As filed with the Securities and Exchange Commission on March 31, 2020April 8, 2021
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20192020
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 | ||
American Depository Shares (as evidenced by American Depository Receipts), each representing 20 common shares par value COP$609 per share | EC | New York Stock Exchange | ||
Ecopetrol common shares par value COP$609 per share | New York Stock Exchange (for listing purposes only) | |||
5.875% Notes due 2023 | EC23 | New York Stock Exchange | ||
4.125% Notes due 2025 | EC25 | New York Stock Exchange | ||
6.875% Notes due 2030 | EC30 | New York Stock Exchange | ||
5.375% Notes due 2026 | EC26 | New York Stock Exchange | ||
7.375% Notes due 2043 | EC43 | New York Stock Exchange | ||
5.875% Notes due 2045 | EC45 | New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
41,116,694,690 Ecopetrol common shares, par value COP$609 per share
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
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 | Accelerated filer | Non-accelerated filer | Emerging growth company |
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.¨ ☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
☒ Yes ☐ No
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
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 20192020
Table of Contents
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1. | Introduction |
1.1 | About This Annual Report |
We file our Annual Report on Form 20-F and other information with the U.S. Securities and Exchange Commission.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”, “we”, “us”, “our”, “Ecopetrol Group,”Group”, or the “Company” are used in this annual report to refer to Ecopetrol S.A. and its subsidiaries on a consolidated basis.
For purposes of the sectionBusiness 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(or the GovernmentGovernment) 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,”“anticipate”, “believe”, “could”, “estimate”, “expect”, “should”, “plan”, “potential”, “predicts”, “prognosticate”, “project”, “target”, “achieve” and “intend,”“intend”, among other similar expressions, are understood as forward-looking statements. We have made forward-looking statements that address, among other things:
Our forward-looking statements and sensitivity analysis are not guarantees of future performance and are subject to assumptions that may prove incorrect and to risks and uncertainties that are difficult to predict. Actual results could differ materially from those expressed or forecasted in any forward-looking statements as a result of a variety of factors. These factors may include, but are not limited to, the following:
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other factors discussed in sectionRisk 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 | 2020 | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||
Oil and gas production (mboed) | 725.1 | 720.4 | 715.1 | 717.9 | 760.7 | 697.0 | 725.1 | 720.4 | 715.1 | 717.9 | ||||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||||||||
Proved oil and gas reserves (mmboe)(1) | 1,770 | 1,893 | 1,727 | 1,659 | 1,598 | |||||||||||||||||||||||||||||||||||
Exploratory wells(2) | 18 | 20 | 17 | 20 | 6 | |||||||||||||||||||||||||||||||||||
Refinery throughput (bpd)(3) | 322,038 | 375,754 | 375,444 | 347,483 | 332,751 | |||||||||||||||||||||||||||||||||||
1P Reserves replacement ratio | 169 | % | 129 | % | 126 | % | (7 | )% | 6 | % | 48 | % | 169 | % | 129 | % | 126 | % | (7 | )% |
(1) | Proved oil and gas reserves include natural gas royalties and exclude crude oil royalties. |
(2) | Gross exploratory wells. |
(3) | Refinery throughput includes the Barrancabermeja, |
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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 and dividends declared per share, which are expressed in Colombian Pesos)Pesos, and common shares and weighted average shares outstanding, which are expressed as number)
Table 2 – Selected Financial Data
Financial Information | 2019 | 2018 | 2017 | 2016 | 2015 | 2020 | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||
Revenue | 71,488,512 | 68,603,872 | 55,954,228 | 48,485,561 | 52,347,271 | 50,223,393 | 71,488,512 | 68,603,872 | 55,954,228 | 48,485,561 | ||||||||||||||||||||||||||||||
Operating income | 21,027,158 | 22,458,414 | 16,171,855 | 8,904,548 | 2,131,165 | 7,181,765 | 21,027,158 | 22,458,414 | 16,171,855 | 8,904,548 | ||||||||||||||||||||||||||||||
Net income (loss) attributable to Ecopetrol’s shareholders | 13,744,011 | 11,381,386 | 7,178,539 | 2,447,881 | (7,193,859 | ) | 1,586,677 | 13,744,011 | 11,381,386 | 7,178,539 | 2,447,881 | |||||||||||||||||||||||||||||
Net operating income per share | 511 | 546 | 393 | 217 | 51.8 | 175 | 511 | 546 | 393 | 217 | ||||||||||||||||||||||||||||||
Weighted average number of shares outstanding | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 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 | ) | ||||||||||||||||||||||||||||||||||
Net income per share (basic and diluted) | 39 | 334 | 277 | 175 | 59.5 | |||||||||||||||||||||||||||||||||||
Total assets | 133,890,296 | 124,643,498 | 117,847,412 | 118,958,977 | 123,588,190 | 137,694,169 | 133,890,296 | 124,643,498 | 117,847,412 | 118,958,977 | ||||||||||||||||||||||||||||||
Total equity | 58,231,628 | 57,107,780 | 48,215,699 | 43,560,501 | 43,100,963 | 53,499,363 | 58,231,628 | 57,107,780 | 48,215,699 | 43,560,501 | ||||||||||||||||||||||||||||||
Subscribed and paid-in capital | 25,040,067 | 25,040,067 | 25,040,067 | 25,040,067 | 25,040,068 | 25,040,067 | 25,040,067 | 25,040,067 | 25,040,067 | 25,040,067 | ||||||||||||||||||||||||||||||
Number of common shares | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 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 | - | 17 | 180 | 314 | 89 | 23 | ||||||||||||||||||||||||||||||
Total liabilities | 75,658,668 | 67,535,718 | 69,631,713 | 75,398,476 | 80,487,227 | 84,194,806 | 75,658,668 | 67,535,718 | 69,631,713 | 75,398,476 |
Our consolidated financial statements for the years ended December 31, 2015, 2016, 2017, 2018, 2019 and 20192020 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 sectionFinancial Review—Summary of Differences between Internal Reporting Policies and IFRS.
Our consolidated financial statements were consolidated line by line and all transactions and balances between subsidiaries have been eliminated. These financial statements include the financial results of all subsidiary companies controlled, directly or indirectly, by Ecopetrol S.A. See Exhibit 1 –Consolidated companies, associates and joint ventures, to our consolidated financial statements included in this annual report.
As indicated in IFRS 10 “Consolidated Financial Statements,” we must present our financial information on a consolidated basis as if we were a single entity, combining the financial statements of Ecopetrol S.A. and its subsidiaries line by line, adding assets, liabilities, shareholder’s equity, revenues and expenses of similar nature, removing the reciprocal items among companies that are members of the Ecopetrol Group (Ecopetrol Group or EG) and recognizing non-controlling interest. We present our operating information on a consolidated basis in accordance with IFRS.
In this annual report, references to “US$” or “U.S. dollars” are to United States dollars and references to “COP$” “Colombian Peso” or “Colombian Pesos” are to Colombian Pesos, the Ecopetrol Group’s functional and presentation currency under which we prepare our consolidated financial statements. This annual report translates certain Colombian Peso amounts into U.S. dollars at specified rates solely for the convenience of the reader. Unless otherwise indicated, such Colombian Peso amounts have been translated at the rate of COP$3,2823,691.27 per US$1.00, which corresponds to the average Tasa Representativa Promedio del Mercado (TRM), or Average Representative Market Exchange Rate, for 2019.2020. Such conversion should not be construed as a representation that the Colombian Peso amounts correspond to, or have been or could be converted into, U.S. dollars at that rate or any other rate. On March27, 2020,April 5, 2021, the Representative Market Exchange Rate was COP$3,9963,679 per US$1.00.
Certain figures shown in this annual report have been subject to rounding adjustments, and, accordingly, certain totals may therefore not precisely equal the sum of the numbers presented. In this annual report a billion is equal to one with nine zeros.
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2. | Strategy and Market Overview |
The US-China trade war escalated in 2019Containment measures and increased average tariffs between the two nations (U.S. tariffs to China rose from 12.0% to 21.0%, and Chinese tariffseconomic disruptions related to the U.S. from 16.5%COVID-19 outbreak led 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 production and mobility worldwide, producing a significant drop in global demand for oil in 2020. Demand contracted for most refined products (especially jet fuel and gasoline), which brought the growthBrent price to US$20/Bl by the end of their economies. InApril 2020. Although demand recovered throughout the second half of the year, it did not reach pre-COVID-19 pandemic levels. The U.S. Energy Information Administration (EIA) estimates that demand contracted by 9.0 mmbd as compared to 2019, these factors led to a 0.75 million barrels of oil equivalent per day (mmboepd) growththe largest annual decline registered in oil demand, the lowest growth rateEIA data since 2012 when demand increased by 0.60 mmboepd.1980.
World oilOil supply remained stableslowly reacted to low prices. Moreover, a price war between Saudi Arabia and Russia in 2019. WhileMarch and April further delayed the supply of those outsideresponse. However, the Organization of the Petroleum Exporting Countries (OPEC) increasedand its allies (including Russia) agreed to a supply cut at the end of April 2020. This, in conjunction with the drop in United States production, was key in balancing the oil market. In total, supply was reduced by 1.94 mmboepd6.4 mmbd in 2019, mainly due to higher production2020, of which OPEC’s share was 4.1 mmbd, the US’s share was 0.9 mmbd and the remaining 1.4 mmbd was contributed by others.
The drop in demand resulted in an increase in inventory and a decline in price during the U.S. (1.62 mmboepd) and Brazil (0.23 mmboepd),first half of 2020. During much of the supply from OPEC countries fell by 2.10 mmboepd. In addition to production declines in Saudi Arabia,second half of the decrease in total OPEC output was largely driven by falling production in Venezuela and Iran due, in part, to U.S. sanctions. Crudeyear, reduced oil production in Venezuela averaged 0.82 mmboepd in 2019,from the 14 OPEC member countries and ten of the world’s major non-OPEC oil-exporting nations, including Russia (OPEC+) and the United States, along with a 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 globalrising oil consumption, grew at the smallest rate since 2009. However, market pessimism increased in 2019 largely duecaused inventory to trade war fears andfall, driving Brent prices to a global slowdown, pushing down the price of oil. Brent averaged US$64/Bl in 2019, down from a 2018monthly average of US$72/Bl. 50/Bl in December 2020.
Graph 1 – Supply/Demand Balance vs ICE Brent Price Evolution
Source:EIA: Short term Energy OutlookTerm Report (January 2021)
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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 couldwill continue to influenceaffect 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.consumption in Colombia. According to the National Administrative Department of Statistics (DANE for its Spanish acronym)acronym in Spanish), during 2019in 2020 Colombia’s GDP grew by3.3%fell 6.8% in real terms, as compared to 2018.2019. The sectors withmain reason for this contraction was derived from the greatest growth rates were retail,COVID-19 pandemic and from the measures taken by the Colombian government to stop the spread of the virus, which included, among other measures, mandatory lockdowns and work slowdowns in certain industries. These measures particularly affected the construction, transportation, and mining industries, whereas the agriculture, financial services and public administration, which had the largest contributionreal estate industries were still able to national GDP. On the other hand, construction had the worst performance.
post positive growth rates along 2020. LocalWithin this context, local sales of liquid fuels(LPG, decreased by 19.9% during 2020, primarily due to lower diesel jet and gasoline)increased by 4% in 2019, boosted by increased demand for gasoline and diesel.demand.
Natural gas demand in Colombia decreased by1.7% 1.4% in 2019 as2020 compared to 2018with 2019, due to lower demand from the industrial sector and refineries. In 2020, the natural gas fired power plants.market was challenged from the supply side itself, primarily due to the decrease in demand needs due to the COVID-19 pandemic, the latter generated several blockades and quarantines in different countries leading to a decrease in natural gas requirements for electricity generation as in the industrial sector. Additionally, it faced the harshness of the hurricane season in the Gulf of Mexico, which also forced the suspension of the mobilization of LNG ships, causing some terminals to suspend their operations. During the months of May to July, natural gas prices for Hubs such as TTF and JKF reached similar ranges to the ones of Henry Hub, placing them in ranges between US$1.43 – US$ 2.38 million British thermal unit (MMbtu). However, these same markers showed a significant recovery by the end of 2020, primarily due to the commencement of the winter season, leading to the production of natural gas from the Gulf of Mexico turning to serve the Asian market.
2.1 | Our Corporate Strategy |
2.1.1 | 2021 – 2023 Business Plan |
The Ecopetrol Group’s 2020 - 2022Organic Business Plan (the Plan)“Business Plan”) for the 2021-2023 period, is alignedaimed at restoring the Ecopetrol Group’s growth trajectory post COVID-19, increasing competitiveness, laying the foundations of energy transition and going deeper into the Technology, Environment, Social and Governance (TESG) agenda through positive social and environmental impact in the territories where we operate. The Business Plan also seeks to maintain the effective response of the Ecopetrol Group to uncertain economic and environmental conditions, ensure the financial sustainability of the Ecopetrol Group and keep the value promise to stakeholders in the medium and long terms. The organic investment included in the Business Plan is expected to be financed mainly with internal cash generation. The Brent price assumptions under the strategic prioritiesBusiness Plan are as follows: US$ 45/Bl in 2021, US$ 50/Bl in 2022 and US$ 54/Bl in 2023.
The Business Plan features an organic investment between US$ 12 billion and US$ 15 billion for the three-year period, mainly focused in Colombia, and seeks to ensure capital allocation towards incorporation of achieving profitablemore competitive reserves and resources within a new scenario of oil and gas prices, competitive positioning in the energy transition (such as gas, decarbonization, short-cycle hydrocarbons and the incorporation of renewable energies), reliability investments necessary for a responsible and sustainable growth, using strict capital disciplineoperation, and cash flow protection, taking into consideration the challenges posed by energy transition, climate change, respectstrategic technologies and social investment for the environment and biodiversity,future of the protection and responsible use of water, and the inclusion of an innovation and technology component, leveraging the integrated value generation for theEcopetrol Group.
The Plan includes76% of the investments between US$13 and US$17 billion, most of which willare expected to be invested in Colombia,allocated towards growth opportunities aimed at continuing reservesthe exploration 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 addressingaccelerating adaptation to the energy transition, with investments focused on the continuation of the enhanced recovery programs and the growth of the gas value chain. The remaining 24% of investments are expected to gas. Investments inbe allocated to operational continuity, (26%) are aimed at preservingseeking to preserve the value of the assets and providingbring reliability and integrity to the operation, and the remaining (16%) of investments will boost innovation and technology and decarbonization goals.Ecopetrol Group’s consolidated operations.
Some of theThe most relevant operational goals of the Business Plan are expected to: (i)the following: (i) to reach organic production levels of between 745 - 800700 and 710 thousand barrels of oil equivalent per day in 2021, with a growth trajectory that allows the Ecopetrol Group to reach production levels of approximately 750 thousand barrels of oil equivalent per day by 2023; (ii) maintainto reach a joint throughput at the replacement rateBarrancabermeja and Cartagena refineries of organic reserves above 100%, without price effect, (iii) realizebetween 340 and 365 thousand barrels per day in 2021, with a growth path that allows reaching a joint throughput between 370 -at such refineries of approximately 420 thousand barrels per day forby 2023 in an expected scenario of recovery in demand and refining margins, as well as the integrated refining system, (iv) achieve between 1.10 - 1.25interconnection of the crude plants at the Cartagena refinery; and (iii) to reach transported volumes of over one million barrels per day of volumes transported,– in line with the expected country’sevolution of the 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.the country.
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Upstream
Upstream
The Plan allocates 83%In terms of total investments to the upstream segment, prioritizing the developmentBusiness Plan allocates an investment range of between US$ 9 billion and US$ 11 billion. The Business Plan maintains the Group’s positiongrowth of this segment as a strategic objective, with a focus on accelerating the progression of resources and reserves, through exploration, drilling and enhanced recovery.
Of the aforementioned resources, (i) 69% is expected to be be allocated in strategic assets such asproduction activities, including the Rubiales, Castilla, 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 maturationfields, with a continued focus on maturity and development of improved recovery activities, will continue. The Plan allocates 72% of upstream investments on projects in Colombia while(ii) 22% is expected to be allocated internationally, where the remaindermain focus areas will be investedBrazil and the Permian Basin in further developing the Group's international operations.
In termsUnited States and (iii) 9% of the resources are expected to be allocated in exploration the Plan provides foractivities, with an expected drilling of more than 30 exploratory40 wells located in the most relevant basins focused mostly in Colombiaof greater materiality, with emphasis on the Llanos Orientales, Middle Magdalena Valley, Lower Magdalena Valley 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$200 million.Sinú-San Jacinto areas.
In relation toterms of unconventional reservoirs, the maturation ofEcopetrol Group will continue the development process for the initiatives associated withto the Comprehensive Research Pilot Project (Proyectos Piloto de Investigación Integral or Projects (PPII as perfor its Spanish acronym)acronym) in the Middle Magdalena Valley Basin will continue,valley basin in Colombia, and well as increasing development activities in the Permian Basin in Texas increase.Texas.
DownstreamRegarding the growth of the natural gas chain (one of the Ecopetrol Group’s strategic pillars), between 9% and 10% of the investment called for by the Business Plan is expected to be allocated towards the development of Piedemonte and other sources of gas in the Middle Magdalena Valley, Guajira and the Sinú-San Jacinto basin areas in Colombia. Additionally, the Business Plan calls for investments for the evaluation and development of the largest offshore gas discoveries in the Colombian Caribbean.
The Business Plan foresees the achievement of reserves replacement ratio greater than 100% after 2022. However, such goal is subject to revision based on the evolution of both the Business Plan and market conditions.
TheMidstream
In terms of the midstream segment, the Business Plan allocates 11%an investment of between US$ 780 million and US$ 960 million, mainly aimed at strengthening the integrity and reliability of the infrastructure, prioritizing resources for the growth of the multi-pipeline business, while advancing in increasing flexibility and efficiency in logistics for the evacuation of heavy crude and the growth of the pipeline infrastructure. These investments are also expected to enable future operating costs optimization by upgrading equipment and improving its performance.
Downstream
In terms of the downstream segment, focusingthe Business Plan allocates an investment between US$ 1.2 billion and US$ 1.4 billion focused on ensuring (i) the useintegrity and optimizationcompetitiveness of existing assets, and (ii) compliance with the fuel quality path. Regulatory compliance investments and major maintenance investment are expected to be made a part of the current infrastructure. To this end, we plan to conduct major maintenance and technological updates atcompliance with the life cycle of the plants in the Cartagena and Barrancabermeja refineries as well as implementrefineries. The expected investments also call for the CartagenaRefinery’s Original Crude Unitexecution of the final phase of the interconnection project. We also plan to expandproject of the Esenttia plant by 70 thousand tonscrude plants of polypropylene per year. A gross refining marginthe Cartagena refinery in an aggregate amount of betweenapproximately US$10 - US$15 per barrel 77 million, which is expected with periods of significant volatility.to commence operations in 2022.
In an effortorder to move forwardadvance with the production of cleaner fuels for the country, investments in the investments made during the 2020 - 20222021-2023 period will consolidate theare expected to make possible to guarantee sustained internal quality of domestic diesel toof between 10 toand 15 ppm of sulphursulfur, and reduce the sulphur into bring 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 asTransmilenio in Bogotá.of sulfur across Colombia.
MidstreamCommercial Strategy
The Business Plan includes allocating 5%maintains the Ecopetrol Group’s strategy of investments to this segment, focuseddiversifying clients and destinations, with an important emphasis on improving efficiency and synergiesthe independent refining sector in China, while maintaining an active participation in the transportation system as well as capturing investment opportunities in multi-purpose pipelines associated withrefining market of the increase in domestic fuel demand. To this end, we foresee investments totaling US$300 million. This segmentUnited States. The foregoing is expected to continue to be an important cash generator.leveraged on our operational flexibility at ports, a stable quality of our crude oil and optimization of logistics.
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Technology and InnovationTESG
In terms of technology, our efforts will focus on realizingTESG, the feasibility of enhanced oil recovery and unconventional hydrocarbons projects in an effective, environmentally and socially sustainable manner, increasing flexibility and logistical efficiencyBusiness Plan allocates approximately COP$ 1.7 trillion for the transportation of heavy crudes2020-2024 period for social and increasing energy efficiency, among others. Additionally, we plan to completeenvironmental investment, aimed at closing social gaps and promoting 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$400 million in funds to our socio-environmental program, designed to help close socioeconomic gaps in Colombia and boost sustainable community development and wellbeing. The priority areas forwell-being of the socio-environmental investment program are public and communitycommunities where the Ecopetrol Group operates, with strategic projects expected in infrastructure, public services, education, sports and health, inclusive rural development and entrepreneurship and business entrepreneurship.development. Additionally, support will continue to be provided with resources in order to meet the COVID-19 pandemic needs of the communities and areas where the Ecopetrol Group operates.
TheBetween US$ 100 million and US$ 150 million are expected to be allocated to the development of the Ecopetrol Group’s digital strategy, in order to capture benefits related to artificial intelligence technologies, block chain and bots, among others. Furthermore, we expect to invest between US$70 million and US$110 million in projects to increase the recovery factor, energy transition and strategic studies on water issues and new materials.
In connection with the Ecopetrol Group’s energy transition strategy, the Business Plan seeks to maintain leveraging metricsallocates investments of more than US$600 million in initiatives focused on the decarbonization agenda, among which stand out solar, wind and geothermal energy projects, followed by energy efficiency and fuel quality projects, among others. Similarly, in March 2021, intermediate and long-term emissions reduction goals and achievement plan were defined in line with the Company’s investment grade rating and competitive vis-à-vis industry peers.Ecopetrol Group’s growth strategy.
The Plan emphasizes Ecopetrol's commitmentIn 2021, the Ecopetrol Group also expects to a safeconsolidate its evaluation of opportunities associated with the hydrogen value chain and sustainable operation, while protecting the environmentwill seek to materialize partnerships in international agreements 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.governments to identify business opportunities.
For more information on the TESG agenda see section entitled Technology, Environment, Social and Governance (TESG) Strategies and Initiatives.
To acknowledge the risks and opportunities that transitioning to a low carbon economy implies for the Ecopetrol Group, we have defined four lines of action, including the aforementioned, to face the energy transition, as described below:
(i) | Continue strengthening the competitiveness of the oil and gas business: The Ecopetrol Group plans to gain resilience in the oil and gas portfolio, which is expected to continue to be our core activities until the peak in oil demand is reached, while increasing its commitment to new businesses resilient to the energy transition. |
(ii) | Diversification of our business portfolio into low-carbon businesses: The Ecopetrol Group is exploring new business opportunities in the electricity value chain specifically in the energy transmission market as well as other potential future low-carbon businesses such as green hydrogen, carbon capture, utilization and storage (CCUS), nature-based solutions, among others, as long as that they meet the Ecopetrol Group’s growth, cash protection, and capital discipline criteria. |
(iii) | Achievement of decarbonization targets: Focused on accelerating and prioritizing energy efficiencies and reductions in carbon emissions the Ecopetrol Group plans on achieving the decarbonization goals mentioned in the section entitled Technology, Environment, Social and Governance (TESG) Strategies and Initiatives. Such targets are aligned with the Ecopetrol Group’s objectives of reducing the carbon emissions associated with its operations, as well as reducing the vulnerability of its operation and infrastructure to climate change. |
(iv) | Achievement of sustainability through the TESG strategy: The Ecopetrol Group’s TESG strategy places a clear focus on climate change (including decarbonization targets), water management, and territorial development as well as biodiversity, circular economy, health, safety and environmental (HSE) practices and diversity, leveraged on technology as a key enabler. |
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Oil and gas companies are evaluating options to reposition themselves along the energy value chain in new business segments aligned with the market trends towards decarbonization and electrification, such as renewable generation, commercialization, and services to end customers, among others. It is Ecopetrol’s view that the need to connect and integrate multiple points and types of generation will reinforce the role of transmission as an indispensable actor in the energy value chain, and a required enabler of the growth of clean generation and electrification.
Our announced interest in acquiring a 51.4% stake in Interconexión Eléctrica S.A. (ISA) is part of this strategy as it would allow us to achieve a relevant position in a strategic sector for the energy transition. Through a single transaction, we would position ourselves in a key link in the electricity business with clear prospects for future growth. For more information on this potential transaction see the section entitled Business Overview-Recent Developments.
2.1.2 | 2021 Investment Plan |
In November 2019,December 2020, the Board of Directors approved between US$4.5 3.5 billion and US$5.5 4.0 billion for the 20202021 investment plan at US$57/ 45/Bl Brent. The Ecopetrol Group plans to produce between 745700 and 760710 thousand barrels of oil equivalent per day during 2020.2021. The Ecopetrol Group expects to allocate 78%80% percent of these investments to projects in Colombia and the remainder to the positioning and developingdevelopment of the Ecopetrol Group’s operations in the United States Mexico and Brazil.
OnMarch 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:
The production target for 2020 set forth above remains unchanged as of phase one, between 745 - 760 mboed. See the section entitledTrend 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):December 2020:
Table 3 – 20202021 Investment Plan(1)
Business Segment | % Percentage | |||
Exploration | % | |||
Production | % | |||
Midstream | 7 | % | ||
Downstream | 11 | % | ||
Other | % | |||
TOTAL | 100 | % |
(1) |
Percentage over the upper range. |
2.2. | Unconventional Energy Sources |
Exploration
Ecopetrol’s strategy for unconventional resources is based on the significant acreage position it has in the Middle Magdalena Basin in Colombia. In September 2019, the Colombian Council of State authorized the execution of the PPII to do the research on the eventual effects of using unconventional technology and made mandatory recommendations in respect of the pilot stage. However, a final decision on the development of unconventional reservoirs will not be issued until the government has evaluated the PPII results.
In exploration, investment has been allocated mainly toOn February 28, 2020, the evaluationMinistry of Mines and appraisalEnergy issued Decree 328 providing the general guidelines for developing PPII on unconventional reservoirs. Furthermore, on December 24, 2020, Ecopetrol signed a contract with the Agencia Nacional de Hidrocarburos - National Hydrocarbons Agency (the “ANH”) in respect of discoveries and ongoing exploration activity of Ecopetrol S.A. (approximately35%), 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. (approximately75%) primarily at Castilla, Rubiales, Chichimene, Llanito, Casabe, Piedemonte and Caño Sur fields. In addition, Ecopetrol plans to spend approximately 19% of the funds allocateda pilot program in the production investment planMiddle Magdalena Basin pursuant to which the potential environmental and social impacts are to be evaluated and the multi-stage hydraulic fracturing 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%horizontal wells concept is to Hocol.be assessed.
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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 ofbetween 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.
3. | Business Overview |
3.1 | Our History |
We were formed in 1951 by the Colombian government asEmpresa 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, theAgencia 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-holdingpublicly-held 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.Biofuels; and (iv) Sales and Marketing.
Our subsidiaries, Refinería de Cartagena S.A.S. (Reficar or Cartagena Refinery), Cenit Transporte y LogisticaLogística 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, 2019,2020, we have seveneight directly owned and 2219 indirectly owned subsidiaries.
During 2019,2020, the following changes were made to the Ecopetrol Group’s structure:
|
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 |
(i) | On December 18, 2020, the liquidation process of ECP Germany Oil and Gas GmbH was completed, with no material adverse effect on Ecopetrol’s consolidated results. |
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Graph 2 – EcopetrolEcopetrol’s Corporate Structure(1)
The stock ownership percentage listed refers to Ecopetrol S.A.’s direct and indirect participation.participation as of December 31, 2020. The data in this structure shows neither the whole ownership nor its decimal figures, so they will be used only for information purposes.
Exhibit 8.1 to this annual report identifies our principal operating subsidiaries, their respective countries of incorporation, and our percentage ownership in each (both directly and indirectly through other subsidiaries).
3.3 | Recent Developments |
Sale of Ecopetrol’s stake in Offshore International Group
On January 19, 2021, Ecopetrol signed a Share Purchase Agreement with De Jong Capital LLC, through one of its subsidiaries as buyer, pursuant to which Ecopetrol sold its 50% ownership interest in Offshore International Group (OIG). This divestment was the result of a competitive process between a number of bidders, jointly carried out by Ecopetrol and its partner, in respect of the sale of 100% of the capital stock of OIG.
Non-binding offer to acquire 51.4% of ISA’s outstanding shares
On January 27, 2021, Ecopetrol announced its interest in acquiring 51.4% of the outstanding shares of ISA, currently owned by the Colombian Ministery of Finance and Public Credit (MHCP by its Spanish acronym). Ecopetrol is pursuing this transaction with a view that an equity stake in ISA can materially increase its exposure to global trends in electrification and decarbonization, provide access to growth opportunities and improve its risk profile by adding stable cash flows to the Ecopetrol Group’s revenue composition. The transaction is expected to be funded through a combination of equity to be issued, in which the MHCP would maintain at least 80% of Ecopetrol's share ownership, cash from operations and/or other financing alternatives available to Ecopetrol. To the extent we decide to finance the ISA acquisition through an equity offering, we are analyzing whether to offer preemptive or similar rights to our existing shareholders.
ISA operates and maintains transmission networks in Colombia, Peru, Bolivia, Brazil and Chile, among others, and participates through its subsidiaries in the toll-road business, telecommunications and management of real-time systems. Based on its public reports as filed with the Superintendencia Financiera de Colombia (the “SFC”), ISA’s consolidated operational revenues and net income for 2020 totaled COP 10.2 trillion and COP 2.1 trillion, respectively; and its total assets were COP 54.0 trillion as of December 31, 2020. As of March 31, 2021, ISA’s market capitalization as reported on the Colombian Stock Exchange (BVC) was COP 24.9 trillion.
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On February 12, 2021, Ecopetrol and the MHCP signed an exclusivity agreement through which the parties will carry out non-binding preliminary conversations on the terms and conditions of the potential transaction. The exclusivity period is initially scheduled to end on June 30, 2021 unless extended by mutual agreement of the parties. During this period, Ecopetrol will carry out a detailed due diligence of ISA and the MHCP has agreed to negotiate exclusively with Ecopetrol.
Although the Colombian Government, through the MHCP, is the majority shareholder of both ISA and Ecopetrol, and will be acting as seller in the proposed transaction for Ecopetrol’s acquisition of ISA's shares, the transaction has been structured and negotiations will be carried out on an arm's length basis, with seller and buyer independent from each other. Ecopetrol and the Colombian Government will each engage their own financial and legal counsel for purposes of carrying out this transaction. In addition, for purposes of determining ISA's valuation, Ecopetrol has engaged two experienced investment banking firms. Ecopetrol intends to engage a separate independent advisor to deliver a fairness opinion related to ISA’s valuation and Ecopetrol’s final purchase price proposal. Moreover, the Board of Directors of Ecopetrol, which is composed by a majority of independent members, retains full oversight and autonomous decision rights over Ecopetrol’s interest in the transaction.
In line with the aforementioned, on March 25, 2021, the Ecopetrol Group’s Board of Directors approved the establishment of a Special Committee that will act as a temporary mechanism to evaluate the valuation of ISA, the price range and/or the price of the potential transaction and make the necessary recommendations to the Board of Directors. The committee will be comprised of the following independent members of Ecopetrol’s Board of Directors:
For information on the regulation of the electricity sector in Colombia, see section Applicable Laws and Regulations—Regulation of the Electric Energy Commercialization Activity and Regulation of the Electricity Self-Generation Activity.
The potential acquisition of a percentage of ISA’s shares would be subject to the approval of the Ecopetrol´s Board of Directors. Likewise, the required authorizations from regulatory and supervisory entities in Colombia and other countries in which ISA has operations are being evaluated.
3.4 | Our Business |
We are a vertically integrated oil and gas company with presence primarily in Colombia and with activities in Peru,the U.S., Brazil Mexico and the U.S.Mexico. The Nation currently owns 88.49% of our voting capital stock. We are among the world’s largest public companies, ranking 300313 on the Forbes Global 2000 Ranking - 2019.– 2020, and the largest Colombian company in this ranking. We play a key role in the local Colombian hydrocarbon market.
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, 2019,2020, we were the largest operator and the largest producer of crude oil and natural gas in Colombia, maintaining the largest acreage exploration position in Colombia.
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Unless otherwise stated, all figures are given before deducting royalties.
Exploration Activities |
Under theour Business Plan, Ecopetrol is aiming to incorporate resources in high reward projects concentrated in: (i) near field exploratory activity, (ii) underexplored onshore basins in Colombia, such as Putumayo and Piedemonte, (iii) offshore Colombia, and (iv) international areas such as offshore Brazil atin Pre-salt Santos Ceara and Foz de Amazonas basins, the U.S. Gulf of Mexico and Offshore Mexico in the Salinas Basin.Mexico.
Graph 3-3 – Sedimentary basins where Ecopetrol executes exploration activities
During 2019,2020, the exploration strategy was directed at leveraging our goal on three working fronts: onshore Colombia, offshore Caribbean, and strengthening and diversifying our exploration overseas.
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 2019,2020, Ecopetrol and its subsidiaries drilled nineteen (19)sixteen (16) wells in Colombia, of which fifteen (15)ten (10) were exploratory (A3/A2) and four (4)six (6) were appraisal wells (A1) in Colombia. Seven (7)wells. As of December 31, 2020, two (2) wells were successful, nine (9)five (5) were plugged and abandoned, and three (3)nine (9) were under evaluation as of December 31, 2019.evaluation. This activity was concentrated mainly in the following basins: Llanos, Lower Magdalena Valley, Middle Magdalena Valley, Upper Magdalena Valley and Piedemonte.Sinú San Jacinto.
In 2020, Ecopetrol participated in the drilling of two (2) successful wells in Colombia:
(i) the Cayena-1 ST1 well, drilled at sole risk by our partner Parex Resources in the Fortuna Association contract (where Ecopetrol holds a 20% working interest and Parex Resources, as the operator, holds the remaining 80% working interest); and
(ii) the Arrecife-3 well, where Ecopetrol holds a 100% working interest, through its subsidiary Hocol, at the VIM 8 Block.
Furthermore, during 2020 the Merecumbé-1 well was tested and declared successful after showing gas production in the Chengue Formation. This well was drilled by Lewis Energy in partnership with our subsidiary Hocol in 2019. As of the date of this annual report, this well is closed and under evaluation.
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The following table sets forth, for the periods indicated, the number of gross and net productive, dry and dryunder evaluation exploratory wells drilled by us and our joint venture partners, and the exploratory wells drilled by third parties pursuant to sole risk contracts with us.
Table 4 – Exploratory Drilling in Colombia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(number of wells) | (Number of wells) | |||||||||||||||||||||||
COLOMBIA | ||||||||||||||||||||||||
Ecopetrol S.A. | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Ecopetrol S.A | ||||||||||||||||||||||||
Gross exploratory wells | ||||||||||||||||||||||||
Owned and operated by Ecopetrol | ||||||||||||||||||||||||
Productive | 1.0 | – | – | - | 1.0 | - | ||||||||||||||||||
Dry(1) | 1.0 | – | 1.0 | 2.0 | 1.0 | - | ||||||||||||||||||
Under Evaluation(2)(3) | 1.0 | - | - | |||||||||||||||||||||
Total | 2.0 | – | 1.0 | 3.0 | 2.0 | - | ||||||||||||||||||
Operated by Partner in Joint Venture | ||||||||||||||||||||||||
Operated by a partner in Joint Venture | ||||||||||||||||||||||||
Productive | 4.0 | 5.0 | 3.0 | - | 4.0 | 5.0 | ||||||||||||||||||
Dry | 1.0 | 1.0 | 2.0 | |||||||||||||||||||||
Dry(1) | - | 1.0 | 1.0 | |||||||||||||||||||||
Under Evaluation(2) | 1.0 | 1.0 | 3.0 | |||||||||||||||||||||
Total | 5.0 | 6.0 | 5.0 | 1.0 | 6.0 | 9.0 | ||||||||||||||||||
Operated by Ecopetrol in Joint Venture | ||||||||||||||||||||||||
Productive | – | – | – | - | - | - | ||||||||||||||||||
Dry | – | – | 1.0 | |||||||||||||||||||||
Dry(1) | - | - | - | |||||||||||||||||||||
Under Evaluation(2) | 2.0 | - | 1.0 | |||||||||||||||||||||
Total | – | – | 1.0 | 2.0 | - | 1.0 | ||||||||||||||||||
Net Exploratory Wells(2) | ||||||||||||||||||||||||
Net Exploratory Wells(4) | ||||||||||||||||||||||||
Productive | 2.8 | 1.9 | 1.5 | - | 2.8 | 1.9 | ||||||||||||||||||
Dry | 1.4 | 0.3 | 2.3 | |||||||||||||||||||||
Dry(1) | 2.0 | 1.4 | 0.3 | |||||||||||||||||||||
Under Evaluation(2) | 2.5 | 0.4 | 2.0 | |||||||||||||||||||||
Total | 4.2 | 2.2 | 3.8 | 4.5 | 4.6 | 4.2 | ||||||||||||||||||
Sole Risk | ||||||||||||||||||||||||
Productive | 1.0 | – | – | 1.0 | 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 | – | – | – | |||||||||||||||||||||
Dry(1) | 1.0 | 5.0 | 2.0 | |||||||||||||||||||||
Under Evaluation(2)(5) | 3.0 | - | - | |||||||||||||||||||||
Total | – | – | – | 5.0 | 6.0 | 2.0 | ||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Productive | 1.0 | 1.0 | – | 1.0 | 1.0 | 1.0 | ||||||||||||||||||
Dry | 2.0 | 4.0 | 1.0 | |||||||||||||||||||||
Dry(1) | 2.0 | 2.0 | 4.0 | |||||||||||||||||||||
Under Evaluation(2) | 2.0 | 2.0 | - | |||||||||||||||||||||
Total | 3.0 | 5.0 | 1.0 | 5.0 | 5.0 | 5.0 | ||||||||||||||||||
Net Exploratory Wells | ||||||||||||||||||||||||
Net Exploratory Wells(4) | ||||||||||||||||||||||||
Productive | 0.5 | 1.0 | – | 1.0 | 0.5 | 1.0 | ||||||||||||||||||
Dry | 2.0 | 3.2 | 1.0 | |||||||||||||||||||||
Dry(1) | 2.0 | 2.0 | 3.2 | |||||||||||||||||||||
Under Evaluation(2) | 1.0 | 1.0 | - | |||||||||||||||||||||
Total | 2.5 | 4.2 | 1.0 | 4.0 | 3.5 | 4.2 |
(1) | A dry well or hole is an exploratory well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well. |
(2) |
(3) | The Flamencos-2 well was classified as “under evaluation” for the year ended December 31, 2020. However, as of January 2021, it has been declared successful. |
(4) | Net exploratory wells were calculated according to our percentage of ownership in these wells. |
(5) | The El Niño-1 well was classified as “under evaluation” for the year ended December 31, 2020. However, as of January 2021, it has been declared successful. |
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Ecopetrol drilled seven (7) successful wellsAs a result of our divestment strategy, Hocol transferred 50% of its interest to Lewis Energy for the exploration of natural gas in Colombiaa frontier play in 2019 (i) Jaspe-8, where Ecopetrol holds a 30% working interest, and Frontera as the operator holdsPerdices block. Additionally, the remaining 70% working interest atAgencia Nacional de Hidrocarburos approved the Quifa Block, (ii) Andina Norte-1, where Ecopetrol holds atransfer of our 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,COL-5, Purple Angel and (vii) Bullerengue-3,Fuerte Sur blocks, where Ecopetrol holdsthe Gorgon and Kronos gas discoveries are located, to Shell. With the arrival of a 50% working interest through its subsidiary Hocol, and Lewis asnew operator with deep-water offshore experience, offshore drilling will recommence with an appraisal well, Gorgon-2, in December 2021. The appraisal well will be drilled in a 2,400 meters water depth, with an expected total depth of 4,543 meters. In case of success, additional drilling is to follow, with the operator holdsexpectations of accelerating the remaining 50% working interest at the Sinú San Jacinto Block.development of this material gas discovery.
Seismic
In Colombia,we acquired a total of 2,000 Ecopetrol purchased 273 km2 of 3D seismic offshoreand 1,328 km of 2D seismic surveys in the Col-5 Block,Llanos, Middle Magdalena Valley and throughUpper Magdalena Valley basins, with the objective of improving 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 theEastern Plains (Llanos Orientales) and Putumayo basin to improve technicalgeological understanding of these prolific basins.
Exploration Activities Outside Colombia |
Our international exploration strategy aims to expand and renew our exploration portfolio in basins with long term potential, dilute our risks and improve the possibility of increasing our reserves. Some key aspects of this strategy include participating in bidding rounds to secure blocks available for exploration and entering into joint ventures with international and regional oil companies that contribute with operational expertise and technology.
In 2020, Ecopetrol America LLC signed a cross-assignment with Chevron, through which new blocks in the US Gulf of Mexico were acquired and participation in other blocks was transferred to Chevron. As a result, Ecopetrol America LLC was able to diversify its portfolio while reducing risk and capital exposure.
On June 12, 2020, Ecopetrol Óleo e Gás do Brasil Ltda. 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 includesofficially entered 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 interestdiscovery in the MC 904 blockBrazilian Pre-Salt, located in the Gulf of Mexico of the United States, in consortium with Fieldwood Energy as the operator withBM-S-54 and Sul de Gato do Mato blocks, where Ecopetrol holds a 58.94%30% working interest, Total holds a 20% 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 CorporationShell as the operator holds a 57.14% working interest, and Chevron holds the remaining 21.43%50% working interest. The Gato do Mato-4 appraisal well is currently being tested,was drilled and results, so far, seem promising.was declared successful.
Additionally,In the pre-salt of the Santos Basin, Ecopetrol Hidrocarburos Mexico Inc. is executingÓleo e Gás do Brasil Ltda. also drilled, together with its partners Shell (as operator) and Chevron, the Saturno-1 well, which was declared a dry hole. Further technical evaluations are being carried out during 2021 to decide the path forward with regards to remaining potential in the Saturno exploration plan for Block 6. block.
17
The following table sets forth information on our international exploratory drilling for the periods indicated.
Table 5 – Exploratory Drilling Outside Colombia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(number of wells) | (Number of wells) | |||||||||||||||||||||||
INTERNATIONAL | ||||||||||||||||||||||||
UNITED STATES | ||||||||||||||||||||||||
Ecopetrol America LLC | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Gross exploratory wells | ||||||||||||||||||||||||
Productive | 1.0 | – | – | - | 1.0 | - | ||||||||||||||||||
Dry(1) | – | – | 2.0 | - | - | - | ||||||||||||||||||
Under Evaluation(2) | - | - | - | |||||||||||||||||||||
Total | 1.0 | – | 2.0 | - | 1.0 | - | ||||||||||||||||||
Net Exploratory Wells(2)(3) | ||||||||||||||||||||||||
Net Exploratory Wells(3)(4) | ||||||||||||||||||||||||
Productive | 0.2 | – | – | - | 0.2 | - | ||||||||||||||||||
Dry | 0.0 | – | 0.6 | |||||||||||||||||||||
Dry(1) | - | - | - | |||||||||||||||||||||
Under Evaluation(2) | - | - | - | |||||||||||||||||||||
Total | 0.2 | – | 0.6 | - | 0.2 | - | ||||||||||||||||||
BRAZIL | ||||||||||||||||||||||||
Ecopetrol Óleo e Gás do Brasil Ltda. | ||||||||||||||||||||||||
Gross Exploratory Wells | – | – | – | |||||||||||||||||||||
Gross exploratory wells | ||||||||||||||||||||||||
Productive(5) | 1.0 | - | - | |||||||||||||||||||||
Dry(1) | 1.0 | - | - | |||||||||||||||||||||
Under Evaluation(2) | - | - | - | |||||||||||||||||||||
Total | 2.0 | - | - | |||||||||||||||||||||
Net Exploratory Wells(3)(4) | ||||||||||||||||||||||||
Productive | – | – | – | 0.3 | - | - | ||||||||||||||||||
Dry | – | – | – | |||||||||||||||||||||
Dry(1) | 0.1 | - | - | |||||||||||||||||||||
Under Evaluation(2) | - | - | - | |||||||||||||||||||||
Total | – | – | – | 0.4 | - | - | ||||||||||||||||||
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) |
(3) | Net exploratory wells |
None of our international wells were drilled pursuant to a sole risk contract. |
(5) | Gato do Mato-4 appraisal well was drilled before Ecopetrol Brasil formal entrance into the joint venture with Shell, while pending the governmental authorities’ approval. Therefore, the well expenditure was part of the acquisition cost under the sale and purchase agreement executed between Ecopetrol Brasil and Shell Brasil Petróleo Ltda. Due to that, the Gato do Mato-4 well cost was recorded as “acquisition cost” in the 2020 financial statements of of Ecopetrol Brasil. |
Seismic
Our subsidiary, Ecopetrol 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, itAmerica LLC, 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 88,0152,423 km2 of 3D seismic fromdata to evaluate the Campeche program for a periodexploratory potential of 24 months.77 U.S. Gulf of Mexico blocks, and to further evaluate the discovery made with the Esox-1 well drilled in 2019.
18
Production Activities |
OurIn 2020, our consolidated average production was 725697 thousand barrels of oil equivalent per day (boepd) in 2019, an increase, a decrease of approximately 4.728 thousand boepd as compared to 2018.2019. This growth was primarily due to the positive resultsfollowing factors: (i) the effects of the COVID-19 pandemic, which caused a significant reduction in oil and gas demand, (ii) the drop in oil prices which led to a slowdown in activity and investment, and (iii) public order issues caused by the slowdown in the Akacias, Yarigui, Caño Sur, Rubiales, and Chichimene fields,economy, impacting our operations in different regions. The aforementioned situations were reflected in the greater commercializationtemporary closure of gas, mostly fromsome wells, negatively affecting the Cupiagua and Floreña fields and the entry into operationproduction of some fields. However, as of the Cupiagua LPG Plant.date of this annual report, all affected wells have been reactivated.
The following table summarizes the results of our oil and gas production activities for the periods indicated:
Table 6 – Ecopetrol Group’s Oil and Gas Production
For the year ended December 31, | ||||||||||||||||||||||||||||||||||||
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 |
For the year ended December 31, | ||||||||||||||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||||||||||||||
Oil | Gas(1) | Total | Oil | Gas(1) | Total | Oil | Gas(1) | Total | ||||||||||||||||||||||||||||
(Thousand boepd) | ||||||||||||||||||||||||||||||||||||
Total gross production in Colombia(2) | 537.4 | 138.1 | 675.5 | 576.6 | 130.5 | 707.1 | 578.4 | 125.0 | 703.4 | |||||||||||||||||||||||||||
Total international gross production(3) | 17.4 | 4.2 | 21.5 | 15.0 | 3.0 | 18.0 | 14.1 | 2.9 | 17.0 | |||||||||||||||||||||||||||
Total gross production of Ecopetrol Group | 554.7 | 142.3 | 697.0 | 591.6 | 133.5 | 725.1 | 592.5 | 127.9 | 720.4 | |||||||||||||||||||||||||||
Total production of Ecopetrol Group for presentation of reserves(4) | 508.5 | 138.8 | 647.3 | 528.9 | 133.7 | 662.6 | 524.3 | 129.8 | 654.1 |
(1) | Conversion between million cubic feet per day (mcfpd) and boepd is performed at 5,700 mcfpd to 1 boepd. |
(2) | Total production in Colombia corresponds to Ecopetrol S.A., Hocol and |
(3) | Total International production corresponds to |
(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), |
Production Activities in Colombia |
Ecopetrol S.A.’s Production Activities in Colombia |
For the year ended December 31, 2019,2020, Ecopetrol S.A. was the largest participant in the Colombian hydrocarbons industry, accounting for approximately 62%66.1% of crude oil production and 62%55.6% of natural gas production (according to calculations made by Ecopetrol(calculations based on information from the Ministry of Mines and Energy). Also during 2019,During 2020, Ecopetrol S.A. carried outcompleted the drilling of 201 development drillingwells, mainly in the EasternCentral and OrinoquiaOrinoquía regions drilling 571 development wells (298 of those(156 through direct operations and 27345 through joint ventures)associated companies).
Ecopetrol S.A. manages its production operations through a regional organization. Our operating assets are distributed in the following vice-presidencies:
A sixth vice-Presidency, the Vice-Presidencyorganization, which comprises a total 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 12379 oil fields with active production in 2019. On2020:
19
Additionally, we operate 104 fields with active production through Associated Operations with different partners.
In February 10, 2020, a newthe 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.by regions.
Graph 4 – Ecopetrol S.A. Operations in Colombia
Note: Associated Operations are conducted through a countrywide Vice-presidency of Associated Operations.
Crude Oil Production
The average daily production of crude oil in Colombia by Ecopetrol S.A. (excluding its subsidiaries), was 548.0516 mbod in 2019, 0.72020, 32 mbod lower than in 2018,2019, which represents a year-to-year decrease of0.1% 6%.
The following chart summarizes Ecopetrol S.A.’s average daily crude oil production in Colombia by region, prior to deducting royalties, for the periods indicated.
20
Table 7 – Ecopetrol S.A.’s Average Daily Crude Oil Production in Colombia by Region 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 |
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Thousand bpd) | ||||||||||||
Central Region | ||||||||||||
La Cira – Infantas | 19.51 | 25.90 | 28.10 | |||||||||
Casabe | 13.11 | 13.20 | 13.90 | |||||||||
Yarigui | 18.90 | 17.90 | 14.40 | |||||||||
Other | 16.95 | 15.90 | 17.30 | |||||||||
Total Central Region | 68.47 | 72.90 | 73.70 | |||||||||
Orinoquía Region | ||||||||||||
Castilla | 112.22 | 114.10 | 113.90 | |||||||||
Chichimene | 68.80 | 69.10 | 67.70 | |||||||||
CPO-09 | 5.25 | 10.90 | 4.50 | |||||||||
Apiay | 6.33 | 7.30 | 7.60 | |||||||||
Other | 7.16 | 5.60 | 4.40 | |||||||||
Total Orinoquía Region | 199.76 | 207.00 | 198.10 | |||||||||
Piedemonte Region | ||||||||||||
Floreña(1)(2) | 25.54 | 22.70 | 25.90 | |||||||||
Cupiagua(3) | 6.22 | 7.20 | 8.30 | |||||||||
Cusiana(3) | 2.13 | 3.10 | 4.00 | |||||||||
Total Piedemonte Region | 33.90 | 33.00 | 38.20 | |||||||||
Andina Oriente Region(4) | ||||||||||||
Rubiales | 106.27 | 119.30 | 119.50 | |||||||||
Caño Sur | 5.06 | 4.50 | 3.20 | |||||||||
San Francisco | 4.05 | 6.20 | 6.00 | |||||||||
Huila Area | 5.55 | 3.80 | 3.50 | |||||||||
Tello | 4.33 | 3.40 | 3.60 | |||||||||
Other | 7.50 | 10.40 | 11.70 | |||||||||
Total Andina Oriente Region | 132.77 | 147.60 | 147.50 | |||||||||
Associated Operations | ||||||||||||
Quifa | 14.73 | 20.50 | 21.20 | |||||||||
Caño Limon | 24.14 | 25.70 | 25.30 | |||||||||
Nare | 9.53 | 10.90 | 12.00 | |||||||||
Floreña(1)(2) | 2.62 | - | - | |||||||||
Other | 30.15 | 30.40 | 32.70 | |||||||||
Total Associated Operations | 81.17 | 87.50 | 91.20 | |||||||||
Total average daily crude oil production Ecopetrol S.A. (Colombia) | 516.03 | 548.00 | 548.70 |
(1) |
(2) | The Floreña fields were |
In |
(4) | In July 2020, the former Southern and Eastern regions joined to form the Andina region. Information as of December 31, 2019 and December 31, 2018 |
Table 8 – Ecopetrol S.A. Production per Type of Crude
2019 (mbod) | Year-on-Year ∆ (%) | 2018 (mbod) | Year-on- Year ∆ (%) | 2017 (mbod) | 2020 (Mbod) | Year-on-Year ∆ (%) | 2019 (Mbod) | Year-on-Year ∆ (%) | 2018 (Mbod) | ||||||||||||||||||||||||||||||||
Light | 36.5 | (10.3 | )% | 40.7 | (4.0 | )% | 42.4 | 39.0 | 6.8 | % | 36.5 | (10.3 | )% | 40.7 | |||||||||||||||||||||||||||
Medium | 150.3 | (2.7 | )% | 154.4 | 1.8 | % | 151.6 | 140.6 | (6.5 | )% | 150.3 | (2.7 | )% | 154.4 | |||||||||||||||||||||||||||
Heavy | 361.2 | 2.1 | % | 353.6 | 0.7 | % | 351.0 | 336.4 | (6.9 | )% | 361.2 | 2.1 | % | 353.6 | |||||||||||||||||||||||||||
Total | 548.0 | 548.7 | 545.0 | 516.0 | (5.8 | )% | 548.0 | (0.1 | )% | 548.7 |
Ecopetrol S.A.’s crude oil production in Colombia during 20192020 was approximately 34%35% light and medium crudes and 65% heavy crudes. In 2019, approximately 34% of the crude oil production consisted of light and medium crudes, and 66% consisted of heavy crudes. In 2018, approximately 36% of the crude oil production consisted of light and medium crudes, and 64% consisted of heavy crudes. In 2017, approximately 36% of the crude oil production consisted of light and medium crudes, and 64% consisted of heavy crudes.
21
Natural Gas Production
In 2019,2020, the average daily production of natural gas by Ecopetrol S.A. (excluding its subsidiaries) reached 116.75121.82 mboed, including natural gas liquids (NGLs), corresponding to a 3.8%4.3% increase in comparisoncompared to 20182019 production.
We have three main natural gas This 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 following fields: Cupiagua (35%), Cusiana (24%), Floreña (18%), Guajira field, 31% from the Cusiana field, 31% from the Cupiagua field(11%), and the remaining 23%12% from other fields.
On October 29, 2019By the newend of December 31, 2020, the Liquefied Petroleum Gas (LPG) plant of the Cupiagua field began operations. This plant is expected to produce between 7,000 and 8,000 LPGproduced 7,500 LGP 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.
Starting May 2020, our subsidiary Hocol took in the position of operator of the heavy crudes producedChevron’s stake in the Chuchupa and Ballena fields, such as Castilla, Rubiales, Chichimene, CPO-09, Quifafollowing the approval of the transaction by the Superintendence of Industry and Caño Sur.Commerce of Colombia in November 2019.
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 |
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | |||||||||||||||||||
Central Region | ||||||||||||||||||||||||
La Cira – Infantas | 0.10 | 0.57 | 0.12 | 0.68 | 0.16 | 0.91 | ||||||||||||||||||
Provincia | 1.48 | 4.84 | 1.58 | 4.96 | 1.96 | 7.30 | ||||||||||||||||||
Yarigui | 0.42 | 2.41 | 0.43 | 2.45 | 0.42 | 2.39 | ||||||||||||||||||
Gibraltar | 5.71 | 29.12 | 6.25 | 31.86 | 6.87 | 34.94 | ||||||||||||||||||
Other | 2.00 | 10.42 | 1.68 | 8.84 | 1.86 | 10.20 | ||||||||||||||||||
Total Central Region | 9.71 | 47.36 | 10.06 | 48.79 | 11.27 | 55.75 | ||||||||||||||||||
Orinoquía Region | ||||||||||||||||||||||||
Apiay | 0.32 | - | 0.29 | - | 0.49 | - | ||||||||||||||||||
Other | 0.58 | - | 0.64 | - | 0.25 | - | ||||||||||||||||||
Total Orinoquía Region | 0.90 | - | 0.93 | - | 0.74 | - | ||||||||||||||||||
Piedemonte Region | ||||||||||||||||||||||||
Floreña(1)(2) | 22.22 | 109.93 | 1.95 | 8.72 | 2.06 | 9.41 | ||||||||||||||||||
Cupiagua(3) | 42.68 | 194.99 | 36.45 | 196.08 | 26.97 | 153.73 | ||||||||||||||||||
Cusiana(3) | 29.57 | 136.63 | 35.72 | 164.67 | 34.73 | 159.83 | ||||||||||||||||||
Total Piedemonte Region | 94.47 | 441.55 | 74.12 | 369.47 | 63.76 | 322.96 | ||||||||||||||||||
Andina Oriente Region(4) | ||||||||||||||||||||||||
Huila Area | 0.19 | 0.34 | 0.09 | 0.40 | 0.13 | 0.68 | ||||||||||||||||||
Tello | 0.08 | 0.47 | 0.07 | 0.40 | 0.11 | 0.63 | ||||||||||||||||||
Other | 0.19 | 0.53 | 0.25 | 0.23 | 0.25 | 0.23 | ||||||||||||||||||
Total Andina Oriente Region | 0.46 | 1.34 | 0.41 | 1.03 | 0.49 | 1.54 | ||||||||||||||||||
Associated Operations | ||||||||||||||||||||||||
Guajira | 12.80 | 72.92 | 17.92 | 102.14 | 23.02 | 131.21 | ||||||||||||||||||
Floreña(1)(2) | 2.15 | 9.91 | 12.50 | 57.51 | 12.20 | 55.46 | ||||||||||||||||||
Other | 1.33 | 5.37 | 0.82 | 3.48 | 1.01 | 4.50 | ||||||||||||||||||
Total Associated Operations | 16.28 | 88.20 | 31.24 | 163.13 | 36.23 | 191.18 | ||||||||||||||||||
Total Natural Gas Production (Colombia) | 121.82 | 578.45 | 116.76 | 582.43 | 112.49 | 571.43 |
(1) | The Piedemonte fields change their name to the Floreña fields as of December 2020. |
(2) | The Floreña fields were included in Associated Operations until February 2020, when the association contract with Equión ended. Starting in March 2020, these fields are reported under the Piedemonte Region. |
(3) | In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana fields were included in the Orinoquía Region, whereas for the year ended December 31, 2020, these fields are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(4) | In July 2020, the former Southern and Eastern regions joined to form the Andina region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd. Conversion was done only in respect of natural gas, since natural gas liquids cannot be converted into mcfpd. Therefore, when the Company’s natural gas production is measured in boepd, it is higher as that includes natural gas and natural gas liquids. The Company’s sales of natural gas liquids represented less than 1% of the Company’s consolidated sales for the periods presented in this annual report.
22
Projects to Increase Recovery Factor
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% of2020, Ecopetrol continued 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 respectimplementation of secondary and tertiary recovery programs to improve the fields’ recovery factor. By the end of 2020, the fields with secondary and tertiary recovery programs contributed with 36% of the daily production of the Ecopetrol Group, underpinned by the good results obtained from the water injection expansion projects in the Chichimene, Castilla and Llanito fields.
The recovery programs increased proven reserves by 113 million boe with an investment close toof approximately US$730 million. Additionally, final investment decisions were taken for 11 new 345 million executed throughout the year. Of 42 recovery projects, 34 correspond to secondary recovery and 16 recovery projects are being structured based on the results of their correspondent pilots.eight to tertiary recovery.
Development Wells
The following table sets forth the number of gross and net development wells drilled in Colombia, both solely by Ecopetrol S.A. and with its joint venturesassociates, that reached total depth for the years ended December 31, 2020, 2019 2018 and 2017.2018.
Table 10 – Ecopetrol S.A.’s Gross and Net Development Wells in Colombia(1)
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 |
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Productive Wells | Dry Wells | Productive Wells | Dry Wells | Productive Wells | Dry Wells | |||||||||||||||||||
Central Region | ||||||||||||||||||||||||
Gross development wells owned and operated by Ecopetrol | 51.0 | - | 84.0 | 1.0 | 12.0 | - | ||||||||||||||||||
Orinoquía Region | ||||||||||||||||||||||||
Gross development wells owned and operated by Ecopetrol | 32.0 | - | 87.0 | 2.0 | 77.0 | - | ||||||||||||||||||
Andina Oriente Region(2) | ||||||||||||||||||||||||
Gross development wells owned and operated by Ecopetrol | 73.0 | - | 124.0 | - | 134.0 | 4.0 | ||||||||||||||||||
Piedemonte Region(3) | ||||||||||||||||||||||||
Gross development wells owned and operated by Ecopetrol | - | - | - | - | - | - | ||||||||||||||||||
Total gross development wells owned and operated in Colombia | 156.0 | - | 295.0 | 3.0 | 223.0 | 4.0 | ||||||||||||||||||
Associated Operations | ||||||||||||||||||||||||
Gross development wells in joint ventures | 45.0 | - | 268.0 | 5.0 | 311.0 | 4.0 | ||||||||||||||||||
Net development wells(4) | 29.0 | - | 137.0 | 2.6 | 148.7 | 1.8 | ||||||||||||||||||
Total gross development wells in joint ventures Ecopetrol S.A. in Colombia | 45 | - | 268.0 | 5.0 | 311.0 | 4.0 | ||||||||||||||||||
Total net development wells in joint ventures Ecopetrol S.A. in Colombia(4) | 29.0 | - | 137.0 | 2.6 | 148.7 | 1.8 | ||||||||||||||||||
Total gross development wells Ecopetrol S.A. in Colombia | 201 | - | 563.0 | 8.0 | 534.0 | 8.0 | ||||||||||||||||||
Total net development wells Ecopetrol S.A. in Colombia(4) | 185.0 | - | 432.0 | 5.6 | 370.7 | 5.8 |
(1) | Includes only wells that were drilled and completed. |
(2) | In July 2020, the former Southern and Eastern regions joined and formed the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(3) | In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and the Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(4) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
23
The following tables set forth activities by geographical area, including the number of gross and net wells in the process of being drilled, completed, or waiting on completion for the year ended December 31, 2020.
Table 11 – Ecopetrol S.A.’s Gross and Net In Process Wells
For the year ended December 31, 2020 | ||||||||||||||||
Drilled but not completed | Mobilization | Being drilled | Being completed | |||||||||||||
(Number of wells) | ||||||||||||||||
COLOMBIA | ||||||||||||||||
Central Region | ||||||||||||||||
Gross in process wells owned and operated by Ecopetrol | 7.0 | - | 4.0 | 8.0 | ||||||||||||
Orinoqula Region | ||||||||||||||||
Gross in process wells owned and operated by Ecopetrol | - | - | - | - | ||||||||||||
Andina Oriente Region(1) | ||||||||||||||||
Gross in process wells owned and operated by Ecopetrol | 1.0 | 1.0 | 2.0 | - | ||||||||||||
Piedemonte Region(2) | ||||||||||||||||
Gross in process wells owned and operated by Ecopetrol | - | - | - | - | ||||||||||||
Total gross in process wells owned and operated in Colombia | 8.0 | 1.0 | 6.0 | 8.0 | ||||||||||||
Associated Operations | ||||||||||||||||
Gross in process wells in joint ventures | 8.0 | - | 1.0 | - | ||||||||||||
Net in process wells(3) | 6.2 | - | 1.0 | - | ||||||||||||
Total gross in process wells in joint ventures Ecopetrol S.A. | 8.0 | - | 1.0 | - | ||||||||||||
Total net in process wells in joint ventures Ecopetrol S.A.(3) | 6.2 | - | 1.0 | - | ||||||||||||
Total gross in process wells Ecopetrol S.A. in Colombia | 16.0 | 1.0 | 7.0 | 8.0 | ||||||||||||
Total net in process wells Ecopetrol S.A. in Colombia(3) | 14.2 | 1.0 | 7.0 | 8.0 |
(1) | In July 2020, the former Southern and Eastern regions joined to form the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(2) | In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and the Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(3) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
24
Production Acreage
The following table sets forth Ecopetrol S.A.’s developed and undeveloped gross and net acreage of crude oil and natural gas production in Colombia for the year ended December 31, 2020.
Table 12 – Ecopetrol SA.’s Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production in Colombia
As of December 31, 2020 | ||||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
(Acres) | ||||||||||||||||
Ecopetrol S.A. | 471,969 | 371,489 | 4,633,683 | 3,443,517 |
Gross and Net Productive Wells
The following table sets forth Ecopetrol S.A.’s total gross and net productive wells by region as of December 31, 2020.
Table 13 – Ecopetrol S.A.’s Gross and Net Productive Wells by Region(1)
For the year ended December 31, 2020 | ||||||||||||||||
Crude Oil(2) | Natural Gas(3) | |||||||||||||||
Gross | Net(4) | Gross | Net(4) | |||||||||||||
(Number of wells) | ||||||||||||||||
COLOMBIA | ||||||||||||||||
Central Region | 2,049 | 1,548 | 4.0 | 4.0 | ||||||||||||
Orinoquía Region | 996 | 985 | - | - | ||||||||||||
Andina Oriente Region(5) | 1,087 | 1,034 | 8.0 | 8.0 | ||||||||||||
Piedemonte Region(6) | 58 | 58 | 17.0 | 17.0 | ||||||||||||
Associated Operations Region | 2,711 | 1,473 | 34.0 | 16.0 | ||||||||||||
Total | 6,901 | 5,098 | 63.0 | 45.0 |
(1) | Includes only wells that were drilled and completed. |
(2) | We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. |
(3) | Natural gas wells are those in which operations are directed only toward the production of commercial gas. |
(4) | Net productive wells are calculated by multiplying gross productive wells by our ownership percentage. |
(5) | In July 2020, the former Southern and Eastern regions joined and formed the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(6) | In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
25
3.5.2.1.2 | Ecopetrol S.A.’s Affiliates and Subsidiaries’ Production Activities in Colombia |
In 2020, the subsidiaries’ production in Colombia came from Hocol and Equión. During the year, the production obtained from these two companies was 37.6 thousand boepd, which represents 5.4% of the Ecopetrol Group’s total production.
Crude Oil Production
The following table sets forth our average daily crude oil production from Hocol and Equion, prior to deducting royalties, for the periods indicated.
Table 14 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Crude Oil Production(1)
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Thousand bpd) | ||||||||||||
COLOMBIA | ||||||||||||
Hocol | ||||||||||||
Joint venture operation | 1.06 | 2.00 | 2.30 | |||||||||
Direct operation | 19.14 | 18.80 | 18.40 | |||||||||
Total Hocol | 20.20 | 20.80 | 20.70 | |||||||||
Equion(1) | ||||||||||||
Joint venture operation | - | - | - | |||||||||
Direct operation | 1.13 | 7.90 | 9.00 | |||||||||
Total Equion | 1.13 | 7.90 | 9.00 | |||||||||
Production Tests | - | - | - | |||||||||
Total Average Daily Crude Oil Production | 21.33 | 28.70 | 29.70 |
(1) | Equion fields were in operation until February 2020. |
The 86% decrease in Equion’s production in 2020, as compared to 2019, was mainly due to the termination of the Piedemonte’s association contract in February 2020.
Natural Gas Production
The following table sets forth our subsidiaries’ average daily natural gas production, prior to deducting royalties, for the periods indicated.
Table 15 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Natural Gas Production
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | |||||||||||||||||||
COLOMBIA | ||||||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Joint venture operation | 2.18 | 12.43 | 2.00 | 11.40 | 1.60 | 9.10 | ||||||||||||||||||
Direct operation(1) | 13.24 | 75.48 | 6.70 | 38.20 | 5.90 | 33.60 | ||||||||||||||||||
Total Hocol | 15.42 | 87.91 | 8.70 | 49.60 | 7.50 | 42.80 | ||||||||||||||||||
Equion(2) | ||||||||||||||||||||||||
Joint venture operation | - | - | - | - | 0.20 | 1.10 | ||||||||||||||||||
Direct operation | 0.86 | 4.10 | 5.00 | 23.29 | 4.80 | 22.34 | ||||||||||||||||||
Total Equion | 0.86 | 4.10 | 5.00 | 23.29 | 5.00 | 23.44 | ||||||||||||||||||
Production Tests | - | - | - | - | - | - | ||||||||||||||||||
Total Average Daily Gas Production (Subsidiaries in Colombia) | 16.28 | 92.01 | 13.70 | 72.89 | 12.50 | 66.24 |
(1) | In November 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields and took the position of operator, this represents the increase in production related to direct operation. |
(2) | Equion fields were in operation until February 2020. |
Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd. Conversion was done only in respect of natural gas, since natural gas liquids cannot be converted into mcfpd. Therefore, when the Company’s natural gas production is measured in boepd, it is higher as that includes natural gas and natural gas liquids. The Company’s sales of natural gas liquids represented less than 1% of the Company’s consolidated sales for the periods presented in this annual report.
