As filed with the Securities and Exchange Commission on April 5, 2019
March 31, 2020
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 20-F
ANNUAL REPORT PURSUANT TO
SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20182019
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 registered: | ||
American Depository Shares (as evidenced by American Depository Receipts), each representing 20 common shares par value COP$609 per share | EC | New York Stock Exchange | ||
Ecopetrol common shares par value COP$609 per share | New York Stock Exchange (for listing purposes only) |
5.875% Notes due 2023 | EC23 | New York Stock Exchange | ||
4.125% Notes due 2025 | EC25 | New York Stock Exchange | ||
5.375% Notes due 2026 | EC26 | New York Stock Exchange | ||
7.375% Notes due 2043 | EC43 | New York Stock Exchange | ||
5.875% Notes due 2045 | EC45 | New York Stock Exchange |
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report.
41,116,694,690 Ecopetrol common shares, par value COP$609 per share
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
x Yes¨ No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
¨ 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 filerx | Accelerated filer¨ | Non-accelerated filer¨ | Emerging growth company¨ |
If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.¨
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
¨ U.S. GAAP | x International Financial Reporting Standards as issued by the International Accounting Standards Board | ¨ Other |
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:
¨ Item 17¨ Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company
(as defined in Rule 12b-2 of the Exchange Act).
¨ Yesx No
Annual Report on Form 20-F 20182019
Table of Contents
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1. | Introduction |
1.1 | About This Annual Report |
We file our Annual Report on Form 20-F and other information with the U.S. Securities and Exchange Commission.
We file reports, including annual reports on Form 20-F, and other information with the SEC pursuant to the rules and regulations of the SEC that apply to foreign private issuers. The materials included in this annual report on Form 20-F may be downloaded at the SEC’s website: http://www.sec.gov. Any filings we make are also available to the public over the Internet at the SEC’s website at www.sec.gov and at our website at www.ecopetrol.com.co. (This URL is intended to be an inactive textual reference only. It is not intended to be an active hyperlink to our website. The information on our website, which might be accessible through a hyperlink resulting from this URL, is not and shall not be deemed to be incorporated into this annual report.)
Unless the context otherwise requires, the terms “Ecopetrol,” “we,” “us,” “our,” “Ecopetrol Group,” or the “Company” are used in this annual report to refer to Ecopetrol S.A. and its subsidiaries on a consolidated basis.
For purposes of the sectionBusiness Overview—Exploration and Production, “we” refers to Ecopetrol S.A., its subsidiaries and the partnerships in which Ecopetrol has an interest.
References to the Nation in this annual report relate to the Republic of Colombia (“Colombia”)(Colombia), our controlling shareholder. References made to the Colombian government or the Government correspond to the executive branch including the President of Colombia, the ministries and other governmental agencies responsible for regulating our business.
1.2 | Forward-looking Statements |
This annual report on Form 20-F contains forward-looking statements within the meaning of the safe harbor provisions of the U.S. Private Securities Litigation Reform Act of 1995. These statements are not based on historical facts and reflect our expectations for future events and results. Most facts are uncertain because of their nature. Words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “should,” “plan,” “potential,” “predicts,” “prognosticate,” “project,” “target,” “achieve” and “intend,” among other similar expressions, are understood as forward-looking statements. We have made forward-looking statements that address, among other things:
· | our exploration and production activities, including drilling; |
· | import and export activities; |
· | our liquidity, cash flow, and sources of funding; |
· | our projected and targeted capital expenditures and other cost commitments and revenues; and |
· | dates by which certain areas will be developed or will come on-stream. |
Our forward-looking statements and sensitivity analysis are not guarantees of future performance and are subject to assumptions that may prove incorrect and to risks and uncertainties that are difficult to predict. Actual results could differ materially from those expressed or forecasted in any forward-looking statements as a result of a variety of factors. These factors may include, but are not limited to, the following:
· | general economic and business conditions, including crude oil and other commodity prices, refining margins and prevailing exchange rates; |
· | competition; |
· | our ability to obtain financing; |
· | our ability to find, acquire or gain access to additional reserves and our ability to develop existing reserves; |
· | uncertainties inherent in making estimates of our reserves; |
· | significant political, economic and social developments in Colombia and other countries where we do business; |
· | natural disasters, pandemics and other health events, military operations, terrorist acts, wars or embargoes; |
· | regulatory developments, including regulations related to climate change; |
· | receipt of government approvals and licenses; |
· | technical difficulties; and |
· | other factors discussed in |
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 | 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||||||||||||||||
Oil and gas production (mboed) | 720.4 | 715.1 | 717.9 | 760.7 | 755.4 | 725.1 | 720.4 | 715.1 | 717.9 | 760.7 | ||||||||||||||||||||||||||||||
Proved oil and gas reserves (Mmboe)(1) | 1,727 | 1,659 | 1,598 | 1,849 | 2,084 | 1,893 | 1,727 | 1,659 | 1,598 | 1,849 | ||||||||||||||||||||||||||||||
Exploratory Wells(2) | 17 | 20 | 6 | 5 | 28 | 20 | 17 | 20 | 6 | 5 | ||||||||||||||||||||||||||||||
Refinery Through-put (bpd)(3) | 375,666 | 347,483 | 332,751 | 234,861 | 240,484 | 375,754 | 375,666 | 347,483 | 332,751 | 234,861 | ||||||||||||||||||||||||||||||
1P Reserves replacement ratio | 129 | % | 126 | % | (7 | )% | 6 | % | 146 | % | 169 | % | 129 | % | 126 | % | (7 | )% | 6 | % |
(1) | Proved oil and gas reserves include natural gas royalties and exclude crude oil royalties. |
(2) | Gross exploratory wells. |
(3) | Refinery throughput includes the Barrancabermeja, Reficar, Apiay and Orito refineries. Reficar operations were shut down in March 2014 for the expansion and modernization plan. The new crude unit began start-up process in October 2015. During 2016, Reficar was undergoing the unit startup phase and commenced full operation in July 2016. The refinery’s global performance testing was successfully completed in the fourth quarter of 2017, resulting in the start of the refinery’s optimization and continuous operation stage. During 2018, Reficar continued its optimization phase. |
Financial Information
International Financial Reporting Standards (“IFRS”)(IFRS)
(Expressed in millions of Colombian Pesos, except for the net income per share and net operating income per share, which are expressed in Colombian Pesos)
Table 2 – Selected Financial Data
Financial Information | 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 | 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||||||||||||||||
Revenue | 71,488,512 | 68,603,872 | 55,954,228 | 48,485,561 | 52,347,271 | |||||||||||||||||||||||||||||||||||
Operating income | 21,027,158 | 22,458,414 | 16,171,855 | 8,904,548 | 2,131,165 | |||||||||||||||||||||||||||||||||||
Net income (loss) attributable to Ecopetrol’s shareholders | 13,744,011 | 11,381,386 | 7,178,539 | 2,447,881 | (7,193,859 | ) | ||||||||||||||||||||||||||||||||||
Net operating income per share | 546 | 393 | 217 | 51.8 | 351.4 | 511 | 546 | 393 | 217 | 51.8 | ||||||||||||||||||||||||||||||
Weighted average number of shares outstanding | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,698,456 | 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 | 334 | 277 | 175 | 59.5 | (175.0 | ) | ||||||||||||||||||||||||||||
Total assets | 124,643,498 | 117,847,412 | 118,958,977 | 123,588,190 | 110,923,851 | 133,890,296 | 124,643,498 | 117,847,412 | 118,958,977 | 123,588,190 | ||||||||||||||||||||||||||||||
Total equity | 57,107,780 | 48,215,699 | 43,560,501 | 43,100,963 | 48,534,228 | 58,231,628 | 57,107,780 | 48,215,699 | 43,560,501 | 43,100,963 | ||||||||||||||||||||||||||||||
Subscribed and paid-in capital | 25,040,067 | 25,040,067 | 25,040,067 | 25,040,068 | 10,279,175 | 25,040,067 | 25,040,067 | 25,040,067 | 25,040,067 | 25,040,068 | ||||||||||||||||||||||||||||||
Number of common shares | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,694,690 | 41,116,698,456 | 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 | 180 | 314 | 89 | 23 | - | ||||||||||||||||||||||||||||||
Total liabilities | 67,535,718 | 69,631,713 | 75,398,476 | 80,487,227 | 62,389,623 | 75,658,668 | 67,535,718 | 69,631,713 | 75,398,476 | 80,487,227 |
Our consolidated financial statements for the years ended December 31, 2014, 2015, 2016, 2017, 2018 and 20182019 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 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$2,956.553,282 per US$1.00, which corresponds to theTasa Representativa Promedio del Mercado (TRM), or Average Representative Market Exchange Rate, for 2018.2019. Such conversion should not be construed as a representation that the Colombian Peso amounts correspond to, or have been or could be converted into, U.S. dollars at that rate or any other rate. On April 1, 2019,March27, 2020, the Representative Market Exchange Rate was COP$3,174.793,996 per US$1.00.
Certain figures shown in this annual report have been subject to rounding adjustments, and, accordingly, certain totals may therefore not precisely equal the sum of the numbers presented. In this annual report a billion is equal to one with nine zeros.
2. | Strategy and Market Overview |
After experiencingThe US-China trade war escalated in 2019 and increased average tariffs between the two nations (U.S. tariffs to China rose from 12.0% to 21.0%, and Chinese tariffs to the U.S. from 16.5% to 21.1% in each case from 2018 to 2019), affecting global confidence. Global industrial production entered a gradual recovery during the first half of 2018downturn, and reachingworld trade stagnated with most countries worldwide recording a peak in October, the ICE Brent price suffered a downward trendslowdown in the latter partgrowth of 2018. The expectationtheir economies. In 2019, these factors led to a 0.75 million barrels 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 tight 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 Arabia 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 economicequivalent per day (mmboepd) growth in China and Europe did not favor crude oil consumption.demand, the lowest growth rate since 2012 when demand increased by 0.60 mmboepd.
According to estimatesWorld oil supply remained stable in 2019. While the supply of those outside the Organization of the Energy Information Administration (“EIA”),Petroleum Exporting Countries (OPEC) increased by 1.94 mmboepd in 2018 global consumption 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,2019, mainly due to unplannedhigher production in the U.S. (1.62 mmboepd) and Brazil (0.23 mmboepd), the supply from OPEC countries fell by 2.10 mmboepd. In addition to production declines in Saudi Arabia, the decrease in total OPEC output was largely driven by falling production in Venezuela and Iran due, in part, to U.S. sanctions. Crude oil production in Venezuela averaged 0.82 mmboepd in 2019, a decline of 0.57 mmboepd as compared to 2018. In 2019, Iranian crude oil disruptions whichproduction decreased by 1.21 mmboepd as compared to 2018.
In conclusion, global oil markets were roughly balanced in December amounted2019, as global oil supply declined slightly, and global oil consumption grew at the smallest rate since 2009. However, market pessimism increased in 2019 largely due to 2.2 mmboepdtrade war fears and a global slowdown, pushing down the price of oil. Brent averaged US$64/Bl in Libya and Nigeria, Iranian sanctions and decreasing production in Venezuela.2019, down from a 2018 average of US$72/Bl.
Graph 1 – Supply/Demand Balance vs ICE Brent Price Evolution
Source:EIA: Short term EnergyEnergy Outlook (January 15, 2019)
During 2020, international reference prices have been impacted due to the disagreement on production cuts between the Organization of the Petroleum Exporting Countries (OPEC) and Russia, global and regional economic and political developments in the OPEC, and its capacity and decision to increase production levels to gain market share.
Although international oil prices and global demand and supply dynamics are significant factors affecting our business and financial condition, Colombia’s local economic factors have also influenced, and could continue to influence our performance, given that we conduct most of our business in Colombia.
The performance of Colombia’s gross domestic product (GDP) is one of the main drivers of fuel consumption in Colombia.consumption. According to the National Administrative Department of Statistics (DANE for its acronym in Spanish)Spanish acronym), during 20182019 Colombia’s GDP grew 2.7%by3.3% in real terms, as compared to 2017.2018. The sectors with the greatest growth rates were retail, manufacturingfinancial services, and state defense spendingpublic administration, which had the largest contribution to national GDP. On the other hand, agricultural and cattle activitiesconstruction had the worst performance.
Local sales of liquid fuels(LPG, diesel, jet and gasoline)increased by 1.3%,4% in 2019, boosted by increased demand for dieselgasoline and jet fuel.diesel.
Natural gas demand in Colombia grewdecreased by 5.1%1.7% in 2019 as compared to 2018 due to higherlower demand from natural gas fired power plants and from non-thermal demand, mainly for household consumption.plants.
2.1 | Our Corporate Strategy |
2.1.1 | Business Plan |
2.1.1The Ecopetrol Group’s 2020 - 2022 Business Plan
Ecopetrol’s 2019 – 2021 (the “Business Plan”) maintainsPlan) is aligned with the strategic priorities set forthof achieving profitable and sustainable growth, using strict capital discipline and cash flow protection, taking into consideration the challenges posed by energy transition, climate change, respect for the environment and biodiversity, the protection and responsible use of water, and the inclusion of an innovation and technology component, leveraging the integrated value generation for the Group.
The Plan includes investments between US$13 and US$17 billion, most of which will be invested in the previous 2020 plan: we continue to prioritize profitableColombia, aimed at continuing reserves and production growth, underpinned by strict capital disciplinethe search and continued focus on cost efficiencydevelopment of investment opportunities to leverage portfolio diversification, and cash flow generation. The plan seeks to maximize value generation for our shareholders with continued focus on our incumbent position in Colombia, ensuring sustainability, competitiveness and profitability.
Among other matters, the Business Plan calls for achieving the following targets by the end of 2021: (i) organic production levels between 750-770 mboed, (ii) optimum throughputcontinuity of the integrated refining system at a level between 370-400 mbpd, (iii) increasing transported volumes in lineoperations. Furthermore, the Plan provides for increased operational sustainability with the country’s production, (iv) investing approximately US$12-15 billion during the periodspecific goals of decarbonization, increased use of renewable energy and (v) maintaining a robust cash position and optimal leverage levels.digital transformation. The Business Plan is based on a referenceBrent price of US$65/bl.57/Bl.
GrowthInvestments in reserves and production will be supported by four levers: (i)growth (58%) are focused on continuing the growthprofitable development of our recovery factorsexisting assets and underlying hydrocarbonsaddressing the transition to gas. Investments in placeoperational continuity (26%) are aimed at preserving the value of the assets and providing reliability and integrity to the operation, and the remaining (16%) of investments will boost innovation and technology and decarbonization goals.
Some of the most relevant operational goals of the Plan are expected to: (i) reach organic production levels of between 745 - 800 thousand barrels of oil equivalent per day, (ii) maintain the replacement rate of organic reserves above 100%, without price effect, (iii) realize throughput between 370 - 420 thousand barrels per day for the integrated refining system, (iv) achieve between 1.10 - 1.25 million barrels per day of volumes transported, in existingline with the expected country’s production and demand for liquid fuels, (v) reduce emissions between 1.8 and 2.0 million metric tons of carbon dioxide equivalent (MmtCO2e) in 2020 and (vi) install approximately 300 Megawatts of renewable energy sources.
Upstream
The Plan allocates 83% of total investments to the upstream segment, prioritizing the development of the Group’s position in strategic assets such as thePiedemonte and Rubiales fields (ii)as well as others in the diversification of our exploration portfolio in Colombia, (iii)Middle Magdalena Valley and key regions such as Brazil and the internationalization of our operations through both organic and inorganic means, and (iv)Permian Basin. Furthermore, the appraisalmaturation and development of identified unconventional hydrocarbon potential in Colombia.
We estimate that by 2021 hydrocarbons originally in place (HCIIP) associated to our assetsimproved recovery activities will continue. The Plan allocates 72% of upstream investments on projects in Colombia while the remainder 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.
Growthinvested 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, andfurther developing the potential of our operations in the offshore Caribbean.Group's international operations.
The internationalization lever seeks to develop and maximize the potential 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, subject to government approval. If successful, we would then move to the commercial development 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, 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.
In ourterms of exploration, the Plan provides for drilling more than 30 exploratory wells located in the most relevant basins, focused mostly in Colombia and implementing an important seismic survey program. Additionally, the Group expects to continue with the evaluation and development of the offshore gas discoveries made in the Colombian Caribbean through investments totaling US$200 million.
In relation to unconventional reservoirs, the maturation of the initiatives associated with the Comprehensive Research Pilot Project (Proyectos Piloto de Investigación Integral or PPII as per its Spanish acronym) in the Middle Magdalena Valley Basin will continue, and development activities in the Permian Basin in Texas increase.
Downstream
The Plan allocates 11% of investments to the downstream segment, (or “refining, petrochemicals, and biofuels segment”), the Business Plan focusesfocusing on the use and optimization of the current infrastructure in orderinfrastructure. To this end, we plan to achieve an expected refining throughput between 370-400 mbpdconduct major maintenance and an expectedtechnological updates at the Cartagena and Barrancabermeja refineries as well as implement the CartagenaRefinery’s Original Crude Unit interconnection project. We also plan to expand the Esenttia plant by 70 thousand tons of polypropylene per year. A gross refining margin of between US$12-15/bl, subject10 - US$15 per barrel is expected, with periods of significant volatility.
In an effort to market conditions.move forward with the production of cleaner fuels for the country, the investments made during the 2020 - 2022 period will consolidate the quality of domestic diesel to between 10 to 15 ppm of sulphur and reduce the sulphur in gasoline to a maximum of 50 ppm. Moreover, we anticipate initiating a project designed to reach levels below 10 ppm in both fuels in the medium term. We expectalready report this quality level for domestic diesel, including the diesel used by mass transport systems such asTransmilenio in Bogotá.
Midstream
The Plan includes allocating 5% of investments to achieve this (i) throughsegment, focused on improving efficiency and synergies in the incorporation of synergies between the Barrancabermeja and Cartagena refineries and (ii) bytransportation system as well as capturing marketinvestment opportunities in multi-purpose pipelines 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 contentincrease in maritime transport. Additionally, asdomestic fuel demand. To this end, we did in 2018, we expectforesee investments totaling US$300 million. This segment is expected 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.to be an important cash generator.
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 2019Technology and 2021, particularly: (i) capital expenditure efficiencies, (ii) revenue and margin optimization and (iii) operating expenditure efficiencies.Innovation
In terms of sustainability,technology, our efforts will focus on realizing the Businessfeasibility of enhanced oil recovery and unconventional hydrocarbons projects in an effective, environmentally and socially sustainable manner, increasing flexibility and logistical efficiency for the transportation of heavy crudes and increasing energy efficiency, among others. Additionally, we plan to complete the ten key projects on our digital agenda that seek to maximize production, improve the commercialization and refining margin, and digitize financial management.
Emission reduction and water management
In line with the Group’s objectives of reducing the carbon emissions associated with its operations, as well as reducing the vulnerability of its operation and infrastructure to climate change, the Plan callsallocates between US$320 and US$430 million for integralinvestments in projects that help reduce carbon emissions between 200 and 400 kilotons of carbon dioxide equivalents (KtCO2e), in order to reach an annual reduction of between 1.8 and 2.0 million of tons of carbon dioxide equivalents (MtCO2e) in 2022.
In order to enhance integrated water management, wastewater reuse, water security and water governance, the protection of biodiversity and a continued focus on climate change, among others, all within the framework of the United Nations Sustainable Development Goals 2030. We expect to invest approximately COP$2 trillion in socio-environmental projects between 2019 and 2021. We are also seeking to reduce our energy costs by US $100 million by 2021 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.
We currently expect the Business Plan to requireallocates investments of between US$12-15 billion during100 and US$150 million in wastewater treatment and final water disposal wells and to provide potable water and sanitation to 900,000 in 40 prioritized municipalities.
Social and Environmental Investment
The Plan expects to allocate between US$350 and US$400 million in funds to our socio-environmental program, designed to help close socioeconomic gaps in Colombia and boost sustainable community development and wellbeing. The priority areas for the 2019-2021 period, of which approximately 82% would be allocated to the upstream segment, 8% to the midstream segment, 7% to the downstream segmentsocio-environmental investment program are public and 3% to other. These investments exclude inorganic growth opportunities, which if materialized, could be financed through cash from operations.community infrastructure, public services, education, sports and health, rural development and business entrepreneurship.
The Business Plan seeks to maintain leverageleveraging metrics to help us preserve ourin line with the Company’s investment grade rating while allowing flexibility for specific optimizations of our capital structure during the period.and competitive vis-à-vis industry peers.
2.1.22019 InvestmentThe Plan emphasizes Ecopetrol's commitment to a safe and sustainable operation, while protecting the environment and the communities in the areas where it operates, and ensuring the satisfaction of its employees, conditions that will help create shared prosperity and constructive dialogue with all its stakeholders.
2.1.2 | 2020 Investment Plan |
In November 2018,2019, the Board of Directors approved between US$3.54.5 and US$4.05.5 billion for the 20192020 investment plan.plan at US$57/Bl Brent. The Ecopetrol Group plans to produce between 720745 and 730760 thousand barrels of oil equivalent per day during 2019. 2020. Ecopetrol expects to allocate 78% percent of these investments to projects in Colombia and the remainder to positioning and developing the Ecopetrol Group’s operations in the United States, Mexico and Brazil.
OnMarch 16, 2020, Ecopetrol announced a set of actions to address current challenging market conditions, which have resulted, among other matters, in a 60% decline in the Brent crude price as compared to the end of 2019, due to external shocks including the strong increase in the supply of oil and the spread of COVID-19. These measures are part of a phased intervention plan that aims for the Company to adapt in a timely and orderly manner to changing market conditions.
The first stage of this plan includes the following actions:
i. | Effective immediately, a COP$2 trillion cutback in costs and expenses to strengthen Ecopetrol’s competitiveness, including austerity measures, prioritization of operational and administrative activities, and control over operational expenses, such as travel restrictions, sponsorships and involvement in events, among others. |
ii. | Implementation of new commercial strategies to maximize the value of the crudes and products sold by the Ecopetrol Group. |
iii. | A US$1.2 billion decrease in the 2020 investment plan so that the new range of the investment plan is now US$3.3 - 4.3 billion. The measures adopted aim to intervene in investment opportunities in the early stages, seeking to preserve production and cash flow and maintain the integrity and reliability of investments, including social investment commitments already made. |
iv. | Regarding the Earnings Distribution Proposal reported to the market on March 2, 2020, the Board of Directors proposed a new payment scheme consisting of the following: a first payment of 100% of the dividend to minority shareholders and 14% of the dividend to the majority shareholder, to be made on April 23, 2020, and the payment of the remaining 86% of the dividend to the majority shareholder to be disbursed during the second half of 2020. |
The production target for 2020 set forth above remains unchanged as of phase one, between 745 - 760 mboed. See the section entitledTrend Analysis and Sensitivity Analysis—Trend Analysis for further information.
Ecopetrol will continue to monitor market developments to determine the need to launch subsequent stages of the intervention plan, seeking to optimize the balance between decisive responses under current market conditions and preservation the Company's long-term value.
The table below sets forth the details of the initial investment plan per business segment.segment announced in November 2019 (which has now been modified as described above):
Table 3 – 20192020 Investment Plan(1)
Business Segment |
| %Percentage(2) | ||||||
Exploration | % | |||||||
Production | % | |||||||
Midstream | 7 | % | ||||||
Downstream | 11 | % | ||||||
Other | 2 | % | ||||||
TOTAL | 100 | % |
(1) |
(2) | Percentage over the upper |
Exploration
In the exploration, segment, US$430-US$490 millioninvestment has been allocated mainly to the evaluation and appraisal of discoveries and ongoing exploration activity of Ecopetrol S.A. (approximately 44%35%), Hocol S.A. (“Hocol”)(Hocol) (approximately 12%9%), Ecopetrol America Inc.LLC (approximately 1%2%), ECP Hidrocarburos Mexico (approximately 7%), Ecopetrol Costa Afuera (approximately 3%) and Ecopetrol Brazil (approximately 33%47%).
Production
In the production segment, US$2,385-US$2,725 millioninvestment has been allocated mainly to the executiondevelopment of development and incremental production projects of Ecopetrol S.A. (approximately 91%75%) primarily at Castilla, Rubiales, Chichimene, Apiay-Suria, Yariguí-Cantagallo, La Cira-Infantas,Llanito, Casabe, Piedemonte and Quifa. We haveCaño Sur fields. In addition, Ecopetrol plans to spend approximately 19% of the funds allocated in the production investment plan in the Permian project as described below. Ecopetrol also has allocated funds for ourits affiliates and subsidiaries as follows: approximately 3%2% for the development, operation and maintenance of fields of Ecopetrol America Inc.LLC in the U.S. Gulf of Mexico and approximately 5%4% to Hocol, approximately 1% to Equion and Savia.Hocol.
Midstream
In the midstream segment, US$240-US$275 million hasresources have been allocated to investments focused onimprove system and operational integrity. The segment seeks to strengthen its profitability by means of higher transported volumes through oil and multi-purpose pipelines and better operating results. These investments are expected to optimize future operating costs due to equipment upgrades and performance improvement.
Downstream
In the downstream segment, investment has been primarily allocated to the Barrancabermeja and Cartagena refineries through initiatives aimed at optimizing maintenance costs, enhancing integrity management, and improving the quality of diesel and gasoline. The segment is seeking a higher efficiency in operations 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.
Environmental, Social and Governance (ESG) and Digital Transformation
Ecopetrol expects to invest US$150 million in energy transition and carbon emission reduction in 2020. The Plan includes funding for the medium-term socio-environmental investment program, with an expected investment ofbetween US$350 and US$400 million for the upcoming three years, aimed at helping close socioeconomic gaps in Colombia and boosting sustainable community development and wellbeing.
To strengthen the digital transformation, Ecopetrol expects to allocate US$91 million in 2020 toward capturing benefits associated with artificial intelligence, blockchain and bot technologies, among others. Ecopetrol expects to invest an additional US$35 million in leveraging new innovation processes, including creating strategic alliances and innovation ecosystems.
3. | Business Overview |
3.1 | Our History |
We were formed in 1951 by the Colombian government asEmpresa Colombiana de Petróleos and began operating the crude oil fields at La Cira-Infantas, the oldest Colombian oil field, where production started in 1918, and the pipeline that connected that field with the Barrancabermeja refinery and the port of Cartagena. In 1961, we assumed the direct operation of the Barrancabermeja refinery and continued its transformation into an industrial complex. In 1974, we acquired the Cartagena 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-holding corporation, one hundred percent state-owned, and continued the development of exploration and production activities in a competitive basis with autonomy over our business decisions. Since 2006, according to Law 1118, we have been evolving from a wholly state-owned entity to a mixed-economy company with private capital. This process has resulted in a substantial change in the legal framework to which we are subject and in the nature of our relationship with the Nation, as our controlling shareholder. As of March 23, 2018, pursuant to our amended bylaws, the duration of the Company is 100 years.
We carried out our initial public offering in November 2007, when our common shares were listed on the Colombian Stock Exchange. Our American Depository Shares (“ADSs”)(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”)(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.
Our subsidiaries, Refinería de Cartagena S.A. (“Reficar”S.A.S. (Reficar or “Cartagena Refinery”)Cartagena Refinery), Cenit Transporte y Logistica de Hidrocarburos S.A.S. (Cenit) and Oleoducto Central S.A. (Ocensa) are significant subsidiaries, as such term is defined under SEC Regulation S-X.
We have a number of directly and indirectly held subsidiaries both in Colombia and abroad. Our subsidiaries are either directly owned by us or indirectly owned by us through one or more of our other subsidiaries. As of December 31, 2018,2019, we have seven directly owned and 2922 indirectly owned subsidiaries.
During 2018,2019, the following changes were made to the Ecopetrol Group’s structure:
i. | We formed a joint venture (JV) with Occidental Petroleum Corp for the development of unconventional reservoirs in approximately 97,000 acres in the Midland Basin, within the Permian Basin, Texas, by which we acquired 49% of Rodeo Midland Basin LLC (Rodeo). We have joint control over Rodeo, and, for that reason, we recognize the proportionate share of the assets, liabilities, revenues and expenses associated with Rodeo. The information we present throughout this annual report with respect to Rodeo represents such proportionate share. To develop the JV, we incorporated two new companies: (i) Ecopetrol |
ii. |
iii. | We became the controlling shareholder of Inversiones de Gases de Colombia S.A. (“Invercolsa”), due to the decision of the Colombian Supreme Court of Justice that returned 145 million ordinary shares of this company to Ecopetrol, thus increasing our equity interest from 43.35% to 51.88%. |
iv. | On March 10, 2020, Bioenergy and Bioenergy Zona Franca S.A.S, were admitted to reorganization processes by the Superintendence of Companies under Law 1116 of 2006, which will allow them to organize financial, administrative and operational aspects to preserve their sustainability. Those entities are not material subsidiaries and therefore these processes are not expected to have a material adverse effect on Ecopetrol’s results of operations or financial condition. |
9
Graph 2 – Ecopetrol Corporate Structure
The stock ownership percentage listed refers to Ecopetrol S.A.’s direct and indirect participation. The data in this structure shows neither the whole ownership nor its decimal figures, so they will be used only for information purposes.
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 | Our Business |
We are a vertically integrated oil and gas company with a presence primarily in Colombia and with activities in Peru, Brazil, Mexico and the U.S. Gulf Coast. The Nation currently controlsowns 88.49% of our voting capital stock. We are among the world’s biggest state-ownedlargest public companies, ranking 300 based on the Forbes Global 2000 Ranking - 2018.2019. We play a key role in the local Colombian hydrocarbon market.
3.4 | Exploration and Production |
Our exploration and production business segment includes exploration, development and production activities in Colombia and abroad. We began local exploration in 1955 and international exploration in 2006. Exploration and production activities are conducted directly by Ecopetrol S.A., and through some of our subsidiaries, as well as through joint ventures with third parties. As of December 31, 2018,2019, we were the largest operator and the largest producer of crude oil and natural gas in Colombia, maintaining the largest acreage exploration position in Colombia.
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.
3.4.1 | Exploration Activities |
Under the framework of the Business Plan, Ecopetrol is aiming to incorporate contingent resources in high reward projects concentrated in: (i) near field exploratory activity, (ii) underexplored basins, such as Putumayo and Piedemonte, (iii) offshore Colombia, and (iv) international areas such as offshore Brazil at Pre-salt Santos, Ceara and Foz de Amazonas basins, the U.S. Gulf of Mexico and Mexico.Offshore Mexico in the Salinas Basin.
Graph 3- Sedimentary Basinsbasins where Ecopetrol executes exploration activities
During 2018,2019, the exploration strategy was directed at leveraging our goal on three working fronts: onshore Colombia, offshore Caribbean, and strengthening and diversifying our exploration overseas.
3.4.1.1 |
The Ecopetrol Group was awarded ten exploration blocks by the National Hydrocarbons Agency (ANH) during the 2019 bidding round process. Three of these were awarded to Ecopetrol S.A, the Gua-Off 10 Block located in the Colombian Caribbean offshore and two blocks in the Llanos Basin. The remaining seven blocks were awarded to our subsidiary Hocol.
During 2018,2019, Ecopetrol and its subsidiaries conducted drilling operationsdrilled nineteen (19) wells in twelve exploration wellsColombia, of which fifteen (15) were exploratory (A3/A2) and in fivefour (4) appraisal wells (A1) in Colombia. Of these seventeenSeven (7) wells six were successful, sevennine (9) were plugged and abandoned, and fourthree (3) were under evaluation as of December 31, 2018.2019. 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.
In terms of onshore Colombia, our exploration efforts were focused on searching for hydrocarbons in mature basins, near-field exploration and areas close to existing production infrastructure.
In offshore activities, we increased our participation from 50% to 100% in theFuerte Sur and Purple Angel blocks (Sinu offshore basin), which were relinquished by Anadarko Petroleum Corporation. In the case of the block Col-5 (Sinu offshore basin), the ANH approved the conversion of a Technical Evaluation Agreement (as defined below) to an Exploration and Production Contract (as defined below), where we have a 100% participation.Piedemonte.
The following table sets forth, for the periods indicated, the number of gross and net productive and dry exploratory wells drilled by us and our joint venture partners, and the exploratory wells drilled by third parties pursuant to sole risk contracts with us.
Table 4 – Exploratory Drilling in Colombia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(number of wells) | (number of wells) | |||||||||||||||||||||||
COLOMBIA | ||||||||||||||||||||||||
Ecopetrol S.A. | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Owned and operated by Ecopetrol | ||||||||||||||||||||||||
Productive | – | – | – | 1.0 | – | – | ||||||||||||||||||
Dry(1) | – | 1.0 | 1.0 | 1.0 | – | 1.0 | ||||||||||||||||||
Total | – | 1.0 | 1.0 | 2.0 | – | 1.0 | ||||||||||||||||||
Operated by Partner in Joint Venture | ||||||||||||||||||||||||
Productive | 5.0 | 3.0 | – | 4.0 | 5.0 | 3.0 | ||||||||||||||||||
Dry | 1.0 | 2.0 | – | 1.0 | 1.0 | 2.0 | ||||||||||||||||||
Total | 6.0 | 5.0 | – | 5.0 | 6.0 | 5.0 | ||||||||||||||||||
Operated by Ecopetrol in Joint Venture | ||||||||||||||||||||||||
Productive | – | – | – | – | – | – | ||||||||||||||||||
Dry | – | 1.0 | – | – | – | 1.0 | ||||||||||||||||||
Total | – | 1.0 | – | – | – | 1.0 | ||||||||||||||||||
Net Exploratory Wells(2) | ||||||||||||||||||||||||
Productive | 1.9 | 1.5 | – | 2.8 | 1.9 | 1.5 | ||||||||||||||||||
Dry | 0.3 | 2.3 | 1.0 | 1.4 | 0.3 | 2.3 | ||||||||||||||||||
Total | 2.2 | 3.8 | 1.0 | 4.2 | 2.2 | 3.8 | ||||||||||||||||||
Sole Risk | ||||||||||||||||||||||||
Productive | – | – | – | 1.0 | – | – | ||||||||||||||||||
Dry | 2.0 | – | – | 5.0 | 2.0 | – | ||||||||||||||||||
Total | 2.0 | – | – | 6.0 | 2.0 | – | ||||||||||||||||||
ECAS | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Productive | – | – | – | |||||||||||||||||||||
Dry | – | – | 1.0 | |||||||||||||||||||||
Total | – | – | 1.0 | |||||||||||||||||||||
Net Exploratory Wells | ||||||||||||||||||||||||
Productive | 2.8 | – | – | |||||||||||||||||||||
Dry | 1.4 | – | 0.5 | |||||||||||||||||||||
Total | 4.2 | – | 0.5 | |||||||||||||||||||||
Equion | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Productive | – | – | – | |||||||||||||||||||||
Dry | – | – | – | |||||||||||||||||||||
Total | – | – | – | |||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Productive | 1.0 | 1.0 | – | |||||||||||||||||||||
Dry | 2.0 | 4.0 | 1.0 | |||||||||||||||||||||
Total | 3.0 | 5.0 | 1.0 | |||||||||||||||||||||
Net Exploratory Wells | ||||||||||||||||||||||||
Productive | 0.5 | 1.0 | – | |||||||||||||||||||||
Dry | 2.0 | 3.2 | 1.0 | |||||||||||||||||||||
Total | 2.5 | 4.2 | 1.0 |
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) | Net exploratory wells were calculated according to our percentage of ownership in these wells. |
Ecopetrol drilled sixseven (7) successful wells in Colombia in 2018:2019 (i) Jaspe 6D,Jaspe-8, where Ecopetrol holds a 30% working interest, and Frontera as the operator holds the remaining 70% working interest at the Quifa block,Block, (ii) Andina-1,Andina Norte-1, where Ecopetrol holds a 50% working interest, and Parex Resources as the operator holds the remaining 50% working interest at the Capachos block,Block, (iii) Rex NE-02 ST-1,Boranda-2 ST1, where Ecopetrol holds a 50% working interest, and Parex Resources as the operator holds the remaining 50% working interest at the Playon Block, (iv) Cosecha CW-01-ST, where Ecopetrol holds a 30% working interest, and Occidental Petroleum Corporation as the operator holds the remaining 70% working interest at the Cosecha block, (iv) Andina-2,Block, (v) Boranda-3 where Ecopetrol holds a 50% working interest, and Parex Resources as the operator holds the remaining 50% working interest at the 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 andPlayon Block, (vi) Arrecife-1, where our subsidiary Hocol owns a 100% working interest in the VIM-8 block.
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,Flamencos-1 operated by our subsidiary HocolEcopetrol 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,VMM Block, and (vii) Bullerengue-3, 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.
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, holdingthrough its subsidiary Hocol, and Lewis as the operator holds the remaining 50%, (iii) Coyote-2 located working interest 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%.Sinú San Jacinto Block.
Seismic
In Colombia, our subsidiary Hocol S.A.we acquired a total of 3372,000 km2 of 2D3D seismic offshore in the SN 15 blockCol-5 Block, and through our joint venture partner, Ismocol-Joshi-Parko, 60Parex Resources, 174 km2 of 3D seismic onshore which were acquired overin the Palagua-CaipalFortuna field.
Furthermore, Ecopetrol purchased threefour additional 3D seismic surveys for a total of 292.51,370 km2 in theEastern Plains (Llanos Orientales) and Putumayo basin to improve the subsurface coverage and imagingtechnical understanding of the basin.these prolific basins.
3.4.1.2Exploration Activities Outside Colombia
3.4.1.2 | 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 operational experienceexpertise and technology into the consortium.technology.
In partnershipEcopetrol Óleo e Gás do Brasil Ltda. has secured an agreement with BPShell Brasil Petróleo Ltda. to acquire 30% of the interests, rights and CNOOC, Ecopetrol was awarded the block Pau-Brazilobligations in the Santos Basin in Brazil during the Pre-Salt 5th bidding round, organized by the National Agencytwo areas of Petroleum, Natural Gas and Biofuels (ANP). Moreover, Ecopetrol is awaiting approval from the ANP to access a 10% working interest in offshore block Saturno, also located in the Santos basin, which is operated byoffshore in Brazil, to pursue Pre-Salt play. One of these blocks includes the Gato do Mato discovery. Under this agreement, Shell (who holds a 45% working interest) in partnership with Chevron (who holdswill reduce its stake from 80% to 50% and continue as operator, while the French company Total will retain the remaining 45% working interest)20%. 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 partMoreover, during the 252 Gulf of the committed 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.
AdditionallyMexico lease sale our subsidiary Ecopetrol America Inc., was awardedLLC acquired a 31.5% working interest in the Green Canyon 404, 405, 448 and 492 blocksMC 904 block located in the Gulf of Mexico during Lease Sale 251.of the United States, in consortium with Fieldwood Energy as the operator with a 58.94% working interest, and Talos Energy with a 9.56% working interest. Also, in 2019 Ecopetrol and its partners successfully drilled the Esox-1 well in the MC 627 block in the Gulf of Mexico, where Ecopetrol America LLC holds a 21.43% working interest, Hess Corporation as the operator holds a 57.14% working interest, and Chevron holds the remaining 21.43% working interest. The well is currently being tested, and results, so far, seem promising.
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 inAdditionally, Ecopetrol Hidrocarburos Mexico in 2020 andInc. is executing the exploration plan for block 8 considers seismic licensing, processing and the interpretation required to identify the potential prospects in the block.
During the course of 2018, Ecopetrol and its partners did not carry out any exploratory drilling outside Colombia.
Block 6. The following table sets forth information on our exploratory drilling for the periods indicated.
Table 5 – Exploratory Drilling Outside Colombia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(number of wells) | (number of wells) | |||||||||||||||||||||||
INTERNATIONAL | ||||||||||||||||||||||||
Ecopetrol America Inc. | ||||||||||||||||||||||||
Ecopetrol America LLC | ||||||||||||||||||||||||
Gross Exploratory Wells | ||||||||||||||||||||||||
Productive | – | – | 1.0 | 1.0 | – | – | ||||||||||||||||||
Dry(1) | – | 2.0 | – | – | – | 2.0 | ||||||||||||||||||
Total | – | 2.0 | 1.0 | 1.0 | – | 2.0 | ||||||||||||||||||
Net Exploratory Wells(2)(3) | ||||||||||||||||||||||||
Productive | – | – | 0.2 | 0.2 | – | – | ||||||||||||||||||
Dry | – | 0.6 | – | 0.0 | – | 0.6 | ||||||||||||||||||
Total | – | 0.6 | 0.2 | 0.2 | – | 0.6 | ||||||||||||||||||
Ecopetrol Óleo e Gás do Brasil Ltda. | ||||||||||||||||||||||||
Gross Exploratory Wells | – | – | – | – | – | – | ||||||||||||||||||
Productive | – | – | – | – | – | – | ||||||||||||||||||
Dry | – | – | – | – | – | – | ||||||||||||||||||
Total | – | – | – | – | – | – | ||||||||||||||||||
Net Exploratory Wells | ||||||||||||||||||||||||
Productive | – | – | – | – | – | – | ||||||||||||||||||
Dry | – | – | – | – | – | – | ||||||||||||||||||
Total | – | – | – | – | – | – | ||||||||||||||||||
Ecopetrol Germany | ||||||||||||||||||||||||
Gross Exploratory Wells | – | – | – | – | – | – | ||||||||||||||||||
Productive | – | – | – | – | – | – | ||||||||||||||||||
Dry | – | – | – | – | – | – | ||||||||||||||||||
Total | – | – | – | – | – | – | ||||||||||||||||||
Net Exploratory Wells | ||||||||||||||||||||||||
Productive | – | – | – | – | – | – | ||||||||||||||||||
Dry | – | – | – | – | – | – | ||||||||||||||||||
Total | – | – | – | – | – | – | ||||||||||||||||||
Savia Perú | ||||||||||||||||||||||||
Gross Exploratory Wells | – | – | – | – | – | – | ||||||||||||||||||
Productive | – | – | – | – | – | – | ||||||||||||||||||
Dry | – | – | – | – | – | – | ||||||||||||||||||
Total | – | – | – | – | – | – | ||||||||||||||||||
Net Exploratory Wells | ||||||||||||||||||||||||
Productive | – | – | – | – | – | – | ||||||||||||||||||
Dry | – | – | – | – | – | – | ||||||||||||||||||
Total | – | – | – | – | – | – |
(1) | A dry well or hole is an exploratory well found to be incapable of producing either crude oil or natural gas in sufficient quantities to justify completion as a crude oil or natural gas well. |
(2) | Net exploratory wells are calculated according to our percentage of ownership in these wells. |
(3) | None of our international wells were drilled pursuant to a sole risk contract. |
Seismic
Our subsidiary, Ecopetrol Brazil, purchased 874 km of 2D (spectrum survey) and 5,441 kminvested in new 3D seismic data obtaining 12,314 Km2 3D (CGG and PGS) to mainly 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 locatedPre-Salt bidding rounds in the pre-salt play over the Santos and Campos basins.basins (Transfer of Rights, Round 16 and Round 6). In addition, it purchased 2,660 Km of 2D seismic to fill information gaps and 12,000 Km of 2D seismic to carry out the regional studies.
Ecopetrol Hidrocarburos Mexico Inc. procured a large 60,076 km 2D seismic survey and 11,009acquired the license for 88,015 km2 of 3D seismic data (surveys:from the Campeche Sur, Campeche Somero and Tabasco), to evaluate the Salina basin in the Gulfprogram for a period of Mexico.
3.4.2 Production Activities24 months.
3.4.2 | Production Activities |
Our consolidated average production was 720.4725 thousand boepdbarrels of oil equivalent per day (boepd) in 2018,2019, an increase of approximately 54.7 thousand boepd as compared to 2017. 2018.This increase is mainlygrowth was primarily due to the resultpositive results in the Akacias, Yarigui, Caño Sur, Rubiales, and Chichimene fields, the greater commercialization of an increase in upstream investments during 2018.
gas, mostly from the Cupiagua and Floreña fields and the entry into operation of the Cupiagua LPG Plant.
The following table summarizes the results of our oil and gas production activities for the periods indicated:
Table 6 – Ecopetrol Group’s Oil and Gas Production
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Oil | Gas(1) | Total | Oil | Gas(1) | Total | Oil | Gas(1) | Total | Oil | Gas(1) | Total | Oil | Gas(1) | Total | Oil | Gas(1) | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
(thousand boepd) | (thousand boepd) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total production in Colombia(2) | 578.4 | 125 | 703.4 | 577.3 | 121.6 | 698.9 | 582.5 | 123.3 | 705.8 | 576.6 | 130.5 | 707.1 | 578.4 | 125 | 703.4 | 577.3 | 121.6 | 698.9 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total International production(3) | 14.1 | 2.9 | 17.0 | 13.6 | 2.6 | 16.2 | 9.6 | 2.5 | 12.1 | 15 | 3.0 | 18 | 14.1 | 2.9 | 17.0 | 13.6 | 2.6 | 16.2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total production of Ecopetrol Group | 592.5 | 127.9 | 720.4 | 590.9 | 124.2 | 715.1 | 592.1 | 125.8 | 717.9 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total production of Ecopetrol Group (Gross) | 591.6 | 133.5 | 725.1 | 592.5 | 127.9 | 720.4 | 590.9 | 124.2 | 715.1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total production of Ecopetrol Group for presentation of reserves(4) | 528.9 | 133.7 | 662.6 | 524.3 | 129.8 | 654.1 | 515.1 | 126.9 | 642.0 |
(1) | Conversion between |
(2) | Total production in Colombia corresponds to Ecopetrol S.A., Hocol and Equion. Includes royalties |
(3) | Total International production corresponds to Rodeo Midland Basin LLC; Savia Perú and Ecopetrol America |
(4) | For the Company’s presentation of reserves, the Company deducts from its total gross production the 100% of crude royalties from Ecopetrol Group companies and gas royalties from non-Colombian Ecopetrol Group companies, Savia Perú S.A. (Peru), Rodeo Midland Basin LLC (United States) and Ecopetrol America LLC (United States). Gas royalties derived from Colombian production are not deducted because according to local regulation the Company is entitled to such gas royalties. Also includes self-consumption, which is only comprised of natural gas self-consumption and is immaterial. |
3.4.2.1 Production Activities in Colombia
3.4.2.1 | Production Activities in Colombia |
3.4.2.1.1 | Ecopetrol S.A.’s Production Activities in Colombia |
3.4.2.1.1Ecopetrol S.A.’s Production Activities in Colombia
For the year ended December 31, 2018,2019, Ecopetrol S.A. was the largest participant in the Colombian hydrocarbons industry, accounting for approximately 63%62% of crude oil production (according to calculations made by Ecopetrol based on information from the Ministry of Mines and Energy) and approximately 66%62% of natural gas production (according to calculations made by Ecopetrol based on information from the Ministry of Mines and Energy). Also during 2018,2019, Ecopetrol S.A. carried out development drilling mainly in the Eastern and Orinoquia regions, drilling 528571 development wells (226(298 of those through direct operations and 302273 through joint ventures).
