ENGIE ENERGIA CHILE S.A. October 28, 2020
ENGIE ENERGÍA CHILE REPORTED EBITDA OF US$338 MILLION AND NET INCOME OF US$123 MILLION IN THE FIRST NINE MONTHS OF 2020.
EBITDA AMOUNTED TO US$136 MILLION IN THE THIRD QUARTER OF 2020, A 6% DECREASE COMPARED TO THE THIRD QUARTER OF 2019, MAINLY DUE TO LOWER VOLUME SALES TO UNREGULATED CLIENTS.
- Operating revenues amounted to US$996 million in the first nine months of 2020, an 11% decrease compared to the same period of 2019, mainly due to lower average realized energy prices and a decrease in other operating income, in turn explained by liquidated damages received in 2019 from the main contractor of the IEM project.
- EBITDA amounted to US$338 million in the first nine months of 2020, a 21% decrease compared to the first nine months of 2019, mainly due to the decrease in other operating income and lower average realized energy prices. EBITDA would have decreased by 4.7% in the first nine months of 2020 after isolating the effect of liquidated damages received in 2019.
- Net income amounted to US$123.3 million in the first nine months of 2020, a 14% decrease as compared to the net income figure reported in the first nine months of 2019. Both periods were affected by non- recurring losses: in 2019, the impairment of the coal-fired units U14 and U15 and, in 2020, the make-whole premium paid to bondholders for the early redemption of the US$400 million 144A/RegS bond originally maturing in January 2021. This bond was prepaid in full with the proceeds of a new US$500 million 144A/RegS issue maturing in January 2030.
Financial Highlights (in US$ millions) | ||||||
3Q19 | 3Q20 | Var % | 9M19 | 9M20 | Var% | |
Total operating revenues | 353.2 | 338.7 | -4% | 1,119.5 | 996.0 | -11% |
Operating income | 103.2 | 86.8 | -16% | 313.6 | 203.4 | -35% |
EBITDA | 144.4 | 135.8 | -6% | 429.2 | 337.8 | -21% |
EBITDA margin | 40.9% | 40.1% | 0,1pp% | 38.3% | 33.9% | +7.3 pp |
Total non-operating results | (12.0) | (11.7) | n.a | (109.6) | (47.6) | -57% |
Net income after tax | 63.6 | 57.0 | -10% | 150.3 | 123.3 | -18% |
Net income attributed to controlling shareholders | 62.4 | 57.0 | -9% | 143.0 | 123.3 | -14% |
Net income attributed to minority shareholders | 1.2 | (0.0) | -100% | 7.3 | (0.0) | -100% |
Earnings per share (US$/share) | 0.059 | 0.054 | 0.136 | 0.117 | ||
Total energy sales (GWh) | 2,873 | 2,783 | -3% | 8,276 | 8,528 | 3% |
Total net generation (GWh) | 1,549 | 1,657 | 7% | 3,843 | 5,305 | 38% |
Energy purchases on the spot market (GWh) | 1,128 | 1,220 | 8% | 4,164 | 3,105 | -25% |
Energy purchases - back up (GWh) | 127 | 127 | 0% | 373 | 377 | 1% |
ENGIE ENERGÍA CHILE S.A. ("ECL") is engaged in the generation, transmission and supply of electricity and the transportation of natural gas in Chile. ECL is the fourth largest electricity generation company in Chile and one of the largest electricity generation companies in the northern segment of the SEN national grid (formerly known as SING). As of September 30, 2020, ECL accounted for 9% of the SEN's installed capacity. ECL primarily supplies electricity to large mining and industrial customers, and it also supplies electricity distribution companies throughout Chile. ECL is currently 52.76% indirectly owned by ENGIE (formerly known as GDF SUEZ). The remaining 47.24% of ECL's shares are publicly traded on the Santiago stock exchange. For more information, please refer to www.engie-energia.cl.
HIGHLIGHTS:
- COVID-19: The Corona virus, or COVID-19, was first detected in Chile on March 3, 2020, and as of October 27, 2020, 505,525 cases have been confirmed and 14,026 deaths have been reported. The current situation has been cataloged as Phase 4, and the country remains under constitutional state of catastrophe. The COVID-19 pandemic is deemed to be the worst sanitary and economic crisis in recent times. Economists estimate that the Chilean economy will contract between 6% and 7% in 2020 as a result of the pandemic. Electricity demand has decreased overall by approximately 8.9% since the third week of March. While the demand from our unregulated clients has so far remained stable, electricity demand from our regulated clients increased in the first two months of the year, but reported a 5% decrease in the second quarter as compared to the second quarter of last year, and has begun showing signs of recovery in the third quarter. The COVID-19 pandemic has posed several challenges forcing us to adapt ourselves and to respond quickly along three lines of action: first, ensuring the safety and wellbeing of our teams; third, ensuring our company's operational continuity, which is essential in providing continued electricity supply in our country; and, finally, coordinating ourselves as best as possible with our stakeholders including our customers, suppliers, shareholders and communities to keep an open, direct and collaborative dialogue. Since the beginning of this crisis we established a crisis committee and have implemented contingency plans, adopting sanitary measures in our sites as necessary to comply with the authority's instructions. Similarly, we have monitored the situation and actions taken by our suppliers and contractors, asking them to comply with safety standards with their own staff. At present, approximately 70% of our staff is working from home, while approximately 300 direct employees and 400 contractors are working in shifts in ten different sites to ensure the continuity of our operations. Our operations are functioning normally. The government has implemented the "Plan Paso a Paso", a step-by-step plan that considers five scenarios from a full lockdown to an advanced opening, each with specific restrictions and obligations. The advance or retrocession from one to another scenario is subject to epidemiologic indicators, sanitary network availability and traceability.
