As filed with the Securities and Exchange Commission on April 5, 20198, 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, 20182020
Commission file number: 001-34175
ECOPETROL S.A.
(Exact name of Registrant as specified in its charter)
N/AN /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
Andrés Felipe SánchezLina 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.
¨☐ Yesx ☒ 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).
¨☐ Yesx ☒ No
Annual Report on Form 20-F 20182020
Table of Contents
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1. | Introduction |
1.1 |
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,” Group”, or the “Company” are used in this annual report to refer to Ecopetrol S.A. and its subsidiaries on a consolidated basis.
For purposes of the section Business Overview—Exploration and Production, “we” refers to Ecopetrol S.A., its subsidiaries and the partnerships in which Ecopetrol has an interest.
References to the Nation in this annual report relate to the Republic of Colombia (“Colombia”)(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 |
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.
1.3Selected Financial and Operating Data
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 | 2018 | 2017 | 2016 | 2015 | 2014 | 2020 | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||
Oil and gas production (mboed) | 720.4 | 715.1 | 717.9 | 760.7 | 755.4 | 697.0 | 725.1 | 720.4 | 715.1 | 717.9 | ||||||||||||||||||||||||||||||
Proved oil and gas reserves (Mmboe)(1) | 1,727 | 1,659 | 1,598 | 1,849 | 2,084 | |||||||||||||||||||||||||||||||||||
Exploratory Wells(2) | 17 | 20 | 6 | 5 | 28 | |||||||||||||||||||||||||||||||||||
Refinery Through-put (bpd)(3) | 375,666 | 347,483 | 332,751 | 234,861 | 240,484 | |||||||||||||||||||||||||||||||||||
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 | 129 | % | 126 | % | (7 | )% | 6 | % | 146 | % | 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”)
(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 | 2018 | 2017 | 2016 | 2015 | 2014 | |||||||||||||||
Revenue | 68,603,872 | 55,954,228 | 48,485,561 | 52,347,271 | 65,971,888 | |||||||||||||||
Operating income | 22,458,414 | 16,171,855 | 8,904,548 | 2,131,165 | 14,449,027 | |||||||||||||||
Net income (loss) attributable to Ecopetrol’s shareholders | 11,381,386 | 7,178,539 | 2,447,881 | (7,193,859 | ) | 5,046,517 |
Financial Information | 2018 | 2017 | 2016 | 2015 | 2014 | 2020 | 2019 | 2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||
Revenue | 50,223,393 | 71,488,512 | 68,603,872 | 55,954,228 | 48,485,561 | |||||||||||||||||||||||||||||||||||
Operating income | 7,181,765 | 21,027,158 | 22,458,414 | 16,171,855 | 8,904,548 | |||||||||||||||||||||||||||||||||||
Net income (loss) attributable to Ecopetrol’s shareholders | 1,586,677 | 13,744,011 | 11,381,386 | 7,178,539 | 2,447,881 | |||||||||||||||||||||||||||||||||||
Net operating income per share | 546 | 393 | 217 | 51.8 | 351.4 | 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 | 41,116,698,456 | 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) | 277 | 175 | 59.5 | (175.0 | ) | 122.7 | ||||||||||||||||||||||||||||||||||
Net income per share (basic and diluted) | 39 | 334 | 277 | 175 | 59.5 | |||||||||||||||||||||||||||||||||||
Total assets | 124,643,498 | 117,847,412 | 118,958,977 | 123,588,190 | 110,923,851 | 137,694,169 | 133,890,296 | 124,643,498 | 117,847,412 | 118,958,977 | ||||||||||||||||||||||||||||||
Total equity | 57,107,780 | 48,215,699 | 43,560,501 | 43,100,963 | 48,534,228 | 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 | 25,040,068 | 10,279,175 | 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 | 41,116,698,456 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | ||||||||||||||||||||||||||||||
Dividends declared per share | 225 | 89 | 23 | - | 133 | 17 | 180 | 314 | 89 | 23 | ||||||||||||||||||||||||||||||
Total liabilities | 67,535,718 | 69,631,713 | 75,398,476 | 80,487,227 | 62,389,623 | 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, 2014, 2015, 2016, 2017, 2018, 2019 and 20182020 were prepared in accordance with IFRS as issued by IASB. References in this annual report to IFRS mean IFRS as issued by the IASB. Our date of transition to IFRS was January 1, 2014. Our consolidated financial statements for the year ended December 31, 2015 were our first set of consolidated financial statements prepared in accordance with IFRS.
IFRS differs in certain significant aspects from the current reporting standards as in effect in Colombia (“Colombian IFRS”)(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—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.report.
As indicated in IFRS 10 “Consolidated Financial Statements”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”(Ecopetrol Group or “EG”)EG) and recognizing non-controlling interest. We present our operating information on a consolidated basis in accordance with IFRS.
The regulations of the SEC do not require foreign private issuers that prepare their financial statements on the basis of IFRS to reconcile such financial statements to U.S. GAAP. Accordingly, while we have in the past reconciled our consolidated financial statements prepared in accordance with Colombian Government Entity GAAP to U.S. GAAP, these reconciliations have not been presented in our filings to the SEC since 2015. We do continue to provide the disclosure required under the U.S. Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 932 “Extractive Activities—Oil and Gas” (which we refer to as ASC Topic 932), as this is required, regardless of the basis of accounting on which we prepare our financial statements.
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$2,956.553,691.27 per US$1.00, which corresponds to the average Tasa Representativa Promedio del Mercado (TRM), or Average Representative Market Exchange Rate, for 2018.2020. Such conversion should not be construed as a representation that the Colombian Peso amounts correspond to, or have been or could be converted into, U.S. dollars at that rate or any other rate. On April 1, 2019,5, 2021, the Representative Market Exchange Rate was COP$3,174.793,679 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 |
After experiencingContainment measures and economic disruptions related to the COVID-19 outbreak led to a gradual recoveryslowdown in production and mobility worldwide, producing a significant drop in global demand for oil in 2020. Demand contracted for most refined products (especially jet fuel and gasoline), which brought the Brent price to US$20/Bl by the end of April 2020. Although demand recovered throughout the second half of the year, it did not reach pre-COVID-19 pandemic levels. The U.S. Energy Information Administration (EIA) estimates that demand contracted by 9.0 mmbd as compared to 2019, the largest annual decline registered in EIA data since 1980.
Oil supply slowly reacted to low prices. Moreover, a price war between Saudi Arabia and Russia in March and April further delayed the supply response. However, the Organization of the Petroleum Exporting Countries (OPEC) and its allies (including Russia) agreed to a supply cut at the end of April 2020. This, in conjunction with the drop in United States production, was key in balancing the oil market. In total, supply was reduced by 6.4 mmbd in 2020, of which OPEC’s share was 4.1 mmbd, the US’s share was 0.9 mmbd and the remaining 1.4 mmbd was contributed by others.
The drop in demand resulted in an increase in inventory and a decline in price during the first half of 2018 and reaching a peak in October,2020. During much of the ICE Brent price suffered a downward trend insecond half of the latter part of 2018. The expectation of weaker economic growth for 2019 and a mismatch of supply and demand of crude played a fundamental role in this trend. The US government imposed sanctions on Iran in August of 2018, announcing the goal of reducing Iranian crude and condensate exports to almost zero. This created an expectation of a tightyear, reduced oil market during the latter part of 2018. However, several factors did not support a strong market outlook: refining margins weakened, inventories began to pile up and production from the US, Saudi Arabia14 OPEC member countries and Russia ramped up, all at the same time. Additionally, the US government provided waivers to Iranian crude importers. As a reaction to low crude prices, the OPEC+ countries agreed to cut production in order to rebalance the crude market. On the demand side, weaker economic growth in China and Europe did not favor crude oil consumption.
According to estimatesten of the Energy Information Administration (“EIA”world’s major non-OPEC oil-exporting nations, including Russia (OPEC+), in 2018 global and the United States, along with a rising oil consumption, caused inventory to fall, driving Brent prices to a monthly average of petroleum and other liquids fuels grew by 1.4 mmboepd while Non-OPEC petroleum and other liquid fuels supply grew by 2.5 mmboepd. On the other hand, OPEC reduced its production by 0.09 mmboepd, mainly due to unplanned crude oil disruptions whichUS$ 50/Bl in December amounted to 2.2 mmboepd in Libya and Nigeria, Iranian sanctions and decreasing production in Venezuela.2020.
Graph 1 – Supply/Demand Balance vs ICE Brent Price Evolution
Source:EIA: Short term Energy OutlookTerm Report (January 15, 2019)2021)
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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 influence,affect our performance, given that we conduct most of our business in Colombia.
The performance of Colombia’s gross domestic product (GDP) is one of the main drivers of fuel consumption in Colombia. According to the National Administrative Department of Statistics (DANE for its acronym in Spanish), during 2018in 2020 Colombia’s GDP grew 2.7%fell 6.8% in real terms, as compared to 2017.2019. The sectors withmain reason for this contraction was derived from the greatestCOVID-19 pandemic and from the measures taken by the Colombian government to stop the spread of the virus, which included, among other measures, mandatory lockdowns and work slowdowns in certain industries. These measures particularly affected the construction, transportation, and mining industries, whereas the agriculture, financial services and real estate industries were still able to post positive growth rates were retail, manufacturing and state defense spending which had the largest contribution to national GDP. On the other hand, agricultural and cattle activities had the worst performance. Localalong 2020. Within this context, local sales of liquid fuels increaseddecreased by 1.3%, boosted by increased demand for19.9% during 2020, primarily due to lower diesel and jet fuel.gasoline demand.
Natural gas demand in Colombia grewdecreased by 5.1%1.4% in 20182020 compared with 2019, due to higherlower demand from the industrial sector and refineries. In 2020, the natural gas fired power plantsmarket 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 non-thermal demand, mainly for household consumption.the Gulf of Mexico turning to serve the Asian market.
2.1 | Our Corporate Strategy |
2.1.1 | 2021 – 2023 Business Plan |
2.1.1The Ecopetrol Group’s Organic Business Plan
Ecopetrol’s 2019 – 2021 (the “Business Plan”) for the 2021-2023 period, is aimed at restoring the Ecopetrol Group’s growth trajectory post COVID-19, increasing competitiveness, laying the foundations of energy transition and going deeper into the Technology, Environment, Social and Governance (TESG) agenda through positive social and environmental impact in the territories where we operate. The Business Plan also seeks to maintain the effective response of the Ecopetrol Group to uncertain economic and environmental conditions, ensure the financial sustainability of the Ecopetrol Group and keep the value promise to stakeholders in the medium and long terms. The organic investment included in the Business Plan is expected to be financed mainly with internal cash generation. The Brent price assumptions under the Business Plan are as follows: US$ 45/Bl in 2021, US$ 50/Bl in 2022 and US$ 54/Bl in 2023.
The Business Plan features an organic investment between US$ 12 billion and US$ 15 billion for the three-year period, mainly focused in Colombia, and seeks to ensure capital allocation towards incorporation of more competitive reserves and resources within a new scenario of oil and gas prices, competitive positioning in the energy transition (such as gas, decarbonization, short-cycle hydrocarbons and the incorporation of renewable energies), reliability investments necessary for a responsible and sustainable operation, and strategic technologies and social investment for the future of the Ecopetrol Group.
76% of the investments are expected to be allocated towards growth opportunities aimed at continuing the exploration and profitable development of existing assets and accelerating adaptation to the energy transition, with investments focused on the continuation of the enhanced recovery programs and the growth of the gas value chain. The remaining 24% of investments are expected to be allocated to operational continuity, seeking to preserve the value of the assets and bring reliability and integrity to the Ecopetrol Group’s consolidated operations.
The most relevant operational goals of the Business Plan are the following: (i) to reach production levels between 700 and 710 thousand barrels of oil equivalent per day in 2021, with a growth trajectory that allows the Ecopetrol Group to reach production levels of approximately 750 thousand barrels of oil equivalent per day by 2023; (ii) to reach a joint throughput at the Barrancabermeja and Cartagena refineries of between 340 and 365 thousand barrels per day in 2021, with a growth path that allows reaching a joint throughput at such refineries of approximately 420 thousand barrels per day by 2023 in an expected scenario of recovery in demand and refining margins, as well as the interconnection of the crude plants at the Cartagena refinery; and (iii) to reach transported volumes of over one million barrels per day – in line with the evolution of the production and demand for liquid fuels in the country.
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Upstream
In terms of the upstream segment, the Business Plan allocates an investment range of between US$ 9 billion and US$ 11 billion. The Business Plan maintains the growth of this segment as a strategic priorities set forthobjective, with a focus on accelerating the progression of resources and reserves, through exploration, drilling and enhanced recovery.
Of the aforementioned resources, (i) 69% is expected to be be allocated in production activities, including the previous 2020 plan: we continue to prioritize profitable reservesRubiales, Castilla, Piedemonte and production growth, underpinned by strict capital discipline andthe Middle Magdalena Valley fields, with a continued focus on cost efficiencymaturity and cash flow generation. The plan seeksdevelopment of improved recovery activities, (ii) 22% is expected to maximize value generationbe allocated internationally, where the main focus areas will be Brazil and the Permian Basin in the United States and (iii) 9% of the resources are expected to be allocated in exploration activities, with an expected drilling of more than 40 wells located in the basins of greater materiality, with emphasis on the Llanos Orientales, Middle Magdalena Valley, Lower Magdalena Valley and Sinú-San Jacinto areas.
In terms of unconventional reservoirs, the Ecopetrol Group will continue the development process for our shareholders with continued focus on our incumbent positionthe initiatives associated to the Comprehensive Research Pilot Projects (PPII for its Spanish acronym) in the Middle Magdalena valley basin in Colombia, ensuring sustainability, competitiveness and profitability.well as increasing development activities in the Permian Basin in Texas.
AmongRegarding 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 matters,sources of gas in the Middle Magdalena Valley, Guajira and the Sinú-San Jacinto basin areas in Colombia. Additionally, the Business Plan calls for achievinginvestments for the following targets by the end of 2021: (i) organic production levels between 750-770 mboed, (ii) optimum throughput of the integrated refining system at a level between 370-400 mbpd, (iii) increasing transported volumes in line with the country’s production, (iv) investing approximately US$12-15 billion during the period and (v) maintaining a robust cash position and optimal leverage levels. The Business Plan is based on a reference price of US$65/bl.
Growth in reserves and production will be supported by four levers: (i) continuing the growth of our recovery factors and underlying hydrocarbons in place in existing fields, (ii) the diversification of our exploration portfolio in Colombia, (iii) the internationalization of our operations through both organic and inorganic means, and (iv) the appraisalevaluation and development of identified unconventional hydrocarbon potential in Colombia.
We estimate that by 2021 hydrocarbons originally in place (HCIIP) associated to our assets in Colombia will be approximately 60 billion barrels compared to 55 billion barrels as of the end of 2018. This increase is expected to be supported by seismic reprocessing, reassessments of reservoirs and drilling of advanced wells, among others. Additionally, the enhanced program is expected to continue to leverage our reserve and production growth.
Growthlargest offshore gas discoveries in the exploratory portfolio in Colombia will prioritize the incorporation of short cycle resources through the strengthening of the near field exploration activity in Colombia, mainly in the Llanos and Middle Magdalena basins. Furthermore, we seek to expand our presence in high potential under-explored basins, such as Putumayo and Piedemonte, and developing the potential of our operations in the offshoreColombian Caribbean.
The internationalization lever seeks to develop and maximizeBusiness Plan foresees the potentialachievement of the position we have built in Brazil, the U.S. Gulf Mexico and Mexico. In addition, we expect to continue assessing business opportunities associated with unconventional hydrocarbon basins in the United States and other mergers and acquisition opportunities in those geographies.
We have identified unconventional hydrocarbons potential in two basins in Colombia of approximately 10 tera cubic feet of gas and between 4 and 7 billion barrels of crude. In our investment plan described below, we are allocating US$500 million for the development of pilot programs between 2019 and 2021,reserves replacement ratio greater than 100% after 2022. However, such goal is subject to government approval. If successful, we would then move torevision based on the commercial developmentevolution of these pilots after 2021.
Our sustainability and growth are also leveraged in the concept of integration of our different segments.
We expect our midstream segment (or “transportation and logistics segment”) to continue being an important cash generator. In order to do so,both the Business Plan calls for, among others, the segment to focus on improving efficiencies and synergies in our transportation system and pursuing investment opportunities in product pipelines given the increase in demand for fuels in Colombia. The Business Plan is currently projecting that our transport systems will move between 1.10-1.25 million barrels of oil and products per day during the period.market conditions.
In our downstream segment (or “refining, petrochemicals, and biofuels segment”), the Business Plan focuses on the use and optimization of current infrastructure in order to achieve an expected refining throughput between 370-400 mbpd and an expected refining margin between US$12-15/bl, subject to market conditions. We expect to achieve this (i) through the incorporation of synergies between the Barrancabermeja and Cartagena refineries and (ii) by capturing market opportunities associated with the implementation of the International Convention for the Prevention of Pollution from Ships (Marpol), which favors the use of fuels with lower sulfur content in maritime transport. Additionally, as we did in 2018, we expect to continue delivering low sulfur diesel of 20 parts per million (ppm) and gasoline of 100 ppm versus the Colombian regulation of 50 ppm and 300 ppm, respectively.
Following the implementation of our transformation program in 2015, we have accumulated approximately US$3.3 billion in efficiencies to date. Our Business Plan is focused on continuing this trend. We expect to capture savings of approximately US$1.45-2.0 billion between 2019 and 2021, particularly: (i) capital expenditure efficiencies, (ii) revenue and margin optimization and (iii) operating expenditure efficiencies.Midstream
In terms of sustainability,the midstream segment, the Business Plan calls for integral water management,allocates an investment of between US$ 780 million and US$ 960 million, mainly aimed at strengthening the protection of biodiversityintegrity and a continued focus on climate change, among others, all within the frameworkreliability of the United Nations Sustainable Development Goals 2030. We expect to invest approximately COP$2 trillioninfrastructure, prioritizing resources for the growth of the multi-pipeline business, while advancing in socio-environmental projects between 2019increasing flexibility and 2021. Weefficiency in logistics for the evacuation of heavy crude and the growth of the pipeline infrastructure. These investments are also seekingexpected to reduce our energyenable future operating costs optimization by US $100 million by 2021upgrading equipment and increase our investments in renewable energy sources through the incorporation of 60 MW of renewable photovoltaic energy to our energy matrix, which already has 43 MW of biomass generation.improving its performance.
We currently expectDownstream
In terms of the downstream segment, the Business Plan allocates an investment between US$ 1.2 billion and US$ 1.4 billion focused on ensuring (i) the integrity and competitiveness of existing assets, and (ii) compliance with the fuel quality path. Regulatory compliance investments and major maintenance investment are expected to requirebe made a part of the compliance with the life cycle of the plants in the Cartagena and Barrancabermeja refineries. The expected investments also call for the execution of the final phase of the interconnection project of the crude plants of the Cartagena refinery in an aggregate amount of approximately US$ 77 million, which is expected to commence operations in 2022.
In order to advance with the production of cleaner fuels for the country, investments in the 2021-2023 period are expected to make possible to guarantee sustained internal quality of diesel of between US$12-15 billion during the 2019-2021 period,10 and 15 ppm of which approximately 82% would be allocatedsulfur, and to the upstream segment, 8%bring gasoline to the midstream segment, 7% to the downstream segment and 3% to other. These investments exclude inorganic growth opportunities, which if materialized, could be financed through cash from operations.a maximum of 50 ppm of sulfur across Colombia.
Commercial Strategy
The Business Plan seeksmaintains the Ecopetrol Group’s strategy of diversifying clients and destinations, with an important emphasis on the independent refining sector in China, while maintaining an active participation in the refining market of the United States. The foregoing is expected to maintain leverage metrics to help us preservebe leveraged on our investment grade rating while allowingoperational flexibility for specific optimizationsat ports, a stable quality of our capital structure during the period.crude oil and optimization of logistics.
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In November 2018,terms of TESG, the Business Plan allocates approximately COP$ 1.7 trillion for the 2020-2024 period for social and environmental investment, aimed at closing social gaps and promoting the development and well-being of the communities where the Ecopetrol Group operates, with strategic projects expected in infrastructure, public services, education, sports and health, inclusive rural development and entrepreneurship and business development. Additionally, support will continue to be provided with resources in order to meet the COVID-19 pandemic needs of the communities and areas where the Ecopetrol Group operates.
Between US$ 100 million and US$ 150 million are expected to be allocated to the development of the Ecopetrol Group’s digital strategy, in order to capture benefits related to artificial intelligence technologies, block chain and bots, among others. Furthermore, we expect to invest between US$70 million and US$110 million in projects to increase the recovery factor, energy transition and strategic studies on water issues and new materials.
In connection with the Ecopetrol Group’s energy transition strategy, the Business Plan allocates investments of more than US$600 million in initiatives focused on the decarbonization agenda, among which stand out solar, wind and geothermal energy projects, followed by energy efficiency and fuel quality projects, among others. Similarly, in March 2021, intermediate and long-term emissions reduction goals and achievement plan were defined in line with the Ecopetrol Group’s growth strategy.
In 2021, the Ecopetrol Group also expects to consolidate its evaluation of opportunities associated with the hydrogen value chain and will seek to materialize partnerships in international agreements and with governments to identify business opportunities.
For more information on the TESG agenda see section entitled Technology, Environment, Social and Governance (TESG) Strategies and Initiatives.
2.1.1.1 | Energy Transition |
To acknowledge the risks and opportunities that transitioning to a low carbon economy implies for the Ecopetrol Group, we have defined four lines of action, including the aforementioned, to face the energy transition, as described below:
(i) | Continue strengthening the competitiveness of the oil and gas business: The Ecopetrol Group plans to gain resilience in the oil and gas portfolio, which is expected to continue to be our core activities until the peak in oil demand is reached, while increasing its commitment to new businesses resilient to the energy transition. |
(ii) | Diversification of our business portfolio into low-carbon businesses: The Ecopetrol Group is exploring new business opportunities in the electricity value chain specifically in the energy transmission market as well as other potential future low-carbon businesses such as green hydrogen, carbon capture, utilization and storage (CCUS), nature-based solutions, among others, as long as that they meet the Ecopetrol Group’s growth, cash protection, and capital discipline criteria. |
(iii) | Achievement of decarbonization targets: Focused on accelerating and prioritizing energy efficiencies and reductions in carbon emissions the Ecopetrol Group plans on achieving the decarbonization goals mentioned in the section entitled Technology, Environment, Social and Governance (TESG) Strategies and Initiatives. Such targets are aligned with the Ecopetrol Group’s objectives of reducing the carbon emissions associated with its operations, as well as reducing the vulnerability of its operation and infrastructure to climate change. |
(iv) | Achievement of sustainability through the TESG strategy: The Ecopetrol Group’s TESG strategy places a clear focus on climate change (including decarbonization targets), water management, and territorial development as well as biodiversity, circular economy, health, safety and environmental (HSE) practices and diversity, leveraged on technology as a key enabler. |
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Oil and gas companies are evaluating options to reposition themselves along the energy value chain in new business segments aligned with the market trends towards decarbonization and electrification, such as renewable generation, commercialization, and services to end customers, among others. It is Ecopetrol’s view that the need to connect and integrate multiple points and types of generation will reinforce the role of transmission as an indispensable actor in the energy value chain, and a required enabler of the growth of clean generation and electrification.
Our announced interest in acquiring a 51.4% stake in Interconexión Eléctrica S.A. (ISA) is part of this strategy as it would allow us to achieve a relevant position in a strategic sector for the energy transition. Through a single transaction, we would position ourselves in a key link in the electricity business with clear prospects for future growth. For more information on this potential transaction see the section entitled Business Overview-Recent Developments.
2.1.2 | 2021 Investment Plan |
In December 2020, the Board of Directors approved between US$3.5 billion and US$4.0 billion for the 20192021 investment plan.plan at US$ 45/Bl Brent. The Ecopetrol Group plans to produce between 720700 and 730710 thousand barrels of oil equivalent per day during 2019. 2021. The Ecopetrol Group expects to allocate 80% percent of these investments to projects in Colombia and the remainder to the positioning and development of the Ecopetrol Group’s operations in the United States and Brazil.
The table below sets forth the details of the investment plan per business segment.segment announced in December 2020:
Table 3 – 20192021 Investment Plan
Business Segment | ||||||||
Exploration | % | |||||||
Production | % | |||||||
Midstream | 7 | % | ||||||
Downstream | % | |||||||
Other | ||||||||
% | ||||||||
TOTAL | 100 | % |
(1) |
Percentage over the upper |
Exploration
In the exploration segment, US$430-US$490 million has been allocated mainly to the evaluation and appraisal of discoveries and ongoing exploration activity of Ecopetrol S.A. (approximately 44%), Hocol S.A. (“Hocol”) (approximately 12%), Ecopetrol America Inc. (approximately 1%), ECP Hidrocarburos Mexico (approximately 7%), Ecopetrol Costa Afuera (approximately 3%) and Ecopetrol Brazil (approximately 33%).
Production
In the production segment, US$2,385-US$2,725 million has been allocated mainly to the execution of development and incremental production projects of Ecopetrol S.A. (approximately 91%) primarily at Castilla, Rubiales, Chichimene, Apiay-Suria, Yariguí-Cantagallo, La Cira-Infantas, Casabe, Piedemonte and Quifa. We have also allocated funds for our affiliates and subsidiaries as follows: approximately 3% for the development, operation and maintenance of fields of Ecopetrol America Inc. in the U.S. Gulf of Mexico, approximately 5% to Hocol, approximately 1% to Equion and Savia.
Midstream
In the midstream segment, US$240-US$275 million has been allocated to investments focused on system and operational integrity. The segment is seeking a higher efficiency in operations and maintenance practices.
Downstream
In the downstream segment, US$365-US$420 million has been principally allocated to Barrancabermeja refinery and Reficar through initiatives aimed at increasing revenues, enhancing integrity management, improving efficiency and reducing operational costs. The segment is seeking a higher efficiency in operations and maintenance practices in order to maximize the value of the existing assets.
2.2. |
3.1Our HistoryEcopetrol’s strategy for unconventional resources is based on the significant acreage position it has in the Middle Magdalena Basin in Colombia. In September 2019, the Colombian Council of State authorized the execution of the PPII to do the research on the eventual effects of using unconventional technology and made mandatory recommendations in respect of the pilot stage. However, a final decision on the development of unconventional reservoirs will not be issued until the government has evaluated the PPII results.
On February 28, 2020, the Ministry of Mines and Energy issued Decree 328 providing the general guidelines for developing PPII on unconventional reservoirs. Furthermore, on December 24, 2020, Ecopetrol signed a contract with the Agencia Nacional de Hidrocarburos - National Hydrocarbons Agency (the “ANH”) in respect of a pilot program in the Middle Magdalena Basin pursuant to which the potential environmental and social impacts are to be evaluated and the multi-stage hydraulic fracturing in horizontal wells concept is to be assessed.
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3. | Business Overview |
3.1 | Our History |
We were formed in 1951 by the Colombian government 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 Refineryrefinery (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”)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”)(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 continuous disclosure obligations in Canada.
We operate in the following business segments: i)(i) Exploration and Production; ii)(ii) Transportation and Logistics; and iii)(iii) Refining, Petrochemicals and Biofuels.Biofuels; and (iv) Sales and Marketing.
Our subsidiaries, Refinería de Cartagena S.A. (“Reficar”S.A.S. (Reficar or “Cartagena Refinery”)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, 2018,2020, we have seveneight directly owned and 2919 indirectly owned subsidiaries.
During 2018,2020, the following changes were made to the Ecopetrol Group’s structure:
On |
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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.
The so-called shareholding (Ecopetrol S.A.’s direct participation), affiliated, subsidiary companies are listed, as well as the stock interest of Ecopetrol S.A.’s subordinate companies.
In 2017, Ecopetrol completed the divestment of its stake in Empresa de Energía de Bogotá S.A. E.S.P. EEB for a total of COP$1,124 billion. The operation was carried out in accordance with the procedures defined by the Law 226 of 1995, the Decree 2305 of November 13, 2014, and the Decree 2110 of December 22, 2016.
We currently own 100% of the total outstanding shares of Esenttia. In connection with the review of its long-term strategy, the Board of Directors decided to suspend the 2016 plan to sell Ecopetrol’s shares in Esenttia.
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.
3.3ISA 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.Our Business
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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 a presence primarily in Colombia and with activities in Peru,the U.S., Brazil Mexico and the U.S. Gulf Coast.Mexico. The Nation currently controlsowns 88.49% of our voting capital stock. We are among the world’s biggest state-ownedlargest public companies, ranking 300 based313 on the Forbes Global 2000 Ranking - 2018.– 2020, and the largest Colombian company in this ranking. We play a key role in the local Colombian hydrocarbon market.
3.5 | Exploration and Production |
Our exploration and production business segment includes exploration, development and production activities in Colombia and abroad. We began local exploration in 1955 and international exploration in 2006. Exploration and production activities are conducted directly by Ecopetrol S.A., and through some of our subsidiaries, as well as through joint ventures with third parties. As of December 31, 2018,2020, 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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For purposes of this exploration section, “we” refers to Ecopetrol S.A., its subsidiaries and partnerships in which Ecopetrol has an interest. Unless otherwise stated, all figures are given before deducting royalties.
3.5.1 | Exploration Activities |
Under the framework of theour Business Plan, Ecopetrol is aiming to incorporate contingent resources in high reward projects concentrated in: (i) near field exploratory activity, (ii) underexplored onshore basins in Colombia, such as Putumayo and Piedemonte, (iii) offshore Colombia, and (iv) international areas such as offshore Brazil in Pre-salt Santos and the U.S. Gulf of Mexico and Mexico.
Graph 3-3 – Sedimentary Basinsbasins where Ecopetrol executes exploration activities
During 2018,2020, the exploration strategy was directed at leveraging our goal on three working fronts: onshore Colombia, offshore Caribbean, and strengthening and diversifying our exploration overseas.
3.4.1.1Exploration Activities in Colombia
3.5.1.1 | Exploration Activities in Colombia |
During 2018,2020, Ecopetrol and its subsidiaries conducted drilling operationsdrilled sixteen (16) wells in twelve explorationColombia, of which ten (10) were exploratory and six (6) were appraisal wells. As of December 31, 2020, two (2) wells (A3/A2) and in five appraisal wells (A1) in Colombia. Of these seventeen wells, six were successful, sevenfive (5) were plugged and abandoned, and fournine (9) were under evaluation as of December 31, 2018.evaluation. This activity was concentrated mainly in the following basins: Eastern Plains (Llanos Orientales),Llanos, Lower Magdalena Valley, Middle Magdalena Valley, Upper Magdalena Valley and foothills.Sinú San Jacinto.
In terms2020, Ecopetrol participated in the drilling of onshore Colombia, our exploration efforts were focused on searching for hydrocarbonstwo (2) successful wells in mature basins, near-field exploration and areas close to existing production infrastructure.Colombia:
In offshore activities, we increased(i) the Cayena-1 ST1 well, drilled at sole risk by our participation from 50% topartner 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 theFuerte Sur and Purple Angel blocks (Sinu offshore basin), which were relinquished Chengue Formation. This well was drilled by Anadarko Petroleum Corporation. In the caseLewis Energy in partnership with our subsidiary Hocol in 2019. As of the block Col-5 (Sinu offshore basin), the ANH approved the conversiondate of a Technical Evaluation Agreement (as defined below) to an Explorationthis annual report, this well is closed and Production Contract (as defined below), where we have a 100% participation.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, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 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 | - | ||||||||||||||||||
Dry(1) | – | 1.0 | 1.0 | 2.0 | 1.0 | - | ||||||||||||||||||
Under Evaluation(2)(3) | 1.0 | - | - | |||||||||||||||||||||
Total | – | 1.0 | 1.0 | 3.0 | 2.0 | - | ||||||||||||||||||
Operated by Partner in Joint Venture | ||||||||||||||||||||||||
Operated by a partner in Joint Venture | ||||||||||||||||||||||||
Productive | 5.0 | 3.0 | – | - | 4.0 | 5.0 | ||||||||||||||||||
Dry | 1.0 | 2.0 | – | |||||||||||||||||||||
Dry(1) | - | 1.0 | 1.0 | |||||||||||||||||||||
Under Evaluation(2) | 1.0 | 1.0 | 3.0 | |||||||||||||||||||||
Total | 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 | 1.9 | 1.5 | – | - | 2.8 | 1.9 | ||||||||||||||||||
Dry | 0.3 | 2.3 | 1.0 | |||||||||||||||||||||
Dry(1) | 2.0 | 1.4 | 0.3 | |||||||||||||||||||||
Under Evaluation(2) | 2.5 | 0.4 | 2.0 | |||||||||||||||||||||
Total | 2.2 | 3.8 | 1.0 | 4.5 | 4.6 | 4.2 | ||||||||||||||||||
Sole Risk | ||||||||||||||||||||||||
Productive | – | – | – | 1.0 | 1.0 | - | ||||||||||||||||||
Dry | 2.0 | – | – | |||||||||||||||||||||
Dry(1) | 1.0 | 5.0 | 2.0 | |||||||||||||||||||||
Under Evaluation(2)(5) | 3.0 | - | - | |||||||||||||||||||||
Total | 2.0 | – | – | 5.0 | 6.0 | 2.0 | ||||||||||||||||||
ECAS | ||||||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Productive | 1.0 | 1.0 | 1.0 | |||||||||||||||||||||
Dry(1) | 2.0 | 2.0 | 4.0 | |||||||||||||||||||||
Under Evaluation(2) | 2.0 | 2.0 | - | |||||||||||||||||||||
Total | 5.0 | 5.0 | 5.0 | |||||||||||||||||||||
Net Exploratory Wells(4) | ||||||||||||||||||||||||
Productive | 1.0 | 0.5 | 1.0 | |||||||||||||||||||||
Dry(1) | 2.0 | 2.0 | 3.2 | |||||||||||||||||||||
Under Evaluation(2) | 1.0 | 1.0 | - | |||||||||||||||||||||
Total | 4.0 | 3.5 | 4.2 |
For the year ended December 31, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(number of wells) | ||||||||||||
Productive | – | – | – | |||||||||
Dry | – | 1.0 | – | |||||||||
Total | – | 1.0 | – | |||||||||
Net Exploratory Wells(2) | ||||||||||||
Productive | – | – | – | |||||||||
Dry | – | 0.5 | – | |||||||||
Total | – | 0.5 | – | |||||||||
Equion | ||||||||||||
Gross Exploratory Wells | ||||||||||||
Productive | – | – | – | |||||||||
Dry | – | – | – | |||||||||
Total | – | – | – | |||||||||
Hocol | ||||||||||||
Gross Exploratory Wells | ||||||||||||
Productive | 1.0 | – | 1.0 | |||||||||
Dry | 4.0 | 1.0 | – | |||||||||
Total | 5.0 | 1.0 | 1.0 | |||||||||
Net Exploratory Wells(2) | ||||||||||||
Productive | 1.0 | – | 0.5 | |||||||||
Dry | 3.2 | 1.0 | – | |||||||||
Total | 4.2 | 1.0 | 0.5 |
(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 six 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 2018: (i) Jaspe 6D, where Ecopetrol holds a 30% working interest, and Frontera as the operator holdsPerdices block. Additionally, the remaining 70% atAgencia Nacional de Hidrocarburos approved the Quifa block, (ii) Andina-1, where Ecopetrol holds atransfer of our 50% working interest, and Parex Resources as the operator holds the remaining 50% at the Capachos block, (iii) Rex NE-02 ST-1, where Ecopetrol holds a 30% working interest, and Occidental Petroleum Corporation as the operator holds the remaining 70% at the Cosecha block, (iv) Andina-2, where Ecopetrol holds a 50% working interest, and Parex Resources as the operator holds the remaining 50% at the Capachos block, (v) Cosecha C-01, where Ecopetrol holds a 30% working interest, and Occidental Petroleum Corporation as the operator holds the remaining 70% at the Cosecha block and (vi) Arrecife-1, where our subsidiary Hocol owns a 100% working interest in the VIM-8 block.COL-5, Purple Angel and Fuerte Sur blocks, where the Gorgon and Kronos gas discoveries are located, to Shell. With the arrival of a new operator with deep-water offshore experience, offshore drilling will recommence with an appraisal well, Gorgon-2, in December 2021. The appraisal well will be drilled in a 2,400 meters water depth, with an expected total depth of 4,543 meters. In case of success, additional drilling is to follow, with the expectations of accelerating the development of this material gas discovery.
Seven wells located in the Eastern plains (Llanos Orientales) and foothills were plugged and abandoned as follows: (i) Payero E-1 ST-1, where Ecopetrol holds a 20% working interest through our subsidiary Hocol, Repsol a 30% working interest and Total a 50% working interest, with Equion as operator in the Niscota block, (ii) Ocelote 500, operated by our subsidiary Hocol who holds a 100% working interest in the Guarrojo block, (iii) Ocelote 510, operated by our subsidiary Hocol who holds a 100% working interest in the Guarrojo block, (iv) Ocelote 520, operated by our subsidiary Hocol who holds a 100% working interest in the Guarrojo block, (v) Jaspe-7D, where Ecopetrol holds a 30% working interest and Frontera Energy Group as the operator holds a 70% working interest in the Quifa block, (vi) the Chipiron Far North-01 sole risk contract from Occidental Petroleum Corporation in the Chipiron block, (vii) the Pulpo-1 sole risk contract from Occidental Petroleum Corporation in the Rondon block.Seismic
In addition, four appraisal wells were drilled as of December 31, 2018, and are currently under evaluation: (i) Cira-7000 located at La Cira Infantas block, operated by Occidental Petroleum Corporation, which holds a 52% working interest in partnership with Ecopetrol, holding the remaining 48% working interest, (ii) Capachos Sur-2 located at the Capachos Block, operated by Parex Resources, which holds a 50% working interest in partnership with Ecopetrol, holding the remaining 50%, (iii) Coyote-2 located at the Mares Block, operated by Parex Resources, which holds a 50% working interest in partnership with Ecopetrol, holding the remaining 50% and (iv) Bufalo-1 located at VMM-32 block, operated by us, where we hold a 51% working interest in partnership with CPVEN, which holds the remaining 49%.
Seismic
In Colombia, our subsidiary Hocol S.A. acquired a total of 337 km of 2D in the SN 15 block and through our joint venture partner, Ismocol-Joshi-Parko, 60Ecopetrol purchased 273 km2 of 3D were acquired overseismic and 1,328 km of 2D seismic surveys in the Palagua-Caipal field.Llanos, Middle Magdalena Valley and Upper Magdalena Valley basins, with the objective of improving our geological understanding of these prolific basins.
Furthermore, Ecopetrol purchased three additional 3D seismic surveys for a total of 292.5 km2 in the Putumayo basin to improve the subsurface coverage and imaging of the basin.
3.4.1.2Exploration Activities Outside Colombia
3.5.1.2 | Exploration Activities Outside Colombia |
Our international exploration strategy aims to expand and renew our exploration portfolio in basins with remaining long term potential, diversifydilute our risks and improve the possibilitiespossibility of increasing our crude oil and natural gas reserves. KeySome key aspects of this strategy might include participating in bidding rounds to secure blocks available for exploration and entering into joint ventures with international and regional oil companies that bringcontribute with operational experienceexpertise and technology into the consortium.technology.
In partnership2020, Ecopetrol America LLC signed a cross-assignment with BPChevron, through which new blocks in the US Gulf of Mexico were acquired and CNOOC,participation in other blocks was transferred to Chevron. As a result, Ecopetrol America LLC was awardedable to diversify its portfolio while reducing risk and capital exposure.
On June 12, 2020, Ecopetrol Óleo e Gás do Brasil Ltda. officially entered the block Pau-BrazilGato do Mato discovery in the Brazilian Pre-Salt, located in the BM-S-54 and Sul de Gato do Mato blocks, where Ecopetrol holds a 30% working interest, Total holds a 20% working interest and Shell as the operator holds the remaining 50% working interest. The Gato do Mato-4 appraisal well was drilled and was declared successful.
In the pre-salt of the Santos Basin, in BrazilEcopetrol Óleo e Gás do Brasil Ltda. also drilled, together with its partners Shell (as operator) and Chevron, the Saturno-1 well, which was declared a dry hole. Further technical evaluations are being carried out during 2021 to decide the Pre-Salt 5th bidding round, organized by the National Agency of Petroleum, Natural Gas and Biofuels (ANP). Moreover, Ecopetrol is awaiting approval from the ANPpath forward with regards to access a 10% working interest in offshore block Saturno, also locatedremaining potential in the Santos basin, which is operated by Shell (who holds a 45% working interest) in partnership with Chevron (who holds the remaining 45% working interest). With the participation in these two deep water blocks, Ecopetrol has managed to obtain a position in the pre-salt play in Brazil. In order to advance our previous commitments in Brazil, we will continue with regional studies in the Ceará, Potiguar and Sergipe Blocks.
As part of the committedSaturno exploration plan in our current assets of the Equatorial Margin (CE-M-715 in the Ceará Basin, POT-M-567 in Potiguar and FZA-M-320 in Foz do Amazonas), both geology and geophysics work and technical maturation activities were carried out to help obtain a deeper understanding of the prospective potential in these provinces.
Additionally our subsidiary, Ecopetrol America Inc., was awarded the Green Canyon 404, 405, 448 and 492 blocks in the Gulf of Mexico during Lease Sale 251.
We secured the approval of the National Hydrocarbons Commission (CNH) for the exploration plan through our partnership with PEMEX in respect of block 8 (October) and Petronas-block 6 (November). The exploration plan for block 6 considers purchasing seismic, geological and geophysical analysis, seismic interpretation and drilling of the first exploration well in Mexico in 2020 and the exploration plan for block 8 considers seismic licensing, processing and the interpretation required to identify the potential prospects in the block.
17
During the course of 2018, Ecopetrol and its partners did not carry out any exploratory drilling outside Colombia.
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, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(number of wells) | ||||||||||||
INTERNATIONAL | ||||||||||||
Ecopetrol America Inc. | ||||||||||||
Gross Exploratory Wells | ||||||||||||
Productive | – | – | 1.0 | |||||||||
Dry(1) | – | 2.0 | – | |||||||||
Total | – | 2.0 | 1.0 | |||||||||
Net Exploratory Wells(2)(3) | ||||||||||||
Productive | – | – | 0.2 | |||||||||
Dry | – | 0.6 | – | |||||||||
Total | – | 0.6 | 0.2 | |||||||||
Ecopetrol Óleo e Gás do Brasil Ltda. | ||||||||||||
Gross Exploratory Wells | – | – | – | |||||||||
Productive | – | – | – | |||||||||
Dry | – | – | – | |||||||||
Total | – | – | – | |||||||||
Net Exploratory Wells | ||||||||||||
Productive | – | – | – | |||||||||
Dry | – | – | – | |||||||||
Total | – | – | – | |||||||||
Ecopetrol Germany | ||||||||||||
Gross Exploratory Wells | – | – | – | |||||||||
Productive | – | – | – | |||||||||
Dry | – | – | – | |||||||||
Total | – | – | – | |||||||||
Net Exploratory Wells | ||||||||||||
Productive | – | – | – | |||||||||
Dry | – | – | – | |||||||||
Total | – | – | – | |||||||||
Savia Perú | ||||||||||||
Gross Exploratory Wells | – | – | – | |||||||||
Productive | – | – | – | |||||||||
Dry | – | – | – | |||||||||
Total | – | – | – | |||||||||
Net Exploratory Wells | ||||||||||||
Productive | – | – | – | |||||||||
Dry | – | – | – | |||||||||
Total | – | – | – |
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Number of wells) | ||||||||||||
UNITED STATES | ||||||||||||
Ecopetrol America LLC | ||||||||||||
Gross exploratory wells | ||||||||||||
Productive | - | 1.0 | - | |||||||||
Dry(1) | - | - | - | |||||||||
Under Evaluation(2) | - | - | - | |||||||||
Total | - | 1.0 | - | |||||||||
Net Exploratory Wells(3)(4) | ||||||||||||
Productive | - | 0.2 | - | |||||||||
Dry(1) | - | - | - | |||||||||
Under Evaluation(2) | - | - | - | |||||||||
Total | - | 0.2 | - | |||||||||
BRAZIL | ||||||||||||
Ecopetrol Óleo e Gás do Brasil Ltda. | ||||||||||||
Gross exploratory wells | ||||||||||||
Productive(5) | 1.0 | - | - | |||||||||
Dry(1) | 1.0 | - | - | |||||||||
Under Evaluation(2) | - | - | - | |||||||||
Total | 2.0 | - | - | |||||||||
Net Exploratory Wells(3)(4) | ||||||||||||
Productive | 0.3 | - | - | |||||||||
Dry(1) | 0.1 | - | - | |||||||||
Under Evaluation(2) | - | - | - | |||||||||
Total | 0.4 | - | - |
(1) | A dry well or hole is an exploratory well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well. |
(2) |
(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,America LLC, purchased 874 km of 2D (spectrum survey) and 5,441 km2 3D (CGG and PGS) to evaluate the structures of Saturno, Titan and Ferradura (Round 15), as well as the blocks Uirapuru (Round 4) and Pau Brazil (Round 5), all of them located in the pre-salt play over the Santos and Campos basins.
Ecopetrol Hidrocarburos Mexico Inc. procured a large 60,076 km 2D seismic survey and 11,0092,423 km2 of 3D seismic data (surveys: Campeche Sur, Campeche Somero and Tabasco), to evaluate the Salina basin in theexploratory potential of 77 U.S. Gulf of Mexico.
Mexico blocks, and to further evaluate the discovery made with the Esox-1 well drilled in 2019.
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3.5.2 | Production Activities |
OurIn 2020, our consolidated average production was 720.4697 thousand boepd in 2018, an increasebarrels of approximately 5oil equivalent per day (boepd), a decrease of 28 thousand boepd as compared to 2017.2019. This increase is mainly was primarily due to the resultfollowing factors: (i) the effects of an increasethe COVID-19 pandemic, which caused a significant reduction in upstream investments during 2018.oil and gas demand, (ii) the drop in oil prices which led to a slowdown in activity and investment, and (iii) public order issues caused by the slowdown in the economy, impacting our operations in different regions. The aforementioned situations were reflected in the temporary closure of some wells, negatively affecting the production of some fields. However, as of the date of this annual report, all affected wells have been reactivated.
The following table summarizes the results of our oil and gas production activities for the periods indicated:
Table 6 – Ecopetrol Group’s Oil and Gas Production
For the year ended December 31, | ||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||
Oil | Gas(1) | Total | Oil | Gas(1) | Total | Oil | Gas(1) | Total | ||||||||||||||||||||||||||||
(thousand boepd) | ||||||||||||||||||||||||||||||||||||
Total production in Colombia(2) | 578.4 | 125 | 703.4 | 577.3 | 121.6 | 698.9 | 582.5 | 123.3 | 705.8 | |||||||||||||||||||||||||||
Total International production(3) | 14.1 | 2.9 | 17.0 | 13.6 | 2.6 | 16.2 | 9.6 | 2.5 | 12.1 | |||||||||||||||||||||||||||
Total production of Ecopetrol Group | 592.5 | 127.9 | 720.4 | 590.9 | 124.2 | 715.1 | 592.1 | 125.8 | 717.9 |
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 |
(2) | Total production in Colombia corresponds to Ecopetrol S.A., Hocol and |
(3) | Total International production corresponds to Ecopetrol Permian LLC; Savia Perú and Ecopetrol America |
(4) | For the Company’s presentation of reserves, the Company deducts from its total gross production the 100% of crude royalties from Ecopetrol Group companies and gas royalties from non-Colombian Ecopetrol Group companies, Savia Perú S.A. (Peru), Ecopetrol Permian LLC (United States) and Ecopetrol America LLC (United States). Gas royalties derived from Colombian production are not deducted because according to local regulation the Company is entitled to such gas royalties. Also includes self-consumption, which is only comprised of natural gas self-consumption and is immaterial. Oil production include NGL, which is inmaterial. |
3.4.2.1 Production Activities in Colombia
3.5.2.1 | Production Activities in Colombia |
3.4.2.1.1Ecopetrol S.A.’s Production Activities in Colombia
3.5.2.1.1 | Ecopetrol S.A.’s Production Activities in Colombia |
For the year ended December 31, 2018,2020, Ecopetrol S.A. was the largest participant in the Colombian hydrocarbons industry, accounting for approximately 63%66.1% of crude oil production (according to calculations made by Ecopetrol based on information from the Ministry of Mines and Energy) and approximately 66%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 2018,During 2020, Ecopetrol S.A. carried outcompleted the drilling of 201 development drillingwells, mainly in the EasternCentral and OrinoquiaOrinoquía regions drilling 528 development wells (226 of those(156 through direct operations and 30245 through joint ventures)associated companies).
In terms of operational structure, Ecopetrol S.A. manages its production operations through a regional organization. Our operating assets are distributed in the following regions:
A fifth 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 12679 oil fields with active production in 2018.2020:
19
Additionally, we operate 104 fields with active production through Associated Operations with different partners.
In February 2020, the Vice-Presidency of Gas was created in order to lead and execute the Ecopetrol Group’s integrated gas strategy.
The map below shows the locations of Ecopetrol S.A.’s operations 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: VAS isAssociated Operations are conducted through a countrywide Vice-presidency.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 548.7516 mbod in 2018, 3.72020, 32 mbod higherlower than in 2017,2019, which represents a year-to-year increasedecrease of 0.7%6%.
The following chart summarizes Ecopetrol S.A.’s average daily crude oil production in Colombia by Region,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, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(thousand bpd) | ||||||||||||
Central Region | ||||||||||||
1) La Cira – Infantas | 28.1 | 22.6 | 19.1 | |||||||||
2) Casabe | 13.9 | 15.9 | 17.8 | |||||||||
3) Yarigui | 14.4 | 14.5 | 16.6 | |||||||||
4) Other | 17.3 | 18.5 | 21.3 | |||||||||
Total Central Region | 73.7 | 71.5 | 74.8 | |||||||||
Orinoquía Region | ||||||||||||
1) Castilla | 113.9 | 114.1 | 121.3 | |||||||||
2) Chichimene | 67.7 | 70.5 | 74.0 | |||||||||
3) Cupiagua | 8.3 | 9.6 | 11.3 | |||||||||
4) Other | 25.5 | 24.3 | 18.3 | |||||||||
Total Orinoquía Region | 215.4 | 218.5 | 224.9 | |||||||||
Eastern Region | ||||||||||||
1) Rubiales(1) | 119.5 | 118.7 | 61.5 | |||||||||
2) Caño Sur(2) | 3.2 | 1.4 | 0.4 | |||||||||
Total Eastern Region | 122.7 | 120.1 | 61.9 | |||||||||
Southern Region | ||||||||||||
1) San Francisco | 6.0 | 6.2 | 6.5 | |||||||||
2) Huila Area(3) | 3.5 | 3.1 | 7.4 | |||||||||
3) Tello | 3.6 | 3.9 | 4.4 | |||||||||
4) Other | 11.7 | 12.2 | 9.4 | |||||||||
Total Southern Region | 24.8 | 25.4 | 27.7 | |||||||||
Associated Operations | ||||||||||||
1) Rubiales(1) | – | – | 41.4 | |||||||||
2) Quifa | 21.2 | 18.8 | 19.6 | |||||||||
3) Caño Limon | 25.3 | 22.2 | 23.3 | |||||||||
4) Cusiana(4) | – | – | 2.6 | |||||||||
5) Other | 65.6 | 68.5 | 75.9 | |||||||||
Total Associated Operations | 112.1 | 109.5 | 162.8 | |||||||||
Total average daily crude oil production Ecopetrol S.A. (Colombia) | 548.7 | 545.0 | 552.1 |
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 included in Associated Operations until February 2020, when the |
In our annual report on form 20-F for the |
(4) | In July 2020, the |
Table 8 – Ecopetrol S.A. Production per Type of Crude
2018 (mbod) | Year-on- Year ∆(%) | 2017 (mbod) | Year-on- Year ∆(%) | 2016 (mbod) | 2020 (Mbod) | Year-on-Year ∆ (%) | 2019 (Mbod) | Year-on-Year ∆ (%) | 2018 (Mbod) | ||||||||||||||||||||||||||||||||
Light | 40.7 | (4.0 | )% | 42.4 | (4.9 | )% | 44.6 | 39.0 | 6.8 | % | 36.5 | (10.3 | )% | 40.7 | |||||||||||||||||||||||||||
Medium | 154.4 | 1.8 | % | 151.6 | (6.1 | )% | 161.5 | 140.6 | (6.5 | )% | 150.3 | (2.7 | )% | 154.4 | |||||||||||||||||||||||||||
Heavy | 353.6 | 0.7 | % | 351.0 | 1.4 | % | 346.0 | 336.4 | (6.9 | )% | 361.2 | 2.1 | % | 353.6 | |||||||||||||||||||||||||||
Total | 548.7 | 545.0 | 552.1 | 516.0 | (5.8 | )% | 548.0 | (0.1 | )% | 548.7 |
Ecopetrol S.A.’s crude oil production in Colombia during 2018 consisted of2020 was approximately 36%35% light and medium crudes and 64%65% heavy crudes. In 2017,2019, 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 2016, approximately 37% of the crude oil production corresponded to light and medium crudes and 63% to heavy crudes.
21
Natural Gas Production
In 2018,2020, the average daily production of natural gas by Ecopetrol S.A. (excluding its subsidiaries) reached 112.5121.82 mboed, including natural gas liquids (“NGLs”)(NGLs), corresponding to a 1.4%4.3% increase in comparisoncompared to 20172019 production.
We have three main natural gas This production fields, Guajira, Cusiana and Cupiagua. In the Guajira field, we have partnered with Chevron who operates the field. The development of Cusiana field had a change in participation, because Tauramena joint venture expired on July 3, 2016. The Tauramena block is part of the Cusiana unified exploitation plan. As a consequence of the termination of the Tauramena joint venture, Ecopetrol’s participation increased from 63.4% to 97.8%, and Ecopetrol assumed the operation of the Cusiana unified exploitation plan. Ecopetrol S.A. is the operator of the Cupiagua field and other wells previously under the Recetor contract that were transferred from Equion to Ecopetrol as a result of the full return of the Recetor Field to Ecopetrol on May 29, 2017.
Of our total natural gas production during the year ended December 31, 2018, approximately 20% was supplied from the following fields: Cupiagua (35%), Cusiana (24%), Floreña (18%), Guajira field, 31% from the Cusiana field, 24% from the Cupiagua field(11%), and the remaining 25%12% from other fields.
By the end of December 31, 2020, the Liquefied Petroleum Gas (LPG) plant of the Cupiagua field produced 7,500 LGP barrels per day. The following table sets forth Ecopetrol S.A.’s average dailyplant produces LPG and other products such as natural gas productionliquids (NGL) and penthane (C5).
Starting May 2020, our subsidiary Hocol took in the position of operator of the Chevron’s stake in the Chuchupa and Ballena fields, following the approval of the transaction by the Superintendence of Industry and Commerce of Colombia including NGLs, prior to deducting royalties, for the years ended on December 31, 2018, 2017 and 2016.in November 2019.
Table 9 – Ecopetrol S.A.’s Average Daily Natural Gas Production in Colombia
For the year ended December 31, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(thousand boepd) | ||||||||||||
COLOMBIA | ||||||||||||
Central Region | ||||||||||||
1) La Cira – Infantas | 0.16 | 0.15 | 0.17 | |||||||||
2) Provincia | 1.96 | 2.41 | 3.09 | |||||||||
3) Yarigui | 0.42 | 0.48 | 0.56 | |||||||||
4) Gibraltar | 6.87 | 7.16 | 6.32 | |||||||||
4) Other | 1.86 | 2.02 | 1.60 | |||||||||
Total Central Region | 11.27 | 12.22 | 11.74 | |||||||||
Orinoquía Region | ||||||||||||
1) Cupiagua | 26.97 | 25.29 | 28.72 | |||||||||
2) Cusiana(1) | 34.73 | 31.97 | 15.98 | |||||||||
3) Other | 2.80 | 2.44 | 1.44 | |||||||||
Total Orinoquía Region | 64.5 | 59.70 | 46.14 | |||||||||
Southern Region | ||||||||||||
1) Huila Area(2) | 0.13 | 0.10 | 0.64 | |||||||||
2) Tello | 0.11 | 0.22 | 0.35 | |||||||||
3) Other | 0.25 | 0.40 | 0.03 | |||||||||
Total Southern Region | 0.49 | 0.72 | 1.02 | |||||||||
Associated Operations | ||||||||||||
1) Guajira | 23.02 | 27.09 | 33.34 | |||||||||
2) Cusiana(1) | 0.00 | 0.00 | 12.65 | |||||||||
3) Other | 13.21 | 11.29 | 11.10 | |||||||||
Total Associated Operations | 36.23 | 38.38 | 57.09 | |||||||||
Total Natural Gas Production (Colombia) | 112.49 | 111.02 | 115.99 |
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | |||||||||||||||||||
Central Region | ||||||||||||||||||||||||
La Cira – Infantas | 0.10 | 0.57 | 0.12 | 0.68 | 0.16 | 0.91 | ||||||||||||||||||
Provincia | 1.48 | 4.84 | 1.58 | 4.96 | 1.96 | 7.30 | ||||||||||||||||||
Yarigui | 0.42 | 2.41 | 0.43 | 2.45 | 0.42 | 2.39 | ||||||||||||||||||
Gibraltar | 5.71 | 29.12 | 6.25 | 31.86 | 6.87 | 34.94 | ||||||||||||||||||
Other | 2.00 | 10.42 | 1.68 | 8.84 | 1.86 | 10.20 | ||||||||||||||||||
Total Central Region | 9.71 | 47.36 | 10.06 | 48.79 | 11.27 | 55.75 | ||||||||||||||||||
Orinoquía Region | ||||||||||||||||||||||||
Apiay | 0.32 | - | 0.29 | - | 0.49 | - | ||||||||||||||||||
Other | 0.58 | - | 0.64 | - | 0.25 | - | ||||||||||||||||||
Total Orinoquía Region | 0.90 | - | 0.93 | - | 0.74 | - | ||||||||||||||||||
Piedemonte Region | ||||||||||||||||||||||||
Floreña(1)(2) | 22.22 | 109.93 | 1.95 | 8.72 | 2.06 | 9.41 | ||||||||||||||||||
Cupiagua(3) | 42.68 | 194.99 | 36.45 | 196.08 | 26.97 | 153.73 | ||||||||||||||||||
Cusiana(3) | 29.57 | 136.63 | 35.72 | 164.67 | 34.73 | 159.83 | ||||||||||||||||||
Total Piedemonte Region | 94.47 | 441.55 | 74.12 | 369.47 | 63.76 | 322.96 | ||||||||||||||||||
Andina Oriente Region(4) | ||||||||||||||||||||||||
Huila Area | 0.19 | 0.34 | 0.09 | 0.40 | 0.13 | 0.68 | ||||||||||||||||||
Tello | 0.08 | 0.47 | 0.07 | 0.40 | 0.11 | 0.63 | ||||||||||||||||||
Other | 0.19 | 0.53 | 0.25 | 0.23 | 0.25 | 0.23 | ||||||||||||||||||
Total Andina Oriente Region | 0.46 | 1.34 | 0.41 | 1.03 | 0.49 | 1.54 | ||||||||||||||||||
Associated Operations | ||||||||||||||||||||||||
Guajira | 12.80 | 72.92 | 17.92 | 102.14 | 23.02 | 131.21 | ||||||||||||||||||
Floreña(1)(2) | 2.15 | 9.91 | 12.50 | 57.51 | 12.20 | 55.46 | ||||||||||||||||||
Other | 1.33 | 5.37 | 0.82 | 3.48 | 1.01 | 4.50 | ||||||||||||||||||
Total Associated Operations | 16.28 | 88.20 | 31.24 | 163.13 | 36.23 | 191.18 | ||||||||||||||||||
Total Natural Gas Production (Colombia) | 121.82 | 578.45 | 116.76 | 582.43 | 112.49 | 571.43 |
(1) | The Piedemonte fields change their name to the Floreña fields as of December 2020. |
(2) | The Floreña fields were included in Associated Operations until February 2020, when the association contract with Equión ended. Starting in March 2020, these fields are reported under the Piedemonte Region. |
(3) | In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana fields were included in the Orinoquía Region, whereas for the year ended December 31, 2020, these fields are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(4) | In July 2020, the former Southern and Eastern regions joined to form the Andina region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd. Conversion was done only in respect of natural gas, since natural gas liquids cannot be converted into mcfpd. Therefore, when the Company’s natural gas production is measured in boepd, it is higher as that includes natural gas and natural gas liquids. The Company’s sales of natural gas liquids represented less than 1% of the Company’s consolidated sales for the periods presented in this annual report.
22
Projects to Increase Recovery Factor
In 2020, Ecopetrol continuescontinued the implementation of secondary and tertiary recovery programs to investimprove 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 itsthe Chichimene, Castilla and Llanito fields.
The recovery factor program in order to increase reserves and production. In 2018, the recovery factor programprograms increased proven reserves by 129113 million boe. US$94 million was invested for the execution of 60 studies and 19 pilots to reduce uncertainties and mature these opportunities into projects in the medium or long term. These pilots under assessment had a daily productionboe with an investment of approximately 17 mboed.
Secondary and tertiary recovery technologies contributed 167 mboed or 23% ofUS$ 345 million executed throughout the Ecopetrol Group’s total daily production, primarily from the Castilla, Chichimene, Teca, La Cira Infantas, Casabe, Yarigui, Tibú, Asociacion Nare, Cusiana, Cupiagua and Piedemonte fields.
In 2018, the following projects exhibited positive results in both efficiency of injection and response in production: (i) the water injection pilots at Castilla, Chichimene, Apiay, Suria and La Cira sands A and B, (ii) the improved water injection pilots at Chichimene, La Cira Infantas, Casabe and Yarigui fields, and (iii) the steam injection pilots at the Teca and Nare fields.
In 2018, a final investment decision was taken in respect of the commencement of eightyear. Of 42 recovery projects, based on the results of their correspondent pilots: (i) six water injection projects (Chichimene, Castilla, Suria, La Cira sands A34 correspond to secondary recovery and B, Llanito-Gala and Galan), (ii) one enhanced water injection project (Dina K) and (iii) one continuous steam injection project (Teca). Additionally, nine recovery technology expansion projects are currently being structured.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, 2018, 20172020, 2019 and 2016.2018.
Table 10 – Ecopetrol S.A.’s Gross and Net Development Wells in Colombia(1)
For the year ended December 31, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(number of wells) | ||||||||||||
COLOMBIA | ||||||||||||
Central Region | ||||||||||||
Gross wells owned and operated by Ecopetrol | 12 | – | – | |||||||||
Orinoquía Region | ||||||||||||
Gross wells owned and operated by Ecopetrol | 77 | 56 | 47 | |||||||||
Southern Region | ||||||||||||
Gross wells owned and operated by Ecopetrol | 19 | – | – | |||||||||
Eastern Region | ||||||||||||
Gross wells owned and operated by Ecopetrol | 118 | 143 | 36 | |||||||||
Total gross wells owned and operated by Ecopetrol S.A. in Colombia | 226 | 199 | 83 | |||||||||
Associated Operations | ||||||||||||
Gross wells in joint ventures | 302 | 276 | 50 | |||||||||
Net wells(1) | 144.2 | 97 | 19 | |||||||||
Total gross wells in joint ventures Ecopetrol S.A. in Colombia | 302 | 276 | 50 | |||||||||
Total net wells in joint ventures Ecopetrol S.A. in Colombia(1) | 144.2 | 97 | 19 | |||||||||
Total gross wells Ecopetrol S.A. in Colombia | 528 | 475 | 133 | |||||||||
Total net wells Ecopetrol S.A. in Colombia(1) | 370.2 | 296 | 102 |
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Productive Wells | Dry Wells | Productive Wells | Dry Wells | Productive Wells | Dry Wells | |||||||||||||||||||
Central Region | ||||||||||||||||||||||||
Gross development wells owned and operated by Ecopetrol | 51.0 | - | 84.0 | 1.0 | 12.0 | - | ||||||||||||||||||
Orinoquía Region | ||||||||||||||||||||||||
Gross development wells owned and operated by Ecopetrol | 32.0 | - | 87.0 | 2.0 | 77.0 | - | ||||||||||||||||||
Andina Oriente Region(2) | ||||||||||||||||||||||||
Gross development wells owned and operated by Ecopetrol | 73.0 | - | 124.0 | - | 134.0 | 4.0 | ||||||||||||||||||
Piedemonte Region(3) | ||||||||||||||||||||||||
Gross development wells owned and operated by Ecopetrol | - | - | - | - | - | - | ||||||||||||||||||
Total gross development wells owned and operated in Colombia | 156.0 | - | 295.0 | 3.0 | 223.0 | 4.0 | ||||||||||||||||||
Associated Operations | ||||||||||||||||||||||||
Gross development wells in joint ventures | 45.0 | - | 268.0 | 5.0 | 311.0 | 4.0 | ||||||||||||||||||
Net development wells(4) | 29.0 | - | 137.0 | 2.6 | 148.7 | 1.8 | ||||||||||||||||||
Total gross development wells in joint ventures Ecopetrol S.A. in Colombia | 45 | - | 268.0 | 5.0 | 311.0 | 4.0 | ||||||||||||||||||
Total net development wells in joint ventures Ecopetrol S.A. in Colombia(4) | 29.0 | - | 137.0 | 2.6 | 148.7 | 1.8 | ||||||||||||||||||
Total gross development wells Ecopetrol S.A. in Colombia | 201 | - | 563.0 | 8.0 | 534.0 | 8.0 | ||||||||||||||||||
Total net development wells Ecopetrol S.A. in Colombia(4) | 185.0 | - | 432.0 | 5.6 | 370.7 | 5.8 |
(1) | Includes only wells that were drilled and completed. |
(2) | In July 2020, the former Southern and Eastern regions joined and formed the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(3) | In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and the Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(4) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
23
The following tables set forth activities by geographical area, including the number of gross and net wells in the process of being drilled, completed, or waiting on completion for the year ended December 31, 2020.
