129 million and COP$432,303 million (including in each case interest), and also filed its Exhaustive Statement of Defense to Reficar’s claims. On this same date, Reficar filed its Exhaustive Statement of Claim seeking, among others, USD$ 139 million for provisionally paid invoices under the Memorandum of Agreement(“MOA”) and Project Invoicing Procedure (“PIP”) Agreements and the EPC Contract.

On June 28, 2019, CB&I submitted its Reply to the Non-Exhaustive Statement of 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.

22.7

Investigations of control entities

Reficar Investigations

F-80

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

As a result, Ecopetrol and Reficar employees are generally subject to the control and supervision of the following control entities, among others:

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:

The Office of the Comptroller General’s investigations and proceedings

1.1

1.2

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 current employee of Ecopetrol, and former employees of Reficar, as well as against (ii) 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, 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 the consolidated financial statements, 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 the consolidated financial statements, no charges have been issued in the second proceeding related to the modifications in the Project’s schedule.

F-81

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

As of the date of the consolidated financial statements, both Ecopetrol and Reficar have no liability under these proceedings.

1.3

1.4

1.5

On January 2019, the Office of the Comptroller General initiated a financial audit in Reficar and delivered a final report to Reficar on May 20, 2019.

1.6

On January 2020, the Office of the Comptroller General initiated a financial audit in Reficar. The final report is expected to be delivered to Reficar in May 2020.

In respect of the special audits mentioned in sections 1.3, 1.4, 1.5 and 1.6 above, as of the date of the consolidated financial statements, Reficar has no knowledge of any procedural actions carried out by any of the Colombian control entities regarding the disciplinary, fiscal and/or criminal investigations ordered by Resolution No. 2713, Resolution No. 3135 or Resolution No. 2898.

Reficar’s external auditors issued an unqualified opinion on Reficar’s financial position as of December 31, 2016, 2017, 2018 and 2019. As of the date of the consolidated financial statements, such auditors have not informed Reficar that there has been any change to their opinion.

As of the date of the consolidated financial statements, 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.

F-82

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

As of the date of the consolidated financial statements, the current Boards of Directors of Ecopetrol and Reficar are not part of the Comptroller General proceedings.

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.

The specific content and status of the remaining three ongoing investigations remains confidential.

As of the date of the consolidated financial statements, the current Boards of Directors of Ecopetrol and Reficar are not part of the Attorney General’s Office proceedings.

The Prosecutor’s Office investigations:

The Prosecutor’s Office has been conducting the following legal proceedings:

3.1

3.2

F-83

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

On January 27, 2020, during the indictment hearing, Ecopetrol and Reficar were recognized as victims.

3.3

As of the date of the consolidated financial statements, the current Boards of Directors of Ecopetrol and Reficar and their employees are not part of the Prosecutor’s Office proceedings. None of the legal proceedings described in this paragraph are related with bribery charges.

As of the date of the consolidated financial statements, Ecopetrol and Reficar have no knowledge of any legal proceeding in the United States regarding the project.

23.

Equity

The main components of equity are detailed below:

23.1

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, 2019 and 2018, subscribed and paid–in capital amounts to COP$25,040,067. There are no potentially dilutive shares.

23.2

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).

23.3

Equity reserves

The following is the composition of the Ecopetrol Business Group’s reserves as of December 31, 2019 and 2018:

	2019		2018
Legal reserve		3,243,832		2,088,192
Fiscal and statutory reserves		509,082		509,081
Occasional reserves (1)		31,744		2,541,622
		3,784,658		5,138,895

The movement of equity reserves is the following for the years ended December 31, 2019 and 2018:

F-84

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

	2019			2018
Opening balance		5,138,895			2,177,869
Release of reserves		(3,050,703	)		(751,718	)
Allocation to reserves		5,355,852			3,712,744
Dividends declared		(3,659,386	)		—
Closing balance		3,784,658			5,138,895

23.4

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 Ordinary General Shareholders’ Meeting, held on March 29, 2019, approved the profit distribution for 2018 and set the distribution of dividends at COP$9,251,256. In addition, the Extraordinary General Shareholders’ Meeting, held on December 16, 2019 approved the change of the occasional reserve destination authorized on March 29, 2019; therefore, the Ecopetrol Business Group distributed as an extraordinary dividend COP$3,659,386. A total of 100% of dividends was paid during 2019.

The Ordinary General Shareholders’ Meeting, held on March 23, 2018, approved the profit distribution for 2017 and set the distribution of dividends at COP$3,659,386. Dividends paid in 2018 attributable to the shareholders of Ecopetrol S.A. amounted to COP$3,659,373 (2017 - COP$945,661) and those of the non-controlling interest to COP$768,328 (2017 – COP$558,986).

23.5

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:

	2019			2018			2017
Foreign currency translation		10,265,398			10,235,891			7,706,623
Cash flow hedge with derivative instruments		3,689			(30,962	)		6,942
Cash flow hedges for future exports		(135,748	)		(374,079	)		159,295
Actuarial gain on defined benefit plans		(2,357,210	)		(557,381	)		(553,091	)
Hedge of a net investment in a foreign operation		(1,130,583	)		(1,069,316	)		(97,362	)
Others		1,114			176,608			176,608
		6,646,660			8,380,761			7,399,015

23.6

Earnings per share

	2019			2018			2017
Profit attributable to Ecopetrol’s shareholders			13,744,011			11,381,386			7,178,539
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$	334.3		COP$	276.8		COP$	174.6

F-85

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

24.

Sales revenue from contracts with customers

	2019			2018		2017
National sales
Mid–distillates		13,541,756			11,586,192		9,590,326
Gasoline and turbo fuels		9,373,030			7,952,852		6,990,187
Transport services		3,829,102			3,531,404		3,589,553
Natural gas		2,305,543			1,885,846		1,815,754
Plastic and rubber		760,301			822,367		833,982
Asphalts		544,200			335,426		275,803
LPG and propane		372,916			574,639		509,619
Crude oil		356,857			550,479		909,871
Services		309,353			239,410		283,799
Aromatics		228,552			282,545		217,418
Polyethylene		190,133			270,887		167,348
Other income gas contracts (1)		102,845			156,031		188,195
Fuel oil		97,907			509,482		354,058
Other products		507,336			489,507		280,226
		32,519,831			29,187,067		26,006,139
Recognition of price differential (2)		1,785,277			3,835,533		2,229,953
		34,305,108			33,022,600		28,236,092
Foreign sales
Crude oil		28,523,596			26,898,737		21,479,063
Diesel		4,391,798			3,050,839		1,213,740
Fuel oil		1,870,929			2,053,594		1,982,408
Plastic and rubber		1,200,668			1,268,582		1,169,101
Gasoline and turbo fuels		1,085,392			1,782,194		1,223,994
Natural gas		27,255			27,899		32,303
LPG and propane		13,591			20,212		15,631
Cash flow hedge for future exports – Reclassification to profit or loss (Note 29.1.2)		(386,773	)		128,404		160,772
Other products		456,948			350,811		441,124
		37,183,404			35,581,272		27,718,136
		71,488,512			68,603,872		55,954,228

(1)

Corresponds to income on the share of gas sales profits, under the agreement signed between Ecopetrol and Chevron in 2004, for the extension of the joint venture contract for the exploitation of gas in La Guajira.

(2)

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). See Note 4.16 – Sales revenue recognition from contracts with customers.

Sales by geographic areas

	2019		%		2018		%		2017		%
Colombia		34,305,108		48.0%		33,022,600		48.1%		28,236,092		50.5%
United States		17,371,173		24.3%		14,765,674		21.5%		12,532,932		22.4%
Asia		13,529,151		18.9%		12,271,225		17.9%		6,136,796		11.0%
Central America and the Caribbean		3,472,665		4.9%		4,449,033		6.6%		6,070,565		10.8%
South America and others		1,502,815		2.1%		2,968,038		4.3%		1,947,226		3.5%
Europe		1,307,600		1.8%		1,127,302		1.6%		1,030,617		1.8%
		71,488,512		100%		68,603,872		100%		55,954,228		100%

F-86

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Concentration of customers

During 2019, Organización Terpel S.A. represented 16.0% of sales revenue for the period (2018 – 14.0% and 2017 – 14.3%); 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.

25.

Cost of sales

	2019			2018			2017
Variable costs
Imported products (1)		12,639,710			11,809,529			11,637,419
Depreciation amortization and depletion		5,523,306			5,064,518			5,765,186
Purchases of crude in association and concession		5,466,496			3,820,746			2,240,704
Purchases of hydrocarbons – ANH (2)		5,437,177			5,667,567			4,338,576
Process materials		1,016,617			968,884			889,122
Electric energy		829,543			662,297			561,424
Hydrocarbon transport services		821,654			696,964			665,714
Taxes and economic rights		788,924			441,207			449,959
Purchases of other products and gas		584,507			632,509			488,056
Services contracted in associations		267,778			260,207			195,689
Others (3)		(676,269	)		(186,087	)		(663,916	)
		32,699,443			29,838,341			26,567,933
Fixed costs
Depreciation and amortization		2,781,446			2,555,176			2,366,849
Maintenance		2,497,002			2,260,984			2,038,970
Labor costs		2,316,567			2,105,803			1,815,213
Services contracted		1,841,009			1,796,354			1,414,056
Services contracted in associations		1,211,510			1,040,221			1,008,336
Materials and operating supplies		574,678			565,601			468,205
Taxes and contributions		516,933			393,690			343,505
Hydrocarbon transport services		268,572			261,237			333,671
General costs		265,200			366,972			551,587
		12,272,917			11,346,038			10,340,392
		44,972,360			41,184,379			36,908,325

(1)

Imported products correspond mainly to diesel fuel 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 capitalization of the inventory, product of the costing and valuation process, ii) the valuation at Net Realizable Value, and iii) the loans of inventories by transport.

F-87

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

26.

Administrative, operations and project expenses

	2019		2018		2017
Administrative expenses
General expenses		1,140,975		911,645		723,341
Labor expenses		759,324		662,258		624,424
Taxes		48,753		39,117		362,963
Depreciation and amortization		202,547		40,838		53,796
		2,151,599		1,653,858		1,764,524
Operations and project expenses
Exploration costs		763,452		1,387,379		1,341,940
Taxes		483,330		433,506		324,223
Commissions, fees, freights and services		558,370		466,862		471,657
Labor expenses		402,531		316,386		310,947
Fee for regulatory entities		94,785		98,794		63,470
Depreciation and amortization		75,484		44,318		95,516
Maintenance		56,333		50,846		122,273
Others		197,469		105,041		196,039
		2,631,754		2,903,132		2,926,065

27.

Other operating income (expenses), net

	2019			2018			2017
Gain (loss) on acquisition of participations and interests (1)		1,048,924			(12,065	)		451,095
(Loss) profit on sale of assets		(148,021	)		(93,601	)		40,227
Expense for legal provisions		(98,020	)		(68,398	)		(72,408	)
Impairment loss of short–term assets		(90,441	)		(105,692	)		(68,800	)
Expense for gas pipeline availability BOMT contracts (2)		—			—			(72,318	)
Other income		344,354			244,301			227,607
		1,056,796			(35,455	)		505,403

(1)

For 2019, this corresponds mainly to gains related to the business combination of Invercolsa S.A. (see Note 12)

(2)

Corresponds to the services rendered in connection with the BOMT contracts for the construction, operation, maintenance and transfer of gas pipelines with Transgas. This contract terminated in August 2017.

F-88

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

28.

Financial result, net

	2019			2018			2017
Finance income
Results from financial assets and others		975,245			745,571			739,148
Yields and interests		481,674			383,624			405,562
Dividends (1)		117,260			—			—
Gain on sale of equity instruments		—			368			13,236
Other financial income		49,157			—			1,410
		1,623,336			1,129,563			1,159,356
Finance expenses
Interest (2)		(1,894,490	)		(2,399,414	)		(2,385,994	)
Financial cost of other liabilities (3)		(757,509	)		(668,782	)		(753,047	)
Results from financial assets and others		(638,767	)		(381,445	)		(481,308	)
Other financial expenses		(43,703	)		(62,520	)		(40,252	)
		(3,334,469	)		(3,512,161	)		(3,660,601	)
Foreign exchange gain (loss), net		40,639			372,223			5,514
Financial result, net		(1,670,494	)		(2,010,375	)		(2,495,731	)

(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. See Note 12 - Business combinations.

(2)

As of December 31, 2019, borrowing costs for the financing of developing natural resources and property, plant and equipment of COP$248,139 (2018 – COP$200,833 and 2017 – COP$191,651) were capitalized.

(3)

Includes the financial expense of the asset retirement obligations and the liabilities for post–employment benefits.

29.

Risk management

29.1

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, which arises from various foreign currency exposures due to commercial transactions, assets and liabilities denominated in foreign currency. The impact of exchange rate fluctuations, especially the Colombian peso/U.S. dollar exchange rate, has been material in previous years.