26
Development Wells
The following table sets forth the number of gross and net development wells drilled exclusively by our subsidiaries and in their joint ventures in Colombia for the periods indicated.
Table 16 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Development Wells(1)
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Productive Wells | Dry Wells | Productive Wells | Dry Wells | Productive Wells | Dry Wells | |||||||||||||||||||
(Number of wells) | ||||||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Gross development wells owned and operated by Hocol | 24.0 | - | 21.0 | 2.0 | 12.0 | - | ||||||||||||||||||
Gross development wells in joint ventures | - | - | 2.0 | - | 2.0 | - | ||||||||||||||||||
Net development wells(2) | 24.0 | - | 22.0 | 2.0 | 13.0 | - | ||||||||||||||||||
Equion | ||||||||||||||||||||||||
Gross development wells owned and operated by Equion(3) | - | - | - | - | - | - | ||||||||||||||||||
Gross development wells in joint ventures | - | - | - | - | - | - | ||||||||||||||||||
Net development wells(2) | - | - | - | - | - | - | ||||||||||||||||||
Total gross development wells owned and operated in Colombia | 24.0 | - | 21.0 | 2.0 | 12.0 | - | ||||||||||||||||||
Total gross development wells in joint ventures in Colombia | - | - | 2.0 | - | 2.0 | - | ||||||||||||||||||
Total net development wells (Subsidiaries in Colombia)(2) | 24.0 | - | 22.0 | 2.0 | 13.0 | - |
(1) | Includes only wells that were drilled and completed. |
(2) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
(3) | Equion fields were in operation until February 2020. |
Note: There were no dry wells in our Colombian subsidiaries’ operations for the year ended December 31, 2018 and December 31, 2020.
27
Table 17 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net In Process Wells(1)
For the year ended December 31, 2020 | ||||||||||||||||
Drilled but not completed | Mobilization | Being drilled | Being completed | |||||||||||||
(Number of wells) | ||||||||||||||||
Hocol | ||||||||||||||||
Gross in process wells owned and operated by Hocol | - | 1.0 | - | 1.0 | ||||||||||||
Gross in process wells in joint ventures | - | - | - | - | ||||||||||||
Net in process wells(1) | - | 1.0 | - | 1.0 | ||||||||||||
Equión(2) | ||||||||||||||||
Gross in process wells owned and operated by Equión | - | - | - | - | ||||||||||||
Gross in process wells in joint ventures | - | - | - | - | ||||||||||||
Net in process wells(1) | - | - | - | - | ||||||||||||
Total gross in process wells owned and operated in Colombia | - | 1.0 | - | 1.0 | ||||||||||||
Total gross in process wells in joint ventures in Colombia | - | - | - | - | ||||||||||||
Total net in process wells (Subsidiaries in Colombia) | - | 1.0 | - | 1.0 |
(1) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
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 Grossand 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.
(2) |
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 |
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 |
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, 2019.2020.
Table 1618 – 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 |
As of December 31, 2020 | |||||||||||||||||
Developed | Undeveloped | ||||||||||||||||
Gross | Net | Gross | Net | ||||||||||||||
(Acres) | |||||||||||||||||
Hocol(1) | 62,774 | 37,608 | 3,005 | 2,967 | |||||||||||||
Equión(2) | - | - | - | - | |||||||||||||
Total | 62,774 | 37,608 | 3,005 | 2,967 |
(1) | In November 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields and took the position of operator since May 2020, this represents the increase in acreage related to Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production. |
(2) | Equion fields were in operation until February 2020. |
28
The following table sets for the expiration dates of material concentrations of the Company’s consolidated undeveloped acreage by geographic area as of December 31, 2020.
Table 19 – Undeveloped Production Acreage as of December 31, 2020 by Expiration Year
For the year ended December 31, | ||||||||||||||||||||||||||||||||||||||||
2021 | 2022 | 2023 | 2024 | 2025 and beyond | ||||||||||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||
(Acres) | ||||||||||||||||||||||||||||||||||||||||
COLOMBIA | ||||||||||||||||||||||||||||||||||||||||
Ecopetrol S.A. | - | - | - | - | - | - | - | - | 551,999 | 321,721 | ||||||||||||||||||||||||||||||
Hocol | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Equión(1) | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Total Colombia | - | - | - | - | - | - | - | - | 551,999 | 321,721 | ||||||||||||||||||||||||||||||
PERÚ | ||||||||||||||||||||||||||||||||||||||||
Savia Perú(2) | - | - | - | - | 57,671 | 28,836 | - | - | - | - | ||||||||||||||||||||||||||||||
Total Perú | - | - | - | - | 57,671 | 28,836 | - | - | - | - | ||||||||||||||||||||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||||||||||||||||||||||||||
Ecopetrol America LLC | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Ecopetrol Permian LLC | - | - | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||||||||
Total United States of America | - | - | - | - | - | - | - | - | - | - |
(1) | Equion fields were in operation until February 2020. |
(2) | Savia’s fields will end operation in November 2023 when the contract expires. |
Gross and Net Productive Wells
The following table sets forth our subsidiaries’ total gross and net productive wells in Colombia for the year ended December 31, 2019.2020.
Table 1720 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Productive Wells(1)(2)
For the year ended December 31, 2019 | For the year ended December 31, 2020 | |||||||||||||||||||||||||||||||
Crude Oil | Natural Gas | Crude Oil | Natural Gas | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net(3) | Gross | Net(3) | |||||||||||||||||||||||||
(number of wells) | (Number of wells) | |||||||||||||||||||||||||||||||
Hocol | 316 | 274.8 | 25 | 23.5 | 279.0 | 240.0 | 52.0 | 34.0 | ||||||||||||||||||||||||
Equion | 15 | 8 | 15 | 8 | ||||||||||||||||||||||||||||
Equión(5) | - | - | - | - | ||||||||||||||||||||||||||||
Total (Subsidiaries in Colombia) | 331 | 282.8 | 40 | 31.5 | 279.0 | 240.0 | 52.0 | 34.0 |
(1) | Information in the table above reflects productive wells that directly contribute to hydrocarbons production and therefore excludes wells used for injection, disposal, water abstraction or other similar activities. We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. Natural gas wells are those in which operations are directed only towards production of commercial gas. |
(2) | Includes only wells that were drilled and completed. |
(3) | Net wells correspond to the sum of wells entirely owned by us or our subsidiaries and our ownership percentage of wells owned in joint ventures with our partners. |
(4) | In November 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields and took the position of operator since May 2020, this represents the increase in the increase in Gross and Net Productive Natural Gas Wells. |
(5) | Equion fields were in operation until February 2020. |
Production Activities Outside Colombia |
The Ecopetrol Group’sIn 2020, the subsidiaries’ production outside of Colombia comescame from Ecopetrol America LLC, (73.3%), Rodeo (0.7%)Ecopetrol Permian LLC and of its share in the Peruvian company Savia (26%).Savia. In 2019,2020, the production obtained from these three companies was 17.7 mboed,21.4 thousand boepd, which represents 2.5% of the total production3.1% of the Ecopetrol Group.Group’s total production.
29
Crude Oil Production
The following table sets forth our average daily crude oil production outside Colombia, prior to deducting royalties, for the periods indicated.
Table 1821 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Crude Oil Production(1)
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(thousand bpd) | (Thousand bpd) | |||||||||||||||||||||||
Savia Perú | 3.5 | 3.9 | 3.9 | (1) | ||||||||||||||||||||
PERÚ | ||||||||||||||||||||||||
Savia Perú(1) | 3.11 | 3.50 | 3.90 | |||||||||||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||||||||||
Ecopetrol America LLC | 11.4 | 10.2 | 9.2 | 10.41 | 11.40 | 10.20 | ||||||||||||||||||
Rodeo Midland Basin LLC(2) | 0.1 | N.A. | N.A. | |||||||||||||||||||||
Ecopetrol Permian LLC | 3.85 | 0.10 | - | |||||||||||||||||||||
Total average daily crude oil production (International) | 15 | 14.1 | 13.1 | 17.37 | 15.00 | 14.10 |
(1) | In |
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 1922 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Natural Gas Production
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||
(thousand boepd) | Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | ||||||||||||||||||||||||||||||
Savia Perú | 0.9 | 1.1 | 1.1 | (1) | ||||||||||||||||||||||||||||||||
PERÚ | ||||||||||||||||||||||||||||||||||||
Savia Perú(1) | 0.91 | 2.44 | 0.90 | 3.99 | 1.10 | 2.90 | ||||||||||||||||||||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||||||||||||||||||||||
Ecopetrol America LLC | 1.8 | 1.8 | 2.0 | 1.78 | 10.15 | 1.80 | 10.26 | 1.80 | 10.30 | |||||||||||||||||||||||||||
Rodeo Midland Basin LLC(2) | 0.0 | N.A. | N.A. | |||||||||||||||||||||||||||||||||
Ecopetrol Permian LLC | 1.46 | 3.26 | - | - | - | - | ||||||||||||||||||||||||||||||
Total average daily natural gas production (International) | 2.7 | 2.9 | 3.1 | 4.15 | 15.85 | 2.70 | 14.30 | 2.90 | 13.10 |
(1) | In |
Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd. Conversion was done only in respect of natural gas, since natural gas liquids cannot be converted into mcfpd. Therefore, when the Company’s natural gas production is measured in boepd, it is higher as that includes natural gas and natural gas liquids. The Company’s sales of natural gas liquids represented less than 1% of the Company’s consolidated sales for the periods presented in this annual report.
30
Development Wells
The following table sets forth the number of gross and net development wells outside Colombia, drilled exclusively by us and in joint ventures for the periods indicated.
Table 2023 – 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 |
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Number of wells | Productive Wells | Dry Wells | Productive Wells | Dry Wells | Productive Wells | Dry Wells | ||||||||||||||||||
PERÚ | ||||||||||||||||||||||||
Savia Peru(2) | ||||||||||||||||||||||||
Gross development wells | - | - | - | - | - | - | ||||||||||||||||||
Net development wells(3) | - | - | - | - | - | - | ||||||||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||||||||||
Ecopetrol America LLC | ||||||||||||||||||||||||
Gross development wells | - | - | 2.0 | - | 1.0 | - | ||||||||||||||||||
Net development wells(3) | - | - | 0.5 | - | 0.3 | - | ||||||||||||||||||
Ecopetrol Permian LLC(4) | ||||||||||||||||||||||||
Gross development wells | 18.0 | - | 6.0 | - | - | - | ||||||||||||||||||
Net development wells(3) | 8.8 | - | 2.0 | - | - | - | ||||||||||||||||||
Total gross wells (International) | 18.0 | - | 8.0 | - | 1.0 | - | ||||||||||||||||||
Total net wells (International)(3) | 8.8 | - | 2.5 | - | 0.3 | - |
(1) |
(2) | In January 2021 Ecopetrol divested its 50% equity share in Savia Peru as the result of a competitive bidding process led jointly with its partner KNOC. |
(3) | Net wells correspond to the sum of wells entirely owned by us or our subsidiaries and our ownership percentage of wells owned in joint ventures with our partners. |
(4) | Includes only wells drilled and completed under direct operation by Occidental Petroleum Corp (OXY). Non-operated wells are not included because they are not considered material. Wells operated by others are not included because Ecopetrol’s share is not material. |
Table 24 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net In Process Wells
For the year ended December 31, 2020 | ||||||||||||||||
Drilled but not completed | Mobilization | Being drilled | Being completed | |||||||||||||
(Number of wells) | ||||||||||||||||
PERÚ | ||||||||||||||||
Savia Perú(1) | ||||||||||||||||
Gross in process wells | - | - | - | - | ||||||||||||
Net in process wells(2) | - | - | - | - | ||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||
Ecopetrol America LLC | ||||||||||||||||
Gross in process wells | - | - | - | - | ||||||||||||
Net in process wells(2) | - | - | - | - | ||||||||||||
Ecopetrol Permian LLC(3) | ||||||||||||||||
Gross in process wells | 18.0 | 2.0 | 2.0 | 3.0 | ||||||||||||
Net in process wells(2) | 8.8 | 1.0 | 1.0 | 1.5 | ||||||||||||
Total gross in process wells (International) | 18.0 | 2.0 | 2.0 | 3.0 | ||||||||||||
Total net in process wells (International)(2) | 8.8 | 1.0 | 1.0 | 1.5 |
(1) | In January 2021 Ecopetrol divested its 50% equity share in Savia Peru as the result of a competitive bidding process led jointly with its partner KNOC. |
(2) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
(3) |
31
Production Acreage
The following table sets forth our developed and undeveloped gross and net acreage of crude oil and natural gas production outside Colombia for the year ended December 31, 2019.2020.
Table 2125 – 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 |
For the year ended December 31, 2020 | ||||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
(Acres) | ||||||||||||||||
PERÚ | ||||||||||||||||
Savia Perú(1) | 79,575 | 39,787 | 57,671 | 28,836 | ||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||
Ecopetrol America LLC | 55,440 | 14,479 | 23,040 | 6,566 | ||||||||||||
Ecopetrol Permian LLC | 65,358 | 47,825 | 1,498 | 258 | ||||||||||||
Total (International) | 200,373 | 102,091 | 82,209 | 35,660 |
(1) |
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, 2019.2020.
Table 2226 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Productive Wells(1)(2)
As of December 31, 2019 | For the year ended December 31, 2020 | |||||||||||||||
Crude Oil | Crude Oil | |||||||||||||||
Gross | Net | Gross | Net(3) | |||||||||||||
(number of wells) | (Number of wells) | |||||||||||||||
INTERNATIONAL | ||||||||||||||||
PERÚ | ||||||||||||||||
Savia Perú | 601 | 300 | 599.0 | 299.5 | ||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||
Ecopetrol America LLC | 13 | 3.3 | 16.0 | 3.9 | ||||||||||||
Rodeo Midland Basin LLC | 6 | 2.0 | ||||||||||||||
Ecopetrol Permian LLC(5) | 22.0 | 10.8 | ||||||||||||||
Total (International) | 620 | 305.3 | 637.0 | 314.2 |
(1) | Includes only wells that were drilled and completed. |
(2) | Information in the table above reflects productive wells that directly contribute to hydrocarbons production and therefore excludes wells used for injection, disposal, water abstraction or other similar activities. We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. Natural gas wells are those in which operations are directed only towards production of commercial gas. |
(3) | Net wells correspond to the sum of wells entirely owned by us or our subsidiaries and our ownership percentage of wells owned in joint ventures with our partners. |
(4) | In January 2021 Ecopetrol S.A. divested its 50% equity share in Savia Peru as the result of a competitive bidding process led jointly with its partner KNOC. |
(5) | Includes only wells drilled and completed under direct operation by Occidental Petroleum Corp (OXY). Non-operated wells are not included because they are not material. |
32
Marketing of Crude Oil and Natural Gas |
In 2019,2020, Ecopetrol sold 928883 mboed, out of which 412425 mboed represented sales of crude oil (44%(48%), 8187 mboed of natural gas (9%(10%) and435 371 mboed of fuels and petrochemicals (47%(42%).
Crude Oil Export Sales
CrudeIn 2020, crude oil export sales in 2019 increased by13 mboed compared to 2018,2019, mainly due to higher production and an effective commercial strategy of domestic purchasesthe greater availability of crude from third parties.oil, supported by our sales and marketing strategy in response to lower crude oil runs at the refineries, which in turn was primarily due to a decrease in the domestic demand for fuels and refined products. Ecopetrol’s crude oil export sales are traded both in the spot and contract markets, primarily to refiners in the United States and Asia.
The Castilla blend is the main type of crude oil for export sales, with 367371 mboed sold during 20192020 (a 91%89% share of ourthe crude oil basket) followed by Vasconia with 24 mboed (a 6% share of the crude oil basket), the domestic crudes sold by Ecopetrol America LLC with 108 mboed, (a 2.5% share in our crude oil basket), Mares blend with 9 mbopd (a 2.2%2% share of ourthe crude oil basket), and Apiay BlendMares blend with 7 mboed (a 1.8%2% share of ourthe crude oil basket).
Ecopetrol places its exports in markets that provide the best value for its crudes. In 2019,2020, Asia was the main destination, representing46.3% 49% of crude oil exports, closely followed by the United States with 42%43%. The expansion of refining capacity in countries like China hasas well as the fast recovery in crude demand of key refining hubs in Asia after lockdown measures to curb the spread of the COVID-19 pandemic were eased in Asia have supported the increase of crude oil flows from Colombia to Asia.
Moreover, volatility in the production of regional competitors has given US refiners in the United States, India and other markets an incentive to diversify their supply sources, which in turn has opened opportunities for Colombian producers. Ecopetrol’s crude basket discount versus ICE Brent price was on average US$ 5.6/Bl. Our crude basket increasedrealization price decreased by US$ 2.9/24/Bl year over year due to market conditions and our commercial strategy focused on markets with higher value.stemming from the effects of the COVID-19 pandemic mentioned above.
Crude Oil Purchase Contracts
Ecopetrol has signed several crude oil purchase contracts with third parties and business partners. Ecopetrol also purchases the country’s crude oil royalties from the National Hydrocarbon Agency (ANH). This oil isHydrocarbons Agency. These crudes are processed in Ecopetrol’s refineries or exported. The purchase price is referenced to export parity based on international market prices, plus a commercial fee. See sectionBusiness Overview—Related Party and Intercompany Transactions.
The table below sets forth the volumes of crude oil purchased from our business partners and third parties and volumes of crude oil purchased from the ANH from royalties for the years ended on December 31, 2020, 2019 2018 and 2017.2018.
Table 2327 – Ecopetrol Consolidated Crude Oil Purchases
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(million barrels) | (Million barrels) | |||||||||||||||||||||||
Ecopetrol Group | ||||||||||||||||||||||||
Crude oil purchased from ANH royalties | 35.4 | 37.6 | 40.3 | 31.0 | 35.4 | 37.6 | ||||||||||||||||||
Crude oil purchased from third parties | 30.0 | 20.7 | 16.7 | 34.0 | 30.0 | 20.7 | ||||||||||||||||||
Crude oil imported from third parties | 9.1 | 14.0 | 24.8 | 5.6 | 9.1 | 14.0 |
33
During 2019,2020, part of Ecopetrol’s crude strategy was centered on increasing the purchase and subsequent commercialization of crude oil from third parties, which enables further optimization of the supply chain and should allow us to capture enhanced margins.margin capture.
Import of Diluents
In 2019,2020, Ecopetrol increaseddecreased the imports of diluent by 1.2 % (0.6 mbpd)32% (17 mbod) compared to 20182019, due to higher production.the use of domestic produced naphtha. 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)2% (2.9 mboed) compared to 2018,2019, due to higher production.production primarily as a result of Hocol’s acquisition of Chevron’s interest in the Guajira association contract.
Natural Gas Delivery Commitments
The table below sets forth the commitments we have in Colombia under firm contracts with local natural gas distribution companies, local industries, gas-fired power generators and internal agreements with our refineries and fields.
Table 2428 – Ecopetrol Consolidated Natural Gas Delivery Commitments
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||||||||||
2020 | 2021 | 2022 | 2023 | 2021 | 2022 | 2023 | 2024 | |||||||||||||||||||||||||
(gbtud) | (gbtud) | |||||||||||||||||||||||||||||||
Volume for sales third parties | 586.9 | 554.8 | 377.9 | 325.1 | 503.3 | 483.3 | 420.9 | 311.1 | ||||||||||||||||||||||||
Volume for self-consumption | 207.7 | 226.8 | 235.7 | 238.9 | 188.2 | 169.4 | 160.9 | 157.1 | ||||||||||||||||||||||||
Volume for intercompany sales | 89.4 | 18.5 | 18.5 | 16.8 | ||||||||||||||||||||||||||||
Total Commitments | 794.6 | 781.6 | 613.6 | 564.0 | 780.9 | 671.2 | 600.3 | 485.0 |
Data was updatedThe table above is based on current contracts of Ecopetrol S.A. and the official report made to the Ministry of Mines and Energy in 2019.2020. Self-consumption volumes decreased over time as a result of more efficient operations in our refineries. Third party volumes do not include potential production coming from exploratory projects. According to current regulations, these volumes will be committed and commercialized after declaring exploratory success.
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, 2019,2020, are based on the average prices during the 12-month period prior to the ending date of the period covered in this annual report, determined as the unweighted arithmetic averages of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.
Our crude oil and natural gas net proved reserves include reserves from our subsidiaries located in the United States and Peru, and Equion andfrom Hocol’s assets in Colombia.
34
Estimated Net Proved Reserves
The following table sets forth our estimated net proved developed reserves of crude oil and gas by region for the years ended December 31, 2020, 2019 2018 and 2017.2018.
Table 2529 – Net Proved Developed Reserves
Net Proved Developed Reserves | Colombia | North America | South America excluding Colombia | Total | ||||||||||||||||||||||||||||
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, 2020(1) | 757.4 | 16.3 | 2.3 | 776.0 | ||||||||||||||||||||||||||||
At December 31, 2019 | 832.0 | 12.0 | 3.8 | 848.0 | ||||||||||||||||||||||||||||
At December 31, 2018 | 814 | 13 | 5 | 832 | 814.0 | 13.0 | 5.0 | 832.0 | ||||||||||||||||||||||||
Net Proved Developed NGL reserves in million barrels oil equivalent | ||||||||||||||||||||||||||||||||
At December 31, 2020 | 57.0 | 1.1 | 0.4 | 58.0 | ||||||||||||||||||||||||||||
At December 31, 2019 | 832 | 12 | 3.8 | 848 | 49.0 | 0.1 | 0.5 | 50.0 | ||||||||||||||||||||||||
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 | 50.5 | - | 0.6 | 51.1 | ||||||||||||||||||||||||
Net Proved Developed gas reserves in billion standard cubic feet | ||||||||||||||||||||||||||||||||
At December 31, 2020(2) | 2,617.0 | 15.0 | 4.4 | 2,636.4 | ||||||||||||||||||||||||||||
At December 31, 2019 | 49 | 0.12 | 0.5 | 50 | 2,645.0 | 11.0 | 7.0 | 2,662.0 | ||||||||||||||||||||||||
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 | 2,865.5 | 10.0 | 7.0 | 2,882.5 | ||||||||||||||||||||||||
Net Proved Developed oil, NGL and gas reserves in million barrels oil equivalent | ||||||||||||||||||||||||||||||||
At December 31, 2020 | 1,273.3 | 20.0 | 3.5 | 1,296.8 | ||||||||||||||||||||||||||||
At December 31, 2019 | 2,645 | 11 | 7 | 2,662 | 1,345.0 | 14.0 | 6.0 | 1,365.0 | ||||||||||||||||||||||||
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 | 1,368.0 | 14.0 | 7.0 | 1,389.0 | ||||||||||||||||||||||||
At December 31, 2019 | 1,345 | 14 | 6 | 1,365 |
Gas Reserves included 381 bcf of Fuel Gas
(1) | Oil Reserves included 14 million barrels of Fuel Oil. |
Oil Reserves included 17 million barrels of Fuel Oil
(2) | Gas Reserves included 411 bcf of Fuel Gas. |
Totals may not exactly equal the sum of the individual entries due to rounding
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.Gibraltar.
Ecopetrol S.A. owns 100% of Cenit, a subsidiary that operates in Colombia and is dedicated to the storage and transportation of hydrocarbons through pipelines. Cenit provides transportation services for the entire Ecopetrol Group and we fully consolidate Cenit into our consolidated results of operations. Therefore, the difference between the tariffs set by the Ministry of Mines and Energy and the real transportation costs (fixed and variable operating expenses) does not affect our consolidated income statement. Thus, in presenting our reserves information in the 2017, 2018, 2019 and 20192020 annual reports, we have used our real transportation costs, rather than the regular tariffs set by the Ministry of Mines and Energy.
35
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 14 million barrels of fuel oil, 411 billion standard cubic feet of fuel gas within our natural gas results and 429 billion cubic feet of royalties, as of December 31, 2020.
Table 30 – Proved Oil, NGL and Natural Gas Reserves for 2020
Oil (mmb) | NGL (mmb) | Natural Gas (bcf) | Total Oil and Gas (mmboe) | |||||||||||||
PROVED DEVELOPED RESERVES | ||||||||||||||||
Colombia | 757.4 | 56.8 | 2,617.0 | 1,273.3 | ||||||||||||
International | ||||||||||||||||
North America | 16.3 | 1.1 | 15.0 | 20.0 | ||||||||||||
South America(1) | 2.3 | 0.4 | 4.4 | 3.5 | ||||||||||||
TOTAL PROVED DEVELOPED RESERVES | 776.0 | 58.2 | 2,636.4 | 1,296.8 | ||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||
Colombia | 290.5 | 6.1 | 179.9 | 328.2 | ||||||||||||
International | ||||||||||||||||
North America | 105.8 | 21.0 | 105.1 | 145.2 | ||||||||||||
South America(1) | - | - | - | - | ||||||||||||
TOTAL PROVED UNDEVELOPED RESERVES | 396.4 | 27.1 | 285.0 | 473.4 | ||||||||||||
TOTAL PROVED RESERVES | 1,172.4 | 85.3 | 2,921.5 | 1,770.2 |
(1) | The reserves in South America include participation in Savia Peru, where we sold our interest on January 19, 2021. |
Note: Totals may not exactly equal the sum of the individual entries due to rounding. The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 17 million barrels of fuel oil, 381 billion standard cubic feet of fuel gas within our natural gas results and 517 billion cubic feet of royalties, as of December 31, 2019.
Table 2631 – 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) | ||||||||||||||||||||||||||||
Oil (mmb) | NGL (mmb) | Natural Gas (bcf) | Total Oil and Gas (mmboe) | |||||||||||||||||||||||||||||
PROVED DEVELOPED RESERVES | ||||||||||||||||||||||||||||||||
Total (Colombia) | 832 | 49 | 2,645 | 1,345 | ||||||||||||||||||||||||||||
International: | ||||||||||||||||||||||||||||||||
Colombia | 832.0 | 49.0 | 2,645.0 | 1,345.0 | ||||||||||||||||||||||||||||
International | ||||||||||||||||||||||||||||||||
North America | 12 | 0.12 | 11 | 14 | 12.0 | 0.1 | 11.0 | 14.0 | ||||||||||||||||||||||||
South America | 3.8 | 0.5 | 7.0 | 6.0 | 3.8 | 0.5 | 7.0 | 6.0 | ||||||||||||||||||||||||
TOTAL PROVED DEVELOPED RESERVES | 848 | 50 | 2,662 | 1,365 | 847.8 | 50.0 | 2,662.0 | 1,365.0 | ||||||||||||||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||||||||||||||||||
Total (Colombia) | 306 | 28 | 111 | 353 | ||||||||||||||||||||||||||||
International: | ||||||||||||||||||||||||||||||||
Colombia | 306.0 | 28.0 | 111.0 | 353.0 | ||||||||||||||||||||||||||||
International | ||||||||||||||||||||||||||||||||
North America | 123 | 29 | 133 | 175 | 123.0 | 29.0 | 133.0 | 175.0 | ||||||||||||||||||||||||
South America | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
TOTAL PROVED UNDEVELOPED RESERVES | 429 | 57 | 244 | 529 | 429.0 | 57.0 | 244.0 | 529.0 | ||||||||||||||||||||||||
TOTAL PROVED RESERVES | 1,277 | 107 | 2,906 | 1,893 | 1,277.0 | 107.0 | 2,906.0 | 1,893.0 |
Note: Totals may not exactly equal the sum of the individual entries due to rounding
rounding. The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
36
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 16 million barrels of fuel oil, 327 billion standard cubic feet of fuel gas within our natural gas results and 534 billion cubic feet of royalties, as of December 31, 2018.
Table 2732 – 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) | ||||||||||||||||||||||||||||
Oil (mmb) | NGL (mmb) | Natural Gas (bcf) | Total Oil and Gas (mmboe) | |||||||||||||||||||||||||||||
PROVED DEVELOPED RESERVES | ||||||||||||||||||||||||||||||||
Total (Colombia) | 814 | 50.5 | 2,866 | 1,368 | ||||||||||||||||||||||||||||
International: | ||||||||||||||||||||||||||||||||
Colombia | 814.0 | 50.5 | 2,866.0 | 1,368.0 | ||||||||||||||||||||||||||||
International | ||||||||||||||||||||||||||||||||
North America | 13 | - | 10 | 14 | 13.0 | - | 10.0 | 14.0 | ||||||||||||||||||||||||
South America | 5 | 0.5 | 7 | 7 | 5.0 | 0.5 | 7.0 | 7.0 | ||||||||||||||||||||||||
TOTAL PROVED DEVELOPED RESERVES | 832 | 51 | 2,883 | 1,389 | 832.0 | 51.0 | 2,883.0 | 1,389.0 | ||||||||||||||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||||||||||||||||||
Total (Colombia) | 285 | 22 | 113 | 327 | ||||||||||||||||||||||||||||
International: | ||||||||||||||||||||||||||||||||
Colombia | 285.0 | 22.0 | 113.0 | 327.0 | ||||||||||||||||||||||||||||
International | ||||||||||||||||||||||||||||||||
North America | 10 | - | 6 | 11 | 10.0 | - | 6.0 | 11.0 | ||||||||||||||||||||||||
South America | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
TOTAL PROVED UNDEVELOPED RESERVES | 295 | 22 | 119 | 338 | 295.0 | 22.0 | 119.0 | 338.0 | ||||||||||||||||||||||||
TOTAL PROVED RESERVES | 1,127 | 73 | 3,002 | 1,727 | 1,127.0 | 73.0 | 3,002.0 | 1,727.0 |
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 |
Note: The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
Changes in Proved Reserves
Table 33 – Changes in Proved Reserves
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Mmboe) | ||||||||||||
Revisions of previous estimates | (71.5 | ) | 83.0 | 120.5 | ||||||||
Improved Recovery | 113.1 | 94.0 | 129.1 | |||||||||
Extensions and discoveries | 42.7 | 67.0 | 57.4 | |||||||||
Purchases | 29.9 | 164.0 | - | |||||||||
Sales | (1.0 | ) | - | - | ||||||||
Total reserves additions | 113.2 | 408.0 | 307.0 | |||||||||
Production | (236.3 | ) | (242.0 | ) | (239.0 | ) | ||||||
Net change in proved reserves | (123.0 | ) | 166.0 | 68.0 |
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Reserves Replacement
The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves divided by produced volumes in any given period. The following table presents the changes in reserves in each category relating to the reserve replacement ratio for the years 2020, 2019 2018 and 2017.2018.
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 20192020 was 1.69 barrels48% compared to 1.29 barrels169% in 20182019 and 1.26 barrels129% in 2017. 2018.
The average replacement ratio for the last three years was 1.4 barrels.115%.
Table 3034 – Reserves Replacement Ratio (including purchase(Including Purchases and sales)Sales)
As of December 31, | For the year ended December 31, | ||||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | ||||||||||||||||||||
Annual | 1.69 | 1.29 | 1.26 | 48 | % | 169 | % | 129 | % | ||||||||||||||||
Three year average | 1.4 | 0.83 | 0.42 | ||||||||||||||||||||||
Three-year average | 115 | % | 140 | % | 83 | % |
Revisions of Previous Estimates
In 2020, revisions decreased reserves by 71 million boe, mainly as a result of:
(i) | A 215 million boe decrease attributed to economic factors and reevaluated projects. More specifically, we were negatively impacted by the substantial decrease in oil prices, with the ICE Brent crude price being 32% lower in 2020 as compared to 2019, which resulted in the lowering of economic limits in some of our fields and some projects becoming uneconomical under SEC standards. |
(ii) | An offsetting positive 114 million boe increase in reserves related to new projects in the Caño Sur, Quifa, Cusiana, Pauto and Rubiales fields as well as new areas included in the approved five-year development plan for our North American fields. |
(iii) | An offsetting positive 30 million boe increase related to field performance studies and development activities in existing fields. |
In 2019, revisions increased reserves by 83 million boe, mainly as a result of:
(i) | An increase of 33 million boe due toimproved reservoir performance in the Rubiales field and continuous development with drilling activities. |
(ii) | An increase of 36 million boe in reserves due to the review of the curve type of new development activities according to updated new wells results in the Caño Sur field and additional gas processing plant capacity to extract NGL in the Cupiagua field. |
(iii) |
Nonetheless, due to the decrease in oil price compared to the Brent reference price used in the reserve estimation process at $63 per barrel in 2019 (as compared to $72 per barrel in 2018), the Company removed volumes of total proved reserves in the amount of 19 million boe, which have become uneconomical. This impact was partially offset by improved reservoir performance and new projects in several fields.
In 2018, revisions increased reserves by 120121 million boe, mainly as a result of:
(i) | An increase of 87 million boe due to the continuous development of the Rubiales, Chichimene and Quifa fields, of which a 68 million boe increase in reserves is due to improved reservoir performance in the Rubiales field. |
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(ii) | An increase 14 million boe increase in reserves due to development activities in the Bonanza and Ocelote fields. |
(iii) |
Improved Recovery
In 2017, revisions2020, improved recovery activities increased reserves by 175113 million boe, mainly as a result of:
Improved Recoveryboe. This increase was associated with new proved areas under water flooding in the Chichimene and Castilla fields, and optimization of the gas injection and blowdown strategy of the Cupiagua field.
In 2019, improved recovery increased reserves by 94 million boe. An increase of 25 million boe was associated with new proved areas under water flooding in the Chichimene and Akacias fields. Furthermore, the continued development of water flooding projects at existing wells in the Castilla, Chichimene, Yarigui, La Cira-Infantas fields accounted for a 45 million boe increase. The remaining 26%, or 24 million boe, increase was due primarily to water injection reservoir responses at various fields.
In 2018, improved recovery increased reserves by 129 million boe. The additions were associated with new proved areas under water flooding in the Chichimene, Castilla, La Cira-Infantas, Apiay, Suria, Yarigui, Casabe and Dina Cretaceo fields (86 million boe increase). In addition, the new steam injection project at the Teca-Cocorná field accounted for a 19 million boe increase in reserves. The remaining 19%, or 24 million boe, increase was due primarily to water injection reservoir responses at various fields.
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 98.7112 million boe each year over the last three years.
Extensions and Discoveries
The following table sets forth the change in the Company’s proved reserves attributed to extensions and discoveries in millions of boe for the periods indicated.
Table 35 – Changes in Proved Reserves Attributed to Extensions and Discoveries
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Mmboe) | ||||||||||||
Extensions and discoveries | ||||||||||||
Total change | 42.7 | 67.0 | 57.4 | |||||||||
Proved Undeveloped Reserves Change | 14.6 | 34.0 | 39.9 | |||||||||
Change from unproved to proved developed reserves | 28.0 | 33.0 | 17.5 |
The difference between the change of developed proved reserves and undeveloped proved reserves is related to the drilling of new wells in unproved acreage that led to new proved producing reserves.
The Company’s extensions and discoveries during 2020 amounted to 43 million boe primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Suria, Yarigui and Llanito fields (accounting for 38.5 million boe of the total change) and newly discovered fields Andina and Esox (accounting for 4 million boe of the total change). The Company’s extensions and discoveries during 2019 amounted to 67 million boe primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Quifa, Suria, Tisquirama, Cupiagua Sur, Castilla and Garza’sGarzas fields which accounted(accounting for 3555 million of the total of 67boe). The remaining 12 million boe from extensions of proved acreage. The remaining 32 million boe correspondscorresponded to smaller changes in several other fields.26 fields with variations between 0.01 to 2.1 million boe.
39
ExtensionsThe Company’s extensions and discoveries during 2018 amounted to 57 million boe primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Castilla, Cupiagua, Pauto and Caño Sur fields which accounted(accounting for 45 million boeboe) and newly discovered fields and reservoirs accounted(accounting for 12 million boe.boe). The remaining 9 million boe correspondscorresponded to smaller changes in several other fields.
Extensions and discoveries during 2017 amounted to 44 million boe primarily due to extensionsPurchases
Starting May 2020, Hocol S.A. took on the position of proved acreage mainly from activitiesoperator of the Guajira Contract, after the approval of the transaction in new proved areaswhich Ecopetrol S.A. through its wholly owned subsidiary, Hocol S.A., acquired 100% of Chevron Petroleum Company’s participation in the Rubiales, Castilla, Pauto, Cajuacontract (comprising the Ballena and ArrayanChuchupa fields in Colombia which accounted for 39 million boecorresponds to 43% of the total of 44contract). This purchase increased proved reserves by 29.9 million boe from extensions of proved acreage. The remaining 5 million boe corresponds to smaller changes in several other fields.boe.
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 beis 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 pursueare pursuing development of unconventional reservoirs in approximately 97,000 acres of the Permian Basin in Texas. For the acquisition and closing of the transaction, Ecopetrol S.A. made an initial payment of approximately US$876.5US $876.5 million dollars. As of December 31, 2020, Ecopetrol had paid a total of US$ 121.8 million of the initial US$ 750 million carry obligation.
There were no purchases or acquisitions in 2018.
Sales
Pursuant to a public auction process carried out by Ecopetrol S.A.’s purchasesand Hocol in December 2020, an offer was received from Cordillera Resources SAS, Nikoil Energy Corp and Petroleum Blending International for 100% of minerals in 2017 included the acquisition of an additional participation of 11.6%our working interest in the K2 Field by Ecopetrol America LLCLa Punta and Santo-Domingo fields, which represented 4 million boe.was declared the winning offer. We are now pending approval of such sale from the ANH, a process that typically takes 18 months. Based on that timing, we do not expect the formal approval to be received until July 2022.
Development of reserves
As of December 31, 2020, our total proved undeveloped oil and gas reserves amounted to 473 million boe, 69% of which is related to development activities at the Rubiales, Castilla and Chichimene fields in Colombia, among others, and 31% of which is related to development activities in North American fields.
Ecopetrol’s year-end development plans are consistent with SEC guidelines for the development of proved undeveloped reserves within five years. The development plan of Rubiales Field goes beyond the five years due to the water disposal restrictions in the facilities. The drilling of two wells in the United States Gulf of Mexico and one well onshore in Colombia also goes beyond five years due to drilling schedule. These wells are part of the ongoing development projects and all remaining development investments for the latter three wells will be completed within six years from their initial disclosure. These exemptions were reviewed and approved by the external certification agent.
As of December 31, 2019, our total proved undeveloped oil and gas reserves amounted to 529 million boe, 46% of which is related to development activities in the Rubiales, Castilla, Caño Sur Chichimene, Teca, Akacias and Pauto fields and 31% of which is related to development of unconventional reservoirs of the U.S. Permian Basin in Texas. The remaining 23% comes from activities at several other fields.
In 2019, Ecopetrol’s year-end development plans arewere consistent with SEC guidelines for the development of proved undeveloped reserves within five years. The development plan of Rubiales Field goeswent beyond the 5five years due to the limitations in water handling in the facilities. This exemption wasThese exemptions were reviewed and approved by the external certification agent.
40
As of December 31, 2018, our total proved undeveloped oil and gas reserves amounted to 338 million boe, 21% of which is related to new drilling activities in the Rubiales field, 41% is related to development activities in the Castilla, Caño Sur, Chichimene, Quifa, Cupiagua and Yarigui fields and 22% of which is related to the new development activities in the Teca, Pauto, Bonanza and Ryberg fields. The remaining 16% comes from activities at several other fields.
In 2018, the development plan of Rubiales and Caño Sur Field went beyond 5 years due to the limitations in water handling in the facilities and Ryberg offshore field. These exemptions were reviewed by the external certification agent.
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%27% of our total proved reserves as of December 31, 2020, 28% as of December 31, 2019, and 20% as of December 31, 2018 and 17% as of December 31, 2017.2018.
The following table reflects the developed and undeveloped proved reserves estimates through the past three fiscal years.
Table 3136 – Developed and Undeveloped Proved Reserves
Oil | NGL | Gas | Total | Oil (mmb) | NGL (mmb) | Natural Gas (bcf) | Total Oil and Gas (mmboe) | |||||||||||||||||||||||||
Proved Reserves as of December 31, | Mmbls | Mmbls | Bcf | Mmboe | ||||||||||||||||||||||||||||
2019 proved reserves | ||||||||||||||||||||||||||||||||
2020 Proved Reserves | ||||||||||||||||||||||||||||||||
Developed | 848 | 50 | 2,662 | 1,365 | 776 | 58 | 2,636 | 1,297 | ||||||||||||||||||||||||
Undeveloped | 429 | 57 | 244 | 529 | 396 | 27 | 285 | 473 | ||||||||||||||||||||||||
2018 proved reserves | ||||||||||||||||||||||||||||||||
2019 Proved Reserves | ||||||||||||||||||||||||||||||||
Developed | 832 | 51 | 2,882 | 1,389 | 848 | 50 | 2,662 | 1,365 | ||||||||||||||||||||||||
Undeveloped | 295 | 23 | 119 | 338 | 429 | 57 | 244 | 529 | ||||||||||||||||||||||||
2017 proved reserves | ||||||||||||||||||||||||||||||||
2018 Proved Reserves | ||||||||||||||||||||||||||||||||
Developed | 763 | 55 | 3,158 | 1,372 | 832 | 51 | 2,882 | 1,389 | ||||||||||||||||||||||||
Undeveloped | 251 | 19 | 96 | 287 | 295 | 23 | 119 | 338 |
Of the total amount of proved undeveloped reserves that Ecopetrol had at the end of 2019 (529 million boe), we converted approximately 69 million boe, or 13%, to proven developed reserves during 2020. Approximately 86% of the total conversion is mainly associated with the development of crude oil and gas projects in the Castilla, Rubiales, and Cupiagua fields, among others, and 14% is associated with development execution in fields, such as the Ocelote field, among others. The amount of investments made during 2020 to convert proved undeveloped reserves to proved developed reserves was US$353 million.
Of the total amount of proved undeveloped reserves that Ecopetrol had at the end of 2018 (338 million boe), we converted approximately 89 million boe, or 26%, to proven developed reserves during 2019. Approximately 75% of the total conversion is primarily associated with the development of crude oil and gas projects in the Castilla, Rubiales, Chichimene and Yarigui fields (67 million boe), while the remaining 25% is associated with development execution in other fields such as the Suria, Casabe, Quifa, Caño Sur and Ocelote fields, among others. The amount of investments made during 2019 to convert proved undeveloped reserves to proved developed reserves was US$791 million.
Of the total amount of proved undeveloped reserves that Ecopetrol had at the end of 2017 (287 million boe), we converted approximately 84 million boe, or 29%, to proven developed reserves during 2018. Approximately 69% of the total conversion is primarily associated with the development of crude oil and gas projects in the Castilla, Rubiales and Chichimene fields (58 million boe), while the remaining 31% is associated with development execution in other fields such as the Ocelote, La Cira-Infantas, Caño Sur and K2 fields, among others. The amount of investments made during 2018 to convert proved undeveloped reserves to proved developed reserves was US$841 million.
41
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, 2020, 2019 2018 and 2017.2018.
Table 3237 – Changes in Undeveloped Proved Reserves
As of December 31, | For the year ended December 31, | |||||||||||||||||||||||
Consolidated Companies (million barrels oil equivalent) | 2019 | 2018 | 2017 | |||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
(Mmboe) | ||||||||||||||||||||||||
Consolidated companies | ||||||||||||||||||||||||
Revisions of previous estimates | 43 | 28.4 | 9 | (46.3 | ) | 43.0 | 28.4 | |||||||||||||||||
Improved recovery | 40 | 67.1 | 36 | |||||||||||||||||||||
Improved Recovery | 45.9 | 40.0 | 67.1 | |||||||||||||||||||||
Extensions and discoveries | 34 | 39.9 | 25 | 14.6 | 34.0 | 39.9 | ||||||||||||||||||
Purchases | 163 | - | - | - | 163.0 | - | ||||||||||||||||||
Proved Undeveloped converted to Proved Developed | (89 | ) | (83.7 | ) | (53 | ) | ||||||||||||||||||
Proved undeveloped converted to proved developed | (69.4 | ) | (89.0 | ) | (83.7 | ) | ||||||||||||||||||
Net change in unproved reserves | 190 | 51.7 | 17 | (55.2 | ) | 190.0 | 51.7 |
Note: The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent. Totals may not exactly equal the sum of the individual entries due to rounding.
Rounded figures
Undeveloped Proved converted to Developed Proved: Of the total amount of undeveloped proved reserves that Ecopetrol had at the end of 2019 (529 million boe), we converted approximately 69 million boe, or 13%, to developed proved reserves during 2020. Approximately 86% of the total conversion was primarily associated with the development of crude oil and gas projects in Ecopetrol S.A Fields as Castilla, Rubiales and Cupiagua fields, among others and 14% was associated with development execution in fields where our subsidiaries are operating.
Reserve
All the explanations that were included in Changes in Proved Reserves apply for this section.
Reserves Process
Ecopetrol’s reserves process is coordinated by Fidel Antonio Delgado Loría the Corporate Resources and Reserves Manager, Manager. Mr. Delgado Loría highly experienced engineer, whois a Petroleum Engineer with over 19 years of experience in the upstream sector of production business in Ecopetrol and other companies in the industry in Colombia and Venezuela. He received his engineering degree from Universidad Central de Venezuela. He reports to the Upstream Chief Financial Officer. TheIn addition, the Ecopetrol reserves groupteam is comprised of reserves coordinators who are geologistgeologists and petroleum engineers, each of them with more than tenfifteen years of experience in reservoir characterization, field development, estimation and reporting of reserves by SEC Guidelines. This team supports and who support and interactinteracts 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, (thisthis year consisting of Ryder Scott Company,DeGolyer and MacNaughton, Gaffney Cline & Associates Sproule International Limited, , Netherland, Sewell & Associates, Inc., Ryder Scott Company, and DeGolyer and MacNaughton)Sproule International Limited, in compliance with the definitions of the Society of Petroleum Engineers and the applicable SEC rules. According to our corporate policy, we report the reserves values obtained from the external engineers, even if they are lower than our expected reserves.
The reserves estimation process ends when the Corporate Reserves Manager consolidates the results and together, with the Development Vice-President and the Upstream Chief Financial Officer, presents the outcome to the Reserves Committee, which comprises the Ecopetrol Group’s CEO, the Group’s CFO and the Vice-President of Development and Production.Production, among others. Results are later presented to the Audit and Risk Committee of the Board of Directors and finally reviewed and approved by the Board of Directors.
PetroleumThe aforementioned external independent 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, 2019.2020. These external engineers estimated 99% of our estimated net proved reserves for the year ended December 31, 2020, 2019 2018 and 2017.2018. The reserves reports of the external engineers are included as exhibits to this annual report.
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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, 20172018 through 2019,2020, and the changes therein.
Table 3338 – 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 | Colombia | North America | South America excluding Colombia | Total | ||||||||||||||||||||||||||||
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 | ) | ||||||||||||||||||||||||
Consolidated Companies | Net proved oil, NGL and gas reserves in mmboe | |||||||||||||||||||||||||||||||
At December 31, 2018 | 1,695 | 25 | 7.2 | 1,727.2 | 1,695.0 | 25.0 | 7.2 | 1,727.2 | ||||||||||||||||||||||||
Revisions | 78.4 | 4.3 | 0.2 | 83 | 78.4 | 4.3 | 0.2 | 83.0 | ||||||||||||||||||||||||
Improved Recovery | 94.3 | - | - | 94 | 94.3 | - | - | 94.0 | ||||||||||||||||||||||||
Extensions and discoveries | 66 | 0.7 | - | 67 | ||||||||||||||||||||||||||||
Extensions and Discoveries | 66.0 | 0.7 | - | 67.0 | ||||||||||||||||||||||||||||
Purchases | - | 164 | - | 164 | - | 164.0 | - | 164.0 | ||||||||||||||||||||||||
Production | (236 | ) | (4.2 | ) | (1.4 | ) | (242 | ) | (236.0 | ) | (4.2 | ) | (1.4 | ) | (242.0 | ) | ||||||||||||||||
At December 31, 2019 | 1,698 | 189.7 | 6 | 1,893 | 1,698.0 | 189.7 | 5.6 | 1,893.0 | ||||||||||||||||||||||||
Revisions | (49.8 | ) | (20.8 | ) | (0.9 | ) | (71.5 | ) | ||||||||||||||||||||||||
Improved Recovery | 113.1 | - | - | 113.1 | ||||||||||||||||||||||||||||
Extensions and Discoveries | 40.8 | 1.8 | - | 42.7 | ||||||||||||||||||||||||||||
Purchases | 29.9 | - | - | 29.9 | ||||||||||||||||||||||||||||
Sales | (1.0 | ) | - | - | (1.0 | ) | ||||||||||||||||||||||||||
Production | (229.6 | ) | (5.6 | ) | (1.2 | ) | (236.3 | ) | ||||||||||||||||||||||||
At December 31, 2020 | 1,601.1 | 165.1 | 3.5 | 1,770.2 |
Note: Totals may not exactly equal the sum of the individual entries due to rounding. For more information regarding the potential impacts of oil prices on our reserve estimates, see the sectionsFinancial Review—Review—Trend Analysis and Sensitivity Analysis andRisk Review—Review—Risk Factors.
Rounded figures
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 typetypes of contractual arrangementarrangements to which we were a party as of December 31, 2019.2020.
Association Contract
The purpose of this type of contract, created by Decree 2310 of 1974, is the exploration of the areas covered by the contract, and the exploitation of hydrocarbons found in that area. This type of contract, together with E&P contracts and Special Contracts (Casabe, La Cira and Teca-Cocorná fields) which are described below, are the most significant in terms of our production and proved reserves.
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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,”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, andwhich 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 Contractfor 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.
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Joint Venture Contracts for Exploration and Exploitation of “La Cira-Infantas” Area and of “Teca-Cocorná” Area
These contracts between Ecopetrol S.A. and SierraCol Energy, formerly known as Occidental Andina LLC, which were executed on September 6, 2005 and June 24, 2014, respectively, have as their purpose, a joint collaboration between the parties with the goal of increasing the economic value of the La Cira-Infantas fieldfields 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.SierraCol Energy. Additionally, pursuant to these contracts, Ecopetrol S.A. provides financial resources and the preferential rights of use for the existing infrastructure in that zone and Occidental Andina LLCSierraCol Energy provides financial resources and the technical and operative experience in mature fields redevelopment projects and enhanced recovery technologies.
Ecopetrol S.A. is the operator under both Joint Venture Contracts, and on behalf of the parties is responsible for the conduction, execution and control, directly or via contractors, of the operational activities.
The La Cira-Infantas contract’scontract term is divided in three phases. The first phase lasts 180 days, the second 730 days and the third phase lasts up to the economical limit.limit of the field.
The incremental production, after deduction of the royalties, is owned 52% by Ecopetrol S.A. and 48% by Occidental Andina LLC.SierraCol Energy. These same percentages apply to the participation in the operational and direct expenses. Adjustments to the participations for the benefit of Ecopetrol S.A. will occur if there are high production levels or high prices.
The Teca-Cocorná contract’scontract term is divided in two phases. The first phase lasts three years, extendable for up to an additional year, the second term is 20 years 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.SierraCol Energy. These same percentages apply to the participation in the operational and direct expenses. Adjustments to the participations for the benefit of Ecopetrol S.A. will occur if there are high production levels and high prices.
Services and Technical Collaboration Contract “Casabe”
The purpose of the contract executed between Ecopetrol S.A. and Schlumberger Surenco S.A. on April 26, 2004, iswas 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. iswas the operator and Schlumberger Surenco S.A. keepskept the right of first option regarding the activities to be executed in the area of interest.
Both parties cancould invest in all the activities seeking to evaluate, obtain and incorporate incremental value in the area of interest. Such activities arewere developed directly by the parties or via contractors (Ecopetrol) or subcontractors (Schlumberger). Amounts expended pursuant to the contract arewere 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. commitcommitted 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 ManagementExecutive Committee.
The contract had an initial term of 10 years and was amended several times to include an additional term of six years for which a new business was structured. The contract ended in April 2020 and is currently in liquidation.
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The National Hydrocarbons Agency (ANH)(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, theThe ANH only receives a percentage of oil revenues in two cases:
i. | when the international oil prices rise beyond a specified price (high price fee), above which the ANH has a right to participate in a share of the increased revenues generated, or |
ii. | in the case of recognition of production rights in an extended contractual |
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,share, upon the commencement of the production phase, and not only in the extension phase of the contract (additional production share) as mentioned in the previous paragraph. In addition, ANH has economic rights when the price of oil exceeds a reference price set in the contract (high price fee) andas well as the superficiary canon. It also has a right to usesurface fee based on the hectares of the subsoil from the beginningassigned area of the contract calculated based on the area of the field during the exploration stage(both with and based on the production during the evaluation and production stage.without production).
E&P contracts have three phases: (i) an exploration period, which term is 6 years counted from the effective date, renewable for two additional years, (ii) an evaluation period of two years, assuming a discovery is made, to determine the commercial potential of the discovery and (iii) a production period, which is, with respect to each production field, 24 years plus any extensions, which are counted from the date of declaration of commerciality of the corresponding field. The abovementioned terms have been modified during ANH’s 2014 bidding round for unconventional and offshore reservoirs to an exploration period of nine years and a 30-year production period. As per the new model E&P contract published by the ANH on June 29, 2018, the term of the evaluation period for offshore contracts entered into as of 2019 will be three, five or seven years, depending on the depth of the water where the discovery is located.
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ANH and Ecopetrol Agreements (Convenios)
Decree Law 1760 of 2003, established that the rights over the production area and over the movable and immovable assets of: (i) all fields that were directly operated by Ecopetrol S.A. as of December 31, 2003, and (ii) all fields in which there were an association contract before said date will continue to belong to Ecopetrol S.A.
Pursuant to Article 2 of Decree 2288 of 2004, which regulates Decree Law 1760 of 2003, Ecopetrol S.A. must execute an agreement with the ANH to regulate the exploration and exploitation terms and conditions of the relevant area, which was previously subject to an association contract.
Decree 2288 of 2004 also established that Ecopetrol S.A. would have to execute agreements with ANH covering fields directly operated by Ecopetrol S.A. Under these agreements ANH recognizes the exclusive right of Ecopetrol S.A. to explore and exploit the hydrocarbons property of the Nation that are obtained in the areas they cover, until resource depletion or until Ecopetrol S.A. returns the area to the Nation through the ANH.
These agreements also provide the conditions under which Ecopetrol S.A. is able to assign, partially or completely, its rights and duties thereunder to third parties.
Transportation and Logistics |
Transportation Activities |
The transportation and logistics segment includes the transportation of crude oil, motor fuels, fuel oil and other refined products including diesel, jet and biofuels. We conduct most of these activities through our wholly owned subsidiary Cenit and its subsidiaries.
The map below shows the locations of the main transportation networks owned by our business partners and us.
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Graph 5 – Map of Oil Pipelines
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Graph 6 – Map of Multi-purpose Pipeline
The table below sets forth the volumes of crude oil and refined products transported through the crude oil pipelines and multi-purpose pipelines owned by us.
Table 3439 – Volumes of Crude Oil and Refined Products Transported
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(thousand bpd) | (thousand bpd) | |||||||||||||||||||||||
Crude oil transport(1) | 877.7 | 836.2 | 823.3 | 785.6 | 877.7 | 836.2 | ||||||||||||||||||
Refined products transport(2) | 275.3 | 273.4 | 268.2 | 231.5 | 275.3 | 273.4 | ||||||||||||||||||
Total | 1,153.0 | 1,109.6 | 1,091.5 | 1,017.1 | 1,153.0 | 1,109.6 |
(1) | The crude oil transported volumes correspond to the following systems: Ocensa Segment 3, ODC, Vasconia-Galan, Ayacucho-Galan, Ayacucho-Coveñas and Trasandino Pipeline. |
(2) | The pipelines transporting refined products include the following: Galan-Sebastopol, Galan-Salgar, Galan-Bucaramanga, Buenaventura-Yumbo and Cartagena-Baranoa. |
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The volume of crude oil transported by Cenit’s main systems and those of its subsidiaries increaseddecreased by 10.5% in 2019 by 5%2020 compared to the previous year. This increasedecrease was mainly the result of (i) increased oil lower 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) increasedlevels, primarily due to low crude oil transportprices in the international markets (ii) a decrease in crude oil demand, fromprimarily due to the Barrancabermeja refinery.lockdowns instituted around the world in response to the COVID-19 pandemic, which in turn resulted in lower transported volumes to the refineries and (iii) slow recovery rates at production fields, primarily due to market uncertainty and lower consumption. Of the total volume of crude transported by oil pipeline,pipelines, approximately 78.1%82.3% belonged to the Ecopetrol Group.
The volume of refined products transported by Cenit increaseddecreased by 0.7%15.9% in 20192020 compared to the previous year, mainly due to growth the impact caused by the different sanitary measures taken by the Colombian government to control the spread of COVID-19. More specifically, measures such as lockdowns and mobility restrictions that led to a decrease in demand 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 offor refined products and hence reduced wholesalers’ needs to transport such products through the Buenaventura port.Cenit’s pipelines. Of the total volume of refined products transported inby multi-purpose pipelines during the year, 32.9%in 2020, 35.7% belonged to the Ecopetrol Group.
Transportation Capacity
Our main crude oil pipeline systems’ operating capacity decreased from 1,497 thousand bpd1,486 kbd in 20182019 to 1,486 thousand bpd1,469 kbd in 20192020 primarily due to scheduled maintenance. Our main multi-purpose pipeline transportation capacity increased from 510 thousand bpd511 kbd in 20182019 to 511 thousand bpd 519 kbd in 2019.2020.
References to our crude oil transportation capacity in this annual report refer to the capacity of the pipelines that belong to Cenit and its subsidiaries to transport crude oil volumes either to the refineries or to our export facilities. In addition, we have other feeder systems that transport oil volumes from producing facilities or other pumping stations to these main pipelines. References to our refined products transportation capacity refer to the capacity of pipelines that begin in the Galan station (Barrancabermeja refinery) and Cartagena station (Cartagena Refinery)refinery).
Pipelines |
As of December 31, 2019,2020, we, directly or indirectly with private partners, own, operate and maintain an extensive network of crude oil and multi-purpose pipelines. These pipelines connect our own and third-party production centers, import facilities and terminals to refineries, major distribution points and export facilities in Colombia.
Cenit directly owns 45% of the total crude oil pipeline shipping capacity in Colombia. When aggregated with the crude oil pipelines in which Cenit owns an interest, Cenit owns 82%81% of the oil pipeline shipping capacity in Colombia. By December 31, 2019,2020, our network of crude oil and multi-purpose pipelines was approximately 9,1069,127 kilometers in length. The transportation network consists of approximately 5,3675,387 kilometers of main crude terminals and oil pipeline networks connecting various fields to the Barrancabermeja refinery and Reficar,Cartagena refinery, as well as to our export facilities.
We also own 3,739 kilometers of multi-purpose pipelines for transportation of refined products from the Barrancabermeja refinery and from ReficarCartagena refineries to major distribution points. Out of the 5,3675,378 kilometers of crude oil pipelines, owned by us, 3,1553,175 kilometers of crude oil pipeline are wholly owned, and 2,212 kilometers of crude oil pipeline are owned through non-wholly owned subsidiaries.
The following table sets forth our main pipelines in which we own an indirect interest as of December 31, 2019.2020.
Table 3540 – Our Main Pipelines
Pipeline | Kilometers | Capacity (mbd) | Product Transported | Origin | Destination | Indirect Ownership Percentage | Kilometers | Capacity (kbd) | Product Transported | Origin | Destination | Indirect Ownership Percentage | ||||||||||||||||||||||||
Caño Limón-Coveñas | 771 | 250 | Crude Oil | Caño Limón | Coveñas | 100.00 | % | 774 | 250 | Crude Oil | Caño Limón | Coveñas | 100.00 | % | ||||||||||||||||||||||
Oleoducto de Alto Magdalena (OAM) | 391 | 110 | Crude Oil | Tenay | Vasconia | 95.8 | % | 391 | 102 | Crude Oil | Tenay | Vasconia | 95.80 | % | ||||||||||||||||||||||
Oleoducto de Colombia (ODC) | 483 | 236 | Crude Oil | Vasconia | Coveñas | 73.00 | % | 483 | 236 | Crude Oil | Vasconia | Coveñas | 73.00 | % | ||||||||||||||||||||||
Oleoducto Central – Ocensa(1) | 848 | 745 | Crude Oil | Cupiagua | Coveñas | 72.65 | % | 848 | 745 | Crude Oil | Cupiagua | Coveñas | 72.65 | % | ||||||||||||||||||||||
Oleoducto de los Llanos (ODL) | 260 | 314 | (2) | Crude Oil | East fields | Monterrey Cusiana | 65.00 | % | 260 | 296 | Crude Oil | East fields | Monterrey Cusiana | 65.00 | % | |||||||||||||||||||||
Oleoducto Bicentenario de Colombia | 230 | 110 | (3) | Crude Oil | Araguaney | Banadia | 55.97 | % | 230 | 110 | Crude Oil | Araguaney | Banadia | 55.97 | % |
(1) | Ocensa has four segments with different capacities. 745 |
a. | Cupiagua-Cusiana (segment zero): 198 |
b. | Cusiana-El Porvenir (segment one): 745 |
c. | Vasconia-Coveñas (segment three): 550 |
(2) | Transportation capacity for this pipeline is measured by using crude oil viscosity of |
(3) | Represents the contractual crude oil transportation capacity for the pipeline currently in operation. |
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As of December 31, 20192020, we owned 7475 stations, 4041 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, 2019,2020, we had a nominal storage capacity associated with the transportation network of 16.416.7 million barrels of crude oil and 4.84.7 million barrels of refined products. We do not own any tankers.
Pipeline Projects
San Fernando – Monterrey
The San Fernando – Monterrey project objectives and scope include ensuring the ability to transport 300,000 bpdbarrels per day at 300 cSt of diluted crude oil from the Chichimene and Castilla fields to the Monterrey pumping station and the transportation of 45,000 bpdbarrels per day of diluent (naphtha) between the Apiay station and the Castilla and Chichimene fields. The project foresees the construction of a new 30” 119-km crude oil pipeline, a new pumping station to include reception, storage and dilution facilities, the conversion of the existing pipeline of 10” between the Castilla II plant and the Apiay station, and the construction of a new 10” pipeline between Chichimene and San Fernando fields in order to transport diluent (naphtha) from the Apiay station to the San Fernando plant.
In 2018, the project completed the maximum pumping test, in accordance with the operational system parameter and owner’s requirements; as a result, the main functional services of the project were validated. The construction, startup phase and commissioning of all systems were completed in January 2018. The system is able to transport crude oil at 750 cSt between the San Fernando and Apiay stations. During 2019, 17 kms of the 30” oil pipeline infrastructure designed to bypass the Apiay station were under construction. The project is currentlywas commissioned in April 2020. The commissioning of this project resulted in the commissioning process.reduction of 13,430 tons of CO2 emissions for the year and it reduced our energy and drag reducing agent (DRA) consumption by approximately 30%.
Chinchina – Pereira product pipeline realignmentCoveñas - Cartagena
The main objective of the Chinchina-PereiraCoveñas - Cartagena project wasis to moveincrease this system’s reliability, capacity, and pipeline infrastructure. To date, this pipeline has a nominal capacity of 135 kbd and feeds the product pipeline infrastructure awayCartagena refinery with national crudes. As the demand for national crudes from densely populated areas.the Cartagena refinery continued to increase, Cenit identified a need to expand this system. In May 2020, Cenit approved the project to increase the system’s nominal capacity by 20 kbd to 155 kbd. The realignment of the pipeline increased the reliabilityproject is currently under construction and safety of the transportation of refined productsit is expected to the western region of Colombiabe in operation by avoiding geotechnically active areas. The pipeline is 55 kilometers long.November 2021.
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$32.8 million in offshore infrastructure as a part of the investment plan signed with the Infrastructure National Agency (ANI), which allows Ocensa to continue operating in a public area of the Morrosquillo Gulf, loading tankers with a capacity of up to 2 million barrels of crude oil. Investments during 2019 consisted of the following: the acquisition of a new, more efficient CALM Turret Buoy and PLEM (Pipeline End Manifold), which will improve the loading times of the tankers; the acquisition of two fiber optic systems, one of which communicates the TLU-2 with land and the other monitors the deformations of the submarine pipeline caused by sea currents; the maintenance of a string of floating hoses; the improvement of the inland transport and handling system; and the completion of integrity works such as inspections of the underwater pipeline, which lead to the repair of four welded joins of 42” and the stabilization of the last 72 meters of the seabed of the offshore pipeline.
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In 2020, Ocensa invested US$ 9.1 million in offshore infrastructure according to an updated investment plan signed with the ANI on December 4, 2019. The new CALM Turret buoy and PLEM are in Colombia and are in the preparation phase with integration tests currently taking place prior to the replacement of the TLU system. The installation of two fiber optic systems was successfully completed.
The maintenance of floating marine hoses and the integrity works of the subsea pipeline was performed according to the plan.
Ocensa Segment 3 Connection to CENIT Tanks in Coveñas
Seeking operational efficiencies for the Ocensa terminal in Coveñas, the Segment 3 Connection Project was developed. This connection consists of enabling direct deliveries from the entrance of the Ocensa pipeline to the tank system of the CENIT station in Coveñas. Previously, crude oil was received in Ocensa’s tanks in Coveñas and then transferred to CENIT’s tanks. The operation of this connection is governed by an agreement between CENIT and Ocensa, which defines the rate and operating conditions that should be in place with the project expected to result in additional income for Ocensa.
In 2019, the engineering for the project was completed and the execution phase was approved.
In 2020, due to the impact of the COVID-19 pandemic in the oil and gas industry, construction was postponed until October 2020, with construction, pre-commissioning and commissioning activities completed in December 2020. The tests and entry into service of the system were undertaken in January 2021 and the project is currently fully operational.
Vasconia Energy Recovery (RECVA)
Given that Vasconia station operates 24 hours a day, an opportunity was identified to recover energy from the system, converting hydraulic energy (flow and pressure) into electrical energy through the installation of a hydraulic power recovery turbine (HPRT). In 2019, the HPRT was purchased, manufacturing was completed, and the engineering development was concluded.
In May 2020, the HPRT was received on site, and during Ocensa’s scheduled plant shutdown in November 2020, the turbine connection points were installed in the existing process lines and 20" valves were installed in the high- and low-pressure line. The project is expected to be commissioned at the end of June 2021.
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 1.621.87 million bpdbarrels per day for crude oil. Our import capacity of refined products and crude oil reached 0.190.61 million bpdbarrels per day and 0.330.14 million bpd,barrels per day, respectively.
Our crude oil loading facilities can load tankers of up to 350 thousand deadweight tonnage (DWT). Adjacent to these loading facilities we also have storage facilities that are capable of storing 11.89.58 million barrels. Our docks used for import and export of refined products can load tankers of 70 thousand DWT. Additionally, these facilities have storage capacity of up to 5.81.1 million barrels.
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, 27.02020, 18.4 million barrels of crude oil and refined products were transported by tanker trucks, and 10.345.7 million barrels of refined products were transported by barges, particularly using the Magdalena River, connecting Barrancabermeja with Barranquilla and Cartagena.
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Marketing of Transportation Services |
Cenit and its subsidiaries’ main line of business is the crude oil pipeline transport (76.7%(76.9% of revenues), followed by the refined products pipeline transport (14.4%(14.26% of revenues) and ports and related services (4.4%(4.25% of revenues). Both crude and refined product pipeline transport are regulated activities; crude oil pipeline transport services are regulated by the Ministry of Mines and Energy, while refined product pipeline transport services are regulated by theComisión 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 represented73.3% 74.94% of this business segment’s revenues in 2019.2020. Transportation services for crude oil provided to Ecopetrol S.A. represented 61.3%87.32% of this business segment’s crude oil transport revenues.
Cenit also transports refined products. Its main client for this service is Ecopetrol S.A., which accounted for 40.1%44.92% of refined products pipeline transport revenues in 2019, principally2020, mainly due to the transport of naphtha, diesel, and gasoline. Cenit also has 1531 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.Petrobras Colombia.
Deregulated businesses, such as ports and crude-loading facilities, represent a smaller portion of Cenit’sCenit and its subsidiaries revenue (4.4%(4.25% in 2019)2020). Clients for these businesses include some of the same parties for which Cenit provides crude oil and refined products transportation services.