Table 11 – Ecopetrol S.A.’s Gross and Net In Process Wells
For the year ended December 31, 2020 | ||||||||||||||||
Drilled but not completed | Mobilization | Being drilled | Being completed | |||||||||||||
(Number of wells) | ||||||||||||||||
COLOMBIA | ||||||||||||||||
Central Region | ||||||||||||||||
Gross in process wells owned and operated by Ecopetrol | 7.0 | - | 4.0 | 8.0 | ||||||||||||
Orinoqula Region | ||||||||||||||||
Gross in process wells owned and operated by Ecopetrol | - | - | - | - | ||||||||||||
Andina Oriente Region(1) | ||||||||||||||||
Gross in process wells owned and operated by Ecopetrol | 1.0 | 1.0 | 2.0 | - | ||||||||||||
Piedemonte Region(2) | ||||||||||||||||
Gross in process wells owned and operated by Ecopetrol | - | - | - | - | ||||||||||||
Total gross in process wells owned and operated in Colombia | 8.0 | 1.0 | 6.0 | 8.0 | ||||||||||||
Associated Operations | ||||||||||||||||
Gross in process wells in joint ventures | 8.0 | - | 1.0 | - | ||||||||||||
Net in process wells(3) | 6.2 | - | 1.0 | - | ||||||||||||
Total gross in process wells in joint ventures Ecopetrol S.A. | 8.0 | - | 1.0 | - | ||||||||||||
Total net in process wells in joint ventures Ecopetrol S.A.(3) | 6.2 | - | 1.0 | - | ||||||||||||
Total gross in process wells Ecopetrol S.A. in Colombia | 16.0 | 1.0 | 7.0 | 8.0 | ||||||||||||
Total net in process wells Ecopetrol S.A. in Colombia(3) | 14.2 | 1.0 | 7.0 | 8.0 |
(1) | In July 2020, the former Southern and Eastern regions joined to form the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(2) | In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and the Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(3) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
24
Production Acreage
The following table sets forth Ecopetrol S.A.’s developed and undeveloped gross and net acreage of crude oil and natural gas production in Colombia for the year ended December 31, 2020.
Table 12 – Ecopetrol SA.’s Developed and Undeveloped Gross and Net Acreage of Crude Oil and Natural Gas Production in Colombia
As of December 31, 2020 | ||||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
(Acres) | ||||||||||||||||
Ecopetrol S.A. | 471,969 | 371,489 | 4,633,683 | 3,443,517 |
Gross and Net Productive Wells
The following table sets forth Ecopetrol S.A.’s total gross and net productive wells by region as of December 31, 2020.
Table 13 – Ecopetrol S.A.’s Gross and Net Productive Wells by Region(1)
For the year ended December 31, 2020 | ||||||||||||||||
Crude Oil(2) | Natural Gas(3) | |||||||||||||||
Gross | Net(4) | Gross | Net(4) | |||||||||||||
(Number of wells) | ||||||||||||||||
COLOMBIA | ||||||||||||||||
Central Region | 2,049 | 1,548 | 4.0 | 4.0 | ||||||||||||
Orinoquía Region | 996 | 985 | - | - | ||||||||||||
Andina Oriente Region(5) | 1,087 | 1,034 | 8.0 | 8.0 | ||||||||||||
Piedemonte Region(6) | 58 | 58 | 17.0 | 17.0 | ||||||||||||
Associated Operations Region | 2,711 | 1,473 | 34.0 | 16.0 | ||||||||||||
Total | 6,901 | 5,098 | 63.0 | 45.0 |
(1) | Includes only wells that were drilled and completed. |
(2) | We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. |
(3) | Natural gas wells are those in which operations are directed only toward the production of commercial gas. |
(4) | Net productive wells are calculated by multiplying gross productive wells by our ownership percentage. |
(5) | In July 2020, the former Southern and Eastern regions joined and formed the Andina Oriente region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
(6) | In our annual report on form 20-F for the year ended December 31, 2019, the Cupiagua and Cusiana wells were included in the Orinoquía Region and Floreña wells were included in Associated Operations, whereas for the year ended December 31, 2020, these wells are reported under the Piedemonte Region. Information as of December 31, 2019 and December 31, 2018 was reclassified in this annual report to conform to the presentation as of December 31, 2020. |
25
3.5.2.1.2 | Ecopetrol S.A.’s Affiliates and Subsidiaries’ Production Activities in Colombia |
In 2020, the subsidiaries’ production in Colombia came from Hocol and Equión. During the year, the production obtained from these two companies was 37.6 thousand boepd, which represents 5.4% of the Ecopetrol Group’s total production.
Crude Oil Production
The following table sets forth our average daily crude oil production from Hocol and Equion, prior to deducting royalties, for the periods indicated.
Table 14 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Crude Oil Production(1)
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Thousand bpd) | ||||||||||||
COLOMBIA | ||||||||||||
Hocol | ||||||||||||
Joint venture operation | 1.06 | 2.00 | 2.30 | |||||||||
Direct operation | 19.14 | 18.80 | 18.40 | |||||||||
Total Hocol | 20.20 | 20.80 | 20.70 | |||||||||
Equion(1) | ||||||||||||
Joint venture operation | - | - | - | |||||||||
Direct operation | 1.13 | 7.90 | 9.00 | |||||||||
Total Equion | 1.13 | 7.90 | 9.00 | |||||||||
Production Tests | - | - | - | |||||||||
Total Average Daily Crude Oil Production | 21.33 | 28.70 | 29.70 |
(1) | Equion fields were in operation until February 2020. |
The 86% decrease in Equion’s production in 2020, as compared to 2019, was mainly due to the termination of the Piedemonte’s association contract in February 2020.
Natural Gas Production
The following table sets forth our subsidiaries’ average daily natural gas production, prior to deducting royalties, for the periods indicated.
Table 15 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Natural Gas Production
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | |||||||||||||||||||
COLOMBIA | ||||||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Joint venture operation | 2.18 | 12.43 | 2.00 | 11.40 | 1.60 | 9.10 | ||||||||||||||||||
Direct operation(1) | 13.24 | 75.48 | 6.70 | 38.20 | 5.90 | 33.60 | ||||||||||||||||||
Total Hocol | 15.42 | 87.91 | 8.70 | 49.60 | 7.50 | 42.80 | ||||||||||||||||||
Equion(2) | ||||||||||||||||||||||||
Joint venture operation | - | - | - | - | 0.20 | 1.10 | ||||||||||||||||||
Direct operation | 0.86 | 4.10 | 5.00 | 23.29 | 4.80 | 22.34 | ||||||||||||||||||
Total Equion | 0.86 | 4.10 | 5.00 | 23.29 | 5.00 | 23.44 | ||||||||||||||||||
Production Tests | - | - | - | - | - | - | ||||||||||||||||||
Total Average Daily Gas Production (Subsidiaries in Colombia) | 16.28 | 92.01 | 13.70 | 72.89 | 12.50 | 66.24 |
(1) | In November 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields and took the position of operator, this represents the increase in production related to direct operation. |
(2) | Equion fields were in operation until February 2020. |
Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd. Conversion was done only in respect of natural gas, since natural gas liquids cannot be converted into mcfpd. Therefore, when the Company’s natural gas production is measured in boepd, it is higher as that includes natural gas and natural gas liquids. The Company’s sales of natural gas liquids represented less than 1% of the Company’s consolidated sales for the periods presented in this annual report.
26
Development Wells
The following table sets forth the number of gross and net development wells drilled exclusively by our subsidiaries and in their joint ventures in Colombia for the periods indicated.
Table 16 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Development Wells(1)
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Productive Wells | Dry Wells | Productive Wells | Dry Wells | Productive Wells | Dry Wells | |||||||||||||||||||
(Number of wells) | ||||||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Gross development wells owned and operated by Hocol | 24.0 | - | 21.0 | 2.0 | 12.0 | - | ||||||||||||||||||
Gross development wells in joint ventures | - | - | 2.0 | - | 2.0 | - | ||||||||||||||||||
Net development wells(2) | 24.0 | - | 22.0 | 2.0 | 13.0 | - | ||||||||||||||||||
Equion | ||||||||||||||||||||||||
Gross development wells owned and operated by Equion(3) | - | - | - | - | - | - | ||||||||||||||||||
Gross development wells in joint ventures | - | - | - | - | - | - | ||||||||||||||||||
Net development wells(2) | - | - | - | - | - | - | ||||||||||||||||||
Total gross development wells owned and operated in Colombia | 24.0 | - | 21.0 | 2.0 | 12.0 | - | ||||||||||||||||||
Total gross development wells in joint ventures in Colombia | - | - | 2.0 | - | 2.0 | - | ||||||||||||||||||
Total net development wells (Subsidiaries in Colombia)(2) | 24.0 | - | 22.0 | 2.0 | 13.0 | - |
(1) | Includes only wells that were drilled and completed. |
(2) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
(3) | Equion fields were in operation until February 2020. |
Note: There were no dry wells in our Colombian subsidiaries’ operations for the year ended December 31, 2018 and December 31, 2020.
27
Table 17 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net In Process Wells(1)
For the year ended December 31, 2020 | ||||||||||||||||
Drilled but not completed | Mobilization | Being drilled | Being completed | |||||||||||||
(Number of wells) | ||||||||||||||||
Hocol | ||||||||||||||||
Gross in process wells owned and operated by Hocol | - | 1.0 | - | 1.0 | ||||||||||||
Gross in process wells in joint ventures | - | - | - | - | ||||||||||||
Net in process wells(1) | - | 1.0 | - | 1.0 | ||||||||||||
Equión(2) | ||||||||||||||||
Gross in process wells owned and operated by Equión | - | - | - | - | ||||||||||||
Gross in process wells in joint ventures | - | - | - | - | ||||||||||||
Net in process wells(1) | - | - | - | - | ||||||||||||
Total gross in process wells owned and operated in Colombia | - | 1.0 | - | 1.0 | ||||||||||||
Total gross in process wells in joint ventures in Colombia | - | - | - | - | ||||||||||||
Total net in process wells (Subsidiaries in Colombia) | - | 1.0 | - | 1.0 |
(1) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
(2) | Equion fields were in operation until February 2020. |
Production Acreage
The following table sets forth 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, 2018.
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, 2018 ( acres) | ||||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Ecopetrol S.A. | 452,121 | 349,954 | 4,653,531 | 3,426,785 |
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, 2018.
Table 12 – Ecopetrol S.A.’s Gross and Net Productive Wells by Region
As of December 31, 2018 (number of wells) | ||||||||||||||||
Crude Oil(1) | Natural Gas(2) | |||||||||||||||
Gross | Net(3) | Gross | Net(3) | |||||||||||||
COLOMBIA | ||||||||||||||||
Ecopetrol S.A. | ||||||||||||||||
Central region | 2,244 | 1,767 | 9 | 9 | ||||||||||||
Orinoquía region | 1,086 | 1,077 | 22 | 18 | ||||||||||||
Southern region | 589 | 534 | 13 | 13 | ||||||||||||
Eastern Region | 693 | 693 | - | - | ||||||||||||
Region of Associated Operations | 2,602 | 1,260 | 16 | 7 | ||||||||||||
Total (Ecopetrol S.A.)(4) | 7,214 | 5,331 | 60 | 47 |
3.4.2.1.2Ecopetrol S.A.’s Affiliates and Subsidiaries’ Production Activities in Colombia
Crude Oil Production
The following table sets forth our average daily crude oil production from Hocol and Equion, prior to deducting royalties, for the periods indicated.
Table 13 – Ecopetrol S.A.’s Subsidiaries in Colombia Average Daily Crude Oil Production
For the year ended December 31, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(thousand bpd) | ||||||||||||
Hocol | ||||||||||||
Joint venture operation | 2.3 | 2.3 | 2.6 | |||||||||
Direct operation | 18.4 | 19.4 | 15.4 | |||||||||
Total Hocol | 20.7 | 21.7 | 18.0 | |||||||||
Equion | ||||||||||||
Joint venture operation | – | 0.1 | 0.1 | |||||||||
Direct operation | 9.0 | 10.5 | 12.3 | |||||||||
Total Equion | 9.0 | 10.6 | 12.4 | |||||||||
Production Tests | – | – | – | |||||||||
Total Average Daily Crude Oil Production (Subsidiaries in Colombia) | 29.7 | 32.3 | 30.4 |
The 4.6% decrease in Hocol’s production in 2018, as compared to 2017, was mainly due to result of the natural production decline of our fields.
The 15.1% decrease in Equion’s production in 2018, as compared to 2017, was mainly due to result of the natural production decline of our fields, and the transfer of a part of its participation in the Recetor contract to Ecopetrol.
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, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(thousand boepd)(1) | ||||||||||||
Hocol | ||||||||||||
Joint venture operation | 1.6 | 0.6 | 0.2 | |||||||||
Direct operation | 5.9 | 5.2 | 0.6 | |||||||||
Total Hocol | 7.5 | 5.8 | 0.8 | |||||||||
Equion | ||||||||||||
Joint venture operation | 0.2 | 0.2 | 0.1 | |||||||||
Direct operation | 4.8 | 4.6 | 6.4 | |||||||||
Total Equion | 5.0 | 4.8 | 6.5 | |||||||||
Production Tests | – | – | – | |||||||||
Total Natural Gas Production (Subsidiaries in Colombia) | 12.5 | 10.6 | 7.3 |
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, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(number of wells) | ||||||||||||
Hocol | ||||||||||||
Gross wells owned and operated by Hocol | 12 | 17 | 9 | |||||||||
Gross wells in joint ventures | 2 | – | – | |||||||||
Net wells(1) | 13 | 17 | 9 | |||||||||
Equion | ||||||||||||
Gross wells owned and operated by Equion(2) | – | – | – | |||||||||
Gross wells in joint ventures | – | 1 | 1 | |||||||||
Net wells(1) | – | – | – | |||||||||
Total gross wells owned and operated in Colombia | 12 | 17 | 9 | |||||||||
Total gross wells in joint ventures in Colombia | 2 | 1 | 1 | |||||||||
Total net wells (Subsidiaries in Colombia) | 13 | 17 | 9 |
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, 2018.2020.
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, 2018 | ||||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
(in acres) | ||||||||||||||||
Hocol | 17,845 | 15,930 | 675 | 666 | ||||||||||||
Equion | 16,300 | 4,104 | 54,666 | 12,162 | ||||||||||||
Total (Subsidiaries in Colombia) | 34,145 | 20,034 | 55,341 | 12,828 |
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, 2018.2020.
Table 1720 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Productive Wells(1)(1)(2)
For the year ended December 31, 2018 | 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 | 281 | 241.9 | 20 | 18.5 | 279.0 | 240.0 | 52.0 | 34.0 | ||||||||||||||||||||||||
Equion | 15 | 8 | 15 | 8 | ||||||||||||||||||||||||||||
Equión(5) | - | - | - | - | ||||||||||||||||||||||||||||
Total (Subsidiaries in Colombia) | 296 | 249.9 | 35 | 26.5 | 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. |
3.5.2.2 | Production Activities Outside Colombia |
3.4.2.2 Production Activities Outside Colombia
The Ecopetrol Group’sIn 2020, the subsidiaries’ production outside of Colombia comescame from 100% of the production of Ecopetrol America Inc.LLC, Ecopetrol Permian LLC and 50% of our share of Savia in Peru.Savia. In 2018,2020, the production obtained from these twothree companies was 1721.4 thousand boepd, which represents 2.4% 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, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(thousand bpd) | ||||||||||||
Savia Perú | 3.9 | 3.9 | (1) | 4.1 | ||||||||
Ecopetrol America Inc. | 10.2 | 9.2 | 5.5 | |||||||||
Total average daily crude oil production (International) | 14.1 | 13.1 | 9.6 |
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Thousand bpd) | ||||||||||||
PERÚ | ||||||||||||
Savia Perú(1) | 3.11 | 3.50 | 3.90 | |||||||||
UNITED STATES OF AMERICA | ||||||||||||
Ecopetrol America LLC | 10.41 | 11.40 | 10.20 | |||||||||
Ecopetrol Permian LLC | 3.85 | 0.10 | - | |||||||||
Total average daily crude oil production (International) | 17.37 | 15.00 | 14.10 |
(1) | In |
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, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(thousand boepd) | ||||||||||||
Savia Perú | 1.1 | 1.1 | (1) | 1.3 | ||||||||
Ecopetrol America Inc. | 1.8 | 2.0 | 1.2 | |||||||||
Total average daily natural gas production (International) | 2.9 | 3.1 | 2.5 |
For the year ended December 31, | ||||||||||||||||||||||||
2020 | 2019 | 2018 | ||||||||||||||||||||||
Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | Thousand bpd | mmcfpd | |||||||||||||||||||
PERÚ | ||||||||||||||||||||||||
Savia Perú(1) | 0.91 | 2.44 | 0.90 | 3.99 | 1.10 | 2.90 | ||||||||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||||||||||
Ecopetrol America LLC | 1.78 | 10.15 | 1.80 | 10.26 | 1.80 | 10.30 | ||||||||||||||||||
Ecopetrol Permian LLC | 1.46 | 3.26 | - | - | - | - | ||||||||||||||||||
Total average daily natural gas production (International) | 4.15 | 15.85 | 2.70 | 14.30 | 2.90 | 13.10 |
(1) | In |
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(1))
For the year ended December 31, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(number of wells) | ||||||||||||
Savia Perú | ||||||||||||
Gross wells | - | - | - | |||||||||
Net wells(2) | - | - | - | |||||||||
Ecopetrol America Inc. | - | - | - | |||||||||
Gross wells | 1 | 2 | 3 | |||||||||
Net wells(2) | 0.3 | 0.4 | 0.7 | |||||||||
Total gross wells (International) | 1 | 2 | 3 | |||||||||
Total net wells (International) | 0.3 | 0.4 | 0.7 |
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) | Includes only wells under direct operation by OXY. Non -operated wells are not included because they are not material. |
31
Production Acreage
The following table sets forth our developed and undeveloped gross and net acreage of crude oil and natural gas production outside Colombia for the year ended December 31, 2018.2020.
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, 2018 | ||||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
(in acres) | ||||||||||||||||
Savia Perú | 79,575 | 39,788 | 57,671 | 28,836 | ||||||||||||
Ecopetrol America Inc.(1) | 55,440 | 15,059 | 23,040 | 6,566 | ||||||||||||
Total (International) | 135,015 | 54,847 | 80,711 | 35,402 |
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, 2018.2020.
Table 2226 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Productive Wells(1)(2)
As of December 31, 2018 | 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 | 606 | 303 | 599.0 | 299.5 | ||||||||||||
Ecopetrol America Inc. | 15 | 3.6 | ||||||||||||||
UNITED STATES OF AMERICA | ||||||||||||||||
Ecopetrol America LLC | 16.0 | 3.9 | ||||||||||||||
Ecopetrol Permian LLC(5) | 22.0 | 10.8 | ||||||||||||||
Total (International) | 621 | 306.6 | 637.0 | 314.2 |
3.4.2.3 Marketing of Crude Oil and Natural Gas
(1) | Includes only wells that were drilled and completed. |
(2) | Information in the table above reflects productive wells that directly contribute to hydrocarbons production and therefore excludes wells used for injection, disposal, water abstraction or other similar activities. We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. Natural gas wells are those in which operations are directed only towards production of commercial gas. |
(3) | Net wells correspond to the sum of wells entirely owned by us or our subsidiaries and our ownership percentage of wells owned in joint ventures with our partners. |
(4) | In January 2021 Ecopetrol S.A. divested its 50% equity share in Savia Peru as the result of a competitive bidding process led jointly with its partner KNOC. |
(5) | Includes only wells drilled and completed under direct operation by Occidental Petroleum Corp (OXY). Non-operated wells are not included because they are not material. |
32
3.5.2.3 | Marketing of Crude Oil and Natural Gas |
In 2018,2020, Ecopetrol sold 899.5883 mboed, out of which 400.4425 mboed represented sales of crude oil (44%(48%), 78.587 mboed of natural gas (9%(10%) and 420.6371 mboed of fuels and petrochemicals (47%(42%).
Crude Oil Export Sales
CrudeIn 2020, crude oil export sales in 2018 decreasedincreased by 24 mbopd13 mboed compared to 20172019, mainly due to the substitutiongreater availability of importscrude oil, supported by our sales and marketing strategy in response to lower crude oil runs at Reficarthe refineries, which in turn was primarily due to a decrease in the domestic demand for domestic crudes.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 Asia and Europe.Asia.
The Castilla blend is the main type of crude oil for export sales, with 334 mbopd371 mboed sold during 20182020 (a 84%89% share of ourthe crude oil basket) followed by the Vasconia with 19 mbopd24 mboed (a 5%6% share in ourof the crude oil basket), South blendthe domestic crudes sold by Ecopetrol America LLC with 11 mbopd8 mboed, (a 3%2% share of ourthe crude oil basket), and Vasconia NorteMares blend with 9.4 mbopd7 mboed (a 2% share of ourthe crude oil basket).
Ecopetrol placedplaces its exports in markets that representprovide the best value for its crudes. In 2018,2020, Asia was the main destination, representing 41%49% of crude oil exports, closely followed by the United States with 40% of crude oil exports.43%. The expansion of refining capacity both in the private and state owned companies 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 inof crude oil flows from Colombia to Asia,Asia.
Moreover, volatility in the production of regional producerscompetitors 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 was discounted by US$ 8.5/bl below the ICE Brent price. Our crude basket increasedrealization price decreased by US$15.4/bl 24/Bl year over year due to market conditions stemming from the strengtheffects of the ICE Brent price and our persistent commercial strategy towards markets with higher value.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 ANH from royalties. This oil isNational Hydrocarbons Agency. These crudes are processed in Ecopetrol’s refineries or exported. The purchase price is referenced to export parity based on international market prices, plus a commercial fee. See section Business Overview—Related Party and Intercompany Transactions.
The table below sets forth the volumes of crude oil purchased from our business partners and third parties and volumes of crude oil purchased from the ANH from royalties for the years ended on December 31, 2018, 20172020, 2019 and 2016.2018.
Table 2327 – Ecopetrol Consolidated Crude Oil Purchases
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
(million barrels) | (Million barrels) | |||||||||||||||||||||||
Ecopetrol Corporate Group | ||||||||||||||||||||||||
Crude oil purchased from ANH royalties | 37.6 | 40.3 | 42.9 | 31.0 | 35.4 | 37.6 | ||||||||||||||||||
Crude oil purchased from third parties | 20.7 | 16.7 | 15.5 | 34.0 | 30.0 | 20.7 | ||||||||||||||||||
Crude oil imported from third parties | 14.0 | 24.8 | 22.0 | 5.6 | 9.1 | 14.0 |
33
During 2018,2020, 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.chain and margin capture.
Import of Diluents
In 2018,2020, Ecopetrol decreased the imports of diluent by 1.7% (0.9 mbpd)32% (17 mbod) compared to 2017.2019, due to the use of domestic produced naphtha. Diluent is used to transport our heavy crudes through the pipeline system, and the reduction is due to optimizations in dilution processes within the transformation plan last year.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 1.0% (0.93 mboepd)2% (2.9 mboed) compared to 2017,2019, due to an increasehigher production primarily as a result of Hocol’s acquisition of Chevron’s interest in short term sales to industrial consumers.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, | |||||||||||||||||||||||||||||||
2019 | 2020 | 2021 | 2022 | 2021 | 2022 | 2023 | 2024 | |||||||||||||||||||||||||
(gbtud) | (gbtud) | |||||||||||||||||||||||||||||||
Volume for sales third parties | 526.8 | 549.2 | 499.9 | 323.0 | 503.3 | 483.3 | 420.9 | 311.1 | ||||||||||||||||||||||||
Volume for self-consumption | 140.4 | 175.2 | 185.3 | 194.8 | 188.2 | 169.4 | 160.9 | 157.1 | ||||||||||||||||||||||||
Volume for intercompany sales | 89.4 | 18.5 | 18.5 | 16.8 | ||||||||||||||||||||||||||||
Total Commitments | 667.2 | 724.4 | 685.2 | 517.8 | 780.9 | 671.2 | 600.3 | 485.0 |
Neither Equion nor Savia Peru are included in theThe table above since they do not consolidate within Ecopetrol Group. Data was updatedis based on current contracts of Ecopetrol S.A. and the official report made to the Ministry of Mines and Energy in 2018. During 2017 the Energy2020. 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 Gas Regulatory Commission published a new resolution modifying the existing trading rules in the Colombian natural gas market. See the sectionBusiness Overview—Applicable Laws and Regulations—Regulation of the Natural Gas Market.commercialized after declaring exploratory success.
3.5.3 | Reserves |
The reserves reporting process was conducted in accordance with SEC definitions and rules set forth in Rule 4-10(a) of Regulation S-X and the disclosure guidelines contained in the SEC’s Modernization of Oil and Gas Reporting final rule dated December 31, 2008 and effective as of January 1, 2010.
The estimated reserve amounts presented in this annual report, as of December 31, 2018,2020, 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 (Gulf of Mexico) 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, 2018, 20172020, 2019 and 2016.2018.
Table 2529 – Net Proved Developed Reserves
Net Proved Developed Reserves | Colombia | North America | South America excluding Colombia | Total | ||||||||||||
Net Proved Developed oil reserves in million barrels oil equivalent | ||||||||||||||||
At December 31, 2016 | 710 | 6 | 7 | 723 | ||||||||||||
At December 31, 2017 | 747 | 10 | 6 | 763 | ||||||||||||
At December 31, 2018 | 814 | 13 | 5 | 832 | ||||||||||||
Net Proved Developed NGL reserves in million barrels oil equivalent | ||||||||||||||||
At December 31, 2016 | 55 | - | 1 | 56 | ||||||||||||
At December 31, 2017 | 54.6 | - | 0.8 | 55.4 | ||||||||||||
At December 31, 2018 | 50.5 | - | 0.6 | 51.1 | ||||||||||||
Net Proved Developed gas reserves in billion standard cubic feet | ||||||||||||||||
At December 31, 2016 | 3,114 | 9 | 8 | 3,131 | ||||||||||||
At December 31, 2017 | 3,143 | 10 | 5 | 3,158 | ||||||||||||
At December 31, 2018 | 2,865.5 | 10 | 7 | 2,882 | ||||||||||||
Net Proved Developed oil, NGL and gas reserves in million barrels oil equivalent | ||||||||||||||||
At December 31, 2016 | 1,311 | 8 | 10 | 1,329 | ||||||||||||
At December 31, 2017 | 1,353 | 11 | 8 | 1,372 | ||||||||||||
At December 31, 2018 | 1,368 | 14 | 7 | 1,389 |
Colombia | North America | South America excluding Colombia | Total | |||||||||||||
Net Proved Developed oil reserves in million barrels oil equivalent | ||||||||||||||||
At December 31, 2020(1) | 757.4 | 16.3 | 2.3 | 776.0 | ||||||||||||
At December 31, 2019 | 832.0 | 12.0 | 3.8 | 848.0 | ||||||||||||
At December 31, 2018 | 814.0 | 13.0 | 5.0 | 832.0 | ||||||||||||
Net Proved Developed NGL reserves in million barrels oil equivalent | ||||||||||||||||
At December 31, 2020 | 57.0 | 1.1 | 0.4 | 58.0 | ||||||||||||
At December 31, 2019 | 49.0 | 0.1 | 0.5 | 50.0 | ||||||||||||
At December 31, 2018 | 50.5 | - | 0.6 | 51.1 | ||||||||||||
Net Proved Developed gas reserves in billion standard cubic feet | ||||||||||||||||
At December 31, 2020(2) | 2,617.0 | 15.0 | 4.4 | 2,636.4 | ||||||||||||
At December 31, 2019 | 2,645.0 | 11.0 | 7.0 | 2,662.0 | ||||||||||||
At December 31, 2018 | 2,865.5 | 10.0 | 7.0 | 2,882.5 | ||||||||||||
Net Proved Developed oil, NGL and gas reserves in million barrels oil equivalent | ||||||||||||||||
At December 31, 2020 | 1,273.3 | 20.0 | 3.5 | 1,296.8 | ||||||||||||
At December 31, 2019 | 1,345.0 | 14.0 | 6.0 | 1,365.0 | ||||||||||||
At December 31, 2018 | 1,368.0 | 14.0 | 7.0 | 1,389.0 |
(1) | Oil Reserves included 14 million barrels of Fuel Oil. |
(2) | Gas Reserves included 411 bcf of Fuel Gas. |
Totals may not exactly equal the sum of the individual entries due to rounding. The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
We are required, as are all oil companies undertaking exploratory and production activities in Colombia, to pay a percentage of our production to the Government as royalties. However, the ANH’s Resolution 877 of 2013, Resolution 351 of 2014 and Resolution 640 of 2014 require natural gas royalties to be paid in cash, which means that the determination of the property rights to the quantities of natural gas we produce is based on the total volume produced without deductions on account of royalties. The main producing gas fields are Guajira, Cusiana, Cupiagua, Pauto, Cusiana, Chuchupa Gibraltar, Ballena and Mamey.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 2016, 20172018, 2019 and 20182020 annual reports, we have used our real transportation costs, rather than the regular tariffs set by the Ministry of Mines and Energy.
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The following table summarizes our proved oil, NGL and natural gas reserves, which includes 14 million barrels of fuel oil, 411 billion standard cubic feet of fuel gas within our natural gas results and 429 billion cubic feet of royalties, as of December 31, 2020.
Table 30 – Proved Oil, NGL and Natural Gas Reserves for 2020
Oil (mmb) | NGL (mmb) | Natural Gas (bcf) | Total Oil and Gas (mmboe) | |||||||||||||
PROVED DEVELOPED RESERVES | ||||||||||||||||
Colombia | 757.4 | 56.8 | 2,617.0 | 1,273.3 | ||||||||||||
International | ||||||||||||||||
North America | 16.3 | 1.1 | 15.0 | 20.0 | ||||||||||||
South America(1) | 2.3 | 0.4 | 4.4 | 3.5 | ||||||||||||
TOTAL PROVED DEVELOPED RESERVES | 776.0 | 58.2 | 2,636.4 | 1,296.8 | ||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||
Colombia | 290.5 | 6.1 | 179.9 | 328.2 | ||||||||||||
International | ||||||||||||||||
North America | 105.8 | 21.0 | 105.1 | 145.2 | ||||||||||||
South America(1) | - | - | - | - | ||||||||||||
TOTAL PROVED UNDEVELOPED RESERVES | 396.4 | 27.1 | 285.0 | 473.4 | ||||||||||||
TOTAL PROVED RESERVES | 1,172.4 | 85.3 | 2,921.5 | 1,770.2 |
(1) | The reserves in South America include participation in Savia Peru, where we sold our interest on January 19, 2021. |
Note: Totals may not exactly equal the sum of the individual entries due to rounding. The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 17 million barrels of fuel oil, 381 billion standard cubic feet of fuel gas within our natural gas results and 517 billion cubic feet of royalties, as of December 31, 2019.
Table 31 – Proved Oil, NGL and Natural Gas Reserves for 2019
Oil (mmb) | NGL (mmb) | Natural Gas (bcf) | Total Oil and Gas (mmboe) | |||||||||||||
PROVED DEVELOPED RESERVES | ||||||||||||||||
Colombia | 832.0 | 49.0 | 2,645.0 | 1,345.0 | ||||||||||||
International | ||||||||||||||||
North America | 12.0 | 0.1 | 11.0 | 14.0 | ||||||||||||
South America | 3.8 | 0.5 | 7.0 | 6.0 | ||||||||||||
TOTAL PROVED DEVELOPED RESERVES | 847.8 | 50.0 | 2,662.0 | 1,365.0 | ||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||
Colombia | 306.0 | 28.0 | 111.0 | 353.0 | ||||||||||||
International | ||||||||||||||||
North America | 123.0 | 29.0 | 133.0 | 175.0 | ||||||||||||
South America | - | - | - | - | ||||||||||||
TOTAL PROVED UNDEVELOPED RESERVES | 429.0 | 57.0 | 244.0 | 529.0 | ||||||||||||
TOTAL PROVED RESERVES | 1,277.0 | 107.0 | 2,906.0 | 1,893.0 |
Note: Totals may not exactly equal the sum of the individual entries due to rounding. The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
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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 2632 – 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 |
Note: The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
Reserves Replacement
The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves divided by produced volumes in any given period. The following table presents the changes in reserves in each category relating to the reserve replacement ratio for the years 2018, 2017 and 2016.
Changes in Proved Reserves
Table 2733 – Changes in Proved Reserves
As of December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
Consolidated Company (million barrels oil equivalent) | ||||||||||||||||||||||||
(Mmboe) | ||||||||||||||||||||||||
Revisions of previous estimates | 120.5 | 174 | (54 | ) | (71.5 | ) | 83.0 | 120.5 | ||||||||||||||||
Improved Recovery | 129.1 | 73 | 11 | 113.1 | 94.0 | 129.1 | ||||||||||||||||||
Extensions and discoveries | 57.4 | 44 | 27 | 42.7 | 67.0 | 57.4 | ||||||||||||||||||
Purchases | - | 4 | – | 29.9 | 164.0 | - | ||||||||||||||||||
Sales | (1.0 | ) | - | - | ||||||||||||||||||||
Total reserves additions | 307 | 295 | (16 | ) | 113.2 | 408.0 | 307.0 | |||||||||||||||||
Production | (239 | ) | (234 | ) | (235 | ) | (236.3 | ) | (242.0 | ) | (239.0 | ) | ||||||||||||
Net change in proved reserves | 68 | 61 | (251 | ) | (123.0 | ) | 166.0 | 68.0 |
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Reserves Replacement
The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves divided by produced volumes in any given period. The following table presents the changes in reserves in each category relating to the reserve replacement ratio for the years 2020, 2019 and 2018.
The reserves replacement ratio for 20182020 was 1.29 barrels48% compared to 1.26 barrels169% in 2017. 2019 and 129% in 2018.
The average replacement ratio for the last three years was 0.83 barrels.115%.
Table 2834 – Reserves Replacement Ratio (including purchase(Including Purchases and sales)Sales)
As of December 31, | For the year ended December 31, | ||||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | ||||||||||||||||||||
Annual | 1.29 | 1.26 | (0.07 | ) | 48 | % | 169 | % | 129 | % | |||||||||||||||
Three year average | 0.83 | 0.42 | 0.48 | ||||||||||||||||||||||
Three-year average | 115 | % | 140 | % | 83 | % |
Revisions of Previous Estimates
In 2020, revisions decreased reserves by 71 million boe, mainly as a result of:
(i) | A 215 million boe decrease attributed to economic factors and reevaluated projects. More specifically, we were negatively impacted by the substantial decrease in oil prices, with the ICE Brent crude price being 32% lower in 2020 as compared to 2019, which resulted in the lowering of economic limits in some of our fields and some projects becoming uneconomical under SEC standards. |
(ii) | An offsetting positive 114 million boe increase in reserves related to new projects in the Caño Sur, Quifa, Cusiana, Pauto and Rubiales fields as well as new areas included in the approved five-year development plan for our North American fields. |
(iii) | An offsetting positive 30 million boe increase related to field performance studies and development activities in existing fields. |
In 2019, revisions increased reserves by 83 million boe, mainly as a result of:
(i) | An increase of 33 million boe due to improved reservoir performance in the Rubiales field and continuous development with drilling activities. |
(ii) | An increase of 36 million boe in reserves due to the review of the curve type of new development activities according to updated new wells results in the Caño Sur field and additional gas processing plant capacity to extract NGL in the Cupiagua field. |
(iii) | An increase of 14 million boe in reserves, due to better production performance mainly in the Akacias, Caño Limón and Chichimene fields. |
Nonetheless, due to the decrease in oil price compared to the Brent reference price used in the reserve estimation process at $63 per barrel in 2019 (as compared to $72 per barrel in 2018), the Company removed volumes of total proved reserves in the amount of 19 million boe, which have become uneconomical. This impact was partially offset by improved reservoir performance and new projects in several fields.
In 2018, revisions increased reserves by 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 2020, improved recovery activities increased reserves by 113 million boe. This increase was associated with new proved areas under water flooding in the Chichimene and Castilla fields, and optimization of the gas injection and blowdown strategy of the Cupiagua field.
In 2019, improved recovery increased reserves by 94 million boe. An increase of 25 million boe was associated with new proved areas under water flooding in the Chichimene and Akacias fields. Furthermore, the continued development of water flooding projects at existing wells in the Castilla, Chichimene, Yarigui, La Cira-Infantas fields accounted for a 45 million boe increase. The remaining 26%, or 24 million boe, increase was due primarily to water injection reservoir responses at various fields.
In 2018, improved recovery increased reserves by 129 million boe. The additions were associated with new proved areas under water flooding in the Chichimene, Castilla, La Cira-Infantas, Apiay, Suria, Yarigui, Casabe and Dina Cretaceo fields 86(86 million boe increase.increase). In addition, the new steam injection project at the Teca-Cocorná field accounted for a 19 million boe increase in reserves.
The remaining 19%, or 24 million boe, increase was due primarily to water injection reservoir responses at various fields.
On average, improved recovery has added 112 million boe each year over the last three years.
Extensions and Discoveries
The following table sets forth the change in the Company’s proved reserves attributed to extensions and discoveries in millions of boe for the periods indicated.
Table 35 – Changes in Proved Reserves Attributed to Extensions and Discoveries
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Mmboe) | ||||||||||||
Extensions and discoveries | ||||||||||||
Total change | 42.7 | 67.0 | 57.4 | |||||||||
Proved Undeveloped Reserves Change | 14.6 | 34.0 | 39.9 | |||||||||
Change from unproved to proved developed reserves | 28.0 | 33.0 | 17.5 |
The difference between the change of developed proved reserves and undeveloped proved reserves is related to the drilling of new wells in unproved acreage that led to new proved producing reserves.
The Company’s extensions and discoveries during 2020 amounted to 43 million boe primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Suria, Yarigui and Llanito fields (accounting for 38.5 million boe of the total change) and newly discovered fields Andina and Esox (accounting for 4 million boe of the total change). The Company’s extensions and discoveries during 2019 amounted to 67 million boe primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Quifa, Suria, Tisquirama, Cupiagua Sur, Castilla and Garzas fields (accounting for 55 million boe). The remaining 12 million boe corresponded to smaller changes in 26 fields with variations between 0.01 to 2.1 million boe.
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The Company’s extensions and discoveries during 2018 amounted to 57 million boe primarily due to extensions of proved acreage, which in turn were mainly from activities in new proved areas in the Rubiales, Castilla, Cupiagua, Pauto and Caño Sur fields 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.
Purchases
Starting May 2020, Hocol S.A. took on the position of operator of the Guajira Contract, after the approval of the transaction in which Ecopetrol S.A. through its wholly owned subsidiary, Hocol S.A., acquired 100% of Chevron Petroleum Company’s participation in the contract (comprising the Ballena and Chuchupa fields in Colombia which corresponds to 43% of the total contract). This purchase increased proved reserves by 29.9 million boe.
In 2019, Ecopetrol S.A. through its wholly owned subsidiary, Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC, a company whose economic activity is directed towards the execution of a joint development plan under the joint venture between Ecopetrol and Occidental Petroleum Corp, announced on July 31, 2019, which represented 164 million boe. Through this joint venture, the Company and Occidental Petroleum Corp are pursuing development of unconventional reservoirs in approximately 97,000 acres of the Permian Basin in Texas. For the acquisition and closing of the transaction, Ecopetrol S.A. made an initial payment of approximately US $876.5 million dollars. As of December 31, 2020, Ecopetrol had paid a total of US$ 121.8 million of the initial US$ 750 million carry obligation.
There were no purchases or acquisitions in 2018.
Sales
Pursuant to a public auction process carried out by Ecopetrol and Hocol in December 2020, an offer was received from Cordillera Resources SAS, Nikoil Energy Corp and Petroleum Blending International for 100% of our working interest in the La Punta and Santo-Domingo fields, which was declared the winning offer. We are now pending approval of such sale from the ANH, a process that typically takes 18 months. Based on that timing, we do not expect the formal approval to be received until July 2022.
Development of reserves
As of December 31, 2020, our total proved undeveloped oil and gas reserves amounted to 473 million boe, 69% of which is related to development activities at the Rubiales, Castilla and Chichimene fields in Colombia, among others, and 31% of which is related to development activities in North American fields.
Ecopetrol’s year-end development plans are consistent with SEC guidelines for the development of proved undeveloped reserves within five years. The development plan of Rubiales Field goes beyond the five years due to the water disposal restrictions in the facilities. The drilling of two wells in the United States Gulf of Mexico and one well onshore in Colombia also goes beyond five years due to drilling schedule. These wells are part of the ongoing development projects and all remaining development investments for the latter three wells will be completed within six years from their initial disclosure. These exemptions were reviewed and approved by the external certification agent.
As of December 31, 2019, our total proved undeveloped oil and gas reserves amounted to 529 million boe, 46% of which is related to development activities in the Rubiales, Castilla, Caño Sur Chichimene, Teca, Akacias and Pauto fields and 31% of which is related to development of unconventional reservoirs of the U.S. Permian Basin in Texas. The remaining 23% comes from activities at several other fields.
In 2019, Ecopetrol’s year-end development plans were consistent with SEC guidelines for the development of proved undeveloped reserves within five years. The development plan of Rubiales Field went beyond the five years due to the limitations in water handling in the facilities. These exemptions were reviewed and approved by the external certification agent.
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As of December 31, 2018, our total proved undeveloped oil and gas reserves amounted to 338 million boe, 21% of which is related to new drilling activities in the Rubiales field, 41% is related to development activities in the Castilla, Caño Sur, Chichimene, Quifa, Cupiagua and Yarigui fields and 22% of which is related to the new development activities in the Teca, Pauto, Bonanza and Ryberg fields. The remaining 16% comes from activities at several other fields.
In 2018, the development plan of Rubiales and Caño Sur Field went beyond 5 years due to the limitations in water handling in the facilities and Ryberg offshore field. These exemptions were reviewed by the external certification agent.
Our proved undeveloped reserves represent 20%27% of our total proved reserves.
The Ecopetrol’s year-end development plans are consistent with SEC guidelines for the developmentreserves as of proved undeveloped reserves within five years.December 31, 2020, 28% as of December 31, 2019, and 20% as of December 31, 2018.
The following table reflects the developed and undeveloped proved reserves estimates through the past three fiscal years.
Table 2936 – Developed and Undeveloped Proved Reserves
Proved Reserves as of December 31, | Oil | NGL | Gas | Total | ||||||||||||||||||||||||||||
Mmbls | Mmbls | Bcf | Mmboe | Oil (mmb) | NGL (mmb) | Natural Gas (bcf) | Total Oil and Gas (mmboe) | |||||||||||||||||||||||||
2018 proved reserves | ||||||||||||||||||||||||||||||||
2020 Proved Reserves | ||||||||||||||||||||||||||||||||
Developed | 832 | 51 | 2,882 | 1,389 | 776 | 58 | 2,636 | 1,297 | ||||||||||||||||||||||||
Undeveloped | 295 | 23 | 119 | 338 | 396 | 27 | 285 | 473 | ||||||||||||||||||||||||
2017 proved reserves | ||||||||||||||||||||||||||||||||
2019 Proved Reserves | ||||||||||||||||||||||||||||||||
Developed | 763 | 55 | 3,158 | 1,372 | 848 | 50 | 2,662 | 1,365 | ||||||||||||||||||||||||
Undeveloped | 251 | 19 | 96 | 287 | 429 | 57 | 244 | 529 | ||||||||||||||||||||||||
2016 proved reserves | ||||||||||||||||||||||||||||||||
2018 Proved Reserves | ||||||||||||||||||||||||||||||||
Developed | 723 | 56 | 3,131 | 1,329 | 832 | 51 | 2,882 | 1,389 | ||||||||||||||||||||||||
Undeveloped | 241 | 13 | 87 | 269 | 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,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.
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Changes in Undeveloped Proved Reserves
The following table reflects the main changes in undeveloped proved reserves duringas of December 31, 2020, 2019 and 2018.
Table 3037 – Changes in Undeveloped Proved Reserves in 2018
For the year ended December 31, | ||||||||||||
2020 | 2019 | 2018 | ||||||||||
(Mmboe) | ||||||||||||
Consolidated companies | ||||||||||||
Revisions of previous estimates | (46.3 | ) | 43.0 | 28.4 | ||||||||
Improved Recovery | 45.9 | 40.0 | 67.1 | |||||||||
Extensions and discoveries | 14.6 | 34.0 | 39.9 | |||||||||
Purchases | - | 163.0 | - | |||||||||
Proved undeveloped converted to proved developed | (69.4 | ) | (89.0 | ) | (83.7 | ) | ||||||
Net change in unproved reserves | (55.2 | ) | 190.0 | 51.7 |
Note: The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent. Totals may not exactly equal the sum of the individual entries due to rounding.
ReserveUndeveloped Proved converted to Developed Proved: Of the total amount of undeveloped proved reserves that Ecopetrol had at the end of 2019 (529 million boe), we converted approximately 69 million boe, or 13%, to developed proved reserves during 2020. Approximately 86% of the total conversion was primarily associated with the development of crude oil and gas projects in Ecopetrol S.A Fields as Castilla, Rubiales and Cupiagua fields, among others and 14% was associated with development execution in fields where our subsidiaries are operating.
All the explanations that were included in Changes in Proved Reserves apply for this section.
Reserves Process
Ecopetrol’s reserves process is coordinated by Fidel Antonio Delgado Loría the Corporate Resources and Reserves Manager, 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, Netherland, Sewell & Associates, Inc., Ryder Scott Company, and Sproule International Limited, and DeGolyer and MacNaughton) in compliance with the definitions of the Society of Petroleum Engineers and the applicable SEC rules. According to our corporate policy, we report the reserves values obtained from the external engineers, even if they are lower than our expected reserves.
The reserves estimation process ends when the Corporate Reserves Manager consolidates the results and together, with the Development Vice-President and the Upstream Chief Financial Officer, presents the outcome to the Reserves Committee, which comprises the Ecopetrol Group’s CEO, the Ecopetrol’s 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 and DeGolyer and MacNaughton have estimated and certified Ecopetrol’s proved reserves as of December 31, 2018.2020. These external engineers estimated 99% of our estimated net proved reserves.reserves for the year ended December 31, 2020, 2019 and 2018. The reserves reports of the external engineers are included as exhibits to this annual report.
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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, with respect to degradation, and thus, the estimates should not be interpreted as being exact amounts. However, the technology used to estimate reserves is considered reliable. 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, 20162018 through 2018,2020, and the changes therein.
Table 3138 – 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, 2016 | 1,577 | 11 | 10 | 1,598 | ||||||||||||||||||||||||||||
Consolidated Companies | Net proved oil, NGL and gas reserves in mmboe | |||||||||||||||||||||||||||||||
At December 31, 2018 | 1,695.0 | 25.0 | 7.2 | 1,727.2 | ||||||||||||||||||||||||||||
Revisions | 170 | 4.6 | (0.3 | ) | 174.3 | 78.4 | 4.3 | 0.2 | 83.0 | |||||||||||||||||||||||
Improved Recovery | 73 | - | - | 73 | 94.3 | - | - | 94.0 | ||||||||||||||||||||||||
Extensions and discoveries | 44 | - | - | 44 | ||||||||||||||||||||||||||||
Extensions and Discoveries | 66.0 | 0.7 | - | 67.0 | ||||||||||||||||||||||||||||
Purchases | - | 4 | - | 4 | - | 164.0 | - | 164.0 | ||||||||||||||||||||||||
Production | (229 | ) | (3.6 | ) | (1.5 | ) | (234.1 | ) | (236.0 | ) | (4.2 | ) | (1.4 | ) | (242.0 | ) | ||||||||||||||||
At December 31, 2017 | 1,635 | 16 | 8.2 | 1,659.2 | ||||||||||||||||||||||||||||
At December 31, 2019 | 1,698.0 | 189.7 | 5.6 | 1,893.0 | ||||||||||||||||||||||||||||
Revisions | 114 | 5.8 | 1 | 120.8 | (49.8 | ) | (20.8 | ) | (0.9 | ) | (71.5 | ) | ||||||||||||||||||||
Improved Recovery | 129 | - | - | 129 | 113.1 | - | - | 113.1 | ||||||||||||||||||||||||
Extensions and discoveries | 50 | 7 | - | 57 | ||||||||||||||||||||||||||||
Extensions and Discoveries | 40.8 | 1.8 | - | 42.7 | ||||||||||||||||||||||||||||
Purchases | 29.9 | - | - | 29.9 | ||||||||||||||||||||||||||||
Sales | (1.0 | ) | - | - | (1.0 | ) | ||||||||||||||||||||||||||
Production | (233 | ) | (3.8 | ) | (2 | ) | (238.8 | ) | (229.6 | ) | (5.6 | ) | (1.2 | ) | (236.3 | ) | ||||||||||||||||
At December 31, 2018 | 1,695 | 25 | 7.2 | 1,727.2 | ||||||||||||||||||||||||||||
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—Trend Analysis and Sensitivity Analysis andRisk Review—Risk FactorsFactors..
3.4.4 Joint Venture and Other Contractual Arrangements
We conduct our exploration and production business through a variety of types of contractual arrangements with the Colombian government or with third parties. Below is a general description of each typethe main types of contractual arrangementarrangements to which we were a party as of December 31, 2018:2020.
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 to such incremental production contract in the proportions established by such contract.
The initial phase of an incremental production contract has a term of up to 3 years, in which the contractual partner executes an initial work program approved by Ecopetrol S.A. in order to gain the right (but not the obligation) to continue with the second phase. If Ecopetrol’s partner decides to continue with the project for the second phase (the complementary phase), it must inform Ecopetrol S.A. in writing no later than 90 days prior to the termination date of the initial phase and deliver a proposed development plan for each covered field. The second phase is the production phase and has a maximum term of 22 years minus the length of the initial phase.
Incremental production contracts provide for an executive committee that is responsible for taking all decisions in order to approve, control and supervise all operations that take place during the duration of the contract. These contracts also provide for a steering committee, which is responsible for the supervision of the execution of the work programs, the annual budget and other items.
Risk Production Contract for Discovered Undeveloped and Inactive Fields (First Round 2003)
We have entered into risk production contracts for discovered undeveloped fields to promote exploration by private companies of both undeveloped and inactive fields. Under these contracts, the contracting party assumes all costs and expenses for the development and operation of a field in exchange for a percentage interest in the field’s production as specified in the contract. This type of contract has a ten-year term calculated from its date of execution: one year for the evaluation period and a maximum of nine years for the development period. Some of these contracts have subsequently been extended beyond their original term.
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 Areascontracted 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) and its Contracts
The National Hydrocarbon Agency (“ANH”)ANH was created by Decree Law 1760 of 2003 and was given the authority to administer all national hydrocarbon reserves under contracts executed beginning on January 1, 2004. Decree Law 1760 of 2003 states, “The Empresa Colombiana de Petróleos, Ecopetrol, is split, its organic structure is modified, and the Agencia Nacional de Hidrocarburos and the Sociedad Promotora de Energía de Colombia S.A. are created.” Prior to January 1, 2004, Ecopetrol S.A. had the authority to contract with third parties for the exploration and production of new areas.
The creation of the ANH did not modify the rights or obligations of Ecopetrol or other parties with respect to contracts in existence before January 1, 2004 when the ANH was created and therefore Ecopetrol retains the authority to execute agreements with respect to all areas that it held prior to that date.
Below, we include a brief description of each type of contract that we have entered into with the ANH:
Technical Evaluation Agreement
This type of contract grants the contractor the right to develop technical evaluation operations with operational autonomy at its own cost and risk, seeking to appraise the hydrocarbon potential, with the purpose of identifying the zones of prospective interest in the area by means of the execution of an exploratory program. The contractor has the option to request the conversion of a technical evaluation agreement (“Technical(Technical Evaluation Agreement”Agreement or “TEA”)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:
when the international oil prices rise beyond a specified price (high price fee), above which the ANH has a right to participate in a share of the increased revenues generated, or |
in the case of recognition of production rights in an extended contractual |
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) as well as the surface fee based on the hectares of the assigned area of the contract (both with and the superficiary canon.without production).
E&P contracts have twothree 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 (ii)(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)
At the timeDecree Law 1760 of termination or extension of any association contract executed by Ecopetrol S.A. before December 31, 2003, established that the rights over the production area and over the movable and immovable assets thereinof: (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 articleArticle 2 of Decree 2288 of 2004, which regulates Decree Law 1760 of 2003, Ecopetrol S.A. must execute an agreement with the ANH to regulate the exploration and exploitation terms and conditions of the relevant area, which was previously subject to an association contract.
Decree 2288 of 2004 also established that Ecopetrol S.A. would have to execute agreements with ANH covering fields directly operated by Ecopetrol S.A. Under these agreements ANH recognizes the exclusive right of Ecopetrol S.A. to explore and exploit the hydrocarbons property of the Nation that are obtained in the areas they cover, until resource depletion or until Ecopetrol S.A. returns the area to the Nation through the ANH.
These agreements also provide the conditions under which Ecopetrol S.A. is able to assign, partially or completely, its rights and duties thereunder to third parties.
3.5 Transportation and Logistics
3.6 | Transportation and Logistics |
3.5.1 Transportation Activities
3.6.1 | Transportation Activities |
The transportation and logistics segment includes the transportation of crude oil, motor fuels, fuel oil and other refined products including diesel, jet and biofuels. We conduct most of these activities through our wholly owned subsidiary Cenit and its subsidiaries.
The map below shows the locations of the main transportation networks owned by our business partners and us.
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Graph 5 – Map of Oil Pipelines
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Graph 6 – Map of MultipurposeMulti-purpose Pipeline
The table below sets forth the volumes of crude oil and refined products transported through the crude oil pipelines and multipurposemulti-purpose pipelines owned by us.
Table 3239 – Volumes of Crude Oil and Refined Products Transported
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
(thousand bpd) | (thousand bpd) | |||||||||||||||||||||||
Crude oil transport(1) | 836.2 | 823.3 | 864.7 | 785.6 | 877.7 | 836.2 | ||||||||||||||||||
Refined products transport(2) | 273.4 | 268.2 | 262.4 | 231.5 | 275.3 | 273.4 | ||||||||||||||||||
Total | 1,109.6 | 1,091.5 | 1,127.1 | 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 affiliates increasedits subsidiaries decreased by 10.5% in 2018 by 1.6%2020 compared to the previous year. This increasedecrease was mainly the result of a higher volume of Castilla Norte(i) lower production levels, primarily due to low crude oil coming from the Barrancabermeja refinery through the Ayacucho-Coveñas 16”/24” systems. Additionally, we experienced an increaseprices in the volume of Castillainternational markets (ii) a decrease in crude oil demand, primarily due to the lockdowns instituted around the world in response to the COVID-19 pandemic, which in turn resulted in lower transported throughvolumes to the Llanos node, which increased the proportion of that crude oil in the systems that reach Coveñas.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 75.7%82.3% belonged to Ecopetrol’s corporate group.the Ecopetrol Group.
The volume of refined products transported by Cenit increaseddecreased by 1.9%15.9% in 20182020 compared to the previous year, mainly due to growththe impact caused by the different sanitary measures taken by the Colombian government to control the spread of local fuel demand.COVID-19. More specifically, measures such as lockdowns and mobility restrictions that led to a decrease in demand for refined products and hence reduced wholesalers’ needs to transport such products through Cenit’s pipelines. Of the total volume of refined products transported inby multi-purpose pipelines during the year, 33%in 2020, 35.7% belonged to Ecopetrol’s corporate group.the Ecopetrol Group.
Transportation Capacity
During 2018, due to the calculation of our service factor (which determines the transportation capacity that can be offered), we decreased the capacity of our primary and secondary oil and product pipelines and loading facilities. Our service factor is calculated on a monthly basis and may vary from time to time, as it considers operative and technical effects (whether scheduled or unscheduled) within a certain period of time. Our main crude oil pipeline systems’ operating capacity decreased from 1,500,000 bpd1,486 kbd in 20172019 to 1,497,000 bpd1,469 kbd in 2018.2020 primarily due to scheduled maintenance. Our main refined productsmulti-purpose pipeline transportation capacity decreasedincreased from 518.6 thousand bpd511 kbd in 20172019 to 510 thousand bpd519 kbd in 2018.2020.
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).
3.6.1.1 | Pipelines |
As of December 31, 2018,2020, we, directly or indirectly with private partners, own, operate and maintain an extensive network of crude oil and refined productsmulti-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, 2018,2020, our network of crude oil and multipurposemulti-purpose pipelines was approximately 9,0719,127 kilometers in length. The transportation network consists of approximately 5,3625,387 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 3,7093,739 kilometers of multipurposemulti-purpose pipelines for transportation of refined products from the Barrancabermeja refinery and from ReficarCartagena refineries to major distribution points. Out of the 5,3625,378 kilometers of crude oil pipelines, owned by us, 3,1503,175 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, 2018.2020.
Table 3340 – 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 | % | |||||||||||||||||||||||||||||
Oleoducto Central – Ocensa(1) | 848 | 745 | Crude Oil | Cupiagua | Coveñas | 72.65 | % | |||||||||||||||||||||||||||||
Oleoducto de los Llanos (ODL) | 260 | 314 | (2) | Crude Oil | East fields | Monterrey Cusiana | 65.00 | % | 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, 20182020, we owned 7375 stations, 3941 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, 2018,2020, we had a nominal storage capacity associated with the transportation network of 17.716.7 million barrels of crude oil and 4.94.7 million barrels of refined products. We do not own any tankers.
The Transportation and Logistics segment has a maintenance operating model with the aim of unifying criteria for planning and execution among the companies of the segment.
Pipeline Projects
San Fernando – Monterrey
The San Fernando – the Monterrey project’s initialproject objectives includedand 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 scope of the project includesforesees the construction of a new 30” 119-km crude oil pipeline, a new pumping station to include reception, storage and dilution facilities, the conversion of the existing pipeline of 10” between the Castilla II plant and the Apiay station, and the construction of a new 10” pipeline between Chichimene and San Fernando fields in order to transport diluent (naphtha) from the Apiay station to the San Fernando plant.
In 2018, the project completed the maximum pumping test, in accordance with the operational system parameter and owner’s requirements; as a result, the main functional services of the project were validated. The construction, startup phase and commissioning of all systems were completed in January 2018. The system is able to transport crude oil at 750 cSt between the San Fernando and Apiay stations. During 2019, 17 kms of the 30” oil pipeline infrastructure designed to bypass the Apiay station were under construction. The project was commissioned in April 2020. The commissioning of this project resulted in the reduction of 13,430 tons of CO2 emissions for the year and it reduced our energy and drag reducing agent (DRA) consumption by approximately 30%.
Oleoducto al Pacifico SASCoveñas - Cartagena
The objective of the Coveñas - Cartagena project is to increase this system’s reliability, capacity, and pipeline infrastructure. To date, this pipeline has a nominal capacity of 135 kbd and feeds the Cartagena refinery with national crudes. As the demand for national crudes from the Cartagena refinery continued to increase, Cenit identified a need to expand this system. In May 2020, Cenit approved the project to increase the system’s nominal capacity by 20 kbd to 155 kbd. The project is currently under construction and it is expected to be in operation by November 2021.
Replacement of Tanker Loading Unit TLU - Coveñas
In 2019, Ocensa invested US$ 32.8 million in offshore infrastructure as a part of the investment plan signed with the Infrastructure National Agency (ANI), which allows Ocensa to continue operating in a public area of the Morrosquillo Gulf, loading tankers with a capacity of up to 2 million barrels of crude oil. Investments during 2019 consisted of the following: the acquisition of a new, more efficient CALM Turret Buoy and PLEM (Pipeline End Manifold), which will improve the loading times of the tankers; the acquisition of two fiber optic systems, one of which communicates the TLU-2 with land and the other monitors the deformations of the submarine pipeline caused by sea currents; the maintenance of a string of floating hoses; the improvement of the inland transport and handling system; and the completion of integrity works such as inspections of the underwater pipeline, which lead to the repair of four welded joins of 42” and the stabilization of the last 72 meters of the seabed of the offshore pipeline.
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In 2020, Ocensa invested US$ 9.1 million in offshore infrastructure according to an updated investment plan signed with the ANI on December 4, 2019. The new CALM Turret buoy and PLEM are in Colombia and are in the preparation phase with integration tests currently taking place prior to the replacement of the TLU system. The installation of two fiber optic systems was successfully completed.
The maintenance of floating marine hoses and the integrity works of the subsea pipeline was performed according to the plan.
Ocensa Segment 3 Connection to CENIT Tanks in Coveñas
Seeking operational efficiencies for the Ocensa terminal in Coveñas, the Segment 3 Connection Project was developed. This connection consists of enabling direct deliveries from the entrance of the Ocensa pipeline to the tank system of the CENIT station in Coveñas. Previously, crude oil was received in Ocensa’s tanks in Coveñas and then transferred to CENIT’s tanks. The operation of this connection is governed by an agreement between CENIT and Ocensa, which defines the rate and operating conditions that should be in place with the project expected to result in additional income for Ocensa.
In 2019, the engineering for the project was completed and the execution phase was approved.
In 2020, due to the impact of the COVID-19 pandemic in the oil and gas industry, construction was postponed until October 2020, with construction, pre-commissioning and commissioning activities completed in December 2020. The tests and entry into service of the system were undertaken in January 2021 and the project is currently fully operational.
Vasconia Energy Recovery (RECVA)
Given that Vasconia station operates 24 hours a day, an opportunity was identified to recover energy from the uncertainties aroundsystem, converting hydraulic energy (flow and pressure) into electrical energy through the future resultsinstallation of a hydraulic power recovery turbine (HPRT). In 2019, the exploration and production activities in ColombiaHPRT was purchased, manufacturing was completed, and the current expected return ofengineering development was concluded.
In May 2020, the investment,HPRT was received on site, and during Ocensa’s scheduled plant shutdown in December 2017November 2020, the parties engagedturbine connection points were installed in the Oleoducto al Pacifico suspended the project. Based on our current view, this decision has had no impact on the oil industry in Colombiaexisting process lines and can be reconsidered20" valves were installed in the eventhigh- and low-pressure line. The project is expected to be commissioned at the transportation system may be necessary.end of June 2021.
Replacement of El Porvenir Station Pumping Units
During 2018, Ocensa began to replace five pumping units with internal combustion engines with electrical energy engines. The goal of this project is to reduce the level of greenhouse gas emissions and noise pollution, thereby having a positive effect on the environment and potentially reduce operation and maintenance costs.