The U.S. dollar/Colombian peso exchange rate has fluctuated over the last few years. As of December 31, 2019, the Colombian peso appreciated 0.8%. The closing rates were COP$3,277.14, COP$3,249.75 and COP$2,984.00 for 2019, 2018 and 2017, respectively.

When the Colombian peso appreciates in relation to the U.S. dollar, export sales revenue decreases when converted to Colombian pesos; by contrast, imported goods, operating costs and interest on foreign debt denominated in U.S. dollars become less expensive. Conversely, when the Colombian peso depreciates, export revenues increase in conversion to Colombian pesos, and servicing of the external debt and imports become more expensive.

The following table sets out the carrying amount for financial assets and liabilities with exchange exposure denominated as of December 31, 2019 and 2018:

F-89

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(in USD$Million)	2019			2018
Cash and cash equivalents		114			514
Other financial assets		1,468			2,138
Trade receivables and payables, net		81			(202	)
Loans and borrowings		(9,429	)		(9,689	)
Other assets and liabilities, net		64			63
Net liability position		(7,702	)		(7,176	)

Of the total net liability position, USD$(7,769) million correspond to net liabilities in dollars with exchange exposure of companies with the Colombian peso as its functional currency and a net amount of USD$67 million corresponds to monetary assets and liabilities with exchange exposure of companies whose functional currency is different from Colombian peso; for both cases valuation is recognized in profit or loss. The balance of loans and borrowings includes non-derivative hedging instruments of Ecopetrol of USD$(7,331), for which valuation is recognized in other comprehensive income, within the equity. The exchange difference valuation of the rest of net assets (USD$438 million) is recognized in profit and loss.

29.1.1

Sensitivity analysis for exchange rate risk

The Ecopetrol Business Group’s risk management strategy involves the use of non-derivative financial instruments related to cash flow hedges for future exports and hedges of a net investment in a foreign operation in order to minimize exposure to currency rate risk, which is detailed below.

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, 2019:

Scenario / Variation in the exchange rate		Effect on income before taxes (+/–)			Effect on other comprehensive income (+/–)
	1%		(12,158	)		(240,247	)
	5%		(60,791	)		(1,201,236	)

The sensitivity analysis only includes financial assets and liabilities in foreign currency at the closing date.

29.1.2

Cash flow hedge for future exports

Ecopetrol is exposed to foreign exchange risk given that a significant percentage of its income from crude oil exports is denominated in U.S. dollars. In recent years, the Ecopetrol Business Group has acquired long–term debt for investment activities in the same currency in which it expects to receive the cash flows of its export sales revenues. This situation creates a natural hedge relationship due to the fact that the risks generated by the foreign exchange difference of export sales revenues when booked in Ecopetrol’s functional currency (Colombian pesos) are naturally hedged with the foreign exchange variances of the long–term debt, in line with the Ecopetrol Business Group’s risk management strategy.

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, 2019 and 2018:

(USD$Million)	2019			2018
Hedging instrument at the beginning of the period		1,300			3,332
Reassignment of hedging instruments		5,551			3,366
Realization of exports		(5,551	)		(3,366	)
Capital payments (1)		—			(2,032	)
Hedging instrument at the end of the period		1,300			1,300

F-90

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(1)

On December 27, 2018, Ecopetrol S.A. paid in advance the entire 10-year international bond issued in 2009, whose nominal value was USD$1,500 million. Equally, on June 30, 2017, Ecopetrol prepaid the entire outstanding balance of the international syndicated loan whose nominal value was USD$1,925 million and original maturity date was February 2020.

The following is the movement of accumulated foreign currency gains and losses in respect of the cash flow hedge recognized in other comprehensive income for the years ended December 31, 2019, 2018 and 2017:

	2019			2018			2017
Opening balance		(374,079	)		159,295			244,131
Exchange difference		(35,607	)		(704,871	)		(15,933	)
Reclassification to profit or loss		386,773			(128,404	)		(160,772	)
Ineffectiveness		5,173			35,617			9,247
Deferred income tax		(118,008	)		264,284			82,622
Closing balance		(135,748	)		(374,079	)		159,295

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
2020		(50,986)		16,316		(34,670	)
2021		(53,249)		16,507		(36,742	)
2022		(53,249)		15,975		(37,274	)
2023		(38,669)		11,607		(27,062	)
		(196,153)		60,405		(135,748	)

29.1.3

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 S.A. has designated its net investments in Ocensa, Ecopetrol America Inc., Hocol Petroleum Ltd. (HPL) and Reficar as the hedged items. The amount of USD$5,200 million of the Ecopetrol Business Group’s U.S. dollar debt was designated as the hedge instrument.

In November 2019, a new hedge designation of USD$930 million was made according to the net investment in Ecopetrol Permian LLC. The value of the hedge instrument as of December 2019 was USD$831 million.

The following is the movement of accumulated foreign currency gains and losses in respect of the net investment hedge recognized in other comprehensive income for the years ended December 31, 2019, 2018 and 2017:

	2019			2018			2017
Opening balance		1,069,316			97,362			155,359
Exchange difference		87,524			1,381,900			(86,892	)
Ineffectiveness		—			378			329
Deferred income tax		(26,257	)		(410,324	)		28,566
Closing balance		1,130,583			1,069,316			97,362

F-91

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

29.1.4

Hedging with financial derivatives to minimize foreign exchange risk

The Ecopetrol Business Group carries out non–delivery forward operations in order to mitigate the volatility of the exchange rate in requirements of cash flow for operations of its subsidiary, Ocensa, whose functional currency is the US dollar.

The forward hedging instruments are used to enable setting sales prices in U.S. dollars, mitigating the foreign exchange variation given Ocensa’s obligations related to operational cost and tax payments that are payable in Colombian pesos. The accounting policy applicable to this operation is described in the Note 4.1.5.1.

As of December 31, 2019, there are forward contracts with a net short position for USD$378 million (2018 – USD$332 million) with maturities between January and December 2020.

The variation and/or compensation of full hedging operations for the payment of taxes is recorded in the statement of comprehensive income, affecting the income tax expense on the initial measurement and the exchange result for subsequent measurements. The variation of the hedging operations related to costs and expenses are recorded as other comprehensive income, in case they are effective; once the result of the compensation is settled, it is recorded as less and/or greater value of the hedged expense amount.

The impact on profit and loss for the settlement of these hedges corresponds to a loss of COP$60,740 (2018 – COP$80,636 of profit) and the amount recognized in the other comprehensive income was a profit of COP$43,141 (2018 COP$52,174 of loss).

29.1.5

Commodity price risk

Ecopetrol’s business is significantly impacted by international prices for crude oil and refined products. The prices for these products are volatile, and drastic changes could adversely affect the Ecopetrol Business Group business prospects and results of operations.

A large proportion of Ecopetrol’s sales revenues come from sales of crude oil, natural gas and refined products. These products are indexed to international reference prices such as the Brent index. Consequently, fluctuations in those international indexes have a direct effect on the financial conditions and the Group’s results of operations.

Prices of crude oil, natural gas and refined products have historically fluctuated as a result of a variety of factors including, among others, competition within the oil and natural gas industry; changes in international prices of natural gas and refined products; long-term changes in the demand for crude oil, natural gas and refined products; regulatory changes; changes in the cost of capital; adverse economic conditions; transactions in derivative financial instruments related to oil and gas and development or availability of alternative fuels.

The Ecopetrol Business Group has a policy approved by the Board of Directors that allows it to use derivative financial instruments in the organized over-the-counter (OTC) market to cover itself from the risk of price fluctuations of crude oil and refined products associated with physical transactions. The Ecopetrol Business Group has established appropriate processes to handle risk, which include constant monitoring of physical and financial markets to identify risks in order to subsequently prepare and execute hedging strategies.

Ecopetrol does not regularly use derivative instruments to hedge risk exposures related to sales or purchases. The impact of the settlement of the price hedges was not material during the year 2019. Hedging instruments were made to mitigate the risk related to differences between price indexes and the benchmark of the Ecopetrol Business Group's international trade strategy on exports of crude and imports of products.

During the year 2019, price hedges were settled with a profit of COP$1,602 and as of December 31, 2019 an open position is maintained in favor of the Ecopetrol Business Group for COP$4,868.

F-92

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

29.2

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.

29.2.1

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 of the Ecopetrol Business Group.

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.

Ecopetrol does not have a significant concentration of credit risk. An aging analysis of the accounts receivable portfolio in arrears, but not impaired, as of December 31, 2019 and 2018 is as follows:

	2019		2018
Less than 3 months overdue		243,893		157,608
Between 3 and 6 months overdue		136,700		41,263
More than 6 months overdue		267,525		93,657
		648,118		292,528

29.2.2

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.

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 21 – Provisions for employees’ benefits.

F-93

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

29.3

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, 2019, 17% (2018, 17% and 2017, 19%) 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.

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		(16,320	)		32,276			(590,991	)
–100 basis points		16,278			(32,345	)		629,633

A sensitivity analysis of discount rates on pension plan assets and liabilities is disclosed in Note 21 – Provisions for employees’ benefits.

29.4

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, 2019. 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$3,277.14 per U.S. dollar:

F-94

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

	Up to 1 year		1–5 years		5–10 years		> 10 years		Total
Loans (payment of principal and interest)		3,680,187		19,206,790		15,022,371		19,480,277		57,389,625
Trade and other payables		10,689,246		26,621		—		—		10,715,867
Total		14,369,433		19,233,411		15,022,371		19,480,277		68,105,492

29.5

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, 2019 and 2018:

	2019			2018
Loans and borrowings (Note 19)		38,239,139			38,062,645
Cash and cash equivalents (Note 6)		(7,075,758	)		(6,311,744	)
Other financial assets (Note 9)		(4,979,292	)		(8,147,815	)
Net financial debt		26,184,089			23,603,086
Equity (Note 23)		58,231,628			57,107,780
Leverage (1)		31.02%			29.24%

(1)

Leverage = Net financial debt / (Net financial debt + Equity)

The movement of the net financial debt is detailed in Note 19.9.

F-95

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

30.

Related parties

Balances with associates and joint ventures as of December 31, 2019 and 2018 are as follows:

	Accounts receivable		Accounts receivable – Loans		Other assets		Accounts payable		Loans		Other liabilities
Joint Ventures
Equion Energy Limited(2)		25,333		—		57,016		153,501		1,108,403		794
Ecodiesel Colombia S.A.		2,116		—		—		29,447		—		1
Offshore International Group Inc.(1)		—		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 20)		(Note 19)

	Accounts receivable		Accounts receivable – Loans		Other assets		Accounts payable		Loans		Other liabilities
Joint Ventures
Equion Energy Limited		22,958		—		19,214		87,079		855,135		67
Ecodiesel Colombia S.A.		522		—		—		23,857		—		1
Offshore International Group Inc.(1)		—		117,824		—		—		—		—
Associates
Serviport S.A.		—		—		—		5,482		—		—
Balance as of December 31, 2018		23,480		117,824		19,214		116,418		855,135		68
Current		23,480		—		19,214		116,418		855,135		68
Non–current		—		117,824		—		—		—		—
		23,480		117,824		19,214		116,418		855,135		68
		(Note 7)		(Note 7)		(Note 11)		(Note 20)		(Note 19)

Loans with related parties:

(1)

Loan granted by Ecopetrol S.A. to Savia Perú S.A. (subsidiary of Offshore International Group) 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, 2019 is USD$28 million (2018 – USD$35 million). On December 11, 2019, Ecopetrol S.A. and the Korea National Oil Corporation ("KNOC") awarded to Savia a modification to the credit conditions. That modification is related to the payments of the principal to expire on December 16, 2019 (USD$7 million), June 15, 2020 (USD$7 million) and December 15, 2020 (USD$7 million), for the debtor to cancel this amount on February 19, 2021, at which time the final payment will be made for USD$28 million.

(2)

The interest rate of the loan with Capital AG corresponds to 2.37%.

The amounts outstanding are not guaranteed and will be settled in cash. No expense has been recognized in the current period or in previous periods with respect to uncollectible or doubtful accounts related to the amounts owed by related parties.

The main transactions with related parties for years ended December 31, 2019, 2018 and 2017 are detailed as follows:

F-96

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

	2019				2018			2017
	Sales and services		Purchases and others		Sales and services	Purchases and others		Sales and services		Purchases and others
Joint Ventures
Equion Energy Limited		317,382		569,105	67,002		846,284		425,881		598,636
Ecodiesel Colombia S.A		8,614		280,649	6,860		267,498		6,583		259,269
Offshore International Group		3,245		—	2,386		—		15,188		—
		329,241		849,754	76,248		1,113,782		447,652		857,905

30.1

Directors and key management personnel

In accordance with the approval given by the shareholders’ meeting in 2012, compensation paid to directors for attending the meetings of the Board of Directors and/or committees increased from four to six minimum legal monthly salaries in force, or approximately to COP$4,969,000 for 2019, from COP$4,687,000 for 2018 and COP$4,426,000 for 2017. For non–face–to–face sessions, 50% of the quota for face–to–face meetings is set. The members of the Board of Directors do not have any kind of variable remuneration. The amount paid in 2019 for compensation to members of the Board of Directors amounted to COP$1,847 (2018 – COP$2,152 and 2017 – COP$1,877).