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:vice-presidencies:
· | Central Region: comprising |
· | Orinoquía Region: comprising |
· | Southern Region: comprising 33 fields with active production in |
· | Eastern Region: comprising 2 fields with active production in |
· | Piedemonte Region: comprising 6 fields with active production in 2019. |
A fifth Vice-Presidency,sixth vice-Presidency, the Vice-Presidency of Associated Operations, is responsible for all of the production activities in which a partner is involved, regardless of the location of such activities in Colombia. This Vice- Presidency is comprised of 126123 fields with active production in 2018.2019. On February 10, 2020, a new Vice-Presidency of Gas was created in order to lead and execute the Ecopetrol Group’s integrated natural gas strategy.
The map below shows the locations of Ecopetrol S.A.’s operations with production information for each of our administrative regions described in the following paragraphs.
Graph 4 – Ecopetrol S.A. Operations in Colombia
Note: VAS isAssociated Operations are conducted through a countrywide Vice-presidency.Vice-presidency of Associated Operations.
Crude Oil Production
Crude Oil Production
The average daily production of crude oil in Colombia by Ecopetrol S.A. (excluding its subsidiaries), was 548.7548.0 mbod in 2018, 3.72019, 0.7 mbod higherlower than in 2017,2018, which represents a year-to-year increasedecrease of 0.7%0.1%.
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.
Table 7 – Ecopetrol S.A.’s Average Daily Crude Oil Production in Colombia by Region Vice-Presidency
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(thousand bpd) | (thousand bpd) | |||||||||||||||||||||||
Central Region | ||||||||||||||||||||||||
1) La Cira – Infantas | 28.1 | 22.6 | 19.1 | 25.9 | 28.1 | 22.6 | ||||||||||||||||||
2) Casabe | 13.9 | 15.9 | 17.8 | 13.2 | 13.9 | 15.9 | ||||||||||||||||||
3) Yarigui | 14.4 | 14.5 | 16.6 | 17.9 | 14.4 | 14.5 | ||||||||||||||||||
4) Other | 17.3 | 18.5 | 21.3 | 15.9 | 17.3 | 18.5 | ||||||||||||||||||
Total Central Region | 73.7 | 71.5 | 74.8 | 72.9 | 73.7 | 71.5 | ||||||||||||||||||
Orinoquía Region | ||||||||||||||||||||||||
1) Castilla | 113.9 | 114.1 | 121.3 | 114.1 | 113.9 | 114.1 | ||||||||||||||||||
2) Chichimene | 67.7 | 70.5 | 74.0 | 69.1 | 67.7 | 70.5 | ||||||||||||||||||
3) Cupiagua | 8.3 | 9.6 | 11.3 | |||||||||||||||||||||
4) Other | 25.5 | 24.3 | 18.3 | |||||||||||||||||||||
3) CPO-09(2) | 10.9 | 4.5 | 3.1 | |||||||||||||||||||||
4) Cupiagua | 7.2 | 8.3 | 9.6 | |||||||||||||||||||||
5) Apiay(2) | 7.3 | 7.6 | 8.5 | |||||||||||||||||||||
6) Other | 12.9 | 13.4 | 12.7 | |||||||||||||||||||||
Total Orinoquía Region | 215.4 | 218.5 | 224.9 | 221.5 | 215.4 | 218.5 | ||||||||||||||||||
Eastern Region | ||||||||||||||||||||||||
1) Rubiales(1) | 119.5 | 118.7 | 61.5 | |||||||||||||||||||||
2) Caño Sur(2) | 3.2 | 1.4 | 0.4 | |||||||||||||||||||||
1) Rubiales | 119.3 | 119.5 | 118.7 | |||||||||||||||||||||
2) Caño Sur | 4.5 | 3.2 | 1.4 | |||||||||||||||||||||
Total Eastern Region | 122.7 | 120.1 | 61.9 | 123.8 | 122.7 | 120.1 | ||||||||||||||||||
Southern Region | ||||||||||||||||||||||||
1) San Francisco | 6.0 | 6.2 | 6.5 | 6.2 | 6.0 | 6.2 | ||||||||||||||||||
2) Huila Area(3) | 3.5 | 3.1 | 7.4 | |||||||||||||||||||||
2) Huila Area(1) | 3.8 | 3.5 | 3.1 | |||||||||||||||||||||
3) Tello | 3.6 | 3.9 | 4.4 | 3.4 | 3.6 | 3.9 | ||||||||||||||||||
4) Other | 11.7 | 12.2 | 9.4 | 10.4 | 11.7 | 12.2 | ||||||||||||||||||
Total Southern Region | 24.8 | 25.4 | 27.7 | 23.8 | 24.8 | 25.4 | ||||||||||||||||||
Associated Operations | ||||||||||||||||||||||||
1) Rubiales(1) | – | – | 41.4 | |||||||||||||||||||||
1) Piedemonte(2) | 18.3 | 21.2 | 19.9 | |||||||||||||||||||||
2) Quifa | 21.2 | 18.8 | 19.6 | 20.5 | 21.2 | 18.8 | ||||||||||||||||||
3) Caño Limon | 25.3 | 22.2 | 23.3 | 25.7 | 25.3 | 22.2 | ||||||||||||||||||
4) Cusiana(4) | – | – | 2.6 | |||||||||||||||||||||
4) Nare(2) | 10.9 | 12.0 | 13.4 | |||||||||||||||||||||
5) Other | 65.6 | 68.5 | 75.9 | 30.6 | 32.4 | 35.2 | ||||||||||||||||||
Total Associated Operations | 112.1 | 109.5 | 162.8 | 106.0 | 112.1 | 109.5 | ||||||||||||||||||
Total average daily crude oil production Ecopetrol S.A. (Colombia) | 548.7 | 545.0 | 552.1 | 548.0 | 548.7 | 545.0 |
(1) |
Huila Area: some assets were reclassified and are reported under Other in the Southern Region. |
In respect of our annual reports on form 20-F for the |
Table 8 – Ecopetrol S.A. Production per Type of Crude
2018 (mbod) | Year-on- Year ∆(%) | 2017 (mbod) | Year-on- Year ∆(%) | 2016 (mbod) | 2019 (mbod) | Year-on-Year ∆ (%) | 2018 (mbod) | Year-on- Year ∆ (%) | 2017 (mbod) | |||||||||||||||||||||||||||||||
Light | 40.7 | (4.0 | )% | 42.4 | (4.9 | )% | 44.6 | 36.5 | (10.3 | )% | 40.7 | (4.0 | )% | 42.4 | ||||||||||||||||||||||||||
Medium | 154.4 | 1.8 | % | 151.6 | (6.1 | )% | 161.5 | 150.3 | (2.7 | )% | 154.4 | 1.8 | % | 151.6 | ||||||||||||||||||||||||||
Heavy | 353.6 | 0.7 | % | 351.0 | 1.4 | % | 346.0 | 361.2 | 2.1 | % | 353.6 | 0.7 | % | 351.0 | ||||||||||||||||||||||||||
Total | 548.7 | 545.0 | 552.1 | 548.0 | 548.7 | 545.0 |
Ecopetrol S.A.’s crude oil production during 2018 consisted of2019 was approximately 36%34% light and medium crudes and 66% heavy crudes. In 2018, approximately 36% of the crude oil production consisted of light and medium crudes, and 64% consisted of heavy crudes. In 2017, approximately 36% of the crude oil production consisted of light and medium crudes, and 64% consisted of heavy crudes. In 2016, approximately 37% of the crude oil production corresponded to light and medium crudes and 63% to heavy crudes.
Natural Gas Production
In 2018,2019, the average daily production of natural gas by Ecopetrol S.A. (excluding its subsidiaries) reached 112.5116.75 mboed, including natural gas liquids (“NGLs”)(NGLs), corresponding to a 1.4%3.8% increase in comparison to 20172018 production.
We have three main natural gas production fields,fields: Guajira, Cusiana and Cupiagua. InOn November 22, 2019, our subsidiary Hocol acquired Chevron’s interest in the Chuchupa and Ballena fields. The fields were operated by Chevron through the Guajira field, we have partnered with Chevron who operatesAssociation Contract (57% Ecopetrol and 43% Chevron). Under 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 partterms of the Cusiana unified exploitation plan. As a consequenceagreement, Hocol will acquire Chevron's stake and will take the position of operator. The transaction is subject to approval by the terminationColombian Superintendence of the Tauramena joint venture, Ecopetrol’s participation increased from 63.4% to 97.8%,Industry 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.Commerce.
Of our total natural gas production during the year ended December 31, 2018,2019, approximately 20%15% was supplied from the Guajira field, 31% from the Cusiana field, 24%31% from the Cupiagua field and the remaining 25%23% from other fields.
On October 29, 2019 the new Liquefied Petroleum Gas (LPG) plant of the Cupiagua field began operations. This plant is expected to produce between 7,000 and 8,000 LPG barrels per day. The plant produces LPG and other products such as natural gas liquids (NGL) and penthane (C5), which are used as a diluent of the heavy crudes produced in fields such as Castilla, Rubiales, Chichimene, CPO-09, Quifa and Caño Sur.
The following table sets forth Ecopetrol S.A.’s average daily natural gas production in Colombia, including NGLs, prior to deducting royalties, for the years ended on December 31, 2019, 2018 2017 and 2016.2017.
Table 9 – Ecopetrol S.A.’s Average Daily Natural Gas Production in Colombia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(thousand boepd) | (thousand boepd) | |||||||||||||||||||||||
COLOMBIA | ||||||||||||||||||||||||
Central Region | ||||||||||||||||||||||||
1) La Cira – Infantas | 0.16 | 0.15 | 0.17 | 0.12 | 0.16 | 0.15 | ||||||||||||||||||
2) Provincia | 1.96 | 2.41 | 3.09 | 1.58 | 1.96 | 2.41 | ||||||||||||||||||
3) Yarigui | 0.42 | 0.48 | 0.56 | 0.43 | 0.42 | 0.48 | ||||||||||||||||||
4) Gibraltar | 6.87 | 7.16 | 6.32 | 6.25 | 6.87 | 7.16 | ||||||||||||||||||
4) Other | 1.86 | 2.02 | 1.60 | |||||||||||||||||||||
5) Other | 1.68 | 1.86 | 2.02 | |||||||||||||||||||||
Total Central Region | 11.27 | 12.22 | 11.74 | 10.06 | 11.27 | 12.22 | ||||||||||||||||||
Orinoquía Region | ||||||||||||||||||||||||
1) Cupiagua | 26.97 | 25.29 | 28.72 | 36.45 | 26.97 | 25.29 | ||||||||||||||||||
2) Cusiana(1) | 34.73 | 31.97 | 15.98 | |||||||||||||||||||||
2) Cusiana | 35.72 | 34.73 | 31.97 | |||||||||||||||||||||
3) Other | 2.80 | 2.44 | 1.44 | 2.87 | 2.80 | 2.44 | ||||||||||||||||||
Total Orinoquía Region | 64.5 | 59.70 | 46.14 | 75.04 | 64.50 | 59.70 | ||||||||||||||||||
Southern Region | ||||||||||||||||||||||||
1) Huila Area | 0.13 | 0.10 | 0.64 | 0.09 | 0.13 | 0.10 | ||||||||||||||||||
2) Tello | 0.11 | 0.22 | 0.35 | 0.07 | 0.11 | 0.22 | ||||||||||||||||||
3) Other | 0.25 | 0.40 | 0.03 | 0.25 | 0.25 | 0.40 | ||||||||||||||||||
Total Southern Region | 0.49 | 0.72 | 1.02 | 0.41 | 0.49 | 0.72 | ||||||||||||||||||
Associated Operations | ||||||||||||||||||||||||
1) Guajira | 23.02 | 27.09 | 33.34 | 17.92 | 23.02 | 27.09 | ||||||||||||||||||
2) Cusiana(1) | 0.00 | 0.00 | 12.65 | |||||||||||||||||||||
2) Piedemonte(2) | 12.50 | 12.20 | 9.70 | |||||||||||||||||||||
3) Other | 13.21 | 11.29 | 11.10 | 0.82 | 1.01 | 1.59 | ||||||||||||||||||
Total Associated Operations | 36.23 | 38.38 | 57.09 | 31.24 | 36.23 | 38.38 | ||||||||||||||||||
Total Natural Gas Production (Colombia) | 112.49 | 111.02 | 115.99 | 116.75 | 112.49 | 111.02 |
Note: Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd.
(1) |
In the Southern Region, some assets that were previously part of the Huila area were reclassified as Other. |
(2) | In respect of our annual reports on form 20-F for the years ended December 31, 2018 and 2017, the Pidemonte and Nare Fields were included in “other” in years 2018 and 2017, whereas for this annual report, these fields are reported separately, and the figures for 2017 and 2018 have been adjusted. |
Projects to Increase Recovery Factor
Ecopetrol continues to invest in its recovery factor program in order to increase reserves and production. In 2018,2019, the recovery factor program increased proven reserves by 12994 million boe.
In 2019, secondary and tertiary recovery technologies contributed 219 mboed or 30% of the Ecopetrol Group’s total daily production, mainly from 30 fields, as compared to 29 fields in 2018. The fields that reported better results in injection efficiency and oil production correspond to both gas injection in Cupiagua, Cusiana and Pauto fields and water injection in La Cira, Yariguí, Chichimene and Casabe fields. Regarding both polymer injection and steamflood, there are currently projects under execution that are expected to have production results in the coming quarters.
US$9462 million was invested forin the execution of 6046 studies and 19eight pilots to reduce uncertainties, and mature these opportunities into projects in the medium or long term.and long-term. These pilots under assessment had a daily production of approximately 1715 mboed.
SecondaryDuring 2019, 17 fields had projects in execution in respect of secondary and tertiary recovery, technologies contributed 167 mboed or 23% of 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, awith an investment close to US$730 million. Additionally, final investment decision wasdecisions were taken in respect of the commencement of eightfor 11 new recovery projects, and 16 recovery projects are being structured based on the results of their correspondent pilots: (i) six water injection projects (Chichimene, Castilla, Suria, La Cira sands A 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.pilots.
Development Wells
The following table sets forth the number of gross and net development wells drilled in Colombia, both solely by Ecopetrol S.A. and with its joint ventures that reached total depth for the years ended December 31, 2019, 2018 2017 and 2016.2017.
Table 10 – Ecopetrol S.A.’s Gross and Net Development Wells in Colombia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(number of wells) | (number of wells) | |||||||||||||||||||||||
COLOMBIA | ||||||||||||||||||||||||
Central Region | ||||||||||||||||||||||||
Gross wells owned and operated by Ecopetrol | 12 | – | – | 85 | 12 | – | ||||||||||||||||||
Orinoquía Region | ||||||||||||||||||||||||
Gross wells owned and operated by Ecopetrol | 77 | 56 | 47 | 89 | 77 | 56 | ||||||||||||||||||
Southern Region | ||||||||||||||||||||||||
Gross wells owned and operated by Ecopetrol | 19 | – | – | 2 | 19 | – | ||||||||||||||||||
Eastern Region | ||||||||||||||||||||||||
Gross wells owned and operated by Ecopetrol | 118 | 143 | 36 | 122 | 118 | 143 | ||||||||||||||||||
Total gross wells owned and operated by Ecopetrol S.A. in Colombia | 226 | 199 | 83 | 298 | 226 | 199 | ||||||||||||||||||
Associated Operations | ||||||||||||||||||||||||
Gross wells in joint ventures | 302 | 276 | 50 | 273 | 302 | 276 | ||||||||||||||||||
Net wells(1) | 144.2 | 97 | 19 | 139.6 | 144.2 | 97 | ||||||||||||||||||
Total gross wells in joint ventures Ecopetrol S.A. in Colombia | 302 | 276 | 50 | 273 | 302 | 276 | ||||||||||||||||||
Total net wells in joint ventures Ecopetrol S.A. in Colombia(1) | 144.2 | 97 | 19 | 139.6 | 144.2 | 97 | ||||||||||||||||||
Total gross wells Ecopetrol S.A. in Colombia | 528 | 475 | 133 | 571 | 528 | 475 | ||||||||||||||||||
Total net wells Ecopetrol S.A. in Colombia(1) | 370.2 | 296 | 102 | 437.6 | 370.2 | 296 |
(1) | Net wells correspond to the sum of wells owned and operated by Ecopetrol plus the net wells in our associated operations. Net wells in the associated operations are the result of our working interest in wells owned in joint ventures with our partners, as defined in the contract obligations. |
Production Acreage
The following table sets forth Ecopetrol S.A.’s developed and undeveloped gross and net acreage of crude oil and natural gas production in Colombia for the year ended December 31, 2018.2019.
Table 11 – Ecopetrol S.A.’s Developed and Undeveloped Gross
and Net Acreage of Crude Oil and Natural Gas Production in Colombia
Production Acreage as of December 31, 2018 ( acres) | ||||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Ecopetrol S.A. | 452,121 | 349,954 | 4,653,531 | 3,426,785 |
Production Acreage as of December 31, 2019 (acres) | ||||||||||||||||
Developed | Undeveloped | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Ecopetrol S.A. | 463,396 | 358,798 | 4,642,257 | 3,412,923 |
Gross and Net Productive Wells
The following table sets forth Ecopetrol S.A.’s total gross and net productive wells by region as of December 31, 2018.2019.
Table 12 – Ecopetrol S.A.’s Gross and Net Productive Wells by Region
As of December 31, 2018 (number of wells) | As of December 31, 2019 (number of wells) | |||||||||||||||||||||||||||||||
Crude Oil(1) | Natural Gas(2) | Crude Oil(1) | Natural Gas(2) | |||||||||||||||||||||||||||||
Gross | Net(3) | Gross | Net(3) | Gross | Net(3) | Gross | Net(3) | |||||||||||||||||||||||||
COLOMBIA | ||||||||||||||||||||||||||||||||
Ecopetrol S.A. | ||||||||||||||||||||||||||||||||
Central region | 2,244 | 1,767 | 9 | 9 | 2,089 | 1,585 | 6 | 6 | ||||||||||||||||||||||||
Orinoquía region | 1,086 | 1,077 | 22 | 18 | 1,012 | 997 | 17 | 16 | ||||||||||||||||||||||||
Southern region | 589 | 534 | 13 | 13 | 518 | 463 | 8 | 8 | ||||||||||||||||||||||||
Eastern Region | 693 | 693 | - | - | 680 | 680 | 0 | 0 | ||||||||||||||||||||||||
Region of Associated Operations | 2,602 | 1,260 | 16 | 7 | 2,794 | 1,402 | 38 | 18 | ||||||||||||||||||||||||
Total (Ecopetrol S.A.) | 7,214 | 5,331 | 60 | 47 | 7,093 | 5,127 | 69 | 48 |
Note: The above table reflects the productive wells that directly contribute to hydrocarbon production and therefore excludes wells used for injection, disposal, water abstraction, or other similar activities.
(1) | We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. |
(2) | Natural gas wells are those in which operations are directed only toward the production of commercial gas. |
(3) | Calculation of net productive wells is calculated by multiplying gross productive wells by our ownership percentage. |
3.4.2.1.2Ecopetrol 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, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(thousand bpd) | (thousand bpd) | |||||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Joint venture operation | 2.3 | 2.3 | 2.6 | 2.0 | 2.3 | 2.3 | ||||||||||||||||||
Direct operation | 18.4 | 19.4 | 15.4 | 18.8 | 18.4 | 19.4 | ||||||||||||||||||
Total Hocol | 20.7 | 21.7 | 18.0 | 20.8 | 20.7 | 21.7 | ||||||||||||||||||
Equion | ||||||||||||||||||||||||
Joint venture operation | – | 0.1 | 0.1 | - | – | 0.1 | ||||||||||||||||||
Direct operation | 9.0 | 10.5 | 12.3 | 7.9 | 9.0 | 10.5 | ||||||||||||||||||
Total Equion | 9.0 | 10.6 | 12.4 | 7.9 | 9.0 | 10.6 | ||||||||||||||||||
Production Tests | – | – | – | - | – | – | ||||||||||||||||||
Total Average Daily Crude Oil Production (Subsidiaries in Colombia) | 29.7 | 32.3 | 30.4 | 28.7 | 29.7 | 32.3 |
The 4.6%12% decrease in Hocol’sEquion’s production in 2018,2019, as compared to 2017,2018, 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, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(thousand boepd)(1) | (thousand boepd)(1) | |||||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Joint venture operation | 1.6 | 0.6 | 0.2 | 2.0 | 1.6 | 0.6 | ||||||||||||||||||
Direct operation | 5.9 | 5.2 | 0.6 | 6.7 | 5.9 | 5.2 | ||||||||||||||||||
Total Hocol | 7.5 | 5.8 | 0.8 | 8.7 | 7.5 | 5.8 | ||||||||||||||||||
Equion | ||||||||||||||||||||||||
Joint venture operation | 0.2 | 0.2 | 0.1 | - | 0.2 | 0.2 | ||||||||||||||||||
Direct operation | 4.8 | 4.6 | 6.4 | 5.0 | 4.8 | 4.6 | ||||||||||||||||||
Total Equion | 5.0 | 4.8 | 6.5 | 5.0 | 5.0 | 4.8 | ||||||||||||||||||
Production Tests | – | – | – | - | – | – | ||||||||||||||||||
Total Natural Gas Production (Subsidiaries in Colombia) | 12.5 | 10.6 | 7.3 | 13.7 | 12.5 | 10.6 |
(1) | Conversion between mcfpd and boepd is performed at 5,700 mcfpd to 1 boepd. |
Development Wells
The following table sets forth the number of gross and net development wells drilled exclusively by our subsidiaries and in their joint ventures in Colombia for the periods indicated.
Table 15 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Development Wells
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(number of wells) | (number of wells) | |||||||||||||||||||||||
Hocol | ||||||||||||||||||||||||
Gross wells owned and operated by Hocol | 12 | 17 | 9 | 23 | 12 | 17 | ||||||||||||||||||
Gross wells in joint ventures | 2 | – | – | 2 | 2 | – | ||||||||||||||||||
Net wells(1) | 13 | 17 | 9 | 24 | 13 | 17 | ||||||||||||||||||
Equion | ||||||||||||||||||||||||
Gross wells owned and operated by Equion(2) | – | – | – | – | – | – | ||||||||||||||||||
Gross wells in joint ventures | – | 1 | 1 | – | – | 1 | ||||||||||||||||||
Net wells(1) | – | – | – | – | – | – | ||||||||||||||||||
Total gross wells owned and operated in Colombia | 12 | 17 | 9 | 23 | 12 | 17 | ||||||||||||||||||
Total gross wells in joint ventures in Colombia | 2 | 1 | 1 | 2 | 2 | 1 | ||||||||||||||||||
Total net wells (Subsidiaries in Colombia) | 13 | 17 | 9 | 24 | 13 | 17 |
(1) | Net wells correspond to the sum of wells owned and operated by our subsidiaries and their ownership percentage of wells owned in joint ventures with their partners. |
(2) | Even though for the last three years Equion has operated every well, Equion has not owned any well 100%; rather Equion has drilled wells in joint venture with Ecopetrol. Therefore, after a careful review of the categories, all Equion data was moved from gross wells owned and operated by Equion to gross wells in joint ventures. However, the number of wells remains the same. |
Production Acreage
The following table sets forth our subsidiaries’ developed and undeveloped gross and net acreage of crude oil and natural gas production in Colombia for the year ended December 31, 2018.2019.
Table 16 – Ecopetrol S.A.’s Subsidiaries in Colombia Developed and Undeveloped Gross and
Net Acreage of
Crude Oil and Natural Gas Production
Production acreage as of December 31, 2018 | Production acreage as of December 31, 2019 | |||||||||||||||||||||||||||||||
Developed | Undeveloped | Developed | Undeveloped | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
(in acres) | (in acres) | |||||||||||||||||||||||||||||||
Hocol | 17,845 | 15,930 | 675 | 666 | 23,211 | 21,576 | 794 | 765 | ||||||||||||||||||||||||
Equion | 16,300 | 4,104 | 54,666 | 12,162 | 16,300 | 4,104 | 54,666 | 12,162 | ||||||||||||||||||||||||
Total (Subsidiaries in Colombia) | 34,145 | 20,034 | 55,341 | 12,828 | 39,511 | 25,680 | 55,460 | 12,927 |
Gross and Net Productive Wells
The following table sets forth our subsidiaries’ total gross and net productive wells in Colombia for the year ended December 31, 2018.2019.
Table 17 – Ecopetrol S.A.’s Subsidiaries in Colombia Gross and Net Productive Wells(1)(1)
For the year ended December 31, 2018 | For the year ended December 31, 2019 | |||||||||||||||||||||||||||||||
Crude Oil | Natural Gas | Crude Oil | Natural Gas | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
(number of wells) | (number of wells) | |||||||||||||||||||||||||||||||
Hocol | 281 | 241.9 | 20 | 18.5 | 316 | 274.8 | 25 | 23.5 | ||||||||||||||||||||||||
Equion | 15 | 8 | 15 | 8 | 15 | 8 | 15 | 8 | ||||||||||||||||||||||||
Total (Subsidiaries in Colombia) | 296 | 249.9 | 35 | 26.5 | 331 | 282.8 | 40 | 31.5 |
(1) | Information in the table above reflects productive wells that directly contribute to hydrocarbons production and therefore excludes wells used for injection, disposal, water abstraction or other similar activities. We consider crude oil wells to be those in which the main operation is oil production, although many of these wells produce gas associated with oil production that, in some cases, have a commercial purpose. Natural gas wells are those in which operations are directed only towards production of commercial gas. |
3.4.2.2 Production Activities Outside Colombia
3.4.2.2 | Production Activities Outside Colombia |
The Ecopetrol Group’s production outside of Colombia comes from 100% of the production of Ecopetrol America Inc.LLC (73.3%), Rodeo (0.7%) and 50% of ourits share ofin the Peruvian company Savia in Peru.(26%). In 2018,2019, the production obtained from these twothree companies was 17 boepd,17.7 mboed, which represents 2.4%2.5% of the total production of the Ecopetrol Group.
Crude Oil Production
The following table sets forth our average daily crude oil production outside Colombia, prior to deducting royalties, for the periods indicated.
Table 18 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Crude Oil Production
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(thousand bpd) | (thousand bpd) | |||||||||||||||||||||||
Savia Perú | 3.9 | 3.9 | (1) | 4.1 | 3.5 | 3.9 | 3.9 | (1) | ||||||||||||||||
Ecopetrol America Inc. | 10.2 | 9.2 | 5.5 | |||||||||||||||||||||
Ecopetrol America LLC | 11.4 | 10.2 | 9.2 | |||||||||||||||||||||
Rodeo Midland Basin LLC(2) | 0.1 | N.A. | N.A. | |||||||||||||||||||||
Total average daily crude oil production (International) | 14.1 | 13.1 | 9.6 | 15 | 14.1 | 13.1 |
(1) | In 2017, Savia’s crude oil production included NGLs. In preparing our 2018 operational information, those NGLs were reclassified into our 2017 natural gas production. |
(2) | In 2019, Ecopetrol S.A., through its wholly-owned subsidiary Ecopetrol Permian LLC, acquired 49% of Rodeo Midland Basin LLC. |
Natural Gas Production
The following table sets forth our average daily natural gas production outside Colombia, prior to deducting royalties, for the periods indicated.
Table 19 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Average Daily Natural Gas Production
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(thousand boepd) | (thousand boepd) | |||||||||||||||||||||||
Savia Perú | 1.1 | 1.1 | (1) | 1.3 | 0.9 | 1.1 | 1.1 | (1) | ||||||||||||||||
Ecopetrol America Inc. | 1.8 | 2.0 | 1.2 | |||||||||||||||||||||
Ecopetrol America LLC | 1.8 | 1.8 | 2.0 | |||||||||||||||||||||
Rodeo Midland Basin LLC(2) | 0.0 | N.A. | N.A. | |||||||||||||||||||||
Total average daily natural gas production (International) | 2.9 | 3.1 | 2.5 | 2.7 | 2.9 | 3.1 |
(1) | In 2017, Savia’s crude oil production included NGLs. In preparing our 2018 operational information, those NGLs were reclassified into our 2017 natural gas production. |
(2) | In 2019, Ecopetrol S.A. through its wholly owned subsidiary, Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC. |
Development Wells
The following table sets forth the number of gross and net development wells outside Colombia, drilled exclusively by us and in joint ventures for the periods indicated.
Table 20 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Development Wells(1(1))
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(number of wells) | (number of wells) | |||||||||||||||||||||||
Savia Perú | ||||||||||||||||||||||||
Gross wells | - | - | - | - | - | - | ||||||||||||||||||
Net wells(2) | - | - | - | - | - | - | ||||||||||||||||||
Ecopetrol America Inc. | - | - | - | |||||||||||||||||||||
Ecopetrol America LLC | - | - | - | |||||||||||||||||||||
Gross wells | 1 | 2 | 3 | 2 | 1 | 2 | ||||||||||||||||||
Net wells(2) | 0.3 | 0.4 | 0.7 | 0.5 | 0.3 | 0.4 | ||||||||||||||||||
Rodeo Midland Basin LLC(3) | ||||||||||||||||||||||||
Gross wells | 6 | N.A. | N.A. | |||||||||||||||||||||
Net wells | 2.0 | N.A. | N.A. | |||||||||||||||||||||
Total gross wells (International) | 1 | 2 | 3 | 8 | 1 | 2 | ||||||||||||||||||
Total net wells (International) | 0.3 | 0.4 | 0.7 | 2.5 | 0.3 | 0.4 |
(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. |
(2) | Net wells correspond to the sum of wells entirely owned by us or our subsidiaries and our ownership percentage of wells owned in joint ventures with our partners. |
(3) | In 2019, Ecopetrol S.A. through its wholly-owned subsidiary Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC. |
Production Acreage
The following table sets forth our developed and undeveloped gross and net acreage of crude oil and natural gas production outside Colombia for the year ended December 31, 2018.2019.
Table 21 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Developed and Undeveloped Gross and
Net
Acreage of Crude Oil and Natural Gas Production
Production acreage as of December 31, 2018 | Production acreage as of December 31, 2019 | |||||||||||||||||||||||||||||||
Developed | Undeveloped | Developed | Undeveloped | |||||||||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
(in acres) | (in acres) | |||||||||||||||||||||||||||||||
Savia Perú | 79,575 | 39,788 | 57,671 | 28,836 | 79,575 | 39,788 | 57,671 | 28,836 | ||||||||||||||||||||||||
Ecopetrol America Inc.(1) | 55,440 | 15,059 | 23,040 | 6,566 | ||||||||||||||||||||||||||||
Ecopetrol America LLC.(1) | 49,680 | 13,243 | 23,040 | 6,566 | ||||||||||||||||||||||||||||
Rodeo Midland Basin LLC(2) | 62,034 | 47,746 | 4,737 | 816 | ||||||||||||||||||||||||||||
Total (International) | 135,015 | 54,847 | 80,711 | 35,402 | 191,289 | 100,777 | 85,448 | 36,218 |
(1) | Production and acreage from Ecopetrol America |
(2) | In 2019, Ecopetrol S.A. through its wholly-owned subsidiary Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC. Acres spaced or assigned to productive wells. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells. |
Gross and Net Productive Wells
The following table sets forth our total gross and net productive wells outside Colombia for the year ended December 31, 2018.2019.
Table 22 – Ecopetrol S.A.’s Subsidiaries Outside Colombia Gross and Net Productive Wells
As of December 31, 2018 | As of December 31, 2019 | |||||||||||||||
Crude Oil | Crude Oil | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
(number of wells) | (number of wells) | |||||||||||||||
INTERNATIONAL | ||||||||||||||||
Savia Perú | 606 | 303 | 601 | 300 | ||||||||||||
Ecopetrol America Inc. | 15 | 3.6 | ||||||||||||||
Ecopetrol America LLC | 13 | 3.3 | ||||||||||||||
Rodeo Midland Basin LLC | 6 | 2.0 | ||||||||||||||
Total (International) | 621 | 306.6 | 620 | 305.3 |
3.4.2.3 | Marketing of Crude Oil and Natural Gas |
3.4.2.3 Marketing of Crude Oil and Natural Gas
In 2018,2019, Ecopetrol sold 899.5928 mboed, out of which 400.4412 mboed represented sales of crude oil (44%), 78.581 mboed of natural gas (9%) and 420.6435 mboed of fuels and petrochemicals (47%).
Crude Oil Export Sales
Crude oil export sales in 2018 decreased2019 increased by 24 mbopd13 mboed compared to 20172018, mainly due to the substitutionhigher production and an effective commercial strategy of imports at Reficar for domestic crudes.purchases of crude from third parties. Ecopetrol’s crude oil export sales are traded both in the spot and contract markets, primarily to refiners in the United States Asia and Europe.Asia.
The Castilla blend is the main type of crude oil for export sales, with 334 mbopd367 mboed sold during 20182019 (a 84%91% share of our crude oil basket) followed by the Vasconiadomestic crudes sold by Ecopetrol America LLC with 19 mbopd10 mboed, (a 5%2.5% share in our crude oil basket), SouthMares blend with 119 mbopd (a 3%2.2% share of our crude oil basket), and Vasconia NorteApiay Blend with 9.4 mbopd7 mboed (a 2%1.8% share of our crude oil basket).
Ecopetrol placedplaces its exports in markets that representprovide the best value for its crudes. In 2018,2019, Asia was the main destination, representing 41%46.3% of crude oil exports, closely followed by the United States with 40% of crude oil exports.42%. The expansion of refining capacity both in the private and state owned companies in countries like China has supported the increase inof crude oil flows from Colombia to Asia,Asia. Moreover, volatility in the production of regional producerscompetitors has given US refiners 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 thediscount versus ICE Brent price.price was on average US$ 5.6/Bl. Our crude basket increased by US$15.4/bl 2.9/Bl year over year due to the strength of the ICE Brent pricemarket conditions and our persistent commercial strategy towardsfocused on markets with higher value.
Crude Oil Purchase Contracts
Ecopetrol has signed several crude oil purchase contracts with third parties and business partners. Ecopetrol also purchases the country’s crude oil royalties from the ANH from royalties.National Hydrocarbon Agency (ANH). This oil is processed in Ecopetrol’s refineries or exported. The purchase price is referenced to export parity based on international market prices, plus a commercial fee. See sectionBusiness Overview—Related Party and Intercompany Transactions.
The table below sets forth the volumes of crude oil purchased from our business partners and third parties and volumes of crude oil purchased from the ANH from royalties for the years ended on December 31, 2019, 2018 2017 and 2016.2017.
Table 23 – Ecopetrol Consolidated Crude Oil Purchases
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(million barrels) | (million barrels) | |||||||||||||||||||||||
Ecopetrol Corporate Group | ||||||||||||||||||||||||
Ecopetrol Group | ||||||||||||||||||||||||
Crude oil purchased from ANH royalties | 37.6 | 40.3 | 42.9 | 35.4 | 37.6 | 40.3 | ||||||||||||||||||
Crude oil purchased from third parties | 20.7 | 16.7 | 15.5 | 30.0 | 20.7 | 16.7 | ||||||||||||||||||
Crude oil imported from third parties | 14.0 | 24.8 | 22.0 | 9.1 | 14.0 | 24.8 |
During 2018,2019, part of Ecopetrol’s crude strategy was centered on increasing the purchase and subsequent commercialization of crude oil from third parties, which enables further optimization of the supply chain.chain and should allow us to capture enhanced margins.
Import of Diluents
In 2018,2019, Ecopetrol decreasedincreased the imports of diluent by 1.7% (0.91.2 % (0.6 mbpd) compared to 2017.2018 due to higher production. 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% (0.933.0% (2.7 mboepd) compared to 2017,2018, due to an increase in short term sales to industrial consumers.higher production.
Natural Gas Delivery Commitments
The table below sets forth the commitments we have in Colombia under firm contracts with local natural gas distribution companies, local industries, gas-fired power generators and internal agreements with our refineries and fields.
Table 24 – Ecopetrol Consolidated Natural Gas Delivery Commitments
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||||||||||
2019 | 2020 | 2021 | 2022 | 2020 | 2021 | 2022 | 2023 | |||||||||||||||||||||||||
(gbtud) | (gbtud) | |||||||||||||||||||||||||||||||
Volume for sales third parties | 526.8 | 549.2 | 499.9 | 323.0 | 586.9 | 554.8 | 377.9 | 325.1 | ||||||||||||||||||||||||
Volume for self-consumption | 140.4 | 175.2 | 185.3 | 194.8 | 207.7 | 226.8 | 235.7 | 238.9 | ||||||||||||||||||||||||
Total Commitments | 667.2 | 724.4 | 685.2 | 517.8 | 794.6 | 781.6 | 613.6 | 564.0 |
Neither Equion nor Savia Peru are included in the table above since they do not consolidate within Ecopetrol Group. Data was updated 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 Energy 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.2019.
3.4.3 | Reserves |
The reserves reporting process was conducted in accordance with SEC definitions and rules set forth in Rule 4-10(a) of Regulation S-X and the disclosure guidelines contained in the SEC’s Modernization of Oil and Gas Reporting final rule dated December 31, 2008 and effective as of January 1, 2010.
The estimated reserve amounts presented in this annual report, as of December 31, 2018,2019, are based on the average prices during the 12-month period prior to the ending date of the period covered in this annual report, determined as the unweighted arithmetic averages of the prices in effect on the first day of the month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations.
Our crude oil and natural gas net proved reserves include reserves from our subsidiaries located in the United States (Gulf of Mexico) and Peru, and Equion and Hocol’s assets in Colombia.
Estimated Net Proved Reserves
The following table sets forth our estimated net proved developed reserves of crude oil and gas by region for the years ended December 31, 2019, 2018 2017 and 2016.2017.
Table 25 – Net Proved Developed Reserves
Net Proved Developed Reserves | Colombia | North America | South America excluding Colombia | Total | Colombia | North America | South America excluding Colombia | Total | ||||||||||||||||||||||||
Net Proved Developed oil reserves in million barrels oil equivalent | ||||||||||||||||||||||||||||||||
At December 31, 2016 | 710 | 6 | 7 | 723 | ||||||||||||||||||||||||||||
At December 31, 2017 | 747 | 10 | 6 | 763 | 747 | 10 | 6 | 763 | ||||||||||||||||||||||||
At December 31, 2018 | 814 | 13 | 5 | 832 | 814 | 13 | 5 | 832 | ||||||||||||||||||||||||
At December 31, 2019 | 832 | 12 | 3.8 | 848 | ||||||||||||||||||||||||||||
Net Proved Developed NGL reserves in million barrels oil equivalent | ||||||||||||||||||||||||||||||||
At December 31, 2016 | 55 | - | 1 | 56 | ||||||||||||||||||||||||||||
At December 31, 2017 | 54.6 | - | 0.8 | 55.4 | 54.6 | - | 0.8 | 55.4 | ||||||||||||||||||||||||
At December 31, 2018 | 50.5 | - | 0.6 | 51.1 | 50.5 | - | 0.6 | 51.1 | ||||||||||||||||||||||||
At December 31, 2019 | 49 | 0.12 | 0.5 | 50 | ||||||||||||||||||||||||||||
Net Proved Developed gas reserves in billion standard cubic feet | ||||||||||||||||||||||||||||||||
At December 31, 2016 | 3,114 | 9 | 8 | 3,131 | ||||||||||||||||||||||||||||
At December 31, 2017 | 3,143 | 10 | 5 | 3,158 | 3,143 | 10 | 5 | 3,158 | ||||||||||||||||||||||||
At December 31, 2018 | 2,865.5 | 10 | 7 | 2,882 | 2,865.5 | 10 | 7 | 2,882.5 | ||||||||||||||||||||||||
At December 31, 2019 | 2,645 | 11 | 7 | 2,662 | ||||||||||||||||||||||||||||
Net Proved Developed oil, NGL and gas reserves in million barrels oil equivalent | ||||||||||||||||||||||||||||||||
At December 31, 2016 | 1,311 | 8 | 10 | 1,329 | ||||||||||||||||||||||||||||
At December 31, 2017 | 1,353 | 11 | 8 | 1,372 | 1,353 | 11 | 8 | 1,372 | ||||||||||||||||||||||||
At December 31, 2018 | 1,368 | 14 | 7 | 1,389 | 1,368 | 14 | 7 | 1,389 | ||||||||||||||||||||||||
At December 31, 2019 | 1,345 | 14 | 6 | 1,365 |
Gas Reserves included 381 bcf of Fuel Gas
Oil Reserves included 17 million barrels of Fuel Oil
Totals may not exactly equal the sum of the individual entries due to rounding
The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
We are required, as are all oil companies undertaking exploratory and production activities in Colombia, to pay a percentage of our production to the Government as royalties. However, the ANH’s Resolution 877 of 2013, Resolution 351 of 2014 and Resolution 640 of 2014 require natural gas royalties to be paid in cash, which means that the determination of the property rights to the quantities of natural gas we produce is based on the total volume produced without deductions on account of royalties. The main producing gas fields are Guajira, Cusiana, Cupiagua, Pauto, Cusiana, Chuchupa Gibraltar, Ballena and Mamey.Bonga.
Ecopetrol S.A. owns 100% of Cenit, a subsidiary that operates in Colombia and is dedicated to the storage and transportation of hydrocarbons through pipelines. Cenit provides transportation services for the entire Ecopetrol Group and we fully consolidate Cenit into our consolidated results of operations. Therefore, the difference between the tariffs set by the Ministry of Mines and Energy and the real transportation costs (fixed and variable operating expenses) does not affect our consolidated income statement. Thus, in presenting our reserves information in the 2016, 2017, 2018 and 20182019 annual reports, we have used our real transportation costs, rather than the regular tariffs set by the Ministry of Mines and Energy.
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 17 million barrels of fuel oil, 381 billion standard cubic feet of fuel gas within our natural gas results and 517 billion cubic feet of royalties, as of December 31, 2019.
Table 26 – Proved Oil, NGL and Natural Gas Reserves for 2019
Reserves Category | Oil (million barrels) | NGL (million barrels) | Natural Gas (bcf) | Total Oil and Gas (Mmboe) | ||||||||||||
PROVED DEVELOPED RESERVES | ||||||||||||||||
Total (Colombia) | 832 | 49 | 2,645 | 1,345 | ||||||||||||
International: | ||||||||||||||||
North America | 12 | 0.12 | 11 | 14 | ||||||||||||
South America | 3.8 | 0.5 | 7.0 | 6.0 | ||||||||||||
TOTAL PROVED DEVELOPED RESERVES | 848 | 50 | 2,662 | 1,365 | ||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||
Total (Colombia) | 306 | 28 | 111 | 353 | ||||||||||||
International: | ||||||||||||||||
North America | 123 | 29 | 133 | 175 | ||||||||||||
South America | - | - | - | - | ||||||||||||
TOTAL PROVED UNDEVELOPED RESERVES | 429 | 57 | 244 | 529 | ||||||||||||
TOTAL PROVED RESERVES | 1,277 | 107 | 2,906 | 1,893 |
Totals may not exactly equal the sum of the individual entries due to rounding
The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 16 million barrels of fuel oil, 327 billion standard cubic feet of fuel gas within our natural gas results and 534 billion cubic feet of royalties, as of December 31, 2018.
Table 2627 – 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 (million barrels) | NGL (million barrels) | Natural Gas (bcf) | Total Oil and Gas (Mmboe) | ||||||||||||||||||||||||
PROVED DEVELOPED RESERVES | ||||||||||||||||||||||||||||||||
Total (Colombia) | 814 | 50.5 | 2,866 | 1,368 | 814 | 50.5 | 2,866 | 1,368 | ||||||||||||||||||||||||
International: | ||||||||||||||||||||||||||||||||
North America | 13 | - | 10 | 14 | 13 | - | 10 | 14 | ||||||||||||||||||||||||
South America | 5 | 0.5 | 7 | 7 | 5 | 0.5 | 7 | 7 | ||||||||||||||||||||||||
TOTAL PROVED DEVELOPED RESERVES | 832 | 51 | 2,883 | 1,389 | 832 | 51 | 2,883 | 1,389 | ||||||||||||||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||||||||||||||||||
Total (Colombia) | 285 | 22 | 113 | 327 | 285 | 22 | 113 | 327 | ||||||||||||||||||||||||
International: | ||||||||||||||||||||||||||||||||
North America | 10 | - | 6 | 11 | 10 | - | 6 | 11 | ||||||||||||||||||||||||
South America | - | - | - | - | - | - | - | - | ||||||||||||||||||||||||
TOTAL PROVED UNDEVELOPED RESERVES | 295 | 22 | 119 | 338 | 295 | 22 | 119 | 338 | ||||||||||||||||||||||||
TOTAL PROVED RESERVES | 1,127 | 73 | 3,002 | 1,727 | 1,127 | 73 | 3,002 | 1,727 |
The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
The following table summarizes our proved oil, NGL and natural gas reserves, which includes 304 billion standard cubic feet of fuel gas within our natural gas results and 562 billion cubic feet of royalties, as of December 31, 2017.
Table 28 – Proved Oil, NGL and Natural Gas Reserves for 2017
Reserves Category | Oil (million barrels) | NGL (million barrels) | Natural Gas (bcf) | Total Oil and Gas (Mmboe) | ||||||||||||
PROVED DEVELOPED RESERVES | ||||||||||||||||
Total (Colombia) | 747 | 54.6 | 3,143 | 1,353 | ||||||||||||
International: | ||||||||||||||||
North America | 10 | - | 10 | 11 | ||||||||||||
South America | 6 | 0.8 | 5 | 8 | ||||||||||||
TOTAL PROVED DEVELOPED RESERVES | 763 | 55.4 | 3,158 | 1,372 | ||||||||||||
PROVED UNDEVELOPED RESERVES | ||||||||||||||||
Total (Colombia) | 247 | 19 | 93 | 282 | ||||||||||||
International: | ||||||||||||||||
North America | 4 | - | 3 | 5 | ||||||||||||
South America | - | - | - | - | ||||||||||||
TOTAL PROVED UNDEVELOPED RESERVES | 251 | 19 | 96 | 287 | ||||||||||||
TOTAL PROVED RESERVES | 1,014 | 74 | 3,253 | 1,659 |
The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
Reserves Replacement
The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves divided by produced volumes in any given period. The following table presents the changes in reserves in each category relating to the reserve replacement ratio for the years 2019, 2018 2017 and 2016.2017.