Adaptation of Cusiana Truck Unloading Facility
The Cusiana truck unloading facilities enables exploration and production companies in blocks or areas not connected to the network to access Ocensa pipeline.
During 2018 Ocensa adapted its facilities to Colombia’s new crude oil quality basket and increased capacity up to 81 thousand bpd by means of the implementation of in-line dilution facilities. As a result, shippers can now unload heavy crudes and blend them with light crudes or refined diluents in order to maximize the value of the crude oil.
3.5.1.2 Export and Import Facilities
We currently have concessions granted by the Colombian Government for four export/import docks for crude oil and refined products: Coveñas, Tumaco, Pozos Colorados and Cartagena. Our export capacity reached 1.241.87 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 0.250.14 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 11.69.58 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 5.61.1 million barrels.
3.5.2 Other Transportation Facilities
3.6.2 | Other Transportation Facilities |
We have entered into transportation agreements with tanker truck and barge companies in order to transport crude oil from locations that do not have pipeline connections to refineries and export facilities. The volume of refined products that cannot be transported by pipelines or tanker trucks because of capacity limitation is transported by barges. During 2018, 27.92020, 18.4 million barrels of crude oil and refined products were transported by tanker trucks, and 7.25.7 million barrels of crude oil and refined products were transported by barges, particularly using the Magdalena River, connecting Barrancabermeja with Barranquilla and Cartagena.
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3.6.3 | Marketing of Transportation Services |
Cenit and its subsidiaries’ main line of business is the crude oil pipeline transport (75%(76.9% of revenues), followed by the refined products pipeline transport (16%(14.26% of revenues) and ports and related services (6%(4.25% of revenues). Both crude and refined product pipeline transport are regulated activities; crude oil pipeline transport services are regulated by the Ministry of Mines and Energy, while refined product pipeline transport services are regulated by the Comisión de Regulación de Energía y Gas (CREG).
Transportation contracts of crude oil may take several forms: ship or pay (payment for the availability of a fixed capacity in the system), ship and pay (payment for volumes actually transported) or spot.spot contracts. The main users for the crude oil transportation business are Ecopetrol S.A., Frontera Energy, Trafigura, Mansarovar, Metapetroleum and Gran Tierra, who collectively represented 93%74.94% of this business segment’s revenues in 2018.2020. Transportation services for crude oil provided to Ecopetrol S.A. represented 57%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%44.92% of refined products pipeline transport revenues in 2018, principally2020, mainly due to the transport of naphtha, diesel, and gasoline. Cenit also has 1431 other fuel wholesalers’ customers for whom it transports refined products. The most significant among them are OrganizacionOrganización Terpel, ExxonMobil,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 (6%(4.25% in 2018)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”)(Frontera), Canacol Energy Colombia S.A.S. (“Canacol”)(Canacol) and Vetra Exploración y Producción Colombia S.A.S. (“Vetra”(Vetra and, together with Frontera and Canacol, the “Carriers”)Carriers) sent letters to Oleoducto Bicentenario de Colombia S.A.S. (“Bicentenario”)(Bicentenario) alleging theythere were early termination rights under the Ship-or-Pay Transport Agreements entered by each of them and Bicentenario in 2012 (the “Transport Agreements”)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 fullfillfulfill 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 28,2019,28, 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.
AsOn June 14, 2019, and June 26, 2019, Bicentenario filed arbitration claims against Vetra and Canacol, respectively, in accordance with the arbitration clause of the date of these financial statements, Bicentenario continues evaluating its options under the Transport Agreements and the ShareholdersTransportation Agreement (Acuerdo Marco de Inversión) in order to guarantee compliance and claim any compensation, indemnification or other restitution deriving from the alleged early termination of said agreementsagreements.
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As part of the litigation strategy of Bicentenario, the above-mentioned claims were withdrawn, and any other contractual breaches by the Carriers.new claims were filed, as explained below:
On November 12, 2019, Bicentenario filed an arbitration claim against Frontera, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 119448), in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).
On December 10, 2019, Bicentenario filed an arbitration claim against Vetra, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120089) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).
On December 26, 2019, Bicentenario filed an arbitration claim against Canacol, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120179) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of the Ship or Pay term (2024).
On December 3, 2019, Bicentenario also filed an arbitration claim against its shareholders Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp., Canacol and Vetra under clause 23(d) of the Acuerdo Marco de Inversión before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 119872) contending that since Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp. Canacol and Vetra did not perform the actions requested by Bicentenario necessary to support the indebtedness of the Bicentenario Project, they are in breach of the Acuerdo Marco de Inversión and therefore must compensate and indemnify Bicentenario due to their unlawful conduct. This arbitration claim was withdrawn by Bicentenario on October 22, 2020, in order to present its claims on the arbitration described in the following paragraph.
On December 3, 2019, Frontera, Pacific OBC Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp. filed an international arbitration request against Bicentenario and Cenit under Commerce (Case No. 120488) to resolve the disputes between the parties concerning: (i) the alleged dividends due by Bicentenario, (ii) the alleged abuse of Cenit as the majority shareholder of Bicentenario, (iii) the termination of the Transportation Agreements and (iv) the tariffs dispute with Cenit.
On January 10, 2020, Bicentenario filed an arbitration claim against Canacol under the storage agreement (contrato de almacenamiento terminal coveñas) before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120386) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the storage agreement up to the end of the Ship or Pay term (2024). See the section Business Overview—Marketing of Transportation Services—Bicentenario, CENIT and Frontera Settlement Agreement.
Cenit Transporte y Logística de Hidrocarburos S.A.S.S.A.S.
DuringIn July 2018, the carriers Frontera, Vetra and Canacol (“carriers”)(carriers) sent notifications to Cenit Transporte y Logística de Hidrocarburos SAS (“Cenit”)(Cenit) alleging they were exercising their early termination right under the Ship-or-Pay Crude Oil Transport Agreements (SoP agreements) entered among each of them and Cenit for the transportation of crude oil through the Caño Limón – Coveñas pipeline (owned by Cenit).
In response to the alleged termination of SoP Agreements, CENIT issued letters stating its position and that the alleged event which would have given the carriers early termination rights had not occurred as provided for in Clause 13.3 and other clauses of the aforementioned SoP agreements. In the same letters, CENIT stated that it would continue invoicing and charging for the transport services as stipulated in the SoP agreements, since they remain in force, and therefore, Carriers must fulfill their contractual obligations.
In November 2018, CENIT filed an arbitration demandclaim against Frontera Energy Group pleadgingclaiming that SoP Agreements are in full force and effect and that Frontera is obliged to comply itswith their terms and conditions and, therefore, is obliged to pay transportation tariffs as agreed in the SoP agreements.conditions. In similar terms, an arbitration demand wasclaims were also filed against Vetra and Canacol in March and June 2019, respectively. See the same will occur against Canacol.
section Business Overview—Marketing of Transportation Services—Bicentenario, CENIT and Frontera Settlement Agreement.
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3.6 RefiningBicentenario, CENIT and PetrochemicalsFrontera Settlement Agreement
On November 17, 2020, CENIT and Frontera reached an agreement, for the joint filing of a petition for a binding settlement which, upon completion and approval by the competent Colombian court, will resolve all the disputes pending among them, related to the Caño Limón – Coveñas pipeline, and will terminate all the pending arbitration proceedings related to such disputes. This transaction eliminates any uncertainty related to the potential outcomes of the disputes, thus protecting the interests of all the parties and those of their stakeholders and create new business opportunities for the parties involved. The settlement arrangement includes a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for the Bicentenario and Caño Limón – Coveñas pipelines. Frontera will also enter into new transportation contracts with CENIT and Bicentenario. The new ship or pay commitment is projected to be approximately 3,900 bbls/day, based on the current oil price, for a term of five years subject to adjustments, at a current rate of US$ 11.5/bl. Frontera will not have to make payments for oil it may have to ship through alternate pipelines. These contracts will allow CENIT and Bicentenario to obtain payment of certain amounts included in the settlement, during the term of the contracts. Additionally, as part of the agreement Frontera will transfer to Cenit its 43.03% of the outstanding shares of Bicentenario, and will transfer to Bicentenario its participation in the Bicentenario pipeline line fill. The arrangement is conditional upon certain regulatory approvals, including approval of the settlement arrangement as a conciliation under Colombian law, which requires an opinion from the Attorney General’s Office (Procuraduría General de la Nación), which was issued on March 24, 2021, and approval of the Administrative Tribunal of Cundinamarca. Once all approvals are obtained and the parties perform all their obligations under the agreement, the Ecopetrol Group’s stake in Bicentenario will be 100%. As of the date of this annual report, the final approval by the Administrative Tribunal of Cundinamarca was pending.
Bicentenario, Cenit and Canacol Settlement Agreement
3.6.1On October 30, 2020, Cenit and Canacol reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for the Caño Limón – Coveñas pipelines. On November 18, 2020, the competent arbitration tribunal approved the settlement agreement entered into by Cenit and Canacol, according to which Canacol was obliged to transfer all its outstanding shares in Bicentenario to Cenit. Additionally, as part of the settlement, Canacol entered into new transportation contracts with Cenit. These contracts will allow Cenit to obtain payment of certain amounts included in the settlement, during the term of the contracts. Furthermore, on March 8, 2021, Bicentenario and Canacol reached an agreement to settle all their aforementioned disputes. The agreement established a formula that seeks to end all contractual obligation disputes between the parties and settle all the outstanding obligations between the companies. As of the date of this annual report, Refiningapproval of the settlement agreement between Bicentenario and Canacol is still pending.
Bicentenario, Cenit and Vetra Settlement Agreement
On November 23, 2020, Cenit and Vetra reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for Caño Limón – Coveñas pipelines. On February 18, 2021, the competent arbitration tribunal approved the settlement agreement entered into by Cenit and Vetra, according to which Vetra is obliged to transfer all its outstanding shares in Bicentenario to Cenit and to make a cash payment for the remaining balance of the amounts included in the settlement. Furthermore, on January 13, 2021, Bicentenario and Vetra reached an agreement to settle all their aforementioned disputes. The agreement established a formula that seeks to end all contractual obligations between the parties and settle all the outstanding obligations between the companies. As of the date of this annual report, approval of the settlement agreement between Bicentenario and Vetra is still pending.
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3.7 | Refining and Petrochemicals |
3.7.1 | Refining |
Our main refineries are the Barrancabermeja refinery, which Ecopetrol S.A. directly owns and operates, and a refinery in the Free Trade Zone in Cartagena owned by Reficar, a wholly owned subsidiary of Ecopetrol S.A. Ecopetrol S.A. also owns, who operates this refinery 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 34 –Average41 – Average Daily Installed and Actual Refinery Capacity
For the year ended December 31, | ||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2016 | ||||||||||||||||||||||||||||||||||
Capacity | Through- put | % Use | Capacity | Through- put | % Use | Capacity | Through- put | % Use | ||||||||||||||||||||||||||||
(bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (bpd) | ||||||||||||||||||||||||||||
Barrancabermeja | 250,000 | 221,946 | 89 | % | 250,000 | 209,838 | 84 | % | 250,000 | 213,091 | 85 | % | ||||||||||||||||||||||||
Reficar(1) | 150,000 | 151,331 | 101 | % | 150,000 | 135,700 | 90 | % | 150,000 | 117,188 | 78 | % | ||||||||||||||||||||||||
Apiay(2) | 2,500 | 939 | 38 | % | 2,500 | 997 | 40 | % | 2,500 | 1,382 | 55 | % | ||||||||||||||||||||||||
Orito(2) | 2,300 | (3) | 1,228 | 53 | % | 2,500 | 948 | 38 | % | 2,500 | 1,090 | 44 | % | |||||||||||||||||||||||
Total | 404,800 | 375,444 | 93 | % | 405,000 | 347,483 | 86 | % | 405,000 | 332,751 | 82 | % |
For the year ended December 31, | |||||||||||||||||||||||||||||||||||||
2020 | 2019 | 2018 | |||||||||||||||||||||||||||||||||||
Capacity | Throughput | Use | Capacity | Throughput | Use | Capacity | Throughput | Use | |||||||||||||||||||||||||||||
(bpd) | (bpd) | (%) | (bpd) | (bpd) | (%) | (bpd) | (bpd) | (%) | |||||||||||||||||||||||||||||
Barrancabermeja | 250,000 | 179,210 | 72 | % | 250,000 | 218,612 | 87 | % | 250,000 | 221,946 | 89 | % | |||||||||||||||||||||||||
Reficar | 150,000 | 140,866 | 94 | % | 150,000 | 155,049 | 103 | % | 150,000 | 151,331 | 101 | % | |||||||||||||||||||||||||
Apiay | 2,500 | 887 | 35 | % | 2,500 | 779 | 31 | % | 2,500 | 939 | 38 | % | |||||||||||||||||||||||||
Orito | 2,300 | 1,074 | 47 | % | 2,300 | 1,314 | 57 | % | 2,300 | 1,228 | 53 | % | |||||||||||||||||||||||||
Total | 404,800 | 322,038 | 80 | % | 404,800 | 375,754 | 93 | % | 404,800 | 375,444 | 93 | % |
3.6.1.1 Barrancabermeja Refinery
We estimate that theThe Barrancabermeja refinery supplies 48%approximately 51.9% of the fuels consumed in Colombia according to internal calculations made by us and Colombia’s fuelsfuel 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 3542 – Production of Refined Products from the Barrancabermeja Refinery
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
(bpd) | (bpd) | |||||||||||||||||||||||
LPG, Propylene and Butane | 11,813 | 10,712 | 11,956 | 9,101 | 10,114 | 11,813 | ||||||||||||||||||
Gasoline Fuels and Naphtha | 58,623 | 56,047 | 59,305 | 50,167 | 64,063 | 58,623 | ||||||||||||||||||
Diesel | 58,305 | 56,090 | 48,233 | 54,261 | 57,469 | 58,305 | ||||||||||||||||||
Jet Fuel and Kerosene | 23,604 | 20,421 | 20,435 | 11,910 | 24,320 | 23,604 | ||||||||||||||||||
Fuel Oil | 36,636 | 38,217 | 55,730 | 25,112 | 32,009 | 36,636 | ||||||||||||||||||
Lube Base Oils and Waxes | 729 | 609 | 668 | 577 | 797 | 729 | ||||||||||||||||||
Aromatics and Solvents | 3,106 | 2,847 | 2,879 | 2,274 | 2,652 | 3,106 | ||||||||||||||||||
Asphalts and Aromatic Tar | 31,104 | 26,468 | 14,092 | 27,018 | 29,593 | 31,104 | ||||||||||||||||||
Polyethylene, Sulfur and Sulfuric Acid | 1,479 | 1,509 | 1,541 | |||||||||||||||||||||
Polyethylene, Sulphur and Sulphuric Acid | 856 | 1,139 | 1,479 | |||||||||||||||||||||
Total | 225,399 | 212,920 | 214,839 | 181,276 | 222,156 | 225,399 | ||||||||||||||||||
Difference between Inventory of Intermediate Products | (1,018 | ) | (405 | ) | (661 | ) | ||||||||||||||||||
Difference between Inventory of Intermediate Product | 1,046 | (703 | ) | (1,018 | ) | |||||||||||||||||||
Total Production | 224,381 | 212,515 | 214,178 | 182,322 | 221,453 | 224,381 |
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In 2018,2020, total production from the Barrancabermeja refinery increaseddecreased by 5.6% from 212,515 bpd17.7% compared with 2019 mainly due to a contraction in 2017 to 224,381 bpd in 2018 primarily as a result of stable operationthe demand for fuels and improved throughputpetrochemical products caused by mobility restrictions imposed at the national level due to the implementation of initiatives to segregate and purchase light and intermediate crudes.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 2018,2020, we produced 48,46820,945 tons of low-density polyethylene, a decrease of 9.3%37.1% compared to the production of 53,41733,309 tons in 2017.2019. This decrease was primarily due primarily to a reductionthe impact on the operation of ethylene availabilityproduction in the cracking units as a result of a lower demand for gasoline due to a turnaround of one of the fluid catalytic cracking (FCC) units.health emergency caused by the COVID-19 pandemic. We produced 894551.1 mboe of aromatics (benzene, toluene, xylene, orthoxylene, heavy aromatics and cyclohexane), a 4.3% increase16.2% decrease as compared with the production of 857657.9 mboe of aromatics in 2017.2019. The increasedecrease was mainly the result of an increasethe decrease in local demand for benzene, toluene, xylene, orthoxylene (BTXO).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$13.5 per barrel 10.6/Bl in 20172019 to US$11.8 per barrel 9.1/Bl in 2018,2020, primarily due to the decreaselower positive differential in product prices versus the Brent price, and the higher cost of refined products, mainly gasoline and fuelthe crude oil as compared to the ICE Brent.basket. The average conversion index for the Barrancabermeja refinery was 84.6%87.6% in 20182020 and 82.7%86.8% in 2017.2019. This increase was primarily due to the operation at higher capacitya better quality of the units that convert bottom streams into diesel.diet and higher deliveries of asphalt compared to the crude load of 2019.
3.7.1.2 | Cartagena Refinery |
The following table sets forth the production of refined products from the Cartagena Refinery for the periods indicated.
Table 3643 – Production of Refined Products from the Cartagena Refinery
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
(bpd) | (bdp) | |||||||||||||||||||||||
LPG, Propylene and Butane | 4,227 | 6,791 | 6,080 | 3,321 | 4,255 | 4,227 | ||||||||||||||||||
Gasoline Fuels and Naphta | 51,703 | 43,728 | 35,012 | |||||||||||||||||||||
Gasoline Fuels and Naphtha | 43,259 | 49,904 | 51,703 | |||||||||||||||||||||
Diesel | 76,833 | 60,467 | 40,950 | 72,170 | 79,069 | 76,833 | ||||||||||||||||||
Jet Fuel and Kerosene | 8,057 | 6,700 | 5,768 | 7,424 | 9,331 | 8,057 | ||||||||||||||||||
Fuel Oil | 4,671 | 10,150 | 24,602 | 2,375 | 3,660 | 4,671 | ||||||||||||||||||
Sulfur | 581 | 446 | 241 | |||||||||||||||||||||
Sulphur | 466 | 585 | 581 | |||||||||||||||||||||
Total | 146,072 | 128,282 | 112,653 | 129,015 | 146,804 | 146,072 | ||||||||||||||||||
Difference between Inventory of Intermediate Products | 39 | 3,916 | 911 | |||||||||||||||||||||
Difference between Inventory of Intermediate Product | 5,318 | 2,262 | 39 | |||||||||||||||||||||
Total Production(1) | 146,111 | 132,198 | 113,564 | 134,333 | 149,066 | 146,111 | ||||||||||||||||||
Petcoke (Metric tons) | 984,558 | 704,073 | 601,163 | |||||||||||||||||||||
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 3744 – Imports and Sales of Refined Products from the Cartagena Refinery
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
(bpd) | (bpd) | |||||||||||||||||||||||
Imports | ||||||||||||||||||||||||
Motor Fuels | - | 212 | 3,641 | - | 521 | - | ||||||||||||||||||
Diesel | - | – | 6,155 | |||||||||||||||||||||
Jet Fuel and Kerosene | 466 | 847 | 2,211 | - | - | 466 | ||||||||||||||||||
Alkylate | - | – | 83 | |||||||||||||||||||||
LPG and Butane | 739 | 618 | 355 | 1,132 | 990 | 739 | ||||||||||||||||||
Total Imports | 1,205 | 1,677 | 12,445 | 1,132 | 1,511 | 1,205 |
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During 2018,2020, the Cartagena Refineryrefinery imported productsbutane in order to coverachieve the North Coast sales demand primarily dueplanned feed of the Butamer Unit and to operational turnarounds duringincrease the last quarterproduction of 2018.alkylate.
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
(bpd) | (bdp) | |||||||||||||||||||||||
Sales | ||||||||||||||||||||||||
Motor Fuels | 52,126 | 44,051 | 38,534 | 43,979 | 49,865 | 52,126 | ||||||||||||||||||
Diesel | 78,007 | 60,289 | 46,060 | 73,188 | 77,981 | 78,007 | ||||||||||||||||||
Jet Fuel and Kerosene | 8,082 | 7,489 | 7,479 | 7,394 | 9,063 | 8,082 | ||||||||||||||||||
Fuel Oil | 4,704 | 7,528 | 16,593 | 2,552 | 3,713 | 4,704 | ||||||||||||||||||
Other Products | 19,942 | 27,099 | 22,990 | 24,275 | 22,435 | 19,942 | ||||||||||||||||||
Total Sales | 162,861 | 146,456 | 131,656 | 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 reached the goal51.6 million barrels of completing individual unit performance tests (for 100%crude were processed in 2020 compared to 56.6 million barrels of units), and the Global Performance Test on December 5, 2017.
As partcrude processed in 2019. Exports to international markets represented 43.66% of the initial phase of the refinery optimization process, during the first half of 2018 the maximum load capacity of certain of the Cartagena Refinery’s plants were tested and provided the following results: (i) the coke unit, with maximum load of 46,088 bpd versus a nominal capacity of 45,000 bpd, (ii) the crude unit, with 166,607 bpd versus a nominal capacity of 150,000 bpd and (iii) the hydrocracking unit with, 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 under regular operation was achieved since the refinery’s commissioning, at 161 mbd.
Finally, the fluid catalytic cracking unit ran at 43,515 bpd versus a nominal capacity of 40,000 bpd after coupling and putting into operation the turbo expander.
In terms of gross refining margin, the refinery progressed from US$9.5 per barrel in 2017 to US$11.0 per barrel in 2018. Throughput also improved during 2018, increasing from an average of 136 mbd in 2017 to 151 mbd in 2018. This result primarily reflects the good performance of the refinery after its stabilization period and commencing its optimization process in 2018.total sales (US$1,047 million).
The Cartagena Refinery’s 2018refinery’s 2020 figures already reflect the operation of all units, thus total sales have increasedunits. The gross refining margin decreased to US$6.6/Bl in 2020 from US$9.2/Bl in 2019 mainly due to the reduction of product demand as compared to 2017, from US$3,085 million in 2017 to US$4,129 million in 2018. A total of 55.3 million barrels of crude were processed in 2018 compared to 49.5 million barrels processed in 2017. Exports to international markets represented 42% of total sales (US$1,749 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 modernizationconsequence 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$3,496.6 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 refineryCOVID-19 public health emergency 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 needRussia-Saudi Arabia oil price war. Throughput decreased during 2020, from an average of 155 mbd in 2019 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 participation141 mbd in Reficar from 75.96% to 99.34%:2020.
During 2018, Esenttia2020, Esenttia’s production totaled 447490 thousand tons of petrochemical products, a 2%6.5% increase compared to the 441460 thousand tons produced in 20172019, primarily due to delays ineffective articulation of the supply chain and the ability of raw materials asEsenttia to maintain its work schedule in in safe conditions given the COVID-19 pandemic. Average capacity increased by 10 thousand tons in 2020, primarily due to the expansion of the extruder capacity and the installation of a result of Hurricane Harvey.second desorber, investments that improved efficiency and reliability in plant performance. The total contribution margin in 20182020 (including the contribution of polypropylene, polyethylene and masterbatches) was 11.2%3% lower than in 2017, a decrease from2019 (from US$215 242 per ton in 20172019 to US$191 235 per ton in 2018. The decrease2020), even in contribution margin was primarily due to higher volatility inadverse market conditions caused by the propylene market, Esenttia’s main feedstock.COVID-19 pandemic.
Table 3845 – Operating Capacity of Esenttia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
(Metric Tons) | (Metric Tons) | |||||||||||||||||||||||
Average capacity | 470,000 | 470,000 | 470,000 | 480,000 | 470,000 | 470,000 | ||||||||||||||||||
Throughput | 447,290 | 440,632 | 444,812 | 489,627 | 459,737 | 447,290 | ||||||||||||||||||
% Use | 95 | % | 94 | % | 95 | % | 102 | % | 98 | % | 95 | % |
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3.7.1.4 | Invercolsa |
3.6.1.4 BiofuelsDuring 2020, Inversiones de Gases de Colombia S.A. (Invercolsa), registered 1.26 million users of natural gas, a slight increase of 3% compared to the 1.22 million users of natural gas in 2019, due to the contraction of residential natural gas installations given the COVID-19 pandemic. In 2020, Invercolsa continued to integrate its operations into the Ecopetrol Group, in connection with the increase in stake completed by Ecopetrol in November 2019. Invercolsa embraced an HSE culture and leadership model based on Ecopetrol Group’s practices.
3.7.1.5 | Biofuels |
We
As of the date of this annual report, we have investments in twothe biofuel companies: (i) Bioenergy S.A.S., in which we own indirectly 99.35% 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.
On March 10, 2020, Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S were admitted to reorganization processes by the Superintendence of Companies of Colombia under Law 1116 of 2006. The reorganization process ended on June 24, 2020, with applicable regulatory authority ordering the start of the liquidation process of both companies. For more information, see the section Risk Review—Legal Proceedings and Related Matters.
Marketing and Supply of Refined Products |
3.6.2 Marketing and Supply of Refined Products
We are the main producer and supplier of refined products in Colombia. We market a full range of refined and feedstock products, including regular and high-octane gasoline, diesel fuel, jet fuel, LPG natural gas and petrochemical products, among others.
Domestic sales of products increaseddecreased by 4.7 mboepd, an increase of 1.6%53 mboed, 17% lower as compared to 2017.2019. This increasedecrease is primarily the result of: (i) a 2.5%, or 3.7 mboepd, increaseof the mandatory lockdowns imposed by the Colombian national government in order to curb the spread of the COVID-19 pandemic, which in turn led to sales of middle distillates sales mainly due to higher economic growth in general and higher airplane transportation demand by passengers, (ii) a 5.3%, or 0.9 mboepd, decrease in LPG sales, primarily as a result of lower production at Reficar and Barrancabermeja, (iii) a 12%, or a 2.2 mboepd, increase in petrochemical sales, due to an increase in asphalt sales by Ecopetrol, as a consequence of the reactivation of domestic demand and local sales to clients who then export the product.gasoline.
During 2018, 8.82020, 3.5 million barrels of diesel and 3.42.5 million barrels of gasoline produced by Reficarthe Cartagena Refinery were allocated to the local market in order to complement the supply from the Barrancabermeja refinery and fulfill Colombia’s demand, avoiding larger imports and allowing Ecopetrol to maintain the share of the national market. In the same way, 5.1 million barrels of diluent produced by Reficar were used to transport crude reducing diluent imports. In addition, Ecopetrol imported petrochemicals in order to complement the national supply, generating additional sales of lubricating bases, polyethylene, hexanes and others.
Exports of products increaseddecreased by 8.3%9% compared to 2017, 12 mbd2019, 8 mboed from Reficar and 3.0 mbd5 mboed from Ecopetrol, primarily due to (i) a 97%, or 16 mbd increase in exports of high sulfur diesel, partially offset by (ii) a 21%, or 8.4 mbd decrease in fuellower crude oil exports.runs at the refineries.
3.7 Research and Development; Intellectual Property
3.8 | Research and Development; Intellectual Property |
Our innovation and technology center is the Colombian Petroleum Institute (ICP for its Spanish acronym), established in 1985 and located in Bucaramanga,Piedecuesta, Santander. In 2018, research and development expenses were US$40.67 million, compared to US$25.7 million in 2017. 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.
The focus ofOur research, technology development isand innovation efforts are focused on designing high added-value productsfour main pillars: (i) extending the technical limits for reserves growth, (ii) increasing the efficiency and solutionssustainability of our operations, (iii) preparing the corporation for Ecopetroldecarbonization and energy transition, and (iv) increasing the Colombian oil industry.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.
We will monitor the progress of technological advances that could enable us to increase the share of low emissions hydrogen in our refining and petrochemical processes. As water is a fundamental resource, our efforts will also include a technology–enabled water management program that encompasses the conservation, recycling, reuse and valorization of production water streams. Finally, we are also exploring avenues for the production of high performance, materials from petroleum molecules, for advanced non-combustion applications.
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Each year Ecopetrol presents to the Colombian InstituteNational Council for the Development of Science and Technology (Instituto Colombiano para el DesarrolloTax Benefits (Consejo Nacional de la Ciencia y la Tecnología,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 2018, we obtained US$1.66 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 224266 patent applications in the last 1115 years, 1719 of them in 2018.2020. Our most recent patent applications include innovative technologies, such as (i) a method that uses nanofluids to improvedevice 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, in heavy and extra-heavy oil fields, (ii) a device for controlling production fluctuations at the well head, and the subsequent separation of heavy oil and water, (iii) a process to enhance the flow capacity of oil-water-diluent mixturesthree dimensional superhydrophobic foam and the dilution capacity of diluents used in heavy and extra-heavy oil production and transportation, (iv) aits preparation method, and device to determine(iv) an online inspection tool for the volumetric contractionefficient detection and classification of mixtures of heavy oil and light hydrocarbons, and (v) a visbreaking process for refining heavy petroleum componentsdamages in the presence of a catalyst and hydrogen at low pressure.transportation pipelines.
In 2018, Ecopetrol declared two industrial secrets that strengthen its competitive advantages in2020, the exploration and transportation of hydrocarbons. The Colombian and international authorities granted us 158 new patents including oneall in Mexico and another in Ecuador.Colombia. We currently hold 87101 patents in Colombia, the United States, Mexico, Russia, Peru, Venezuela, Ecuador, Brazil, Nigeria, Indonesia, India and Malaysia.
In 2018,2020, Ecopetrol S.A. licensed 710 of its technologies to private companies for manufacturing, marketing commercialization and after-sales support. To date, wetechnical support including 5 to a North American company for tackling oil theft in pipelines.
We currently have 52 technologies licensed 49 technologies to Colombian and multi-national companies.
3.8 Applicable Laws and Regulations
3.9 | Applicable Laws and Regulations |
3.8.1 Regulation of Exploration and Production Activities
3.9.1 | Regulation of Exploration and Production Activities |
3.9.1.1 | Business Regulation |
Pursuant to the Colombian Constitution, the Nation is the exclusive owner of all hydrocarbonminerals and non-renewable resources located in Colombiathe 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:
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; |
The establishment of procedures to transfer investments in exploration programs between allocated areas; and |
The leveling of the contractual terms of offshore contracts entered before 2014 to the ones included in the contracts executed as a result of the 2014 Colombian Round. |
Agreement 003 of 2015, as issued by the ANH, modifies and, also partially amends, Agreement 004 of 2012, and provides certain rules and measures the Government can take to mitigate the adverse effects of the decline of international oil prices. This agreement permits performance guarantees required under E&P contracts to be reduced in the same amount as the works actually performed during the term of the respective phase.
Agreement 004 of 2015, as issued by the ANH, also partially amends Agreement 004 of 2012, and provides certain rules and measures for the Government to mitigate the adverse effects of the decline of international oil prices. This agreement allows contractors to attribute additional activities carried out under a TEA to commitments under the first phase of an E&P contract.
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Agreement 002 of 2017, as issued by the ANH on May 18, 2017, replaces Agreement 004 of 2012, Agreement 003 of 2014, and Agreements 002, 003, 004 and 005 of 2015. It establishes the general structure of the New Regulation for Administration and Assignment of Areas and the general guidelines regarding future hydrocarbon contracts in Colombia. Seeking the interests of the Nation, the market conditions, the national hydrocarbon sector strategy, the competitive context of producer countries and the Nation’s social and environmental evolution.
Agreement 002 of 2017 adapts the existing regulations for the selection of contractors, and the applicable rules for the award, execution, termination, liquidation, monitoring, control and surveillance of the contracts signed with the ANH. In regard to unconventional reservoirs, this agreement also establishes the need to sign additional contracts and additional arrangements for the industry to exploit unconventional reservoirs in Colombia.
On November 8, 2018, the High Court for Administrative Matters (Consejo de Estado) analyzed the potential annulment of Decree 3004 of 2013 and Resolution 90341 of 2014 and issued an interim order to suspend their effects as of such date. However, the aforementioned Court established that, “… if the National Government is interested in investigation, clarifying and exploring the feasibility of the hydraulic fracturing procedure for the exploration and exploitation of hydrocarbons in unconventional reservoirs (YNC), it could advance in the PPII to identify the risks of unconventional activity.”
On February 4, 2019, the ANH published the new model contract for offshore exploration and production. The purpose of this new model contract is to foster and stimulate investments in exploration and the exploitation of offshore hydrocarbons, enhancing Colombia’s competitiveness to attract and retain investments from large and experienced O&G operators.
On February 5, 2019, the ANH by implementing the Acuerdo No. 2 (Agreement No. 2) opened a Permanent Competitive Bidding Procedure (PPAA), which aims to select, among previously qualified proponents on equal terms, the most favorable offers to allocate the areas previously determined, demarcated and classified by the ANH. Several addendums have modified the terms of references of the PPAA, but, as to date, the applicable terms of reference of such bidding process are included in Addendum No. 19 of November 4, 2020.
The Agreement 02 of 2017 was partially modified by agreement 03 of February 18, 2019 to clarify the moment in which contractors may withdraw from the contracts signed with the ANH and also presents another alternative for those interested in the PPAA when they belong to business groups, other than the issuance of a parent company guarantee.
Resolution 078 of 2019, as issued by the ANH, approved the final terms of reference and the model of the onshore and offshore contract for the “permanent bidding procedure.”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.
3.8.1.1.1 Environmental LicensingAs a result, in 2019, the ANH issued terms of references for the PPAA and Prior Consultationcarried out two cycles both of which were divided in the following four stages: (i) submission of the proposals and selection of the initial proponent, (ii) submission of counterproposals and selection of the most favorable counterproposal, (iii) the exercise of the right of option of improvement by the initial proponent and (iv) allocation of areas, contract awards and execution of contracts. In 2020 a third cycle was carried out by the ANH.
As result of the first cycle of the PPAA, the ANH awarded 11 onshore areas and 1 offshore area. As part of the second cycle, the ANH allocated 14 onshore blocks. Finally, as a result of the third cycle, the ANH awarded 4 onshore areas.
Agreement 01 of March 27, 2020 of the ANH regulates the transfer of activities or investments between legal instruments signed with the ANH to promote exploratory investment in the country and to seek the incorporation of new reserves, repealing the articles of Agreement 02 of 2017.
Agreement 02 of April 7, 2020 of the ANH regulates temporary measures to strengthen the hydrocarbon sector due to the effects generated by the fall in international oil prices. This agreement takes into account what is regulated by Decree 417 of 2020, where the Government declared the State of Economic, Social and Ecological Emergency throughout the national territory, and tlhe declaration by the World Health Organization (WHO) of the outbreak of COVID-19 as a global pandemic. Among the legal measures enacted were: (i) the extension of terms and deadlines in the contracts signed with the ANH; (ii) exceptions to the requirements established in Agreement 01 of 2020 mentioned above, which considers the status of the international oil prices; (iii) possibility of allocating resources from the Benefit Programs to the Communities “PBC” to strengthen measures applied by the Government to face the crisis; and (iv) reduction of contractual guarantees, complying with the requirements established there.
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Agreement 06 of September 11, 2020 of the ANH added Agreement 18 of 2004, Agreement 04 of 2005, Agreement 21 of 2006, and Agreement 2 of 2017 to incorporate into the Contracting Regulations for the Exploration and Exploitation of Hydrocarbons, the contractual elements that allow entities to carry out PPII on hydrocarbons in unconventional reservoirs (YNC) with the use of the Multistage Hydraulic Fracturing with Horizontal Drilling (FHPH) technique.
Through Resolution 0613 of September 14, 2020, the ANH opened a competitive process for the development of Research Projects in Unconventional Reservoirs by the use of the FHPH technique.
A first round was carried out between September 14, 2020 and November 25, 2020, allocating one area to Ecopetrol S.A. Therefore, by means of Resolution 0802 of November 25, 2020, the ANH awarded a Special Contract for Research Projects (CEPI) to Ecopetrol S.A. This contract will allow Ecopetrol, to execute activities in the interest of investigation, clarifying and exploring the feasibility of the hydraulic fracturing procedure for the exploration and exploitation of hydrocarbons in unconventional reservoirs in Colombia. The name of the contract is KALÉ and is located in Puerto Wilches (Department of Santander). As of the date of this annual report, the second round had commenced and was concluded in March 2021.
Temporary regulation for the Comprehensive Research Pilot Projects (PPII)
Ecopetrol has actively participated in the formulation of specific regulation for the implementation of the PPII. The regulatory framework includes:
As of the date of this annual report, additional items of the PPII regulatory framework are being discussed with the Colombian Governement pursuant to which we have made comments. In particular, the Colombian Government and the oil & gas industry are waiting for the final versions of the regulatory framework for pilot evaluation criteria, radioactive materials monitoring, health base lines and evaluation variables.
3.9.1.1.1 | Environmental Licensing and Prior Consultation |
Law 99 of 1993 and other environmental regulations, such as Decree 1076 of 2015 in particular (compilation decree regarding the administrative sector of environment and sustainable development), impose 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 entityauthority 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”)(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 filingproject or activity requires permits for the use of anforestry species that are banned, these should be included in the environmental license process. The EIA andmust 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.
MESDThe 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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3.8.1.1.2 Royalties
3.9.1.1.2 | 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 articleArticle 16 Law 756 of 2002, and articleArticle 29 of the Law 1753 of 2015, the changes in the royalty regime only apply to new discoveries and do not apply to fields already in the production stage as of July 29, 1999. Producing fields pay royalties in accordance with the royalty law in force at the time of the discovery.
With the issuance of Law 2056 of 2020, (“Through which the organization and operation of the general system of royalties is regulated”), the royalties regime applicable to the hydrocarbon fields on which there have been made additional investments aimed at increasing the recovery factor of existing deposits was established. Article 18 of this law established that all the volumes produced in these fields will be considered incremental.
Regarding natural gas, in accordance with Resolution 877 of 2013, as amended by Resolution 640 of 2014, starting on January 1, 2014, the ANH has received royalties in cash rather than in kind. Thus, the producer may dispose of its gas production volumes corresponding to royalties paid in cash.
3.8.2 Regulation of Transportation Activities
Hydrocarbon transportation activity is a public interest activity in Colombia and a public service. As such, it is under governmental supervision and control, regulated mainly by the Ministry of Mines and Energy and theComisión de Regulación de Energía y Gas (“CREG”(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, multipurposemulti-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 byand 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 2015 and due to the dramatic changes in international crude oil prices,2019, the Ministry of Mines and Energy, allowed, by means of Resolution 31325Resolutions 31123 and Resolution 3148931132 of 2015,2019 established the applicable rules for transportation companies and oil production companies to engage in direct negotiations in order to agree on a tariff suitablenegotiate tariffs for both parties. Thethe next four years. Once the negotiation period was extended until June 2016. Notwithstanding the fact that tariff agreements were reached with certain companies, the results of the negotiations were not positive. Thus, tariffs were set byover, 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 accordanceline with the criteria previously establishedtariff 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 as further amended by Resolution 31325has been finalized. The results of 2015such study will be analyzed and Resolution 31285discussed between all the stakeholders prior to the enforcement of 2016.any changes.
The Port Superintendence is the authority that oversees the port business for crude oil and refined products. Although this business is not highly regulated, market participants are required to report certain information to the Port Superintendence.
As a result of the enactment of Decree 119 of 2015, operators of private use hydrocarbon ports are currently able to provide hydrocarbon transport services to third parties pursuant to a mechanism established under that decree.
Decree 119 of 2015 was incorporated into Decree 1079 of 2015 issued by the Ministry of Transport, which compiles the majority of Colombian decrees and regulations in force regarding the administrative sector of transportation.
Refined products and liquefied petroleum gas transport
In 2014, CREG assumed responsibility for regulating product pipeline transportation from the Ministry of Mines and Energy, in addition to its pre-existing regulatory responsibility for liquefied petroleum gas, natural gas and electric energy transportation.
The applicable framework regarding LGP transportation was established by CREG Resolution 092 of 2009 (amended by Resolution 153 of 2014), which, among other issues, sets forth: (i) the obligation of the owners and operators of transportations infrastructure to guarantee access to their infrastructure to other market agents, as long as they pay the fees regulated by CREG; (ii) the general obligations applicable to LGP transporters; (iii) the requirements applicable to the LGP transportation agreement; and (iv) establishes the non-discrimination principle regarding the access to the national transportation infrastructure.
In August 2017January 2021, CREG issuedpresented a new draft resolution 113232 of 2017,2020, which introduced 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, but the final resolution has not been issued yet. 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.
3.8.3 Regulation of Refining and Petrochemical Activities
3.9.3 | Regulation of Refining and Petrochemical Activities |
Article 58 of the Petroleum Code establishes that oil refining activities can be developed throughout the Colombian territory and are not reserved to the State. However, Article 4 establishes that such activities are considered of public interest subject to governmental regulation, and the development of those activities must comply with technical requirements established by regulation.
In 2008, Law 1205, further developed by Resolution 180689 of 2010, issued by the Ministry of Mines and Energy, was issued with the main purpose of contributing to a cleaner environment. It established the minimum quality specifications for liquid fuels in Colombia. Since August 2010, Ecopetrol has been producing and selling diesel and gasoline that compliescomply with the requirements of the aforementioned law and, for some cities, we sell with better standards.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, 2017.2017 as amended by Resolution 40575 of 2019, which extended the validity period. Ecopetrol has been complying with this regulation and working with governmental entities in order to improve air quality in the most critical areas in Colombia.
3.8.3.1 Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels
3.9.3.1 | Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels |
Wholesale marketing, transport, distribution and retail marketing of LPG are mainly regulated by CREG Resolution 74 of 1996, and subsequent resolutions. LPG in Colombia is primarily obtained through Ecopetrol’s refineries, field production and imports. The LPG must meet minimum quality standards to be marketed. Our marketing activities are regulated by CREG Resolution 53 of 2011 (as amended by CREG Resolutions 108 of 2011, 154 of 2014, 01919 of 2015, 18, 34, 63, 64 of 2016 and 034, 063 and 064171 of 2016)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)1989 and as amended by Law 812 of 2003), the distribution of crude oil and its derivatives has a public purpose (utilidad pública), and the distribution of fuel oil and crude oil by-products is considered a public utility activity. Consequently, individuals or entities engaged in these activities are subject to regulations issued by the Colombian government. The Government has the power to determine quality standards, measurement and control of liquid fuels, and establish penalties that may apply to dealers who do not operate in compliance therewith.
The Ministry of Mines and Energy is the entity that controls and exercises technical supervision over the distribution of liquid fuels derived from petroleum, including the refining, import, storage, transportation and distribution in the country. Article 61 of Law 812 of 2003 (whose validity was extended by Law 1955 of 2019) identified the agents of the supply chain of petroleum-based liquid fuels. In this context, the Ministry of Mines and Energy through Resolution 40344 of 2017, published the required actions to ensure the LPG supply for the priority sectors in the country.
The distribution of liquid fuels, except LPG, is governed by Decree 1073 of 2015 (as amended), which establishes the requirements, obligations and penalties applicable to supply agents in the distribution, refining, import, storage, wholesale, transportation, retail sale and consumption of liquid fuels.
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Decree 1073 of 2015 establishes the minimum technical requirements for the construction of storage plants and service stations. This Decree also regulates the distribution of liquid fuels, except LPG establishing the minimum requirements for distributors and the activities and types of agreements permitted for these agents. The Ministry of Mines and Energy also regulates the types of liquid fuels that can be sold and purchased and the penalties for noncompliance with governmental regulations.
Pursuant to Law 1430 of 2010, modified by Article 220 of Law 1819 of 2016, the distribution of fuels in areas near Colombian borders is the responsibility of the Ministry of Mines and Energy and is subject to specific regulations that impose strong control procedures and requirements. The Ministry of Mines and Energy establishes the safety standards for LPG, storage equipment, maintenance and distribution of LPG.
The Superintendence of Public Domestic Utilities also oversees the liquefied petroleum gas transportation business.
3.8.3.2 Regulation Concerning Production and Prices
3.9.3.2 | 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 fixessets the prices for most crude oil by-products, butexcept for gasoline, diesel and biofuels. CREG determines the methodology to calculate their price while the Ministry of Mines and Energy fixessets 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-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 articleArticle 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 Positionnet 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 withdrawwithdrawal 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(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.
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As of the date of this report, the Ministry of Mines and Energy has not calculated the Net Positions corresponding to the year 2018.
3.8.3.3 Regulation of Biofuel and Related Activities
3.9.3.3 | Regulation of Biofuel and Related Activities |
The sale and distribution of biofuels is regulated by the Ministry of Mines and Energy. Regulations establish the quality and pricing standards for biofuels and impose minimum requirements for mixing ethanol with gasoline and biodiesel with diesel.
The sale and distribution of biofuels is provided under CREG Resolution 240 of 2016, which particularly regulates: a) the sorts of market that will be served with biogas and biomethane; b) the quality and safety conditions; and c) the tariff regime. Pursuant to articleArticle 4 of the foregoing Resolution, biogas supply through isolated networks to serve non-regulated users and natural gas vehicles (“GNV”(GNV as per its Spanish acronym), shall be incorporated as a public utility company. Furthermore, articleArticle 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, articleArticle 12 states that biogas suppliers may develop the production, transportation, distribution and commercialization activities through integrated structures, provided that they keep separate accounts for each activity and grant free access to the networks to both regulated and non-regulated users. To the same extent, production, distribution and commercialization of biomethane through interconnected networks to the National Transportation System may be developed through integrated structures, as long as the supplier keeps separate accounts for each activity and grants free access to the networks to both regulated and non-regulated users.
3.8.4 Regulation of the Natural Gas Market
3.9.4 | Regulation of the Natural Gas Market |
Decree 1073 of 2015, Part 2, Title 2, Chapter 2, established that all producers have to issue a production statement that includes the volumes of natural gas available for sale for a period of ten years. This decree established the regime for the selling and marketing of natural gas in Colombia, including specific procedures that regulate the Colombian market in order to manage the remaining natural gas reserves owned by the Nation, and to protect domestic consumers, especially residential consumers, by prioritizing delivery of gas to residential consumers, regulating the export of natural gas and setting forth the export restrictions applicable during an internal shortage of natural gas.
Currently in Colombia the price of natural gas is determined by the market, but some agreements still have to conform to the regulated formula. CREG issued Resolutions 185 (for transportation) and 186 (for supply) of 2020, which jointly replace Resolution 114 of 2017 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 internaldomestic 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 articleArticle 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 ColombianSpanish 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.
3.9.5 | Regulation of the Electric Energy Commercialization Activity |
3.9 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.Sustainability Initiatives
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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3.9.1 Decree 348 of 2017, as currently compiled by Section 4A of Decree 1073 of 2015, establishes public policy guidelines on efficient energy management and delivery of small-scale electricity self-generation surpluses. In addition, this regulation establishes the conditions for the connection of small-scale self-generators (AGPE for its Spanish acronym) to the SIN, the parameters to be an AGPE, the reporting of surpluses to the Mining and Energy Planning Unit (“UPME”) and the remuneration of surplus energy. Note that, as determined by Resolution UPME 281 of 2018, the maximum electricity generation limit to be considered an AGPE is one (1) MW and will correspond to the installed capacity of the self-generator’s generation system. Above that limit, an electricity self-generator will be considered a big-scale electricity self-generator (“AGGE” as per its acronym in Spanish).
The specific regulation for AGGE is currently determined by CREG Resolution 024 of 2015, whereas the specific regulation for AGPE is currently set by CREG Resolution 030 of 2018.
CREG Resolution 024 of 2015 (modified by CREG Resolution 140 of 2017) sets conditions for surplus sales of an AGGE, connection and metering conditions, and back-up and energy supply conditions. Specifically, this resolution determines that AGGE must follow the general connection rules to the SIN for a generation plant, that they must have a remote telemetry system, and that they must have a back-up power purchase agreement, among others.
CREG Resolution 030 of 2018 establishes the connection conditions for AGPE, surplus sales conditions, metering conditions and energy commercialization rules for AGPE. Note that CREG published CREG Resolution 002 of 2021, by means of which it published a project resolution in which it modifies the regulation for AGPE regarding the connection measurement, and surplus trade rules.
The Ecopetrol Group has invested in several projects that are considered projects from AGGE, which means that CREG Resolution 024 of 2015 is the main regulation that applies to Ecopetrol’s self-generation projects. As of the date of this annual report, Ecopetrol complies with all regulations, as set forth in the above-mentioned resolution and Decree 2469 of 2014 regarding the delivering of electricity surpluses to the SIN and to its subsidiaries or controlled parties.
3.10 | Technology, Environment, Social and Governance (TESG) Strategies and Initiatives |
Ecopetrol has a long-standing commitment to positively contribute in terms of economic, social, and environmental development, and grounds its behavior on a solid corporate governance, a business conduct based on values and ethical principles, with transparency at its core. This work has been led in collaboration with our stakeholders through initiatives and strategies that have been framed in corporate responsibility and sustainability. The Company has strengthened its metrics and reporting of environmental, social and governance (ESG) issues in line with international standards.
Furthermore, Ecopetrol has identified that Technology (T), leveraged on applied innovation and the revolution brought about by digital transformation, is a key catalyst to accelerate and achieve in a timely manner the necessary changes to face ESG challenges. This is the new concept of TESG. The convergence between TESG and Ecopetrol’s corporate strategy marks a milestone that will change the future of the Company, where its transformation into an energy company is leveraged by technology. With this, we validate our commitment to be a Company that moves towards value creation in a sustainable future.
During 2020, Ecopetrol reviewed its environmental, social and governance (ESG) taxonomy, considering shifts in international trends related to these. One of the main findings of the project was that sustainability needs to be addressed from a technology standpoint that allows for the implementation of innovative solutions to current and future challenges in an accelerated and exponential way. The TESG strategy integrates technology to environmental, social, economic and governance issues, allowing for innovative solutions to have accelerated implementations and timely scalability, and is one of the four lines of action of our energy transition plan (See the section entitled HSEStrategy and Market Overview—Our Corporate Strategy—2021 – 2023 Business Plan—Energy Transition).
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This strategy is based on a materiality analysis, which allowed the identification of 28 TESG topics that have or could have a significant impact (positive or negative) on our ability to generate value in the short, medium and long term and/or a significant relevance to stakeholders. Based on this analysis, Ecopetrol identified materiality as a dynamic and recurring process that is expected to be constantly reviewed. Moreover, although Ecopetrol manages all 28 TESG topics using four distinct categories (exceptional, outstanding, differentiated and compliance), in its disclosures, Ecopetrol will prioritize the following, based on their materiality:
Ecopetrol’s Material Topics
• Climate Change | • Circular Economy |
• Water Management | • Air Quality |
• Regional Development | • Fuel Quality |
• Health and Safety | • Use of energy and alternative sources |
• Biodiversity and Ecosystem Services | • Prevention and management of incidents by operations |
• Talent attraction, development and retention | • Prevention and management of incidents causes by third parties |
During 2020, we reviewed and updated our seven stakeholder groups (as defined below), given that their expectations and perceptions are considered within the materiality analysis. The methodology used for this update was based on the application of the AA1000 standard. Its purpose is to responsibly manage relationships with our key stakeholders, which leverages decision-making and strategic vision, resulting in long-term value creation.
Ecopetrol’s seven key stakeholder Groups are: (i) associates and partners, (ii) investors, (iii) clients, (iv) suppliers, contractors and their employees, (v) employees, retirees and their beneficiaries, (vi) state, and (vii) society and community.
As in previous years, during 2020 the Corporate Responsibility Area consulted the perceptions and expectations of our seven stakeholder groups with respect to the 28 TESG topics and corporate responsibility attributes. The results obtained for corporate responsibility in 2020 (84%) represent an improvement of 2% over the results obtained in 2019 (82%).
We also remain committed to improving our information disclosure standards by following international best practices. In particular, during 2020, and early 2021, the Company decided to begin the adoption of the Sustainability Accounting Standards Board (SASB), the recommendations of the Taskforce on Climate-related Financial Disclosures (TCFD), and the Stakeholder Capitalism Metrics (SCM) into our stakeholders’ reports.
During 2020, the environmental management strategy of Ecopetrol S.A. included the following components:
i. | Environmental Viability: this strategy concentrates on the planning, execution and submission of environmental impact assessments to national and regional authorities in order to obtain licenses and permits for project execution. Adequate project planning allows projects to pursue impact prevention and minimization through the mitigation hierarchy approach, ensuring the sustainability of operations and systematic relationships with stakeholders. |
ii. | Climate Change: this strategy aims to decrease our carbon emissions and manage climate-related risks and opportunities, through the implementation of four strategic action lines: |
Mitigation: reducing our greenhouse gas emissions (GHG) and creating carbon offset alternatives as part of a comprehensive decarbonization plan;
Vulnerability and Adaptation: reducing the risks and impacts to our operations posed by climate variability and change;
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Research and Technology: investing on research and development to reduce our GHG emissions through low carbon technologies; and
Involvement in Policymaking: advising and influencing government policies on climate change.
Our decarbonization plan has four components: (i) GHG emissions inventory verification, (ii) development and implementation of an emissions reduction portfolio, (iii) design and implementation of an offset portfolio of natural climate solutions, and (iv) development of a net zero emissions roadmap.
As part of Ecopetrol S.A.’s efforts to contribute to the Sustainable Development Goals and the Paris Agreement, on March 25, 2021, Ecopetrol announced its plan to achieve net zero carbon emissions by 2050 (scopes 1 & 2), in line with its commitment to mitigate climate change and further the energy transition and the TESG agenda.
By 2030, Ecopetrol seeks to reduce its CO2e emissions by 25% as compared to the 2019 baseline for scopes 1 and 2, which correspond to direct and indirect emissions associated with the purchase of energy. In addition, Ecopetrol will seek to reduce 50% of its total emissions (scopes 1, 2 and 3) associated with the company’s value chain, which includes the use of its products, by 2050. However, we cannot offer any assurance on our ability to meet these goals by such dates.
The development of the goals proposed are a part of the Ecopetrol Group’s Corporate Strategy and energy transition roadmap. Progress on these goals is expected to be reported periodically in line with Company’s earnings results.
Ecopetrol continues to implement its emissions reduction portfolio, which includes specific programs and targets in relation to renewable energies, elimination of routine flaring, energy efficiency and reduction of fugitive emissions and venting. In 2020, we achieved a reduction of 199,847 tons of CO2e from projects implemented during that year. Ecopetrol has achieved a total accumulated reduction of 8,472,766 tons of CO2e during the 2010-2020 period, of which 1,756,163 tons of CO2e have already been verified by a third party.
iii. | Sustainable production system and biodiversity: Ecopetrol’s biodiversity strategy is based on two components: i) prevention and mitigation of biodiversity impacts and ii) implementation of nature-based solutions, to offset residual impacts and actively respond to challenges related to climate change, water resources and biodiversity management, food security or disaster risks, among others. Each of these themes are described below. |
i. | Prevention and mitigation of biodiversity impacts: |
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. Currently, subsidiaries of Ecopetrol S.A. establish their own HSE models, provided that these modelsSubsidiaries guidelines must be consistent with guidelinesthose established by Ecopetrol S.A.
3.10.3.1 | Ecopetrol S.A. |
One of the principles that guides Ecopetrol is ourthe commitment to ourits 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 2018,2020, compared with the prior year, were:
A 67% decrease in road accidents, due to improvements in real-time monitoring of drivers’ safety habits, |
We did observe an increase in some other indicatorscontrol check points for tracking tankers and awareness campaigns for drivers
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 Incident RateIncidents 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 0.630.43 in 2018.2020. In 2018, 682020, 46 recordable cases occurred, where 24%15% led to restricted work, 7%9% required medical treatment and 69%76% led to lost days. Additionally, we had a 12% increase38% decrease in the number of occupational incidents compared to 2017 due to a higher level of activity at the Company which led to a higher exposure of workers to incidents.2019, however, with decreased work hours in 2020.
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Graph 7 – Total Recordable Incident RateFrequency – Employees and
Contractors(*) (**)
* | Number of employee or contractor injuries requiring minimum medical treatment |
** | Includes data for Ecopetrol S.A. and the Vice-Presidency of Transport and Logistics, but does not include data for subsidiaries of |
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:
Our contingency plan includes, among others:
Further, we are upgrading the skills
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Ecopetrol continuously implements training programs for all personnel involved in emergency or contingency response plans. In the last four years, 13,457 trainings have taken place to improve our performance during emergency drills.employees’ skills. During 2019 and 2020, 7,033 training were carried out as shown in the table below:
In offshore operations,Graph 8 – Trained personnel
Performance improvement has been achieved through the operator hasexecution of the responsibility of designing36 emergency and implementing plans and strategies aligned with international best practices that cover various emergency response scenarios.contingency plans.
Frequency of process safety incidents
Our “ProcessProcess Safety Management”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. We maintained the same Tier 1 process safety performance compared to 2017 (0.05 in both 2017 and 2018). 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 2018,2020, there were 0.05 Tier 1 process safety incidents per million hours worked.worked, an increase from the 0.03 recorded in 2019.
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Frequency of Tier 1 process safety incidents per hours worked (per million hours worked):
Graph 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 2018,2020, Ecopetrol S.A. recorded 114 environmental incidents, compared with 146 in 20172019 and 811 in 2016.2018. The volume of oil spills was 730.26125 in 2020, a decrease from 142 barrels in 2018, an increase2019 and a decrease from 50.7710.26 barrels in 2017 and 202 barrels in 2016. The decrease in the numbers of environmental incidents was the result of improvement in the identification of critical equipment operating in high- or very high-risk conditions, and the implementation of asset integrity plans designed to mitigate those risk conditions. The increase in oil spilled was due mainly to the Lisama 158/La Fortuna incident as described below.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 for the Lisama Well, Ecopetrol did the following:
In terms of attention to the incident, Ecopetrol coordinated actions and additional mitigation activities with several Colombian governmental authorities, including: the municipalities of Barrancabermeja, San Vicente de Chucurí and Puerto Wilches, the Department of Santander, the Environmental Regional Autonomous Authority of Santander, the Environmental Police of Barrancabermeja, the National Licensing Authority, the Colombian Red Cross, the Civil Defense, the Ministry Public, the Hydrocarbons National Authority, the Ministry of Environment and Sustainable Development, the Institute of Hydrology, Meteorology and Environmental Studies and, the Colombian Public Defender Office.
In addition, for the preparation and performance of the Environmental Recovery Plan (PRA) which Ecopetrol proposed and filed before the environmental authorities, Ecopetrol had the support of the Biological Resources Investigation Institute Alexander Von Humboldt (pursuant to which a contract was entered into between the aforementioned parties). Furthermore, to ensure the attention and management of wildlife actually and potentially affected by the incident, Ecopetrol had the support and advice of Cabildo Verde Sabana de Torres, a non-governmental agency.
On another hand, 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 the attention of the incident:
Since April 8, 2018, Ecopetrol intervened the Lisama Well with a snubbing unit (specialized unit which handles pressure), with the purpose to verify the integrity of the casing, the cement used for the casing and to seal off the area where the spill was occurring. These activities finalized successfully on May 8, of 2018, when the Lisama Well was finally plugged with a double seal of cement.
On May 27, 2018, after ensuring that the activities described above were successfully performed to control the spill, the 63 families (approximately 177 individuals) which were directly affected by the spill returned to their homes.
On June 2, 2018, the technical abandonment of the Lisama Well initiated, a process which ended on the July 11, 2018.Well.
On October 19, 2018After closing the event and abandoning of the well, Ecopetrol continues to implement environmental recovery actions, in accordance with the orders given by and in compliance to Resolution 1767 of 2006, Ecopetrol filed beforecoordination with the ANLA the Environmental Recovery Plan (PRA), whereby a plan to perform several activities to ensure the recovery of affected natural resources (water, air and land) plus fauna and flora was prepared, including the following aspects:environmental authorities. Likewise, voluntary social investments have been fulfilled.
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 |
(i) Felipe Bayón (CEO and former Chief Operating Officer)
(ii) Héctor Manosalva Rojas (former Vice-President of Development and Production)
(iii) Ricardo Ernesto Coral Lucero (former Vice-President of the Central Region)
(iv) Oscar Ferney Rincón (Development and Production Operations Manager of the De Mares region)
An initial suspension order against those Ecopetrol workers was at first issued and lifted in August 2018. Currently, their investigations are infinished the probationary stage.
The Prosecutor’s Office – National Human Rights Unit and International Human Rights has conducted a preliminary investigation against Ecopetrol and governmental employees for the alleged crime of environmental pollution due to the exploitation of mining or hydrocarbon deposits. Currently, the investigation is in the pre-trial stage.
Legal Claims
As of the date of this annual report:
There are two more actions that have been filed before the Administrative Court of Santander, related to the Lisama 158 incident:
-Approximately 600 people, members of the community and fishermen who live in the vicinity of where the incident took place, filed a class action in the amount of COP $614,503,232,689, seeking compensation for damages allegedly suffered as consequence of the incident. As of the date of this annual report the court has not scheduled a hearing date. On September 25, 2020, Ecopetrol informed Mapfre Seguros Generales de Colombia S.A. that it was seeking to invoke guarantee coverage by the guarantors.
-Senator Antonio Eresmid Sanguino filed a class action, seeking protection of collective rights (no compensation or indemnification petitions), arguing that the incident led to the destruction of (i) people´s health and (ii) damages to the environment caused by the incident.
On October 2, 2018, the Administrative Court of Santander (competent judge) issued an interim measure whereby the latter ordered different authorities and Ecopetrol to perform various activities to prevent any additional environmental damage to occur.
On January 16, 2020, the High Court for Administrative Matters (Consejo de Estado) revoked the interim measure imposed by the Administrative Court of Santander, considering that with the abandonment of the well “the risk that caused the production of the spill has been surpassed”. In its ruling, the High Court for Administrative Matters also mentioned that Ecopetrol has been taking the necessary actions to solve the damages produced by the incident, and also implemented the actions to repair the alleged damage. As of the date of this annual report, both complaints were properly answered and we are currentlystill awaiting for the commencement of the evidentiary stage.
On March 22, 2018, Ecopetrol made a claim to MAPFRE SEGUROS GENERALES DE COLOMBIA S.A., based on its Control of Well Policy and received the US$19 million in October 2019. Thereafter, as a result of the third party liability policy claim objection, Ecopetrol has taken the relevant actions to obtain the guarantee coverage of guarantors. On February 27, 2020, Ecopetrol filed a lawsuit against “MAPRE SEGUROS GENERALES DE COLOMBIA S.A.” to obtain recognition and payment of COP$ 128,807,833,685 based on civil liability. The court is analyzing the lawsuit.
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3.10.3.2 | Cenit |
Cenit established its own HSE Management System based on Decree 1072 of 2015 in 2017, and this was implemented during 2018. Cenit is also leading the definition of standard HSE key process indicators (“KPIs”)(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 20182019 KPIs and agreed upon the goals for 20192020 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.
3.10.3.3 | Cartagena Refinery |
In 2018, around 6,779,7292020, approximately 5,179,195 man-hours were employed conducting Reficar’s business activities. Our HSE performance indicators for Total Recordable Incidents Frequency (TRIF), Process Safety Incident (ISP)(PSI) and Environmental Incident (EI) were well within our established expectations, but the indicator for Total Recordable Cases (TRIF) exceeded our established expectations (TRIF=1.2).expectations.
The following table covers Reficar’s TRIF for 2016, 20172018, 2019 and 2018,2020, which includeincludes Ecopetrol Operation and Maintenance (O&M), Reficar and subcontractors. The table presents statistics related to construction, pre-commissioning, start-upoperating and operatingmaintenance activities. Reficar has not reported fatalities (accidents that caused deaths) during the period 2010 – 2018.2020.
Table 3946 – Performance Indicators
METRIC | 2018 | 2017 | 2016 | |||||||||||||||||||||
For the year ended December 31, | ||||||||||||||||||||||||
Metric | 2020 | 2019 | 2018 | |||||||||||||||||||||
Man-hours | 6.779.729 | 7.495.531 | 10.351.896 | 5,179,195 | 6,538,295 | 6,779,729 | ||||||||||||||||||
Recordable accidents | 12 | 9 | 29 | 1 | 1 | 12 | ||||||||||||||||||
Total recordable cases (TRIF)* | 1,77 | 1,2 | 2,80 | |||||||||||||||||||||
Total recordable incidents frequency (TRIF)* | 0.19 | 0.15 | 1.77 | |||||||||||||||||||||
Environmental Incidents (EI) | 0 | 0 | 0 | - | - | - | ||||||||||||||||||
Process Safety Incidents (ISP)* | 0 | 0,13 | 0,19 | |||||||||||||||||||||
Process Safety Incidents (PSI) | - | - | - |
* These risks were associated with normal operations. |
The results of other related performance indicators during 2018 were:
3.9.2 Corporate Responsibility
During 2018, Ecopetrol updated its corporate responsibility strategic guidelines. These updated guidelines were developed based on the following three pillars:
As in previous years, during 2018 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) in respect of 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, 73% of respondents rated these attributes in the two highest options on the scale. This represents an improvement of 3% to the result obtained in 2017 (70%). Of particular note, are the improvements in results obtained in the community and local government and associates and partners stakeholder groups.