The total compensation paid to Directors as of December 31, 2019, amounted to COP$22,632 (2018 – COP$21,580 and 2017 – COP$20,669). Directors are not eligible to receive pension and retirement benefits. The total amount reserved as of December 31, 2019, to provide pension and retirement benefits to the eligible executive officers amounted to COP$18,740 (2018 – COP$5,491 and 2017 – COP$5,401).

As of December 31, 2019, 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
Maria Consuelo Barrera		<1% outstanding shares
Rafael Espinosa Rozo		<1% outstanding shares

30.2

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.

30.3

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:

F-97

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

(a)

Purchase of oil from the National Hydrocarbons Agency – ANH

By nature of the business, the Ecopetrol Business Group has a direct relationship with ANH, an entity which operates under the rules of the Ministry of Mines and Energy, whose objective is to manage the oil and gas reserves and resources owned by the Colombian Nation.

Ecopetrol purchases the crude oil that the ANH receives from producers in Colombia at the prices set in accordance with a jointly established formula, which reflects the export sale prices (crude oils and products), adjusted for API gravity quality, sulfur content, transportation rates from the wellhead to the ports of Coveñas and Tumaco, refining process cost and a commercialization rate. This contract was extended to April 30, 2020.

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 25 – 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 National Government regulates the prices related to regular gasoline and diesel. In that way, the price will vary a maximum of 3% monthly establishing price stability for the final customer.

This price called Producer Income does not necessarily reflect the opportunity cost of fuels. For that reason, it is necessary to recognize that price difference to the refiner/importer. In this sense, the National Government, through the Fund of Fuel Price Stabilization, grants the price differences to the refiner/importer in cases where the cost of opportunity is higher than the Producer Income, or charges the refiner/import the difference when the Producer Incomer is higher than the opportunity cost.

This scheme ensures that the Company always receives the opportunity cost of these fuels that it sells in the country to the wholesale distributor. The value of this differential is detailed in Note 24 – Sales revenue from contracts with customers.

(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-98

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

31.

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 2019 are as follows:

31.1

Contracts in which Ecopetrol is not the operator

Partners	Contract	Type	% Participation	Geographic area of operations
Occidental Andina LLC	Chipirón Cosecha Cravo Norte Rondón	Production	30–40% 30% 55% 50%	Colombia
Chevron Petroleum Group	Guajira	Production	57%	Colombia
Mansarovar Energy Colombia Ltd	Nare	Production	50%	Colombia
Meta Petroleum Corp	Quifa	Production	40%	Colombia
Equion Energy Limited	Piedemonte	Production	55%	Colombia
Perenco Colombia Limited	Casanare Corocora Estero Garcero Orocúe	Production	74.40% 83.91% 95.98% 91.22% 86.47%	Colombia
Petrobras, Repsol & Statoil	Tayrona	Exploration	30%	North Caribbean Offshore
Shell	Deep Rydberg/Aleatico	Exploration	29%	Gulf of Mexico
Noble Energy	Gunflint	Production	32%	Gulf of Mexico
Murphy Oil	Dalmatian	Production	30%	Gulf of Mexico
Anadarko	K2	Production	21%	Gulf of Mexico
Shell – Parmer	Palmer	Exploration	30%	Gulf of Mexico
OXY (Anadarko)	Warrior	Exploration	30%	Gulf of Mexico
HESS	ESOXX	Exploration	21%	Gulf of Mexico
PEMEX Exploracion Y Produccion	Bloque 8	Exploration	50%	Gulf of Mexico
PETRONAS PC Carigali Mexico Operations, S.A. de C.V.	Bloque 6	Exploration	50%	Gulf of Mexico
Occidental Petroleum Company	Rodeo Midland Basin	Production	49%	Texas U.S. - Midland Basin
Equion Energia Limited	Niscota	Production	20%	Colombia
CNOOC – British Petroleum	Pau Brasil	Exploration	20%	Brazil
Shell / Chevron	Saturno	Exploration	10%	Brazil
Chevron	CE–M–715_R11	Exploration	50%	Brazil
Lewis	SSJN1	Exploration	50%	Colombia
Interoil Colombia	Mana	Production	30%	Colombia
Interoil Colombia	Ambrosia	Production	30%	Colombia
Interoil Colombia	Rio Opia	Production	30%	Colombia
Canacol	Rancho Hermoso Otras formaciones	Production	70%	Colombia
Vetra	La Punta Santo Domingo	Production	45%	Colombia
Geopark	Llanos 86	Exploration	50%	Colombia
Geopark	Llanos 87	Exploration	50%	Colombia
Geopark	Llanos 104	Exploration	50%	Colombia

F-99

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

31.2

Contracts in which Ecopetrol is the operator

Partners	Contract	Type	% Participation	Geographic area of operations
ExxonMobil Exploration Colombia	VMM29 CR2 C62	Exploration	50%	Colombia
Talisman Colombia Oil	CPO9	Exploration	55%	Colombia
ONGC Videsh Limited Colombia Branch	RC9	Exploration	50%	Colombia
CPVEN 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
Talismán Colombia oil and gas Ltd.	CPO9 – Akacias	Production	55%	Colombia
Parex Resourses Colombia Ltd.	ORC401 CRC-2004-01	Exploration	50%	Colombia
Occidental Andina LLC	La Cira Infantas Teca	Exploration	58% 76%	Colombia
Ramshorn International Limited	Guariquies I	Production	50%	Colombia
Equion Energy Limited	Cusiana Planta de Gas	Production	98%	Colombia
Perenco Oil And Gas Cepsa Colombia	San Jacinto Rio Paez	Production	68%	Colombia
Total Colombie Talisman Oil & Gas	Mundo Nuevo	Exploration	15%	Colombia
ONGC Videsh Limited	Block RC–9 Contract– Caribbean Round No. 37–2007	Exploration	50%	Gulf of Mexico

31.3

Relevant operations during the period

During 2019 and 2018, the following significant events occurred in respect of joint operations contracts:

(a)

Strategic alliance with Occidental Petroleum Corp.

OXY holds a 51% interest in the joint operation, while Ecopetrol holds the remaining 49%. This interest was acquired by means of a 50% advance payment at the close of the transaction on November 13, 2019 with the remaining 50% as a deferred investment to be paid over time in the activities included in the development plan. The total payment by Ecopetrol will amount to USD$1,500 million.

To enable the operation, two companies were established: Ecopetrol USA Inc. and Ecopetrol Permian LLC.

(b)

Acquisition 30% Sul de Gato do Mato discovery

F-100

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

On October 21, 2019, Ecopetrol S.A. announced that it had signed an agreement for USD$105 million with Shell Brasil Petróleo Ltda through its subsidiary Ecopetrol Óleo e Gás do Brasil Ltda., to acquire 30% of the interests, rights and obligations in two areas corresponding to the BM-S-54 Concession Agreement and the Sul de Gato do Mato shared production agreement, located offshore in Brazil’s pre-salt Santos basin, where a hydrocarbons deposit known as “Gato do Mato” was discovered. Shell will reduce its stake from 80% to 50% with this agreement and will continue as an operator, while the French company Total will retain the remaining 20%.

The agreement signed by Ecopetrol Óleo e Gás do Brasil Ltda. and Shell Brasil Petróleo Ltda. is undergoing the respective approval process before Brazil's Ministry of Mines and Energy, and its National Agency of Petroleum, Natural Gas and Biofuels.

(c)

Agreement for the acquisition of 10% in Saturn Block

In December 2018, the Group entered into an agreement with Shell and Chevron, for a 10% stake in the Saturn block, located in the central region of the Santos basin, which was assigned to Shell and Chevron on September 28, 2018 in the Fifth Pre-Salt Round conducted by the National Petroleum, Natural Gas and Biofuels Agency of Brazil (ANP).

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, a 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 (the operator) and Chevron each retain 45% of the total.

(d)

Stake in Guajira Association

On November 22, 2019, Hocol signed an agreement with Chevron Petroleum Company to acquire its share in the Chuchupa and Ballena fields located in the department of La Guajira. These fields are operated by Chevron through the Guajira Association Agreement (57% Ecopetrol and 43% Chevron). Under the terms of the agreement, Hocol will acquire Chevron’s share (43%), and will assume the position of operator. This transaction is subject to approval by the Superintendence of Industry and Commerce (SIC), and has no impact on the accounting figures as of December 31, 2019.

32.

Information by segments

A description of the Ecopetrol Business Group’s business segments is in Note 4.19 – Information by business segment.

32.1

Statement of profit or loss

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.

F-101

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

Below are the consolidated statements of profit or loss by segment for the years ended December 31, 2019, 2018 and 2017:

	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-102

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-103

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, 2017
	Exploration and Production			Refining and Petrochemicals			Transport and Logistics			Eliminations			Total
Third–party sales		25,004,320			27,343,359			3,606,549			—			55,954,228
Inter–segment sales		11,490,614			1,300,657			6,991,515			(19,782,786	)		—
Total sales revenue		36,494,934			28,644,016			10,598,064			(19,782,786	)		55,954,228
Fixed costs		(8,055,925	)		(2,886,745	)		(2,637,604	)		3,239,880			(10,340,394	)
Variable costs		(18,254,159	)		(23,968,650	)		(634,231	)		16,289,109			(26,567,931	)
Cost of sales		(26,310,084	)		(26,855,395	)		(3,271,835	)		19,528,989			(36,908,325	)
Gross profit		10,184,850			1,788,621			7,326,229			(253,797	)		19,045,903
Administrative expenses		(781,386	)		(516,501	)		(466,669	)		32			(1,764,524	)
Operation and project expenses		(2,070,916	)		(965,457	)		(142,847	)		253,155			(2,926,065	)
Impairment of non–current assets		183,718			1,067,965			59,455			—			1,311,138
Other operating income and expenses, net		545,218			(11,694	)		(28,121	)		—			505,403
Operating income (expenses)		8,061,484			1,362,934			6,748,047			(610	)		16,171,855
Financial result, net
Financial income		1,062,393			164,006			106,659			(173,702	)		1,159,356
Financial expenses		(2,288,576	)		(1,110,874	)		(434,664	)		173,513			(3,660,601	)
Foreign exchange gain (loss), net		(101,030	)		163,992			(57,448	)		—			5,514
		(1,327,213	)		(782,876	)		(385,453	)		(189	)		(2,495,731	)
Share of profits of associates and joint ventures		120,786			15,245			(42,493	)		—			93,538
Income before tax		6,855,057			595,303			6,320,101			(799	)		13,769,662
Income tax		(3,034,556	)		(238,625	)		(2,527,087	)		—			(5,800,268	)
Net profit (loss) for the period		3,820,501			356,678			3,793,014			(799	)		7,969,394
Profit (loss) attributable to:
Group owners of parent		3,820,501			358,859			2,999,978			(799	)		7,178,539
Non–controlling interest		—			(2,181	)		793,036			—			790,855
		3,820,501			356,678			3,793,014			(799	)		7,969,394
Supplementary information
Depreciation, depletion and amortization		5,981,294			1,188,871			1,111,182			—			8,281,347

F-104

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

32.2

Sales by product

The sales by product for each segment are detailed below for the years ended December 31, 2019, 2018 and 2017:

	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-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
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-106

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, 2017
	Exploration and Production		Refining and Petrochemicals		Transport and Logistics		Eliminations			Total
Local sales
Mid–distillates		1,334		9,588,992		—		—			9,590,326
Gasoline and turbo fuel		—		8,052,289		—		(1,062,102	)		6,990,187
Transport service		41,157		41,998		10,277,921		(6,771,523	)		3,589,553
Natural gas		2,540,233		4		—		(724,483	)		1,815,754
Plastic and rubber		—		833,982		—		—			833,982
Crude		11,668,529		—		—		(10,758,658	)		909,871
LPG and propane		199,796		309,823		—		—			509,619
Fuel oil		14,758		339,300		—		—			354,058
Asphats		34,834		240,969		—		—			275,803
Aromatics		—		217,418		—		—			217,418
Polyethylene		—		167,348		—		—			167,348
Services		140,227		179,912		319,776		(356,116	)		283,799
Other income gas contracts		188,195		—		—		—			188,195
Other products		11,107		379,023		—		(109,904	)		280,226
		14,840,170		20,351,058		10,597,697		(19,782,786	)		26,006,139
Recognition of price differential		—		2,229,953		—		—			2,229,953
		14,840,170		22,581,011		10,597,697		(19,782,786	)		28,236,092
Foreign sales
Crude		21,426,666		52,397		—		—			21,479,063
Diesel		—		1,213,740		—		—			1,213,740
Fuel oil		—		1,982,408		—		—			1,982,408
Gasoline and turbo fuels		—		1,223,994		—		—			1,223,994
Plastic and rubber		—		1,169,101		—		—			1,169,101
Natural gas		32,303		—		—		—			32,303
LPG and propane		15,631		—		—		—			15,631
Cash flow hedge for future exports – Reclassification to profit or loss		160,772		—		—		—			160,772
Other products		19,392		421,365		367		—			441,124
		21,654,764		6,063,005		367		—			27,718,136
		36,494,934		28,644,016		10,598,064		(19,782,786	)		55,954,228

F-107

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

32.3

Capital expenditures by segments

The following are the investments amounts made by each segment for the years ended December 31, 2019, 2018 and 2017:

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

2017	Exploration and Production		Refining and Petrochemicals		Transport and Logistics		Total
Property, plant and equipment		927,282		606,749		829,252		2,363,283
Natural and environmental resources		3,568,355		—		—		3,568,355
Intangibles		154,155		4,941		16,772		175,868
		4,649,792		611,690		846,024		6,107,506

F-108

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

33.