Changes in Proved Reserves
Table 2729 – Changes in Proved Reserves
As of December 31, | As of December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
Consolidated Company (million barrels oil equivalent) | ||||||||||||||||||||||||
Revisions of previous estimates | 120.5 | 174 | (54 | ) | 83 | 120.5 | 174 | |||||||||||||||||
Improved Recovery | 129.1 | 73 | 11 | 94 | 129.1 | 73 | ||||||||||||||||||
Extensions and discoveries | 57.4 | 44 | 27 | 67 | 57.4 | 44 | ||||||||||||||||||
Purchases | - | 4 | – | 164 | - | 4 | ||||||||||||||||||
Total reserves additions | 307 | 295 | (16 | ) | 408 | 307 | 295 | |||||||||||||||||
Production | (239 | ) | (234 | ) | (235 | ) | (242 | ) | (239 | ) | (234 | ) | ||||||||||||
Net change in proved reserves | 68 | 61 | (251 | ) | 166 | 68 | 61 |
The reserves replacement ratio for 20182019 was 1.69 barrels compared to 1.29 barrels compared toin 2018 and 1.26 barrels in 2017. The average replacement ratio for the last three years was 0.831.4 barrels.
Table 2830 – Reserves Replacement Ratio (including purchase and sales)
As of December 31, | As of December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
Annual | 1.29 | 1.26 | (0.07 | ) | 1.69 | 1.29 | 1.26 | |||||||||||||||||
Three year average | 0.83 | 0.42 | 0.48 | 1.4 | 0.83 | 0.42 |
Revisions of Previous Estimates
In 2019, revisions increased reserves by 83 million boe, mainly as a result of:
(i) | An increase of 33 million boe due toimproved reservoir performance in the Rubiales field and continuous development with drilling activities. |
(ii) | An increase of 36 million boe in reserves due to review of the curve type of new development activities according to new wells results in the Caño Sur field and additional gas processing plant capacity to extract NGL in the Cupiagua field. |
(iii) | The remaining 17% (or 14 million boe) increase in reserves, was due to varying increases and decreases from other fields. |
In 2018, revisions increased reserves by 120 million boe, mainly as a result of:
(i) | An increase of 87 million boe due to the continuous development of the Rubiales, Chichimene and Quifa fields, of which a 68 million boe increase in reserves is due to improved reservoir performance in the Rubiales field. |
(ii) | An increase 14 million boe increase in reserves due to development activities in the Bonanza and Ocelote fields. |
(iii) | The remaining 16%, or 19.8 million boe, increase in reserves was due to varying increases and decreases from other fields. |
In 2017, revisions increased reserves by 175 million boe, mainly as a result of:
(i) | An increase of 49 million boe due to the continuous development of the Castilla, Chichimene, Rubiales, Caño Sur and Akacias fields of which a 32 million boe increase in reserves is due to the new development projects in the Caño Sur and Akacias fields, and a 17 million boe increase in reserves is due to development activities and improved reservoir performance in the Chichimene, Castilla and Rubiales fields. |
(ii) | An increase of 23 million boe due to improved natural gas sales in the Cupiagua and Pauto fields, which in turn was due to better performance and improved output of such fields. Additionally, new gas and NGL projects in the Cupiagua Sur field led to a 27 million boe increase in reserves. Revisions in the Nutria, Llanito, Tibu, Casabe and Cohembi fields as a result of drilling activities and better production performance accounted for a 23 million boe increase in reserves. |
(iii) | The remaining 30%, or 52 million boe, increase in reserves was due to varying increases and decreases from other fields. |
Improved Recovery
In 2019, improved recovery increased reserves by 94 million boe. An increase of 25 million boe was associated with new proved areas under water flooding in the Chichimene and Akacias fields. Furthermore, the continued development of water flooding projects at existing wells in the Castilla, Chichimene, Yarigui, La Cira-Infantas fields accounted for a 45 million boe increase. The remaining 26%, or 24 million boe, increase was due primarily to water injection reservoir responses at various fields.
In 2018, improved recovery increased reserves by 129 million boe. The additions were associated with new proved areas under water flooding in the Chichimene, Castilla, La Cira-Infantas, Apiay, Suria, Yarigui, Casabe and Dina Cretaceo fields 86(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.
In 2017, improved recovery increased reserves by 73 million boe. The additions were associated with new proved areas under water flooding in the Chichimene and Castilla fields (47 million boe increase). The continued development of water flooding projects at existing wells in the Tibú, La Cira, Infantas, Casabe and Guando SW fields, accounting for a 24 million boe increase. The remaining 3%, or 2 million boe, increase was due primarily to water injection pilots in the Apiay and Palogrande fields.
On average, improved recovery has added 98.7 million boe each year over the last three years.
Extensions and Discoveries
Extensions and discoveries during 2019 amounted to 67 million boe primarily due to extensions of proved acreage mainly from activities in new proved areas in the Rubiales, Quifa, Suria, Tisquirama, Castilla and Garza’s fields, which accounted for 35 million of the total of 67 million boe from extensions of proved acreage. The remaining 32 million boe corresponds to smaller changes in several other fields.
Extensions and discoveries during 2018 amounted to 57 million boe primarily due to extensions of proved acreage mainly from activities in new proved areas in the Rubiales, Castilla, Cupiagua, Pauto and Caño Sur fields, which accounted for 45 million boe and newly discovered fields and reservoirs accounted for 12 million boe. The remaining 9 million boe corresponds to smaller changes in several other fields.
Extensions and discoveries during 2017 amounted to 44 million boe primarily due to extensions of proved acreage mainly from activities in new proved areas in the Rubiales, Castilla, Pauto, Cajua and Arrayan fields, which accounted for 39 million boe of the total of 44 million boe from extensions of proved acreage. The remaining 5 million boe corresponds to smaller changes in several other fields.
Purchases
In 2019, Ecopetrol S.A. through its wholly owned subsidiary, Ecopetrol Permian LLC acquired 49% of Rodeo Midland Basin LLC, a company whose economic activity will be directed towards the execution of a joint development plan under the joint venture between Ecopetrol and Occidental Petroleum Corp, announced on July 31, 2019,which represented 164 million boe. Through this joint venture, the Company and Occidental Petroleum Corp will pursue development of unconventional reservoirs in approximately 97,000 acres of the Permian Basin in Texas. For the acquisition and closing of the transaction, Ecopetrol S.A. made an initial payment of approximately US$876.5 million dollars.
There were no purchases or acquisitions in 2018.
Ecopetrol S.A.’s purchases of minerals in 2017 included the acquisition of an additional participation of 11.6% in the K2 Field by Ecopetrol America LLC which represented 4 million boe.
Development of reserves
DevelopmentAs of December 31, 2019, our total proved undeveloped oil and gas reserves amounted to 529 million boe, 46% of which is related to development activities in the Rubiales, Castilla, Caño Sur Chichimene, Teca, Akacias and Pauto fields and 31% of which is related to development of unconventional reservoirs of the U.S. Permian Basin in Texas. The remaining 23% comes from activities at several other fields.
Ecopetrol’s year-end development plans are consistent with SEC guidelines for the development of proved undeveloped reserves within five years. The development plan of Rubiales Field goes beyond the 5 years due to the limitations in water handling in the facilities. This exemption was reviewed and approved by the external certification agent.
As of December 31, 2018, our total proved undeveloped oil and gas reserves amounted to 338 million boe, 21% of which is related to new drilling activities in the Rubiales field, 41% is related to development activities in the Castilla, Caño Sur, Chichimene, Quifa, Cupiagua and Yarigui fields and 22% of which is related to the new development activities in the Teca, Pauto, Bonanza and Ryberg fields. The remaining 16% comes from activities at several other fields.
In 2018, the development plan of Rubiales and Caño Sur Field went beyond 5 years due to the limitations in water handling in the facilities and Ryberg offshore field. These exemptions were reviewed by the external certification agent.
As of December 31, 2017, our total proved undeveloped oil and gas reserves amounted to 287 million boe, 24% of which is related to the drilling activities in the Castilla field, 11% is related to gas sale projects in the Pauto and Cupiagua fields and 42% of which is related to the development activities in the Rubiales, Caño Sur, Chichimene, Yarigui, Tibu, Nutria, Palagua and Quifa fields. The Moriche, Ocelote, Akacias, Dina, Casabe, Llanito, La Cira and Cajua fields collectively accounted for 11% of total proved undeveloped oil and gas reserves with the remaining 12% from several other fields.
Our proved undeveloped reserves represent 20%28% 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, 2019, 20% as of December 31, 2018 and 17% as of December 31, 2017.
The following table reflects the developed and undeveloped proved reserves estimates through the past three fiscal years.
Table 2931 – Developed and Undeveloped Proved Reserves
Oil | NGL | Gas | Total | |||||||||||||||||||||||||||||
Proved Reserves as of December 31, | Oil | NGL | Gas | Total | Mmbls | Mmbls | Bcf | Mmboe | ||||||||||||||||||||||||
Mmbls | Mmbls | Bcf | Mmboe | |||||||||||||||||||||||||||||
2019 proved reserves | ||||||||||||||||||||||||||||||||
Developed | 848 | 50 | 2,662 | 1,365 | ||||||||||||||||||||||||||||
Undeveloped | 429 | 57 | 244 | 529 | ||||||||||||||||||||||||||||
2018 proved reserves | ||||||||||||||||||||||||||||||||
Developed | 832 | 51 | 2,882 | 1,389 | 832 | 51 | 2,882 | 1,389 | ||||||||||||||||||||||||
Undeveloped | 295 | 23 | 119 | 338 | 295 | 23 | 119 | 338 | ||||||||||||||||||||||||
2017 proved reserves | ||||||||||||||||||||||||||||||||
Developed | 763 | 55 | 3,158 | 1,372 | 763 | 55 | 3,158 | 1,372 | ||||||||||||||||||||||||
Undeveloped | 251 | 19 | 96 | 287 | 251 | 19 | 96 | 287 | ||||||||||||||||||||||||
2016 proved reserves | ||||||||||||||||||||||||||||||||
Developed | 723 | 56 | 3,131 | 1,329 | ||||||||||||||||||||||||||||
Undeveloped | 241 | 13 | 87 | 269 |
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.
Of the total amount of proved undeveloped reserves that Ecopetrol had at the end of 2016 (269.3 million boe), we converted approximately 53 million boe, or 20%, to proven developed reserves during 2017 (286.6 million boe), primarily associated with the development of crude oil and gas projects in the Castilla, Rubiales, Pauto, Quifa, La Cira Infantas and K2 fields. These projects accounted for approximately 89% of the total conversion while the remaining 11% is associated with development execution in other fields such as the Chichimene and Ocelote fields, among others. The amount of investments made during 2017 to convert proved undeveloped reserves to proved developed reserves was US$494 million.
Changes in Undeveloped Proved Reserves
The following table reflects the main changes in undeveloped proved reserves during 2018.as of December 31, 2019, 2018 and 2017.
Table 3032 – Changes in Undeveloped Proved Reserves in 2018
As of December 31, | ||||||||||||
Consolidated Companies (million barrels oil equivalent) | 2019 | 2018 | 2017 | |||||||||
Revisions of previous estimates | 43 | 28.4 | 9 | |||||||||
Improved recovery | 40 | 67.1 | 36 | |||||||||
Extensions and discoveries | 34 | 39.9 | 25 | |||||||||
Purchases | 163 | - | - | |||||||||
Proved Undeveloped converted to Proved Developed | (89 | ) | (83.7 | ) | (53 | ) | ||||||
Net change in unproved reserves | 190 | 51.7 | 17 |
The conversion rate used is 5,700 standard cubic feet = 1 barrel of oil equivalent.
Rounded figures
Reserve Process
Ecopetrol’s reserves process is coordinated by the Corporate Reserves Manager, a highly experienced engineer, who reports to the Upstream Chief Financial Officer. The Ecopetrol reserves group is comprised of reserves coordinators who are geologist and petroleum engineers, each with more than ten years of experience in reservoir characterization, field development, estimation and reporting of reserves and who support and interact with the specialists involved in the estimation and reporting process, following an established procedure with its corresponding internal controls. As in previous years, the reserves are estimated and certified by recognized external independent engineers (this year consisting of Ryder Scott Company, Gaffney, Cline & Associates, Sproule International Limited, Netherland Sewell & Associates, Inc. and DeGolyer and MacNaughton) in compliance with the definitions of the Society of Petroleum Engineers and the applicable SEC rules. According to our corporate policy, we report the reserves values obtained from the external engineers, even if they are lower than our expected reserves.
The reserves estimation process ends when the Corporate Reserves Manager consolidates the results and together, with the Development Vice-President and the Upstream Chief Financial Officer, presents the outcome to the Reserves Committee, which comprises the Group’s CEO, the Ecopetrol’s Group’s CFO and the Vice-President of Development and Production. Results are later presented to the Audit and Risk Committee of the Board of Directors and finally reviewed and approved by the Board of Directors.
Petroleum engineering consultants Ryder Scott Company, Gaffney, Cline & Associates, Sproule International Limited, Netherland, Sewell & Associates, Inc. and DeGolyer and MacNaughton have estimated and certified Ecopetrol’s proved reserves as of December 31, 2018.2019. These external engineers estimated 99% of our estimated net proved reserves.reserves for the year ended December 31, 2019, 2018 and 2017. The reserves reports of the external engineers are included as exhibits to this annual report.
Ecopetrol’s reserves process uses deterministic methods which are commonly used internationally to estimate reserves. These methods whilst reliable, have some inherent uncertainty, 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, 20162017 through 2018,2019, and the changes therein.
Table 3133 – Estimated Proved Reserves of Oil and Gas
Consolidated companies | Colombia | North America | South America excluding Colombia | Total | Colombia | North America | South America excluding Colombia | Total | ||||||||||||||||||||||||
Net proved oil, NGL and gas reserves in Mmboe | Net proved oil, NGL and gas reserves in Mmboe | |||||||||||||||||||||||||||||||
At December 31, 2016 | 1,577 | 11 | 10 | 1,598 | ||||||||||||||||||||||||||||
Revisions | 170 | 4.6 | (0.3 | ) | 174.3 | |||||||||||||||||||||||||||
Improved Recovery | 73 | - | - | 73 | ||||||||||||||||||||||||||||
Extensions and discoveries | 44 | - | - | 44 | ||||||||||||||||||||||||||||
Purchases | - | 4 | - | 4 | ||||||||||||||||||||||||||||
Production | (229 | ) | (3.6 | ) | (1.5 | ) | (234.1 | ) | ||||||||||||||||||||||||
At December 31, 2017 | 1,635 | 16 | 8.2 | 1,659.2 | 1,635 | 16 | 8.2 | 1,659.2 | ||||||||||||||||||||||||
Revisions | 114 | 5.8 | 1 | 120.8 | 114 | 5.8 | 1 | 120.8 | ||||||||||||||||||||||||
Improved Recovery | 129 | - | - | 129 | 129 | - | - | 129 | ||||||||||||||||||||||||
Extensions and discoveries | 50 | 7 | - | 57 | 50 | 7 | - | 57 | ||||||||||||||||||||||||
Production | (233 | ) | (3.8 | ) | (2 | ) | (238.8 | ) | (233 | ) | (3.8 | ) | (2 | ) | (238.8 | ) | ||||||||||||||||
At December 31, 2018 | 1,695 | 25 | 7.2 | 1,727.2 | 1,695 | 25 | 7.2 | 1,727.2 | ||||||||||||||||||||||||
Revisions | 78.4 | 4.3 | 0.2 | 83 | ||||||||||||||||||||||||||||
Improved Recovery | 94.3 | - | - | 94 | ||||||||||||||||||||||||||||
Extensions and discoveries | 66 | 0.7 | - | 67 | ||||||||||||||||||||||||||||
Purchases | - | 164 | - | 164 | ||||||||||||||||||||||||||||
Production | (236 | ) | (4.2 | ) | (1.4 | ) | (242 | ) | ||||||||||||||||||||||||
At December 31, 2019 | 1,698 | 189.7 | 6 | 1,893 |
For more information regarding the potential impacts of oil prices on our reserve estimates, see the sectionsFinancial Review—Review—Trend Analysis and Sensitivity Analysis and andRisk Review—Review—Risk FactorsFactors..
Rounded figures
3.4.4 Joint Venture and Other Contractual Arrangements
We conduct our exploration and production business through a variety of types of contractual arrangements with the Colombian government or with third parties. Below is a general description of eachthe main type of contractual arrangement to which we were a party as of December 31, 2018:2019.
Association Contract
The purpose of this type of contract, created by Decree 2310 of 1974, is the exploration of the areas covered by the contract, and the exploitation of hydrocarbons found in that area. This type of contract, together with E&P contracts and Special Contracts (Casabe, La Cira and Teca-Cocorná fields) which are described below, are the most significant in terms of our production and proved reserves.
Under association contracts, the exploratory risk is assumed entirely by Ecopetrol S.A.’s contractual partner, the associate. If there is a discovery and Ecopetrol S.A. agrees that the relevant field is commercially viable, Ecopetrol S.A. will participate in the field’s development. A joint account will be created, and Ecopetrol S.A. and the partner will participate in the expenses and investments in the proportions established in the corresponding contract. Ecopetrol S.A. will reimburse the direct exploratory expenses incurred by the contractual partner in the proportions established by the contract.
If Ecopetrol S.A. does not believe that the relevant field is commercially viable, the partner has the right to execute on its own all activities considered necessary for the field’s exploitation as a “sole risk operation,” and to be reimbursed for a defined percentage of all investments for such sole risk operation in accordance with the corresponding contract.
Every association contract provides for an executive committee that makes all technical, financial and operational decisions if Ecopetrol S.A. has agreed that a field is economically viable. All major decisions of this committee must be made unanimously by the parties.
The maximum term of an association contract is 28 years. The first six years of the contract are for the exploratory phase, and are extendible for 1 or 2 more years at the partner’s request. The remaining time is for the exploitation phase.
Incremental Production Contract
We enter into incremental production contracts to obtain additional hydrocarbon production beyond a base production curve that is established based on the proven reserves of a specific field or well. Under this type of arrangement, Ecopetrol S.A. owns 100% of the hydrocarbons defined by the base production curve. The incremental production (i.e., the hydrocarbon volume obtained beyond the basic production as a result of investment activities), will be owned by the contract parties 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 Contractfor Discovered Undeveloped and Inactive Fields (First Round 2003)
We have entered into risk production contracts for discovered undeveloped fields to promote exploration by private companies of both undeveloped and inactive fields. Under these contracts, the contracting party assumes all costs and expenses for the development and operation of a field in exchange for a percentage interest in the field’s production as specified in the contract. This type of contract has a ten-year term calculated from its date of execution: one year for the evaluation period and a maximum of nine years for the development period. Some of these contracts have subsequently been extended beyond their original term. Currently, Ecopetrol does not have any contract under this type of contractual arrangement.
Special Contracts
We are party to a Joint Venture Contract for Exploration and Exploitation of “La Cira-Infantas” Area, “Teca Cocorná” Area; and a Services and Technical Collaboration Contract for the “Casabe” field.
Joint Venture Contracts for Exploration and Exploitation of “La Cira-Infantas” Area and of “Teca-Cocorná” Area
These contracts between Ecopetrol S.A. and Occidental Andina LLC, executed on September 6, 2005 and June 24, 2014, respectively, have as their purpose, a joint collaboration between the parties with the goal of increasing the economic value of the La Cira-Infantas field and the Teca-Corcorná field by means of hydrocarbon exploration and production activities, including, among others, an incremental production project to improve the recovery factor, process optimization and exploratory activities.
Ecopetrol S.A. partially assigned its exploratory and production rights in the Contracted Areascontracted areas to Occidental Andina LLC. Ecopetrol S.A. provides financial resources and the preferential rights of use for the existing infrastructure in that zone and Occidental Andina LLC provides financial resources and the technical and operative experience in mature fields redevelopment projects and enhanced recovery technologies.
Ecopetrol S.A. is the operator under both Joint Venture Contracts, and on behalf of the parties is responsible for the conduction, execution and control, directly or via contractors, of the operational activities.
The La Cira-Infantas contract’s term is divided in three phases. The first phase lasts 180 days, the second 730 days and the third up to the economical limit.
The incremental production, after deduction of the royalties, is owned 52% by Ecopetrol S.A. and 48% by Occidental Andina LLC. These same percentages apply to the participation in the operational and direct expenses. Adjustments to the participations for the benefit of Ecopetrol S.A. will occur if there are high production levels or high prices.
The Teca-Cocorná contract’s term is divided in two phases. The first phase lasts three years, extendable for up to an additional year, the second 20 years counted as from the initiation for the second phase and will be reduced by the term of any extensions of the first phase.
The basic production is 100% owned by Ecopetrol S.A. The incremental production, after deduction of the royalties, is owned 60% by Ecopetrol S.A. and 40% by Occidental Andina LLC. These same percentages apply to the participation in the operational and direct expenses. Adjustments to the participations for the benefit of Ecopetrol S.A. will occur if there are high production levels and high prices.
Services and Technical Collaboration Contract “Casabe”
The purpose of the contract executed between Ecopetrol S.A. and Schlumberger Surenco S.A. on April 26, 2004, is the evaluation, design and execution of work programs specifically with the purpose of increasing the value in the Casabe field by means of hydrocarbon exploration and production activities to obtain incremental production, application of new technologies, application of techniques for deposits management and operational costs reduction. Ecopetrol S.A. is the operator and Schlumberger Surenco S.A. keeps the right of first option regarding the activities to be executed in the area of interest.
Both parties can invest in all the activities seeking to evaluate, obtain and incorporate incremental value in the area of interest. Such activities are developed directly by the parties or via contractors (Ecopetrol) or subcontractors (Schlumberger). Amounts expended pursuant to the contract are reimbursed depending on the incremental value (monthly valuation in US$ of the results obtained from the execution of the work programs) created through the contract and the activities executed thereunder.
Both Ecopetrol S.A. and Schlumberger Surenco S.A. commit to assume full responsibility for damages and/or losses suffered by their respective personnel and goods in development of the contract, regardless of the cause. The maximum authority is the Management Committee.
The contract had an initial term of 10 years and was amended several times to include an additional term of six years for which a new business was structured.
The National Hydrocarbons Agency (ANH)(ANH) and its Contracts
The National Hydrocarbon Agency (“ANH”)(Agencia Nacional de Hidrocarburos or ANH as per its Spanish acronym) was created by Decree Law 1760 of 2003 and was given the authority to administer all national hydrocarbon reserves under contracts executed beginning on January 1, 2004. Decree Law 1760 of 2003 states, “The Empresa Colombiana de Petróleos, Ecopetrol, is split, its organic structure is modified, and the Agencia Nacional de Hidrocarburos and the Sociedad Promotora de Energía de Colombia S.A. are created.” Prior to January 1, 2004, Ecopetrol S.A. had the authority to contract with third parties for the exploration and production of new areas.
The creation of the ANH did not modify the rights or obligations of Ecopetrol or other parties with respect to contracts in existence before January 1, 2004 when the ANH was created and therefore Ecopetrol retains the authority to execute agreements with respect to all areas that it held prior to that date.
Below, we include a brief description of each type of contract that we have entered into with the ANH:
Technical Evaluation Agreement
This type of contract grants the contractor the right to develop technical evaluation operations with operational autonomy at its own cost and risk, seeking to appraise the hydrocarbon potential, with the purpose of identifying the zones of prospective interest in the area by means of the execution of an exploratory program. The contractor has the option to request the conversion of a technical evaluation agreement (“Technical(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, the ANH only receives a percentage of oil revenues in two cases:
when the international oil prices rise beyond a specified price, above which the ANH has a right to participate in a share of the increased revenues generated, or |
in the case of recognition of production rights in an extended contractual phase. |
Under all E&P contracts executed since ANH’s 2008 bidding round, the ANH receives a percentage of the production from the beginning of the contract, upon the commencement of the production phase, and not only in the extension phase of the contract as mentioned in the previous paragraph. In addition, ANH has economic rights when the price of oil exceeds a reference price set in the contract (high price fee) and the superficiary canon. It also has a right to use of the subsoil from the beginning of the contract, calculated based on the area of the field during the exploration stage and based on the production during the evaluation and production stage.
E&P contracts have 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.
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
3.5 | Transportation and Logistics |
3.5.1 Transportation Activities
3.5.1 | Transportation Activities |
The transportation and logistics segment includes the transportation of crude oil, motor fuels, fuel oil and other refined products including diesel, jet and biofuels. We conduct most of these activities through our wholly owned subsidiary Cenit and its subsidiaries.
The map below shows the locations of the main transportation networks owned by our business partners and us.
Graph 5 – Map of Oil Pipelines
Graph 6 – Map of 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 3234 – Volumes of Crude Oil and Refined Products Transported
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(thousand bpd) | (thousand bpd) | |||||||||||||||||||||||
Crude oil transport(1) | 836.2 | 823.3 | 864.7 | 877.7 | 836.2 | 823.3 | ||||||||||||||||||
Refined products transport(2) | 273.4 | 268.2 | 262.4 | 275.3 | 273.4 | 268.2 | ||||||||||||||||||
Total | 1,109.6 | 1,091.5 | 1,127.1 | 1,153.0 | 1,109.6 | 1,091.5 |
(1) | The crude oil transported volumes correspond to the following systems: Ocensa Segment 3, ODC, Vasconia-Galan, Ayacucho-Galan, Ayacucho-Coveñas and Trasandino Pipeline. |
(2) | The pipelines transporting refined products include the following: Galan-Sebastopol, Galan-Salgar, Galan-Bucaramanga, Buenaventura-Yumbo and Cartagena-Baranoa. |
The volume of crude oil transported by Cenit’s main systems and those of affiliatesits subsidiaries increased in 20182019 by 1.6%5% compared to the previous year. This increase was mainly the result of a higher volume(i) increased oil production at the national level, including production by third parties, (ii) commercial strategies at the Monterrey facilities which facilitated the transport of Castilla Norteoil previously transported outside of our infrastructure, (iii) transportation of crude from the Acordionero oil field, and iv) increased crude oil comingtransport demand from the Barrancabermeja refinery through the Ayacucho-Coveñas 16”/24” systems. Additionally, we experienced an increase in the volume of Castilla crude oil transported through the Llanos node, which increased the proportion of that crude oil in the systems that reach Coveñas.refinery. Of the total volume of crude transported by oil pipeline, approximately 75.7%78.1% belonged to Ecopetrol’s corporate group.the Ecopetrol Group.
The volume of refined products transported by Cenit increased by 1.9%0.7% in 20182019 mainly due to growth of local fuel demand.demand from the frontier with Venezuela and higher volumes in the Cartagena – Baranoa pipeline, which more than offset lower volumes in the Galan – Sebastopol pipeline, which in turn was due to programed maintenance at the Barrancabermeja refinery and the import of refined products through the Buenaventura port. Of the total volume of refined products transported in multi-purpose pipelines during the year, 33%32.9% 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 1,500,0001,497 thousand bpd in 20172018 to 1,497,0001,486 thousand bpd in 2018.2019 primarily due to scheduled maintenance. Our main refined productsmulti-purpose pipeline transportation capacity decreasedincreased from 518.6 thousand bpd in 2017 to 510 thousand bpd in 2018.2018 to 511 thousand bpd in 2019.
References to our crude oil transportation capacity in this annual report refer to the capacity of the pipelines that belong to Cenit and its subsidiaries to transport crude oil volumes either to the refineries or to our export facilities. In addition, we have other feeder systems that transport oil volumes from producing facilities or other pumping stations to these main pipelines. References to our refined products transportation capacity refer to the capacity of pipelines that begin in the Galan station (Barrancabermeja refinery) and Cartagena station (Cartagena Refinery).
3.5.1.1 | Pipelines |
As of December 31, 2018,2019, 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% of the oil pipeline shipping capacity in Colombia. By December 31, 2018,2019, our network of crude oil and multipurposemulti-purpose pipelines was approximately 9,0719,106 kilometers in length. The transportation network consists of approximately 5,3625,367 kilometers of main crude terminals and oil pipeline networks connecting various fields to the Barrancabermeja refinery and Reficar, as well as to our export facilities.
We also own 3,7093,739 kilometers of multipurposemulti-purpose pipelines for transportation of refined products from the Barrancabermeja refinery and from Reficar to major distribution points. Out of the 5,3625,367 kilometers of crude oil pipelines, owned by us, 3,1503,155 kilometers of crude oil pipeline are wholly owned, and 2,212 kilometers of crude oil pipeline are owned through non-wholly owned subsidiaries.
The following table sets forth our main pipelines in which we own an indirect interest as of December 31, 2018.2019.
Table 3335 – Our Main Pipelines
Pipeline | Kilometers | Capacity (mbd) | Product Transported | Origin | Destination | Indirect Ownership Percentage | Kilometers | Capacity (mbd) | Product Transported | Origin | Destination | Indirect Ownership Percentage | ||||||||||||||||||||||||
Caño Limón-Coveñas | 771 | 250 | Crude Oil | Caño Limón | Coveñas | 100.00 | % | 771 | 250 | Crude Oil | Caño Limón | Coveñas | 100.00 | % | ||||||||||||||||||||||
Oleoducto de Alto Magdalena (OAM) | 391 | 110 | Crude Oil | Tenay | Vasconia | 95.8 | % | 391 | 110 | Crude Oil | Tenay | Vasconia | 95.8 | % | ||||||||||||||||||||||
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 | 314 | (2) | Crude Oil | East fields | Monterrey Cusiana | 65.00 | % | ||||||||||||||||||||
Oleoducto Bicentenario de Colombia | 230 | 110 | (3) | Crude Oil | Araguaney | Banadia | 55.97 | % | 230 | 110 | (3) | Crude Oil | Araguaney | Banadia | 55.97 | % |
(1) | Ocensa has four segments with different capacities. 745 mbd refers to the capacity of segment two (El Porvenir-Vasconia). The capacity of the other segments are as follows: |
a. | Cupiagua-Cusiana (segment zero): 198 mbd |
b. | Cusiana-El Porvenir (segment one): 745 mbd |
c. | Vasconia-Coveñas (segment three): 550 mbd |
(2) | Transportation capacity for this pipeline is measured by using crude oil viscosity of 690 cStk (30° C). |
(3) | Represents the contractual crude oil transportation capacity for the pipeline currently in operation. |
As of December 31, 20182019 we owned 7374 stations, 3940 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, 2018,2019, we had a nominal storage capacity associated with the transportation network of 17.716.4 million barrels of crude oil and 4.94.8 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 bpd at 300 cSt of diluted crude oil from the Chichimene and Castilla fields to the Monterrey pumping station and the transportation of 45,000 bpd of diluent (naphtha) between the Apiay station and the Castilla and Chichimene fields.
The 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 is currently in the commissioning process.
Chinchina – Pereira product pipeline realignment
Oleoducto al Pacifico SASThe main objective of the Chinchina-Pereira project was to move the product pipeline infrastructure away from densely populated areas. The realignment of the pipeline increased the reliability and safety of the transportation of refined products to the western region of Colombia by avoiding geotechnically active areas. The pipeline is 55 kilometers long.
GivenThe refined product pipeline Salgar - Cartago - Yumbo realignment between the uncertainties aroundtowns Chinchiná and Pereira passes through the future resultsmunicipalities of the explorationSanta Rosa de Cabal and production activities in ColombiaMarsella. The project was commissioned and the current expected return of the investment, in December 2017 the parties engaged in the Oleoducto al Pacifico suspended the project. Based on our current view, this decision has had no impact on the oil industry in Colombia and can be reconsidered in the event the transportation system may be necessary.inaugurated during September 2019.
Replacement of El Porvenir Station Pumping Units
During 2018,2019, Ocensa began to replacecompleted the replacement of five internal combustion pumping units with internal combustionelectrical energy engines and the installation of an electrical power generation plant with electrical energy engines.a 6 MW gas turbine. The goalstartup of thisthe project isreduces Ocensa’s CO2 emission to reduce the level44,000 tons of greenhouseCO2 equivalent per year, which represents about 15% of Ocensa’s total operations gas emissions and noise pollution, thereby having a positive effect on the environment and potentially reduceemissions. The project has also resulted in savings in operation and maintenance costs.
Adaptationcosts of Cusiana Truck Unloading FacilityUS$9.8 million between 2018 and 2019.
The Cusiana truck unloading facilities enables explorationReplacement 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 production companies in blocks or areas not connectedPLEM (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 network to access Ocensarepair of four welded joins of 42” and the stabilization of the last 72 meters of the seabed of the offshore 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
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 1.241.62 million bpd for crude oil. Our import capacity of refined products and crude oil reached 0.19 million bpd and 0.250.33 million bpd, respectively.
Our crude oil loading facilities can load tankers of up to 350 thousand deadweight tonnage (DWT). Adjacent to these loading facilities we also have storage facilities that are capable of storing 11.611.8 million barrels. Our docks used for import and export of refined products can load tankers of 70 thousand DWT. Additionally, these facilities have storage capacity of up to 5.65.8 million barrels.
3.5.2 Other Transportation Facilities
3.5.2 | Other Transportation Facilities |
We have entered into transportation agreements with tanker truck and barge companies in order to transport crude oil from locations that do not have pipeline connections to refineries and export facilities. The volume of refined products that cannot be transported by pipelines or tanker trucks because of capacity limitation is transported by barges. During 2018, 27.92019, 27.0 million barrels of crude oil and refined products were transported by tanker trucks, and 7.210.34 million barrels of crude oil and refined products were transported by barges, particularly using the Magdalena River, connecting Barrancabermeja with Barranquilla and Cartagena.
3.5.3 Marketing of Transportation Services
3.5.3 | Marketing of Transportation Services |
Cenit and its subsidiaries’ main line of business is the crude oil pipeline transport (75%(76.7% of revenues), followed by the refined products pipeline transport (16%(14.4% of revenues) and ports and related services (6%(4.4% of revenues). Both crude and refined product pipeline transport are regulated activities; crude oil pipeline transport services are regulated by the Ministry of Mines and Energy, while refined product pipeline transport services are regulated by theComisión de Regulación de Energía y Gas(CREG).
Transportation contracts of crude oil may take several forms: ship or pay (payment for the availability of a fixed capacity in the system), ship and pay (payment for volumes actually transported) or spot.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%73.3% of this business segment’s revenues in 2018.2019. Transportation services for crude oil provided to Ecopetrol S.A. represented 57%61.3% of this business segment’s crude oil transport revenues.
Cenit also transports refined products. Its main client for this service is Ecopetrol S.A., which accounted for 40%40.1% of refined products pipeline transport revenues in 2018,2019, principally due to the transport of naphtha, diesel and gasoline. Cenit also has 1415 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.
Deregulated businesses, such as ports and crude-loading facilities, represent a smaller portion of Cenit’s revenue (6%(4.4% in 2018)2019). Clients for these businesses include some of the same parties for which Cenit provides crude oil and refined products transportation services.
Developments with certain clients of Bicentenario and Cenit
Oleoducto Bicentenario de Colombia S.A.S.
During July 2018, the carriers Frontera Energy Colombia Corp. (“Frontera”)(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 on March, 2019.
On June 14, 2019, and June 26 2019, Bicentenario filed arbitration claims against Vetra and Canacol, respectively, in accordance with the arbitration clause of the Transportation Agreement to claim any compensation, indemnification or other restitution deriving from the alleged early termination of said agreements.
As part of the litigation strategy of Bicentenario, the above-mentioned claims were withdrawn, and new claims were filed, as explained below:
· | On November 12, 2019, Bicentenario filed an arbitration claim against Frontera, before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 119448), in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the Transportation Agreement up to the end of theShip 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 theShip 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 theShip or Pay term (2024). |
On December 3, 2019, Bicentenario also filed an arbitration claim against its shareholders Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp., Canacol and Vetra under clause 23(d) of theAcuerdo Marco de Inversiónbefore the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 119872) contending that since Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp. Canacol and Vetra did not perform the actions requested by Bicentenario necessary to support the indebtedness of the Bicentenario Project, they are in breach of theAcuerdo Marco de Inversiónand therefore must compensate and indemnify Bicentenario due to their unlawful conduct.
On January 10, 2020, Bicentenario filed an arbitration claim against Canacol under the storage agreement (contrato de almacenamiento terminal coveñas) before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce (Case No. 120386) in order to obtain the corresponding compensation, indemnification or other restitution deriving from the alleged early termination of the storage agreement up to the end of theShip or Pay term (2024).
As of the date of these financial statements,this annual report, Bicentenario continues evaluating its options under the Transport Agreements and the Shareholders Agreement (Acuerdo Marco de Inversión) in order to guarantee compliance and claim anythe compensation, indemnification or other restitution deriving from the alleged early termination of said agreements and any other contractual breaches by the Carriers.
Cenit Transporte y Logística de Hidrocarburos S.A.S.
During July 2018, the carriers Frontera, Vetra and Canacol (“carriers”)(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.
InDuring 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 on March and June 2019, respectively.
As of the same will occur against Canacol.
date of this annual report, arbitrators have been designated by the parties for the aforementioned proceedings.
Refining and Petrochemicals |
3.6 Refining and Petrochemicals
3.6.1 | Refining |
Our main refineries are the Barrancabermeja refinery, which Ecopetrol S.A. directly owns and operates, and a refinery in the Free Trade Zone in Cartagena owned by Reficar, a wholly owned subsidiary of Ecopetrol S.A. Ecopetrol S.A. operates this refinery and also owns and operates two other minor refineries – Orito and Apiay -, but these are considered part of the upstream segment since the majority of production is for self-consumption.
Our refineries produce a full range of refined products, including gasoline, diesel, jet fuel, LPG and heavy fuel oils, among others.
The following table sets forth our average daily installed and actual refinery capacity for each of the last three years:
Table 34 –Average36 – Average Daily Installed and Actual Refinery Capacity
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capacity | Through- put | % Use | Capacity | Through- put | % Use | Capacity | Through- put | % Use | Capacity | Through-put | % Use | Capacity | Through-put | % Use | Capacity | Through-put | % Use | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
(bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (bpd) | (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 | % | 250,000 | 218,612 | 87 | % | 250,000 | 221,946 | 89 | % | 250,000 | 209,838 | 84 | % | ||||||||||||||||||||||||||||||||||||||||||||||||
Reficar(1) | 150,000 | 151,331 | 101 | % | 150,000 | 135,700 | 90 | % | 150,000 | 117,188 | 78 | % | 150,000 | 155,049 | 103 | % | 150,000 | 151,331 | 101 | % | 150,000 | 135,700 | 90 | % | ||||||||||||||||||||||||||||||||||||||||||||||||
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 | % | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Apiay | 2,500 | 779 | 31 | % | 2,500 | 939 | 38 | % | 2,500 | 997 | 40 | % | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Orito | 2,300 | 1,314 | 57 | % | 2,300 | 1,228 | 53 | % | 2,500 | 948 | 38 | % | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total | 404,800 | 375,444 | 93 | % | 405,000 | 347,483 | 86 | % | 405,000 | 332,751 | 82 | % | 404,800 | 375,754 | 93 | % | 404,800 | 375,444 | 93 | % | 405,000 | 347,483 | 86 | % |
(1) | Reficar’s operations were fully stabilized during the second half of 2017. |
3.6.1.1 Barrancabermeja Refinery
We estimate that theThe Barrancabermeja refinery supplies 48%approximately 51.6% 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 3537 – Production of Refined Products from the Barrancabermeja Refinery
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(bpd) | (bpd) | |||||||||||||||||||||||
LPG, Propylene and Butane | 11,813 | 10,712 | 11,956 | 10,114 | 11,813 | 10,712 | ||||||||||||||||||
Gasoline Fuels and Naphtha | 58,623 | 56,047 | 59,305 | 64,063 | 58,623 | 56,047 | ||||||||||||||||||
Diesel | 58,305 | 56,090 | 48,233 | 57,469 | 58,305 | 56,090 | ||||||||||||||||||
Jet Fuel and Kerosene | 23,604 | 20,421 | 20,435 | 24,320 | 23,604 | 20,421 | ||||||||||||||||||
Fuel Oil | 36,636 | 38,217 | 55,730 | 32,009 | 36,636 | 38,217 | ||||||||||||||||||
Lube Base Oils and Waxes | 729 | 609 | 668 | 797 | 729 | 609 | ||||||||||||||||||
Aromatics and Solvents | 3,106 | 2,847 | 2,879 | 2,652 | 3,106 | 2,847 | ||||||||||||||||||
Asphalts and Aromatic Tar | 31,104 | 26,468 | 14,092 | 29,593 | 31,104 | 26,468 | ||||||||||||||||||
Polyethylene, Sulfur and Sulfuric Acid | 1,479 | 1,509 | 1,541 | |||||||||||||||||||||
Polyethylene, Sulphur and Sulphuric Acid | 1,139 | 1,479 | 1,509 | |||||||||||||||||||||
Total | 225,399 | 212,920 | 214,839 | 222,156 | 225,399 | 212,920 | ||||||||||||||||||
Difference between Inventory of Intermediate Products | (1,018 | ) | (405 | ) | (661 | ) | ||||||||||||||||||
Difference between Inventory of Intermediate Product | (703 | ) | (1,018 | ) | (405 | ) | ||||||||||||||||||
Total Production | 224,381 | 212,515 | 214,178 | 221,453 | 224,381 | 212,515 |
In 2018,2019, total production from the Barrancabermeja refinery increaseddecreased by 5.6% from 212,515 bpd in 2017 to 224,381 bpd in 2018 primarily as a result of stable operation and improved throughput1.3% mainly due to the implementationimpact of initiatives to segregate and purchase light and intermediate crudes.the scheduled maintenance of the diesel hydrotreating unit.
We own and operate four petrochemical plants and one paraffin and lube plant located within the Barrancabermeja refinery. In 2018,2019, we produced 48,46833,309 tons of low-density polyethylene, a decrease of 9.3%31.3% compared to the production of 53,41748,468 tons in 2017.2018. This decrease was due primarily to a reduction of ethylene availability due to a turnaround of one ofmaintenance performed on the fluid catalytic cracking (FCC) units.Turboexpander unit. We produced 894657.9 mboe of aromatics (benzene, toluene, xylene, orthoxylene, heavy aromatics and cyclohexane), a 4.3% increase26.4% decrease as compared with the production of 857894 mboe of aromatics in 2017.2018. The increasedecrease was mainly the result of an increase in local demand for benzene, toluene, xylene, orthoxylene (BTXO).scheduled planned maintenance of the Aromatic unit.
The gross refining margin decreased from US$13.5 per barrel in 2017 to US$11.8 per barrel in 2018 to US$10.6 per barrel in 2019, primarily due to lower product prices and higher crude price spreads for the decrease in the price of refined products, mainly gasoline and fuel oil, as compared to the ICE Brent.refinery feed slate. The average conversion index for the Barrancabermeja refinery was 86.8% in 2019 and 84.6% in 2018 and 82.7% in 2017.2018. This increase was primarily due to the operation at higher capacityyields of the units that convert bottom streams into diesel.valuable products and lower fuel oil yields.
3.6.1.2 | Cartagena Refinery |
The following table sets forth the production of refined products from the Cartagena Refinery for the periods indicated.
Table 3638 – Production of Refined Products from the Cartagena Refinery
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(bpd) | (bpd) | |||||||||||||||||||||||
LPG, Propylene and Butane | 4,227 | 6,791 | 6,080 | 4,255 | 4,227 | 6,791 | ||||||||||||||||||
Gasoline Fuels and Naphta | 51,703 | 43,728 | 35,012 | 49,904 | 51,703 | 43,728 | ||||||||||||||||||
Diesel | 76,833 | 60,467 | 40,950 | 79,069 | 76,833 | 60,467 | ||||||||||||||||||
Jet Fuel and Kerosene | 8,057 | 6,700 | 5,768 | 9,331 | 8,057 | 6,700 | ||||||||||||||||||
Fuel Oil | 4,671 | 10,150 | 24,602 | 3,660 | 4,671 | 10,150 | ||||||||||||||||||
Sulfur | 581 | 446 | 241 | |||||||||||||||||||||
Sulphur | 585 | 581 | 446 | |||||||||||||||||||||
Total | 146,072 | 128,282 | 112,653 | 146,804 | 146,072 | 128,282 | ||||||||||||||||||
Difference between Inventory of Intermediate Products | 39 | 3,916 | 911 | 2,262 | 39 | 3,916 | ||||||||||||||||||
Total Production(1) | 146,111 | 132,198 | 113,564 | 149,066 | 146,111 | 132,198 | ||||||||||||||||||
Petcoke (Metric tons) | 984,558 | 704,073 | 601,163 | 922,460 | 984,558 | 704,073 |
(1) | Does not include petcoke. |
The following tables set forth the imports and sales of refined products from the Cartagena Refinery for the periods indicated.
Table 3739 – 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 | 2019 | 2018 | 2017 | |||||||||||||||||||
(bpd) | (bpd) | |||||||||||||||||||||||
Imports | ||||||||||||||||||||||||
Motor Fuels | - | 212 | 3,641 | 521 | - | 212 | ||||||||||||||||||
Diesel | - | – | 6,155 | - | - | – | ||||||||||||||||||
Jet Fuel and Kerosene | 466 | 847 | 2,211 | - | 466 | 847 | ||||||||||||||||||
Alkylate | - | – | 83 | - | - | – | ||||||||||||||||||
LPG and Butane | 739 | 618 | 355 | 990 | 739 | 618 | ||||||||||||||||||
Total Imports | 1,205 | 1,677 | 12,445 | 1,511 | 1,205 | 1,677 |
During 2018,2019, the Cartagena Refinery imported products in order to achieve the planned input of the Alkylation Unit and to cover the North Coast sales demand primarily due to an unscheduled operational turnarounds duringevent at this unit in the lastthird quarter of 2018.the year.
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(bpd) | (bpd) | |||||||||||||||||||||||
Sales | ||||||||||||||||||||||||
Motor Fuels | 52,126 | 44,051 | 38,534 | 49,865 | 52,126 | 44,051 | ||||||||||||||||||
Diesel | 78,007 | 60,289 | 46,060 | 77,981 | 78,007 | 60,289 | ||||||||||||||||||
Jet Fuel and Kerosene | 8,082 | 7,489 | 7,479 | 9,063 | 8,082 | 7,489 | ||||||||||||||||||
Fuel Oil | 4,704 | 7,528 | 16,593 | 3,713 | 4,704 | 7,528 | ||||||||||||||||||
Other Products | 19,942 | 27,099 | 22,990 | 22,435 | 19,942 | 27,099 | ||||||||||||||||||
Total Sales | 162,861 | 146,456 | 131,656 | 163,057 | 162,861 | 146,456 |
During its stabilization period in the second half of 2017, the Cartagena Refinery reached the goal of completingcompleted individual unit performance tests (for 100% of units), and the Global Performance Test on December 5, 2017.
As part ofDuring the initial phase of the refinery optimization process, duringin the first half of 2018, the maximum loadcharge capacity of certainseveral of the Cartagena Refinery’sRefinery plants were tested and provided the following results: (i) the cokeDelayed Coking unit, withreaching a maximum loadfeed of 46,088 bpd versus a nominal capacity of 45,000 bpd, (ii) the crude unit, withreaching 166,607 bpd versus a nominal capacity of 150,000 bpd and (iii) the hydrocracking unit with,reaching 38,204 bpd versus a nominal capacity of 35,000 bpd.
In August 2018 a test was run using 100% domestic crude during nine days, achieving an average throughput of 164 mbd. In September 2018, the highest average throughput per month under regular operationof 161 mbd was achieved since the refinery’s commissioning, at 161 mbd.commissioning.