During 2018, following the United Nations Guiding Principles on Business and Human Rights, we conducted two Human Rights risk assessments for the activities we carry out in our Oriente and Orinoquía regions, which represent the largest part of our gross production. As a result of the evaluations, action plans were proposed, which will guide the incorporation of the results in the processes of each relevant company.
Additionally, in 2018 we applied the Corporate Social Responsibility self-diagnosis designed by UNICEF for children and adolescents. The recommendations we received from this self-diagnosis will also be incorporated into the processes of each relevant company.
3.9.3 Environmental Sustainability
3.9.3.1 Environmental Practices
Ecopetrol S.A.
During 2018, the environmental management strategy of Ecopetrol included the following components:
In 2018, Ecopetrol reported its performance related to environmental management in its Sustainability Management Report to relevant institutions focused in promoting sustainable issues, such as the environmental benchmarking of Asociación Regional de Empresas del Sector Petróleo, Gas y Biocombustibles en Latinoamérica y el Caribe (ARPEL).
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 sulfur content in our diesel B2 (98% fossil and 2% biodiesel) to under 25 ppm. In particular, in December 2018, the diesel that we distributed in Colombia had an average of 16 ppm of sulfur and the gasoline we distributed had an average of 108 ppm of sulfur, values that are lower than the current local regulations of 50 ppm in diesel and 300 ppm in gasoline.
In compliance with Ecopetrol's Climate Change Strategy, since 2010, we have developed greenhouse gas reduction projects in various of our operating areas. As a result, in 2018, we achieved a reduction of about 1.2 million tons of CO2e, through the implementation of projects in energy efficiency and reducing gas flaring, among others.
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 2018, the Barrancabermeja refinery’s average monthly energy consumption was 66 GWhm (gigawatts per hour per month), provided through self-generation. The Cartagena Refinery’s average monthly energy consumption was 67 GWhm (gigawatts per hour per month), 100% was provided through self-generation.
Production
Further, during 2018, Ecopetrol S.A.’s production segment had an average monthly energy consumption of 399 GWhm (gigawatts per hour per month) for its direct operation, from which 68% was provided through self-generation and the remaining 32% 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 contracts.
We also began the construction of our first solar complex that will allow us to supply part of the energy required by the Castilla field, becoming the largest self-generation park with non-conventional renewable sources in Colombia.
Transport
The cost of power transmission for Oleoducto de los Llanos (ODL) was reduced due to the optimization of its take or pay contract.
3.10 Related Party and Intercompany Transactions
Set forth below is a description of material related-party transactions. For additional information about transactions with related parties, see Note 2931 to our consolidated financial statements.
Ocensa
Ecopetrol S.A. has entered into a number of agreements with its 72.65%-owned subsidiary, Ocensa, of which the following are the most significant:
In March 1995, Ecopetrol S.A. entered into an agreement for the transportation of crude oil through the Ocensa pipeline. Pursuant to the terms of this agreement, Ecopetrol S.A. was required to make monthly payments that varied, depending on both the volume of crude oil transported through the pipeline and a tariff imposed by Ocensa on the basis of Ocensa’s financial projections and their expected volumes of crude oil. On January 17, 2013, this agreement was amended as a result of Ocensa’s new business model. Among other changes, this amendment to the transportation agreement establishes the payment of the tariff, calculated according to Resolutions issued in 2010 by the Ministry of Mines and Energy. In 2013, another amendment was executed that modified the terms by which the payments of invoices should be made. In 2020, an amendment including security standards for the supply chain was executed.
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On July 29, 2014, after Ocensa implemented and carried out an open process to receive offers to enter into transportation agreements for an extended capacity of approximately 135,000 barrels per day in Ocensa’s pipeline (the “P135 Project”)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'sOcensa’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'sOcensa’s offer and (ii) the corresponding amendments to the transportation agreements.
In 2018,2020, payments made by Ecopetrol S.A. under these two agreements amounted to US$1.049 1,099.85 million.
On October 28, 2013, Ecopetrol entered into a natural gas supply contract in force until November 30, 2018, pursuant to which Ecopetrol S.A. supplies gas to Ocensa and receives a fixed price per MBTU (Million British Thermal Units). This agreement replaced the contract for natural gas supply in Cusiana entered into in December of 2004, under which Ocensa paid a variable rate to Ecopetrol. In 2018, Ecopetrol S.A. received an aggregate sum of US$ 5.25 million under the contract. On December 1, 2018, the parties agreed to extend the term of the agreements for one year until November 30, 2019. On December 1, 2019, the parties agreed to extend the term of the agreements for two years until December 1, 2021. In 2020, Ecopetrol S.A. received an aggregate sum of US$ 3.67 million under the contract.
Ocensa has entered into the following agreements, among others, with some of our other subsidiaries:
In March 1995, Equión and Santiago Oil Company entered into agreements for the transportation of crude oil through the Oleoducto Central S.A. (Ocensa) pipeline. In November 2012, Equión and Santiago Oil Company transferred, by means of various transactions, its shares (24.8%) and transportation rights (19.8%) holdings in the Ocensa pipeline to wholly owned subsidiaries of Ecopetrol S.A. (51%) and Talisman (49%). Equión and Santiago Oil Company kept 5% of transportation rights in Ocensa. In 2014, the transportation fees billed by Ocensa were: Equión (US$ 44.4 million), Santiago Oil Company (US$ 3.8 million) and Hocol (US$ 30.8 million). On January 17, 2013, this agreement was amended as a result of Ocensa’s new business model. Among other changes, the amendment to the transportation agreement establishes that tariff payments are to be calculated according to resolutions issued by the Ministry of Mines and Energy. On May 23, 2013, another amendment was executed that modified the terms by which the payments of invoices should be made. In 2020, Equión paid Ocensa US$ 0.26 million. Hocol paid Ocensa, as assignee of transportation rights from original shippers, US$ 30.30 million in 2020.
Oleoducto de Colombia S.A. (ODC)
Ecopetrol S.A. entered into the following agreements with its 73%-owned subsidiary, ODC:
In July 1992, a ship-and-pay agreement was signed for the transportation of hydrocarbons. Pursuant to this agreement, Ecopetrol S.A. must pay a previously agreed tariff for the volume of hydrocarbons transported. The duration of this agreement is indefinite; however, the contract will remain in force as long as Ecopetrol S.A. holds shares in Oleoducto de Colombia S.A., whether directly, or through an affiliate. As of January 2013, the parties agreed that the applicable tariff would be the one set by the Ministry of Mines and Energy (the MME Tariff). The MME Tariff had been set in 2011 for a four-year term, with a yearly adjustment based on the consumer price index. In 2020, payments made by Ecopetrol S.A. under this agreement amounted to US$140 million.
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In August 1992, an operation and maintenance agreement was signed for the Vasconia and Coveñas terminals both property of ODC. The duration of this agreement is indefinite, but can be terminated by any party upon six months’ notice. The initial contract included services rendered by Ecopetrol directly or by third-party contractors hired by Ecopetrol through mandate, with a variable surcharge over expenses and third-party contracts between 5% and 12% plus any applicable taxes. In 2014, an amendment to the agreement was signed, adjusting the monthly fixed rate to include expenses of services rendered directly by Ecopetrol, plus an additional 10% fee, and to eliminate the administrative surcharge. The contract also includes a variable sum related to contracts and purchases made by Ecopetrol through mandate. In March 2015, the monthly rate was adjusted for both Vasconia and Coveñas Stations. In March 2016, an amendment to the agreement was signed, adjusting the agreement’s scope to include the pipeline’s maintenance and adjusting the monthly fixed rate. In December 2017, an amendment to the agreement was signed, adjusting the agreement’s scope according to the change of the maintenance model of the midstream segment and including the Caucasia station and the Vasconia-Coveñas pipeline system into the scope. In March 2018, the parties amended the agreement in order to narrow the scope to the purchase and contracting management, and adjust the monthly rate. In February 2019 the scope of this agreement was amended to include planning, structuring, administration, and execution of the agreements signed with the Ministry of National Defense- Fuerzas Militares de Colombia. In July 2020, an amendment to the agreement was signed, adjusting the monthly fixed rate. Pursuant to the terms of this agreement, ODC paid approximately US$ 4.36 million in 2020.
In March 1998, a joint operation agreement was signed for the TLU-1 Coveñas buoy. The duration of this agreement is indefinite and can be terminated by mutual agreement. In December 2013, Ecopetrol S.A. assigned its rights under this agreement to Cenit, though Ecopetrol S.A. kept its role as operator under the agreement. Pursuant to the terms of this agreement, ODC paid Ecopetrol S.A. approximately US$0.86 million in 2020.
In September 1999, a joint operation agreement was signed for the TLU-3 Coveñas buoy between Ocensa, ODC and Ecopetrol. Pursuant to the terms of this agreement, ODC paid approximately US$1.96 million in 2020. The duration of this agreement is indefinite. In December 2013, Ecopetrol S.A. assigned its rights under this agreement to Cenit, though Ecopetrol S.A. kept its role as operator under the agreement.
ODC has entered into the following agreements with some of our other subsidiaries:
Between March 1992 and January 1993, Hocol, Equión and Santiago Oil Company each entered into agreements with ODC for the transportation of crude oil through the Vasconia-Coveñas pipeline. The term of each of these agreements is indefinite. As of January 2013, the applicable tariff is the one set by the Ministry of Mines and Energy. In 2020, the transportation fees billed by ODC were: Equión (US$ 0.71 million) and Hocol (US$ 0.66 million).
Oleoducto de los Llanos Orientales (ODL)
Ecopetrol S.A. has entered into the following agreements, among others, with its 65%-owned subsidiary, ODL:
In March 2009, Ecopetrol S.A. entered into a ship-or-pay agreement with ODL that establishes a financing tariff used to pay ODL’s indebtedness to Grupo Aval for five years. This agreement was superseded by a new contract executed in May 2010, with a seven-year term, to reflect new conditions agreed with Grupo Aval. In August 2013, this contract was amended, providing a new term of seven years, including a two-year grace period, and an interest rate of DTF + 2.5%. This financing tariff is collected through a trust fund, which in turn is responsible for making the debt service payments to Grupo Aval. Under this agreement, ODL has committed to transport 75,000 bpd during the initial two-year grace period of the facility and 90,000 bpd during the remaining years, including the new term. Ecopetrol S.A. is responsible for 65% of this capacity. Payments by Ecopetrol S.A. under this contract were COP$ 63.87 billion in 2020.
In December 2009, Ecopetrol S.A. entered into a service agreement with ODL to transport crude oil. This agreement was replaced in January 2014 by a new agreement that expires in December 2020. This is a ship-or-pay agreement covering 167,000 bpd for 2014, 149,000 bpd for 2015 and 139,000 bpd until 2020. In January 2017, this agreement was amended in order to maintain the economic and commercial balance for the parties, based on changes to the standard condition of the system (to transport crude oil with a 690 cStk viscosity), reducing the “ship-or-pay” capacity from 139,000 bpd to 129.139 bpd until 2020. This agreement was extended under the “ship-and-pay” conditions until December 2021. Payments by Ecopetrol S.A. under this contract were COP$ 678.4 billion in 2020.
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In March 2010, Ecopetrol S.A. entered into a pipeline operating and maintenance agreement with ODL. This agreement had an original five-year term and was amended in 2015 to extend the term another ten years, adjusting certain conditions. In January 2017, this agreement was partially assigned by Ecopetrol to Cenit, due to matters related to the management of plants and pipeline assets. In August 2017, the maintenance obligations were partially assigned by Ecopetrol to a third party. In October 2017 and February 2018, the name of the contract, some technical definitions and the annexes of the contract were updated and certain Ecopetrol’s obligations were removed, in line with the partial assignment. In March 2020 the agreement was finished by the term of the contract and the new one was assigned to a third party. Pursuant to the terms of this agreement, ODL paid to Ecopetrol S.A. COP$ 2.17 billion, plus applicable taxes, in 2020. In addition, pursuant to the partial assignment ODL paid to Cenit COP$ 0.05 billion, plus applicable taxes, in 2020; this agreement terminated in March 2020, and the operation was assigned to a third party.
On August 1, 2015, ODL entered into an indefinite management agreement with Oleoducto Bicentenario by means of which ODL receives legal representation and provides management services to Oleoducto Bicentenario. On August 1, 2017, the agreement was amended in order to change the way ODL is remunerated by this service, improving the structure of the agreement. Pursuant to the terms of this agreement, Bicentenario paid to ODL COP$ 7.68 billion plus applicable taxes in 2020.
Oleoducto Bicentenario de Colombia S.A.S.
Ecopetrol S.A. has entered into the following agreements, among others, with its 55.97% owned subsidiary, Oleoducto Bicentenario:
In June 2012, Ecopetrol S.A. entered into ship-or-pay and ship-and-pay agreements with Oleoducto Bicentenario for the transportation of crude oil from Araguaney to Banadía that established a price which requires the payment of Oleoducto Bicentenario’s indebtedness to local banks for 12 years. This tariff is collected through a trust; the trust is also responsible for making the debt service payments to the banks. The duration of the ship-or-pay agreement is the earlier of 12 years or when the credit has been entirely paid, and the duration of the ship-and-pay agreement is 20 years after the ship-or-pay terminates. Under these agreements, Oleoducto Bicentenario has committed to transport at least 110,000 bpd, of which 55% of the agreement volume is provided directly by Ecopetrol S.A. and 0.97% indirectly by Hocol. In March 2014, the parties signed an amendment to these agreements under which Oleoducto Bicentenario acknowledges having received an advance tariff payment which can be amortized through volumes of crude transported in excess of 110,000 bpd. In April 2015, these agreements were amended to modify certain definitions to reflect new terms from the negotiation of the debt, which included a modification of participant banks and a reduction of the interest rate. In March 2017, the parties signed an amendment to these agreements in order to include the terms and conditions of the “contingent service” that involves the transportation of crude oil from Banadía to Araguaney when this service is required, and includes a ship-or-pay commitment of 270,000 bpd when the contingent service is needed. In addition, this amendment includes an equivalent credit note of one and a half days of service into the original ship-or-pay agreement for the transportation of crude oil from Araguaney to Banadía. Hocol has signed an amendment to the transportation agreement from Araguaney to Banadía, in order to receive the related credit note in case that the availability of the service in that direction is suspended in order to enable the contingent service (Banadía-Araguaney). In September 2017 the agreement was amended to specify that the “contingent capacity” could be over 180,000 barrels per any “contingent service” operation and to extend the term until July 30, 2018. In July |
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In June 2012, Ecopetrol S.A. and Hocol entered into storage or pay and storage and pay agreements with Oleoducto Bicentenario. Under these agreements, Oleoducto Bicentenario is committed to receive, store, preserve and deliver our crude oil. The storage or pay agreement will terminate when Oleoducto Bicentenario’s indebtedness to local banks has been entirely paid, and the duration of the storage and pay agreement is 20 years after the storage or pay agreement terminates. In April 2015, this contract was amended to modify certain definitions to reflect new terms from the negotiation of the debt, which included a modification of participant banks and a reduction of the interest rate. In September 2018, this agreement was assigned by Hocol to Ecopetrol. Pursuant to the terms of this agreement, Ecopetrol and Hocol paid to Bicentenario COP$ 39.0 billion, plus applicable taxes, in 2020.
In August 2012, Ecopetrol S.A. entered into an Operation and Maintenance agreement for the Araguaney – Banadia pipeline system. The duration of this agreement is 15 years. This agreement was partially assigned in January 2017 by Ecopetrol to Cenit due to matters related to the management of plants and pipeline assets. In July 2018 Oleoducto Bicentenario and Cenit signed a settlement agreement to recognize costs related to this contract. The scope of the contract assigned by Ecopetrol to Cenit was finished by the mutual agreement of the parties (Bicentenario and Cenit) in March 2020. Pursuant to the terms of those agreements, Bicentenario paid to Cenit COP$ 0.05 billion, plus applicable taxes, in 2020.
In November 2017, the maintenance obligations of the transportation system (from the first agreement mentioned in the preceding paragraph) were partially assigned to a third party. During December 2017, the agreement with Ecopetrol was modified to exclude from its scope the Araguaney and Banadía Stations’ maintenance. In November 2018, the pipeline maintenance obligations were extended until April 2019. In April 2019, the pipeline maintenance obligations were extended until July 2019. In July 2019, the pipeline maintenance obligations were extended until October 2019. In October 2019, the pipeline maintenance scope was substituted by technical supervision and in July 2020, the technical supervision scope was terminated by mutual agreement of the parties. However, the operational scope of the contract is still valid. Pursuant to the terms of this agreement, Bicentenario paid to Ecopetrol S.A. COP$ 5.83 billion, plus applicable taxes, in 2020.
Ecodiesel
Ecopetrol S.A. (Ecopetrol) entered into a supply agreement for the Barrancabermeja refinery, with Ecodiesel Colombia S.A. (Ecodiesel), a company in which Ecopetrol has a 50% equity interest. The current agreement began on January 25, 2018. Pursuant to the terms of this agreement, Ecodiesel must deliver to Ecopetrol and Ecopetrol must in turn purchase 48,100 barrels of Ecodiesel’s biodiesel production each month. Payments vary depending on the purchased volumes and the prices of biodiesel. This agreement expires on January 31, 2021. In 2020 a total of COP$ 283.4 billion was paid under this contract. In April 2020, Ecopetrol made a spot purchase to Ecodiesel for consumption in the Port of Buenaventura for COP$ 0.4 billion. A new agreement began on February 1, 2020 for the delivery of 50,880 barrels of Ecodiesel’s biodiesel production each month. The new agreement will be active until January 31, 2026.
Additionally, Ecopetrol, as Reficar’s legal agent, signed another supply agreement with Ecodiesel on October 2, 2019 that was valid until September 30, 2020 and pursuant to which Ecopetrol agreed to buy up to 156,000 barrels of biodiesel for a year from Ecodiesel. A total of COP$ 46.4 billion was paid under this contract. On October 1, 2020, Ecopetrol and Ecodiesel signed another supply agreement for the supply of biodiesel to Reficar that is valid until September 30, 2023. Pursuant to the terms of this agreement, Ecodiesel must deliver to Reficar, and Reficar must in turn purchase 10,400 barrels of Ecodiesel’s biodiesel production each month. In the fourth quarter of 2020, Reficar paid a total of COP$ 19.6 billion to Ecodiesel under this agreement.
In 2020, Ecopetrol bought COP$ 283.8 billion worth of biodiesel from Ecodiesel for its own consumption and COP$ 66 billion worth of biodiesel for Reficar’s consumption.
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Savia Peru S.A.
On February 19, 2016, Ecopetrol S.A., as lender and shareholder of 50%, and Savia Perú S.A., as borrower, entered into a five-year loan agreement for an aggregate principal amount not to exceed US$70 million. The proceeds of the facility were used to (i) repay short term loans and (ii) pay shortfalls related to final judgments (in case they materialize). The loan agreement accrues interest at an annual rate of 4.99%, which can be adjusted on an annual basis, with semi-annual interest payments and principal payments beginning on the 21st month following the disbursement date. Total disbursement was US$57 million through the disbursement period ended on December 31, 2017. On December 11, 2019, Ecopetrol and Savia Perú agreed on an amendment to the terms of the loan agreement, in order to revise the payment schedule of the loan, without changing the original maturity, nor the interest rate. As of December 2020, the outstanding balance of the obligation with Ecopetrol is US$28.3 million under the loan agreement. Korea National Oil Corporation (KNOC), as shareholder of the other 50% of Savia Perú S.A., signed a facility under the same terms and conditions as described above.
On January 19, 2021, Ecopetrol S.A. signed a Share Purchase Agreement with De Jong Capital LLC, through one of its subsidiaries as buyer, pursuant to which Ecopetrol sold its 50% ownership interest in OIG. Korea National Oil Corporation (KNOC) also sold its participation on OIG (the remaining 50%) to De Jong Capital LLC, under the same terms and conditions as Ecopetrol.
On the same date, Ecopetrol and Savia Perú agreed on an amendment to the terms of the loan agreement described above, in order to revise the payment schedule of the loan and its maturity, with the interest rate remaining unchanged. As of the date of this annual report, Savia Peru owed US$ 26.8 million to Ecopetrol under this loan agreement.
Transactions with Other State-Controlled Entities
Other than the agreements that we have entered into with the ANH, inIn the ordinary course of business, we enter into transactions with other state-owned entitiesenterprises that include but are not limited to the following:
In addition, we have an agreement with the ANH (National Hydrocarbons Agency) by which we purchase all crude oil delivered to the ANH as royalties by us and by third parties. The purchase price is calculated according to a formula set forth in a contract between Ecopetrol and the ANH that reflects our export sales prices (crudes and products), a quality adjustment for API gravity and sulphur content, transportation rates from the wellhead to the Coveñas or Tumaco ports and a marketing fee. We sell the physical product purchased from the ANH as part of our ordinary business.
For the years ended December 31, 2018, 20172020, 2019 and 2016,2018, we purchased the following volumes of crude oil from the ANH (National Hydrocarbon Agency) corresponding to royalties paid in kind by oil producers in Colombia: 31.0 million barrels, 35.4 million barrels and 37.6 million barrels, 40.3 million barrelsrespectively. The contract between the ANH and 42.9 million barrels, respectively.us was extended until October 31, 2022. See the sectionBusiness Overview—Applicable Laws and Regulations—Regulation of Exploration and Production Activities—Business Regulation—Royalties for a description of the current royalty scheme.
3.11 InsuranceThe ANH is a state agency responsible for the administration and regulation of the nation’s hydrocarbon resources and therefore it is controlled by the State. The State’s control of the ANH arises from the fact that it is a state agency and hence a part of the Colombian government. On the other hand, Ecopetrol is a state-owned enterprise and the Nation’s control of Ecopetrol results from the fact that it is one of our shareholders and owns more than a majority of our common shares. Neither Ecopetrol nor the ANH have the ability to control each other’s actions. Notwithstanding that as a matter of Colombian law neither entity can influence the other, as a matter of U.S. regulation, they are considered to be under common control.
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3.12 | Insurance |
We have a clear and defined corporate policy based on risk financing guidelines that summarizes the Company’s risk transfer and retention alternatives and provides support and guidance for all the insurance-related issues of all of our affiliated and subsidiary companies.
As a proactive strategy to deal with the hardening conditions of the worldwide reinsurance market for the last three years, in July 2020, Ecopetrol became a member of the OIL Pool. OIL is an energy industry mutual insurance company based in Hamilton, Bermuda, established since 1972. This organization operates on the basis of the concept of mutualization, in which several companies threatened by similar risks and with comparable exposure profiles decide to constitute a common fund, based on the individual contribution of each one, depending on the size of their operation and the estimated losses they may suffer as a result of the materialization of such risks. OIL insures assets worldwide for a total value over US$3trillion. Its credit rating is A (S&P) and A2 (Moody's). Currently, 61 companies in the world are members of OIL.
There are threeUnder the model described above, the corporate insurance program has been consolidated in two main categories:
i. | Category A: Coverage through the OIL pool and reinsurance market that includes the risks of physical damage, control of wells and leakage, pollution or contamination (which for the purposes of this annual report, are included in the limit of the third party liability coverage). |
ii. | Category B: Coverage only through the traditional insurance and reinsurance market that includes third party liability, directors and officers, cargo, crime, charterers’ liability and cyber-attack insurance. |
These structures provide coverage for our consolidated downstream, upstream and midstream operations in excess of our local insurance programs covering Ecopetrol S.A. and its subsidiaries. (when applicable).
In the text and tables below we set forth our insurance programsprogram and the companies covered, along with limits and coverage details.
Group 1-Table 47 – Category A: Coverages through the Oil Pool and Reinsurance and Insurance Market for the Downstream Program:This insurance program provides coverage for downstream (assets and operations) of Ecopetrol S.A. and all of its subsidiaries in excess of their local insurance programs, when applicable. Coverage includes all physical damage and sabotage and terrorism, which were designed to cover downstream operations.Segment
Table 40 – Group 1 Downstream Program
Limit (eel / agg)(1) | Deductible | Ecopetrol | ||||||||||||||||||||||||||
US$ Millions | Onshore | Offshore | Onshore | Offshore | Downstream | Reficar | Esenttia | |||||||||||||||||||||
Policies | ||||||||||||||||||||||||||||
Property all risk | 2,200 | N/A | 5 | N/A | X | X | X | |||||||||||||||||||||
Sabotage and terrorism | 600 | N/A | 0.5 | N/A | X | X | X |
Limit (eel/agg)(1) | Deductible | Ecopetrol | ||||||||||||||||||
Onshore | Off shore | On shore | Off shore | Downstream | Reficar | Bioenergy | Esenttia | |||||||||||||
(figures in USD millions) | ||||||||||||||||||||
Policies | ||||||||||||||||||||
Property all risk | 3.50 | N/A | 5 | N/A | X | X | X | X | ||||||||||||
Sabotage and terrorism | 600 | N/A | 0.5 | N/A | X | X | X | X |
(1) | Eel: each and every loss. Agg: Aggregate. |
Group 2 – Upstream Program:This program provides coverage for upstream (assets and operations)Note: Due to its liquidation, Bioenergy was not included in the renewal of Ecopetrol’s interestscorporate insurance program for 2021.
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Table 48 – Category A: Coverages through the Oil Pool and all of its upstream subsidiaries. Coverage includes all physical damage, sabotageReinsurance and terrorism and control of wells.Insurance market for the Upstrem segment
Table 41 – Group 2 Upstream Program
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 |
Limit (eel/agg)*(1) | Deductible | Ecopetrol | Santiago | ECP | ECP Costa | |||||||||||||||||||||||||||
Policies | Onshore | Offshore | Onshore | Offshore | Upstream | Equion | Hocol | Oil | America | Brazil | ODL | Cenit | Afuera | |||||||||||||||||||
(figures in USD millions) | ||||||||||||||||||||||||||||||||
Property all risk | 400(2) | 0.25 for assets over 5 million; 0.05 for assets under 5 million | 0.5 | X | X | X | X | N/A | N/A | N/A | N/A | X | ||||||||||||||||||||
Sabotage and terrorism | 55 | 0 | 0.5 | N/A | X | X | X | X | N/A | N/A | N/A | N/A | X | |||||||||||||||||||
Control of Wells | 250 / 100(3) | 800/ 162.5 / 135 | 0.25 | 5 | /6 | X | X | X | N/A | X | X | N/A | N/A | X |
(1) | Eel: each and every loss. Agg: Aggregate. |
(2) | US$250 million Property All Risk but US$400 million Maximum Loss limit and in the aggregate in respect of earthquakes. |
(3) |
Group 3Table 49 – Category B: Transversal Program:This program provides coverageCoverages through the Traditional Insurance and Reinsurance Market for downstream, upstreamthe Downstream, Upstream and midstream operations of Ecopetrol and its subsidiaries and all of its subsidiaries in excess of their local insurance programs. Coverage includes general liability, directors and officers, cargo, crime and charterers’ liability.Midstream Segments
Table 42 – Group 3 Transversal Program
US$ 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 | ||||||||||||||||
(figures in USD millions) | ||||||||||||||||||||||||||||||||
Third Party Liability | 500 | 1 | X | X | X | X | X | X | X | X | X | X | X | X | X | X | ||||||||||||||||
Crime | 75/150 | Various | X | X | X | X | X | X | X | X | X | N/A | N/A | N/A | N/A | N/A | ||||||||||||||||
Directors & Officers | 170 | Various | X | X | X | X | X | X | X | X | X | X | X | X | X | X | ||||||||||||||||
Cargo | 120 | 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 | ||||||||||||||||
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 |
(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 and ODC) havecontinue having an independent program for itstheir oil transportation companies (including crime and directors & officers policies).
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Table 4350 – Midstream Program
Limit (eel/agg)(1) | Deductible | |||||||||||||||||||||||||
Onshore | Offshore | Onshore | Offshore | Cenit | Ocensa | ODL | OBC | ODC | ||||||||||||||||||
(figures in millions of USD) | ||||||||||||||||||||||||||
Policies | ||||||||||||||||||||||||||
Property all risk | 200 | (2) | 200 | (2) | 0.25 | 0.5 | X | X | X | X | X | |||||||||||||||
Sabotage and terrorism | 70 | 20 | (3) | 0.075 | 0.5 | X | X | X | X | X | ||||||||||||||||
Third Party Liability | 100 | 100 | 0.35 | (4) | 0.35 | (4) | X | X | X | X | X |
Limit (eel / agg)(1) | Deductible | |||||||||||||||||||||||||||||||||||
US$ Millions | Onshore | Offshore | Onshore | Offshore | Cenit | Ocensa | ODL | OBC | ODC | |||||||||||||||||||||||||||
Policies | ||||||||||||||||||||||||||||||||||||
Property all risk(2) | 200 | 200 | 0.250 | 0.50 | X | X | X | X | X | |||||||||||||||||||||||||||
Sabotage and terrorism(3) | 70 | 30 | 0.075 | 0.15 | X | X | X | X | X | |||||||||||||||||||||||||||
Third party liability | 100 | 100 | 0.100 | 0.50 | X | X | X | X | X | |||||||||||||||||||||||||||
Directors & Officers(4) | 75 | - | X | X | X | X | X | |||||||||||||||||||||||||||||
Crime | 50 | 0.175 | X | X | X | X | X |
(1) | Eel: each and every loss. Agg: Aggregate. |
(2) | US$200 million each company and an aggregated excess shared limit of US$ |
(3) |
(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 Inc. is party to Operating Agreements, or OAs, that include customary conditions and which contain similar terms and provisions to those in the Model Form of Offshore Deepwater Operating Agreement of the American Association of Professional Landmen. In general, pursuant to these OAs, the obligations, duties, and liabilities of the contract parties are several, and not joint or collective, for all operations covered by the OAs.
With respect to onshore operations in the U.S., Ecopetrol Permian has been included since its beginning in the Control of Wells, D&O, and cyber and crime policies. In 2020, we obtained a stand-alone policy for the third party liability coverage. Ecopetrol S.A. has a contract with twoan insurance broker for local insurance companies forpolicies related to domestic operations. The local policies relate to transit, accidents, mandatory policies, liability mandatory policies, and personal accidents policies, among others. Additional policies are requested from the insurers as they are needed.
3.13 | Human Resources/Labor Relations |
3.12 Human Resources/Labor Relations
3.13.1 | Employees |
As of December 31, 2018,2020, the Ecopetrol Corporate Group had 12,22813,977 employees, an increasea decrease of 4.3% from 2017.7.8% compared to 2019. This decrease was primarily due to the Bioenergy liquidation, the early retirement plan offered to a group of employees, resignations and termination of temporary contracts. Most of our employees are located in Colombia.
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The table below presents the breakdown of Ecopetrol employees according to the business segments where they work, and the personnel of our subsidiaries for the years ended December 31, 2018, 20172020, 2019 and 2016.2018.
Table 4451 – CorporateEcopetrol Group’s Employees
As of December 31, | ||||||||||||
2018 | 2017 | 2016 | ||||||||||
(number of employees) | ||||||||||||
Ecopetrol S.A. | ||||||||||||
Exploration and Production | ||||||||||||
Exploration | 215 | 197 | 225 | |||||||||
Production | 2,258 | 2,141 | 2,095 | |||||||||
Others | 758 | 639 | 452 | |||||||||
Total Exploration and Production | 3,231 | 2,977 | 2,772 | |||||||||
Downstream | ||||||||||||
Refining | 2,696 | 2,669 | 2,685 | |||||||||
Marketing | 136 | 132 | 133 | |||||||||
Others | 74 | 67 | 72 | |||||||||
Total Downstream | 2,906 | 2,868 | 2,890 | |||||||||
Transport | 798 | 817 | 949 | |||||||||
Others | 351 | 330 | 244 | |||||||||
Total Operations | 7,286 | 6,992 | 6,855 | |||||||||
Corporate | 2,417 | 2,290 | 1,993 | |||||||||
TOTAL ECOPETROL S.A. | 9,703 | 9,282 | 8,848 |
As of December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2020 | 2019 | 2018 | |||||||||||||||||||
(number of employees) | (Number of employees) | |||||||||||||||||||||||
Ecopetrol America Inc. | 68 | 70 | 71 | |||||||||||||||||||||
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. | 441 | 358 | 145 | - | 478 | 441 | ||||||||||||||||||
Bioenergy Zona Franca S.A.S. | 279 | 316 | 258 | - | 287 | 279 | ||||||||||||||||||
Hocol S.A. | 221 | 205 | 179 | 346 | 249 | 221 | ||||||||||||||||||
Equion Energía Limited | 284 | 298 | 321 | |||||||||||||||||||||
Equión Energía Limited | 38 | 242 | 284 | |||||||||||||||||||||
Oleoducto Central S.A. | 275 | 290 | 290 | 283 | 288 | 275 | ||||||||||||||||||
Oleoducto de Colombia S.A. | 3 | 1 | 2 | 15 | 7 | 3 | ||||||||||||||||||
Oleoducto de los Llanos S.A. | 75 | 68 | 55 | 77 | 79 | 75 | ||||||||||||||||||
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 | 6 | 0 | - | - | - | ||||||||||||||||||
Refinería de Cartagena S.A.S. | 153 | 185 | 170 | 98 | 143 | 153 | ||||||||||||||||||
Ecopetrol Óleo e Gás do Brasil Ltda. | 16 | 16 | 16 | 35 | 31 | 16 | ||||||||||||||||||
Polipropileno del Caribe S.A. (now Esenttia S.A.) | 428 | 417 | 408 | |||||||||||||||||||||
Esenttia S.A. | 417 | 412 | 428 | |||||||||||||||||||||
Esenttia MB | 41 | 46 | - | |||||||||||||||||||||
Cenit Transporte y Logistica de Hidrocarburos S.A.S. | 282 | 217 | 156 | 511 | 366 | 282 | ||||||||||||||||||
Invercolsa | 2,247 | 2,371 | - | |||||||||||||||||||||
Ecopetrol Energía S.A. E.S.P | 7 | 5 | - | |||||||||||||||||||||
TOTAL | 12,228 | 11,729 | 10,919 | 13,977 | 15,157 | 12,228 |
The numberAs of Polipropileno del Caribe S.A. (now Esenttia S.A.) employees reported in 2017 was re-stated to include Esenttia Masterbach’sDecember 31, 2020, the subsidiaries Kalixpan Servicios Técnicos, S. de R.L. de C.V., Topili Servicios Administrativos S. de R.L. de C.V., Ecopetrol Capital AG and Black Gold RE did not have direct employees. Essentia Masterbach is a subsidiary of Esenttia S.A.
Loans and investment on training and development for our employees
As partTo improve the quality of its total compensation programme,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. Since January, 2018 and up February 2019,In 2020, Ecopetrol S.A. has extended 913833 housing loans for a total of COP$184 209.6 billion and 2,3291,411 general-purpose loans for a total of COP$21 15.3 billion. In 2018,2020, Ecopetrol S.A. also provided on-site and external training and development, which totaled to COP$20.8 15.9 billion, and it extended a total of COP$213 186.5 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 (defined as first line management under the bylaws of Ecopetrol S.A.) 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 housing loans from Ecopetrol.officers.
Labor Regulation
In accordance with articleArticle 123 of the Colombian Constitution and the articleArticle 7th of the Law 1118 of 2006, our employees are considered “public servants,” even though they are subject to the common labor law. As such, their behavior is subject to the rules to those who handle public interests and goods and could be held liable for their illegal actions and omissions pursuant to the following regimes: (i) disciplinary (Law 734 of 2002), (ii) criminal or (iii) civil.
3.12.2 Declaration of CultureCollective Bargaining Arrangements
In 2020, Ecopetrol updated its Declaration of Culture, which contains the six principles that guide our operation: (i) Life First, (ii) Collaboration, (iii) Ethics & Transparency, (iv) Innovation, (v) Excellence and (vi) Leadership.
3.13.2 | Collective Bargaining Arrangements |
Ecopetrol S.A.
A collective bargaining agreement between us and our mainwith some labor unions governs labor relations with ourbetween Ecopetrol and its unionized employees,workers, which amounted to 50.3%4,933 employees as of January 1, 2019.December 31, 2020. The agreement also governs our labor relations with the 2,657other 2,777 non-unionized employees who, according to current labor legislation, have beenare beneficiaries of the collective bargaining agreement.
We currently have eighteleven industry-wide labor unions and sevennine company labor unions:
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Any employee working forIn 2020, 50.3% of Ecopetrol’s employees were affiliated with one of the above trade union organizations. As of the same date and in accordance with the governing legal provisions, the current Collective Bargaining Agreement (described below) applied to 78.3% of Ecopetrol S.A.’s total workers, out of which 28% were workers who were not affiliated with any company inTrade Union Organization but were beneficiaries of the oil and gas industry may joinCollective Bargaining Agreement by extension under Article 471 numeral 1 of the USO, ADECO, SINDISPETROL, UTIPEC, ASTIP, SINATRINHI, ASINTRAHC or SINTRAMANPETROL. Only our employees may join the company labor unions.Substantive Labor Code.
Ecopetrol S.A.’s relations with unions are based on a permanent dialogue and communication sessions where different matters are discussed in order to solve and prevent any labor conflict.
Our current collective bargaining agreement has been in effect since July 1, 2018 and has a term of four and half years, expiring on December 31, 2022. The collective bargaining agreement included an increase in salaries at an annual rate of the local consumer price index (CPI) +1.21% for the remainder of 2018 and CPI +1.70% every year for the remainder of its duration. The agreement covers health, food, loans and transportation, among other benefits for workers, within reasonable criteria. It also includes union guarantees and addresses regulatory issues.
During 2020, the agreements contained in the Collective Labor Convention 2018 – 2022 were performed, as were other agreements signed in the framework of the collective bargaining agreement process. In addition, a number of areas of dialogue with trade unions were advanced and different issues pertaining to their interest were addressed. A total of 425 meetings were scheduled.
The followingCompany manages compliance with trade unions are partiesrights with respect to the new collective bargaining agreement: USO, ADECO, TRASINE, UTIPEC, APROTECO, SINDISPETROLdiscount of trade union dues, permits and ASINTRAHC.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, 2016, 20172018, 2019 and 20182020 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.
4.1 Factors Affecting Our Operating Results
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 section Trend Analysis and Sensitivity Analysis—Trend Analysis for further information.
Sales volumes and prices
Our results from the exploration and production segment depend mainly on our sales volumes and average local and international prices for crude oil and natural gas. Additionally, sales volumes also reflect the purchase of crude oil and natural gas that we make from third parties and the ANH.
We sell crude oil and natural gas in the local and the international market.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 49.9%represented 48.4% of our total revenues, on average, for the past three years.
International Salessales and Pricesprices
Our foreigninternational sales represented 50.1%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$423,939787,466 million in 2018.2020.
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 sulfursulphur 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 JanuaryOctober 31, 2020.2022.
Since 2016, we have imported crude oil for Reficar feedstock when such imports result in better operational or economic performance of the Ecopetrol Group.
4.2 | Effect of the COVID-19 Pandemic on our 2020 Results |
The Covid-19 outbreak was first reported in late 2019 in China. Subsequently, taking into account the level of Taxes, Exchange Rate Variation, Inflationexpansion, 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 Price of Oil on our Resultsimpact could be material.”
4.2.1 TaxesThis 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 |
4.3.1 | Taxes |
In December 2016, the Colombian Congress adopted Law 1819, which introduced changes to the Colombian tax system, applicable beginning in 2017.
The 2016 Tax Reform included two tax benefits that are expected to improve the operations of the oil and gas industry:
Certificado de Reembolso Tributario (CERT) incentive:
For exploration activities, the “CERT” incentive was approved, consisting of the reimbursement of part of the investment made in the exploration phase.
The CERT is granted when the income tax return is filed.
The CERT can only be redeemed to pay taxes at the national level and its effective maturity date is two years after it is issued. Nevertheless, Decree 2253 of 2017 establishes that a CERT redemption can be made from year two to year five, as from the date of the granting of the incentive. The CERT can also be sold and traded in fixed income market.
For production activities, the CERT reimbursement is granted exclusively to investments that increase the recovery factor, i.e. investments that increase the reserves that are currently proved in certain wells.
On December 29, 2017, the Colombian Government issued Decree 2253, which establishes that companies who (i) qualify as operators of association agreements entered into with Ecopetrol, (ii) have exploration and production of hydrocarbons agreements and (iii) are currently involved in the exploration and production of hydrocarbons, among others, can also qualify for the CERT. Additionally, the CERT will not qualify as taxable income or capital gain for the taxpayer receiving or acquiring such incentive.
On March 23, 2018, the following Resolutions were issued in order to regulate the procedures and requirements that companies must comply to claim the CERT: 0860 of Ministry of Finance and Public Credit, 108 of ANH and 40284 and 40285 of Ministry of Mines and Energy.
On December 20, 2019, the Ministry of Finance and Public Credit informed the Company that the PGN includes the resources of CERT.
Refundable VAT on oil and gas exploration:
Taxpayers in the oil and gas industry are entitled to refund VAT paid in the exploration phase for offshore projects. Taxpayers can request for this VAT as of the next fiscal year in which the investment was made. VAT that is reimbursed cannot be used as a higher cost or expense for income tax purposes.
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Additionally, in December 2018, the Colombian Congress adopted Law 1943, which introduced the following key changes to the Colombian tax system, applicable beginning in 2019, including the following aspects:
The corporate income tax rates were set to be reduced gradually from 33% to 30% as follows: 33% in 2019, 32% in 2020, 31% in 2021 and 30% from 2022 onward.
The presumptive income tax rate was reduced to 1.5% for fiscal year 2019.
Taxpayers must calculate their taxable income taking as initial base the year and result under Colombian IFRS. Accounting profit is reconciled to obtain the net income tax, which is the basis to calculate the income tax.
For fiscal year 2018 and 2019 the newly enacted dividends tax applies as follows:
For non-resident shareholders: (i) a 5% dividend tax |
For Colombian individuals: for fiscal year 2018, dividends paid were taxed at 5% if they were between 600 and 1,000 Tax Value Unit |
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 Seesee Note 10.410.2.4 of our Finacial Statements.
The 2016 Tax Reform included two tax benefits that are expected to improve the operations of the oil and gas industry:
“CERT: Certificado de Reembolso Tributario” incentive:
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.
Refundable VAT on O&G exploration:
In December 2018,2019, the Colombian Congress adopted Law 1943,2010, 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:
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 |
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
4.2.2Exchange Rate VariationThe wealth tax at a rate of 1%, on January 1 of each fiscal year 2020 and 2021. The taxable base is the taxpayer’s net equity on each of the accrual dates (gross equity less liabilities and certain exclusions, including a portion of the value of the dwelling house and 50% of the goods repatriated to normalization). In any case, the taxable base for fiscal year 2021 may not vary by more than 25% of the prior year’s inflation.
Thin capitalization: A 2:1 debt-to-equity ratio determines the amount of deductible interests on loans with related parties.
Law 2010 maintains the tax regime for profits derived from indirect transfer of Colombian assets.
As of 2020, the transfer (or disposal) of real estate whose value is higher than 29,800 UVT (approximately COP$918,436,000) will no longer be subject to the real estate consumption (excise) tax (formerly applied at 2%). This tax was specifically repealed by the Constitutional Court and was not re-introduced by Congress in Law 2010.
A special regime (the Mega Investments Regime) was created for taxpayers who (i) generate at least 400 direct jobs and (ii) make new investments in Colombia in an amount equal to or greater than 30,000,000 UVT (COP$1,068,210,000,000) by 2020, with a view for them to calculate and settle their income tax liability for the next 20 years using the following metrics and/or policies:
i. | 27% income tax rate; |
ii. | Two-year term for the depreciation for fixed assets; |
iii. | Exclusion from the presumptive income regime; |
iv. | Exclusion from the wealth tax; and |
v. | 0.75% premium over the investment value to be paid on an annual basis. |
In addition, legal taxpayers who qualify for this Mega Investment Regime are required to enter into agreements with the tax authority.
These rules do not apply to taxpayers engaged in the exploration of non-renewable natural resources.
4.3.2 | Exchange Rate Variation |
The functional currency of each of the companies of Ecopetrol Group is determined in relation to the main economic environment where each company operates; however, our consolidated financial results are reported in Colombian Pesos, which is the Ecopetrol Group’s functional and presentation currency. A substantial part of our consolidated revenues comes from the Ecopetrol 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 2018, the Colombian Peso depreciated slightly on average 0.2% against the U.S. dollar. During 2017, the Colombian Peso appreciated on average 3.35% against the U.S. dollar. In 2016,2020, the Colombian Peso depreciated on average 11.18%12.46% against the U.S. dollar. During 2019 and 2018, the Colombian Peso depreciated on average 11.02% and 0.2%, respectively, against the U.S. dollar. Additionally, as of December 31, 2020, December 31, 2019 and December 31, 2018, the Colombian Peso/U.S. dollar exchange rate had depreciated 8.91% from the rate a year earlier. In contrast, of December 31, 20174.74%, 0.84% and December 31, 2016, the Colombian Peso/U.S. dollar exchange rate appreciated 0.56% and 4.72%8.91% respectively from the rate a year earlier.
In 2020, our consolidated debt in foreign currency increased by a total of US$2,420 million as Ecopetrol S.A. entered into committed credit lines in an aggregate principal amount of US$665 million and issued an SEC-registered bond in an aggregate amount of US$2,000 million. In 2019, our consolidated debt in foreign currency decreased by a total of US$159 million mainly as a result of amortization of foreign currency capital expenditures. In 2018, our consolidated debt in foreign currency decreased by a total of US$2,123 million mainly as a result of prepayments of local and foreign currency of US$2,446 million and amortization of foreign currency capital expenditures. 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. In 2016, our consolidated debt in foreign currency increased by a total of US$975 million as Ecopetrol S.A. raised US$475 million through international loans and US$500 million through an international bond issuance.
As of December 31, 20182020, our U.S. dollar denominated total debt was US$10,46712,728 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$9,68912,598 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.
InSince 2015, Ecopetrol S.A. adopted hedge accounting, using two types of natural hedges with its U.S. dollar debt as a financial instrument: (i) a cash flow hedge for exports of crude oil and (ii) a hedge of the net investment in foreign operations. As a result of the implementation of both hedges 67.1%67.9% (US$6,5008,549 million) of Ecopetrol S.A.’s debt in U.S. dollars, as of December 31, 2018,2020, 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, 2018,2020, the Ecopetrol GroupGroup’s companies have the equivalent of a net U.S. dollar liability position of US$0.71,424 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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4.3.3 | Effects of Inflation |
The average annual rate of inflation in Colombia for the past ten years is 4.04%3.70%. It decreased in 20182020 as compared to 2017.2019. As measured by the general consumer price index, average annual inflation in Colombia for the years ended December 31, 2020, 2019 and 2018 2017was 1.61%, 3.80% and 2016 was 3.18%, 4.09% and 5.75%, respectively. The decrease in inflation in 20182020 is mainly due to the favorableCOVID-19 pandemic, which created an abrupt supply and demand shock on Colombian CPI, particularly as a result of weak demand, significant excess productive capacity, a very tight labor market and price behavior of both tradable and non-tradable items. 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.
4.2.4Effects of the Crude Oil Price
4.3.4 | Effects of Crude Oil and Refined Product Prices |
The average price of ICE Brent crude in 20182020 was US$71.743.2 per barrel as compared to US$54.764.2 per barrel in 20172019 and US$45.171.7 per barrel in 2016.2018. See sectionStrategy and Market Overview. for more information.
In addition, Ecopetrol’Ecopetrol’s average crude oil basket price relative to ICE Brent reported a discount ofwas US$8.5034.4 per barrel in 2018, a higher discount than2020, as compared to US$58.6 per barrel in 2019 and US$63.2 per barrel in 2018. The decrease of US$24.2 per barrel in 2020 as compared to 2019 was mainly due to the US$6.90decrease in 2017the international Brent price and a lower discount thanweaker spread between the $9.40 observedprice 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 2016 due to: (i) our knowledge of the refiningIndia and Spain, and a sustained market for heavy and intermediate crudes, (ii) the ability to identify and capture opportunitiesshare in the United States Gulf of Mexico and Asia, and (iii) the incorporation of new refinery customers in those markets. OurChina.
In addition, Ecopetrol’s average product basket price crude oil basket was US$63.249.2 in 2020, US$69.8 in 2019, and US$77.30 in 2018. The decrease of US$20.6 per barrel in 20182020 as compared to US$47.8 per barrel2019 was primarily the result of a decrease in 2017 and US$35.7 per barrel in 2016, which representsthe international Brent price, partially offset by (i) an increase in our sales volumes at the beginning of US$15.4 per barrelthe year at higher prices and (ii) our active commercial management that allowed us to export the production surpluses, which in 2018 compared to 2017.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-recurringnon-current assets.
For additional information about impairment charges and reversals, see sectionsOperating Results—Results—Consolidated Results of Operations—Impairment of non-currentNon-Current assets,Segment Performance and Analysis and Note 1618 to our consolidated financial statements.
4.4 | Accounting Policies |
Our consolidated financial statements for the years ended December 31, 2018, 20172020, 2019 and 20162018 were prepared in accordance with IFRS. The detail of the accounting policies is described in Note 4 to our consolidated financial statements.
We adopted IFRS 16 – Leases as from January 1, 2019. Also, we adopted IFRS 9 – Financial Instruments and IFRS 15 – Renevue fron Contracts and Customers as from January 1, 2018. The adoption of such standards did not generate a material impact in our results. For more information regarding the adoption of new accounting standards and their effects on our financial statements, see Note 5.1 New standards adopted by the Ecopetrol Group to our consolidated financial statements included in this annual report.
4.4Critical Accounting Judgments and Estimates
4.5 | Critical Accounting Judgments and Estimates |
Critical accounting policies are those policies that require us to exercise judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations. The accounting judgments and estimates we make in these contexts require us to calculate variables and make assumptions about matters that are highly uncertain. In each case, if we had made other estimates, or if changes in the estimates occur from period to period, our financial condition and results of operations could be materially affected.
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See Note 3 to our consolidated financial statements for a summary of the critical accounting judgments and estimates applicable to us. There are many other areas in which we use estimates about uncertain matters, but we believe the reasonably likely effect of changedchanges or differentdifferences within critical accounting judgments and estimates would not behave a material toimpact on our financial presentation.statements.
4.6 | Operating Results |
The following discussion is based on information contained in our audited consolidated financial statements and should be read in conjunction therewith.
4.5.1Consolidated Results of Operations
4.6.1 | Consolidated Results of Operations |
The following table sets forth components of our income statement for the years ended December 31, 2018, 20172020, 2019 and 2016.2018.
Table 4552 – Consolidated Income Statement
Income Statement | For the Years ended December 31, | % Change | For the year ended December 31, | % Change | ||||||||||||||||||||||||||||||||||||
(Colombian Pesos in millions) | 2018 | 2017 | 2016 | 2018/2017 | 2017/2016 | |||||||||||||||||||||||||||||||||||
(COP$ Million) | 2020 | 2019 | 2018 | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||||||
Revenue | 68,603,872 | 55,954,228 | 48,485,561 | 22.6 | 15.4 | 50,223,393 | 71,488,512 | 68,603,872 | (29.7 | ) | 4.2 | |||||||||||||||||||||||||||||
Cost of sales | 41,184,379 | 36,908,325 | 34,251,423 | 11.6 | 7.8 | 37,567,472 | 44,972,360 | 41,184,379 | (16.5 | ) | 9.2 | |||||||||||||||||||||||||||||
Gross Profit | 27,419,493 | 19,045,903 | 14,234,138 | 44.0 | 33.8 | 12,655,921 | 26,516,152 | 27,419,493 | (52.3 | ) | (3.3 | ) | ||||||||||||||||||||||||||||
Operating expenses | 4,592,445 | 4,185,186 | 4,400,843 | 9.7 | (4.9 | ) | 4,841,000 | 3,726,557 | 4,592,445 | 29.9 | (18.9 | ) | ||||||||||||||||||||||||||||
Impairment of non-current assets | 368,634 | (1,311,138 | ) | 928,747 | (128.1 | ) | (241.2 | ) | ||||||||||||||||||||||||||||||||
Impairment (recovery) of non-current assets, net | 633,156 | 1,762,437 | 368,634 | (64.1 | ) | 378.1 | ||||||||||||||||||||||||||||||||||
Operating Income | 22,458,414 | 16,171,855 | 8,904,548 | 38.9 | 81.6 | 7,181,765 | 21,027,158 | 22,458,414 | (65.8 | ) | (6.4 | ) | ||||||||||||||||||||||||||||
Finance results, net | (2,010,375 | ) | (2,495,731 | ) | (1,175,367 | ) | (19.4 | ) | 112.3 | (2,481,587 | ) | (1,670,494 | ) | (2,010,375 | ) | 48.6 | (16.9 | ) | ||||||||||||||||||||||
Share of profit of companies | 165,836 | 93,538 | 61,345 | 77.3 | 52.5 | |||||||||||||||||||||||||||||||||||
Share of profit in associates and joint ventures | 76,336 | 366,904 | 165,836 | (79.2 | ) | 121.2 | ||||||||||||||||||||||||||||||||||
Income before income tax | 20,613,875 | 13,769,662 | 7,790,526 | 49.7 | 76.7 | 4,776,514 | 19,723,568 | 20,613,875 | (75.8 | ) | (4.3 | ) | ||||||||||||||||||||||||||||
Income tax | (8,258,485 | ) | (5,800,268 | ) | (4,543,046 | ) | 42.4 | 27.7 | ||||||||||||||||||||||||||||||||
Net Income (loss) | 12,355,390 | 7,969,394 | 3,247,480 | 55.0 | 145.4 | |||||||||||||||||||||||||||||||||||
Net income (loss) attributable to: | ||||||||||||||||||||||||||||||||||||||||
Income tax expense | (2,038,661 | ) | (4,718,413 | ) | (8,258,485 | ) | (56.8 | ) | (42.9 | ) | ||||||||||||||||||||||||||||||
Net Income | 2,737,853 | 15,005,155 | 12,355,390 | (81.8 | ) | 21.4 | ||||||||||||||||||||||||||||||||||
Net income attributable to: | ||||||||||||||||||||||||||||||||||||||||
Company’s shareholders | 11,381,386 | 7,178,539 | 2,447,881 | 58.5 | 193.3 | 1,586,677 | 13,744,011 | 11,381,386 | (88.5 | ) | 20.8 | |||||||||||||||||||||||||||||
Non-controlling interest | 974,004 | 790,855 | 799,599 | 23.2 | (1.1 | ) | 1,151,176 | 1,261,144 | 974,004 | (8.7 | ) | 29.5 | ||||||||||||||||||||||||||||
Net Income (loss) | 12,355,390 | 7,969,394 | 3,247,480 | 55.0 | 145.4 | |||||||||||||||||||||||||||||||||||
Net Income | 2,737,853 | 15,005,155 | 12,355,390 | (81.8 | ) | 21.4 |
4.6.1.1 | Total Revenues |
The following table sets forth our principal sources of third-party revenues by business segment for the years ended December 31, 2018, 20172020, 2019 and 2016.2018. An explanation of how we classify our operations into business segments is included in Section 4.5.1.8section 4.6.1.8 below.
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Table 4653 – Third-Party Revenues by Business Segment
2018 | 2017 | 2016 | Change Sales Revenues (%) | |||||||||||||||||||||||||||||||||||||||||
Revenue by segment | Volumen (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) | 2018/2017 | 2017/2016 | |||||||||||||||||||||||||||||||||
Local Crude oil | 2,919,416 | 60.8 | 550,479 | 6,629,362 | 46.5 | 909,871 | 5,288,631 | 35.0 | 553,666 | (39.5 | ) | 64.3 | ||||||||||||||||||||||||||||||||
Foreign Crude oil | 143,208,235 | 63.2 | 26,898,737 | 151,619,346 | 47.8 | 21,426,666 | 159,311,257 | 35.7 | 17,278,579 | 25.5 | 24.0 | |||||||||||||||||||||||||||||||||
Natural gas local | 28,065,889 | 22.5 | 1,885,846 | 26,998,537 | 22.8 | 1,815,754 | 27,543,046 | 23.6 | 1,988,336 | 3.9 | (8.7 | ) | ||||||||||||||||||||||||||||||||
Foreign natural gas | 530,945 | 17.7 | 27,899 | 618,022 | 17.7 | 32,303 | 931,754 | 20.9 | 58,809 | (13.6 | ) | (45.1 | ) | |||||||||||||||||||||||||||||||
Other income(1) | 3,216,650 | - | 749,939 | 3,412,568 | 819,726 | 1,288,736 | 647,942 | (8.5 | ) | 26.5 | ||||||||||||||||||||||||||||||||||
Exploration and production sales | 177,941,135 | 30,112,900 | 189,277,835 | 25,004,320 | 194,363,424 | 20,527,332 | 20.4 | 21.8 | ||||||||||||||||||||||||||||||||||||
Local refined products | 108,781,359 | 81.9 | 26,354,549 | 106,891,163 | 67.2 | 21,187,091 | 106,047,637 | 54.9 | 17,771,166 | 24.4 | 19.2 | |||||||||||||||||||||||||||||||||
Foreign refined products | 41,577,284 | 68.6 | 8,485,932 | 38,268,394 | 53.2 | 6,005,556 | 51,843,743 | 40.4 | 6,330,648 | 41.3 | (5.1 | ) | ||||||||||||||||||||||||||||||||
Foreign Crude oil | - | - | - | 341,366 | 53.0 | 52,397 | - | - | - | (100.0 | ) | - | ||||||||||||||||||||||||||||||||
Other income(1) | - | - | 107,467 | - | 98,315 | - | - | 92,210 | 9.3 | �� | 6.6 | |||||||||||||||||||||||||||||||||
Refining and petrochemicals | 150,358,643 | 34,947,948 | 145,500,923 | 27,343,359 | 157,891,380 | 24,194,024 | 27.8 | 13.0 | ||||||||||||||||||||||||||||||||||||
Transportation services | - | 3,543,024 | - | 3,606,549 | - | - | 3,764,205 | (1.8 | ) | (4.2 | ) | |||||||||||||||||||||||||||||||||
Transportation and logistics | - | - | 3,543,024 | - | - | 3,606,549 | - | - | 3,764,205 | (1.8 | ) | (4.2 | ) | |||||||||||||||||||||||||||||||
Total sales | 328,299,778 | 68,603,872 | 334,778,758 | 55,954,228 | 352,254,804 | - | 48,485,561 | 22.6 | 15.4 | |||||||||||||||||||||||||||||||||||
Crude Oil | 146,127,651 | 63.2 | 27,449,216 | 158,590,074 | 47.8 | 22,388,934 | 164,599,888 | 35.7 | 17,832,245 | 22.6 | 25.6 | |||||||||||||||||||||||||||||||||
Natural gas | 28,596,834 | 22.4 | 1,913,745 | 27,616,559 | 22.7 | 1,848,057 | 28,474,800 | 23.5 | 2,047,145 | 3.6 | (9.7 | ) | ||||||||||||||||||||||||||||||||
Refined products | 153,575,293 | 77.3 | 35,590,420 | 148,572,125 | 62.7 | 28,012,373 | 159,180,116 | 50.1 | 24,101,814 | 27.1 | 16.2 | |||||||||||||||||||||||||||||||||
Transportation services and others | - | 3,650,491 | - | 3,704,864 | - | 4,504,357 | (1.5 | ) | (17.8 | ) | ||||||||||||||||||||||||||||||||||
Total sales | 328,299,778 | 68,603,872 | 334,778,758 | 55,954,228 | 352,254,804 | 48,485,561 | 22.6 | 15.4 | ||||||||||||||||||||||||||||||||||||
2020 | 2019 | 2018 | Change Sales Revenues (%) | ||||||||||||||||||||||||||||||
Revenue by segment | Volume (barrels equivalent) | Average price US$/barrels | Sales revenues (COP$ Million) | Volume (barrels equivalent) | Average price US$/barrels | Sales revenues (COP$ Million) | Volume (barrels equivalent) | Average price US$/barrels | Sales revenues (COP$ Million) | 2020/2019 | 2019/2018 | ||||||||||||||||||||||
Local Crude oil | 2,208,356 | 28.6 | 230,520 | 2,232,087 | 48.6 | 356,857 | 2,919,416 | 60.8 | 550,479 | (35.4 | ) | (35.2 | ) | ||||||||||||||||||||
Foreign Crude oil | 153,185,623 | 34.4 | 19,498,553 | 147,692,547 | 58.7 | 28,461,601 | 143,208,235 | 63.2 | 26,898,737 | (31.5 | ) | 5.8 | |||||||||||||||||||||
Natural gas local | 31,391,611 | 24.5 | 2,845,155 | 28,798,105 | 23.8 | 2,256,123 | 28,065,889 | 22.5 | 1,885,846 | 26.1 | 19.6 | ||||||||||||||||||||||
Foreign natural gas | 554,742 | 8.6 | 17,231 | 506,556 | 16.6 | 27,255 | 530,945 | 17.7 | 27,899 | (36.8 | ) | (2.3 | ) | ||||||||||||||||||||
Other income(1) | 5,409,528 | - | 263,466 | 3,788,550 | - | 193,282 | 3,216,650 | - | 749,939 | 36.3 | (74.2 | ) | |||||||||||||||||||||
Exploration and production sales | 192,749,860 | - | 22,854,925 | 183,017,845 | - | 31,295,118 | 177,941,135 | - | 30,112,900 | (27.0 | ) | 3.9 | |||||||||||||||||||||
Local refined products | 90,659,046 | 54.1 | 17,745,376 | 111,095,596 | 74.5 | 27,170,498 | 108,781,359 | 81.9 | 26,354,549 | (34.7 | ) | 3.1 | |||||||||||||||||||||
Foreign refined products | 39,668,072 | 42.4 | 6,165,364 | 44,007,684 | 62.3 | 8,977,662 | 41,577,284 | 68.6 | 8,485,932 | (31.3 | ) | 5.8 | |||||||||||||||||||||
Foreign Crude Oil | - | - | 29 | 289,289 | 62.6 | 61,995 | - | - | - | (100.0 | ) | 100.0 | |||||||||||||||||||||
Other income(1) | - | - | 894,118 | - | - | 183,315 | - | - | 107,467 | 387.7 | 70.6 | ||||||||||||||||||||||
Refining and petrochemicals(2) | 130,327,118 | - | 24,804,887 | 155,392,569 | - | 36,393,470 | 150,358,643 | - | 34,947,948 | (31.8 | ) | 4.1 | |||||||||||||||||||||
Transportation services | - | - | 2,563,581 | - | - | 3,799,924 | - | - | 3,543,024 | (32.5 | ) | 7.3 | |||||||||||||||||||||
Transportation and logistics | - | - | 2,563,581 | - | - | 3,799,924 | - | - | 3,543,024 | (32.5 | ) | 7.3 | |||||||||||||||||||||
Total sales | 323,076,978 | - | 50,223,393 | 338,410,414 | - | 71,488,512 | 328,299,778 | - | 68,603,872 | (29.7 | ) | 4.2 | |||||||||||||||||||||
Crude Oil | 155,393,979 | 34.4 | 19,729,102 | 150,213,923 | 58.6 | 28,880,453 | 146,127,651 | 63.2 | 27,449,216 | (31.7 | ) | 5.2 | |||||||||||||||||||||
Natural gas | 31,946,353 | 24.3 | 2,862,386 | 29,304,661 | 23.7 | 2,283,378 | 28,596,834 | 22.4 | 1,913,745 | 25.4 | 19.3 | ||||||||||||||||||||||
Refined products | 135,736,646 | 49.2 | 24,174,206 | 158,891,830 | 69.8 | 36,341,442 | 153,575,293 | 77.3 | 35,590,420 | (33.5 | ) | 2.1 | |||||||||||||||||||||
Transportation services and others | - | - | 3,457,699 | - | - | 3,983,239 | - | 3,650,491 | (13.2 | ) | 9.1 | ||||||||||||||||||||||
Total sales | 323,076,978 | - | 50,223,393 | 338,410,414 | - | 71,488,512 | 328,299,778 | - | 68,603,872 | (29.7 | ) | 4.2 |
(1) | Since 2020, Invercolsa’s sales are recognized as income from gas service without associated volume. In order to give comparability to our financial information, the values reported as residential gas were classified as “other income” in 2019. |
(2) | In the case of the exploration and production segment, other income corresponds mostly to services and sales of refined products (mainly LPG and asphalt) |
In 2018,2020, total revenues increaseddecreased by 22.6%29.7% as compared to 2017,2019, primarily as a result of: (i) a COP$12,898,39221,330,388 million increasedecrease in revenues mainly due to the 32.2%a 41.3%, or US$15.424.2 per barrel, decrease of our average crude oil basket price and a 29.5%, or US$20.6 per barrel decrease of our average refined products basket price, which in case in turn was primarily the result of the decrease in the international crude oil and product reference prices, (ii) a COP$4,246,388 million decrease in revenues attributable to the decrease in our sales volume (as further explained below) and (iii) a COP$723,744 decrease in revenues attributable to a decrease in the service revenue of our transportations and logistics segment, which in turn was primarily due to a decrease in transported volumes. These decreases were partially offset by a COP$5,035,401 million increase in revenues resulting from a 12.46% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$3,282.39/US$1.00 in 2019 to an average exchange rate of COP$3,691.27/US$1.00 in 2020, resulting in an increase in revenue from exports.