Subsequent events

On January 31, 2020, the General Shareholders' Meeting of Bioenergy SAS and on January 27, 2020, the sole shareholder of Bioenergy Zona Franca SAS, approved that those companies will submit a reorganization request under Law 1116 of 2006. This process intends to preserve the viability of the companies and normalize their business and credit relations, through operational and administrative restructuring, as well as their assets and liabilities. On March 10, 2020, the Superintendence of Companies issued a resolution admitting Bioenergy to the reorganization process regulated by the aforementioned law.

This decision is a result of: 1) the accumulated accounting losses of the companies, 2) the increase in the level of indebtedness compared to the initial planned capital structure, and 3) the fact that the plant failed in working at its maximum capacity due to the low productivity of the cane generated by its own crops and by third parties.

On February 7, 2020, Ecopetrol reported that an agreement with Shell was signed, through its subsidiary Shell EP Offshore Ventures Limited (“Shell”). According to the agreement, Shell will acquire a 50% interest in the Fuerte Sur, Purple Angel and COL-5 blocks. They are located in deep waters of the Colombian Caribbean, where a new gas province was discovered considering the wells Kronos (2015), Purple Angel and Gorgon (2017).

Following the commercial agreement, Shell will assume the operation of the blocks, and drilling activities of a delimiter well will be executed at the end of 2021. The activities to be performed, once the company gets respective approvals of the authorities, include a production test.

On February 21, 2020, the Ministry of Finance and Public Credit authorized Ecopetrol S.A. to arrange for issuance and placement of bonds in the international capital market in an amount up to two billion dollars (USD$2 billion). This authorization, along the other available funding sources of the Company, allows Ecopetrol to strengthen its liquidity position in case of unexpected fluctuations in crude prices, to finance potential growth opportunities, to optimize the current debt portfolio and/or to reduce the refinancing risk.

Public health problems, such as epidemics, pandemics, and other contagious diseases can affect the operations and financial statements of the Ecopetrol Business Group. In December 2019, a new class of coronavirus called COVID-19 appeared in China; it has spread worldwide including in Colombia and the United States, during the first quarter of 2020. The outbreaks have already been identified worldwide, and it has forced several governments, including Colombia, to decree mandatory isolation.

In addition, during the last few weeks, global and regional economic and political developments in the Organization of the Petroleum Exporting Countries (OPEC) and the willingness and ability of the OPEC and its members to set production levels have impacted the international reference prices. Extended periods of low prices for crude oil, refined products can have a material adverse impact on the Group’s results of operations. Among other things, the upstream and downstream earnings, cash flows, dividends, refining margins, operational and capital expenditures, and exploratory expenditure programs could be negatively affected, as could its production.

The fluctuations presented in the reference prices added to the COVID-19 outbreaks are leading to a decrease in economic activity, including oil, gas and refined products demand, and therefore these could affect negatively the Group's results of operations and financials. The effects and duration of this situation will depend on future developments, which are highly uncertain and cannot be predicted at this time.

F-109

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

34.

Supplemental information on oil and gas producing activities (unaudited)

The information in this note is referred to as “unaudited” as a means of clarifying that it is not covered by the audit opinion of the independent registered public accounting firm that has audited and reported on the “Consolidated Financial Statements.”

In accordance with the requirements of the United States Securities and Exchange Commission (SEC), Rule 4–10(a) of Regulation S–X, Release 33–8879, Accounting Standards Codification 932 and the ASU– 2010–03 “Oil and Gas reserve Estimation and Disclosures” rule, this section provides supplemental information on oil and gas exploration and producing activities of the Ecopetrol Business Group. The information included in sections (1) to (3) provides historical cost information pertaining to costs incurred in exploration, property acquisitions and development, capitalized costs and results of operations. The information included in sections (4) and (5) presents information on Ecopetrol’s estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proved reserves and changes in estimated discounted future net cash flows.

The following information corresponds to Ecopetrol’s oil and gas producing activities as of December 31 2019, 2018 and 2017, 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.

34.1

Capitalized costs relating to oil and gas exploration and production activities

	2019			2018			2017
Natural and environmental properties		60,261,025			53,752,436			48,129,595
Wells, equipment and facilities – property, plant and equipment		30,150,268			29,416,081			30,405,565
Exploration and production projects		8,801,630			8,463,584			6,632,812
Accumulated depreciation, depletion and amortization		(60,346,094	)		(55,689,222	)		(51,791,897	)
Net capitalized cost		38,866,829			35,942,879			33,376,075

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$2,260,113, COP$1,076,116 and COP$598,125 during 2019, 2018 and 2017, respectively.

34.2

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.

	2019		2018		2017
Acquisition of proved properties (1)		2,668,960		—		591,875
Acquisition of unproved properties (2)		261,231		81,295		164,180
Exploration costs		640,556		1,197,946		1,095,588
Development costs		8,084,283		6,346,276		3,599,385
		11,655,030		7,625,517		5,451,028

(1)

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). On December 2017, Ecopetrol América Inc. acquired an 11.6% interest in the K2 oil field in the Gulf of Mexico from MCX, increasing its share from 9.2% to 20.8%.

(2)

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. As of December 2017, the investments were mainly made by Ecopetrol América Inc. in offshore exploration projects of the Warrior and Rydberg wells.

F-110

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

34.3

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, 2019, 2018 and 2017 are as follows:

	2019			2018			2017
Net revenues
Sales		42,070,018			39,633,866			29,823,565
Transfers		11,564,358			11,794,014			7,518,216
		53,634,376			51,427,880			37,341,781
Production costs(1)		9,336,387			8,337,413			6,535,794
Depreciation, depletion and amortization(2)		6,049,543			5,591,774			6,349,382
Other production costs(3)		21,550,907			18,918,275			14,066,593
Exploration expenses(4)		763,562			1,387,463			1,342,952
Other expenses(5)		4,163,241			1,036,983			882,743
		41,863,640			35,271,908			29,177,464
Income before income tax expense		11,770,736			16,155,972			8,164,317
Income tax expense		(2,107,363	)		(6,303,251	)		(3,678,955	)
Results of operations for exploration and production activities		9,663,373			9,852,721			4,485,362

(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 2019, 2018 and 2017 of COP$198,394, COP$187,340 and COP$380,810, respectively.

(2)

In accordance with IAS 37, the expense related to asset retirement obligations that were recognized during 2019, 2018 and 2017 in depreciation, depletion and amortization, were COP$272,147, COP$180,193 and COP$179,601, respectively.

(3)

Corresponds to 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 2019, 2018 and 2017, the Ecopetrol Business Group transferred approximately 21.6%, 22.9% and 20.1%, respectively, of its crude oil and gas production; (percentages based on the value sales in Colombian pesos) to intercompany business units. Those transfers were 51.5%, 51.8% and 48.4%, respectively, of crude oil and gas production volume (including Reficar).

The intercompany transfers were realized at market prices.

34.4

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.

F-111

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following information relates to the net proven reserves owned by the Ecopetrol Business Group in 2019, 2018 and 2017, and corresponds to the official reserves statements prepared by the Ecopetrol Business Group:

	2019									2018									2017
	Oil			Gas			Total			Oil			Gas			Total			Oil			Gas			Total
	(Mbls)			(Gpc)			(Mbe)			(Mbls)			(Gpc)			(Mbe)			(Mbls)			(Gpc)			(Mbe)
Proved reserves:
Opening balance (1)		1,200			3,002			1,727			1,088			3,254			1,659			1,033			3,218			1,598
Revisions of previous estimates(2)		74			51			83			121			(4	)		121			124			294			175
Improved recovery		94			3			94			128			4			129			72			4			73
Purchases		142			126			164			—			—			—			3			2			4
Extensions and discoveries		66			2			67			54			18			57			44			—			43
Production		(193	)		(278	)		(242	)		(191	)		(270	)		(239	)		(188	)		(264	)		(234	)
Closing balance		1,383			2,906			1,893			1,200			3,002			1,727			1,088			3,254			1,659
Proved developed reserves:
Opening balance		883			2,882			1,389			818			3,158			1,372			779			3,131			1,329
Closing balance		898			2,662			1,365			883			2,882			1,389			818			3,158			1,372
Proved undeveloped reserves:
Opening balance		317			119			338			270			96			287			254			87			269
Closing balance		486			244			529			317			119			338			270			96			287

(1)

The values for 2019 were not rounded for presentation purposes.

(2)

Represents changes in previous proved reserves, upward or downward, resulting from new information (except for an increase in a proved area), usually obtained from development drilling and production history or result from changes in economic factors.

For additional information about the changes in Proved Reserves and the process for estimating reserves, see section 3.1 – Oil and Gas Reserves.

34.5

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.

	2019			2018			2017
Future cash inflows		279,722,107			275,046,421			182,114,282
Future costs
Production		(93,589,960	)		(90,176,326	)		(70,159,534	)
Development		(32,734,702	)		(21,945,453	)		(14,860,992	)
Income taxes		(37,077,231	)		(41,102,015	)		(23,660,328	)
Future net cash flow		116,320,214			121,822,627			73,433,428
10% discount factor		(36,934,889	)		(35,518,187	)		(22,216,583	)
Standardized measure of discounted net cash flows		79,385,325			86,304,440			51,216,845

F-112

Ecopetrol S.A.

Notes to the consolidated financial statements

(Figures expressed in millions of Colombian pesos, unless otherwise stated)

The following are the principal sources of change in the standardized measure of discounted net cash flows in 2019, 2018 and 2017:

	2019			2018			2017
Net change in sales and transfer prices and in production cost (lifting) related to future production		2,411,040			79,632,263			26,918,170
Changes in estimated future development costs		(12,627,361	)		(13,141,340	)		(1,978,913	)
Sales and transfer of oil and gas produced, net of production costs		(44,297,989	)		(43,090,467	)		(30,805,987	)
Net change due to extensions, discoveries and improved recovery (1)		7,061,712			8,496,249			3,226,852
Net change due to purchase and sales of minerals in place		213,539			—			211,777
Net change due to revisions in quantity estimates		6,756,418			10,163,131			9,090,882
Previously estimated development costs incurred during the period		23,200,357			12,505,421			3,482,570
Accretion of discount		11,542,289			6,771,897			4,416,512
Timing and other ⁽¹⁾		(4,993,389	)		(13,633,228	)		8,991,981
Net change in income taxes		3,814,269			(12,616,331	)		(6,462,611	)
Aggregate change in the standardized measure of discounted future net cash flows for the year		(6,919,115	)		35,087,595			17,091,233

⁽¹⁾ For comparative purposes, figures as of December 2017 were reclassified.