Finally, the fluid catalytic cracking unit ran atreached 43,515 bpd versus a nominal capacity of 40,000 bpd after coupling and putting into operation the turbo expander.expander into operation.
In terms ofThe gross refining margin, the refinery progresseddecreased from US$9.5 per barrel in 2017 to US$11.0 per barrel in 2018.2018 to US$9.2 in 2019 mainly due to lower product prices and higher crude price spreads across international markets. Throughput also improvedincreased during 2018, increasing2019, 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 process2018 to 155 mbd in 2018.
2019. The Cartagena Refinery’s 20182019 figures already reflect the operation of all units, thus totalunits.
Total sales have increaseddecreased as compared to 2017, from US$3,085 million in 2017 to2018, US$4,129 million in 2018.2018 versus US$3,904 million in 2019, mainly due to trends in the international market behavior characterized by lower product prices. A total of 55.356.6 million barrels of crude were processed in 20182019 compared to 49.555.3 million barrels of crude processed in 2017.2018. Exports to international markets represented 42%46% of total sales (US$1,7491,800 million).
Financing
On December 30, 2011, with the approval from the Colombian Ministry of Finance and Public Credit, Reficar executed a US$3.5 billion project finance to partially fund the expansion and modernization of the Cartagena Refinery, loans with tenors of 14 and 16 years from Commercial Banks and Export Credit Agency Facilities, respectively. The aggregate amount drawn under these finance agreements totaled US$3,496.63,497 million. These credit agreements included a mechanism by which Reficar can exit the facility by transferring the debt to the Ecopetrol parent level by either (i) the occurrence of a mandatory debt assumption event or (ii) a voluntary debt assumption.
During 2017, Reficar received capital injections of US$269 million to cover project capital expenditures, start-up costs, one-off stabilization costs of the new refinery and the debt service payments due on June 20, 2017. The amount requested by Reficar under the Construction Support Agreement was US$97 million. The amount requested by Reficar under the Debt Service Guarantee Agreement was US$172 million. There was no need to request additional contributions under the Debt Service Guarantee to cover the debt service payment due on December 2017.
The principal amount repaid by Reficar during 2016 was US$269 million and during 2017 was US$130 million. Interest payments during 2016 and 2017 were US$87 million and US$42 million, respectively.
As part of Ecopetrol Group’s strategy to optimize its capital structure, on December 13, 2017, with the approval of the senior lenders and the Colombian Ministry of Finance and Public Credit, Ecopetrol S.A. voluntarily assumed Reficar’s senior debt. As of the date of the voluntary assumption, Reficar owed the senior lenders a principal amount of US$2,666 million (in nominal terms).
In order to finalize the implementation of Ecopetrol Group’s strategy to optimize its capital structure, the following capital injections were undertaken by Ecopetrol on December 13, 2017, increasing its shareholding participation in Reficar from 75.96% to 99.34%:
i. | As a result of the voluntary debt assumption, Reficar assumed an account payable in the amount of US$2,596 million (book value for Reficar’s senior debt under IFRS) in favor of Ecopetrol. As a shareholder, Ecopetrol requested that such account be repaid with Reficar shares. |
ii. | Ecopetrol requested that the existing subordinated COP-denominated loan it granted |
iii. | Additionally, on December 7, 2018, the direct shareholding participation of Ecopetrol S.A. in Reficar increased from 75.96% to 99.34%, after additional contributions of paid-in capital. |
3.6.1.3 | Esenttia S.A. |
During 2018, Esenttia2019, Esenttia’s production totaled 447460 thousand tons of petrochemical products, a 2%3% increase compared to the 441447 thousand tons produced in 20172018, primarily due to delaysgreater supply of the required raw material due to conditions in the supply of raw materials as a result of Hurricane Harvey.American market. The total contribution margin in 20182019 (including the contribution of polypropylene, polyethylene and masterbatches) was 11.2% lower27% higher than in 2017, a decrease2018, an increase from US$215 per ton in 2017 to US$191 per ton in 2018.2018 to US$242 per ton in 2019. The decreaseincrease in contribution margin was primarily due to higher volatilityinventory levels of the required raw material allowing for a reduction in the propylene market, Esenttia’s main feedstock.costs.
Table 3840 – Operating Capacity of Esenttia
For the year ended December 31, | For the year ended December 31, | |||||||||||||||||||||||
2018 | 2017 | 2016 | 2019 | 2018 | 2017 | |||||||||||||||||||
(Metric Tons) | (Metric Tons) | |||||||||||||||||||||||
Average capacity | 470,000 | 470,000 | 470,000 | 470,000 | 470,000 | 470,000 | ||||||||||||||||||
Throughput | 447,290 | 440,632 | 444,812 | 459,737 | 447,290 | 440,632 | ||||||||||||||||||
% Use | 95 | % | 94 | % | 95 | % | 98 | % | 95 | % | 94 | % |
3.6.1.4 | Biofuels |
We have investments in two biofuel companies: (i) Bioenergy S.A.S., in which we own indirectly 99.35%99.61% of the shares, that in 2017 began the operation of an ethanol plant with nominal capacity of 480,000 liters/day, and (ii) Ecodiesel Colombia S.A., in which we own 50% of the shares, currently in operation with a theoretical capacity of 100,000 tons per year of biodiesel.
OnMarch 10, 2020, Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S were admitted to reorganization processes by the Superintendence of Companies of Colombia under Law 1116 of 2006, which will allow them to organize financial, administrative and operational aspects to preserve their sustainability. Those entities are not material subsidiaries and therefore these processes are not expected to have a material adverse effect on our consolidated results of operations and financial condition.
3.6.2 MarketingBioenergy S.A.S. and SupplyBioenergy Zona Franca S.A.S. were admitted to this reorganization process mainly due to lower than expected agricultural productivity and a deterioration in market conditions that make the current level of Refined Productsdebt unsustainable. By this process, they will seek to establish agreements with their main creditors as well as liquidity alternatives to maintain the viability of the companies.
3.6.2 | Marketing and Supply of Refined Products |
We are the main producer and supplier of refined products in Colombia. We market a full range of refined and feedstock products, including regular and high-octane gasoline, diesel fuel, jet fuel, LPG, natural gas and petrochemical products, among others.
Domestic sales of products increased by 4.77.9 mboepd, an increase of 1.6%2.6% compared to 2017.2018. This increase is primarily the result of: (i) a 2.5%4.3%, or 3.76.5 mboepd, increase in middle distillates sales mainly due to higher economic growth in general, change in the bio-fuel blend percent and higher airplane transportation demand by passengers,passengers; (ii) a 5.3%5%, or 0.95.5 mboepd, increase in gasoline primarily as a result of higher economic growth and increased demand in the border region, given the decrease in the supply of Venezuelan gasoline; and (iii) a 77%, or 6.5 mboepd, decrease in LPGfuel oil sales primarily as a result of lower production at Reficar and Barrancabermeja, (iii) a 12%, or a 2.2 mboepd, increase in petrochemical sales, dueorder 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.generate products with higher value.
During 2018, 8.82019, 3.4 million barrels of diesel and 3.43.8 million barrels of gasoline produced by Reficar 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, 1.2 million barrels of diluent produce by Reficar were used to transport crude reducing diluent imports. In addition, Ecopetrol imported petrochemicals in order to complement the national supply, generating additional sales of lubricating bases, polyethylene, hexanes and others.
Exports of products increased by 8.3%5.9% compared to 2017, 12 mbd2018, 6.4 mboepd from Reficar and 3.0 mbd-0.2 mboepd from Ecopetrol, primarily due to (i) a 97%39%, or 16 mbd13 mboepd increase in exports of high sulfur diesel partially offset byand (ii) a 21%35%, or 8.4 mbd8.3 mboepd decrease in fuel oilgasoline exports.
3.7 Research and Development; Intellectual Property
3.7 | Research and Development; Intellectual Property |
Our innovation and technology center is the Colombian Petroleum Institute, established in 1985 and located in Bucaramanga, Santander. In 2018,2019, research and development expenses were US$40.6750.1 million, compared to US$25.740.7 million in 2017.2018. Technology and innovation are essential to our efforts to add value to our business segments through the development of proprietary technologies and competitive advantages and the adaptation of third-party technologies to our processes.
The focus ofOur research, technology development isand innovation efforts are focused on designing high added-value productsfour main strategies: extending the technical limits for reserves growth; increasing the efficiency and solutionssustainability of our operations preparing the corporation for Ecopetroldecarbonization and the Colombian oil industry.energy transition; and increasing the digitalization of our company. The scope of the Colombian Petroleum Institute activities covers all of our value chain segments: exploration, production, refining, transportation and commercialization, as well as environmental sustainability and asset integrity.
By 2030, our goal is to achieve a 20% reduction of our equivalent carbon dioxide emissions through energy efficiency projects, abatement of fugitive methane emissions, zero routine gas flaring in our operations, and carbon capture, utilization and storage (CCUS). We are diversifying the sources of energy for our operations by deploying a portfolio of renewables, including solar, wind and possibly geothermal resources. We will also monitor the progress of technological advances that could enable the use of green hydrogen in our refining and petrochemical processes. As water is a fundamental resource, our efforts will also include a water management program that encompasses the conservation, recycling, reuse and valorization of production water streams. Finally, we will also explore the production of high performance, non-combustible materials from petroleum molecules.
Each year Ecopetrol presents to the Colombian Institute for the Development of Science and Technology (Instituto(Instituto Colombiano para el Desarrollo de la Ciencia y laTecnología,, or COLCIENCIAS) its research, technology development projects and innovation initiatives, in order to obtain certifications for its science and technology investments. COLCIENCIAS certifies science and technology investments, which are deductible from income tax upon execution; and Ecopetrol applies the tax benefit. In 2018,2019, we obtained US$1.661.38 million in science-and-technology-related tax benefits certified by COLCIENCIAS.
Our intangible assets are preserved through a technological value-generation process and an intellectual property protection process, which include the consolidation of trade secrets, patents, copyrights, trademarks, industrial designs, and publications in specialized journals. Ecopetrol has filed 224247 patent applications in the last 11 years, 1723 of them in 2018.2019. Our most recent patent applications include innovative technologies, such as (i)(i) a method that uses nanofluids to improve the oil relative permeability in heavyobtaining carbon quantum dots from petroleum molecules and extra-heavy oil fields,its applications, (ii) a deviceprocess for controlling production fluctuations at the well head, and the subsequent separationobtaining a transportable hydrocarbon blend composed of heavy oilcrudes and water,non-conventional diluents, (iii) a downhole diluent injection process to enhanceand its monitoring and control scheme for the flow capacityrecovery of oil-water-diluent mixtures and the dilution capacity of diluents used inextra heavy and extra-heavy oil production and transportation, (iv) a method and device to determine the volumetric contraction of mixtures of heavy oil and light hydrocarbons, and (v) a visbreaking process for refining heavy petroleum components in the presence of a catalyst and hydrogen at low pressure.oil.
In 2018,2019, Ecopetrol declared two industrial secrets that strengthen its competitive advantages in heavy oil processing and flow assurance; and in offshore exploration, specifically in the exploration and transportationColombian sector of hydrocarbons.the Caribbean Sea. The Colombian and international authorities granted us 15eight new patents, includingpatents—seven in Colombia and one in Mexico and another in Ecuador.India. We currently hold 8793 patents in Colombia, the United States, Mexico, Russia, Peru, Venezuela, Ecuador, Brazil, Nigeria, Indonesia, India and Malaysia.
In 2018,2019, Ecopetrol S.A. licensed 7six of its technologies to private companies for manufacturing, marketing commercialization and after-salestechnical support. To date, weWe currently have 46 technologies licensed 49 technologies to Colombian and multi-national companies.
3.8 Applicable Laws and Regulations
3.8 | Applicable Laws and Regulations |
3.8.1 Regulation of Exploration and Production Activities
3.8.1 | Regulation of Exploration and Production Activities |
3.8.1.1 | Business Regulation |
Pursuant to the Colombian Constitution, the Nation is the exclusive owner of 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.
Decree 3004 of 2013, sets forth guidelines regarding future regulation related to the exploration and exploitation of unconventional hydrocarbon resources in Colombia. Under Decree 3004, an unconventional field is defined as a rock formation with low primary permeability that requires stimulation in order to improve the conditions of mobility and recovery of hydrocarbons. Resolution 90341 was issued on March 27, 2014 in development of the mandate of Decree 3004 setting the technical conditions, requirements and procedures for the exploration and exploitation of unconventional fields. Resolution 90341 of 2014 is currently suspended by order of the Council of State, as a precautionary measure in the analysis of a legal action filed by the Universidad del Norte. This precautionary measure covers both the Decree 3004 of December 26, 2013 and Resolution N° 90341 of March 27, 2014, related to unconventional fields.
On May 26, 2015, Decree 1073 compiled the majority of Colombian decrees in force regarding the administrative sector of mines and energy.
Agreement (Acuerdo, a type of regulation) 004 of 2012, as issued by the ANH, amends Agreement 008 of 2004 and sets forth the rules governing the award of exploration and production areas and the execution of contracts. As set forth below, Agreement 002 of 2017 replaces 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.
Agreement 002 of 2017, as issued by the ANH on May 18, 2017, replaces Agreement 004 of 2012, Agreement 003 of 2014, and Agreements 002, 003, 004 and 005 of 2015. It establishes the general structure of the New Regulation for Administration and Assignment of Areas and the general guidelines regarding future hydrocarbon contracts in Colombia. Seeking the interests of the Nation, the market conditions, the national hydrocarbon sector strategy, the competitive context of producer countries and the Nation’s social and environmental evolution.
Agreement 002 of 2017 adapts the existing regulations for the selection of contractors, and the applicable rules for the award, execution, termination, liquidation, monitoring, control and surveillance of the contracts signed with the ANH.
As mentioned above, on November 8, 2018, the High Court for Administrative Matters (Consejo de Estado) analyzed the potential annulment of Decree 3004 of 2013 and Resolution 90341 of 2014 and issued an interim order to suspend their effects as of such date. However, the aforementioned Court established that, “… if the National Government is interested in investigation, clarifying and exploring the feasibility of the hydraulic fracturing procedure for the exploration and exploitation of hydrocarbons in unconventional reservoirs (YNC), it could advance in the so-called Comprehensive Research Pilot Projects (PPII).”
On February 4, 2019, the ANH published the new model contract for offshore exploration and production. The purpose of this new model contract is to foster and stimulate investments in exploration and the exploitation of offshore hydrocarbons, enhancing Colombia’s competitiveness to attract and retain investments from large and experienced O&G operators.
On February 5, 2019, the ANH by implementing theAcuerdo No. 2 (Agreement No. 2) opened a permanent competitive bidding procedure (PPAA), which aims to select, among previously qualified proponents on equal terms, the most favorable offers to allocate the areas previously determined, demarcated and classified by the ANH.
As a result, in 2019, the ANH issued terms of references for the PPAA and carried out two cycles both of which were divided in the following four stages: (i) submission of the proposals and selection of the initial proponent, (ii) submission of counterproposals and selection of the most favorable counterproposal, (iii) the exercise of the right of option of improvement by the initial proponent and (iv) allocation of areas and execution of contracts.
As result of the first cycle of the PPAA, the ANH offered 18 continental areas and two offshore areas. As part of the second cycle, the ANH allocated 14 onshore blocks.
Resolution 078 of 2019, as issued by the ANH, approved the terms of reference and the model of the contract for the “permanent bidding procedure.” Pursuant to this procedure, the ANH will select areas over which proposals may be received at any time, without the need of launching specific bidding procedures for their allocation.
3.8.1.1.1 Environmental Licensing and Prior Consultation
3.8.1.1.1 | Environmental Licensing and Prior Consultation |
Law 99 of 1993 and other environmental regulations, such as Decree 1076 of 2015 in particular (compilation decree regarding the administrative sector of environment and sustainable development), impose on companies, including oil and gas companies, the obligation to obtain an environmental license prior to undertaking any activity that may result in the serious deterioration of renewable natural resources, or that may have the capacity of materially modifying the physical environment.
The National Authority on Environmental Licensing (ANLA), created by means of Decree 3573 of 2011, is the 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.
If the projects or activities could have a direct impact over the territories or the interests of indigenous, Afro-Colombian or Raizal communities, the Colombian Constitution provides that the companies developing such projects or activities must undertake a public consultation process with those communities before initiating such projects or activities. This consultation process is a prerequisite for obtaining the required environmental licenses.
In addition, the Colombian Constitution and laws establish that, as part of the public participation mechanisms, Colombian individuals may request information regarding the activities of the project and their potential impacts. They may also request to undertake an environmental hearing so as to obtain information of the project subject to environmental licensing.
On May 26, 2015, the Ministry of Environment and Sustainable Development (“MESD”)(MESD) issued Decree 1076, which compiles the majority of Colombian regulations in force regarding environment and sustainable development.
The environmental license encompasses all of the necessary permits, authorizations, concessions and other control instruments necessary under Colombian environmental law to undertake a project or activity that may result in the serious deterioration of renewable natural resources, or that have the capacity of materially modifying the physical environment. The license shall define specific conditions under which the beneficiary of the license may undertake such project or activity. The procedure to obtain an environmental license begins when the company files an Environmental Impact Study (EIA) related to the project before the ANLA. The licensing process includes an application for the use of natural renewable resources (water, soil and air), according to Decree 2106 of 2019. When the 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 Ministry of Environment and Sustainable Development (MESD) is also responsible for establishing guidelines regarding climate change policies for the hydrocarbon sector in Colombia. We comply with those guidelines. At present, MESD has not proposed any specific steps for the implementation of the Kyoto Protocol or the Paris Agreement, as they relate to our operations. We are continuously monitoring climate change requirements that could be applicable to us. A company that does not comply with the applicable environmental laws and regulations, does not execute the Environmental Management Plan (PMA) approved by the environmental authority or ignores the requirements imposed by an environmental license may be subject to an administrative proceeding initiated by the ANLA or the regional environmental authorities established by Law 1333 of 2009. The proceeding may result in oral or written warnings, monetary penalties, fines, license revocation or the temporary or permanent suspension of the activity being undertaken. Apart from administrative sanctions, the Colombian judiciary or other law enforcement authorities may also impose civil and even criminal sanctions if environmental damages are verified as a consequence of having breached the environmental laws and regulations applicable to the project.
3.8.1.1.2 Royalties
3.8.1.1.2 | Royalties |
In Colombia, the Nation is the owner of minerals and non-renewable resources located in the subsoil, including hydrocarbons. Thus, companies engaged in exploration and production of hydrocarbons, such as Ecopetrol, must pay to the National Hydrocarbons Agency (ANH), as representative of the National Government of Colombia, a royalty on the production volume of each production field, as determined by the ANH.
Royalties may be paid in kind or in cash. Each production contract has its applicable royalty arrangement in accordance with applicable law. In 1999, a modification to the royalty regime established a sliding scale for royalty payments for crude oil and natural gas production fields discovered after July 29, 1999 and depending on the quality of the crude oil produced. Since 2002, as a result of the enactment of Law 756 of 2002, the royalty rate was fixed as a sliding scale depending on the produced volume from 8% for fields producing up to 5 mbd to 25% for fields producing in excess of 600 mbd. Notwithstanding the royalties for Incremental Production Contracts, Contracts for Undeveloped and Inactive Fields, and Incremental Production Projects defined in paragraph 3 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.
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 Development and regional environmental authorities, respectively.
Crude oil transport
The regulatory framework relating to crude oil transportation accounts for both private use and public use pipelines. Private use pipelines are those built by the operating or refining entity for its own exclusive right and that of its affiliates. Public access pipelines are defined as pipelines built and operated by a public or private legal entity, for the purpose of publicly providing crude oil transportation services. The Colombian government, through the ANH, has a preferential right to use up to 20% of the total capacity of any public or private access pipeline to transport its crude oil royalties. However, for both private and public access pipelines, the ANH must pay the tariff for the pipeline use to transport its percentage of production.
The Ministry of Mines and Energy is responsible for reviewing and approving the design of and tracks for crude oil pipelines 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 3148931332 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 tariff methodology that has been in place since 2014, providing more regulatory stability for the criteria previously established by Resolution 72146 of 2014, as further amended by Resolution 31325 of 2015 and Resolution 31285 of 2016.Midstream companies through June 2023.
The Port Superintendence is the authority that oversees the port business for crude oil and refined products. Although this business is not highly regulated, market participants are required to report certain information to the Port Superintendence.
As a result of the enactment of Decree 119 of 2015, operators of private use hydrocarbon ports are currently able to provide hydrocarbon transport services to third parties pursuant to a mechanism established under that decree.
Decree 119 of 2015 was incorporated into Decree 1079 of 2015 issued by the Ministry of Transport, which compiles the majority of Colombian decrees and regulations in force regarding the administrative sector of transportation.
Refined products and liquefied petroleum gas transport
In 2014 CREG assumed responsibility for regulating product pipeline transportation from the Ministry of Mines and Energy, in addition to its pre-existing regulatory responsibility for liquefied petroleum gas, natural gas and electric energy transportation.
The applicable framework regarding LGP transportation was established by CREG of 2009 (amended by Resolution 152 of 2014), which, among other issues, sets forth: (i) the obligation of the owners and operators of transportations infrastructure to guarantee access to their infrastructure to other market agents, as long as they pay the fees regulated by CREG; (ii) the general obligations applicable to LGP transporters; (iii) the requirements applicable to the LGP transportation agreement; and (iv) establishes the non-discrimination principle regarding the access to the national transportation infrastructure.
In August 2017 CREG issuedprepared a draft resolution 113 of 2017, which introducedhas not been issued. It introduces a new framework for the transportation regulation of liquefied petroleum gas and refined products. The draft resolution was open for observations from the general public and the oil and gas industry until January 12, 2018, but the final resolution has not been issued yet.2018. CREG is also in the process of defining the transportation regulation and the rate calculation method for refined products. The primary goals and components of the proposed regulation are: (i) to ensure access to the transport systems for liquid fuels and the LPG pipeline systems without discrimination; (ii) to promote the timely expansion of the transport system in line with the needs of the market; (iii) to promote competition and prevent restrictive practices; (iv) to separate the operations of refining and transport; and (v) to ensure the efficient and continuous operation of transport systems. As of the date of this annual report, the above mentioned resolution has not been issued.issued.
3.8.3 Regulation of Refining and Petrochemical Activities
3.8.3 | Regulation of Refining and Petrochemical Activities |
Article 58 of the Petroleum Code establishes that oil refining activities can be developed throughout the Colombian territory and are not reserved to the State. However, Article 4 establishes that such activities are considered of public interest subject to governmental regulation, and the development of those activities must comply with technical requirements established by regulation.
In 2008, Law 1205, further developed by Resolution 180689 of 2010, issued by the Ministry of Mines and Energy, was issued with the main purpose of contributing to a cleaner environment. It established the minimum quality specifications for liquid fuels in Colombia. Since August 2010, Ecopetrol has been producing and selling diesel and gasoline that 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
3.8.3.1 | Regulation of Liquefied Petroleum Gas (LPG) and Liquid Fuels |
Wholesale marketing, transport, distribution and retail marketing of LPG are mainly regulated by CREG Resolution 74 of 1996, and subsequent resolutions. LPG in Colombia is primarily obtained through Ecopetrol’s refineries, field production and imports. The LPG must meet minimum quality standards to be marketed. Our marketing activities are regulated by CREG Resolution 53 of 2011 (as amended by CREG Resolutions 108 of 2011, 154 of 2014, 019 of 2015, and 034, 063, and 064 of 2016)2016 and 171 of 2017). The LPG price is regulated by CREG Resolutions 66 of 2007 (as amended by CREG Resolutions 59 of 2008, 002 of 2009, 123 of 2010, 095 of 2011, and 65 and 129 of 2016). as well as by CREG Resolution 80 of 2017 which sets forth that the price of LPG imported by Ecopetrol, which is meant to be marketed for the provision of public utilities, shall be the result of competitive procedures.
According to Article 4 and 212 of the Petroleum Code and Law 39 of 1987 (added by Law 26 of 1989)1989 and as amended by Law 812 of 2003), the distribution of crude oil and its derivatives has a public purpose (utilidad pública), and the distribution of fuel oil and crude oil by-products is considered a public utility activity. Consequently, individuals or entities engaged in these activities are subject to regulations issued by the Colombian government. The Government has the power to determine quality standards, measurement and control of liquid fuels, and establish penalties that may apply to dealers who do not operate in compliance therewith.
The Ministry of Mines and Energy is the entity that controls and exercises technical supervision over the distribution of liquid fuels derived from petroleum, including the refining, import, storage, transportation and distribution in the country. Article 61 of Law 812 of 2003 (whose validity was extended by Law 1955 of 2019) identified the agents of the supply chain of petroleum-based liquid fuels. In this context, the Ministry of Mines and Energy through Resolution 40344 of 2017, published the required actions to ensure the LPG supply for the priority sectors in the country.
The distribution of liquid fuels, except LPG, is governed by Decree 1073 of 2015 (as amended), which establishes the requirements, obligations and penalties applicable to supply agents in the distribution, refining, import, storage, wholesale, transportation, retail sale and consumption of liquid fuels.
Decree 1073 of 2015 establishes the minimum technical requirements for the construction of storage plants and service stations. This Decree also regulates the distribution of liquid fuels, except LPG establishing the minimum requirements for distributors and the activities and types of agreements permitted for these agents. The Ministry of Mines and Energy also regulates the types of liquid fuels that can be sold and purchased and the penalties for noncompliance with governmental regulations.
Pursuant to Law 1430 of 2010, modified by Article 220 of Law 1819 of 2016, the distribution of fuels in areas near Colombian borders is the responsibility of the Ministry of Mines and Energy and is subject to specific regulations that impose strong control procedures and requirements. The Ministry of Mines and Energy establishes the safety standards for LPG, storage equipment, maintenance and distribution of LPG.
The Superintendence of Public Domestic Utilities also oversees the liquefied petroleum gas transportation business.
3.8.3.2 Regulation Concerning Production and Prices
3.8.3.2 | Regulation Concerning Production and Prices |
According to the Decree - Law 4130 of 2011 and Decree 1260 of 2013, CREG is in charge of setting the prices of petroleum by-products throughout the entire chain of production and distribution, except for current gasoline engine, diesel and biofuels. On the other hand, by Decree 381 of 2012, as amended by Decree 1617 of 2013, and Decree 2881 of 2013, the Ministry of Mines and Energy is in charge of setting the methodology to determine the reference price of gasoline, diesel, biofuels and mixtures thereof.
Then, since May 2012, CREG 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.
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). Law 1955 of 2019 (Article 33) authorizes the Ministry of Finance and Public Credit to enter into hedging agreements and establishes the conditions thereof, for purposes of guaranteeing the sustainability and the functioning of the FEPC.
The Ministry of Mines and Energy issued Resolutions 31536 and 31538 of 2018 which contain the settlement of our Net Positions corresponding to: (i) the period between December 29 and 31, 2016 and the first and second quarters of 2017, and (ii) the third and fourth quarters of 2017. In those resolutions the FEPC was ordered to transfer COP $729,729,493,450.88 and COP $1,183,672,269,819.52 to Ecopetrol, respectively.
AsLaw 1955 of 2019 authorizes the Ministry of Finance, as administrator of the dateFEPC, to carry out, directly or indirectly, the design, management, acquisition and/or execution of this report,hedges on (i) crude oil liquid fuel oils prices in the international market or (ii) the exchange rate of the Colombian Peso. This law also authorizes the Ministry of Finance to set stabilization mechanisms of the reference recommended retail prices of regulated fuel oil, as well as the subsidies to such regulated fuel oils to be executed through the FEPC. The Ministry of Mines and Energy has notcalculated the net positions corresponding to the year 2018 (Resolutions 31093 of 2019, 31219 of 2019 and 31227 of 2019), which totaled COP$3,137,557,402,233.94. The Ministry of Mines and Energy calculated the Net Positions corresponding to the year 2018.2019 (Resolutions 31254 of 2019 and 31271 of 2019), which totaled COP$1,298,416,657,817.56.
3.8.3.3 Regulation of Biofuel and Related Activities
3.8.3.3 | Regulation of Biofuel and Related Activities |
The sale and distribution of biofuels is regulated by the Ministry of Mines and Energy. Regulations establish the quality and pricing standards for biofuels and impose minimum requirements for mixing ethanol with gasoline and biodiesel with diesel.
The sale and distribution of biofuels is provided under CREG Resolution 240 of 2016, which particularly regulates: a) the sorts of market that will be served with biogas and biomethane; b) the quality and safety conditions; and c) the tariff regime. Pursuant to 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
3.8.4 | Regulation of the Natural Gas Market |
Decree 1073 of 2015, Part 2, Title 2, Chapter 2, established that all producers have to issue a production statement that includes the volumes of natural gas available for sale for a period of ten years. This decree established the regime for the selling and marketing of natural gas in Colombia, including specific procedures that regulate the Colombian market in order to manage the remaining natural gas reserves owned by the Nation, and to protect domestic consumers, especially residential consumers, by prioritizing delivery of gas to residential consumers, regulating the export of natural gas and setting forth the export restrictions applicable during an internal shortage of natural gas.
Currently in Colombia the price of natural gas is determined by the market, but some agreements still have to conform to the regulated formula. CREG issued Resolution 114 of 2017, partially amended by CREG Resolution 21 of 2019 which adjusted commercial aspects of the wholesale natural gas market in Colombia and compiled CREG Resolution 089 of 2013 and its amendments. However, pursuant to Decree 1073 of 2015, such procedures do not apply to the following activities: a) natural gas exports; b) natural gas as raw material in petrochemical production; c) natural gas commercialization from minor fields (production capacity under 30 million SCFD); d) natural gas commercialization from hydrocarbon fields under testing phase or which have not yet been declared commercially viable; e) natural gas commercialization from unconventional reservoirs; and f) internal consumption from natural gas producers.
CREG determines which agents can participate in the primary and secondary markets. Ecopetrol is authorized to participate as a seller in the primary market as a natural gas producer and as a buyer in the secondary market when Ecopetrol requires natural gas from other producers for its own needs. CREG regulations provide that a natural gas producer cannot participate as a merchant of natural gas in the secondary market, except that it may purchase gas to meet its existing contractual obligations. Ecopetrol is also able to resell available natural gas transportation capacity into the secondary market.
Priority for the Supply of Natural Gas
The export of natural gas, in contrast, is not considered a public utility activity under Colombian law and therefore is not subject to Law 142 of 1994. Nevertheless, the 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).
Decree 1073 of 2015 (amended by Decree 2345 of 2015) establishes an order of supply when restrictions are placed on the supply of natural gas or serious emergency situations arise that preclude the continued provision of certain services, as follows: (i) essential demand, as established in Decree 1073 of 2015, (ii) non-essential demand under an existing agreement with a warranty of uninterrupted provision and (iii) firm exports delivery.
The order of priority for the supply of natural gas is as follows: (i) the operation of the compressor stations of the National Transportation System, (ii) residential users and small business users engaged in the distribution network, (iii) vehicular compressed natural gas and (iv) gas refineries, excluding those destined for self-generation of electricity that can be replaced with energy from National Transportation System, which has first priority. The Ministry of Mines and Energy also establishes distribution priorities in the event of a natural gas shortfall derived from supply or infrastructure issues. This order of priority is based on the type of contract, with firm supply contracts having priority over interruptible supply contracts.
Decree 1073 of 2015 and CREG Resolution 114 of 2017: (i) provide specific procedures and forms of supply agreements determined by CREG pursuant to which an agent may sell and buy natural gas in the Colombian primary and secondary market produced from large fields (capacity of more than 30 million CFPD); and (ii) permit the sale of natural gas from small fields (capacity under 30 million CFPD) pursuant to contracts that fulfill certain regulatory requirements but whose form is not prescribed by law.
3.9 Sustainability Initiatives
3.9 | Environmental, Social and Governance (ESG) Strategies and Initiatives |
3.9.1 | HSE |
This section describes the health, safety and environmental (HSE) practices of Ecopetrol S.A. 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.
3.9.1.1 | Ecopetrol S.A. |
One of the principles that guides Ecopetrol is ourthe commitment to our employees and the development of those communities in which we operate. For that reason, Ecopetrol S.A. is devoted to improving our health, safety and environmental (HSE) practices.
The results of the HSE performance in 2018,2019, compared with the prior year, were:
· | A reduction in the Total Recordable Incidents Frequency |
· | A |
· |
· | We |
We did observe an increase in some other indicators as set forth below:
· |
· | An increase greater than |
· |
We have several programs in place aimed at increasing the safety of our industrial processes and minimizing the number of occupational accidents and other major incidents. Our HSE management model is based on key focus areas that are aligned with our integrated management system.
Total Recordable Incident RateIncidents Frequency – Employees and Contractors
Ecopetrol S.A. places an important emphasis on understanding, monitoring and controlling our impacts on workers and contractors.
TRIF has improved from 2.96 incidents per million hours worked in 2012 to 0.630.59 in 2018.2019. In 2018, 682019, 74 recordable cases occurred, where 24%31% led to restricted work, 7%11% required medical treatment and 69%58% led to lost days. Additionally, we had a 12%an 8% increase 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.2018, however, with increased work hours in 2019.
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 our operational areas have preparedness and emergency response plans, each in accordance with Colombian legal requirements and our new internal guidelines for emergency management.
Our preparedness and emergency response plans have been developed based on our analysis of risk scenarios, the estimated consequences of these events and the implementation of strategies to be followed in response to each scenario. These contingency plans have the approval of the ANLA.
The objectives of our contingency plans are to:
· | Protect the health and safety of our workers, contractors and the communities in which we operate; and |
· | Prevent oil spills and leaks of harmful substances in offshore and onshore areas, fires and explosions and mitigate environmental impacts. |
Our contingency plan includes, among others:
· | Our contingency plan includes, among others: |
· | Procedures for the containment of oil and other harmful substances, as well as procedures to safeguard the safety of affected communities, the environment and the personnel involved in such containment actions; and |
· | Strategies for responding to emergencies located outside of our facilities and mutual aid emergency plans, including actions developed with local environmental authorities, the local community and other organizations for containment and recovery of spilled product, cleaning and recovery of affected areas, monitoring of the environmental effects and, if the spill or leak has an operational source, compensation for local communities and other affected persons. |
Further, through our training programs, we are upgrading the skills of our fire brigade, ensuring the reliability of firefighting and emergency equipment and working on improving our performance during emergency drills. In 2019, about 85% of the fire brigade completed the training program.
In offshore operations, the operator has the responsibility of designing and implementing plans and strategies aligned with international best practices that cover various emergency response scenarios.
Frequency of process safety incidents
Our “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 2018,2019, there were 0.050.03 Tier 1 process safety incidents per million hours worked.worked, an improvement from the 0.05 recorded in 2018.
Frequency of Tier 1 process safety incidents per hours worked (per million hours worked):
Graph 8 – Tier 1 Process Safety Incidents(*) (**)
* | Tier 1 process safety incidents per million hours worked (API-754). |
** | Includes data for Ecopetrol S.A. and the Vice-Presidency of Transport and Logistics classified according to the criteria in API-754 Tier 1, but does not include Ecopetrol S.A.’s subsidiaries. |
Environmental Incidents
In 2018,2019, Ecopetrol S.A. recorded 116 environmental incidents, compared with 11 in 2018 and 14 in 2017 and 8 in 2016.2017. The volume of oil spills was 730.26142 barrels in 2019, a decrease from 710.26 barrels in 2018 and an increase from 50.7 barrels in 2017 and 202 barrels in 2016.2017. The decrease compared to 2018 in the numbers of environmental incidents was the result an improvement 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.maintenance systems monitoring.
Lisama 158/La Fortuna Incident
On March 2, 2018, a seepage of water and traces of crude oil occurred near the Lisama 158 well, located in the village of La Fortuna, in the Middle Magdalena Valley of Colombia. Ecopetrol activated its contingency plan to contain the spill. It is estimated that between March 12 and March 15, 550 barrels of crude, mixed with mud and rainwater, seeped into the streams of La Lizama and Caño Muerto. As of March 30, 2018, the Lisama 158 well was sealed and stopped flowing.
Ecopetrol’s internal investigation concluded that there were four concurrent critical factors leading to the incident and that in the absence of any of them, the incident would not have occurred.
The four critical factors were the following:
i. | A reservoir in natural overpressure conditions (4,850 PSI). During a well intervention in November 2017, a section of a working string fell to the bottom causing the rupture of the “blanking plug”, which served the purpose of preventing reservoir fluids from reaching the wellhead. |
ii. | The rupture or failure of the “blanking plug” produced a flow of unexpected fluids that required the injection of fluids at a pressure of 1,250 PSI, which in turn could have generated the loss of the mechanical integrity in the casing of 9 5/8” affected by wear. |
iii. | Presence of a natural system of geological faults in the area, which in addition to the other factors, allowed well fluids to migrate to the surface. |
iv. | Time of exposure of the upper formations to the over-pressure of the reservoir, which contributed to the emergence of fluids in a farm near the well, a mixture of water, mud, crude oil and gas. |
Corrective and mitigation actions implemented by Ecopetrol
With respect to the actions performed by Ecopetrol to address, mitigate other damages and manage the incident, in compliance of the obligations contained in Law 1523 of 2012, Presidential Decree 321 of 1999 and the contingency plan for the Lisama Well, Ecopetrol did the following:
i. | Implementation of control and containment procedures to slow the spread of the spill and keep it contained. |
ii. | Activities to protect the life and health of the surrounding communities. |
iii. | Monitoring of the following resources: water, air and land. |
iv. | Activities to protect and preserve fauna and flora in the area of influence and. |
v. | Operational attention and verification of the causes which led to the incident. |
In terms of attentionresponse 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,Additionally, the government of Colombia, through the Ministry of Environment and Sustainable Development, requested an independent audit review from a group of environmental and humanitarian experts, composed by the Joint UNEP/OCHA Environment Unit (JEU) and the activation of the UNDAC mechanism of the United Nations Office for the Coordination of Humanitarian Affairs. The aforementioned experts delivered a report that included a set of conclusions and recommendations which were accepted and included by Ecopetrol within the guidelines of its Environmental Recovery Plan (PRA).
The following are the most important milestones which were carried out by Ecopetrol in the attention ofresponse to the incident:
Since April 8, 2018, Ecopetrol intervened the Lisama Well with a snubbing unit (specialized unit which handles pressure), with the purpose to verify the integrity of the casing, the cement used for the casing and to seal off the area where the spill was occurring. These activities finalized successfully on May 8, of 2018, when the Lisama Well was finally plugged with a double seal of cement.
· | 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 May 27, 2018, after ensuring that the activities described above were successfully performed to control the spill, the 63 families (approximately 177 individuals) which were directly affected by the spill returned to their homes. |
On June 2, 2018, the technical abandonment of the Lisama Well initiated, a process which ended on the July 11, 2018.
· | On June 2, 2018, the technical abandonment of the Lisama Well initiated, a process which ended on the July 11, 2018. |
On October 19, 2018 and in compliance to Resolution 1767 of 2006, Ecopetrol filed before the ANLA the Environmental Recovery Plan (PRA), 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:
· | On October 19, 2018 and in compliance to Resolution 1767 of 2006, Ecopetrol filed before the ANLA the Environmental Recovery Plan (PRA), a plan to perform several activities to ensure the recovery of affected natural resources (water, air and land) plus fauna and flora was prepared, including the following aspects: |
Components of intervention:
Activities to recover the biotic environment. |
Activities to recover the abiotic environment. |
Socio-economical activities. |
Follow up activities. |
Intervention strategies:
Water: Recovery of affected water bodies. |
Land: Dismantling of the protection and defense mechanisms in place and reconfiguration and land suitability procedures on the site of the spill. |
Flora: Following up and monitoring of regeneration regarding sapling and pole stage (brinzal y latizal) specimens; following up and monitoring of affected specimens; recovery of vegetation in place; recovery of the riparian vegetation of the gorge La Lizama and La Muerte canyon; incorporation of tree nurseries for the riparian vegetation recovery. |
Fauna: Activities to manage wildlife specimens affected. |
Social and |
Monitoring: Supervising and following up procedures of natural recovery. |
Additionally, Ecopetrol has been reporting the advances achieved of the Environmental Recovery Plan (PRA) to all competent authorities.
Investigations and legal claims
Investigations
As of the date of this annual report the following investigations are being conducted by environmental authorities and control agencies in respect of the incident:
On January 20, 2020, Ecopetrol was informed that the National Environmental Licensing Authority (ANLA), in the course of the administrative process initiated by said authority as a consequence of the events occurred during the Lisama 158 well spill, decided to impose a fine to Ecopetrol in an amount of COP$5.155 million. In the course of said administrative process, the ANLA exonerated Ecopetrol from liability for some charges, due to the fact that ANLA evidenced that Ecopetrol had activated its contingency plan and implemented the corresponding actions. It also mentioned that Ecopetrol’s environmental control actions were taken in an appropriate manner. Nonetheless, it decided to impose the fine, because the ANLA considered that the actions were not taken in a timely manner and because, it considered that Ecopetrol did not adopt and implement the necessary actions to correct the mechanic failures in the well, in order to prevent the environmental damage. On February 11, 2020, Ecopetrol filed a reconsideration appeal before ANLA requesting the reversal of this decision.
The Attorney General’s Office (First Solicitor’s Office Delegate for Administrative Supervision) opened disciplinary investigations against certain of Ecopetrol’s employees for alleged disciplinary infringements related to the oil well abandonment process. The Company´s employees currently being investigated are:
(i) Felipe Bayón (CEO and former Chief Operating Officer)
iii. | Ricardo Ernesto Coral Lucero (former Vice-President of the Central Region) |
(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)
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:
Seven writs of protection (injunctive actions) seeking the protection of fundamental rights have been ruled in favor of Ecopetrol. In addition, there are two additional actions that have been filed before the Administrative Court of Santander, related to the Lisama 158 incident:
On January 16, 2020 the High Court for Administrative Matters (Consejo de Estado) revoked the interim measure imposed by the Administrative Tribunal of Santander, considering that with the abandonment of the
alleged damage. As of the date of this annual report, both complaints were properly answered and we are
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
In
The following table covers Reficar’s TRIF for
Table
* These risks were associated with normal operations.
The results of other related performance indicators during
As in previous years, during
On average,
Ecopetrol S.A.
During
In line with Ecopetrol’s Climate Change Strategy, we are prioritizing three areas: 1) updating our emissions inventory, 2) developing greenhouse gas reduction projects in various operating areas and 3) defining the compensation portfolio through nature based solutions. As part of our efforts to contribute towards preserving the environment, in 2019, we declared our commitment to reduce carbon dioxide emissions by 20% by 2030 and to reduce the operation’s vulnerability to climate change. This decrease has been ongoing for several years. In 2019, we achieved a reduction of 380,603 tons of CO2e, for a cumulative decrease of 1.6 million tons of CO2 equivalent from our direct operations through the implementation of energy efficiency projects, the reduction of routine flaring in Chichimene and the use of renewable energy, among others. We also verified a reduction of 1,068,394 tons of CO2e in previous years through a third party certification.
In this sense, the main goal of the circular economy model is to incorporate this concept into management processes in order to promote economic growth, improve competitiveness, and mitigate risks related to environment and price volatility in raw materials, in the medium term. The model’s five components are (i) efficient use of resources and new businesses, (ii) improvement and development of products and services, (iii) standards and public policy, (iv) territory management towards circularity, and (v) culture.
Ecopetrol is committed to improving the quality of the fuels it supplies in order to contribute to a better air quality for Colombians and comply with fuel quality regulations. Taking advantage of being an integrated company, after April 2018, we reduced the
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
Production In October 2019, our first solar complex, “Parque Solar Castilla,” began operations. This plant has a capacity of 21 MW and will prevent the emission of more than 154 thousand tons of CO2. The Castilla solar farm is the largest self-generation plant with non-conventional renewable sources in Colombia and it is expected to supply part of the energy required by the Castilla field.
Further, during
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
Transport
Set forth below is a description of material related-party transactions. For additional information about transactions with related parties, see Note
Ocensa
Ecopetrol S.A. has entered into a number of agreements with its 72.65%-owned subsidiary, Ocensa, of which the following are the most significant:
In March 1995, Ecopetrol S.A. entered into an agreement for the transportation of crude oil through the Ocensa pipeline. Pursuant to the terms of this agreement, Ecopetrol S.A. was required to make monthly payments that varied, depending on both the volume of crude oil transported through the pipeline and a tariff imposed by Ocensa on the basis of Ocensa’s financial projections and their expected volumes of crude oil. On January 17, 2013, this agreement was amended as a result of Ocensa’s new business model. Among other changes, this amendment to the transportation agreement establishes the payment of the tariff, calculated according to Resolutions issued in 2010 by the Ministry of Mines and Energy. In 2013, another amendment was executed that modified the terms by which the payments of invoices should be made. In 2015 Ecopetrol received a temporary release of capacity from Vitol of 24,000 barrels per day for segment I and II and 14,000 barrels per day for segment III.
On July 29, 2014, after Ocensa implemented and carried out an open process to receive offers to enter into transportation agreements for an extended capacity of approximately 135,000 barrels per day in Ocensa’s pipeline (the
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
In
On October 28, 2013, Ecopetrol entered into a natural gas supply contract in force until November 30, 2018, pursuant to which Ecopetrol S.A. supplies gas to Ocensa and receives a fixed price per MBTU (million British Thermal Units). This agreement replaced the contract for natural gas supply in Cusiana entered into in December of 2004, under which Ocensa paid a variable rate to Ecopetrol. In 2018, Ecopetrol S.A. received an aggregate sum of US$5.25 million under the contract. On December 1, 2018, the parties agreed to extend the term of the agreements for one year until November 30, 2019. In 2019, Ecopetrol S.A. received an aggregate sum of US$4.62 million under the contract. On December 1, 2019, the parties agreed to extend the term of the agreements for two years until December 1, 2021.
Ocensa has entered into the following agreements, among others, with some of our other subsidiaries:
In March 1995, Equion and Santiago Oil Company entered into agreements for the transportation of crude oil through the Oleoducto Central S.A. (Ocensa) pipeline. In November 2012, Equion and Santiago Oil Company transferred, by means of various transactions, its shares (24.8%) and transportation rights (19.8%) holdings in the Ocensa pipeline to wholly owned subsidiaries of Ecopetrol S.A. (51%) and Talisman (49%). Equion and Santiago Oil Company kept 5% of transportation rights in Ocensa. In 2014, the transportation fees billed by Ocensa were: Equion (US$44.4 million), Santiago Oil Company (US$3.8 million) and Hocol (US$30.8 million). On January 17, 2013, this agreement was amended as a result of Ocensa’s new business model. Among other changes, the amendment to the transportation agreement establishes that tariff payments are to be calculated according to resolutions issued by the Ministry of Mines and Energy. On May 23, 2013, another amendment was executed that modified the terms by which the payments of invoices should be made. In 2019, Equion paid Ocensa US$3.07 million and Santiago Oil Company US$0.25 million, in each case for transportation fees. Hocol paid Ocensa, as assignee of transportation rights from original shippers, US$28.73 million in 2019.