The decrease of our sales volume in 2020 as compared to 2019 was the result of a 14.6%, or 23.2 mbe, decrease in refined products volumes, which in turn was primarily due to the contraction in demand caused by the COVID-19 pandemic. This decrease was partially offset by (i) a 3.4%, or 5.2 mbpe, increase in our crude sales volume which was resulting from higher availability associated with lower throughput at our refineries and (ii) a 9.0%, or 2.6 mbe, increase in natural gas sales volume due to Hocol’s acquisition of 100% of Chevron Petroleum Company’s participation in the Guajira association contract (which corresponds to 43% of the total contract) and the entry into operation of the Cupiagua LPG plant.
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In 2019, total revenues increased by 4.2% as compared to 2018, primarily as a result of: (i) a COP$5,951,875 million increase resulting from the 11.02% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$2,956.55/US$1.00 in 2018 to an average exchange rate of COP$3,282.39/US$1.00 in 2019, resulting in an increase in sales revenue from exports, (ii) a COP$2,322,792 million revenue increase attributable to the increase in our sales volume explained below and (iii) a COP$292,590 increase in services revenue from our transportations and logistics segment, primarily due to an increase in transported volumes. This increase was partially offset by: the 7.3%, or US$4.6 per barrel, decrease of our average crude oil basket price, which in turn was primarily the result of the betterlower performance of the Brent crude benchmark price, and the 23.3%9.7%, or US$14.67.5 per barrel increase,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 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.IMO 2020.
The decreaseincrease of our sales volume in 20182019 as compared to 20172018 was the result ofof: (i) the 7.9%2.8%, or 12.5 mbe, decrease4.1 mbpe, increase in our crude sales volume which was primarily the result of lowerhigher crude exports due to Asia and the US Gulf Coast as a greater allocationresult of domestic crudes to supply Reficar in order to replace imports. This decrease was partially offset by (i) the 3.4%Company’s commercial strategy, higher production level and an increase of purchases, (ii) the 3.5%, or 5.05.3 mbe, increase in refined products volumes due to greater refining throughputan 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 (ii)an increase in exports of diesel due to better realization price in the 3.5%international markets and (iii) the 2.5%, or 1.00.7 mbe, increase in natural gas sales volume, primarily due to greater demandthe incorporation of new fields and active incremental sales.marketing processes during 2019.
In 2017, total revenues increased by 15.4% as compared to 2016, primarily as a result of a COP$10,971,709 million increase in revenues mainly due to the 33.9%, or US$12.1 per barrel increase of our average crude oil basket price and a smaller discount of Ecopetrol’s average crude oil basket price from international prices. This increase was partially offset by: (i) a COP$1,894,819 million decrease in revenues attributable to the decrease in our sales volume and a COP$261,200 decrease in services provided by our transportations and logistics segment and (ii) the 3.35% appreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$3,053.42/US$1.00 in 2016 to an average exchange rate of COP$2,951.15/US$1.00 in 2017, resulting in a decrease in sales revenue from exports, which represented a decrease of COP$1,347,023 million.
The decrease of our sales volume in 2017 as compared to 2016 was the result of (i) the 3.7%, or 6 mbe, decrease in our crude sales volume caused mainly by lower crude exports due to a greater allocation of domestic crudes to supply Reficar in order to replace imports, (ii) the 6.7%, or 10.7 mbe, decrease in refined products volumes due to lower exports of diesel, primarily due to: (a) our strategy of focusing on allocating higher volumes to the domestic market to supply local demand and replace imports which resulted in lower cost of sales and better gross margin, (b) lower exports of fuel oil, and (c) a decrease in production at the Barrancabermeja refinery as a result of reliance on more efficient alternative sources, and (iii) the 3%, or 0.86 mbe, decrease in natural gas sales volume due to continued lower thermal demand as a result of no effect of the “El Niño” weather phenomenon that ended in the middle of 2016.
Our cost of sales was principally affected by the factors described below. See Note 2426 to our consolidated financial statements for more detail.
Cost of sales in 20182020 was COP$41,184,37937,567,472 million, representing a COP$4,276,0547,404,888 million or 11.6%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$3,787,981 million or 9.2% increase as compared to 2017,2018, primarily as a result of the following factors:
A COP$ |
A COP$ |
A COP$ |
A COP$ |
A COP$ |
The factors mentioned above were partially offset by:
A COP$ |
Cost of sales in 2017 was COP$36,908,325 million, representing a COP$2,656,902 million or 7.8% increase as compared to 2016, primarily as a result of the following factors:
The factors mentioned above were partially offset by a COP$231,222490,183 million increasedecrease in our consumption of inventories and an increasegiven our strategy to supply products in unit costs associated with the increase of the Brent price of crude oils and products.country.
4.5.1.3Operating Expenses before impairment of non-current assets effects
4.6.1.3 | Operating Expenses before Impairment of Non-Current Assets Effects |
Operating expenses, andwhich include selling, general and administrative expenses before taking into account the impairment of non-current assets amounted to COP$4,592,4454,841,000 million in 2018,2020, a COP$407,2591,114,443 million or 9.7%29.9% increase as compared to 2017,2019, mainly as a result of the following factors (see Notes 2527 and 2628) 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$865,888 million or 18.9% decrease as compared to 2018, mainly as a result of the following factors: (see Notes 27 and 28 to our consolidated financial statements for more detail).
A COP$ |
A COP$ |
This increase was partially offset by:
Operating expenses and selling, general and administrative expenses before taking into account the impairment of non-current assets, amounted to COP$4,185,186 million in 2017, a COP$215,657 million or 4.9% decrease as compared to 2016, mainly as a result of the following factors (see Notes 25 and 26 to our consolidated financial statements for more detail).
This decrease was partially offset by:
A COP$ |
A COP$ |
(iii) | A COP$192,875 million increase in depreciation and amortization mainly related to retirement cost of three fields without reserves. |
(iv) | A COP$59,460 million increase in taxes mainly in the industry and trade tax (associated with higher revenues) and tax on financial transactions (associated with higher cash disbursements throughout the year). |
(v) | A COP$154,152 million increase in other minor items. |
Each of our operating segments bears the costs and expenses incurred for product use and marketing and each segment assumes administrative expenses and all non-operational transactions related to its activity. Discussion of operating expenses by business segment is included in the sectionFinancial Review—Review—Operating Results—Consolidated Results of Operations—Segment Performance and Analysis.
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4.6.1.4 | Impairment of Non-Current Assets |
The impairment of our non-current assets includes 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 1618 to our consolidated financial statements for more detail).
In 2018,2020, we recognized impairment losses of non-current assets of COP$368,634633,156 million as compared to a COP$1,311,138 million net reversal of impairment of non-current assets in 2017 and impairment losses of COP$928,7471,762,437 million in 2016.2019 and COP$368,634 million in 2018. These impairments are a non-cash accounting effect and consequently do not involve any disbursement or cash inflow. Further, any cumulative impairment amount of non-current assets, except for goodwill, is susceptible to reversion when the fair value of the asset exceeds its book value. On the contrary, in the event that the book value exceeds the fair value of the asset, an additional impairment expense could be recognized.
The 2020 impairment losses, net of non-current assets of COP$633,156 million, corresponds to the net result of:
An impairment of non-current assets in the exploration and production segment of COP$192,693 million, mainly due to the decrease in crude oil price forecast in the short and long term. |
(ii) | An impairment of non-current assets in the refining and petrochemicals segment of COP$781,528 million, primarily related to the lower refining margins at the Cartagena Refinery by COP$440,525 million and the Barrancabermeja Refinery Modernization Plan by COP$341,000 million, considering the progress in technical analysis of the project. |
(iii) | A reversal of impairment of non-current assets in the transportation and logistics segment of COP$341,065 million, primarily as a result of a recovery in transported volumes in 2020 through: (i) South CGU, which includes the Transandino pipeline – OTA and the port of Tumaco and (ii) North CGU, which includes the Banadía–Ayacucho’s pipeline, part of the Caño Limón-Coveñas system. |
The 2019 impairment loss, net of non-current assets of COP$1,762,437, corresponds to the net result of:
(i) | An impairment of non-current assets in the exploration and production segment primarily due to the decrease in estimations of short-term hydrocarbon price outlook, in spite of the incorporation of new reserves and technical and operational information variables and lower discount rate. |
(ii) | An impairment of non-current assets in the transportation and logistics segment, primarily associated with the south generating unit, comprised of Puerto Tumaco and the TransAndino Pipeline (OTA), and the north generating unit, comprised of the Caño Limón – Coveñas Pipeline, which was especially affected by damages to its infrastructure attributed to attacks by third-parties. |
(iii) | A reversal of impairment of non-current assets in the refining and petrochemicals segment, primarily related to the net effect of i) a reversal of impairment of the Cartagena Refinery due to a lower discount rate associated with external market factors, ii) an impairment loss in Bioenergy primarily due to the decrease in availability of cane, partially offset by an improvement in the projection of the realization price of ethanol and a decrease in the discount rate and iii) an impairment loss associated with the modernization plan for the Barrancabermeja refinery, considering the state of the technical alternatives analysis of possible future increases in conversion. |
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As mentioned above, in 2018, Ecopetrol recognized impairment losses, net of non-current assets of COP$368,634 million, which corresponds to the net result of:
An impairment of non-current assets in the refining and petrochemicals segment, primarily due to adjustments in market expectations with respect to the impact of implementation of IMO regulations on projected margins for Reficar’s refined products, (ii) a decrease in the short-term outlook for the ethanol prices given a global over-supply of ethanol, (iii) downward updates to Bioenergy’s near-term agricultural outputs and (iv) an increase in the discount rate used for Reficar and Bioenergy, reflecting updated macroeconomic conditions. These negative impacts were partially offset by the commencement of the stabilization period at both Reficar and Bioenergy as well as tax benefits associated with Law 1942, 2018. |
An impairment of non-current assets in the transportation and logistics segment, primarily the result of a decrease in the forecast of the volume to be transported by the southern transportation unit and an increase in investment needs to mitigate the operative risk of our transportation systems. |
A reversal of impairment of non-current assets in the exploration and production segment primarily due to an improved short- term hydrocarbon price outlook, incorporation of new reserves and technical and operational information variables. |
The partial reversal of the impairment recorded in 2017 is primarily the result of an improved hydrocarbon prices outlook, incorporation of new reserves, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, favorable refining margins outlook, market conditions affecting the discount rate and technical operational capacity, among other factors.
The impairment losses recognized in 2016 were mainly due to lower estimates of the outlook for oil prices given the oil price environment during those years, operational variables in the exploration and production and refining segments, market and country risk assessments reflected in the discount rate, and a reduction in the amount of recoverable reserves, among others.
For more information regarding impairment by segment, see the sectionFinancial Review—Review—Operating Results—Consolidated Results of Operations—Segment Performance and Analysis.
4.6.1.5 | Finance Results, Net |
Finance results, net, mainly includes exchange rate gains or losses, interest expense, yields and interest from our investments and non-current liabilities financial costs (asset retirement obligation and post-benefits plan).
Finance results, net, amounted to a loss of COP$2,010,3752,481,587 million in 20182020 as compared to a loss of COP$2,495,7311,670,494 million in 2017. This decrease in loss was mainly due to:
Finance results, net, amounted to a loss of COP$2,495,731 million in 2017 as compared to a loss of COP$1,175,367 million in 2016.2019. This increase in loss was mainly due to:
A COP$ |
(iii) | A COP$147,458 million decrease in financial income |
A COP$ |
This increase in our financial loss was partially offset by: (i)by the use of cash flow and net investment hedge accounting, which has allowed us to neutralize, overall,positive impact resulting from the effectstrong appreciation of the exchange rate fluctuation on 71.2% ofColombian Peso against the U.S. dollar debtin the last quarter of Ecopetrol S.A., since2020 had on our U.S. dollar net liability position. In 2020, our exchange rate changes are recognized under other comprehensive income within equity, (ii) the efficient allocationgain was COP$346,774 million, as compared to a gain of debt within the companies that make up the Ecopetrol Group, thereby achieving an approximately zeroCOP$40,639 million in 2019.
Finance results, net, positionamounted to a loss of COP$1,670,494 million in U.S. dollars2019 as compared to a loss of December 31, 2017, and (iii) a COP$379,0302,010,375 million in 2018. This decrease in loss was mainly due to:
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This decrease was partially offset by:
For more details on our financial income and expenses see Note 2729 to our consolidated financial statements for more details.
4.6.1.6 | Income Tax |
Income taxes amounted to and COP$2,038,661 million in 2020, COP$4,718,413 million in 2019 and COP$8,258,485 million in 2018, COP$5,800,268 million in 2017 and COP$4,543,046 million in 2016.2018. The above is equivalent to an effective tax rate of 40.1%42.7%, 42.1%23.9% and 58.3%40.1% in 2018, 20172020, 2019 and 2016,2018, respectively.
The increase in the effective tax rate from 2019 to 2020 was mainly due to: (i) the recognition of a deferred tax asset in the amount of COP$1,550,152 in 2019 as a result of the expectation to recover the historical tax losses of Ecopetrol America that were not recognized up until that time , and (ii) higher losses in the Ecopetrol Group’s companies that are taxed under a special regime. This increase was partially offset by Ecopetrol S.A.’s presumptive income in 2020 being taxed at a lower nominal rate.
The decrease in the effective tax rate from 20172018 to 20182019 was mainly due to: (i)to the positive impactfollowing: 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 Law 1943, 2018 that ledEcopetrol America. Under IFRS regulations, we are allowed to highercreate a deferred asset taxes, primarily at Reficar and Bioenergy, giventax receivable in the lower presumptive income rateamount of 0% starting in 2021,COP$1,550,152 million, which will allow them togradually offset higheragainst the tax losses from previous years; (ii)charge on future taxable profits generated; ii) the 300 basis points nominal tax decrease as a consequenceaccounting recognition of the 2016 tax reform; and (iii) an increase in the contributionmarket value of our income from Reficar, which is taxed atincreased equity interest in Invercolsa did not generate a lower nominal rate of 15%. This decrease was partially offset by (i)tax charge as it did not constitute non-fiscal revenue and iii) 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.
The4% decrease in the effectivenominal tax rate from 2016 to 2017 was mainly due to: (i)established by the better financial performance of the exploration and production segment, (ii) the reduction of losses at Reficar and Ecopetrol America Inc, which also resulted in lower tax rates and (iii) the reduction of the wealth tax rate from 1% in 2016 to 0.4% in 2017.Colombian Financing Law (Ley de Financiamiento).
See Note 10 to our consolidated financial statements for more details.
4.5.1.7Net Income (Loss) Attributable to Owners of Ecopetrol
As a result of the foregoing, in 2020, net income attributable to owners of Ecopetrol was COP$1,586,677. In 2019, net income attributable to owners of Ecopetrol was COP$13,744,011, whereas in 2018 net income attributable to owners of Ecopetrol was COP$11,381,386 in 2017, net income attributable to owners of Ecopetrol was COP$7,178,539 million whereas and, in 2016, net income attributable to owners of Ecopetrol was COP$2,447,881 million.
4.5.1.8Segment Performance and Analysis
4.6.1.8 | Segment Performance and Analysis |
In this section, including the tables below, we present our financial information by segment: Exploration and Production, Refining and Petrochemicals and Transportation and Logistics. See the sectionBusiness Overview for a description of each segment.
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The following tables present our revenues and net income by business segment for the years ended December 31, 2018, 20172020, 2019 and 2016:2018:
Table 4754 – Revenues by Business Segment
Year ended December 31, | % Change | For the year ended December 31, | % Change | |||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2016 | 2018/2017 | 2017/2016 | 2020 | 2019 | 2018 | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||
(Colombian Pesos in millions) | (COP$ Million) | |||||||||||||||||||||||||||||||||||||||
Exploration and Production | 50,372,764 | 36,494,934 | 28,221,210 | 38.0 | 29.3 | 36,839,997 | 52,667,990 | 50,372,764 | (30.1 | ) | 4.6 | |||||||||||||||||||||||||||||
Third parties | 30,112,900 | 25,004,320 | 20,527,332 | 20.4 | 21.8 | 22,854,925 | 31,295,118 | 30,112,900 | (27.0 | ) | 3.9 | |||||||||||||||||||||||||||||
Local crude oil | 550,479 | 909,871 | 553,666 | (39.5 | ) | 64.3 | 230,520 | 356,857 | 550,479 | (35.4 | ) | (35.2 | ) | |||||||||||||||||||||||||||
Foreign crude oil | 26,898,737 | 21,426,666 | 17,278,579 | 25.5 | 24.0 | 19,498,553 | 28,461,601 | 26,898,737 | (31.5 | ) | 5.8 | |||||||||||||||||||||||||||||
Natural gas local | 1,885,846 | 1,815,754 | 1,988,336 | 3.9 | (8.7 | ) | ||||||||||||||||||||||||||||||||||
Local natural gas | 2,845,155 | 2,256,123 | 1,885,846 | 26.1 | 19.6 | |||||||||||||||||||||||||||||||||||
Foreign natural gas | 27,899 | 32,303 | 58,809 | (13.6 | ) | (45.1 | ) | 17,231 | 27,255 | 27,899 | (36.8 | ) | (2.3 | ) | ||||||||||||||||||||||||||
Other income | 749,939 | 819,726 | 647,942 | (8.5 | ) | 26.5 | 263,466 | 193,282 | 749,939 | 36.3 | (74.2 | ) | ||||||||||||||||||||||||||||
Inter-segment net operating revenues | 20,259,864 | 11,490,614 | 7,693,878 | 76.3 | 49.3 | 13,985,072 | 21,372,872 | 20,259,864 | (34.6 | ) | 5.5 | |||||||||||||||||||||||||||||
Refining and Petrochemicals | 37,011,373 | 28,644,016 | 24,823,714 | 29.2 | 15.4 | 26,104,351 | 38,770,806 | 37,011,373 | (32.7 | ) | 4.8 | |||||||||||||||||||||||||||||
Third parties | 34,947,948 | 27,343,359 | 24,194,024 | 27.8 | 13.0 | 24,804,887 | 36,393,470 | 34,947,948 | (31.8 | ) | 4.1 | |||||||||||||||||||||||||||||
Local refined products | 26,354,549 | 21,187,091 | 17,771,166 | 24.4 | 19.2 | 17,745,376 | 27,170,498 | 26,354,549 | (34.7 | ) | 3.1 | |||||||||||||||||||||||||||||
Foreign refined products | 8,485,932 | 6,005,556 | 6,330,648 | 41.3 | (5.1 | ) | 6,165,364 | 8,977,662 | 8,485,932 | (31.3 | ) | 5.8 | ||||||||||||||||||||||||||||
Foreign crude oil | - | 52,397 | - | (100.0 | ) | - | 29 | 61,995 | - | (100.0 | ) | 100.0 | ||||||||||||||||||||||||||||
Other income | 107,467 | 98,315 | 92,210 | 9.3 | 6.6 | |||||||||||||||||||||||||||||||||||
Other income(1) | 894,118 | 183,315 | 107,467 | 387.7 | 70.6 | |||||||||||||||||||||||||||||||||||
Inter-segment net operating revenues | 2,063,425 | 1,300,657 | 629,690 | 58.6 | 106.6 | 1,299,464 | 2,377,336 | 2,063,425 | (45.3 | ) | 15.2 | |||||||||||||||||||||||||||||
Transportation and Logistics | 11,354,167 | 10,598,064 | 10,648,776 | 7.1 | (0.5 | ) | 12,194,440 | 13,070,736 | 11,354,167 | (6.7 | ) | 15.1 | ||||||||||||||||||||||||||||
Third parties | 3,543,024 | 3,606,549 | 3,764,205 | (1.8 | ) | (4.2 | ) | 2,563,581 | 3,799,924 | 3,543,024 | (32.5 | ) | 7.3 | |||||||||||||||||||||||||||
Inter-segment net operating revenues | 7,811,143 | 6,991,515 | 6,884,571 | 11.7 | 1.6 | 9,630,859 | 9,270,812 | 7,811,143 | 3.9 | 18.7 | ||||||||||||||||||||||||||||||
Eliminations of consolidations | (30,134,432 | ) | (19,782,786 | ) | (15,208,139 | ) | 52.3 | 30.1 | (24,915,395 | ) | (33,021,020 | ) | (30,134,432 | ) | (24.5 | ) | 9.6 | |||||||||||||||||||||||
Total revenues | 68,603,872 | 55,954,228 | 48,485,561 | 22.6 | 15.4 | 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—Review—Operating Results—Consolidated Results of Operations—Total Revenues for prices and volumes to third parties.
Table 4855 – Operating and Net Income by Business Segment
Year ended December 31, | % change | For the year ended December 31, | % Change | |||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2016 | 2018/2017 | 2017/2016 | 2020 | 2019 | 2018 | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||
(Colombian Pesos in millions) | (COP$ Million) | |||||||||||||||||||||||||||||||||||||||
Exploration and Production | ||||||||||||||||||||||||||||||||||||||||
Operating Income | 15,899,337 | 8,061,484 | 2,912,307 | 97 | 177 | 1,149,291 | 11,601,485 | 15,899,337 | (90.0 | ) | (27.0 | ) | ||||||||||||||||||||||||||||
Net income attributable to owners | 9,930,519 | 3,820,501 | 1,322,370 | 160 | 189 | (139,279 | ) | 9,382,129 | 9,930,519 | (101.0 | ) | (6.0 | ) | |||||||||||||||||||||||||||
Refining and Petrochemicals | ||||||||||||||||||||||||||||||||||||||||
Operating Income | (757,793 | ) | 1,362,934 | (595,712 | ) | (156 | ) | (329 | ) | (2,185,511 | ) | 1,142,204 | (757,793 | ) | (291.0 | ) | (251.0 | ) | ||||||||||||||||||||||
Net income attributable to owners | (1,973,075 | ) | 358,859 | (1,823,020 | ) | (650 | ) | (120 | ) | (2,848,511 | ) | 117,708 | (1,973,075 | ) | (2,520.0 | ) | (106.0 | ) | ||||||||||||||||||||||
Transportation and Logistics | ||||||||||||||||||||||||||||||||||||||||
Operating Income | 7,317,513 | 6,748,047 | 6,589,251 | 8 | 2 | 8,218,724 | 8,366,747 | 7,317,513 | (2.0 | ) | 14.0 | |||||||||||||||||||||||||||||
Net income attributable to owners | 3,424,234 | 2,999,978 | 2,960,449 | 14 | 1 | 4,574,800 | 4,244,860 | 3,424,234 | 8.0 | 24.0 | ||||||||||||||||||||||||||||||
Eliminations in consolidation | ||||||||||||||||||||||||||||||||||||||||
Operating Income | (643 | ) | (610 | ) | (1,298 | ) | 5 | (53 | ) | (739 | ) | (83,278 | ) | (643 | ) | (99.0 | ) | 12,851.0 | ||||||||||||||||||||||
Net income attributable to owners | (292 | ) | (799 | ) | (11,918 | ) | (63 | ) | (93 | ) | (333 | ) | (686 | ) | (292 | ) | (51.0 | ) | 135.0 | |||||||||||||||||||||
Ecopetrol consolidated | ||||||||||||||||||||||||||||||||||||||||
Operating Income | 22,458,414 | 16,171,855 | 8,904,548 | 39 | 82 | 7,181,765 | 21,027,158 | 22,458,414 | (66.0 | ) | (6.0 | ) | ||||||||||||||||||||||||||||
Net income attributable to owners | 11,381,386 | 7,178,539 | 2,447,881 | 59 | 193 | 1,586,677 | 13,744,011 | 11,381,386 | (88.0 | ) | 21.0 |
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4.6.1.9 | Exploration and Production Segment Results |
In 2018,2020, exploration and production segment sales were COP$50,372,76436,839,997 million, compared to COP$36,494,93452,667,990 million in 2017.2019. In 2018,2020, our segment sales increaseddecreased by 38.0%30.1% as compared with 20172019 mainly as a result of:
The 27.0% decrease in sales of crude oil to third parties in 2020 as compared to 2019 primarily due to: (i) a decrease in the price of our crude oil basket of US$21.0 per barrel, (ii) an increased spread in our crude oil basket versus the Brent price, (iii) lower production levels, primarily due to lower demand as a result of the mobility restrictions and lockdown that were imposed throughout the year because of the COVID-19 pandemic and impacts due to public order issues. This decrease was partially offset by (i) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in revenue recorded in U.S. dollars, (ii) an increase in crude oil sales of 5.2 mmbls, which in turn was primarily related to an increase in availability associated with lower throughput at our refineries, (iii) an increase in natural gas sales of 2.6 mmbls, which in turn was primarily due to Hocol’s acquisition of 100% of Chevron Petroleum Company’s participation in the Guajira association contract (which corresponds to 43% of the total contract), positive results of our United States Permian operations, the reversion of the Pauto and Floreña fields from Equión to Ecopetrol and the start-up of the Cupiagua LPG Plant. |
(ii) | The 34.6% decrease in inter-segment revenues in 2020 as compared to 2019 mainly due to: (i) the decrease in the price of our crude oil basket and a worsening spread as compared to the Brent price and (ii) lower refineries throughputs due to the global contraction in demand as a result of the COVID-19 pandemic. This decrease was partially offset by the impact of the depreciation of the Colombian Peso against the U.S dollar. |
In 2019, exploration and production segment sales were COP$52,667,990 million, compared to COP$50,372,764 million in 2018. In 2019, our segment sales increased by 4.6% as compared with 2018 mainly as a result of:
(i) | Increased sales of crude oil to third parties, which increased by |
Increased inter-segment revenues, which increased by |
In 2017, exploration and production segment sales were COP$36,494,934 million, compared to COP$28,221,210 million in 2016. In 2017, our segment sales increased by 29.3% as compared with 2016 mainly as a result of:
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 2018,2020, the cost of sales for this segment increaseddecreased by 22.5%9.5% as compared with 2017,2019 due to the net effect of:
Fixed costs decreasing by 1.1%, or COP$108,644 million, in 2020 as compared to 2019 mainly due to the optimization plan adopted by the Ecopetrol Group which was reflected in fewer contracted services, lower process materials usage and lower general costs. This decrease was partially offset by higher fixed transportation costs, primarily due to the depreciation of Colombian Peso against U.S dollar. |
(ii) | Variable costs decreasing by 12.5%, or COP$ 3,356,802 million in 2020 as compared to 2019, as a result of (i) the decrease in the price of our crude oil basket resulting in a lower cost of oil, (ii) a decrease in volume of naphtha purchased for dilution as a consequence of lower production of heavy oil and (iii) non-execution of reversal cycles in the Bicentenario pipeline and lower transported volume. The latter was partially offset by (i) an increase in crude oil volume purchases due to a strategy that enabled further optimization of the supply chain, (ii) the decrease in the price of our crude oil basket that impacted the inventory valuation and (iii) higher energy purchases given operative issues in our self-generating plants. |
In 2019, the cost of sales for this segment increased by 12.8% as compared with 2018, due to the net effect of:
(i) | Fixed costs increasing by |
Variable costs increasing by |
In 2017, the cost of sales for this segment increased by 14.5% as compared with 2016, due to the net effect of:
In 2018,2020, operating expenses before impairment of non-current assets increaseddecreased by 30.9%4.5% as compared to 2017,2019 primarily as a net result ofof: (i) the bargain purchase in ourrecorded gain on interests derived from Hocol’s acquisition of an additional stake100% of Chevron Petroleum Company’s participation in the K2 field in 2017, (ii) the saleGuajira Contract (which corresponds to 43% 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 Inc.’s León 1 and 2 wells and Hocol’s Bonifacio, Hurón and Payero wells in 2018, (iv) an increase in operation expenses related to the Lizama’s well environmental incident that occurred in the first half of 2018. This increase was partially offset by (i) the elimination of the wealth tax since 2018total contract) and (ii) a decrease in exploratory activity atmainly as a result of lower drilling and seismic activity. The latter was partially offset by (i) higher labor expenses due to certain employees choosing to accept a voluntary retirement plan we offered in 2020, (ii) the Kronos-1, Parmer-1, Warrior 2, Lunera-1, Brama-1, Molusco-1, Godric, Dumbowrite off of certain assets due to the completion of economic feasibility studies, (iii) higher environmental provisions and Polleraasset retirement obligations for noncommercial wells, recognized(iv) social investment costs associated with our support to the country to combat the COVID-19 pandemic, and (v) increase in 2017.fees and freight costs for exports to China and Korea.
In 2017,2019, operating expenses before impairment of non-current assets increaseddecreased by 7.8% in 201710.3% as compared to 2016,2018 primarily as a net result of: (i) a decrease in exploratory expenses mainly as a result of (i) higher expenses related to our exploratory activity as we engaged in more seismic activity and recorded expenses related tothe recognition of spending on exploratory activity at the Kronos-1, Parmer-1, WarriorEcopetrol America’s León 1 and 2 Lunera-1, Brama-1, Molusco-1, Godric, Dumbowells in 2018, (ii) an increase in depreciation and Pollera wells, (ii) the terminationamortization related to retirement costs of three fields without reserves, (iii) an increase in 2016 of the deferred income amortization we had been recognizing since 2007 for the advance paymentsocial investments made by the Ministry of FinanceCompany, (iv) higher taxes mainly the industry and Public Credit of the obligations under Ecogas, in relation to the Built, Operate and Transfer contracts (BOMT’s) for the construction, operation, maintenance and transfer of gas pipelines. This increase was partially offset by (i) increased incometrade tax due to the acquisition ofa sales increase and (v) 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 valuelevel of seismic acquisition compared to 2018, with the asset above the value paid for the additional interestCOL5 and (ii) the reduction of the wealth tax rate from 1%Saturn programs in 2016 to 0.4% in 2017.Brazil.
The net reversal ofThere was an impairment of non-current assets recognized in the exploration and production segment in 2018, which totaled2020, totaling COP$785,940192,594 million in 20182020 as compared to a COP$183,7181,982,044 million in 2017, increased by 327.8 % as compared to 20172019. The impairment loss in this segment in 2020 was mainly due to due to the incorporation of new reserves, improved short-term hydrocarbondecrease in the crude oil price outlookforecast in the short and improvements in technical operational capacity.long term.
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The net reversal ofThere was an impairment of non-current assets recognized in the exploration and production segment in 2017 totaled2019, totaling COP$183,718 million1,982,044 billion in 2019 as compared to an impairment loss of COP$196,448 million in 2016. Thethe net reversal of theCOP$785,940 million in 2018. The impairment loss in this segment in 2019 was primarilymainly due to (i) a decrease in the increasedprice projection of our crude oil and ii) an increase in net book value of offshore oil fields, partially offset by an impairment of onshore fields, both as a result of calculating their valuation taking into account market variables, reserves, price spreadshigher asset short-term retirement obligations.
Because of all the above, the segment recorded a net loss attributable to owners of Ecopetrol of COP$139,279 million in 2020 as compared to the ICE Brent price,net income attributable to owners of Ecopetrol of COP$9,382,129 million in 2019 and available technical and operational information.
The segment recorded net income attributable to owners of Ecopetrol of COP$9,930,519 million in 2018 as compared to net income attributable to owners of Ecopetrol of COP$3,820,501 million in 2017 and net income attributable to owners of Ecopetrol of COP$1,322,370 million in 2016.2018.
Lifting and Production Costs
The aggregate average production cost, on a Colombian Peso basis, has increaseddecreased to COP$27,782 28,634 per boe during 20182020 from COP$23,684 29,275 per boe during 2017. 2019. This decrease was primarily due to:
(i) | A decrease in activity, mainly in subsoil and surface maintenance, primarily due to the restrictions driven by the COVID-19 pandemic. |
(ii) | A decrease in costs related to support services in line with the decrease in our operating activity and a decrease in supplies used in the production process. |
(iii) | An increase in the cost of energy, primarily due to the use of more costly thermal generation and an increase in our purchases from the national interconnected system; partially offset by our new energy self-generation strategies, which led to a reduction in diesel, fuel oil and residual distillate energy costs. |
(iv) | A decrease in costs related to optimizations in maintenance contracts and others, which allowed us to have better rates and discounts in operation contracts. |
On a dollar basis, ourthe aggregate average production cost increaseddecreased to US$9.40 7.75 per boe in 20182020 from US$8.028.92 per boe in 2017,2019 primarily due to a 0.18%12.46% depreciation of the average exchange rate of the Colombian Peso against the U.S. dollar in 2018.2020.
The aggregate average lifting cost, on a Colombian Peso basis, increaseddecreased to COP$25,614 27,555 per boe during 20182020 from COP$22,58528,100 per boe during 2017. 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, it increasedthe aggregate average lifting cost decreased to US$8.66 7.46 per boe in 20182020 from US$7.658.56 per boe in 2017 also2019 due partially to the 0.18%a 12.46% depreciation of the average exchange rate of the Colombian Peso against the U.S. dollar in 2018.2020.
The abovementioned increases were primarily due to:
The difference between the aggregate average lifting cost and aggregate average production cost is that lifting costcosts does not include the costs related to hydrocarbon self-consumption requiredconsumption of hydrocarbons by the Company in theour production process or the deliveries we makeoutput that the Company sells to our refineries and natural gas liquid plants.
The following table sets forth crude oil and natural gas average sales prices, the aggregate average lifting costs and aggregate average unit production cost for the years ended December 31, 2018, 20172020, 2019 and 2016.2018.
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Table 4956 – Crude Oil and Natural Gas Average Prices and Costs
2018 | 2017 | 2016 | ||||||||||
Crude Oil Average Sales Price (U.S. dollars per barrel)(1) | 63.2 | 47.8 | 35.7 | |||||||||
Crude Oil Average Sales Price (COP$ per barrel)(1) | 187,845 | 141,175 | 108,337 | |||||||||
Natural Gas Average Sales Price (U.S. dollars per barrel equivalent) | 22.4 | 22.7 | 23.5 | |||||||||
Natural Gas Average Sales Price (COP$ per barrel equivalent) | 66,922 | 66,919 | 71,893 | |||||||||
Aggregate Average Unit Production Costs (U.S. dollars per boe)(2) | 9.40 | 8.02 | 6.88 | |||||||||
Aggregate Average Unit Production Cost (COP$ per boe)(2) | 27,782 | 23,684 | 20,993 | |||||||||
Aggregate Average Lifting Costs (U.S. dollars per boe)(3)(4)(5) | 8.66 | 7.65 | 6.49 | |||||||||
Aggregate Average Lifting Costs (COP$ per boe)(3)(4) (5) | 25,614 | 22,585 | 19,799 |
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 |
4.6.1.10 | Transportation and Logistics Segment Results |
4.5.1.10Transportation and Logistics Segment Results
In 2018,2020, our transportation and logistics segment sales were COP$11,354,16712,194,440 million compared to COP$10,598,06413,070,736 million in 2017.2019. The 7.1% increase6.7% decrease in 20182020 as compared with 20172019 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 bythrough our pipelines which was primarily due to an increase of oil production at the national level, including production by third parties, (ii) reversal cycles through the Bicentenario pipeline, (iii) commercial strategies implemented for industrial services such as oil dilution, unloading facilities at the startupMonterrey facility that enabled the transport of the San Fernando-Apiay Systemoil previously transported outside of our infrastructure and the expansion of the P135 Project, (ii)oil injection at Ayacucho, (iv) an increase in the volume of refined products transported mainly due to growth of the increaseborder zone demand and higher volumes in production at Barrancabermejathe Cartagena - Baranoa pipeline and, Reficar, (iii)(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. 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.
In 2017, our transportation and logistics segment sales were COP$10,598,064 million compared to COP$10,648,776 million in 2016. The 0.5% decrease in 2017 as compared with 2016 was mainly due to (i) a 5% decrease in the volume of crude oil transported by our pipelines, which was primarily due to the production decrease at the national level and (ii) the negative effect on our U.S. dollar-indexed transportation fees resulting from the appreciation of the Colombian Peso against the U.S. dollar. This decrease was almost offset by a 1.9% increase in the volume of refined products transported primarily due to the increase in demand for refined products in Colombia and the elimination of restrictions in the Pozos Colorados - Galán system. Sales to third parties decreased in 2017 as compared to 2016 primarily due to the fact that the segment received income from the transportation services to Frontera Energy for its participation in the Rubiales field, and once the field returned to us in July 2016, these services were recognized as inter-segment sales.
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$3,402,0873,738,194 million in 20182019 as compared to COP$3,271,8353,402,087 million in 2017.2018. The cost of sales for this segment increased by 4.0%9.9% in 20182019 as compared with 20172018 mainly due to (i) an increase in costs associated with higher transported volumes, transported, primarily due to the reasons described above and (ii) an increased consumption of materials, supplies and depreciation resulting from toan adjustment in the startuseful life of the San Fernando – Apiay system at Cenit since January 2018 and the expansion of the P135 Project since July 2017.
The cost of sales amounted to COP$3,271,835 million in 2017 as compared to COP$3,349,791 million in 2016. The cost of sales for this segment decreased by 2.3% in 2017 as compared with 2016 mainly due to a decrease in costs associated with maintenance, operating supplies and materials due to the continuitysome of our efficiency program to optimize our operating costs. This decrease was partially offset by (i) an increase in material processing costs needed for power generation in three new pumping stations to operate Ocensa’s P135 projecttransportations systems, and (ii) an increase in depreciation resulting from the start of P135.(iii) higher electricity market prices.
In 2018,2020, operating expenses before the impairment of non-current assets decreasedincreased by 27.1%27.6% as compared to 20172019 due to: (i) a reversalan increase in labor expenses given that certain of a provisionthe segment’s employees chose to take the voluntary retirement plan we had set asideoffered in respect of tariff dispute we were having in connection with the P135 Project2020 and (ii) the elimination of wealth tax since 2018.an extraordinary income recognized in 2019 associated to a favorable litigation related to Ocensa’s line filled and no similar income in 2020. This decreaseincrease was partially offset by highera decrease in the expenses associated withto the remediation of the damages caused by terrorist attacks onand illicit taps into our infrastructure by third parties.transportation infrastructure.
In 2017,2019, operating expenses before the impairment of non-current assets decreasedincreased by 15.1%57.8% as compared to 20162018 due to lower administrativethe expenses mainly as a resultassociated to the remediation of the consolidationdamages caused by terrorist attacks and illicit taps in our transportation infrastructure. This increase was partially offset by the favorable ruling in the arbitration claim regarding Ocensa’s line filled with Equión and Santiago.
The reversal of administration areas withinimpairment of non-current assets recognized in the segment in 2020, totaled COP$341,065 million as compared to impairment losses of non-current assets of COP$232,556 million in 2019. This reversal in the impairment of this segment was primarily by a recovery in transported volumes in 2020 through: (i) South CGU, which includes the Transandino pipeline – OTA and a decrease in taxes becausethe port of Tumaco and (ii) North CGU, which includes the Banadia- Ayacucho pipeline, part of the reduction of the wealth tax rate discussed previously.Caño Limon- Coveñas system.
The impairment losses of non-current assets recognized in the segment in 2018,2019, totaled COP$232,556 million in 2019 as compared to impairment losses of non-current assets of COP$169,870 million in 2018 as compared to an2018. The increase in the impairment recoveryloss of COP$59,455 million in 2017. The difference in impairment from a reversal in 2017 to a loss in 2018this 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 an increase in investment needs to mitigate the operative riskimpact of our transportation systems.
The impairment recovery of non-current assets recognizedthe terrorist attacks that took place in the segment in 2017, totaled COP$59,455 million in 2017 as compared to an impairment recovery of COP$41,062 million in 2016. The increase in the impairment recovery was due to the inclusion, in the assessmentBanadia- Ayacucho portion of the recovery amount of this segment’s assets, of flows associated with the Port of Tumaco that positively affects the recoverable amount of the southern cash generating unit (See Note 16.3 to our consolidated financial statements for more detail).Caño Limon- Coveñas pipeline.
The segment recorded net income attributable to owners of Ecopetrol of COP$3,424,2344,574,800 million in 20182020 as compared to net income of COP$2,999,9784,244,860 million in 20172019 and COP$2,960,4493,424,234 million in 2016.2018.
4.5.1.11Refining and Petrochemicals Segment Results
4.6.1.11 | Refining and Petrochemicals Segment Results |
In 2018,2020, the refining and petrochemical segment sales were COP$37,011,37326,104,351 million compared to COP$28,644,01638,770,806 million in 2017.2019. In 2018,2020, 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 29.2%4.6% as compared with 2017,2018, mainly due to:to (i) an increase of our average products basket pricediesel exports 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 operatingtheir improved economic performance at our refineries.
In 2017, the refining and petrochemical segment sales were COP$28,644,016 million compared to COP$24,823,714 million in 2016. In 2017, sales of refined products and petrochemicals increased by 15.4% as compared with 2016, mainly due to an increase of our average products basket price due to the increase in the international prices.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 (i) a decrease in exportslower prices of our refined product basket and the weakening of international fuel oil primarily due to reduced production at the Barrancabermeja refinery as a result of reliance on more efficient alternative sources and stabilization of the coker unit at the Cartagena Refinery and (ii) a decrease in exports of diesel due to our commercial strategy of focusing on selling to the domestic market due to better commercial conditions, replacing lace imports of such products.
prices.
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The cost of sales for our refined products and petrochemicals segment is mainly related to the purchase of crude oil and natural gas for our refineries, imported crude oil and products to supply local demand, feedstock transportation services, services contracted for maintenance of the refineries and the amortization and depreciation of refining assets. Cost of sales amounted to COP$25,825,555 million in 2020, compared to COP$37,856,219 million in 2019 and COP$35,658,753 million in 2018, compared to COP$26,855,395 million in 2017 and COP$22,843,987 million in 2016.2018.
In 2018,2020, the cost of sales for this segment decreased 31.8% as compared with 2019, principally due to (i) decreased in volume purchases of crude oil for use by our refineries primarily due to lower throughput, which in turn was caused by the COVID-19 pandemic (ii) lower average purchase prices, (iii) a decrease in diesel imports associated with the lower demand caused by COVID-19 national lockdowns and (iii) the inclusion of a higher percentage of domestic crude in the Cartagena refinery, which resulted in a more cost-effective crude slate.
In 2019, the cost of sales for this segment increased 32.8%6.2% as compared with 2017,2018, principally due to (i) an increase inincreased purchases of crude oil at higher international benchmark prices, (ii) higher volumes purchase of crude oil for use by our refineriesCartagena refinery primarily due to higher throughput (iii)and higher feedstock costs due to the appreciation of our crude as compared to Brent, (ii) an increase in cost of transportationdiesel imports associated with higher productionfirst quarter operational events in our refineries.the Barrancabermeja refinery as well as increased purchases of products to reduce the sulphur content of fuels for the local market. This increase was partially offset by: (i) lower importsby the inclusion of products primarily medium distillates and gasolines as a resulthigher percentage of higher production at Barrancabermeja Reficar and (ii) lower imports of lightdomestic crude used atin the Cartagena Refinery as a result of the substitution of such crude,refinery, which resulted in a more cost-effective crude slate for the Cartagena Refinery.slate.
In 2017,2020, operating expenses before the costimpairment of sales for this segmentnon-current assets increased 18%by 649% as compared with 2016, principallyto 2019, mainly due toto: (i) an increase in purchasesincome as a result of crude oilour recognition of the Invercolsa’s valuation in 2019 once we became their controlling shareholder and no similar recognition in 2020, (ii) recognition of the fixed cost of plants temporarily halted at increased international benchmark pricesthe Barrancabermeja refinery given the COVID-19 pandemic and (ii)decrease in product demand, (iii) the consolidation of Invercolsa during the entire year of 2020 versus two months in 2019 and (iv) higher volumeslabor expenses due certain of imports of crude oil and inter-segment purchases of crude oil for the Cartagena Refinery. This increase was partially offset by lower imports of other fuels, especially diesel and gasoline, duesegment’s employees choosing to accept the use of products produced by the Cartagena Refinery rather than imported products.voluntary retirement plan in Ecopetrol, previously mentioned.
In 2018,2019, operating expenses before the impairment of non-current assets decreased by 24.6%80.1% as compared to 2017,2018, mainly due to stabilization expensesthe gain of the Cartagena Refinery which was reflectedCOP$1,048,924 recognized when we obtained control of Invercolsa in lower maintenance expenses, contracted services and general expenses.November 2019.
In 2017, operating expenses before the2020, we recognized an impairment loss of non-current assets decreased by 17.2% as compared to 2016, due to a decrease of stabilization expenses of the Cartagena Refinery and a decrease in taxes because of the reduction of the wealth tax rate.
The impairment losses of non-current assets recognized in thethis segment in 2018, which totaledtotaling COP$984,704781,528 million, in 2018, as compared to a net reversal of impairment of COP$1,067,965452,163 million in 2017,2019. The impairment loss we observed in 2020 is primarily the result of:of (i) adjustments in market expectations with respectan impairment loss of COP $440,525 million attributable to the impactCartagena refinery, which in turn was mainly due to lower refining margins; and (ii) an impairment loss of implementation of IMO regulation on projected margins forCOP $341,000 million attributable to the Cartagena Refinery’s refined products, (ii) a decreaseBarrancabermeja Refinery Modernization Plan, taking into account progress 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 commencementtechnical analysis of the stabilization period at both Reficar and Bioenergy as well as tax benefits associated with Law 1942, 2018.project.
The netIn 2019, we recognized a reversal of impairment of non-current assets recognized in thethis segment in 2017, which totaledtotaling COP$1,067,965452,163 million, in 2017 as compared to an impairment losslosses of COP$773,361984,704 million in 2016, decreased as compared to 2016 as a2018. The reversal we observed in 2019 is primarily the result of (i)net effect between i) a net reversal of the impairment of Reficar as a result of an improved outlook in refining marginsthe Cartagena Refinery was mainly due to the anticipated effects of the ratification of Marpol which goes into effect in 2020, (ii) a lower discount rate resulting from the application of WACC methodology and (iii) operational and financial optimizationassociated with external market factors, ii) an impairment loss in Bioenergy which was generated primarily due to the stabilizationdecrease in availability of the refinery. This reversal wassugar cane, partially offset by Bioenergy’s impairment related toan improvement in the changeprojection of the project start date,realization price of ethanol and a decrease in the process of stabilizationdiscount rate, and iii) an impairment loss associated with the modernization plan for the Barrancabermeja refinery, considering the state of the industrial plant, the updatingtechnical alternatives analysis of operational variables and the financial expenses of the Barrancabermeja refinery’s modernization project, which is currently postponed.possible future increases in conversion.
As mentioned earlier, the refining segment is highly sensitive to changes in product prices and feedstock in the international market, discount rate, refining margins, changes in environmental regulations and cost structure and the level of capital expenditures.
The refining and petrochemicals segment recorded net loss attributable to owners of Ecopetrol of COP$1,973,0752,848,511 million in 2018, asin 2020 compared to a net income to owners of Ecopetrol of COP$358,859117,708 million in 2017,2019 and a net loss attributable to owners of Ecopetrol of COP$1,823,0201,973,075 million in 2016.
2018.
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4.6Liquidity and Capital Resources
4.7 | Liquidity and Capital Resources |
Our principal sourcesources of liquidity in 2018 was2020 were: (i) cash flows from our operations amounting to COP$22,469,1949,186,704 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 2018 were2020 were: (i) COP$11,363,077 in debt payments through the pre-payment of local and foreign currency-denominated loans totaling the equivalent of US$2,446 million in 2018 and amortizations to capital and interest payments, (ii) COP$8,460,42611,116,861 million in capital expenditures, which included investments in property, plant and equipment, natural and environmental resources and intangibles, (iii)(ii) dividend payments amounting to COP$4,427,7018,734,351 million, which includesincluded dividends relatingof COP$7,369,499 million to fiscal year 2017 forEcopetrol’s shareholders, including the Nation, and dividends paid to the non-controlling shareholders of our subsidiaries totaling COP$3,659,3731,364,852 million, and the payment of dividends to non-controlling interest for(iii) COP$768,328 million.
350,539 million in lease payments. For more information regarding our debt, see the sectionFinancial Review—Review—Financial Indebtedness and Other Contractual Obligations.
4.7.1 | Review of Cash Flows |
Cash from operating activities
Net cash provided by operating activities increaseddecreased by 32.4%66.8% in 20182020 as compared to 2017,2019, mainly as a result of a 31.9% increase in our operational income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to (i) higher hydrocarbon production levels, (ii) an increase in our refining throughput, (iii) our continued strategy of replacing imports of crude oil and refined products with domestic production, (iv) the commencement of operations of the San Fernando – Apiay project and expansion of the P135 Project in our the midstream segment, (v) cost efficiencies from our transformation plan and (vi) a favorable price environment. This increase was partially offset by higher working capital needs mainly due to an increase in accounts receivable from the FEPC and the payment in advance of the capital gains tax due in 2019 pursuant to Decree 2146, 2018.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 19.3%23.3% in 20172019 as compared to 2016,2018, mainly as a result of (i) a 32.7% increase in our operational income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets and efficiency gains and cost-savings generated by our corporate strategy. This increase was partially offset by (i) higher working capital needs mainly due to increase in accounts receivable from the FEPC and commercial receivable accounts and (ii) an increase in our costs due to the effect of recovery in international crude oil prices on our purchases and an increase in maintenance activities, contracted services and operating supply needs associated with an increase in our operational activities.of:
i) | A 2.8% increase in our operating income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to i) higher levels of hydrocarbon production, ii) a record refining throughput of 374 mbd, similar to that of 2018, despite major scheduled maintenance for our units, iii) a solid performance of the midstream segment, which guaranteed operational continuity despite third-party damages to its infrastructure, iv) a successful commercial management that enabled us to materialize better oil spreads vs the Brent price and v) a favorable COP peso/U.S. dollar devaluation environment. This increase was partially offset by lower international crude and product prices. |
ii) | Lower working capital expenditures needs mainly due to a decrease in accounts receivable from the FEPC and a lower payment in advance of the capital gains tax. |
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Cash used in investing activities
In 2018,2020, net cash used in investing activities decreased by 15.0% as compared to 2019, mainly as a result of (i) a 20.5% decrease in investments in capital expenditures, mainly due to the work restrictions implemented to contain the cases of contagion of COVID-19 (under the concept of operational vital minimum), that was reflected in temporary closure of some wells and negatively affected our production. All the above primarily affected our capital expenditures in the Rubiales, Caño Sur, Casabe, Sur and Recetor assets as well as the Cartagena refinery, (ii) blockages by the communities in the Rubiales, Apiay and Tibu fields, and (iii) a decrease in our securities investment levels in order to conserve liquidity given the lower generation of cash from the operations.
In 2019, net cash used in investing activities increased by 98.9%15.1% as compared to 2017,2018, mainly as a result of:of (i) a 38.5%65.2% increase in investments in capital expenditures, mainly due to a drilling campaign which was driven mainly by drillingconcentrated in the Castilla, Rubiales, Chichimene, Suria, Casabe, Yariguí-Cantagallo and La Cira InfantasCira-Infantas fields and inorganic investment from international agreements such as the B3 module ofstrategic alliance with OXY in the Rubiales field and (ii)US Permian basin. This increase was partially offset by a 249.4% increasedecrease in our investment portfolio as a result of excess liquidity.
In 2017, net cash used in investing activities decreased by 53.3% as compared to 2016, mainly as a result of a 110.4% decrease insupport our investment portfolios as a result of pre-payments of foreign currency-denominated loans totaling US$2,400 million in 2017. This decrease was partially offset by (i) cash proceeds from the sale of our shares in Empresa de Energía de Bogotá, which totaled COP$56,930 million in the aggregate and (ii) a 4.6% increase in investments in capital expenditures which was driven mainly by the reactivation of activity in our Castilla and Rubiales fields, the development of improved recovery projects in fields such as La Cira and Chichimene, and an increase in exploration activities.dividends received from affiliates.
Cash used in financing activities
Net cash used in financing activities increaseddecreased by 23.7%84.7% in 2018,2020, as compared to 2017,2019, due to (i) prepaymentsan increase in cash from borrowings, net of localrelated payments of principal and foreign currency-denominated loans totaling the equivalentinterest, of US$2,446COP$6,455,835 million as compared to US$2,400a decrease of COP$3,002,977 million in prepayments2019, which in turn primarily reflects Ecopetrol S.A. entering into committed credit lines in an aggregate principal amount of foreign currency-denominated loans madeUS$665 million and issuing an SEC-registered bond in 2017 andan 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 of COP$2,713,712 million(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 COP$209,342 million.
Net cash used in financing activities increased by 362% in 2017, as compared to 2016, due to (i) prepayments oflocal and foreign currency-denominated loans totaling US$2,400COP$3,002,977 million and (ii) an increase in dividend payments to the shareholders of Ecopetrol of(iii) COP$255,484300,326 million in 2017 as compared to 2016, which was partially offset by a COP$463,135 million decrease in dividend payments made by certain of our subsidiaries to their non-controlling shareholders.lease payments.
4.7.2 | Capital Expenditures |
Our consolidated capital expenditures in 2018, 20172020, 2019 and 20162018 were COP$8,460,42611,116,861 million, COP$6,107,50613,979,141 million and COP$5,837,4778,460,426 million, respectively. These investments were distributed by business segment on average, for the past three years as follows: 73.0%83.5% for the exploration and production segment, 12.5%8.1% for refining and petrochemicals and 14.5%8.4% for the transportation and logistics segment. See Note 31.333.3 to our consolidated financial statements for more detail about capital expenditures by segment.
Our investment plan approved for 20192021 is a range of between US$3,500 million and US$4,000 million. The investments will be distributed approximately as follows: 81.0%See the section entitled Strategy and Market Overview—2021 Investment Plan for explorationfurther information and production, 11.0% for refining, petrochemicals, and transportation and logistics, and 8.0% for other investments.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.
4.7.3 | Dividends |
In 2018, we paidOn March 26, 2021, our shareholders at the ordinary General Shareholders Assembly approved a distribution of ordinary dividends for the fiscal year ended December 31, 20172020 amounting to COP$698,984 million, or COP$17 per share, based on the number of outstanding shares as of December 31, 2020. The payment date will be April 22, 2021 for 100% of shareholders.
In 2020, we paid dividends of COP$7,369,499 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$1,364,852 million.
In 2019, we paid dividends of COP$12,910,611 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$956,418 million.
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In 2018, we paid dividends of COP$3,659,373 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$768,328 million.
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.
In 2016, we paid the last installment of dividends relating to 2014 net income to the Nation for COP$690,177 million and our transportation and logistics subsidiaries paid dividends to their non-controlling shareholders for COP$1,022,121 million.
On March 29, 2019, our shareholders at the ordinary General Shareholders Assembly approved a distribution of dividends for the fiscal year ended December 31, 2018 amounting to COP$9,251,256 million, or COP$225 per share, based on the number of outstanding shares as of December 31, 2018. Of the total dividends that will be paid, COP$169 per share corresponds to an ordinary dividend pursuant to our current dividend policy and COP$56 per share corresponds to an extraordinary dividend given the strong operational results and robust cash position of the Company in 2018. The dividend payment was approved to be made in one installment for the minority shareholders of Ecopetrol on April 25, 2019 and three installments for the Nation, the first to be paid on April 25, 2019, the second to be paid on June 25, 2019 and the final installment to be paid on September 25, 2019.
4.7Summary of Differences between Internal Reporting (Colombian IFRS and IFRS)
4.8 | Summary of Differences between Internal Reporting (Colombian IFRS and IFRS) |
We prepare our interim and annual statutory financial information in accordance with our internal reporting policies, which follow Colombian IFRS and differ in certain significant aspects from IFRS. The following table sets forth our consolidated net income and equity for years ended December 31, 2018, 20172020, 2019 and 2016,2018, in accordance with Colombian IFRS and IFRS:
Table 5057 – Consolidated Net Income and Equity
For the year ended December 31, | % Change | For the year ended December 31, | % Change | |||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2016 | 2018/2017 | 2017/2016 | 2020 | 2019 | 2018 | 2020/2019 | 2019/2018 | |||||||||||||||||||||||||||||||
(Colombian Pesos in millions) | (COP$ Million) | |||||||||||||||||||||||||||||||||||||||
Net income attributable to owners of Ecopetrol (IFRS) | 11,381,386 | 7,178,539 | 2,447,881 | 58.5 | 193.3 | 1,586,677 | 13,744,011 | 11,381,386 | (88.5 | ) | 20.8 | |||||||||||||||||||||||||||||
Cash flow hedge for future company exports | (471,314 | ) | (366,048 | ) | (494,604 | ) | 28.8 | (26.0 | ) | (122,375 | ) | (419,275 | ) | (471,314 | ) | (70.8 | ) | (11.0 | ) | |||||||||||||||||||||
Exchange rate effects on tax bases – Deferred tax | 646,333 | (192,079 | ) | (388,568 | ) | (436.5 | ) | (50.6 | ) | 223,775 | (73,253 | ) | 646,333 | (405.5 | ) | (111.3 | ) | |||||||||||||||||||||||
Net income Attributable to owners of Ecopetrol (Colombian IFRS) | 11,556,405 | 6,620,412 | 1,564,709 | 74.6 | 323.1 | 1,688,077 | 13,251,483 | 11,556,405 | (87.3 | ) | 14.7 | |||||||||||||||||||||||||||||
Net Equity (IFRS) | 57,107,780 | 48,215,699 | 43,560,501 | 18.4 | 10.7 | 53,499,363 | 58,231,628 | 57,107,780 | (8.1 | ) | 2.0 | |||||||||||||||||||||||||||||
Cash flow hedge for future company exports | (20,792 | ) | (29,258 | ) | (39,803 | ) | (28.9 | ) | (26.5 | ) | - | (10,099 | ) | (20,792 | ) | (100.0 | ) | (51.4 | ) | |||||||||||||||||||||
Exchange rate effects on tax bases – Deferred tax | 2,217,450 | 1,594,864 | 1,799,020 | 39.0 | (11.3 | ) | 2,319,907 | 2,122,593 | 2,217,450 | (9.3 | ) | (4.3 | ) | |||||||||||||||||||||||||||
Net Equity (Colombian IFRS) | 59,304,438 | 49,781,305 | 45,319,718 | 19.1 | 9.8 | 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 acronym in Spanish)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, 2018,2020, our net income as reported under IFRS was COP$471,314122,375 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, 2018,2020, our net income attributable to owners of Ecopetrol as reported under IFRS was COP$646,333223,775 million lower than our net income attributable to owners of Ecopetrol as reported under Colombian IFRS.
The application of IAS12.41 also generated adjustments to our goodwill and investments in companies impairments of COP$12,435 million in 2020, COP$14,865 million in 2019 and COP$22,030 million in 2018 COP$61,893 million in 2017 and COP$86,781 million in 2016 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 COP$60,748 million in 2017 and COP$71,056 million in 2016 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, 2018,2020, 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. For the year ended December 31, 2016, these same accounting differences led us to report net income attributable to the owners of Ecopetrol under IFRS of COP$2,447,881 million as opposed to a net income attributable to the owners of Ecopetrol of COP$1,564,709 million reported under Colombian IFRS for the same period.
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4.9 | Financial Indebtedness and Other Contractual Obligations |
As of December 31, 2018,2020, we had outstanding consolidated indebtedness of COP$33.244.5 trillion, which corresponded primarily to the following long-term transactions:
Table 5158 – Consolidated Financial Indebtedness
Company | Type | Initial Date | Original Amount | Maturity | Interest Rate | Amortization | ||||||||||||
Ecopetrol S.A. | Bonds | September 18, 2013 | US$1,300 million | September 18, 2023 | 5.875 | % | Bullet | |||||||||||
September 18, 2013 | US$850 million | September 18, 2043 | 7.375 | % | Bullet | |||||||||||||
May 28, 2014 | US$2,000 million | May 28, 2045 | 5.875 | % | Bullet | |||||||||||||
September 16, 2014 | US$1,200 million | January 16, 2025 | 4.125 | % | Bullet | |||||||||||||
June 26, 2015 | US$1,500 million | June 26, 2026 | 5.357 | % | Bullet | |||||||||||||
June 15, 2016* | US$500 million | September 18, 2023 | 5.875 | % | Bullet | |||||||||||||
December 1, 2010 | COP$ | |||||||||||||||||
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 | US$ | December 20, 2025 | Floating | Semi-annual | |||||||||||||
April 15, 2020 | US$ 665 million | September 20, 2023 | Floating | Semi-annual | ||||||||||||||
ECAs | December 30, 2011** | US$2,650 million | December 20, 2027 | Fixed | Semi-annual | |||||||||||||
December 30, 2011** | US$100 million | December 20, 2027 | Floating | Semi-annual | ||||||||||||||
December 30, 2011** | US$97 million | December 20, 2027 | Fixed | Semi-annual | ||||||||||||||
December 30, 2011** | US$210 million | December 20, 2027 | Floating | Semi-annual | ||||||||||||||
Invercolsa & Subsidiaries | Bank Loans | Various | US$ 377,202 million | Various | Fixed | Fixed | ||||||||||||
Leases | Various | US$ 4,471 million | Various | Floating | Various | |||||||||||||
Ocensa | Bond | US$500 million | July 14, 2027 | 4.000 | % | Bullet | ||||||||||||
Oleoducto Bicentenario | Bank Loan | July 5, 2012 | COP$2.1 trillion | July 5, 2024 | Floating | Quarterly | ||||||||||||
ODL | COP$ | 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. |
* ReopeningThe Colombian Superintendence of bond dueFinance, 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 2023.structure the issuance and placement of bonds in the international capital markets for up to two billion US dollars (US$2,000,000,000).
** Debt originally obtained by Reficar
These authorizations themselves do not constitute an approval for the Refinery modernization and voluntarily assumed by Ecopetrol.issuance of securities or any financing transaction.
The short and long term debt balance for the end of 2018 is explainedtransactions executed in 2020 were as follows:
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Ecopetrol did not incur any short-term or long-term bank loans or bonds in 2018.2019.
Contractual Obligations
We enter into various commitments and contractual obligations that may require future cash payments. The following table summarizes our contractual obligations as of December 31, 2018.2020.