Developments with certain clients of Bicentenario and Cenit
Oleoducto Bicentenario de Colombia S.A.S.
During July 2018, the carriers Frontera Energy Colombia Corp. (Frontera), Canacol Energy Colombia S.A.S. (Canacol) and Vetra Exploración y Producción Colombia S.A.S. (Vetra and, together with Frontera and Canacol, the Carriers) sent letters to Oleoducto Bicentenario de Colombia S.A.S. (Bicentenario) alleging there were early termination rights under the Ship-or-Pay Transport Agreements entered by each of them and Bicentenario in 2012 (the Transport Agreements). Bicentenario has rejected the terms of the letters, noting that there is no option for early termination and reiterating to the Carriers that the Transport Agreements are current and therefore the Carriers must fulfill their obligations under the Transport Agreements in a timely fashion. Under Bicentenario’s understanding that the Transport Agreements remain current and that the Carriers are in violation of their obligations under such agreements, Bicentenario declared the Carriers delinquent because of their failure to pay for transport service under the aforementioned agreements. Consequently, Bicentenario executed the standby letters of credit posted as guarantee for the Transport Agreements. On October 19, 2018, Bicentenario notified Frontera of the existence of a “Dispute” pursuant to Clause 20 of the respective Transport Agreement and moved to the party dispute settlement stage as provided for in such clause. Such discussions ended without an agreement on December 19, 2018. On January 28, 2019, Bicentenario filed an Arbitration Claim against Frontera in accordance with the arbitration clause of the Transportation Agreement to claim any compensation, indemnification or other restitution deriving from the alleged early termination of said agreements.
Similarly, on November 1, 2018, Bicentenario notified Vetra and Canacol of the existence of a “Dispute” pursuant to Clause 20 of the respective Transport Agreement and moved to the party dispute settlement stage as provided for in each such respective clause. Such discussions ended without agreement onin March 2019.
On June 14, 2019, and June 26, 2019, Bicentenario filed arbitration claims against Vetra and Canacol, respectively, in accordance with the arbitration clause of the Transportation Agreement to claim any compensation, indemnification or other restitution deriving from the alleged early termination of said agreements.
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As part of the litigation strategy of Bicentenario, the above-mentioned claims were withdrawn, and new claims were filed, as explained below:
On November 12, 2019, Bicentenario filed an arbitration claim against Frontera, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 119448), in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).
On December 10, 2019, Bicentenario filed an arbitration claim against Vetra, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120089) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).
On December 26, 2019, Bicentenario filed an arbitration claim against Canacol, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120179) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).
On December 3, 2019, Bicentenario also filed an arbitration claim against its shareholders Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp., Canacol and Vetra under clause 23(d) of theAcuerdo Marco de Inversiónbefore 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 theAcuerdo Marco de Inversiónand therefore must compensate and indemnify Bicentenario due to their unlawful conduct. This arbitration claim was withdrawn by Bicentenario on October 22, 2020, in order to present its claims on the arbitration described in the following paragraph.
On December 3, 2019, Frontera, Pacific OBC Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp. filed an international arbitration request against Bicentenario and Cenit under Commerce (Case No. 120488) to resolve the disputes between the parties concerning: (i) the alleged dividends due by Bicentenario, (ii) the alleged abuse of Cenit as the majority shareholder of Bicentenario, (iii) the termination of the Transportation Agreements and (iv) the tariffs dispute with Cenit.
On January 10, 2020, Bicentenario filed an arbitration claim against Canacol under the storage agreement (contrato de almacenamiento terminal coveñas) before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120386) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the storage agreement up to the end of theShip or Pay term (2024). See the section Business Overview—Marketing of Transportation Services—Bicentenario, CENIT and Frontera Settlement Agreement.
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.S.A.S.
DuringIn 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.
DuringIn 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 onin March and June 2019, respectively. See the section Business Overview—Marketing of Transportation Services—Bicentenario, CENIT and Frontera Settlement Agreement.
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Bicentenario, CENIT and Frontera Settlement Agreement
On November 17, 2020, CENIT and Frontera reached an agreement, for the joint filing of a petition for a binding settlement which, upon completion and approval by the competent Colombian court, will resolve all the disputes pending among them, related to the Caño Limón – Coveñas pipeline, and will terminate all the pending arbitration proceedings related to such disputes. This transaction eliminates any uncertainty related to the potential outcomes of the disputes, thus protecting the interests of all the parties and those of their stakeholders and create new business opportunities for the parties involved. The settlement arrangement includes a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for the Bicentenario and Caño Limón – Coveñas pipelines. Frontera will also enter into new transportation contracts with CENIT and Bicentenario. The new ship or pay commitment is projected to be approximately 3,900 bbls/day, based on the current oil price, for a term of five years subject to adjustments, at a current rate of US$ 11.5/bl. Frontera will not have to make payments for oil it may have to ship through alternate pipelines. These contracts will allow CENIT and Bicentenario to obtain payment of certain amounts included in the settlement, during the term of the contracts. Additionally, as part of the agreement Frontera will transfer to Cenit its 43.03% of the outstanding shares of Bicentenario, and will transfer to Bicentenario its participation in the Bicentenario pipeline line fill. The arrangement is conditional upon certain regulatory approvals, including approval of the settlement arrangement as a conciliation under Colombian law, which requires an opinion from the Attorney General’s Office (Procuraduría General de la Nación), which was issued on March 24, 2021, and approval of the Administrative Tribunal of Cundinamarca. Once all approvals are obtained and the parties perform all their obligations under the agreement, the Ecopetrol Group’s stake in Bicentenario will be 100%. As of the date of this annual report, arbitrators have been designatedthe final approval by the Administrative Tribunal of Cundinamarca was pending.
Bicentenario, Cenit and Canacol Settlement Agreement
On October 30, 2020, Cenit and Canacol reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for the Caño Limón – Coveñas pipelines. On November 18, 2020, the competent arbitration tribunal approved the settlement agreement entered into by Cenit and Canacol, according to which Canacol was obliged to transfer all its outstanding shares in Bicentenario to Cenit. Additionally, as part of the settlement, Canacol entered into new transportation contracts with Cenit. These contracts will allow Cenit to obtain payment of certain amounts included in the settlement, during the term of the contracts. Furthermore, on March 8, 2021, Bicentenario and Canacol reached an agreement to settle all their aforementioned proceedings.disputes. The agreement established a formula that seeks to end all contractual obligation disputes between the parties and settle all the outstanding obligations between the companies. As of the date of this annual report, approval of the settlement agreement between Bicentenario and Canacol is still pending.
Bicentenario, Cenit and Vetra Settlement Agreement
On November 23, 2020, Cenit and Vetra reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for Caño Limón – Coveñas pipelines. On February 18, 2021, the competent arbitration tribunal approved the settlement agreement entered into by Cenit and Vetra, according to which Vetra is obliged to transfer all its outstanding shares in Bicentenario to Cenit and to make a cash payment for the remaining balance of the amounts included in the settlement. Furthermore, on January 13, 2021, Bicentenario and Vetra reached an agreement to settle all their aforementioned disputes. The agreement established a formula that seeks to end all contractual obligations between the parties and settle all the outstanding obligations between the companies. As of the date of this annual report, approval of the settlement agreement between Bicentenario and Vetra is still pending.
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Refining and Petrochemicals |
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., who operates this refinery and also owns and operates two other minor refineries – Orito-Orito and Apiay -,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 3641 – 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 | % |
For the year ended December 31, | |||||||||||||||||||||||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||
Capacity | Throughput | Use | Capacity | Throughput | Use | Capacity | Throughput | Use | |||||||||||||||||||||||||||||
(bpd) | (bpd) | (%) | (bpd) | (bpd) | (%) | (bpd) | (bpd) | (%) | |||||||||||||||||||||||||||||
Barrancabermeja | 250,000 | 179,210 | 72 | % | 250,000 | 218,612 | 87 | % | 250,000 | 221,946 | 89 | % | |||||||||||||||||||||||||
Reficar | 150,000 | 140,866 | 94 | % | 150,000 | 155,049 | 103 | % | 150,000 | 151,331 | 101 | % | |||||||||||||||||||||||||
Apiay | 2,500 | 887 | 35 | % | 2,500 | 779 | 31 | % | 2,500 | 939 | 38 | % | |||||||||||||||||||||||||
Orito | 2,300 | 1,074 | 47 | % | 2,300 | 1,314 | 57 | % | 2,300 | 1,228 | 53 | % | |||||||||||||||||||||||||
Total | 404,800 | 322,038 | 80 | % | 404,800 | 375,754 | 93 | % | 404,800 | 375,444 | 93 | % |
Barrancabermeja Refinery |
The Barrancabermeja refinery supplies approximately 51.6%51.9% of the fuels consumed in Colombia according to internal calculations made by us and Colombia’s fuel consumption as reported by the Ministry of Finance.
The following table sets forth the production of refined products of the Barrancabermeja refinery for the periods indicated.
Table 3742 – Production of Refined Products from the Barrancabermeja Refinery
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(bpd) | (bpd) | |||||||||||||||||||||||
LPG, Propylene and Butane | 10,114 | 11,813 | 10,712 | 9,101 | 10,114 | 11,813 | ||||||||||||||||||
Gasoline Fuels and Naphtha | 64,063 | 58,623 | 56,047 | 50,167 | 64,063 | 58,623 | ||||||||||||||||||
Diesel | 57,469 | 58,305 | 56,090 | 54,261 | 57,469 | 58,305 | ||||||||||||||||||
Jet Fuel and Kerosene | 24,320 | 23,604 | 20,421 | 11,910 | 24,320 | 23,604 | ||||||||||||||||||
Fuel Oil | 32,009 | 36,636 | 38,217 | 25,112 | 32,009 | 36,636 | ||||||||||||||||||
Lube Base Oils and Waxes | 797 | 729 | 609 | 577 | 797 | 729 | ||||||||||||||||||
Aromatics and Solvents | 2,652 | 3,106 | 2,847 | 2,274 | 2,652 | 3,106 | ||||||||||||||||||
Asphalts and Aromatic Tar | 29,593 | 31,104 | 26,468 | 27,018 | 29,593 | 31,104 | ||||||||||||||||||
Polyethylene, Sulphur and Sulphuric Acid | 1,139 | 1,479 | 1,509 | 856 | 1,139 | 1,479 | ||||||||||||||||||
Total | 222,156 | 225,399 | 212,920 | 181,276 | 222,156 | 225,399 | ||||||||||||||||||
Difference between Inventory of Intermediate Product | (703 | ) | (1,018 | ) | (405 | ) | 1,046 | (703 | ) | (1,018 | ) | |||||||||||||
Total Production | 221,453 | 224,381 | 212,515 | 182,322 | 221,453 | 224,381 |
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In 2019,2020, total production from the Barrancabermeja refinery decreased by 1.3%17.7% compared with 2019 mainly due to a contraction in the impact ofdemand for fuels and petrochemical products caused by mobility restrictions imposed at the scheduled maintenance ofnational level due to the diesel hydrotreating unit.health emergency caused by the COVID-19 pandemic.
We own and operate four petrochemical plants and one paraffin and lube plant located within the Barrancabermeja refinery. In 2019,2020, we produced 33,30920,945 tons of low-density polyethylene, a decrease of 31.3%37.1% compared to the production of 48,46833,309 tons in 2018.2019. This decrease was primarily due to maintenance performedthe impact on the Turboexpander unit.operation of ethylene production in the cracking units as a result of a lower demand for gasoline due to the health emergency caused by the COVID-19 pandemic. We produced657.9 551.1 mboe of aromatics (benzene, toluene, xylene, orthoxylene, heavy aromatics and cyclohexane), a 26.4%16.2% decrease as compared with the production of 894657.9 mboe of aromatics in 2018.2019. The decrease was mainly the result of scheduled planned maintenance of the Aromatic unit.decrease in demand by our national clients given a decrease in their activity, which in turn was due to mobility and work restrictions imposed at the national level due to the health emergency caused by the COVID-19 pandemic.
The gross refining margin decreased from US$11.8 per barrel 10.6/Bl in 20182019 to US$10.6 per barrel 9.1/Bl in 2019,2020, primarily due to the lower positive differential in product prices versus the Brent price, and the higher cost of the crude price spreads for the refinery feed slate.oil basket. The average conversion index for the Barrancabermeja refinery was 87.6% in 2020 and 86.8% in 2019 and 84.6% in 2018.2019. This increase was primarily due to a better quality of the diet and higher yieldsdeliveries of valuable products and lower fuel oil yields.asphalt compared to the crude load of 2019.
Cartagena Refinery |
The following table sets forth the production of refined products from the Cartagena Refinery for the periods indicated.
Table 3843 – Production of Refined Products from the Cartagena Refinery
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(bpd) | (bdp) | |||||||||||||||||||||||
LPG, Propylene and Butane | 4,255 | 4,227 | 6,791 | 3,321 | 4,255 | 4,227 | ||||||||||||||||||
Gasoline Fuels and Naphta | 49,904 | 51,703 | 43,728 | |||||||||||||||||||||
Gasoline Fuels and Naphtha | 43,259 | 49,904 | 51,703 | |||||||||||||||||||||
Diesel | 79,069 | 76,833 | 60,467 | 72,170 | 79,069 | 76,833 | ||||||||||||||||||
Jet Fuel and Kerosene | 9,331 | 8,057 | 6,700 | 7,424 | 9,331 | 8,057 | ||||||||||||||||||
Fuel Oil | 3,660 | 4,671 | 10,150 | 2,375 | 3,660 | 4,671 | ||||||||||||||||||
Sulphur | 585 | 581 | 446 | 466 | 585 | 581 | ||||||||||||||||||
Total | 146,804 | 146,072 | 128,282 | 129,015 | 146,804 | 146,072 | ||||||||||||||||||
Difference between Inventory of Intermediate Products | 2,262 | 39 | 3,916 | |||||||||||||||||||||
Difference between Inventory of Intermediate Product | 5,318 | 2,262 | 39 | |||||||||||||||||||||
Total Production(1) | 149,066 | 146,111 | 132,198 | 134,333 | 149,066 | 146,111 | ||||||||||||||||||
Petcoke (Metric tons) | 922,460 | 984,558 | 704,073 | |||||||||||||||||||||
Petcoke (Metric Tons) | 828,931 | 922,460 | 984,558 |
(1) | Does not include petcoke. |
The following tables set forth the imports and sales of refined products from the Cartagena Refinery for the periods indicated.
Table 3944 – Imports and Sales of Refined Products from the Cartagena Refinery
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(bpd) | (bpd) | |||||||||||||||||||||||
Imports | ||||||||||||||||||||||||
Motor Fuels | 521 | - | 212 | - | 521 | - | ||||||||||||||||||
Diesel | - | - | – | |||||||||||||||||||||
Jet Fuel and Kerosene | - | 466 | 847 | - | - | 466 | ||||||||||||||||||
Alkylate | - | - | – | |||||||||||||||||||||
LPG and Butane | 990 | 739 | 618 | 1,132 | 990 | 739 | ||||||||||||||||||
Total Imports | 1,511 | 1,205 | 1,677 | 1,132 | 1,511 | 1,205 |
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During 2019,2020, the Cartagena Refineryrefinery imported productsbutane in order to achieve the planned inputfeed of the AlkylationButamer Unit and to coverincrease the North Coast sales demand primarily due to an unscheduled operational event at this unit in the third quarterproduction of the year.alkylate.
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(bpd) | (bdp) | |||||||||||||||||||||||
Sales | ||||||||||||||||||||||||
Motor Fuels | 49,865 | 52,126 | 44,051 | 43,979 | 49,865 | 52,126 | ||||||||||||||||||
Diesel | 77,981 | 78,007 | 60,289 | 73,188 | 77,981 | 78,007 | ||||||||||||||||||
Jet Fuel and Kerosene | 9,063 | 8,082 | 7,489 | 7,394 | 9,063 | 8,082 | ||||||||||||||||||
Fuel Oil | 3,713 | 4,704 | 7,528 | 2,552 | 3,713 | 4,704 | ||||||||||||||||||
Other Products | 22,435 | 19,942 | 27,099 | 24,275 | 22,435 | 19,942 | ||||||||||||||||||
Total Sales | 163,057 | 162,861 | 146,456 | 151,388 | 163,057 | 162,861 |
During its stabilization periodTotal sales decreased from US$3,904 million in the second half2019 to US$2,399 million in 2020. A total of 2017, the Cartagena Refinery completed individual unit performance tests (for 100%51.6 million barrels of units), and the Global Performance Test on December 5, 2017.
During the initial phasecrude were processed in 2020 compared to 56.6 million barrels of the refinery optimization process,crude processed in the first half2019. Exports to international markets represented 43.66% 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 operationtotal sales (US$1,047 million).
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 2019refinery’s 2020 figures already reflect the operation of all units.
Total sales have The gross refining margin decreased as compared to 2018, US$4,129 million6.6/Bl in 2018 versus2020 from US$3,904 million9.2/Bl in 2019 mainly due to trends in the international market behavior characterized by lowerreduction of product prices. A totaldemand as consequence of 56.6 million barrelsthe COVID-19 public health emergency and the Russia-Saudi Arabia oil price war. Throughput decreased during 2020, from an average of crude were processed155 mbd in 2019 compared to 55.3 million barrels of crude processed141 mbd 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%:2020.
Esenttia S.A. |
During 2019,2020, Esenttia’s production totaled 460490 thousand tons of petrochemical products, a 3%6.5% increase compared to the 447460 thousand tons produced in 2018,2019, primarily due to greater supplyeffective articulation of the required raw materialsupply chain and the ability of Esenttia to maintain its work schedule in in safe conditions given the COVID-19 pandemic. Average capacity increased by 10 thousand tons in 2020, primarily due to conditionsthe expansion of the extruder capacity and the installation of a second desorber, investments that improved efficiency and reliability in the American market.plant performance. The total contribution margin in 20192020 (including the contribution of polypropylene, polyethylene and masterbatches) was 27% higher3% lower than in 2018, an increase from2019 (from US$191 per ton in 2018 to US$242 per ton in 2019. The increase2019 to US$ 235 per ton in contribution margin was primarily due to higher inventory levels of2020), even in adverse market conditions caused by the required raw material allowing for a reduction in costs.COVID-19 pandemic.
Table 4045 – Operating Capacity of Esenttia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2019 | 2018 | 2017 | 2020 | 2019 | 2018 | |||||||||||||||||||
(Metric Tons) | (Metric Tons) | |||||||||||||||||||||||
Average capacity | 470,000 | 470,000 | 470,000 | 480,000 | 470,000 | 470,000 | ||||||||||||||||||
Throughput | 459,737 | 447,290 | 440,632 | 489,627 | 459,737 | 447,290 | ||||||||||||||||||
% Use | 98 | % | 95 | % | 94 | % | 102 | % | 98 | % | 95 | % |
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3.7.1.4 | Invercolsa |
During 2020, Inversiones de Gases de Colombia S.A. (Invercolsa), registered 1.26 million users of natural gas, a slight increase of 3% compared to the 1.22 million users of natural gas in 2019, due to the contraction of residential natural gas installations given the COVID-19 pandemic. In 2020, Invercolsa continued to integrate its operations into the Ecopetrol Group, in connection with the increase in stake completed by Ecopetrol in November 2019. Invercolsa embraced an HSE culture and leadership model based on Ecopetrol Group’s practices.
Biofuels |
WeAs of the date of this annual report, we have investments in twothe 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)company Ecodiesel Colombia S.A., in which we own 50% of the shares, currently in operation with a theoretical capacity of 100,000 tons per year of biodiesel.
OnMarch 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, administrative2006. The reorganization process ended on June 24, 2020, with applicable regulatory authority ordering the start of the liquidation process of both companies. For more information, see the section Risk Review—Legal Proceedings and 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.Related Matters.
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.
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 increaseddecreased by 7.9 mboepd, an increase of2.6%53 mboed, 17% lower as compared to 2018.2019. This increasedecrease 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 inof the bio-fuel blend percent and higher airplane transportation demandmandatory lockdowns imposed 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 productionColombian national government in order to generate products with higher value.curb the spread of the COVID-19 pandemic, which in turn led to sales of middle distillates and gasoline.
During 2019, 3.42020, 3.5 million barrels of diesel and3.8 2.5 million barrels of gasoline produced by Reficarthe Cartagena Refinery were allocated to complement the supply from the Barrancabermeja refinery and fulfill Colombia’s demand, avoiding larger imports and allowing Ecopetrol to maintain the share of the national market. In the same way, 1.25.1 million barrels of diluent produceproduced 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 increaseddecreased by 5.9%9% compared to 2018, 6.4 mboepd2019, 8 mboed from Reficar and -0.2 mboepd5 mboed 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.lower crude oil runs at the refineries.
Research and Development; Intellectual Property |
Our innovation and technology center is the Colombian Petroleum Institute (ICP for its Spanish acronym), established in 1985 and located in Bucaramanga,Piedecuesta, Santander. In 2019, research and development expenses were US$50.1 million, compared to US$40.7 million in 2018. Technology and innovation as a key lever of our TESG strategy, are essential to our efforts to add value to our business segments through the development of proprietary technologies and competitive advantages and the adaptation of third-party technologies to our processes. processes, and for embracing the low carbon energy transition.
Our research, technology development and innovation efforts are focused on four main strategies:pillars: (i) extending the technical limits for reserves growth;growth, (ii) increasing the efficiency and sustainability of our operations, (iii) preparing the corporation for decarbonization and the energy transition;transition, and (iv) increasing the digitalization of our company. The scope of the Colombian Petroleum Institute activities covers all of our value chain segments: exploration, production, refining, transportation and commercialization,sales and marketing, 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 us to increase the useshare of greenlow emissions hydrogen in our refining and petrochemical processes. As water is a fundamental resource, our efforts will also include a technology–enabled water management program that encompasses the conservation, recycling, reuse and valorization of production water streams. Finally, we willare also exploreexploring avenues for the production of high performance, non-combustible materials from petroleum molecules.molecules, for advanced non-combustion applications.
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Each year Ecopetrol presents to the Colombian InstituteNational Council for the Development of Science and Technology (Instituto Colombiano para el DesarrolloTax Benefits (Consejo Nacional de la Ciencia y laTecnología,Beneficios Tributarios, or COLCIENCIAS)CNBT) its research, technology development projects and innovation initiatives, in order to obtain certifications for its science and technology investments. COLCIENCIASThe CNBT certifies eligible 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 247266 patent applications in the last 15 years, 2319 of them in 2019.2020. Our most recent patent applications include innovative technologies, such as (i)(i) a method obtaining carbon quantum dots from petroleum moleculesdevice for the coalescence of oil droplets dispersed in industrial wastewaters, (ii) synthesis and formulation of a nanofluid based on polymer-coated silica nanoparticles for the modification of relative permeability, (iii) a three dimensional superhydrophobic foam and its applications, (ii) a process for obtaining a transportable hydrocarbon blend composed of heavy crudespreparation method, and non-conventional diluents, (iii) a downhole diluent injection process and its monitoring and control scheme(iv) an online inspection tool for the recoveryefficient detection and classification of extra heavy oil.damages in transportation pipelines.
In 2019, Ecopetrol declared two industrial secrets that strengthen its competitive advantages in heavy oil processing and flow assurance; and in offshore exploration, specifically in2020, the Colombian sector of the Caribbean Sea. The Colombian and international authorities granted us eight8 new patents—sevenpatents all in Colombia and one in India.Colombia. We currently hold 93101 patents in Colombia, the United States, Mexico, Russia, Peru, Venezuela, Ecuador, Brazil, Nigeria, Indonesia, India and Malaysia.
In 2019,2020, Ecopetrol S.A. licensed six10 of its technologies to private companies for manufacturing, marketing commercialization and technical support. support including 5 to a North American company for tackling oil theft in pipelines.
We currently have 4652 technologies licensed to Colombian and multi-national companies.
Applicable Laws and Regulations |
Regulation of Exploration and Production Activities |
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, orCódigo de Petróleos) declares that the hydrocarbon industry and its activities of exploration, exploitation, refinement, transportation and distribution are of public interest, which means that, in the interest of the hydrocarbon industry, the Colombian government may order, for example, necessary expropriations in order to develop such industry. The hydrocarbon industry is under governmental supervision and control, regulated mainly by the Ministry of Mines and Energy and the ANH.
Ministry of Mines and Energy Resolution 181495 of 2009, as amended by Resolution 40048 of 2015, establishes a series of regulations regarding hydrocarbon exploration and production.
Ministry of Mines and Energy Resolution 180742 of 2012, partially repealed by Resolution 90341 of 2014, includes a series of technical regulations for unconventional hydrocarbon resources, including the procedures for advancing the exploration and exploitation of unconventional reserves. It also establishes the types of wells and their classification, as well as the fulfillment of those minimum (drilling and abandoning) conditions necessary to initiate or perform E&P activities. Furthermore, it contemplates the applicable procedure to resolve disputes between the mining sector and the oil and gas sector, regarding the coexistence of their rights in some specific projects.
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Decree 3004 of 2013, issued by the Ministry of Mines and Energy, sets forth guidelines regarding future regulation related to the exploration and exploitation of unconventional hydrocarbon resources in Colombia. Under Decree 3004, an unconventional field is defined as a rock formation with low primary permeability that requires stimulation in order to improve the conditions of mobility and recovery of hydrocarbons. This regulation contains a series of guidelines regarding the regulation for unconventional hydrocarbon resources, including a definition of unconventional reservoirs and the term in which the Ministry of Mines and Energy has to issue the specific technical regulation regarding the exploration and exploitation of unconventional hydrocarbons and the proceedings that interested actors have to follow in order to seek the exploration and exploitation of unconventional hydrocarbons in Colombia. Resolution 90341 was issued on March 27, 2014 in development of the mandate of Decree 3004 setting the technical conditions, requirements and procedures for the exploration and exploitation of unconventional fields. Resolution 90341 of 2014 is currently suspended by order of the Council of State, as a precautionary measure in the analysis of a legal action filed by the Universidad del Norte. This precautionary measure covers both the Decree 3004 of December 26, 2013 and Resolution N° 90341 of March 27, 2014, related to unconventional fields.
On May 26, 2015, Decree 1073 compiled the majority of Colombian decrees in force regarding the administrative sector of mines and energy.
Decree Law 4137 of 2011, which modified the legal nature of the ANH regulates what corresponds to the integral administration of the hydrocarbon reserves and resources owned by the nation of Colombia.
In accordance with the aforementioned Decree Law, it is the responsibility of the Board of Directors of the ANH to define the criteria for administration and allocation of the areas; approve model contracts for their exploration and exploitation, while establishing the rules and criteria for their management and monitoring the contribution to the economic and social development of the country through the promotion and sustainable use of reserves and resources.
Agreement (Acuerdo, a type of regulation) 004 of 2012, as issued by the ANH, amends Agreement 008 of 2004 and sets forth the rules governing the award of exploration and production areas and the execution of contracts. As set forth below, Agreement 002 of 2017 replaces thisAcuerdo.
Agreement 003 of 2014, as issued by the ANH, complements Agreement 004 of 2012 by setting forth the contractual framework for the carrying out of activities in unconventional reservoirs, the procurement regulations for the exploration and exploitation of unconventional fields and the procurement process for the awarding of hydrocarbon exploration and exploitation areas.
Agreement 002 of 2015, as issued by the ANH, partially amends Agreement 004 of 2012 and sets forth the initial rules and measures the Government can take to mitigate the adverse effects of the decline of international oil prices. The main measures established by this agreement are the following:
i. | The extension of terms and deadlines for the execution of activities related to investments in exploration and evaluation phases and for the declaration of commercial discoveries; |
ii. | The establishment of procedures to transfer investments in exploration programs between allocated areas; and |
iii. | The leveling of the contractual terms of offshore contracts entered before 2014 to the ones included in the contracts executed as a result of the 2014 Colombian Round. |
Agreement 003 of 2015, as issued by the ANH, modifies and, also partially amends, Agreement 004 of 2012, and provides certain rules and measures the Government can take to mitigate the adverse effects of the decline of international oil prices. This agreement permits performance guarantees required under E&P contracts to be reduced in the same amount as the works actually performed during the term of the respective phase.
Agreement 004 of 2015, as issued by the ANH, also partially amends Agreement 004 of 2012, and provides certain rules and measures for the Government to mitigate the adverse effects of the decline of international oil prices. This agreement allows contractors to attribute additional activities carried out under a TEA to commitments under the first phase of an E&P contract.
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Agreement 002 of 2017, as issued by the ANH on May 18, 2017, replaces Agreement 004 of 2012, Agreement 003 of 2014, and Agreements 002, 003, 004 and 005 of 2015. It establishes the general structure of the New Regulation for Administration and Assignment of Areas and the general guidelines regarding future hydrocarbon contracts in Colombia. Seeking the interests of the Nation, the market conditions, the national hydrocarbon sector strategy, the competitive context of producer countries and the Nation’s social and environmental evolution.
Agreement 002 of 2017 adapts the existing regulations for the selection of contractors, and the applicable rules for the award, execution, termination, liquidation, monitoring, control and surveillance of the contracts signed with the ANH. In regard to unconventional reservoirs, this agreement also establishes the need to sign additional contracts and additional arrangements for the industry to exploit unconventional reservoirs in Colombia.
As mentioned above, onOn 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).PPII to identify the risks of unconventional activity.”
On February 4, 2019, the ANH published the new model contract for offshore exploration and production. The purpose of this new model contract is to foster and stimulate investments in exploration and the exploitation of offshore hydrocarbons, enhancing Colombia’s competitiveness to attract and retain investments from large and experienced O&G operators.
On February 5, 2019, the ANH by implementing theAcuerdo No. 2 (Agreement No. 2) opened a permanent competitive bidding procedurePermanent Competitive Bidding Procedure (PPAA), which aims to select, among previously qualified proponents on equal terms, the most favorable offers to allocate the areas previously determined, demarcated and classified by the ANH. Several addendums have modified the terms of references of the PPAA, but, as to date, the applicable terms of reference of such bidding process are included in Addendum No. 19 of November 4, 2020.
The Agreement 02 of 2017 was partially modified by agreement 03 of February 18, 2019 to clarify the moment in which contractors may withdraw from the contracts signed with the ANH and also presents another alternative for those interested in the PPAA when they belong to business groups, other than the issuance of a parent company guarantee.
Resolution 078 of 2019, as issued by the ANH, approved the final terms of reference and the model of the onshore and offshore contract for the PPAA. Pursuant to this procedure, the ANH will select areas over which proposals may be received at any time, without the need of launching specific bidding procedures for their allocation.
As a result, in 2019, the ANH issued terms of references for the PPAA and carried out two cycles both of which were divided in the following four stages: (i) submission of the proposals and selection of the initial proponent, (ii) submission of counterproposals and selection of the most favorable counterproposal, (iii) the exercise of the right of option of improvement by the initial proponent and (iv) allocation of areas, contract awards and execution of contracts. In 2020 a third cycle was carried out by the ANH.
As result of the first cycle of the PPAA, the ANH offered 18 continentalawarded 11 onshore areas and two1 offshore areas.area. As part of the second cycle, the ANH allocated 14 onshore blocks. Finally, as a result of the third cycle, the ANH awarded 4 onshore areas.
Resolution 078Agreement 01 of 2019, as issuedMarch 27, 2020 of the ANH regulates the transfer of activities or investments between legal instruments signed with the ANH to promote exploratory investment in the country and to seek the incorporation of new reserves, repealing the articles of Agreement 02 of 2017.
Agreement 02 of April 7, 2020 of the ANH regulates temporary measures to strengthen the hydrocarbon sector due to the effects generated by the fall in international oil prices. This agreement takes into account what is regulated by Decree 417 of 2020, where the Government declared the State of Economic, Social and Ecological Emergency throughout the national territory, and tlhe declaration by the World Health Organization (WHO) of the outbreak of COVID-19 as a global pandemic. Among the legal measures enacted were: (i) the extension of terms and deadlines in the contracts signed with the ANH; (ii) exceptions to the requirements established in Agreement 01 of 2020 mentioned above, which considers the status of the international oil prices; (iii) possibility of allocating resources from the Benefit Programs to the Communities “PBC” to strengthen measures applied by the Government to face the crisis; and (iv) reduction of contractual guarantees, complying with the requirements established there.
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Agreement 06 of September 11, 2020 of the ANH approvedadded Agreement 18 of 2004, Agreement 04 of 2005, Agreement 21 of 2006, and Agreement 2 of 2017 to incorporate into the termsContracting Regulations for the Exploration and Exploitation of referenceHydrocarbons, the contractual elements that allow entities to carry out PPII on hydrocarbons in unconventional reservoirs (YNC) with the use of the Multistage Hydraulic Fracturing with Horizontal Drilling (FHPH) technique.
Through Resolution 0613 of September 14, 2020, the ANH opened a competitive process for the development of Research Projects in Unconventional Reservoirs by the use of the FHPH technique.
A first round was carried out between September 14, 2020 and November 25, 2020, allocating one area to Ecopetrol S.A. Therefore, by means of Resolution 0802 of November 25, 2020, the modelANH awarded a Special Contract for Research Projects (CEPI) to Ecopetrol S.A. This contract will allow Ecopetrol, to execute activities in the interest of investigation, clarifying and exploring the feasibility of the hydraulic fracturing procedure for the exploration and exploitation of hydrocarbons in unconventional reservoirs in Colombia. The name of the contract is KALÉ and is located in Puerto Wilches (Department of Santander). As of the date of this annual report, the second round had commenced and was concluded in March 2021.
Temporary regulation for the “permanent bidding procedure.” Pursuant to this procedure,Comprehensive Research Pilot Projects (PPII)
Ecopetrol has actively participated in the ANH will select areas over which proposals may be received at any time, withoutformulation of specific regulation for the needimplementation of launching specific bidding procedures for their allocation.the PPII. The regulatory framework includes:
As of the date of this annual report, additional items of the PPII regulatory framework are being discussed with the Colombian Governement pursuant to which we have made comments. In particular, the Colombian Government and the oil & gas industry are waiting for the final versions of the regulatory framework for pilot evaluation criteria, radioactive materials monitoring, health base lines and evaluation variables.
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 onto 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.activity.
If the projects or activities could have a direct impact over the territories or the interests of indigenous, Afro-Colombian or Raizal communities, the Colombian Constitution provides that the companies developing such projects or activities must undertake a publicconduct the prior consultation process with those communities before initiating such projects or activities. This consultation process is a prerequisite for obtaining the required environmental licenses.
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In addition, the Colombian Constitution and laws establish that, as part of the public participation mechanisms, Colombian individuals may request information regarding the activities of the project and their potential impacts. They may also request to undertake an environmental hearing so as to obtain information of the project subject to environmental licensing.
On May 26, 2015, the Ministry of Environment and Sustainable Development (MESD) issued Decree 1076, which compiles the majoritymost of Colombian regulations in force regarding environment and sustainable development.
The environmental license encompasses all of the necessary permits, authorizations, concessions and other control instruments necessary under Colombian environmental law to undertake a project or activity that may result in the serious deterioration of renewable natural resources, or that have the capacity of materially modifying the physical environment. The license shall define specific conditions under which the beneficiary of the license may undertake such project or activity. The procedure to obtain an environmental license begins when the company files an Environmental Impact Study (EIA) related to the project before the ANLA. The licensing process includes an application for the use of natural renewable resources (water, soil and air), according to Decree 2106 of 2019. When the project or activity requires permits for the use of forestry species that are banned, these should be included in the environmental license process. The EIA must be filed as well as a plan to prevent, mitigate, correct and compensate for any activity that may harm the environment, known as the Environmental Management Plan (PMA).
The environmental licensing procedure in Colombia is set forth in Decree 1076 of 2015. According to the regulation currently in effect, the procedure to obtain an environmental license shall not take more than 90 business days. But, depending on the complexity of the information requested by the ANLA and administrative delays, including an oral hearing to determine the viability of the project, the procedure may take between 165 and 265 business days, depending on whether the applicant is required to file additional information. The actual procedure incorporates an oral hearing between the ANLA and the applicant in order to evaluate the information provided in the license application and whether it is necessary or not to request additional information about the proposed project. The ANLA will have no other opportunities to request additional information after this hearing.
The environmental licensing process for activities in unconventional reservoirs is that of Decree 1076 of 2015. However, the Ministry of Environment and Sustainable Development issued resolution 0821 of September 24, 2020, which established the terms of reference for the preparation of the Environmental Impact Study of the PPII, on unconventional hydrocarbon reservoirs using the FHPH technique.
The Ministry of Environment and Sustainable Development (MESD) is also responsible for issuing regulation and establishing guidelines regarding climate change policies for the hydrocarbon sectordifferent sectors in Colombia. WeThe Ecopetrol Group comply with those guidelines. At present,all applicable regulations. In particular, MESD has not proposed any specific stepsis responsible for issuing regulation regarding Law 1931 of 2018 (Climate Change Law), which outlines provisions for the implementationestablishment of a National Program of Greenhouse Gas (GHG) Tradable Emission Quotas (PNCTE for its Spanish acronym). The PNCTE is expected to enter into force in 2022. The MEDS is also responsible for the Kyoto Protocol or the Paris Agreement, as they relateNational Emission Reductions Registry (RENARE for its Spanish acronym), in which companies must register verified GHG emission reductions. RENARE is expected to start operating in 2021. As part of our operations. We are continuouslycontinuous monitoring of climate change requirements, that could be applicablewe also identified ongoing regulatory processes related to us.the reduction of fugitive emissions and routine flaring, led by the Ministry of Energy and Mines. A company that does not comply with the applicable environmental laws and regulations, does not execute the corresponding Environmental Management PlanPlans (PMA) approved by the environmental authority or ignores the requirements imposed by an environmental license may be subject to an administrative sanction proceeding initiated either by the ANLA or the regional environmental authorities established by Law 1333 of 2009. The proceeding may result in oral or written warnings, monetary penalties, fines, license revocation or the temporary or permanent suspension of the activity being undertaken. Apart from administrative sanctions, the Colombian judiciary or other law enforcement authorities may also impose civil and even criminal sanctions if environmental damages are verified as a consequence of having breached the environmental laws and regulations applicable to the project.
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Royalties |
In Colombia, the Nation is the owner of minerals and non-renewable resources located in the subsoil,subsurface, 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.
With the issuance of Law 2056 of 2020, (“Through which the organization and operation of the general system of royalties is regulated”), the royalties regime applicable to the hydrocarbon fields on which there have been made additional investments aimed at increasing the recovery factor of existing deposits was established. Article 18 of this law established that all the volumes produced in these fields will be considered incremental.
Regarding natural gas, in accordance with Resolution 877 of 2013, as amended by Resolution 640 of 2014, starting on January 1, 2014, the ANH has received royalties in cash rather than in kind. Thus, the producer may dispose of its gas production volumes corresponding to royalties paid in cash.
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 theComisión 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 DevelopmentMESD and regional environmental authorities, respectively.
Crude oil transport
The regulatory framework relating to crude oil transportation accounts for both private use and public use pipelines. Private use pipelines are those built by the operating or refining entity for its own exclusive right and that of its affiliates. Public access pipelines are defined as pipelines built and operated by a public or private legal entity, for the purpose of publicly providing crude oil transportation services. The Colombian government, through the ANH, has a preferential right to use up to 20% of the total capacity of any public or private access pipeline to transport its crude oil royalties. However, for both private and public access pipelines, the ANH must pay the tariff for the pipeline use to transport its percentage of production.
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The Ministry of Mines and Energy is responsible for reviewing and approving the design of and tracks for crude oil pipelines and establishing transport rates based on information provided by the service providers. It also oversees the calculation and payment of hydrocarbon transport-related taxes and manages the information system for the oil product distribution chain.
In 2014, the Ministry updated the transport regulation and the rate calculation method for this line of business. It introduced a framework for the secondary market and incentives for new pipeline construction and current pipeline capacity expansions. According to the Petroleum Code, rates must be revised every four years.
During the scheduled revision of 2019, the Ministry of Mines and Energy, by means of Resolutions 31123 and 3133231132 of 2019 established the applicable rules for transportation and oil production companies to negotiate tariffs for the next four years. Once the negotiation period was over, the Ministry of Mines and Energy through a series of resolutions set the applicable tariffs for transportation of crude oil through pipelines. Such resolutions, were in line with the tariff methodology that has been in place since 2014, providing more regulatory stability for the Midstream companies through June 2023.
In August 2020, the MME started a consulting process to carry out a study with the purpose of reviewing, adjusting, and updating the crude oil tariff setting methodology. The scope of the study requires the contractor to prepare a document proposing changes to the current methodology and analyze whether it would be possible to implement the proposed methodology once the current tariff period (2019-2023), determined by Resolution 72146 of 2014 has been finalized. The results of such study will be analyzed and discussed between all the stakeholders prior to the enforcement of any changes.
The Port Superintendence is the authority that oversees the port business for crude oil and refined products. Although this business is not highly regulated, market participants are required to report certain information to the Port Superintendence.
As a result of the enactment of Decree 119 of 2015, operators of private use hydrocarbon ports are currently able to provide hydrocarbon transport services to third parties pursuant to a mechanism established under that decree.
Decree 119 of 2015 was incorporated into Decree 1079 of 2015 issued by the Ministry of Transport, which compiles the majority of Colombian decrees and regulations in force regarding the administrative sector of transportation.
Refined products and liquefied petroleum gas transport
In 2014, CREG assumed responsibility for regulating product pipeline transportation from the Ministry of Mines and Energy, in addition to its pre-existing regulatory responsibility for liquefied petroleum gas, natural gas and electric energy transportation.
The applicable framework regarding LGP transportation was established by CREG Resolution 092 of 2009 (amended by Resolution 152153 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 2017January 2021, CREG preparedpresented a new draft resolution 113232 of 2017,2020, which has not been issued. It introduces a new frameworkestablishes the Regulations for the transportation regulation of liquefied petroleum gas and refined products.Transportation by multipurpose pipeline. The draft resolution was open for observationsto comments 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.February 26, 2021. The primary goals and componentsmain objectives of the proposed regulation are: (i) to ensure free access to the transport systems for liquid fuels and the LPG pipeline systemstransportation system without discrimination; (ii) to promoteoffer optimal conditions in the timely expansionoperation and provision of the public transport systemservice. In 2021, CREG also plans to define the methodology for calculating transportation rates for multipurpose pipelines.
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In February 2021, CREG issued resolution 004 of 2021.Through this resolution CREG defined the Weighted Average Cost of Capital (WACC) methodology that will be applicable to the different activities that this entity regulates. The activities regulated by CREG include energy distribution and transmission, gas distribution and transportation and refined products transportation. The discount rate for transportation of refined products will be calculated in lineaccordance with the needsinputs defined by the resolution and will be applicable once the tariff methodology for this activity is updated and published. As required by article 87 of Law 142 of 1994, regulatory agencies may modify the 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.tariff methodologies every five (5) years. As of the date of this annual report, the above mentioned resolution hastariff methodology had not yet been issued.issued.
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.
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, 01919 of 2015, and 034, 063, 06418, 34, 63, 64 of 2016 and 171 of 2017). The LPG price is regulated by CREG Resolutions 66 of 2007 (as amended by CREG Resolutions 59 of 2008, 002 of 2009, 123 of 2010, 09595 of 2011, and 65 and 129 of 2016) as well as by CREG Resolution 80 of 2017 which sets forth that the price of LPG imported by Ecopetrol, which is meant to be marketed for the provision of public utilities, shall be the result of competitive procedures.
According to Article 4 and 212 of the Petroleum Code and Law 39 of 1987 (added by Law 26 of 1989 and as amended by Law 812 of 2003), the distribution of crude oil and its derivatives has a public purpose (utilidad pública), and the distribution of fuel oil and crude oil by-products is considered a public utility activity. Consequently, individuals or entities engaged in these activities are subject to regulations issued by the Colombian government. The Government has the power to determine quality standards, measurement and control of liquid fuels, and establish penalties that may apply to dealers who do not operate in compliance therewith.
The Ministry of Mines and Energy is the entity that controls and exercises technical supervision over the distribution of liquid fuels derived from petroleum, including the refining, import, storage, transportation and distribution in the country. Article 61 of Law 812 of 2003 (whose validity was extended by Law 1955 of 2019) identified the agents of the supply chain of petroleum-based liquid fuels. In this context, the Ministry of Mines and Energy through Resolution 40344 of 2017, published the required actions to ensure the LPG supply for the priority sectors in the country.
The distribution of liquid fuels, except LPG, is governed by Decree 1073 of 2015 (as amended), which establishes the requirements, obligations and penalties applicable to supply agents in the distribution, refining, import, storage, wholesale, transportation, retail sale and consumption of liquid fuels.
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Decree 1073 of 2015 establishes the minimum technical requirements for the construction of storage plants and service stations. This Decree also regulates the distribution of liquid fuels, except LPG establishing the minimum requirements for distributors and the activities and types of agreements permitted for these agents. The Ministry of Mines and Energy also regulates the types of liquid fuels that can be sold and purchased and the penalties for noncompliance with governmental regulations.
Pursuant to Law 1430 of 2010, modified by Article 220 of Law 1819 of 2016, the distribution of fuels in areas near Colombian borders is the responsibility of the Ministry of Mines and Energy and is subject to specific regulations that impose strong control procedures and requirements. The Ministry of Mines and Energy establishes the safety standards for LPG, storage equipment, maintenance and distribution of LPG.
The Superintendence of Public Domestic Utilities also oversees the liquefied petroleum gas transportation business.
Regulation Concerning Production and Prices |
According to the Decree - Law 4130 of 2011 and Decree 1260 of 2013, CREG is in charge ofresponsible for setting the prices of petroleum by-products throughout the entire chain of production and distribution, except for current gasoline engine, diesel and biofuels. On the other hand, by Decree 381 of 2012, as amended by Decree 1617 of 2013, and Decree 2881 of 2013, the Ministry of Mines and Energy is in charge of setting the methodology to determine the reference price of gasoline, diesel, biofuels and mixtures thereof.
Then, since May 2012, CREG sets the prices for most crude oil by-products, except for gasoline, diesel and biofuels. CREG determines the methodology to calculate their price while the Ministry of Mines and Energy sets the relevant prices in accordance with said methodology. The ANH does not intervene in the definition of prices of gasoline and diesel fuel. In addition, under Resolution 007 of 2017, CREG determined the basis for the methodology of compensation of terrestrial transportation of liquid fuel-oil, including current gasoline, diesel and biofuels between the storage plant and the fuel service station.
The methodology for calculating jet fuel prices is set out in Law 1450 of 2011, and jet fuel prices themselves are set by the Ministry of Mines and Energy.
The ANH determines the formula that is used to calculate royalty payments corresponding to the production of crude oil.
Decree 381 of 2012 and 1617 of 2013, as amended by Decree 2881 of 2013, as compiled in Decree 1073 of 2015, restructured the Ministry of Mines and Energy and gave it the responsibility to study industry problems and implement short and long-term refining planning policies. The Ministry is also responsible for establishing the governmental policies and goals to ensure the reliability, stability and continuity for the production of liquid fuels, biofuels and others.
Pursuant to Article 58 of the Petroleum Code, if there is a fuel shortage, any refining company operating in Colombia must offer to sell a portion or, if needed, the total of its production to supply local demand prior to exporting any production.
Fuel Price Stabilization Fund (FEPC)
The Fuel Price Stabilization Fund was created by Law 1151 of 2007. It is a fund assigned and administered by the Ministry of Finance and Public Credit. Its function is to attenuate, in the domestic market, the impact of fluctuations on fuel prices in international markets.
According to Article 2.3.4.1.3 of Decree 1068 of 2015, amended by Decree 1451 of 2018, the resources for the functioning of the FEPC come from the following sources: (a) financial returns of resources of the Fund; (b) extraordinary credit resources received from the National Treasury; (c) funds allocated to the FEPC in the national general budget; (d) fuel taxes and; (e) bonds or other public debt securities issued by the Nation in favor of the FEPC, in order to cover the obligations of the Fund.
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The operation of the FEPC is governed by Decree 1068 of 2015, amended by Decree 1451 of 2018, Chapter 1, and Title 4 (compilation decree regarding treasury public sector). First, refiners and/or importers of regular gasoline and diesel must report to the Ministry of Mines and Energy the volume of regular gasoline and diesel sold in the previous month and such reports must be made within the next 35 calendar days of each month.
The report must also contain, among other matters: information corresponding to each fuel disaggregated daily; the discrimination of the volumes sold, and the origin national or imported of the gasoline and diesel sold. If the regular gasoline or the diesel is of national origin, the refiner/importer must inform from which refinery they come. Secondly, the Ministry of Mines and Energy calculates and liquidates, by resolution, the net position of each refiner/importer and each fuel to be stabilized by the FEPC.
Decree 1068 of 2015, amended by Decree 1451 of 2018, provides that the FEPC will pay in Colombian pesos the value corresponding to the calculation and settlement of the Net Position of each refiner and/or importer within the term defined by the Ministry of Mines and Energy and based on availability of FEPC resources.
Law 1819 of 2016 as amended created a tax, related contribution to finance the FEPC. This contribution is caused when the sum of the Differentials of Participation (difference between the Producer Income and the International Parity Price, when the first is greater than the second on the date of issuance of the sales invoice, multiplied by the volume of fuel sold) is greater than the sum of the Differentials of Compensation (the difference presented between the Producer Income and the International Parity Price, when the second is greater than the first on the date of issuance of the sales invoice, multiplied by the volume of fuel sold).
The event that generates the contribution is the sale in Colombia of gasoline or diesel by the refiners and/or importers to the wholesale distributor of fuels, according to the price set by the Ministry of Mines and Energy, however, if the importer is at the same time a wholesale distributor, the triggering event shall be the withdrawal of the product to be sold. The taxpayer responsible for the contribution is the refiner and/or importer and the active subject is the Nation. The tax base corresponds to the positive difference between the sum of the Differentials of Participation and the sum of the Differentials of Compensation.
The Ministry of Mines and Energy calculates the contribution through the liquidation of the Net Position of each refiner or importer with respect to the FEPC based on the report that the refiners and/or importers submit. If the sum of the Differentials of Participation is greater than the sum of the Differentials of Compensation and the contribution is caused, the Ministry of Mines and Energy will order the refiner or the importer to pay the contribution to the National Treasury within the 30 days following the execution of the liquidation resolution.
Subsequently, Law 1837 of 2017 (Article 16) provided that the remaining resources that were in the Ecopetrol’s accounts as of December 2014, as a result of the collection of the Differential Contribution from the FEPC, would be transferred to the General Direction of Public Credit and Treasury of the Ministry of Finance and Public Credit (DGCPTN)(DGCPTN for its Spanish acronym). Law 1955 of 2019 (Article 33) authorizes the Ministry of Finance and Public Credit to enter into hedging agreements and establishes the conditions thereof, for purposes of guaranteeing the sustainability and the functioning of the FEPC.
The Ministry of Mines and Energy issued Resolutions 31536 and 31538Resolution 31435 of 20182020, which containcontains the settlement of our Net Positions corresponding to: (i) the period between December 29fourth quarter of 2019 and 31, 2016 and(ii) the first and the second quartersquarter of 2017, and (ii) the third and fourth quarters of 2017.2020. In those resolutions the FEPCthis Resolution, Ecopetrol was ordered to transfer COP $729,729,493,450.88COP$50,131,065,625.67 to the DGCPTN. Also, by means of Resolution 31434 and COP $1,183,672,269,819.52for the same periods, the Ministry ordered Refinería de Cartagena S.A.S. to Ecopetrol, respectively.transfer COP157,942,973,442.41 to the DGCPTN.
Law 1955 of 2019 authorizes the Ministry of Finance, as administrator of the FEPC, to carry out, directly or indirectly, the design, management, acquisition and/or execution of hedges on the Ministry of Finance’s direct exposure to (i) crude oil liquid fuel oils prices in the international market or (ii) the exchange rate of the Colombian Peso. This law also authorizes the Ministry of Finance to set stabilization mechanisms of the reference recommended retail prices of regulated fuel oil, as well as the subsidies to such regulated fuel oils to be executed through the FEPC. 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.
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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.
Regulation of the Natural Gas Market |
Decree 1073 of 2015, Part 2, Title 2, Chapter 2, established that all producers have to issue a production statement that includes the volumes of natural gas available for sale for a period of ten years. This decree established the regime for the selling and marketing of natural gas in Colombia, including specific procedures that regulate the Colombian market in order to manage the remaining natural gas reserves owned by the Nation, and to protect domestic consumers, especially residential consumers, by prioritizing delivery of gas to residential consumers, regulating the export of natural gas and setting forth the export restrictions applicable during an internal shortage of natural gas.
Currently in Colombia the price of natural gas is determined by the market, but some agreements still have to conform to the regulated formula. CREG issued Resolutions 185 (for transportation) and 186 (for supply) of 2020, which jointly replace Resolution 114 of 2017 partially amended by CREG Resolution 21 of 2019 which adjustedand its amendments, related to commercial aspects of the wholesale natural gas market in Colombia and compiled CREG Resolution 089 of 2013 and its amendments.Colombia. However, pursuant to Decree 1073 of 2015, such procedures do not apply to the following activities: a) natural gas exports; b) natural gas as raw material in petrochemical production; c) natural gas commercialization from minor fields (production capacity under 30 million SCFD); d) natural gas commercialization from hydrocarbon fields under testing phase or which have not yet been declared commercially viable; e) natural gas commercialization from unconventional reservoirs; and f) internal consumption from natural gas producers.
CREG determines which agents can participate in the primary and secondary markets. Ecopetrol is authorized to participate as a seller in the primary market as a natural gas producer and as a buyer in the secondary market when Ecopetrol requires natural gas from other producers for its own needs. CREG regulations provide that a natural gas producer cannot participate as a merchant of natural gas in the secondary market, except that it may purchase gas to meet its existing contractual obligations. Ecopetrol is also able to resell available natural gas transportation capacity into the secondary market.market as a non-regulated consumer.
Priority for the Supply of Natural Gas
The export of natural gas, in contrast, is not considered a public utility activity under Colombian law and therefore is not subject to Law 142 of 1994. Nevertheless, the domestic supply of natural gas is a priority for the Colombian government and is considered to be a public utility complementary activity, and therefore public utility regulations apply to the internal supply of natural gas.
Decree 1073 of 2015 (amended by Decree 2345 of 2015) provides that in the event the supply of natural gas is reduced or halted as a result of a shortage, the Colombian government has the right to suspend the supply of natural gas for export. If such export contracts are suspended by the Colombian government, the export agents are entitled to receive compensation in accordance to Article 2.2.2.2.15 and 2.2.2.2.38 of Decree 1073, 2015. Notwithstanding the foregoing, Decree 1073 of 2015 establishes freedom to export natural gas under normal gas-reserve conditions. Producers of natural gas may enter into natural gas export contracts if the ratio of proved reserves to consumption exceeds seven years, as determined by the Colombian Energy Planning Authority (or UPME for its Spanish acronym).
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Decree 1073 of 2015 (amended by Decree 2345 of 2015) establishes an order of supply when restrictions are placed on the supply of natural gas or serious emergency situations arise that preclude the continued provision of certain services, as follows: (i) essential demand, as established in Decree 1073 of 2015, (ii) non-essential demand under an existing agreement with a warranty of uninterrupted provision and (iii) firm exports delivery.
The order of priority for the supply of natural gas is as follows: (i) the operation of the compressor stations of the National Transportation System, (ii) residential users and small business users engaged in the distribution network, (iii) vehicular compressed natural gas and (iv) gas refineries, excluding those destined for self-generation of electricity that can be replaced with energy from National Transportation System, which has first priority. The Ministry of Mines and Energy also establishes distribution priorities in the event of a natural gas shortfall derived from supply or infrastructure issues. This order of priority is based on the type of contract, with firm supply contracts having priority over interruptible supply contracts.
Decree 1073 of 2015 and CREG Resolution 114186 of 2017:2020: (i) provide specific procedures and forms of supply agreements determined by CREG pursuant to which an agent may sell and buy natural gas in the Colombian primary and secondary market produced from large fields (capacity of more than 30 million CFPD); and (ii) permit the sale of natural gas from small fields (capacity under 30 million CFPD) pursuant to contracts that fulfill certain regulatory requirements but whose form is not prescribed by law.
As determined by article 11 of Law 143 of 1994, commercialization activities, which are developed by commercialization agents, consist of the purchase of electricity in the electric energy market (“MEM”, for its Spanish acronym) and the subsequent resale to other participants of the wholesale such as commercialization agents, generation agents, or to end-customers, both regulated and non-regulated. Ecopetrol Energía S.A.S E.S.P., one subsidiary of Ecopetrol, is registered as a commercialization agent before the manager of the commercial exchanges systems and performs commercialization activities within the MEM.
Commercialization activity is regulated by CREG Resolution 156 of 2011, which establishes the regulations and the rights and duties of the agents. The main income of commercialization agents comes from the variable and fixed components of the unit cost tariff formula described in CREG Resolution 119 of 2007, as modified by CREG Resolutions 191 of 2014 and 030 of 2018. The variable component considers:
Regarding the markets that commercialization agents attend, Law 143 of 1994 divides the market into two segments: regulated market (“Regulated Market”) and the non-regulated market (“Non-Regulated Market”).
The Non-Regulated Market is comprised of electricity consumers that either have a peak demand greater than 0.10 MW or a minimum monthly consumption greater than 55.0 MWh. This segment is attended by generation and commercialization companies. Purchases of electricity in this segment can be freely agreed among participants at freely negotiated prices for the commercialization and generation components of the tariff’s unitary price.
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Resolution CREG 015 of 2018 establishes the obligations for Network Operators (owner of the physical networks) and commercialization agents for the transportation and distribution of energy and also regulates the quality standards for the delivery of energy at the point of consumption, and the applicable methodology for calculating the distribution charges of each Network Operator.
As determined by article 74 of Law 143 of 1994, as modified by article 298 of Law 1955 of 2019, any public utilities company that makes part of the National Interconnected System (“SIN” for its Spanish acronym) can perform the generation, (which consists of the production of electricity through any generation plant connected to the SIN, activity performed by generation agents, who participate in the MEM by selling electric energy to other generation and commercialization agents, or to Non-Regulated Users), distribution (which consists of transporting and delivering electric energy to end users through the Regional Transmission Systems (STR for its Spanish acronym), and the Local Distribution Systems (SDL for its Spanish acronym) deploying tension levels under 220 kV;. agents in charge of providing the distribution public utility are called Distribution Agents or Grid Operators (OR for its Spanish acronym) and commercialization activities in an integrated manner.
This provision also applies to companies having the same controlling party or between those where there is a situation of control, which encompasses the real beneficiary rationale applicable under Colombian electric energy regulation (for reference see article 74 of 1994, as amended by Law 1955 of 2019. A situation of control is defined by article 260 of the Code of Commerce. On the other hand, transmission companies are prevented by law from holding market shares in generation, commercialization, or distribution companies (see CREG Resolution 001 of 2006).
In relation with transmission, (which comprises the transportation of electrical energy in the STN deploying tension levels of 220 kV or higher, guaranteeing the required quality standards and the availability of the transmission assets; the owners of the transmission assets must ensure free access to the transmission networks to the users and to generation agents) companies carrying out this activity are not able to develop commercialization, distribution or generation activities. However, commercialization, distribution and generation companies are allowed to hold shares, quotas or participation of corporate interest in the capital of transmission companies, as long as they represent no more than 15% of the company’s capital. Please note that, in this case, neither the transmission company nor the other companies may have a control situation over the other.
Exceptionally, commercialization, distribution and generation companies may own more than 15% of a transmission company if the income of the transmission company does not represent more than 2% of the total transmission income from the SIN. If the company engaged in the transmission activity, with a cut-off date of December 31 of each year, exceeds this limit, the commercialization, generation or distribution company who has shares, quotas or interest shares in the capital of the company must sell, within six months following the occurrence of this fact, the shares, quotas or interest shares that exceed 15% of the capital stock of the transmission company. This, unless within the same period, the transmission company sells the assets that makes it exceed the 2% limit of the total income.
The rules set forth by CREG Resolution 095 of 2007 Article 2 are applicable to Ecopetrol and, as of the date of this annual report, we are in compliance with all such requirements.
3.9.6 | Regulation of the Electricity Self-Generation Activity |
Law 1715 of 2014 regulates the integration of non-conventional renewable energies to the National Interconnected System. Among other aspects, this law obliges the Colombian Government and the CREG to develop the regulatory framework for the promotion of the electricity self-generating activity from non-conventional renewable energy sources, and the sale of self-generation surpluses.
Based on Law 1715 of 2014, Decree 2469 of 2014, as currently compiled by Section 4 of Decree 1073 of 2015, established energy policy guidelines regarding the delivery of self-generation surpluses through the SIN. In addition, this decree sets forth the parameters for a person to be considered as an electricity self-generator. Specifically, it states that in order to be considered a self-generator a person must (a) receive electricity for its consumption without it being necessary to use assets of the SIN, (b) the electricity surpluses may be higher in any measure, and without any regulatory limit or restrictions, than the value of its own consumption, (c) for the delivery of surpluses to the SIN it will be necessary for the self-generator to submit itself to the regulation of the CREG, case in which large-scale self-generators must be represented before the wholesale energy market, and (d) the generation assets may be owned by the self-generator and may be owned and operated by third parties.
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Decree 348 of 2017, as currently compiled by Section 4A of Decree 1073 of 2015, establishes public policy guidelines on efficient energy management and delivery of small-scale electricity self-generation surpluses. In addition, this regulation establishes the conditions for the connection of small-scale self-generators (AGPE for its Spanish acronym) to the SIN, the parameters to be an AGPE, the reporting of surpluses to the Mining and Energy Planning Unit (“UPME”) and the remuneration of surplus energy. Note that, as determined by Resolution UPME 281 of 2018, the maximum electricity generation limit to be considered an AGPE is one (1) MW and will correspond to the installed capacity of the self-generator’s generation system. Above that limit, an electricity self-generator will be considered a big-scale electricity self-generator (“AGGE” as per its acronym in Spanish).
The specific regulation for AGGE is currently determined by CREG Resolution 024 of 2015, whereas the specific regulation for AGPE is currently set by CREG Resolution 030 of 2018.
CREG Resolution 024 of 2015 (modified by CREG Resolution 140 of 2017) sets conditions for surplus sales of an AGGE, connection and metering conditions, and back-up and energy supply conditions. Specifically, this resolution determines that AGGE must follow the general connection rules to the SIN for a generation plant, that they must have a remote telemetry system, and that they must have a back-up power purchase agreement, among others.
CREG Resolution 030 of 2018 establishes the connection conditions for AGPE, surplus sales conditions, metering conditions and energy commercialization rules for AGPE. Note that CREG published CREG Resolution 002 of 2021, by means of which it published a project resolution in which it modifies the regulation for AGPE regarding the connection measurement, and surplus trade rules.
The Ecopetrol Group has invested in several projects that are considered projects from AGGE, which means that CREG Resolution 024 of 2015 is the main regulation that applies to Ecopetrol’s self-generation projects. As of the date of this annual report, Ecopetrol complies with all regulations, as set forth in the above-mentioned resolution and Decree 2469 of 2014 regarding the delivering of electricity surpluses to the SIN and to its subsidiaries or controlled parties.
3.10 | Technology, Environment, Social and Governance |
Ecopetrol has a long-standing commitment to positively contribute in terms of economic, social, and environmental development, and grounds its behavior on a solid corporate governance, a business conduct based on values and ethical principles, with transparency at its core. This work has been led in collaboration with our stakeholders through initiatives and strategies that have been framed in corporate responsibility and sustainability. The Company has strengthened its metrics and reporting of environmental, social and governance (ESG) issues in line with international standards.
Furthermore, Ecopetrol has identified that Technology (T), leveraged on applied innovation and the revolution brought about by digital transformation, is a key catalyst to accelerate and achieve in a timely manner the necessary changes to face ESG challenges. This is the new concept of TESG. The convergence between TESG and Ecopetrol’s corporate strategy marks a milestone that will change the future of the Company, where its transformation into an energy company is leveraged by technology. With this, we validate our commitment to be a Company that moves towards value creation in a sustainable future.
During 2020, Ecopetrol reviewed its environmental, social and governance (ESG) taxonomy, considering shifts in international trends related to these. One of the main findings of the project was that sustainability needs to be addressed from a technology standpoint that allows for the implementation of innovative solutions to current and future challenges in an accelerated and exponential way. The TESG strategy integrates technology to environmental, social, economic and governance issues, allowing for innovative solutions to have accelerated implementations and timely scalability, and is one of the four lines of action of our energy transition plan (See the section entitled Strategy and Market Overview—Our Corporate Strategy—2021 – 2023 Business Plan—Energy Transition).
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This strategy is based on a materiality analysis, which allowed the identification of 28 TESG topics that have or could have a significant impact (positive or negative) on our ability to generate value in the short, medium and long term and/or a significant relevance to stakeholders. Based on this analysis, Ecopetrol identified materiality as a dynamic and recurring process that is expected to be constantly reviewed. Moreover, although Ecopetrol manages all 28 TESG topics using four distinct categories (exceptional, outstanding, differentiated and compliance), in its disclosures, Ecopetrol will prioritize the following, based on their materiality:
Ecopetrol’s Material Topics
• Climate Change | • Circular Economy |
• Water Management | • Air Quality |
• Regional Development | • Fuel Quality |
• Health and Safety | • Use of energy and alternative sources |
• Biodiversity and Ecosystem Services | • Prevention and management of incidents by operations |
• Talent attraction, development and retention | • Prevention and management of incidents causes by third parties |
During 2020, we reviewed and updated our seven stakeholder groups (as defined below), given that their expectations and perceptions are considered within the materiality analysis. The methodology used for this update was based on the application of the AA1000 standard. Its purpose is to responsibly manage relationships with our key stakeholders, which leverages decision-making and strategic vision, resulting in long-term value creation.
Ecopetrol’s seven key stakeholder Groups are: (i) associates and partners, (ii) investors, (iii) clients, (iv) suppliers, contractors and their employees, (v) employees, retirees and their beneficiaries, (vi) state, and (vii) society and community.
As in previous years, during 2020 the Corporate Responsibility Area consulted the perceptions and expectations of our seven stakeholder groups with respect to the 28 TESG topics and corporate responsibility attributes. The results obtained for corporate responsibility in 2020 (84%) represent an improvement of 2% over the results obtained in 2019 (82%).
We also remain committed to improving our information disclosure standards by following international best practices. In particular, during 2020, and early 2021, the Company decided to begin the adoption of the Sustainability Accounting Standards Board (SASB), the recommendations of the Taskforce on Climate-related Financial Disclosures (TCFD), and the Stakeholder Capitalism Metrics (SCM) into our stakeholders’ reports.
During 2020, the environmental management strategy of Ecopetrol S.A. included the following components:
i. | Environmental Viability: this strategy concentrates on the planning, execution and submission of environmental impact assessments to national and regional authorities in order to obtain licenses and permits for project execution. Adequate project planning allows projects to pursue impact prevention and minimization through the mitigation hierarchy approach, ensuring the sustainability of operations and systematic relationships with stakeholders. |
ii. |
Mitigation: reducing our greenhouse gas emissions (GHG) and creating carbon offset alternatives as part of a comprehensive decarbonization plan;
Vulnerability and Adaptation: reducing the risks and impacts to our operations posed by climate variability and change;
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Research and Technology: investing on research and development to reduce our GHG emissions through low carbon technologies; and
Involvement in Policymaking: advising and influencing government policies on climate change.
Our decarbonization plan has four components: (i) GHG emissions inventory verification, (ii) development and implementation of an emissions reduction portfolio, (iii) design and implementation of an offset portfolio of natural climate solutions, and (iv) development of a net zero emissions roadmap.
As part of Ecopetrol S.A.’s efforts to contribute to the Sustainable Development Goals and the Paris Agreement, on March 25, 2021, Ecopetrol announced its plan to achieve net zero carbon emissions by 2050 (scopes 1 & 2), in line with its commitment to mitigate climate change and further the energy transition and the TESG agenda.
By 2030, Ecopetrol seeks to reduce its CO2e emissions by 25% as compared to the 2019 baseline for scopes 1 and 2, which correspond to direct and indirect emissions associated with the purchase of energy. In addition, Ecopetrol will seek to reduce 50% of its total emissions (scopes 1, 2 and 3) associated with the company’s value chain, which includes the use of its products, by 2050. However, we cannot offer any assurance on our ability to meet these goals by such dates.