Oleoducto de Colombia S.A. (ODC)
Ecopetrol S.A. entered into the following agreements with its 73%-owned subsidiary, ODC:
In July 1992, a ship-and-pay agreement was signed for the transportation of hydrocarbons. Pursuant to this agreement, Ecopetrol S.A. must pay a previously agreed tariff for the volume of hydrocarbons transported. The duration of this agreement is indefinite; however, the contract will remain in force as long as Ecopetrol S.A. holds shares in Oleoducto de Colombia S.A., whether directly, or through an affiliate. As of January 2013, the parties agreed that the applicable tariff would be the one set by the Ministry of Mines and Energy (the MME Tariff). The MME Tariff had been set in 2011 for a four-year term, with a yearly adjustment based on the consumer price index. In 2019, payments made by Ecopetrol S.A. under this agreement amounted to US$89.6 million.
In August 1992, an operation and maintenance agreement was signed for the Vasconia and Coveñas terminals both property of ODC. The duration of this agreement is indefinite, but can be terminated by any party upon six months’ notice. The initial contract included services rendered by Ecopetrol directly or by third-party contractors hired by Ecopetrol through mandate, with a variable surcharge over expenses and third-party contracts between 5% and 12% plus any applicable taxes. In 2014, an amendment to the agreement was signed, adjusting the monthly fixed rate to include expenses of services rendered directly by Ecopetrol, plus an additional 10% fee, and to eliminate the administrative surcharge. The contract also includes a variable sum related to contracts and purchases made by Ecopetrol through mandate. In March 2015, the monthly rate was adjusted for both Vasconia and Coveñas Stations. In March 2016, an amendment to the agreement was signed, adjusting the agreement’s scope to include the pipeline’s maintenance and adjusting the monthly fixed rate. In December 2017, an amendment to the agreement was signed, adjusting the agreement’s scope according to the change of the maintenance model of the midstream segment and including the Caucasia station and the Vasconia-Coveñas pipeline system into the scope. In March 2018, the parties amended the agreement in order to narrow the scope to the purchase and contracting management, and adjust the monthly rate. In February 2019 the scope of this agreement was amended to include planning, structuring, administration, and execution of the agreements signed with the Ministry of National Defense- Fuerzas Militares de Colombia. Pursuant to the terms of this agreement, ODC paid approximately US$4.0 million in 2019.
In March 1998, a joint operation agreement was signed for the TLU-1 Coveñas buoy. The duration of this agreement is indefinite and can be terminated by mutual agreement. In December 2013, Ecopetrol S.A. assigned its rights under this agreement to Cenit, though Ecopetrol S.A. kept its role as operator under the agreement. Pursuant to the terms of this agreement, ODC paid Ecopetrol S.A. approximately US$12.2 million in 2019.
In September 1999, a joint operation agreement was signed for the TLU-3 Coveñas buoy between Ocensa, ODC and Ecopetrol. Pursuant to the terms of this agreement, ODC paid approximately US$5.6 million in 2019. The duration of this agreement is indefinite. In December 2013, Ecopetrol S.A. assigned its rights under this agreement to Cenit, though Ecopetrol S.A. kept its role as operator under the agreement.
ODC has entered into the following agreements with some of our other subsidiaries:
Between March 1992 and January 1993, Hocol, Equion and Santiago Oil Company each entered into agreements with ODC for the transportation of crude oil through the Vasconia-Coveñas pipeline. The term of each of these agreements is indefinite. As of January 2013, the applicable tariff is the one set by the Ministry of Mines and Energy. In 2019, the transportation fees billed by ODC were: Equion (US$1.0 million), Santiago Oil Company (US$0.002 million) and Hocol (US$0.58 million).
Oleoducto de los Llanos Orientales (ODL)
Ecopetrol S.A. has entered into the following agreements, among others, with its 65%-owned subsidiary, ODL:
In March 2009, Ecopetrol S.A. entered into a ship-or-pay agreement with ODL that establishes a financing tariff used to pay ODL’s indebtedness to Grupo Aval for five years. This agreement was superseded by a new contract executed in May 2010, with a seven-year term, to reflect new conditions agreed with Grupo Aval. In August 2013, this contract was amended, providing a new term of seven years, including a two-year grace period, and an interest rate of DTF + 2.5%. This financing tariff is collected through a trust fund, which in turn is responsible for making the debt service payments to Grupo Aval. Under this agreement, ODL has committed to transport 75,000 bpd during the initial two-year grace period of the facility and 90,000 bpd during the remaining years, including the new term. Ecopetrol S.A. is responsible for 65% of this capacity. Payments by Ecopetrol S.A. under this contract were COP$90.3 billion in 2019.
In December 2009, Ecopetrol S.A. entered into a service agreement with ODL to transport crude oil. This agreement was replaced in January 2014 by a new agreement that expires in December 2020. This is a ship-or-pay agreement covering 167,000 bpd for 2014, 149,000 bpd for 2015 and 139,000 bpd until 2020. In January 2017, this agreement was amended in order to maintain the economic and commercial balance for the parties, based on changes to the standard condition of the system (to transport crude oil with a 690 cStk viscosity), reducing the “ship-or-pay” capacity from 139,000 bpd to 129.139 bpd until 2020. Payments by Ecopetrol S.A. under this contract were COP$808.7 billion in 2019.
In March 2010, Ecopetrol S.A. entered into a pipeline operating and maintenance agreement with ODL. This agreement had an original five-year term and was amended in 2015 to extend the term another ten years, adjusting certain conditions. In January 2017, this agreement was partially assigned by Ecopetrol to Cenit, due to matters related to the management of plants and pipeline assets. In August 2017, the maintenance obligations were partially assigned by Ecopetrol to a third party. In October 2017 and February 2018, the name of the contract, some technical definitions and the annexes of the contract were updated and certain Ecopetrol’s obligations were removed, in line with the partial assignment, Pursuant to the terms of this agreement, ODL paid to Ecopetrol S.A. COP$6.56 billion, plus applicable taxes, in 2019. In addition, pursuant to the partial assignment ODL paid to Cenit COP$0.82 billion, plus applicable taxes, in 2019.
In August 1, 2015, ODL entered into an indefinite management agreement with Oleoducto Bicentenario by means of which ODL receives legal representation and provides management services to Oleoducto Bicentenario. In August 1, 2017, the agreement was amended in order to change the way ODL is remunerated by this service, improving the structure of the agreement. Pursuant to the terms of this agreement, Bicentenario paid to ODL COP$7.8 billion plus applicable taxes in 2019.
Oleoducto Bicentenario de Colombia S.A.S.
Ecopetrol S.A. has entered into the following agreements, among others, with its 55.97% owned subsidiary, Oleoducto Bicentenario:
In June 2012, Ecopetrol S.A. and Hocol entered into storage or pay and storage and pay agreements with Oleoducto Bicentenario. Under these agreements, Oleoducto Bicentenario is committed to receive, store, preserve and deliver our crude oil. The storage or pay agreement will terminate when Oleoducto Bicentenario’s indebtedness to local banks has been entirely paid, and the duration of the storage and pay agreement is 20 years after the storage or pay agreement terminates. In April 2015, this contract was amended to modify certain definitions to reflect new terms from the negotiation of the debt, which included a modification of participant banks and a reduction of the interest rate. In September 2018, this agreement was assigned by Hocol to Ecopetrol. Pursuant to the terms of this agreement, Ecopetrol and Hocol paid to Bicentenario COP$27.4 billion, plus applicable taxes, in 2019.
In August 2012, Ecopetrol S.A. entered into an Operation and Maintenance agreement for the Araguaney – Banadia pipeline system. The duration of this agreement is 15 years. This agreement was partially assigned in January 2017 by Ecopetrol to Cenit due to matters related to the management of plants and pipeline assets. In July 2018 Oleoducto Bicentenario and Cenit signed a settlement agreement to recognize costs related to this contract. Pursuant to the terms of those agreements, Bicentenario paid to Cenit COP$0.93 billion, plus applicable taxes, in 2019. In November 2017, the maintenance obligations of the transportation system were partially assigned to Cenit S.A.S. During December 2017 the agreement was modified to exclude from its scope the Araguaney and Banadía Stations’ maintenance. In November 2018 the pipeline maintenance obligations were extended until April 2019. While this agreement has now been terminated, pursuant to the terms of this agreement, Bicentenario paid to Ecopetrol S.A. COP$8.8 billion, plus applicable taxes, in 2019. Ecodiesel Ecopetrol S.A. entered into a supply agreement with Ecodiesel Colombia S.A. (Ecodiesel), a company in which Ecopetrol S.A. has a 50% equity interest. The current agreement began on January 25, 2018. Pursuant to the terms of this agreement, Ecodiesel must deliver to Ecopetrol S.A. and Ecopetrol S.A. must in turn purchase 48,100 barrels of Ecodiesel’s biodiesel production each month. Payments vary depending on the purchased volumes and the prices of biodiesel. This agreement expires on January 31, 2021. In 2019 a total of COP$270 billion was paid under this contract. Savia Peru S.A.
On February 19, 2016, Ecopetrol S.A., as lender and shareholder of 50%, and Savia Perú S.A., as borrower, entered into a five-year loan agreement for an aggregate principal amount not to exceed US$70 million. The proceeds of the facility were used to (i) repay short term loans and (ii) pay shortfalls related to final judgments (in case they materialize). The loan agreement accrues interest at an annual rate of 4.99%, which can be adjusted on an annual basis, with semi-annual interest payments and principal payments beginning on the 21st month following the disbursement date. Total disbursement was US$57 million through the disbursement period ended on December 31, 2017. On December 11, 2019, Ecopetrol and Savia Perú agreed on an amendment to the terms of the loan agreement, in order to revise the payment schedule of the loan, without changing the original maturity, nor the interest rate. As of April 2020, the outstanding balance of the obligation with Ecopetrol is US$28.3 million under the loan agreement. Korea National Oil Corporation (KNOC), as shareholder of the other 50% of Savia Perú S.A., signed a facility under the same terms and conditions as described above.
Transactions with Other State-Controlled Entities
In addition, we have an agreement with the ANH (National Hydrocarbon Agency) by which we purchase all crude oil delivered to the ANH as royalties by us and by third parties. The purchase price is calculated according to a formula set forth in a contract between Ecopetrol and the ANH that reflects our export sales prices (crudes and products), a quality adjustment for API gravity and sulphur content, transportation rates from the wellhead to the Coveñas or Tumaco ports and a marketing fee. We sell the physical product purchased from the ANH as part of our ordinary business. For the years ended December 31, 2019, 2018
We have a clear and defined corporate policy based on risk financing guidelines that summarizes the Company’s risk transfer and retention alternatives and provides support and guidance for all the insurance-related issues of all of our affiliated and subsidiary companies.
There are three corporate insurance programs covering Ecopetrol S.A. and its subsidiaries. In the text and tables below, we set forth our insurance programs and the companies covered, along with limits and coverage details. Group 1- Downstream Program:This insurance program provides coverage for downstream (assets and operations) of Ecopetrol S.A. and all of its subsidiaries in excess of their local insurance programs, when applicable. Coverage includes all physical damage and sabotage and terrorism, which were designed to cover downstream operations.
Table
Group 2 – Upstream Program:This program provides coverage for upstream (assets and operations) of Ecopetrol’s interests and all of its upstream subsidiaries. Coverage includes all physical damage, sabotage and terrorism and control of wells.
Table
Group 3 – Transversal Program:This program provides coverage for downstream, upstream and midstream operations of Ecopetrol
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Our third-party liability insurance policies cover Ecopetrol S.A., our subsidiaries and affiliates in excess of local underlying policy limits for claims made against them by third parties. Our commercial general liability coverage will pay on behalf of or indemnify amounts for which an insured becomes legally obligated to pay, including damages in respect of bodily injury, property, pollution and product liability. Coverage of bodily injury and property damage is subject to coverage territory during the policy period.
Ecopetrol’s midstream subsidiaries (Cenit, Ocensa, ODL, Bicentenario Pipeline and ODC) have an independent program for its oil transportation companies (including crime and directors & officers policies).
Table
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
With respect to onshore operations in the U.S., Ecopetrol Permian has been included since its beginning in the Control of Wells, D&O, and cyber and crime policies. For the other insurance lines, stand-alone policies have been analyzed to start coverage in 2020. Ecopetrol S.A. has a contract with
As of December 31,
Table
The number of Polipropileno del Caribe S.A. (now Esenttia S.A.) employees reported in 2017 was re-stated to include Esenttia Masterbach’s employees. Essentia Masterbach is a subsidiary of Esenttia S.A.
As of December 31, 2019, the subsidiaries Ecopetrol USA Inc, Ecopetrol Permian LLC, Kalixpan Servicios Técnicos, S. de R.L. de C.V., Topili Servicios Administrativos S. de R.L. de C.V., Ecopetrol Capital AG and Black Glod RE did not have direct employees. Loans and investment on training and development for our employees
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
There are no executive officers with
Labor Regulation
In accordance with
Ecopetrol S.A.
A collective bargaining agreement between us and our main labor unions governs labor relations with our unionized employees, which amounted to
We currently have
In 2019, 50.9% of Ecopetrol’s employees were affiliated with one of the above trade union organizations. As of the same date and in accordance with the governing legal provisions, the current Collective Bargaining Agreement (described below) applied to 79.0% of Ecopetrol S.A.’s total workers. Out of that 79.0%, 28.1% were workers who were not affiliated with any
Ecopetrol S.A.’s relations with unions are based on a permanent dialogue and communication sessions where different matters are discussed in order to solve and prevent any labor conflict.
Our current collective bargaining agreement has been in effect since July 1, 2018 and has a term of four and half years, expiring on December 31, 2022. The collective bargaining agreement included an increase in salaries at an annual rate of the local consumer price index (CPI) +1.21% for the remainder of 2018 and CPI +1.70% every year for the remainder of its duration. The agreement covers health, food, loans and transportation, among other benefits for workers, within reasonable criteria. It also includes union guarantees and addresses regulatory issues. During 2019, the agreements contained in the Collective Labor Convention 2018 – 2022 were performed, as were other agreements signed in the framework of the collective bargaining agreement process. In addition, a number of areas of dialogue with trade unions were advanced and different issues pertaining to their interest were addressed. A total of 249 meetings were scheduled. The
Our consolidated financial statements for the years ended December 31,
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.
Our consolidated financial statements were consolidated line by line and all transactions and significant balances between affiliates have been eliminated. These financial statements include the financial results of all subsidiaries companies controlled, directly or indirectly, by Ecopetrol S.A. See Exhibit 1—Consolidated companies, associates and joint ventures, to our consolidated financial statements included in this annual
Our operating results were affected mainly by international prices of crude oil, international prices for refined products and local prices for natural gas, as well as sales volumes, product mix, exchange rate and our operational performance. Crude oil prices and volumes are particularly important to the results of our exploration and production segment. This is because as export volumes or export prices of crude oil and products decrease or increase, our revenues do also. Results from our refining activities are also affected by the price of crude oil used as raw material, changes in product prices in the international market, change in environmental regulations, conversion ratios and utilization rates and refining capacity, all of which affect our refining margins. Terrorist attacks by guerillas against our pipelines and other facilities or social unrest can lead to loss of revenues by restricting the availability of transport systems for exports or sales of crude oil and products and/or production activities, in addition to the direct costs of repairing and cleaning. Finally, changes in the value of foreign currencies, particularly the U.S. dollar against the Colombian Peso, can also have a significant effect on our financial statements.See sectionTrend Analysis and Sensitivity Analysis—Trend Analysis for further information.
Sales volumes and prices
Our results from the exploration and production segment depend mainly on our sales volumes and average local and international prices for crude oil and natural gas. Additionally, sales volumes also reflect the purchase of crude oil and natural gas that we make from third parties and the ANH.
We sell crude oil and natural gas in the local and the international market. We also process crude oil at Barrancabermeja and Reficar and sell refined and other petrochemical products in the local and international markets.
Local sales and prices
We have a number of crude oil short-term commercial agreements with local customers, and natural gas short and long-term supply contracts with gas-fired power plants and local natural gas distribution companies. Local sale prices are determined in accordance with existing regulations, contractual arrangements and the spot market linked to international benchmarks. Local sales represent
International Sales and Prices
Our foreign sales represented
International sale prices are determined in accordance with contractual arrangements and the spot market linked to international benchmarks primarily ICE Brent benchmark.
A market diversification strategy has allowed us to capture markets where we have been able to obtain higher prices for our crudes and refined products. We sell our crudes and refined products in various regions, such as the U.S., Central America and the Caribbean, Asia and Europe. In our negotiations with potential customers, we seek to use the most liquid benchmark reference prices in each region.
Exploration costs
We account for exploratory drilling costs using the successful efforts method, whereby all costs associated with the exploration and drilling of productive wells are initially capitalized. Costs incurred in exploring and drilling dry or unsuccessful wells are expensed in the period in which the well is determined to be a dry or unsuccessful well and are accounted for under “Exploration and Project expenses.” Consequently, an increase in the number of exploratory wells we declare as dry or unsuccessful will negatively affect our results and may cause volatility in our operating expenses. See Note 4.7 to our consolidated financial statements for a summary of our accounting policy for exploration costs.
Royalties
Each of our production contracts has its own royalty arrangement in accordance with applicable law. Law 141 of 1994 established a royalty fixed rate equivalent to 20% of total production. In 1999, a modification to the royalty system established a sliding scale for royalty percentage linked to the production level of crude oil and natural gas to fields discovered after July 29, 1999, depending on whether the production is crude oil or natural gas, and on the quality of the crude oil produced. Since 2002, as a result of the enactment of Law 756 of 2002, the royalty percentage has ranged from 8% for fields producing up to five thousand bpd to 25% for fields producing an excess of 600 thousand bpd. Producing fields pay royalties in accordance with the applicable royalty rate at the time of the discovery. Also, Law 756 of 2002 establishes that in the fields of the association contracts that finalize or revert back, an additional royalty rate of 12% of the basic production applies.
Since January 2014, the ANH has collected natural gas production royalties from producers settled in cash based on a formula, regardless of whether a producer has sold the gas. As a result, we no longer commercialize this gas on behalf of the ANH. In addition, because the royalties are now payable to the ANH in cash, all the gas we produce is considered part of our reserves and production, without any deduction for royalties. The cost of natural gas royalties totaled COP$
Purchases of hydrocarbons
We purchase all crude oil delivered to the ANH as royalties by us and by third parties. The purchase price is calculated according to a formula set forth in a contract between Ecopetrol and the ANH that reflects our export sales prices (crudes and products), a quality adjustment for API gravity and
Since 2016, we have imported crude oil for Reficar feedstock when such imports result in better operational or economic performance of the Ecopetrol Group.
In December 2016, the Colombian Congress adopted Law 1819, which introduced changes to the Colombian tax system, applicable beginning in 2017, including the following
The 2016 Tax Reform included two tax benefits that are expected to improve the operations of the oil and gas industry:
Refundable VAT on
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:
For additional information see Note 10.2.4 of our consolidated financial statements. In October 2019, the Constitutional Court declared Law 1943 of 2018 (the Financing Law) unconstitutional effective January 1, 2020. Therefore, the Financing Law continued to have full effect for the full fiscal year 2019. In December 2019, the Colombian Congress adopted Law 2010, which introduced the following key changes to the Colombian tax system, among others:
Part A: Applicable Taxpayers
In addition, legal taxpayers who qualify for this Mega Investment Regime will be required to enter into agreements with the tax authority. These rules do not apply to taxpayers engaged in the exploration of non-renewable natural resources.
The functional currency of each of the companies of Ecopetrol Group is determined in relation to the main economic environment where each company operates; however our consolidated financial results are reported in Colombian Pesos, which is the Ecopetrol Group’s functional and presentation currency. A substantial part of our consolidated revenues comes from Ecopetrol Group companies whose functional currency is the Colombian Peso. The conversion effect from U.S. dollar to Colombian Peso is mainly due to local sales and exports of crude oil, natural gas and refined products whose prices are based on benchmarks quoted in U.S. dollars. Therefore, they are exposed to foreign currency exchange risk on revenues, capital expenditures and financial instruments that are denominated in a currency other than its functional currency.
Fluctuations in the U.S. dollar-Colombian Peso exchange rate have effects on our consolidated financial statements. As crude oil is priced in U.S. dollars, fluctuations in the exchange rate of the Colombian Peso against the U.S. dollar may have a significant impact on revenues, cost, monetary assets and liabilities held in foreign currency.
An appreciation of the Colombian Peso has a negative impact on our results of operations because our revenues from exports of crude oil, natural gas and refined products are primarily expressed in U.S. dollars. Costs of imported products and contracted services expressed in U.S. dollars will also be lower when expressed in Colombian Pesos, but on balance, our operating income in Colombian Pesos tends to decline when the Colombian Peso appreciates, other factors being equal. The appreciation of the Colombian Peso against the U.S. dollar also decreases the debt service requirements of our Companies with the Colombian Peso as their functional currency, as the amount of the Colombian pesos necessary to pay principal and interest on foreign currency debt decreases with the appreciation of the Colombian Peso.
Conversely, when the Colombian Peso depreciates against the U.S. dollar, our reported revenues, costs related to imported products and services, interest costs, and operating income, all tend to increase.
During 2019 and 2018, the Colombian Peso depreciated
In 2019, our consolidated debt in foreign currency decreased by a total of US$159 million mainly as a result of amortization of foreign currency capital expenditures. In 2018, our consolidated debt in foreign currency decreased by a total of US$2,123 million mainly as a result of prepayments of local and foreign currency of US$2,446 million and amortization of foreign currency capital expenditures. In 2017, our consolidated debt in foreign currency decreased by a total of US$2,582 million mainly as a result of prepayments of foreign currency denominated loans of US$2,400 million and amortization of foreign currency capital expenditures.
As of December 31,
The remaining portion of Ecopetrol S.A.’s U.S. dollar-denominated debt, as well as the financial assets and liabilities denominated in foreign currency, continues to be exposed to the fluctuation in the exchange rate, which means that an appreciation of the Colombian Peso against the U.S. dollar could generate a loss for companies whose functional currency is the Colombian Peso that have a net asset position in U.S. dollars or a gain if they have a net liability position in U.S. dollars. Conversely, a depreciation of the Colombian Peso against the U.S. dollar could generate a gain for companies whose functional currency is the Colombian peso that have a net asset position in U.S. dollars or a loss if they have a net liability position in U.S. dollars.
As of December 31,
The average annual rate of inflation in Colombia for the past ten years is
The average price of ICE Brent crude in
In addition, Ecopetrol’s average products basket price relative to ICE Brent reported a discount of US$
In theOperating Results section below, we present the impact of the price increase on our revenue and cost of sales.
Additionally, fluctuations in the price of oil had an impact on the value of our oil and gas reserves. Reserves valuation is made in accordance with SEC price regulations. Volatility in hydrocarbon prices, refining margins and reserves, as well as changes in environmental regulations may lead to the recognition of impairment or recovery of
For additional information about impairment charges and reversals, see sectionsOperating
In addition, as described in Section2.1.2 Strategy and Market Overview—2020 Investment Plan above, on March 16, 2020, Ecopetrol announced a set of actions to address current challenging market conditions, which have resulted, among other matters, in a 60% decline in the Brent crude price as compared to the end of 2019, due to external shocks including the strong increase in the supply of oil and the spread of COVID-19. See the section entitledTrend Analysis and Sensitivity Analysis—Trend Analysis for further information.
Our consolidated financial statements for the years ended December 31, 2019, 2018
From January 1, 2019, we were required to adopt IFRS 16 – Leases and from January 1, 2018, we were required to adopt IFRS 9 – Financial Instruments and IFRS 15 – Operating income. Our financial statements as of and for the years ended December 31, 2019 and 2018, reflect the adoption of these new standards, which did not generate a material impact in our results. For more information regarding the adoption of new accounting standards and their effects on our financial statements, see note 5.1New standards adopted by the Group to our consolidated financial statements included in this annual report.
Critical accounting policies are those policies that require us to exercise judgment or involve a higher degree of complexity in the application of the accounting policies that currently affect our financial condition and results of operations. The accounting judgments and estimates we make in these contexts require us to calculate variables and make assumptions about matters that are highly uncertain. In each case, if we had made other estimates, or if changes in the estimates occur from period to period, our financial condition and results of operations could be materially affected.
See Note
The following discussion is based on information contained in our audited consolidated financial statements and should be read in conjunction therewith.
The following table sets forth components of our income statement for the years ended December 31, 2019, 2018
Table
The following table sets forth our principal sources of third-party revenues by business segment for the years ended December 31, 2019, 2018
Table
In 2019, total revenues increased by 4.2% as compared to 2018, primarily as a result of: (i) a COP$5,951,875 million increase resulting from the 11.02% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$2,956.55/US$1.00 in 2018 to an average exchange rate of COP$3,282.39/US$1.00 in 2019, resulting in an increase in sales revenue from exports, (ii) a COP$2,322,792 million revenue increase attributable to the increase in our sales volume explained below and (iii) a COP$292,590 increase in services revenue from our transportations and logistics segment, primarily due to an increase in volumes transported. This increase was partially offset by: the 7.3%, or US$4.6 per barrel, decrease of our average crude oil basket price, which in turn was primarily the result of the lower performance of the Brent crude benchmark price, and the 9.7%, or US$7.5 per barrel decrease of our average refined products basket price, which in turn was primarily the result of the lower result of the international product prices performance, mainly in gasoline, naphtha and fuel oil prices, in spite of better diesel crack due to IMO 2020.
The increase of our sales volume in 2019 as compared to 2018 was the result of: (i) the 2.8%, or 4.1 mbpe, increase in our crude sales volume which was primarily the result of higher crude exports to Asia and the US Gulf Coast as a result of the Company’s commercial strategy, higher production level and an increase of purchases, (ii) the 3.5%, or 5.3 mbe, increase in refined products volumes due to an increase in consumption in border areas, which in turn was primarily due to a decrease in imports of Venezuelan products, a change in the biodiesel blend, an increased demand for jet fuel by the aviation industry and an increase in exports of diesel due to better realization price in the international markets and (iii) the 2.5%, or 0.7 mbe, increase in natural gas sales volume, primarily due to the incorporation of new fields and marketing processes during 2019.
In 2018, total revenues increased by 22.6% as compared to 2017, primarily as a result of: (i) a COP$12,898,392 million increase in revenues mainly due to the 32.2%, or US$15.4 per barrel increase of our average crude oil basket price, which in turn was primarily the result of the better performance of the Brent crude benchmark price and the 23.3%, or US$14.6 per barrel increase, of our average refined products basket price, which in turn was primarily due to strengthening of diesel prices, and (ii) the 0.2% depreciation of the Colombian Peso against the U.S. dollar, from an average exchange rate of COP$2,951.15 /US$1.00 in 2017 to an average exchange rate of COP$2,956.55/US$1.00 in 2018, resulting in an increase in sales revenue from exports, which represented an increase of COP$297,937 million. This increase was partially offset by: (i) a COP$407,261 million revenue decrease attributable to the decrease in our sales volume explained below and (ii) a COP$139,424 decrease in services revenue from our transportations and logistics segment, primarily due to the resolution of the disagreement regarding the P135 Project tariffs leading to lower tariffs, which was partially offset by higher volumes transported through the San Fernando – Apiay system and the expansion of the P135 Project.
The decrease of our sales volume in 2018 as compared to 2017 was the result of (i) the 7.9%, or 12.5 mbe, decrease in our crude sales volume was primarily the result of lower crude exports due to a greater allocation of domestic crudes to supply Reficar in order to replace imports. This decrease was partially offset by (i) the 3.4%, or 5.0 mbe, increase in refined products volumes due to greater refining throughput and (ii) the 3.5%, or 1.0 mbe, increase in natural gas sales volume, primarily due to greater demand and active incremental sales.
Our cost of sales was principally affected by the factors described below. See Note Cost of sales in 2019 was COP$44,972,360 million, representing a COP$3,787,981 million or 9.2% increase as compared to 2018, primarily as a result of the following factors: A COP$2,197,539 million increase in the purchase costs of crude oil, natural gas and refined products, which were purchased for sales and, in the case of crude oil, for refining, which was primarily the result of (i) lower average purchase prices due to the COP$2,894,955 million decrease in international benchmark prices for crude oil, natural gas and refined products, (ii) a COP$2,702,726 million increase in volumes purchased, primarily to ensure domestic supply of diesel and new contracts of domestic crude and (iii) a COP$2,389,768 million increase in costs in Colombian Peso terms due to the depreciation of the average exchange rate of the Colombian Peso against the U.S. dollar. A COP$685,059 million increase in depreciation, amortization and depletion expenses primarily due to (i) an increase in our level of capital expenditures and (ii) higher production levels associated with the results of our drilling campaign. The above mentioned was partially offset by a decrease in depreciation expenses due to higher hydrocarbon proved developed reserves in 2019 as compared to 2018. A COP$626,779 million increase in maintenance, contracted services and energy, associated with increased operating activity, incremental production costs, entry into operation of new wells, greater share in fields, higher electrical power rates, among others. A COP$210,764 million increase in labor costs, which is primarily the result of: (i) the recognition of employee benefits under the new collective bargaining agreement, (ii) a salary increase in 2019 and (iii) an increase in the number of employees. A COP$470,960 million increase in taxes and contributions, primarily due to: (i) higher taxes assumed mainly for VAT on gasoline and ACPM that went from being taxed at the general rate of 19% to 5%, thus limiting the VAT discount on goods and services purchased and (ii) greater economic rights to the ANH due to the production reactivation of the CP09 field. A COP$87,063 million increase in other minor items. The factors mentioned above were partially offset by a COP$490,183 million decrease in our consumption of inventories given our strategy to supply products in the country.
Cost of sales in 2018 was COP$41,184,379 million, representing a COP$4,276,054 million or 11.6% increase as compared to 2017, primarily as a result of the following factors:
A COP$3,225,596 million increase in the purchase costs of crude oil, natural gas and refined products, which were purchased for sales and, in the case of crude oil, for refining, which was primarily the result of (i) higher average purchase prices due to the COP$5,359,427 million increase in international benchmark prices for crude oil, natural gas and refined products, (ii) a COP$59,117 million increase in natural gas purchase volume, primarily to ensure the supply to our refineries during periods of ongoing maintenance in our natural gas production fields and (iii) a COP$52,233 million increase in costs in Colombian Peso terms due to the depreciation of the average exchange rate of the Colombian Peso against the U.S. dollar. This increase was partially offset by (i) a COP$1,478,718 million decrease in crude oil volumes purchased due to lower imports of light crude used by Reficar that were replaced by our own crude volumes and (ii) a COP$766,463 million decrease in products purchase volume, primarily medium distillates and gasolines, primarily due to higher production at Barrancabermeja and Reficar in order to supply the local market.
A COP$700,715 million increase in maintenance cost and contracted services, primarily due to: (i) additional costs for community management and well integrity and (ii) services contracted for water treatment, workover campaigns, surface maintenance, as well as costs associated with higher production and the increase in the throughput of our refineries.
A COP$477,829 million increase in inventory consumption associated with higher level of sales volumes in 2018 compared to 2017.
A COP$290,590 million increase in labor costs, which is primarily the result of: (i) the recognition of employee benefits under the new collective bargaining agreement, (ii) a 4.4% salary increase in 2018 and (iii) an increase in the number of employees.
A COP$177,158 million increase in the cost of processing materials and operating supplies due to an increase in our operational activities.
The factors mentioned above were partially offset by:
A COP$83,493 million decrease in other minor items.
The factors mentioned above were partially offset by a COP$231,222 million increase in inventories and an increase in unit costs associated with the increase of the Brent price of crude oils and products.
Operating expenses and selling, general and administrative expenses before taking into account the impairment of non-current assets A COP$1,060,989 million increase in other income, with no cash impact, mainly from the difference between the fair value and book value of Invercolsa. As a result of the ruling issued by the Colombian Supreme Court of Justice in October 2019, we increased our shareholding in Invercolsa from 43.35% to 51.88%, which in addition with another aspects represents a change in control of that entity; therefore, Invercolsa became our subsidiary rather than an affiliate, and we began to fully consolidate Invercolsa into our consolidated financial statements as of such date. According to IFRS “Business combinations,” the investment in Invercolsa must be recognized at fair value. A COP$623,927 million decrease in exploratory expenses mainly as a result of the recognition of spending on exploratory activity at Ecopetrol America’s León 1 and 2 wells in 2018. This decrease was partially offset by:
Operating expenses and selling, general and administrative expenses before taking into account the impairment of non-current assets amounted to COP$4,592,445 million in 2018, a COP$407,259 million or 9.7% increase as compared to 2017, mainly as a result of the following factors (see Notes 25 and 26 to our consolidated financial statements for more detail).
A COP$463,160 million decrease in other income due to the acquisition of an additional 11.6% interest at the K2 field in the Gulf of Mexico, which generated a gain due to the increase in the book value of the asset above the price paid for the additional interest. This non-cash gain is the result of the fair value valuation of the interest acquired, reflecting a price increase between the date of the deal and the price outlook by the end of 2017, among other factors.
A COP$188,304 million increase in general expenses due to the negative impact in our midstream segment of attacks by third parties and higher expenses incurred in respect of environmental incidents in our upstream segment.
A COP$133,828 million decrease in other income due to the sale of the following fields in 2017: Sogamoso, Río Zulia, Río de Oro and Puerto Barco, Santana, Nancy Maxine Burdine and Valdivia Almagro.
A COP$45,439 million increase in exploratory expenses as a result of a (i) higher seismic activity and (ii) the recognition of spending on exploratory activity mainly at the León 1, León 2, Bonifacio, Huron and Payero wells in 2018.
This increase was partially offset by:
A COP$214,563 million decrease in taxes mainly due to the elimination of the wealth tax since 2018.
A COP$136,591 million decrease in other minor items, particularly a reversal of
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
The impairment of our non-current assets includes expenses (or recovery) of impairment of property, plant and equipment and natural resources, investments in companies, goodwill and other non-current assets. The Company is exposed to future risks derived mainly from variations in: (i) oil prices outlook, (ii) refining margins and profitability, (iii) cost profile, (iv) investment and maintenance expenses, (v) amount of recoverable reserves, (vi) market and country risk assessments reflected in the discount rate, and (vii) changes in domestic and international regulations, among others.
Any change in the foregoing variables used to calculate the recoverable amount of a non-current asset can have a material effect on the recognition of either losses or recovery of impairment charges in the profit or loss statement. In our business segments highly sensitive variables can include among others: (i) in the exploration and production segment, variations of the hydrocarbon prices outlook; (ii) in the refining segment, changes in product and crude oil prices, discount rate, refining margins, changes in environmental regulations, cost structure and the level of capital expenditures; (iii) in the transportation and logistics segment, changes in tariffs regulation and volumes transported. (See Notes 3.2, 4.12 and
In
The 2019 impairment loss, net of non-current assets of COP$1,762,437, corresponds to the net result of:
An impairment of non-current assets in the exploration and production segment primarily due to the decrease in estimations of short-term hydrocarbon price outlook, in spite of the incorporation of new reserves and technical and operational information variables and lower discount rate.
An impairment of non-current assets in the transportation and logistics segment, primarily associated with the south generating unit, comprised of Puerto Tumaco and the TransAndino Pipeline (OTA), and the north generating unit, comprised of the Caño Limón – Coveñas Pipeline, which was especially affected by damages to its infrastructure attributed to attacks by third-parties. A reversal of impairment of non-current assets in the refining and petrochemicals segment, primarily related to the net effect of i) a reversal of impairment of the Cartagena Refinery due to a lower discount rate associated with external market factors, ii) an impairment loss in Bioenergy primarily due to the decrease in availability of cane, partially offset by an improvement in the projection of the realization price of ethanol and a decrease in the discount rate and iii) an impairment loss associated with the modernization plan for the Barrancabermeja Refinery, considering the state of the technical alternatives analysis of possible future increases in conversion. As mentioned above, in 2018, Ecopetrol recognized impairment losses, net of non-current assets of COP$368,634 million, which corresponds to the net result of:
An impairment of non-current assets in the refining and petrochemicals segment, primarily due to adjustments in market expectations with respect to the impact of implementation of IMO regulations on projected margins for Reficar’s refined products, (ii) a decrease in the short-term outlook for the ethanol prices given a global over-supply of ethanol, (iii) downward updates to Bioenergy’s near-term agricultural outputs and (iv) an increase in the discount rate used for Reficar and Bioenergy, reflecting updated macroeconomic conditions. These negative impacts were partially offset by the commencement of the stabilization period at both Reficar and Bioenergy as well as tax benefits associated with Law 1942, 2018.
An impairment of non-current assets in the transportation and logistics segment, primarily the result of a decrease in the forecast of the volume to be transported by the southern transportation unit and an increase in investment needs to mitigate the operative risk of our transportation systems.
The partial reversal of the impairment recorded in 2017 is primarily the result of an improved hydrocarbon prices outlook, incorporation of new reserves, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, favorable refining margins outlook, market conditions affecting the discount rate and technical operational capacity, among other factors.
For more information regarding impairment by segment, see the sectionFinancial
Finance results, net, mainly includes exchange rate gains or losses, interest expense, yields and interest from our investments and non-current liabilities financial costs (asset retirement obligation and post-benefits plan).
Finance results, net, amounted to a loss of COP$1,670,494 million in 2019 as compared to a loss of COP$2,010,375 million in 2018. This decrease in loss was mainly due to:
Finance results, net, amounted to a loss of COP$2,010,375 million in 2018 as compared to a loss of COP$2,495,731 million in 2017. This decrease in loss was mainly due to:
For more details on our financial income and expenses see Note
Income taxes amounted to COP$4,718,413 million in 2019, COP$8,258,485 million in 2018 and COP$5,800,268 million in The decrease in the effective tax rate from 2018
The decrease in the effective tax rate from 2017 to 2018 was mainly due to: (i) the positive impact of Law 1943, 2018 that led to higher deferred asset taxes, primarily at Reficar and Bioenergy, given the lower presumptive income rate of 0% starting in 2021, which will allow them to offset higher tax losses from previous years; (ii) the 300 basis points nominal tax decrease as a consequence of the 2016 tax reform; and (iii) an increase in the contribution of our income from Reficar, which is taxed at a lower nominal rate of 15%. This decrease was partially offset by (i) a non-deductible expense effect, primarily due to exploratory activity at Ecopetrol América Inc.’s León 1 and 2 wells and (ii) exchange rate effects on tax bases for companies with the U.S. dollar as their functional currency but with profit or tax losses in Colombian pesos, which required them to recognize a deferred taxes according to IAS 12.41 between the carrying amount of non-monetary assets in their financial statements and their respective tax bases converted from Colombian pesos to
See Note 10 to our consolidated financial statements for more details.
As a result of the foregoing, in 2019, net income attributable to owners of Ecopetrol was COP$13,744,011. In 2018, net income attributable to owners of Ecopetrol was COP$11,381,386 million whereas, in 2017, net income attributable to owners of Ecopetrol was COP$7,178,539
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.
The following tables present our revenues and net income by business segment for the years ended December 31, 2019, 2018
Table
Total revenues by segment include exports and local sales to third-parties and inter-segment sales. See the sectionFinancial
Table
In 2019, exploration and production segment sales were COP$52,667,990 million, compared to COP$50,372,764 million in 2018. In 2019, our segment sales increased by 4.6% as compared with 2018 mainly as a result of: Increased sales of crude oil to third parties, which increased by 3.9% in 2019 as compared to 2018 primarily due to: (i) an increase in local and exports sales of crude oil (4.1 mmbls) mainly due to higher crude exports to Asia and the US Gulf Coast as a result of the Company’s commercial strategy, a higher production level and an increase of purchases to third parties, (ii) an increase in sales of natural gas (0.7 mmbls) due to greater demand, (iii) an increased spread in our crude oil basket versus the Brent price and (iii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars. This increase was partially offset by the decrease in the price of our crude oil basket of US$4.6 per barrel. Increased inter-segment revenues, which increased by 5.5% in 2019 as compared to 2018 mainly due to: i) higher production volumes as a result of drilling campaigns and purchases to third parties, emphasized deliveries of crude oil in order to supply Reficar and Barrancabermeja in order to replace imported crudes and (ii) the depreciation of the Colombian Peso against the U.S dollar. This increase was partially offset by the decrease in the price of our crude oil basket in spite of better spreads as compared to the Brent price.
In 2018, exploration and production segment sales were COP$50,372,764 million, compared to COP$36,494,934 million in 2017. In 2018, our segment sales increased by 38.0% as compared with 2017 mainly as a result of:
Increased sales of crude oil to third parties, which increased by 20.4% in 2018 as compared to 2017 primarily due to: (i) an increase in the price of our crude oil basket of US$15.4 per barrel, (ii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars, (iii) an increase of 1.0 mmboe in sales of natural gas mainly due to greater demand and management of incremental sales. This increase was partially offset by the decrease in local and exports sales of crude oil (12.1 mmbls) mainly due to an increase in the use of local crude by Reficar and Barrancabermeja for their operations.
Cost of sales affecting our exploration and production segment are mainly related to: (i) the amortization and depletion of our production assets, (ii) contracted services and (iii) costs related to maintenance, operational services, electric power, projects and labor in the exploration and production segment. In addition, this segment’s costs are impacted by the purchases of crude oil from ANH and third parties, naphtha for dilution and transportation services.
In 2019, the cost of sales for this segment increased by 12.8% as compared with 2018, due to the net effect of: Fixed costs increasing by 8.1%, or COP$716,252 million, in 2019 as compared to 2018, mainly due to: (i) an increase in planned maintenance, higher tariffs and the depreciation of the Colombian Peso against the U.S dollar and (ii) higher labor costs due the recognition of salary increases and benefits for employees under our new collective bargaining agreement along with an increase in the number of employees. Variable costs increasing by 14.6%, or COP$3,418,429 million, in 2019 as compared to 2018, as a result of (i) an increase of purchases of crude oil due to the strategy, which enables further optimization of the supply chain, (ii) higher transportation costs due to the use of alternative oil pipelines to transport crude oil given attacks against the Caño Limón - Coveñas pipeline and an increase in tariffs, (iii) an increase in natural gas royalties due to higher production, (iv) an increase in depreciation and amortization mainly due to increased investment levels which in turn were primarily due to positive results from the drilling campaign and the improvement in the asset recovery factor and (v) an increase in electricity cost related to higher tariffs. In 2018, the cost of sales for this segment increased by 22.5% as compared with 2017, due to the net effect of:
Fixed costs increasing by 10.1%, or COP$815,784 million, in 2018 as compared to 2017, mainly due to (i) an increase in contracted services mainly due to the reactivation of the activity at the CPO-09 Block, an environmental audit contract primarily at the Rubiales and Cira-Teca fields, as well as water treatment expenses at the Magdalena Medio and Meta fields, (ii) an increase in maintenance and operating materials due to greater well preventive interventions, mainly in assets of the Central and Orinoquía Regional Vice-Presidencies, as well as an increase in maintenance in the K2 field for corrosion management, and (iii) higher labor costs due the recognition of salary increases and benefits for employees under our new collective bargaining agreement along with an increase in the number of employees.
Variable costs increasing by 28.0%, or COP$5,113,316 million, in 2018 as compared to 2017, as a result of (i) an increase of purchases of crude oil due to the increase in international benchmark prices, (ii) higher transportation costs due to the use of alternative oil pipelines to transport crude oil given attacks against the Caño Limón - Coveñas pipeline, (iii) an increase in operating activity costs such us electricity, process materials and services contracted associated with higher production. This increase was partially offset by lower depreciation and amortization mainly due of an increase in hydrocarbon proved developed reserves in 2018 as compared to 2017, which led to a decrease in depreciation expenses.
In
In 2018, operating expenses before impairment of non-current assets increased by 30.9% as compared to 2017, primarily as a result of (i) the bargain purchase in our acquisition of an additional stake in the K2 field in 2017, (ii) the sale of the following fields in 2017: Sogamoso, Río Zulia, Río de Oro and Puerto Barco, Santana, Nancy Maxine Burdine and Valdivia Almagro, (iii) the recognition of exploratory activity at Ecopetrol America
The net reversal of impairment of non-current assets recognized in the exploration and production segment in 2018, which totaled COP$785,940 million in 2018 as compared to COP$183,718 million in 2017, increased by
The segment recorded net
Lifting and Production Costs
The aggregate average production cost, on a Colombian Peso basis, The aggregate average lifting cost, on a Colombian Peso basis, increased to COP$28,100 per boe during 2019 from COP$25,614 per boe during
On a dollar basis, the aggregate average production cost decreased to US$8.92 per boe in 2019 from US$9.40 per boe in 2018 primarily due to a0.11% depreciation of the Colombian Peso against the U.S. dollar in 2019. Production volumes also increased compared to 2018 by 5.4 mboed.
On a dollar basis,the aggregate average lifting cost, decreased to US$8.56 per boe in 2019 from US$8.66 per boe in 2018 also due to a 0.11% depreciation of the Colombian Peso against the U.S. dollar in 2019.
The difference between the aggregate average lifting cost and aggregate average production cost is that lifting
The following table sets forth crude oil and natural gas average sales prices, the aggregate average lifting costs and aggregate average unit production cost for the years ended December 31, 2019, 2018
Table
In 2019, our transportation and logistics segment sales were COP$13,070,736 million compared to COP$11,354,167 million in 2018. The 15.1% increase in 2019 as compared with 2018 was mainly due to: (i) higher volumes of crude oil transported through our pipelines which was primarily dueto an increase of oil production at the national level, including production by third parties, (ii) reversal cycles through the Bicentenario pipeline, (iii) commercial strategies implemented for industrial services such as oil dilution, unloading facilities at the Monterrey facility that enabled the transport of oil previously transported outside of our infrastructure and oil injection at Ayacucho, (iv) an increase in the volume of refined products transported mainly due to growth of the border zone demand and higher volumes in the Cartagena - Baranoa pipeline and, (v) the positive effect on our U.S. dollar-indexed transportation fees resulting from the depreciation of the Colombian peso against the U.S. dollar.
In 2018, our transportation and logistics segment sales were COP$11,354,167 million compared to COP$10,598,064 million in 2017. The 7.1% increase in 2018 as compared with 2017 was mainly due to (i) higher volumes of crude oil transported by our pipelines which was primarily due to reversal cycles through the Bicentenario pipeline, the startup of the San Fernando-Apiay System and the expansion of the P135 Project, (ii) an increase in the volume of refined products transported mainly due to the increase in production at Barrancabermeja and Reficar, (iii) the positive effect on our U.S. dollar-indexed transportation fees resulting from the depreciation of the Colombian peso against the U.S. dollar. This increase was partially offset by a decrease in revenue due to the resolution of the disagreement regarding the P135 Project tariffs, leading to lower tariffs.