F-113

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		17,260,342		63,700			26,738,049		9,477,707
Cenit Transporte y Logística S.A.S.	Colombian peso		100%	Storage and transport by pipelines of hydrocarbons	Colombia	Colombia		15,289,423		4,322,501			17,470,013		2,180,590
Oleoducto Central S. A. - Ocensa	U.S. dollar		72.65%	Transportation by crude oil pipelines	Colombia	Colombia		3,718,707		2,697,990			7,172,245		3,453,538
Ecopetrol Global Energy S.L.U	U.S. dollar		100%	Investment vehicle	Spain	Spain		7,889,271		1,256,639			7,892,018		2,747
Hocol Petroleum Limited	U.S. dollar		100%	Investment vehicle	Bermuda	Bermuda		3,008,263		378,889			3,008,416		153
Ecopetrol América LLC.	U.S. dollar		100%	Exploration and exploitation of hydrocarbons	United States	United States		2,529,782		(64,032	)		3,067,856		538,074
Hocol S.A.	U.S. dollar		100%	Exploration, exploitation and production of hydrocarbons	Cayman Islands	Colombia		2,000,248		366,311			3,293,912		1,293,664
Esenttia S.A.	U.S. dollar		100%	Production and commercialization of polypropylene resin	Colombia	Colombia		1,652,851		197,639			2,100,014		447,163
Ecopetrol Capital AG	U.S. dollar		100%	Collection of surpluses from, and providing funds to, companies of the Ecopetrol Business Group.	Switzerland	Switzerland		1,630,044		124,098			6,885,838		5,255,794
Andean Chemicals Ltd.	U.S. dollar		100%	Investment vehicle	Bermuda	Bermuda		1,158,661		(190,135	)		1,159,558		897
Oleoducto Bicentenario de Colombia S.A.S.	Colombian peso		55.97%	Transportation by crude oil pipelines	Colombia	Colombia		1,569,418		575,910			3,792,998		2,223,580
Oleoducto de los Llanos Orientales S. A. - ODL	Colombian peso		65%	Transportation by crude oil pipelines	Panama	Colombia		1,079,130		485,516			1,654,772		575,642
Inversiones de Gases de Colombia S.A. Invercolsa S.A. (1)	Colombian peso		51.88%	Holding with investments in natural gas and LPG transportation and distribution companies in Colombia	Colombia	Colombia		817,849		18,198			1,361,333		543,484

F-114

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
Black Gold Re Ltd.	U.S. dollar		100%	Reinsurer for companies of the Ecopetrol Business Group	Bermuda	Bermuda		751,916			54,547			888,577		136,661
Oleoducto de Colombia S.A. – ODC	Colombian peso		73%	Transportation by crude oil pipelines	Colombia	Colombia		422,898			329,775			663,666		240,768
Bioenergy S.A.S	Colombian peso		99.61%	Production of biofuels	Colombia	Colombia		46,756			(270,376	)		219,686		172,930
Esenttia Masterbatch Ltda	Colombian peso		100%	Manufacture of polypropylene compounds and masterbatches	Colombia	Colombia		263,152			113,587			347,308		84,156
Ecopetrol Oleo é Gas do Brasil Ltda.	Brazilian real		100%	Exploration and exploitation of hydrocarbons	Brazil	Brazil		728,744			(140,819	)		757,348		28,604
Bioenergy Zona Franca S.A.S.	Colombian peso		99.61%	Production of biofuels	Colombia	Colombia		(89,565	)		(236,088	)		358,751		448,316
Ecopetrol del Perú S.A.	U.S. dollar		100%	Exploration and exploitation of hydrocarbons	Peru	Peru		50,311			(2,025	)		52,351		2,040
ECP Hidrocarburos de México S.A. de C.V.	U.S. dollar		100%	Offshore exploration	Mexico	Mexico		38,144			(73,303	)		70,854		32,710
Ecopetrol Costa Afuera S.A.S.	Colombian peso		100%	Offshore exploration	Colombia	Colombia		12,208			(3,760	)		32,130		19,922
Esenttia Resinas del Perú SAC	U.S. dollar		100%	Commercialization polypropylene resins and masterbatches	Peru	Peru		4,830			101			28,831		24,001
Ecopetrol Energía S.A.S E.S.P.	Colombian peso		100%	Energy supply service	Colombia	Colombia		7,405			3,990			106,773		99,368
Ecopetrol Germany Gmbh (2)	U.S. dollar		100%	Exploration and exploitation of hydrocarbons	Germany	Angola		2,283			(12	)		2,283		—
Ecopetrol USA Inc.	U.S. dollar		100%	Exploration and exploitation of hydrocarbons	United States	United States		7,070,295			1,483,597			7,070,295		—
Ecopetrol Permian LLC.	U.S. dollar		100%	Exploration and exploitation of hydrocarbons	United States	United States		3,043,138			(4,768	)		3,044,851		1,713
Topili Servicios Administrativos S de RL de CV	Mexican peso		100%	Specialized management services	Mexico	Mexico		46			(4	)		49		3
Kalixpan Servicios Técnicos S de RL de CV	Mexican peso		100%	Specialized services related to oil and gas industry	Mexico	Mexico		(3	)		(3	)		1		4

(1)

Values according to consolidated financial statements of the company. The result in profit (loss) corresponds to one month of operation. Assets and liabilities values as of December 2019.

(2)

Company in liquidation process.

F-115

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
Associates
Serviport S.A. (1)	Colombian peso		49%	Services for the support of loading and unloading of oil ships, supply of equipment, technical inspections and load measurements	Colombia	Colombia		22,593		1,164			59,044		36,451
Sociedad Portuaria Olefinas y Derivados S.A. (1)	Colombian peso		50%	Construction, use, maintenance and administration of port facilities, ports, private docks	Colombia	Colombia		3,816		646			6,753		2,937

Joint ventures
Equion Energía Limited	U.S. dollar		51%	Exploration, exploitation and production of hydrocarbons	United Kingdom	Colombia		2,234,067		396,380			2,625,837		391,770
Offshore International Group Inc.	U.S. dollar		50%	Exploration, exploitation and production of hydrocarbons	United States	Peru		736,847		(48,247	)		1,766,271		1,029,424
Ecodiesel Colombia S.A. (2)	Colombian peso		50%	Production, commercialization and distribution of biofuels and oleochemicals	Colombia	Colombia		92,191		17,964			147,087		54,896

(1)

Information available as of September 30, 2019. The investment is 100% impaired as of December 31, 2019.

(2)

Information available as of November 30, 2019.

F-116

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 loans

Type of credit

Company

Issue date

Expiry date

Currency

Disbursement

Outstanding
balance
Dec 31, 2019

Outstanding
balance
Dec 31, 2018

Interest
rate

Amortization
plan

Payment of
interest

dec-10

dec-20

COP

479,900

Floating

Bullet

Half-yearly

dec-10

dec-40

COP

284,300

Floating

Bullet

Half-yearly

Bonds, domestic

Ecopetrol S.A.

aug-13

aug-23

COP

168,600

Floating

Bullet

Half-yearly

Currency

aug -13

aug-28

COP

347,500

Floating

Bullet

Half-yearly

aug -13

aug-43

COP

262,950

Floating

Bullet

Half-yearly

Local currency

Oleoducto Bicentenario S.A.S

jul-12

jul-24

COP

2,100,000

1,021,890

1,191,050

Floating

Quarterly

syndicated loan

ODL Finance S.A.

aug -13

aug-20

COP

800,000

312,608

224,000

Floating

Quarterly

Commercial loan

Bioenergy

abr-11

dec-31

COP

505,723

530,733

444,157

Floating

Monthly

sep-13

sep-23

USD

1,300

Fixed

Bullet

Half-yearly

sep-13

sep-43

USD

850

Fixed

Bullet

Half-yearly

Bonds, foreign

Ecopetrol S.A.

may-14

may-45

USD

2,000

Fixed

Bullet

Half-yearly

currency

sep-14

may-25

USD

1,200

Fixed

Bullet

Half-yearly

jun-15

jun-26

USD

1,500

Fixed

Bullet

Half-yearly

jun-16

sep-23

USD

500

Fixed

Bullet

Half-yearly

Oleoducto Central S.A.

may-14

may-21

USD

500

506

500

Fixed

Bullet

Half-yearly

International

dec-17

dec-27

USD

2,001

1,530

1,742

Fixed

Half-yearly

commercial credits -

dec-17

dec-27

USD

Floating

Half-yearly

Refinería de

Ecopetrol S.A.

dec-17

dec-27

USD

Fixed

Half-yearly

Cartagena

dec-17

dec-27

USD

159

121

138

Floating

Half-yearly

dec-17

dec-25

USD

359

288

321

Floating

Half-yearly

F-117

Signature Page

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

Ecopetrol S.A.

By:	/s/ Felipe Bayón Pardo
	Name:	Felipe Bayón Pardo
	Title:	Chief Executive Officer

By:	/s/ Jaime Caballero Uribe
	Name:	Jaime Caballero Uribe
	Title:	Chief Financial Officer

Dated: March 31, 2020

175

10.

Exhibits

Exhibit No.		Description
1.1		Amended and Restated Bylaws of Ecopetrol S.A., dated March 27, 2020 (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).
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).

176

Exhibit No.		Description
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)).
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

177

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	5.1
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; 4.5.1
	C.	Organizational Structure	3.2
	D.	Property, Plants and Equipment	3.4 – 3.6; 4.6.2; 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; 5.1; 5.2
	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.	3.7; Note 16 to the consolidated financial statements
	D.	Trend Information	4.10
	E.	Off-Balance Sheet Arrangements	4.9
	F.	Tabular Disclosure of Contractual Obligations	4.8
	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	3.12
	E.	Share Ownership	7.7
Item 7.	Major Shareholders and Related Party Transactions
	A.	Major Shareholders	6.9; 7.7
	B.	Related Party Transactions	3.10; 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; 5.3; 6.2; 8
	B.	Significant Changes	7.8; Note 33 to the consolidated financial statements

178

			Sections
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	3.4.4; 4.8; Exhibits 4.1 – 4.15
	D.	Exchange Controls	5.1.4; 6.7
	E.	Taxation	4.2.1; 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; 5.1.1; 5.2.1; 5.2.3; Note 29 to the consolidated financial statements
Item 12.	Description of Securities Other than Equity Securities
	A.	Debt Securities	6.4; Exhibits 4.13-4.19
	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		5.2; 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

179

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:

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.

ii.

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.

iii.

Exploration and operation of oil areas or fields assigned to Ecopetrol by the National Hydrocarbons Agency - ANH, or the entity acting as such.

iv.

Exploration and operation of hydrocarbons abroad, directly or through agreements entered into with third parties.

Export and import of hydrocarbons, its derivatives and their byproducts.

vi.

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.

vii.

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.

viii.

Transportation and storage of hydrocarbons, their byproducts and similar, through transportation or storage systems.

ix.

Export and import of fuels and oxygenating components of vegetable origin.

Construction, operation and maintenance of ports infrastructure for the export and import of hydrocarbons, and their byproducts or oxygenating components.

xi.

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.

xii.

Design, construct, operate, and maintain port infrastructure for the export and import of hydrocarbons, its derivatives, products or oxygenates.

xiii.

Construct, operate, administer, maintain, dispose and manage all infrastructure, facilities and property that is required to achieve the Company’s corporate purpose.

xiv.

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.

xv.

Concluding all kinds of credit and financing operations with financial entities or insurers.

xvi.

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.

xvii.

Securitizing assets and investments.

xviii.

Temporarily or permanently manage the group’s 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.

xix.

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.

xx.

Training personnel in all specialties required for the proper implementation of the corporate purpose.

xxi.

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.

xxii.

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.

xxiii.

Participate in the development of social programs for the community, especially with the community that is in places where the Company has influence.

xxiv.

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.

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.

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.

ii.

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.

The shareholders of the Company, in addition to what is established by law, will enjoy the following rights and guarantees:

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.

ii.

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.

iii.

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.

iv.

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.

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.

vi.

Transfer or dispose their shares, as established by law and these Bylaws.

vii.

Provide recommendations on corporate governance to the Company, through written requests presented to the Shareholder and Investor Attention Office.

viii.

Request, with other shareholders, that a special Shareholders Assembly be held, in accordance with the provisions of Article 17 of these Bylaws.

ix.

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:

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.

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.

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.

In no case, the specialized audits may imply impairment to managers’ autonomy, in accordance with legal and bylaw powers.

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.

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.

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.

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.

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.

xi.

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.

xii.

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.

xiii.

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.

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:

General Shareholders Assembly.

ii.

Board of Directors, and

iii.

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.

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:

Appoint the person who will be the chair of the meeting.

ii.

Examine, approve or reject the end-of-year financial statements and the accounts that the Managers must submit.

iii.

Appoint and remove the members of the Board of Directors.

iv.

Appoint and remove the Statutory Auditor, and set their fees.

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.

vi.

Define how the way to cancel loses if there were any to offset losses, if any.

vii.

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.

viii.

Authorize any issuance of preferred or dividend right shares and order the reduction or elimination of preferences.

ix.

Determine the reserves that must be established, in addition to statutory reserves.

Order the repurchase of own shares and their subsequent sale.

xi.

Adopt all measures required for compliance with these Bylaws or required in the interests of the Company.

xii.

Study and approve the amendments to the Bylaws, in accordance with the rules that govern the matter.

xiii.

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.

xiv.

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, if applicable.

xv.

Approve all mergers, spin-offs or transformations.

xvi.

Approve authorized capital increases.

xvii.

Issue its own regulations.

xviii.

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 newspaper that is widely circulated nationwide.