The development of the goals proposed are a part of the Ecopetrol Group’s Corporate Strategy and energy transition roadmap. Progress on these goals is expected to be reported periodically in line with Company’s earnings results.
Ecopetrol continues to implement its emissions reduction portfolio, which includes specific programs and targets in relation to renewable energies, elimination of routine flaring, energy efficiency and reduction of fugitive emissions and venting. In 2020, we achieved a reduction of 199,847 tons of CO2e from projects implemented during that year. Ecopetrol has achieved a total accumulated reduction of 8,472,766 tons of CO2e during the 2010-2020 period, of which 1,756,163 tons of CO2e have already been verified by a third party.
iii. | Sustainable production system and biodiversity: Ecopetrol’s biodiversity strategy is based on two components: i) prevention and mitigation of biodiversity impacts and ii) implementation of nature-based solutions, to offset residual impacts and actively respond to challenges related to climate change, water resources and biodiversity management, food security or disaster risks, among others. Each of these themes are described below. |
i. | Prevention and mitigation of biodiversity impacts: |
ii. | Implementation of nature-based solutions: |
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iv. | Circular Economy: the circular economy model of Ecopetrol was structured in alignment with the National Circular Economy Strategy declared by the Ministry of Environment and Sustainable Development in 2019. This strategy defined the concept of circular economy as “production and consumption systems that promote efficiency in the use of materials, water and energy, taking into account ecosystem resilience, circular use of material flows through implementation of technological innovation, partnerships and collaborations between actors, and promotion of business models that respond to the fundamentals of sustainable development.” |
In this sense, the main goal of the circular economy model is to incorporate the concept into management processes in order to promote economic growth, improve competitiveness, and mitigate risks related to environment and price volatility in raw materials. The model’s five components are (i) efficient use of resources and new businesses, (ii) improvement and development of products and services, (iii) standards and public policy, (iv) territory management towards circularity, and (v) corporate culture.
The circular initiatives portfolio includes 333 initiatives: out of which 230 are being developed directly by Ecopetrol S.A., 97 by the Ecopetrol Group, and 6 by industrial symbiosis
v. | Water Management: this strategy aims to incorporate water management efficiency into the organization’s value chain, as a key element in project decision-making. Based on a sustainability framework, we aim to reduce environmental impacts and water-related conflicts, as well as incorporate water security stewardship initiatives in accordance with the following areas: (i) operational efficiency in water management; (ii) sustainability and water security in the environment; and (iii) water planning and governance. This strategy is aligned with the 2010 National Water Resources Policy, the 2018-2022 National Development Plan, the Green Growth Mission and the UN 2030 Sustainable Development Goals. |
Ecopetrol is also committed to improving the quality of the fuels it supplies in order to contribute to a better air quality for Colombians and comply with fuel quality regulations. Taking advantage of being an integrated company, after April 2018, we reduced the sulphur content in our diesel B2 (98% fossil and 2% biodiesel) to under 25 ppm. In particular, in 2020, the diesel and the gasoline that we distributed in Colombia had an average of 9.9 ppm and 84.9 ppm of Sulphur, respectively, below the current local regulations of 50 ppm in diesel and 300 ppm in gasoline.
Further information can be found in Ecopetrol’s 2020 Sustainability Report which is available on our website at: www.ecopetrol.com.co.
3.10.2 | Energy Initiatives |
Ecopetrol has been undertaking significant efforts to make efficient and rational use of energy resources in its production processes and to reduce energy consumption, costs and carbon dioxide emissions. We focus on efficiency, reliability, optimization and energy diversification.
Production
Further, during 2020, Ecopetrol’s production segment had an average monthly energy consumption of 402 GWhm (gigawatts per hour per month) for its direct operation, from which 66% was provided through self-generation and the remaining 34% with non-regulated energy purchased from the National Transmission System.
Transport
In January 2021, Ecopetrol started the construction of a second solar complex, San Fernando, in order to supply renewable energy to its transport and production operations. This second solar farm will have an installed capacity of 59 MW, which will add up, along with the current capacity of the Castilla Solar Farm (21 MW), a total capacity of 80 MW of solar generation in the Castillas’ solar farm. The San Fernando solar farm will supply part of the energy required by the San Fernando transport station and the Castilla field.
In 2021, the Ecopetrol Group will begin the development of six new photovoltaic projects for 45 MW that are expected to boost Colombia’s energy transition and that will be added to the San Fernando and Castilla solar farms.
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In terms of wind generation, we have identified prospects on the Atlantic Coast and Huila. Furthermore, the wind measurement activity was awarded in the Casablanca lot adjacent to the Cartagena Refinery, which began in January 2021.
Refining
During 2020, the Barrancabermeja refinery’s average monthly energy consumption was 53 GWhm (gigawatts per hour per month), provided through self-generation. The Cartagena Refinery’s average monthly energy consumption was 58 GWhm (gigawatts per hour per month), provided through self-generation.
3.10.3 | HSE |
This section describes the health, safety and environmental (HSE) practices of Ecopetrol S.A. Subsidiaries guidelines must be consistent with those established by Ecopetrol S.A.
Ecopetrol S.A. |
One of the principles that guides Ecopetrol is the commitment to its employees and the development of thosethe 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 2019,2020, compared with the prior year, were:
We have several programs in place aimed at increasing the safety of our industrial processes and minimizing the number of occupational accidents and other major incidents. Our HSE management model is based on key focus areas that are aligned with our integrated management system.
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Total Recordable Incidents Frequency – Employees and Contractors
Ecopetrol S.A. places an important emphasis on understanding, monitoring and controlling ourthe impacts on workers and contractors.
TRIF has improved from 2.96 incidents per million hours worked in 2012 to 0.590.43 in 2019.2020. In 2019, 742020, 46 recordable cases occurred, where 31%15% led to restricted work, 11%9% required medical treatment and 58%76% led to lost days. Additionally, we had an 8% increasea 38% decrease in the number of occupational incidents compared to 2018,2019, however, with increaseddecreased work hours in 2019.2020.
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Graph 7 – Total Recordable Incident Frequency – Employees and Contractors(*) (**)
* | Number of employee or contractor injuries requiring minimum medical treatment for every million hours worked. |
** | Includes data for Ecopetrol S.A. and the Vice-Presidency of Transport and Logistics, but does not include data for subsidiaries of Ecopetrol. |
Contingency Plans and Environmental Remediation
All of ourIn order to protect and minimize damage to people, the environment, and assets, Ecopetrol’s operational areas have preparednessdocumented, updated, disclosed and trained emergency and contingency plans to guarantee immediate, timely and effective intervention in the event of emergencies and disasters that may occur in our facilities and operations.
Emergency and contingency response plans eachare prepared in accordance with Colombian legal requirements and our newconsidering internal guidelines for emergency management.
Our preparedness and emergency responseguidelines. These 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 planswhich have the approval of the ANLA.National Authority for Environmental Licenses (ANLA), are part of the risk management procedures of the territories where we operate.
The objectives of ouremergency and contingency plans, are to:which have been developed from a risk and consequence analysis, cover the preparedness, response and recovery phases and include the following elements:
Further,
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Ecopetrol continuously implements training programs we are upgradingfor all personnel involved in emergency or contingency response plans. In the skills oflast four years, 13,457 trainings have taken place to improve our fire brigade, ensuringemployees’ skills. During 2019 and 2020, 7,033 training were carried out as shown in 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.table below:
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.Graph 8 – Trained personnel
Performance improvement has been achieved through the execution of the 36 emergency and contingency plans.
Frequency of process safety incidents
Our Process Safety Management (PSM) strategy is to: first, define high-risk processes; second, prioritize intervention in high-risk processes; and third, apply all PSM elements in the prioritized high-risk processes.
Loss of primary containment is the number of unplanned or uncontrolled releases of oil, gas or other hazardous materials.
We report Tier 1 process safety events per million hours worked, which are the losses of primary containment of greatest consequence causing harm to a member of the workforce, costly damage to equipment or exceeding defined quantities according to API-754. The reporting thresholds for API-754 Tier 1 is an unplanned or uncontrolled release of any material, including non-toxic and non-flammable materials, from a process that results in one or more health, safety or environmental consequences set forth under those guidelines. In 2019,2020, there were 0.030.05 Tier 1 process safety incidents per million hours worked, an improvementincrease from the 0.050.03 recorded in 2018.2019.
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Frequency of Tier 1 process safety incidents per hours worked (per million hours worked):
Graph 89 – 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 2019,2020, Ecopetrol S.A. recorded 64 environmental incidents, compared with 6 in 2019 and 11 in 2018 and 14 in 2017.2018. The volume of oil spills was 125 in 2020, a decrease from 142 barrels in 2019 and a decrease from 710.26 barrels in 2018 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.2018.
Lisama 158/La Fortuna Incident
On March 2, 2018, a seepage of water and traces of crude oil occurred near the Lisama 158 well, located in the village of La Fortuna, in the Middle Magdalena Valley of Colombia. Ecopetrol activated its contingency plan to contain the spill. 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:
Corrective and mitigation actions implemented by Ecopetrol
With respectIn due course, Ecopetrol carried out all the social, environmental and technical actions to fully attend the actions performed by Ecopetrol to address,event and mitigate other damages and manage the incident, in compliance ofwith the obligations contained in Law 1523 of 2012, Presidential Decree 321 of 1999 and the contingency plan forof the Lisama Well, Ecopetrol did the following:
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.Well.
In addition, forAfter closing the preparationevent and performanceabandoning of the Environmental Recovery Plan (PRA) whichwell, Ecopetrol proposedcontinues to implement environmental recovery actions, in accordance with the orders given by and filed beforein coordination with 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.authorities. Likewise, voluntary social investments have been fulfilled.
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:
Components of intervention:
Intervention strategies:
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$5.155 million. In the course of said administrative process, the ANLA exonerated Ecopetrol from liability for some charges, due to the fact that ANLA evidenced that Ecopetrol had activated its contingency plan and implemented the corresponding actions. It also mentioned that Ecopetrol’s environmental control actions were taken in an appropriate manner. Nonetheless, it decided to impose the fine, because the ANLA considered that the actions were not taken in a timely manner and because, it considered that Ecopetrol did not adopt and implement the necessary actions to correct the mechanic failures in the well, in order to prevent the environmental damage. On February 11, 2020, Ecopetrol filed a reconsideration appeal before ANLA requesting the reversal of this decision. On February 9, 2021, through Resolution 290, the decision of the ANLA was announced and reduced the fine to COP$ 3,863,918,267. The file is now closed by the environmental authority.
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The Attorney General’s Office (First Solicitor’s Office Delegate for Administrative Supervision) opened disciplinary investigations against certain of Ecopetrol’s employees for alleged disciplinary infringements related to the oil well abandonment process. The Company´s employees currently being investigated are:
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, thereThere are two additionalmore actions that have been filed before the Administrative Court of Santander, related to the Lisama 158 incident:
Approximately 600 people, members of the community and fishermen who live in the vicinity of where the incident took place, filed a class action in the amount of COP $614,503,232,689, seeking compensation for damages allegedly suffered as consequence of the incident. As of the date of this annual report the court has not scheduled a hearing date. On September 25, 2020, Ecopetrol informed Mapfre Seguros Generales de Colombia S.A. that it was seeking to invoke guarantee coverage by the guarantors.
Senator Antonio Eresmid Sanguino filed a class action, seeking protection of collective rights (no compensation or indemnification petitions), arguing that the incident led to the destruction of (i) people´s health and (ii) damages to the environment caused by the incident.
On October 2, 2018, the Administrative Court of Santander (competent judge) issued an interim measure whereby the latter ordered different authorities and Ecopetrol to perform various activities to prevent any additional environmental damage to occur.
On January 16, 2020, the High Court for Administrative Matters (Consejo de Estado) revoked the interim measure imposed by the Administrative TribunalCourt of Santander, considering that with the abandonment of the well “the risk that caused the production of the spill has been surpassed”. In its ruling, the High Court for Administrative Matters also mentioned that Ecopetrol has been taking the necessary actions to solve the damages produced by the incident, and also implemented the actions to repair the alleged damage. As of the date of this annual report, both complaints were properly answered and we are still awaiting for the commencement of the evidentiary stage.
On March 22, 2018, Ecopetrol made a claim to MAPFRE SEGUROS GENERALES DE COLOMBIA S.A., based on its Control of Well Policy and received the US$19 million in October 2019. Thereafter, as a result of the third party liability policy claim objection, Ecopetrol has taken the relevant actions to obtain the guarantee coverage of guarantors. On February 27, 2020, Ecopetrol filed a lawsuit against “MAPRE SEGUROS GENERALES DE COLOMBIA S.A.” to obtain recognition and payment of COP$ 128,807,833,685 based on civil liability. The court is analyzing the lawsuit.
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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 arehave been mainly conducted under Ecopetrol’s HSE model and guidelines, but from early 2021 Cenit controls all transportation activities under its own HSE model and guidelines.
Cartagena Refinery |
In 2019,2020, approximately 6,538,2955,179,195 man-hours were employed conducting Reficar’s business activities. Our HSE performance indicators for Total Recordable Incidents Frequency (TRIF), Process Safety Incident (PSI) and Environmental Incident (EI) were well within our established expectations, and Total Recordable Incidents Frequency (TRIF) performance improved in 2019 as compared to 2018.expectations.
The following table covers Reficar’s TRIF for 2017, 2018, 2019 and 2019,2020, which includeincludes 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 – 2019.2020.
Table 4146 – Performance Indicators
METRIC | 2019 | 2018 | 2017 | |||||||||||||||||||||
For the year ended December 31, | ||||||||||||||||||||||||
Metric | 2020 | 2019 | 2018 | |||||||||||||||||||||
Man-hours | 6,538,295 | 6,779,729 | 7,495,531 | 5,179,195 | 6,538,295 | 6,779,729 | ||||||||||||||||||
Recordable accidents | 1 | 12 | 9 | 1 | 1 | 12 | ||||||||||||||||||
Total recordable incidents frequency (TRIF)* | 0.15 | 1.77 | 1.2 | 0.19 | 0.15 | 1.77 | ||||||||||||||||||
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:
3.11 |
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:
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.
Ecopetrol S.A.
During 2019, the environmental management strategy of Ecopetrol included the following components:
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.
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.
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
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.
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 3031 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 day2020, an amendment including security standards for segment I and II and 14,000 barrels per day for segment III.the supply chain was executed.
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On July 29, 2014, after Ocensa implemented and carried out an open process to receive offers to enter into transportation agreements for an extended capacity of approximately 135,000 barrels per day in Ocensa’s pipeline (the P135 Project), Ocensa accepted the proposal made by Ecopetrol S.A. to enter into a ship-or-pay transportation agreement for 70,000 barrels per day of crude.
On November 20, 2014, after a total and definitive assignment agreement that was notified to Ocensa on December 15, 2016, Ecopetrol became the successor of Hocol, of a ship-or-pay transportation agreement for 17,500 barrels per day, thus increasing Ecopetrol’s contracted capacity in the P135 Project to 87,500 barrels per day.
On July 1, 2017, with the consent of Ecopetrol and Ocensa, and as contemplated in the Act of Commencement of Operations issued by the Ministry of Mines and Energy (Resolution 31344 dated April 27, 2017), Ocensa started supplying increased capacity in the P135 Project.
On July 17, 2018, Ecopetrol and Ocensa entered into an amendment to the P135 Project ship-or-pay transportation agreements mentioned above (consisting of a capacity of 87,500 barrels of crude per day) in order to adjust the standard tariff and monetary conditions. This followed Ocensa having entered into a settlement agreement as approved by an arbitration panel with Frontera Energy Colombia and executed on May 15, 2018 pursuant to which the transportation tariff and monetary conditions in Ocensa’s ship-or-pay transportation agreement with Frontera Energy Colombia in respect of the P135 Project were adjusted. Therefore, in application of regulatory principles, Ocensa offered similar terms to the remaining shippers of the P135 Project, including Ecopetrol, and executed (i) settlement agreements with those who accepted Ocensa’s offer and (ii) the corresponding amendments to the transportation agreements.
In 2019,2020, payments made by Ecopetrol S.A. under these two agreements amounted to US$1,193.37 1,099.85 million.
On October 28, 2013, Ecopetrol entered into a natural gas supply contract in force until November 30, 2018, pursuant to which Ecopetrol S.A. supplies gas to Ocensa and receives a fixed price per MBTU (million(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$4.62 million under the contract. On December 1, 2019, the parties agreed to extend the term of the agreements for two years until December 1, 2021. In 2020, Ecopetrol S.A. received an aggregate sum of US$ 3.67 million under the contract.
Ocensa has entered into the following agreements, among others, with some of our other subsidiaries:
In March 1995, EquionEquión and Santiago Oil Company entered into agreements for the transportation of crude oil through the Oleoducto Central S.A. (Ocensa) pipeline. In November 2012, EquionEquión 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%). EquionEquión and Santiago Oil Company kept 5% of transportation rights in Ocensa. In 2014, the transportation fees billed by Ocensa were: EquionEquión (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, Equion2020, Equión paid Ocensa US$3.07 million and Santiago Oil Company US$0.25 million, in each case for transportation fees. 0.26 million. Hocol paid Ocensa, as assignee of transportation rights from original shippers, US$28.73 30.30 million in 2019.2020.
Oleoducto de Colombia S.A. (ODC)
Ecopetrol S.A. entered into the following agreements with its 73%-owned subsidiary, ODC:
In July 1992, a ship-and-pay agreement was signed for the transportation of hydrocarbons. Pursuant to this agreement, Ecopetrol S.A. must pay a previously agreed tariff for the volume of hydrocarbons transported. The duration of this agreement is indefinite; however, the contract will remain in force as long as Ecopetrol S.A. holds shares in Oleoducto de Colombia S.A., whether directly, or through an affiliate. As of January 2013, the parties agreed that the applicable tariff would be the one set by the Ministry of Mines and Energy (the MME Tariff). The MME Tariff had been set in 2011 for a four-year term, with a yearly adjustment based on the consumer price index. In 2019,2020, payments made by Ecopetrol S.A. under this agreement amounted to US$89.6140 million.
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In August 1992, an operation and maintenance agreement was signed for the Vasconia and Coveñas terminals both property of ODC. The duration of this agreement is indefinite, but can be terminated by any party upon six months’ notice. The initial contract included services rendered by Ecopetrol directly or by third-party contractors hired by Ecopetrol through mandate, with a variable surcharge over expenses and third-party contracts between 5% and 12% plus any applicable taxes. In 2014, an amendment to the agreement was signed, adjusting the monthly fixed rate to include expenses of services rendered directly by Ecopetrol, plus an additional 10% fee, and to eliminate the administrative surcharge. The contract also includes a variable sum related to contracts and purchases made by Ecopetrol through mandate. In March 2015, the monthly rate was adjusted for both Vasconia and Coveñas Stations. In March 2016, an amendment to the agreement was signed, adjusting the agreement’s scope to include the pipeline’s maintenance and adjusting the monthly fixed rate. In December 2017, an amendment to the agreement was signed, adjusting the agreement’s scope according to the change of the maintenance model of the midstream segment and including the Caucasia station and the Vasconia-Coveñas pipeline system into the scope. In March 2018, the parties amended the agreement in order to narrow the scope to the purchase and contracting management, and adjust the monthly rate. In February 2019 the scope of this agreement was amended to include planning, structuring, administration, and execution of the agreements signed with the Ministry of National Defense- Fuerzas Militares de Colombia. In July 2020, an amendment to the agreement was signed, adjusting the monthly fixed rate. Pursuant to the terms of this agreement, ODC paid approximately US$4.0 4.36 million in 2019.2020.
In March 1998, a joint operation agreement was signed for the TLU-1 Coveñas buoy. The duration of this agreement is indefinite and can be terminated by mutual agreement. In December 2013, Ecopetrol S.A. assigned its rights under this agreement to Cenit, though Ecopetrol S.A. kept its role as operator under the agreement. Pursuant to the terms of this agreement, ODC paid Ecopetrol S.A. approximately US$12.20.86 million in 2019.2020.
In September 1999, a joint operation agreement was signed for the TLU-3 Coveñas buoy between Ocensa, ODC and Ecopetrol. Pursuant to the terms of this agreement, ODC paid approximately US$5.61.96 million in 2019.2020. The duration of this agreement is indefinite. In December 2013, Ecopetrol S.A. assigned its rights under this agreement to Cenit, though Ecopetrol S.A. kept its role as operator under the agreement.
ODC has entered into the following agreements with some of our other subsidiaries:
Between March 1992 and January 1993, Hocol, EquionEquión 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 2019,2020, the transportation fees billed by ODC were: EquionEquión (US$1.0 million), Santiago Oil Company (US$0.002 0.71 million) and Hocol (US$0.58 0.66 million).
Oleoducto de los Llanos Orientales (ODL)
Ecopetrol S.A. has entered into the following agreements, among others, with its 65%-owned subsidiary, ODL:
In March 2009, Ecopetrol S.A. entered into a ship-or-pay agreement with ODL that establishes a financing tariff used to pay ODL’s indebtedness to Grupo Aval for five years. This agreement was superseded by a new contract executed in May 2010, with a seven-year term, to reflect new conditions agreed with Grupo Aval. In August 2013, this contract was amended, providing a new term of seven years, including a two-year grace period, and an interest rate of DTF + 2.5%. This financing tariff is collected through a trust fund, which in turn is responsible for making the debt service payments to Grupo Aval. Under this agreement, ODL has committed to transport 75,000 bpd during the initial two-year grace period of the facility and 90,000 bpd during the remaining years, including the new term. Ecopetrol S.A. is responsible for 65% of this capacity. Payments by Ecopetrol S.A. under this contract were COP$90.3 63.87 billion in 2019.2020.
In December 2009, Ecopetrol S.A. entered into a service agreement with ODL to transport crude oil. This agreement was replaced in January 2014 by a new agreement that expires in December 2020. This is a ship-or-pay agreement covering 167,000 bpd for 2014, 149,000 bpd for 2015 and 139,000 bpd until 2020. In January 2017, this agreement was amended in order to maintain the economic and commercial balance for the parties, based on changes to the standard condition of the system (to transport crude oil with a 690 cStk viscosity), reducing the “ship-or-pay” capacity from 139,000 bpd to 129.139 bpd until 2020. This agreement was extended under the “ship-and-pay” conditions until December 2021. Payments by Ecopetrol S.A. under this contract were COP$808.7 678.4 billion in 2019.2020.
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In March 2010, Ecopetrol S.A. entered into a pipeline operating and maintenance agreement with ODL. This agreement had an original five-year term and was amended in 2015 to extend the term another ten years, adjusting certain conditions. In January 2017, this agreement was partially assigned by Ecopetrol to Cenit, due to matters related to the management of plants and pipeline assets. In August 2017, the maintenance obligations were partially assigned by Ecopetrol to a third party. In October 2017 and February 2018, the name of the contract, some technical definitions and the annexes of the contract were updated and certain Ecopetrol’s obligations were removed, in line with the partial assignment,assignment. In March 2020 the agreement was finished by the term of the contract and the new one was assigned to a third party. Pursuant to the terms of this agreement, ODL paid to Ecopetrol S.A. COP$6.56 2.17 billion, plus applicable taxes, in 2019.2020. In addition, pursuant to the partial assignment ODL paid to Cenit COP$0.82 0.05 billion, plus applicable taxes, in 2019.2020; this agreement terminated in March 2020, and the operation was assigned to a third party.
InOn 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. InOn 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 7.68 billion plus applicable taxes in 2019.2020.
Oleoducto Bicentenario de Colombia S.A.S.
Ecopetrol S.A. has entered into the following agreements, among others, with its 55.97% owned subsidiary, Oleoducto Bicentenario:
In June 2012, Ecopetrol S.A. entered into ship-or-pay and ship-and-pay agreements with Oleoducto Bicentenario for the transportation of crude oil from Araguaney to Banadía that established a price which requires the payment of Oleoducto Bicentenario’s indebtedness to local banks for 12 years. This tariff is collected through a trust; the trust is also responsible for making the debt service payments to the banks. The duration of the ship-or-pay agreement is the earlier of 12 years or when the credit has been entirely paid, and the duration of the ship-and-pay agreement is 20 years after the ship-or-pay terminates. Under these agreements, Oleoducto Bicentenario has committed to transport at least 110,000 bpd, of which 55% of the agreement volume is provided directly by Ecopetrol S.A. and 0.97% indirectly by Hocol. In March 2014, the parties signed an amendment to these agreements under which Oleoducto Bicentenario acknowledges having received an advance tariff payment which can be amortized through volumes of crude transported in excess of 110,000 bpd. In April 2015, these agreements were amended to modify certain definitions to reflect new terms from the negotiation of the debt, which included a modification of participant banks and a reduction of the interest rate. In March 2017, the parties signed an amendment to these agreements in order to include the terms and conditions of the “contingent service” that involves the transportation of crude oil from Banadía to Araguaney when this service is required, and includes a ship-or-pay commitment of 270,000 bpd when the contingent service is needed. In addition, this amendment includes an equivalent credit note of one and a half days of service into the original ship-or-pay agreement for the transportation of crude oil from Araguaney to Banadía. Hocol has signed an amendment to the transportation agreement from Araguaney to Banadía, in order to receive the related credit note in case that the availability of the service in that direction is suspended in order to enable the contingent service (Banadía-Araguaney). In September 2017 the agreement was amended to specify that the “contingent capacity” could be over 180,000 barrels per any “contingent service” operation and to extend the term until July 30, 2018. In July 2018, the agreement was amended to extend the term to provide the “contingent service” until March 23, 2019. In September 2018, this agreement was assigned by Hocol to Ecopetrol. In November 2018, the agreement was amended to remove the restriction on the number of contingent services during 2018. In March 2019, the agreement was amended to extend the term to provide the “contingent service” until June 21, 2019. In June 2019, the agreement was amended to extend the term to provide the “contingent service” until September 21, 2019. In September 2019, the agreement was amended to extend the term to provide the “contingent service” until December 21, 2019. In October 2019, the agreement was amended to remove the restriction on the number of contingent services during 2019. In December 2019, the agreement was amended to extend the term to provide the “contingent service” until June 21, 2020. In June 2020 and December 2020, the agreement was amended to extend the term for six months to provide the “contingent service” until June 21, 2021. Pursuant to the terms of these agreements, in 2019,2020, Ecopetrol and Hocol paid COP$839.7 626.77 billion to Bicentenario S.A.
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In June 2012, Ecopetrol S.A. and Hocol entered into storage or pay and storage and pay agreements with Oleoducto Bicentenario. Under these agreements, Oleoducto Bicentenario is committed to receive, store, preserve and deliver our crude oil. The storage or pay agreement will terminate when Oleoducto Bicentenario’s indebtedness to local banks has been entirely paid, and the duration of the storage and pay agreement is 20 years after the storage or pay agreement terminates. In April 2015, this contract was amended to modify certain definitions to reflect new terms from the negotiation of the debt, which included a modification of participant banks and a reduction of the interest rate. In September 2018, this agreement was assigned by Hocol to Ecopetrol. Pursuant to the terms of this agreement, Ecopetrol and Hocol paid to Bicentenario COP$27.4 39.0 billion, plus applicable taxes, in 2019.2020.
In August 2012, Ecopetrol S.A. entered into an Operation and Maintenance agreement for the Araguaney – Banadia pipeline system. The duration of this agreement is 15 years. This agreement was partially assigned in January 2017 by Ecopetrol to Cenit due to matters related to the management of plants and pipeline assets. In July 2018 Oleoducto Bicentenario and Cenit signed a settlement agreement to recognize costs related to this contract. The scope of the contract assigned by Ecopetrol to Cenit was finished by the mutual agreement of the parties (Bicentenario and Cenit) in March 2020. Pursuant to the terms of those agreements, Bicentenario paid to Cenit COP$0.93 0.05 billion, plus applicable taxes, in 2019.2020.
In November 2017, the maintenance obligations of the transportation system (from the first agreement mentioned in the preceding paragraph) were partially assigned to Cenit S.A.S.a third party. During December 2017, the agreement with Ecopetrol was modified to exclude from its scope the Araguaney and Banadía Stations’ maintenance. In November 2018, the pipeline maintenance obligations were extended until April 2019. While thisIn April 2019, the pipeline maintenance obligations were extended until July 2019. In July 2019, the pipeline maintenance obligations were extended until October 2019. In October 2019, the pipeline maintenance scope was substituted by technical supervision and in July 2020, the technical supervision scope was terminated by mutual agreement has now been terminated, pursuantof the parties. However, the operational scope of the contract is still valid. Pursuant to the terms of this agreement, Bicentenario paid to Ecopetrol S.A. COP$8.8 5.83 billion, plus applicable taxes, in 2019.2020.
Ecodiesel
Ecopetrol S.A. (Ecopetrol) entered into a supply agreement for the Barrancabermeja refinery, with Ecodiesel Colombia S.A. (Ecodiesel), a company in which Ecopetrol 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 20192020 a total of COP$270 283.4 billion was paid under this contract. In April 2020, Ecopetrol made a spot purchase to Ecodiesel for consumption in the Port of Buenaventura for COP$ 0.4 billion. A new agreement began on February 1, 2020 for the delivery of 50,880 barrels of Ecodiesel’s biodiesel production each month. The new agreement will be active until January 31, 2026.
Additionally, Ecopetrol, as Reficar’s legal agent, signed another supply agreement with Ecodiesel on October 2, 2019 that was valid until September 30, 2020 and pursuant to which Ecopetrol agreed to buy up to 156,000 barrels of biodiesel for a year from Ecodiesel. A total of COP$ 46.4 billion was paid under this contract. On October 1, 2020, Ecopetrol and Ecodiesel signed another supply agreement for the supply of biodiesel to Reficar that is valid until September 30, 2023. Pursuant to the terms of this agreement, Ecodiesel must deliver to Reficar, and Reficar must in turn purchase 10,400 barrels of Ecodiesel’s biodiesel production each month. In the fourth quarter of 2020, Reficar paid a total of COP$ 19.6 billion to Ecodiesel under this agreement.
In 2020, Ecopetrol bought COP$ 283.8 billion worth of biodiesel from Ecodiesel for its own consumption and COP$ 66 billion worth of biodiesel for Reficar’s consumption.
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Savia Peru S.A.
On February 19, 2016, Ecopetrol S.A., as lender and shareholder of 50%, and Savia Perú S.A., as borrower, entered into a five-year loan agreement for an aggregate principal amount not to exceed US$70 million. The proceeds of the facility were used to (i) repay short term loans and (ii) pay shortfalls related to final judgments (in case they materialize). The loan agreement accrues interest at an annual rate of 4.99%, which can be adjusted on an annual basis, with semi-annual interest payments and principal payments beginning on the 21st month following the disbursement date. Total disbursement was US$57 million through the disbursement period ended on December 31, 2017. On December 11, 2019, Ecopetrol and Savia Perú agreed on an amendment to the terms of the loan agreement, in order to revise the payment schedule of the loan, without changing the original maturity, nor the interest rate. As of AprilDecember 2020, the outstanding balance of the obligation with Ecopetrol is US$28.3 million under the loan agreement. Korea National Oil Corporation (KNOC), as shareholder of the other 50% of Savia Perú S.A., signed a facility under the same terms and conditions as described above.
On January 19, 2021, Ecopetrol S.A. signed a Share Purchase Agreement with De Jong Capital LLC, through one of its subsidiaries as buyer, pursuant to which Ecopetrol sold its 50% ownership interest in OIG. Korea National Oil Corporation (KNOC) also sold its participation on OIG (the remaining 50%) to De Jong Capital LLC, under the same terms and conditions as Ecopetrol.
On the same date, Ecopetrol and Savia Perú agreed on an amendment to the terms of the loan agreement described above, in order to revise the payment schedule of the loan and its maturity, with the interest rate remaining unchanged. As of the date of this annual report, Savia Peru owed US$ 26.8 million to Ecopetrol under this loan agreement.
Transactions with Other State-Controlled Entities
In the ordinary course of business, we enter into transactions with other state-owned enterprises that include but are not limited to the following:
In addition, we have an agreement with the ANH (National HydrocarbonHydrocarbons Agency) by which we purchase all crude oil delivered to the ANH as royalties by us and by third parties. The purchase price is calculated according to a formula set forth in a contract between Ecopetrol and the ANH that reflects our export sales prices (crudes and products), a quality adjustment for API gravity and sulphur content, transportation rates from the wellhead to the Coveñas or Tumaco ports and a marketing fee. We sell the physical product purchased from the ANH as part of our ordinary business.
For the years ended December 31, 2020, 2019 2018 and 2017,2018, we purchased the following volumes of crude oil from the ANH corresponding to royalties paid in kind by oil producers in Colombia: 31.0 million barrels, 35.4 million barrels 37.6 million barrels and 40.337.6 million barrels, respectively. The contract between the ANH and us was extended until April 30, 2020.October 31, 2022. See the sectionBusiness Overview—Overview—Applicable Laws and Regulations—Regulation of Exploration and Production Activities—Business Regulation—Regulation—Royalties for a description of the current royalty scheme.
The ANH is a state agency responsible forthe administration and regulation of the nation'snation’s hydrocarbon resources and therefore it is controlled by the State. The State’s control of the ANH arises from the fact that it is a state agency and hence a part of the Colombian government. On the other hand, Ecopetrol is a state-owned enterprise and the Nation’s control of Ecopetrol results from the fact that it is one of our shareholders and owns more than a majority of our common shares. Neither Ecopetrol nor the ANH have the ability to control each other’s actions. Notwithstanding that as a matter of Colombian law neither entity can influence the other, as a matter of U.S. regulation, they are considered to be under common control.
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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.
ThereAs a proactive strategy to deal with the hardening conditions of the worldwide reinsurance market for the last three years, in July 2020, Ecopetrol became a member of the OIL Pool. OIL is an energy industry mutual insurance company based in Hamilton, Bermuda, established since 1972. This organization operates on the basis of the concept of mutualization, in which several companies threatened by similar risks and with comparable exposure profiles decide to constitute a common fund, based on the individual contribution of each one, depending on the size of their operation and the estimated losses they may suffer as a result of the materialization of such risks. OIL insures assets worldwide for a total value over US$3trillion. Its credit rating is A (S&P) and A2 (Moody's). Currently, 61 companies in the world are threemembers of OIL.
Under the model described above, the corporate insurance program has been consolidated in two main categories:
i. | Category A: Coverage through the OIL pool and reinsurance market that includes the risks of physical damage, control of wells and leakage, pollution or contamination (which for the purposes of this annual report, are included in the limit of the third party liability coverage). |
ii. | Category B: Coverage only through the traditional insurance and reinsurance market that includes third party liability, directors and officers, cargo, crime, charterers’ liability and cyber-attack insurance. |
These structures provide coverage for our consolidated downstream, upstream and midstream operations in excess of our local insurance programs covering Ecopetrol S.A. and its subsidiaries. (when applicable).
In the text and tables below we set forth our insurance programsprogram and the companies covered, along with limits and coverage details.
Group 1-Table 47 – Category A: Coverages through the Oil Pool and Reinsurance and Insurance Market for the Downstream Program:This insurance program provides coverage for downstream (assets and operations) of Ecopetrol S.A. and all of its subsidiaries in excess of their local insurance programs, when applicable. Coverage includes all physical damage and sabotage and terrorism, which were designed to cover downstream operations.
Table 42 – Group 1 Downstream Program(figures in US$ millions)Segment
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 | 5 | N/A | X | X | X | X | ||||||||
Sabotage and terrorism | 600 | N/A | 0.5 | N/A | X | X | X | X |
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 | Limit (eel / agg)(1) | Deductible | Ecopetrol | ||||||||||||||||||||||||||||||||||||||||||||||||||
US$ Millions | Onshore | Offshore | Onshore | Offshore | Downstream | Reficar | Esenttia | |||||||||||||||||||||||||||||||||||||||||||||||||||
Policies | Onshore | Offshore | Onshore | Offshore | Upstream | Equion | Hocol | Oil | America | Brazil | Afuera | |||||||||||||||||||||||||||||||||||||||||||||||
Property all risk | 400 | (2) | N/A | 0.5 | 0.5 | X | X | X | X | X | N/A | X | 2,200 | N/A | 5 | N/A | X | X | X | |||||||||||||||||||||||||||||||||||||||
Sabotage and terrorism | 55 | N/A | 0.5 | N/A | X | X | X | X | N/A | N/A | X | 600 | N/A | 0.5 | N/A | X | X | X | ||||||||||||||||||||||||||||||||||||||||
Control of Wells | 350 / 75 | (3) | 800 / 300 | 0.25 | 5/6 | X | X | X | N/A | X | X | X |
(1) | Eel: each and every loss. Agg: Aggregate. |
Note: Due to its liquidation, Bioenergy was not included in the renewal of Ecopetrol’s corporate insurance program for 2021.
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Table 48 – Category A: Coverages through the Oil Pool and Reinsurance and Insurance market for the Upstrem segment
Limit (eel / agg)(1) | Deductible | Ecopetrol | |||||||||||||||||||||||||||||
US$ Millions | Onshore | Offshore | Onshore | Offshore | Upstream | Equión | Hocol | Santiago Oil | ECP America | Permian | ECP Costa Afuera | ||||||||||||||||||||
Policies | |||||||||||||||||||||||||||||||
Property all risk(2) | 400 | N/A | 1.0 | N/A | X | X | X | X | X | X | X | ||||||||||||||||||||
Sabotage and terrorism | 400 | N/A | 0.5 | N/A | X | X | X | X | N/A | X | N/A | ||||||||||||||||||||
Control of wells(3) | 250 / 75 | 800 / 300 | 1.0 | 5 / 6 | X | X | X | N/A | X | X | N/A |
(1) | Eel: each and every loss. Agg: Aggregate. |
(2) | US$250 million Property All Risk but US$400 million Maximum Loss limit and in the aggregate in respect of earthquakes. |
(3) |
Group 3Table 49 – Category B: Transversal Program:This program provides coverageCoverages through the Traditional Insurance and Reinsurance Market for downstream, upstreamthe Downstream, Upstream and midstream operations of Ecopetrol and all of its subsidiaries in excess of their local insurance programs. Coverage includes general liability, directors and officers, cargo, crime, charterers’ liability and cyber-attack insurance.Midstream Segments
Table 44 – Group 3 Transversal Program(figures in US$ millions)
US$ Millions | Limit (eel / agg)(1) | Deductible | Ecopetrol | Reficar | Esenttia | Esenttia MB | Equión | Hocol | Santiago Oil | ECP America | Permian | Brazil | ECP Costa Afuera | Cenit | Ocensa | ODL | OBC | ODC | Invercolsa | ||||||||||||||||||||||
Policies | |||||||||||||||||||||||||||||||||||||||||
Third party liability | 500 | 10.0 | X | X | X | X | X | X | X | X | X | X | X | X | X | X | X | X | N/A | ||||||||||||||||||||||
Crime | 35 | 0.5 | X | X | X | X | X | X | X | X | X | X | X | N/A | N/A | N/A | N/A | N/A | X | ||||||||||||||||||||||
Directors & Officers | 65 | Various | X | X | X | X | X | X | X | X | X | X | X | X | X | X | X | X | X | ||||||||||||||||||||||
Cargo | 75 | 3% dispatch | X | X | N/A | N/A | N/A | X | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | ||||||||||||||||||||||
Charterers | 750 | 0.02 | X | X | N/A | N/A | N/A | X | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | ||||||||||||||||||||||
Cyber(2) | 25 / 150 | Various | X | X | X | X | X | X | X | X | X | X | X | X | X | X | X | X | X |
Limit (eel/agg)(1) | ||||||||||||||||||||||||||||||||
Policies | Limit | Deductible | Ecopetrol | Reficar | Esenttia | Bioenergy | Equion | Hocol | Santiago Oil | ECP America | Brazil | Cenit | Ocensa | ODL | OBC | ODC | ||||||||||||||||
Third Party Liability | 500 | Various | X | X | X | X | X | X | X | X | X | X | X | X | X | X | ||||||||||||||||
Crime | 30/60 | Various | X | X | X | X | X | X | X | X | X | N/A | N/A | N/A | N/A | N/A | ||||||||||||||||
Directors & Officers | 50 | Various | X | X | X | X | X | X | X | X | X | X | X | X | X | X | ||||||||||||||||
Cargo | 75 | 3% dispatch | X | N/A | N/A | N/A | N/A | X | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | ||||||||||||||||
Charterers | 750 | 0.02 | X | X | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | N/A | ||||||||||||||||
Cybers | 25/200 | Various | X | X | X | X | X | X | X | X | N/A | N/A | N/A | N/A | N/A | N/A |
(1) | Eel: each and every loss. Agg: Aggregate. |
(2) | Coverage under section one (buyback for property) only applies to Ecopetrol S.A. whereas coverage under Sections two to nine apply to Ecopetrol and its downstream, midstream and upstream subsidiaries. |
Our third-party liability insurance policies coverpolicy covers Ecopetrol S.A., our subsidiaries and affiliates in excess of local underlying policy limits for claims made against them by third parties. Our commercial general liability coverage will pay on behalf of or indemnify amounts for which an insured becomes legally obligated to pay, including damages in respect of bodily injury, property, pollution and product liability. Coverage of bodily injury and property damage is subject to coverage territory during the policy period.
Ecopetrol’s midstream subsidiaries (Cenit, Ocensa, ODL, Bicentenario Pipeline and ODC) havecontinue having an independent program for itstheir oil transportation companies (including crime and directors & officers policies).
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Table 4550 – Midstream Program(figures in US$ millions)
Limit (eel/agg)(1) | Deductible | Limit (eel / agg)(1) | Deductible | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Onshore | Offshore | Onshore | Offshore | Cenit | Ocensa | ODL | OBC | ODC | ||||||||||||||||||||||||||||||||||||||||||||||||
US$ Millions | Onshore | Offshore | Onshore | Offshore | Cenit | Ocensa | ODL | OBC | ODC | |||||||||||||||||||||||||||||||||||||||||||||||
Policies | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property all risk | 200(2) | 200(2) | 0.25 | 0.5 | X | X | X | X | X | 200 | 200 | 0.250 | 0.50 | X | X | X | X | X | ||||||||||||||||||||||||||||||||||||||
Sabotage and terrorism(3) | 70 | 20 | 0.075 | 0.5 | X | X | X | X | X | 70 | 30 | 0.075 | 0.15 | X | X | X | X | X | ||||||||||||||||||||||||||||||||||||||
Third Party Liability | 100 | 100 | 0.35 | 0.35 | X | X | X | X | X | |||||||||||||||||||||||||||||||||||||||||||||||
D&O | 100(4) | 0.05 | X | X | X | X | X | |||||||||||||||||||||||||||||||||||||||||||||||||
Third party liability | 100 | 100 | 0.100 | 0.50 | X | X | X | X | X | |||||||||||||||||||||||||||||||||||||||||||||||
Directors & Officers(4) | 75 | - | X | X | X | X | X | |||||||||||||||||||||||||||||||||||||||||||||||||
Crime | 25 | 0.1 | X | X | X | X | X | 50 | 0.175 | X | X | X | X | X |
(1) | Eel: each and every loss. Agg: Aggregate. |
(2) | US$200 million each company and an aggregated excess shared limit of US$ |
(3) | Does not include Caño Limón – Coveñas (CLC) and Oleoducto Transandino (OTA) systems owned by Cenit. |
(4) | Aggregate limit of US$ |
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. ForIn 2020, we obtained a stand-alone policy for the other insurance lines, stand-alone policies have been analyzed to start coverage in 2020.
third party liability coverage. Ecopetrol S.A. has a contract with an insurance broker for local policies related to domestic operations. The local policies relate to transit, accidents, mandatory policies, liability mandatory policies, and personal accidents policies, among others. Additional policies are requested from the insurers as they are needed.
Human Resources/Labor Relations |
Employees |
As of December 31, 2019,2020, the Ecopetrol Group had 15,15713,977 employees, an increasea decrease of 23.95% from 2018.7.8% compared to 2019. This increasedecrease was primarily due to the inclusionBioenergy liquidation, the early retirement plan offered to a group of Invercolsaemployees, resignations and its subsidiaries’ employees within the consolidated resultstermination of the Ecopetrol Group.temporary contracts. Most of our employees are located in Colombia.
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The table below presents the breakdown of Ecopetrol employees according to the business segments where they work, and the personnel of our subsidiaries for the years ended December 31, 2020, 2019 2018 and 2017.2018.
Table 46 –Ecopetrol51 – 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.
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Number of employees) | ||||||||||||
Ecopetrol S.A. | ||||||||||||
Exploration and Production | ||||||||||||
Exploration | 208 | 227 | 215 | |||||||||
Production | 2,271 | 2,324 | 2,258 | |||||||||
Others | 712 | 501 | 758 | |||||||||
Total Exploration and Production | 3,191 | 3,052 | 3,231 | |||||||||
Downstream | - | - | - | |||||||||
Refining | 2,526 | 2,661 | 2,696 | |||||||||
Marketing | 145 | 145 | 136 | |||||||||
Others | 38 | 37 | 74 | |||||||||
Total Downstream | 2,709 | 2,843 | 2,906 | |||||||||
Transport | 802 | 860 | 798 | |||||||||
Others | 820 | 796 | 351 | |||||||||
Total Operations | 7,522 | 7,551 | 7,286 | |||||||||
Corporate | 2,248 | 2,536 | 2,417 | |||||||||
Total Ecopetrol S.A. | 9,770 | 10,087 | 9,703 | |||||||||
Ecopetrol America LLC. | 47 | 66 | 68 | |||||||||
Ecopetrol Permian LLC. | 16 | - | - | |||||||||
Ecopetrol USA | 29 | - | - | |||||||||
Bioenergy S.A.S. | - | 478 | 441 | |||||||||
Bioenergy Zona Franca S.A.S. | - | 287 | 279 | |||||||||
Hocol S.A. | 346 | 249 | 221 | |||||||||
Equión Energía Limited | 38 | 242 | 284 | |||||||||
Oleoducto Central S.A. | 283 | 288 | 275 | |||||||||
Oleoducto de Colombia S.A. | 15 | 7 | 3 | |||||||||
Oleoducto de los Llanos S.A. | 77 | 79 | 75 | |||||||||
Oleoducto Bicentenario de Colombia S.A.S. | - | - | - | |||||||||
Ecopetrol del Perú S.A. | - | - | - | |||||||||
Ecopetrol Costa Afuera de Colombia S.A.S. | - | - | - | |||||||||
Refinería de Cartagena S.A.S. | 98 | 143 | 153 | |||||||||
Ecopetrol Óleo e Gás do Brasil Ltda. | 35 | 31 | 16 | |||||||||
Esenttia S.A. | 417 | 412 | 428 | |||||||||
Esenttia MB | 41 | 46 | - | |||||||||
Cenit Transporte y Logistica de Hidrocarburos S.A.S. | 511 | 366 | 282 | |||||||||
Invercolsa | 2,247 | 2,371 | - | |||||||||
Ecopetrol Energía S.A. E.S.P | 7 | 5 | - | |||||||||
TOTAL | 13,977 | 15,157 | 12,228 |
As of December 31, 2019,2020, 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 GlodGold 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 2019,2020, Ecopetrol S.A. has extended 1,248833 housing loans for a total of COP$292 209.6 billion and 2,5271,411 general-purpose loans for a total of COP$25.9 15.3 billion. In 2019,2020, Ecopetrol S.A. also provided on-site and external training and development, which totaled to COP$38.9 15.9 billion, and it extended a total of COP$171.7 186.5 billion in subsidies for education.
We have not provided loans (including housing loans), extended or maintained credit lines, arranged for the extension of credit by third parties, materially modified or renewed an extension of credit lines, in the form of a personal loan to or for any of our executive officers since our ADSs were registered under the Exchange Act.
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There are noEcopetrol does not offer credits to any of its executive officers with loans from Ecopetrol.officers.
Labor Regulation
In accordance with Article 123 of the Colombian Constitution and the Article 7th of the Law 1118 of 2006, our employees are considered “public servants,” even though they are subject to the common labor law. As such, their behavior is subject to the rules to those who handle public interests and goods and could be held liable for their illegal actions and omissions pursuant to the following regimes: (i) disciplinary (Law 734 of 2002), (ii) criminal or (iii) civil.
Declaration of Culture
In 2020, Ecopetrol updated its Declaration of Culture, which contains the six principles that guide our operation: (i) Life First, (ii) Collaboration, (iii) Ethics & Transparency, (iv) Innovation, (v) Excellence and (vi) Leadership.
Collective Bargaining Arrangements |
Ecopetrol S.A.
A collective bargaining agreement between us and our mainwith some labor unions governs labor relations with ourbetween Ecopetrol and its unionized employees,workers, which amounted to 5,1314,933 employees as of January 1,December 31, 2020. The agreement also governs our labor relations with other 2,8362,777 non-unionized employees who, according to current labor legislation, are beneficiaries of the collective bargaining agreement.
We currently have teneleven industry-wide labor unions and nine company labor unions:
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In 2019, 50.9%2020, 50.3% of Ecopetrol’s employees were affiliated with one of the above trade union organizations. As of the same date and in accordance with the governing legal provisions, the current Collective Bargaining Agreement (described below) applied to 79.0%78.3% of Ecopetrol S.A.’s total workers. Outworkers, out of that 79.0%, 28.1%which 28% were workers who were not affiliated with any Trade Union Organization but were beneficiaries of the Collective Bargaining Agreement by extension under Article 471 numeral 1 of the Substantive Labor Code.
Ecopetrol S.A.’s relations with unions are based on a permanent dialogue and communication sessions where different matters are discussed in order to solve and prevent any labor conflict.
Our current collective bargaining agreement has been in effect since July 1, 2018 and has a term of four and half years, expiring on December 31, 2022. The collective bargaining agreement included an increase in salaries at an annual rate of the local consumer price index (CPI) +1.21% for the remainder of 2018 and CPI +1.70% every year for the remainder of its duration. The agreement covers health, food, loans and transportation, among other benefits for workers, within reasonable criteria. It also includes union guarantees and addresses regulatory issues.
During 2019,2020, the agreements contained in the Collective Labor Convention 2018 – 2022 were performed, as were other agreements signed in the framework of the collective bargaining agreement process. In addition, a number of areas of dialogue with trade unions were advanced and different issues pertaining to their interest were addressed. A total of 249425 meetings were scheduled.
The Company manages compliance with trade unions rights with respect to the discount of trade union dues, permits and trade union guarantees. It also fully observes the rules governing aspects such as trade union law and other rights related to freedom of association.
4. | Financial Review |
Our consolidated financial statements for the years ended December 31, 2017, 2018, 2019 and 20192020 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 underFinancial Review -Summary of Differences between Internal Reporting (Colombian IFRS and IFRS) below.
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Our consolidated financial statements were consolidated line by line and all transactions and significant- balances between affiliatessubsidiaries 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.report.
4.1 | Factors Affecting Our Operating Results |
Our operating results were affected mainly by (i) international prices of crude oil, international prices for refined products and local prices for natural gas, as well as sales(ii) the reduced demand levels for crude oil and its derivative products, and (iii) volumes, product mix, exchange rate, and our operational performance. Crude oil prices and volumes are particularly important to the results of our exploration and production segment.segments. This is because as export volumes or export prices of crude oil and products decrease or increase, our revenues do also. Results from our refining activities are also affected by the price of crude oil used as raw material, changes in productinternational prices in the international market,for refined products, change in environmental regulations, drastic changes in demand due to market factors, conversion ratios and utilization rates and refining capacity, all of which affect our refining margins. Terrorist attacks by guerillas against our pipelines and other facilities or social unrest can lead to loss of revenues by restricting the availability of transport systems for exports or sales of crude oil and products and/or production activities, in addition to the direct costs of repairing and cleaning. Finally, changes in the value of foreign currencies, particularly the U.S. dollar against the Colombian Peso, can also have a significant effect on our financial statements.See sectionTrend 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.markets. We also process crude oil at the Barrancabermeja and Reficar refineries and sell refined and other petrochemical products in the local and international markets.
Local sales and prices
We have a number of crude oil short-term commercial agreements with local customers, and natural gas short and long-term supply contracts with gas-fired power plants and local natural gas distribution companies. Local sale prices are determined in accordance with existing regulations, contractual arrangements and the spot market, in turn, linked to international benchmarks. Local sales represent 49%represented 48.4% of our total revenues, on average, for the past three years.
International Salessales and Pricesprices
Our foreigninternational sales represented 51%51.6% of our total revenues, on average, for the past three years.
International sale prices are determined in accordance with contractual arrangements and the spot market, in turn, linked to international benchmarks primarily the ICE Brent benchmark.
A market diversification strategy has allowed us to capture markets where we have been able to obtain higher prices for our crudes and refined products. We sell our crudes and refined products in various regions, such as the U.S., Central America and the Caribbean, Asia and Europe. In our negotiations with potential customers, we seek to use the most liquid benchmark reference prices in each region.
Exploration costs
We account for exploratory drilling costs using the successful efforts method, whereby all costs associated with the exploration and drilling of productive wells are initially capitalized. Costs incurred in exploring and drilling dry or unsuccessful wells are expensed in the period in which the well is determined to be a dry or unsuccessful well and are accounted for under “Exploration and Project expenses.” Consequently, an increase in the number of exploratory wells we declare as dry or unsuccessful will negatively affect our results and may cause volatility in our operating expenses. See Note 4.7 to our consolidated financial statements for a summary of our accounting policy for exploration costs.
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Royalties
Each of our production contracts has its own royalty arrangement in accordance with applicable law. Law 141 of 1994 established a royalty fixed rate equivalent to 20% of total production. In 1999, a modification to the royalty system established a sliding scale for royalty percentage linked to the production level of crude oil and natural gas to fields discovered after July 29, 1999, depending on whether the production is crude oil or natural gas, and on the quality of the crude oil produced. Since 2002, as a result of the enactment of Law 756 of 2002, the royalty percentage has ranged from 8% for fields producing up to five thousand bpd to 25% for fields producing an excess of 600 thousand bpd. Producing fields pay royalties in accordance with the applicable royalty rate at the time of the discovery. Also, Law 756 of 2002 establishes that in the fields of the association contracts that finalize or revert back, an additional royalty rate of 12% of the basic production applies.
Since January 2014, the ANH has collected natural gas production royalties from producers settled in cash based on a formula, regardless of whether a producer has sold the gas. As a result, we no longer commercialize this gas on behalf of the ANH. In addition, because the royalties are now payable to the ANH in cash, all the gas we produce is considered part of our reserves and production, without any deduction for royalties. The cost of natural gas royalties totaled COP$614,336787,466 million in 2019.2020.
On September 30, 2020, Law 2056 of 2020, (“Through which the organization and operation of the general system of royalties is regulated”), was issued. Article 18 of this law broadened the definition of incremental production to all production from fields where additional investments have been made to increase the recovery factor. In this sense, the total production of these fields benefits from the variable royalty established in article 16 of Law 756 of 2002, and therefore, the additional 12% royalty referred to in article 39 of Law 756 of 2002 does not apply to these fields.
Purchases of hydrocarbons
We purchase all crude oil delivered to the ANH as royalties by us and by third parties. The purchase price is calculated according to a formula set forth in a contract between Ecopetrol and the ANH that reflects our export sales prices (crudes oil and products), a quality adjustment for API gravity and sulphur content, transportation rates from the wellhead to the Coveñas or Tumaco ports and a marketing fee. We sell the physical product purchased from the ANH as part of our ordinary business. The contract between the ANH and usEcopetrol S.A. was extended until April 30, 2020.October 31, 2022.
Since 2016, we have imported crude oil for Reficar feedstock when such imports result in better operational or economic performance of the Ecopetrol Group.
4.2 |
The Covid-19 outbreak was first reported in late 2019 in China. Subsequently, taking into account the level of expansion, the World Health Organization (WHO) declared the outbreak as a pandemic on March 11, 2020. Said status is maintained to the date of this annual report.
Many countries have undertaken various public health measures to control the spread of COVID-19, including mandatory quarantines, forced economic shutdowns and travel restrictions, as well as economic measures to mitigate the impacts of such public health policies on their respective national economy.
On March 17, 2020, the Colombian Government, through Legislative Decree 417 of 2020, declared a 30-day state of national emergency in light of the health and economic crisis caused by the outbreak of COVID-19. On May 6, 2020, through Legislative Decree 637 of 2020, the Colombian Government declared a state of emergency for an additional 30 days. The Government has implemented various economic and public health measures to address the crisis. See “Risk Factors – Risks Related to Colombia’s Political and Regional Environment."
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The COVID-19 pandemic has also caused significant volatility in financial and commodity markets around the world. While governments have announced aid packages to the most affected people and taken macroeconomic measures to face the crisis, the COVID-19 pandemic has disrupted economies worldwide. See “Risk Factors – Risks Related to Our Business – Our business operations could be disrupted by the Coronavirus or other pandemic disease and health events for further information on the effects of the coronavirus pandemic and – Risks Related to Colombia’s Political and Regional Environment – The worldwide economic effects of the outbreak and economic shutdown caused by the COVID-19 pandemic is adversely affecting Colombia’s economy, and the impact could be material.”
This situation has had a significant impact on the oil industry. Most specifically, travel bans imposed by several countries and established quarantine measures reduced demand levels for oil and its derivative products in 2020. Ecopetrol’s operations were affected by this situation and as a consequence, some plants in our refineries and some of our wells were temporarily closed due to low demand and prices and the measures taken to contain the spread of COVID-19 in workers and contractors. In this context, Ecopetrol took the following actions during 2020 to face the impacts of the COVID-19 pandemic:
These measures were aimed at ensuring the sustainability of the Ecopetrol Group’s business in an environment of low prices, prioritizing cash-generating opportunities with better equilibrium prices, maintaining growth dynamics with a focus on the execution of strategic asset development plans, and in asset value preservation through investments to gain reliability, integrity and continuity to the current operation in refineries, transportation systems and production fields. Similarly, these actions are covered by Ecopetrol’s risk management policies and procedures.
In terms of Ecopetrol’s results of operations as of and for the year ended December 31, 2020, the most significant impacts were the following: (i) a reduction in revenues, especially due to the contraction in demand and a decrease in the international Brent price partially offset with the higher exchange rate, (ii) an increase in financial costs due to an increase in debt, a decrease in valuation to fair value and lower yields of the securities portfolio, which in turn were as a result of low market rates, (iii) recognition of impairment at the end of the year as described above, and (iv) an increase in our depreciation expenses, partly generated by the update of the Ecopetrol’s reserve balance.
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As a result of the measures taken, the constant monitoring of the COVID-19 pandemic, the ongoing vaccination programs and the evolution of the Ecopetrol Group’s results, while we cannot offer any assurances, as of the date of this annual report, Ecopetrol does not believe that the COVID-19 pandemic will have a significant impact on the Ecopetrol Group in the long-term.
Nonetheless, the Ecopetrol Group will continue to monitor the evolution of the COVID-19 pandemic and the market to determine the need to implement subsequent stages of the COVID-19 intervention plan and will continuously review impairment indicators on long-lived assets and on investments in companies.
4.3 | Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results |
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:2017.
The 2016 Tax Reform included two tax benefits that are expected to improve the operations of the oil and gas industry:
Certificado de Reembolso Tributario (CERT) incentive:
For exploration activities, the “CERT” incentive was approved, consisting of the reimbursement of part of the investment made in the exploration phase.
The CERT is granted when the income tax return is filed.
The CERT can only be redeemed to pay taxes at the national level and its effective maturity date is two years after it is issued. Nevertheless, Decree 2253 of 2017 establishes that a CERT redemption can be made from year two to year five, as from the date of the granting of the incentive. The CERT can also be sold and traded in fixed income market.
For production activities, the CERT reimbursement is granted exclusively to investments that increase the recovery factor, i.e. investments that increase the reserves that are currently proved in certain wells.
On December 29, 2017, the Colombian Government issued Decree 2253, which establishes that companies who (i) qualify as operators of association agreements entered into with Ecopetrol, (ii) have exploration and production of hydrocarbons agreements and (iii) are currently involved in the exploration and production of hydrocarbons, among others, can also qualify for the CERT. Additionally, the CERT will not qualify as taxable income or capital gain for the taxpayer receiving or acquiring such incentive.
On March 23, 2018, the following Resolutions were issued in order to regulate the procedures and requirements that companies must comply to claim the CERT: 0860 of Ministry of Finance and Public Credit, 108 of ANH and 40284 and 40285 of Ministry of Mines and Energy.
On December 20, 2019, the Ministry of Finance and Public Credit informed the Company that the PGN includes the resources of CERT.
Refundable VAT on oil and gas exploration:
Taxpayers in the oil and gas industry are entitled to refund VAT paid in the exploration phase for offshore projects. Taxpayers can request for this VAT as of the next fiscal year in which the investment was made. VAT that is reimbursed cannot be used as a higher cost or expense for income tax purposes.
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Additionally, in December 2018, the Colombian Congress adopted Law 1943, which introduced the following key changes to the Colombian tax system, applicable beginning in 2019, including the following aspects:
The corporate income tax rates were set to be reduced gradually from 33% to 30% as follows: 33% in 2019, 32% in 2020, 31% in 2021 and 30% from 2022 onward.
The presumptive income tax rate was reduced to 1.5% for fiscal year 2019.
Taxpayers must calculate their taxable income taking as initial base the year and result under Colombian IFRS. Accounting profit is reconciled to obtain the net income tax, which is the basis to calculate the income tax.
For fiscal year 2018 and 2019 the newly enacted dividends tax applies as follows:
i. | For non-resident shareholders: (i) a 5% dividend tax for dividends paid out of profits that were accrued as of January 1, 2017 and a 7.5% dividend tax for dividends paid out of profits that accrued as of January 1, 2019 and were taxed at the corporate level; (ii) no dividend tax on dividends paid out of profits that accrued until December 31, 2016 and were taxed at the corporate level; (iii) a 35% withholding tax rate on dividends distributed from profits not taxed at the corporate level if the dividend is paid out of profits that accrued as of January 1, 2017, plus an additional, 5% dividend tax after applying the initial 35% withholding tax rate and a 33% withholding tax rate on dividends distributed from profits not taxed at the corporate level if the dividend is paid out of profits that accrued as of January 1, 2019, plus an additional, 7.5% dividend tax after applying the initial 33% withholding tax rate; and (iv) a 35% withholding tax rate on dividends distributed from profits not taxed at the corporate if the dividend is paid out of profits that accrued until December 31, 2016. |
ii. | For Colombian individuals: for fiscal year 2018, dividends paid were taxed at 5% if they were between 600 and 1,000 Tax Value Unit (UVT or Unidad de Valor Tributario for its Spanish acronym) and 10% if they were greater than 1,000 UVT. For fiscal year 2019, dividends paid were taxed at 15% if they were greater than 300 UVT. |
Dividends paid to local corporations during 2018 were not subject to any income tax, provided that such dividends were taxed at the corporate level. For fiscal year 2019 and 2020, these dividends were taxed at 7.5%.
Tax losses accrued as of fiscal year 2017 may be offset against ordinary net income obtained in the following 12 taxable years.
Depreciation and amortization methods and annual percentages are limited to those established in the tax rule and depend on the type of asset. For example, machinery and equipment depreciate at an annual rate of 10%, infrastructure (including pipelines) at 2.22% and vehicles and computers at 20%, among others.
Income tax for free trade zone users increased from 15% to 20% as of fiscal year 2017. The tax rate for free trade zone users with a legal stability agreement (in which the income tax rate was stabilized) remains at 15% during the term of said agreement.
The general value added tax (VAT) rate increased to 19% and a differential rate of 5% for certain goods and services is maintained. The modification of the general VAT rate is effective from January 1, 2017.
The charge on financial transactions is 0.4%, with half of the tax liability being deductible.
Carbon tax accrues on the carbon content of fossil fuels used for combustion. The rate will be COP$ 16,422 and COP$ 17,211 per ton of CO2, for fiscal year 2019 and 2020, respectively.
For additional information see Note 10.2.4 of our consolidated financial statements.
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In October 2019, the Constitutional Court declared Law 1943 of 2018 (the Financing Law) unconstitutional effective January 1, 2020. Therefore, the Financing Law continued to have full effect for the full fiscal year 2019.
In December 2019, the Colombian Congress adopted Law 2010, which introduced the following key changes to the Colombian tax system, among others:
The corporate income tax rates will be gradually reduced from 32% to 30% as follows: 32% in 2020, 31% in 2021 and 30% in 2022 onward.
The presumptive income tax rate will be reduced to 0.5% for fiscal year 2020 and to 0% from 2021 onward. |
The creation of a “normalization tax” to enable taxpayers to regularize certain omissions of information about their assets and/or incorrect information about their liabilities, subject to the payment of a 15% tax on the value of the amount of the omitted information.
Introduces the Colombian Holding Companies (CHC) regime.
As of 2020, taxes are fully deductible if they are effectively paid during the fiscal year, except for: (i) income tax, equity tax and normalization tax are non-deductible; (ii) only 50% of the financial transactions tax is deductible; and (iii) only 50% of the industry and commerce tax can be taken as a discount (tax credit) to income tax.
VAT paid on the acquisition, import, creation or construction of tangible fixed assets used in income generating activities may be treated as discount (tax credit) for income tax purposes, in the same year or in future years.
The dividend tax regime was modified and, as of 2020, is as follows:
i. | Dividends paid to non-resident shareholders: (i) a 10% dividend tax on dividends distributed from profits taxed at the corporate level (except that dividends paid to non-resident shareholders out of profits taxed at the corporate level prior to and including December 31, 2016, are not subject to this tax); or (ii) 32% withholding tax rate on dividends distributed from profits not taxed at the corporate level (31% for 2021 and 30% as of 2022), plus an additional 10% dividend tax after applying the initial 32% withholding tax rate (i.e., 38.8% in 2020). |
ii. | Dividends paid to Colombian companies: (i) a 7.5% dividend tax on dividends distributed from taxed profits, or (ii) a 32% withholding tax on dividends distributed from non-taxed profits (31% on 2021 and 30% as from 2022), plus an additional 7.5% dividend tax on the balance of the dividend amount after the initial 32% withholding. |
iii. | For Colombian resident individuals: dividend income in excess of 300 UVT is taxed at a rate of 10%. |
Part A: Applicable Taxpayers
Resident individuals with assets located in Colombia and abroad.
Non-resident individuals with their assets located in Colombia (either with or without permanent establishment).
Non-residents with non-cash assets in Colombia.
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Part B: Tax Accrual Rules
The wealth tax at a rate of 1%, on January 1 of each fiscal year 2020 and 2021. The taxable base is the taxpayer’s net equity on each of the accrual dates (gross equity less liabilities and certain exclusions, including a portion of the value of the dwelling house and 50% of the goods repatriated to normalization). In any case, the taxable base for fiscal year 2021 may not vary by more than 25% of the prior year’s inflation.
Thin capitalization: A 2:1 debt-to-equity ratio determines the amount of deductible interests on loans with related parties.
Law 2010 maintains the tax regime for profits derived from indirect transfer of Colombian assets.
As of 2020, the transfer (or disposal) of real estate whose value is higher than 29,800 UVT (approximately COP$918,436,000) will no longer be subject to the real estate consumption (excise) tax (formerly applied at 2%). This tax was specifically repealed by the Constitutional Court and was not re-introduced by Congress in Law 2010.
A special regime (the Mega Investments Regime) was created for taxpayers who (i) generate at least 400 direct jobs and (ii) make new investments in Colombia in an amount equal to or greater than 30,000,000 UVT (COP$1,068,210,000,000) by 2020, with a view for them to calculate and settle their income tax liability for the next 20 years using the following metrics and/or policies:
i. | 27% income tax rate; |
ii. | Two-year term for the depreciation for fixed assets; |
iii. | Exclusion from the presumptive income regime; |
iv. | Exclusion from the wealth tax; and |
v. | 0.75% premium over the investment value to be paid on an annual basis. |
In addition, legal taxpayers who qualify for this Mega Investment Regime will beare 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.