The cost of sales for our transportation and logistics segment is mainly related to: (i) project costs associated with the maintenance of transportation networks and (ii) operating costs related to these systems, including the costs of labor, energy, fuels and lubricants and others. The cost of sales amounted to COP$3,738,194 million in 2019 as compared to COP$3,402,087 million in 2018. The cost of sales for this segment increased by 9.9% in 2019 as compared with 2018 mainly due to (i) an increase in costs associated with higher volumes transported, (ii) an increased consumption of materials, supplies and depreciation resulting from an adjustment in the useful life of some of our transportations systems, and (iii) higher electricity market prices.
The cost of sales amounted to COP$3,402,087 million in 2018 as compared to COP$3,271,835 million in 2017. The cost of sales for this segment increased by 4.0% in 2018 as compared with 2017 mainly due to (i) an increase in costs associated with higher volumes transported, primarily due to the reasons described above and (ii) increased consumption of materials, supplies and depreciation resulting from
In 2018, operating expenses before the impairment of non-current assets decreased by 27.1% as compared to 2017 due to: (i) a reversal of a provision we had set aside in respect of tariff dispute we were having in connection with the P135 Project and (ii) the elimination of wealth tax since 2018. This decrease was partially offset by higher expenses associated with attacks on our infrastructure by third parties.
The impairment losses of non-current assets recognized in the segment in 2018, totaled COP$169,870 million in 2018 as compared to an impairment recovery of COP$59,455 million in 2017. The difference in impairment from a reversal in 2017 to a loss in 2018 was primarily the result of a decrease in the forecast of the volume to be transported by the southern cash generating unit and an increase in investment needs to mitigate the operative risk of our transportation systems.
The
In 2019, the refining and petrochemical segment sales were COP$38,770,806 million compared to COP$37,011,373 million in 2018. In 2019, sales of refined products and petrochemicals increased by 4.6% as compared with 2018, mainly due to (i) an increase of our diesel exports due to their improved economic performance in the international market and (ii) the depreciation of the Colombian Peso against the U.S dollar, resulting in an increase in sales revenue recorded in U.S. dollars. This increase was partially offset by lower prices of our refined product basket and the weakening of international fuel prices.
In 2018, the refining and petrochemical segment sales were COP$37,011,373 million compared to COP$28,644,016 million in 2017. In 2018, sales of refined products and petrochemicals increased by 29.2% as compared with 2017, mainly due to: (i) an increase
The cost of sales for our refined products and petrochemicals segment is mainly related to the purchase of crude oil and natural gas for our refineries, imported crude oil and products to supply local demand, feedstock transportation services, services contracted for maintenance of the refineries and the amortization and depreciation of refining assets. Cost of sales amounted to COP$37,856,219 million in 2019, compared to COP$35,658,753 million in 2018 In 2019, the cost of sales for this segment increased 6.2% as compared with 2018, principally due to (i) increased purchases of crude oil for use by our Cartagena refinery primarily due to higher throughput and
In 2018, the cost of sales for this segment increased 32.8% as compared with 2017, principally due to (i) an increase in
In
In 2018, operating expenses before the impairment of non-current assets decreased by 24.6% as compared to 2017, due to stabilization expenses of the Cartagena Refinery which was reflected in lower maintenance expenses, contracted services and general expenses.
In
The impairment losses of non-current assets recognized in the segment in 2018, which totaled COP$984,704 million in 2018, as compared to a net reversal of impairment of COP$1,067,965 million in 2017, is primarily the result of: (i) adjustments in market expectations with respect to the impact of implementation of IMO regulation on projected margins for the Cartagena Refinery’s refined products, (ii) a decrease in the short-term outlook for the ethanol prices given a global over-supply of ethanol, (iii) downward updates to Bioenergy’s near-term agricultural outputs and (iv) an increase in the discount rate used for Reficar and Bioenergy, reflecting updated macroeconomic conditions. These negative impacts were partially offset by the commencement of the stabilization period at both Reficar and Bioenergy as well as tax benefits associated with Law 1942, 2018.
As mentioned earlier, the refining segment is highly sensitive to changes in product prices and feedstock in the international market, discount rate, refining margins, changes in environmental regulations and cost structure and the level of capital expenditures.
The refining and petrochemicals segment recorded net
Our principal source of liquidity in
Our main uses of cash in
For more information regarding our debt, see the sectionFinancial
Cash from operating activities Net cash provided by operating activities increased by 23.3% in 2019 as compared to 2018, mainly as a result of:
Net cash provided by operating activities increased by 32.4% in 2018 as compared to 2017, mainly as a result of a 31.9% increase in our operational income before depreciation, depletion and amortization (DD&A) and impairment of non-current assets primarily due to (i) higher hydrocarbon production levels, (ii) an increase in our refining throughput, (iii) our continued strategy of replacing imports of crude oil and refined products with domestic production, (iv) the commencement of operations of the San Fernando – Apiay project and expansion of the P135 Project in our the midstream segment, (v) cost efficiencies from our transformation plan and (vi) a favorable price environment. This increase was partially offset by higher working capital needs mainly due to an increase in accounts receivable from the FEPC and the payment in advance of the capital gains tax due in 2019 pursuant to Decree 2146, 2018.
In 2019, net cash
In 2018, net cash used in investing activities increased by 98.9% as compared to 2017, mainly as a result of: (i) a 38.5% increase in investments in capital expenditures, which was driven mainly by drilling in the Castilla and La
Net cash used in
Net cash used in financing activities increased by 23.7% in 2018, as compared to 2017, due to (i) prepayments of local and foreign currency-denominated loans totaling the equivalent of US$2,446 million as compared to US$2,400 million in prepayments of foreign currency-denominated loans made in 2017 and (ii) an increase in dividend payments to the shareholders of Ecopetrol of COP$2,713,712 million and in dividend payments made by certain of our subsidiaries to their non-controlling shareholders of COP$209,342 million.
Our consolidated capital expenditures in 2019, 2018 and 2017
Our investment plan approved for
The resources required for the investment plan can be funded through internal cash generation with no need to raise additional net financing.
On March 27, 2020, our shareholders at the ordinary General Shareholders Assembly approved a distribution of ordinary dividends for the fiscal year ended December 31, 2019 amounting to COP$ 7,401,005 million, or COP$180 per share, based on the number of outstanding shares as of December 31, 2019. The payment dates will be April 23, 2020 (100% to minority shareholders / 14% to the majority shareholder), and during the second half of 2020 the remaining 86% to the majority shareholder. In 2019, we paid dividends of COP$12,910,611 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$956,418 million.
In 2018, we paid dividends for the fiscal year ended December 31, 2017 amounting to COP$3,659,373 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$768,328 million.
In 2017, we paid dividends for the fiscal year ended December 31, 2016 amounting to COP$945,661 million to Ecopetrol’s shareholders, including the Nation, and dividends paid to non-controlling shareholders of our subsidiaries totaling COP$558,986 million.
We prepare our interim and annual statutory financial information in accordance with our internal reporting policies, which follow Colombian IFRS and differ in certain significant aspects from IFRS. The following table sets forth our consolidated net income and equity for years ended December 31, 2019, 2018
Table
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
As a result of this accounting policy difference, for the year ended December 31, 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,
The application of IAS12.41 also generated adjustments to our goodwill and investments in companies impairments of COP$14,865 million in 2019, COP$22,030 million in 2018 and COP$61,893 million in 2017
As a result of these accounting policy differences described above, for the year ended December 31,
As of December 31,
Table
The Colombian Superintendence of Finance, through Resolution 1379 of October 10, 2019, authorized the renewal of the term of the Issuance and Placement Program of Internal Debt Bonds and Commercial Papers of the Company for three (3) additional years, until October 10, 2022.
Further, the Ministry of Finance and Public Credit of Colombia, through Resolution 0600 of February 18, 2020, authorized the Company to structure the issuance and placement of bonds in the international capital markets for up to two billion US dollars (US$2,000,000,000).
These authorizations themselves do not constitute an approval for the issuance of securities or any financing transaction.
Ecopetrol did not incur any short-term or long-term bank loans or bonds in
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,
Table
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
As of December 31,
Trend Analysis
Ecopetrol updated its Business Plan on February 26, As described in the section entitledStrategy and Market Overview—2020 Investment Plan above, on March 16, 2020, Ecopetrol announced a set of actions to address current challenging market conditions, which have resulted, among other matters, in a 60% decline in the Brent crude price as compared to the end of 2019, due to external shocks including the strong increase in the supply of oil and the spread of COVID-19. These measures are part of an intervention plan that seeks to have the Ecopetrol Group adapt in a timely and orderly manner to changing market conditions. The first stage of this plan includes the following actions:
The production target for 2020 set forth above remains unchanged as of phase one, between 745 - 760 mboed. Ecopetrol will continue to monitor market developments to determine the need to launch subsequent stages of the intervention plan, seeking to optimize the balance between decisive responses under current market conditions and preservation the Company's long-term value. Furthermore, the economies of all the countries where the Ecopetrol Group is located are currently experiencing negative economic consequences from the COVID-19 pandemic including, a significant drop in worldwide stock prices, decreasing oil prices, rise in unemployment, decreasing interest rates, liquidity concerns and devalued currencies. There is concern that the United States and other developed countries will fall into a recession in the near term, which will negatively impact the Colombian economy. Any such continued macroeconomic downturn could have a material adverse effect on our results of operations and business condition. Sensitivity Analysis
Sensitivity Analysis of Reserves
The following table provides information about the sensitivity analysis conducted on our oil and gas reserves as of December 31,
Table
The conversion rate used is 5,700 cf = 1 boe.
Assumptions for the Sensitivity Analysis of Reserves
The sensitivity of the ICE Brent price of US$40 per barrel in 2020, US$50 per barrel in 2021 and between US$53 and US$72 onwards, and costs of management portfolio.
The base scenario on which our sensitivity analysis is made corresponds to 83% of our oil, NGL and natural gas reserves, as of December 31, 2019, as presented elsewhere in this annual report. Other variables such as the operating costs, capital costs and portfolio price remain unchanged for purposes of the analysis. Sensitivity Analysis of our Results
The following table provides information about the sensitivity of our results as of December 31,
Table 56 –Results of Reserves’ Sensitivity Analysis
Assumptions for the Sensitivity Analysis of our Results
Our sensitivity analysis is based on the Consolidated Statement of Profit or Loss for 2019, as presented elsewhere in this annual report.
The sensitivity of the ICE Brent price index is in reference to an increase of US$1 per barrel of crude oil in the average ICE Brent reference price based on a 365-day year for 2019. Prices assumed correspond to realized prices for crude oil, natural gas and refined products for 2019, adjusted to account for the differences between such realized prices and the ICE Brent reference price.
The sensitivity of our results to changes in the exchange rate is in reference to a 1% average depreciation of the Colombian Peso against the U.S. dollar during 2019. Prices are the realized prices of crude oil, natural gas and refined products in 2019 and are expressed for the sensitivity using the adjusted exchange rate (i.e. a 1% average depreciation of the Colombian Peso against the U.S. dollar during 2019).
The income tax for each of our sensitivity analyses (price of ICE Brent and COP$/US$ exchange rate) is estimated using the effective corporate tax rate of 24% for 2019.
The table below sets forth the line items that are being affected by the variation on the reference prices or the average exchange rate.
Table
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.
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, 2019, 2018
Furthermore, at least once a year, or more frequently if the circumstances require, the Company ascertains whether there are indicators of impairment to its assets or cash-generating units (CGUs) due to the difference between the carrying amount of such assets or CGUs against to their recoverable amounts, using reasonable assumptions, based on internal and external factors, which reflect market conditions. The recoverable amount is considered to be the higher of the fair value less costs of disposal and value in use, based on the free cash flow method, discounted at the weighted average capital cost (WACC). Whenever the recoverable amount of an asset or CGU is lower than its net carrying amount, such amount is reduced to its recovery amount, recognizing a loss for impairment as an expense in the consolidated statement of profit or loss. External and internal sources of information may indicate that an impairment loss recognized for an asset, other than goodwill, may no longer exist or may have decreased, in this case, the reversal is recognized as an impairment recovery in the consolidated statement of profit or loss.
In
An impairment of non-current assets in the exploration and production segment primarily due to the decrease in estimations of short-term hydrocarbon price outlook, in spite of the incorporation of new reserves and technical and operational information variables and lower discount rate.
An impairment of non-current assets in the transportation and logistics segment, primarily associated with the south generating unit, comprised of Puerto Tumaco and the TransAndino Pipeline (OTA), and the north generating unit, comprised of the Caño Limón – Coveñas Pipeline, which was especially affected by damages to its infrastructure attributed to attacks by third-parties.
A reversal of impairment of non-current assets in the refining and petrochemicals segment, primarily related to net effect of i) a reversal of impairment of the Cartagena Refinery due to a lower discount rate associated with external market factors, ii) an impairment loss in Bioenergy primarily due to the decrease in availability of cane, partially offset by an improvement in the projection of the realization price of ethanol and a decrease in the discount rate and iii) an impairment loss associated with the modernization plan for the Barrancabermeja Refinery, considering the state of the technical alternatives analysis of possible future increases in conversion.
Any significant change in estimates and judgments could have a material effect on the quantity and present value of our proved reserves and subsequently on the recognition or recovery of impairment charges. Changes to estimations of reserves are applied prospectively to the amounts of depreciation, depletion and amortization charged and, consequently, the carrying amounts of exploration and production assets.
In order to assess the possible impact of current expected oil price scenarios and market conditions, as well as of further developments driven by the economic environment for the oil and gas industry, the Company has performed a sensitivity analysis over its proved reserve balance as of December 31,
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.
Our long-term growth objectives depend largely on our ability to develop the reserves recovery potential associated with existing fields and to discover and/or acquire new reserves, and in turn develop them successfully. Our exploration activities expose us to the inherent geological and drilling risks including the risk of not discovering commercially viable crude oil or natural gas reserves, and the risk that some exploratory wells initially budgeted for may be drilled at a later stage or not be drilled at all. Despite the effort we make to control costs associated with drilling, these are often uncertain, and numerous factors beyond our control may cause drilling operations to be curtailed, delayed or cancelled.
Our ability to add and develop reserves also depends on our capacity to structurally reduce costs to maintain the profitability of oil fields already being exploited without compromising infrastructure integrity and HSE performance.
Additionally, our strategy 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. On February 28, 2020, the Ministry of Mines and Energy issued Decree 328 that rules the general guidelines for the development of PPII on unconventional reservoirs by using fracking technology. Further regulations are required to advance in the PPII implementation.
If we are unable to achieve expected recovery factors in our existing fields, or successfully discover and develop additional reserves, or if we do not acquire properties having proved reserves, our reserves portfolio will decline. Failure to secure additional reserves may impede us from achieving or maintaining production targets, and may have a negative impact on our results of operations and financial condition.
In addition, our business growth and sustainability depend on our ability to manage the capital investments and operate efficiently, in accordance with the corporate strategy guidelines. See the sectionStrategy and Market
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
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, Currently, the spread of the coronavirus disease (COVID-19) generates uncertainty about a
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
In
A reduction of international crude oil prices could also result in a delay or a change in our capital expenditure plan, in particular delaying exploration and development activities, thereby delaying the development of reserves and affecting future cash flows. In order to maintain a profitable operation and preserve the cash flow of the Company at certain oil price levels, some of our producing fields may have to be closed or their operations temporarily suspended which would affect our production levels and expected revenues.
Changes in the Colombian Peso/U.S. dollar exchange rate could have an adverse effect on our financial condition and results of operations given the amount of U.S. dollar denominated debt held by the company and the fact that most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars.
Most of our revenues are derived from sales of products quoted in or with reference to U.S. dollars. Therefore when the Colombian Peso depreciates against the U.S. dollar, our revenues converted into Colombian Pesos, increase. Conversely, when the Colombian Peso appreciates against the U.S. dollar, our revenues decrease.
On the other hand, imported goods, oil services and the debt, which is mainly denominated in U.S. dollars, become less expensive when the Colombian Peso appreciates against the U.S. dollar and more expensive when the Colombian Peso depreciates against the U.S. dollar.
As of December 31,
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$
The U.S. dollar/Colombian Peso exchange rate has fluctuated during the last several years. On average, the Colombian Peso
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
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
If we are unable to adequately compete with local and foreign oil companies, or if we cannot enter into joint ventures with market players having high potential exploration projects, our exploration activities may be limited. This could reduce our market share and, in turn, adversely affect our financial condition.
If operational risks to which we are exposed in Colombia or overseas materialize, the health and safety of our workforce, the local community and the environment may be affected. In addition, we may suffer a disruption or shutdown of our operational activities.
Our exploration, production, refining and transportation activities in Colombia and in the foreign countries in which we operate are subject to industry-specific operating risks, some of which, despite our internal procedures and adherence to industry best practices, are beyond our control. Our operations may be curtailed, delayed or cancelled due to adverse or abnormal weather conditions, natural disasters, blockages in the communities in which we operate, equipment failures or accidents, oil or natural gas spills or leaks, shortages or delays in the availability or in the delivery of equipment, delays or cancellation of environmental licenses or other government authorizations or judicial decisions, fires, explosions, blow-outs, surface cratering, pipeline failures, theft and damage to our transportation infrastructure, sabotage, terrorist attacks and criminal activities.
Some of our operations in Colombia and abroad could be conducted in remote and uninhabited locations that involve health and safety risks that could affect our workforce. By our own Company policy and practices, as well as under Colombian law and international industrial safety regulations, we are required to have health and safety practices that minimize risks and health issues faced by our workforce. Failure to comply with health and safety regulations in the jurisdictions where we operate may lead to investigations by health officials that could result in lawsuits or fines.
We may be required to incur in additional costs and expenses to allocate funds to industrial safety and health compliance under Colombian law and international industrial safety regulations. Additionally, if any operational incident occurs that affects local communities and ethnic communities in nearby areas, we will need to incur in additional costs and expenses in order to return affected areas to normality and to compensate for any damages we may cause. These additional costs may have a negative impact on the profitability of the projects we may decide to undertake.
The occurrence of any of these operating risks could result in substantial losses or slowdowns to our operations, including injury to our employees, malfunction or destruction of property, equipment and infrastructure, clean-up responsibilities, third-party liability claims, government investigations and imposition of fines, withdrawal of environmental licenses and other government permits, suspension or shutdown of our activities and loss of revenue. The occurrence of any of these events may have a material adverse effect on our financial condition and results of operations.
Our involvement in deep-water drilling either as direct operator or in conjunction with our business partners involves risks and costs, which may be out of our control.
Our deep-water drilling activities present severe risks, such as the risk of spills, explosions on platforms and drilling operations, and natural disasters. The occurrence of any of these events or other incidents could result in personal injuries, loss of life, severe environmental damage with the resulting containment, clean-up and repair expenses, equipment damage and liability in civil and administrative proceedings.
As a result,
See the sectionBusiness Overview—Exploration and Production for a summary of our current deep-water drilling activities. We are exposed to the credit, political and regulatory risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.
Some of our customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In addition, many of our customers finance their activities through their cash flows from operations, short and long term debt or equity.
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
Such financial problems experienced by our customers or deterioration in our relations with our customers could result in the impairment of our assets, a decrease in our operating cash flows and may also reduce or restrict our customers’ future use of our products and services, which may have an adverse effect on our revenues and our ability to make payments under our existing debt obligations.
Our ability to access the credit and capital markets on favorable terms to obtain funding to refinance our debt maturities may be limited due to the deterioration of these markets, any change to our credit ratings and the authorizations we need before incurring any financial indebtedness.
A new financial crisis, volatility in prices in the oil and gas sector (as what is currently being experienced with the significant drop of the price of Brent crude in 2020 year to date), the spread in protectionist policies in the United States, China and Europe, the lack of consensus among
As a result of these factors, we may be forced to revise the timing and scope of our capital projects as necessary to adapt to existing market and economic conditions, downgrades to our credit ratings or to access the financial markets on terms less favorable, therefore negatively affecting our results of operations and financial condition.
In addition, under applicable regulation, the Government, through the Ministry of Finance and Public Credit and the favorable opinion of the National Planning Department, must authorize all indebtedness of state-owned entities and government-controlled companies through a majority equity stake. Consequently, excluding our foreign subsidiaries or those subsidiaries in which we hold minority interest, most of our indebtedness must be previously authorized by the Colombian Ministry of Finance and Public Credit and the National Planning Department. As such, our indebtedness is subject to the Government’s time frames and policies, and we cannot guarantee that such authorizations would be granted in a timely fashion or granted at all.
We may be exposed to increases in interest rates, thereby increasing our financial costs.
We may incur debt locally and in the international capital markets and, consequently, may be affected by changes in prevailing interest rates. If market interest rates increase, our financing expenses may increase, which could have an adverse effect on our results of operations and financial condition.
As of December 31,
Our current and planned investments and exploration activities outside Colombia are exposed to political and economic risks.
We began exploration activities outside Colombia in 2006 through our Brazilian subsidiary, Ecopetrol Óleo e Gás do Brasil Ltda. We operate through business partners, subsidiaries or affiliates outside Colombia. We currently have investments, joint ventures and subsidiaries incorporated in Peru, Brazil, Mexico, Bermuda, Panama, the Cayman Islands, Switzerland, Spain, the United Kingdom and the United States, and we are analyzing investments in other countries. In connection with making investments, we are and will be subject to risks related to economic and political conditions and governmental economic actions. We cannot predict the positions of foreign governments relating to the oil and gas industry, land tenure, protection of private property, environmental standards, regulation or taxation; nor can we assure that future governments will maintain policies favorable to foreign investment or repatriation of capital. Additionally, we may face new and unexpected risks involving environmental and other legal requirements beyond those we currently experience.
The results of operations and financial condition of our subsidiaries in these countries also may be adversely affected not only by risks associated with hydrocarbon exploration and production, but also by fluctuations in their local economies, political instability and government actions, including: the imposition of price controls, the imposition of restrictions on hydrocarbon exports, fluctuation of local currencies against the Colombian Peso, the nationalization of oil and gas reserves, increases in export and income tax rates for crude oil and oil products, and unilateral (governmental) institutional and contractual changes, including controls on investments and limitations on new projects.
Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas, or our production to decline, limit our ability to pursue new opportunities, affect the recoverability of our assets, or cause us to incur additional costs or delay the timeline of our projects.
Our future performance depends on the successful selection, development and deployment of new technologies and the knowledge to
Technology, knowledge and innovation are essential to our business, especially for
Our performance could be negatively affected by a deficiency in leadership capacity and lack of key skilled employees.
As the oil and gas industry faces an increasing number of challenges, the ability to react quickly to these challenges has become a key factor in achieving efficiency, profitability, growth and sustainability. Our ability to achieve these goals can be negatively affected by a deficiency in leadership capacity and a lack of key skilled employees that can execute our business strategy with competency, creativity and determination.
Our operations may not be able to keep pace with the increasing domestic demand for natural gas.
According to the latest Natural Gas Supply Plan issued by the Mining and Energy Planning Unit in January 2020 (Unidad de Planeación Minero Energética-UPME), under a medium forecasted demand scenario there would be a natural gas deficit in Colombia as of January 2024. Considering the CREG Resolution 114 of 2017,
Additionally, we are currently party to a number of national gas supply contracts that have firm gas commitments. If we
Delays in the start of new projects could result in penalties imposed on us by our clients.
We depend on others for the construction and availability of natural gas transportation infrastructure for the transport of our gas, which may limit our ability to develop new or existing fields or lead to the deterioration of related assets and may not allow us to recover the cost of capital invested in natural gas discoveries.
Ecopetrol S.A. can only hold up to 25% of the equity of any natural gas transportation company according to Article 5 of CREG Resolution 057 of 1996. Therefore, there can be no assurance that the transportation infrastructure necessary to transport natural gas from the fields to distribution points and our customers will be built by third parties or that if built there will be sufficient capacity available to us for the exploitation of new natural gas discoveries or the development of existing
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.
We are exposed to several risks that may partially interrupt our activities. They include fires or explosions, natural disasters, criminal acts and acts of terror, malfunction of pipelines and emission of toxic substances.
Also, the effects of climate variability and climate change could create impacts and losses in any part of our business operations, for instance, as the result of increase in the intensity of the “La Niña” and “El Niño” climate phenomena, causing floods and drought periods, increased temperature and rising sea and river levels.
The “El Niño” climate phenomenon is characterized by (i) a lack of rainfall, which limits the amount of water necessary for the development of various activities of the company, (ii) increased temperatures, which could have a direct impact on our worker’s health given an increased occurrence of heat waves and the increased occurrence of epidemics and diseases and (iii) potential negative impact on energy supply. The “La Niña” climate phenomenon is characterized by increased rainfall, which can generate (i) landslides that threaten pipeline infrastructure and increase the risk of ruptures that may cause hydrocarbon spills and limit road transportation and (ii) flooding, which could limit operations in our production fields and facilities.
As a result, our activities could be significantly
Our business operations could be disrupted by the Coronavirus or other pandemic diseases and health events. Pandemic diseases and health events, such as the recent outbreak of the novel strain of coronavirus infection (COVID-19) have the potential to negatively impact economic activities in many countries, including the countries in which we operate or have trade links, with consequent adverse effects on our customers and business. The ongoing outbreak of COVID-19 was first reported on December 31, 2019 in Wuhan, Hubei Province, China. From Wuhan, the disease spread rapidly to other parts of China as well as other countries, including Colombia and the United States, growing into a global pandemic. Since the outbreak began, countries have responded by taking various measures including imposing quarantines and medical screenings, restricting travel, limiting public gatherings and suspending certain activities. In addition, concerns related to COVID-19 have negatively impacted global financial markets and the demand for crude oil and refining products, resulting, among others, in the fall of oil prices, a trend which may continue. There are other broad and continuing concerns related to the potential effects of COVID-19 on international trade (including supply chains and export levels), travel, employee productivity, securities markets, and other economic activities that may have a destabilizing effect on financial markets and economic activity. On March 17, 2020, the Colombian government declared a State of Economic, Social and Ecological Emergency to contain the dissemination of COVID-19 and mitigate the risks associated with the pandemic. In the exercise of its powers, the Colombian government is entitled to implement extraordinary measures that might affect ongoing business operations. We cannot assure that such measures will not adversely affect our business. Furthermore, in the case of a forced shutdown involving any of the companies comprising the Ecopetrol Group, our contractors, suppliers, customers and other business partners, we may be unable to meet certain of our business obligations for an unknown period of time, which could adversely affect our business, financial condition and results of operations. See Note 33 to our consolidated financial statements for further information. Our operations, including our activities in areas classified as indigenous reserves and Afro-Colombian lands, are subject to opposition from members of various communities.
We currently carry out and plan to continue carrying out activities in areas classified by the Government as indigenous reserves and Afro-Colombian lands. In order to undertake these activities, we must first comply with the previous consultation process, set forth by Colombian law. These consultation processes are part of the administrative procedures for obtaining environmental licenses to start our projects, works or activities in areas belonging to ethnic communities. In addition, consultations can be seen as a potential instrument to involve communities in the decision of developing extracting industry and infrastructure projects in their territories. Generally, these consultation processes last between six months to one year depending on the community expectations, but may be significantly delayed if we cannot reach an agreement with the communities. We strive to be respectful of the Constitution and laws and the autonomy of indigenous and Afro-descendant communities, and we therefore do not enter their territories until we have reached an agreement with them.
Our activities are subject to opposition, including protests by various communities, and even in areas in which the previous consultation process does not apply. Recently, through popular consultation, some communities have voted against the development of extractive industry projects. Any such similar situation may affect our future projects.
In recent years, indigenous communities have been claiming their ancestral territories and requesting recognition
No certainty can be given that we will be able to reach an agreement with the different communities opposed to our operations or that such communities will participate in consultation processes if available. We may be exposed to similar delays due to opposition from local communities in other countries where we carry out our activities.
We have made significant investments in acquisitions and we may not realize the expected value.
We have acquired interests in several companies in Colombia and In our shale operations in the U.S., the ability to drill and develop different locations is subject to uncertainties such as natural gas and oil prices, drilling and production costs, availability of drilling services and equipment, lease acquisitions and expirations, processing capacity constraints, pipeline transportation bottlenecks, access to and availability of water sourcing and distribution systems, regulatory approvals, among others. We cannot assure if the well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil at the planned levels. We might be required to provide financial support to our subsidiaries in Colombia or abroad.
Although currently Ecopetrol is not the sponsor and has not provided financing guarantees to any of its subsidiaries, some financial support at any point in time might be needed to assure the long term viability of such subsidiaries when exposed to unexpected conditions or results.
Any situation that could affect the operations of our subsidiaries, or make them financially non-viable, particularly for those that recently entered into operations, such as Bioenergy, may have a negative impact on their profitability as well as on their ability to pay their liabilities, which in turn could adversely affect our financial condition and results of operations.
OnMarch 10, 2020, Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S were admitted to reorganization processes by the Superintendence of Companies of Colombia under Law 1116 of 2006, which will allow them to organize financial, administrative and operational aspects to preserve their sustainability. Those entities are not material subsidiaries and therefore these processes are not expected to have a material adverse effect on our consolidated results of operations and financial condition. Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S. were admitted to this reorganization process mainly due to lower than expected agricultural productivity and a deterioration in market conditions that make their current level of debt unsustainable. By these processes, they will seek to establish agreements with their main creditors as well as liquidity alternatives to maintain their viability.
Ongoing Colombian State control entities investigations regarding our subsidiaries Reficar and Bioenergy could adversely affect us.
Ecopetrol, Bioenergy and Reficar’s employees are generally subject to the control and supervision of the Colombian State control entities. See sectionRisk
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
Our results may be affected by the performance of our suppliers, our business partners or their third-party service providers.
Some of our suppliers may face financial or operational problems that could led them to a breach of their obligations settled under contractual arrangements. Other suppliers may also be subject to regulatory changes or sanctions that could increase the risk of defaulting on their obligations to us, which could have an adverse effect on our operations and financial condition.
In addition, some of our operations and projects are performed through joint ventures or other contractual arrangements with our business partners or third party service providers. Consequently, we depend on the performance of our business partners or third party service providers. The poor performance of any of them, especially in those projects in which we do not act as operator, could negatively impact the execution of projects and operating performance, which in turn could have a negative impact on our results of operations and financial condition. We are exposed to the risk of not finding business partners with the appropriate skills and performance we require for our projects. We are also indirectly exposed to supply agreements and other third-party services contracted by our business partners acting as operators under joint venture agreements.
Our insurance policies do not cover all liabilities and may not be available for all risks.
Our insurance policies do not cover all liabilities, and insurance may not be available for all risks. There can be no assurance that incidents will not occur in the future, that insurance will adequately cover the entire scope or extent of our losses or that we will not be found liable in connection with claims arising from these and other events, which could adversely affect our financial condition and results of operations.
A failure in our information technology systems or cyber security attacks may adversely affect our financial results.
We depend on the reliability and security of our information technology systems to conduct certain exploration, development and production activities, process financial records and operating data and communicate with our employees and business partners, and for many other activities related to our business. Our information technology systems may fail or have other significant shortcomings due to operational system flaws or employee misuse, tampering or manipulation. In addition, we may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.
During
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
Our self-generation is subject to fuel availability. In addition, several producing fields are connected to the national transmission system and depend on its expansion and reliability to keep steady production levels. The national electricity market is volatile due to changes in hydrology and availability of fuels (natural gas, diesel etc.), bringing uncertainty to prices. If energy were to become unavailable or difficult to obtain, our results of operation and financial condition could be adversely affected.
Rising water production levels may affect or constrain our crude oil production.
During
This section discusses potential risks related to our extensive operations in Colombia.
The Colombian government could seize or expropriate Ecopetrol’s assets under certain circumstances for fair compensation.
Pursuant to Articles 58 and 59 of the Colombian constitution, the Government can exercise its eminent domain powers in respect of private property assets in the event such action is deemed by the Government to be required in order to protect public interests. According to Law 388 of 1997, eminent domain powers may be exercised through: (i) an ordinary expropriation proceeding, or (ii) an administrative expropriation. In all cases we would be entitled to a fair compensation for the expropriated assets. Also, as a general rule, compensation must be paid before the asset is effectively expropriated. However, the compensation may be lower than the price for which the expropriated asset could be sold in a free-market sale or the value of the asset as part of an ongoing business. The aforementioned Article 59 of the Colombian constitution
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 Limó
During Guerilla attacks have resulted in unscheduled shutdowns of our transportation systems in order to repair or
Likewise, the theft of refined products and crude oil, resulting from security issues, may impact our operating and financial results in the future. Theft of refined products
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.
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 crude oil and natural gas production and the production of our refineries located in Colombia. Accordingly, our financial condition and results of operations depend to a significant extent on macroeconomic and political conditions prevailing from time to time in Colombia and on the exchange rates between the Colombian Peso and the U.S. dollar.
If the perception of improved overall security in Colombia deteriorates or if the investment climate worsens, the Colombian economy may face lower growth rates than the ones posted recently, which could negatively affect our financial condition and results of operations. Furthermore, the market price of our shares and American Depositary Shares, or ADSs, may be adversely affected by changes in governmental policies, particularly those affecting economic growth, exchange rates, interest rates, inflation and taxes. The Government has changed monetary, fiscal, taxation, labor and other policies over time and has thus influenced the performance of theColombian economy. We have no control over the extent and timing of government intervention and policies.
Our operations might be affected by rising climate change and energy transition concerns Due to worldwide agreements addressing the concern for increased of global temperatures, companies have had to take actions in order to respond and counteract the effects of their operations regarding climate change. Governments have also created additional legal and regulatory measures, such as increased restrictions of greenhouse gas (also “GHG”) emissions that could prompt more stringent domestic regulations related to climate change, with potential impact on project delays, new costs of production, and future investments and operational plans. The Colombian government currently imposes a carbon tax on fuel consumption (approximately COP$5/ton of CO2e). The Climate Change Law (1931/18) will mandate the implementation of a national cap and trade system, which could potentially increment the price of carbon. In addition, we see growing pressure from investors towards companies in order to lower carbon footprints and establish a credible energy transition pathway linked to a near net zero carbon scenario, which could in turn increase our costs of operation. Additionally, our operations could be exposed to climate variability and climate changes, which could potentially materialize in water shortages, floods, fires, storms and hurricanes, rising sea levels, among other natural occurrences, which could potentially lead to a materially adverse effect on our results of operation and financial condition. Colombian political and economic conditions have a direct impact on our business and may have a material adverse effect on us.
Colombia’s economic policies may have direct impact on our Company as well as market conditions, the prices of securities and our ability to access national and international capital markets. Our financial condition and results of operations may be adversely affected by the following factors, among others, and the Government’s response to such factors: exchange rate movements; inflation; exchange control policies; price instability; interest rates; liquidity of domestic capital and lending markets; tax policy; regulatory policy for the oil and gas industry, including pricing policy; and other political, diplomatic, social and economic developments in or affecting Colombia.
Uncertainty over whether the Government will implement changes in policy or regulations that may affect any of the factors mentioned above or other factors in the future may lead to economic uncertainty in Colombia and increase the volatility of the Colombian securities market and securities issued abroad by Colombian companies.
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 For a description of taxes affecting our results of operations and financial condition in
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
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
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
Our operations in Colombia are subject to extensive national, state and local environmental regulations. Environmental rules and regulations are applicable to our exploration, production, refining, transportation, supply and marketing activities, as well as the biofuels we produce. These regulations establish, among other things, quality standards for hydrocarbon products, air emissions and greenhouse gases, water discharges and waste disposal, soil remediation, water pollution and the general storage, handling, transportation and treatment of hydrocarbons in Colombia. Currently, all exploratory drilling projects in areas that do not yet have a license must undergo an environmental impact assessment and must receive an environmental license from the governmental agency responsible for awarding environmental licenses, the Environmental License National Agency or ANLA. Environmental authorities with jurisdiction over our activities routinely inspect our crude oil fields, refineries and other production sites, and they may decide to open investigations or sanction proceedings, which may result in the imposition of fines, restrictions on operations or other sanctions in connection with potential non-compliance with environmental laws.
We are also subject to control and monitoring by the regional autonomous corporations (CAR), which are regional environmental authorities that grant permits for the use and exploitation of natural resources in areas or fields that have an Environmental Management Plan (PMA as per its Spanish acronym), in the same way they establish compensation measures for the use of these resources and perform monitoring, control and impose sanctions as result of investigations.
If we fail to comply with any of these national or regional environmental regulations, we could be subject to administrative and criminal penalties, including warnings, fines or closure orders of our facilities. Any such criminal penalty would be imposed on the legal representatives of the Company, including any legal representative, director or worker who participated or failed to take action related to the activities that lead to environmental damage. See sectionBusiness
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,
In addition, the companies of the business group conducting upstream activities outside Colombia may be subject to foreign health, safety and environmental regulations. Foreign health and safety regulations may be more severe than those established under Colombian law and, therefore, we may be required to make additional investments to comply with those regulations.
Under certain of our credit agreements, we are under an obligation to comply with international environmental standards established by our lenders or by multilateral institutions. Failure to comply with such environmental standards could result in an event of default under the relevant credit agreements that we, or our subsidiaries, have entered into, which would affect our financial condition.
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,
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
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
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.
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. Colombian residents who acquire ADRs and either receive profits from this investment, surrender their ADRs or liquidate their investment in ADRs, must register their investment by means of the procedures set forth in section 7.4.1 of the External Regulation of the Circular DCIN-83 of the Colombian Central Bank. In the future, the Government, the Colombian Congress or the Colombian Central Bank may amend Colombia’s International Investment Statute or the foreign investment rules, which could result in more restrictive rules and could negatively affect trading of our ADSs.
Colombia currently has a free convertibility system. If a more restrictive convertibility system is implemented, the Depositary may experience difficulties when converting Colombian Peso amounts into U.S. dollars to remit dividend payments. Also, currently Colombia has a floating exchange rate system that might be subject to change in the future. See sectionShareholder
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
The protections afforded to minority shareholders in Colombia are different from those in the United States, and may be difficult to enforce.
Under Colombian law, the protections afforded to minority shareholders are different from those in the United States. In particular, the legal framework with respect to shareholder disputes is substantially different under Colombian law than U.S. law and there are different procedural requirements for commencing shareholder lawsuits, such as shareholder derivative suits. As a result, it may be more difficult for our minority shareholders to enforce their rights against us or our Directors or controlling shareholder than it would be for shareholders of a U.S. company.
ADRs do not have the same tax treatment as other equity investments in Colombia.
Although ADRs represent Ecopetrol’s 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
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,
As of December 31,
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.
Our controlling shareholder’s interests may be different from those of certain minority shareholders.
The Nation currently holds 88.49% of our outstanding capital stock, making it our controlling shareholder. The Nation as our controlling shareholder has majority voting rights at the General Shareholders Assembly to elect the members of our Board of Directors and may propose and approve decisions that may be in its own interest and that may not necessarily benefit minority shareholders.
Our controlling shareholder may propose and approve
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.
Under the leadership of the Vice-Presidency of Compliance, Ecopetrol S.A. consolidated its internal control systems into a unified system that integrates the best practices called for by the Committee of Sponsoring Organizations of the Treadway Commission (COSO 2013), Sarbanes–Oxley Act (SOX), governance and management of enterprise IT (COBIT), Enterprise Risk Management
The main purpose of the Ecopetrol S.A.’s Internal Control System is to provide reasonable assurance regarding the achievement of all of the Company’s objectives relating to operations, strategy, reporting and compliance, through the appropriate risks management and ensuring the effectiveness of its controls. The system performance is systematically monitored by the Board of Directors.
Ecopetrol S.A.’s Internal Control System is aligned to the Company’s strategy and business processes and gives responsibility to all employees to manage risk, to maintain the effectiveness of controls, to report incidents in order to preventively correct possible deficiencies and to provide reasonable assurance of achieving corporate objectives and goals.
The risk management component of our Internal Control System is in charge of identifying events or situations that may affect our defined objectives, assessing and prioritizing them to implement the most appropriate response. This component has been designed and implemented across the organization, with a two-level focus: Enterprise Risk and Processes Risks.
Our risk management approach is based on the risk management cycle, consisting in five main stages: planning, identifying, evaluating, treatment and monitoring risks, as well as communication across all stages. This cycle is supported in three pillars of risk management: culture, organizational structure and normative and management tools.
Three of our most important tools within the risk management component are:
Ecopetrol has also defined guidelines and implemented an Internal Control System, the scope of which includes its subsidiaries. Under those guidelines, each subsidiary must implement and report the performance of its Internal Control System to Ecopetrol S.A. to ensure compliance with the above measures, and the subsidiaries have methodological support from Ecopetrol S.A. when requested. Ecopetrol S.A. also performs preventive monitoring in selected subsidiaries to assure all the components and principles of their Internal Control Systems are present and operating.
Ecopetrol S.A. has a dedicated management team focused on information security issues such as risk analysis, treatment of information, safe information management practices and classification of critical business information, control systems compliance and effectiveness of available information security technologies, all of which are articulated with the ERM system at the enterprise level.
Ecopetrol S.A. has included cybersecurity risk as one of the key enterprise risks. Based on that, a working group formed in 2014, coordinated by the cybersecurity area with the participation of industrial control systems specialists, has been understanding the new challenges of cybersecurity risk, developing activities to identify and protect critical digital assets.
During
Ecopetrol’s cybersecurity team established a plan to continue the incorporation of cybersecurity practices to enhance the awareness about these risks at an operational level and adjust current information security practices considering the cyber-threat context. Likewise, as a result of this process, we are currently continuing the incorporation of elements relative to management of the cyber security threat, including policies, specialized monitoring and control mechanisms, vulnerability management and cybersecurity insurance coverage, among others.
Ecopetrol S.A. has a Security Operations Center service, in order to enhance the ability to foresee and identify trends in attacks in Ecopetrol S.A.’s information technology infrastructure and to monitor Ecopetrol’s reputation on the internet.
While there were cyber-attacks during
Furthermore, during
Ecopetrol
We are exposed to certain risks associated with the nature of our operations and the financial instruments we use. Among the risks that affect our financial assets, liabilities and expected future cash flows are changes in commodity prices, currency exchange rates, interest rates and the credit quality of our counterparties.
Commodity price risk is associated with our day-to-day operations as we export and import crude oil, natural gas and refined products. We occasionally use hedges to partially protect our financial results from price fluctuations taking into account that part of our financial exposure under purchase contracts for crude oil and refined products depends on international oil prices. We believe that the risk of such exposure is partially naturally hedged since we are an integrated group (with operations in the upstream, midstream and downstream segments) and either export crude oil at international market prices or sell refined products at prices that are correlated to international market prices. During the second half of 2019, Ecopetrol S.A. executed hedging operations due to its exposure to pricing indices different from the commercialization benchmark and different pricing periods between the buying and the selling of physical barrels. We do not use derivative financial instruments for speculative or profit-generating purposes.
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,
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
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
The trust funds linked to Ecopetrol S.A.’s pension obligations (PAP) are also exposed to changes in interest rates, as they include fixed- and floating-rate instruments that are mark to market. This exposure is continuously monitored by our treasury office given the potential impact volatility may have on our financial results. The treasury office’s information is gathered from reports provided by the asset managers. These reports refer to regulatory limits as well as market, credit and liquidity risks. The investment guidelines with respect to the PAPs are issued by the Colombian regulation for pension funds, as stipulated in the Decree 1833 of 2016 and Decree 1913 of 2018, where it is indicated that they have to follow the same regime as the regular obligatory pension funds in their moderate (i.e., neither conservative nor aggressive) portfolio. For further information regarding the trust funds linked to the pension obligations of the company, see Note
Finally, counterparty risk is the potential probability that a borrower or counterparty defaults on any obligation. In our case, we are exposed to this risk as we invest in different financial instruments and receive letters of credit in order to mitigate our exposure with our commercial counterparties. We manage this risk by monitoring and analyzing the counterparty’s creditworthiness, stock price behavior, spreads on credit default swaps, probability of default, among others.
Hedging guidelines for Ecopetrol S.A. and its subsidiaries Ecopetrol S.A.’s management established new guidelines for hedging strategies for Ecopetrol S.A. and its subsidiaries. These guidelines allow us to use financial instruments in order to mitigate the impacts in Ecopetrol’s financial statements as a result of the fluctuation of risk factors, such as commodity prices, exchange rate, interest rate and others. These guidelines determine general principles governing hedging operations, corporate governance, the process for implementing operations which includes the identification of risk exposition as an integrated group, the identification and design of the financial structures, and execution and monitoring, among others. The guidelines also include a list of allowable financial assets, such as forwards, futures, options and swaps and describe the differences between strategic and tactical hedging, where the former focus on protecting our financial results from market volatility and the latter is mainly designed to hedge the market risk of specific trading in physical markets. Investment Guidelines
Ecopetrol S.A.
Ecopetrol S.A.’s management established guidelines for our investment portfolios. These guidelines determine that investments in Ecopetrol S.A.’s U.S. dollar portfolio are generally limited to investments of our excess cash in fixed-income securities issued by entities rated A or higher in the long term and A1/P1/F1 or higher in the short term (international scale) by Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings. In addition, Ecopetrol S.A. may also invest in securities issued or guaranteed by the U.S. government or Colombian government, without regard to the ratings assigned to such securities. In Ecopetrol S.A.’s Colombian Peso portfolio, it must invest our excess cash in fixed-income securities of issuers rated AAA in the long term, and F1+/BRC1+ in the short term (local scale) by Fitch Ratings Colombia or BRC Standard & Poor’s. In addition, Ecopetrol S.A. may also invest in securities issued or guaranteed by the Colombian government without rating restrictions.
On December 2018, Ecopetrol S.A.’s management approved an update to the investment guidelines applicable for both U.S. Dollars and Colombian Pesos, that has been effective since January 1, 2019. The guidelines were updated in light of the following: the current reality of the financial markets, alignment with the practices of comparable companies in the oil sector, the Ecopetrol Group’s current corporate structure and the need to have a larger investment universe with the objective of generating higher returns on resources with an acceptable level of risk. The primary changes are:
Both the Ecopetrol S.A. U.S. Dollar portfolio and the Colombian Peso portfolio may be invested in fixed income securities issued by entities with a rating equal to or greater than Ecopetrol S.A’s credit risk rating, but which at all times must be a minimum of investment grade as rated by any of the internationally recognized rating agencies (Standard & Poor’s Moody’s, and Fitch Ratings). In order to diversify risk in both our U.S. Dollar and Colombian Peso portfolios, Ecopetrol S.A.’s management will determine short and long term limits by issuer and issuance based on internal analyzes and external risk ratings. Additionally, the portfolios in U.S. Dollar and Colombian Peso of Ecopetrol S.A. will be segmented in the tranches determined by Ecopetrol S.A.’s management, meeting the Company’s working capital and liquidity needs, benchmarks and cash flow projections.
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, Caño Limón – Coveñas Crude Oil Pipeline Spill
On December 11, 2011, the Caño Limó
A class action lawsuit has been filed against Ecopetrol S.A. and against employees of the company, and the First Administrative Court has jurisdiction to conduct the case, which is in the probatory stage.