In the ordinary meetings, the General Shareholders Assembly must deal with the following issues, in addition to those assigned by Law:

Examine the position of the Company.

ii.

Elect members of the Board of Directors and the Company’s auditor.

iii.

Determine the economic guidelines of the Company.

iv.

Analyze the accounts and financial statements for the last fiscal year.

Decide on the disposal and distribution of profits.

vi.

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 newspaper that is widely circulated 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 newspaper of wide and national circulation.

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.

ARTICLE EIGHTEEN. UNIVERSAL MEETING. - 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 appointment to the Board of Directors of the Company, may be carried out in personal capacity or as the holder of a specific public office. 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 Board of Directors will be comprised by Independent members. Independent Members of the Board will be elected in accordance with the criteria set forth in paragraph two, article 44 of Law 964 of 2005 and the procedure established in Decree 3923 of 2006, or any provision that regulates, modifies, replaces or adds to it.

Elected independent Board Members, upon their acceptance of the position will agree in writing, to retain their condition as independent throughout their tenure as Board Members. 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:

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.

ii.

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:

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.

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.

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.

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 and 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. In addition, gender, diversity and inclusion criteria will be taken into consideration when comprising the Board of Directors.

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.

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:

iii.

All members of the Board of Directors are present.

iv.

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.

ARTICLE TWENTY-THREE. DUTIES. - The Board of Directors will have the following duties:

Appoint, evaluate and remove the President of Ecopetrol, determine his/her succession plan and compensation in accordance with the responsibility of the position and market guidelines.

ii.

Issue its own regulations.

iii.

Authorize, the following decisions or activities:

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.

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.

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.

The disposal of shares, interests, contractual positions and rights in companies in which it has an interest.

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.

iv.

Approve the Company’s budget and investment plan.

Examine and approve the reports that the President must submit on the work carried out by the Company.

vi.

Approve the annual reserve report and the 20F annual report.

vii.

Establish the criteria for determining the 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.

viii.

Appoint and remove the employees who lead the first level areas of the Company.

ix.

Implement the decisions adopted by the General Shareholders Assembly related to the repurchase of shares of the Company.

Intervene in any activities for which the purpose, in its judgement, is to better pursue the Company's activities through requests for reports from Company workers.

xi.

Propose to the General Shareholders Assembly the approval of reserve funds beyond the legal reserves.

xii.

When considered necessary, examine the Company’s documents and ledgers.

xiii.

Together with the President of the Company, present for approval of the General Shareholders’ Assembly 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.

xiv.

Together with the chair, present to the General Shareholders’ Assembly 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.

xv.

Fulfill the provisions of Article 447 of the Commercial Code or any provisions that regulate or amend it, on the right of inspection.

xvi.

Serve as an advisory body for all matters that the President of the Company requires.

xvii.

Approve the Corporate Governance Code, the Code of Ethics and its amendments.

xviii.

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.

xix.

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.

xx.

Together with the President of the Company, submit a report to the General Shareholders Assembly describing the matters set forth in section xix above.

xxi.

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.

xxii.

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.

xxiii.

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.

xxiv.

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.

xxv.

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.

xxvi.

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.

xxvii.

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.

xxviii.

Appoint and remove the legal representatives of the Company and their respective alternates.

xxix.

Approve the granting of guarantees to third parties within the course of the Company's business and within the framework of its corporate purpose, in accordance with the provisions of these Bylaws.

xxx.

Ensure the effectiveness of the internal control and risk management systems.

xxxi.

The Board of Directors of the Company, in its capacity as the strategic guiding body, will have the following duties:

Approve the strategy and business plan for Ecopetrol group.

Approve the budget and investment plan for Ecopetrol group and issue the rules for their elaboration and execution.

Approve the consolidated objectives and targets Ecopetrol group.

Issue compensation guidelines for Ecopetrol and its subsidiaries companies.

Approve the consolidated financial statements.

Approve the guidelines for retaining, transferring and mitigating financial risks, including insurance for the Ecopetrol group.

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.

Approve the corporate governance model applicable to Ecopetrol group.

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. MEETINGS OF THE GENERAL SHAREHOLDERS ASSEMBLY OR THE BOARD OF DIRECTORS WITH NO PERSONAL ATTENDANCE. - In addition to the face-to-face meetings that are regulated in other sections of these Bylaws, the General Shareholders Assembly or the Board of Directors may meet remotely if all members can deliberate and decide through simultaneous or sequential communications using any technological mean with no personal attendance required when the provisions of article 19 of Law 222 of 1995 are complied with or the rules that replace or modify it.

Thus, there will be a meeting of the General Shareholders Assembly and of the Board of Directors when, by any means, all the shareholders or directors can discuss and decide through simultaneous or successive communication. In the latter case, the successive communication must occur immediately, as per the means employed.

Therefore, there will be General Shareholders Assembly or Board of Directors when through any mean all the shareholders or members can deliberate and decide through simultaneous or consecutive communication. In the latter case, the communications must be immediately received according to the method used.

ARTICLE TWENTY-SEVEN. DECISION-MAKING MECHANISM. - In accordance with the provisions of Article 20, Law 222 of 1995, or the rules that replace or amend it, the decisions of the General Shareholders Assembly or the Board of Directors shall be valid when all shareholders or directors express their voting decision in writing. In this event, the respective majority will be calculated based on the total shares in circulation or the members of the Board of Directors, as the case may be. If the shareholders or members have expressed their vote in separate documents, these must be received within a maximum period of one month, counted from the first communication received. The legal representative will inform the General Shareholders Assembly or the Board of Directors (as applicable) regarding the outcome of the decision, within five (5) business days following the receipt of the documents in which the vote is expressed.

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 within thirty (30) days following the date on which the decision was made. The Legal Representative and the Secretary of the Company, will sign the minutes. In the absence of the latter, any of the shareholders or members of the Board of Directors (as applicable) will sign the minutes for meetings in which there is no personal attendance.

With regard to meetings where there is no personal attendance, decisions will be void and null when adopted without the participation of a shareholder or member of the Board of Directors in the simultaneous or consecutive communications. Regarding decision-making through a written vote mechanism, the decisions adopted when the shareholders or members of the Board do not express the meaning of their vote or exceed the term mentioned in the previous article for the mailing of the vote by the end of one month, the decisions made will be ineffective.

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.

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:

Execute the strategy and business plan approved by the Board of Directors.

ii.

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.

iii.

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.

iv.

Implement the compensation policy, and present the Board of Directors with initiatives aimed at amending, supplementing or adjusting said policies.

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.

vi.

Execute and enforce all acts, operations, and authorizations comprised within the corporate purpose.

vii.

Together with the Board of Directors, present to the General Shareholders Assembly 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.

viii.

Together with the Board of Directors, present to the General Shareholders’ Assembly 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.

ix.

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

Submit the following documents to the Board of Directors:

The budget and investment plan for the Company and its subsidiaries companies.

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.

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.

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.

All other information requested by the Board of Directors for the fulfillment of the duties assigned to it.

xi.

Execute the budget and investment plan, consistent with the standards for its execution, as set by the Board of Directors.

xii.

Comply with and enforce the decisions of the Board of Directors.

xiii.

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.

xiv.

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.

xv.

Direct Ecopetrol's employment relations and appoint, remove and hire Company personnel in accordance with the legal, regulatory and statutory standards, and consistent with the provisions of Section 6), Article 23 of these Bylaws.

xvi.

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).

xvii.

Represent the shares, participations or interests that Ecopetrol has in companies, partnerships, foundations, or any other type of association.

xviii.

Summon the Board of Directors and the General Shareholders Assembly to ordinary and extraordinary meetings.

xix.

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.

xx.

Treat all shareholders fairly.

xxi.

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.

xxii.

Present a Corporate Governance Code and the Code of Ethics to the Board of Directors for approval.

xxiii.

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.

xxiv.

Establish and maintain the Company's Internal Control System.

xxv.

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.

xxvi.

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.

xxvii.

Execute and develop corporate governance guidelines applicable to Ecopetrol group.

xxviii.

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.

xxix.

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.

xxx.

Perform all other duties established by Law.

PARAGRAPH: The President will organize the government of the Company for which, without the authorization of another body, will be able to assign other workers 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 shall exercise the commercial and legal representation of Ecopetrol for all purposes and will have at least two (2) personal alternates. 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. If the Board of Directors fails to choose the alternates when needed, the previous ones shall remain in their position until a new appointment is effected.

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.

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.

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:

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.

ii.

Examine all transactions, inventories, minutes, books, correspondence, account vouchers and business relating to the Company.

iii.

Verify the cash count on the occasions that the Statutory Auditor deems appropriate.

iv.

Verify of all the Company's securities, as well as the others that it has in safekeeping.

Inspect the assets of the Company and ensure that measures are taken for the conservation and security thereof.

vi.

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.

vii.

Authorize the Company's financial statements by means of their signature.

viii.

Summon the General Shareholders Assembly to special meetings, in accordance with the provisions of Article 17 of these Bylaws.

ix.

Comply with the provisions of Article 447 of the Commerce Code or the legal provisions that govern or amend it.

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.

xi.

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.

xii.

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).

xiii.

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.

xiv.

Report relevant findings to the Company's bodies, to the authorities and to the market, as appropriate.

xv.

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.

xvi.

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.

xvii.

All others indicated in Article 207 of the Commerce Code or other legal provisions

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:

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.

ii.

Summon extraordinary meetings of the General Shareholders Assembly when necessary

iii.

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 two (2) periods, and it may once again be hired after one (1) period away from the 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:

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.

ii.

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.

iii.

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 ii) 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:

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.

ii.

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.

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 Foreign Corrupt Practices Act (“FCPA”), money laundering and terrorist financing. Furthermore, they manifestly reject any behavior that may constitute a breach 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:

Refrain from participating in events considered compliance risks (fraud, bribery, violations to FCPA, money laundering and terrorist financing).

ii.

Promote, maintain and strengthen the Compliance Program, the Internal Control System and an ethics and transparency culture in the Company to prevent and mitigate the materialization of compliance risks.

iii.

Have in place tools to identify the risks of the Company and that include means of control to mitigate such risks.

iv.

Reject and penalize behaviors involving the materialization of any of the risks set forth in this article.

Zero-tolerance of acts of favoritism or nepotism in selection processes.

vi.

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.

vii.

Cooperate with national and foreign authorities in carrying out any inquiry and/or investigation involving Ecopetrol Group, its employees, contractors, suppliers, partners or allies.

viii.

Have within its organizational structure, an independent unit that ensures the adoption and management of the Compliance Program, the Internal Control 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, and in the legal provisions that govern, amend or replace these, or that are applicable.

ARTICLE FORTY-EIGHT. INCOMPATIBILITIES INHABILITES

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.

ii.

No member of the Board of Directors or employee of the Company may reveal disclose to third parties (to third parties) the Company's operations, plans or initiatives, or communicate any technical procedure or the results for the explorations exploration or activities of conducted by Ecopetrol, except with such unless there is an instruction or order in this regard from a competent state authority.

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 FORTY-NINE. CONFLICTS OF INTEREST. - Among others, a conflict of interest shall be deemed to exist when:

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

ii.

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:

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.

ii.

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. 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-ONE. 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-TWO. SUPPLEMENTARY RULES. - In matters not provided for in these Bylaws, the relevant legal provisions shall apply.

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 March 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 GLOBAL ENERGY S.L.U.	Spain	100%
HOCOL PETROLEUM LIMITED	Bermuda	100%
BIOENERGY S.A.S.**	Colombia	99.60%
BIOENERGY ZONA FRANCA S.A.S.**	Colombia	99.60%
ESENTTIA MASTERBATCH LTDA**	Colombia	100%
ECOPETROL AMERICA LLC**	United States	100%
ECOPETROL PERMIAN LLC**	United States	100%
ECOPETROL USA INC**	United States	100%
ECOPETROL DEL PERU S.A.**	Peru	100%
ECOPETROL OLEO & GAS DO BRASIL LTDA**	Brazil	100%
ECP OIL AND GAS GERMANY GMBH**	Germany	100%
HOCOL S.A.**	Cayman Islands	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%
REFINERIA DE CARTAGENA S.A.S **	Colombia	100%
ESENTTIA S.A. **	Colombia	100%
ESENTTIA RESINAS DEL PERU SAC**	Peru	100%
ECP Hidrocarburos de México **	Mexico	100%
KALIXPAN SERVICIOS TÉCNICOS S. de r.l. de c.v**	Mexico	100%
TOPILI SERVICIOS ADMINISTRATIVOS** de r.l. de c.v	Mexico	100%
ECOPETROL ENERGÍA SAS ESP **	Colombia	100%
INVERSIONES GASES DE COLOMBIA S.A.	Colombia	51.87%
ECOPETROL COSTA AFUERA COLOMBIA S.A.S.**	Colombia	100%

*Direct and/or indirect participation.