Exchange Rate Variation |
The functional currency of each of the companies of Ecopetrol Group is determined in relation to the main economic environment where each company operates; however, our consolidated financial results are reported in Colombian Pesos, which is the Ecopetrol Group’s functional and presentation currency. A substantial part of our consolidated revenues comes from the Ecopetrol GroupGroup’s companies whose functional currency is the Colombian Peso. The conversion effect from U.S. dollar to Colombian Peso is mainly due to local sales and exports of crude oil, natural gas and refined products whose prices are based on benchmarks quoted in U.S. dollars. Therefore, they are exposed to foreign currency exchange risk on revenues, capital expenditures and financial instruments that are denominated in a currency other than its functional currency.
Fluctuations in the U.S. dollar-Colombian Peso exchange rate have effects on our consolidated financial statements. As crude oil is priced in U.S. dollars, fluctuations in the exchange rate of the Colombian Peso against the U.S. dollar may have a significant impact on revenues, cost, monetary assets and liabilities held in foreign currency.
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An appreciation of the Colombian Peso has a negative impact on our results of operations because our revenues from exports of crude oil, natural gas, and refined products are primarily expressed in U.S. dollars. Costs of imported products and contracted services expressed in U.S. dollars will also be lower when expressed in Colombian Pesos, but on balance, our operating income in Colombian Pesos tends to decline when the Colombian Peso appreciates, other factors being equal. The appreciation of the Colombian Peso against the U.S. dollar will also decreasesdecrease the debt service requirements of our Companies with the Colombian Peso as their functional currency and with indebtedness in U.S. dollars, as the amount of the Colombian pesos necessary to pay principal and interest on foreign currency debt decreases with the appreciation of the Colombian Peso.
Conversely, when the Colombian Peso depreciates against the U.S. dollar, our reported revenues, costs related to imported products and services, interest costs,operating income, and operating income,debt service requirements of foreign-denominated debt all tend to increase.
During 2020, the Colombian Peso depreciated on average 12.46% against the U.S. dollar. During 2019 and 2018, the Colombian Peso depreciated on average 11.02% and 0.2% against the U.S. dollar. During 2017, the Colombian Peso appreciated on average 3.35%, respectively, against the U.S. dollar. Additionally, as of December 31, 2020, December 31, 2019 and December 31, 2018, the Colombian Peso/U.S. dollar exchange rate had depreciated 4.74%, 0.84% and 8.91% respectively from the rate a year earlier. In contrast, as of December 31, 2017, the Colombian Peso/U.S. dollar exchange rate appreciated 0.56% from the rate a year earlier.
In 2020, our consolidated debt in foreign currency increased by a total of US$2,420 million as Ecopetrol S.A. entered into committed credit lines in an aggregate principal amount of US$665 million and issued an SEC-registered bond in an aggregate amount of US$2,000 million. In 2019, our consolidated debt in foreign currency decreased by a total of US$159 million mainly as a result of amortization of foreign currency capital expenditures. In 2018, our consolidated debt in foreign currency decreased by a total of US$2,123 million mainly as a result of prepayments of local and foreign currency of US$2,446 million and amortization of foreign currency capital expenditures. 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, 2019,2020, our U.S. dollar denominated total debt was US$10,30812,728 million, which we recognizerecognized in our financial statements at its amortized cost, which corresponds to the present value of cash flows, discounted at the effective interest rate.rate of each loan. Out of thisthe total U.S. dollar denominated debt, US$10,24412,598 million relates toare in Ecopetrol S.A.,’s balance sheet, whose functional currency is the Colombian Peso. Therefore, when the Colombian Peso depreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate loss. In contrast, when the Colombian Peso appreciates against the U.S. dollar, Ecopetrol S.A. has an exchange rate gain. Some of the Ecopetrol GroupGroup’s companies have the U.S. dollar as their functional currency and are not exposed to a material exchange rate risk resulting from fluctuations in the Colombian Peso against the U.S. dollar. On the asset side, whenWhen the financial statements of the Ecopetrol Group are consolidated, the exchange rate differential of the subsidiaries’ assets and liabilities whose functional currency is the U.S. dollar is recognized directly in equity, as part of other comprehensive income.
Since 2015, Ecopetrol S.A. adopted hedge accounting, using two types of natural hedges with its U.S. dollar debt as a financial instrument: (i) a cash flow hedge for exports of crude oil and (ii) a hedge of the net investment in foreign operations. As a result of the implementation of both hedges 71.6%67.9% (US$7,3318,549 million) of Ecopetrol S.A.’s debt in U.S. dollars, as of December 31, 2019,2020, was designated as a hedge. With the adoption of hedge accounting, the effect of the volatility of the foreign exchange rate on the hedged portion of the debt is recognized directly in equity, as part of other comprehensive income.
The remaining portion of Ecopetrol S.A.’s U.S. dollar-denominated debt, as well as the financial assets and liabilities denominated in foreign currency, continues to be exposed to the fluctuation in the exchange rate, which means that an appreciation of the Colombian Peso against the U.S. dollar could generate a loss for companies whose functional currency is the Colombian Peso that have a net asset position in U.S. dollars or a gain if they have a net liability position in U.S. dollars. Conversely, a depreciation of the Colombian Peso against the U.S. dollar could generate a gain for companies whose functional currency is the Colombian peso that have a net asset position in U.S. dollars or a loss if they have a net liability position in U.S. dollars.
As of December 31, 2019,2020, the Ecopetrol GroupGroup’s companies have the equivalent of a net U.S. dollar liability position of US$3711,424 million after the implementation of the natural hedging previously mentioned above, neutralizingminimizing the effect of exchange rate fluctuations in their results for the year.
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Effects of Inflation |
The average annual rate of inflation in Colombia for the past ten years is 3.85%3.70%. It increaseddecreased in 20192020 as compared to 2018.2019. As measured by the general consumer price index, average annual inflation in Colombia for the years ended December 31, 2020, 2019 and 2018 was 1.61%, 3.80% and 2017 was 3.80%, 3.18%, and 4.09%, respectively. The increasedecrease in inflation in 20192020 is mainly due to the “El Niño” weather phenomenon, the indirect tax increase, the devaluation of the Colombian peso against the dollarCOVID-19 pandemic, which created an abrupt supply and demand pressures. shock on Colombian CPI, particularly as a result of weak demand, significant excess productive capacity, a very tight labor market and price relief measures.
Cost inflation in the prices of goods, raw materials, debt interest cost of debtexpenses denominated in local currency indexed to inflation and services for operation of oil and gas producing assets can vary over time and between each market segment.
Effects of Crude Oil and Refined Product Prices |
The average price of ICE Brent crude in 20192020 was US$64.243.2 per barrel as compared to US$64.2 per barrel in 2019 and US$71.7 per barrel in 2018 and US$54.7 per barrel in 2017.2018. See sectionStrategy and Market Overview. for more information.
Ecopetrol’s average crude oil basket price relative to ICE Brent reported a discount ofwas US$5.634.4 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 due2020, as compared 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 toand US$63.2 per barrel in 2018 and2018. The decrease of US$47.824.2 per barrel in 2017, which represents a decrease of US$4.6 per barrel in 20192020 as compared to 2018.2019 was mainly due to the decrease in the international Brent price and a weaker spread between the price of heavy crude oil versus the Brent price, which was partially offset by proactive sales and marketing management towards the diversification of clients and destinations, with sales of our Castilla and Vasconia blend crudes to South Korea, customers reactivation in India and Spain, and a sustained market share in the United States Gulf of Mexico and China.
In addition, Ecopetrol’s average productsproduct basket price relative to ICE Brent reported a discountwas US$49.2 in 2020, US$69.8 in 2019, and US$77.30 in 2018. The decrease of US$5.6, US$5.6 and US$7.920.6 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 20192020 as compared to 2018.2019 was primarily the result of a decrease in the international Brent price, partially offset by (i) an increase in our sales volumes at the beginning of the year at higher prices and (ii) our active commercial management that allowed us to export the production surpluses, which in turn were the result of a decrease in domestic demand, largely for gasoline, diesel and jet fuel as a result of the effects of the COVID-19 pandemic.
In theOperating Results section below, we present the impact of the price increasedecrease 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. ReservesReserves’ 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 sectionsOperating Results—Consolidated Results of Operations—Impairment of Non-Current assets,Segment Performance and Analysis and Note 1718 to our consolidated financial statements.
In addition, as described in Section2.1.2 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 entitledTrend Analysis and Sensitivity Analysis—Trend Analysis for further information.
Accounting Policies |
Our consolidated financial statements for the years ended December 31, 2020, 2019 2018 and 20172018 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 adoptWe adopted IFRS 16 – Leases andas from January 1, 2018,2019. Also, we were required to adoptadopted IFRS 9 – Financial Instruments and IFRS 15 – Operating income. Our financial statementsRenevue fron Contracts and Customers as of and for the years ended December 31, 2019 and 2018, reflect thefrom January 1, 2018. The adoption of these newsuch 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 noteNote 5.1New standards adopted by the Ecopetrol Group to our consolidated financial statements included in this annual reportreport..
Critical Accounting Judgments and Estimates |
Critical accounting policies are those policies that require us to exercise judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations. The accounting judgments and estimates we make in these contexts require us to calculate variables and make assumptions about matters that are highly uncertain. In each case, if we had made other estimates, or if changes in the estimates occur from period to period, our financial condition and results of operations could be materially affected.
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See Note 43 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 changedchanges or differentdifferences within critical accounting judgments and estimates would not behave a material toimpact on our financial presentation.statements.
Operating Results |
The following discussion is based on information contained in our audited consolidated financial statements and should be read in conjunction therewith.
Consolidated Results of Operations |
The following table sets forth components of our income statement for the years ended December 31, 2020, 2019 2018 and 2017.2018.
Table 4752 – Consolidated Income Statement
Income Statement | For the Years ended December 31, | % Change | For the year ended December 31, | % Change | ||||||||||||||||||||||||||||||||||||
(Colombian Pesos in millions) | 2019 | 2018 | 2017 | 2019/2018 | 2018/2017 | |||||||||||||||||||||||||||||||||||
(COP$ Million) | 2020 | 2019 | 2018 | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||||||
Revenue | 71,488,512 | 68,603,872 | 55,954,228 | 4.2 | 22.6 | 50,223,393 | 71,488,512 | 68,603,872 | (29.7 | ) | 4.2 | |||||||||||||||||||||||||||||
Cost of sales | 44,972,360 | 41,184,379 | 36,908,325 | 9.2 | 11.6 | 37,567,472 | 44,972,360 | 41,184,379 | (16.5 | ) | 9.2 | |||||||||||||||||||||||||||||
Gross Profit | 26,516,152 | 27,419,493 | 19,045,903 | (3.3 | ) | 44.0 | 12,655,921 | 26,516,152 | 27,419,493 | (52.3 | ) | (3.3 | ) | |||||||||||||||||||||||||||
Operating expenses | 3,726,557 | 4,592,445 | 4,185,186 | (18.9 | ) | 9.7 | 4,841,000 | 3,726,557 | 4,592,445 | 29.9 | (18.9 | ) | ||||||||||||||||||||||||||||
Impairment (recovery) of non-current assets, net | 1,762,437 | 368,634 | (1,311,138 | ) | 378.1 | (128.1 | ) | 633,156 | 1,762,437 | 368,634 | (64.1 | ) | 378.1 | |||||||||||||||||||||||||||
Operating Income | 21,027,158 | 22,458,414 | 16,171,855 | (6.4 | ) | 38.9 | 7,181,765 | 21,027,158 | 22,458,414 | (65.8 | ) | (6.4 | ) | |||||||||||||||||||||||||||
Finance results, net | (1,670,494 | ) | (2,010,375 | ) | (2,495,731 | ) | (16.9 | ) | (19.4 | ) | (2,481,587 | ) | (1,670,494 | ) | (2,010,375 | ) | 48.6 | (16.9 | ) | |||||||||||||||||||||
Share of profit of companies | 366,904 | 165,836 | 93,538 | 121.2 | 77.3 | |||||||||||||||||||||||||||||||||||
Share of profit in associates and joint ventures | 76,336 | 366,904 | 165,836 | (79.2 | ) | 121.2 | ||||||||||||||||||||||||||||||||||
Income before income tax | 19,723,568 | 20,613,875 | 13,769,662 | (4.3 | ) | 49.7 | 4,776,514 | 19,723,568 | 20,613,875 | (75.8 | ) | (4.3 | ) | |||||||||||||||||||||||||||
Income tax | (4,718,413 | ) | (8,258,485 | ) | (5,800,268 | ) | (42.9 | ) | 42.4 | |||||||||||||||||||||||||||||||
Income tax expense | (2,038,661 | ) | (4,718,413 | ) | (8,258,485 | ) | (56.8 | ) | (42.9 | ) | ||||||||||||||||||||||||||||||
Net Income | 15,005,155 | 12,355,390 | 7,969,394 | 21.4 | 55.0 | 2,737,853 | 15,005,155 | 12,355,390 | (81.8 | ) | 21.4 | |||||||||||||||||||||||||||||
Net income attributable to: | ||||||||||||||||||||||||||||||||||||||||
Company’s shareholders | 13,744,011 | 11,381,386 | 7,178,539 | 20.8 | 58.5 | 1,586,677 | 13,744,011 | 11,381,386 | (88.5 | ) | 20.8 | |||||||||||||||||||||||||||||
Non-controlling interest | 1,261,144 | 974,004 | 790,855 | 29.5 | 23.2 | 1,151,176 | 1,261,144 | 974,004 | (8.7 | ) | 29.5 | |||||||||||||||||||||||||||||
Net Income | 15,005,155 | 12,355,390 | 7,969,394 | 21.4 | 55.0 | 2,737,853 | 15,005,155 | 12,355,390 | (81.8 | ) | 21.4 |
Total Revenues |
The following table sets forth our principal sources of third-party revenues by business segment for the years ended December 31, 2020, 2019 2018 and 2017.2018. An explanation of how we classify our operations into business segments is included in section 4.5.1.84.6.1.8 below.
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Table 4853 – Third-Party Revenues by Business Segment
2019 | 2018 | 2017 | Change Sales Revenues (%) | 2020 | 2019 | 2018 | 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 | Volume (barrels equivalent) | Average price US$/barrels | Sales revenues (COP$ Million) | Volume (barrels equivalent) | Average price US$/barrels | Sales revenues (COP$ Million) | Volume (barrels equivalent) | Average price US$/barrels | Sales revenues (COP$ Million) | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Local Crude oil | 2,232,087 | 48,6 | 356,857 | 2,919,416 | 60.8 | 550,479 | 6,629,362 | 46.5 | 909,871 | (35.2 | ) | (39.5 | ) | 2,208,356 | 28.6 | 230,520 | 2,232,087 | 48.6 | 356,857 | 2,919,416 | 60.8 | 550,479 | (35.4 | ) | (35.2 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||
Foreign Crude oil | 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 | 153,185,623 | 34.4 | 19,498,553 | 147,692,547 | 58.7 | 28,461,601 | 143,208,235 | 63.2 | 26,898,737 | (31.5 | ) | 5.8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Natural gas local | 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 | 31,391,611 | 24.5 | 2,845,155 | 28,798,105 | 23.8 | 2,256,123 | 28,065,889 | 22.5 | 1,885,846 | 26.1 | 19.6 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Foreign natural gas | 506,556 | 16,6 | 27,255 | 530,945 | 17.7 | 27,899 | 618,022 | 17.7 | 32,303 | (2.3 | ) | (13.6 | ) | 554,742 | 8.6 | 17,231 | 506,556 | 16.6 | 27,255 | 530,945 | 17.7 | 27,899 | (36.8 | ) | (2.3 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||
Other income(1) | 3,788,550 | - | 193,282 | 3,216,650 | - | 749,939 | 3,412,568 | 819,726 | (74.2 | ) | (8.5 | ) | 5,409,528 | - | 263,466 | 3,788,550 | - | 193,282 | 3,216,650 | - | 749,939 | 36.3 | (74.2 | ) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
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 | 192,749,860 | - | 22,854,925 | 183,017,845 | - | 31,295,118 | 177,941,135 | - | 30,112,900 | (27.0 | ) | 3.9 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Local refined products | 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 | 90,659,046 | 54.1 | 17,745,376 | 111,095,596 | 74.5 | 27,170,498 | 108,781,359 | 81.9 | 26,354,549 | (34.7 | ) | 3.1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Foreign refined products | 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 | 39,668,072 | 42.4 | 6,165,364 | 44,007,684 | 62.3 | 8,977,662 | 41,577,284 | 68.6 | 8,485,932 | (31.3 | ) | 5.8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Foreign Crude Oil | 289,289 | 62.6 | 61,995 | - | - | - | 341,366 | 53.0 | 52,397 | 100.0 | (100.0 | ) | - | - | 29 | 289,289 | 62.6 | 61,995 | - | - | - | (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 | - | - | 894,118 | - | - | 183,315 | - | - | 107,467 | 387.7 | 70.6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Refining and petrochemicals(2) | 130,327,118 | - | 24,804,887 | 155,392,569 | - | 36,393,470 | 150,358,643 | - | 34,947,948 | (31.8 | ) | 4.1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Transportation services | - | 3,799,924 | - | 3,543,024 | - | 3,606,549 | 7.3 | (1.8 | ) | - | - | 2,563,581 | - | - | 3,799,924 | - | - | 3,543,024 | (32.5 | ) | 7.3 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Transportation and logistics | - | - | 3,799,924 | - | - | 3,543,024 | - | - | 3,606,549 | 7.3 | (1.8 | ) | - | - | 2,563,581 | - | - | 3,799,924 | - | - | 3,543,024 | (32.5 | ) | 7.3 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Total sales | 338,555,482 | 71,488,512 | 328,299,778 | 68,603,872 | 334,778,758 | 55,954,228 | 4.2 | 22.6 | 323,076,978 | - | 50,223,393 | 338,410,414 | - | 71,488,512 | 328,299,778 | - | 68,603,872 | (29.7 | ) | 4.2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 | 155,393,979 | 34.4 | 19,729,102 | 150,213,923 | 58.6 | 28,880,453 | 146,127,651 | 63.2 | 27,449,216 | (31.7 | ) | 5.2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Natural gas | 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 | 31,946,353 | 24.3 | 2,862,386 | 29,304,661 | 23.7 | 2,283,378 | 28,596,834 | 22.4 | 1,913,745 | 25.4 | 19.3 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
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 | 135,736,646 | 49.2 | 24,174,206 | 158,891,830 | 69.8 | 36,341,442 | 153,575,293 | 77.3 | 35,590,420 | (33.5 | ) | 2.1 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Transportation services and others | - | 3,933,819 | - | 3,650,491 | - | 3,704,864 | 7.8 | (1.5 | ) | - | - | 3,457,699 | - | - | 3,983,239 | - | 3,650,491 | (13.2 | ) | 9.1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total sales | 338,555,482 | 71,488,512 | 328,299,778 | 68,603,872 | 334,778,758 | 55,954,228 | 4.2 | 22.6 | 323,076,978 | - | 50,223,393 | 338,410,414 | - | 71,488,512 | 328,299,778 | - | 68,603,872 | (29.7 | ) | 4.2 |
(1) | Since 2020, Invercolsa’s sales are recognized as income from gas service without associated volume. In order to give comparability to our financial information, the values reported as residential gas were classified as “other income” in 2019. |
(2) | In the case of the exploration and production segment, other income corresponds mostly to services and sales of refined products (mainly LPG and asphalt) |
In 2020, total revenues decreased by 29.7% as compared to 2019, primarily as a result of: (i) a COP$21,330,388 million decrease in revenues mainly due to a 41.3%, or US$24.2 per barrel, decrease of our average crude oil basket price and a 29.5%, or US$20.6 per barrel decrease of our average refined products basket price, which in case in turn was primarily the result of the decrease in the international crude oil and product reference prices, (ii) a COP$4,246,388 million decrease in revenues attributable to the decrease in our sales volume (as further explained below) and (iii) a COP$723,744 decrease in revenues attributable to a decrease in the service revenue of our transportations and logistics segment, which in turn was primarily due to a decrease in transported volumes. These decreases were partially offset by a COP$5,035,401 million increase in revenues resulting from a 12.46% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$3,282.39/US$1.00 in 2019 to an average exchange rate of COP$3,691.27/US$1.00 in 2020, resulting in an increase in revenue from exports.
The decrease of our sales volume in 2020 as compared to 2019 was the result of a 14.6%, or 23.2 mbe, decrease in refined products volumes, which in turn was primarily due to the contraction in demand caused by the COVID-19 pandemic. This decrease was partially offset by (i) a 3.4%, or 5.2 mbpe, increase in our crude sales volume which was resulting from higher availability associated with lower throughput at our refineries and (ii) a 9.0%, or 2.6 mbe, increase in natural gas sales volume due to Hocol’s acquisition of 100% of Chevron Petroleum Company’s participation in the Guajira association contract (which corresponds to 43% of the total contract) and the entry into operation of the Cupiagua LPG plant.
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In 2019, total revenues increased by 4.2% as compared to 2018, primarily as a result of: (i) a COP$5,951,875 million increase resulting from the 11.02% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$2,956.55/US$1.00 in 2018 to an average exchange rate of COP$3,282.39/US$1.00 in 2019, resulting in an increase in sales revenue from exports, (ii) a COP$2,322,792 million revenue increase attributable to the increase in our sales volume explained below and (iii) a COP$292,590 increase in services revenue from our transportations and logistics segment, primarily due to an increase in volumes transported.transported volumes. This increase was partially offset by: the 7.3%, or US$4.6 per barrel, decrease of our average crude oil basket price, which in turn was primarily the result of the lower performance of the Brent crude benchmark price, and the 9.7%, or US$7.5 per barrel decrease of our average refined products basket price, which in turn was primarily the result of the lower result of the international product prices performance, mainly in gasoline, naphtha and fuel oil prices, in spite of better diesel crack due to IMO 2020.
The increase of our sales volume in 2019 as compared to 2018 was the result of: (i) the 2.8%, or 4.1 mbpe, increase in our crude sales volume which was primarily the result of higher crude exports to Asia and the US Gulf Coast as a result of the Company’s commercial strategy, higher production level and an increase of purchases, (ii) the 3.5%, or 5.3 mbe, increase in refined products volumes due to an increase in consumption in border areas, which in turn was primarily due to a decrease in imports of Venezuelan products, a change in the biodiesel blend, an increased demand for jet fuel by the aviation industry and an increase in exports of diesel due to better realization price in the international markets and (iii) the 2.5%, or 0.7 mbe, increase in natural gas sales volume, primarily due to the incorporation of new fields and marketing processes during 2019.
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.
Cost of Sales |
Our cost of sales was principally affected by the factors described below. See Note 2526 to our consolidated financial statements for more detail.
Cost of sales in 2020 was COP$37,567,472 million, representing a COP$7,404,888 million or 16.5% decrease as compared to 2019, primarily as a result of the following factors:
The factors mentioned above were partially offset by: (i) a COP$1,333,903 million increase in our consumption of inventories given a greater consumption of refined products and the effect of lower prices and (ii) a COP$695,271 million increase in depreciation, amortization and depletion expenses primarily due to a higher level of capital investment and the devaluation of the average exchange rate of the Colombian Peso against the U.S. dollar in subsidiaries with the US dollar as their functional currency (which was partially offset by a lower depreciation rate associated with decreased levels of production).
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Cost of sales in 2019 was COP$44,972,360 million, representing a COP$3,787,981 million or 9.2% increase as compared to 2018, primarily as a result of the following factors:
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.
(i) | A COP$2,197,539 million increase in the purchase costs of crude oil, natural gas and refined products, which were purchased for sales and, in the case of crude oil, for refining, which was primarily the result of (i) lower average purchase prices due to the COP$2,894,955 million decrease in international benchmark prices for crude oil, natural gas and refined products, (ii) a COP$2,702,726 million increase in volumes purchased, primarily to ensure domestic supply of diesel and new contracts of domestic crude and (iii) a COP$2,389,768 million increase in costs in Colombian Peso terms due to the depreciation of the average exchange rate of the Colombian Peso against the U.S. dollar. |
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.
(ii) | A COP$685,059 million increase in depreciation, amortization and depletion expenses primarily due to (i) an increase in our level of capital expenditures and (ii) higher production levels associated with the results of our drilling campaign. The above mentioned was partially offset by a decrease in depreciation expenses due to higher hydrocarbon proved developed reserves in 2019 as compared to 2018. |
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.
(iii) | A COP$626,779 million increase in maintenance, contracted services and energy, associated with increased operating activity, incremental production costs, entry into operation of new wells, greater share in fields, higher electrical power rates, among others. |
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.
(iv) | A COP$210,764 million increase in labor costs, which is primarily the result of: (i) the recognition of employee benefits under the new collective bargaining agreement, (ii) a salary increase in 2019 and (iii) an increase in the number of employees. |
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.
(v) | A COP$470,960 million increase in taxes and contributions, primarily due to: (i) higher taxes assumed mainly for VAT on gasoline and ACPM that went from being taxed at the general rate of 19% to 5%, thus limiting the VAT discount on goods and services purchased and (ii) greater economic rights to the ANH due to the production reactivation of the CP09 field. |
A COP$87,063 million increase in other minor items.
(vi) | A COP$87,063 million increase in other minor items. |
The factors mentioned above were partially offset by a COP$490,183 million decrease in our consumption of inventories given our strategy to supply products in the country.
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.
Operating Expenses before Impairment of Non-Current Assets Effects |
Operating expenses, andwhich include selling, general and administrative expenses before taking into accountimpairment of non-current assets amounted to COP$4,841,000 million in 2020, a COP$1,114,443 million or 29.9% increase as compared to 2019, mainly as a result of the following factors (see Notes 27 and 28) to our consolidated financial statements for more detail):
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These results were partially offset by:
Operating expenses, which include selling, general and administrative expenses before impairment of non-current assets amounted to COP$3,726,557 million in 2019, a COP$865,888 million or 18.9% decrease as compared to 2018, mainly as a result of the following factorsfactors: (see Notes 2627 and 2728 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.
(i) | A COP$1,060,989 million increase in other income, with no cash impact, mainly from the difference between the fair value and book value of Invercolsa. As a result of the ruling issued by the Colombian Supreme Court of Justice in 2019, we increased our shareholding in Invercolsa from 43.35% to 51.88%, which in addition with another aspects represents a change in control of that entity; therefore, Invercolsa became our subsidiary rather than an affiliate, and we began to fully consolidate Invercolsa into our consolidated financial statements from November 2019. According to IFRS “Business combinations,” the acquisition of Invercolsa was recognized at fair value. |
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.
(ii) | A COP$623,927 million decrease in exploratory expenses mainly as a result of the recognition of spending on exploratory activity at Ecopetrol America’s León 1 and 2 wells in 2018. |
This decrease was partially offset by:
A COP$229,330 million increase in general expenses mainly due to (i) the negative impact on our midstream segment of attacks by third parties and illegal valves, and (ii) an increase in our social investment made, especially the connection of the Middle Magdalena |
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 sectionFinancial Review—Operating Results—Consolidated Results of Operations—Segment Performance and Analysis.
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Impairment of Non-Current Assets |
The impairment of our non-current assets includes expenseslosses (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.statement in any given fiscal year. In our business segments highly sensitive variables can include, among others: (i) in the exploration and production segment, variations of the hydrocarbon prices outlook; (ii) in the refining segment, changes in product and crude oil prices, discount rate, refining margins, changes in environmental regulations, cost structure and the level of capital expenditures; (iii) in the transportation and logistics segment, changes in tariffs regulation and volumes transported.transported volumes. (See Notes 3.2, 4.12 and 1718 to our consolidated financial statements for more detail).
In 2019,2020, we recognized impairment losses of non-current assets of COP$1,762,437633,156 million as compared to impairment losses of non-current assets ofCOP$1,762,437 million in 2019 and COP$368,634 million in 2018 and a COP$1,311,138 million net reversal of impairment of non-current assets in 2017.2018. These impairments are a non-cash accounting effect and consequently do not involve any disbursement or cash inflow. Further, any cumulative impairment amount of non-current assets, except for goodwill, is susceptible to reversion when the fair value of the asset exceeds its book value. On the contrary, in the event that the book value exceeds the fair value of the asset, an additional impairment expense could be recognized.
The 2020 impairment losses, net of non-current assets of COP$633,156 million, corresponds to the net result of:
(i) | An impairment of non-current assets in the exploration and production segment of COP$192,693 million, mainly due to the decrease in crude oil price forecast in the short and long term. |
(ii) | An impairment of non-current assets in the refining and petrochemicals segment of COP$781,528 million, primarily related to the lower refining margins at the Cartagena Refinery by COP$440,525 million and the Barrancabermeja Refinery Modernization Plan by COP$341,000 million, considering the progress in technical analysis of the project. |
(iii) | A reversal of impairment of non-current assets in the transportation and logistics segment of COP$341,065 million, primarily as a result of a recovery in transported volumes in 2020 through: (i) South CGU, which includes the Transandino pipeline – OTA and the port of Tumaco and (ii) North CGU, which includes the Banadía–Ayacucho’s pipeline, part of the Caño Limón-Coveñas system. |
The 2019 impairment loss, net of non-current assets of COP$1,762,437, corresponds to the net result of:
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.
(i) | An impairment of non-current assets in the exploration and production segment primarily due to the decrease in estimations of short-term hydrocarbon price outlook, in spite of the incorporation of new reserves and technical and operational information variables and lower discount rate. |
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.
(ii) | An impairment of non-current assets in the transportation and logistics segment, primarily associated with the south generating unit, comprised of Puerto Tumaco and the TransAndino Pipeline (OTA), and the north generating unit, comprised of the Caño Limón – Coveñas Pipeline, which was especially affected by damages to its infrastructure attributed to attacks by third-parties. |
(iii) | A reversal of impairment of non-current assets in the refining and petrochemicals segment, primarily related to the net effect of i) a reversal of impairment of the Cartagena Refinery due to a lower discount rate associated with external market factors, ii) an impairment loss in Bioenergy primarily due to the decrease in availability of cane, partially offset by an improvement in the projection of the realization price of ethanol and a decrease in the discount rate and iii) an impairment loss associated with the modernization plan for the Barrancabermeja refinery, considering the state of the technical alternatives analysis of possible future increases in conversion. |
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.109
As mentioned above, in 2018, Ecopetrol recognized impairment losses, net of non-current assets of COP$368,634 million, which corresponds to the net result of:
(i) | An impairment of non-current assets in the refining and petrochemicals segment, primarily due to adjustments in market expectations with respect to the impact of implementation of IMO regulations on projected margins for Reficar’s refined products, (ii) a decrease in the short-term outlook for the ethanol prices given a global over-supply of ethanol, (iii) downward updates to Bioenergy’s near-term agricultural outputs and (iv) an increase in the discount rate used for Reficar and Bioenergy, reflecting updated macroeconomic conditions. These negative impacts were partially offset by the commencement of the stabilization period at both Reficar and Bioenergy as well as tax benefits associated with Law 1942, 2018. |
An impairment of non-current assets in the refining and petrochemicals segment, primarily due to adjustments in market expectations with respect to the impact of implementation of IMO regulations on projected margins for Reficar’s refined products, (ii) a decrease in the short-term outlook for the ethanol prices given a global over-supply of ethanol, (iii) downward updates to Bioenergy’s near-term agricultural outputs and (iv) an increase in the discount rate used for Reficar and Bioenergy, reflecting updated macroeconomic conditions. These negative impacts were partially offset by the commencement of the stabilization period at both Reficar and Bioenergy as well as tax benefits associated with Law 1942, 2018.
(ii) | An impairment of non-current assets in the transportation and logistics segment, primarily the result of a decrease in the forecast of the volume to be transported by the southern transportation unit and an increase in investment needs to mitigate the operative risk of our transportation systems. |
(iii) | A reversal of impairment of non-current assets in the exploration and production segment primarily due to an improved short- term hydrocarbon price outlook, incorporation of new reserves and technical and operational information variables. |
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 sectionFinancial Review—Operating Results—Consolidated Results of Operations—Segment Performance and Analysis.
Finance Results, Net |
Finance results, net, mainly includes exchange rate gains or losses, interest expense, yields and interest from our investments and non-current liabilities financial costs (asset retirement obligation and post-benefits plan).
Finance results, net, amounted to a loss of COP$2,481,587 million in 2020 as compared to a loss of COP$1,670,494 million in 2019. This increase in loss was mainly due to:
(i) | A COP$489,852 million increase in interest expenses, primarily as a result of the increase in the Ecopetrol Group’s financial debt in 2020 given that Ecopetrol S.A. entered into committed credit lines in an aggregate principal amount of US$665 million in committed credit lines and issued an SEC-registered bond in an aggregate amount of US$2,000 million and the negative effect of the devaluation of the Colombian peso against the US dollar in 2020 had on our foreign currency debt. |
(ii) | A COP$327,194 million decrease in valuation to fair value and lower yields of the securities portfolio, as a result of low market rates and a lower average cash position in 2020 as compared to 2019. |
(iii) | A COP$147,458 million decrease in financial income related to retroactive dividends and interest received by us in respect of Invercolsa’s profits in 2019, before we acquired control of this entity in November 2019. |
(iv) | A COP$152,724 million increase in financial expenses related to long term obligations, which in turn was mainly to the increase in our asset retirement and pension obligations. |
This increase was partially offset by the positive impact resulting from the strong appreciation of the Colombian Peso against the U.S. dollar in the last quarter of 2020 had on our U.S. dollar net liability position. In 2020, our exchange rate gain was COP$346,774 million, as compared to a gain of COP$40,639 million in 2019.
Finance results, net, amounted to a loss of COP$1,670,494 million in 2019 as compared to a loss of COP$2,010,375 million in 2018. This decrease in loss was mainly due to:
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This decrease was partially offset by:
the negative impact resulting from the 0.8% depreciation of the Colombian Peso against the U.S. dollar on our U.S. dollar net debt position. In 2019, our exchange rate gain was COP$40,639 million, |
Finance results, net, amounted to a loss of COP$2,010,375 million in 2018 as compared to a lossgain of COP$2,495,731372,223 million in 2017. This decrease2018.
For more details on our financial income and expenses see Note 2829 to our consolidated financial statements for more details.
Income Tax |
Income taxes amounted to and COP$2,038,661 million in 2020, COP$4,718,413 million in 2019 and COP$8,258,485 million in 2018 and COP$5,800,268 million in 2017.2018. The above is equivalent to an effective tax rate of 23.9%42.7%, 23.9% and 40.1% in 2020, 2019 and 42.1% in 2019, 2018, and 2017, respectively.
The increase in the effective tax rate from 2019 to 2020 was mainly due to: (i) the recognition of a deferred tax asset in the amount of COP$1,550,152 in 2019 as a result of the expectation to recover the historical tax losses of Ecopetrol America that were not recognized up until that time , and (ii) higher losses in the Ecopetrol Group’s companies that are taxed under a special regime. This increase was partially offset by Ecopetrol S.A.’s presumptive income in 2020 being taxed at a lower nominal rate.
The decrease in the effective tax rate from 2018 to 2019 was mainly due to the following: i) the agreement signed with Oxy in the U.S. Permian Basin as described elsewhere in this annual report, due to which the Company expects that sufficient future taxable income will be generated in its subsidiaries located in the United States to deduct the historical tax losses of Ecopetrol America. Under IFRS regulations, we are allowed to create a deferred tax receivable in the amount of COP$1,550,152 million, which will gradually offset against the tax charge on future taxable profits generated; ii) the accounting recognition of the market value of our increased equity interest in Invercolsa did not generate a tax charge as it did not constitute non-fiscal revenue and iii) a 4% decrease in the nominal tax rate established by the Colombian Financing Law (Ley de Financiamiento).
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.
Net Income (Loss) Attributable to Owners of Ecopetrol |
As a result of the foregoing, in 2020, net income attributable to owners of Ecopetrol was COP$1,586,677. In 2019, net income attributable to owners of Ecopetrol was COP$13,744,011. In13,744,011, whereas 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$7,178,539 million.
Segment Performance and Analysis |
In this section, including the tables below, we present our financial information by segment: Exploration and Production, Refining and Petrochemicals and Transportation and Logistics. See the sectionBusiness Overview for a description of each segment.
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The following tables present our revenues and net income by business segment for the years ended December 31, 2020, 2019 2018 and 2017:2018:
Table 4954 – Revenues by Business Segment
Year ended December 31, | % Change | For the year ended December 31, | % Change | |||||||||||||||||||||||||||||||||||||
2019 | 2018 | 2017 | 2019/2018 | 2018/2017 | 2020 | 2019 | 2018 | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||
(Colombian Pesos in millions) | (COP$ Million) | |||||||||||||||||||||||||||||||||||||||
Exploration and Production | 52,667,990 | 50,372,764 | 36,494,934 | 4.6 | 38.0 | 36,839,997 | 52,667,990 | 50,372,764 | (30.1 | ) | 4.6 | |||||||||||||||||||||||||||||
Third parties | 31,295,118 | 30,112,900 | 25,004,320 | 3.9 | 20.4 | 22,854,925 | 31,295,118 | 30,112,900 | (27.0 | ) | 3.9 | |||||||||||||||||||||||||||||
Local crude oil | 356,857 | 550,479 | 909,871 | (35.2 | ) | (39.5 | ) | 230,520 | 356,857 | 550,479 | (35.4 | ) | (35.2 | ) | ||||||||||||||||||||||||||
Foreign crude oil | 28,461,601 | 26,898,737 | 21,426,666 | 5.8 | 25.5 | 19,498,553 | 28,461,601 | 26,898,737 | (31.5 | ) | 5.8 | |||||||||||||||||||||||||||||
Local natural gas | 2,256,123 | 1,885,846 | 1,815,754 | 19.6 | 3.9 | 2,845,155 | 2,256,123 | 1,885,846 | 26.1 | 19.6 | ||||||||||||||||||||||||||||||
Foreign natural gas | 27,255 | 27,899 | 32,303 | (2.3 | ) | (13.6 | ) | 17,231 | 27,255 | 27,899 | (36.8 | ) | (2.3 | ) | ||||||||||||||||||||||||||
Other income | 193,282 | 749,939 | 819,726 | (74.2 | ) | (8.5 | ) | 263,466 | 193,282 | 749,939 | 36.3 | (74.2 | ) | |||||||||||||||||||||||||||
Inter-segment net operating revenues | 21,372,872 | 20,259,864 | 11,490,614 | 5.5 | 76.3 | 13,985,072 | 21,372,872 | 20,259,864 | (34.6 | ) | 5.5 | |||||||||||||||||||||||||||||
Refining and Petrochemicals | 38,770,806 | 37,011,373 | 28,644,016 | 4.8 | 29.2 | 26,104,351 | 38,770,806 | 37,011,373 | (32.7 | ) | 4.8 | |||||||||||||||||||||||||||||
Third parties | 36,393,470 | 34,947,948 | 27,343,359 | 4.1 | 27.8 | 24,804,887 | 36,393,470 | 34,947,948 | (31.8 | ) | 4.1 | |||||||||||||||||||||||||||||
Local refined products | 27,170,498 | 26,354,549 | 21,187,091 | 3.1 | 24.4 | 17,745,376 | 27,170,498 | 26,354,549 | (34.7 | ) | 3.1 | |||||||||||||||||||||||||||||
Foreign refined products | 8,977,662 | 8,485,932 | 6,005,556 | 5.8 | 41.3 | 6,165,364 | 8,977,662 | 8,485,932 | (31.3 | ) | 5.8 | |||||||||||||||||||||||||||||
Foreign crude oil | 61,995 | - | 52,397 | 100.0 | (100.0 | ) | 29 | 61,995 | - | (100.0 | ) | 100.0 | ||||||||||||||||||||||||||||
Natural gas local | 49,420 | - | - | 100.0 | - | |||||||||||||||||||||||||||||||||||
Other income | 133,895 | 107,467 | 98,315 | 24.6 | 9.3 | |||||||||||||||||||||||||||||||||||
Other income(1) | 894,118 | 183,315 | 107,467 | 387.7 | 70.6 | |||||||||||||||||||||||||||||||||||
Inter-segment net operating revenues | 2,377,336 | 2,063,425 | 1,300,657 | 15.2 | 58.6 | 1,299,464 | 2,377,336 | 2,063,425 | (45.3 | ) | 15.2 | |||||||||||||||||||||||||||||
Transportation and Logistics | 13,070,736 | 11,354,167 | 10,598,064 | 15.1 | 7.1 | 12,194,440 | 13,070,736 | 11,354,167 | (6.7 | ) | 15.1 | |||||||||||||||||||||||||||||
Third parties | 3,799,924 | 3,543,024 | 3,606,549 | 7.3 | (1.8 | ) | 2,563,581 | 3,799,924 | 3,543,024 | (32.5 | ) | 7.3 | ||||||||||||||||||||||||||||
Inter-segment net operating revenues | 9,270,812 | 7,811,143 | 6,991,515 | 18.7 | 11.7 | 9,630,859 | 9,270,812 | 7,811,143 | 3.9 | 18.7 | ||||||||||||||||||||||||||||||
Eliminations of consolidations | (33,021,020 | ) | (30,134,432 | ) | (19,782,786 | ) | 9.6 | 52.3 | (24,915,395 | ) | (33,021,020 | ) | (30,134,432 | ) | (24.5 | ) | 9.6 | |||||||||||||||||||||||
Total revenues | 71,488,512 | 68,603,872 | 55,954,228 | 4.2 | 22.6 | 50,223,393 | 71,488,512 | 68,603,872 | (29.7 | ) | 4.2 |
(1) | Since 2020, Invercolsa’s sales are recognized as income from gas service without associated volume. In order to give comparability to our financial information, the values reported as residential gas were classified as “other income” in 2019. |
Total revenues by segment include exports and local sales to third-parties and inter-segment sales. See the sectionFinancial Review—Operating Results—Consolidated Results of Operations—Total Revenues for prices and volumes to third parties.
Table 5055 – Operating and Net Income by Business Segment
Year ended December 31, | % change | For the year ended December 31, | % Change | |||||||||||||||||||||||||||||||||||||
2019 | 2018 | 2017 | 2019/2018 | 2018/2017 | 2020 | 2019 | 2018 | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||
(Colombian Pesos in millions) | (COP$ Million) | |||||||||||||||||||||||||||||||||||||||
Exploration and Production | ||||||||||||||||||||||||||||||||||||||||
Operating Income | 11,601,485 | 15,899,337 | 8,061,484 | (27 | ) | 97 | 1,149,291 | 11,601,485 | 15,899,337 | (90.0 | ) | (27.0 | ) | |||||||||||||||||||||||||||
Net income attributable to owners | 9,382,129 | 9,930,519 | 3,820,501 | (6 | ) | 160 | (139,279 | ) | 9,382,129 | 9,930,519 | (101.0 | ) | (6.0 | ) | ||||||||||||||||||||||||||
Refining and Petrochemicals | ||||||||||||||||||||||||||||||||||||||||
Operating Income | 1,142,204 | (757,793 | ) | 1,362,934 | (251 | ) | (156 | ) | (2,185,511 | ) | 1,142,204 | (757,793 | ) | (291.0 | ) | (251.0 | ) | |||||||||||||||||||||||
Net income attributable to owners | 117,708 | (1,973,075 | ) | 358,859 | (106 | ) | (650 | ) | (2,848,511 | ) | 117,708 | (1,973,075 | ) | (2,520.0 | ) | (106.0 | ) | |||||||||||||||||||||||
Transportation and Logistics | ||||||||||||||||||||||||||||||||||||||||
Operating Income | 8,366,747 | 7,317,513 | 6,748,047 | 14 | 8 | 8,218,724 | 8,366,747 | 7,317,513 | (2.0 | ) | 14.0 | |||||||||||||||||||||||||||||
Net income attributable to owners | 4,244,860 | 3,424,234 | 2,999,978 | 24 | 14 | 4,574,800 | 4,244,860 | 3,424,234 | 8.0 | 24.0 | ||||||||||||||||||||||||||||||
Eliminations in consolidation | ||||||||||||||||||||||||||||||||||||||||
Operating Income | (83,278 | ) | (643 | ) | (610 | ) | 12,851 | 5 | (739 | ) | (83,278 | ) | (643 | ) | (99.0 | ) | 12,851.0 | |||||||||||||||||||||||
Net income attributable to owners | (686 | ) | (292 | ) | (799 | ) | 135 | (63 | ) | (333 | ) | (686 | ) | (292 | ) | (51.0 | ) | 135.0 | ||||||||||||||||||||||
Ecopetrol consolidated | ||||||||||||||||||||||||||||||||||||||||
Operating Income | 21,027,158 | 22,458,414 | 16,171,855 | (6 | ) | 39 | 7,181,765 | 21,027,158 | 22,458,414 | (66.0 | ) | (6.0 | ) | |||||||||||||||||||||||||||
Net income attributable to owners | 13,744,011 | 11,381,386 | 7,178,539 | 21 | 59 | 1,586,677 | 13,744,011 | 11,381,386 | (88.0 | ) | 21.0 |
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Exploration and Production Segment Results |
In 2020, exploration and production segment sales were COP$36,839,997 million, compared to COP$52,667,990 million in 2019. In 2020, our segment sales decreased by 30.1% as compared with 2019 mainly as a result of:
(i) | The 27.0% decrease in sales of crude oil to third parties in 2020 as compared to 2019 primarily due to: (i) a decrease in the price of our crude oil basket of US$21.0 per barrel, (ii) an increased spread in our crude oil basket versus the Brent price, (iii) lower production levels, primarily due to lower demand as a result of the mobility restrictions and lockdown that were imposed throughout the year because of the COVID-19 pandemic and impacts due to public order issues. This decrease was partially offset by (i) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in revenue recorded in U.S. dollars, (ii) an increase in crude oil sales of 5.2 mmbls, which in turn was primarily related to an increase in availability associated with lower throughput at our refineries, (iii) an increase in natural gas sales of 2.6 mmbls, which in turn was primarily due to Hocol’s acquisition of 100% of Chevron Petroleum Company’s participation in the Guajira association contract (which corresponds to 43% of the total contract), positive results of our United States Permian operations, the reversion of the Pauto and Floreña fields from Equión to Ecopetrol and the start-up of the Cupiagua LPG Plant. |
(ii) | The 34.6% decrease in inter-segment revenues in 2020 as compared to 2019 mainly due to: (i) the decrease in the price of our crude oil basket and a worsening spread as compared to the Brent price and (ii) lower refineries throughputs due to the global contraction in demand as a result of the COVID-19 pandemic. This decrease was partially offset by the impact of the depreciation of the Colombian Peso against the U.S dollar. |
In 2019, exploration and production segment sales were COP$52,667,990 million, compared to COP$50,372,764 million in 2018. In 2019, our segment sales increased by 4.6% as compared with 2018 mainly as a result of:
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.
(i) | Increased sales of crude oil to third parties, which increased by 3.9% in 2019 as compared to 2018 primarily due to: (i) an increase in local and exports sales of crude oil (4.1 mmbls) mainly due to higher crude exports to Asia and the US Gulf Coast as a result of the Company’s commercial strategy, a higher production level and an increase of purchases to third parties, (ii) an increase in sales of natural gas (0.7 mmbls) due to greater demand, (iii) an increased spread in our crude oil basket versus the Brent price and (iii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars. This increase was partially offset by the decrease in the price of our crude oil basket of US$4.6 per barrel. |
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.
(ii) | Increased inter-segment revenues, which increased by 5.5% in 2019 as compared to 2018 mainly due to: i) higher production volumes as a result of drilling campaigns and purchases to third parties, emphasized deliveries of crude oil in order to supply Reficar and Barrancabermeja in order to replace imported crudes and (ii) the depreciation of the Colombian Peso against the U.S dollar. This increase was partially offset by the decrease in the price of our crude oil basket in spite of better spreads as compared to the Brent price. |
Cost of sales affecting our exploration and production segment are mainly related to: (i) the amortization and depletion of our production assets, (ii) contracted services and (iii) costs related to maintenance, operational services, electric power, projects and labor in the exploration and production segment.cost. In addition, this segment’s costs are impacted by the purchases of crude oil from ANH and third parties, naphtha for dilution and transportation services.
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In 2020, the cost of sales for this segment decreased by 9.5% as compared with 2019 due to the net effect of:
(i) | Fixed costs decreasing by 1.1%, or COP$108,644 million, in 2020 as compared to 2019 mainly due to the optimization plan adopted by the Ecopetrol Group which was reflected in fewer contracted services, lower process materials usage and lower general costs. This decrease was partially offset by higher fixed transportation costs, primarily due to the depreciation of Colombian Peso against U.S dollar. |
(ii) | Variable costs decreasing by 12.5%, or COP$ 3,356,802 million in 2020 as compared to 2019, as a result of (i) the decrease in the price of our crude oil basket resulting in a lower cost of oil, (ii) a decrease in volume of naphtha purchased for dilution as a consequence of lower production of heavy oil and (iii) non-execution of reversal cycles in the Bicentenario pipeline and lower transported volume. The latter was partially offset by (i) an increase in crude oil volume purchases due to a strategy that enabled further optimization of the supply chain, (ii) the decrease in the price of our crude oil basket that impacted the inventory valuation and (iii) higher energy purchases given operative issues in our self-generating plants. |
In 2019, the cost of sales for this segment increased by 12.8% as compared with 2018, due to the net effect of:
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.
(i) | Fixed costs increasing by 8.1%, or COP$716,252 million, in 2019 as compared to 2018, mainly due to: (i) an increase in planned maintenance, higher tariffs and the depreciation of the Colombian Peso against the U.S dollar and (ii) higher labor costs due the recognition of salary increases and benefits for employees under our new collective bargaining agreement along with an increase in the number of employees. |
(ii) | Variable costs increasing by 14.6%, or COP$3,418,429 million, in 2019 as compared to 2018, as a result of (i) an increase of purchases of crude oil due to the strategy, which enables further optimization of the supply chain, (ii) higher transportation costs due to the use of alternative oil pipelines to transport crude oil given attacks against the Caño Limón - Coveñas pipeline and an increase in tariffs, (iii) an increase in natural gas royalties due to higher production, (iv) an increase in depreciation and amortization mainly due to increased investment levels which in turn were primarily due to positive results from the drilling campaign and the improvement in the asset recovery factor and (v) an increase in electricity cost related to higher tariffs. |
In 2020, operating expenses before impairment of non-current assets decreased by 4.5% as compared to 2019 primarily as a net result of: (i) recorded gain on interests derived from Hocol’s acquisition of 100% of Chevron Petroleum Company’s participation in the Guajira Contract (which corresponds to 43% of the total contract) and (ii) a decrease in exploratory activity mainly as a result of (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 pipelinelower drilling and an increase in tariffs, (iii) an increase in natural gas royalties due to higher production, (iv) an increase in depreciation and amortization mainly due to increased investment levels which in turn were primarily due to positive results from the drilling campaign and the improvement in the asset recovery factor and (v) an increase in electricity cost related to higher tariffs.
In 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 increaseseismic activity. The latter was partially offset by lower depreciation(i) higher labor expenses due to certain employees choosing to accept a voluntary retirement plan we offered in 2020, (ii) the write off of certain assets due to the completion of economic feasibility studies, (iii) higher environmental provisions and amortization mainly due of anasset retirement obligations for noncommercial wells, (iv) social investment costs associated with our support to the country to combat the COVID-19 pandemic, and (v) increase in hydrocarbon proved developed reserves in 2018 as comparedfees and freight costs for exports to 2017, which led to a decrease in depreciation expenses.China and Korea.
In 2019, operating expenses before impairment of non-current assets decreased by 10.310.3% 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 beforeThere was an impairment of non-current assets increased by 30.9%recognized in the exploration and production segment in 2020, totaling COP$192,594 million in 2020 as compared to 2017, primarily as a result of (i)COP$1,982,044 million in 2019. The impairment loss in this segment in 2020 was mainly due to the bargain purchase in our acquisition of an additional stakedecrease 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 occurredcrude oil price forecast in the first half of 2018. This increase was partially offset by (i) the elimination of the wealth tax since 2018short 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.long term.
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There was an impairment of non-current assets recognized in the exploration and production segment in 2019, totaling COP$1,982,044 billion in 2019 as compared to the net reversal of COP$785,940 million in 2018. The impairment loss in this segment in 2019 was mainly due to (i) a decrease in the price projection of our crude oil and ii) an increase in net book value as a result of higher asset short-term retirement obligations.
TheBecause of all the above, the segment recorded a net reversalloss attributable to owners of impairmentEcopetrol of non-current assets recognized in the exploration and production segment in 2018, which totaled COP$785,940139,279 million in 20182020 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 toand 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$3,820,501 million in 2017.2018.
Lifting and Production Costs
The aggregate average production cost, on a Colombian Peso basis, increaseddecreased to COP$ 28,634 per boe during 2020 from 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$25,614 per boe during 2018. These increases are2019. This decrease was primarily due to:
A decrease in activity, mainly in subsoil and surface maintenance, primarily due to the restrictions driven by the COVID-19 pandemic. |
(ii) | A decrease in costs related to support services in line with the decrease in our operating activity and a decrease in supplies used in the production process. |
(iii) | An increase in the cost of energy, |
On a dollar basis, the aggregate average production cost decreased to US$ 7.75 per boe in 2020 from US$8.92 per boe in 2019 from US$9.40 per boe in 2018 primarily due to a0.11% 12.46% depreciation of the Colombian Peso against the U.S. dollar in 2019. Production volumes also increased compared to 2018 by 5.4 mboed.2020.
The aggregate average lifting cost, on a Colombian Peso basis, decreased to COP$ 27,555 per boe during 2020 from COP$28,100 per boe during 2019, primarily due to:
(i) | A decrease in activity, mainly in subsoil and surface maintenance, primarily due to the restrictions driven by the COVID-19 pandemic. |
(ii) | A decrease in costs related to support services in line with the decrease in our operating activity and a decrease in supplies used in the production process. |
(iii) | An increase in the cost of energy, primarily due to the use of more costly thermal generation and an increase in our purchases from the national interconnected system; partially offset by our new energy self-generation strategies, which led to a reduction in diesel, fuel oil and residual distillate energy costs. |
(iv) | A decrease in costs related to optimizations in maintenance contracts and others, which allowed us to have better rates and discounts in operation contracts. |
(v) | A decrease in property production volumes compared to 2019 of 6.7 mbed per day. |
On a dollar basis,the aggregate average lifting cost decreased to US$ 7.46 per boe in 2020 from US$8.56 per boe in 2019 from US$8.66 per boe in 2018 also due to a 0.11%12.46% depreciation of the Colombian Peso against the U.S. dollar in 2019.2020.
The difference between the aggregate average lifting cost and aggregate average production cost is that lifting costs does not include costs related to consumption of hydrocarbons by the Company in our production process or the output that we sellthe Company sells to our refineries and natural gas liquid plants.
The following table sets forth crude oil and natural gas average sales prices, the aggregate average lifting costs and aggregate average unit production cost for the years ended December 31, 2020, 2019 2018 and 2017.2018.
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Table 5156 – Crude Oil and Natural Gas Average Prices and Costs
2019 | 2018 | 2017 | ||||||||||
Crude Oil Average Sales Price (U.S. dollars per barrel)(1) | 58.6 | 63.2 | 47.8 | |||||||||
Crude Oil Average Sales Price (COP$ 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 |
2020 | 2019 | 2018 | ||||||||||
Crude Oil Average Sales Price (US$ per barrel)(1) | 34.4 | 58.6 | 63.2 | |||||||||
Crude Oil Average Sales Price (COP$ per barrel)(1) | 126,962 | 192,262 | 187,845 | |||||||||
Natural Gas Average Sales Price (US$ per barrel equivalent) | 4.3 | 4.2 | 3.9 | |||||||||
Natural Gas Average Sales Price (COP$ per barrel equivalent)(2) | 15,719 | 13,670 | 11,741 | |||||||||
Aggregate Average Unit Production Costs (US$ per boe)(3) | 7.75 | 8.92 | 9.40 | |||||||||
Aggregate Average Unit Production Cost (COP$ per boe)(3) | 28,634 | 29,275 | 27,782 | |||||||||
Aggregate Average Lifting Costs (US$ per boe)(4)(5)(6) | 7.46 | 8.56 | 8.66 | |||||||||
Aggregate Average Lifting Costs (COP$ per boe)(4)(5)(6) | 27,555 | 28,100 | 25,614 |
(1) | Corresponds to our average sales price on a consolidated basis. |
(2) | Since 2020, Invercolsa’s sales are recognized as income from gas service without associated volume. In order to give comparability to our financial information, the values reported as residential gas were classified as “other income” in 2019. |
(3) | Unit production costs correspond to consolidated average costs on total production volumes net of royalties. Production costs do not include costs related to transport, commercialization and administrative expenses. |
Lifting costs per barrel are calculated based on total production (excluding production tests and discovered undeveloped fields), which are net of royalties, and correspond to our lifting costs on a consolidated basis. |
The cost indicator is calculated by using the cost of production (does not include costs related to hydrocarbons consumption by Ecopetrol in the production process, such as by our refineries and natural gas liquid plants) and dividing by the net produced volume (excluding royalties) as the denominator. |
As a result of the evaluation of control over companies under IFRS, Ecopetrol does not consolidate Savia Perú and |
Transportation and Logistics Segment Results |
In 2020, our transportation and logistics segment sales were COP$12,194,440 million compared to COP$13,070,736 million in 2019. The 6.7% decrease in 2020 as compared with 2019 was mainly due to: (i) lower volumes of crude oil transported through our pipelines which was primarily due to a decrease of oil production at the national level, including production by third parties, (ii) a decrease in the volumes of refined products transported mainly due to lower demand as a result of the mobility restrictions and quarantines that were imposed throughout the year in order to combat the of the COVID-19 pandemic, (iii) the impact of IFRS 15 in revenue recognition from contracts with customers given that during 2020 the revenue associated with our ship or pay contracts in the Bicentenario and Caño Limón- Coveñas pipelines were not recognized due to the ongoing legal process we were under with some of their shippers (See Note 23.3 to our consolidated financial statements for more details) and (iv) a decrease in our sales of services due to zero reversal cycles through the Bicentenario pipeline during the year as result of a stable operation of the Caño Limón - Coveñas pipeline throughout 2020. This decrease was partially offset by the positive effect on our U.S. dollar-indexed transportation fees resulting from the depreciation of the Colombian peso against the U.S. dollar, previously mentioned.
In 2019, our transportation and logistics segment sales were COP$13,070,736 million compared to COP$11,354,167 million in 2018. The 15.1% increase in 2019 as compared with 2018 was mainly due to: (i) higher volumes of crude oil transported through our pipelines which was primarily dueto 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.
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The cost of sales amounted to COP$3,381,357 in 2020 as compared to COP$3,738,194 million in 2019. The cost of sales for this segment decreased by 9.5% in 2020 as compared with 2019 mainly due to (i) a decrease in costs associated with lower transported volumes, (ii) lower fixed costs mainly as a result of contract renegotiations, (iii) a decrease in depreciation as a result of an adjustment in the useful life of some of our transportations systems, and (iv) a decrease in costs related to the rescheduling of maintenance activities throughout the year, which in turn was primarily due to the effects of the COVID-19 pandemic.
The cost of sales amounted to COP$3,738,194 million in 2019 as compared to COP$3,402,087 million in 2018. The cost of sales for this segment increased by 9.9% in 2019 as compared with 2018 mainly due to (i) an increase in costs associated with higher transported volumes, 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 costIn 2020, operating expenses before the impairment of sales amounted to COP$3,402,087 million in 2018non-current assets increased by 27.6% 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 mainly2019 due toto: (i) an increase in costslabor expenses given that certain of the segment’s employees chose to take the voluntary retirement plan we offered in 2020 and (ii) an extraordinary income recognized in 2019 associated with higher volumes transported, primarily dueto a favorable litigation related to Ocensa’s line filled and no similar income in 2020. This increase was partially offset by a decrease in the expenses associated to the reasons described above and (ii) increased consumption of materials, supplies and depreciation resulting from the startremediation of the San Fernando – Apiay system at Cenit since January 2018damages caused by terrorist attacks and the expansion of the P135 Project since July 2017.illicit taps into our transportation infrastructure.
In 2019, operating expenses before the impairment of non-current assets increased by 57.8% as compared to 2018 due to the expenses associated to the remediation of the damages caused by terrorist attacks and illicit taps in our transportation infrastructure. This increase was partially offset by the favorable ruling in the arbitration claim regarding Ocensa’s line filled with EquionEquión and Santiago. SeeBusiness Overview -Related Party and Intercompany Transactions.
In 2018, operating expenses before theThe reversal of impairment of non-current assets decreased by 27.1%recognized in the segment in 2020, totaled COP$341,065 million as compared to 2017 due to:impairment losses of non-current assets of COP$232,556 million in 2019. This reversal in the impairment of this segment was primarily by a recovery in transported volumes in 2020 through: (i) a reversalSouth CGU, which includes the Transandino pipeline – OTA and the port of a provision we had set aside in respect of tariff dispute we were having in connection with the P135 ProjectTumaco and (ii) North CGU, which includes the eliminationBanadia- Ayacucho pipeline, part of wealth tax since 2018. This decrease was partially offset by higher expenses associated with attacks on our infrastructure by third parties.the Caño Limon- Coveñas system.
The impairment losses of non-current assets recognized in the segment in 2019, totaled COP$232,556 million in 2019 as compared to impairment losses of non-current assets of COP$169,870 million in 2018. The increase in the impairment loss of this segment was primarily the result of a decrease in the forecast of the volume to be transported by the southern cash generating unit, Transandino pipeline and the impact of the terrorist attacks that took place in the Banadia- Ayacucho portion of the Caño Limon- Coveñas pipeline.
The 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$4,244,8604,574,800 million in 20192020 as compared to net income of COP$4,244,860 million in 2019 and COP$3,424,234 million in 2018 and COP$2,999,978 million in 2017.2018.
Refining and Petrochemicals Segment Results |
In 2020, the refining and petrochemical segment sales were COP$26,104,351 million compared to COP$38,770,806 million in 2019. In 2020, sales of refined products and petrochemicals decreased by 32.7% as compared with 2019, mainly due to (i) a decrease of our volumes of gasoline and diesel sales due to a drastic worldwide drop in demand as a result of the COVID-19 pandemic and (ii) lower prices of the product basket given external market factors. This decrease was partially offset by: (i) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars, (ii) higher volumes of polypropylene produced by Esenttia and the strengthening of its international margins and (iii) the consolidation of Invercolsa into our consolidated results of operations as form November 2019.
In 2019, the refining and petrochemical segment sales were COP$38,770,806 million compared to COP$37,011,373 million in 2018. In 2019, sales of refined products and petrochemicals increased by 4.6% as compared with 2018, mainly due to (i) an increase of our diesel exports due to their improved economic performance in the international market and (ii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars. This increase was partially offset by lower prices of our refined product basket and the weakening of international fuel prices.
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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$25,825,555 million in 2020, compared to COP$37,856,219 million in 2019 compared toand COP$35,658,753 million in 20182018.
In 2020, the cost of sales for this segment decreased 31.8% as compared with 2019, principally due to (i) decreased in volume purchases of crude oil for use by our refineries primarily due to lower throughput, which in turn was caused by the COVID-19 pandemic (ii) lower average purchase prices, (iii) a decrease in diesel imports associated with the lower demand caused by COVID-19 national lockdowns and COP$26,855,395 million(iii) the inclusion of a higher percentage of domestic crude in 2017.the Cartagena refinery, which resulted in a more cost-effective crude slate.
In 2019, the cost of sales for this segment increased 6.2% as compared with 2018, principally due to (i) increased purchases of crude oil for use by our Cartagena refinery primarily due to higher throughput and higher feedstock costs due to the appreciation of our crude as compared to Brent, (ii) an increase in diesel imports associated with first quarter operational events in the Barrancabermeja Refineryrefinery 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 slateslate.
In 2018,2020, operating expenses before the costimpairment of sales for this segmentnon-current assets increased 32.8%by 649% as compared with 2017, principallyto 2019, mainly due toto: (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 gasolinesincome as a result of higher production at Barrancabermejaour recognition of the Invercolsa’s valuation in 2019 once we became their controlling shareholder and Reficar refineries andno similar recognition in 2020, (ii) lower importsrecognition of light crude usedthe fixed cost of plants temporarily halted at the Cartagena Refinery as a resultBarrancabermeja refinery given the COVID-19 pandemic and decrease in product demand, (iii) the consolidation of Invercolsa during the entire year of 2020 versus two months in 2019 and (iv) higher labor expenses due certain of the substitution of such crude, which resultedsegment’s employees choosing to accept the voluntary retirement plan in a more cost-effective crude slate for the Refinery.Ecopetrol, previously mentioned.
In 2019, operating expenses before the impairment of non-current assets decreased by 80.1% as compared to 2018, mainly due to the difference between the fair value and book valuegain of COP$1,048,924 recognized when we obtained control of Invercolsa of COP$1,048,924 as noted in sectionFinancial 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.November 2019.
In 2018, operating expenses before the2020, we recognized an impairment loss of non-current assets decreased by 24.6%in this segment totaling COP$781,528 million, as compared to 2017,a reversal of impairment of COP$452,163 million in 2019. The impairment loss we observed in 2020 is primarily the result of (i) an impairment loss of COP $440,525 million attributable to the Cartagena refinery, which in turn was mainly due to stabilization expenseslower refining margins; and (ii) an impairment loss of COP $341,000 million attributable to the Barrancabermeja Refinery Modernization Plan, taking into account progress in the technical analysis of the Cartagena Refinery which was reflected in lower maintenance expenses, contracted services and general expenses.project.
In 2019, we recognized a reversal of impairment of non-current assets in this segment totallingtotaling 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,refinery, considering the state of the technical alternatives analysis of possible future increases in conversion.
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 incomeloss attributable to owners of Ecopetrol of COP$2,848,511 million in in 2020 compared to a net income of COP$117,708 million in 2019 compared toand 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 2017.2018.
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Liquidity and Capital Resources |
Our principal sourcesources of liquidity in 2019 was2020 were: (i) cash flows from our operations amounting to COP$27,711,7679,186,704 million, (ii) cash flow from financing activities, mainly from the proceeds from new issuances of debt instruments, net of related payments of principal and interest, which totaled COP$6,455,835 million and (iii) cash flows from net sales of securities investment portfolio amounting to COP$2,107,856 million.
Our main uses of cash in 2019 were2020 were: (i) COP$13,979,14111,116,861 million in capital expenditures, which included investments in property, plant and equipment, natural and environmental resources and intangibles, (ii) dividend payments amounting to COP$13,867,0298,734,351 million, which included dividends of COP$12,910,6117,369,499 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to the non-controlling shareholders of our subsidiaries totaling COP$956,4181,364,852 million, iii)and (iii) COP$3,002,977 million related to amortizations of capital and debt interest payments and iv) COP$300,326350,539 million in lease payments.
For more information regarding our debt, see the sectionFinancial Review—Financial Indebtedness and Other Contractual Obligations.
Review of Cash Flows |
Cash from operating activities
Net cash provided by operating activities decreased by 66.8% in 2020 as compared to 2019, mainly as a result of:
i) | A 45.4% decrease in our operating income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to (i) lower sales volumes associated with the decrease in demand and weighted average sale prices which in turn primarily reflects the effects of the COVID-19 pandemic as previously discussed, and (ii) expenses in 2020, such as the voluntary retirement plan we offered certain of our employees and aid granted to support Colombian Government efforts to mitigate the health and other social impacts of the COVID-19 pandemic. This decrease was partially offset by (i) lower operational costs given the decrease in our activity levels generally, (ii) new businesses integrated into the Ecopetrol Group’s consolidated results, such as Invercolsa and Permian, and our increased participation in the Guajira association contract and iii) good results of our performance of subsidiaries that are not sensitive to the Brent price, such as Esenttia and Cenit. |
ii) | Higher working capital expenditures needs mainly due to the decrease in operating activity generated by the COVID-19 pandemic, which derived into lower accounts payable with suppliers and an increase in tax assets give that income tax advances did not offset charged taxes as Ecopetrol S.A. will be taxed at the presumptive income tax rate given its decreased income results for 2020. The factor mentioned was partially offset by a decrease in accounts receivable and inventories, which in turn was due to the decrease in sales. |
Net cash provided by operating activities increased by 23.3% in 2019 as compared to 2018, mainly as a result of:
i) | A 2.8% increase in our |
ii) | Lower working capital expenditures needs mainly due to a decrease in accounts receivable from the FEPC and a lower payment in advance of the capital gains tax. |
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Cash used in investing activities
NetIn 2020, net cash providedused in investing activities decreased by operating activities increased by 32.4% in 201815.0% as compared to 2017,2019, mainly as a result of (i) a 31.9% increase20.5% decrease 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 increaseinvestments 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 needsexpenditures, mainly due to an increasethe work restrictions implemented to contain the cases of contagion of COVID-19 (under the concept of operational vital minimum), that was reflected in accounts receivabletemporary closure of some wells and negatively affected our production. All the above primarily affected our capital expenditures in the Rubiales, Caño Sur, Casabe, Sur and Recetor assets as well as the Cartagena refinery, (ii) blockages by the communities in the Rubiales, Apiay and Tibu fields, and (iii) a decrease in our securities investment levels in order to conserve liquidity given the lower generation of cash from the FEPC and the payment in advance of the capital gains tax due in 2019 pursuant to Decree 2146, 2018.