The Regional Environmental authority of Norte de Santander, or Corporación Autónoma Regional de la Frontera Nororiental (CORPONOR) has filed a lawsuit against Ecopetrol at the Administrative Court of Norte de Santander claiming for (i) the environmental loss caused by the incident and (ii) for compensation costs relating to the environment damage for approximately COP$33 billion. Ecopetrol’s legal counsel filed to dismiss the lawsuit on June 2, 2014, based on three grounds: (i) there is no proof of environmental loss, (ii) CORPONOR does not have the authority to file this lawsuit and (iii) CORPONOR’s petition for direct compensation is not the proper legal action according to the applicable procedural rules. Currently this lawsuit is in the evidentiary stage.
Ecopetrol and national and local authorities convened to develop a project consisting of an alternative to the water supply
BT Energy Challenger
On October 22, 2014, we were served with a class action suit against us seeking monetary damages of approximately COP$7.4 trillion related to an incident that occurred on August 21, 2014, during the loading operations of the BT Energy Challenger vessel. The claimants alleged possible damage to the port area of Ecopetrol’s terminal in Coveñas, as well as of marine and submarine areas and beaches that form the geographical area of the Morrosquillo Gulf. This allegation is currently under investigation by the Harbor Master of Coveñas. Ecopetrol filed a motion requesting the judge to require the claimants to amend their claim to more precisely set forth the facts and evidence it believes establishes Ecopetrol’s liability.
On March 3, 2015, Ecopetrol filed its statement of defense arguing the exclusive fault of a third party. On October 20, 2015, the Court denied a class action of more than 100 informal traders in the region because there is no common identity with the initial class (hotel employees). However, during 2016 the Sucre Administrative Tribunal accepted another 1,208 informal traders and fishermen as claimants.
On March 10, 2017, a mandatory conciliatory hearing was held in order to seek an agreement but it failed.
In January 2018, a judicial order was issued to commence the evidence gathering process, a decision which was objected by the parties.
In September 2018, all the ordered statements were made, the evidentiary stage was finalized and the parties filed their final closing briefs. As of the date of this annual report the case remained pending.
As of the date of this annual report, the claims have decreased to COP$7.3 trillion, as a result of the reconsideration of the amount initially requested and the inclusion of new claimants in the process. PetroTiger
As highlighted in previous 20-F and 6-K filings, on January 6, 2014, the United States Department of Justice (DOJ) announced the unsealing of charges against two former co-chief executive officers (CEOs) and the former general counsel of PetroTiger Ltd. (PetroTiger), alleging, among other things, violations of the U.S. Foreign Corrupt Practices Act (FCPA) and conspiracy to commit violations of the FCPA and money laundering in connection with payments made to an Ecopetrol employee. By the time of the DOJ announcement, that employee no longer worked at the Company. The DOJ alleged the payments were made to secure Ecopetrol’s approval for PetroTiger’s entry into an oil services contract with Mansarovar Energy Colombia Ltd. Ecopetrol participated in the Mansarovar project as non-operating partner in a joint operating agreement. Also on January 6, 2014, the DOJ announced that the general counsel of PetroTiger had pled guilty on November 8, 2013, to one count of conspiracy to violate the FCPA and to commit wire fraud. One of the charged former co-CEOs pleaded guilty on February 18, 2014, to the same charge. On May 9, 2014, the DOJ charged the other former co-CEO with conspiracy to violate the anti-bribery provisions of the FCPA, conspiracy to commit wire fraud, conspiracy to launder money, and substantive FCPA anti-bribery and money laundering violations. On June 15, 2015, that co-CEO pleaded guilty to conspiracy to violate the FCPA.
After the DOJ unsealed its charges on January 6, 2014, Ecopetrol filed a complaint the same month, jointly with the Transparency Secretariat of the Presidency of the Republic, to Colombia’s Attorney General’s office requesting the investigation of individuals who may have been involved in the wrongdoing related to the Mansarovar contract. Colombian authorities initiated a proceeding related to PetroTiger, and on March 11, 2015, arrested four current Ecopetrol employees and two former Ecopetrol employees related to their investigation of the Mansarovar project and five other contracts involving PetroTiger and Ecopetrol. To date, four investigations of the control entities continue in course. During 2017 and 2018 to date, Colombian authorities have resolved an appeal confirming the conviction of a former Ecopetrol employee and another person involved in the case but not linked with Ecopetrol. Likewise,
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
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 Class action of the AWA Indigenous Community
On April 2, 2018, a class action lawsuit was filed against Ecopetrol and CENIT by the Inda Guacaray and Inda Sabaleta reservations of the AWA Indigenous community who claim damages to their communities by environmental contamination and damage to natural resources that the defendants supposedly caused by act or omission during various environmental incidents. In August 2018 Ecopetrol answered the complaint. The parties are currently waiting for the evidentiary stage to start.
Although the plaintiffs did not clearly determine the amount of their claims, Ecopetrol and the National Agency for Legal Defense (Agencia Nacional de Defensa Jurídica del Estado or ANDJE) have initially calculated the amount to be up to COP$358,201,371,800.
Foncoeco On March 18 2019, Ecopetrol received judicial notice of a lawsuit filed by workers and former workers seeking if between 1997 and 2017 the company allocated part of its profits for the wellbeing of their workers. The plaintiffs considered that they had the right to receive those profits up to COP $ 3,157,461,510,000. This lawsuit is similar the one that was ruled on behalf of Ecopetrol in 2011. Environmental Administrative Proceedings
As of December
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:
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 current employee of Ecopetrol, and former employees of Reficar, as well as against (ii) Chicago Bridge & Iron Company N.V., CBI - Chicago Bridge & Iron company (CB&I) Americas Ltd., Chicago Bridge & Iron Company CB&I UK Limited, CBI Colombiana S.A., Foster Wheeler USA Corporation and Process Consultants Inc, and the following insurance companies, Compañía Aseguradora de Fianzas S.A, Coaseguro Confianza S.A. ,Liberty Seguros S.A., CHUBB de Colombia Compañía de Seguros S.A., Seguros Colpatria S.A. and Mapfre Seguros Generales de Colombia S.A., as third parties with joint liability.
As for the other 21 individuals initially investigated in 2017, the Office of the Comptroller General closed the investigations. Therefore, as of the date of this annual report, no current or former member of Ecopetrol’s Board of Directors was charged in the first proceeding
As of the date of this annual report, no charges have been issued in the second proceeding
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
On February 2, 2018, the Legal Accounts Commission of the National House of Representatives of the Republic of Colombia informed Reficar that the House of Representatives decided, through Resolution No. 2713 on December 3, 2017, that it would not close the General Budget and Treasury Account and the National Balance Sheet for the 2016 fiscal year, since the 2016 Financial Statements of several state entities, among them Reficar, had received a negative opinion from the Office of the Comptroller General. Pursuant to Resolution No. 2713, Colombian control entities were ordered to initiate the corresponding disciplinary, fiscal and/or criminal investigations.
On February 6, 2019, the Legal Accounts Commission of the National House of Representatives of the Republic of Colombia informed Reficar that the House of Representatives decided, through Resolution No. 3135 on December 18, 2018, that it would not close the General Budget and Treasury Account and the National Balance Sheet for the 2017 fiscal year, since the 2017 Financial Statements of several state entities, among them Reficar, had received a negative opinion from the Office of the Comptroller General. Pursuant to Resolution No. 3135, Colombian control entities were ordered to initiate the corresponding disciplinary, fiscal and/or criminal investigations.
In respect of the special audits mentioned in sections 1.3, 1.4, 1.5 and 1.6 above, as of the date of this annual report, Reficar has no knowledge of any procedural actions carried out by any of the Colombian control entities regarding the disciplinary, fiscal and/or criminal investigations ordered by Resolution No. 2713, Resolution No. 3135 or Resolution No. 2898.
Reficar’s external auditors issued an unqualified opinion on Reficar’s financial position as of December 31, 2016, 2017, 2018 and
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.
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. The specific content and status of the remaining As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar are not part of the Attorney General’s Office proceedings.
The Prosecutor’s Office has been conducting the following legal proceedings:
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
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. On January 27, 2020, during the indictment hearing, Ecopetrol and Reficar were recognized as victims.
Ecopetrol and Reficar have cooperated closely and extensively with the control entities in furthering their investigations and will continue to monitor the status and development of these investigations.
As of the date of this annual report, the current Boards of Directors of Ecopetrol and Reficar and their employees are not part of the Prosecutor’s Office proceedings. None of the legal proceedings described in this paragraph are related with bribery charges. As of the date of this annual report, Ecopetrol and Reficar have no knowledge of any legal proceeding in the United States regarding the project.
On May 25, 2016, CB&I filed its Answer to the Request for Arbitration and Counterclaim for approximately US$106 million and COP$324,052 million. On June 27, 2016, Reficar filed its reply to CB&I’s counterclaim denying and disputing the declarations and relief requested by CB&I. On April 28, 2017, CB&I submitted its Statement of Counterclaim increasing its claims to approximately US$116 million and COP$387,558 million. On March 16, 2018, CB&I submitted its Exhaustive Statement of Counterclaim further increasing its claims to approximately US$129 million and COP$432,303 million (including in each case interest), and also filed its Exhaustive Statement of Defense to Reficar’s claims. On this same date, Reficar filed its Exhaustive Statement of Claim seeking, among others, US$139 million for provisionally paid invoices under the Memorandum of Agreement(“MOA”) and Project Invoicing Procedure (“PIP”) Agreements and the EPC Contract. On June 28, 2019, CB&I submitted its Reply to the Non-Exhaustive Statement of Defence to Counterclaim increasing its claims to approximately US$137 million and COP$503,241 million (including in each case interest, respectively). On this same date, Reficar filed its Reply to CB&I’s Non-Exhaustive Statement of Defense and its Exhaustive Statement of Defense to CB&I’s counterclaim, updating its claim for provisionally paid invoices under the MOA and PIP Agreements and the EPC Contract to approximately US$137 million. In January 2020, McDermott International Inc., CB&I’s parent company, filed for bankruptcy and announced that it would initiate a reorganization plan pursuant to Chapter 11 of the United States Bankruptcy Law. In response to this situation, Reficar has implemented actions to protect its interests and is advised by a group of experts with whom it will continue to analyze other available measures under these new circumstances.
The
On January 21, 2020, Comet II B.V., the successor in interest to Chicago Bridge & Iron Company N.V., commenced a bankruptcy case under title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. Upon the bankruptcy filing, an automatic stay of the commencement or continuation of any action or proceeding, or the enforcement of any judgment or award, against Comet II B.V. became effective, staying the arbitration against Comet II B.V. On January 23, 2020, Comet II B.V. obtained an order from the Bankruptcy Court permitting it to, in its discretion, modify the automatic stay to permit it to proceed with litigation or other contested matters. On March 14, 2020, the Bankruptcy Court entered an order confirming a plan of reorganization, and the order provides for the stay against the arbitration to end upon the earlier of the effective date of the plan and August 30, 2020. In respect of the arbitration involving Reficar, the confirmation order provides that the proper forum for adjudication of the merits of the arbitration is the International Chamber of Commerce tribunal, the arbitration claims will not be subject to estimation in the Bankruptcy Court, and the stay will not be violated if the parties discuss logistical items with the International Chamber of Commerce tribunal or each other. The order reserves all rights and arguments of the parties related to the arbitration schedule, hearing location, and arbitration logistics and also recognizes that, without waiving any arguments, including but not limited to the Debtors’ objections to alternative hearing locations and long gap(s) between hearing dates, lifting the stay on August 30, 2020 provides sufficient time to commence hearings on or after December 7, 2020. Bioenergy Special Audit
The Office of the Comptroller General, in exercise of its fiscal monitoring duties and authority as set forth in Article 267 of the Political Constitution, has undertaken audits of the performance of the Bioenergy S.A.S. and Bioenergy Zona Franca S.A.S. investments.
On February 6, 2017 the Office of the Comptroller General initiated a Special Intervention (Special Audit) in order to evaluate the use of public funds in the project carried out by Bioenergy Zona Franca S.A.S. and Bioenergy S.A. On July 10, 2017 the Office of the Comptroller General issued its final report with 15 findings related to: (i) acquisition, lease payments and the use of agricultural lands, (ii) loss of profits due to the project’s delay; and (iii) execution of contracts related with the building, commissioning and start-up of the industrial plant and the agricultural component of the project. On December 28, 2018, Bioenergy completed all of the activities set forth in the remediation plan to address the 15 findings.
Finally, in 2019 the Office of the Comptroller General initiated and ended a compliance audit of Bioenergy S.A.S for the period starting July 1, 2017 to May 31, 2019. The Comptroller General issued its compliance audit final report with seven findings related to: (i) agricultural lands productivity, (ii) incomes and expenses from rental payments of subleased agricultural lands, (iii) Balanced scorecard results for 2017-2018, (iv) update of laboratory procedures, (v) transport contract number 0029-17 settlement, (vi) document handling and (vii) Campo Victoria plot of Land. Bioenergy filed the remediation plan on February 25, 2020.
Our Shareholders’ General Assembly was held on March
In 2018, the Board of Directors approved a dividend policy consisting of the ordinary distribution of between 40% and 60% of the adjusted net income of the Company of each fiscal year. For this purpose, the Board of Directors shall assess overall delivery against the Company’s financial targets, as well as the macroeconomic environment, projected cash requirements for delivering on our Business Plan and strategy, while maintaining appropriate financial flexibility in keeping the Company’s debt metrics in line with an investment grade rating. The policy does not preclude the distribution of extraordinary dividends above the 40% to 60% range, under exceptional circumstances and with due consideration of the above criteria. The maximum amount to be distributed is the profits available to shareholders (net income after release and appropriation for legal, fiscal and occasional reserves).
Pursuant to Colombian law, dividend distribution to our shareholders must be approved by a 78% majority of the shares represented in the corresponding General Shareholders Assembly. In the absence of this special majority, at least 50% of the net profits must be distributed.
On March 27, 2020, our shareholders at the ordinary General Shareholders’ Assembly approved an ordinary dividend of56% of our net income for the fiscal year ended December 31, 2019. At the Extraordinary General Shareholders’ Meeting held on December 16, 2019, the Company’s Shareholders approved the following: i) the change in the destination of the Company's occasional reserve that had been constituted in the General Shareholders’ Meeting held on March 29, 2019 and ii) its subsequent distribution as an extraordinary dividend of 89 Colombian pesos (COP$89) per share. On March 29, 2019, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 60% of our net income or COP$169 per share (within the dividend policy of 40% and 60% of net income), for the fiscal year ended December 31, 2018 and an extraordinary dividend of 20% of our net income or COP$56 per share, given our strong operational and robust cash position in 2018,for a total dividend per share of COP$225. On March 23, 2018, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 55% of our net income for the fiscal year ended December 31, 2017. On March 31, 2017, our shareholders at the ordinary General Shareholders Assembly approved an ordinary dividend of 40% of our net income before the impairment of non-current assets (net of taxes) for the fiscal year ended December 31, 2016.
Ecopetrol S.A. is required to have legal reserves equal to 50% of its subscribed capital. If the legal reserves are less than 50% of subscribed capital, we will contribute 10% of net income to our legal reserves every year until our legal reserves meet the required level.
On August 2010, our ADSs began trading on the Toronto Stock Exchange Registration and Transfer of Shares
Under Colombian law, transfers of shares must be registered on the issuer’s stock ledger. Only those holders registered on the stock ledger are considered by law as shareholders. Ecopetrol’s shares are in electronic form, other than those shares held by the Nation, which are in physical form.
Transfers of electronic shares is required to be negotiated through the Colombian Stock Exchange. In Colombia, only the relevant stockbrokers calledsociedades comisionistas de bolsa are authorized to make the transfer of shares through the Colombian Stock Exchange. The transfer of shares is registered in the Centralized Security Deposit (Depósito Centralizado de Valores) or DECEVAL, through the relevant stockbrokers. DECEVAL records the share transfer on its systems, in order to make the corresponding registration in the issuer stock ledger.
Under Colombian legislation, if a transfer of shares has a value equivalent to or higher than 66,000 UVR (the UVR was COP$
Nevertheless, pursuant to Decree 2555 of 2010
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.
Ecopetrol
5.875% Notes due 2023 4.125% Notes due 2025 5.375% Notes due 2026 7.375% Notes due 2043 5.875% Notes due 2045 Please refer to Exhibits 4.13, 4.14, 4.15, 4.16, 4.17, 4.18 and 4.19 to this annual report for the information relating to these debt securities required by Item 12.A of Form 20-F.
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:
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 Other Please refer to Exhibit 2.1 to this annual report for the remaining information relating to our American Depository Shares required by Item 12.D of Form 20-F.
The following is a general description of the Colombian tax considerations for investments in common shares in Colombia or for the purchase of ADSs, in a foreign securities market. This description is based on applicable law in effect as of the date of this annual report is issued, which may be subject to changes.
Prospective purchasers of common shares or ADSs should consult their own tax advisors for a detailed analysis of the tax consequences in Colombia, resulting from the acquisition, ownership and disposition of common shares or ADSs.
General Rules
Colombian entities and individuals who are deemed to be residents within the Colombian national territory for Colombian tax purposes are subject to Colombian income tax on their worldwide income. Foreign entities and individuals who are not deemed to be residents in Colombia, are subject to income tax in Colombia only with respect to their Colombian-source income, which is generally defined as income obtained from
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
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:
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:
Law 1739 of 2014 clarifies that Colombian nationals who meet any of the following requirements will not be deemed as tax residents:
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:
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:
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:
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
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.
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 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%
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
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:
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.
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
Each holder is encouraged to consult such holder’s tax advisor concerning the overall tax consequences to it, including the consequences under laws other than U.S. federal income tax laws, of an investment in common shares or ADSs.
In this discussion, references to a “U.S. Holder” are to a beneficial owner of a common share or an ADS that is for U.S. federal income tax purposes (1) an individual citizen or resident of the United States, (2) a corporation, or any other entity taxable as a corporation, organized under the laws of the United States, any state thereof or the District of Columbia, (3) an estate whose income is subject to U.S. federal income tax regardless of its source, or (4) a trust if (i) a United States court can exercise primary supervision over the trust’s administration and one or more United States persons are authorized to control all substantial decisions of the trust or (ii) it has in effect a valid election under applicable U.S. Treasury regulations to be treated as a U.S. person.
For U.S. federal income tax purposes, holders of ADSs generally will be treated as owners of the common shares represented by such ADSs.
This discussion does not address any aspect of U.S. federal taxation other than U.S. federal income taxation (such as the estate and gift tax or the Medicare tax on net investment income). Holders of common shares or ADSs should consult their own tax advisor regarding the U.S. federal, state and local and other tax consequences of owning and disposing of common shares and ADSs in their particular circumstances.
Distributions on Common Shares or ADSs
A distribution to U.S. Holders made by us of cash or property with respect to common shares or ADSs generally will be treated as a dividend for U.S. federal income tax purposes to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Distributions in excess of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes, will be treated first as a tax-free return of capital reducing such U.S. Holder’s adjusted tax basis in the common shares or ADSs. Any distribution in excess of such adjusted tax basis will be treated as capital gain and will be either long-term or short-term capital gain depending upon whether the U.S. Holder held the common shares or ADSs for more than one year. Distributions of additional common shares or ADSs to U.S. Holders that are part of a pro rata distribution to all of our shareholders generally will not be subject to U.S. federal income tax. We do not maintain calculations of our earnings and profits under U.S. federal income tax principles, and, therefore, except as described in the previous sentence, U.S. Holders should expect that any distributions generally will be reported as dividends for U.S. federal income tax purposes. As used below, the term “dividend” means a distribution that constitutes a dividend for U.S. federal income tax purposes.
The amount of any distribution will include the amount of any Colombian tax withheld on the amount distributed, and the amount of a distribution paid in Colombian Pesos will be measured by reference to the exchange rate for converting Colombian Pesos into U.S. dollars in effect on the date the distribution is received by the Depositary (or by a U.S. Holder in the case of a holder of common shares) regardless of whether the payment is in fact converted into U.S. dollars. If the Depositary (or U.S. Holder in the case of a holder of common shares) does not convert such Colombian Pesos into U.S. dollars on the date it receives them, generally, any gain or loss resulting from currency exchange fluctuations during the period from the date the dividend payment is included in income to the date the payment is converted into U.S. dollars will be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income (as discussed below). The gain or loss generally will be income or loss from sources within the United States for foreign tax credit limitation purposes. Dividends paid by us will not be eligible for the dividends received deduction allowed to corporations under the Code.
If you are a non-corporate U.S. Holder, dividends that constitute qualified dividend income will be taxable to you at the preferential rates applicable to long-term capital gains, provided that you meet certain holding requirements. Dividends paid on the ADSs will be treated as qualified dividend income if (1) the ADSs are readily tradable on an established securities market in the United States and (2) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, a passive foreign investment company (PFIC). The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States, as long as they are so listed. Based on our audited financial statements and 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
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
With respect to the sale or exchange of common shares or ADSs, the amount realized generally will be the U.S. dollar value of the payment received determined on (1) the date of receipt of payment in the case of a cash basis U.S. Holder and (2) the date of disposition in the case of an accrual basis U.S. Holder. If the common shares or ADSs are treated as traded on an “established securities market,” a cash basis taxpayer, or, if it elects, an accrual basis taxpayer, will determine the U.S. dollar value of the amount realized by translating the amount received at the spot rate of exchange on the settlement date of the sale.
Deposits and withdrawals of common shares in exchange for ADSs, and of ADSs for common shares, generally will not result in the realization of gain or loss for U.S. federal income tax purposes.
Backup Withholding and Information Reporting
In general, dividends on common shares or ADSs, and payments of the proceeds of a sale, exchange or other taxable disposition of common shares or ADSs, paid within the United States, by a U.S.
Backup withholding is not an additional tax. The amount of any backup withholding tax from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability, provided that the required information is timely furnished to the IRS.
U.S. 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.
Payments in foreign currency with respect to certain foreign exchange transactions including international investments between Colombian residents and non-Colombian residents must be conducted through the foreign exchange market. Therefore, any foreign currency income or expense under the ADRs must be completed through the appropriate channels of the foreign exchange market. Transactions conducted through the foreign exchange market are made at market rates freely negotiated with authorized foreign exchange intermediaries (local banks, financial corporations, administrators and others). Since September 25, 1999, the Colombian foreign exchange regime is structured under the system of free flotation of the exchange rate, whereby market forces determine the level of exchange rate from time to time.
Foreign portfolio investments must be made through authorized foreign exchange investment management companies. Only brokerage firms, trust companies and investment management companies, subject to the inspection and supervision of the Superintendence of Finance, are allowed to make investments in the local Colombian market on behalf of foreign investors. Such brokerage firms, trust companies and investment management companies also act as the foreign investors’ local representatives for tax and foreign exchange purposes.
Colombian law provides that the Colombian Central Bank may intervene in the foreign exchange market at its own discretion at any time (i.e., it may limit the remittance of dividends whenever the international reserves fall below an amount equal to three months of imports). Additionally, from time to time, the Colombian government introduces amendments to the International Investment Statute. Hence, we cannot assure you that the Colombian Central Bank will not intervene in the future imposing restrictions to the free convertibility system currently applicable in Colombia. See sectionRisk
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.
On
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,
Table
All our common shares have identical voting rights.
As of February
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.
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:
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.
Since 2004, Ecopetrol S.A. has voluntarily adopted transparency, governance and control practices to facilitate corporate governance in order to generate confidence among stakeholders and ensure the sustainability of its business.
The corporate governance practices at Ecopetrol S.A.:
Corporate Governance System
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
156 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:
According to corporate governance practices recommended by the OECD, an organization to which Colombia has been a member since 2018, the National Government implemented the practice of
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
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
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
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.
Preference Rights and Restrictions Attaching to Our Shares
Under Commercial Colombian law, our shareholders have the following economic privileges and voting rights:
Sale of Assets. For a ten-year period counted from the date of subscription of the declaration of the Nation dated February 16, 2018 or until the Nation loses its status as majority shareholder, the Nation guarantees that any sale of 15% or more of our assets requires the approval of the General Shareholders Assembly and that the Nation would only be allowed to vote its shares in favor of the proposal if 2% or more of our minority shareholders accept the proposal.
Candidate List. Pursuant to our bylaws and Law 1118 of 2006, the Nation will include in its candidate list for election of members of the Board of Directors one member selected by the departments that produce hydrocarbons. In addition, pursuant to the declaration of the Nation dated February 16, 2018, the Nation will include in its candidate list for election of members of the Board of Directors one member selected by the ten largest minority shareholders. The minority shareholders’ right to select a candidate loses its effect when minority shareholders, according to their share participation, name a member to our Board of Directors.
Extraordinary Shareholders Meetings. Our bylaws provide that the entity exercising permanent control over Ecopetrol must instruct the Company’s CEO or External Auditor to call an extraordinary meeting of the Company’s shareholders when so requested by a plurality of shareholders holding at least 5% of the total number of outstanding shares. Such requests shall be made in writing and must clearly indicate the purpose of the meeting.
Investor Relations Office. Ecopetrol has an investor relations office, a specialized unit responsible for our shareholders. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may request that the investor relations office conduct a special audit, provided that such audit does not hinder the day-to-day operations of the Company, of the following documents: the income statement; the proposal for the distribution of profits; the report of the Board of Directors as to the economic and financial status of our Company; the report from our general counsel as to the legal status of our Company; and the report from the independent auditors. Special audits cannot be made of documents that contain scientific, technological or statistical information of our Company, or agreement that gives us competitive and economic advantages over our competitors, or in respect of any document related to intellectual property. Shareholders also have the right to propose good corporate governance recommendations to the office for the protection of investors.
Others. Pursuant to our bylaws, shareholders holding at least 5% of the total number of shares outstanding may propose recommendations to our Board of Directors pertaining to the management of our Company. Any shareholder may file a written petition to our Board of Directors to investigate corporate governance violations that the shareholder believes to have been committed.
Amendments to Rights and Restrictions to Shares
We have only one class of stock and it has no special rights or restrictions (ordinary shares). Our shareholders do not have any type of preemptive rights. The rights given to our shareholders by law are described in our bylaws and may only be modified through an amendment to the law.
The additional rights given to our minority shareholders in our bylaws and corporate governance code may only be modified through an amendment of those internal documents.
Limitations on the Rights to Hold Securities
There are no limitations in our bylaws or Colombian law on the rights of Colombian residents or foreign investors to own the shares of our Company, or on the right to hold or exercise voting rights with respect to those shares, except in cases of legal
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
All of our agreements with suppliers or third parties include a provision relating to compliance with applicable anti-bribery and anti-corruption regulations. These agreements also require our suppliers and third parties to accept our Code of Ethics and Conduct and our compliance manuals.
Our https://www.ecopetrol.com.co/wps/portal/web_es/ecopetrol-web/corporate-responsibility/ethics-and-compliance/code-of-ethics
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
160
Independent members:
The
Germán Eduardo Quintero Rojas Orlando Ayala Lozano Luis Guillermo Echeverri Vélez
Juan Emilio Posada Echeverri Sergio Restrepo Isaza Santiago Perdomo Maldonado Esteban Piedrahita Uribe
Hernando Ramírez Plazas
Carlos Gustavo Cano Sanz
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
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.
Compensation and Nomination Committee
Our compensation and nomination committee, which must be comprised of at least three members, including at least one independent director, provides general guidelines for the selection and compensation of our executive officers and employees.
Corporate Governance and Sustainability Committee
Our corporate governance and sustainability committee, which must be comprised of at least three members, including at least one independent director, makes proposals to our Board of Directors to ensure and supervise the fulfillment of our good corporate governance and sustainability practices in accordance with our corporate governance code.
New Business Committee
Our new business committee, which must be comprised of at least five members, including at least one independent Director, assists our Board in analyzing potential business ventures. Based on its delegation of power, the committee studies and analyzes capital expenditure policies, major investment projects, strategy, new business and other matters that would help us move forward in our efforts toward the consolidation of our strategy. The primary criteria used in the committee’s decision-making process are the optimization of our portfolio and the proper allocation of our resources.
HSE Committee (Health, Safety and Environment)
Our HSE Committee, which must be comprised of at least three members, the majority of which must be independent, supports the management of the Board of Directors in respect of the monitoring and management of risks associated with the health and safety of our employees, contractors and partners, as well as the performance of the Ecopetrol Group’s environmental management.
Technology and Innovation Committee Our technology and innovation committee, which must be comprised of at least three members, the majority of which must be independent, supports the management of the Board of Directors in respect of the technological and digital transformation, as well as the cultural change that Ecopetrol is going through in order to transform Ecopetrol into a leading company in the use of technology and digital innovation in the hydrocarbons sector.
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.
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 Jorge Arturo Calvache Archila (59)has served as Vice-President of Exploration since February 1, 2019. He has more than 30 years of experience. He has served in companies such as Shell and Hocol, where he led exploration projects in the Netherlands, the United States and Colombia. Mr. Calvache holds a degree in Rubén Darío Moreno Rojas (54)has served as Vice-President of Transport Operations and Maintenance since March 1, 2019. Prior to his appointment as Vice-President of Transport Operations and Maintenance, he had served as deputy Vice-President of Transport Operations and Maintenance since April 2018. He has a 30-year career at Ecopetrol S.A., where he has held several managerial positions in the Vice-Presidency of Transportation
Jurgen Gerardo Loeber Rojas
Pedro Fernando Manrique Gutierrez
Juan Manuel Rojas Payán
Yeimy Báez (40) has servedas Gas Vice-President since March 2020. In this position, Ms. Báez will be responsible for leading, strengthening and executing an integrated strategy to develop gas, which being a clean energy source, is fundamental for energy transition and Ecopetrol Group’s sustainability. She has over 16 years of experience in the Mauricio Jaramillo Galvis has served as Vice-President of Health, Safety and Environment (HSE) since January 2020. Mr Jaramillo has 25 years of experience in the oil and gas private sector in Colombia and Latin America. He has been appointed to several leadership roles as Vice-President of HSE of BP Colombia, Vice-President of HSE and Engineering at the Andean Strategic Planning Unit of BP, Vice-President of Corporate Affairs and HSE, and Vice-President of Human Resources and Sustainability at Equión, among others. Mr. Jaramillo holds a master’s degree from Universidad Javeriana, a specialization in Occupational Health and Safety from Universidad El Bosque and a degree from the Operations Academy at MIT. Walter Fabián Canova (53) will serve as Vice-President of Refining and Industrial Processes starting April 16, 2020. Since joining the Ecopetrol Group in
Fernán Ignacio Bejarano Arias Mónica Jiménez González María Juliana Alban Durán Alejandro Arango Lopez Andres Eduardo Mantilla Zarate
Carlos Andrés Santos Nieto (42)has served as Vice-President of Supply and Services since August 7, 2018. Prior to his appointment as Vice-President of Supply and Services, he was Procurement and Supply Chain Manager at Ecopetrol. Mr. Santos is an
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$
Only
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.
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,
Consistent with the guidance issued by the Securities and Exchange Commission that an assessment of recently acquired businesses may be omitted from management’s annual report on internal control over financial reporting in the year of acquisition, management excluded the assessment of the effectiveness of internal control over financial reporting of Inversiones de Gases de Colombia S.A. and its subsidiaries (“Invercolsa”). Invercolsa, which is included in the 2019 consolidated financial statements of the Company, represented 0.8% of total and net assets as of December 31, 2019, and 0.1% and 0.2% of revenues and net income, respectively, for the year then ended. More details regarding Invercolsa’s acquisition can be found in note 12 of our 2019 consolidated financial statements. Based on the assessment performed, management concluded that our internal control over financial reporting was effective as of the end of the period covered by this annual report.
The effectiveness of our internal control over financial reporting has been audited by Ernst & Young Audit S.A.S., an independent registered public accounting firm, as stated in their audit report accompanying our consolidated financial statements.
172 Audit and Non-Audit Fees
Our consolidated financial statements for the fiscal years ended December 31, 2019, 2018
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. Audit-related Fees. The audit-related fees listed in the table above are the fees billed by Ernst & Young Audit S.A.S. in connection with their agreed-upon procedures of our variable compensation bonus system and its review procedures in connection with the offering document related to the SEC-registered bonds we reopened in 2016. Tax Fees. For 2018 the tax fees listed in the table above correspond to a conceptual analysis for a subsidiary about the tax consequences associated with new or proposed legislation based on the economic models prepared by the subsidiary.
Changes in Internal Control over Financial Reporting
There were no changes made in our internal control over financial reporting during the year ended December 31,
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,
Ecopetrol S.A.
174
Index
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Ecopetrol S.A.
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of Ecopetrol S.A. (the Company) as of December 31,
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.
/s/ Ernst & Young Audit S.A.S. We have served as the Company’s auditor since 2016. Bogota, Colombia March 31, 2020 Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of Ecopetrol S.A.
Opinion on Internal Control over Financial Reporting
We have audited Ecopetrol S.A.’ internal control over financial reporting as of December 31, As indicated in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Inversiones de Gases de Colombia S.A. and its subsidiaries (“Invercolsa”), which is included in the 2019 consolidated financial statements of the Company and constituted 0.8% of total and net assets as of December 31, 2019 and 0.1% and 0.2% of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Invercolsa.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Company as of December 31,
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.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young Audit S.A.S. Bogotá, Colombia March 31, 2020 F-6 Ecopetrol S.A. Consolidated statement of financial position
(In millions of Colombian pesos)
Consolidated statement of profit or loss
(In millions of Colombian pesos, except for
Ecopetrol S.A. Consolidated statement of
(In millions of Colombian pesos)
Consolidated statement of changes in equity
(In millions of Colombian pesos)
Ecopetrol S.A. Consolidated statement of changes in equity
(In millions of Colombian pesos)
Consolidated statement of cash flows
(In millions of Colombian pesos)
F-12
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
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:
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Subsidiaries are consolidated from the date on which control is obtained until the date that such control ceases.
All inter–company assets and liabilities, equity, income, expenses and cash flows relating to transactions between entities of the Ecopetrol Business Group were eliminated on consolidation. Unrealized losses are also eliminated. Non–controlling interest represents the proportion of profit, other comprehensive income and net assets in subsidiaries that are not attributable to Ecopetrol shareholders. The following subsidiaries were incorporated in the years indicated: 2019
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
2018
2017
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.
Non–monetary items measured at fair value that are denominated in a foreign currency are translated using the exchange rates prevailing on the date when the fair value is determined. The gain or loss arising on translation of non–monetary items measured at fair value is treated in line with the recognition of the gain or loss on the change in fair value of the item.
F-15 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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 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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The reserves estimation is performed annually as of December 31 in accordance with the United States Securities and Exchange Commission (SEC) definitions and rules set forth in Rule 4–10(a) of SEC Regulation S–X and the disclosure guidelines contained in the SEC final rule – Modernization of Oil and Gas Reporting.
As required by current regulations, the future estimated date on which a field will no longer produce for economic reasons, is based on actual costs and average of crude prices (calculated as the arithmetical average of prices on the first day of the past 12 months). The estimated date for end of production will affect the amount of reserves, unless the prices have been defined by contractual agreements; therefore, if the prices and costs change from one year to the next, the proved reserves estimate also changes. Generally, our proved reserves decrease as prices go down and increase when prices go up.
Reserves estimation is an inherently complex process and it involves professional judgments. Reserves estimations are prepared using geological, technical and economic factors, including projections of future production rates, oil prices, engineering data and duration and amount of future investments, and they imply a certain degree of uncertainty. These estimations reflect the regulatory and market conditions existing on the date of reporting, which could significantly differ from other conditions during the year or in future periods. Any changes in regulatory and/or market conditions and assumptions could materially affect the reserves estimation.
Impact of oil reserves and natural gas in depreciation and depletion
Changes to estimations for proven developed reserves may affect the carrying amounts of exploration and production assets, natural resources and environment, goodwill, liabilities for dismantling and depreciation, depletion and amortization. With all other variables remaining unchanged, a decrease in estimated proven reserves would increase, prospectively, depreciation, depletion and amortization costs, while an increase in reserves would reduce depreciation and amortization expenses, as depreciation, depletion and amortization charges are calculated using the units of production method.
Information about the carrying amounts of exploration and production assets and the amounts charged to income, including depreciation, depletion and amortization, is presented in Notes
Management uses its professional judgment in assessing the existence of evidence of an impairment loss or reversal, based on internal and external factors.
When an indicator of impairment loss or reversal of
The assessments require the use of estimates and assumptions, such as, among other factors: (1) estimation of the volumes and market value of oil and natural gas reserves; (2) production profiles for oilfields and the future production of refined and petrochemical products; (3) investments, taxes and future costs; (4) useful life of assets; (5) long–term prices; (6) the discount rate, which is revised annually and determined as the weighted average cost of capital (WACC); and (7) changes in environmental regulation. The recoverable amount is compared to the carrying amount of the asset, thus determining whether the asset is impaired or if the impairment recognized in prior periods should be reversed.
A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the assets or in the CGU’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of an asset or CGU, other than goodwill, does not exceed either its recoverable amount, or the carrying amount that would have been determined (net of amortization or depreciation) had no impairment loss been recognized for the asset or CGU in prior periods.
Future oil price assumptions are estimated at current market conditions. Expected production volumes, which comprise proven unproved, probable and possible reserves are used for impairment testing because management believes this to be the most appropriate indicator of expected future cash flows, which would also be considered by market participants. Reserves estimates are inherently imprecise and subject to risk and uncertainty. Furthermore, projections about unproved volumes are based on information that is necessarily less robust than what is available for mature reservoirs.
These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may also impact the recoverable amount of assets and/or CGUs, hence, may also affect the recognition of an impairment loss or the reversal of prior period impairment amounts. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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 –impairment of non–financial assets for more information.
According to environmental and oil regulations, the Ecopetrol Business Group is required to bear the costs for the abandonment of oil extraction and transportation facilities, which include the cost of plugging and abandoning wells, dismantling facilities, and environmental remediation in the affected areas.
Estimated abandonment and dismantling costs are recorded at the time of the installation of the assets and are reviewed annually.
The calculations for these estimations are complex and involve significant judgments by Management. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing, extent and amount of expenditure may also change, for example, in response to changes in internal cost projections, changes in reserve estimates, future inflation rates and discount rates. The Ecopetrol Business Group considers that the abandonment and dismantling costs are reasonable, based on the experience of the Ecopetrol Business Group and market conditions; nevertheless, significant variations in external factors used for the calculation of the estimation could significantly impact the amounts recorded in the financial statements.
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The determination of the recoverable amount is described in Note 4.12, and its calculation requires assumptions and estimates. The Ecopetrol Business Group considers that the assumptions and estimations used are reasonable and supportable based on the current market conditions and are aligned to the risk profile of the related assets. However, if different assumptions and estimations are used, they could lead to different results. Valuation models used to determine fair value are sensitive to changes in the underlying assumptions. For example, sales volumes and prices that will be paid for the purchase of raw materials are assumptions that may vary in the future. Adverse changes in any of these assumptions could lead to the recognition of goodwill impairment.
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.
The process of identifying hedging relationships between hedged items and the underlying instruments (derivative and non–derivative, such as long–term, foreign currency–denominated debt), and their corresponding effectiveness, requires the use of judgment by management. The Ecopetrol Business Group periodically monitors the alignment between its hedge instruments and its risk management policy. F-19 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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.
Equity investments available for sale that do not have a market quotation price and for which fair value cannot be reliably measured are measured at cost less any impairment identified at the end of each reporting period.
Measurements at fair value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in the principal market of the asset or liability or in the absence of a principal market in the most advantageous
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:
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 Ecopetrol S.A. Notes to the (Figures expressed in
This category is the most relevant to the Group. The Group’s financial assets at amortized cost includes trade receivables, other receivables, loans to associates, and loans to employees.
Loans and receivables are non–derivative financial assets with fixed or determinable payments that are not quoted in an active market. Loans and receivables, including trade and other receivables, are measured initially at fair value and then at amortized cost using the effective interest rate method, less impairment.
Loans to employees are initially recorded using the present value of the future cash flows, discounted at the current market rate for similar loans. If the interest rate is less than the current market rate, fair value will be less than the amount of the loan. This difference is recorded as a benefit to employees.
Financial assets at amortized cost are subsequently measured using the effective interest (EIR) method and are subject to impairment. Gains and losses are recognized in profit or loss when the asset is derecognized, modified or impaired.
De–recognition of financial assets
The Ecopetrol Business Group derecognizes a financial asset only upon the expiration of the contractual rights to the cash flows of the asset or, when it has transferred its rights to receive such cash flows or has assumed the obligation to pay the cash flows received in full without material delay to a third party and (a) it has transferred substantially all the risks and benefits inherent in the ownership of the financial asset or (b) it has neither transferred nor retained substantially all the risks and benefits of the asset, but has transferred control of the asset.
When the Ecopetrol Business Group does neither transfer nor retain substantially all the risks and benefits of the asset or transfer control of the asset, the Ecopetrol Business Group continues to recognize the transferred asset, to the extent of its continuing participation, and it also recognizes the associated liability.
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Derecognition
A financial liability is derecognized when the obligation specified in the contract is discharged,
Financial instruments are initially recognized at fair value on the date on which a derivative contract is entered into and are subsequently remeasured at fair value. Changes in the fair value of derivatives are recognized as gains or losses in the statement of profit or loss, except for the effective portion of cash flow hedges, which is recognized in other comprehensive income and later reclassified to profit or loss when the hedge item affects profit or loss.
Changes in fair value of derivative contracts, which do not qualify or are not designated as hedges, including forward contracts for the purchase and sale of commodities under negotiation for physical delivery or receipt of the commodity are recorded in profit or loss.
Derivatives embedded in the host contract are accounted for as separate derivatives at fair value if their economic characteristics and risks are not closely related to those of the host contracts and the host contracts are not held for trading or designated at fair value through profit or loss. These embedded derivatives are measured at fair value with changes in fair value recognized in profit or loss.
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 accumulated in OCI are accounted for, depending on the nature of the underlying hedged transaction. If the hedged transaction subsequently results in the recognition of a non-financial item, the amount accumulated in equity is removed from the separate component of equity and included in the initial cost or other carrying amount of the hedged asset or liability.
If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked or when the hedge no longer meets the criteria for hedge accounting, any cumulative gain or loss previously recognized in other comprehensive income remains separately in equity until the forecast transaction occurs is recognized in the consolidated statement of profit or loss. When it is no longer expected that the initially hedged transaction will occur. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Ecopetrol designates long–term loans as hedging instruments for its exposure to the exchange risk in future oil exports. See Note 28 for further information.
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 28 for further information.
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.
Inventories are stated at the lower of cost and net realizable value.
Inventories mainly comprise crude oil, fuels and petrochemicals and consumable inventories (spares and supplies).
The cost of crude oil is the production costs, including transportation costs.
The cost required to bring a pipeline into working order, is treated as part of the related pipeline.
The cost of other inventories is determined based on the weighted average cost method, which includes acquisition costs (deducting commercial discounts, rebates and other similar items), transformation, and other costs incurred to bring inventory to their current location and condition, such as transportation costs.
Consumable inventories (spares and supplies) are recognized as inventory and then charged to expense, maintenance or project to the extent that such items are consumed.
Ecopetrol estimates the net realizable value of inventories at the end of the period. When the circumstances that previously caused inventories to be written down below cost no longer exist, or when there is clear evidence of an increase in the net realizable value because of a change in economic circumstances, the amount of the write–down is reversed. The reversal cannot be greater than the amount of the original write–down, so that the new carrying amount will always be the lower of the cost and the revised net realizable value.
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
F-24 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
An associate is an entity over which the Ecopetrol Business Group has significant influence but not control. Significant influence is the power to participate in the financial and operational policy decisions of the investee, but it is not control or joint control over those policies. Generally, these entities are those in which the Ecopetrol Business Group holds an equity interest with voting rights of 20% to 50%. See Exhibit I –Consolidated companies, associates and joint ventures for further details.
Investments in associates are accounted for using the equity method. Under this method, the investment in an associate is initially recognized at cost. The carrying amount of the investment is adjusted to recognize changes in the Ecopetrol Business Group’s share of net assets of the associate since the acquisition date. Goodwill related to the associate is included in the carrying amount of the investment and it is not tested for impairment separately.
The Ecopetrol Business Group’s share of the results of operations of the associate is recognized in the consolidated statement of profit or loss. Any change in other comprehensive income is recognized in other comprehensive income of the Ecopetrol Business Group.
After application of the equity method, the Ecopetrol Business Group determines if it is necessary to recognize an impairment on its investment in its associate. The Ecopetrol Business Group determines whether there is objective evidence that the investment is impaired. If there is such evidence, the amount of the impairment is calculated as the difference between the recoverable amount and its carrying value, and then the impairment is recognized in the consolidated statement of profit or loss.
When necessary, the Ecopetrol Business Group makes adjustments to the accounting policies of associates to ensure consistency with the policies adopted by the Ecopetrol Business Group. Additionally, the equity method of these companies is measured on their most recent financial statements.
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 records the assets, liabilities, sales revenues, cost of sales and expenses based on the operator’s report. When Ecopetrol is the direct operator of joint venture contracts, it records its percentage of assets, liabilities, sales revenues, costs and expenses, based on the participation of each partner in the items corresponding to assets, liabilities, sales revenues, costs and expenses.
When the Ecopetrol Business Group acquires or increases its participation in a joint operation in which the activity constitutes a business combination, such transaction is recorded applying the acquisition method in accordance with IFRS 3 – Business combination. The acquisition cost is the sum of the consideration transferred, which corresponds to the fair value, on the date of acquisition of the assets transferred and the liabilities incurred. Any transaction cost related to the acquisition or increased share in the joint operation that constitutes a business combination is recognized in the consolidated statement of profit or loss. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The excess of the sum of the consideration transferred and the amount paid in the operation is recognized as goodwill. If the result is in an excess value of the net assets acquired over the amount paid in the operation, the difference is recognized as income in the consolidated statement of profit or loss on the date of recognition of the transaction.
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.
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The estimated useful life of assets fluctuates in the following ranges:
Land is recorded separately from buildings and facilities and it is not subject to depreciation.
Depreciation methods and useful lives are reviewed annually and adjusted if appropriate.
Recognition and measurement
Ecopetrol uses the successful efforts method to account for exploration and production of crude oil and gas activities, following the provisions of IFRS 6 – Exploration for the evaluation of mineral resources.
Exploration costs
Acquisition and exploration costs are recorded as exploration and evaluation assets until the determination of whether the exploration drilling is successful or not; if determined to be unsuccessful, all costs incurred are recognized as expenses in the consolidated statement of profit or loss.
Exploration costs are those incurred with the objective of identifying areas that are considered to have prospects of containing oil and gas reserves, including geological and geophysical, seismic costs, viability, and others, which are recognized as expenses when incurred. Furthermore, disbursements associated with the drilling of exploratory wells and those related to stratigraphic wells of an exploratory nature are charged as assets until it is determined if they are commercially viable; otherwise, they are expensed in the consolidated statement of profit or loss as dry wells expense. Other expenditures are recognized as expenses when incurred.