**Solely indirect participation through subsidiaries or affiliates.

Exhibit 12.1

CERTIFICATION

I, Felipe Bayón Pardo, certify that:

I have reviewed this annual report on Form 20-F of Ecopetrol S.A.;

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;

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;

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

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: March 31, 2020

By:	/s/ Felipe Bayón Pardo
	Name:	Felipe Bayón Pardo
	Title:	Chief Executive Officer

Exhibit 12.2

CERTIFICATION

I, Jaime Caballero Uribe, certify that:

I have reviewed this annual report on Form 20-F of Ecopetrol S.A.;

(a)

(b)

(c)

(d)

(a)

(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: March 31, 2020

By:	/s/ Jaime Caballero Uribe
	Name:	Jaime Caballero Uribe
	Title:	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, 2019 (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: March 31, 2020
	By:	/s/ Felipe Bayón Pardo
		Name:	Felipe Bayón Pardo
		Title:	Chief Executive Officer
Dated: March 31, 2020
	By:	/s/ Jaime Caballero Uribe
		Name:	Jaime Caballero Uribe
		Title:	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 March 31, 2020, 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, 2019.

/s/ Ernst & Young Audit S.A.S.

Bogotá Colombia

March 31, 2020

Exhibit 23.2

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA STREET SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

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, 2020 (our “Report”) included in Ecopetrol S.A.’s annual report on Form 20-F for the year ended December 31, 2019 (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 S.A.’s registration statement on Form F-3 filed with the United States Securities and Exchange Commission on June 1st, 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

March 31^st, 2020

SUITE 600, 1015 4TH STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790
621 17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

Exhibit 23.3

Ref.: 4377.71001

February 25, 2020

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, 2019)” dated February 14, 2020 (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”) in the Company’s annual report Form 20-F for the year ended December 31, 2019 (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


	Cameron P. Six, P.Eng
	Chief Executive Officer

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

March 31, 2020

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, 2020, containing our opinions regarding our estimates, as of December 31, 2019, of the proved oil, condensate, natural gas liquids, gas, and oil equivalent reserves of certain selected properties that Ecopetrol S.A. has represented that it holds in Colombia and the United States as set forth under the headings “3. Business Overview–3.4 Exploration and Production–3.4.3 Reserves,” “8. Financial Statements,” and “9. 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, 2019 (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.

5555 San Felipe Street

Suite 550

Houston, TX 77056, USA

Telephone: +1 713 850 9955

www.gaffney-cline.com

March 27, 2020

Board of directors

Ecopetrol S.A.

Calle 13 No. 36 -34

Bogotá, D.C.

Colombia

CONSENT OF GAFFNEY, CLINE & ASSOCIATES

Dear Sirs,

As independent reserve engineers for Ecopetrol S.A.(Ecopetrol), Gaffney, Cline & Associates (GCA) hereby confirms that it has granted and not withdrawn its consent to (i) the references to GCA and to the inclusion of information contained in our third-party letter report entitled “ SEC Proved Reserves Statement for Forty Nine Fields in Colombia as of December 31, 2019”, dated February 24, 2020, 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, 2019 , 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, INC.

/s/ Daniel Amitrano

Project Manager

Daniel Amitrano, 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, 2019 (the "Annual Report") of our report dated March 13, 2020, with respect to estimates of net reserves to the Ecopetrol S.A. interest, as of December 31, 2019 (our "Report") and to all references to our firm included in the Annual Report, as well as to the incorporation by reference of 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

March 27, 2020

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		FAX (713) 651-0849
	1100 LOUISIANA SUITE 4600	HOUSTON, TEXAS 77002-5294	TELEPHONE (713) 651-9191

February 10, 2020

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, 2019. The subject properties are located in the country of Colombia and the United States of America. 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 15, 2020 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, 2019. Based on information provided by Ecopetrol, the third party estimate conducted by Ryder Scott addresses 77 percent of the total proved developed net liquid hydrocarbon reserves and 64 percent of the total proved undeveloped net liquid hydrocarbon reserves of Ecopetrol. The Ryder Scott evaluation also addresses 83 percent of the total proved developed net gas reserves and 38 percent of the total proved undeveloped net gas reserves of Ecopetrol.

The estimated reserve amounts presented in this report, as of December 31, 2019, 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 significantly from the prices that were used in this report. 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 800, 350 7TH AVENUE, S.W. CALGARY, ALBERTA T2P 3N9		TEL (403) 262-2799	FAX (403) 262-2790
633 17TH STREET, SUITE 1700	DENVER, COLORADO 80202	TEL (303) 339-8110

Ecopetrol

February 10, 2020

Page 2

SEC PRICES PARAMETERS

Estimated Net Reserves

Attributable to Certain Interests of

Ecopetrol

As of December 31, 2019

	Proved
	Developed						Total
Net Reserves	Producing		Non-Producing		Undeveloped		Proved
Oil/Condensate – Barrels		576,000,689		60,615,635		279,754,400		916,370,724
Plant Products – Barrels		44,330,003		0		27,855,196		72,185,199
Sales Gas – MMcf		1,661,525		249,111		85,418		1,996,054
Fuel Oil - Barrels		12,242,275		46,712		1,137,048		13,426,035
Fuel Gas - MMcf		286,884		1,381		6,925		295,190

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels. All 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 gas reserves volumes include certain gas royalty volumes 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 the proved reserves attributable to the properties evaluated herein.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Ecopetrol

February 10, 2020

Page 3

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 the country 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. However, the gross future revenue presented herein is after these royalty payments.

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

Ecopetrol

February 10, 2020

Page 4

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 98 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, 2019 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 2 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

Ecopetrol

February 10, 2020

Page 5

Approximately 98 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, 2019. 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

Ecopetrol

February 10, 2020

Page 6

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, 2019. 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

Ecopetrol

February 10, 2020

Page 7

Geographic Area	Product	Price Reference	Average Benchmark Price	Average Proved Realized Price
	Oil/Condensate	Brent	$63.03/bbl	$56.36/bbl
North and South America	NGLs	Brent	$63.03/bbl	$26.47/bbl
	Gas	Gas Sales Agreement		$4.18/Mc

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 87 percent and gas reserves account for the remaining 13 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, 2019. 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, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Ecopetrol

February 10, 2020

Page 8

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

Ecopetrol

February 10, 2020

Page 9

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.

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 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 20 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 February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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. 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.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

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

PETROLEUM RESERVES DEFINITIONS

Page 3

(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

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

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

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

Exhibit 99.2

February 25, 2020

Ecopetrol S.A.

Cra. 13 No. 36-24

Edfificio 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 10 blocks (17 fields) in Colombia, as of December 31, 2019, 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 14, 2020 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 31,2019.

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 10 blocks (17 fields) evaluated by Sproule after December 31, 2019 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 S\V. Suite 900

Calgary. AB. Canada T2P 3N3

Sproule.com

T •1403 294 5500 F •1403 295590 TF •1 877 777 6135

Sproule International Limited

-2-

February 25, 2020

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, 2019
	Proved
Net Remaininq Reserves	Developed		Undeveloped		Total Proved
Light and Medium Crude Oil (Mbbl)		10,321.9		7,611.8		17,933.7
Conventional Natural Gas (Solution Gas) (MMcf)		4,371		1,164		5,535
Gas Consumed in Operations (MMcf)		9,450		6,969		16,420

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.

Sproule International Limited

-3-

February 25, 2020

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

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	63.03 USD/bbl

Gas:
	Henry Hub	2.53 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.

Sproule International Limited

-4-

February 25, 2020

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.

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 a technical office in Mexico City, Mexico, we also have commercial representation offices in The Hague, Netherlands and 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.

Sproule International Limited

-5-

February 25, 2020

The professional qualifications of the technical person primarily responsible for reviewing and approving the reservies evaluation of the properties contained herein, are included as an attachment to this letter.

	Sincerly,

	SPROULE INTERNATIONAL LIMITED
	Alberta Permit to Practice number P06151

	/s/ Cameron P. Six, P.Eng
	Cameron P. Six, P.Eng
	Chief Executive Officer

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.

degolyer and macnaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 12, 2020

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, 2019, 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 subsidiary Ecopetrol Permian LLC (collectively, “ECOPETROL”). This evaluation was completed on February 12, 2020. ECOPETROL has represented that these properties account for 20 percent on a net equivalent barrel basis of ECOPETROL’s net proved reserves as of December 31, 2019. 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, 14 percent of its total proved developed net gas reserves, 32 percent of its total proved undeveloped net liquid reserves, and 52 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 Securities and Exchange Commission (SEC) of the United States. 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, 2019. 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.

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 of the properties was not considered necessary for the purposes of this report.

degolyer and macnaughton

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:

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)

(iii)

(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)

degolyer and macnaughton

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)

(ii)

(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.

degolyer and macnaughton

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.

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.

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, 2019, 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 September, October, or November 2019. Estimated cumulative production, as of December 31, 2019, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 3 months.

degolyer and macnaughton

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 reported herein 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, gas injection, and shrinkage resulting from field separation and before and after low-temperature separation in consideration of separate gas sales agreements that take gas before and after processing for sales. Gas reserves estimated herein 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 reserves presented in this report are expressed in millions of cubic feet (10⁶ft³).

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. This conversion factor was provided by ECOPETROL.

degolyer and macnaughton

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 estimated proved reserves for the properties in Colombia evaluated herein were U.S.$59.54 per barrel for oil and condensate and U.S.$49.66 per barrel for NGL, based on a 12-month average Brent reference price of U.S.$63.03 per barrel. ECOPETROL supplied differentials by field to the Brent reference price. The volume-weighted average adjusted product prices attributable to estimated proved reserves for the properties in the United States evaluated herein were U.S.$55.25 per barrel for oil and condensate and U.S.$17.70 per barrel for NGL, based on a 12-month average West Texas Intermediate reference price of U.S.$55.85 per barrel. These prices were held constant for the lives of the properties.

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 estimated proved reserves was U.S.$5.19 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.$2.62 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 over the lives of the properties was U.S.$1.96 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.

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 estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year.

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.

degolyer and macnaughton

Summary of Conclusions

The estimated net proved reserves, as of December 31, 2019, 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, 2019
	Oil and				Marketable		Fuel		Sales		Oil
	Condensate		NGL		Gas		Gas		Gas		Equivalent
	(10⁶bbl)		(10⁶bbl)		(10⁶ft³)		(10⁶ft³)		(10⁶ft³)		(10⁶boe)
Colombia
Proved Developed		125.643		2.324		378,161.383		43,814.064		334,347.319		194.311
Proved Undeveloped		14.156		0.000		2,220.883		1,043.337		1,177.546		14.545
Colombia Total Proved		139.799		2.324		380,382.266		44,857.401		335,524.865		208.857

United States
Proved Developed		0.569		0.116		428.144		0.000		428.144		0.761
Proved Undeveloped		112.164		28.804		125,511.706		0.000		125,511.706		162.987
United States Total Proved		112.733		28.920		125,939.850		0.000		125,939.850		163.748

Total Proved		252.532		31.244		506,322.116		44,857.401		461,464.715		372.604

Notes:

Totals may vary due to rounding.

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.

Oil reserves estimated herein for the properties in Colombia include fuel oil. The estimated fuel oil contained in the oil reserves is 2.585 10⁶bbl for proved developed reserves, 0.559 10⁶bbl for proved undeveloped reserves, and 3.144 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, 2019, estimated reserves.

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,

	/s/ DeGOLYER and MacNAUGHTON
	DeGOLYER and MacNAUGHTON
	Texas Registered Engineering Firm F-716

	/s/ Thomas C. Pence, P.E
	Thomas C. Pence, P.E.
	Senior Vice President
	DeGolyer and MacNaughton

degolyer and macnaughton

CERTIFICATE of QUALIFICATION

I, Thomas C. Pence, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A, hereby certify:

That I am a Senior Vice President of DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to ECOPETROL dated February 12, 2020, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in 1982; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and that I have in excess of 37 years of experience in oil and gas reservoir studies and reserves evaluations.

	/s/ Thomas C. Pence, P.E
	Thomas C. Pence, P.E.
	Senior Vice President
	DeGolyer and MacNaughton

Exhibit 99.4



	Gaffney, Cline & Associates, Inc. 5555 San Felipe Street, Suite 550 Houston, TX 77056, USA Telephone: +1 713 850 9955 www.gaffney-cline.com

	February 24, 2020

Fidel Delgado Doria

Gerente de Reservas

Ecopetrol S.A.

Calle 13 No. 36 -34

Bogotá, D.C.

Colombia

fidel.delgado@ecopetrol.com.co

Dear Fidel,

SEC Proved Reserves Statement

for Forty Nine Fields in Colombia

as of December 31, 2019

This Proved Reserves statement has been prepared by Gaffney, Cline & Associates (GCA) and issued on February 24, 2020 at the request of Ecopetrol S.A. (Ecopetrol, or “the Client”), 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, 2019 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.