Cash used in investing activitiesoperations.
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 decreased by 84.7% in 2020, as compared to 2019, due to (i) an increase in cash from borrowings, net of related payments of principal and interest, of COP$6,455,835 million as compared to a decrease of COP$3,002,977 million in 2019, which in turn primarily reflects Ecopetrol S.A. entering into committed credit lines in an aggregate principal amount of US$665 million and issuing an SEC-registered bond in an aggregate amount of US$2,000 million in 2020, (ii) a COP$5,132,678 decrease in dividend payments in 2020 as compared to 2019.
Net cash used in financing activities increased by 8.7% in 2019, as compared to 2018, due to (i) an increase in dividend payments to the shareholders of Ecopetrol (COP$12,910,611 million) and in dividend payments made by certain of our subsidiaries to their non-controlling shareholders (COP$956,418 million), (ii) payments of local and foreign currency-denominated loans totaling COP$3,002,977 million and (iii) COP$300,326 million in lease payments.
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.
Capital Expenditures |
Our consolidated capital expenditures in 2020, 2019 and 2018 and 2017 were COP$11,116,861 million, COP$13,979,141 million COP$8,460,426 million and COP$6,107,5068,460,426 million, respectively. These investments were distributed by business segment on average, for the past three years as follows: 85.7%83.5% for the exploration and production segment, 3.7%8.1% for refining and petrochemicals and 10.6%8.4% for the transportation and logistics segment. See Note 32.333.3 to our consolidated financial statements for more detail about capital expenditures by segment.
Our investment plan approved for 20202021 is a range of between US$3,3003,500 million and US$4,3004,000 million. See the section entitledStrategy and Market Overview—20202021 Investment Plan for further information and implicit Brent prices.
The resources required for the investment plan can be funded through internal cash generation with no need to raise additional net financing.and cash surpluses existing at the beginning of the year.
Dividends |
On March 27, 2020,26, 2021, our shareholders at the ordinary General Shareholders Assembly approved a distribution of ordinary dividends for the fiscal year ended December 31, 20192020 amounting to COP$ 7,401,005698,984 million, or COP$18017 per share, based on the number of outstanding shares as of December 31, 2019.2020. The payment datesdate will be April 23,22, 2021 for 100% of shareholders.
In 2020, (100%we paid dividends of COP$7,369,499 million to minorityEcopetrol’s shareholders, / 14%including the Nation, and dividends paid to the majority shareholder), and during the second halfnon-controlling shareholders of 2020 the remaining 86% to the majority shareholder.our subsidiaries totaling COP$1,364,852 million.
In 2019, we paid dividends of COP$12,910,611 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$956,418 million.
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In 2018, we paid dividends for the fiscal year ended December 31, 2017 amounting toof 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$558,986 million.
Summary of Differences between Internal Reporting (Colombian IFRS and IFRS) |
We prepare our interim and annual statutory financial information in accordance with our internal reporting policies, which follow Colombian IFRS and differ in certain significant aspects from IFRS. The following table sets forth our consolidated net income and equity for years ended December 31, 2020, 2019 2018 and 2017,2018, in accordance with Colombian IFRS and IFRS:
Table 5257 – Consolidated Net Income and Equity
For the year ended December 31, | % Change | For the year ended December 31, | % Change | |||||||||||||||||||||||||||||||||||||
2019 | 2018 | 2017 | 2019/2018 | 2018/2017 | 2020 | 2019 | 2018 | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||
(Colombian Pesos in millions) | (COP$ Million) | |||||||||||||||||||||||||||||||||||||||
Net income attributable to owners of Ecopetrol (IFRS) | 13,744,011 | 11,381,386 | 7,178,539 | 20.8 | 58.5 | 1,586,677 | 13,744,011 | 11,381,386 | (88.5 | ) | 20.8 | |||||||||||||||||||||||||||||
Cash flow hedge for future company exports | (419,275 | ) | (471,314 | ) | (366,048 | ) | (11.0 | ) | 28.8 | (122,375 | ) | (419,275 | ) | (471,314 | ) | (70.8 | ) | (11.0 | ) | |||||||||||||||||||||
Exchange rate effects on tax bases – Deferred tax | (73,253 | ) | 646,333 | (192,079 | ) | (111.3 | ) | (436.5 | ) | 223,775 | (73,253 | ) | 646,333 | (405.5 | ) | (111.3 | ) | |||||||||||||||||||||||
Net income Attributable to owners of Ecopetrol (Colombian IFRS) | 13,251,483 | 11,556,405 | 6,620,412 | 14.7 | 74.6 | 1,688,077 | 13,251,483 | 11,556,405 | (87.3 | ) | 14.7 | |||||||||||||||||||||||||||||
Net Equity (IFRS) | 58,231,628 | 57,107,780 | 48,215,699 | 2.0 | 18.4 | 53,499,363 | 58,231,628 | 57,107,780 | (8.1 | ) | 2.0 | |||||||||||||||||||||||||||||
Cash flow hedge for future company exports | (10,099 | ) | (20,792 | ) | (29,258 | ) | (51.4 | ) | (28.9 | ) | - | (10,099 | ) | (20,792 | ) | (100.0 | ) | (51.4 | ) | |||||||||||||||||||||
Exchange rate effects on tax bases – Deferred tax | 2,122,593 | 2,217,450 | 1,594,864 | (4.3 | ) | 39.0 | 2,319,907 | 2,122,593 | 2,217,450 | (9.3 | ) | (4.3 | ) | |||||||||||||||||||||||||||
Net Equity (Colombian IFRS) | 60,344,122 | 59,304,438 | 49,781,305 | 1.8 | 19.1 | 55,819,270 | 60,344,122 | 59,304,438 | (7.5 | ) | 1.8 |
As noted above, certain differences exist between our net income and equity as determined in accordance with our internal reporting policies, which follow Colombian IFRS, which are used for management reporting purposes, as presented in the business segment information, and our net income and equity as determined under IFRS, as presented in our consolidated financial statements.
The primary differences between Colombian IFRS and IFRS as they apply to our results of operations are summarized below:
Cash flow hedge for future company exports. In September 2015, in order to hedge the effect of exchange rate volatility on Ecopetrol’s foreign currency debt, Ecopetrol’s Board of Directors approved a cash flow hedge for future crude oil exports. According to IAS 39 – Financial Instruments, Ecopetrol implemented this hedge beginning on October 1, 2015, the date on which it formally completed the related hedging documentation.
Under Colombian IFRS, the General Accounting Office of the Nation (CGN for its Spanish acronym) issued Resolution 509, which allows companies to apply hedge accounting for non-derivative financial instruments from any date within the transition period or the first period of application of International Accounting Standards in Colombia, even if such company has not yet formally documented the hedging relationship, the objective or the risk management strategy. Under these rules, Ecopetrol applied cash flow hedge accounting from January 1, 2015 in its financial statements under Colombian IFRS.
As a result of this accounting policy difference, for the year ended December 31, 2019,2020, our net income as reported under IFRS was COP$419,275122,375 million higher than our net income as reported under Colombian IFRS.
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Exchange rate effects on tax bases – Deferred tax. According to IAS 12.41, companies with a U.S. dollar functional currency and profit or tax loss in Colombian Pesos are required to recognize deferred taxes attributable to the difference between the carrying amounts of non-monetary assets in their financial statements and their respective tax bases converted from Colombian Pesos to U.S. dollars using the exchange rate on the closing date. The effect of the temporary difference is charged to profit and losses without a cash outflow expected in the future. Under local accounting principles (The General Accounting Office opinion No. 20162000000781 dated January 18, 2016), the result attributable to the aforementioned difference in accounting policies does not generate any deferred taxes.
Ecopetrol’s functional currency is the Colombian Peso and it consolidates some subsidiaries whose functional currency is the U.S. dollar but who settled their taxes in Colombian Pesos. As a result of the application of paragraph 41 – IAS 12, such subsidiaries are required to calculate deferred taxes under IFRS.
As a result of this accounting policy difference, for the year ended December 31, 2019,2020, our net income attributable to owners of Ecopetrol as reported under IFRS was COP$73,253223,775 million higherlower than our net income attributable to owners of Ecopetrol as reported under Colombian IFRS.
The application of IAS12.41 also generated adjustments to our goodwill and investments in companies impairments of COP$12,435 million in 2020, COP$14,865 million in 2019 and COP$22,030 million in 2018 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$12,091 million in 2020, COP$12,630 million in 2019 and 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, 2020, we reported net income attributable to the owners of Ecopetrol under IFRS of COP$1,586,677 million as opposed to a net income attributable to the owners of Ecopetrol of COP$1,688,077 million reported under Colombian IFRS for the same period. For the year ended December 31, 2019, we reported net income attributable to the owners of Ecopetrol under IFRS of COP$13,744,011 million as opposed to a net income attributable to the owners of Ecopetrol of COP$13,251,483 million reported under Colombian IFRS for the same period. For the year ended December 31, 2018, these same accounting differences led us to report net income attributable to the owners of Ecopetrol under IFRS of COP$11,381,386 million as opposed to a net income attributable to the owners of Ecopetrol of COP$11,556,405 million reported under Colombian IFRS for the same period. 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.
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Financial Indebtedness and Other Contractual Obligations |
As of December 31, 2019,2020, we had outstanding consolidated indebtedness of COP$3644.5 trillion, which corresponded primarily to the following long-term transactions:
Table 5358 – Consolidated Financial Indebtedness
Company | Type | Initial Date | Original Amount | Maturity | Interest Rate | Amortization | |||||||||||||
Ecopetrol S.A. | Bonds | September 18, 2013 | US$1,300 million | September 18, 2023 | 5.875 | % | Bullet | ||||||||||||
September 18, 2013 | US$850 million | September 18, 2043 | 7.375 | % | Bullet | ||||||||||||||
May 28, 2014 | US$2,000 million | May 28, 2045 | 5.875 | % | Bullet | ||||||||||||||
September 16, 2014 | US$1,200 million | January 16, 2025 | 4.125 | % | Bullet | ||||||||||||||
June 26, 2015 | US$1,500 million | June 26, 2026 | 5.357 | % | Bullet | ||||||||||||||
June 15, | US$500 million | September 18, 2023 | 5.875 | % | Bullet | ||||||||||||||
December 1, 2010 | COP$ | ||||||||||||||||||
December 1, 2040 | Floating | Bullet | |||||||||||||||||
August 27, 2013 | COP$168,600 million | August 27, 2023 | Floating | Bullet | |||||||||||||||
August 27, 2013 | COP$347,500 million | August 27, 2028 | Floating | Bullet | |||||||||||||||
August 27, 2013 | COP$262,950 million | August 27, 2043 | Floating | Bullet | |||||||||||||||
April 29, 2020 | US$ 2,000 million | April 29, 2030 | 6.875 | % | Bullet | ||||||||||||||
Bank Loans | December 30, | US$ | December 20, 2025 | Floating | Semi-annual | ||||||||||||||
April 15, 2020 | US$ 665 million | September 20, 2023 | Floating | Semi-annual | |||||||||||||||
ECAs | December 30, | US$2,650 million | December 20, 2027 | Fixed | Semi-annual | ||||||||||||||
December 30, | US$100 million | December 20, 2027 | Floating | Semi-annual | |||||||||||||||
December 30, | US$97 million | December 20, 2027 | Fixed | Semi-annual | |||||||||||||||
December 30, | US$210 million | December 20, 2027 | Floating | Semi-annual | |||||||||||||||
Invercolsa & Subsidiaries | Bank Loans | Various | US$ 377,202 million | Various | Fixed | Fixed | |||||||||||||
Leases | Various | US$ 4,471 million | Various | Floating | Various | ||||||||||||||
Ocensa | Bond | US$ 500 million | % | Bullet | |||||||||||||||
Oleoducto Bicentenario | Bank Loan | July 5, 2012 | COP$2.1 trillion | July 5, 2024 | |||||||||||||||
Floating | Quarterly | ||||||||||||||||||
ODL | Lease | November 5, 2015 | COP$ 308,221 billion | November 4, 2032 | Floating | Monthly |
* | Reopening of bond due to 2023. |
** | Debt originally obtained by Reficar for the Refinery modernization and voluntarily assumed by Ecopetrol. In prior annual reports on form 20-F, there was a typographical error in respect of the original amount outstanding on such bank loan. It was listed as US$321 million and the correct amount as listed in the table above is US$440 million. |
The Colombian Superintendence of Finance, through Resolution 1379 of October 10, 2019, authorized the renewal of the term of the Issuance and Placement Program of Internal Debt Bonds and Commercial Papers of the Company for three (3) additional years, until October 10, 2022.
Further, the Ministry of Finance and Public Credit of Colombia, through Resolution 0600 of February 18, 2020, authorized the Company to structure the issuance and placement of bonds in the international capital markets for up to two billion US dollars (US$2,000,000,000).
These authorizations themselves do not constitute an approval for the issuance of securities or any financing transaction.
The short and long term debt transactions executed in 2020 were as follows:
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Ecopetrol did not incur any short-term or long-term bank loans or bonds in 2019.
Contractual Obligations
We enter into various commitments and contractual obligations that may require future cash payments. The following table summarizes our contractual obligations as of December 31, 2019.2020.
Table 5459 – Our Contractual Obligations
COP$ 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 | |||||||||||||||||||||||||||||||||||
Payments due by period | ||||||||||||||||||||||||||||||||||||||||
COP$ Millions | Total | Less than 1 year | 1 to 3 years | 3 to 5 years | More than 5 years | |||||||||||||||||||||||||||||||||||
Employee Benefit Plan | 29,814,647 | 1,326,347 | 2,744,022 | 2,845,377 | 22,898,901 | 33,222,962 | 1,450,763 | 3,017,049 | 3,130,406 | 25,624,744 | ||||||||||||||||||||||||||||||
Contract Service Obligations | 23,942,962 | 5,962,450 | 8,077,571 | 4,488,763 | 5,414,178 | 16,030,925 | 5,155,544 | 3,024,772 | 4,057,953 | 3,792,655 | ||||||||||||||||||||||||||||||
Operating Lease Obligations | 410,126 | 255,187 | 51,373 | 20,253 | 83,312 | 211,661 | 155,862 | 37,506 | 14,550 | 3,742 | ||||||||||||||||||||||||||||||
Natural Gas Supply Agreements | 3,439,765 | 3,258,259 | 3,184 | 0 | 178,322 | 12,157,544 | 5,027,100 | 3,429,898 | 2,678,858 | 1,021,688 | ||||||||||||||||||||||||||||||
Purchase Obligations | 1,552,454 | 895,001 | 377,878 | 45,793 | 233,783 | 2,663,077 | 843,285 | 576,356 | 660,593 | 582,843 | ||||||||||||||||||||||||||||||
Energy Supply Agreements | 1,106,008 | 59,585 | 146,358 | 16,175 | 883,890 | 1,496,929 | 4,598 | 90,733 | 233,353 | 1,168,245 | ||||||||||||||||||||||||||||||
Capital Expenditures | 14,368,402 | 4,688,138 | 4,083,070 | 3,601,107 | 1,996,088 | 13,573,859 | 3,806,896 | 5,566,521 | 2,178,127 | 2,022,316 | ||||||||||||||||||||||||||||||
Build, Operate, Maintain and Transfer Contracts (BOMT) | 325,539 | 32,647 | 66,276 | 67,609 | 159,007 | 469,712 | 81,101 | 139,646 | 107,041 | 141,925 | ||||||||||||||||||||||||||||||
Capital (Finance) Lease Obligations | 766,391 | 95,673 | 151,674 | 120,713 | 398,331 | 308,125 | 34,891 | 63,571 | 59,798 | 149,865 | ||||||||||||||||||||||||||||||
Financial Sector Debt | 8,220,705 | 1,371,546 | 2,529,532 | 2,733,243 | 1,586,384 | 9,499,662 | 1,324,669 | 5,133,819 | 2,339,691 | 701,483 | ||||||||||||||||||||||||||||||
Bonds | 27,844,279 | 556,113 | 1,578,675 | 6,202,348 | 19,507,143 | 34,635,738 | - | 6,379,460 | 4,080,000 | 24,176,278 | ||||||||||||||||||||||||||||||
Total | 111,791,278 | 18,500,946 | 19,809,613 | 20,141,381 | 53,339,339 | 124,270,194 | 17,884,709 | 27,459,331 | 19,540,370 | 59,385,784 |
Note: For the presentation of the contractual obligations in this annual report, contractual obligations beyond the current year represent the expected amount to be committed by us according to our framework contracts. Previously, we were reporting our obligations beyond the current year based on individual orders instead of framework contracts. The implementation of this methodology has resulted in a material increase of our commitments from what was previously reported.
Off Balance Sheet Arrangements |
As of December 31, 2019,2020, we did not have off-balance sheet arrangements of the type that is required to be disclosed under Item 5.E of Form 20-F.
Trend Analysis and Sensitivity Analysis |
Trend Analysis
Ecopetrol updated its Business Plan on February 26, 2020.23, 2021. See the section entitledStrategy and Market Overview—Overview—Our Corporate Strategy—2021 – 2023 Business Plan for a discussion of the trends recognized in the development of that plan.
As described in the section entitledStrategy and Market Overview—2020 Investment PlanSensitivity Analysis 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:
The production target for 2020 set forth above remains unchanged as of phase one, between 745 - 760 mboed.
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.
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.
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 account2020, considering 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.management portfolio costs.
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Table 5560 – 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 | |||||||||||||||||||||
COP$ Millions | Oil and NGL (mmb) | Natural Gas (bcf) | Total Oil and Gas (mmboe) | |||||||||||||||||||||
Reserves as of December 31, 2020 | 1,068.0 | 2,466.0 | 1,501.0 | |||||||||||||||||||||
Sensitivity Scenario | 1,159.4 | 2,309.4 | 1,564.6 | 1,167.0 | 2,509.0 | 1,607.0 | ||||||||||||||||||
Difference (million barrels) | (4.4 | ) | 3.0 | (3.9 | ) | |||||||||||||||||||
Difference (mmb) | 99.0 | 43.0 | 106.0 | |||||||||||||||||||||
Difference (%) | (0.4 | ) | 0.1 | (0.2 | ) | 0.09 | 0.02 | 0.07 |
The conversion rate used is 5,700 cf = 1 boe.
Assumptions for the Sensitivity Analysis of Reserves
The sensitivity of theanalysis assumes a constant ICE Brent price of US$40 per barrel in 2020, US$50 46 per barrel in 2021, between US$ 55 and US$ 58 per barrel in the period 2022-2025, and between US$5361 and US$7268 onwards, and costs of management portfolio.
The base scenario on which our sensitivity analysis is made corresponds to 83%85% of our oil, NGL and natural gas reserves, as of December 31, 2019,2020, as presented elsewhere in this annual report.
Other variables such as the operating costs, capital costs and portfolio price remain unchanged for purposes of the analysis.
Sensitivity Analysis of our Results
The following table provides information about the sensitivity of our results as of December 31, 2019,2020, due to variations of US$1 in the price of ICE Brent crude and of 1% in the COP$/US$ exchange rate.
Table 5661 –Results of Reserves’ Sensitivity Analysis of our Results
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) | ||||||||||||||||||||||||||||||||||||||||
COP$ Million | Income Statement 2020 | Income Statement Case ICE Brent(1) +US$1 | Difference Between Real 2020 and Case ICE Brent | Income Statement Case TRM(2) +1% | Difference Between Real 2020 and Case TRM | |||||||||||||||||||||||||||||||||||
Revenue | 71,488.51 | 72,502.72 | 1,014.21 | 72,185.51 | 697.00 | 50,223.39 | 51,298.64 | 1,075.25 | 50,710.48 | 487.09 | ||||||||||||||||||||||||||||||
Cost of sales | 44,972.36 | 45,376.30 | 403.94 | 45,218.97 | 246.61 | 37,567.47 | 37,963.58 | 396.11 | 37,727.33 | 159.86 | ||||||||||||||||||||||||||||||
Gross Income | 26,516.15 | 27,126.42 | 610.27 | 26,966.54 | 450.39 | 12,655.92 | 13,335.06 | 679.14 | 12,983.15 | 327.23 | ||||||||||||||||||||||||||||||
Operating expenses | 3,726.56 | 3,726.56 | - | 3,726.56 | - | 4,841.00 | 4,841.00 | - | 4,841.00 | - | ||||||||||||||||||||||||||||||
Impairment of non-current assets | 1,762.44 | 1,762.44 | - | 1,762.44 | - | 633.16 | 633.16 | - | 633.16 | - | ||||||||||||||||||||||||||||||
Operating income | 21,027.15 | 21,637.42 | 610.27 | 21,477.54 | 450.39 | 7,181.76 | 7,860.90 | 679.14 | 7,508.99 | 327.23 | ||||||||||||||||||||||||||||||
Finance results, net | (1,670.49 | ) | (1,670.49 | ) | - | (1,670.49 | ) | - | (2,481.59 | ) | (2,481.59 | ) | - | (2,481.59 | ) | - | ||||||||||||||||||||||||
Share of profit of associates and joint ventures | 366.90 | 366.90 | - | 366.90 | - | 76.34 | 76.34 | - | 76.34 | - | ||||||||||||||||||||||||||||||
Income before income tax | 19,723.56 | 20,333.83 | 610.27 | 20,173.95 | 450.39 | 4,776.51 | 5,455.65 | 679.14 | 5,103.74 | 327.23 | ||||||||||||||||||||||||||||||
Income Tax | (4,718.41 | ) | (4,864.41 | ) | (145.99 | ) | (4,826.16 | ) | (107.75 | ) | (2,038.66 | ) | (2,328.52 | ) | (289.86 | ) | (2,178.32 | ) | (139.66 | ) | ||||||||||||||||||||
Net Income | 15,005.15 | 15,469.43 | 464.27 | 15,347.79 | 342.64 | 2,737.85 | 3,127.13 | 389.28 | 2,925.42 | 187.57 |
(1) | ICE Brent = US$ |
(2) | Exchange rate (TRM) = COP$ |
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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 2019,2020, as presented elsewhere in this annual report.
The sensitivity of the ICE Brent price index is in reference to an increase of US$1 per barrel of crude oil in the average ICE Brent reference price based on a 365-day366-day year for 2019.2020. Prices assumed correspond to realized prices for crude oil, natural gas and refined products for 2019,2020, adjusted to account for the differences between such realized prices and the ICE Brent reference price.
The sensitivity of our results to changes in the exchange rate is in reference to a 1% average depreciation of the Colombian Peso against the U.S. dollar during 2019.2020. Prices are the realized prices of crude oil, natural gas and refined products in 20192020 and are expressed for the sensitivity using the adjusted exchange rate (i.e.a 1% average depreciation of the Colombian Peso against the U.S. dollar during 2019)2020).
The income tax for each of our sensitivity analyses (price of ICE Brent and COP$/US$ exchange rate) is estimated using the effective corporate tax rate of 24%43% for 2019.2020.
This sensitivity analysis keeps everything constant. In the case of significant variations of the ICE Brent price, Ecopetrol will perform interventions in its operating expenditures.
The table below sets forth the line items that are being affected by the variation on the reference prices or the average exchange rate.
Table 5762
VARIATION ON ICE BRENT REFERENCE PRICE | VARIATION ON AVERAGE EXCHANGE RATE | |
REVENUE | ||
Sales of crude oil | Sales of crude oil | |
Sales of refined products | Sales of refined products | |
Sales of natural gas | Sales of natural gas | |
COST OF SALES | ||
Local purchases from business partners | Local purchases from business partners | |
Local purchases of hydrocarbons from the ANH | Local purchases of hydrocarbons from the ANH | |
Local purchases of natural gas | Local purchases of natural gas | |
Imports of products | Imports of products |
5. | Risk Review |
5.1 |
The following is a summary of the principal risks we face:
1. | Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time. |
2. | Achieving our long-term growth depends on our ability to execute our strategic plan— specifically, the discovery and/or successful development of additional reserves and our capacity to adapt our business to the transition to a low carbon economy and climate change. |
3. | Our business depends substantially on international prices for crude oil and refined products. |
4. | Changes in the Colombian Peso/U.S. dollar exchange rate could have an adverse effect on our financial condition and results of operations. |
5. | Increased competition from local and foreign oil companies may have a negative impact on our ability to gain access to additional crude oil and natural gas reserves in Colombia and abroad. |
6. | If operational risks to which we are exposed in Colombia or overseas materialize, the health and safety of our workforce, the local community and the environment may be affected. In addition, we may suffer a disruption or shutdown of our operational activities. |
7. | Our involvement in deep-water drilling either as direct operator or in conjunction with our business partners involves risks and costs, which may be out of our control. |
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8. | We are exposed to the credit, political and regulatory risks of our customers. |
9. | Our ability to access the credit and equity capital markets on favorable terms to obtain funding to finance our operations or refinance our debt maturities. |
10. | We may be exposed to increases in interest rates, thereby increasing our financial costs. |
11. | Our interest rate expense may be subject to uncertainty associated with the replacement or reform of benchmark indices. |
12. | Our current and planned investments and exploration activities outside Colombia are exposed to political and economic risks. |
13. | Our future performance depends on the successful selection, development and deployment of new technologies and the knowledge to operate, maintain and improve them. |
14. | Our performance could be negatively affected by the lack of skilled employees to execute our business strategy. |
15. | If the strategic plans associated to natural gas and NGL failed to yield the expected results, our operations may not be able to keep pace with the increasing domestic demand for these products. |
16. | Our operations could be affected by reactions of labor unions, social organizations, communities and contractors to Colombia’s political and social environment, environmental and climate change concerns and organizational changes. |
17. | Our activities may be interrupted or affected by external factors, such as abnormal weather conditions and natural disasters. |
18. | Our business operations and financial condition could be negatively affected by the COVID-19 or other pandemic diseases and health incidents. |
19. | Our operations, including our activities in areas classified as indigenous reserves and Afro-Colombian lands, are subject to opposition from members of various communities. |
20. | We have made significant investments in acquisitions and divestments and we may not realize the expected value. |
21. | We might be required to provide financial support to our subsidiaries in Colombia or abroad. |
22. | Ongoing Colombian State control entities investigations regarding our subsidiary Reficar and our former subsidiary Bioenergy could adversely affect us. |
23. | Our results may be affected by the performance of our suppliers, our business partners or their third-party service providers. |
24. | Our insurance policies do not cover all liabilities and may not be available for all risks. |
25. | New trends in the insurance sector in the face of climate change may bring additional costs or create new conditions to be addressed by our Corporate Insurance Program |
26. | A failure in our information technology systems or cyber security attacks may adversely affect our financial results. |
27. | We are exposed to behaviors incompatible with our ethics and compliance standards. |
28. | The reliability and capacity of national power supply systems may affect or limit the continuity of our operations or limit growth. |
29. | Rising water production levels may affect or constrain our crude oil production. |
Risks Related to Colombia’s Political and Regional Environment
30. | The worldwide economic effects of the outbreak and economic shutdown caused by the COVID-19 pandemic is adversely affecting Colombia’s economy, and the impact could be material. |
31. | The Colombian government could seize or expropriate Ecopetrol’s assets under certain circumstances for fair compensation. |
32. | Colombia has experienced internal security issues that have had or could have a negative effect on the Colombian economy and on us. |
33. | Despite the peace agreement between the Colombian government and the FARC and the peace negotiation process attempts with the National Liberation Army (the ELN), some illegal and terrorist activities of guerrilla groups or their members may continue. |
34. | There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries. |
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35. | The investment climate in Colombia, may be less stable than the prevailing economic conditions and investment climate in developed countries. |
36. | Our operations might be affected by rising climate change and energy transition concerns. |
37. | New or higher taxes resulting from changes in tax regulations or the interpretation thereof in Colombia could adversely affect our results of operations and financial condition. |
Legal and Regulatory Risks
38. | Our operations are subject to extensive regulation. |
39. | Our operations might be affected by rising climate change and energy transition regulatory developments. |
40. | New or higher taxes resulting from changes in tax regulations or the interpretation thereof in Colombia could adversely affect our results of operations and financial condition. |
41. | We may incur losses and spend time and money defending pending lawsuits and arbitrations and responding to administrative investigations. |
Risks Related to Our ADSs
42. | Holders of our ADSs may encounter difficulties in protecting their interests. |
43. | Our ADSs holders may be subject to restrictions on foreign investment in Colombia |
44. | Holders of our ADSs may not be able to effect service of process on us, our directors or executive officers within the United States, which may limit your recovery in any foreign judgment you obtain against us. |
45. | The protections afforded to minority shareholders in Colombia are different from those in the United States, and may be difficult to enforce. |
46. | ADRs do not have the same tax treatment as other equity investments in Colombia. |
47. | Judgments of Colombian courts with respect to our ADSs will be payable only in Colombian Pesos. |
48. | The relative volatility and illiquidity of the Colombian securities markets may substantially limit our investors’ ability to sell our ADSs at the price and time they desire. |
49. | We are not required to disclose as much information to investors as a U.S. issuer is required to disclose. |
Risks Related to the Controlling Shareholder
50. | Our controlling shareholder’s interests may be different from those of certain minority shareholders. |
5.2 | Risk Factors |
The risks discussed below could have a material adverse effect, separately or in combination, on our business’s operating results, cash flows, liquidity and financial condition. Investors should carefully consider these risks.
Risks Related to Our Business |
This section describes the most significant potential risks to our business.
Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time, which could adversely affect our ability to generate revenue.
Reserves estimates are prepared using generally accepted geological and engineering evaluation methods and procedures. Estimates are based on geological, topographical and engineering facts. Actual reserves and production may vary materially from estimates shown in this annual report, and downward revisions in our reserve estimates could lead to lower future production which could affect our results of operations and financial condition.
Hydrocarbon reserves presented in this annual report were calculated in accordance with SEC regulations. As required by those regulations, reserves were valued based on the unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2020, 2019 2018 and 2017,2018, as well as other conditions in existence at those dates. The average of closing prices of ICE Brent crude oil for the first day of each month in the 12-month periodperiods was US$54.93 per barrel in 2017, US$72.20 per barrel 72.2/Bl in 2018, US$ 63/Bl in 2019 and US$63 per barrel 43/Bl in 2019.2020. In 2018,2020, the Company recognized an increasea decrease in oil and gas proven reserves of 4%6.5% as compared to 2017,2019, to 1,7271,770 mmboe in 20182020 from 1,6591,893 mmboe in 2017.2019. In 2019, the Company recognized an increase in oil and gas proven reserves of 9.6% as compared to 2018, to 1,893 mmboe in 2019 from 1,727 mmboe in 2018. For more information, see the sectionBusiness Overview—Exploration and Production—Reserves.
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Furthermore, at least once a year, or more frequently if the circumstances require, the Company ascertains whether there are indicators of impairment to its assets or cash-generating units (CGUs) due to the difference between the carrying amount of such assets or CGUs against to their recoverable amounts, using reasonable assumptions, based on internal and external factors, which reflect market conditions. The recoverable amount is considered to be the higher of the fair value less costs of disposal and value in use, based on the free cash flow method, discounted at the weighted average capital costWeighted Average Cost of Capital (WACC). Whenever the recoverable amount of an asset or CGU is lower than its net carrying amount, such amount is reduced to its recovery amount, recognizing a loss for impairment as an expense in the consolidated statement of profit or loss. External and internal sources of information may indicate that an impairment loss recognized for an asset, other than goodwill, may no longer exist or may have decreased, in this case, the reversal is recognized as an impairment recovery in the consolidated statement of profit or loss.
In 2019,2020, Ecopetrol recognized impairment losses of non-current assets of COP$1,762,437 633,156 million which corresponds to the net result of:
An impairment of non-current assetsforecast in the transportationshort 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
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, 2019.2020. Based on these calculations, assuming an average price per barrel of ICE Brent price of US$40 per barrel in 2020, US$50 per barrel 46/Bl in 2021, US$ 55/Bl and US$ 58/Bl between 2022 and 2025, and between US$53 61/Bl and US$72 68/Bl onwards, Ecopetrol could recognize a decreasean increase in oil and gas proved reserves of approximately 0.2%7%. This analysis takes into account Ecopetrol’s estimates and expectations regarding the main assumptions used in its proven reserve calculation, which final actual result may fluctuate and differ substantially from those provided herein due to several factors outside of the control of the Company. For additional information see the sectionFinancial Review—Trend Analysis and Sensitivity Analysis.
On the contrary, any upward revision in our estimated quantities of proved reserves would indicate higher future production volumes, which could result in lower expenses for depreciation, depletion and amortization for properties to which we apply the units of production method for calculating these expenses. These lower expenses, and any higher revenues as a result of actual production volumes and realized prices, could benefit our results of operations and financial condition.
Achieving our long-term growth depends on our ability to execute our strategic plan — specifically, the discovery and/or successful development of additional reserves.reserves and our capacity to adapt our business to the transition to a low carbon economy and climate change.
Our long-term growth objectives depend largely on our ability to develop the reserves recovery potential associated with existing fields and to discover and/or acquire new reserves, and in turn develop them successfully. Our exploration activities expose us to the inherent geological and drilling risks including the risk of not discovering commercially viable crude oil or natural gas reserves, and the risk that some exploratory wells initially budgeted for may be drilled at a later stage or not be drilled at all. Despite the effort we make to control costs associated with drilling, these are often uncertain, and numerous factors beyond our control may cause drilling operations to be curtailed, delayed or cancelled.
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Our ability to add and develop reserves also depends on our capacity to structurally reduce costs to maintain the profitability of oil fields already being exploited without compromising infrastructure integrity and HSE performance.
Additionally, our strategy envisioned the exploration and development of unconventional reservoirs in Colombia, by using fracking technology. See the sectionStrategy and Market Overview—2021 – 2023 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, obtainingunder implementation by the requisiteColombian Government, the environmental license required for the exploratory phase (including the Integral Pilot Research Projects –PPII) to beginPPII, 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 ablescientific information 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.collected.
If we are unable to achieve expected recovery factors in our existing fields, or successfully discover and develop additional reserves, or if we do not acquire properties having proved reserves, our reserves portfolio will decline. Failure to secure additional reserves may impede us from achieving or maintaining production targets, and may have a negative impact on our results of operations and financial condition.
Furthermore, we are subject to risks related to the transition to a low carbon economy and to climate change. In terms of our physical risks, these are related to the exposure we have to Colombia’s current climate conditions that might affect water availability and increase the exposure of our assets and operations to potential damages. These conditions could result, among others, in water shortages, floods, fires, storms, and hurricanes, rising sea levels that can change in frequency and intensity because of climate change. Extreme weather events could result in damages to our assets and negatively affect our operations and financial condition.
In terms of energy transition risks, we face risks related to our capacity to implement measures to reduce and offset carbon and methane emissions, our adaptation to climate variability and climate change, regulatory risks related to the new climate change regulations implemented in Colombia, such as the carbon tax in place since 2017, the implementation of an emissions trading system (ETS) expected to be implemented in 2022, the updated nationally determined contribution (NDC), and the oil & gas industry’s climate change plan that includes new national mitigation and adaptation measures. These changes could lead to increases in our costs and investments in the short term (Ecopetrol has already incurred in costs related with these regulations and it is expected that continuing to comply with this evolving regulatory landscape will bring additional costs and investments for the Company in the short term). See the section Legal and Regulatory Risks - Our operations might be affected by rising climate change and energy transition regulatory developments.
Additionally, we face the risk of having stranded assets across our business segments. Specifically, we define a stranded asset as an asset or investment that loses its capacity to create economic return before ending its life cycle due to the changes brought about by the low carbon energy transition. Stranded asset risk is measured through a stranded asset risk index methodology that takes into account three risk elements: market (increasing uncertainty in price, accelerated peak oil demand); sustainability (reduced probability of developing an asset because of less community and society support to fossil fuels developments, increased pressure from investors to produce cleaner energies, regulatory changes), and capability (lack of technological capabilities to produce in the short term). Assets that have a score over a threshold in this index are considered in high risk. As of the date of this annual report, the index has been applied to our upstream segment assets with the stranded risk evaluation still being developed in our midstream and downstream segments. Our analysis resulted in no stranded assets in our upstream segment, with the assets with the highest risk of becoming stranded being just initiating their development (either still in the exploratory stage or having just commenced production). While we have begun to implement a mitigation plan in respect of assets with a high risk of becoming stranded, such as prioritizing short cycle projects, starting projects earlier, making current production cleaner and more efficient, and divesting less strategic assets, we can offer no assurance that certain of our assets will not become stranded in the medium to long term.
In addition, our business growth and sustainability depend on our ability to manage theour capital investments and operate efficiently, in accordance with theour corporate strategy guidelines.
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See the sectionStrategy 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,2020, approximately 95%94% of the revenues came from sales of crude oil, natural gas and refined products and 91%90% of the total volume sold of these products was indexed to international reference prices or benchmarks such as ICE Brent. Consequently, fluctuations in those international indexes have a direct effect on our financial condition and results of operations.
Prices of crude oil, natural gas and refined products have traditionally fluctuated as a result of a variety of factors including, among others, competition within the international oil and natural gas industry, long-term changes in the demand for crude oil, natural gas and refined products, notably associated to the transition to a low carbon economy, the economic policies in the United States, China and the European Union, regulatory changes, changes in global supply, inventory levels, changes in the cost of capital, adverse or favorable economic conditions, global financial crises, substitute sources of energy, development of new technologies, global and regional economic and political developments in the Organization of the Petroleum Exporting Countries (OPEC), the willingness and ability of the OPEC and its members to set production levels, local and global demand and supply for crude oil, refined products and natural gas, trading activity in oil and natural gas; weather conditions, natural events or disasters, which are changing in intensity and frequency due to climate change, and terrorism and global conflict. In addition, due to the disagreement on production cuts between the Organization of the Petroleum Exporting Countries (OPEC) and Russia, 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.prices in the past.
Currently, theThe continuing spread of the coronavirus disease (COVID-19) generates uncertainty about a possible slowdowncontinues to lead to periods of instability in the global economy, which in turn could continue to cause a decreaseinstability in crude oil, NGL, and gas demand and oil, NGL, and gas prices. Additionally, the level of global oil inventories caused by the COVID-19 pandemic has created surpluses for oil and may result in the cost of exploring for, developing, producing and transporting oil to go up due to surpluses created by the pandemic. The COVID-19 pandemic may further impact the prices of crude oil, natural gas and refined products as expectations about future commodity prices become unpredictable due to the inability to forecast the duration scope of impact of the pandemic. SeeOur business operations could be disrupted by the CoronavirusCOVID-19 or other pandemic disease and health events for further information on the effects of the coronavirus pandemic.
When crude oil, refined products and natural gas prices are low, we earn less revenue and we generate lower cash flow and less income. Conversely, when crude oil, refined product and natural gas prices are high, we earn more and generate a larger amount of cash and net income. During 2019,2020, our crude oil basket price was US$58.6 per barrel 34.4/Bl versus US$63.2 per barrel 58.6/Bl in 2018,2019, the refined product basket price was US$69.8 per barrel 49.2/Bl versus US$77.3 per barrel 69.8/Bl in 2018;2019; and the natural gas price was US$24.1 24.3 per barrel equivalent in 20192020 versus US$22.4 23.7 per barrel equivalent in 2018.2019. However, it is important to consider that the margin on refined products can result either in higher or lower margins due to a change in price of crude the same way gas prices can be impacted by local conditions, such as local demand and weather conditions.
In 2019,2020, we had an impairment of non-current assets of COP$1,762,437633,156 million, as compared to theCOP$1,762,437 million in 2019 and 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 2017.2018. These impairments are an accounting effect that does not involve any inflow of resources and they are susceptible to reversion when the fair value of the asset is above its book value. For additional information about this impairment charges, see the sectionFinancial Review—Operating Results—Consolidated Results of Operations—Impairment of Non-Current Assets and Note 1718 to our consolidated financial statements.
A reduction of international crude oil prices could also result in a delay or a change in our capital expenditure plan, in particular delaying exploration and development activities, thereby delaying the development of reserves and affecting future cash flows. In order to maintain a profitable operation and preserve the cash flow of the Company at certain oil price levels, some of our producing fields may have to be closed or their operations temporarily suspended which would affect our production levels and expected revenues.
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Changes in the Colombian Peso/U.S. dollar exchange rate could have an adverse effect on our financial condition and results of operations given the amount of U.S. dollar denominated debt held by the company and the fact that most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars.
Most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars. Therefore, when the Colombian Peso depreciates against the U.S. dollar, our revenues converted into Colombian Pesos, increase. Conversely, when the Colombian Peso appreciates against the U.S. dollar, our revenues decrease.
On the other hand, imported goods, oil services and the debt, which is mainly denominated in U.S. dollars, become less expensive when the Colombian Peso appreciates against the U.S. dollar and more expensive when the Colombian Peso depreciates against the U.S. dollar.
As of December 31, 20192020, our U.S. dollar-denominated total aggregate principal amount was US$9.9 12.3 billion, which we recognize in our consolidated financial statements at its amortized cost, which corresponds to the present value of cash flows, discounted at the effective interest rate. Out of this total, an aggregate principal amount of US$9.4 11.8 billion relate to Ecopetrol S.A., whose functional currency is the Colombian Peso. Therefore, when the Colombian Peso depreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate loss. In contrast, when the Colombian Peso appreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate gain. Some of the Ecopetrol Group’s affiliates have the U.S. dollar as functional currency and are not exposed to a material exchange rate risk resulting from fluctuations in the Colombian Peso against the U.S. dollar. On the asset side, when the financial statements of the Ecopetrol Group are consolidated, the exchange rate differential of the affiliates’ assets and liabilities whose functional currency is the U.S. dollar is recognized directly in the equity, as part of other comprehensive income.
The 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.
The U.S. dollar/Colombian Peso exchange rate has fluctuated during the last several years. On average, the Colombian Peso appreciated 3.35%depreciated 12.46% in 2017, depreciated2020, 10.98% in 2019 and 0.18% in 2018, and2018. Additionally, as of December 31, 2020, the Colombian Peso depreciated 10.98% in 2019. Additionally,4.74%; as of December 31, 2019, the Colombian Peso depreciated 0.84%; and as of December 31, 2018, the Colombian Peso depreciated 8.91%, 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 effect of COVID-19 on the world’s economies, 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 sectionFinancial Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results—Exchange Rate Variation and in Note 29.130.1 to our consolidated financial statements.
Increased competition from local and foreign oil companies may have a negative impact on our ability to gain access to additional crude oil and natural gas reserves in Colombia and abroad.
We must bid for exploration blocks offered by the ANH in Colombia and similar authorities in other countries, which means we compete under the same conditions as other domestic and foreign oil and gas companies, and receive no special treatment. Our ability to obtain access to potential fields also depends on our ability for evaluating and selecting potential opportunities and to adequately bid for such opportunities.
We are also exposed to international competition as a result of our international exploratory activities. Currently, we are exploring in Brazil, Mexico and the United States, where we partner and compete with other oil and gas companies operating in those locations.
If we are unable to adequately compete with local and foreign oil companies, or if we cannot enter into joint ventures with market players having high potential exploration projects, our exploration activities may be limited. This could reduce our market share and, in turn, adversely affect our financial condition.
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If operational risks to which we are exposed in Colombia or overseas materialize, the health and safety of our workforce, the local community and the environment may be affected. In addition, we may suffer a disruption or shutdown of our operational activities.
Our exploration, production, refining and transportation activities in Colombia and in the foreign countries in which we operate are subject to industry-specific operating risks, some of which, despite our internal procedures and adherence to industry best practices, are beyond our control. Our operations may be curtailed, delayed or cancelled due to adverse or abnormal weather conditions and natural disasters (mainly due to climate variability or climate change), blockages in the communities in which we operate, equipment failures or accidents, oil or natural gas spills or leaks, shortages or delays in the availability or in the delivery of equipment, delays or cancellation of environmental licenses or other government authorizations or judicial decisions, fires, explosions, blow-outs, surface cratering, pipeline failures, theft and damage to our transportation infrastructure, sabotage, terrorist attacks and criminal activities.
Some of our operations in Colombia and abroad could be conducted in remote and uninhabited locations that involve health and safety risks that could affect our workforce. By our own Company policy and practices, as well as under Colombian law and international industrial safety regulations, we are required to have health and safety practices that minimize risks and health issues faced by our workforce. Failure to comply with health and safety regulations in the jurisdictions where we operate may lead to investigations by health officials that could result in lawsuits or fines.
We may be required to incur in additional costs and expenses to allocate funds to industrial safety and health compliance under Colombian law and international industrial safety regulations. Additionally, if any operational incident occurs that affects local communities and ethnic communities in nearby areas, we will need to incur in additional costs and expenses in order to return affected areas to normality and to compensate for any damages we may cause. These additional costs may have a negative impact on the profitability of the projects we may decide to undertake.
The occurrence of any of these operating risks could result in substantial losses or slowdowns to our operations, including injury to our employees, malfunction or destruction of property, equipment and infrastructure, clean-up responsibilities, third-party liability claims, government investigations and imposition of fines, withdrawal of environmental licenses and other government permits, suspension or shutdown of our activities and loss of revenue. The occurrence of any of these events may have a material adverse effect on our financial condition and results of operations.
Our involvement in deep-water drilling either as direct operator or in conjunction with our business partners involves risks and costs, which may be out of our control.
Our deep-water drilling activities present severe risks, such as the risk of spills, explosions on platforms and drilling operations, and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings. As a result, more stringent government regulation may result in increased costs and longer exploration and development timeframes for our deep-water drilling operations and consequently could adversely affect our results of operations and financial condition. Heightened risks and costs associated with deep-water drilling may have a negative effect on our results of operations and financial condition and in our reputation.
See the sectionBusiness Overview—Exploration and Production for a summary of our current deep-water drilling activities.
We are exposed to the credit, political and regulatory risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.
Some of our customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, many of our customers finance their activities through their cash flows from operations, short and long term debt or equity.
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The combination of decreasing cash flows as a result of declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity may result in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform their obligations to us according to their contractual terms.
Furthermore, some of our customers may be highly leveraged and subject to their own operating expenses. Therefore, the risk we face in doing business with these customers may increase. Other customers may also be subject to regulatory changes, which could increase the risk of defaulting on their obligations to us. We also could have disagreements with customers regarding tariffs, excusable events, or other aspects of our commercial relations that could lead to contract breaches by our clients. See Note 29.230.7 to our consolidated financial statements for more details.
Such financial problems experienced by our customers or deterioration in our relations with our customers could result in the impairment of our assets, a decrease in our operating cash flows and may also reduce or restrict our customers’ future use of our products and services, which may have an adverse effect on our revenues and our ability to make payments under our existing debt obligations.
Our ability to access the credit markets as well as the debt and equity capital markets on favorable terms to obtain funding to finance our operations or refinance our debt maturities may be limited due to the deterioration of these markets, any change to our credit ratings and the authorizations we need before incurring any financial indebtedness.indebtedness or executing any equity offering.
A new financial crisis, volatility in prices in the oil and gas sector, (as what is currently being experienced with the significant droppotential impacts on demand of the pricefurther lockdowns or outbreaks of Brent crude in 2020 year to date), the spread in protectionist policies in the United States, China and Europe,COVID-19, the lack of consensus among OPEC+ members, the political uncertainty in the region, the discovery of corruption by governments and private companies in emerging markets and further geopolitical disruptions in the Middle East, which could involve developed countries, whichand in turn could worsen risk perception with respect to the emerging markets, or the occurrence of any of the risks described in the sectionRisk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Environment could make it more difficult for us and our subsidiaries to access international and local capital markets and finance our operations and potentially refinance our debt maturities on terms acceptable to us. These conditions, along with significant write-offs in the financial services sector and the re-pricing of credit risk, can make it difficult for us to obtain funding for our capital needs on favorable terms. Our cost and ability to obtain capital might be affected as well if our creditors and potential investors believe that we are not actively responding to the new low carbon economy, integrating ESG considerations in our operation and management, and addressing risks related to climate change; considering further the evolving restrictions to invest in pure fossil fuels companies announced by certain investors worldwide.
Access to credit and capital markets is also dependent on our credit ratings, which are mainly determined by our financial and operational strength, oil and gas market conditions and the support that could be provided by the Colombian government. We cannot assure that our credit ratings will continue for any given period of time or that the ratings will not be further lowered or withdrawn. An assigned rating may be raised or lowered depending, among other things, on the respective rating agency’s assessment of our financial strength. In addition, a downgrade in the rating of the Republic of Colombia could also trigger a downgrade on our ratingsours, as our ratingit 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,April 3, 2020, Fitch Ratings downgraded our credit rating from BBB to BBB- as a consequence of our direct linkage of the company to the sovereign rating downgrade of the Republic of Colombia. On March 26, 2020, S&P revised our outlook to negative from stable, as a consequence of the adjustment made to the Colombia´s Sovereign Rating Outlook. On June 27, 2019, S&P upgradedand affirmed our stand-alone credit rating to bbb- from bb+ and maintained our long-term corporate credit rating at BBB- and our outlook at stable.in bbb-. On July 29, 2019,31, 2020, 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.
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.Department and local bond issuances by the Financial Superintendency of Colombia. Likewise, our equity offerings must abide to the terms set forth in Law 1118 of 2006 and any operation within the domestic equity capital market must be previously approved by the Financial Superintendency of Colombia. As such, our indebtednessaccess to debt and equity funding is subject to the Government’s time frames and policies, and we cannot guarantee that such authorizations would be granted in a timely fashion or granted at all.
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We may be exposed to increases in interest rates, thereby increasing our financial costs.
We may incur debt locally and in the international capital markets and, consequently, may be affected by changes in prevailing interest rates. If market interest rates increase, our financing expenses may increase, which could have an adverse effect on our results of operations and financial condition.
As of December 31, 2019,2020, approximately 14.18%13.62%, or a principal of US$1.5 1.8 billion (COP$5.1 6.1 trillion, using a COP$3.277,14/ 3,432.50/1.00 US exchange rate as of December 31, 2019)2020), of our total indebtedness consisted of floating rate debt. If market interest rates rise, our financing expenses will increase, which could have an adverse effect on our results of operations and financial condition. In addition, as we refinance our existing debt in the coming years, the mix of our indebtedness may change, specifically as it relates to the ratio of fixed to floating interest rates, the ratio of short-term to long-term debt, and the currencies in which our debt is denominated in or indexed to. We cannot assure that such changes will not result in increased financing expenses borne by us. Finally, as we incur new debt in the future to fund our capital projects or inorganic acquisitions, the prevailing interest rates and spreads at any specific time could be less favorable in terms of cost when compared to our previous financing transactions, which could adversely affect our financial condition and results of operations.
Our interest rate expense may be subject to uncertainty associated with the replacement or reform of benchmark indices, particularly London Interbank Offered Rate (“LIBOR”).
Interest rate, equity, foreign exchange rate and other types of indices which are deemed to be “benchmarks,” including those in widespread and long-standing use, have been the subject of ongoing international, national and other regulatory scrutiny and initiatives and proposals for reform. Some of these reforms are already effective while others are still to be implemented or are under consideration. These reforms may cause benchmarks to perform differently than in the past, or to disappear entirely, or have other consequences, which cannot be fully anticipated.
Any of the benchmark reforms that have been proposed or implemented, or the general increased regulatory scrutiny of benchmarks, could also increase the costs and risks of administering or otherwise participating in the setting of benchmarks and complying with regulations or requirements relating to benchmarks. Such factors may have the effect of discouraging market participants from continuing to administer or contribute to certain benchmarks, trigger changes in the rules or methodologies used in certain benchmarks or lead to the disappearance of certain benchmarks.
In this regard, on July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. Similarly, it is not possible to predict whether LIBOR will continue to be viewed as an acceptable market benchmark, what rate or rates may become acceptable alternatives to LIBOR, or what effect these changes in views or alternatives may have on financial markets for LIBOR-linked financial instruments. As of December 31, 2020, 8.3% of our long-term nominal debt was subject to floating interest rates that used LIBOR as the benchmark. Although we expect to adapt such contracts as developments relating to a LIBOR replacement arise, currently, we cannot reasonably estimate the impact that the transition to alternative reference rates may have on the valuation, pricing and operation of our LIBOR-based financial obligations, however such changes could have a material adverse effect on our financial condition and results of operations.
Our current and planned investments and exploration activities outside Colombia are exposed to political and economic risks.
We began exploration activities outside Colombia in 2006 through our Brazilian subsidiary, Ecopetrol Óleo e Gás do Brasil Ltda. We operate through business partners, subsidiaries or affiliates outside Colombia. We currently have investments, joint ventures and subsidiaries incorporated in Peru, Brazil, Mexico, Bermuda, Panama, the Cayman Islands, Switzerland, Spain, the United Kingdom and the United States, and we are analyzing investments in other countries. In connection with making investments, we are and will be subject to risks related to economic and political conditions and governmental economic actions. We cannot predict the positions of foreign governments relating to the oil and gas industry, land tenure, protection of private property, environmental standards, regulation or taxation; nor can we assure that future governments will maintain policies favorable to foreign investment or repatriation of capital. Additionally, we may face new and unexpected risks involving environmental and other legal requirements beyond those we currently experience.
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The results of operations and financial condition of our subsidiaries in these countries also may be adversely affected not only by risks associated with hydrocarbon exploration and production, but also by fluctuations in their local economies, political instability and government actions, including: the imposition of price controls, the imposition of restrictions on hydrocarbon exports, fluctuation of local currencies against the Colombian Peso, the nationalization of oil and gas reserves, increases in export and income tax rates for crude oil and oil products, and unilateral (governmental) institutional and contractual changes, including controls on investments and limitations on new projects.
Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas, or our production to decline, limit our ability to pursue new opportunities, affect the recoverability of our assets, or cause us to incur additional costs or delay the timeline of our projects.
Our future performance depends on the successful selection, development and deployment of new technologies and the knowledge to operate, maintain and improve them.
Technology, knowledge and innovation are essential to our business, especially for the addition of reserves in complex settings, reducing operational costs, reducing the carbon footprint of our operations and forin our adaptation to the energy transition. If we do not develop the right technology, or do not secure access to required third-party technology, or if we fail to deploy the right technology, do not obtain the expertise to operate our deployed technology or to improve our processes, or do not deploy the knowledge necessary to improve such technology effectively, the achievement of our corporate goals, our profitability and our earnings may be adversely affected. Furthermore, as we transition to a new low carbon economy and address climate change, we face the risk that our progress may be curtailed due to the high cost of low-carbon and water management technologies. In the case of our enhanced oil recovery program, we not only depend on the successful selection, adaptation, demonstration and deployment of appropriate technologies but also in the reservoir response to the application of these recovery technologies.
Our performance could be negatively affected by a deficiency in leadership capacity andthe lack of key skilled employees.employees with the skills needed to execute our business strategy.
As the oil and gas industry faces an increasing number of challenges, the ability to react quickly to these challenges has become a key factor in achieving efficiency, profitability, growth and sustainability. Our ability to achieve these goals cancould be negatively affected by a deficiency in leadership capacity and a lack of key skilled employees that can execute our business strategy and transition to a low carbon economy with competency, creativity and determination. This situation poses a risk if we are unable to timely strengthen the capacities of management at all levels of the organization and develop the skills they need to find the solutions to implement climate-resilient initiatives and to achieve our decarbonization goals.
OurIf the strategic plans associated to natural gas and NGL failed to yield the expected results, our operations may not be able to keep pace with the increasing domestic demand for natural gas.these products.
According to the latest Natural Gas Supply Plan issued by the Mining and Energy Planning Unit in January 2020 (Unidad de Planeación Minero Energética-UPME), under a medium forecasted demand scenario there wouldis expected to be a natural gas deficit in Colombia as of January 2024.
Considering the CREG Resolution 114186 of 2017,2020, the natural gas market is a physical market, which means that suppliers must comply with the quantitiesagreed 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.
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Additionally, we are currently party to a number of national gas supply contracts that have firm gas commitments. If we were unable to deliver natural gas to these clients as a result of cuts in operations delays in the completion of projects relating to our production facilities or the acceleration of thehigher decline rates in our gas production,fields, among other reasons, we may be required to compensate our customers for our failure to supply natural gas.
Delays in the startimplementation of new projectsour strategic plans associated to natural gas and NGL could result in penalties imposed on us by our clients. We pay penalties dueEcopetrol losing market share if clients choose 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 affectsecure their supply with other sources instead (such as third party gas suppliers or imports). As a result, our financial condition and results of operations.operations could be impacted.
We depend on others for the construction and availability of natural gas transportation infrastructure for the transport of our gas, which may limit our ability to develop new or existing fields or lead to the deterioration of related assets and may not allow us to recover the cost of capital invested in natural gas discoveries.
Ecopetrol S.A. can only hold up to 25% of the equity of any natural gas transportation company according to Article 5 of CREG Resolution 057 of 1996.1996 (except for transportation assets acquired before this Resolution). Therefore, there can be no assurance that the transportation infrastructure necessary to transport natural gas from the fields to distribution points and our customers will be built by third parties or that if built there will be sufficient capacity available to us for the exploitation of new natural gas discoveries or the development of existing fields due to the non-financial closure of transport projects or lack of signed contracts with transporters. The failure to commercially exploit new or existing discoveries may result in impairment of the related assets and our inability to recover the capital expenditures invested to make these natural gas discoveries.
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.
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.disasters that can be exacerbated by climate change.
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, theThe effects of climate variability and climate change, could create impacts and losses in any part of our business operations, for instance,such as the result of increase in the frequency and intensity of theclimate phenomena such as “La Niña” and “El Niño” climate phenomena, causing, intensify the risk of natural disaster occurrence, such as floods, and drought periods,landslides, water availability, wild fires, droughts, increased temperature and rising sea and river levels.levels, among others, which may affect our business operations.
TheIn Colombia, the “El Niño” climate phenomenon is characterized by (i) a lack of rainfall, which limits the amount of water necessarymay drastically decrease surface waterbodies flows, affecting both freshwater withdrawals required for the development of various activitiesoperations and wastewater discharges because of the company,reduction on dilution potential of receiving waterbodies, (ii) increased temperatures, which causes heat waves and could have a direct impact on the health of our worker’s health givenworkers and cause an increased occurrence of heat waves and the increased occurrence ofincrease in epidemics and diseases and (iii) potential negative impact on energy supply. Thesupply due to the decrease in the level of the rivers that feed the hydroelectric generation system of the country. In addition to the “El Niño” climate phenomenon, some basins in Colombia may be affected by seasonal variability in some periods of the year (normally January to March - June to July), which could reduce water flows, affecting freshwater withdrawals and surface discharges, as mentioned previously.
Furthermore, the “La Niña” climate phenomenon is characterized by increased rainfall, which can generate (i) landslides that threaten pipeline infrastructure and increase the risk of ruptures that may cause hydrocarbon spills and limit road transportation and (ii) flooding, which could limit operations in our production fields and facilities.
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As a result, our activities could be significantly affected. These risks could result in property damage, loss in production, loss of revenue, loss of life, pollution and harm to the environment, among others. If any of these occur, we may be exposed to economic sanctions, damages, fines or penalties in addition to the negative effects these events may have on our operations and the costs required to repair or remediate the related damage. These costs, fines and penalties may adversely affect our financial condition, reputation and results of operations.
Our business operations and financial condition could be disruptednegatively affected by the CoronavirusCOVID-19 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)COVID-19, have the potential to negatively impact economic activities in many countries, including the countries in which we operate or have trade links, with consequent adverse effects on our customers and business.
In particular, the timeline and potential magnitude of the COVID-19 outbreak still remain unknown. The ongoingpersistence and variation of the virus could continue to more broadly affect the Colombian and global economy, including our business and operations, because of its impact on the demand for oil and gas. For example, the outbreak of COVID-19 was first reported on December 31, 2019coronavirus has resulted in Wuhan, Hubei Province, China. From Wuhan,a widespread health crisis that has adversely affected the disease spread rapidly to other partseconomies and financial markets of China as well as othermany 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.resulting in an economic downturn that affected our operating results in 2020. In addition, the effects of COVID-19 and concerns related to COVID-19regarding its global spread have recently negatively impacted global financial marketsthe domestic and theinternational demand for crude oil and refiningnatural gas, which has contributed to price volatility, impacted the revenues we receive for oil and natural gas, and has materially and adversely affected the demand for and marketability of our production, and is anticipated to continue to adversely affect the same for the foreseeable future. As the potential impact from COVID-19 is difficult to predict, the extent to which it will negatively affect our operating results, or the duration of any potential business disruption is uncertain. The magnitude and duration of any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control.
In terms of the impact on Ecopetrol, the disagreement on production cuts between the Organization of the Petroleum Exporting Countries (OPEC) and Russia since the beginning of March 2020 through April, 2020, followed by the decision of Saudi Arabia to reduce its sale oil prices and increase its production to gain market share, negatively impacted the international reference prices for crude oil and refined products resulting, among others,in 2020. Furthermore, as a result of the COVID-19 pandemic and measures put in place to slow its spread, including the imposition of quarantines and medical screenings, travel restrictions and the suspension of certain activities, we have seen and expect to continue to see substantial uncertainty in macro-economic conditions with regards to lower prices and demand for oil, gas and related products. These recent global developments resulted in a significant drop in Brent crude prices during 2020 as compared to 2019. As our business depends substantially on international prices for crude oil and refined products, while we were able to recuperate some of the losses suffered during the second quarter of 2020, the sharp decrease in oil prices in 2020 negatively impact our results of operations and business prospects for the year ended December 31, 2020 as compared to the year ended December 31, 2010. In particular, our consolidated gross profit, consolidated operating income, and consolidated net income for 2020 decreased by 52.3%, 65.8% and 81.8%, respectively, as compared to the same line items in 2019. Our operating results were affected mainly by (i) decreases in international prices of crude oil, international prices for refined products and local prices for natural gas, (ii) the reduced demand levels for crude oil and its derivative products, and (iii) decreases in sales volumes, product mix and exchange rate volatility.
For the year ended December 31, 2020, we also recognized impairment losses of non-current assets of COP$ 633,156 million, which corresponds to the net result of:
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At this point, we cannot forecast the duration of the effects of COVID-19 on our business or when international trade (includingprices for crude oil and refined products will stabilize. Our future business results will be affected by the extent and duration of these conditions and the effectiveness of responsive actions that we and others take, including (i) our actions to reduce capital and operating expenses, (ii) in respect of oil supply, chainsany cooperation between OPEC member countries, and export levels), travel, employee productivity, securities markets,(iii) in respect of COVID-19, the impact of vaccination programs, coverage and other economic activities that may have a destabilizing effect on financial marketsimmunity achieved, the severity and economic activity.
On March 17, 2020,duration of the Colombianoutbreak, and the actions by national and international government declared a State of Economic, Social and Ecological Emergencyauthorities to contain the disseminationpandemic and minimize its impact, among other things. We will continue to monitor market developments and evaluate the impacts of COVID-19decreased demand on our production levels as well as impacts on project development 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.
future production.
See Note 332.8 to our consolidated financial statements for further information.
Our operations, including our activities in areas classified as indigenous reserves and Afro-Colombian lands, are subject to opposition from members of various communities.
We currently carry out and plan to continue carrying out activities in areas classified by the Government as indigenous reserves and Afro-Colombian lands. In order to undertake these activities, we must first comply with the previousprior consultation process,processes, set forth by Colombian law. These prior consultation processes are part of the administrative proceduresrequired for obtaining environmental licenses to start our projects, works or activities in areas belonging toinhabited by ethnic communities. In addition, consultations can be seen as a potential instrument to involve communities in the decision of developing extracting industry and infrastructure projects in their territories. Generally, these consultation processes last between six months to one year depending on the community expectations, but may be significantly delayed if we cannot reach an agreement with the communities. We strive to be respectful of the Constitution and laws and the autonomy of indigenous and Afro-descendantafro-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 also been claiming their ancestral territories and requesting recognition of their right to be consulted about projects already in operation. We may be exposed to operational restrictions as a result of the opposition of these communities.
No certainty can be given that we will be able to reach an agreement with the different communities opposedthat do not agree and object to our operations or that such communities will participate in consultation processes if available. We may be exposed to similar delays due to oppositionthe objection from local communities in other countries where we carry out our activities.
Our activities may be subject to objection, including protests by not-ethnic communities. We are also subject to other participation mechanisms, such as popular consultation “acción popular”, where local communities vote against the development of extractive industry projects. Any such similar situation may affect our future projects.
We have made significant investments in acquisitions and divestments and we may not realize the expected value.
We have acquired interests in several companies in Colombia and abroad and have most recentlyin 2019 entered into a joint venture with Oxy in the U.S. Permian Basin. See the sectionBusiness Overview—Our Corporate Structure. Obtaining the expected benefits of the acquisitions will depend, in part, on our ability to (i) obtain the expected results of operations and financial condition from these acquisitions, (ii) manage different sets of assets and operations and integrate distinct corporate cultures, (iii) manage our objectives as a corporate group, and (iv) institute our corporate governance rules as well as other factors beyond our control such as the economic and regulatory environment in countries in which we have made acquisitions as well as all other risks affecting the oil and gas industry. These efforts may not succeed. Our failure to successfully obtain the expected results from our acquisitions could adversely affect our financial condition and results of operations. Also, the acquisitions may be subject of review by administrative control entities in Colombia, which could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations.
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In our shale operations in the U.S., the ability to drill and develop different locations is subject to uncertainties such as natural gas and oil prices, drilling and production costs, availability of drilling services and equipment, lease acquisitions and expirations, processing capacity constraints, pipeline transportation bottlenecks, access to and availability of water sourcing and distribution systems, regulatory approvals, among others. We cannot assure ifthat all the well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil at the planned levels.
As of the date of this annual report, there is not a clear position of the new United States’ administration regarding policies concerning Colombia. Moreover, from the original executive orders signed by President Biden related to climate change, there is a 60 day suspension to issue, extend or amend federal leases or drilling permits on federal land, while a task force conducts an environmental study. This order does not affect operations that were already on going or under drilling permits issued prior the order, but we cannot assure there will be no further executive orders that may adversely affect our U.S. operations. These executive orders also established additional task force groups to review changes in fiscal and regulatory policies, which may include changes in royalty rates, minimum bids and lease terms for federal land. Ecopetrol´s investments in the United States include federal land (Gulf of Mexico), therefore there is uncertainty in terms of how any future regulatory changes by the Biden administration will affect such leases.
In addition, as a result of strategic reassessments of our core operations and portfolio management analysis, we have executed partial or total divestments in our current businesses and the sale price in these transactions might not have been enough to realize the original expected value or to recover the investments the company has made. These transactions may also be subject to review by administrative control entities in Colombia, which could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations.
We might be required to provide financial support to our subsidiaries in Colombia or abroad.
Although currently Ecopetrol is not the sponsor and has not provided financing guarantees to third parties to support the financing activities of any of its subsidiaries, some financial support at any point in time might be needed to assure the long term viability of such subsidiaries when exposed to unexpected conditions, results, or results.when it is utterly required to support projects in their developing phase, in particular with respect of those pre-operative affiliates.
Any situation that could affect the operations of our subsidiaries, or make them financially non-viable, particularly for those that are about to enter into their development phase or for those that recently entered into operations, 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.
OnMarch 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.
Ongoing Colombian State control entities investigations regarding our subsidiariessubsidiary Reficar and our former subsidiary Bioenergy could adversely affect us.