Table 5259 – Our Contractual Obligations
COP$ 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 | 30,269,275 | 1,281,826 | 2,657,497 | 2,755,849 | 23,574,103 | 33,222,962 | 1,450,763 | 3,017,049 | 3,130,406 | 25,624,744 | ||||||||||||||||||||||||||||||
Contract Service Obligations | 3,951,217 | 1,453,298 | 1,609,737 | 412,396 | 475,786 | 16,030,925 | 5,155,544 | 3,024,772 | 4,057,953 | 3,792,655 | ||||||||||||||||||||||||||||||
Operating Lease Obligations | 407,664 | 96,976 | 116,620 | 86,154 | 107,914 | 211,661 | 155,862 | 37,506 | 14,550 | 3,742 | ||||||||||||||||||||||||||||||
Natural Gas Supply Agreements | 363,735 | 109,927 | 99,440 | 0 | 154,368 | 12,157,544 | 5,027,100 | 3,429,898 | 2,678,858 | 1,021,688 | ||||||||||||||||||||||||||||||
Purchase Obligations | 1,653,507 | 80,698 | 1,525,351 | 8,092 | 39,366 | 2,663,077 | 843,285 | 576,356 | 660,593 | 582,843 | ||||||||||||||||||||||||||||||
Energy Supply Agreements | 848,790 | 153,205 | 172,200 | 70,347 | 453,038 | 1,496,929 | 4,598 | 90,733 | 233,353 | 1,168,245 | ||||||||||||||||||||||||||||||
Capital Expenditures | 556,157 | 397,522 | 130,214 | 28,421 | 0 | 13,573,859 | 3,806,896 | 5,566,521 | 2,178,127 | 2,022,316 | ||||||||||||||||||||||||||||||
Build, Operate, Maintain and Transfer Contracts (BOMT) | 665,759 | 64,748 | 123,481 | 129,283 | 348,247 | 469,712 | 81,101 | 139,646 | 107,041 | 141,925 | ||||||||||||||||||||||||||||||
Capital (Finance) Lease Obligations | 454,631 | 55,087 | 80,812 | 63,353 | 255,379 | 308,125 | 34,891 | 63,571 | 59,798 | 149,865 | ||||||||||||||||||||||||||||||
Financial Sector Debt | 10,071,534 | 1,576,597 | 2,906,067 | 2,886,955 | 2,701,915 | 9,499,662 | 1,324,669 | 5,133,819 | 2,339,691 | 701,483 | ||||||||||||||||||||||||||||||
Bonds | 25,986,306 | 64,995 | 3,542,961 | 5,388,600 | 16,989,750 | 34,635,738 | - | 6,379,460 | 4,080,000 | 24,176,278 | ||||||||||||||||||||||||||||||
Total | 72,228,575 | 5,334,879 | 12,964,380 | 11,829,450 | 45,099,866 | 124,270,194 | 17,884,709 | 27,459,331 | 19,540,370 | 59,385,784 |
The table does not include
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 Equion, Savia and Ecodiesel, which do not consolidate within the Ecopetrol’s Group.framework contracts. The implementation of this methodology has resulted in a material increase of our commitments from what was previously reported.
4.9 Off Balance Sheet Arrangements
As of December 31, 2018,2020, we did not have off-balance sheet arrangements of the type that is required to be disclosed under Item 5.E of Form 20-F.
4.10 Trend Analysis and Sensitivity Analysis
4.11 | Trend Analysis and Sensitivity Analysis |
Trend Analysis
Ecopetrol updated its Business Plan on February 26, 2019.23, 2021. See the section entitled Strategy and Market Overview—Our Corporate Strategy—2021 – 2023 Business Plan for a discussion of the trends recognized in the development of that plan.
Sensitivity Analysis
Sensitivity Analysis of Reserves
The following table provides information about the sensitivity analysis conducted on our oil and gas reserves as of December 31, 2018, taking into account2020, considering ICE Brent crude oil prices that reasonably reflect management’s view of crude oil prices given prevailing market conditions.conditions, and management portfolio costs.
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Table 5360 – Sensitivity Analysis of Reserves
Oil and NGL (million barrels) | Natural Gas (bcf) | Total Oil and Gas (Mmboe) | ||||||||||||||||||||||
Reserves as of December 31, 2018 | 1,200 | 3,002 | 1,727 | |||||||||||||||||||||
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 | 1,155 | 2,958 | 1,674 | 1,167.0 | 2,509.0 | 1,607.0 | ||||||||||||||||||
Difference (million barrels) | (45 | ) | (44 | ) | (53 | ) | ||||||||||||||||||
Difference (mmb) | 99.0 | 43.0 | 106.0 | |||||||||||||||||||||
Difference (%) | (4 | )% | (1 | )% | (3 | )% | 0.09 | 0.02 | 0.07 |
The conversion rate used is 5,700 cf = 1 boe.
Assumptions for the Sensitivity Analysis of Reserves
The sensitivity analysis assumes a constant ICE Brent price of US$ 46 per barrel in 2021, between US$ 55 and US$ 58 per barrel in the period 2022-2025, and between US$61 and US$68 onwards, and costs of management portfolio.
The base scenario on which our sensitivity analysis is made corresponds to 85% of our oil, NGL and natural gas reserves, as of December 31, 2020, as presented elsewhere in this annual report.
Other variables such as the operating costs, capital costs and portfolio price remain unchanged for purposes of the analysis.
Sensitivity Analysis of our Results
The following table provides information about the sensitivity of our results as of December 31, 2018,2020, due to variations of US$1 in the price of ICE Brent crude and of 1% in the COP$/US$ exchange rate.
Table 5461 – Sensitivity Analysis of our Results
Income Statement 2018 | Income | Difference Between Real 2018 and Case ICE Brent | Income | Difference Between Real 2018 and Case TRM | ||||||||||||||||||||||||||||||||||||
(COP$ in billions) | ||||||||||||||||||||||||||||||||||||||||
COP$ Million | Income Statement 2020 | Income Statement Case ICE Brent(1) +US$1 | Difference Between Real 2020 and Case ICE Brent | Income Statement Case TRM(2) +1% | Difference Between Real 2020 and Case TRM | |||||||||||||||||||||||||||||||||||
Revenue | 68,603.87 | 69,602.13 | 998.26 | 69,324.68 | 720.81 | 50,223.39 | 51,298.64 | 1,075.25 | 50,710.48 | 487.09 | ||||||||||||||||||||||||||||||
Cost of sales | 41,184.38 | 41,560.55 | 376.17 | 41,514.49 | 330.11 | 37,567.47 | 37,963.58 | 396.11 | 37,727.33 | 159.86 | ||||||||||||||||||||||||||||||
Gross Income | 24,419.49 | 28,041.58 | 622.09 | 27,810.19 | 390.70 | 12,655.92 | 13,335.06 | 679.14 | 12,983.15 | 327.23 | ||||||||||||||||||||||||||||||
Operating expenses | 4,592.45 | 4,592.45 | - | 4,592.45 | - | 4,841.00 | 4,841.00 | - | 4,841.00 | - | ||||||||||||||||||||||||||||||
Impairment of non-current assets | 368.63 | 368.63 | - | 368.63 | - | 633.16 | 633.16 | - | 633.16 | - | ||||||||||||||||||||||||||||||
Operating income | 22,458.41 | 23,080.50 | 622.09 | 22,849.11 | 390.70 | 7,181.76 | 7,860.90 | 679.14 | 7,508.99 | 327.23 | ||||||||||||||||||||||||||||||
Finance results, net | (2,010.38 | ) | (2,010.38 | ) | - | (2,010.38 | ) | - | (2,481.59 | ) | (2,481.59 | ) | - | (2,481.59 | ) | - | ||||||||||||||||||||||||
Share of profit of associates and joint ventures | 165.84 | 165.84 | - | 165.84 | - | 76.34 | 76.34 | - | 76.34 | - | ||||||||||||||||||||||||||||||
Income before income tax | 20,613.87 | 21,235.96 | 622.09 | 21,004.57 | 390.70 | 4,776.51 | 5,455.65 | 679.14 | 5,103.74 | 327.23 | ||||||||||||||||||||||||||||||
Income Tax | (8,258.49 | ) | (8,507.71 | ) | (249.23 | ) | (8,415.01 | ) | (156.52 | ) | (2,038.66 | ) | (2,328.52 | ) | (289.86 | ) | (2,178.32 | ) | (139.66 | ) | ||||||||||||||||||||
Net Income | 12,355.38 | 12,728.25 | 372.86 | 12,589.56 | 234.18 | 2,737.85 | 3,127.13 | 389.28 | 2,925.42 | 187.57 |
(1) | ICE Brent = US$ |
(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 2020, as presented elsewhere in this annual report.
The sensitivity of the ICE Brent price index is in reference to an increase of US$1 per barrel of crude oil in the average ICE Brent reference price based on a 366-day year for 2020. Prices assumed correspond to realized prices for crude oil, natural gas and refined products for 2020, adjusted to account for the differences between such realized prices and the ICE Brent reference price.
The sensitivity of our results to changes in the exchange rate is in reference to a 1% average depreciation of the Colombian Peso against the U.S. dollar during 2020. Prices are the realized prices of crude oil, natural gas and refined products in 2020 and are expressed for the sensitivity using the adjusted exchange rate (i.e. a 1% average depreciation of the Colombian Peso against the U.S. dollar during 2020).
The income tax for each of our sensitivity analyses (price of ICE Brent and COP$/US$ exchange rate) is estimated using the effective corporate tax rate of 43% for 2020.
This sensitivity analysis keeps everything constant. In the case of significant variations of the ICE Brent price, Ecopetrol will perform interventions in its operating expenditures.
The table below sets forth the line items that are being affected by the variation on the reference prices or the average exchange rate.
Table 5562
VARIATION ON ICE BRENT REFERENCE | 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 |
5.1 | Risk |
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. |
5.1 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. |
Risk FactorsLegal and Regulatory Risks
38. | Our operations are subject to extensive regulation. |
39. | Our operations might be affected by rising climate change and energy transition regulatory developments. |
40. | New or higher taxes resulting from changes in tax regulations or the interpretation thereof in Colombia could adversely affect our results of operations and financial condition. |
41. | We may incur losses and spend time and money defending pending lawsuits and arbitrations and responding to administrative investigations. |
Risks Related to Our ADSs
42. | Holders of our ADSs may encounter difficulties in protecting their interests. |
43. | Our ADSs holders may be subject to restrictions on foreign investment in Colombia |
44. | Holders of our ADSs may not be able to effect service of process on us, our directors or executive officers within the United States, which may limit your recovery in any foreign judgment you obtain against us. |
45. | The protections afforded to minority shareholders in Colombia are different from those in the United States, and may be difficult to enforce. |
46. | ADRs do not have the same tax treatment as other equity investments in Colombia. |
47. | Judgments of Colombian courts with respect to our ADSs will be payable only in Colombian Pesos. |
48. | The relative volatility and illiquidity of the Colombian securities markets may substantially limit our investors’ ability to sell our ADSs at the price and time they desire. |
49. | We are not required to disclose as much information to investors as a U.S. issuer is required to disclose. |
Risks Related to the Controlling Shareholder
50. | Our controlling shareholder’s interests may be different from those of certain minority shareholders. |
5.2 | Risk Factors |
The risks discussed below could have a material adverse effect, separately or in combination, on our business’s operating results, cash flows, liquidity and financial condition. Investors should carefully consider these risks.
5.1.1 Risks Related to Our Business
5.2.1 | Risks Related to Our Business |
This section describes the most significant potential risks to our business.
Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time, which could adversely affect our ability to generate revenue.
Reserves estimates are prepared using generally accepted geological and engineering evaluation methods and procedures. Estimates are based on geological, topographical and engineering facts. Actual reserves and production may vary materially from estimates shown in this annual report, and downward revisions in our reserve estimates could lead to lower future production which could affect our results of operations and financial condition.
Hydrocarbon reserves presented in this annual report were calculated in accordance with SEC regulations. As required by those regulations, reserves were valued based on the unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2018, 20172020, 2019 and 2016,2018, 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$44.49 per barrel 72.2/Bl in 2016,2018, US$54.93 per barrel 63/Bl in 20172019 and US$72.20 per barrel 43/Bl in 2018.2020. In 2017,2020, the Company recognized a decrease in oil and gas proven reserves of 6.5% as compared to 2019, to 1,770 mmboe in 2020 from 1,893 mmboe in 2019. In 2019, the Company recognized an increase in oil and gas proven reserves of 4%9.6% as compared to 2016,2018, to 1,6591,893 mmboe in 20172019 from 1,598 mmboe in 2016. In 2018, the Company recognized an increase in oil and gas proven reserves of 4% as compared to 2017, to 1,727 mmboe in 2018 from 1,659 mmboe in 2017.2018. For more information, see the sectionBusiness Overview—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 2018,2020, Ecopetrol recognized an impairment loss, netlosses of non-current assets of COP$368,634 633,156 million which corresponds to the net result 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, 2018.2020. Based on these calculations, assuming an average price per barrel of ICE Brent price of US$67 per barrel in 2019, US$71 per barrel in 2020, US$69 per barrel 46/Bl in 2021, US$ 55/Bl and US$ 58/Bl between 2022 and 2025, and between US$66 61/Bl and US$71 68/Bl onwards, Ecopetrol could recognize a decreasean increase in oil and gas proved reserves of approximately 3%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—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 includesenvisioned the exploration and development of unconventional reservoirs in Colombia, by using fracking technology. See the section Strategy and Market Overview—2021 – 2023 Business Plan. However, the implementation of this strategy depends, among others, on the final outcome of the regulatory framework affecting this technology currently being discussed in Colombia, obtainingunder implementation by the requisiteColombian Government, the environmental license required for the exploratory phase (including pilot wells) to beginPPII, and the results of these pilot projects. 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. See the sectionBusiness Plan. However, we cannot assure you that unconventional reservoirs in Colombia will be ablescientific information to be exploited.collected.
If we are unable to achieve expected recovery factors in our existing fields, or successfully discover and develop additional reserves, or if we do not acquire properties having proved reserves, our reserves portfolio will decline. Failure to secure additional reserves may impede us from achieving or maintaining production targets, and may have a negative impact on our results of operations and financial condition.
Furthermore, we are subject to risks related to the transition to a low carbon economy and to climate change. In terms of our physical risks, these are related to the exposure we have to Colombia’s current climate conditions that might affect water availability and increase the exposure of our assets and operations to potential damages. These conditions could result, among others, in water shortages, floods, fires, storms, and hurricanes, rising sea levels that can change in frequency and intensity because of climate change. Extreme weather events could result in damages to our assets and negatively affect our operations and financial condition.
In terms of energy transition risks, we face risks related to our capacity to implement measures to reduce and offset carbon and methane emissions, our adaptation to climate variability and climate change, regulatory risks related to the new climate change regulations implemented in Colombia, such as the carbon tax in place since 2017, the implementation of an emissions trading system (ETS) expected to be implemented in 2022, the updated nationally determined contribution (NDC), and the oil & gas industry’s climate change plan that includes new national mitigation and adaptation measures. These changes could lead to increases in our costs and investments in the short term (Ecopetrol has already incurred in costs related with these regulations and it is expected that continuing to comply with this evolving regulatory landscape will bring additional costs and investments for the Company in the short term). See the section Legal and Regulatory Risks - Our operations might be affected by rising climate change and energy transition regulatory developments.
Additionally, we face the risk of having stranded assets across our business segments. Specifically, we define a stranded asset as an asset or investment that loses its capacity to create economic return before ending its life cycle due to the changes brought about by the low carbon energy transition. Stranded asset risk is measured through a stranded asset risk index methodology that takes into account three risk elements: market (increasing uncertainty in price, accelerated peak oil demand); sustainability (reduced probability of developing an asset because of less community and society support to fossil fuels developments, increased pressure from investors to produce cleaner energies, regulatory changes), and capability (lack of technological capabilities to produce in the short term). Assets that have a score over a threshold in this index are considered in high risk. As of the date of this annual report, the index has been applied to our upstream segment assets with the stranded risk evaluation still being developed in our midstream and downstream segments. Our analysis resulted in no stranded assets in our upstream segment, with the assets with the highest risk of becoming stranded being just initiating their development (either still in the exploratory stage or having just commenced production). While we have begun to implement a mitigation plan in respect of assets with a high risk of becoming stranded, such as prioritizing short cycle projects, starting projects earlier, making current production cleaner and more efficient, and divesting less strategic assets, we can offer no assurance that certain of our assets will not become stranded in the medium to long term.
In addition, our business growth and sustainability depend on our ability to manage our capital investments and operate efficiently, in accordance with our corporate strategy guidelines.
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See the section Strategy and Market Overview—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 2018, 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, (as further explained below), 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, which thereby affects their respective margins, derivative financial instruments related to oil and gas; weather conditions, natural events or disasters, which are changing in intensity and frequency due to climate change, and terrorism and global conflict. After experiencing gradual recovery duringIn addition, due to the first halfdisagreement on production cuts between the Organization of 2018the Petroleum Exporting Countries (OPEC) and reaching a peak in October, Brent suffered a downward rallyRussia, the OPEC and its capacity and decision to increase production levels to gain market share have impacted the international reference prices in the latter partpast.
The continuing spread of 2018.the coronavirus disease (COVID-19) continues to lead to periods of instability in the global economy, which in turn could continue to cause instability in crude oil, NGL, and gas demand and oil, NGL, and gas prices. Additionally, the level of global oil inventories caused by the COVID-19 pandemic has created surpluses for oil and may result in the cost of exploring for, developing, producing and transporting oil to go up due to surpluses created by the pandemic. The outlook of weaker economic growth for 2019 and a mismatch of supply and demandCOVID-19 pandemic may further impact the prices of crude played a fundamental role for this trend.oil, natural gas and refined products as expectations about future commodity prices become unpredictable due to the inability to forecast the duration scope of impact of the pandemic. See Our business operations could be disrupted by the sectionStrategyCOVID-19 or other pandemic disease and Market Overviewhealth events for a discussionfurther information on the effects of the market overview.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 2018,2020, our crude oil basket price was US$63.2 per barrel 34.4/Bl versus US$47.8 58.6/Bl in 2017,2019, the refined product basket price was US$77.3 per barrel 49.2/Bl versus US$62.7 per barrel 69.8/Bl in 2017;2019; and the natural gas price was US$22.4 24.3 per barrel equivalent in 20182020 versus US$22.7 23.7 per barrel equivalent in 2017.2019. 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 2018,2020, we had an impairment of non-current assets of COP$633,156 million, as compared to COP$1,762,437 million in 2019 and COP$368,634 million compared to the COP$1,311,138 million net reversal of the impairment of non-current assets in 2017 and the impairment of non-current assets of COP$928,747 million in 2016.2018. 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 belowabove its book value. For additional information about this impairment charges, see the sectionFinancial Review—Review—Operating Results—Consolidated Results of Operations—Impairment of non-current assetsNon-Current Assets and Note 1618 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, 20182020, our U.S. dollar-denominated total debtaggregate principal amount was US$10.5 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$9.7 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$6,500 million of Ecopetrol S.A.’s debt in U.S. dollars as of December 31, 2018, 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 depreciated 11.18%12.46% in 2016, appreciated 3.35%2020, 10.98% in 20172019 and depreciated 0.18% in 2018. Additionally, as of December 31, 2020, the Colombian Peso depreciated 4.74%; as of December 31, 2019, the Colombian Peso depreciated 0.84%; and as of December 31, 2018, the Colombian Peso depreciated 8.91%, as of December 31, 2017, the Colombian Peso appreciated 0.56% and as of December 31, 2016, the Colombian Peso appreciated 4.72%, 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 ratesrate in the U.S., different global growth perspectives, commercial and political tensions in the biggest world economies, current and expected crude oil prices in the next few years and political uncertainty in Colombia, there is no clear view of how the U.S. dollar and the Colombian peso will behave in the medium to long-term. Given that markets are dealing with a great deal of uncertainty, it is expected that U.S. dollar movements will remain difficult to forecast.
A future depreciation in the exchange rate of the Colombian Peso against the U.S. dollar may affect our financial results when converted into Colombian Pesos, given our current net position in U.S. dollars, the fact that most of our revenues are collected in U.S. dollars and the portion of our U.S. dollar debt that is not designated as hedge instrument and the future debt we may acquire. Please see our sensitivity analysis on our results of operation to exchange rate fluctuations in the sectionFinancial Review—Review—Effect of Taxes, Exchange Rate Variation, Inflation and the Price of Oil on our Results—Exchange Rate Variation and in Note 28.130.1 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 US Gulf of Mexico,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. 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 Productionfor a summary of our current deep-water drilling activities.
As a result, of the oil spill in the Macondo field operated by BP in the U.S. Gulf Coast in April 2010, significant concerns regarding the safety of deep-water drilling have been raised and, as a result, applicable regulations in various countries have changed. Moremore stringent government regulation may result in increased costs and longer exploration and development timeframes for our deep-water drilling operations and consequently could adversely affect our results of operations and financial condition. Heightened risks and costs associated with deep-water drilling may have a negative effect on our results of operations and financial condition and in our reputation.
See the section Business Overview—Exploration and Production for a summary of our current deep-water drilling activities.
We are exposed to the credit, political and regulatory risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.
Some of our customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, many of our customers finance their activities through their cash flows from operations, short and long term debt or equity.
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The combination of decreasing cash flows as a result of declines in commodity prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity may result in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform their obligations to us according to their contractual terms.
Furthermore, some of our customers may be highly leveraged and subject to their own operating expenses. Therefore, the risk we face in doing business with these customers may increase. Other customers may also be subject to regulatory changes, which could increase the risk of defaulting on their obligations to us. We also could have disagreements with customers regarding tariffs, excusable events, or other aspects of our commercial relations that could lead to contract breaches by our clients. See Note 28.230.7 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, the spread in protectionist policies in the United States, China and Europe,potential impacts on demand of further lockdowns or outbreaks of COVID-19, the lack of consensus among OPECOPEC+ 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—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 February 23, 2018, despiteApril 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, Moody’s maintainedColombia. On March 26, 2020, S&P revised our long term internationaloutlook to negative and affirmed our stand-alone credit rating and outlook.in bbb-. On June 27, 2018, S&P maintainedJuly 31, 2020, Moody’s confirmed our long-term corporate credit rating at BBB- and our outlook at stable. On July 16, 2018, Moody’s upgraded our BCA (Baseline Credit Assessment) to ba1 from ba3 and maintained our long term international credit rating at Baa3, and outlook at stable. On December 6, 2018, Fitch Ratings maintained our long term international credit rating at BBB stable.with a stable outlook. We cannot offer any assurance that our credit rating will continue.
As a result of these factors, we may be forced to revise the timing and scope of our capital projects as necessary to adapt to existing market and economic conditions, downgrades to our credit ratings or to access the financial markets on terms less favorable, therefore negatively affecting our results of operations and financial condition.
In addition, under applicable regulation, 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, 2018,2020, approximately 13.9%13.62%, or a principal of US$1,569 1.8 billion (COP$5.1 trillion) 6.1 trillion, using a COP$ 3,432.50/1.00 US exchange rate as of December 31, 2020), of our total indebtedness consisted of floating rate debt. If market interest rates rise, our financing expenses will increase, which could have an adverse effect on our results of operations and financial condition. In addition, as we refinance our existing debt in the coming years, the mix of our indebtedness may change, specifically as it relates to the ratio of fixed to floating interest rates, the ratio of short-term to long-term debt, and the currencies in which our debt is denominated in or indexed to. We cannot assure that such changes will not result in increased financing expenses borne by us. Finally, as we incur new debt in the future to fund our capital projects or inorganic acquisitions, the prevailing interest rates and spreads at any specific time could be less favorable in terms of cost when compared to our previous financing transactions, which could adversely affect our financial condition and results of operations.
Our interest rate expense may be subject to uncertainty associated with the replacement or reform of benchmark indices, particularly London Interbank Offered Rate (“LIBOR”).
Interest rate, equity, foreign exchange rate and other types of indices which are deemed to be “benchmarks,” including those in widespread and long-standing use, have been the subject of ongoing international, national and other regulatory scrutiny and initiatives and proposals for reform. Some of these reforms are already effective while others are still to be implemented or are under consideration. These reforms may cause benchmarks to perform differently than in the past, or to disappear entirely, or have other consequences, which cannot be fully anticipated.
Any of the benchmark reforms that have been proposed or implemented, or the general increased regulatory scrutiny of benchmarks, could also increase the costs and risks of administering or otherwise participating in the setting of benchmarks and complying with regulations or requirements relating to benchmarks. Such factors may have the effect of discouraging market participants from continuing to administer or contribute to certain benchmarks, trigger changes in the rules or methodologies used in certain benchmarks or lead to the disappearance of certain benchmarks.
In this regard, on July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. Similarly, it is not possible to predict whether LIBOR will continue to be viewed as an acceptable market benchmark, what rate or rates may become acceptable alternatives to LIBOR, or what effect these changes in views or alternatives may have on financial markets for LIBOR-linked financial instruments. As of December 31, 2020, 8.3% of our long-term nominal debt was subject to floating interest rates that used LIBOR as the benchmark. Although we expect to adapt such contracts as developments relating to a LIBOR replacement arise, currently, we cannot reasonably estimate the impact that the transition to alternative reference rates may have on the valuation, pricing and operation of our LIBOR-based financial obligations, however such changes could have a material adverse effect on our financial condition and results of operations.
Our current and planned investments and exploration activities outside Colombia are exposed to political and economic risks.
We began exploration activities outside Colombia in 2006 through our Brazilian subsidiary, Ecopetrol Óleo e Gás do Brasil Ltda. We operate through business partners, subsidiaries or affiliates outside Colombia. We currently have investments, joint ventures and subsidiaries incorporated in Peru, Brazil, Mexico, Bermuda, Panama, the Cayman Islands, Switzerland, Spain, the United Kingdom and the United States, and we are analyzing investments in other countries. In connection with making investments, we are and will be subject to risks related to economic and political conditions and governmental economic actions. We cannot predict the positions of foreign governments relating to the oil and gas industry, land tenure, protection of private property, environmental standards, regulation or taxation; nor can we assure that future governments will maintain policies favorable to foreign investment or repatriation of capital. Additionally, we may face new and unexpected risks involving environmental and other legal requirements beyond those we currently experience.
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The results of operations and financial condition of our subsidiaries in these countries also may be adversely affected not only by risks associated with hydrocarbon exploration and production, but also by fluctuations in their local economies, political instability and government actions, including: the imposition of price controls, the imposition of restrictions on hydrocarbon exports, fluctuation of local currencies against the Colombian Peso, the nationalization of oil and gas reserves, increases in export and income tax rates for crude oil and oil products, and unilateral (governmental) institutional and contractual changes, including controls on investments and limitations on new projects.
Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas, or our production to decline, limit our ability to pursue new opportunities, affect the recoverability of our assets, or cause us to incur additional costs or delay the timeline of our projects.
Our future performance depends on the successful selection, development and deployment of new technologies and the knowledge to applyoperate, maintain and improve them.
Technology, knowledge and innovation are essential to our business, especially for reductions tothe addition of reserves in complex settings, reducing operational costs, reducing the carbon footprint of our operating costsoperations and improvements in processes relatedour adaptation to the production, refining and transportation of heavy crude oil and the exploitation of mature fields.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), there is expected to be a natural gas deficit in Colombia as of January 2024.
Considering the CREG Resolution 114186 of 2017, former Resolution 089 of 2013,2020, the natural gas market is a physical market, which means that suppliers must comply with the quantities agreed in their contracts. Hence, Ecopetrol will not be able to keep or increase its market participation unless the Company increases its naturalcontracts with firm gas reserves as local demand grows.commitments.
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Additionally, we are currently party to a number of national gas supply contracts that have firm gas commitments. If we arewere 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. Although we did not pay penalties dueEcopetrol losing market share if clients choose to delays in the start of new projects in 2018, 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.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. As a result, we may be required to enter into agreements with natural gas transportation companies on terms that are not favorable to us.
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 levels.and river 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 or even paralyzed. These risks could result in property damage, loss in production, loss of revenue, loss of life, pollution and harm to the environment, among others. If any of these occur, we may be exposed to economic sanctions, damages, fines or penalties in addition to the negative effects these events may have on our operations and the costs required to repair or remediate the related damage. These costs, fines and penalties may adversely affect our financial condition, reputation and results of operations.
Our business operations and financial condition could be negatively affected by the COVID-19 or other pandemic diseases and health events.
Pandemic diseases and health events, such as COVID-19, have the potential to negatively impact economic activities in many countries, including the countries in which we operate or have trade links, with consequent adverse effects on our customers and business.
In particular, the timeline and potential magnitude of the COVID-19 outbreak still remain unknown. The persistence and variation of the virus could continue to more broadly affect the Colombian and global economy, including our business and operations, because of its impact on the demand for oil and gas. For example, the outbreak of coronavirus has resulted in a widespread health crisis that has adversely affected the economies and financial markets of many countries, resulting in an economic downturn that affected our operating results in 2020. In addition, the effects of COVID-19 and concerns regarding its global spread have recently negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility, impacted the revenues we receive for oil and natural gas, and has materially and adversely affected the demand for and marketability of our production, and is anticipated to continue to adversely affect the same for the foreseeable future. As the potential impact from COVID-19 is difficult to predict, the extent to which it will negatively affect our operating results, or the duration of any potential business disruption is uncertain. The magnitude and duration of any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control.
In terms of the impact on Ecopetrol, the disagreement on production cuts between the Organization of the Petroleum Exporting Countries (OPEC) and Russia since the beginning of March 2020 through April, 2020, followed by the decision of Saudi Arabia to reduce its sale oil prices and increase its production to gain market share, negatively impacted the international reference prices for crude oil and refined products in 2020. Furthermore, as a result of the COVID-19 pandemic and measures put in place to slow its spread, including the imposition of quarantines and medical screenings, travel restrictions and the suspension of certain activities, we have seen and expect to continue to see substantial uncertainty in macro-economic conditions with regards to lower prices and demand for oil, gas and related products. These recent global developments resulted in a significant drop in Brent crude prices during 2020 as compared to 2019. As our business depends substantially on international prices for crude oil and refined products, while we were able to recuperate some of the losses suffered during the second quarter of 2020, the sharp decrease in oil prices in 2020 negatively impact our results of operations and business prospects for the year ended December 31, 2020 as compared to the year ended December 31, 2010. In particular, our consolidated gross profit, consolidated operating income, and consolidated net income for 2020 decreased by 52.3%, 65.8% and 81.8%, respectively, as compared to the same line items in 2019. Our operating results were affected mainly by (i) decreases in international prices of crude oil, international prices for refined products and local prices for natural gas, (ii) the reduced demand levels for crude oil and its derivative products, and (iii) decreases in sales volumes, product mix and exchange rate volatility.
For the year ended December 31, 2020, we also recognized impairment losses of non-current assets of COP$ 633,156 million, which corresponds to the net result of:
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At this point, we cannot forecast the duration of the effects of COVID-19 on our business or when international prices for crude oil and refined products will stabilize. Our future business results will be affected by the extent and duration of these conditions and the effectiveness of responsive actions that we and others take, including (i) our actions to reduce capital and operating expenses, (ii) in respect of oil supply, any cooperation between OPEC member countries, and (iii) in respect of COVID-19, the impact of vaccination programs, coverage and immunity achieved, the severity and duration of the outbreak, and the actions by national and international government authorities to contain the pandemic and minimize its impact, among other things. We will continue to monitor market developments and evaluate the impacts of decreased demand on our production levels as well as impacts on project development and future production.
See Note 2.8 to our consolidated financial statements for further information.
Our operations, including our activities in areas classified as indigenous reserves and Afro-Colombian lands, are subject to opposition from members of various communities.
We currently carry out and plan to continue carrying out activities in areas classified by the Government as indigenous reserves and Afro-Colombian lands. In order to undertake these activities, we must first comply with 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 on previously closed consultation processes.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.abroad and in 2019 entered into a joint venture with Oxy in the U.S. Permian Basin. See the sectionBusiness Overview—Overview—Our Corporate Structure. Obtaining the expected benefits of the acquisitions will depend, in part, on our ability to (i) obtain the expected results of operations and financial condition from these acquisitions, (ii) manage different sets of assets and operations and integrate distinct corporate cultures, (iii) manage our objectives as a corporate group, and (iv) institute our corporate governance rules as well as other factors beyond our control such as the economic and regulatory environment in countries in which we have made acquisitions as well as all other risks affecting the oil and gas industry. These efforts may not succeed. Our failure to successfully obtain the expected results from our acquisitions could adversely affect our financial condition and results of operations. Also, the acquisitions may be subject of review by administrative control entities in Colombia, which could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations.
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In our shale operations in the U.S., the ability to drill and develop different locations is subject to uncertainties such as natural gas and oil prices, drilling and production costs, availability of drilling services and equipment, lease acquisitions and expirations, processing capacity constraints, pipeline transportation bottlenecks, access to and availability of water sourcing and distribution systems, regulatory approvals, among others. We cannot assure that all the well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil at the planned levels.
As of the date of this annual report, there is not a clear position of the new United States’ administration regarding policies concerning Colombia. Moreover, from the original executive orders signed by President Biden related to climate change, there is a 60 day suspension to issue, extend or amend federal leases or drilling permits on federal land, while a task force conducts an environmental study. This order does not affect operations that were already on going or under drilling permits issued prior the order, but we cannot assure there will be no further executive orders that may adversely affect our U.S. operations. These executive orders also established additional task force groups to review changes in fiscal and regulatory policies, which may include changes in royalty rates, minimum bids and lease terms for federal land. Ecopetrol´s investments in the United States include federal land (Gulf of Mexico), therefore there is uncertainty in terms of how any future regulatory changes by the Biden administration will affect such leases.
In addition, as a result of strategic reassessments of our core operations and portfolio management analysis, we have executed partial or total divestments in our current businesses and the sale price in these transactions might not have been enough to realize the original expected value or to recover the investments the company has made. These transactions may also be subject to review by administrative control entities in Colombia, which could negatively impact us and could divert the efforts and attention of our management team from our ordinary business operations.
We might be required to provide financial support to our subsidiaries in Colombia or abroad.
Although currently Ecopetrol is not the sponsor and has not provided 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.
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—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—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 2018,2020, our internal cyber security systems identified and contained cyber security attacks such as malware, phishing and denial of service. In total, we had 20We 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 20182020 was 7,1387,097 GWh/year, of which 66%68% was supplied through self-generation, and the remaining 34%32% through power grid. Our demand is 10.5%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 2018,2020, the Ecopetrol Group produced approximately 13.816.3 million barrels of water per day. Taking into account the nature of our reservoirs, the water production levels to be managed by the Company may increase in the future. In order to achieve our oil and gas production goals and to avoid any production restrictions going forward, we will need to secure the required capacity to manage water levels. Factors that may trigger a possible constraint in our crude oil production due to the rising water production levels are: (i) ineffective project management of the required facilities, (ii) the Company’s and its partners’ ability to timely obtain the environmental permits related to water management, (iii) social and community interactions that could affect the development and operation of these projects, and (iv) the availability of capital to execute the required projects.
5.1.2 Risks Related to Colombia’s Political and Regional Environment
5.2.2 | Risks Related to Colombia’s Political and Regional Environment |
This section discusses potential risks related to our extensive operations in Colombia.
The worldwide economic effects of the outbreak and economic shutdown caused by the COVID-19 pandemic is adversely affecting Colombia’s economy, and the impact could be material.
The COVID-19 pandemic is currently having an adverse impact on the world economy. Many countries have undertaken various public health measures to control the spread of COVID-19, including mandatory quarantines, forced economic shutdowns and travel restrictions, as well as economic measures to mitigate the impacts of such public health policies on their respective national economy. As of March 31, 2021, Colombia had 2,406,377 confirmed cases of COVID-19, 2,285,515 recovered cases and 63,422 deaths.
On March 17, 2020, the Government, through Legislative Decree 417 of 2020, declared a 30 day state of national emergency in light of the health and economic crisis caused by the outbreak of COVID-19. On May 6, 2020, through Legislative Decree 637 of 2020, the Government declared a state of emergency for an additional 30 days. The Government has implemented various economic and public health measures to address the crisis, including (i) mandatory shelter in place orders; (ii) border closure for all non-citizens and non-residents; (iii) short term and low interest loans for all types of agricultural producers; (iv) payroll subsidies for companies and credit lines for different sectors of the economy; (iv) closure of all schools and universities; (v) incentivizing working from home and a mandatory work from home order for 80% of Government employees; (vi) actions by the Banco de la Republica, including reductions of its interest rate by 250 basis points in 2020, the provision of non-delivery forwards in the amount of up to U.S. $1 billion and supplying liquidity auctions up to COP$ 20 trillion; (vii) suspension of increases in utility tariffs; (viii) reduction in the prices of gasoline; (ix) changes to the general budget and measures to render more flexible certain procedures to enable the Government to access the credit markets; and (x) increased COVID-19 testing of up to 15,000 per day, among others. The efficacy of certain of these measures cannot yet be evaluated, and their duration and effect remain uncertain. On December 18, 2020, the Government announced that the country had purchased 40 million doses of COVID-19 vaccines, composed of 10 million doses from Pfizer Inc., 10 million doses from AstraZeneca and 20 million doses from the multilateral Covax agreement. Vaccination began in February 2021 and will have 5 phases, prioritizing those at higher risk, such as health workers and citizens over 80 years old.
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From a macroeconomic point of view, the COVID-19 pandemic had a negative impact on Colombia in 2020 with GDP decreasing by 6.8% for the year ended December 31, 2020 as compared to the year ended December 31, 2019. The main industries that lead to this decrease were construction, transportation, and accommodation, real estate and food services. Economic stagnation, the depreciation of the Colombian Peso, contraction and decreased income levels and increased unemployment levels could result in a pronounced period of economic slowdown in Colombia, which could lead to a further decrease in oil and gas demand and hence could continue to negatively impact our business and financial condition. Furthermore, the COVID-19 outbreak has also resulted in increased volatility in both the local and the international financial markets and economic indicators, such as exchange rates, interest rates, credit spreads and commodity prices. Any shocks or unexpected movements in these market factors could result in financial losses in our investment portfolio.
If the economic and public health crisis caused by the COVID-19 outbreak continues and the Government’s measures are not effective, the economic performance of the country may suffer further than already anticipated, as a result of adverse effects on commerce, transportation and foreign investment, among other things, and thus may potentially adversely affect Ecopetrol’s ability to service its debt, including the bonds. The effects of the COVID-19 pandemic and the economic shutdown may also include an increase in unemployment, a reduction in household income, reduction in Government revenues, increased Government expenditures and a deterioration of Ecopetrol’s and Colombia’s financial position. The sharply lower demand for oil and its derivatives due to decreased demand as a result of the COVID-19 pandemic in turn resulted in lower and more volatile price of oil and gas, which has also negatively affected the Colombian economy and the financial position of Ecopetrol. The Government has projected negative GDP growth of 6.8% for 2020, the first recession in Colombia in over two decades.
The COVID-19 pandemic, any additional wave or resurgence and/or new pandemic may also have the effect of heightening the other risks described herein, such as those relating to economic, social and political developments in Colombia and its credit ratings. Consequently, the current COVID-19 pandemic and its potential impact on the global economy may require Colombia to enact additional changes to existing regulations or implement more stringent regulations, which may further adversely impact the Republic’s economy, the prices of, and Colombia’s ability to make payments on, its outstanding securities or other indebtedness.
The Colombian government could seize or expropriate Ecopetrol’s assets under certain circumstances for fair compensation.
Pursuant to Articles 58 and 59 of the Colombian constitution, the Government can exercise its eminent domain powers in respect of private property assets in the event such action is deemed by the Government to be required in order to protect public interests. According to Law 388 of 1997, eminent domain powers may be exercised through: (i) an ordinary expropriation proceeding, or (ii) an administrative expropriation. In all cases we would be entitled to a fair compensation for the expropriated assets. Also, as a general rule, compensation must be paid before the asset is effectively expropriated. However, the compensation may be lower than the price for which the expropriated asset could be sold in a free-market sale or the value of the asset as part of an ongoing business. The aforementioned Article 59 of the Colombian constitution establishes ana temporary expropriation for war reasons, which does not require that compensation be paid before expropriation but can only be executed on a temporary basis.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-Coveñn - Coveñas and Oleoducto Bicentenario pipelines, and other related infrastructure disrupting our activities and those of our business partners.
During 2018,2020, the attacks against our pipeline infrastructure increaseddecreased by 66%29% in relation to 2017 (632019 (51 attacks in 20172020 compared with 10572 attacks in 2018)2019). In 2019, there have been 20Nonetheless, the attacks to date. This situation especially affected the infrastructure located in the following departments: Norte de Santander, Arauca and Nariño departments and the following pipelines: Caño Limón - Coveñas and Transandino. Transandino pipelines. There was no deferred production directly related to these attacks in 2020 as compared to a deferred production of 660,052 barrels in 2019. Throughout the first quarter of 2021, there were 12 attacks against our pipeline infrastructure.
Guerilla attacks have resulted in unscheduled shutdowns of our transportation systems in order to repair or replace sections of pipelines or production facilities that have been damaged, with deferral of production in certain fields, as well as caused us to undertake environmental remediation. For example, these attacks led to a deferred productionof 11,102 barrels in 2018. This represented a decrease from 2017 (when similar attacks led to a deferred production of 1.6 million barrels) due to the transportationIn respect of the crude frompipeline infrastructure, the Caño Limón field through the Bicentenario pipeline from Banadia in Arauca to Araguaney in Casanare. However, we cannot offer any assurance that we will continue to ensure such transportation through alternate routes.
The direct cost of repairs due to terrorist attacks and illicit taps in 20182020 was approximately COP$153 billion213,300 million (US$4762.147 million, withusing a COP$3,249.75/3,432.50/1.00 US exchange rate as of December 31, 2018)2020). Additionally, these attacks haveDuring 2020 we also experienced one particular attack to our production infrastructure in Casanare, specifically on the transfer line parallel to the Liria well that, while not affecting people or the environment, resulted in in a dent.
During 2018, attacks resulted in the unavailability of our Caño Limón-Coveñas pipeline which led certain of our customers 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 21.423.3 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 these products within the alkaloid chain production and the possible impact to communities and the environment, derived from this illegal practice. Associated with the above, the theft of crude oil has increased from approximately 1,808 bod in 2019 to approximately 2,744 bod in 2020, representing for Ecopetrol and its partners a consolidated loss of COP$367,515 million for the year ended December 31, 2020 (US$107,069 million, using COP$3,432.50/US$1.00 exchange rate as of December 31, 2020) and COP$ 241,840 million for the year ended December 31, 2019. This situation is directly related to the increase of illicit crops, presence of guerilla dissidents and other illegal groups in the areas of influence of the main crude transportation systems, such as as Caño Limón – Coveñas System (Catatumbo and Norte de Santander) and the Trasandino System (Tumaco and Nariño). Furthermore, the theft of refined products decreased fromis related to the presence of common crime that illegally markets these products, presenting losses of approximately 34.9 boed in 2017 to approximately 21 boed in 2018. Theft of crude oil decreased from approximately 1,88324 bod and 37 bod in 2017 to approximately 1,324 bod in 2018.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. Currently,Since then, the Colombian government ishas 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.
On the other hand,Likewise, the National Liberation Army, or ELN, an insurgency 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 which formally began in February 2016. In February 2017, the public dialogue phase began in Quito, Ecuador. These dialoguesthat were interrupted since January 2019, as a result of the terrorist attacks carried out by the ELN since January 2018. In April 2018, theELN. The Colombian Government decided to resumeproclaims that the dialogue, due tocontinuity of the suspension of ELN terrorist actions duringdialogues depends on the electoral period in March 2018.
The new Colombian President Ivan Duque took office in August 2018 and set the following conditions for the continuation of dialogue with the ELN: the suspensioncessation of terrorist activities and the release of hostages.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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However, following the terrorist attack by ELN against the National Police Academy (Escuela de Policía General Santander) on January 17, 2019, the Colombian Government decided to suspend dialogue with the ELN indefinitely.
ItTherefore, it is expected that some guerilla groups, such as the ELN, may continue their illegal and terrorist activities, including attacks on our infrastructure, resulting in a deterioration of Colombia’s national security and our assets, which consequently may negatively impact our operating results.
There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries.
There have been certain events in Colombia and abroad, which have resulted in political tensions between Colombia and some of its neighboring countries.
In particular, the economic, political and social crisis in Venezuela is having a severe impact on Colombia’s economy and social situation. This situation could affect the countries’ diplomatic relations, impact border towns and cities, accelerate Venezuelan migration flow into Colombia, affect our borderline operations and therefore may have a negative impact on Colombia’s economy and general security situation as well as in our operating results.
Companies operating in Colombia, including us, are subject to the prevailing economic conditions and the investment climate in Colombia, which may be less stable than the prevailing economic conditions and investment climate in developed countries.
Market prices of securities issued by Colombian companies, including us, are subject to the prevailing economic conditions in Colombia. A large portion of our assets and operations are located in Colombia and most of our sales are currently derived from our local crude oil and natural gas production and the production of our refineries located in Colombia. Accordingly, our financial condition and results of operations depend to a significant extent on macroeconomic and political conditions prevailing from time to time in Colombia and on the exchange rates between the Colombian Peso and the U.S. dollar.
If the perception of improved overall security in Colombia deteriorates or if the investment climate worsens, the Colombian economy may face lower growth rates than the ones posted recently, which could negatively affect our financial condition and results of operations. Additionally, the uncertainty of Colombia´s economic recovery due to the COVID-19 pandemic could have an impact on our results.
Furthermore, the market price of our shares and American Depositary Shares, or ADSs, may be adversely affected by changes in governmental policies, particularly those affecting economic growth, exchange rates, interest rates, inflation and taxes. The Government has changed monetary, fiscal, taxation, labor and other policies over time and has thus influenced the performance of the Colombian economy. We have no control over the extent and timing of government intervention and policies.
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.
The administration of President Iván Duque took office in August 2018. 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 addition, in December 2016, pursuant to Law 1819, the Colombian Congress enacted a tax reform, which became effective in 2017. Furthermore, 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 modifies the Colombian income tax regime. For a description of taxes affecting our results of operations and financial condition in 2018, 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 of January 1, 2019, the withholding tax rates applicable to dividends paid to non-resident shareholders 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% dividend tax after applying the initial 33% withholding tax rate. Tax treaty rules might also apply on dividend distributions when a shareholder is a resident in a country that has executed a tax treaty with Colombia and reduce or eliminate the applicable taxes if the applicable requirements are met.
5.1.3 Legal and Regulatory Risks
This section discusses potential legal and regulatory risks to Ecopetrol, including the risk of having to comply with new laws and regulations.
Our operations are subject to extensive regulation.
The Colombian hydrocarbons industry is subject to extensive regulation and supervision by the Government and regulatory agencies in matters including the award of exploration and production blocks by the ANH, the imposition of specific drilling and exploration obligations, restrictions on production, price controls, capital expenditures, liquidation of the Net Position of each refiner or importer with respect to the FEPC and required divestments. Existing regulation applies to virtually all aspects of our operations in Colombia and abroad. The commercialization activities of some of our products also face extensive regulation. Such regulation is subject to change by the applicable regulator affecting our ability to commercialize our products. See sectionBusiness Overview—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 for new contracts and such changes could have an adverse effect on our future exploration and production in Colombia. See sectionBusiness Overview—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—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, suchthose 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, 2018,2020, Ecopetrol S.A. was a party to 4,6815.361 legal proceedings relating to civil, criminal, administrative, environmental, tax, and labor claims, of which 3,2793.641 were filed against us in the Colombian courts and arbitration tribunals and of which 386234 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—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—Legal Proceedings and Related Matters.
5.1.4 Risks Related to Our ADSs
5.2.4 | Risks Related to Our ADSs |
This section discusses potential risks associated with an investment in our American Depository Shares (as opposed to our common shares) by investors outside Colombia.
Holders of our ADSs may encounter difficulties in protecting their interests.
Holders of our ADSs do not have the same voting rights as holders of our common shares. As set forth in the amended and restated deposit agreement, dated December 29, 2017, among Ecopetrol S.A., JP Morgan Chase Bank, N.A., as depositary (the “Depositary”)Depositary), and all holders from time to time of our American Depositary Receipts (as amended and restated, the “Deposit Agreement”)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”)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. InvestorsForeign 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 a non-residentan investor to report or register foreign exchange transactions with the Colombian Central Bank relating to investments in Colombia on a timely basis may prevent the investor from remitting dividends abroad or result in the initiation of an investigation and in the imposition of fines.
Colombian residents who acquire ADRs and either receive profits from this investment, surrender their ADRs or liquidate their investment in ADRs, must handle their investment by means of the procedures set forth in section 7.4.1 of the External Regulation of the Circular DCIN-83 of the Colombian Central Bank.
In the future, the Government, the Colombian Congress or the Colombian Central Bank may amend Colombia’s International Investment Statute or the foreign investment rules, which could result in more restrictive rules and could negatively affect trading of our ADSs.
Colombia currently has a free convertibility system. If a more restrictive convertibility system is implemented, the Depositary may experience difficulties when converting Colombian Peso amounts into U.S. dollars to remit dividend payments.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—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”)(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—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—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, 2018,2020, the Colombian Stock Exchange (“BVC”)(BVC) had a market capitalization of approximately COP$339,653365,657 billion (US$104.52105 billion using the closing rate for 2018)2020), a 7%16% decrease when compared with the amount at the end of 2017,2019, a daily average trading volume of approximately COP$147,031122,752 million (US$45.2433 million, using the average exchange rate for 2018)2020), a 6% increase14% decrease when compared with the volume in 2017.2019. By comparison, the New York Stock Exchange (the “NYSE”)NYSE) had a market capitalization of US$25.732.6 trillion as of December 31, 2018,2020, and a daily trading volume of approximately US$71.8182.7 billion in 2018.2020.
As of December 31, 2018,2020, our shares represented the highest market capitalization of the BVC accounting for 14.54%11% of the total COLCAP index, which reflects the price volatility of the 20 most-liquid stocks.
Given the current ownership structure of our shares, it may be difficult for you to purchase large quantities of shares from a single shareholder. We cannot assure you that a liquid trading market for our ADSs will develop or, if developed, that it will be maintained. Without a liquid trading market, the ability of investors in our ADSs to sell them at the desired price and time could be substantially limited.
We are not required to disclose as much information to investors as a U.S. issuer is required to disclose.
We are subject to the reporting requirements set by Law 964 of 2005, the Superintendence of Finance and the BVC - (Colombian Stock Exchange). The corporate disclosure requirements that apply to us may not be equivalent to the disclosure requirements that apply to a U.S. issuer and, as a result, you may receive less interim information about us than you would receive from a U.S. issuer.
5.1.5 Risks Related to the Controlling Shareholder
5.2.5 | Risks Related to the Controlling Shareholder |
Our controlling shareholder’s interests may be different from those of certain minority shareholders.
The Nation currently holds 88.49% of our outstanding capital stock, making it our controlling shareholder. The Nation as our controlling shareholder has majority voting rights at the General Shareholders Assembly to elect the members of our Board of Directors and may propose and approve decisions that may be in its own interest and that may not necessarily benefit minority shareholders.
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Our controlling shareholder may suggest and approve dividendsdividend 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.
5.3 | Risk Management |
5.2.1 Managing Risk through Our Internal Control System
5.3.1 | Integrated Risk Management System and Internal Control System |
Under the leadership of the Vice-Presidency of Compliance, in 2020 Ecopetrol S.A. 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 (ERM)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:
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 |
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. |
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.
5.2.2 Managing Information SecurityThe 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 Cybersecurityprioritizing them to implement the most appropriate response. This component has been designed and implemented across the organization, with a two-level focus: Enterprise Risk and Processes Risks.
Ecopetrol S.A.’s Internal Control System is aligned to the Company’s strategy and business processes and gives responsibility to all employees to manage risk, to maintain the effectiveness of controls, to report incidents in order to preventively correct possible deficiencies and to provide reasonable assurance of achieving corporate objectives and goals. The scope of this system includes the Company’s subsidiaries who must implement and report on the performance of its internal control system to the Company to ensure compliance with the above measures.
5.3.2 | Managing Low Carbon Economy and Climate Change Risks |
To manage and mitigate the risks related to the transition to a low carbon economy and climate change, Ecopetrol, as part of its energy transition and decarbonization activities, expects to invest approximately US$ 600 million in the next three years in projects that aim to meet our mitigation targets. Additionally, Ecopetrol has set a shadow price on carbon at US$ 20/TCO2 in 2021, 30 USD/TCO2 from 2025, and 40 USD/TCO2 from 2030 onwards, which will be used to assess and evaluate current and future projects and investments. See the section entitled Business Overview—Environmental, Social and Governance (ESG) Strategies and Initiatives—Environmental sustainability for detailed information on our strategy and carbon shadow price.
To properly adapt the Ecopetrol Group’s business strategy to the transition to a low carbon economy for ensuring long-term value creation, Ecopetrol has been conducting energy transition scenario analysis since 2018. These analyses are being updated and refined reflecting two elements: i) the acceleration of the transition in recent years given a reduction of costs of electrification and renewables earlier than expected, accompanied by increasing oil price volatility and decreased investment appetite in the hydrocarbon sector; and ii) decrease in the demand for oil & gas brought by the COVID-19 pandemic. We have assumed a peak oil scenario (globally in the late 2020s and in Colombia between the 2030s and 2040s), to reflect more ambitious actions and goals in the decarbonization path and to seize the opportunities of the transition. Our climate risk strategy is being aligned with the recommendations of the Task Force on Climate-related Financial Disclosures (TCFD) and includes the addition of a new climate-related risk to our 2020 enterprise risks, in respect of inadequate management of climate change and water. This risk complements the risk of not responding to the new low carbon economy.
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See the section entitled Strategy and Market Overview—Our Corporate Strategy for more details about our energy transition roadmap.
5.3.3 | Managing Information Security and Cybersecurity |
Ecopetrol S.A. has a dedicated management team focused on information security issues such as risk analysis, treatment of information, safe information management practices and classification of critical business information, control systems compliance and effectiveness of available information security technologies, all of which are articulated with the ERM system at the enterprise level. The Cybersecurity unit is part of the Digital Vice-presidency, reporting to senior management and to the Company’s Board of Directors.
Ecopetrol S.A. has included cybersecurity risk as one of the key enterprise risks. Based on that, a working group formed in 2014, coordinated by the cybersecurity area with the participation of industrial control systems and information technology specialists, has been understanding the new challenges of cybersecurity risk, developing activities to identify and protect critical digital assets.
During 2018,2019, 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 2018,2020, 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 2018,2020, the internal audit department conducted an auditaudits on cybersecurity processes with an emphasis on the exploration area and followfollowing up on our prior enhancement plans. As a result of such audit,the aforementioned, an action plan was established to be implementedadopted in 2019.2020. 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.
In connection therewith,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, by namingwhich now covers ensuring connectivity for teleworking, remote work and articulation with the management teammigration into the cloud for critical applications and all of the Cybersecurity unit to oversee information technology, operational technology and activities at the Ecopetrol Group level. In addition, the Cybersecurity unit was placed within the Digital Vice Presidency, reporting directlycompanies. Likewise, Ecopetrol S.A. strengthened its capabilities to senior management.
monitor and response against malicious activities.
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Ecopetrol adopteduses the ONG-C2M2 (Oil & Gas - Cybersecurity Capability Maturity Model) as a framework to manage its cybersecurity profile. maturity and to establish its Cybersecurity Program and its Cybersecurity Management System, implementing practices and capabilities those covers the following domains: Risk Management, Asset Change and Configuration Management, Identity and Access Management, Threat and Vulnerability Management, Situational Awareness, Information Sharing and Communications, Event and Incident Response - Continuity of Operations, Supply Chain and External Dependencies Management, Workforce Management and Cybersecurity Program Management.
Finally, in order to update the cybersecurity strategy for 2021 to 2023, Ecopetrol 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 cyber-incidents response procedure. a set of advanced protection controls for critical information (military grade), with focus on the reduction of cyber risk level in business units and the increase of the cultural awareness in cybersecurity terms.
5.3.4 | Managing Financial Risk |
We are exposed to certain risks associated with the nature of our operations and the financial instruments we use. Among the risks that affect our financial assets, liabilities and expected future cash flows are changes in commodity prices, currency exchange rates, interest rates and the credit quality of our counterparties.
Commodity price risk is associated with our day-to-day operations as we export and import crude oil, natural gas and refined products. We occasionally use hedges to partially protect our financial results from price fluctuations taking into account that part of our financial exposure under purchase contracts for crude oil and refined products depends on international oil prices. We believe that the risk of such exposure is partially naturally hedged since we are an integrated group (with operations in the upstream, midstream and downstream segments) and either export crude oil at international market prices or sell refined products at prices that are correlated to international market prices. During 2020, Ecopetrol S.A. executed strategic and tactical hedging operations due to its exposure to pricing indices different from the commercialization benchmark and different pricing periods between the buying and the selling of physical barrels. We do not use derivative financial instruments for speculative or profit-generating purposes. A total of 30 million barrels (mmbls) were the subject of strategic hedges oriented at protecting the Ecopetrol’s income and cash flow, limiting losses, covering production costs and avoiding potential closures of production fields; for this purpose. A total of 21.7 million barrels (mmbls) were the subject of tactical hedges oriented at mitigating risks associated with storage marketing strategies, anticipated purchases of raw materials, supply to refineries, international sales delivered at the destination port and exports of heavy fuel oil.
Currency risk arises in our operations given the fact that most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars. Therefore, when the Colombian Peso depreciates against the U.S. dollar, our revenues converted into Colombian Pesos increase. Conversely, when the Colombian Peso appreciates against the U.S. dollar, our revenues decrease. On the other hand, imported goods, oil services and the debt, which is mainly denominated in U.S. dollars, become less expensive when the Colombian Peso appreciates against the U.S. dollar and more expensive when the Colombian Peso depreciates against the U.S. dollar.
As of December 31, 20182020, our U.S. dollar-denominated total debt principal was US$10.512.3 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$9.711.8 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 incomeincomes 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, in November 2019 Ecopetrol hedged a new portion of the dollar-denominated debt against its new investment in the U.S. Permian Basin in an amount of US$0.93 billion and during 2020 Ecopetrol hedged US$1.22 billion with its foreign investments.
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As of December 31, 2018,2020, the outstanding value of the natural accounting hedges was US$6.58.5 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 28.130.1 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 CPIIBR (with a participation of 4.6%8.3%, 5.0%1.8%, 2.5% and 4.2%1.0%, respectively, of the nominal debt balance as of December 31, 2018)2020). Thus, volatility in interest rates may affect the fair value of and cash flows related to our investments and floating rate debt. In 2018,2020, 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 20.222.2 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 a set of guidelines for hedging strategies for Ecopetrol S.A. and its subsidiaries. These guidelines allow us to use financial instruments in order to mitigate the impacts in Ecopetrol’s financial statements as a result of the fluctuation of risk factors, such as commodity prices, exchange rate, interest rate and others.
These guidelines determine general principles governing hedging operations, corporate governance, the process for implementing operations which includes the identification of risk exposition as an integrated group, the identification and design of the financial structures, and execution and monitoring, among others.
The guidelines also include a list of allowable financial assets, such as forwards, futures, options and swaps and describe the differences between strategic and tactical hedging, where the former focus on protecting our financial results from market volatility and the latter is mainly designed to hedge the market risk of specific trading in physical markets.
Investment Guidelines
Ecopetrol S.A.
Ecopetrol S.A.’s management established guidelines for our investment portfolios. These guidelines determine that investments in Ecopetrol S.A.’s U.S. dollar portfolio are generally limited to investments of our excess cashand the Colombian Peso portfolio may be invested in fixed-incomefixed 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 A or higher inby any of the long term and A1/P1/F1 or higher in the short term (international scale) by Standardinternationally recognized rating agencies (Standard & Poor’s, Ratings Services, Moody’s, Investors Service orand Fitch Ratings.Ratings). In addition, Ecopetrol S.A. may also investorder to diversify risk in securities issued or guaranteed by theboth our U.S. government or Colombian government, without regard to the ratings assigned to such securities. In Ecopetrol S.A.’sDollar and 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,portfolios, Ecopetrol S.A.’s management approved an update towill determine both short- and long-term limits by issuer and issuance based on internal analyses and external risk ratings.
Additionally, the investment guidelines applicable for bothportfolios in U.S. DollarsDollar and Colombian Pesos, that has been effective since January 1, 2019. The guidelines were updated in lightPeso of the following: the current reality of the financial markets, alignment with the practices of comparable companiesEcopetrol S.A. will be segmented in the oil sector,tranches determined by Ecopetrol S.A.’s management, meeting the Ecopetrol Group’s current corporate structureCompany’s working capital 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:liquidity needs, benchmarks and cash flow projections.
5.3 Legal Proceedings and Related Matters
We are a party to various legal proceedings in the ordinary course of business. Other than the proceedings disclosed in this annual report, we are not involved in any pending (or, to our knowledge, threatened) litigation or arbitration proceeding that we believe will have a material adverse effect on our Company. Other legal proceedings that are pending against or involve us and our subsidiaries are incidental to the conduct of our and their business. We believe that the ultimate disposition of such other proceedings individually or in an aggregate basis will not have a material adverse effect on our consolidated financial condition or results of operations.
As of December 31, 2018,2020, Ecopetrol S.A. was a party to 4,6815,361 legal proceedings relating to civil, criminal, administrative, environmental, tax and labor claims, of which 3,2793,641 were filed against us in the Colombian courts and arbitration tribunals, of which 386234 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 2123 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-Coveñn - 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 in the 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, another appealtwo other appeals are in progress, one of them submitted by Ecopetrol and the Prosecutor’s Office is in progress in a case in which a former Ecopetrol employee was acquitted.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 MultipurposeMulti-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 eightfour lawsuits related to this incident with possible damages of approximately COP$7.76.95 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 approximately COP$358,201,371,800. However, based on the November 14, 2020 decision, Ecopetrol, ANDJE and CENIT, need to recalculate the amount of the claims.
As of the date of this annual report, the court has not yet set a hearing date.
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Foncoeco
On March 18, 2019, Ecopetrol received judicial notice of a lawsuit filed by workers and former workers seeking if between 1997 and 2017 the company allocated part of its profits for the wellbeing of their workers. The plaintiffs considered that they had the right to receive those profits up to COP$358,201,371,800.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 2018,2020, Ecopetrol S.A. was party to 218211 environmental administrative proceedings, of which 206185 were initiated before 2018,2020 and 1226 during 2018. During 2018, six proceedings were concluded, in two of them we were subject to monetary fines through Resolutions 200.36.18.0999 of July 16, 2018 and 200.36.18-1028 of July 17, 2018. However, another proceeding was suspended due to the replenishment of resources.2020. It is not possible for us to determine whether the pending proceedings could have a material effect on Ecopetrol. During 2020, 50 proceedings were concluded, in two of them we were subject to monetary fines through resolution 0710-0667 of 2020, in the aggregate amount of COP $265.836.101 and resolution 0052 of 2020, in the aggregate amount of COP$5.155.203.368, with the latter pending a final decision by the Environmental Authority.
Reficar Investigations
Reficar is a wholly owned subsidiary of Ecopetrol. According to Colombian regulations, Ecopetrol’s and Reficar’s employees are considered public servants, and as such can be held liable for negligent use or management of public resources. In this context, given that Ecopetrol is majority owned by the Colombian Government and Reficar is a wholly owned subsidiary of Ecopetrol, Ecopetrol and Reficar administer public resources.
As a result, Ecopetrol and Reficar employees are generally subject to the control and supervision of the following control entities, among others:
The Office of the Comptroller General (Contraloría General de la República) oversees the adequate use of public resources and has the authority to investigate public employees or private sector employees that use or manage public resources.
The Attorney General’s Office (Procuraduría General de la Nación) supervises compliance with applicable law by public employees and private sector employees that carry out public functions. The Attorney General’s Office investigates and disciplines individuals for compliance failures.
The Prosecutor’s Office (Fiscalía General de la Nación) investigates potential crimes and prosecutes alleged crimes before the court in judicial proceedings.
The following are the most significant investigations and proceedings carried out by the aforementioned state entities:
1. | The Office of the Comptroller General’s investigations and |
1.1 | Because of the modifications of the schedule and budget related to Reficar’s expansion and modernization project (the |
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 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 relatingrelated 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 relatingrelated 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 hashave 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 informedthe end of each year. This situation originates in the different interpretation, by Reficar that the House of Representatives decided, through Resolution No. 2713, 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, 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.
In respect of the special audits mentioned in sections 1.3 and 1.4 above, as of the date of this annual report, Reficar has no knowledge of any procedural action carried out by any of the Colombian control entities regarding the disciplinary, fiscal and/or criminal investigations ordered neither by the Resolution No. 2713 nor by the Resolution No. 3135.
Reficar’s external auditors issued an unqualified opinion on Reficar’s financial position as of December 31, 2016, 2017 and 2018. 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 fivefour ongoing investigationinvestigations related to the Project.
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Regarding one of these fivefour 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 (v)(vi) Reyes Reinoso YañezYanes (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 fourtwo ongoing investigations remains confidential.