An exploration and evaluation asset is no longer classified as such when the technical feasibility and commercial viability of extracting a mineral resource are demonstrable. Exploration and evaluation assets are reclassified to the natural and environmental resources account after being assessed for impairment.
All capitalized costs are subjected to technical and commercial revisions at least once a year to confirm the evaluation and exploration efforts continue on the fields; otherwise, these costs are written off through to profit or loss.
Exploration costs are net of the revenues obtained from the sale of crude oil during the extensive testing period, net of cost of sales, since they are considered necessary to complete the asset.
Development costs
Development costs correspond to those costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing. When a project is approved for development, the corresponding capitalized acquisition and exploration costs are classified as natural and environmental resources and costs subsequent to the exploration phase are capitalized as development costs of the properties that contain such natural resources. All development costs are capitalized, including drilling costs of unsuccessful development wells. F-27 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Production costs
Production costs are those incurred to operate and maintain productive wells, and are part of the corresponding equipment and facilities. Production activity includes extraction of oil and gas to the surface, its gathering, treatment and processing as well as storage in the field. Production costs are expenses recorded in the consolidated statement of profit or loss as incurred unless they add oil and gas reserves, in which case they are capitalized.
Production and support equipment is recognized at cost and is part of property, plant and equipment subject to depreciation.
Capitalized costs also include decommissioning, dismantling, retiring and restoration costs, as well as the estimated cost of future environmental obligations. The estimation includes plugging and abandonment costs, facility dismantling and environmental recovery of areas and wells. Changes arising in new abandonment liability estimations and environmental remediation are capitalized in the carrying amount of the related asset.
Depletion
Depletion of natural and environmental resources is determined using the unit–of–production method per field, using proved developed reserves as a base, except in limited exceptional cases that require greater judgment by Management to determine a better amortization factor of future economic benefits over the useful life of the asset. Depreciation rates are reviewed annually, based on reserves reports and the impact of any changes is recognized prospectively in the financial statements.
Reserves are independently estimated by internationally recognized external consultants and approved by Ecopetrol’s Board of Directors. Proved reserves consist of the estimated quantities of crude oil and natural gas demonstrated with reasonable certainty by geological and engineering data to be recoverable in future years from known reserves under existing economic and operating conditions, that is, at the prices and costs that apply at the date of the estimation.
Impairment
Assets associated to exploration, evaluation and production are subject to review for possible impairment in their carrying amount. See Notes 3.2 —Asset impairment
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.
Intangible assets with a defined useful life, are stated at cost less accumulated amortization and any impairment loss. Intangible assets are amortized under the straight–line method, over their estimated useful lives. The estimated useful lives and amortization method are revised at the end of each reporting period; any change in estimates is recognized on a prospective basis.
The disbursements in relation to research activities are expensed as incurred.
Goodwill is initially measured at cost (being the excess of the aggregate of the consideration transferred and the amount recognized for non–controlling interest and any previous interest held over the net identifiable assets acquired and liabilities assumed). After initial recognition goodwill is measured at cost less any accumulated impairment loss. Goodwill is not amortized but tested for impairment annually. F-28 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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,
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The recognition of these provisions coincides with the identification of an obligation related to environmental remediation and Ecopetrol uses available information to determine a reasonable estimation of the related cost.
Provisions for which a negative outcome is assessed as possible are not recognized but are disclosed in the explanatory notes; including those for which the amount cannot be estimated.
If there is an expectation that the provision will be reimbursed, either in whole or in part, for example by virtue of an insurance contract, the amounts expected to be reimbursed are recognized as a separate asset only when such reimbursement is almost certain.
If the effect of the time value of money is significant, the provisions are discounted using the current market rate before taxes reflecting, as applicable, the liability specific risks. When recognizing the discount, the increase of the provision resulting from time elapsed is recognized as financial cost in the profit or loss statement.
Asset retirement obligation
Liabilities associated with the retirement of assets are recognized when there are current obligations, either legal or constructive, related to the abandonment and dismantling of wells, facilities, pipelines, buildings and equipment.
The obligation is usually recorded when the assets are installed or when the surface or the environment are altered at the operating sites. These liabilities are calculated using the discounted cash flow method, using a pre–tax rate reflecting current market conditions similar liabilities and considering the economic limits of the field or the useful life of the respective asset. When it is not possible to determine a reliable estimation in the period in which the obligation originates, a provision is recognized when there is enough information available to make the best estimation.
The carrying amount of the provision is reviewed and adjusted annually considering changes in the assumptions used for its estimation, using a rate that reflects the risk specific to the liability. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment and natural and environmental resources. When a decrease in the asset retirement obligation related to a producing asset exceeds the carrying amount of the asset, the excess is recognized in the consolidated statement of profit or loss. The increase in the provision due to the passage of time is recognized in results for the period as a financial expense.
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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.
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
For employees who joined Ecopetrol after the Act 50 of 1990 went in effect, Ecopetrol makes periodic contributions for severance payments, pensions and labor risks to the respective funds.
In 2008, Ecopetrol partially settled the value corresponding to monthly pension payments from its pension liabilities, transferring such liabilities and their underlying amounts to autonomous pension funds (PAP, for its acronym in Spanish). The funds transferred, and returns on those funds, cannot be redirected, nor can they be returned to the Ecopetrol Business Group, until all of the pension obligations have been fulfilled. The settled obligation covers allowances and pension bonds
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:
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
In determining the appropriate discount rate, in absence of a broad high quality bond market, Management considers interest rates corresponding to the class B TES bonds issued by the Colombian Government as its best reference, at an appropriate discount rate with maturities extrapolated in line with the term expected for each benefit plan. The mortality rate is based on the particular country’s rate, the latest version of which is the RV08 mortality table published in resolution 1555 of October 2010. The future salary and pension increases are linked to the country’s future inflation rates. Note
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.
F-33 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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
For some natural gas supply contracts with a replacement period, a distinction is made between quantities of gas consumed and not consumed in order to recognize the respective revenue or liability relating to quantities that will be requested in the future. Once the customer claims such natural gas, the revenue is recognized.
Services associated with hydrocarbons transport
Revenue from transport services is recognized when the service is provided to the customer and there are no contractual conditions that prevent recognition of the revenue. Ecopetrol Business Group companies
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, petrochemicals and biofuels, such as fuel oil, asphalt, polyethylene, LPG and propane and gasoline, etc., revenue is recognized when the products are shipped and delivered by the refinery; subsequently, they are adjusted for price changes, in the case of products with regulated prices.
In other cases the, Ecopetrol Business Group
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 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
According to the risk profiles, the Ecopetrol Business Group manages advance payment systems for some of its
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
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.
F-35 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
See information by segments in Note
IFRS 16 - Leases As of January 1, 2019, the Ecopetrol Business Group adopted IFRS 16, “Leases” (“IFRS 16”). The effects of the adoption of IFRS 16 are described below: IFRS 16 was issued in January 2016 and supersedes IAS 17 “Leases,” IFRIC 4 “Determining whether an Arrangement Contains a Lease” (“IFRIC 4”), SIC-15 “Operating leases – Incentives” and SIC-27 “Evaluating the Substance of Transactions in the Legal Form of a Lease.” IFRS 16 sets the principles of recognition, measurement, presentation and disclosure of leases and requires lessees to record all their leases under a balance sheet registration model similar to the recording of financial leases under IAS 17. The standard includes two practical expedients for lessees: leases of low-value assets and short-term leases (those with lease terms of 12 months or less). On the commencement date of the lease, a lessee is required to recognize a liability corresponding to the total lease payments and a right-of-use asset which is an asset representing the lessee’s right-of-use of the leased asset during the lease term. The lessees is required to separately recognize interest expense on the lease liability and the depreciation expense on the right-of-use asset. The Ecopetrol Business Group elected to use the transition practical expedient not to reassess whether a contract is, or contains, a lease at January 1, 2019. Instead, the Group applied the standard only to contracts that were previously identified as leases under IAS 17 and IFRIC 4.
The Ecopetrol Business Group adopted IFRS 16, using the modified retrospective method of adoption. The Ecopetrol Business Group recognised right-of-use assets and subleases for COP$490,245 as of January 1, 2019, and a corresponding lease liability for the same amount. Therefore, there was no effect in retained earnings upon initial application.
Definition of a lease Prior to the application of IFRS 16, the Ecopetrol Business Group assessed at contract inception whether a contract is, or contained, a lease in accordance with IFRIC 4. Upon application of IFRS 16, the Ecopetrol Business Group assesses whether a contract is, or contains, a lease by determining whether it conveys the right-of-use of an asset (the underlying asset) for a period of time in exchange for consideration. To assess whether a contract conveys the right to control an identified asset, the regulations of IFRS 16 are used. Ecopetrol Business Group as a lessee On the commencement date of the lease, the Ecopetrol Business Group recognizes lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying asset during the lease term. The interest expense on the lease liability and the depreciation expense on the right-of-use asset are recognised separately. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Right-of-use assets
At the commencement date of the lease, the Ecopetrol Business Group recognizes lease liabilities measured at the present value of the lease payments to be made during the term of the lease. The lease payments include fixed payments (including in-substance fixed payments) less any lease incentives receivable, variable lease payments that depend on an index or a rate, and amounts expected to be paid under residual value guarantees. Variable payments that do not depend on an index or rate are recognised as expenses in 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 Short-term leases and The Ecopetrol Business Group elected to
Leases in which the Ecopetrol Business Group Other leases are classified as finance leases, and
In JOA agreements, the Ecopetrol Business Group assesses whether it controls the use of the asset. If the Ecopetrol Business Group,
The book values of the right-of-use assets, the lease liabilities and
The right-of-use assets are tested for impairment. F-37 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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
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, 2019, 2018 and
Crude oil, fuel and petrochemicals inventories are adjusted to the lowest between the cost and the net realizable value, as a result of fluctuations in international crude oil prices. The amount recorded for this in 2019 was COP$9,759 (2018 - COP$30,252).
The following
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The average return of the investment portfolio in Colombian pesos and U.S. dollars
Changes in fair value are recognized in financial results (Note
As of December 31,
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 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Constitutional Court judged Law 1943 of 2018 (Tax reform) to be unconstitutional and established that this decision would take effect as of January 1, 2020. However, the this law must be followed for the fiscal year 2019. Below is indicated the tax effects applicable in Colombia for 2019:
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
In Statute of limitations on review of tax returns By general rule, the statute of limitations for the income tax return is three (3) years from the deadline to timely file the return as of the date of expiration or as of the filing date, when these have been filed extemporaneously. Returns filed by taxpayers that have made transactions subject to the transfer pricing regulations have a statute of limitations of six years. For tax returns in which tax losses
Income tax expense
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Reconciliation of the income tax expenses
The reconciliation between the income tax expenses and the tax determined based on the statutory tax rate applicable to the Ecopetrol Business Group in Colombia is as follows:
*Information from the years 2018 and 2017 were reclassified for purposes of comparability with 2019.
The effective tax rate balances; among others. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Deferred income tax
The
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Deferred tax details are as follows:
The Ecopetrol Business Group offsets deferred taxes assets and liabilities
Deferred tax assets Deferred tax assets recognized in the consolidated financial statements as of December 31, 2019 and 2018 amounted to COP$6,809,347 and COP$3,879,427, respectively and is mainly comprised of the
Deferred tax assets for tax loss carryforwards and excesses of presumptive income amounted to COP$2,849,087 as of December 31, 2019 and is mainly comprised of:
Additionally, as of December 31, 2019 the excess of presumptive income amounted to COP$1,332,854 that generates a deferred tax assets of COP$228,569 in Refinería de Cartagena, COP$5,361 in Bioenergy and COP$22,590 in Ecopetrol USA. As of December 31, 2018, deferred tax assets have been recognized for an amount of COP$1,002,063 related to excesses of presumptive income and the accumulated tax losses of Refinería de Cartagena amount to COP$948,671 and Bioenergy Zona Franca S.A.S. amount to COP$53,392, as management expects these amounts will be realized in future periods.
The Refinería de Cartagena, Bioenergy, Ecopetrol Costa Afuera (“ECAS”), Ecopetrol USA, Permian and Andean Chemicals Ltd (“Andean”) have accumulated tax losses for a net amount of COP$12,402,061 as of December 2019 and COP$4,292,418 as of December 2018.
In accordance with the tax rules regulation applicable until December 31, 2016, excess presumptive income and minimum base excesses generated before 2017 in income and supplementary taxes and in income tax for equity equality
F-45 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Deferred tax assets not recognized Deferred tax assets related to the tax loss carryforwards generated by the subsidiaries Bioenergy S.A. Ecopetrol Costa Afuera and Andean Chemicals Ltd in the amount of COP$105,592, and excess of presumptive income of Bioenergy SA, Ecopetrol Costa Afuera, Hocol Petroleum Company, Andean in the amount of COP$74,481, were not recognized, as Management believes it is not likely that these deferred tax assets will be recoverable in the short term. If the Ecopetrol Business Group had recognized this deferred tax asset, the profit for the year ending December 31, 2019 would have increased by COP$180,073. The movements of deferred income tax for the years ended December 31, 2019, 2018 and 2017 are as follows:
F-46
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Deferred tax assets (liabilities) not recognized
As of December 31,
Income tax provisions and contingent liabilities Income tax returns for the 2011, 2012, 2014, 2015, 2016, 2017 and 2018 tax years and the CREE for the 2014, 2015, and 2016 tax years of the Group’s companies are subject to acceptance and review by the tax authorities. The management of the Group's companies considers whether the amounts accounted for as liabilities for taxes payable are sufficient and supported by current regulations, doctrine and jurisprudence to meet any claim that may be established with respect to these years. The Company's strategy is to avoid making fiscal decisions resulting in aggressive or risky positions that may call into question its tax returns. Uncertain tax positions - IFRIC 23 The Ecopetrol Business Group’s strategy is to avoid making aggressive tax decisions that may cause questioning of its tax returns, in order to minimize the risk of possible challenge by the tax authorities. Regarding uncertain positions where it has been determined that there may be a possible controversy with the tax authority that could result in an income tax increase, a success rate above 75% has been established, which has been calculated based on current regulations and official interpretations. In accordance with the aforementioned standard, the Ecopetrol Group considers that uncertain tax positions included in its determination of income tax payable will not affect results if the success rate is above 75%. Notwithstanding, the Ecopetrol Business Group will continue to monitor new regulations and doctrine issued by the tax authority and other entities.
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
There are no effects on income tax related to dividend payments made by the Company to its shareholders during
According to the Colombian tax law, income taxpayers who enter into transactions with related parties or related parties located in foreign jurisdictions and in free trade zones or with residents located in jurisdictions considered tax havens, are obliged to determine their ordinary and extraordinary income for purposes of the income and supplementary tax, its costs and deductions, considering for these operations the arm's length principle.
Ecopetrol submitted its transfer pricing informative return for the
For fiscal year
2019. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Law 1943/2018 established that VAT paid on the import, creation, construction or acquisition of real productive fixed assets may be treated as a tax credit for income tax purposes. This VAT cannot be assumed simultaneously as a cost or expense in the income tax nor will it be discounted from the sales tax.
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
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%. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Tax
With regards to procedure, changes have been made: (i) declarations for withholding at source which, that being inefficient, will be enforceable, (ii) electronic notification of administrative actions; (iii) payment of the entire amount covered by a statement of objections to avoid delinquent interest at the current rate plus two points; and (iv) elimination of the extension of enforcement to three (3) additional years to offset tax
Additionally, an audit benefit was included for fiscal years
The above benefit does not apply to: (i) taxpayers who enjoy tax benefits due to their location in a specified geographic region; (ii) if it is demonstrated that declared withholdings at source are non-existent; (iii) if the net income tax is less than 71 UVT (COP$
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
On November 29, 2019, Ecopetrol obtain an additional interest of 8.53% in Invercolsa (See Note 2.2 Basis of consolidation) obtaining control of Invercolsa and resulting in a total ownership interest of 51.88%. Upon obtaining control of Invercolsa, the Ecopetrol Business Group accounted for the transaction as a business combination and started consolidating Invercolsa (including its subsidiaries and associated companies) on the date control was obtained. The previously held interest in Invercolsa, which was accounted for under the equity method, was remeasured at fair value on such the date. The acquisition of controlling interest did not require the payment of any consideration and was recorded using the acquisition method of accounting. The effect of the changes in the Ecopetrol Business Group ownership intrest in Invercolsa is summarized as follow:
The increase in the ownership interest in Invercolsa resulted in a gain recorded in profit or loss since no consideration was paid for such additional interest. Revenue and profits included in the consolidated profit or loss statement upon consolidation of Invercolsa were COP$72,712 and COP$18,198 respectively. If the acquisition had occurred on January 1, 2019, management estimates that the consolidated revenue and net profit attributable to owners of the parent would have increased by COP$459,286 and COP$134,464, respectively. Identifiable assets acquired and liabilities assumed The table below summarizes the amounts recognized for the assets acquired and the liabilities assumed at the date of acquisition.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The fair values of property, plant and equipment, intangible assets and deferred tax have been provisionally determined and may be adjusted in accordance with measurement period included in IFRS 3 - Business combinations. 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.
Equion Energía Limited and Ecopetrol fulfilled the Piedemonte association contract, as well as the delivery and receipt of the operations that are covered under the same. This process established five stages: i) analysis and start-up, ii) planning, iii) execution, iv) delivery and receipt and v) closing. As of December 31, 2019, the project was in the delivery and receipt stage. During the first months of 2020, the next steps have been followed: reach the final agreements, deliver the operations and formalize the contract termination act, which was signed on February 29, 2020 and where the agreements, indemnities, closing of issues, list of pending and inventory of information delivery were included. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following is the movement of investments in associates and joint ventures:
For the year ended December 31, 2019:
For the year ended December 31, 2018:
For the year ended December 31, 2017:
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 assets, liabilities and results of the two main investments in associates and joint ventures, Equion Energy Limited and the Offshore International Group, as of December 31,
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:
Guarantees The Esperanza 1 and 2 farms were pledged as a guarantee for the loan obtained by Bioenergy S.A.S. for the financing of the project (see Note 19.5 – Guarantees and covenants). Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Guarantees
The Esperanza 1 and 2 farms were pledged as guarantee for the loan obtained by Bioenergy S.A.S. for the financing of the project (see Note 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)
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Accounting for suspended exploratory wells
The following table shows the classification by age, from the completion date, of the exploratory wells that are suspended as of December 31, 2019, 2018
F-59 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 intangibles and their amortization and impairment for the years ended December 31,
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 impairment of non–financial assets includes property, plant and equipment and natural resources, investments in companies, goodwill and other non–current assets. The Ecopetrol Business Group is exposed to future risks derived mainly from variations in: (i) the estimate of future oil prices, (ii) refining margins and profitability, (iii) cost profile, (iv) investments and maintenance expenses, (v) amounts of recoverable reserves, (vi) market and country risk assessments reflected in the discount rate and (vii) changes in domestic and international regulations, among others.
Any changes in the above estimates used to calculate the recoverable amount of a non–current
Based on the impairment tests conducted by the Ecopetrol Business Group, the following are the impairment (losses) or reversals for the years ended on December 31, 2019, 2018
The impairment (loss) reversal of assets of the Exploration and Production segment for the years ended December 31 of 2019, 2018
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
In 2018, based on new market variables, incorporation of new reserves, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, available technical and operational information, there was a partial reversal of an impairment recognized in previous years for the oil fields that operate in Colombia Casabe, Provincia, Underriver, Tisquirama and Orito and in fields operated abroad Gunflint and K2, and an impairment mainly in Tibú and Dina Norte fields.
In 2017, based on new market variables, incorporation of new reserves, Ecopetrol’s crude oil basket price discounts as compared to the ICE Brent crude price, available technical and operational information, there was a partial reversal of an impairment recognized in previous years for the oil fields that operate in Colombia CPO09, Casabe and Oripaya and in fields operated abroad Gunflint Dalmatian and K2, and an impairment in the Tibú, Underriver, Provincia and Orito fields, mainly.
The following is the breakdown of oilfields impairment losses or reversals for the years ended December 31, 2019, 2018 and 2017: 2019
2018
2017
The grouping of assets to determine the CGUs is consistent as compared to the prior periods. The assumptions used to determine the recoverable amount include the following: F-62 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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 In 2019, an impairment loss for both. Offshore International Group and
In 2018, the market showed an improvement in the crude oil and gas production forecast. Operational performance and technical evolution have contributed to strengthening future cash flows that, in turn, contributed to the reversal of the impairment charged recognized in previous years for Offshore International Group and Equion Energy.
In 2017, because of new market variables, new reserves, price differentials against reference indicators and available technical and operational information, there was a
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Cash Generating Units with an (expense for)
2019
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) an actual discount rate of
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. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) The reversal of impairment recorded for 2019, is mainly related to macroeconomic assumptions changes which decreased the discount rate used to value the assets; this is explained by the decreasing risk and the Company’s cost of the debt. Together, operational management and financial results allowed the support of operational improvements included in the forecast that compensate in some measure the effects related to the impact that the MARPOL regulation will have on the margins’ forecast of refined products and the crude oil basket price discounts. The results of 2019 were impacted by a higher knowledge of the Refinery capabilities and efficient operational management.
The impairment recorded for 2018 is explained by: i) an adjustment in market expectations in relation to the impact that the implementation of the MARPOL regulation will have on margins of refined products, ii) the differential of light and heavy crudes that serve as raw material; and iii) fundamental macroeconomic changes that increased the discount rate used for the valuation of Reficar's assets, mainly associated with the increase in the risk-free rate and higher market risk premiums. Improvements in operational and commercial inputs associated to the refinery optimization as well as the tax effects of the
In 2017, we recorded a partial reversal of the impairment recorded in previous periods primarily as a result of: (a) an improved outlook in refining margins due to the ratification of the implementation of the International Convention for the Prevention of Pollution from Ships (Marpol) starting in 2020; (b) a lower discount rate resulting from the application of WACC methodology; and (c) operational and financial optimizations identified as part of the stabilization of the refinery.
The recoverable amount of Bioenergy was calculated based on the fair value less the costs of disposal level, which is greater than the value in use and corresponds to the future cash flows discounted after taxes on profit. The fair value hierarchy is 3.
The significant assumptions used to determine the recoverable amount included: (a) forecast of ethanol prices based on projections made by Group
In 2019, we recorded an impairment loss of COP$234,340, due to changes in the operative variables, changes in the projection of the operational cash flows and the need for higher resources, mainly by the results of the renovation of older reeds. In 2018, impairment is presented due to: i) a lower prospect of short-term ethanol prices, associated with imports from abroad in an environment of global over-supply of ethanol, ii) the updating of agricultural variables in the short term, iii) an increase in the discount rate used for the valuation in line with fundamentals of the market. These impacts were partially offset by the updating of operating variables associated with the stabilization and tax effects of the
In 2017,
During 2019, a loss of COP$225,094 was recorded, primarily related to engineered works for the integral development of the Refinería de Barrancabermeja Modernization Project, mainly due to the advance in the technical analysis of options to the eventual improvement of the conversion of the Refinery. Once the project is reactive, Ecopetrol will evaluate whether it could revers any impairment loss recorded in the previous years.
During 2018, the Refinería de Barrancabermeja Modernization Project, which is currently suspended, was evaluated and there were no indications that implied the recognition of additional impairment.
During 2017, an impairment loss of COP$273,987 was recognized on the Refinería de Barrancabermeja, mainly related to the write off of certain management and financial capitalized balances associated with the suspension of the modernization project of the Refinery. This suspension is in response to capital discipline criteria implemented to ensure the growth and financial sustainability of Ecopetrol S.A. and the Ecopetrol Business Group in the adverse context that the hydrocarbons sector experienced in previous years. This project is being assessed within the Ecopetrol Business Group’s strategic plan therefore any impairment loss recognized in previous years may be subject to Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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 2018, the main impairment recorded was COP$167,917, corresponding to the systems of the Southern Cash Generating Unit (CGU), composed of the Tumaco Port and the TransAndino Pipeline (OTA) and its afferent pipelines, the Mansoyá - Orito Pipeline (OMO), San Miguel - Orito (OSO), and Churuyaco- Orito (OCHO). This value was generated mainly by a decrease in the volume projections for the southern systems, and an increase in the need for maintenance capex to reduce the operational risk of the transport systems.
In 2017, there was a
As of December 31,
F-66 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Exhibit 2 details the main conditions of the most significant loans of the Business Group.
The balances of the loans and financing, which are recorded at amortized cost, as of December 31,
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following are the maturities of loans and borrowing as of December 31, 2018:
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
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The fair value of loans and borrowings is COP$
For fair value measurement, local currency bonds were valued using
The following is the movement of net financial debt as of December 31, 2019, 2018
F-69
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The carrying amount of trade accounts and other accounts payable approximates their fair value due to their short–term nature.
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,
The following table shows the movement in profit and loss and in other comprehensive income as of December 31, 2019, 2018
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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 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
See credit risk policy in Note 29.2. Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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,
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:
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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,
In October 2017, the Ecopetrol’s Board of Directors approved a new employee retirement plan that included four categories of retirements from January 2020 until December 2023: compliance of the work cycle (pension), Retirement Plan A (rent), Retirement Plan B (Bonus) and improved compensation. As for December 31, 2019, the Ecopetrol Business Group has not recognize a provision related to this plan, since it will be understood as an obligation at the time the Company offers the plan and each employee voluntarily accepts their retirement by taking advantage of any of the mentioned categories.
In August 2016, the Ecopetrol Business Group offered a voluntary retirement plan to 200 employees who met certain criteria. As of December 31,
F-75 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,
The following is a summary of the main legal proceedings recognized in the consolidated statement of financial position, where the expectation of loss is probable and could imply an outflow of resources as of December 31, Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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.
As of December 31, 2018, the provision for the 1% mandatory investment for the use of water was estimated based on the parameters established in Decree 1076 of 2015. The Ecopetrol Business Group is in the process of analyzing the impact of the applicability of the changes set out in the aforementioned decrees.
As of December 31, 2019, the Ecopetrol Business Group achieved a new certification of a settlement base and the acceptance of the percentage of the investment values’ update of 1% in compliance with article 321 of Law 1955 of 2019 generating a lower provision of this obligation.
Oleoducto Bicentenario de Colombia S.A.S.
During July 2018, the carriers Frontera Energy Colombia Corp. (“Frontera”), Canacol Energy Colombia S.A.S. (“Canacol”) and Vetra Exploración y Producción Colombia S.A.S. (“Vetra” and, together with Frontera and Canacol, the “Carriers”) sent letters to Oleoducto Bicentenario de Colombia S.A.S. (“Bicentenario”) alleging In accordance with the foregoing, the carriers have ceased to fulfill their obligations under said Transport Agreements. Bicentenario has rejected the terms of the letters, noting that there
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 F-77
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Having exhausted the direct settlement stages with each carrier, Bicentenario withdrew the initially filed claims and filed arbitration claims against each of them as follows: (i) on November 12, 2019, Bicentenario filed a claim against Frontera under cover of the arbitration agreement contained in the Transport Agreement; (ii) on December 10, 2019, Bicentenario filed a claim against Vetra under the arbitration agreement contained in the Transport Agreement; and (iii) on December 26, 2019, Bicentenario filed a claim against Canacol under the arbitration agreement contained in the Transport Agreement. On December 3, 2019, Bicentenario also filed an arbitration claim against Frontera, Pacific OBC, Corp., Pacific OBC 1, Corp., Pacific OBC 4, Corp., Canacol and Vetra under the Acuerdo Marco de Inversión before the Center for Arbitration and Conciliation of the Bogotá Chamber of Commerce. The four arbitration proceedings are ongoing. Simultaneously, Bicentenario will continue to exercise its rights under the terms of the Transportation Agreements and its related agreements, to guarantee compliance and claim any compensation, indemnity or restitution arising from the alleged early termination of said agreements, together with other breaches. Cenit Transporte y Logística de Hidrocarburos S.A.S. Ship or pay transport agreements: The clauses in the agreements signed with Frontera Energy Group with respect to the Caño Limón Coveñas Pipeline, and in particular clause 13.3 establish that, in the event of the suspension of services for reasons not attributable to any of the parties, for a period over 180 continuous calendar days, either party may request the early termination of the agreement. Based on this, on July 12, 2018, CENIT received a communication from Frontera Energy Group, whereby the latter expressed its decision to exercise the provision set forth in clause 13.3 for each of the Transport Agreements signed with respect to the Caño Limón - Coveñas Pipeline, requesting their early termination. In relation to the foregoing, CENIT issued communication CEN-PRE-3451-2018-E dated July 17, 2018 whereby it stated that the grounds to exercise clause 13.3 of the agreements in question have not occurred; therefore, Frontera Energy Group cannot exercise its contractual right to early termination. Included in that same communication, CENIT stated its intention to continue billing and charging the transportation services established in the aforementioned agreements, considering that they are still valid, therefore Frontera must comply with the obligations assumed therein. In 2019, CENIT evaluated the revenue recognition principle in accordance with the criteria contained in IFRS 15, determining that it is not possible to recognize the income associated with this agreement in the amount of COP$163,852, notwithstanding the aforementioned, the contractual rights and obligations remain and therefore the controversy with the Frontera Energy Group continues. As of December 31, 2019, the amounts owed by the Frontera Energy Group in relation to the case described above amount to COP$334,582. F-78 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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,
The following is a breakdown of the Ecopetrol Business Group’s principal contingent assets, where the associated contingent gain is likely, but not certain:
F-79
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Refinería de Cartagena
On May 25, 2016, CB&I filed its Answer to the Request for Arbitration and Counterclaim for approximately 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 January 2020, McDermott International Inc., CB&I’s parent company, filed for bankruptcy and announced that it would initiate a reorganization plan pursuant to Chapter 11 of the United States Bankruptcy Law. In response to this situation, Reficar has implemented actions to protect its interests and is advised by a group of experts with whom it will continue to analyze other available measures under these new circumstances.
The On January 21, 2020, Comet II B.V., the successor in interest to Chicago Bridge & Iron Company N.V., commenced a bankruptcy case under title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. Upon the bankruptcy filing, an automatic stay of the commencement or continuation of any action or proceeding, or the enforcement of any judgment or award, against Comet II B.V. became effective, staying the arbitration against Comet II B.V. On January 23, 2020, Comet II B.V. obtained an order from the Bankruptcy Court permitting it to, in its discretion, modify the automatic stay to permit it to proceed with litigation or other contested matters. On March 14, 2020, the Bankruptcy Court entered an order confirming a plan of reorganization, and the order provides for the stay against the arbitration to end upon the earlier of the effective date of the plan and August 30, 2020. In respect of the arbitration involving Reficar, the confirmation order provides that the proper forum for adjudication of the merits of the arbitration is the International Chamber of Commerce tribunal, the arbitration claims will not be subject to estimation in the Bankruptcy Court, and the stay will not be violated if the parties discuss logistical items with the International Chamber of Commerce tribunal or each other. The order reserves all rights and arguments of the parties related to the arbitration schedule, hearing location, and arbitration logistics and also recognizes that, without waiving any arguments, including but not limited to the Debtors’ objections to alternative hearing locations and long gap(s) between hearing dates, lifting the stay on August 30, 2020 provides sufficient time to commence hearings on or after December 7, 2020.
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. F-80 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
As a result, Ecopetrol and Reficar employees are generally subject to the control and supervision of the following control entities, among others: The 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:
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 current employee of Ecopetrol, and former employees of Reficar, as well as against (ii) Chicago Bridge & Iron Company N.V., CBI - Chicago Bridge & Iron company (CB&I) Americas Ltd., Chicago Bridge & Iron Company CB&I UK Limited, CBI Colombiana S.A., Foster Wheeler USA Corporation and Process Consultants Inc, and the following insurance companies, Compañía Aseguradora de Fianzas S.A, Coaseguro Confianza S.A., Liberty Seguros S.A., CHUBB de Colombia Compañía de Seguros S.A., Seguros Colpatria S.A. and Mapfre Seguros Generales de Colombia S.A., as third parties with joint liability. As for the other 21 individuals initially investigated in 2017, the Office of the Comptroller General closed the investigations. Therefore, as of the date of As of the date of F-81 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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
On February 2, 2018, the Legal Accounts Commission of the National House of Representatives of the Republic of Colombia informed Reficar that the House of Representatives decided, through Resolution No. 2713 on December 3, 2017, that it would not close the General Budget and Treasury Account and the National Balance Sheet for the 2016 fiscal year, since the 2016 Financial Statements of several state entities, among them Reficar, had received a negative opinion from the Office of the Comptroller General. Pursuant to Resolution No. 2713, Colombian control entities were ordered to initiate the corresponding disciplinary, fiscal and/or criminal investigations.
On February 6, 2019, the Legal Accounts Commission of the National House of Representatives of the Republic of Colombia informed Reficar that the House of Representatives decided, through Resolution No. 3135 on December 18, 2018, that it would not close the General Budget and Treasury Account and the National Balance Sheet for the 2017 fiscal year, since the 2017 Financial Statements of several state entities, among them Reficar, had received a negative opinion from the Office of the Comptroller General. Pursuant to Resolution No. 3135, Colombian control entities were ordered to initiate the corresponding disciplinary, fiscal and/or criminal investigations.
investigations. In respect of the special audits mentioned in sections 1.3, 1.4, 1.5 and 1.6 above, as of the date of the consolidated financial statements, Reficar has no knowledge of any procedural actions carried out by any of the Colombian control entities regarding the disciplinary, fiscal and/or criminal investigations ordered by Resolution No. 2713, Resolution No. 3135 or Resolution No. 2898. Reficar’s external auditors issued an unqualified opinion on Reficar’s financial position as of December 31, 2016, 2017, 2018 and As of the date of F-82
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) As of the date of the consolidated financial statements, the current Boards of Directors of Ecopetrol and Reficar are not part of the Comptroller General proceedings.
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. The specific content and status of the remaining
Directors of Ecopetrol and Reficar are not part of the Attorney General’s Office proceedings.
The Prosecutor’s Office has been conducting the following legal proceedings:
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 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.
F-83
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) 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.
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 the consolidated financial statements, the current Boards of Directors of Ecopetrol and Reficar and their employees are not part of the Prosecutor’s Office proceedings. None of the legal proceedings described in this paragraph are related with bribery charges. As of the date of the consolidated financial statements, Ecopetrol and Reficar have no knowledge of any legal proceeding in the United States regarding the project.
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, 2019 and 2018:
The movement of equity reserves is the following for the years ended December 31, 2019 and 2018:
F-84 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The Ecopetrol Business Group distributes dividends based on its separate annual financial statements, prepared under International Financial Reporting Standards accepted in Colombia (NCIF, by its acronym in Spanish).
The Ordinary General Shareholders’ Meeting, held on March 29, 2019, approved the profit distribution for 2018 and set the distribution of dividends at COP$9,251,256. In addition, the Extraordinary General Shareholders’ Meeting, held on December 16, 2019 approved the change of the occasional reserve destination authorized on March 29, 2019; therefore, the Ecopetrol Business Group distributed as an extraordinary dividend COP$3,659,386. A total of 100% of dividends was paid during 2019.
The Ordinary General Shareholders’ Meeting, held on March 23, 2018, approved the profit distribution for 2017 and set the distribution of dividends at COP$3,659,386. Dividends paid in 2018 attributable to the shareholders of Ecopetrol S.A. amounted to COP$3,659,373 (2017 - COP$945,661) and those of the non-controlling interest to COP$768,328 (2017 – COP$558,986).
The following is the composition of the other comprehensive income attributable to the shareholders of the parent, Ecopetrol S.A., net of tax:
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Sales by geographic areas
F-86 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Concentration of customers
During
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
F-88
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 risk, which arises from various foreign currency exposures due to commercial transactions,
The U.S. dollar/Colombian peso exchange rate has fluctuated over the last few years. As of December 31,
When the Colombian peso appreciates in relation to the U.S. dollar, export sales revenue decreases when converted to Colombian pesos; by contrast, imported goods, operating costs and interest on foreign debt denominated in U.S. dollars become less expensive. Conversely, when the Colombian peso depreciates, export revenues
The following table sets out the carrying amount for financial assets and liabilities with exchange exposure denominated as of December 31,
F-89 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Of the total net liability position,
The Ecopetrol Business Group’s risk management strategy involves the use of non-derivative financial instruments related to cash flow hedges for future exports and hedges of a net investment in a foreign operation in order to minimize exposure to currency rate risk, which is detailed below.
The following is the effect of a change of 1% and 5% in the exchange rate of the Colombian peso as compared with the U.S. dollar, on the balance of financial assets and liabilities denominated in foreign currency as of December 31,
The sensitivity analysis only includes financial assets and liabilities in foreign currency at the closing date.
Ecopetrol is exposed to foreign exchange risk given that a significant percentage of its income from crude oil exports is denominated in U.S. dollars. In recent years, the Ecopetrol Business Group has acquired long–term debt for investment activities in the same currency in which it expects to receive the cash
The following is the movement of foreign currency debt designated as a non–derivative hedging instrument for the years ended December 31,
F-90 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 accumulated foreign currency gains and losses in respect of the cash flow hedge recognized in other comprehensive income for the years ended December 31, 2019, 2018
The expected reclassification of the cumulative exchange
The Board of Directors approved the application of net investment hedge accounting from June 8, 2016. The measure is intended to reduce the volatility of non–operating income due to exchange rate variations. The net investment hedge will be applied on a portion of the Ecopetrol Business Group’s investments in foreign operations, in this case on investments in subsidiaries which have the U.S. dollar as their functional currency, using a portion of the Ecopetrol Business Group’s U.S. dollar denominated debt as the hedging instrument.
Ecopetrol S.A. has designated its net investments in Ocensa, Ecopetrol America Inc., Hocol Petroleum Ltd. (HPL) and Reficar as the hedged In November 2019, a
The following is the movement of accumulated foreign currency gains and losses in respect of the net investment hedge recognized in other comprehensive income for the years ended December 31, 2019, 2018
F-91 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 The forward hedging instruments are used to enable setting sales prices in U.S. dollars, mitigating the foreign exchange variation given Ocensa’s obligations
As of December 31, The variation and/or compensation of full hedging operations for the payment of taxes is recorded in the statement of comprehensive income, affecting the income tax expense on the initial measurement and the exchange result for subsequent measurements. The variation of the hedging operations related to costs and expenses are recorded as other comprehensive income, in case they are effective; once the result of the compensation is settled, it is recorded as less and/or greater value of the hedged expense amount.
The impact on
Ecopetrol’s business is significantly impacted by international prices for crude oil and refined products. The prices for these products are volatile, and drastic changes could adversely affect the Ecopetrol Business Group business prospects and results of operations.
A large proportion of Ecopetrol’s sales revenues come from sales of crude oil, natural gas and refined products. These products are indexed to international reference prices such as the Brent index. Consequently, fluctuations in those international indexes have a direct effect on the financial
Prices of crude oil, natural gas and refined products have historically fluctuated as a result of a variety of factors including, among others, competition within the oil and natural gas industry; changes in international prices of natural gas and refined products; long-term changes in the demand for crude oil, natural gas and refined products; regulatory changes; changes in the cost of capital; adverse economic conditions; transactions in derivative financial instruments related to oil and gas and development or availability of alternative fuels.
The Ecopetrol Business Group has a policy approved by the Board of Directors that allows it to use derivative financial instruments in the organized
Ecopetrol does not regularly use derivative instruments to hedge risk exposures related to sales or
F-92 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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.
In the selling process of crude oil, gas, refined products and petrochemicals, and transport services, the Ecopetrol Business Group may be exposed to credit risk in the event that customers fail to fulfill their payment obligations. The Ecopetrol Business Group’s risk management strategy has designed mechanisms and procedures that aim to minimize such events, thus safeguarding the Ecopetrol Business Group’s cash flow.
The Ecopetrol Business Group performs a continuous analysis of the financial strength of its counterparties, by classifying them according to their risk level and financial guarantees in the event of a default of payments. Similarly, the Ecopetrol Business Group continuously monitors national and international market conditions for early alerts of major changes that may have an impact on the timely payment of obligations from customers of the Ecopetrol Business Group.
Ecopetrol does not have a significant concentration of credit risk. An aging analysis of the accounts receivable portfolio in arrears, but not impaired, as of December 31,
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
F-93 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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,
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
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 markets to obtain resources for the investment plan execution for the Business Group may be limited due to adverse changes in market conditions. A global financial crisis could worsen risk perception in emerging markets. Events that could affect the political and regional environment of Colombia may make it difficult for our subsidiaries to access the capital markets. These conditions, together with potential significant losses in the financial services sector and changes in credit risk assessments, may make it difficult to obtain resources on favorable terms. As a result, the Ecopetrol Business Group may be forced to review the conditions of the investment plan (as necessary), or access financial markets under unfavorable terms, thereby negatively affecting the Ecopetrol Business Group’s results of operations and financial results. Liquidity risk is managed in accordance with the Ecopetrol Business Group’s policies aimed at ensuring that enough cash flows to comply with the Ecopetrol Business Group’s financial commitments within the established dates and with no additional costs. The main method for the measurement and monitoring of liquidity is cash flow forecasting. The following is a summary of the maturity of financial liabilities as of December 31, 2019. The amounts disclosed in the table are the contractual undiscounted cash flows. The payments in foreign currency were restated taking a constant exchange rate of COP$3,277.14 per U.S. dollar:
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
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
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,
Loans with related parties:
The amounts outstanding are not guaranteed and will be settled in cash. No expense has been recognized in the current period or in previous periods with respect to uncollectible or doubtful accounts related to the amounts owed by related parties. The main transactions with related parties for years ended December 31, 2019, 2018 and 2017 are detailed as follows: F-96 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
In accordance with the approval given by the shareholders’ meeting in 2012, compensation paid to directors for attending the meetings of the Board of Directors and/or committees increased from four to six minimum legal monthly salaries in force, or approximately to COP$4,969,000 for 2019, from COP$4,687,000 for 2018
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
The Colombian Government controls Ecopetrol with a stock ownership of 88.49%. The most significant transactions with governmental entities are comprised as follows:
F-97 Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
By nature of the business, the Ecopetrol Business Group has a direct relationship with ANH, an entity which operates under the rules of the Ministry of Mines and Energy, whose objective is to manage the oil and gas reserves and resources owned by the Colombian Nation.
Ecopetrol purchases the crude oil that the ANH receives from producers in Colombia at the prices set in accordance with a jointly established formula, which reflects the export sale prices (crude oils and products), adjusted for API gravity quality, sulfur content, transportation rates from the wellhead to the ports of Coveñas and Tumaco, refining process cost and a commercialization rate. This contract was extended to
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
This price called Producer Income does not necessarily reflect the opportunity cost of fuels. For that reason, it is necessary to recognize that price difference to the refiner/importer. In this sense, the National This scheme ensures that the
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
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
During 2019 and 2018, the following significant events occurred in respect of joint operations contracts:
In July 2019, Ecopetrol S.A. and Occidental Petroleum Corp. (OXY) entered into a Joint Operation contract in order to execute a joint plan for the development of unconventional drilling in the Permian Basin in the US state of Texas. OXY holds a 51% interest in the joint operation, while Ecopetrol holds the remaining 49%. This interest was acquired by means of a 50% advance payment at the close of the transaction on November 13, 2019 with the remaining 50% as a deferred investment to be paid over time in the activities included in the development plan. The total payment by Ecopetrol will amount to USD$1,500 million. To enable the operation, two companies were established: Ecopetrol USA Inc. and Ecopetrol Permian LLC.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
On October 21, 2019, Ecopetrol S.A. announced that it had signed an agreement for USD$105 million with Shell Brasil Petróleo Ltda through its subsidiary Ecopetrol Óleo e Gás do Brasil Ltda., to acquire 30% of the interests, rights and obligations in two areas corresponding to the BM-S-54 Concession Agreement and theSul de Gato do Matoshared production agreement, located offshore in Brazil’s pre-salt Santos basin, where a hydrocarbons deposit known as “Gato do Mato” was discovered. Shell will reduce its stake from 80% to 50% with this agreement and will continue as an operator, while the French company Total will retain the remaining 20%.
In December 2018, the On July 17, 2019, the Ministry of Mines and Energy of Brazil authorized the transfer of 10% of the Saturn block for USD$85 million, located in the Santos basin, to Ecopetrol Óleo e Gás do Brasil, a percentage of which Shell Brasil Petróleo Ltda and Chevron Brasil Óleo e Gas Ltda. were equal holders. In the new shareholding structure, Ecopetrol retains 10% of the interests of the block, while Shell (the operator) and Chevron each retain 45% of the total.
On November 22, 2019, Hocol signed an agreement with Chevron Petroleum Company to acquire its share in the Chuchupa and Ballena fields located in the department of La Guajira. These fields are operated by Chevron through the Guajira Association Agreement (57% Ecopetrol and 43% Chevron). Under the terms of the agreement, Hocol will acquire Chevron’s share (43%), and will assume the position of operator. This
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.
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Below are the consolidated statements of profit or loss by segment for the years ended December 31, 2019, 2018 and 2017:
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)
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, 2019, 2018 and 2017:
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)
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, 2019, 2018 and 2017:
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
This decision is a result of: 1) the accumulated accounting losses of the companies, 2) the increase in the level of indebtedness compared to the initial planned capital structure, and 3) the fact that the plant failed in working at its maximum capacity due to the low productivity of the cane generated by its own crops and by third parties.
Following the commercial agreement, Shell will assume the operation of the blocks, and drilling activities of a delimiter well will be executed at the end of 2021. The
In addition, during the last few weeks, global and regional economic and political developments in the Organization of the Petroleum Exporting Countries (OPEC) and the willingness and ability of the OPEC and its members to set production levels have impacted the international reference prices. Extended periods of low prices for crude oil, refined products can have a material adverse impact on the
The fluctuations presented in the reference prices added to the COVID-19 outbreaks are leading to a decrease in economic activity, including oil, gas and refined products demand, and therefore these could affect negatively the Group's results of operations and financials. The effects and duration of this situation will depend on future developments, which are highly uncertain and cannot be predicted at this time.
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 2019, 2018
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$2,260,113, COP$1,076,116 and COP$598,125 during 2019, 2018 and
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, 2019, 2018
During 2019, 2018
The intercompany transfers were realized at market prices.
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,
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
The following information relates to the net proven reserves owned by the Ecopetrol Business Group in 2019, 2018 and 2017, and corresponds to the official reserves statements prepared by the Ecopetrol Business Group:
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.
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)
Consolidated subsidiary companies (1/2)
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated)
Consolidated subsidiaries (2/2)
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Associated companies and joint ventures
Ecopetrol S.A. Notes to the consolidated financial statements (Figures expressed in millions of Colombian pesos, unless otherwise stated) Exhibit 2 – Conditions of the most significant loans
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: March 31, 2020
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