Ecopetrol, Bioenergy and Reficar’s employees are generally subject to the control and supervision of the Colombian State control entities. See sectionRisk 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 sectionRisk 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 sectionRisk Review—Risk Factors—Legal and Regulatory Risk—We may incur losses and spend time and money defending pending lawsuits and arbitrations and responding to administrative investigations.
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Our results may be affected by the performance of our suppliers, our business partners or their third-party service providers.
Some of our suppliers may face financial or operational problems that could led them to a breach of their obligations settled under contractual arrangements. Other suppliers may also be subject to regulatory changes or sanctions that could increase the risk of defaulting on their obligations to us, which could have an adverse effect on our operations and financial condition.
Most of our activity depends on suppliers, sub-contractors and third party service providers that provide goods and services for our operations and projects. In addition, some of our operations and projects are performed through joint ventures or other contractual arrangements with our business partners or third party service providers. Consequently, we depend on the performance of our business partners or third party service providers. The poor performance of our suppliers, in any of them,criteria such as operational efficiency, deadlines, administrative aspects, HSE, or our business partners or third party providers, especially in those projects in which we do not act as operator, could negatively impact the execution of projects and operating performance, which in turn could have a negative impact on our results of operations and financial condition. We are exposed to the risk of not finding business partners or suppliers with the appropriate skills and performance we require for our projects. We are also indirectly exposed to supply agreements and other third-party services contracted by our business partners acting as operators under joint venture agreements.
Our insurance policies do not cover all liabilities and may not be available for all risks.
Our insurance policies do not cover all liabilities, and insurance may not be available for all risks. There can be no assurance that incidents will not occur in the future, that insurance will adequately cover the entire scope or extent of our losses or that we will not be found liable in connection with claims arising from these and other events, which could adversely affect our financial condition and results of operations.
Additionally, due to worldwide market conditions and limitations associated to interpretations and decisions made by the Colombian Surveillance and the Office of the Comptroller General with regards to director and officer insurance, in recent years the terms and conditions of our director and officer insurance policy have been affected, including through a decrease in limits and coverages, which could affect future decisions expected to be made by such directors and officers and could lead to an adverse effect on our financial condition and results of operations.
New trends in the insurance sector in the face of climate change may bring additional costs or create new conditions to be addressed by our Corporate Insurance Program.
We have identified three main insurance trends arising from the transition to a new low carbon economy and climate change that could have a negative impact on the Company (i) insurance and reinsurance companies are considering retiring from the oil & gas industry or are imposing new demands regarding decarbonization targets, which may affect the insurability of assets or higher premiums (ii) policy coverage may change as climate risk modeling and assessment advance, leading to changes in underwriting policies and new policy exclusions, and (iii) increase frequency or intensity of climate related events may lead to increase in premium prices. While we plan to address these trends by quantifying their financial impact and in assessing the need for new risk transfer and risk retention strategies, we can not yet assure that these trend will not increase our insurance costs or reduce our insurance coverage, which could adversely affect our financial condition and results of operations.
A failure in our information technology systems or cyber security attacks may adversely affect our financial results.
We depend on the reliability and security of our information technology systems to conduct certain exploration, development and production activities, process financial records and operating data and communicate with our employees and business partners, and for many other activities related to our business. Our information technology systems may fail or have other significant shortcomings due to operational system flaws or employee misuse, tampering or manipulation. In addition, we may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.
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During 2019,2020, our internal cyber security systems identified and contained cyber security attacks such as malware, phishing and denial of service. In total, we had fourWe did not have any critical incidents during the year and although we have not experienced any material losses relating to failure of our information technology systems or cyber incidents, there can be no assurance that we will not suffer such losses in the future.
We are exposed to behaviors incompatible with our ethics and compliance standards.
Given the large number of contracts that we are a party to in Colombia and abroad with local and foreign suppliers, the geographic distribution of our operations and the great variety of actors that we interact within the course of business, we are subject to the risk that our employees, contractors, or any person having relations with us may misappropriate our assets, manipulate our assets or information or engage in money laundering or the financing of terrorism, for such person’s personal or business advantage. Our systems for identifying and monitoring these risks may not be effective to fully mitigate them in all situations. Such acts may result in material financial losses or reputational harm to the Company.
The reliability and capacity of national power supply systems may affect or limit the continuity of our operations or limit growth.
Our average energy consumption in 20192020 was 7,5027,097 GWh/year, of which 71%68% was supplied through self-generation, and the remaining 29%32% through power grid. Our demand is 10% of the total energy demand in Colombia.
Our self-generation is subject to fuel and solar availability. In addition, several producing fields are connected to the national transmission system and depend on its expansion and reliability to keep steady production levels. The national electricity market is volatile due to changes in hydrology and availability of fuels (natural gas, diesel etc.), bringing uncertainty to prices. If energy were to become unavailable or difficult to obtain, our results of operation and financial condition could be adversely affected.
Rising water production levels may affect or constrain our crude oil production.
During 2019,2020, the Ecopetrol Group produced approximately 16.516.3 million barrels of water per day. Taking into account the nature of our reservoirs, the water production levels to be managed by the Company may increase in the future. In order to achieve our oil and gas production goals and to avoid any production restrictions going forward, we will need to secure the required capacity to manage water levels. Factors that may trigger a possible constraint in our crude oil production due to the rising water production levels are: (i) ineffective project management of the required facilities, (ii) the Company’s and its partners’ ability to timely obtain the environmental permits related to water management, (iii) social and community interactions that could affect the development and operation of these projects, and (iv) the availability of capital to execute the required projects.
Risks Related to Colombia’s Political and Regional Environment |
This section discusses potential risks related to our extensive operations in Colombia.
The worldwide economic effects of the outbreak and economic shutdown caused by the COVID-19 pandemic is adversely affecting Colombia’s economy, and the impact could be material.
The COVID-19 pandemic is currently having an adverse impact on the world economy. Many countries have undertaken various public health measures to control the spread of COVID-19, including mandatory quarantines, forced economic shutdowns and travel restrictions, as well as economic measures to mitigate the impacts of such public health policies on their respective national economy. As of March 31, 2021, Colombia had 2,406,377 confirmed cases of COVID-19, 2,285,515 recovered cases and 63,422 deaths.
On March 17, 2020, the Government, through Legislative Decree 417 of 2020, declared a 30 day state of national emergency in light of the health and economic crisis caused by the outbreak of COVID-19. On May 6, 2020, through Legislative Decree 637 of 2020, the Government declared a state of emergency for an additional 30 days. The Government has implemented various economic and public health measures to address the crisis, including (i) mandatory shelter in place orders; (ii) border closure for all non-citizens and non-residents; (iii) short term and low interest loans for all types of agricultural producers; (iv) payroll subsidies for companies and credit lines for different sectors of the economy; (iv) closure of all schools and universities; (v) incentivizing working from home and a mandatory work from home order for 80% of Government employees; (vi) actions by the Banco de la Republica, including reductions of its interest rate by 250 basis points in 2020, the provision of non-delivery forwards in the amount of up to U.S. $1 billion and supplying liquidity auctions up to COP$ 20 trillion; (vii) suspension of increases in utility tariffs; (viii) reduction in the prices of gasoline; (ix) changes to the general budget and measures to render more flexible certain procedures to enable the Government to access the credit markets; and (x) increased COVID-19 testing of up to 15,000 per day, among others. The efficacy of certain of these measures cannot yet be evaluated, and their duration and effect remain uncertain. On December 18, 2020, the Government announced that the country had purchased 40 million doses of COVID-19 vaccines, composed of 10 million doses from Pfizer Inc., 10 million doses from AstraZeneca and 20 million doses from the multilateral Covax agreement. Vaccination began in February 2021 and will have 5 phases, prioritizing those at higher risk, such as health workers and citizens over 80 years old.
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From a macroeconomic point of view, the COVID-19 pandemic had a negative impact on Colombia in 2020 with GDP decreasing by 6.8% for the year ended December 31, 2020 as compared to the year ended December 31, 2019. The main industries that lead to this decrease were construction, transportation, and accommodation, real estate and food services. Economic stagnation, the depreciation of the Colombian Peso, contraction and decreased income levels and increased unemployment levels could result in a pronounced period of economic slowdown in Colombia, which could lead to a further decrease in oil and gas demand and hence could continue to negatively impact our business and financial condition. Furthermore, the COVID-19 outbreak has also resulted in increased volatility in both the local and the international financial markets and economic indicators, such as exchange rates, interest rates, credit spreads and commodity prices. Any shocks or unexpected movements in these market factors could result in financial losses in our investment portfolio.
If the economic and public health crisis caused by the COVID-19 outbreak continues and the Government’s measures are not effective, the economic performance of the country may suffer further than already anticipated, as a result of adverse effects on commerce, transportation and foreign investment, among other things, and thus may potentially adversely affect Ecopetrol’s ability to service its debt, including the bonds. The effects of the COVID-19 pandemic and the economic shutdown may also include an increase in unemployment, a reduction in household income, reduction in Government revenues, increased Government expenditures and a deterioration of Ecopetrol’s and Colombia’s financial position. The sharply lower demand for oil and its derivatives due to decreased demand as a result of the COVID-19 pandemic in turn resulted in lower and more volatile price of oil and gas, which has also negatively affected the Colombian economy and the financial position of Ecopetrol. The Government has projected negative GDP growth of 6.8% for 2020, the first recession in Colombia in over two decades.
The COVID-19 pandemic, any additional wave or resurgence and/or new pandemic may also have the effect of heightening the other risks described herein, such as those relating to economic, social and political developments in Colombia and its credit ratings. Consequently, the current COVID-19 pandemic and its potential impact on the global economy may require Colombia to enact additional changes to existing regulations or implement more stringent regulations, which may further adversely impact the Republic’s economy, the prices of, and Colombia’s ability to make payments on, its outstanding securities or other indebtedness.
The Colombian government could seize or expropriate Ecopetrol’s assets under certain circumstances for fair compensation.
Pursuant to Articles 58 and 59 of the Colombian constitution, the Government can exercise its eminent domain powers in respect of private property assets in the event such action is deemed by the Government to be required in order to protect public interests. According to Law 388 of 1997, eminent domain powers may be exercised through: (i) an ordinary expropriation proceeding, or (ii) an administrative expropriation. In all cases we would be entitled to a fair compensation for the expropriated assets. Also, as a general rule, compensation must be paid before the asset is effectively expropriated. However, the compensation may be lower than the price for which the expropriated asset could be sold in a free-market sale or the value of the asset as part of an ongoing business. The aforementioned Article 59 of the Colombian constitution establishesestablishes a temporary expropriation for war reasons, which does not require that compensation be paid before expropriation.
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Colombia has experienced internal security issues that have had or could have a negative effect on the Colombian economy and on us.
Colombia has experienced internal security issues, primarily due to the activities of guerrillas, paramilitary groups, drug cartels and criminal bands known asBacrim. 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 2019,2020, the attacks against our pipeline infrastructure decreased by 31.4%29% in relation to 2018 (1052019 (51 attacks in 20182020 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 inThere was no deferred production directly related to these attacks in 2020 as compared to a deferred production of 660,052 barrels in 2019 from 11,102 barrels in 2018, mainly due to social problems in2019. Throughout the area impacted by the third partyfirst quarter of 2021, there were 12 attacks principally in the Arauca department.against our pipeline infrastructure.
Guerilla attacks have resulted in unscheduled shutdowns of our transportation systems in order to repair or replacereplace 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 20192020 was approximately COP$236,059213,300 million (US$72.0362.147 million, using a COP$3.277,14/3,432.50/1.00 US exchange rate as of December 31, 2019)2020). During 2020 we also experienced one particular attack to our production infrastructure in Casanare, specifically on the first three monthstransfer line parallel to the Liria well that, while not affecting people or the environment, resulted in in a dent.
During 2018, attacks resulted in the unavailability of 2020, there have been 18 attacks against the infrastructure of theour Caño Limón Coveñn-Coveñas and Transandino pipelines. Additionally, these attacks have resulted inpipeline which led certain of our customers requestingto request the early termination of their transport agreements. WeWhile we have reached preliminary settlement agreements with our customers in respect of these disputes, such agreements are currently disputing such terminations.subject to regulatory approvals. See Note 22.423.3 to our consolidated financial statements for further information.
Likewise, the theft of refined products and crude oil, resulting fromas a result of security issues, may impact our operating and financial results in the future. Theftfuture, as well as our reputation, due to the potential use of refinedthese products increasedwithin the alkaloid chain production and the possible impact to communities and the environment, derived from approximately 21 bod in 2018 to approximately 37 bod in 2019. Theftthis illegal practice. Associated with the above, the theft of crude oil has increased from approximately 1,324 bod in 2018 to approximately 1,808 bod in 2019 to approximately 2,744 bod in 2020, representing for Ecopetrol and its partners a consolidated loss of COP$367,515 million for the year ended December 31, 2020 (US$107,069 million, using COP$3,432.50/US$1.00 exchange rate as of December 31, 2020) and COP$ 241,840 million for the year ended December 31, 2019. This situation is directly related to the increase of illicit crops, presence of guerilla dissidents and other illegal groups in the areas of influence of the main crude transportation systems, such as as Caño Limón – Coveñas System (Catatumbo and Norte de Santander) and the Trasandino System (Tumaco and Nariño). Furthermore, the theft of refined products is related to the presence of common crime that illegally markets these products, presenting losses of approximately 24 bod and 37 bod in the years ended December 31, 2020 and 2019, respectively.
These activities and their possible escalation and the effects associated with them have had, and may have in the future, a negative impact on the Colombian economy or on us, which may affect our customers, employees, assets or the environment, with resulting containment, clean-up and repair expenses.
Despite the peace agreement between the Colombian government and the FARC and the peace negotiation process attempts with the National Liberation Army (the ELN), some illegal and terrorist activities of guerrilla groups or their members may continue.
On November 30, 2016, the Colombian Congress approved a peace agreement between the Colombian government and the Revolutionary Armed Forces of Colombia, or FARC. Since then, the Colombian government has advanced in the process of gradually integrating many of the FARC members into civilian and political life. In spite of these efforts, in August 2019 some former leaders of this guerilla left the process and announced the resumption of hostilities.
Likewise, the National Liberation Army, or ELN, guerrilla group, has increased its actions against the Colombian security forces and the critical infrastructure of the Nation, which we believe is an attempt to show its presence and influence in some regions and put pressure to resume peace negotiations that were interrupted since January 2019, as a result of the terrorist attacks carried out by the ELN.The Colombian Government maintainsproclaims that the continuity of the dialogues depends on the cessation of terrorist activities and the release of hostages by this group. It is expected that attacks against critical infrastructure will continue until a new bilateral ceasefire can be agreed upon.
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Therefore, it is expected that some guerilla groups, such as the ELN, may continue their illegal and terrorist activities, including attacks on our infrastructure, resulting in a deterioration of Colombia’s national security and our assets, which consequently may negatively impact our operating results.
There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries.
There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries.
In particular, the economic, political and social crisis in Venezuela is having a severe impact on Colombia’s economy and social situation. This situation could affect the countries’ diplomatic relations, impact border towns and cities, accelerate Venezuelan migration flow into Colombia, affect our borderline operations and therefore may have a negative impact on Colombia’s economy and general security situation as well as in our operating results.
Companies operating in Colombia, including us, are subject to the prevailing economic conditions and the investment climate in Colombia, which may be less stable than the prevailing economic conditions and investment climate in developed countries.
Market prices of securities issued by Colombian companies, including us, are subject to the prevailing economic conditions in Colombia. A large portion of our assets and operations are located in Colombia and most of our sales are currently derived from our local crude oil and natural gas production and the production of our refineries located in Colombia. Accordingly, our financial condition and results of operations depend to a significant extent on macroeconomic and political conditions prevailing from time to time in Colombia and on the exchange rates between the Colombian Peso and the U.S. dollar.
If the perception of improved overall security in Colombia deteriorates or if the investment climate worsens, the Colombian economy may face lower growth rates than the ones posted recently, which could negatively affect our financial condition and results of operations. Additionally, the uncertainty of Colombia´s economic recovery due to the COVID-19 pandemic could have an impact on our results.
Furthermore, the market price of our shares and American Depositary Shares, or ADSs, may be adversely affected by changes in governmental policies, particularly those affecting economic growth, exchange rates, interest rates, inflation and taxes. The Government has changed monetary, fiscal, taxation, labor and other policies over time and has thus influenced the performance of theColombian 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.
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 sectionFinancial 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.
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 sectionBusiness 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 sectionBusiness Overview—Applicable Laws and Regulations—Regulation of Exploration and Production Activities—Business Regulation—Royalties for a description of the current royalty scheme.
Our operations in Colombia are subject to extensive national, state and local environmental regulations. Environmental rules and regulations are applicable to our exploration, production, refining, transportation, supply and marketing activities, as well as the biofuels we produce. These regulations establish, among other things, quality standards for hydrocarbon products, air emissions and greenhouse gases, water discharges and waste disposal, soil remediation, water pollution and the general storage, handling, transportation and treatment of hydrocarbons in Colombia. Currently, all exploratory drilling projects in areas that do not yet have a license must undergo an environmental impact assessment and must receive an environmental license from the governmental agency responsible for awarding environmental licenses, the National Authority on Environmental License 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 sectionBusiness Overview—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.Ecopetrol Group.
In addition, the companies of the business group conducting upstream activities outside Colombia may be subject to foreign health, safety and environmental regulations. Foreign health and safety regulations may be more severe than those established under Colombian law and, therefore, we may be required to make additional investments to comply with those regulations.
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Under certain of our credit agreements, we are under an obligation to comply with international environmental standards established by our lenders or by multilateral institutions. Failure to comply with such environmental standards could result in an event of default under the relevant credit agreements that we, or our subsidiaries, have entered into, which would affect our financial condition.
Our operations might be affected by rising climate change and energy transition regulatory developments.
The increase in global temperature due to the substantial increase of GHG is a concern worldwide. The Paris Agreement calls for immediate and forceful actions to be taken to limit the increase of global temperature below 1.5°C. In response, government agendas have increasingly been defining normative and regulatory frameworks that determine local actions related to climate change.
As a result, companies are increasingly subject to regulatory risks and public policy changes related to climate change. For instance, as of December 2020 Colombia announced an ambition goal to reduce carbon emissions by 51% by 2030 as part of its Nationally Determined Contribution (NDC). This national commitment is considered in Ecopetrol’s ongoing review of its objectives on emission reductions.
Furthermore, in addition to the carbon tax that Colombia imposed for fuel consumption, of approximately US$5 per ton of CO2, in 2022 we expect a National Program of Tradable Quotas of (PNCTE), a type of Emissions Trading System (ETS) to enter into force. Additionally, the Colombian government is planning a regulation on reduction of routine flaring and fugitive emissions. While we expect these to be in line with our current decarbonization policy for the identification, measurement, and correction of fugitive emissions and vents, we can offer no assurance that we will meet the new regulations or that the new regulations will not need to increased costs. Any of the two mentioned effects could negatively impact our financial condition and results of operations.
New or higher taxes resulting from changes in tax regulations or the interpretation thereof in Colombia could adversely affect our results of operations and financial condition.
New tax laws and regulations, and uncertainties in the interpretation with respect to existing and future tax policies pose risks to us. In recent years, the Colombian Congress and tax authorities have enacted modifications to taxes related to financial transactions, income, value added tax (VAT), and taxes on net worth. In December 2018, pursuant to Law 1943, the Colombian Congress enacted a tax reform (the Financing Law), which became effective as of January 1, 2019 and modified the Colombian income tax regime. This Law 1943 was declared unconstitutional as of January 1, 2020 but continued to have full effect until December 31, 2019. In December 2019, Congress passed Law 2010 called “Ley de Crecimiento Económico” or “Economic Growth Law” which largely maintains the changes of the previous tax reform along with some changes to tax legislation.
For a description of taxes affecting our results of operations and financial condition in 2019, see section Financial Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on Our Results—Taxes. Changes in tax-related laws and regulations, and interpretations thereof, can affect tax burdens by increasing tax rates and fees, creating new taxes, limiting tax deductions, and eliminating tax-based incentives and non-taxed income. In addition, tax authorities and tax courts may interpret tax regulations differently than we do, which could result in tax litigation and associated costs and penalties.
Until 2016, for Colombian income tax purposes, dividends that were distributed from profits taxed at the corporate level were not taxed or subject to withholding tax at the shareholder level. However, beginning in 2017, the regulation changed so that dividends paid to non-resident shareholders are subject to a withholding tax. For further detail and a description of such changes, see section Financial Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results – Taxes. Further changes to Colombian tax laws may subject us and our shareholders to higher taxes and could adversely affect our results of operations and financial condition.
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We may incur losses and spend time and money defending pending lawsuits and arbitrations and responding to administrative investigations.
We are currently a party to several legal proceedings filed against us. We are also subject to labor-related lawsuits filed by current and former employees in connection with pension plans and retirement benefits. As of December 31, 2019,2020, Ecopetrol S.A. was a party to 4,9885.361 legal proceedings relating to civil, criminal, administrative, environmental, tax, labor claims, of which 3,4453.641 were filed against us in the Colombian courts and arbitration tribunals and of which 266234 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 2122 to our consolidated financial statements and see sectionRisk Review—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 sectionRisk Review—Review—Legal Proceedings and Related Matters.
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 registerhandle 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.payments, especially if the foreign investment is not duly registered before the Colombian Central Bank. Also, currently Colombia has a floating exchange rate system that might be subject to change in the future. See sectionShareholder Information—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 youADSs holders to effect service of process within the United States upon us or these persons or to enforce judgments against us or them in U.S. courts obtained in such courts predicated upon the civil liability provisions of the U.S. federal securities laws. Colombian courts determine whether to enforce a U.S. judgment predicated on the U.S. securities laws through a procedural system known asexequatur. For a description of these limitations, see sectionShareholder Information—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 sectionShareholder Information—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, 2019,2020, the Colombian Stock Exchange (BVC) had a market capitalization of approximately COP$436,786365,657 billion (US$133.28105 billion using the closing rate for 2019)2020), a 29% increase16% decrease when compared with the amount at the end of 2018,2019, a daily average trading volume of approximately COP$142,796122,752 million (US$43.5033 million, using the average exchange rate for 2019)2020), a 3%14% decrease when compared with the volume in 2018.2019. By comparison, the New York Stock Exchange (the NYSE) had a market capitalization of US$30.932.6 trillion as of December 31, 2019,2020, and a daily trading volume of approximately US$135.8182.7 billion in 2019.2020.
As of December 31, 2019,2020, our shares represented the highest market capitalization of the BVC accounting for 14.70%11% of the total COLCAP index, which reflects the price volatility of the 20 most-liquid stocks.
Given the current ownership structure of our shares, it may be difficult for you to purchase large quantities of shares from a single shareholder. We cannot assure you that a liquid trading market for our ADSs will develop or, if developed, that it will be maintained. Without a liquid trading market, the ability of investors in our ADSs to sell them at the desired price and time could be substantially limited.
We are not required to disclose as much information to investors as a U.S. issuer is required to disclose.
We are subject to the reporting requirements set by Law 964 of 2005, the Superintendence of Finance and the BVC - (Colombian Stock Exchange). The corporate disclosure requirements that apply to us may not be equivalent to the disclosure requirements that apply to a U.S. issuer and, as a result, you may receive less interim information about us than you would receive from a U.S. issuer.
Risks Related to the Controlling Shareholder |
Our controlling shareholder’s interests may be different from those of certain minority shareholders.
The Nation currently holds 88.49% of our outstanding capital stock, making it our controlling shareholder. The Nation as our controlling shareholder has majority voting rights at the General Shareholders Assembly to elect the members of our Board of Directors and may propose and approve decisions that may be in its own interest and that may not necessarily benefit minority shareholders.
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Our controlling shareholder may proposesuggest 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 sectionShareholder 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.
Risk Management |
Under the leadership of the Vice-Presidency of Compliance, in 2020 Ecopetrol S.A. consolidatedstrengthened 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), EnterpriseIntegrated Risk Management (COSO 2017)System based on the international technical standard ISO 31000, which establishes a set of principles, frame of reference and our ethics and compliance rules, withprocess or cycle that allow 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 employeesorganization to manage risk, to maintain the effectivenesseffects of controls, to report incidentsuncertainty on meeting objectives, in order to preventively correct possible deficienciesmaximize opportunities and to provide reasonable assurance of achieving corporate objectivesassist in establishing strategies and goals.making informed decisions.
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.
Our risk management approach is based on the risk management cycle, consisting in fivewhich consists of four main stages: planning, identifying, evaluating, treatment and monitoringmanaging risks, as well as cross-cutting stages of communication across all stages.and consulting, record and reporting and monitoring. This cycle is supported in three pillarsby the principles of risk management: integration, continuous improvement, structure, information, culture, organizational structure and normative and management tools.
Three of our most important tools within theour risk management componentapproach are:
i. | Risk Assessment Methodology: In order to properly prioritize mitigation, treatment and monitoring efforts of risk management at the process level, a standardized methodology was established to assess inherent and residual risk levels. The risk level (Very High, High, Medium, Low or None) is obtained from the combination of the |
ii. | Mitigation Plans: Each year, by performing the stages of the risk management cycle, we define and implement mitigation plans in order to reduce the levels of exposure to risk through mitigation or elimination of some of its causes. Metrics and goals must be defined during the development of each plan to ensure its effectiveness and to prioritize our efforts on those with the greatest impacts. |
iii. | Monitoring Indicators: As part of the monitoring stage of the risk management cycle, Ecopetrol has implemented Key Risk Indicators (KRIs) which are metrics used to provide early signals of increasing risk exposures. These signals constitute information for preventative decision making in order to avoid risk materialization. |
The Integrated Risk Management System establishes the definition of risk as the effect of uncertainty on the fulfillment our objectives, considering the effect as the deviation positive, negative or both, compared to what is expected. Our risks can be classified as:
i. | Enterprise Risks: These are those risks that are directly associated with the business strategy plan of the Company and are systematically monitored by the Management Committee. When defining the enterprise risks, the analysis of the internal and external environment is carried out to determine the topics and trends that could have potential or real impact on Ecopetrol´s strategy. Emerging risks are selected from those trends, and they are included in the enterprise risks as a new risk or as a cause of existing enterprise risk. Further information can be found in Ecopetrol’s 2020 Enterprise Risk Map which is available on our website at: |
https://www.ecopetrol.com.co/wps/portal/Home/es/NuestraEmpresa/%C3%89tica%20y%20Transparencia/GestionDeRiesgos.
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The management of those risks is led by the person accountable for the process and each risk has a defined treatment plan and monitoring indicators.
ii. | Processes Risks: These are those risks that tend to identify potential failures in the activities related to our core and support business processes that drive us to achieve our objectives. At this level, our processes have identified risks with their respective mitigation methods, including financial and non-financial controls, treatment plans and/or monitoring indicators. |
iii. | Operational Risks: These are those risks that are at an operational level of detail and occur in our day-to-day activities and tasks. |
Ecopetrol has also continued consolidating its internal control systems into a unified system that integrates the best practices called for by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013), Sarbanes–Oxley Act (SOX), governance and management of enterprise IT (COBIT), Enterprise Risk Management (COSO 2017) and our ethics and compliance rules, with the aim of establishing an integrated management system for all control components, thereby allowing us to strengthen all of our control system.
Ecopetrol has also defined guidelines and implemented an Internal Control System (which includes subsidiaries), the main purpose of which is to provide reasonable assurance regarding the achievement of all of the Company’s objectives relating to operations, strategy, reporting and compliance, through the appropriate risks management and ensuring the effectiveness of its controls and the scope of which includes its subsidiaries. Under those guidelines, each subsidiary must implement and report the performance of its Internal Control System to Ecopetrol S.A. to ensure compliance with the above measures, and the subsidiaries have methodological support from Ecopetrol S.A. when requested. Ecopetrol S.A. also performs preventive monitoring in selected subsidiaries to assure all the components and principles of their Internal Control Systems are present and operating. The system performance is systematically monitored by the Board of Directors.
The risk management component of our Internal Control System is in charge of identifying negative events or situations that may affect our defined objectives, assessing and prioritizing them to implement the most appropriate response. This component has been designed and implemented across the organization, with a two-level focus: Enterprise Risk and Processes Risks.
Ecopetrol S.A.’s Internal Control System is aligned to the Company’s strategy and business processes and gives responsibility to all employees to manage risk, to maintain the effectiveness of controls, to report incidents in order to preventively correct possible deficiencies and to provide reasonable assurance of achieving corporate objectives and goals. The scope of this system includes the Company’s subsidiaries who must implement and report on the performance of its internal control system to the Company to ensure compliance with the above measures.
5.3.2 |
To manage and mitigate the risks related to the transition to a low carbon economy and climate change, Ecopetrol, as part of its energy transition and decarbonization activities, expects to invest approximately US$ 600 million in the next three years in projects that aim to meet our mitigation targets. Additionally, Ecopetrol has set a shadow price on carbon at US$ 20/TCO2 in 2021, 30 USD/TCO2 from 2025, and 40 USD/TCO2 from 2030 onwards, which will be used to assess and evaluate current and future projects and investments. See the section entitled Business Overview—Environmental, Social and Governance (ESG) Strategies and Initiatives—Environmental sustainability for detailed information on our strategy and carbon shadow price.
To properly adapt the Ecopetrol Group’s business strategy to the transition to a low carbon economy for ensuring long-term value creation, Ecopetrol has been conducting energy transition scenario analysis since 2018. These analyses are being updated and refined reflecting two elements: i) the acceleration of the transition in recent years given a reduction of costs of electrification and renewables earlier than expected, accompanied by increasing oil price volatility and decreased investment appetite in the hydrocarbon sector; and ii) decrease in the demand for oil & gas brought by the COVID-19 pandemic. We have assumed a peak oil scenario (globally in the late 2020s and in Colombia between the 2030s and 2040s), to reflect more ambitious actions and goals in the decarbonization path and to seize the opportunities of the transition. Our climate risk strategy is being aligned with the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD) and includes the addition of a new climate-related risk to our 2020 enterprise risks, in respect of inadequate management of climate change and water. This risk complements the risk of not responding to the new low carbon economy.
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See the section entitled Strategy and Market Overview—Our Corporate Strategy for more details about our energy transition roadmap.
5.3.3 | Managing Information Security and Cybersecurity |
Ecopetrol S.A. has a dedicated management team focused on information security issues such as risk analysis, treatment of information, safe information management practices and classification of critical business information, control systems compliance and effectiveness of available information security technologies, all of which are articulated with the ERM system at the enterprise level. The Cybersecurity unit is part of the Digital Vice-presidency, reporting to senior management and to the Company’s Board of Directors.
Ecopetrol S.A. has included cybersecurity risk as one of the key enterprise risks. Based on that, a working group formed in 2014, coordinated by the cybersecurity area with the participation of industrial control systems and information technology specialists, has been understanding the new challenges of cybersecurity risk, developing activities to identify and protect critical digital assets.
During 2019, Ecopetrol S.A., as a NOC (National Oil Company), provided updates to the Cyber Defense Command Unit (an entity under the control of the Colombian Ministry of Defense) regarding the inventory of its critical cybernetic infrastructure that was included in the classified catalogue of national critical cybernetic infrastructure. In 2020, no such updates were provided.
Ecopetrol’s cybersecurity team established a plan to continue the incorporation of cybersecurity practices to enhance the awareness about these risks at an operational level and adjust current information security practices considering the cyber-threat context. Likewise, as a result of this process, we are currently continuing the incorporation of elements relative to management of the cyber security threat, including proper configuration of storage devices, overall control of information security, policies and procedures that address trading information security, control mechanisms for remote work, specialized monitoring and control mechanisms,cyber threat services, vulnerability management, cyber incident response management and cybersecurity insurance coverage, among others.
Ecopetrol S.A. has a Security Operations Center (SOC) service, in order to enhance the ability to foresee and identify trends in attacks in Ecopetrol S.A.’s information technology infrastructure and to monitor Ecopetrol’s reputation on the internet.
During 2020, Ecopetrol strengthened the SOC by incorporating updated capabilities, expanding the scope of services to Operational Technology (OT) digital assets, conducting redteam exercises and improving monitoring coverage. While there were cyber-attacks during 2019,2020, every event was controlled and there were no material effects on processes, equipment, products, services, relationships with customers or suppliers, competitive conditions or critical information. Ecopetrol S.A. does not have any current proceedings that relate to cybersecurity issues.cyber breaches.
Furthermore, during 2019,2020, the internal audit department conducted an auditaudits on cybersecurity processes following up on our prior enhancement plans. As a result of this audit, the aforementioned, an action plan was updated to be implementedadopted in 2020. The primary goal of the plan iswas to reinforce our cybersecurity strategyculture and refine certain technical components of our cybersecurity program. Ecopetrol S.A. also recently updated its cybersecurity policies and cyber incidents response procedure which was tested in several wargames exercises covering all business segments and their subsidiaries.
During the first quarter of 2020, in response to the requirements derived from the COVID-19 pandemic, Ecopetrol S.A. updated its cybersecurity risk profile and its cybersecurity strategy, defining the management’s scope, which now covers information technologiesensuring connectivity for teleworking, remote work and articulation with the companiesmigration into the cloud for critical applications and all of the Ecopetrol Group. The Cybersecurity unit is part of the Digital Vice-presidency, reportingGroup companies. Likewise, Ecopetrol S.A. strengthened its capabilities to senior management.monitor and response against malicious activities.
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Ecopetrol useduses the ONG-C2M2 (Oil & Gas - Cybersecurity Capability Maturity Model) as a framework to manage its cybersecurity maturity and to establish its Cybersecurity Program.Program and its Cybersecurity Management System, implementing practices and capabilities those covers the following domains: Risk Management, Asset Change and Configuration Management, Identity and Access Management, Threat and Vulnerability Management, Situational Awareness, Information Sharing and Communications, Event and Incident Response - Continuity of Operations, Supply Chain and External Dependencies Management, Workforce Management and Cybersecurity Program Management.
Finally, in order to update the cybersecurity strategy for 2021 to 2023, Ecopetrol also recently updatedS.A. formulated an approach to strengthen its cybersecurity policiesprogram, in which the Cybersecurity Capability Maturity Model (C2M2) framework will be complemented with zero trust practices and a set of advanced protection controls for critical information (military grade), with focus on the reduction of cyber incidents response procedure which was testedrisk level in three wargames exercises.business units and the increase of the cultural awareness in cybersecurity terms.
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 2019,2020, Ecopetrol S.A. executed strategic and tactical hedging operations due to its exposure to pricing indices different from the commercialization benchmark and different pricing periods between the buying and the selling of physical barrels. We do not use derivative financial instruments for speculative or profit-generating purposes. A total of 30 million barrels (mmbls) were the subject of strategic hedges oriented at protecting the Ecopetrol’s income and cash flow, limiting losses, covering production costs and avoiding potential closures of production fields; for this purpose. A total of 21.7 million barrels (mmbls) were the subject of tactical hedges oriented at mitigating risks associated with storage marketing strategies, anticipated purchases of raw materials, supply to refineries, international sales delivered at the destination port and exports of heavy fuel oil.
Currency risk arises in our operations given the fact that most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars. Therefore, when the Colombian Peso depreciates against the U.S. dollar, our revenues converted into Colombian Pesos increase. Conversely, when the Colombian Peso appreciates against the U.S. dollar, our revenues decrease. On the other hand, imported goods, oil services and the debt, which is mainly denominated in U.S. dollars, become less expensive when the Colombian Peso appreciates against the U.S. dollar and more expensive when the Colombian Peso depreciates against the U.S. dollar.
As of December 31, 20192020, our U.S. dollar-denominated total debt principal was US$9.912.3 billion, which we recognize in our consolidated financial statements at its amortized cost, which corresponds to the present value of cash flows, discounted at the effective interest rate. Out of this total, a principal US$9.411.8 billion relate to Ecopetrol S.A., whose functional currency is the Colombian Peso. Therefore, when the Colombian Peso depreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate loss. In contrast, when the Colombian Peso appreciates against the U.S. dollar, Ecopetrol S.A. is exposed to an exchange rate gain. Some of the Ecopetrol Group’s subsidiaries have the U.S. dollar as functional currency and are not exposed to a material exchange rate risk resulting from fluctuations in the Colombian Peso against the U.S. dollar. On the asset side, when the financial statements of the Ecopetrol Group are consolidated, the exchange rate differential of the subsidiaries’ assets and liabilities whose functional currency is the U.S. dollar is recognized directly in equity, as part of other comprehensive income.
Taking previous considerations into account, Ecopetrol seeks to identify and manage currency risk in a comprehensive manner, using an integrated analysis of natural hedges in order to benefit from the correlation between incomes or investments in a foreign operation and debt denominated in foreign currency. In addition, theThe Company adopted hedge accounting as part of its risk management strategy, using two types of natural hedges with its U.S. dollar denominated debt as a financial instrument: i) cash flow hedge for exports of crude oil and ii) hedge of a net investment in a foreign operation. In addition, the Company may involve the use of financial derivative instruments, and non-derivative financial instruments. As a part of its risk management strategy, using the natural hedge between exports and dollar-denominated debt, on October 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. OnIn 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, onin November 12,2019 Ecopetrol hedged a new portion of the dollar-denominated debt against its new investment in the U.S. Permian Basin in an amount of US$0.93 billion. billion and during 2020 Ecopetrol hedged US$1.22 billion with its foreign investments.
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As of December 31, 2019,2020, the outstanding value of the natural accounting hedges was US$7.3billion. 8.5 billion. With the adoption of hedge accounting, the effect of the volatility of the foreign exchange rate on the hedged portion of the debt is recognized directly in equity, as part of other comprehensive income. In addition, the Company entered into financial derivative instruments in order to mitigate the impact of exchange rate volatility on its financial statements by selling US dollars in order to fulfil Colombian peso denominated debt obligations.
The remaining portion of our dollar-denominated debt, as well as the financial assets and liabilities denominated in foreign currency continue to be exposed to the fluctuation of the exchange rate, which means that an appreciation of the Colombian peso against the U.S. dollar could generate a loss if companies whose functional currency is the Colombian peso have an active net position in U.S. dollars or a gain if they have a net liability position in U.S. dollars. Conversely, a depreciation of the Colombian peso against the U.S. dollar could generate a gain if companies whose functional currency is the Colombian peso have a net active position in U.S. dollars or a loss if they have a net liability position in U.S. dollars. Finally, the Company maintains enough cash in Colombian pesos and U.S. dollars to meet its expenses in each currency (see Note 4.1.5 to our financial statements for further explanation of our accounting policy and Note 29.130.1 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%8.3%, 4.2%1.8%, 4.9%2.5% and 0.9%1.0%, respectively, of the nominal debt balance as of December 31, 2019)2020). Thus, volatility in interest rates may affect the fair value of and cash flows related to our investments and floating rate debt. In 2019,2020, our analysis of credit risk events and global financial markets drove us to decide not to hedge interest rate risk. Nevertheless, our capital markets office continuously monitors the performance of interest rates and the effect of interest rates on our financial statements.
The trust funds linked to Ecopetrol S.A.’s pension obligations (PAP)(PAP for its acronym in Spanish) are also exposed to changes in interest rates, as they include fixed- and floating-rate instruments that are mark to market. This exposure is continuously monitored by our treasury office given the potential impact volatility may have on our financial results. The treasury office’s information is gathered from reports provided by the asset managers. These reports refer to regulatory limits as well as market, credit and liquidity risks. The investment guidelines with respect to the PAPs are issued by the Colombian regulation for pension funds, as stipulated in the Decree 1833 of 2016 and Decree 1913 of 2018, where it is indicated that they have to follow the same regime as the regular obligatory pension funds in their moderate (i.e., neither conservative nor aggressive) portfolio. For further information regarding the trust funds linked to the pension obligations of the company, see Note 21.222.2 Plan assets to our consolidated financial statements.
Regarding liquidity risk, Ecopetrol forecasts and monitors its cash position on a daily basis in order to review updated expectations for liquidity conditions and the capacity to attend short term obligations. This forecast mainly includes operational income and expenses, capital expenditures expectations, debt and dividend related cash-flows, and other financial cash movements. Additionally, on a monthly basis, management reviews cash evolution, availability and forecasts under different scenarios.
Finally, counterparty risk is the potential probability that a borrower or counterparty defaults on any obligation. In our case, we are exposed to this risk as we invest in different financial instruments and receive letters of credit in order to mitigate our exposure with our commercial counterparties. We manage this risk by monitoring and analyzing the counterparty’s creditworthiness, stock price behavior, spreads on credit default swaps, probability of default, among others.
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Hedging guidelines for Ecopetrol S.A. and its subsidiaries
Ecopetrol S.A.’s management established newa set of guidelines for hedging strategies for Ecopetrol S.A. and its subsidiaries. These guidelines allow us to use financial instruments in order to mitigate the impacts in Ecopetrol’s financial statements as a result of the fluctuation of risk factors, such as commodity prices, exchange rate, interest rate and others.
These guidelines determine general principles governing hedging operations, corporate governance, the process for implementing operations which includes the identification of risk exposition as an integrated group, the identification and design of the financial structures, and execution and monitoring, among others.
The guidelines also include a list of allowable financial assets, such as forwards, futures, options and swaps and describe the differences between strategic and tactical hedging, where the former focus on protecting our financial results from market volatility and the latter is mainly designed to hedge the market risk of specific trading in physical markets.
Investment Guidelines
Ecopetrol S.A.
Ecopetrol S.A.’s management established guidelines for our investment portfolios. These guidelines determine that investments in Ecopetrol S.A.’s U.S. dollar portfolio 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 shortboth short- and long termlong-term limits by issuer and issuance based on internal analyzesanalyses 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.
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, 2019,2020, Ecopetrol S.A. was a party to 4,9885,361 legal proceedings relating to civil, criminal, administrative, environmental, tax and labor claims, of which 3,4453,641 were filed against us in the Colombian courts and arbitration tribunals, of which 266234 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 2223 to our consolidated financial statements included in this annual report for a discussion of our legal proceedings.
Caño Limón – Coveñas Crude Oil Pipeline Spill
On December 11, 2011, the Caño Limón - Coveñas oil pipeline ruptured and caused the spill of approximately 3,267 barrels of crude oil into the Iscala creek, which connects with the Pamplonita River that provides water to the city of Cúcuta. The incident did not cause any fatalities or injuries.
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A class action lawsuit has been filed against Ecopetrol S.A. and against employees of the company, and the First Administrative Court has jurisdiction to conduct the case, which is in the probatory stage.
The Regional Environmental authority of Norte de Santander, or Corporación Autónoma Regional de la Frontera Nororiental (CORPONOR) has filed a lawsuit against Ecopetrol at the Administrative Court of Norte de Santander claiming for (i) the environmental loss caused by the incident and (ii) for compensation costs relating to the environment damage for approximately COP$33 billion. Ecopetrol’s legal counsel filed to dismiss the lawsuit on June 2, 2014, based on three grounds: (i) there is no proof of environmental loss, (ii) CORPONOR does not have the authority to file this lawsuit and (iii) CORPONOR’s petition for direct compensation is not the proper legal action according to the applicable procedural rules. Currently this lawsuit is in the evidentiary stage. In July 2020 the evidentiary stage closed and we are awaiting a ruling in the first instance.
Ecopetrol and national and local authorities convened to develop a project consisting of an alternative to the water supply intake of the aqueduct in Cúcuta, The Company’s Board of Directors in December 2011 approved the participation of Ecopetrol in the project as part of the strengthening of its contingency plans and its relationship with its stakeholders. On November 10, 2017, the relevant parties entered into an agreement with the purpose of building the alternative water supply at a cost of approximately COP$385 billion. According to the agreement Ecopetrol will be in charge of the construction of the above mentionedabove-mentioned infrastructure. As of the date of this annual report, Ecopetrol has awarded onetwo construction contract.contracts. For the initial segment of the project and a second construction contract for a subsequent segment is soon to be awarded. The corresponding auditing contract has also been awarded.
BT Energy Challenger
On October 22, 2014, we were served with a class action suit against us seeking monetary damages of approximately COP$7.4 trillion related to an incident that occurred on August 21, 2014, during the loading operations of the BT Energy Challenger vessel. The claimants alleged possible damage to the port area of Ecopetrol’s terminal in Coveñas, as well as of marine and submarine areas and beaches that form the geographical area of the Morrosquillo Gulf. This allegation is currently under investigation by the Harbor Master of Coveñas. Ecopetrol filed a motion requesting the judge to require the claimants to amend their claim to more precisely set forth the facts and evidence it believes establishes Ecopetrol’s liability.
On March 3, 2015, Ecopetrol filed its statement of defense arguing the exclusive fault of a third party. On October 20, 2015, the Court denied a class action of more than 100 informal traders in the region because there is no common identity with the initial class (hotel employees). However, during 2016 the Sucre Administrative TribunalCourt accepted another 1,208 informal traders and fishermen as claimants.
On March 10, 2017, a mandatory conciliatory hearing was held in order to seek an agreement, but it failed.
In January 2018, a judicial order was issued to commence the evidence gathering process, a decision which was objected by the parties.
In September 2018, all the ordered statements were made, the evidentiary stage was finalized and the parties filed their final closing briefs. As of the date of this annual report the case remained pending.
As of the date of this annual report, the claims have decreased to COP$7.3 trillion, as a result of the reconsideration of the amount initially requested and the inclusion of new claimants in the process.
PetroTiger
As highlighted in previous 20-F and 6-K filings, on January 6, 2014, the United States Department of Justice (DOJ) announced the unsealing of charges against two former co-chief executive officers (CEOs) and the former general counsel of PetroTiger Ltd. (PetroTiger), alleging, among other things, violations of the U.S. Foreign Corrupt Practices Act (FCPA) and conspiracy to commit violations of the FCPA and money laundering in connection with payments made to an Ecopetrol employee. By the time of the DOJ announcement, that employee no longer worked at the Company. The DOJ alleged the payments were made to secure Ecopetrol’s approval for PetroTiger’s entry into an oil services contract with Mansarovar Energy Colombia Ltd. Ecopetrol participated in the Mansarovar project as non-operating partner in a joint operating agreement. Also on January 6, 2014, the DOJ announced that the general counsel of PetroTiger had pled guilty on November 8, 2013, to one count of conspiracy to violate the FCPA and to commit wire fraud. One of the charged former co-CEOs pleaded guilty on February 18, 2014, to the same charge. On May 9, 2014, the DOJ charged the other former co-CEO with conspiracy to violate the anti-bribery provisions of the FCPA, conspiracy to commit wire fraud, conspiracy to launder money, and substantive FCPA anti-bribery and money laundering violations. On June 15, 2015, that co-CEO pleaded guilty to conspiracy to violate the FCPA.
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After the DOJ unsealed its charges on January 6, 2014, Ecopetrol filed a complaint the same month, jointly with the Transparency Secretariat of the Presidency of the Republic, to Colombia’s Attorney General’s office requesting the investigation of individuals who may have been involved in the wrongdoing related to the Mansarovar contract. Colombian authorities initiated a proceeding related to PetroTiger, and on March 11, 2015, arrested four current Ecopetrol employees and two former Ecopetrol employees related to their investigation of the Mansarovar project and five other contracts involving PetroTiger and Ecopetrol. To date, four investigations of the control entities continue in course. During 2017 and 2018 to date, Colombian authorities have resolved an appeal confirming the conviction of a former Ecopetrol employee and another person involved in the case but not linked with Ecopetrol. Likewise, two other appeals are in progress, one of them submitted by Ecopetrol and the Prosecutor’s Office in a case in which a former Ecopetrol employee was acquitted, and the other submitted by the defense attorney of a former Ecopetrol employee in a case in which the employee pleaded guilty.
Ecopetrol has responded to information requests from the DOJ and Colombian authorities in connection with their investigations of PetroTiger. Ecopetrol has been designated with the formal status of victim in the local Colombian proceedings. It has terminated the employment of the four charged individuals who were Ecopetrol employees at the time of the arrests. Ecopetrol has concluded an internal investigation and has not identified any new issues relating to PetroTiger.
Salgar-Cartago Multi-purpose Pipeline Spill
On December 23, 2011 our Salgar-Cartago pipeline ruptured. Internal and external experts believe this incident occurred as a result of creep movement of soil caused by severe weather conditions, causing the soil surrounding the pipeline to exert strong pressure on the pipeline and rupture it. As of the date of this annual report, there are sixfour lawsuits related to this incident with possible damages of approximately COP$7.476.95 billion.
Class action of the AWA Indigenous Community
On April 2, 2018, a class action lawsuit was filed against Ecopetrol and CENIT by the Inda Guacaray and Inda Sabaleta reservations of the AWA Indigenous community who claim damages to their communities by environmental contamination and damage to natural resources that the defendants supposedly caused by act or omission during various environmental incidents. In August 2018 Ecopetrol answered the complaint. The parties are currently waiting for the evidentiary stage to start.
On November 14, 2020, the Administrative Court of Cundinamarca declared that an inadequate claim was filed by the AWA community, considering that the claims related to the reestablishment of measures specific to restitution, rehabilitation, satisfaction and guarantees of non-repetition, could not be sought through a class action.
The foregoing implies that Ecopetrol, along with the National Agency for Legal Defense of the State (Agencia Nacional de Defensa Jurídica del Estado or ANDJE) and CENIT, need to recalculate the amount of the claims based on the decision of the Administrative Court of Cundinamarca.
Although the plaintiffs did not clearly determine the amount of their claims, Ecopetrol and the National Agency for Legal Defense (Agenciaof the State (Agencia Nacional de Defensa Jurídica del Estado or ANDJE) havehad initially calculatedestimated the amount to be upapproximately COP$358,201,371,800. However, based on the November 14, 2020 decision, Ecopetrol, ANDJE and CENIT, need to COP$358,201,371,800.recalculate the amount of the claims.
As of the date of this annual report, the court has not yet set a hearing date.
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Foncoeco
On March 18, 2019, Ecopetrol received judicial notice of a lawsuit filed by workers and former workers seeking if between 1997 and 2017 the company allocated part of its profits for the wellbeing of their workers. The plaintiffs considered that they had the right to receive those profits up to COP $ 3,157,461,510,000. This lawsuit is similar the one that was ruled on behalf of Ecopetrol in 2011.
The lawsuit is in the evidentiary stage and on February 10, 2021, a hearing will be held to collect evidence, hear the parties’ final closing briefs and the court will issue the final ruling.
Environmental Administrative Proceedings
As of December 2019,2020, Ecopetrol S.A. was party to 243211 environmental administrative proceedings, of which 218185 were initiated before 2019,2020 and 2526 during 2019.2020. It is not possible for us to determine whether the pending proceedings could have a material effect on Ecopetrol. During 2019, nine2020, 50 proceedings were concluded, in fourtwo of them we were subject to monetary fines through resolution 200.36-19.06490710-0667 of 2019, resolution 199, September 20, 2019, resolution DGL 0366 May 20, 2019 and resolution DGL 0534, August 2, 20192020, in the aggregate amount of COP $265.836.101 and resolution 0052 of 2020, in the aggregate amount of COP$2 billion.5.155.203.368, with the latter pending a final decision by the Environmental Authority.
Reficar Investigations
Reficar is a wholly owned subsidiary of Ecopetrol. According to Colombian regulations, Ecopetrol’s and Reficar’s employees are considered public servants, and as such can be held liable for negligent use or management of public resources. In this context, given that Ecopetrol is majority owned by the Colombian Government and Reficar is a wholly owned subsidiary of Ecopetrol, Ecopetrol and Reficar administer public resources.
As a result, Ecopetrol and Reficar employees are generally subject to the control and supervision of the following control entities, among others:
The Office of the Comptroller General (Contraloría General de la República) oversees the adequate use of public resources and has the authority to investigate public employees or private sector employees that use or manage public resources.
The Attorney General’s Office (Procuraduría General de la Nación) supervises compliance with applicable law by public employees and private sector employees that carry out public functions. The Attorney General’s Office investigates and disciplines individuals for compliance failures.
The Prosecutor’s Office (Fiscalía General de la Nación) investigates potential crimes and prosecutes alleged crimes before the court in judicial proceedings.
The following are the most significant investigations and proceedings carried out by the aforementioned state entities:
1. | The Office of the Comptroller General’s investigations and |
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 |
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These actions were initiated based on the Office of the Comptroller General’s theory that lower than expected profitability at Reficar could have been caused by (i) modifications to the schedule and, (ii) the increase of the budget for the Project.
On June 5, 2018, the Office of the Comptroller General split the initial proceeding in two. The first one is related to the increase of the Project’s budget and the second one is related to the modifications in the Project’s schedule.
Regarding the first proceeding, on June 5, 2018, the Office of the Comptroller General issued charges for financial responsibility (proceso de responsabilidad fiscal) against (i) 15 individuals, which include former members of Reficar’s Board of Directors, a currentformer 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, 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 |
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.
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.
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.
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.
2. | The Attorney General’s Office investigations: |
Reficar has been officially informed that the Attorney General’s Office currently has four ongoing investigations related to the Project.
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Regarding one of these four investigations, on September 12, 2017, the Attorney General’s Office issued a list of charges against certain former members of Reficar’s Board of Directors, as well as certain former officers of Reficar. The charges were related to the failure to fulfill some of their duties as administrators and/or for acting “ultra vires” in the exercise of their functions against: (i) Javier Genaro Gutiérrez (Ecopetrol CEO, 2007-2015); (ii) Felipe Laverde (Reficar General Counsel, 2009-March 2017); (iii) Pedro Rosales (Ecopetrol Downstream Executive Vice President, 2008-2015); (iv) Diana Constanza Calixto (Ecopetrol Head of the Corporate Finance Unit, 2009-2014), (v) Orlando José Cabrales (Reficar CEO, 2009-2012) and (vi) Reyes Reinoso Yanes (Reficar CEO, 2012-2016). The Attorney General’s Office closed the case against the rest of the members of Reficar’s Board of Directors and the rest of the former officers of Reficar.
On January 17, 2020 the Attorney General’s Office issued its judgment against Reyes Reinoso Yanes for acting “ultra vires” in the exercise of his functions promoting a special billing procedure without the due diligence required to protect Reficar’s resources. As for the other four individuals initially investigated, they were acquitted of the charges. Mr. Reinoso filed an appeal against the decision and is awaiting resolution.
In another investigation, on October 21, 2020, the Attorney General’s Office issued its judgment against a former employee of Reficar, Nicolas Isaksson Palacios, related to the failure to fulfill some of his duties for acting “ultra vires” in the exercise of his functions. The Attorney General’s Office closed the case against the rest of the former members of Reficar’s Board of Directors and the other Reficar employees.
The specific content and status of the remaining threetwo ongoing investigations remains confidential.
As of the date of this annual report, no member of Ecopetrol’s current management team, nor the current Boards of Directors of Ecopetrol andor Reficar are not part of the Attorney General’s Office proceedings.
3. | The Prosecutor’s Office investigations: |
The Prosecutor’s Office has been conducting the following legal proceedings:proceedings in which Ecopetrol has been recognized as a victim:
3.1 | Between July 25 and August 2, 2017, the Prosecutor’s Office indicted the following individuals with charges, the majority of which are related to offenses against the public administration and illegal interest in the execution of agreements: (i) Orlando José Cabrales Martínez (Reficar CEO, 2009-2012); (ii) Reyes Reinoso Yanes (Reficar CEO, 2012-2016); (iii) Felipe Laverde Concha (Reficar General Counsel, 2009-March 2017); (iv) Pedro Alfonso Rosales Navarro (Ecopetrol Downstream Executive Vice President, 2008-2015); (v) Masoud Deidehban (CBI Executive Project Director); (vi) Phillip Asherman (CBI CEO) and (vii) Carlos Lloreda (Reficar’s statutory auditor from 2013-2015.) The arraignment hearing began on May 30, 2018 and concluded on August 22, |
The Prosecutor’s Office has already made public the factual basis for such charges, which is based on the theory that: (i) executing a cost reimbursable engineering, procurement and construction contract (EPC) and not a lump sum agreement favored CBI interests, and (ii) executing special invoicing procedures (MOA –Memorandum of Agreement and PIP –Project Invoicing Procedure) with CBI allowed the payments of unreasonable amounts not duly verified by the Joint Venture Foster Wheeler USA Corporation and Process Consultant Inc (FPJVC). The defense attorneys have not yet had an opportunity to present their case against such facts in a court of law.
On May 9, 2017, Ecopetrol’s Audit and Risk Committee retained a U.S.-based outside law firm to commence a third-party investigation into the matters set forth in the Prosecutor’s Office announcement. The results were presented in December 2017 to Ecopetrol’s Audit and Risk Committee. This investigation concluded that to date there has been no evidence of possible unlawful acts that affect Ecopetrol’s internal control over the financial reporting of the Company, on the allegations made by the Prosecutor’s Office.
3.2 | On October 22 and 23, 2018, the Prosecutor’s Office indicted the following individuals with charges related to improper management and obtaining false public documents: Javier Genaro Gutiérrez Pemberthy (Ecopetrol CEO, 2007-2015), Reyes Reinoso Yánez (Reficar CEO, 2012-2016), Pedro Alfonso Rosales Navarro (Ecopetrol Downstream Executive Vice President, 2008-2015), and Diana Constanza Calixto Hernández (Ecopetrol Head of the Corporate Finance Unit, 2009-2014). The arraignment hearing took place on August 5, 2019. |
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The Prosecutor’s Office made public the factual basis of the charges, which is based on the theory that the indicted directors hid necessary information from Ecopetrol’s Board of Directors before the approval of amendment No. 3 of the EPC contract. The defense attorneys have not yet had an opportunity to present their case against such facts in a court of law.
On January 27, 2020, during the indictment hearing, Ecopetrol and Reficar were recognized as victims.
3.3 | On March 18, 2019, the Prosecutor’s Office indicted the following individuals with charges related to entering into agreements without compliance with legal requirements: Orlando José Cabrales Martínez (Reficar CEO, 2009-2012) and Felipe Castilla (Reficar CEO, |
The Prosecutor’s Office has already made public the factual basis of the charges, which is based on the theory that hiring FPJVC as the PMC of the project through a sole source process violated the objective selection principle. The defense attorneys have not yet had an opportunity to present their case against such facts in a court of law.
Ecopetrol and Reficar have cooperated closely and extensively with the control entities in furthering their investigations and will continue to monitor the status and development of these investigations.
As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar and theirthe current employees are not part of the Prosecutor’s Officeabove proceedings. None of the legal proceedings described in this paragraph are related with bribery charges.
As of the date of this annual report, Ecopetrol and Reficar have no knowledge of any legal proceeding in the United States regarding the project.
4. | Arbitration Tribunal |
On March 8, 2016, Reficar filed a Request for Arbitration before the International Chamber of Commerce (the “ICC”), against Chicago Bridge & Iron Company N.V., CB&I (UK) Limited, and CBI Colombiana S.A. (jointly “CB&I”) concerning a dispute related to the Engineering, Procurement, and Construction Agreements entered into by and between Reficar and CB&I for the expansion of the Cartagena Refinery in Cartagena, Colombia. Reficar is the Claimant in the ICC arbitration and seeks no less than US$2 billion in damages plus lost profits.
On May 25, 2016, CB&I filed its Answer to the Request for Arbitration and Counterclaim for approximately US$106 million and COP$324,052 million. On June 27, 2016, Reficar filed its reply to CB&I’s counterclaim denying and disputing the declarations and relief requested by CB&I. On April 28, 2017, CB&I submitted its Statement of Counterclaim increasing its claims to approximately US$116 million and COP$387,558 million. On March 16, 2018, CB&I submitted its Exhaustive Statement of Counterclaim further increasing its claims to approximately US$129 million and COP$432,303 million (including in each case interest), and also filed its Exhaustive Statement of Defense to Reficar’s claims. On this same date, Reficar filed its Exhaustive Statement of Claim seeking, among others, US$139 million for provisionally paid invoices under the Memorandum of Agreement(“MOA”) and Project Invoicing Procedure (“PIP”) Agreements and the EPC Contract.
On June 28, 2019, CB&I submitted its Reply to the Non-Exhaustive Statement of Defence to Counterclaim increasing its claims to approximately US$137 million and COP$503,241 million (including in each case interest, respectively). On this same date, Reficar filed its Reply to CB&I’s Non-Exhaustive Statement of Defense and its Exhaustive Statement of Defense to CB&I’s counterclaim, updating its claim for provisionally paid invoices under the MOA and PIP Agreements and the EPC Contract to approximately US$137 million.
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In January 2020, McDermott International Inc., CB&I’s parent company, filed for bankruptcy and announced that it would initiate a reorganization plan pursuant to Chapter 11 of the United States Bankruptcy Law. In response to this situation, Reficar has implemented actions to protect its interests and is advised by a group of experts with whom it will continue to analyze other available measures under these new circumstances.
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 titleChapter 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. Upon the bankruptcy filing, an automatic stay of the commencement or continuation of any action or proceeding, or the enforcement of any judgment or award, against Comet II B.V. became effective, staying the arbitration against Comet II B.V. On January 23, 2020, Comet II B.V. obtained an order from the Bankruptcy Court permitting it to, in its discretion, modify the automatic stay to permit it to proceed with litigation or other contested matters. On March 14, 2020, the Bankruptcy Court entered an order confirming a plan of reorganization, and the order provides for the stay against the arbitration to end upon the earlier of the effective date of the plan and August 30, 2020.
As a consequence of the bankruptcy filing, the arbitration was stayed until July 1, 2020, as described below.
In respect of the arbitration involving Reficar, the confirmation order provides that the proper forum for adjudication of the merits of the arbitration is the International Chamber of Commerce tribunal, the arbitration claims will not be subject to estimation in the Bankruptcy Court, and the stay will not be violated if the parties discuss logistical items with the International Chamber of Commerce tribunal or each other. The order reserves all rights and arguments of the parties related to the arbitration schedule, hearing location, and arbitration logistics and also recognizes that, without waiving any arguments, including but not limited to the Debtors’ objections to alternative hearing locations and long gap(s) between hearing dates, liftingdates. On June 30, 2020, McDermott International Inc. notified the relevant parties of the occurrence of the effective date of the plan of reorganization, and thus the stay lifted on August 30, 2020 provides sufficient time to commence hearingsthe arbitration was lifted on or after December 7,July 1, 2020.
On May 6, 2020, the Superintendence of Corporations ordered the liquidation of CBI Colombiana S.A., a respondent in the arbitration against CB&I. On October 22, 2020, Reficar submitted a proof of claim in the liquidation proceeding to seek recognition as a creditor of CBI Colombiana S.A. for the amounts of its claims in the arbitration. On January 15, 2021, the liquidator of CBI Colombiana S.A. accepted Reficar’s petition.
On September 22, 2020, the Tribunal scheduled the commencement of the hearing in May 2021. Until the Tribunal renders its final decision, the outcome of this arbitration is unknown.
Bioenergy Special Audit
The Office of the Comptroller General, in exercise of its fiscal monitoring duties and authority as set forth in Article 267 of the Political Constitution, has undertaken audits of the performance of the Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S. investments.
On February 6, 2017 the Office of the Comptroller General initiated a Special Intervention (Special Audit) in order to evaluate the use of public funds in the project carried out by Bioenergy Zona Franca S.A.S. and Bioenergy S.A.S.A.S. On July 10, 2017 the Office of the Comptroller General issued its final report with 15 findings related to: (i) acquisition, lease payments and the use of agricultural lands, (ii) loss of profits due to the project’s delay; and (iii) execution of contracts related with the building, commissioning and start-up of the industrial plant and the agricultural component of the project. On December 28, 2018, Bioenergy completed all of the activities set forth in the remediation plan to address the 15 findings.
Moreover,As a result of some of the findings, the Office of the Comptroller General opened several actions of fiscal liability (proceso de responsabilidad fiscal) against former members of Bioenergy’s administration and third-party companies.
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In 2018, the Office of the Comptroller General initiated a financial audit of Bioenergy’s financial statements for the year ended December 31, 2018. On May 21, 2019, the Comptroller General issueddelivered its financial audit final report, with sixissuing: (i) an unqualified opinion on Bioenergy’s financial statements, (ii) an efficient and effective internal control process opinion, and (iii) a reasonable opinion, since the budget was prepared and executed, in all relevant matters, according to Bioenergy’s budgeting internal regulation. Finally, the Office of the Comptroller General determined three findings related to: (i) plots of land pending to legalize, (ii) ethanol imports and (iii) the leasing agreement of the Casa Roja plot of Land. On December 31, 2019,2020, Bioenergy completed fourall of the activities set forth in the remediation plan. Completion ofplan to address the two remaining items are pending but expected to be completed within the allotted time period.three findings.
Finally, inIn 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 issuednotified Bioenergy on February 4, 2020 its compliance audit final report withdetermining seven findings related to: (i) agricultural lands productivity, (ii) incomes and expenses from rental payments of subleased agricultural lands, (iii) Balanced scorecard results for 2017-2018, (iv) update of laboratory procedures, (v) transport contract number 0029-17 settlement, (vi) document handling and (vii) Campo Victoria plot of Land. Bioenergy filed the remediation plan on February 25, 2020.
Until June 24, 2020, when the Superintendence of Companies of Colombia gave the order to start the Bioenergy’s liquidation process, Bioenergy S.A.S. completed activities as scheduled in the remediation plan according to the June 30, 2020 deadline. Any pending activities related to the aforementioned remediation plan, are in charge of the liquidator appointed by the Superintendence of Companies of Colombia in Bioenergy’s liquidation process.
6. | Shareholder Information |
6.1 | Shareholders’ General Assembly |
Our Shareholders’ General Assembly was held on March27, 2020 26, 2021 and the following matters were approved:
Amendment of our bylaws. For further information please see the sectionCorporate |
6.2 | Dividend Policy |
In 2018, the Board of Directors approved a dividend policy consisting of the ordinary distribution of between 40% and 60% of the adjusted net income of the Company of each fiscal year. For this purpose, the Board of Directors shall assess overall delivery against the Company’s financial targets, as well as the macroeconomic environment, projected cash requirements for delivering on our Business Plan and strategy, while maintaining appropriate financial flexibility in keeping the Company’s debt metrics in line with an investment grade rating. The policy does not preclude the distribution of extraordinary dividends above the 40% to 60% range, under exceptional circumstances and with due consideration of the above criteria. The maximum amount to be distributed is the profits available to shareholders (net income after release and appropriation for legal, fiscal and occasional reserves).
Pursuant to Colombian law, dividend distribution to our shareholders must be approved by a 78% majority of the shares represented in the corresponding General Shareholders Assembly. In the absence of this special majority, at least 50% of the net profits must be distributed.
On March 26, 2021, our shareholders at the ordinary General Shareholders’ Assembly approved an ordinary dividend of 41.41% of our net income for the fiscal year ended December 31, 2020 amounting to COP$698,984 million, or COP$17 per share, based on the number of outstanding shares as of December 31, 2020. The payment date will be April 22, 2021 for 100% of our shareholders.
On March 27, 2020, our shareholders at the ordinary General Shareholders’ Assembly approved an ordinary dividend of56% 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'sCompany’s occasional reserve that had been constituted in the General Shareholders’ Meeting held on March 29, 2019 and ii) its subsequent distribution as an extraordinary dividend of 89 Colombian pesos (COP$89) per share.
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On March 29, 2019, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 60% of our net income or COP$169 per share (within the dividend policy of 40% and 60% of net income), for the fiscal year ended December 31, 2018 and an extraordinary dividend of 20% of our net income or COP$56 per share, given our strong operational and robust cash position in 2018,for a total dividend per share of COP$225. On March 23, 2018, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 55% of our net income for the fiscal year ended December 31, 2017. On March 31, 2017, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 40% of our net income before the impairment of non-current assets (net of taxes) for the fiscal year ended December 31, 2016. See sectionFinancial Review—Review—Liquidity and Capital Resources—Dividends.
Ecopetrol S.A. is required to have legal reserves equal to 50% of its subscribed capital. If the legal reserves are less than 50% of subscribed capital, we will contribute 10% of net income to our legal reserves every year until our legal reserves meet the required level.
6.3 | Market and Market Prices |
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 calledsociedades comisionistasSociedades Comisionistas de bolsaBolsa 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 275.0626 as of December 31, 2019)2020) it must be made through the BVC if the shares are registered with the BVC. Otherwise, shareholders can freely negotiate a transfer of shares.