As of the date of this annual report, no member of Ecopetrol’s current management team, nor the current Boards of Directors of Ecopetrol or Reficar are part of the Attorney General’s Office proceedings.
3. | The Prosecutor’s Office investigations: |
The Prosecutor’s Office has been conducting the following legal proceedings: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 |
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.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). |
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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 |
ConsideringThe Prosecutor’s Office has already made public the current stage of these legal proceedings, we are not in a position to predict the outcome of the Prosecutor’s Office’s investigation or the disposition of anyfactual basis of the charges, brought bywhich is based on the Prosecutor’s Office.theory that hiring FPJVC as the PMC of the project through a sole source process violated the objective selection principle. The defense attorneys have not yet had an opportunity to present their case against such facts in a court of law.
Ecopetrol and Reficar have cooperated closely and extensively with the control entities in furthering their investigations and will continue to monitor the status and development of these investigations.
As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar and the current employees are not part of the above proceedings. None of the legal proceedings described in this paragraph are related with bribery charges.
As of the date of this annual report, Ecopetrol and Reficar have no knowledge of any legal proceeding in the United States regarding the project.
4. | Arbitration Tribunal |
InOn 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.
TheOn June 28, 2019, CB&I submitted its Reply to the Non-Exhaustive Statement of Defence to Counterclaim increasing its claims to approximately US$137 million and COP$503,241 million (including in each case interest, respectively). On this same date, Reficar filed its Reply to CB&I’s Non-Exhaustive Statement of Defense and its Exhaustive Statement of Defense to CB&I’s counterclaim, updating its claim for provisionally paid invoices under the MOA and PIP Agreements and the EPC Contract to approximately US$137 million.
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In January 2020, McDermott International Inc., CB&I’s parent company, filed for bankruptcy and announced that it would initiate a reorganization plan pursuant to Chapter 11 of the United States Bankruptcy Law. In response to this situation, Reficar has implemented actions to protect its interests and is advised by a group of experts with whom it will continue to analyze other available measures under these new circumstances.
On January 21, 2020, Comet II B.V., the successor in interest to Chicago Bridge & Iron Company N.V., commenced a bankruptcy case under Chapter 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. Upon the bankruptcy filing, an automatic stay of the Third Written Submission iscommencement 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, be set byin its discretion, modify the Arbitral Tribunalautomatic 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 oralorder 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 islocation, and arbitration logistics and also recognizes that, without waiving any arguments, including but not limited to the Debtors’ objections to alternative hearing locations and long gap(s) between hearing dates. On June 30, 2020, McDermott International Inc. notified the relevant parties of the occurrence of the effective date of the plan of reorganization, and thus the stay lifted on the arbitration was lifted on July 1, 2020.
On May 6, 2020, the Superintendence of Corporations ordered the liquidation of CBI Colombiana S.A., a respondent in the arbitration against CB&I. On October 22, 2020, Reficar submitted a proof of claim in the liquidation proceeding to seek recognition as a creditor of CBI Colombiana S.A. for the amounts of its claims in the arbitration. On January 15, 2021, the liquidator of CBI Colombiana S.A. accepted Reficar’s petition.
On September 22, 2020, the Tribunal scheduled to begin in April 2020. Afterthe commencement of the hearing in May 2021. Until the Tribunal will analyze the parties’ arguments to renderrenders its final decision, on Reficar’s and CB&I’s claims. Until then, 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.
As a result of some of the date of this annual report,findings, the Office of the Comptroller General hadopened several actions of fiscal liability (proceso de responsabilidad fiscal) against former members of Bioenergy’s administration and third-party companies.
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In 2018, the Office of the Comptroller General initiated a financial audit of Bioenergy’s financial statements for the year ended December 31, 2018. On May 21, 2019, the Comptroller General delivered its financial audit final report, issuing: (i) an unqualified opinion on Bioenergy’s financial statements, (ii) an efficient and effective internal control process opinion, and (iii) a reasonable opinion, since the budget was prepared and executed, in all relevant matters, according to Bioenergy’s budgeting internal regulation. Finally, the Office of the Comptroller General determined three findings related to: (i) plots of land pending to legalize, (ii) ethanol imports and (iii) the leasing agreement of the Casa Roja plot of Land. On December 31, 2020, Bioenergy completed all of the activities set forth in the remediation plan to address the three findings.
In 2019, the Office of the Comptroller General initiated and ended a compliance audit of Bioenergy S.A.S for the period starting July 1, 2017 to May 31, 2019. The Comptroller General notified Bioenergy on February 4, 2020 its compliance audit final report determining seven findings related to: (i) agricultural lands productivity, (ii) incomes and expenses from rental payments of subleased agricultural lands, (iii) Balanced scorecard results for 2017-2018, (iv) update of laboratory procedures, (v) transport contract number 0029-17 settlement, (vi) document handling and (vii) Campo Victoria plot of Land. Bioenergy filed the remediation plan on February 25, 2020.
Until June 24, 2020, when the Superintendence of Companies of Colombia gave the order to start the Bioenergy’s liquidation process, Bioenergy S.A.S. completed activities as scheduled in the remediation plan according to the June 30, 2020 deadline. Any pending activities related to the aforementioned remediation plan, are in charge of the liquidator appointed by the Superintendence of Companies of Colombia in Bioenergy’s liquidation process.
6. | Shareholder Information |
6.1 Shareholders’ General Assembly
6.1 | Shareholders’ General Assembly |
Our Shareholders’ General Assembly was held on March 29, 201926, 2021 and the following matters were approved:
Amendment of our bylaws. For further information please see the sectionCorporate Governance—Bylaws. |
Non-Independent Directors:
Independent Directors:
In 2018, the Board of Directors approved a dividend policy consisting of the ordinary distribution of between 40% and 60% of the adjusted net income of the Company of each fiscal year. For this purpose, the Board of Directors shall assess overall delivery against the Company’s financial targets, as well as the macroeconomic environment, projected cash requirements for delivering on our Business Plan and strategy, while maintaining appropriate financial flexibility in keeping the Company’s debt metrics in line with an investment grade rating. The policy does not preclude the distribution of extraordinary dividends above the 40% to 60% range, under exceptional circumstances and with due consideration of the above criteria. The maximum amount to be distributed is the profits available to shareholders (net income after release and appropriation for legal, fiscal and occasional reserves).
Pursuant to Colombian law, dividend distribution to our shareholders must be approved by a 78% majority of the shares represented in the corresponding General Shareholders Assembly. In the absence of this special majority, at least 50% of the net profits must be distributed.
On March 26, 2021, our shareholders at the ordinary General Shareholders’ Assembly approved an ordinary dividend of 41.41% of our net income for the fiscal year ended December 31, 2020 amounting to COP$698,984 million, or COP$17 per share, based on the number of outstanding shares as of December 31, 2020. The payment date will be April 22, 2021 for 100% of our shareholders.
On March 27, 2020, our shareholders at the ordinary General Shareholders’ Assembly approved an ordinary dividend of 56% of our net income for the fiscal year ended December 31, 2019. At the Extraordinary General Shareholders’ Meeting held on December 16, 2019, the Company’s Shareholders approved the following: i) the change in the destination of the Company’s occasional reserve that had been constituted in the General Shareholders’ Meeting held on March 29, 2019 and ii) its subsequent distribution as an extraordinary dividend of 89 Colombian pesos (COP$89) per share.
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On March 29, 2019, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 60% of our net income or COP$169 per share (within the dividend policy of 40% and 60% of net income), for the fiscal year ended December 31, 2018 and an extraordinary dividend of 20% of our net income or COP$56 per share, given our strong operational and robust cash position in 2018,for a total dividend per share of COP$225. On March 23, 2018, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 55% of our net income for the fiscal year ended December 31, 2017. On March 31, 2017, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 40% of our net income before the impairment of non-current assets (net of taxes) for the fiscal year ended December 31, 2016. Given that the fiscal year ended December 31, 2015 resulted in a net loss for Ecopetrol S.A., our shareholders at the General Shareholders Assembly held on March 31, 2016, approved that there was no distribution of profits for the fiscal year ended December 31, 2015. See sectionFinancial 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 continuous 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$260.6658 275.0626 as of December 31, 2018)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 articleArticle 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 ADR Program Feeshas issued the following classes of registered notes under an indenture (the Indenture), dated as of July 23, 2009, and amended as of June 26, 2015, between the Company and the Bank of New York Mellon, as trustee:
5.875% Notes due 2023
4.125% Notes due 2025
5.375% Notes due 2026
6.875% Notes due 2030
7.375% Notes due 2043
5.875% Notes due 2045
Please refer to Exhibits 4.13, 4.14, 4.15, 4.16, 4.17, 4.18, 4.19, and 4.20 to this annual report for the information relating to these debt securities required by Item 12.A of Form 20-F.
6.5 | Description of Ecopetrol ADRs |
Fees and Charges That a Holder of Our ADSs May Have to Pay, Either Directly or Indirectly
JPMorgan Chase Bank, N.A., our Depositary, may charge each person to whom ADSs are issued, including, without limitation, issuances against deposits of shares, issuances in respect of share distributions, rights and other distributions, issuances pursuant to a stock dividend or stock split declared by us or issuances pursuant to a merger, exchange of securities or any other transaction or event affecting the ADSs or Deposited Securities, and each person surrendering ADSs for withdrawal of Deposited Securities in any manner permitted by the Deposit Agreement or whose ADSs are cancelled or reduced for any other reason, US$5.00 for each 100 ADS (or any portion thereof) issued, delivered, reduced, cancelled or surrendered, as the case may be. The Depositary may sell (by public or private sale) sufficient securities and property received in respect of a share distribution, rights and/or other distribution prior to such deposit to pay such charge.
The Depositary collects its fees for issuance and cancellation of ADSs directly from investors depositing common shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The Depositary may collect its annual fee for Depositary services by deduction from cash distributions, or by directly billing investors, or by charging the book-entry system accounts of participants acting for them. The Depositary may generally refuse to provide services to any holder until the fees and expenses owing by such holder for those services or otherwise are paid.
The following additional charges may be incurred by holders of ADRs, by any party depositing or withdrawing common shares or by any party surrendering ADSs and/or to whom ADSs are issued (including, without limitation, issuance pursuant to a stock dividend or stock split declared by us or an exchange of stock regarding the ADRs or the Deposited Securities or a distribution of ADSs), whichever is applicable:
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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 2016, reimbursements were made in the amount of approximately US$2,366,395 for expenses related to investor relations activities. 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.
6.5 Taxation 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.
6.5.1 Colombian Tax ConsiderationsOther
Please refer to Exhibit 2.1 to this annual report for the remaining information relating to our American Depository Shares required by Item 12.D of Form 20-F.
6.6 | Taxation |
6.6.1 | Colombian Tax Considerations |
The following is a general description of the Colombian tax considerations for investments in common shares in Colombia or for the purchase of ADSs, in a foreign securities market. This description is based on applicable law in effect as of the date of this annual report is issued, which may be subject to changes.
Prospective purchasers of common shares or ADSs should consult their own tax advisors for a detailed analysis of the tax consequences in Colombia, resulting from the acquisition, ownership and disposition of common shares or ADSs.
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General Rules
Colombian entities and individuals who are deemed to be residents within the Colombian national territory for Colombian tax purposes are subject to Colombian income tax on their worldwide income. Foreign entities and individuals who are not deemed to be residents in Colombia, are subject to income tax in Colombia only with respect to their Colombian-source income, which is generally defined as income obtained from (i) the rendering of services inside Colombian territory, (ii) the exploitation of tangible and intangible assets in Colombia, and (iii) the sale of tangible or intangible assets that are located inside Colombian territory at the time of the sale.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 articlesArticles 48 and 49 of the Colombian Tax Code (hereinafter “CTC”). For more information related to the Colombian dividends tax regime, seeRisk Review—Risk Factors—Risks Related to Colombia’s Political and Regional Information.
As mentioned above, Law 1819 of 2016 created a new dividends tax that applies on all dividend distributions to Colombian individuals or to any type of non-resident shareholder, absent any specific treaty or exception, regardless that dividends are paid from taxed or non-taxed profits. According to the aforementioned law, dividend payments made to foreign shareholders out of profits accrued at the corporate level as of 2017 were subject to a 5% withholding. That rate was subsequently modified by Law 1943 of 2018, which increased it to 7.5% and extended dividend taxation to intercompany dividends between Colombian resident companies (with certain exceptions).
From fiscal year 2019 onwards, a withholding tax on dividends paid applies as follows:
For resident companies and non-resident shareholders (companies and individuals): (i) a |
For Colombian individuals: dividend income in excess of 300 UVT are taxed at a 15% and 10% rate, |
Note that the dividend tax applies simultaneously with the aforementioned system. Accordingly, dividends paid from non-taxed profits were subject to a 35% withholding for income tax, plus an additional 5% dividend tax on the balance. This means that the overall burden in this scenario was 38.25% (e.g. $100 *35% = $35, plus $65 * 5% = $3.25). As for taxable year 2019, dividends paid from non-taxed profits are subject to a 33% withholding for income tax (32% for 2020, 31% for 2021 and 30% as of 2022), and an additional 7.5% dividend tax on the balance. In this case, the combined tax rate is approximately 38.025% (e.g. $100 *33% = $33, plus $67 * 7.5% = $5.025).
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:
He/she remains in Colombia continuously or discontinuously for more than 183 calendar days within any given 365-consecutive-day term; |
He/she is related to the Colombian government’s foreign service or to individuals who are in the Colombian government’s foreign service and who, by virtue of the Vienna Conventions on diplomatic and consular relations, are exempted from taxes during the time of their service; or |
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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:
If more than 50% of his or her annual income has its source in the jurisdiction where he or she is domiciled and whose country of domicile is not Colombia. |
If more than 50% of his/her assets are located in the jurisdiction where he or she is domiciled and whose country of domicile is not Colombia. |
For purposes of Colombian taxation, an entity is deemed to be a “national” or a “Colombian entity” and, therefore, subject to taxation in Colombia on its worldwide income, if it meets any of the following criteria:
It has its place of effective management, in Colombia during the corresponding year or taxable period; |
It has its main domicile in the Colombian territory; or |
It has been incorporated in Colombia, in accordance with Colombian laws. |
Pursuant to the Colombian Tax Code, a foreign company or non-resident individual has a permanent establishment in Colombia when said company or individual performs activities in Colombia through: (1)(i) a fixed place of business (i.e., branches, factories or offices), or (2)(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 establishmentsestablishments..
Tax Treatment of a Non-Colombian Entity and a Non-Resident Individual of Colombia Who Purchases an ADS in a Foreign Securities Market
Dividends
As a general rule, dividends paid to foreign companies, foreign entities or non-resident individuals who are investing in ADSs which underlying assets are Colombian shares are treated as Colombian-source income and are thus subject to Colombian income tax.
To avoid double taxation, dividends paid by Colombian entities are not subject to income tax at the shareholder level when they are paid out of corporate profits that have been previously taxed at the corporate level. For fiscal years 2017 and 2018, a withholding tax on dividends was triggered for dividends paid to non-resident shareholders. Withholding tax rates on dividends were as follows: (i) a 5% dividend tax for dividends distributed out of profits already taxed at the company’s level; (ii) 35% withholding tax rate for dividends distributed out of profits that were not taxed at the company’s level, plus a 5% dividend tax rate after having applied and deducted the initial 35% withholding.Note that dividends paid to non-resident shareholders out of profits taxed at the corporate level until December 31, 2016, are not subject to the aforementioned 5% dividend tax or any other income tax.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 20192020 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.
To avoid double taxation, dividends 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. However, for 2017 and 2018, a withholding tax on dividends was triggered for dividends paid to non-resident shareholders. Withholding tax rates on dividends varied as follows: (i) 5%The dividend tax for dividends distributed out of profits already taxed at the company’s level (except that dividends paid to non-resident shareholders out of profits taxed at the corporate level prior to and including December 31, 2016, are not subject to this tax); and (ii) 35% withholding tax for dividends distributed out of profits not taxed at the company’s level. As of 2019, the withholding tax rates applicable to dividends paid 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%regime as of 2022), plus an additional 7.5% dividend tax after applying the initial 33% withholding tax rate.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, provided that their investments qualify as portfolio investments (i.e., investing through a FFAA) andmechanism. In this case withholding will apply at 25% on dividends that are distributed by the Colombian entity are not taxed at the corporate level. In this case, pursuantPursuant to Article 18-1 of the Colombian Tax Code, the applicable withholding tax rate is 25%, 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.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 1943/2018.2018 and Law 2010/2019. See sectionFinancial 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.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 20192020 onwards). See sectionFinancial 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 articleArticle 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:
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 |
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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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 arrangementsarrangements) by vote or by value),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, which we call 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 20182020 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 20192021 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”)(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. payorpayer 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. A U.S. Holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed its U.S. federal income tax liability by timely filing a refund claim with the IRS.
U.S. Tax Considerations for Non-U.S. Holders
A holder or beneficial owner of common shares or ADSs that is not a U.S. Holder for U.S. federal income tax purposes (a “non-U.S. Holder”) generally will not be subject to U.S. federal income or withholding tax on dividends received on common shares or ADSs, unless the dividends are “effectively connected” with the non-U.S. Holder’s conduct of a trade or business within the United States. In such a case, a non-U.S. Holder generally will be taxed in the same manner as a U.S. Holder. In the case of “effectively connected” dividends received by a corporate non-U.S. Holder, the corporate non-U.S. Holder may, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate.
A non-U.S. Holder of common shares or ADSs will not be subject to U.S. federal income or withholding tax on gain realized on the sale of common shares or ADSs, unless (i) the gain is “effectively connected” with the non-U.S. Holder’s conduct of a trade or business in the United States or (ii) in the case of gain realized by an individual non-U.S. Holder, the non-U.S. Holder is present in the United States for 183 days or more in the taxable year of the sale and certain other conditions are met. In the case of “effectively connected” gains realized by a corporate non-U.S. Holder, the corporate non-U.S. Holder may, under certain circumstances, be subject to an additional “branch profits tax” at a 30% rate.
Although non-U.S. Holders generally are exempt from backup withholding and information reporting requirements, a non-U.S. Holder may be required to comply with certification and identification procedures in order to establish its exemption from information reporting and backup withholding.
Exchange Controls and Limitations |
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—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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Exchange Rates |
On April 1, 2019,5, 2021, the Representative Market Exchange Rate was COP$3,174,79 3,679 per US$1.00. The Federal Reserve Bank of New York does not report a noon-buying rate for Colombian Pesos. The Superintendence of Finance calculates the Representative Market Exchange Rate based on the weighted averages of the buy and sell foreign exchange rates quoted daily by foreign exchange rate market intermediaries including financial institutions for the purchase and sale of U.S. dollars. The Superintendence of Finance also calculates the Representative Market Exchange Rate for each month for purposes of preparing financial statements and converting amounts in foreign currency to Colombian Pesos.
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, 2019:2021:
Table 5663 – Major Shareholders
At March 31, 2019 | 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 25, 2019,16, 2021, the registration date of our annual general shareholders’ meeting, 2.7%1.39% of our common shares were held of record in the form of American Depository Shares, we had 3738 registered holders, and 20,74913,048 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.
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.:
Promote and guarantee all stakeholders transparency, objectivity and competitiveness; Add value to the company and attract investors; Protect shareholders, investors and stakeholders’ rights; Encourage financial markets confidence; and Accomplish the highest corporate governance standards. Corporate Governance System Corporate governance is the system of rules and practices that govern the decision-making process between the governing bodies of the Ecopetrol Group, as well as the relationships between the companies that comprise it. Corporate Governance in Ecopetrol is more than a key element for organizational management—it is a strategy enabler that our stakeholders value and monitor continuously, as it generates trust, sustainable results over time and results in long-term value relationships. 177 Our model is structured based on the law, international standards, good practices and the strategy of the Ecopetrol Group, in order to ensure adequate decision-making of the governing bodies of the Ecopetrol Group in terms of agility, clarity and consistency, as well as the promotion of the realization of synergies between Ecopetrol and the Ecopetrol Group companies. To leverage the business strategy, Ecopetrol has a Corporate Governance System that aims to provide a consistent, sustainable and objective framework for action to safeguard Ecopetrol’s governance as well as generate synchrony and articulation with the companies of the Ecopetrol Group. The main elements of this system are:
Statement of the Nation as Majority Shareholder
Ecopetrol’s majority shareholder (the Nation, represented by the Ministry of Finance and Public Credit), is unilaterally committed to protect the interests of the minority shareholders in the following topics:
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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,
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—Board of Directors—Board Practices andCorporate Governance—Board of Directors—Board Committees.
General
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
Extraordinary
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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
The vote of at least 70% of the shares present and entitled to vote at the ordinary shareholders’ meeting is required to approve the issuance of stock not subject to preemptive rights;
The vote of at least 78% of the shares represented entitled to vote is required to approve the distribution of the annual net profits. In the absence of this special majority, at least 50% of the net profits must be distributed. If the sum of all legal reserves (statutory, legal and optional) exceeds the amount of the outstanding capital, the Company must distribute at least 70% of the annual net profits;
The vote of at least 80% of the shares represented is required to approve the payment of dividends in shares; and
The vote of 100% of the outstanding and issued shares is required to replace a vacancy on the Board of Directors without applying the electoral quotient system.
Shareholders may be represented by proxies, provided that the proxy:
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
Under Commercial Colombian law, our shareholders have the following economic privileges and voting rights:
to participate and vote on the decisions of the General Shareholders Assembly; to receive dividends based on the financial performance of the Company in proportion to their share ownership; to transfer and sell shares according to our bylaws and Colombian law; to inspect corporate books and records with 15 business days prior to the ordinary shareholders’ meeting where the year-end financial statements are to be approved; 180 upon liquidation, to receive a proportional amount of the corporate assets after the payment of external liabilities; and
Sale of Assets. For a ten-year period counted from the date of subscription of the declaration of the Nation dated February 16, 2018 or until the Nation loses its status as majority shareholder, the Nation guarantees that any sale of 15% or more of our assets requires the approval of the General Shareholders Assembly and that the Nation would only be allowed to vote its shares in favor of the proposal if 2% or more of our minority shareholders accept the proposal.
Candidate List. Pursuant to our bylaws and Law 1118 of 2006, the Nation will include in its candidate list for election of members of the Board of Directors one member selected by the departments that produce hydrocarbons. In addition, pursuant to the declaration of the Nation dated February 16, 2018, the Nation will include in its candidate list for election of members of the Board of Directors one member selected by the ten largest minority shareholders. The minority shareholders’ right to select a candidate loses its effect when minority shareholders, according to their share participation, name a member to our Board of Directors.
Extraordinary Shareholders Meetings. Our bylaws provide that the entity exercising permanent control over Ecopetrol must instruct the Company’s CEO or External Auditor to call an extraordinary meeting of the Company’s shareholders when so requested by a plurality of shareholders holding at least 5% of the total number of outstanding shares. Such requests shall be made in writing and must clearly indicate the purpose of the meeting.
Investor Relations Office. Ecopetrol has an investor relations office, a specialized unit responsible for our shareholders. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may request that the investor relations office conduct a special audit, provided that such audit does not hinder the day-to-day operations of the Company, of the following documents: the income statement; the proposal for the distribution of profits; the report of the Board of Directors as to the economic and financial status of our Company; the report from our general counsel as to the legal status of our Company; and the report from the independent auditors. Special audits cannot be made of documents that contain scientific, technological or statistical information of our Company, or agreements that give us competitive and economic advantages over our competitors, or in respect of any document related to intellectual property. Shareholders also have the right to propose good corporate governance recommendations to the office for the protection of investors.
Others. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may propose recommendations to our Board of Directors pertaining to the management of our Company. Any shareholder may file a written petition to our Board of Directors to investigate corporate governance violations that the shareholder believes to have been committed.
Amendments to Rights and Restrictions to Shares
We have only one class of stock and it has no special rights or restrictions (ordinary shares). Our shareholders do not have any type of preemptive rights. The rights given to our shareholders by law are described in our bylaws and may only be modified through an amendment to the law.
The additional rights given to our minority shareholders in our bylaws and corporate governance code may only be modified through an amendment of those internal documents. 181
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
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.
In our
Our
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Our https://www.ecopetrol.com.co/wps/portal/
The current Board of Directors was elected at the General Shareholders Ordinary Meeting held on March
The current Board of Directors is composed as follows:
Non-independent
Germán Eduardo Quintero Rojas.
Independent members:
Luis Guillermo Echeverri Vélez
Carlos Gustavo Cano Sanz (nominated by ten (10) minority shareholders with major shareholding)
The information below sets forth the names and business experience of each of the Directors elected at the General Shareholders Ordinary Meeting held on March Germán Eduardo Quintero Rojas Cecilia María Vélez White has extensive professional experience, having occupied the
183 Luis Guillermo Echeverri Vélez
Juan Emilio Posada Echeverri 184 Sergio Restrepo Isaza Luis Santiago Perdomo Maldonado Esteban Piedrahíta Uribe is currently Chairperson of the Chamber of Commerce of Cali. He previously held the positions of General Director at Departamento de Planeación Nacional, Advisor to the President and then Senior Specialist at the Inter-American Development Bank, Economic Editor of Semana magazine and General Manager of Endriven Colombia/Gas Meridional S.A.S. E.S.P., among others. He has been a member of the Boards of Directors of
Hernando Ramírez Plazas Carlos Gustavo Cano Sanz 185
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
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.
Pursuant to our bylaws, our Board of Directors has the ability to constitute the committees it considers necessary. The Board of Directors currently has 186
Table
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
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. 187
Our
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,
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 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
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.
188
189
The following presents information concerning our executive officers and senior management. Unless otherwise noted, the majority of these individuals are Colombian citizens. Executive Officers Felipe Bayon Pardo Alberto Consuegra Granger
Jaime Caballero Uribe Management Team Jorge Elman Osorio Franco 190 Jorge Arturo Calvache Archila
Jurgen Gerardo Loeber Rojas
Pedro Fernando Manrique Gutierrez
Juan Manuel Rojas Payán Yeimy Báez has served as Gas Vice-President since March 2020. In this position, Ms. Báez is responsible for leading, strengthening and executing an integrated strategy to develop natural gas, LPG, biogas and hydrogen, which being clean energy sources are fundamental for energy transition and the Ecopetrol Group’s sustainability. She has over 17 years of experience in the oil and gas industry, where she successfully fulfilled a broad range of technical, commercial, strategic and financial roles; including as the Corporate Manager of Financial Planning and Business Performance in Ecopetrol. She holds a degree in Petroleum Engineering from the Industrial University of Santander, an MBA degree from Externado of Colombia University and is highly-skillful in Project Management (PMP certified). Prior to her current assignment, she served for recognized players in the industry such as Equión, BP and Weatherford. 191 Mauricio Jaramillo Galvis has served as Vice-President of Health, Safety and Environment (HSE) since January 2020. Mr Jaramillo has 26 years of experience in the oil and gas private sector in Colombia and Latin America. He has been appointed to several leadership roles as Vice-President of HSE of BP Colombia, Vice-President of HSE and Engineering at the Andean Unit of BP, Vice-President of Corporate Affairs and HSE, and Vice-President of Human Resources and Sustainability at Equión, among others. Mr. Jaramillo holds an MD from Universidad Javeriana, a specialization in Occupational Health and Safety from Universidad El Bosque and a degree from the Operations Academy at MIT.
Fernán Ignacio Bejarano Arias Mónica Jiménez González María Juliana Alban Durán Alejandro Arango Lopez 192 Andres Eduardo Mantilla Zarate
Carlos Andrés Santos Nieto
Ernesto Gutiérrez de Piñeres
None of our Directors, Executive Officers or members of senior management has any familial relationship with any Director, Executive Officer or member of senior management.
Based on a resolution adopted at our annual shareholders’ meeting in 2012, compensation for Directors’ attendance in person at meetings of the Board of Directors and/or committee meetings increased from the equivalent of four to six minimum monthly wage salaries, which totals approximately COP$ 193
No individual Director or executive officer beneficially owns more than 1% of our outstanding shares.
The following executive officers own shares of Ecopetrol:
Table
Under Colombian law, all of our shareholders have the same economic privileges and voting rights.
Disclosure Controls and Procedures
As required by Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as of December 31,
Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of the end of the period covered by this annual report, our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in the reports that we file and submit under the Securities Exchange Act of 1934 is recorded, summarized and reported as and when required and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15(d)-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer, and monitored by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with generally accepted accounting principles, and it includes those policies and procedures that: i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets; ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorization of our management and directors; and iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. 194
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, effective control over financial reporting cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projection of any evaluation of the effectiveness of the internal controls to future periods is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
As of the year ended December 31,
Based on the assessment performed, management concluded that our internal control over financial reporting was effective as of the end of the period covered by this annual report.
The effectiveness of our internal control over financial reporting has been audited by Ernst & Young Audit S.A.S., an independent registered public accounting firm, as stated in their audit report accompanying our consolidated financial statements.
Audit and Non-Audit Fees
Our consolidated financial statements for the fiscal years ended December 31,
Table
Audit Fees. The audit fees listed in the table above are the aggregated fees billed by Ernst & Young Audit S.A.S. in connection with their audits of our annual consolidated financial statements (IFRS), interim consolidated financial statements (under IFRS), statutory audits of Ecopetrol S.A. and its consolidated subsidiaries and some of its associate entities (under local GAAP) and review of periodic documents filed with the SEC. In addition, these audit fees include fees related to our independent auditors’ audits of our internal controls over financial reporting.
Changes in Internal Control over Financial Reporting
There were no changes made in our internal control over financial reporting during the year ended December 31, 195
Attestation Report of the Registered Public Accounting Firm
Ernst & Young Audit S.A.S.’s attestation report on our internal control over financial reporting is included in their audit report accompanying our consolidated financial statements. SeeReport of Independent Registered Public Accounting Firm to the consolidated financial statements.
Significant Changes
For a description of significant events since December 31,
196
Ecopetrol S.A. Consolidated Financial Statements At December 31,
197
F-1
To the Shareholders and the Board of Directors of Ecopetrol S.A.
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of Ecopetrol S.A. (the Company) as of December 31,
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31,
Basis for Opinion
These financial statements are the responsibility of the
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. F-2
F-3
F-4
F-5
To the Shareholders and the Board of Directors of Ecopetrol S.A.
Opinion on Internal Control over Financial Reporting
We have audited Ecopetrol S.A.’ internal control over financial reporting as of December 31,
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Company as of December 31,
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. F-6
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
F-7 Ecopetrol S.A. Consolidated statement of financial position (In millions of Colombian pesos)
F-8 Ecopetrol S.A. Consolidated statement of profit or loss
(In millions of Colombian pesos, except for
F-9 Ecopetrol S.A. Consolidated statement of
(In millions of Colombian pesos)
F-10 Ecopetrol S.A. Consolidated statement of changes in equity
(In millions of Colombian pesos)
F-11 Ecopetrol S.A. Consolidated statement of changes in equity
(In millions of Colombian pesos)
F-12 Ecopetrol S.A. Consolidated statement of cash flows
(In millions of Colombian pesos)
F-13 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Ecopetrol S.A. (“Ecopetrol”) is a mixed economy company, of a commercial nature, incorporated in 1948 in Bogotá – Colombia, and the parent company of the Ecopetrol Business Group. Its corporate purpose is to conduct commercial or industrial activities related to the exploration, exploitation, production, refining, transportation, storage, distribution and commercialization of hydrocarbons and their derivatives and products, directly or through its subsidiaries (collectively referred to as “Ecopetrol Business Group”).
11.51% of Ecopetrol shares are publicly traded on the New York and Colombian Stock
The address of the main office of Ecopetrol is Bogotá – Colombia, Carrera 13 No. 36 – 24.
The consolidated financial statements of Ecopetrol and its subsidiaries as of December 31,
Accounting policies described in Note 4 have been applied consistently in all years presented.
These consolidated financial statements were approved and authorized for issuance by the Board of Directors of Ecopetrol on April
The consolidated financial statements were prepared by consolidating all companies set out in Exhibit 1, which are those over which Ecopetrol exercises direct or indirect control. Control is achieved when the Ecopetrol Business Group:
F-14 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases.
All inter–company assets and liabilities, equity, income, expenses and cash flows relating to transactions between entities of the Ecopetrol Business Group were eliminated on consolidation. Unrealized losses are also eliminated. Non–controlling interest represents the proportion of profit, other comprehensive income and net assets in subsidiaries that are not attributable to Ecopetrol shareholders. The following subsidiaries had changes in the Group: 2020
2019
F-15 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
2018
The consolidated financial statements have been prepared on a historical cost basis, except for financial assets and liabilities that are measured at fair value through profit or loss and/or changes in other comprehensive income at the end of each reporting period, as explained in the accounting policies included below.
Historical cost is generally based on fair value of the consideration given in exchange for goods and services.
The fair value is the price that would be received from selling an asset or that would be paid for transferring a liability among market participants, in an orderly transaction, on the date of measurement. When estimating the fair value, the Ecopetrol Business Group uses assumptions that market participants would use for pricing an asset or liability at current market conditions, including risk assumptions.
The consolidated financial statements are presented in Colombian Pesos, which is the Ecopetrol’s functional currency. For each Ecopetrol Business Group entity, its functional currency is determined based of the main economic environment where it operates.
The statements of profit or loss and cash flows of subsidiaries with functional currencies different from Ecopetrol S.A.’s functional currency are translated at the exchange rates on the dates of the transaction or based on the monthly average exchange rate. Assets and liabilities are translated at the closing rate, and other equity items are translated at exchange rates at the time of the transaction. All resulting exchange differences are recognized in other comprehensive income. On disposal of all or significant part of a foreign operation, the cumulative translation adjustment related to the particular foreign operation is reclassified to profit or loss.
The financial statements are presented in Colombian pesos rounded up to the closest million unit
Transactions in foreign currencies are initially recorded by the Ecopetrol Business Group’s entities at their respective functional currency spot rates at the transactions date. Monetary items denominated in foreign currencies are translated at the functional currency spot rates prevailing at the reporting date. Differences arising on settlement or translation or monetary items are recognized in profit or loss, in financial results, net, except those resulting from the conversion of loans and borrowings designated as cash flow hedges or net investment in a foreign operation hedge, which are recognized in other comprehensive income within equity. When the hedged item affects the financial results, exchange differences accumulated in equity are reclassified to profit or loss as part of operating results. F-16 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Non–monetary items measured at fair value that are denominated in a foreign currency are translated using the exchange rates prevailing on the date when the fair value is determined. The gain or loss arising on translation of non–monetary items measured at fair value is treated in line with the recognition of the gain or loss on the change in fair value of the item.
The Ecopetrol Business Group presents assets and liabilities in the consolidated statement of financial position based on whether assets are classified as current or non–current.
An asset or liability is classified as current when:
Other assets and liabilities are classified as non–current.
Deferred tax assets and liabilities are classified as non–current assets and liabilities.
Basic earnings per share is calculated by dividing the profit for the year attributable to equity holders of Ecopetrol S.A., the parent company, by the weighted average number of ordinary shares outstanding during the year. There is no potential dilution of shares.
The Covid-19 outbreak was first reported in late 2019 in China. Subsequently, taking into account the level of expansion, the World Health Organization (WHO) declared the outbreak as a pandemic on March 11, 2020. Said status is maintained to the date of this annual report. Many countries have undertaken various public health measures to control the spread of COVID-19, including mandatory quarantines, forced economic shutdowns and travel restrictions, as well as economic measures to mitigate the impacts of such public health policies on their respective national economy. The Covid-19 pandemic has also caused significant volatility in financial and commodity markets around the world. While governments have announced aid packages to the most affected people and taken macroeconomic measures to face the crisis, the COVID-19 pandemic has disrupted economies worldwide. On March 17, 2020, Colombia Government, through Legislative Decree 417 of 2020, declared a 30 day state of national emergency in light of the health and economic crisis caused by the outbreak of COVID-19. On May 6, 2020, the Government declared a state of emergency for an additional 30 days. For the rest of 2020, the National Government and local authorities implemented sectored lockdowns, and partial closures of commerce and not essential economic activities according to the number of new cases of infected population and hospital capacity. The Government also has implemented other economic and public health measures to address the crisis, including (i) border closure for all non-citizens and non-residents; (ii) short term and low interest loans for all types of agricultural producers; (iii) payroll subsidies for companies and credit lines for different sectors of the economy; (iv) incentivizing working from home and a mandatory work from home order for 80% of Government employees and (v) reduction in the prices of gasoline, among others. F-17 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) This situation has had a significant impact on the oil industry. Most specifically, travel bans imposed by several countries and established quarantine measures reduced demand levels for oil and its derivative products in 2020. Ecopetrol’s operations were affected by this situation and as a consequence, some plants in our refineries and some of our wells were temporarily closed due to low demand and prices and the measures taken to contain the spread of COVID-19 in workers and contractors. In this context, Ecopetrol took the following actions during 2020 to face the impacts of the pandemic:
These measures were aimed at ensuring the sustainability of the Ecopetrol Group’s business in an environment of low prices, prioritizing cash-generating opportunities with better equilibrium prices, maintaining growth dynamics with a focus on the execution of strategic asset development plans, and in asset value preservation through investments to gain reliability, integrity and continuity to the current operation in refineries, transportation systems and production fields. Similarly, these actions are covered by Ecopetrol’s risk management policies and procedures. (Note 30). In terms of Ecopetrol’s results of operations as of and for the year ended December 31, 2020, the most significant impacts were the following in: (i) a reduction in revenues (Note 25), especially due to the contraction in demand and a decrease in the international Brent price, partially offset with the higher exchange rate, (ii) an increase in financial costs due to an increase in debt (Note 29), a decrease in valuation to fair value and lower yields of the securities portfolio, which in turn were as a result of low market rates, (iii) recognition of impairment at the end of the year as described above (Note 18), and (iv) an increase in our depreciation expenses (Notes 14, 15, 16 and 17), partly generated by the update of the Ecopetrol’s reserve balance (Note 35). As a result of the measures taken, the constant monitoring of the COVID-19 pandemic, the ongoing vaccination programs and the evolution of the Ecopetrol Group’s results, while we cannot offer any assurances, as of the date of this annual report, Ecopetrol does not believe that the Covid-19 pandemic will have a significant impact on the Ecopetrol Group in the long-term. Nonetheless, the Ecopetrol Group will continue to monitor the evolution of the COVID-19 pandemic and the market to determine the need to implement subsequent stages of the COVID-19 intervention plan and will continuously review impairment indicators on long-lived assets and on investments in companies. F-18 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
For presentation purposes, the Group reclassifies some items in the comparative figures as of December 2019. This had no impact on the items in the statements of financial position, profit or loss, comprehensive income, changes in equity or cash flows.
The preparation of the consolidated financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts of assets, liabilities, sales revenues, costs and commitments recognized in the financial statements and the accompanying disclosures. The Ecopetrol Business Group based its assumptions and estimates on parameters available when these consolidated financial statements were prepared. Uncertainty about these assumptions and estimates could result in outcomes that required a material adjustment to the carrying amount of assets or liabilities affected in future periods. Changes in estimates are adjusted prospectively in the period in which the estimate is revised.
In the process of applying the Ecopetrol Business Group’s accounting policies, management has made the following judgments and estimates which have the most significant impact on the amounts recognized in the consolidated financial statements:
Hydrocarbon reserves are estimates of the amount of hydrocarbons that can be economically and legally extracted from the Ecopetrol Business Group’s oil and gas properties.
The reserves estimation is performed annually as of December 31 in accordance with the United States Securities and Exchange Commission (SEC) definitions and rules set forth in Rule 4–10(a) of SEC Regulation S–X and the disclosure guidelines contained in the SEC final rule – Modernization of Oil and Gas Reporting.
As required by current regulations, the future estimated date on which a field will no longer produce for economic reasons, is based on actual costs and average of crude prices (calculated as the arithmetical average of prices on the first day of the past 12 months). The estimated date for end of production will affect the amount of reserves, unless the prices have been defined by contractual agreements; therefore, if the prices and costs change from one year to the next, the proved reserves estimate also changes. Generally, our proved reserves decrease as prices go down and increase when prices go up.
Reserves estimation is an inherently complex process and it involves professional judgments. Reserves estimations are prepared using geological, technical and economic factors, including projections of future production rates, oil prices, engineering data and duration and amount of future investments, and they imply a certain degree of uncertainty. These estimations reflect the regulatory and market conditions existing on the date of reporting, which could significantly differ from other conditions during the year or in future periods. Any changes in regulatory and/or market conditions and assumptions could materially affect the reserves estimation.
Impact of oil reserves and natural gas in depreciation and depletion
Changes to estimations for proven developed reserves may affect the carrying amounts of exploration and production assets, natural resources and environment, goodwill, liabilities for dismantling and depreciation, depletion and amortization. With all other variables remaining unchanged, a decrease in estimated proven reserves would increase, prospectively, depreciation, depletion and amortization costs, while an increase in reserves would reduce depreciation and amortization expenses, as depreciation, depletion and amortization charges are calculated using the units of production method.
Information about the carrying amounts of exploration and production assets and the amounts charged to income, including depreciation, depletion and amortization, is presented in Notes
Management uses its professional judgment in assessing the existence of evidence of an impairment loss or reversal, based on internal and external factors.
F-19 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) When an indicator of impairment loss or reversal of
The assessments require the use of estimates and assumptions, such as, among other factors: (1) estimation of the volumes and market value of oil and natural gas reserves; (2) production profiles for oilfields and the future production of refined and petrochemical products; (3) investments, taxes and future costs; (4) useful life of assets; (5) long–term prices; (6) the discount rate, which is revised annually and determined as the weighted average cost of capital (WACC); and (7) changes in environmental regulation. The recoverable amount is compared to the carrying amount of the asset, thus determining whether the asset is impaired or if the impairment recognized in prior periods should be reversed.
A previously recognized impairment loss is reversed (except over the goodwill), only if there has been a change in the assumptions used to determine the assets or in the CGU’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of an asset or CGU, other than goodwill, does not exceed either its recoverable amount, or the carrying amount that would have been determined (net of amortization or depreciation) had no impairment loss been recognized for the asset or CGU in prior periods.
Future oil price assumptions are estimated at current market
These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may also impact the recoverable amount of assets and/or CGUs, hence, may also affect the recognition of an impairment loss or the reversal of prior period impairment amounts.
The application of the Ecopetrol Business Group’s accounting policy for exploration and evaluation costs requires judgment in order to determine whether future economic benefits are likely, either from future exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. Certain exploration and evaluation costs are initially capitalized when it is expected that commercially viable reserves will result. The Ecopetrol Business Group uses its professional judgment of future events and circumstances and makes estimates in order to annually assess the generation of future economic benefits for extracting oil resources, as well as technical and commercial analyses to confirm its intention of continuing their development. Changes regarding available information, such as drilling success level or changes in the project’s economics, production costs, and investment levels, as well as other factors, may result in capitalized exploration drilling costs being recognized in profit or loss for the period. The expenses for dry wells is included in operating activities in the consolidated statement of cash flows.
The allocation of assets in cash generating units requires significant judgment, as well as assessments regarding integration among assets, the existence of active markets, and similar exposure to market risk, shared infrastructure, and the way in which management monitors the operations. See Note 4.12 –
According to environmental and oil regulations, the Ecopetrol Business Group is required to bear the costs for the abandonment of oil extraction, refining plants and transportation facilities, which include the cost of plugging and abandoning wells, dismantling facilities, and environmental remediation in the affected areas.
Estimated abandonment and dismantling costs are recorded at the time of the installation of the assets and are reviewed annually. F-20 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The calculations for these estimations are complex and involve significant judgments by Management. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing, extent and amount of expenditure may also change, for example, in response to changes in internal cost projections, changes in reserve estimates, future inflation rates and discount rates. The Ecopetrol Business Group considers that the abandonment and dismantling costs are reasonable, based on the experience of the Ecopetrol Business Group and market conditions; nevertheless, significant variations in external factors used for the calculation of the estimation could significantly impact the amounts recorded in the financial statements. See Note 4.13 - Provisions and contingent liabilities (Obligation to withdraw assets).
The determination of expenses, liabilities and adjustments relating to pension plans and other defined retirement benefits makes it necessary for management to use its judgment in the application of actuarial assumptions made in the actuarial calculation. The actuarial assumptions include estimates regarding future mortality, retirement, changes in compensation and discount rate in order to reflect the time value of money, in addition to the rate of return on the plan’s assets. Due to the complexity in the valuation of these variables, as well as their long-term nature, the estimated amounts are quite sensitive to any change in these assumptions.
These assumptions are reviewed on an annual basis and may differ materially from actual results due to changes in economic and market conditions, regulatory changes, judicial rulings, higher or lower retirement rates, or longer or shorter life expectancies among employees.
In December of each year, the Ecopetrol Business Group performs an annual impairment test on goodwill to assess if its carrying amount may be impaired.
The determination of the recoverable amount is described in Note 4.12, and its calculation requires assumptions and estimates. The Ecopetrol Business Group considers that the assumptions and estimations used are reasonable and supportable based on the current market conditions and are aligned to the risk profile of the related assets. However, if different assumptions and estimations are used, they could lead to different results. Valuation models used to determine fair value are sensitive to changes in the underlying assumptions. For example, sales volumes and prices that will be paid for the purchase of raw materials are assumptions that may vary in the future. Adverse changes in any of these assumptions could lead to the recognition of goodwill impairment.
The Ecopetrol Business Group is subject to claims relating to regulatory and arbitration proceedings, tax assessments and other claims arising in the normal course of business. Management evaluates these claims based on their nature, the likelihood that they materialize and the amounts involved, to decide on the amounts recognized and/or disclosed in the financial statements.
This analysis, which may require considerable judgment, includes the assessment of current legal proceedings brought against the Ecopetrol Business Group and claims not yet initiated. A provision is recognized when the Ecopetrol Business Group has a present obligation derived from a past event, it is likely that an outflow of resources of economic benefits will be required to settle the obligation, and a reliable estimate of the amount of such obligation can be made.
Calculation of the income tax provision requires interpretation of tax law in the jurisdictions where the Ecopetrol Business Group operates. Significant judgment is required to determine estimates for income tax on taxable profits and to evaluate the recoverability of deferred tax assets, which are based on the ability to generate sufficient taxable income during the periods in which such deferred taxes could be used or deduct.
To the extent that future cash flows and taxable income differ significantly from the estimates, the Ecopetrol Business Group’s ability to realize the deferred tax assets recorded could be affected.
Furthermore, changes in tax rules could limit the capacity of the Ecopetrol Business Group to obtain tax deductions in future years, as well as the recognition of new tax liabilities resulting from auditing conducted by the tax authorities.
Tax positions taken involve a thorough assessment by Management, and are reviewed and adjusted in response to situations such as expiration in the applicability of laws, closing of tax audits, additional disclosures caused by any legal issue or a court decision relevant to a particular tax issue. The Ecopetrol Business Group records provisions based on estimated potential liabilities that could be derived from a tax audit. The amount of these provisions depends on factors such as previous experience in tax audits and different interpretations of tax legislation. The actual results may differ from the estimates recorded.
F-21 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The process of identifying hedging relationships between hedged items and the underlying instruments (derivative and non–derivative, such as long–term, foreign currency–denominated debt), and their corresponding effectiveness, requires the use of judgment by management. The Ecopetrol Business Group periodically monitors the alignment between its hedge instruments and its risk management policy. F-22 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The accounting policies indicated below have been applied consistently for all the periods presented.
A financial instrument is any contract that
The classification of financial instruments depends on the nature and purpose for which the financial assets or liabilities were acquired and is determined at the time of initial recognition. Financial assets and financial liabilities are initially measured at their fair value.
Transaction costs that are directly attributable to the acquisition or issue of financial assets and financial liabilities (other than financial assets and financial liabilities at fair value through profit or loss) are added to or deducted from the fair value of the financial assets or financial liabilities, as appropriate, on initial recognition. Transaction costs directly attributable to the acquisition of financial assets or financial liabilities at fair value through profit or loss are recognized immediately in profit or loss.
Measurements at fair value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in the principal market of the asset or liability or in the absence of a principal market in the most advantageous
The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest.
A fair value measurement of a non-financial asset takes into account a market participant's ability to generate economic benefits by using the asset
The Group uses valuation techniques that are appropriate
All assets and liabilities for which fair value is measured or disclosed in the financial statements are classified within the following scale, based on the lowest level input that is significant to the fair value measurement as a whole, as follows:
F-23 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Effective interest rate method
The effective interest rate method is a method of calculating the amortized cost of a financial instrument and accounting of income or financial cost over the relevant period. The effective interest rate is the discount rate that exactly discounts estimated future cash receipts or payments (including all fees, transaction costs and other premiums or discounts) through the expected life of the financial instrument (or, when appropriate, at a shorter period), to the net carrying amount on initial recognition.
Impairment
The Ecopetrol Business Group evaluates if there is objective evidence that a financial asset or group of financial assets are impaired. Financial assets are evaluated for the impairment indicators at the end of each reporting period. Financial assets are considered to be impaired when there is objective evidence that, as a result of one or more events that occurred after initial recognition, the estimated future cash flows of the asset have been affected. For financial assets measured at amortized cost, the amount of the impairment loss recognized is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the financial asset’s original effective interest rate.
Cash and cash equivalents include cash on hand, financial investments that are highly liquid, bank deposits and special funds with original maturity dates of ninety days or less which are subject to an insignificant risk of changes in value.
The classification of financial assets at initial recognition depends on the financial asset’s contractual cash flow characteristics and the Group’s business model for managing them. With the exception of trade receivables that do not contain a significant financing component or for which the Ecopetrol Business Group has applied the practical expedient, the Ecopetrol Business Group initially measures a financial asset at its fair value plus, and, in the case of a financial asset not at fair value through profit or loss, at transaction costs. Trade receivables that do not contain a significant financing component or for which the Ecopetrol Business Group has applied the practical expedient are measured at the transaction price determined under IFRS 15.
The Ecopetrol Business Group classifies its financial assets in the following categories:
Financial assets
These are equity instruments of other non–controlled and non–strategic companies not allowing for any type of control or significant influence thereon and where the Ecopetrol Business Group’s management does not intend to negotiate with them in the short term. These investments are recorded at their fair value and unrealized gains or losses are recognized in other comprehensive
This category is the most relevant to the Group. The Group’s financial assets at amortized cost includes trade receivables, other receivables, loans to associates, and loans to employees.
Loans and receivables are non–derivative financial assets with fixed or determinable payments that are not quoted in an active market. Loans and receivables, including trade and other receivables, are measured initially at fair value and then at amortized cost using the effective interest rate method, less impairment. F-24 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Loans to employees are initially recorded using the present value of the future cash flows, discounted at the current market rate for similar loans. If the interest rate is less than the current market rate, fair value will be less than the amount of the loan. This difference is recorded as a benefit to employees.
Financial assets at amortized cost are subsequently measured using the effective interest (EIR) method and are subject to
De–recognition of financial assets
The Ecopetrol Business Group derecognizes a financial asset only upon the expiration of the contractual rights to the cash flows of the asset or, when it has transferred its rights to receive such cash flows or has assumed the obligation to pay the cash flows received in full without material delay to a third party and (a) it has transferred substantially all the risks and benefits inherent in the ownership of the financial asset or (b) it has neither transferred nor retained substantially all the risks and benefits of the asset, but has transferred control of the asset.
When the Ecopetrol Business Group does neither transfer nor retain substantially all the risks and benefits of the asset or transfer control of the asset, the Ecopetrol Business Group continues to recognize the transferred asset, to the extent of its continuing participation, and it also recognizes the associated liability.
Financial liabilities correspond to the financing obtained by the Ecopetrol Business Group through bank credit facilities and bonds, accounts payable to suppliers and creditors.
Accounts payable to suppliers and creditors are short–term financial liabilities recorded at nominal value, since it does not significantly differ from fair value.
Derecognition
A financial liability is derecognized when the obligation specified in the contract is discharged,
Financial instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Changes in the fair value of derivatives are recognized as gains or losses in the statement of profit or loss, except for the effective portion of cash flow hedges, which is recognized in other comprehensive income and later reclassified to profit or loss when the hedge item affects profit or loss.
Changes in fair value of derivative contracts, which do not qualify or are not designated as hedges, including forward contracts for the purchase and sale of commodities under negotiation for physical delivery or receipt of the commodity are recorded in profit or loss.
F-25 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Derivatives embedded in the host contract are accounted for as separate derivatives at fair value if their economic characteristics and risks are not closely related to those of the host contracts and the host contracts are not held for trading or designated at fair value through profit or loss. These embedded derivatives are measured at fair value with changes in fair value recognized in profit or loss.
For purposes of hedge accounting, hedges are classified as:
At the inception of a hedge relationship, the Group formally designates and documents the hedge relationship to which it wishes to apply hedge accounting and the risk management objective and strategy for undertaking the hedge. Such hedges are expected to be highly effective in achieving offsetting changes in fair value or cash flows and are assessed on an ongoing basis to determine whether they have been highly effective throughout the financial reporting periods for which they were designated.
The effective portion of the gain or loss on the hedging instrument is recognized in Other Comprehensive Income (OCI) in the cash flow hedge reserve, while any ineffective portion is recognized immediately in the statement of profit or loss.
The amounts previously accumulated in OCI are
If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked or when the hedge no longer meets the criteria for hedge accounting, any cumulative gain or loss previously recognized in other comprehensive income remains separately in equity until the forecast transaction occurs is recognized in the consolidated statement of profit or loss. When it is no longer expected that the initially hedged transaction will occur.
Ecopetrol designates long–term loans as hedging instruments for its exposure to the exchange risk in future oil exports. See Note
Hedges of a net investment in a foreign operation, including a hedge of a monetary item that is accounted for as part of the net investment, are accounted for in a way similar to cash flow hedges.
Gains or losses on the hedging instrument relating to the effective portion of the hedge are recognized as OCI while any gains or losses relating to the ineffective portion are recognized in the statement of profit or loss. On the disposal of
Ecopetrol allocates long–term loans as hedging instruments for its exposure to foreign exchange risk on its investment in subsidiaries whose functional currency is the U.S. dollar. See Note
The gain or loss on the hedging instrument shall be recognized in profit or loss or other comprehensive income, if the hedging instrument hedges an equity instrument for which an entity has elected to present changes in fair value in other comprehensive income. The hedging gain or loss on the hedged item shall adjust the carrying amount of the hedged item (if applicable) and be recognized in profit or loss. If the hedged item is a financial asset (or a component thereof) that is measured at fair value through other comprehensive income, the hedging gain or loss on the hedged item shall be recognized in profit or loss. However, if the hedged item is an equity instrument for which an entity has elected to present changes in fair value in other comprehensive income, those amounts shall remain in other comprehensive income. F-26 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Inventories are stated at the lower of cost and net realizable value.
Inventories mainly comprise crude oil, fuels and petrochemicals and consumable inventories (spares and supplies).
The cost of crude oil is the production costs, including transportation costs.
The cost required to bring a pipeline into working order, is treated as part of the related pipeline.
The cost of other inventories is determined based on the weighted average cost method, which includes acquisition costs (deducting commercial discounts, rebates and other similar items), transformation, and other costs incurred to bring inventory to their current location and condition, such as transportation costs.
Consumable inventories (spares and supplies) are recognized as inventory and then charged to expense, maintenance or project to the extent that such items are consumed.
Ecopetrol estimates the net realizable value of inventories at the end of the period. When the circumstances that previously caused inventories to be written down below cost no longer exist, or when there is clear evidence of an increase in the net realizable value because of a change in economic circumstances, the amount of the
Related parties are considered those in which one party has the ability to control, or has joint control of the other, or exercises significant influence over the other party in making financial or operational decisions, or is a member of key management personnel (or close relative of a member). The Ecopetrol Business Group considers related parties to be associates, joint ventures, key management executives, entities managing resources for payment of employee post–employment benefit plans and Colombian government entities for the purposes of certain relevant transactions, such as the purchase of hydrocarbons and the fuel price stabilization fund (see Note
An associate is an entity over which the Ecopetrol Business Group has significant influence but not control. Significant influence is the power to participate in the financial and operational policy decisions of the investee, but it is not control or joint control over those policies. Generally, these entities are those in which the Ecopetrol Business Group holds an equity interest with voting rights of 20% to 50%. See Exhibit I –Consolidated companies, associates and joint ventures for further details.
Investments in associates are accounted for using the equity method. Under this method, the investment in an associate is initially recognized at cost. The carrying amount of the investment is adjusted to recognize changes in the Ecopetrol Business Group’s share of net assets of the associate since the acquisition date. Goodwill related to the associate is included in the carrying amount of the investment and it is not tested for impairment separately.
The Ecopetrol Business Group’s share of the results of operations of the associate is recognized in the consolidated statement of profit or loss. Any change in other comprehensive income is recognized in other comprehensive income of the Ecopetrol Business Group.
After application of the equity method, the Ecopetrol Business Group determines if it is necessary to recognize an impairment on its investment in its associate. The Ecopetrol Business Group determines whether there is objective evidence that the investment is impaired. If there is such evidence, the amount of the impairment is calculated as the difference between the recoverable amount and its carrying value, and then the impairment is recognized in the consolidated statement of profit or loss.
F-27 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) When necessary, the Ecopetrol Business Group makes adjustments to the accounting policies of associates to ensure consistency with the policies adopted by the Ecopetrol Business Group. Additionally, the equity method of these companies is measured on their most recent financial statements.
A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint arrangement. Joint control exists only when decisions about the relevant activities require unanimous consent of the parties sharing such control. The accounting treatment for the recognition of joint ventures is the same as investments in associates.
A joint operation is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets and obligations for the liabilities, relating to the arrangement.
Joint operation contracts are entered into between Ecopetrol and third parties to share risk, secure capital, maximize operating efficiency and optimize the recovery of reserves. In these joint operations, one party is designated as the operator to execute the operations and report to partners according to their participating interests. Likewise, each party takes its share of the produced hydrocarbons (crude oil or gas), according to their share in production.
When Ecopetrol participates as a non–operator partner, it
When the Ecopetrol Business Group acquires or increases its participation in a joint operation in which the activity constitutes a business combination, such transaction is
The excess of the sum of the consideration transferred and the amount paid in the operation is recognized as goodwill. If the result is in an excess value of the net assets acquired over the amount paid in the
Non–current assets are classified as held for sale if their carrying values will be recovered principally through a sale transaction rather than through continued use. Non–current assets are classified as held for sale only when the sale is highly probable within one year from the classification date and the asset (or group of assets) is available for immediate sale in its present condition. These assets are measured at the lower of their carrying amount and fair value less related costs of disposal.
Recognition and measurement
Property, plant and equipment are stated at cost less accumulated depreciation and accumulated impairment losses. Tangible components related to natural and environmental resources are part of property, plant and equipment.
The initial cost of an assets comprises its purchase price or construction cost, including import duties and non–refundable purchase taxes, any costs directly attributable to bringing the asset into operation, costs of employee benefits arising directly from the construction or acquisition, borrowing costs incurred that are attributable to the acquisition and construction of qualifying assets and the initial estimate of the costs of dismantling and abandonment of the item.
Spare parts and servicing equipment are recorded as inventories and recognized as an expense as they are used. Major spare parts and stand–by equipment that the entity expects to use during more than one period are recognized as property, plant and equipment. F-28 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Any gain or loss arising from the disposal of a property, plant and equipment is recognized in profit or loss of the period.
Subsequent disbursements
Subsequent disbursements correspond to all payments to be made on existing assets in order to increase or extend the initial expected useful life, increase productivity or productive efficiency, allow for significant reduction of operating costs, increase the level of reserves in exploration or production areas or replace a part or component of an asset that is considered critical for the operation.
The costs of repair, conservation and maintenance of a day to day nature are expensed as incurred. However, disbursements related to major maintenance are capitalized.
Depreciation
Property, plant and equipment is depreciated using the straight–line method, except for those associated with exploration and production activities which are depreciated using the units–of–production method. Technical useful lives are updated annually considering factors such as: additions or improvements (due to parts replacement or critical components for the asset’s operation), technological advances, obsolescence and other factors; the effect of this change is recognized from the period in which it was executed. Depreciation of an asset starts when it is ready to be used.
Useful lives are determined based on the period over which an asset is expected to be available for use, physical exhaustion, technical or commercial obsolescence and legal limits or restrictions over the use of the asset.
The estimated useful life of assets fluctuates in the following ranges:
Depreciation methods and useful lives are reviewed annually and adjusted if appropriate.
Recognition and measurement
Ecopetrol uses the successful efforts method to account for exploration and production of crude oil and gas activities, following the provisions of IFRS 6 – Exploration for the evaluation of mineral resources. Exploration costs
Acquisition and exploration costs are recorded as exploration and evaluation assets until the determination of whether the exploration drilling is successful or not; if determined to be unsuccessful, all costs incurred are recognized as expenses in the
Exploration costs are those incurred with the objective of identifying areas that are considered to have prospects of containing oil and gas reserves, including geological and geophysical, seismic costs, viability, and others, which are recognized as expenses when incurred. Furthermore, disbursements associated with the drilling of exploratory wells and those related to stratigraphic wells of an exploratory nature are charged as assets until it is determined if they are commercially viable; otherwise, they are expensed in the consolidated statement of profit or loss as dry wells expense. Other expenditures are recognized as expenses when incurred.
An exploration and evaluation asset is no longer classified as such when the technical feasibility and commercial viability of extracting a mineral resource are demonstrable. Exploration and evaluation assets are reclassified to the natural and environmental resources account after being assessed for impairment.
F-29 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) All capitalized costs are subjected to technical and commercial revisions at least once a year to confirm the evaluation and exploration efforts continue on the fields; otherwise, these costs are written off through to profit or loss.
Exploration costs are net of the revenues obtained from the sale of crude oil during the extensive testing period, net of cost of sales, since they are considered necessary to complete the asset. Development costs
Development costs correspond to those costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing. When a project is approved for development, the corresponding capitalized acquisition and exploration costs are classified as natural and environmental resources and costs subsequent to the exploration phase are capitalized as development costs of the properties that contain such natural resources. All development costs are capitalized, including drilling costs of unsuccessful development wells.
Production costs
Production costs are those incurred to operate and maintain productive wells, and are part of the corresponding equipment and facilities. Production activity includes extraction of oil and gas to the surface, its gathering, treatment and processing as well as storage in the field. Production costs are expenses recorded in the consolidated statement of profit or loss as incurred unless they add oil and gas reserves, in which case they are capitalized.
Production and support equipment is recognized at cost and is part of property, plant and equipment subject to depreciation.
Capitalized costs also include decommissioning, dismantling, retiring and restoration costs, as well as the estimated cost of future environmental obligations. The estimation includes plugging and abandonment costs, facility dismantling and environmental recovery of areas and wells. Changes arising in new abandonment liability estimations and environmental remediation are capitalized in the carrying amount of the related asset.
Depletion
Depletion of natural and environmental resources is determined using the unit–of–production method per field, using proved developed reserves as a base, except in limited exceptional cases that require greater judgment by Management to determine a better amortization factor of future economic benefits over the useful life of the asset.
Reserves are independently estimated by internationally recognized external consultants and approved by Ecopetrol’s Board of Directors. Proved reserves consist of the estimated quantities of crude oil and natural gas demonstrated with reasonable certainty by geological and engineering data to be recoverable in future years from known reserves under existing economic and operating conditions, that is, at the prices and costs that apply at the date of the estimation.
Impairment
Assets associated to exploration, evaluation and production are subject to review for possible impairment in their carrying amount. See Notes 3.2 —
Borrowing costs related to the acquisition, construction or production of a qualifying asset that requires a substantial period of time to get ready for its intended use are capitalized as part of the cost of such asset when it is probable that future economic benefits associated with the item will flow to the Ecopetrol Business Group and costs can be measured reliably. Other borrowing costs are recognized as finance costs. Projects that have been suspended but that the Ecopetrol Business Group intends to continue to pursue their development in the future, are not considered qualifying assets for the purpose of capitalization of borrowing costs.
F-30 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Intangible assets with a defined useful life, are stated at cost less accumulated amortization and any impairment loss. Intangible assets are amortized under the straight–line method, over their estimated useful lives. The estimated useful lives and amortization method are revised at the end of each reporting period; any change in estimates is recognized on a prospective basis.