GCA has prepared a reserves certification (study), as of December 31, 2019, of the hydrocarbon liquids and natural gas reserves of the fields indicated in Table 1.

Table 1: Assets and Fields Reviewed by GCA

AREA	FIELD	BASIN	AREA	FIELD	BASIN
ARAUCA	ARAUCA	Llanos	LISAMA	NUTRIA	Middle Magdalena Valley
ARRAYAN	ARRAYAN	Upper MagdalenaValley		TESORO	Middle Magdalena Valley
BALCON	BALCON	Upper Magdalena Valley	NEIVA CPI	DINA TERCIARIO	Upper Magdalena Valley
CAGUAN	RIO CEIBAS	Upper Magdalena Valley	ORIPAYA	ORIPAYA	Catatumbo
	ESPINO	Upper Magdalena Valley	PROVINCIA	PROVINCIA	Middle Magdalena Valley
CAPACHOS SUR	CAPACHOS	Llanos		BONANZA	Middle Magdalena Valley
	ANDINA	Llanos		AULLADOR	Middle Magdalena Valley
CARACARA	CARACARA SUR A	Llanos	SAN FRANCISCO	SAN FRANCISCO	Upper Magdalena Valley
	CARACARA SUR B-C	Llanos	SAN ROQUE	SAN ROQUE	Middle Magdalena Valley
	UNUMA	Llanos	SANTA CLARA	SANTA CLARA	Upper Magdalena Valley
DINA CRETACEO	DINA CRETACEO	Upper Magdalena Valley		PALERMO	Upper Magdalena Valley
	PALOGRANDE	Upper Magdalena Valley	TELLO	TELLO	Upper Magdalena Valley
	CEBU	Upper Magdalena Valley		LA JAGUA	Upper Magdalena Valley
DINA NORTE	DINA TERCIARIO ECP	Upper Magdalena Valley	TEMPRANILLO	TEMPRANILLO	Upper Magdalena Valley
HOBO	YAGUARA	Upper Magdalena Valley		TEMPRANILLO NORTE	Upper Magdalena Valley
JAGUAR	PEGUITA	Llanos	TIBU	TIBU	Catatumbo
	PEGUITA II	Llanos	TISQUIRAMA	TISQUIRAMA	Middle Magdalena Valley
	PEGUITA III	Llanos	TISQUIRAMA ASOCIACION	LOS ANGELES	Middle Magdalena Valley
	PEGUITA SOUTH WEST	Llanos		QUERUBIN	Middle Magdalena Valley
	ELIZITA	Llanos	TORO SENTADO	TORO SENTADO	Llanos
LAS MONAS	PAYOA	Middle Magdalena Valley		TORO SENTADO WEST	Llanos
	LA SALINA	Middle Magdalena Valley		RANCHO QUEMADO	Llanos
	CORAZON	Middle Magdalena Valley	VIGIA	VIGIA	Llanos
	CORAZON WEST	Middle Magdalena Valley		VIGIA SUR	Llanos
LISAMA	LISAMA	Middle Magdalena Valley

Ecopetrol S.A.	2
February 24, 2020

On the basis of technical and other information made available to GCA concerning these property units, GCA hereby provides the reserves statement in Table 2.

Table 2: Statement of Hydrocarbon Reserves Volumes

Forty-Nine Fields, Colombia

as of December 31, 2019

	Reserves Net to Ecopetrol’s Interest
Reserves	Oil/Cond.	NGL's	Gas	Fuel gas
	(MBbl)	(M Bbl)	(BCF)	(BCF)
Developed
Producing	51,846	2,160	39.861	21.138
Non-Producing	4,171	21	0.760	0.642
Undeveloped	13,937	378	13.661	2.204
Total Proved	69,954	2,558	54.282	23.984
Probable	17,815	954	28.475	5.910
Possible	7,873	297	8.074	1.782

Notes:

Oil, condensate and NGL 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.

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 ANH and the corresponding clarification note from ANH# 20146240188522.

Net sales gas reserves exclude volumes consumed in operations (fuel gas), which are reported separately.

Fuel gas represent working interest volumes consumed in operations.

The above Reserves include production:

Until the economic limit when contracts are solely operated by Ecopetrol.

Beyond the end of the current license period in concession contracts that include an expiry date, it was assumed that the fields would 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.

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 of stock tank barrels. The volumes reported as gas represent expected gas sales and are reported in billions of standard cubic feet at standard conditions of 14.7 psia and 60 degrees Fahrenheit.

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 S.A.	3
February 24, 2020

Ecopetrol has advised GCA that these Proved volumes represent 5% of Ecopetrol’s total Proved reserves on an oil-equivalent basis. GCA 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 separate technical reports.

Reserves Assessment

This certification examination was based on reserves estimates and other information provided by Ecopetrol to GCA through December 2019, and included such tests, procedures and adjustments as were considered necessary. Field data and information provided by Ecopetrol varies from field to field. Ecopetrol provided production data sets through September 2019. 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.

Recoverable volume estimates as derived from profiles of expected future performance were checked for consistency with the development plans provided by Ecopetrol. These were further verified on the basis of individual well decline analysis, typical well performance models, material balance calculations, reservoir simulation results, analogies, etc. as appropriate to the available information and category of the reserves. 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, 2019 reserves volumes were based on a prior twelve-month first-day-of-the-month average reference price for Brent crude of US$ 63.03/Bbl, corrected for location and quality to a weighted average price of US$ 61.38/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$ 17.61/Bbl. The weighted average sale gas price used to derive proved reserves is US$ 5.28/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. GCA has found that sufficient capital investments and operating expenses have been projected to produce the estimated volumes.

It is GCA’s opinion that the estimates of total remaining recoverable hydrocarbon liquids and gas volumes at December 31, 2019 are, in the aggregate, reasonable and the reserves classification and categorization is appropriate and consistent with the SEC definitions and guidelines for reserves.

Ecopetrol S.A.	4
February 24, 2020

GCA concludes that the methodologies employed by Ecopetrol in the derivation of the volume estimates are appropriate and that the quality of the data relied upon, the depth and thoroughness of the estimation process are adequate. GCA 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.

Basis of Opinion

This document reflects GCA’s informed professional judgment based on accepted standards of professional investigation and, as applicable, the data and information provided by the Client, 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. GCA has not independently verified any information provided by or at the direction of the Client and has accepted the accuracy and completeness of these data. GCA has no reason to believe that any material facts have been withheld from it, 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 GCA has used Part 210 Rule 4-10(a) of Regulation S-X of the United States Securities and Exchange Commission (see Appendix III).

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, reserves 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.

GCA’s review and certification involved reviewing pertinent facts, interpretations and assumptions made by Ecopetrol or others in preparing estimates of reserves. GCA 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 and resources estimation process, classification and categorization of reserves and resources appropriate to the relevant definitions used, and reasonableness of the estimates.

Ecopetrol S.A.	5
February 24, 2020

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. The proved 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).

GCA has not undertaken a site visit and inspection because it was not included in the scope of work. As such, GCA 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, GCA is not in a position to comment on any aspect of health, safety, or environment of such operation.

This report has been prepared based on GCA’s understanding of the effects of petroleum legislation and other regulations that currently apply to these properties. However, GCA 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).

Qualifications

In performing this study, GCA is not aware that any conflict of interest has existed. As an independent consultancy, GCA is providing impartial technical, commercial, and strategic advice within the energy sector. GCA’s remuneration was not in any way contingent on the contents of this report.

In the preparation of this document, GCA has maintained, and continues to maintain, a strict independent consultant-client relationship with Ecopetrol. Furthermore, the management and employees of GCA 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 certification are provided in Appendix I.

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.

Ecopetrol S.A.	6
February 24, 2020

Notice

This report was prepared for public disclosure in its entirety by Ecopetrol S.A. in conjunction with its reporting obligations to the SEC. Ecopetrol S.A. will obtain GCA's prior written approval for any other use of any results, statements or opinions expressed to Ecopetrol S.A. in this report that are attributed to GCA.

Yours sincerely,

Gaffney, Cline & Associates

Project Manager

Daniel Amitrano, Principal Advisor

Reviewer

Rawdon J.H. Seager, Technical Director

Appendices

Appendix I

Technical Qualifications of Person Primarily Responsible for Certification

Appendix II

SEC Reserves Definitions

Ecopetrol S.A.	7
February 24, 2020

Appendix I

Technical Qualifications of Person

Primarily Responsible for Certification

Ecopetrol S.A.	8
February 24, 2020

Technical Qualifications of Person

Primarily Responsible for the Reserves Certification

The reserve estimate of certain of Ecopetrol’s interests prepared by Gaffney, Cline & Associates (GCA), the results of which are presented in this report, was carried out by engineers and geoscientists under the direction of Mr. Daniel Amitrano, primarily responsible for the preparation of this certification.

Mr. Amitrano has over 29 years of experience of diversified international industry experience mainly in reservoir engineering, geology, reserves estimation, project development and implementation including classification and reporting of reserves and resources. He is a member of the Society of Petroleum Engineers (SPE) and holds a BS degree in Civil Engineering and a Master’s degree in Field Exploitation from Buenos Aires University, Argentina.

Ecopetrol S.A.	9
February 24, 2020

Appendix II

SEC Reserves Definitions

Ecopetrol S.A.	10
February 24, 2020

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.

(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

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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February 24, 2020

(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.

(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.

Ecopetrol S.A.	12
February 24, 2020

(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

(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.

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February 24, 2020

If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

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

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.

Ecopetrol S.A.	14
February 24, 2020

(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.

(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.

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February 24, 2020

(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.

(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)

(ii)

(iii)

(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:

Ecopetrol S.A.	16
February 24, 2020

(A)

(B)

The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)

(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).

(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.

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February 24, 2020

(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)

(ii)

(iii)

(32)

Unproved properties. Properties with no proved reserves.

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February 24, 2020

Exhibit 99.5

March 13, 2020

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, 2019, 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 Ecopetrol owns a 50 percent interest in Savia and that the proved reserves estimated in this report constitute approximately 0.3 percent of all proved reserves owned by Ecopetrol. We completed our evaluation on January 29, 2020. 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.

We estimate the net reserves to the Ecopetrol interest in these properties, as of December 31, 2019, to be:

	Net Reserves
Category	Oil (MBBL)		NGL (MBBL)		Gas (MMCF)
Proved Developed Producing		3,478.2		481.1		6,953.9
Proved Developed Non-Producing		312.9		68.7		0.0

Total Proved Developed		3,791.2		549.8		6,953.9

Totals may not add because of rounding.

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) or millions of barrels (MMBBL); 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, 2019, 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-dayof- the-month price for each month in the period January through December 2019. The average Brent Crude price of US$63.03 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$62.70 per barrel of oil, US$48.20 per barrel of NGL, and US$1.960 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 workovers; well services; 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.

	Sincerely,

	NETHERLAND, SEWELL & ASSOCIATES, INC.
	Texas Registered Engineering Firm F-2699

	By:	/s/ C.H. (Scott) Rees III, P.E.
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer

	By:	/s/ Andres F. Castaño, P.E.
		Andres F. Castaño, P.E. 121698
		Vice President

	Date Signed: March 13, 2020

AFC:JCW

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 - Page 1 of 6

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 exploratorytype 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 - Page 2 of 6

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D)

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)

Definitions - Page 3 of 6

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)

(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)

Definitions - Page 4 of 6

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)

(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 - Page 5 of 6

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)

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 6 of 6

	PPE and Natural resources			Provisions			Employee benefits			Loss carry forwards			Accounts payable
As of December 31, 2017		(1,006,299	)		1,840,988			1,373,561			611,766			208,618
Profit or loss		(1,297,841	)		153,774			(178,160	)		390,296			984,480
OCI		—			—			(33,541	)		—			—
As of December 31, 2018		(2,304,140	)		1,994,762			1,161,860			1,002,062			1,193,098
Profit or loss		(736,296	)		409,270			(57,343	)		1,847,025			438,608
OCI		—			—			771,355			—			—
As of December 31, 2019		(3,040,436	)		2,404,032			1,875,872			2,849,087			1,631,706

		Accounts receivable			Goodwill			Right-of-use assets			Others			Total
As of December 31, 2017		94,864			(408,932	)		—			(31,685	)		2,682,881
Profit or loss		(15,273	)		4,538			—			(884,261	)		(842,447	)
OCI		—			—			—			734,591			701,050
As of December 31. 2018		79,591			(404,394	)		—			(181,355	)		2,541,484
Profit or loss		59,819			40,426			(33,592	)		441,162			2,409,079
OCI		—			—			—			(143,397	)		627,958
Increase in Invercolsa shareholding		—			—			—			(98,005	)		(98,005	)
As of December 31, 2019		139,410			(363,968	)		(33,592	)		18,405			5,480,516