Nevertheless, pursuant to Decree 2555 of 2010 Article 6.15.1.1.2 the following transfers are not required to be performed through the BVC:
Transfer of shares made by the Nation or the Financial Institutions Warranty Fund (Fondo de Garantías de Instituciones Financieras) or FOGAFIN; |
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For the purposes described above, multiple transfer transactions made within one hundred twenty (120) calendar days, between the same parties on shares of the same issuer and under similar conditions, are considered a single transfer.
6.4 | Description of Ecopetrol Registered Debt Securities |
Ecopetrol has issued the following classes of registered notes under an indenture (the Indenture), dated as of July 23, 2009, and amended as of June 26, 2015, between the Company and the TankBank of New York Mellon, as trustee:
5.875% Notes due 2023
4.125% Notes due 2025
5.375% Notes due 2026
6.875% Notes due 2030
7.375% Notes due 2043
5.875% Notes due 2045
Please refer to Exhibits 4.13, 4.14, 4.15, 4.16, 4.17, 4.18, 4.19, and 4.194.20 to this annual report for the information relating to these debt securities required by Item 12.A of Form 20-F.
6.5 | Description of Ecopetrol ADRs |
Fees and Charges That a Holder of Our ADSs May Have to Pay, Either Directly or Indirectly
JPMorgan Chase Bank, N.A., our Depositary, may charge each person to whom ADSs are issued, including, without limitation, issuances against deposits of shares, issuances in respect of share distributions, rights and other distributions, issuances pursuant to a stock dividend or stock split declared by us or issuances pursuant to a merger, exchange of securities or any other transaction or event affecting the ADSs or Deposited Securities, and each person surrendering ADSs for withdrawal of Deposited Securities in any manner permitted by the Deposit Agreement or whose ADSs are cancelled or reduced for any other reason, US$5.00 for each 100 ADS (or any portion thereof) issued, delivered, reduced, cancelled or surrendered, as the case may be. The Depositary may sell (by public or private sale) sufficient securities and property received in respect of a share distribution, rights and/or other distribution prior to such deposit to pay such charge.
The Depositary collects its fees for issuance and cancellation of ADSs directly from investors depositing common shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The Depositary may collect its annual fee for Depositary services by deduction from cash distributions, or by directly billing investors, or by charging the book-entry system accounts of participants acting for them. The Depositary may generally refuse to provide services to any holder until the fees and expenses owing by such holder for those services or otherwise are paid.
The following additional charges may be incurred by holders of ADRs, by any party depositing or withdrawing common shares or by any party surrendering ADSs and/or to whom ADSs are issued (including, without limitation, issuance pursuant to a stock dividend or stock split declared by us or an exchange of stock regarding the ADRs or the Deposited Securities or a distribution of ADSs), whichever is applicable:
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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$2,458,847. In 2020, reimbursements were made in the amount of approximately US$ 2,020,472.
Other
Please refer to Exhibit 2.1 to this annual report for the remaining information relating to our American Depository Shares required by Item 12.D of Form 20-F.
6.6 | Taxation |
6.6.1 | Colombian Tax Considerations |
The following is a general description of the Colombian tax considerations for investments in common shares in Colombia or for the purchase of ADSs, in a foreign securities market. This description is based on applicable law in effect as of the date of this annual report is issued, which may be subject to changes.
Prospective purchasers of common shares or ADSs should consult their own tax advisors for a detailed analysis of the tax consequences in Colombia, resulting from the acquisition, ownership and disposition of common shares or ADSs.
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General Rules
Colombian entities and individuals who are deemed to be residents within the Colombian national territory for Colombian tax purposes are subject to Colombian income tax on their worldwide income. Foreign entities and individuals who are not deemed to be residents in Colombia, are subject to income tax in Colombia only with respect to their Colombian-source income, which is generally defined as income obtained from (i)(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.sale among others. Double taxation treaties signed by Colombia, if applicable, may provide for special regulations regarding income taxation. Until 2018, foreign residents deriving income through a permanent establishment were subject to Colombian income tax on the Colombian source income attributable to their permanent establishment only. As of 2019, foreign tax residents deriving income through a permanent establishment will be subject to Colombian income tax on their global source income attributable to their permanent establishment in Colombia.
Dividends paid by Colombian companies, as well as profits distributed by branches/permanent establishments of foreign entities, are deemed as a dividend and as Colombian income. However, the applicable tax depends on an imputation system set forth in Articles 48 and 49 of the Colombian Tax Code (hereinafter “CTC”). For more information related to the Colombian dividends tax regime, see Risk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Information.
As mentioned above, Law 1819 of 2016 created a new dividends tax that applies on all dividend distributions to Colombian individuals or to any type of non-resident shareholder, absent any specific treaty or exception, regardless that dividends are paid from taxed or non-taxed profits. According to the aforementioned law, dividend payments made to foreign shareholders out of profits accrued at the corporate level as of 2017 were subject to a 5% withholding. That rate was subsequently modified by Law 1943 of 2018, which increased it to 7.5% and extended dividend taxation to intercompany dividends between Colombian resident companies (with certain exceptions).
From fiscal year 2019 onwards, a withholding tax on dividends paid applies as follows:
i. | For resident companies and non-resident shareholders (companies and individuals): (i) a 10% dividend (7.5% for fiscal year 2019) tax on dividends distributed from profits taxed at the corporate level (except that dividends paid to non-resident shareholders out of profits taxed at the corporate level prior to and including December 31, 2016, are not subject to this tax); and (ii) 32% (33% for fiscal year 2019) withholding tax rate on dividends distributed from profits not taxed at the corporate level (31% for 2021 and 30% as of 2022), plus an additional 10% (7.5% for fiscal year 2019) dividend tax after applying the initial 32% withholding tax rate (i.e., 38.8% in 2020 = $100 *32% = $32, plus $68 * 10% = $6.8). |
ii. | For Colombian individuals: dividend income in excess of 300 UVT are taxed at a 15% and 10% rate, for fiscal years 2019 and 2020 (2021 onwards), respectively. |
Relief or reduced tax rates may apply under an applicable treaty to avoid double taxation, but the application of any such rules must be analyzed on a case-by-case basis.
For Colombian tax purposes, an individual is considered to be a Colombian resident when he/she meets any of the following criteria:
i. | He/she remains in Colombia continuously or discontinuously for more than 183 calendar days within any given 365-consecutive-day term; |
ii. | He/she is related to the Colombian government’s foreign service or to individuals who are in the Colombian government’s foreign service and who, by virtue of the Vienna Conventions on diplomatic and consular relations, are exempted from taxes during the time of their service; or |
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iii. | He/she is a Colombian national and: |
Law 1739 of 2014 clarifies that Colombian nationals who meet any of the following requirements will not be deemed as tax residents:
i. | If more than 50% of his or her annual income has its source in the jurisdiction where he or she is domiciled and whose country of domicile is not Colombia. |
ii. | If more than 50% of his/her assets are located in the jurisdiction where he or she is domiciled and whose country of domicile is not Colombia. |
For purposes of Colombian taxation, an entity is deemed to be a “national” or a “Colombian entity” and, therefore, subject to taxation in Colombia on its worldwide income, if it meets any of the following criteria:
i. | It has its place of effective management, in Colombia during the corresponding year or taxable period; |
ii. | It has its main domicile in the Colombian territory; or |
iii. | It has been incorporated in Colombia, in accordance with Colombian laws. |
Pursuant to the Colombian Tax Code, a foreign company or non-resident individual has a permanent establishment in Colombia when said company or individual performs activities in Colombia through: (i) a fixed place of business (i.e., branches, factories or offices), or (ii) an individual who is not an independent agent empowered to execute agreements on behalf of the foreign company. As noted above, until 2018 permanent establishments were considered Colombian taxpayers in connection with their Colombian source income. As of fiscal year 2019, foreign residents deriving income through a Colombian permanent establishment are subject to Colombian income tax on the worldwide income attributable to the Colombian permanent establishment. A foreign company or entity will not be deemed to have a permanent establishment by the sole fact that it acts through a broker or any other independent agent. In addition, passive-income generating activities, such as dividends, royalties and interests, typically do not qualify as entrepreneurial and are not deemed to create permanent establishments.
Tax Treatment of a Non-Colombian Entity and a Non-Resident Individual of Colombia Who Purchases an ADS in a Foreign Securities Market
Dividends
As a general rule, dividends paid to foreign companies, foreign entities or non-resident individuals who are investing in ADSs which underlying assets are Colombian shares are treated as Colombian-source income and are thus subject to Colombian income tax.
To avoid double taxation, dividends paid by Colombian entities are not subject to income tax at the shareholder level when they are paid out of corporate profits that have been previously taxed at the corporate level. For fiscal years 2017 and 2018, a withholding tax on dividends was triggered for dividends paid to non-resident shareholders. Withholding tax rates on dividends were as follows: (i)(i) a 5% dividend tax for dividends distributed out of profits already taxed at the company’s level; (ii) 35% withholding tax rate for dividends distributed out of profits that were not taxed at the company’s level, plus a 5% dividend tax rate after having applied and deducted the initial 35% withholding. Note that dividends paid to non-resident shareholders out of profits taxed at the corporate level until December 31, 2016, are not subject to the aforementioned 5% dividend tax or any other income tax. As of 2019, the withholding tax rates applicable to dividends paid to resident companies and non-resident shareholders (companies and individuals) are: (i) a 7.5% dividend tax on dividends distributed from profits taxed at the corporate level (except that dividends paid to non-resident shareholders out of profits taxed at the corporate level prior to and including December 31, 2016, are not subject to this tax); and (ii) 33% withholding tax rate on dividends distributed from profits not taxed at the corporate level (32% for 2020, 31% for 2021 and 30% as of 2022), plus an additional 7.5% (10% from 2020 onward) dividend tax after applying the initial 33% (32%, 31% or 30%) withholding tax rate.
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Furthermore to the above, non-resident entities or non-resident individuals whose investment qualifies as portfolio investments (i.e., investing through a Foreign Funds Administration Account - FFAA) will be taxed upon distribution by means of a withholding tax mechanism. In this case, pursuant to Article 18-1 of the Colombian Tax Code, the applicable withholding tax rate on taxable dividends is 25%, assuming that the dividends cannot be attributed to a permanent establishment in Colombia belonging to the shareholder and were not subject to taxation at the corporate level. The abovementioned 5% dividend tax (7.5% in 2019 and 10% from 2020 onwards) applies on the balance of dividends to be distributed to the shareholder investing through an FFAA, or on the gross amount in such cases the dividend is paid out of profits that were subject to taxation at the corporate level. These foreign shareholders subject to this withholding tax are not required to file an income tax return in Colombia.
Taxation of Capital Gains from the Sale of ADSs
Capital gains obtained from the sale of ADSs by non-Colombian entities, Colombian individuals who are non-residents in Colombia and foreign non-resident individuals, are not subject to income tax in Colombia, as such sale does not generate Colombian-source income to the extent that the ADSs are not deemed to be sourced in Colombia.
If the holder of the ADSs who is a non-resident entity, a Colombian individual who is not a resident in Colombia or a foreign non-resident individual, decides to surrender the ADSs and withdraw the underlying common shares, it is arguable that such transaction does not generate a capital gain subject to income tax in Colombia. However, different interpretations may be adopted by the Colombian Tax Authorities on this matter.
Tax Treatment in Colombia of a Non-Colombian Entity and a Non-Resident Individual of Colombia Who Purchases Ecopetrol’s Shares in Colombia’s Securities Market
Dividends
As a general rule, dividends paid to foreign companies, foreign entities, or to non-resident individuals in Colombia, who are investing in Colombian shares directly or through a FFAA, are treated as national-source income; thus, they are subject to Colombian income tax.
The dividend tax regime as of 2020 was modified as follows:
i. | Dividends paid to non-resident shareholders: (i) a 10% dividend tax on dividends distributed from profits taxed at the corporate level (except that dividends paid to non-resident shareholders out of profits taxed at the corporate level prior to and including December 31, 2016, are not subject to this tax); or (ii) 32% withholding tax rate on dividends distributed from profits not taxed at the corporate level (31% for 2021 and 30% as of 2022), plus an additional 10% dividend tax after applying the initial 32% withholding tax rate (i.e., 38.8% in 2020). |
ii. | Dividends paid to Colombian companies: (i) a 7.5% dividend tax on dividends distributed from taxed profits, or (ii) a 32% withholding tax on dividends distributed from non-taxed profits (31% on 2021 and 30% as from 2022), plus an additional 7.5% dividend tax on the balance of the dividend amount after the initial 32% withholding. |
iii. | For Colombian resident individuals: dividend income in excess of 300 UVT is taxed at a rate of 10%. |
Non-resident entities or non-resident individuals whose investment qualifies as portfolio investment (i.e., investing through a FFAA), will be taxed upon distribution by means of the withholding tax mechanism. In this case withholding will apply at 25% on dividends that are distributed by the Colombian entity are not taxed at the corporate level. Pursuant to Article 18-1 of the Colombian Tax Code, assuming that the dividends cannot be attributed to a permanent establishment in Colombia belonging to the shareholder. These foreign shareholders subject to this withholding tax are not required to file an income tax return in Colombia, nevertheless those rules would not apply to foreign investments whereby the final beneficiary is a tax resident in Colombia who has control over such investments. This treatment was modified by Law 1943/2018 and Law 2010/2019. See section Financial Review—Review—Effect of Taxes, Exchange Rate.
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Variation, Inflation and the Price of Oil on our Results—Taxes—Taxes..
In addition to the above, the new dividend tax will apply at a 5% rate over dividends distributed from profits taxed at the corporate level. This treatment was modified by Law 1943 of 2018 and Law 2010 of 2019 (7.5% in 2019 and 10% from 2020 onwards). See sectionFinancial Review—Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results—Taxes—Taxes.”
Taxation of Capital Gains for the Sale of Shares
Pursuant to Article 36-1 of the Colombian Tax Code, capital gains derived from the sale of shares listed on the BVC and owned by the same beneficial owner, are deemed as non-taxable income in Colombia, provided that the shares sold during the same taxable year do not represent more than 10% of the outstanding shares of the listed company. Pursuant to Section 1.6.1.13.2.19 of Regulatory Decree 1625 of 2016, sellers of shares are not required to file an income tax return for the transfer of securities that are listed in the National Registry of Securities and Issuers (Registro Nacional de Valores y Emisores) as long as the foreign investment is treated as a portfolio investment according to Article 3 of Decree 2080 of 2000 (currently compiled in Article 2.17.2.2.1.2 of Decree 1068 of 2015) and the abovementioned 10% threshold is not surpassed.
If the abovementioned requirements are not met, the capital gain obtained in the sale of shares is subject to income tax or capital gains tax, under the following rules:
(i) | The gain or loss arising therefrom will be the difference between the sale price and the tax basis of the shares. As a general rule, the tax basis of shares is equal to the price paid for such shares (i.e., cost of acquisition). |
(ii) | The applicable tax rate and the withholding tax rate have to be determined on a case-by-case basis. Generally, if the shares have been owned for at least two years and qualify as fixed assets (i.e., they are not sold within their ordinary course of business), the profits from the sale will qualify as capital gains taxable at 10%; otherwise, profits will qualify as ordinary income, subject to a 33% income tax for fiscal years 2018 and 2019 (2020 – 32%; 2021 – 31%; 2022 onwards – 30%). |
Tax Treatment of Non-Residents Who Purchase Ecopetrol’s Shares in the BVC Market and Exchange Them for ADSs
Dividends
Payment of dividends by Colombian entities to foreign companies, foreign entities or to non-resident individuals who are investing in ADSs which underlying assets are Colombian shares or in Colombian shares directly are subject to the tax treatment described above.
Taxation on Capital Gains for the Sale of Shares
If the holder of the Colombian shares is a non-resident entity, a Colombian individual who is not a resident in Colombia or a foreign non-resident individual, and such holder decides to exchange such common shares for ADSs, it is arguable that such transaction should not generate a capital gain subject to income tax in Colombia. However, different interpretations may be adopted by the Colombian tax authorities on this matter. For instance, assuming that the exchange of securities is treated as a sale of Ecopetrol’s shares, the seller would be subject to the tax treatment described above in connection with the taxation of capital gains for the sale of shares. Absent any specific rules or regulations addressing this specific situation, a case-by-case analysis would be necessary.
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6.6.2 | U.S. Federal Income Tax Consequences |
This summary describes the principal U.S. federal income tax consequences of the ownership and disposition of common shares or ADSs, but it does not purport to be a comprehensive description of all of the U.S. tax consequences that may be relevant to a decision to hold or dispose of common shares or ADSs. This summary applies only to purchasers of common shares or ADSs who will hold the common shares or ADSs as capital assets for U.S. federal income tax purposes and does not apply to special classes of holders such as dealers in securities or currencies, holders whose functional currency is not the U.S. dollar, holders of 10% or more of our shares (taking into account shares held directly or through depositary arrangements) by vote or by value, tax-exempt organizations, financial institutions, holders liable for the alternative minimum tax, securities traders who elect to account for their investment in common shares or ADSs on a mark-to-market basis, partnerships or other pass-through entities or arrangements and investors therein, insurance companies, U.S. expatriates, persons that purchase or sell common shares or ADSs as part of a wash sale for tax purposes, and persons holding common shares or ADSs in a hedging transaction or as part of a straddle, conversion or other integrated transaction for U.S. federal income tax purposes. The statements regarding U.S. tax law set forth in this summary are based on the Internal Revenue Code of 1986, as amended, the “Code,” its legislative history, existing and proposed U.S. Treasury regulations, published rulings and court decisions, all as in force on the date of this annual report, and changes to such law subsequent to the date of this annual report may affect the tax consequences described herein (possibly with retroactive effect). This summary is also based in part on the representations of the Depositary and the assumption that each obligation in the Deposit Agreement and any related agreement will be performed in accordance with its terms.
Each holder is encouraged to consult such holder’s tax advisor concerning the overall tax consequences to it, including the consequences under laws other than U.S. federal income tax laws, of an investment in common shares or ADSs.
In this discussion, references to a “U.S. Holder” are to a beneficial owner of a common share or an ADS that is for U.S. federal income tax purposes (1) an individual citizen or resident of the United States, (2) a corporation, or any other entity taxable as a corporation, organized under the laws of the United States, any state thereof or the District of Columbia, (3) an estate whose income is subject to U.S. federal income tax regardless of its source, or (4) a trust if (i) a United States court can exercise primary supervision over the trust’s administration and one or more United States persons are authorized to control all substantial decisions of the trust or (ii) it has in effect a valid election under applicable U.S. Treasury regulations to be treated as a U.S. person.
For U.S. federal income tax purposes, holders of ADSs generally will be treated as owners of the common shares represented by such ADSs.
This discussion does not address any aspect of U.S. federal taxation other than U.S. federal income taxation (such as the estate and gift tax or the Medicare tax on net investment income). Holders of common shares or ADSs should consult their own tax advisor regarding the U.S. federal, state and local and other tax consequences of owning and disposing of common shares and ADSs in their particular circumstances.
Distributions on Common Shares or ADSs
A distribution to U.S. Holders made by us of cash or property with respect to common shares or ADSs generally will be treated as a dividend for U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Distributions in excess of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, will be treated first as a tax-free return of capital reducing such U.S. Holder’s adjusted tax basis in the common shares or ADSs. Any distribution in excess of such adjusted tax basis will be treated as capital gain and will be either long-term or short-term capital gain depending upon whether the U.S. Holder held the common shares or ADSs for more than one year. Distributions of additional common shares or ADSs to U.S. Holders that are part of a pro rata distribution to all of our shareholders generally will not be subject to U.S. federal income tax. We do not maintain calculations of our earnings and profits under U.S. federal income tax principles, and, therefore, except as described in the previous sentence, U.S. Holders should expect that any distributions generally will be reported as dividends for U.S. federal income tax purposes. As used below, the term “dividend” means a distribution that constitutes a dividend for U.S. federal income tax purposes.
The amount of any distribution will include the amount of any Colombian tax withheld on the amount distributed, and the amount of a distribution paid in Colombian Pesos will be measured by reference to the exchange rate for converting Colombian Pesos into U.S. dollars in effect on the date the distribution is received by the Depositary (or by a U.S. Holder in the case of a holder of common shares) regardless of whether the payment is in fact converted into U.S. dollars. If the Depositary (or U.S. Holder in the case of a holder of common shares) does not convert such Colombian Pesos into U.S. dollars on the date it receives them, generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend payment is included in income to the date the payment is converted into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income (as discussed below). The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.
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If you are a non-corporate U.S. Holder, dividends that constitute qualified dividend income will be taxable to you at the preferential rates applicable to long-term capital gains, provided that you meet certain holding requirements. Dividends paid on the ADSs will be treated as qualified dividend income if (1) the ADSs are readily tradable on an established securities market in the United States and (2) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a passive foreign investment company (PFIC). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States, as long as they are so listed. Based on our audited financial statements and relevant market and shareholder data, we believe that we were not treated as a PFIC for U.S. federal income tax purposes with respect to our 20192020 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 20202021 taxable year. However, this conclusion is a factual determination that is made annually and thus may be subject to change. Based on existing guidance, it is not clear whether dividends received with respect to the common shares will be treated as qualified dividends. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to which holders of ADSs or common shares and intermediaries through whom such securities are held will be permitted to rely on certifications from issuers to treat dividends as qualified for tax reporting purposes. Because such procedures have not yet been issued, it is not clear whether we will be able to comply with them. Holders of ADSs and common shares should consult their own tax advisers regarding the availability of the reduced dividend tax rate in the light of the considerations discussed above and their own particular circumstances.
A U.S. Holder will be entitled, subject to a number of complex limitations and conditions, to claim a U.S. foreign tax credit in respect of any Colombian income taxes withheld on dividends received on common shares or ADSs. U.S. Holders who do not elect to claim a credit for any foreign income taxes paid during the taxable year may instead claim a deduction in respect of such Colombian income taxes, provided the U.S. Holder elects to deduct (rather than credit) all foreign income taxes for that year. Dividends received with respect to the common shares or ADSs will be treated as foreign source income, subject to various classifications and other limitations. For the purposes of the U.S. foreign tax credit limitations, the dividends paid with respect to our common shares or ADSs generally will constitute “passive category income” for most U.S. Holders. The rules relating to computing foreign tax credits or deducting foreign income taxes are extremely complex, and U.S. Holders are urged to consult their own independent tax advisers regarding the availability of foreign tax credits with respect to any Colombian income taxes withheld.
Sale, Exchange or Other Taxable Dispositions of Common Shares or ADSs
A U.S. Holder generally will recognize capital gain or loss upon the sale, exchange or other taxable disposition of common shares or ADSs in an amount equal to the difference between the U.S. dollar value of the amount realized on the sale, exchange or other taxable disposition of the common shares or ADSs and the U.S. Holder’s adjusted tax basis, determined in U.S. dollars, in the common shares or ADSs. Any gain or loss will be long-term capital gain or loss if the common shares or ADSs have been held for more than one year. Certain non-corporate U.S. Holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. The deductibility of capital losses is subject to limitations under the Code.
If you are a U.S. Holder of common shares or ADSs, the initial tax basis of your common shares or ADSs will be the U.S. dollar value of the Colombian Peso-denominated purchase price determined on the date of purchase. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis U.S. Holder, or, if it elects, an accrual basis U.S. Holder, will determine the dollar value of the cost of such common shares or ADSs by translating the amount paid at the spot rate of exchange on the settlement date of the purchase. Such an election by an accrual basis U.S. Holder must be applied consistently from year to year and cannot be revoked without the consent of the Internal Revenue Service (IRS). If you convert U.S. dollars to Colombian Pesos and immediately use that currency to purchase common shares or ADSs, such conversion generally will not result in taxable gain or loss to you.
With respect to the sale or exchange of common shares or ADSs, the amount realized generally will be the U.S. dollar value of the payment received determined on (1) the date of receipt of payment in the case of a cash basis U.S. Holder and (2) the date of disposition in the case of an accrual basis U.S. Holder. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis taxpayer, or, if it elects, an accrual basis taxpayer, will determine the U.S. dollar value of the amount realized by translating the amount received at the spot rate of exchange on the settlement date of the sale.
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Deposits and withdrawals of common shares in exchange for ADSs, and of ADSs for common shares, generally will not result in the realization of gain or loss for U.S. federal income tax purposes.
Backup Withholding and Information Reporting
In general, dividends on common shares or ADSs, and payments of the proceeds of a sale, exchange or other taxable disposition of common shares or ADSs, paid within the United States, by a U.S. payer through certain U.S.-related financial intermediaries to a U.S. Holder are subject to information reporting and may be subject to backup withholding at a current rate of 24%, unless the holder (1) establishes that it is a corporation or other exempt recipient or (2) with respect to backup withholding, provides an accurate taxpayer identification number and certifies that it is a U.S. person and that no loss of exemption from backup withholding has occurred.
Backup withholding is not an additional tax. The amount of any backup withholding tax from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability, provided that the required information is timely furnished to the IRS. U.S. Holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed its U.S. federal income tax liability by timely filing a refund claim with the IRS.
U.S. Tax Considerations for Non-U.S. Holders
A holder or beneficial owner of common shares or ADSs that is not a U.S. Holder for U.S. federal income tax purposes (a “non-U.S. Holder”) generally will not be subject to U.S. federal income or withholding tax on dividends received on common shares or ADSs, unless the dividends are “effectively connected” with the non-U.S. Holder’s conduct of a trade or business within the United States. In such a case, a non-U.S. Holder generally will be taxed in the same manner as a U.S. Holder. In the case of “effectively connected” dividends received by a corporate non-U.S. Holder, the corporate non-U.S. Holder may, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate.
A non-U.S. Holder of common shares or ADSs will not be subject to U.S. federal income or withholding tax on gain realized on the sale of common shares or ADSs, unless (i) the gain is “effectively connected” with the non-U.S. Holder’s conduct of a trade or business in the United States or (ii) in the case of gain realized by an individual non-U.S. Holder, the non-U.S. Holder is present in the United States for 183 days or more in the taxable year of the sale and certain other conditions are met. In the case of “effectively connected” gains realized by a corporate non-U.S. Holder, the corporate non-U.S. Holder may, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate.
Although non-U.S. Holders generally are exempt from backup withholding and information reporting requirements, a non-U.S. Holder may be required to comply with certification and identification procedures in order to establish its exemption from information reporting and backup withholding.
6.7 | Exchange Controls and Limitations |
Payments in foreign currency with respect to certain foreign exchange transactions including international investments between Colombian residents and non-Colombian residents must be conducted through the foreign exchange market. Therefore, any foreign currency income or expense under the ADRs must be completed through the appropriate channels of the foreign exchange market. Transactions conducted through the foreign exchange market are made at market rates freely negotiated with authorized foreign exchange intermediaries (local banks, financial corporations, administrators and others). or using a bank accounts opened abroad and registered as compensation account without effective conversion of the currencies into Colombian Pesos. Since September 25, 1999, the Colombian foreign exchange regime is structured under the system of free flotation of the exchange rate, whereby market forces determine the level of exchange rate from time to time.
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Foreign portfolio investments must be made through authorized foreign exchange investment management companies. Only brokerage firms, trust companies and investment management companies, subject to the inspection and supervision of the Superintendence of Finance, are allowed to make investments in the local Colombian market on behalf of foreign investors. Such brokerage firms, trust companies and investment management companies also act as the foreign investors’ local representatives for tax and foreign exchange purposes.
Colombian law provides that the Colombian Central Bank may intervene in the foreign exchange market at its own discretion at any time (i.e., it may limit the remittance of dividends whenever the international reserves fall below an amount equal to three months of imports). Additionally, from time to time, the Colombian government introduces amendments to the International Investment Statute. Hence, we cannot assure you that the Colombian Central Bank will not intervene in the future imposing restrictions to the free convertibility system currently applicable in Colombia. See sectionRisk Review—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,April 5, 2021, the Representative Market Exchange Rate was COP$ 3,9963,679 per US$1.00. The Federal Reserve Bank of New York does not report a noon-buying rate for Colombian Pesos. The Superintendence of Finance calculates the Representative Market Exchange Rate based on the weighted averages of the buy and sell foreign exchange rates quoted daily by foreign exchange rate market intermediaries including financial institutions for the purchase and sale of U.S. dollars. The Superintendence of Finance also calculates the Representative Market Exchange Rate for each month for purposes of preparing financial statements and converting amounts in foreign currency to Colombian Pesos.
6.9 | Major Shareholders |
The following table sets forth the names of our major shareholders, and the number of shares and the percentage of outstanding shares owned by them at March 31, 2020:2021:
Table 5863 – Major Shareholders
At March 31, 2020 | As of March 31, 2021 | |||||||||||||||
Shareholders | Number of shares | % Ownership | Number of shares | % Ownership | ||||||||||||
Nation(1) – Ministry of Finance and Public Credit | 36,384,788,417 | 88.49 | 36,384,788,417 | 88.49 | ||||||||||||
Public float | 4,731,906,273 | 11.51 | 4,731,906,273 | 11.51 | ||||||||||||
Total | 41,116,694,690 | 100.00 | 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, 2020,16, 2021, the registration date of our annual general shareholders’ meeting, 2.15%1.39% of our common shares were held of record in the form of American Depository Shares, we had 38 registered holders, and 14,52213,048 beneficiaries of common shares, or ADSs representing common shares, in the United States.
Changes in the Capital of the Company
There are no conditions in our bylaws governing changes in our capital stock that are more stringent than those required under Colombian law, with the exception that the Nation must hold a minimum of 80% in any stock issuance undertaken under Law 1118 of 2006.
6.10 | Enforcement of Civil Liabilities |
We are a Colombian company. Most of our Directors and executive officers and some of the experts named in this annual report reside outside the United States. All or a substantial portion of our assets and the assets of these persons are located outside of the United States. As a result, it may not be possible for you to affect service of process within the United States upon us or these persons who are residents in Colombia or to enforce against us or these persons who are residents in Colombia judgments in U.S. courts obtained in such courts predicated upon the civil liability provisions of the U.S. federal securities laws. Colombian courts will enforce a U.S. judgment predicated on the U.S. securities laws through a procedural system known under Colombian Law as “exequatur.” The Colombian Supreme Court will enforce a foreign judgment, without reconsideration of the merits only if the judgment satisfies the requirements set forth in Articles 605 through 607 of Law 1564 of 2012 (Código General del Proceso) which entered into force on January 1, 2016, pursuant toAcuerdo No. PSAA15-10392, of October 1, 2015, issued by the Colombian Superior Council of the Judiciary (Consejo Superior de la Judicatura), as follows:
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The United States and Colombia do not have a bilateral treaty providing for automatic reciprocal recognition and enforcement of judgments in civil and commercial matters. The Colombian Supreme Court has in the past accepted that reciprocity exists when it has been proven that either a U.S. court has enforced a Colombian judgment or that a U.S. court would enforce a foreign judgment, including a judgment issued by a Colombian court. However, such enforceability decisions are considered by Colombian courts on a case-by-case basis.
Proceedings for enforcement of a money judgment by attachment or execution against any assets or property located in Colombia are within the exclusive jurisdiction of Colombian courts, and such proceedings are conducted in Spanish. All parties affected by a foreign judgment in exequatur proceedings must be summoned to the exequatur proceedings in accordance with the rules that apply to the Colombian courts. In the course of such proceedings, both the plaintiff and the defendant are afforded the opportunity to request that evidence be collected in connection with the requirements listed above. In addition, before the judgment is rendered, each party may file final allegations in support of such party’s position regarding the abovementioned requirements.
Assuming that a foreign judgment complies with the standards set forth in the preceding paragraphs and the absence of any condition referred to above that would render a foreign judgment not subject to recognition under Colombian law, such foreign judgment would be enforceable in Colombia in an enforcement proceeding under the laws of Colombia, provided that the Colombian Supreme Court has previously granted exequatur upon the foreign judgment.
7. | Corporate Governance |
Since 2004, Ecopetrol S.A. has voluntarily adopted transparency, governance and control practices to facilitate corporate governance in order to generate confidence among stakeholders and ensure the sustainability of its business.
The corporate governance practices at Ecopetrol S.A.:
Corporate Governance System
Corporate governance is the system of rules and practices that govern the decision-making process between the governing bodies of the Ecopetrol Group, as well as the relationships between the companies that comprise it. Corporate Governance in Ecopetrol is more than a key element for organizational management—it is a strategy enabler that our stakeholders value and monitor continuously, as it generates trust, sustainable results over time and results in long-term value relationships.
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Our model is structured based on the law, international standards, good practices and the strategy of the Ecopetrol Group, in order to ensure adequate decision-making of the governing bodies of the Ecopetrol Group in terms of agility, clarity and consistency, as well as the promotion of the realization of synergies between Ecopetrol and the Ecopetrol Group companies.
To leverage the business strategy, Ecopetrol has a Corporate Governance System that aims to provide a consistent, sustainable and objective framework for action to safeguard Ecopetrol'sEcopetrol’s governance as well as generate synchrony and articulation with the companies of the Ecopetrol Group. The main elements of this system are:
i. | Boards of Directors: Ecopetrol and Subsidiaries |
a. | Promote best management practices in the Boards of Ecopetrol and in the other Ecopetrol |
b. | Ensure alignment of the strategy under the Ecopetrol Group’s management by segments. |
ii. | Senior Management Committees |
a. | Establish the structure of the Senior Management Committees (operating, monitoring and improvement mechanisms). |
b. | Optimize Ecopetrol senior management time. |
iii. | Matrix of Decisions and Attributions |
a. | Define the key or more relevant decisions of the Ecopetrol Group. |
b. | Establish which governing bodies are responsible for making key decisions. |
c. | Define how these decisions are made. |
iv. | Relationship Model |
a. | Establish the way in which the areas within the Ecopetrol Group’s scope are related to the Ecopetrol Group’s companies. |
b. | Capture the Ecopetrol |
c. | 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 Government implemented the practice of eliminating the participation of Directors with a ministerial level in the company’s Board of Directors. Therefore, in 2019 the Government nominated one (1) non-independent Director without ministerial rank. The current Board of Directors is composed by eight (8) independent members and one (1) non-independent member. |
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. |
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Asset disposal: ensuring that any asset disposal of an amount equal or higher than 15% of the stock exchange capitalization of Ecopetrol is discussed and decided by the General Shareholders’ Assembly and that the Nation will only vote affirmatively if the vote of minority shareholders is equal to or exceeds 2% of the shares subscribed by shareholders other than the Nation. |
7.1 | Bylaws |
The Bylaws of Ecopetrol S.A. are contained in Public Deed No. 5314 of December 14, 2007, issued by the Second Notary of Bogotá; amended by Public Deed No. 560 of May 23, 2011, issued by the Notary Forty-Six of Bogotá, Deed No. 666 of May 7, 2013, issued by the Notary Sixty-Five of Bogotá, Deed No. 1049 of May 19, 2015, issued by the Notary Second of Bogotá, Deed No. 0685 of May 2, 2018, issued by the Notary Twenty of Bogotá and Deed No. 888 of May 28, 2019 issued by the Notary Twenty Third of Bogotá., Deed No. 6527 issued by the Notary Twenty Nine of Bogotá of June 08, 2020. In addition, the bylaws were amended in the ordinary meeting of the General Shareholders Assembly held on March 27, 2020.26, 2021. The text of the amended bylaws is yet to be recorded in public deed and registered before the mercantile registry, which in Colombia corresponds to the Chamber of Commerce. An English translation of the amended bylaws is included as Exhibit 1.1 to this annual report.
This summary does not purport to be complete and is qualified by reference to our bylaws, which are filed as an exhibit to this annual report. For a description of the provisions of our bylaws relating to our Board of Directors and its committees, see the sectionsCorporate Governance—Governance—Board of Directors—Board Practices andCorporate Governance—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.www.ecopetrol.com.co.
The Annual General Shareholders’ Meeting provides shareholders with the opportunity to make key management decisions reserved to shareholders. At the General Shareholders’ Meeting, our Board of Directors and the external auditor are appointed. Decisions are taken regarding the company’s annual financial statements, profit distribution, audit and management reports, including our corporate governance report and sustainability report, and any other matter provided under applicable law or our corporate bylaws.
Extraordinary Shareholders’ Meetings are summoned by our Board of Directors, by our president or chief executive officer, by our external auditor, or by shareholders holding at least 5% of the outstanding shares, or when unforeseen or urgent needs of the Company require it. An Extraordinary Shareholders’ Meeting should be called no later than 15 calendar days prior to the date of the meeting. The only exception is when the Law requires a greater time between the summons and the meeting. Such notice to the Extraordinary Shareholders’ Meeting is published on the Ecopetrol S.A. website and in a newspaper of national circulation. The notice informs the agenda for the meeting to the company’s shareholders.
For both the ordinary and extraordinary meetings, the quorum required is a plural number of shareholders representing 50% plus one of the subscribed shareholders entitled to vote. Decisions are approved with a majority of the members present. This quorum is exempted in the case of “second-call meetings,” which may take place when a meeting fails to obtain the required quorum and is called within a period between 10 business days and 30 business days from the first date, in which case decisions may be adopted by a majority of the shares present regardless of the number represented.
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Decisions made at ordinary and extraordinary shareholders’ meeting must be approved by a plural number of shareholders representing the majority of the shares present. Colombian law requires higher majorities in the following cases:
Shareholders may be represented by proxies, provided that the proxy: (i) is in writing (faxes and electronic documents are valid), (ii) specifies the name of the representative, (iii) specifies the date or time of the meeting for which the proxy is given and (iv) includes other information specified by the applicable law. Proxies granted abroad do not require legalization or an apostille.
During our ordinary annual shareholders’ meeting, our employees and Directors are only allowed to represent their own shares, unless they act as legal representatives.
In 2020, due to the exceptional situation arising from the COVID-19 pandemic, our annual shareholders’ meeting was held virtually for the first time. However, our shareholders were able to follow the meeting through our website and the live broadcast on the National Institutional Channel. We had 2,198 connections via streaming and 134,058 viewers through the National Institutional Channel.
To facilitate the correct representation of its shareholders, Ecopetrol, after review and authorization by the Financial Superintendence of Colombia and the Superintendence of Corporations, provided a digital proxy system through which our shareholders were represented by attorneys provided by the Company, and enabled them to submit their voting decisions. The instructions for the use of this system, the list of proxies, and the forms, were available on our website.
Our 2021 annual shareholders’ meeting was held in the same way. Additionally, to guarantee the active participation and rights of the shareholders, the Company provided channels for the submission of proposals that were included in the agenda and a virtual and in-person system to inspect our books and documents. For the 2021 meeting, there were 2,388 connections via streaming and 122,630 viewers through the National Institutional Channel.
Preference Rights and Restrictions Attaching to Our Shares
There are only ordinary shares, and these carry no special rights or restrictions (ordinary shares). Our current shareholders do not have any type of preemptive rights. However, in the case of a future equity offering, we will review whether or not existing shareholders would be entitled to preemptive or similar rights and, if that were the case, the corporate approvals and offering documents for any such equity offering would regulate the subject matter accordingly.
Under Commercial Colombian law, our shareholders have the following economic privileges and voting rights:
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to sell the shares, known as right of withdrawal (derecho de retiro), if a corporate restructuring affects the economic or voting rights of the shareholders in the terms and conditions established under Colombian law. |
Ecopetrol’s bylaws provide additional rights to our minority shareholders. These rights include:
Sale of Assets. For a ten-year period counted from the date of subscription of the declaration of the Nation dated February 16, 2018 or until the Nation loses its status as majority shareholder, the Nation guarantees that any sale of 15% or more of our assets requires the approval of the General Shareholders Assembly and that the Nation would only be allowed to vote its shares in favor of the proposal if 2% or more of our minority shareholders accept the proposal.
Candidate List. Pursuant to our bylaws and Law 1118 of 2006, the Nation will include in its candidate list for election of members of the Board of Directors one member selected by the departments that produce hydrocarbons. In addition, pursuant to the declaration of the Nation dated February 16, 2018, the Nation will include in its candidate list for election of members of the Board of Directors one member selected by the ten largest minority shareholders. The minority shareholders’ right to select a candidate loses its effect when minority shareholders, according to their share participation, name a member to our Board of Directors.
Extraordinary Shareholders Meetings. Our bylaws provide that the entity exercising permanent control over Ecopetrol must instruct the Company’s CEO or External Auditor to call an extraordinary meeting of the Company’s shareholders when so requested by a plurality of shareholders holding at least 5% of the total number of outstanding shares. Such requests shall be made in writing and must clearly indicate the purpose of the meeting.
Investor Relations Office. Ecopetrol has an investor relations office, a specialized unit responsible for our shareholders. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may request that the investor relations office conduct a special audit, provided that such audit does not hinder the day-to-day operations of the Company, of the following documents: the income statement; the proposal for the distribution of profits; the report of the Board of Directors as to the economic and financial status of our Company; the report from our general counsel as to the legal status of our Company; and the report from the independent auditors. Special audits cannot be made of documents that contain scientific, technological or statistical information of our Company, or agreementagreements that givesgive us competitive and economic advantages over our competitors, or in respect of any document related to intellectual property. Shareholders also have the right to propose good corporate governance recommendations to the office for the protection of investors.
Others. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may propose recommendations to our Board of Directors pertaining to the management of our Company. Any shareholder may file a written petition to our Board of Directors to investigate corporate governance violations that the shareholder believes to have been committed.
Amendments to Rights and Restrictions to Shares
We have only one class of stock and it has no special rights or restrictions (ordinary shares). Our shareholders do not have any type of preemptive rights. The rights given to our shareholders by law are described in our bylaws and may only be modified through an amendment to the law.
The additional rights given to our minority shareholders in our bylaws and corporate governance code may only be modified through an amendment of those internal documents.
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Limitations on the Rights to Hold Securities
There are no limitations in our bylaws or Colombian law on the rights of Colombian residents or foreign investors to own the shares of our Company, or on the right to hold or exercise voting rights with respect to those shares, except in cases of legal representation.
Restrictions on Change of Control, Mergers, Spin-offs or Transformations of the Company
Under Colombian law and our bylaws, the General Shareholders Assembly has full authority to approve any mergers, spin-offs or transformations, subject to compliance of applicable law. Corporate restructurings are subject to the requirement that the Nation must hold a minimum of 80% of our common stock in any issuance of stock pursuant to Law 1118 of 2006.
Ownership Threshold Requiring Public Disclosure
The Corporate Governance Code, Title III, Chapter 1, Section 5, states: Identification of Major Shareholders. The shareholding composition of the Company, indicating at least the twenty (20) people with the greatest number of shares, is disclosed on Ecopetrol’s website atwww.ecopetrol.com.co. Colombian securities regulations set forth the obligation to disclose any material event orhecho relevante. Any transfer of shares equal or greater than 5% of our capital stock, or any legal entity or individual acquiring a percentage of shares that would make him the beneficial owner of 5% or more of our capital stock, is a material event, and therefore, must be disclosed to the Superintendence of Finance. The regulation includes other criteria in order to identify when to report a material event other than the situations described in the previous sentence.
External Auditor
Pursuant to our bylaws, the external auditor will be appointed for periods of two (2) years and may be reelected consecutively for two (2) periods, and it may once again be hired after one (1) period away from the position.
7.2 | Code of Ethics and Conduct |
Our recently updated Code of Ethics and Conduct considers, as ethical principles of the organization, the integrity, responsibility, respect and commitment to life. Our Code of Ethics and Conduct also states that we must comply with the provisions contained in the applicable national and international laws in the countries where we have operations, including the U.S. and Colombia.
In our Code, we define the guidelines for the following aspects: conflict of interest; ethical conflict; prohibition of bribery, other forms of corruption and violations of the FCPA; integrity in accounting; prevention of money laundering and financing of terrorism; gifts, amenities and hospitalities; protection and use of resources; information managementmanagement; security and security;confidentiality; prohibition of insider trading and use of inside information, environmental policy, social responsibility, and respect for human rights;rights and rejection of discrimination, antitrust and anticompetitive practices and sexual harassment in the workplace; whistleblowing channel; and examples of ethical behaviors. As part of the Ethics guidelines of Ecopetrol, facilitation payments, political contributions and donations, diversion of money from social investment activities or sponsorships towards political activities or other than the purposes established by the Company and lobbying are prohibited.
Our Code of Ethics and Conduct applies to our Board of Directors, our Chief Executive Officer, our Chief Financial Officer, principal accounting officer, persons performing similar functions, to all of the other employees of the company and its affiliates and all individuals or legal entities that have any relationship with it, including beneficiaries, shareholders, contractors, suppliers, agents, partners, customers, allies (included joint ventures) and suppliers, in addition to the personnel and companies that the contractors engage for the execution of the agreed activities.
All 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.
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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-ethicsHome/en/Ourcompany/Ethics%2C%20Transparency%20and%20Compliance%20Program/Code%20of%20Ethics%20and%20Conduct%20of%20the%20Ecopetrol%20Business%20Group
7.3 | Board of Directors |
The current Board of Directors was elected at the General Shareholders Ordinary Meeting held on March 29, 2019,26, 2021, for a two-year term beginning on April 10, 2019.9, 2021.
The current Board of Directors is composed as follows:
Non-independent member:
Germán Eduardo Quintero Rojas. |
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Independent members:
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, 201926, 2021 for a two-year term beginning on April 10, 2019:9, 2021:
Germán Eduardo Quintero Rojas (44)has served as ManagingGeneral Director of Fogafin, President of the National Hydrocarbons Agency, Secretary General of of the Ministry of Mines and Energy, Interior and Finance and Public Credit, as well as Secretary General and Advisor to the Ministry of Trade,Commerce, Industry and Tourism, and General Secretary of the Ministry of Mines and Energy. He has been an advisorAdvisor to the Secretary General Secretary of the Office of the President of the Republic of Colombia,Colombia. He has also served as Director General and 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 of Public Credit, among other positions in the public and Public Credit. Mr. Quinteroprivate sectors. He is an attorney with a lawyerdegree from Sergio Arboleda University, having studied administrative law and received a degreestudies in Administrative Law 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 isHe was a member of the boarddrafting commission of directors atthe current Code of Administrative Procedures and Administrative Litigation. He has been a member of several top-level national Boards of Directors, highlighting his directorship in Ecopetrol (2019-January 2021) and the Financiera de Desarrollo Nacional (FDN) andas well as his service as Chairperson of the Boards of Directors of Bancoldex S.A., Gecelca S.A. E.S.P. Currently, as the General Secretary, Urrá S.A. and Cisa, among others. He is a current Director of the MinistryBoard of FinanceDirectors of FDN and Public Credit,is Legal Secretary to the Office of the President of the Republic. Mr. Quintero is a non-independent member of Ecopetrol’sthe Board of Directors.Directors of Ecopetrol S.A.
Orlando Ayala Lozano (63)Cecilia María Vélez White has 40 years ofextensive professional experience, having occupied the following positions in the global technology industry, 25 yearspublic sector: Minister of which he spent workingEducation of Colombia, Secretary of Education of Bogota, Minister Counselor for Microsoft in Seattle, Washington, where he served in a numberEconomic Affairs at the Embassy of managerial positions, including Vice President for the Intercontinental Region where he covered all countriesColombia in the southern hemisphere, Executive World Vice President for Sales, MarketingUnited Kingdom, Deputy Director and Support,Head of the Territorial Development Unit at the National Planning Department, Head of Planning of the Urban Development Fund at Banco Central Hipotecario, and World President for Emerging Markets. Before joining Microsoft, he worked for NCR Corp., where he held the positionDeputy Director of Sales Director for NCR Mexico and Senior Product Manager in Dayton, Ohio. His studied information systems administrationPlanning at Banco de la República (National Central Bank). She has served as Dean of Universidad Jorge Tadeo Lozano University in Bogotá in 1981,and was Visiting Professor at the Graduate School of Education at the same University. She studied Economics at Universidad de Antioquia from 1972-1976 and received her degree from Universidad Jorge Tadeo Lozano in 1977. She also holds a Doctorate Honoris Causa granted byMaster’s degree in Economics from the same universityUniversity of Louvain in 1998, where heBelgium and was a Fellow at the Special Urban and Regional Studies program (SPURS) at Massachusetts Institute of Technology (MIT) in Boston. She is currently a member of several Boards of Directors and Advisory Boards, including: Suramericana de Seguros, Fedesarrollo, Eafit, Fundación Luker, United Way, and Empresarios por la Educación. She assists on the Management Board. Mr. Ayala was honored byAdvisory Board of the Antioquia newspaper El Colombiano with its 18th annual “Exemplary Colombian Citizen Living Abroad” award in 2013. Mr. AyalaHarvard Ministerial Leadership Program and provides advisory and consulting services. Mrs. Vélez is currently an independent directorDirector 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.Ecopetrol S.A.
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Luis Guillermo Echeverri Vélez (62) has over 2030 years of experience in the development, marketing, promotionstimulation and conductingperformance of international business, exports and imports and exports,in the formulationpreparation and implementation of public and corporate policies, the development and implementation of conventional projects andas well as those relating to information technology, ventures, strategic planning, the financing of public and private projects and raising cooperation funds.the obtainment of funds and resources. His professional practice includes experience as an international business advisor. He served as Executive Director of the Inter-American Development Bank, the Inter-American Investment Corporation and the Multilateral Investment Fund on behalf of the governmentsGovernments of Colombia, Peru, and Ecuador. He was Director and Founder of various companies and large projects between 2000 and 2010. He served as Commercial Attaché in Colombia’s diplomatic missionColombia´s Diplomatic Mission to the US and as Director of Proexport’s Miamithe Regional Office.Office of Proexport (now ProColombia) in Miami. Mr. Echeverri is an attorney who graduatedwith a degree from the Bolivarian Pontifical University ofUniversidad Pontificia Bolivariana de Medellín and earnedalso holds a Master’s degreeMaster in Agricultural Economics from Cornell University in New York. In his position as international business advisor, he has successfully directed business initiatives as well as change, innovation, methodological and technological implementation processes in various companies and organizations. He successfully managed the presidential campaign of Iván Duque Márquez, present President of the Republic of Colombia. Currently, Mr. Echeverri is 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 the Asociación Primero Colombia, Association, a non-governmental associationnonprofit think tank dedicated to the promotion ofpromoting democratic values and young leadership, Chairmanyouth leadership; former Chairperson and member of the Board of Directors of the Chamber of Commerce of Bogota,Bogotá and a member of the BoardsBoard of Directors of TelefonicaTelefónica, Pragma and Pragma. Currently, Mr. Echeverri is ChairmanColmédica. He serves as an independent Director and independent memberChairperson of Ecopetrol’sthe Board of Directors.Directors of Ecopetrol S.A.
Juan Emilio Posada Echeverri (61) has been the CEO of several large companiesa Board Member and is currentlyAdvisory Council Member for many public and private, both a professional board memberprofit and an entrepreneur. He has sat on the boards of companiesnonprofit organizations in the fieldsareas of infrastructure, air transportation, hospitality, national defense, banking, insurance, air travel, hotels, infrastructure, telecoms, banks,securities brokerage, telecommunications, technology, start-ups, trading companies, trade associations, international and domesticmedia, education, children’s rights, chambers of commerce and localbusiness associations, as well as in a Latin American youth orchestra and international non-governmental associations.a national competitiveness program, in which he led the private portion of the initiative. He has held senior management positions at Billiton M & T (then a subsidiary of Royal Dutch Shell Group) in the Netherlands as well as Banco Cafetero in New York and Miami, where he also served as International Vice President and was also theresponsible for its subsidiaries and investments in seven countries. Founder, Chairman, Executive ChairmanChairperson 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-ChiefDirector of Synergy Aerospace. Mr. Posada is also a member of the board of Avianca Holdings and was formerly theAerospace; CEO of Avianca Airlines, Alianza Summa (Avianca-Aces-Sam) and Aces airlines. Mr. Posada currently serves asAirlines; CEO of Puerto Brisa, a deep water mega-port in Colombia; Executive ChairmanChairperson of Táximo Ltd., ChairmanLtd, Chairperson of Direktio and Fundacion Plan, directorFundación Plan; Director of Allianz Life and Allianz General in Colombia,Colombia; Board member of Avianca Holding and Sociedad Hotelera Tequendama (seven hotels in Colombia), Plan International (Brazil) and member of the Nominating and Governance Committee of Plan International’s Global Assembly, as well as, a member of the nominationsAdvisory Councils of Grupo Empresarial del Sector Defensa (GESED), Disán (international fertilizer and governance committeechemical products trading company), Flores de la Campiña (producer and exporter of fresh flowers), YPO Gold Colombia (global CEO network), NT3 (real estate project developers), Polymath Ventures, AMROP-Top Management and the Orchestra of the Global Assembly of Plan International. Mr. PosadaAmericas (Washington D. C.). He has been actively involved in fourth industrial revolution ventures and a middle-class housing construction firm. He holds a degree in Business Administration from EAFIT University in Medellin, Colombia, an MBA in International Business and Finance from Pace University in New York graduating with honors in international academic excellence, and a degree in International FinancialFinance Law from the London School of Economics. HisDue to his experience in audit and risksrisk matters, he has been acquired through his time oncalled upon to participate in the finance and audit committees of the boardsseveral different Boards of directors at different companies and atDirectors, including that of the Banco Nacional del Comercio, Corredores Asociados (a securitiesstock brokerage housefirm in Colombia), and is held in high regard by the financial sector in general. He has received numerous awards such as the Cruz de Boyacá, Grado Gran Cruz, EY’s 2016 Emerging Entrepreneur Award, multiple medals from the Colombian Armed Forces and 10 Best Junior Chamber of Commerce Executives, among other activities. Heothers. The companies under his leadership have also received awards and recognitions in service and quality, such as the Portafolio Award for Service, and recognitions from Fenalco Antioquia, Cotelco and the Government of Antioquia. Currently, he has a consulting agreement with the International Cooperation Agency, United Nations Development Program (UNDP), is also a member of the advisory councilsBoard of Grupo Empresarial del Sector Defensa (GESED), Disán (international fertilizerDirectors of Financiera de Desarrollo Nacional (FDN) and chemicals trading company), Floresof Sociedad de la Campiña (producerAcueducto de Alcantarillado y Aseo de Barranquilla S.A. E.S.P. 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 Orchestraan independent Director of the Americas. Currently, Mr. Posada serves as an independent member of Ecopetrol’s Board of Directors.Directors of Ecopetrol S.A.
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Sergio Restrepo Isaza (58)served in the Bancolombia Group as Vice President forof Capital Markets and Executive Vice President forof Corporate Development.Development at Grupo Bancolombia. He initiatedbegan his professional career at Corporación Financiera Corfinsura, where he held the positions of Company President,served as CEO, Vice President forof Investment Banking and Investment and International Vice President for Investments and International.President. He also served inhas been a member of several boardsBoards of Directors including Cementos Argos, Compañía Nacional de Chocolates, Conavi, Asobancaria, Bolsa de Valores de Colombia, Conglomerado Financiero Internacional Banagrícola S.A., Suramericana Asset Managementmanagement SUAM and several others in the community sector. Mr. Restrepo graduated withHe holds a degree in Business Administration from EAFIT University of Medellín, with a master’s degree in Business AdministrationMedellin, Colombia, and an MBA from Stanford University in California. He has extensive experience in the areas of audit and risk matters, having served as member of several audit and risk committees during in different companies 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 veryplayed an active role in the analysis of financial statementsinformation and was in charge of the investor’s relations of many of these companies. Healso responsible for investor relations. Currently he is currently a partner at Exponencial Banca de Inversión S.A.S., a member and ChairmanChairperson of the Board of directorsDirectors of theGrupo BIOS SAS Group, andS.A.S., a member of the boardsBoard of directorsDirectors of Odinsa S.A. Mineros S.A. and Consorcio Financiero. Currently, Mr. Restrepo serves asHe is an expert in financial, auditing and business risk matters and an independent memberDirector of Ecopetrol’sthe Board of Directors.Directors of Ecopetrol S.A.
Luis Santiago Perdomo Maldonado (62) has over 3040 years of senior management experience in the Colombian banking industry, having held senior management positions, including as Presidentthat of CEO of Banco Colpatria, part of the Scotiabank Group. He has been a member of various boardsseveral Boards of directors atDirectors in Colombian and Latin American companies in a range ofvarious economic sectors such asincluding finance, and mining and agriculture, including Bladex,in organizations such as Banco Latinoamericano de Comercio Exterior (Bladex), Scotiabank Peru, Asociación Bancaria de Colombia, Deceval, CESA, the Asociación Nacional de Empresarios de Colombia (ANDI), and the Asociación Nacional de Instituciones Financieras (ANIF), and he was. He is also a founding memberFounding Member of the Colombian Institute of Corporate Governance. Mr. PerdomoGovernance, and serves as CEO of Grupo Mercantil Colpatria S.A. He has been a member of the Boards of Directors of Colegio de Estudios Superiores (CESA), Fundación de Cirugía Reconstructiva (CIREC) and the Plenary Council of Gimnasio Moderno, as well as having collaborated with the Fundación Universitaria Minuto de Dios. He holds a degree in business administrationBusiness Administration from the CESA School of Advanced Studies in Administration.Colegio de Estudios Superiores de Administración (CESA). He is currently the Executive Directora member of the Colpatria Group andBoard of Directors of Mineros S.A. Currently, Mr. Perdomo, and serves as an independent memberDirector of Ecopetrol’sthe Board of Directors.Directors of Ecopetrol S.A.
Esteban PiedrahitaPiedrahíta Uribe (48) is Presidentcurrently Chairperson of the Commerce Chamber of Cali andCommerce of Cali. He previously served asheld the positions of General Director of Colombia’s National Planning Department, advisorat Departamento de Planeación Nacional, Advisor to the President and then Senior Specialist at the Inter-American Development Bank, and EconomicsEconomic Editor of the Semana’sSemana magazine and General Manager of Endriven Colombia/Gas Meridional S.A.S. E.S.P., among other positions.others. He has served onbeen a member of the boardsBoards of directorsDirectors of Banco Agrario, Metrocali, Amalfi S.A. Carvajal Educación and Alianza Valores. Mr. Piedrahita graduated withValores, and a member of the Advisory Council for Colombia at The Nature Conservancy. He holds a degree in economicsEconomics from Harvard University and earned a master’s degree in philosophyPhilosophy and historyHistory of scienceScience from the London School of Economics and Political Science. Mr. PiedrahitaHe is currently a member of the Boards of Directors of Fedesarollo, Cementos Argos, and Centro de Eventos Valle del Pacífico, a memberand of the Advisory Council of the Fundación Panthera, and is an independent Director of the Board of Fedesarrollo and the Advisory CouncilDirectors 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.Ecopetrol S.A.
Hernando Ramírez Plazas (66) has held positions at Universidad Surcolombiana asbeen the Dean of the FacultySchool of Engineering, Academic Vice-Principal, Principal,Vice-Rector, Rector and Professor.Professor at Universidad Sucolombiana. He has worked at the National Institute of Health and at the Ministry of Health. He had a roleHealth and served as an external evaluator forof Colciencias in technologytechnological development and innovation projects in the area of natural gas. Additionally, he has actedHe also participated as a trainer in gas issues for the production personnelstaff at Canacol Energy Inc., and he currently provides professional services to Comfamiliar Huila. Mr. Ramirez isEnergy. He holds a chemical engineer who graduateddegree in Chemical Engineering from the Universidad Nacional de Colombia, with a master’s degree in public healthPublic Health from the same university and a specializationSpecialist degree in gas engineeringGas Engineering from the Universidad de Zulia (Venezuela). Currently, he is an independent Director of the Board of Directors of Ecopetrol S.A. nominated by the Hydrocarbon Producing Departments since March 23, 2018.
Carlos Gustavo Cano Sanz (73) holds a degree in Economics from Universidad de los Andes in Bogotá, a master’s degree from Lancaster University in England, a postgraduate degree in Government, Business and International Economics from Harvard University in Boston, and a postgraduate degree from the Instituto de Alta Dirección Empresarial (INALDE) in Bogotá. He has been PresidentChairperson of the Colombian Agriculture AssociationFederación Nacional de Arroceros (FEDEARROZ), Chairperson of the Sociedad de Agricultores de Colombia (SAC), Founderfounder and DirectorChairperson of Corporación Colombia Internacional (CCI), PresidentChairperson of the Agrarian Bank,Caja Agraria and PresidentChairperson of the newspaper El Espectador.Espectador (newspaper). He was the Minister of Agriculture in the administration of President Álvaro Uribe, between August 7, 2002 and February 3, 2005, and the Co-DirectorDirector of Banco de la República between February 4, 2005 and January 31, 2017. He is an Economist from thecurrently a Professor at 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 CouncilBoard of Trustees of Universidad EAFIT in Medellín, of the EAFIT University of Medellín, the ConsultativeAdvisory Committee for Agriculture at Bancolombia, of Bancolombia. Mr. Cano has served asthe Advisory Council for Colombia of The Nature Conservancy (TNC) and of the Board of Directors of Minka S.A.S. Additionally, since March 31, 2017, he is an independent Director in Ecopetrol’sof the Board of Directors sinceof Ecopetrol S.A., nominated by the minority shareholders with the largest shareholding in Ecopetrol, Vice Chairperson of said Board of Directors and Chairperson of its Business Committee. His latest published book is “Mi paso por el Banco: Desaprendiendo y aprendiendo” published by Banco de la República and Universidad de Ibagué on March 31, 2017.2020.
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7.3.1 | Board Practices |
Our Board of Directors is composed of nine members and is responsible for, among other things, establishing our general business policies. The majority of the Board of Directors must be independent, and must be elected pursuant to the criteria set out in paragraph two, Article 44, Law 964, 2005, and in accordance with the procedure determined in Decree 3923, 2006, or any other provisions that regulate, amend, replace or add such regulations. In addition, pursuant to our bylaws and in accordance with the procedures described therein, our majority shareholder must include, in its list of candidates for the last two seats in the Board of Directors, the name of one individual jointly proposed by departments that produce hydrocarbons and one individual jointly proposed by the ten minority shareholders with the highest equity participation. According to Colombian law, the members of the Board of Directors must be elected by the General Shareholders Assembly in accordance with a proportional representation system similar to cumulative voting (through an electoral quota voting system). The number of votes required to fill each position is calculated by dividing the number of possible votes by the number of open board positions. The members of the Board of Directors may be elected without an electoral quota voting system when there is unanimity. Pursuant to our bylaws, (i) positions on our Board of Directors are filled either by person or by position, (ii) at least three members appointed for a specific period must be nominated for the following period, and (iii) beginning in 2019, Directors will be elected for a two-year term. Currently, we have one Director appointed by his position without Ministerial rank. Our current Directors were elected at the General Shareholders Assembly held on March 29, 2019.26, 2021. Members of the Board may be reelected indefinitely.
Our CEO is appointed by the Board of Directors and will have at least two alternates. The CEO is elected for a two-year term, may be reelected indefinitely and freely removed prior to the expiration of his term. In accordance with our bylaws, the Board of Directors must evaluate the annual performance of the CEO, and such results must be published in Ecopetrol’s web page or in an alternative media vehicle.
The compensation of our Directors is set exclusively by the shareholders at the General Shareholders Assembly. Directors are compensated for attending board meetings and committee meetings. A Board meeting requires a quorum of at least five members and decisions are approved with a majority of the Directors present. In the practice a consensus decision making operates in the Board.
Under Colombian law, a director or executive officer must abstain from participating in any transaction that may result in a conflict of interest or that involves competing with the company, unless authorized at a General Shareholders Assembly. The general shareholders may approve or reject the transaction giving rise to the conflict of interest with the vote of the majority of the shares present at the General Shareholders Assembly. If the director or executive officer who has the conflict is a shareholder, his or her vote must be excluded. We disclose the number of conflicts of interest of our employees, executive officers and Directors in our annual reports.
Neither our bylaws nor our corporate governance code provide a retirement age for our Directors. Under our bylaws, there is no requirement for a person to have a minimum number of shares to be elected as a Director. Colombian law provides that Directors willing to sell or purchase shares in our Company need prior authorization from the entire Board of Directors. Colombian law does not impose any limitation as to the number of shares that may be acquired by a Director.
7.3.2 | Board Committees |
Pursuant to our bylaws, our Board of Directors has the ability to constitute the committees it considers necessary. The Board of Directors currently has six committees (audit and risk committee, corporate governance and sustainability committee, compensationremuneration, appointments and nominationculture committee, business committee, HSE (health, security and environment) committee and technology and innovation committee). These committees establish guidelines, set specific actions and evaluate and submit proposals designed to improve performance in the areas under their supervision and control. The committees are comprised of members of the Board of Directors who are also appointed by the same members. The chairman of each of the committees must be an independent Director. In addition to applicable regulations, the committees also have their own specific regulations that establish their purposes, duties and responsibilities.
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Table 5964 – Composition of committees of the Board of Directors as of March 31, 202026, 2021*
Audit and Risk Committee |
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Sergio Restrepo Isaza
| Juan Emilio Posada Echeverri
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Hernando Ramírez Plazas | Santiago Perdomo Maldonado | |
Santiago Perdomo Maldonado | Germán Eduardo Quintero | |
Juan Emilio Posada Echeverri | Esteban Piedrahita Uribe | |
Orlando Ayala Lozano | ||
Corporate Governance and Sustainability |
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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
Technology and Environment)Innovation Committee
Our HSE Committee, which must
* | The composition may be |
** | Member of this Committee since April 2019 until January 12, 2021. He was elected again at the
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*** | Not elected to the Board of Directors |
Audit and Risk Committee
Our audit and risk committee, which must be comprised of at least three members, all of them independent Directors, is our highest internal control body and provides support to our Board of Directors on risk, accounting and financial matters. It is in charge of guaranteeing the design, implementation and supervision of our internal control over financial reporting. It also ratifies the annual hydrocarbons reserves report and provides support for our Board on analyzing topics related to financial matters, risks, control, environment and the assessment of the Company’s internal and external auditors.
All committee members are required to be knowledgeable in accounting matters and at least one of them is required to be an expert in financial and accounting matters.
Our Board of Directors has determined that Sergio Restrepo Isaza qualifies as an “audit committee financial expert” and he is independent under the definition of “independent” applicable to us under the rules of the NYSE.
The audit and risk committee approves on a case-by-case basis any engagement of our external independent auditors to provide services different than those related to auditing our financial statements. The audit and risk committee reviews that the additional services do not affect the external auditor’s independence.
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Remuneration, Appointments and Culture Committee
Our remuneration, appointments and culture committee, which must be comprised of at least three members, including at least one independent director, provides general guidelines for the selection and compensation of our executive officers and employees, and within the framework of the Ecopetrol Group’s strategy, oversee matters of organizational culture.
Corporate Governance and Sustainability Committee
Our corporate governance and sustainability committee, which must be comprised of at least three members, including at least one independent director, supports the Board of Directors in the analysis and decision making related to systems for the adoption of best practices in corporate governance for the oil and gas industry, which include matters related to the adoption of specific measures regarding the Ecopetrol Group’s governance. This Committee also supports the analysis and makes recommendations related to the Ecopetrol Group’s sustainability agenda and TESG topics.
New Business Committee
Our new business committee, which must be comprised of at least five members, including at least one independent Director, assists our Board in analyzing potential business ventures. Based on its delegation of power, the committee studies and analyzes capital expenditure policies, major investment projects, strategy, new business and other matters that would help us move forward in our efforts toward the consolidation of our strategy. The primary criteria used in the committee’s decision-making process are the optimization of our portfolio and the proper allocation of our resources.
HSE Committee (Health, Safety and Environment)
Our HSE Committee, which must be comprised of at least three members, the majority of which must be independent, supports the management of the Board of Directors with respect to monitoring and management of risks associated with the health and safety of our employees, contractors and partners, The HSE Committee is also responsible for monitoring Ecopetrol’s environmental management strategy, which includes matters related to the adoption of specific metrics regarding, for example, decarbonization.
Technology and Innovation Committee
Our technology and innovation committee, which must be comprised of at least three members, the majority of which must be independent, supports the management of the Board of Directors with respect to technological and digital transformation, as well as the cultural change that Ecopetrol is undergoing to transform itself into a leading company in the use of technology and digital innovation in the hydrocarbons sector. Starting in 2020, the Technology & Innovation Committee also reviewed TESG-related topics starting 2020.
7.4 | Compliance with NYSE Listing Rules |
The following is a summary of the significant differences between our corporate governance practices and those required for U.S. companies under the NYSE listing standards.
| Our Corporate Governance Practices
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