The disbursements
The Group recognizes business combinations using the acquisition method. Identifiable assets acquired and liabilities assumed are initially measured at fair value on the acquisition date, subject to certain exceptions. On the acquisition date, the acquirer will separately recognize the identifiable assets acquired, the liabilities assumed, any non-controlling interest in the acquiree, and any goodwill or bargain purchase resulting from the acquisition. The company that acted as buyer will recognize the goodwill generated as an asset on the acquisition date, measured as the difference between (i) the aggregate of the consideration transferred, the amount of any non-controlling interest and in a business combination achieved in stages the acquisition-date fair value of the acquirer’s previously held equity interest in the acquiree and (ii) the net amount on the acquisition date of the identifiable assets acquired and the liabilities assumed.
Goodwill is initially measured at cost (being the excess of the aggregate of the consideration transferred and the amount recognized for non–controlling interest and any previous interest held over the net identifiable assets acquired and liabilities assumed). After initial recognition goodwill is measured at cost less any accumulated impairment The acquirer will identify the acquisition date as the date on which control of the acquiree is obtained. The measurement period is the period after the acquisition date during which the acquirer can adjust the provisional amounts recognized in a business combination. The measurement period cannot exceed one year from the acquisition date. During 2019 and 2020 the Group recognized transactions as business combinations (Note 12).
As of January 1, 2019, the Ecopetrol Business Group adopted IFRS 16, “Leases” (“IFRS 16”) applying the modified retrospective scope. At the beginning of a contract, the Business Group assesses whether a contract is, or contains, a lease. This situation arises if the contract transfers the right to control the use of an identified asset for a period of time in exchange for a consideration. To assess whether a contract conveys the right to control an identified asset, the regulations of IFRS 16 are used. Ecopetrol Business Group as a lessee On the commencement date of the lease, Ecopetrol Business Group recognizes lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying asset during the lease term. The interest expense on the lease liability and the depreciation expense on the right-of-use asset are recognised separately. In subsequent recognition, Ecopetrol business Group makes a remeasurement of the lease obligation upon the occurrence of events such as: a) changes in the lease term, b) changes in future lease payments resulting from variations in an index or in the rate used for determine the payments. The amount of the remeasurement of the obligation will be recognized as an adjustment to the asset for the right of use. F-31 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Ecopetrol Business Group as a lessor
Leases
Right-of-use assets The Ecopetrol Business Group recognizes right-of-use assets on the commencement date of the Lease liabilities At the commencement date of the lease, the Ecopetrol Business Group recognizes lease liabilities measured at the present value of the
In order to calculate the present value of the lease payments, the Ecopetrol Business Group uses the incremental borrowing rate on the lease’s commencement date. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments or a change in the assessment of an option to purchase the underlying asset. Short-term leases and low-value asset leases The Ecopetrol Business Group elected to use the recognition exemptions for lease contracts that, at the commencement date, have a lease term of 12 months or less and do not contain a purchase option (short-term leases), and lease contracts for which the underlying asset is of low value (low-value assets). Joint Operating Agreements (JOA) In JOA agreements, the Ecopetrol Business Group assesses whether it controls the use of the asset. If the Ecopetrol Business Group, as the operator, controls the use of the asset, it recognizes the entire right-of-use and lease liability in the consolidated financial statements. If it is the JOA who controls, it is analyzed whether the contract meets the characteristics of a sublease, and in that case each party must recognize the right of use in proportion to their participation.
In order to evaluate if any tangible or intangible assets are impaired, Ecopetrol compares its carrying amount with its recoverable amount at the end of each reporting period or earlier, if there is any indicator that an asset may be impaired.
For purposes of impairment testing,
F-32 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) The recoverable amount of
Fair value less costs of disposal is usually higher than the value in use for the asset’s in the production segment due to some significant restrictions in the estimation of future cash flows, such as: a) future capital expenses that improve the CGU performance, which could result in expected increase of net cash flows, and b) items before taxes that reflect specific business risks, resulting in a higher discount rate.
Fair value less costs of disposal is determined as the sum of the future discounted cash flows adjusted to the estimated risk. The estimations of expected future cash flows used in the assessment of impairment of the assets include estimates of futures commodity prices, supply and demand estimations, and the margins of the products.
Fair value less costs of disposal, as described above, is compared to valuation multiples and quoted prices of shares in companies comparable to Ecopetrol, in order to determine if it is reasonable.
When an impairment loss is recorded, future amortization expenses are calculated on the basis of the adjusted recoverable amount. Impairment losses may be recovered only if the
The carrying amount of non–current assets reclassified as assets held–for–sale is compared to its fair value less costs of disposal. No other provision for depreciation, depletion or amortization is recorded if the fair value less costs of sale is lower than the carrying amount.
Provisions are recognized when the Ecopetrol Business Group has a current obligation (legal or constructive) as a result of a past event, it is probable that Ecopetrol will be required to settle the obligation, and a reliable estimation can be made of the amount of the obligation. Where applicable, they are recorded at present value, using a rate reflecting the risk specific to the liability.
Future environmental decommissioning costs related to current or future operations, are accounted for as expenses or assets, as the case may be. Expenditures related to past operations that do not contribute to the obtaining of current or future benefits, are expensed as incurred.
The recognition of these provisions coincides with the identification of an obligation related to environmental remediation and Ecopetrol uses available information to determine a reasonable estimation of the related cost.
Provisions for which a negative outcome is assessed as possible are not recognized but are disclosed in the explanatory notes; including those for which the amount cannot be estimated.
If there is an expectation that the provision will be reimbursed, either in whole or in part, for example by virtue of an insurance contract, the amounts expected to be reimbursed are recognized as a separate asset only when such reimbursement is almost certain.
If the effect of the time value of money is significant, the provisions are discounted using the current market rate before taxes reflecting, as applicable, the liability specific risks. When recognizing the discount, the increase of the provision resulting from time elapsed is recognized as financial cost in the profit or loss statement.
Asset retirement obligation
Liabilities associated with the retirement of assets are recognized when there are current obligations, either legal or constructive, related to the abandonment and dismantling of wells, facilities, pipelines, buildings and equipment.
The obligation is usually recorded when the assets are installed or when the surface or the environment are altered at the operating sites. These liabilities are calculated using the discounted cash flow method, using a pre–tax rate reflecting current market conditions similar liabilities and considering the economic limits of the field or the useful life of the respective asset. When it is not possible to determine a reliable estimation in the period in which the obligation originates, a provision is recognized when there is enough information available to make the best estimation.
F-33 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) The carrying amount of the provision is reviewed and adjusted annually considering changes in the assumptions used for its estimation, using a risk-free rate adjusted by a premium that reflects the risk
Income tax expense is comprised of income tax payable for the period
Current income taxes are recognized in income except when they relate to items recognized in other comprehensive income, in which case the corresponding tax effect is also recognized in other comprehensive income. Income tax assets and liabilities are presented separately in the consolidated statement of financial position, except where there is a right of setoff within fiscal jurisdictions and an intention to settle such balances on a net basis.
Income tax is paid by each legal entity and not on a consolidated basis.
The Ecopetrol Business Group determines the provision for income tax based on the highest amount between taxable income and presumptive income (the minimum estimated amount of taxable profit on which the law expects to quantify and collect income taxes). Taxable income differs from profit before tax as reported in the consolidated statement of profit or loss, because of: items of income or expense that are taxable or deductible in other periods, special taxable deductions, tax losses and income and line items measured that, according to applicable tax laws in each jurisdiction, are considered nontaxable or nondeductible.
Deferred tax is provided using the liability method for temporary differences between the carrying amounts of existing assets and liabilities in the consolidated financial statements and their respective tax bases. A deferred tax liability is recognized for all taxable temporary differences. A deferred tax asset is recognized for all deductible temporary differences and for all accumulated tax losses, if there is a reasonable expectation that the Ecopetrol Business Group will generate future tax profits against which they will be used.
Deferred taxes on assets and liabilities are calculated based on the tax rates that are expected to apply during the years in which temporary differences between the carrying amounts and tax bases are expected to be reversed.
The carrying amount of a deferred tax asset is subject to review at the end of each reporting period, and it is reduced to the extent it is no longer probable that the corresponding legal entity will generate enough future taxable profit to realize such deferred tax asset.
In the statement of financial position, deferred tax assets are reflected net and as an offset against deferred tax liabilities, depending on the overall tax position in a particular jurisdiction and on the same taxable entity.
Deferred taxes are not recognized when they arise in the initial recognition of an asset or liability in a transaction (except in a business combination) and at the time of the transaction, do not affect the accounting or tax profit, or in respect of the taxes on the possible future distribution of accumulated profits of subsidiaries or investments accounted for by the equity method, if at the time of the distribution it may be controlled by Ecopetrol and it is probable that the retained earnings will be reinvested by the Ecopetrol Business Group companies and, therefore, will not be distributed to
The Ecopetrol Business Group recognizes in profit or loss the costs and expenses related to other taxes than the income tax, such as the wealth tax, which is determined based on the tax equity, the industry and commerce tax on income obtained in the municipalities for performance of commercial, industrial and service activities, and the transport tax on volumes loaded in the transport systems. Taxes are calculated in accordance with current tax regulations. For more details, see Note 10.
F-34 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Salaries and benefits
Ecopetrol belonged to the special pension regime under which pension liabilities are Ecopetrol’s responsibility and not pension fund’s responsibility. However, Law 797 of January 29, 2003 and Legislative Act 001 of 2005 determined that Ecopetrol will no longer belong to the said regime and that from that point on employees would be part of the General Pension Regime. Consequently, pension obligations related to employees pensioned until July 31, 2010 are still Ecopetrol’s responsibility. Employees are entitled to such pension bonus if they worked with Ecopetrol prior to January 29, 2003, but whose labor agreement expired without renewal before that date.
All labor benefits of employees who joined Ecopetrol before 1990 are Ecopetrol’s responsibility, without the involvement of any social security entity or institution. Service cost for the employee and his/her relatives registered with Ecopetrol is determined by means of a mortality table, prepared based on facts occurring during the year.
For employees who joined Ecopetrol after the Act 50 of 1990 went in effect, Ecopetrol makes periodic contributions for severance payments, pensions and labor risks to the respective funds.
In 2008, Ecopetrol partially settled the value corresponding to monthly pension payments from its pension liabilities, transferring such liabilities and their underlying amounts to autonomous pension funds (PAP, for its acronym in Spanish). The funds transferred, and returns on those funds, cannot be redirected, nor can they be returned to the Ecopetrol Business Group, until all of the pension obligations have been fulfilled. The settled obligation covers allowances and pension bonds
Employee benefits are divided into four groups comprised as follows:
Benefits to employees in the short term mainly correspond to those which payment will be made in the term of twelve months following the closing of the period in which the employees have rendered their services. These mainly include salaries, severance payments, vacation, bonuses and other benefits.
Post–employment benefits of defined contributions plans correspond to the periodic payments for severance, pensions and labor risk payments that the Ecopetrol Business Group makes to the respective funds that assume these obligations in their entirety.
The above benefits are recognized as an expense with an associated liability after deducting any already paid amounts.
In the defined benefits plan, the Ecopetrol Business Group provides the benefits agreed to current and former employees and assumes the actuarial and investment risks.
The following benefits are classified as long–term defined benefit plans recognized in the financial statements according to the calculations of an independent actuary:
F-35 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Liabilities recognized in the statement of financial position with respect to these benefit plans are determined
The defined benefit obligation is calculated annually by independent actuaries using the projected credit unit method, which takes into account employees’ years of service and, for pensions, average or final pensionable remuneration. This obligation is discounted at its present value using interest rates of high–quality government bonds denominated in the currency in which the benefits will be paid and of a duration consistent with the plan obligations.
These actuarial calculations involve several assumptions that could differ from the events that will effectively take place in the future. Said assumptions include the determination of a discount rate, future salary increases, mortality rates and future pension increases. Because of the complexity of the calculation, the underlying assumptions and long–term nature of these plans, the obligations for defined benefits are extremely sensitive to changes in assumptions. All key assumptions are revised at the end of the reported period.
In determining the appropriate discount rate, in absence of a broad high quality bond market, Management considers interest rates corresponding to the class B TES bonds issued by the Colombian Government as its best reference, at an appropriate discount rate with maturities extrapolated in line with the term expected for each benefit plan. The mortality rate is based on the particular country’s rate, the latest version of which is the RV08 mortality table published in resolution 1555 of October 2010. The future salary and pension increases are linked to the country’s future inflation rates. Note 22 –Provisions for employee benefits provides further details on key assumptions used.
The amounts recognized in the consolidated statement of profit or loss related to employees defined benefit plans are comprised mainly by service cost and the net financial expense. Service cost includes mainly the increase in present value of the benefit obligation during the period (current service cost) and the amount resulting from a new benefit plan. Plan amendments corresponds to changes in benefits and are usually recognized when all legal and regulatory approvals have been obtained and the effects have been conveyed to the employees involved. The net financial expense is calculated using the net liability for defined benefits as compared with the yield curve of the discount rate at the beginning of each year for each plan. The net defined benefit obligation or asset resulting from actuarial profits and losses, the asset ceiling effect and the asset profitability, excluding the value of recognized in the consolidated statement of profit or loss, are recognized in other comprehensive income.
When the plan assets exceed the gross obligation, the recognized asset is limited to the lower of the surplus in the defined benefits plan and the ceiling of assets determined using a discount rate based on Colombian Government bonds.
Others long–term benefits include the five–year term bonus which also considered in the actuarial calculation. This benefit is a cash bond that accumulates annually and is paid every five years to employees. The Ecopetrol Business Group recognizes in the consolidated statement of profit or loss the service cost, the net financial cost and the adjustment to the obligation of the defined benefit plan.
Termination benefits are recognized only when a detailed plan exists and there is no possibility to withdraw the offer. The Ecopetrol Business Group recognizes a liability and an expense for termination benefits at the earliest date between the date when the offer of such benefits cannot be withdrawn and the date when the restructuring costs are recognized.
The Ecopetrol Business Group’s business is based on three principal sources of revenue from
Sales of crude oil and natural gas
Revenue from sales of crude oil and natural gas is recognized upon transfer of control to the F-36 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
For some natural gas supply contracts with a replacement period, a distinction is made between quantities of gas consumed and not consumed in order to recognize the respective revenue or liability relating to quantities that will be requested in the future. Once the customer claims such natural gas, the revenue is recognized.
Services associated with hydrocarbons transport
Revenue from hydrocarbons transport services is recognized when the service is provided to the customer and there are no contractual conditions that prevent recognition of the revenue. Ecopetrol Business Group companies
Ship/ Take-or-Pay contracts for the sale of refined products, storage and transport specify minimum quantities of products or services for which a customer will pay, even if the latter does not receive them or use them (“deficient quantities”). Although the Ecopetrol Business Group expects customers to recover all deficient quantities to which they are contractually entitled, any load revenue received related to temporary shortfalls that will be offset in a future period will be deferred and that amount recognized as revenue in the event any of the following scenarios occurs:
a)The customer exercises its right to deficient volumes or services, or
b)
Refined products and biofuels
In the case of refined products
In other cases the, Ecopetrol Business Group
Under current local regulation, Ecopetrol sells regular gasoline and ACPM in Colombia at a regulated price.
In accordance with Decree 1068 of 2015, the Ministry of Mines and Energy semiannually calculates
According to the risk profiles, the Ecopetrol Business Group manages advance payment systems for some of its
Significant financing component
Generally payments received from customers are short term. Using the practical expedient in IFRS 15, the Group does not adjust the promised amount of consideration for the effects of a significant financing component if it expects, at contract inception, that the period between the transfer of the promised good or service to the customer and
Variable considerations
Upon fulfillment of the obligations set forth in agreements with customers, via delivery of the product or provision of the service, variable components of the transaction price may exist, such as the exchange rate for crude exports or international price fluctuations. In these cases, the Ecopetrol Business Group will make its best estimate of the transaction price that reflects the goods and services transferred to customers.
Agreements signed with customers do not include variable considerations F-37 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Non-cash considerations
Agreements signed in the Ecopetrol Business Group does not consider non-cash transactions.
Customer advances
These correspond to contractual obligations in which the Ecopetrol Business Group receives advances from customers. These advances by customers form part of the policies and risk assessment defined by the Business Group.
Costs and expenses are presented according to their nature; they are detailed in the related disclosures in cost of sales, and administrative, operating, projects and other associated expenses.
Finance income and expenses include mainly: a) borrowings costs on loans and financing, except for those that are capitalized on qualifying asset, b) gains and losses on changes in fair value of financial instruments measured at fair value through profit or loss, c) currency exchange differences of financial assets and liabilities, except for debt instruments designated as hedging instruments, d) interest expenses as a result of discounting long–term liabilities (abandonment costs and pension liabilities), e) dividends derived from equity instruments measured at fair value with changes in other comprehensive income.
Ecopetrol presents the information related to its business segments in its consolidated financial statements in accordance with paragraph 4 of IFRS 8 – Operation segments.
The operations of the Ecopetrol Business Group are performed through three business segments: 1) Exploration and Production, 2) Transport and Logistics and 3) Refining, Petrochemical and Biofuels. Segments are determined based on management objectives and corporate strategic plans, considering that these businesses: (a) are engaged in different commercial activities, which generate sales revenue and incur costs and expenses; (b) the operational results are revised regularly by the Ecopetrol Business Group’s Governance that makes operational decisions to allocate resources to the various segments and assess their performance; and (c) there is differentiated financial information available. Internal transfers represent sales to inter–company segments and are recorded and presented at market prices.
See information by segments in Note
F-38
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Ecopetrol applied certain standards and amendments which were effective for annual periods beginning on or after January 1, 2020. Ecopetrol has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective.
These modifications have no impact on the consolidated financial statements, as there is currently no interest rate coverage.
These modifications have not had any impact on the consolidated financial statements.
These modifications have not had an impact on the consolidated financial statements.
This amendment was not applied given that the number of contracts that would be within its scope is reduced and – evaluating its impact at the business group level – it is not material. Consequently, each company will guarantee that the changes in the lease contracts under IFRS 16 F-39 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
5.2 New standards issued by the IASB that will enter into force in future periods The new amended standards and interpretations that are issued, but not yet effective, up to the date of issuance of the Group’s financial statements are disclosed below. Ecopetrol intends to adopt these new and amended standards and interpretations, if applicable, when they become effective. Effective January 1, 2021:
Within the accounting Effective as of January 1, 2022 with early adoption in 2021:
The amendment is effective for annual reporting periods beginning on or after 1 January 2022 and must be applied retrospectively to items of property, plant and equipment made available for use on or after the beginning of the earliest period presented when the entity first applies the amendment. Ecopetrol will apply the amendment with early adoption in 2021 subject to
Entry into force as of January 1, 2022 or later periods:
The Company constantly monitors the
F-40 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of
As of December 31,
The fair value of cash and cash equivalents approximates their book value due to their short–term nature.
The return on cash and cash equivalents for the
The following table reflects the credit quality of issuers of investments included in cash and cash equivalents:
See credit risk policy in Note F-41 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The The changes in the allowance for doubtful accounts for the year ended December 31, 2020, 2019 and 2018
F-42
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following are the changes of the allowances for losses for the years ended December 31, 2020, 2019 and 2018:
Crude oil, fuel and petrochemicals inventories are adjusted to the lowest between the cost and the net realizable value, as a result of fluctuations in international crude oil prices. The
The average return of the investment portfolio in Colombian pesos and U.S. dollars
Changes in fair value are recognized in financial results (Note
As of December 31,
F-43 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following is the balance of other financial assets by fair value hierarchy level as of December 31,
There were no transfers between hierarchy levels for the years ended December 31,
The securities comprising
For U.S. dollar–denominated investments, fair value is based on information released by Bloomberg, while for investments denominated in Colombian pesos, fair value is provided by
Within the investment valuation hierarchy process, other relevant aspects are taken into account, such as the issuer’s rating, investment rating and the risk analysis of the issuer performed by the Ecopetrol Business Group.
The following table reflects the credit quality of the issuers of other financial assets measured at fair value through profit or loss:
See credit risk policy in Note
F-44
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-45
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
In accordance with Law 2010/2019 (Tax Reform) the tax provisions applicable to individual companies in Colombia for the taxable year 2020 are the following:
Statute of limitations
With respect to tax returns where tax losses are calculated, the statute of limitations will be 12 years and if the losses are carried forward within the last 2 years of the 12–year period, the statute of limitations will be extended up to 3 additional years from the year of
F-46
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Income
Reconciliation of the income tax expenses The reconciliation between the income tax expense and the current tax applicable to the Ecopetrol Business Group in Colombia is as follows:
F-47 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Deferred income tax
The detail of
F-48 Ecopetrol Notes to the (Figures expressed in millions of Colombian pesos, unless otherwise stated) Deferred tax
Deferred tax
Deferred tax assets
Deferred tax assets
Additionally, as of
F-49
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Ecopetrol Business Group recognizes deferred tax assets to the extent that it is probable that they will be realized against available sources of income, including projections of future taxable income. In accordance to the tax rules regulation applicable until December 31, 2016, excess of presumptive income and excess minimum base excesses before 2017 incurred in the income tax and income tax for equity equality - (CREE, as its acronym in Spanish) respectively, may be offset with the ordinary taxable income in the following five (5) years, using for this purpose, the formula established in numeral 6th, of Article 290 of Law 1819/2016. The tax loss carryforwards of Ecopetrol USA generated between 2008 and 2017, expire in 20 years from the year in which they were incurred. The tax loss carryforwards generated starting January 1, 2018 have no expiration date and its use is limited to 80% of taxable income. The movements of deferred income tax for the years
Deferred tax assets not recognized Deferred tax assets related to the tax loss carryforwards incurred by the subsidiaries Andean Chemicals Ltd and Ecopetrol Costa Afuera S.A.S. in the amount of COP$1,912 and COP$71,305, respectively, excess of presumptive income of Hocol Petroleum Company, and Reficar in the amount of COP$245,508, were not recognized, as the Management considered that it is not probable that these deferred tax assets will be recoverable in the foreseeable future. If the Ecopetrol Business Group had recognized this deferred tax asset, the profit for the year ending December 31, 2020 would have increased by COP$247,420. F-50 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Deferred tax assets (liabilities) not recognized
As of December 31, Income tax provisions and contingent liabilities The income tax returns for taxable years 2011, 2012, 2014, 2015, 2016, 2017, 2018 and 2019 and CREE tax returns for taxable years 2014, 2015, and 2016 of Group companies are subject to acceptance and review by part of the tax authorities. The management of the Group companies considers that the amounts recorded as tax liabilities are sufficient and are supported by current regulations, doctrine and jurisprudence to address any claim that may be established with respect to such years. Uncertain tax positions - IFRIC 23 Ecopetrol Business Group’s strategy is to avoid making aggressive tax decisions that may cause questioning of its tax returns, by tax authorities. Regarding uncertain tax positions where it has been determined that there may be a possible controversy with the tax authority that could result in an income tax increase, a success threshold has been established by IFRIC 23, which has been calculated based on current regulations and tax opinion provided by our tax advisors. In accordance with the aforementioned interpretation, the Ecopetrol Business Group
Dividends related to profits generated from the year ended December 31,
The non-taxed dividends that the Company will receive will not be subject to withholding tax due to the express provision of the regulation that establishes the dividends that are distributed within the business groups duly registered with the Chamber of Commerce and decentralized
According to the Colombian tax law, income taxpayers who enter into transactions with related parties or related parties located in foreign jurisdictions and in free trade zones or with residents located in jurisdictions considered tax havens, are obliged to determine their ordinary and extraordinary income for purposes of the income
Ecopetrol
For fiscal year
F-51
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Law 2010/2019 established that VAT paid on the import, creation, construction or acquisition of real productive fixed assets, may be treated as a tax credit for income tax purposes. This VAT cannot be assumed simultaneously as a cost or expense in the income tax and is not allowed to be discounted from the VAT return.
The Government issued the Law
The presumptive income tax rate (i.e., an alternative tax based on a percentage of the net equity of the last year) is reduced from
The thin capitalization rule ratio is modified from 3:1 (which includes all debt that generates interest with local and foreign entities, related or unrelated) to a 2:1 ratio that only considers debt transactions involving related local and foreign parties (including back-to-back transactions involving foreign third parties).
Normalization tax
The Tax Reform establishes a tax amnesty to “normalize” (i) unreported assets; or (ii) nonexistent liabilities that were included on a tax return. The amnesty will apply only for
Value Added Tax Law 2010 of 2019 established that VAT paid on the import, construction or acquisition of real productive fixed assets may be deducted from taxable income. This VAT cannot be reported simultaneously as a cost and expense in the income tax return nor will it be discounted from the sales tax.
Concerning VAT, changes have been made to the list of goods and services excluded from VAT as set forth in Articles 424, 426 and 476 of the Tax Code, adding Article 437 to the Tax Code, with regard to guidelines on compliance with formal duties concerning VAT by service providers abroad, and it has been noted that VAT withholding may be up to 50% of the tax amount, subject to regulation by the National Government. The VAT rate remains at 19%.
Tax
With regards to procedure, changes have been made: (i)
Additionally, an audit benefit was included for fiscal years
F-52
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The above benefit does not apply to: (i) taxpayers who have access to tax benefits due to their location in a specified geographic region; (ii) if it is demonstrated that the withholding taxes reported are non-existent; (iii) if the net income tax is less than 71 UVT (COP$2,5 for fiscal year 2020). The reduced status of limitation stated is not applicable for withholding tax returns and VAT retuns, which shall follow the general tax rules.
F-53 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
12.1 Additional interest in Invercolsa On November 29, 2019, Ecopetrol acquired an additional interest of 8.53% in Invercolsa (See Note 2.2 Basis of consolidation) obtaining control of Invercolsa and resulting in a total ownership interest of 51.88%. In 2020 Ecopetrol finalized the fair value of separately identified assets and liabilities acquired, that resulted in an adjustment of COP$434,357 from Property, Plant and Equipment and Natural Resources to Goodwill (Note 19). 12.2 Guajira association contract On November 22, 2019, Hocol S.A. – a 100% subsidiary of Ecopetrol Corporate Group – signed a Purchase Agreement and Sale of Assets with “Chevron” in order to acquire the entire stake owned by the latter in the Guajira Association (43% of the association contract) and its position as operator. The remaining 57% stake in this association belongs to Ecopetrol S.A. The transaction was subject to the approval of the Superintendence of Industry and Commerce (SIC), which was made official on April 2, 2020, through resolution 12785/2020. As established in the agreement, the start of the operation by Hocol would be the first business day of the month following the date of this approval, i.e. May 1, 2020. Therefore, this is the acquisition date for accounting recognition purposes. The transaction price was determined based on a fixed reference value as of January 1, 2019 plus or minus price adjustments that relied directly on variables associated with the Guajira asset between January 1, 2019 and May 1, 2020. The clauses of the purchase agreement indicate that there is a 180-day term to finish adjusting the differences arising from the movement on the assets acquired and the liabilities assumed. During the review and approval process to determine the final price, Chevron and Hocol signed an agreement to extend the deadline for the closing of the transaction, which is expected to end during the first half of 2021. These deadlines are in regulatory compliance. Ecopetrol and Hocol measured the assets acquired and the liabilities assumed in proportion to their participation in accordance with the provisions of IFRS 11 - Joint agreements and IFRS 3 - Business combinations. For Ecopetrol, this transaction is configured as an acquisition in stages. Fair value was determined using the income approach applying the discounted cash flow methodology. The fair values of property, plant and equipment, natural and environmental resources and deferred tax have been determined based on the information available and following the guidelines of IFRS 3. Therefore, they may have adjustments associated with working capital, in compliance with the clauses of the purchase agreement and the guidelines defined in IFRS 3. The table below summarizes the amounts recognized for the assets acquired and the liabilities assumed at the acquisition date:
F-54 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) The effect on operating results as of December 31, 2020 is summarized below:
Costs related to the acquisition of $19,898 million were excluded from the pre-existing participation and were recognized as operating expenses in the period. Effects on the Ecopetrol Group's results Ecopetrol Group's income includes COP$238,955 related to the acquisition of the Guajira association, while the profit for the year increased by COP$161,423. If this business combination took place on January 1, 2020, the Group's income would have an amount of COP$50,308,407, while the profit for the year would be COP$2,766,398. Management considers that these figures represent an approximate measure of the performance on an annualized basis and provide a benchmark for comparison for future periods. In determining the Group's anticipated income and profits, if the Guajira association had been acquired at the beginning of the current reporting period, management would have calculated the depreciation of property, plant and equipment and natural resources acquired on the basis of its fair value in the initial recognition for the business combination instead of the carrying amounts recognized in the financial statements prior to the acquisition. F-55 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The details on the participations, economic activity, address, area of operations and financial information of the investments in joint ventures and associates can be found in Exhibit 1.
The following is the movement of investments in associates and joint ventures: For the year ended December 31, 2020:
F-56 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
For the year ended December 31, 2018:
The following is the breakdown of assets, liabilities and results of the two main investments in associates and joint ventures, Equion
F-57 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
This is a reconciliation of equity of the significant investments and the carrying amount of investments as of December 31:
F-58 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-59
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-60 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-61
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-62 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Accounting for suspended exploratory wells
The following table shows the classification by age, from the completion date, of the exploratory wells that are suspended as of December 31,
F-63
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following is the movement of right-of-use assets for the years ended December 31, 2020 and 2019:
The following is the movement of intangibles and their amortization and impairment for the years ended December 31, 2020 and 2019:
F-64 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
As mentioned in Note 4.12, each year the Ecopetrol Business Group assesses whether there is an indication that an asset or cash–generating unit may be impaired or if impairment losses recognized in previous periods should be reversed (except for goodwill impairment losses).
The
Any changes in the above estimates used to calculate the recoverable amount of a non–current
As described in Note 2.8, the 2020 Covid-19 pandemic generated a significant impact on the world’s economy and consequently on the oil industry – hand in hand with significant volatility in the financial and commodity markets of all the world. This situation has been improving in recent months, as a result of the reopening of different sectors of the economy and the advancement of vaccination programs. F-65 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Based on the impairment tests conducted by the Ecopetrol Business Group, the following are the impairment
The impairment
F-66 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
An impairment expense was recognized in the year 2020 as a result of the current economic context of the hydrocarbons sector, the behavior of market variables, price differentials versus the reference to Brent, technical and operational information available. This impairment was mainly recognized in fields that operate in Colombia: Occidente B, Sur, Teca, Tibú, La Hocha and Espinal, and in the field K2 abroad. In addition, a recovery was recognized in: Casabe, as a consequence of a significant increase in its reserves, as well as Provincia, Lisama and Orito. In 2019, as a result of the current hydrocarbons sector’s economic context, the behavior of the market variables, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, available technical and operational information, there was an impairment loss in the oilfields that operate in Colombia mainly Tibú, Casabe, Provincia, Underriver, La Hocha y Andalucía and the oilfield operated abroad K2.
In 2018, based on new market variables, incorporation of new reserves, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, available technical and operational information, there was a partial reversal of an impairment recognized in previous years for the oil fields that operate in Colombia Casabe, Provincia, Underriver, Tisquirama and Orito and in fields operated abroad Gunflint and K2, and an impairment mainly in Tibú and Dina Norte fields.
The following is the breakdown of oilfields impairment losses or reversals for the years ended December 31,
2020
2019
2018
F-67
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The grouping of assets to determine the CGUs is consistent as compared to the prior periods. The assumptions used to determine the recoverable amount include the following:
Investments in joint ventures in the Exploration and Production segment are recorded using the equity method of accounting. Ecopetrol evaluates if there is any objective evidence that indicate that the fair value of such investments has deteriorated in the period, especially those for which goodwill has been recorded.
As a result, Ecopetrol recognized an (impairment loss) or reversal of impairment on the carrying value as of December 31, as follows:
The significant assumptions used to determine the recoverable amount of these investments are consistent with those described in the previous section, except for the use of a discount rate in real terms in There was a recovery in 2020 on the investment in Equion mainly originated by the update of the transport rates through pipelines where Ecopetrol has a shareholding, and In 2019, an impairment loss for both. Offshore International Group and Equion Energía Limited was recorded, due to current market variables, decreasing international crude oil prices, conservative position over projects and increasing costs.
In 2018, the market showed an improvement in the crude oil and gas production forecast. Operational performance and technical evolution have contributed to strengthening future cash flows that, in turn, contributed to the reversal of the impairment charged recognized in previous years for Offshore International Group and Equion Energy.
F-68
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following is the Cash Generating Units
The grouping of assets to determine the CGUs is consistent with prior periods.
The recoverable amount of the Refinería de Cartagena was calculated based on its fair value less costs of disposal, which is higher than its value in continued use. The fair value less costs of disposal of the Refinería de Cartagena was determined based on cash flows after taxes that are derived from business plans approved by the Ecopetrol Business Group’s management, which are developed based on market prices provided by a third-party expert, which considers long–term macroeconomic variables and fundamental supply and demand assumptions for crude oil and refined products. The fair value hierarchy is 3.
The significant assumptions to determine the recoverable amount included: (i) a gross refining margin determined by crude oil feedstock and products price outlook provided by an independent third-party expert; (ii)
It is important to mention that the refining business is highly sensitive to the volatility of the margins and the macroeconomic variables implicit in the determination of the discount rate, therefore, any change in these assumptions could potentially result in significant variations in the determination of impairment losses or reversal amounts.
F-69 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) The impairment expense for 2020 was mainly derived from lower refining margins associated with external factors associated with the COVID-19 pandemic. On the other hand, management endured operational improvements that compensate to a certain extent for the effects of macroeconomic variables. The reversal of impairment recorded for 2019, is mainly related to macroeconomic assumptions changes which decreased the discount rate used to value the assets; this is explained by the decreasing risk and the Company’s cost of the debt. Together, operational management and financial results allowed the support of operational improvements included in the forecast that compensate in some measure the effects related to the impact that the MARPOL regulation will have on the margins’ forecast of refined products and the crude oil basket price discounts. The results of 2019 were impacted by a higher knowledge of the Refinery capabilities and efficient operational management.
The impairment recorded for 2018 is explained by: i) an adjustment in market expectations in relation to the impact that the implementation of the MARPOL regulation will have on margins of refined products, ii) the differential of light and heavy crudes that serve as raw material; and iii) fundamental macroeconomic changes that increased the discount rate used for the valuation of Reficar's assets, mainly associated with the increase in the risk-free rate and higher market risk premiums. Improvements in operational and commercial inputs associated to the refinery optimization as well as the tax effects of the
Starting June 24, 2020, Bioenergy entered the mandatory liquidation process. Therefore, as of this date the Group does not have control over Bioenergy and it is no longer a An impairment expense was recorded in
The recoverable amount of Bioenergy for 2019 and 2018 was calculated based on the fair value less the costs of disposal level, which is greater than the value in use and corresponds to the future cash flows discounted after taxes on profit. The fair value hierarchy is 3.
The significant assumptions used to determine the recoverable amount included: (a) forecast of ethanol prices based on projections made by Group
An impairment During 2019, a loss of COP$225,094 was recorded, primarily related to engineered works for the
During 2018, the Refinería de Barrancabermeja Modernization Project, which is currently suspended, was evaluated and there were no indications that implied the recognition of additional impairment.
F-70 Ecopetrol S.A. Notes to the (Figures expressed in millions of
The recoverable amount of these assets was determined based on its fair value with costs of disposal, which corresponds to discounted cash flows based on the hydrocarbon production curves and refined products transport curves. The fair value hierarchy is 3.
The assumptions used in the model to determine the recoverable value included: i) the tariffs regulated by the Ministry of Mines and Energy and the Energy and Gas Regulation Commission - CREG, ii) the actual discount rate used in the valuation was
In 2019, we recorded an impairment loss of
In 2018, the main impairment recorded was COP$167,917, corresponding to the systems of the Southern Cash Generating Unit (CGU), composed of the Tumaco Port and the TransAndino Pipeline (OTA) and its afferent pipelines, the Mansoyá - Orito Pipeline (OMO), San Miguel - Orito (OSO), and Churuyaco- Orito (OCHO). This value was generated mainly by a decrease in the volume projections for the southern systems, and an increase in the need for maintenance capex to reduce the operational risk of the transport systems.
As of December 31,
F-71 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
In 2020, financial obligations were acquired for a total amount of COP$13,805,403 (2019 – COP$359,876 and 2018 – COP$517,747) as part of the market risk mitigation strategy (Note 30).
The fair value of loans and borrowings is COP$52,721,790 and COP$43,261,792 as of December 31, 2020 and 2019, respectively. For fair value measurement, local currency bonds were valued using Precia reference prices, while bonds in U.S. dollars were valued using Bloomberg. With regard to the other financial obligations for which there is no market benchmark, a discount to present value technique was used. These rates incorporate market risk through some benchmarks (Libor, FTD) and the Ecopetrol Business Group’s credit risk (spread). F-72 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following are the maturities of loans and borrowing as of December 31,
The following are the maturities of loans and borrowing as of December 31,
F-73 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following is the breakdown of loans and borrowing by type of interest rate as of December 31,
The interest on the bonds in national currency is indexed to the CPI (Consumer Price Index) and bank loans and variable rate leasing in Colombian pesos are indexed to the DTF (Fixed Term Deposits) and IBR (Banking Reference Indicator), plus a differential. Interest on loans in foreign currency is calculated based on the LIBOR rate plus a spread and the interests of the other types of debt are at a fixed rate.
As of December 31,
Financing obtained directly by Ecopetrol S.A. in capital markets has no guarantees granted or financial covenant restrictions.
The following is a summary of certain restrictions contained in certain other loan instruments of
F-74
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following is the movement of net financial debt as of December 31,
The carrying amount of trade accounts and other accounts payable approximates their fair value due to their short–term nature.
F-75
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following table shows the movement in liabilities and assets, net of post-employment benefits and termination benefits, as of December 31,
F-76
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following table shows the movement in profit and loss and in other comprehensive income as of December 31, 2020, 2019 and 2018:
Plan assets are resources held by pension trusts for payment of pension obligations. Payments for health and education post–employment benefits is Ecopetrol’s responsibility. The destination of trust resources and its yields cannot be changed or returned to the Ecopetrol Business Group until all pension obligations have been fulfilled.
The following is the composition of the plan assets of pension and pension bonds by type of investment as of December 31,
The fair value of level 2 plan assets is calculated using prices quoted in the assets’ market. The Ecopetrol Business Group obtains these prices through reliable financial data providers recognized in Colombia or abroad depending on the investment.
For the securities issued in local currency, the fair value of plan assets is calculated using information published by
The average price is calculated based on the most representative market of the transactions carried out through electronic platforms approved and supervised by the regulator.
On the other hand, the estimated price is calculated for investments that do not reflect enough information to estimate an average market price, replicating the quoted prices for similar assets or prices obtained through quotes from brokers. This estimated price is also given by
F-77
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following table reflects the credit ratings of the issuers and counterparties in assets held by the autonomous pension funds:
See credit risk policy in Note 30.8.
The following are the actuarial assumptions used in determining the present value of defined employee benefit obligations used for the actuarial calculations as of December 31,
F-78 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
N/A: Not applicable for this benefit.
The cost trend is the projected increase for the initial year, which includes the expected inflation rate.
The mortality table used for the calculations was that of ‘Valid Annuitant’ for men and women based on the experience gained for the period 2005–2008 of the Colombian Social Security Institute.
The cash flows required for payment of post–employment obligations are the following:
The following sensitivity analysis shows the effect of such possible changes on the obligation for defined benefits, while keeping the other assumptions constant, as of December 31,
F-79 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
In October 2019, the Ecopetrol’s Board of Directors approved a new employee retirement plan that included four categories of retirements from January 2020 until December 2023: compliance of the work cycle (pension), Retirement Plan A (rent), Retirement Plan B (Bonus) and improved compensation. As for December 31, 2019, the Ecopetrol Business Group has not recognize a provision related to this plan, since it will be understood as an obligation at the time the Company offers the plan and each employee voluntarily accepts their retirement by taking advantage of any of the mentioned categories. In May 2020, Ecopetrol started offering this retirement plan, to which 421 workers have applied.
In August 2016, the Ecopetrol
F-80 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The estimated liability for asset retirement obligation costs corresponds to the future obligation that the Ecopetrol Business Group to restore environmental conditions to a level similar to that existing before the start of projects or activities, as described in Note 3.5 – Abandonment and dismantling costs of fields and other facilities. As these relate to long–term obligations, this liability is estimated by projecting the expected future payments and discounting at present value with a rate indexed to the Ecopetrol Business Group’s financial obligations, taking into account the temporariness and risks of this obligation. The discount rates used in the estimate of the obligation as of December 31,
These correspond to contingencies for environmental incidents and obligations related to environmental compensation and mandatory investment of 1% for the use of, exploitation of or effect on natural resources imposed by national, regional and local environmental authorities. Mandatory investment of 1% is based on the use of water taken directly from natural sources in accordance with the provisions of Law 99 of 1993, Article 43, Decree 1900 of 2006, Decree 2099 of 2017 and 075 and 1120 of 2018 and article 321 of Law 1955 of 2019 in relation to the projects that Ecopetrol develops in Colombia.
The Colombian Government through the Ministry of Environment and Sustainable Development, issued in December 2016 and in January 2017 the Decrees 2099 and 075, which modify the Single Regulatory Decree of the environment and sustainable development sector, Decree 1076 of 2015, related to the mandatory investment for the use of water taken directly from natural sources.
On June 30, 2017, Ecopetrol filed with the National Environmental Licensing Authority (ANLA) certain investment plans to meet the 1% mandatory investment based on the new decrees, relative to investment lines, maintaining the settlement base of Decree 1900.
F-81 Ecopetrol S.A. Notes to the (Figures expressed in millions of
Oleoducto Bicentenario de Colombia S.A.S.
During July 2018, the carriers Frontera Energy Colombia Corp.
Under Bicentenario’s understanding that the Transport Agreements remain current and that the Carriers are in violation of their obligations under such agreements, Bicentenario declared the Carriers delinquent because of their failure to pay for transport service under the aforementioned agreements. Consequently, Bicentenario executed the standby letters of credit posted as guarantee for the Transport Agreements.
On October 19, 2018, Bicentenario notified Frontera of the existence of a “Dispute” pursuant to Clause 20 of the respective Transport Agreement and moved to the party dispute settlement stage as provided for in such clause. Such discussions ended without an agreement on December 19, 2018. On January 28, 2019, Bicentenario filed an Arbitration Claim against Frontera in accordance with the arbitration clause of the Transportation Agreement to claim any compensation, indemnification or other restitution deriving from the alleged early termination of said agreements. Similarly, on November 1, 2018, Bicentenario notified Vetra and Canacol of the existence of a “Dispute” pursuant to Clause 20 of the respective Transport Agreement and moved to the party dispute settlement stage as provided for in each such respective clause. Such discussions ended without agreement on March, 2019.
Cenit Transporte y Logística de Hidrocarburos S.A.S. (“Cenit”)
The abovementioned fees dispute was at the root of the opposition manifested by Frontera Group against the application of the fees defined by the Ministry of Mines and Frontera has not paid the component of the fee related to the abandonment fund to which Cenit considers they are entitled by virtue of the application of resolutions 31480 and 31661 issued by the Ministry of Mines and Energy. Frontera Energy Group owed $ 9,663 in connection therewith. Bicentenario, Cenit and Frontera Settlement Agreement On November 17, 2020, Cenit, Bicentenario and Frontera reached an agreement, for the joint filing of a petition for a binding settlement which, upon completion and approval by the competent Colombian court, will resolve all the disputes pending among them, related to the Caño Limón – Coveñas pipeline,
F-82
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The new ship or pay commitment is projected to be approximately 3,900 bbls/day, based on the current oil price, for a term of five years subject to adjustments, at a current fee of $11.5/bbl. Frontera will not have to make payments for oil it may have to ship through alternate pipelines. These contracts will allow Cenit and Bicentenario to obtain payment of certain amounts included in the settlement, during the term of the contracts. The arrangement is conditional upon certain regulatory approvals, including approval of the settlement arrangement as a conciliation under Colombian law, which requires an opinion from the Attorney General’s Office (Procuraduría General de la Nación) which was issued on March 24, 2021 and approval of the Administrative Tribunal of Cundinamarca. As of the date of this annual report the final approval by the Administrative Tribunal of Cundinamarca was pending.
Bicentenario, Cenit and Canacol Settlement Agreement On October 30, 2020 Cenit and Canacol reached an agreement to settle all their aforementioned disputes. The Bicentenario, Cenit and Vetra Settlement Agreement On November 23, 2020, Cenit and Vetra reached an agreement to settle all their aforementioned disputes. The settlement arrangement includes a full and final mutual release upon closing of all present and future amounts claimed by all parties in respect of the terminated transportation contracts for Caño Limón – Coveñas pipelines. On February 18, 2021 the competent arbitration tribunal approved the conciliation agreement entered into by Cenit and Vetra, according to which Vetra is obliged to transfer all its outstanding shares in Bicentenario to Cenit and to make a cash payment for the
Refinería de Cartagena
On March 8, 2016, Reficar filed a
On May 25, 2016, CB&I filed its Answer to the Request for Arbitration and On April 28, 2017, Reficar filed its non-detailed claim and, on the same date, CB&I submitted its Statement of Counterclaim increasing its claims to approximately
F-83 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
On June 28, 2019, CB&I submitted its Reply to the Non-Exhaustive Statement of Defence to Counterclaim increasing its claims to approximately USD$137 million and COP$503,241 million (including in each case interest, respectively). On this same date, Reficar filed its Reply to CB&I’s Non-Exhaustive Statement of Defense and its Exhaustive Statement of Defense to CB&I’s counterclaim, updating its claim for provisionally paid invoices under the MOA and PIP Agreements and the EPC Contract to approximately USD$ 137 million. In relation to this matter, as of December 31, 2020 there is a balance of approximately USD $ 122 million, in invoices paid by Reficar to CB&I, under the PIP and MOA Agreements of the EPC contract, whose supports provided to date by CB&I do not show acceptance by AMEC Foster Wheeler - PCIB. In January 2020, McDermott International Inc. – CB&I parent company – commenced a bankruptcy case under title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. Faced with this situation, Refinería de Cartagena has taken actions to protect its interests and has a group of experts with whom it will continue to evaluate other measures it may adopt in this new circumstance. As a consequence of the initiation of the reorganization process, the arbitration was suspended until July 1, 2020, as described below. On January 21, 2020, Comet II BV, the successor in interest to Chicago Bridge & Iron Company NV, commenced bankruptcy case under title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. Before the beginning of the insolvency process of Comet II BV, an automatic suspension of the initiation or continuation of any action, process or execution of judgment or award against Comet II BV became effective, which suspended the arbitration. On January 23, 2020, Comet II B.V. obtained an order from the Bankruptcy Court permitting it to, in its discretion, modify the automatic stay to permit it to proceed with litigation or other contested matters. On March 14, 2020, the Bankruptcy Court entered an order confirming a plan of reorganization, and the order provides for the stay against the arbitration to end upon the earlier of the effective date of the plan or August 30, 2020.- whichever would occur first. On June 30, 2020, McDermott International Inc. notified the occurrence of the effective date of the reorganization plan, for which the suspension of arbitration was lifted on July 1, 2020. On May 6, 2020, the Superintendence of Companies ordered the judicial liquidation of CBI Colombiana SA, one of the defendants in the CB&I arbitration. On October 22, 2020, Reficar requested its recognition as a creditor of CBI Colombiana SA, up to the maximum amount of its claims in the arbitration. On January 15, 2021, the liquidator of CBI Colombiana SA accepted Reficar’s request. On September 22, 2020, the tribunal scheduled the start of the hearings for May 2021. The outcome of the arbitration remains uncertain until such time as the arbitration ruling is issued. 23.4 Investigations of control entities – Reficar Reficar is a wholly owned subsidiary of Ecopetrol. According to Colombian regulations, Ecopetrol’s and Reficar’s employees are considered public servants, and as such can be held liable for negligent use or management of public resources. In this context, given that Ecopetrol is majority owned by the Colombian Government and Reficar is a wholly owned subsidiary of Ecopetrol, Ecopetrol and Reficar administer public resources. As a result, Ecopetrol and Reficar employees are generally subject to the control and supervision of the following control entities, among others: The Office of the Comptroller General (Contraloría General de la República) oversees the adequate use of public resources and has the authority to investigate public employees or private sector employees that use or manage public resources. The Attorney General’s Office (Procuraduría General de la Nación) supervises compliance with applicable law by public employees and private sector employees that carry out public functions. The Attorney General’s Office investigates and disciplines individuals for compliance failures.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Prosecutor’s Office (Fiscalía General de la Nación) investigates potential crimes and prosecutes alleged crimes before the court in judicial proceedings. The following are the most significant investigations and proceedings carried out by the aforementioned state entities:
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
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
As of the date of
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
F-85 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
As of the date of
As of the date of this annual report, the former and current Boards of Directors of Ecopetrol and Reficar are not part of the Comptroller General proceedings.
Reficar has been officially informed that the Attorney General’s Office currently has
Regarding one of these
On January 17, 2020 the Attorney General’s Office issued its judgment against Reyes Reinoso Yanes for acting “ultra vires” in the exercise of his functions promoting a special billing procedure without the due diligence required to protect Reficar’s resources. As for the other four individuals initially investigated, they were acquitted of the charges. Mr. Reinoso filed an appeal against the decision and is awaiting resolution. In another investigation, on October 21, 2020, the Attorney General’s Office issued its judgment against a former employee of Reficar, Nicolas Isaksson Palacios, related to the failure to fulfill some of his duties for acting “ultra vires” in the exercise of his functions. The Attorney General’s Office closed the case against the rest of the former members of Reficar’s Board of Directors and other Reficar employee. The specific content and status of the remaining As of the date of this annual report, the current Boards of Directors of Ecopetrol
The Prosecutor’s Office has been conducting the following legal
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
F-86 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) On May 9, 2017, Ecopetrol’s Audit and Risk Committee retained a U.S.-based outside law firm to commence a third-party investigation into the matters set forth in the Prosecutor’s Office announcement. The results were presented in December 2017 to Ecopetrol’s Audit and Risk Committee. This investigation concluded that to date there has been no evidence of possible unlawful acts that affect Ecopetrol’s internal control over the financial reporting of the Company, on the allegations made by the Prosecutor’s Office.
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.
Ecopetrol and Reficar have cooperated closely and extensively with the control entities in furthering their investigations and will continue to monitor the status and development of these investigations.
As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar and the current employees are not part of the above proceedings. None of the legal proceedings described in this paragraph are related with bribery charges. As of the date of this annual report, Ecopetrol and Reficar have no knowledge of any legal proceeding in the United States regarding the project.
The following is a summary of the main contingent liabilities that have not been recognized in the statement of financial position as, according to the evaluations made by internal and external advisors of the Ecopetrol Business Group, the expectation of loss is not probable as of December 31, 2020 and 2019:
F-87 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following is a breakdown of the Ecopetrol Business Group’s principal contingent assets, where the associated contingent gain is likely, but not certain:
The main components of equity are detailed below:
Ecopetrol’s authorized capital amounts to
Additional paid–in capital mainly corresponds to: (i) share premium from the Ecopetrol Business Group’s capitalization in 2007, for COP$4,457,997, (ii) share premium from the sale of shares awarded in the second capitalization, which took place in September 2011, of COP$2,118,468, iii) a COP$31,377 share premium from the placement of shares on the secondary market, arising from the calling of guarantees from debtors in arrears, according to the provisions of Article 397 of the Code of Commerce,
The following is the composition of the Ecopetrol Business Group’s reserves as of December 31, 2020 and 2019:
(1) Ecopetrol's General Shareholders' Meeting, held on March 27, 2020, approved the 2019 profit distribution project and set up a reserve of 4,557,074 in order to support the Company's financial sustainability and flexibility in development of its strategy. F-88 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The movement of equity reserves is the following for the years ended December 31,
The Ecopetrol Business Group distributes dividends based on its separate annual financial statements, prepared under International Financial Reporting Standards accepted in Colombia (NCIF, by its acronym in Spanish).
The On March 26, 2021, the ordinary General Shareholders Assembly approved
The following is the composition of the other comprehensive income attributable to the shareholders of the parent, Ecopetrol S.A., net of tax:
F-89 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-90 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Sales by geographic areas
Concentration of customers
During
F-91 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-92 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Ecopetrol Business Group operates mainly in Colombia and makes sales in the local and international markets, for that reason, it is exposed to exchange rate
When the Colombian peso
The
F-93 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Of the total net
The following is the effect of a change of 1% and 5% in the exchange rate of the Colombian peso as compared with the U.S. dollar, on the balance of financial assets and liabilities denominated in foreign currency as of December 31,
The following is the movement of foreign currency debt designated as a non–derivative hedging instrument for the years ended December 31,
The following is the movement
The expected reclassification of the cumulative exchange
F-94 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Board of Directors approved the application of net investment hedge accounting from June 8, 2016. The measure is intended to reduce the volatility of non–operating income due to exchange rate variations. The net investment hedge will be applied on a portion of the Ecopetrol Business Group’s investments in foreign operations, in this case on investments in subsidiaries which have the U.S. dollar as their functional currency, using a portion of the Ecopetrol Business Group’s U.S. dollar denominated debt as the hedging instrument.
Ecopetrol The following is the movement in other comprehensive income for the years ended December 31:
30.5 Hedging with financial derivatives In 2020, Ecopetrol carries out forward non-delivery operations for the sale of dollars in order to mitigate the volatility of the The impact on the profit or loss as of December 31, 2020 due to the settlement of these hedges generated a loss of COP$62,911 (2019 - COP$60,740) and the amount recognized in the other comprehensive income was a profit of COP$51,486 (2019 - COP$43,141). 30.6 Commodity price risk The price risk of raw materials is associated with the Group’s The risk of such exposure is partially hedged in a natural way, as an integrated Group (with operations in the exploration and production, transportation and logistics and refining segments) and carries out both crude exports at international market prices and sales of refined products at prices correlated with international prices. The Group has a policy for the execution of (strategic and tactical) hedges and implemented processes, procedures and controls for their management. The main purpose of the strategic hedging F-95 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following is the
The The operations carried out
The commitments in physical spots and term contracts in the
Similarly, hedges on exports of
Credit risk is the risk that the Ecopetrol Business Group may suffer financial losses as a consequence of default of: (a) payments by its clients for the sale of crude oil, gas, products or services; (b) financial institutions in which it keeps investments, or (c) by counterparties with which it has contracted financial instruments.
Credit risk related to customers
In the selling process of crude oil, gas, refined products and petrochemicals, and transport services, the Ecopetrol Business Group may be exposed to credit risk in the event that customers fail to fulfill their payment obligations. The Ecopetrol Business Group’s risk management strategy has designed mechanisms and procedures that aim to minimize such events, thus safeguarding the Ecopetrol Business Group’s cash flow.
The Ecopetrol Business Group performs a continuous analysis of the financial strength of its counterparties, by classifying them according to their risk level and financial guarantees in the event of a default of payments. Similarly, the Ecopetrol Business Group continuously monitors national and international market conditions for early alerts of major changes that may have an impact on the timely payment of obligations from For the receivables that are considered exposed to credit risk, Ecopetrol Business
F-96
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
An aging analysis of the accounts receivable portfolio in arrears, but not impaired, as of December 31, 2020 and 2019 is as follows:
Credit risk in financial assets
Following the promulgation of Decree 1525 of 2008, which provides general rules on investments for public entities, Ecopetrol’s management established guidelines for
In addition, Ecopetrol S.A. may also invest in securities issued or guaranteed by the
In order to diversify the risk in
The credit rating of issuers and counterparties in transactions involving financial instruments is disclosed in Note 6 – Cash and cash equivalents, Note 9 – Other financial assets and Note
Interest rate risk arises from Ecopetrol’s exposure to changes in interest rates because the Ecopetrol Business Group has investments in fixed and floating–rate instruments and has issued floating rate debt linked to LIBOR, DTF and CPI interest rates. Thus, interest rate volatility may affect the fair value and cash flows of the Ecopetrol Business Group’s investments and the financial expense of floating rate loans and financing.
As of December 31, 2020, 16% (2019, 17% and 2018, 17%
Ecopetrol controls the exposure to interest rate risk by establishing limits to
Autonomous equities linked to Ecopetrol’s pension obligations are also exposed to changes in interest F-97 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following table provides information about the sensitivity of the Ecopetrol Business Group’s results and other comprehensive income for the next 12 months to variations in interest rate of 100 basis points:
A sensitivity analysis of discount rates on pension plan assets and liabilities is disclosed in Note
The ability to access credit and capital
Events
Liquidity risk is managed in accordance with the Ecopetrol Business Group’s policies aimed at ensuring that
The following is a summary of the maturity of financial liabilities as of December 31,
The main objective of the capital management of the Ecopetrol Business Group is to ensure a financial structure that optimizes the cost of capital, maximizes the rate of return to its shareholders and allows access to financial markets at a competitive cost to cover
(1) Leverage = Net financial debt
The movement of the net financial debt is detailed in Note
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Balances with associates and joint ventures as of December 31,
Accounts receivable – Loans:
F-99 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The main transactions with related parties
In accordance with the approval given by the shareholders’ meeting in 2012,
The total compensation paid to Directors as of December 31,
As of December 31,
The administration and management of resources for payment of Ecopetrol’s pension obligations are managed by autonomous pension funds (PAPs, by its acronym in Spanish) which serve as guarantee and payment sources. In 2008, Ecopetrol S.A. received the authorization to partially commute the value corresponding to monthly payments, bonds and quotas, transferring said obligations and the
Since November 2016, the entities that
These
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Colombian Government controls Ecopetrol with a stock ownership of 88.49%. The most significant transactions with governmental entities are comprised as follows:
By nature of the business, Ecopetrol purchases the crude oil that the ANH receives from producers in Colombia at the prices set in accordance with a
From December 2013 the Ecopetrol Business Group commercialized, on behalf of the ANH, the natural gas received by the latter in kind from producers. Since January 2014, ANH has received royalties in cash for the production of natural gas.
The purchase value of oil and gas from ANH is detailed in Note
Additionally Ecopetrol, like other oil and gas companies, takes part in “rounds” for the allocation of exploration blocks in Colombia without implying special treatment for Ecopetrol on
Ecopetrol, just like any other company in Colombia, has tax obligations that it must comply with and does not have any other kind of association or commercial relationship with the National Tax and Customs
Ecopetrol, just like any other state entity in Colombia, is obliged to comply with the requirements set out by the Comptroller General of the Republic and make an annual payment to this entity on account of a maintenance fee. Ecopetrol does not have any other kind of association or commercial relationship with this entity.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Ecopetrol Business Group carries out exploration and production operations through Exploration and Production (E&P) Contracts, Technical Evaluation (TEA) Contracts and Agreements signed with the National Hydrocarbons Agency or ANH, as well as through Partnership Contracts and other types of contracts. The main joint operations in
F-102 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
During 2020 the following relevant events were presented in the joint operations contracts:
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
A description of the Ecopetrol Business Group’s business segments is in Note 4.19 – Information by business segment.
The following segment information is reported based on the information used by the Board of Directors as the top body to make strategic and operational decisions of these business segments. The performance of the segments are based primarily on an analysis of income, costs, expenses and results for the period generated by each segment which are regularly monitored.
The information disclosed in each segment is presented net of transactions between the Ecopetrol Business Group companies.
Below are the consolidated statements of profit or loss by segment for the years ended December 31,
F-104 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-105
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The sales by product for each segment are detailed below for the years ended December 31, 2020, 2019 and 2018:
F-107 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-108 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-109 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following are the investments amounts made by each segment for the years ended December 31, 2020, 2019 and 2018:
F-110
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
On January 27, 2021, Ecopetrol announced its interest in acquiring 51.4% of the outstanding shares of ISA, currently owned by ISA operates and maintains a high voltage transmission network in Colombia, Peru, Bolivia, Brazil and Chile, among others, and participates through its subsidiaries in the toll-road business, telecommunications and management of real-time systems. Based on its public reports as filed with the Superintendencia Financiera de Colombia (the “SFC”), ISA’s consolidated revenues and net income for the
On February 12, 2021, Ecopetrol and the MHCP signed an exclusivity agreement through which the parties will carry out non-binding preliminary conversations on the terms and conditions of the potential transaction. The exclusivity period is initially scheduled to end on June 30, 2021 unless extended by mutual agreement of the parties. During this period, Ecopetrol will carry out due diligence activities on ISA and the MHCP has agreed to negotiate exclusively with Ecopetrol.
On February 1, 2021, Cenit assumed the integral operation of its infrastructure, directly executing the local and centralized operation of its hydrocarbon transport systems. With this change, Cenit also assumes the local operation of the Ocensa, Bicentenario and ODC (Oleoducto de Colombia) systems, and consolidates itself as the leader of Ecopetrol Group’s transport segment.
On February 8, 2021, the Energy and Gas Regulatory Commission (CREG) issued resolution 004 of 2021, whereby the Energy and Gas Regulatory Commission (CREG) establishes the WACC calculation methodology for activities regulated by CREG. Said activities include electric power distribution and transmission, and distribution and transportation of gas and liquid fuels. The discount rate for the transportation of liquid fuels through pipelines will be calculated and applied once the rate methodology for this activity is updated. In accordance with the CREG’s regulatory agenda, the methodology proposal is expected to be issued for comments during the second half of 2021 and the final document is expected to be published at the end of the year.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The information in this note is referred to as “unaudited” as a means of clarifying that it is not covered by the audit opinion of the independent registered public accounting firm that has audited and reported on the “Consolidated Financial Statements.”
In accordance with the requirements of the United States Securities and Exchange Commission (SEC), Rule 4–10(a) of Regulation S–X, Release 33–8879, Accounting Standards Codification 932 and the ASU– 2010–03 “Oil and Gas reserve Estimation and Disclosures” rule, this section provides supplemental information on oil and gas exploration and producing activities of the Ecopetrol Business Group. The information included in sections
The following information corresponds to Ecopetrol’s oil and gas producing activities as of December 31
Under the SEC final rule optional disclosure of possible and probable reserves is allowed but, the Ecopetrol Business Group opted not to do so. Ecopetrol estimated its reserves without considering non–traditional resources.
It includes information of the Exploration and Production segment subsidiaries and joint ventures.
In accordance with IAS 37, costs capitalized to natural and environmental properties include provisions for asset retirement obligations of COP$
Costs incurred are summarized below and include both amounts expensed and capitalized in the corresponding period.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Ecopetrol Business Group’s results of operations from oil and gas exploration and production activities for the years ended December 31,
During
The intercompany transfers were realized at market prices.
F-113 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Ecopetrol Business Group follows international standards for estimating, classifying and reporting reserves framed under SEC definitions. Corporate Reserve Management of Ecopetrol, Upstream Management and the Vice-Presidency of Development and Production, present the reserves balance to the Board of Directors for approval.
The reserves were estimated at a level of 99% by specialized firms: DeGolyer and MacNaughton,
The following information relates to the net proven reserves owned by the Ecopetrol Business Group in
Some values were rounded for presentation purposes.
For additional information about the changes in Proved Reserves and the process for estimating reserves, see section
The standardized measure of discounted future net cash flows related to the above proved crude oil and natural gas reserves is calculated in accordance with the requirements of ASU 2010–03. Estimated future cash inflows from production under SEC requirements are computed by applying unweighted arithmetic average of the first–day–of–the–month for oil and gas price to year–end quantities of estimated net proved reserves, with cost factors based on those at the end of each year, currently enacted tax rates and a 10% annual discount factor. In our view, the information so calculated does not provide a reliable measure of future cash flows from proved reserves, nor does it permit a realistic comparison to be made of one entity with another because the assumptions used cannot reflect the varying circumstances within each entity. In addition, a substantial but unknown proportion of future real cash flows from oil and gas production activities is expected to derive from reserves which have already been discovered, but which cannot yet be regarded as proved.
F-114 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following are the principal sources of change in the standardized measure of discounted net cash flows in 2020, 2019 and 2018:
F-115 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Exhibit 1 – Consolidated subsidiaries, associates and joint ventures
Consolidated subsidiary companies (1/2)
(*) Includes the effect of unrealized profits from transactions of companies in the transport and logistics segment.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Consolidated subsidiaries (2/2)
F-117 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Associated companies and joint ventures
(1) Companies in liquidation process. See Note 2.2 Basis for consolidation.
(2) Information available as of November 30, 2020.
(3) Information available as of September 30, 2020, The investment is 100% impaired.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Exhibit 2 – Conditions of the most significant
F-119
SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
Dated: April
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