SUBSEQUENT EVENTS:
- Provisional dividend: On October 27, 2020, the Board of Directors approved the distribution of a provisional dividend in the amount of US$66.6 million (US$0.0632310 per share) on account of 2020 net income. The dividend will be paid on November 30, 2020, in pesos at the dollar-equivalent rate published in the Official Gazette on November 23.
- Chile rating downgrade by Fitch: On October 15, Fitch Ratings downgraded Chile's Long-Term Foreign- Currency Issuer Default Rating (IDR) to 'A-' and revised its Outlook to Stable. The Stable Outlook reflects Fitch's view that Chile's lower trend growth prospects, eroding fiscal balance sheet and political/social risks are captured in the lower rating, which is supported by a credible macroeconomic policy framework and still-low government debt burden compared with 'A' range peers.
RECENT EVENTS:
3Q20
- Public auction to supply regulated clients: The National Energy Commission (CNE) postponed the 2,200 GWh power supply auction for regulated clients originally scheduled for November 2020 due to slower projected demand growth. The auction, which seeks to obtain the lowest possible power prices for regulated clients, has been deferred to the first half of 2021.
- Transmission segment annual assessment report: The final report on the status of the National Transmission System was submitted for approval by the committee in charge, which will validate it before the CNE publicly divulges its results.
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- Zonal transmission valuation report: The first version of the final report will be submitted to the supervisory committee on October 30 for review. In a following stage, the CNE will call for a public audience to communicate the results.
- Environmental impact assessment for the Vientos del Loa wind project: On August 18, the Company submitted to the Environmental Impact Evaluation Service an environmental impact declaration (DIA) to expand the capacity of the Vientos del Loa wind project from an initially submitted 126.5 MW to a new total installed capacity of 204.6 MW.
- Result of land auction: On July 15, in an auction launched by the Ministry of National Assets, ENGIE Energía Chile (EECL) was awarded one of the available land plots in the Antofagasta Region for the development of renewable energy projects. This land plot is located in Tal-Tal. It covers a 2,347-hectare surface area and will permit the development of up to 320 MW of renewable energy projects.
- Eólica Monte Redondo acquisiton: On July 1, EECL informed the acquisition of Eólica Monte Redondo SpA ("EMR") from ENGIE Latam, through a Material Event notice filed with the Comisión para el Mercado Financiero (the Capital Markets Commission or "CMF"). Through this acquisition, EECL added two renewable assets to its generation fleet, the 48 MW Monte Redondo wind farm and the 34.4MW Laja hydroelectric plant. The Monte Redondo wind farm is located in the Coquimbo region, 43 kilometers away from the city of Ovalle, has 24 wind turbines and began commercial operations in January 2010. The Laja hydroelectric plant is located in the Biobío region, 60 kilometers away from the city of Los Ángeles, and began commercial operations in 2015. It is a run-of-the-river facility including a 14Mm3 reservoir, with a 26-meter high concrete dam, five spillway radial gates and two gantry cranes. EECL paid a price of US$53 million plus approximately US$2 million of available cash at EMR at the time of the acquisition, and the company was acquired on a debt-free basis. The Directors Committee, formed by the independent board members, mandated 350 Renewables and GTD Consultores for a technical and commercial due diligence, respectively, and Scotiabank to perform an independent valuation of the company. The EMR acquisition is consistent with the company's portfolio diversification strategy and its transition to renewable energy and is expected to have a US$3 million positive impact on EECL's consolidated net income in the second half of 2020.
2Q20
- Rating upgrade: On June 12, Fitch Ratings upgraded EECL's international credit rating to BBB+ from BBB. The outlook was changed to Stable. The national-scale rating was upgraded to AA from AA-. This upgrade recognizes EECL's high quality contract portfolio, with an average remaining life of 12 years. Fitch also expects EECL to maintain adequate liquidity levels in the medium term, supported by predictable cash flow generation. The agency also considered EECL's capacity and financial support to migrate to cleaner energy generation sources, consistently with its asset transition strategy.
- New PPA with CAP Aceros: On May 18, 2020, the company was awarded a new, 15-year power supply agreement with the steel company, CAP Aceros S.A., for up to 420 GWh/y beginning 2021.
- PPA renegotiations: On April 1, 2020, in a Material Event notice filed with the CMF, the company informed about new commercial agreements with its client, Minera Centinela, an affiliate of Antofagasta Minerals S.A. (AMSA). In first place, the agreement comprises the amendment of the existing energy supply contracts between our subsidiary, Inversiones Hornitos S.A. and Minera Centinela concerning its Esperanza and El Tesoro mines for an aggregate volume of 186 MW. This amendment considers the application of a price discount during 2020 and 2021 and a change in the contract maturity date to December 31, 2021. In addition, the agreement includes the execution of a new 186 MW power supply contract between EECL and Minera Centinela for the period between January 2022 and December 2033 with prices indexed to CPI. There will be one tariff applicable for the period between 2022 and 2028 and a lower tariff for the period running between 2029 and 2033. This new contract and its price scheme will allow the company to gradually adapt its electricity production to generation with renewable sources and at the same time will extend the average life of its contracts with Minera Centinela by 7.5 years. Finally, the
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agreement considers the amendment of the shareholders' agreement ruling the ownership and corporate governance of Inversiones Hornitos S.A., including (a) an agreement not to distribute any dividends until Inversiones Hornitos' debt with EECL is repaid in full and to use any excess cash to repay this debt; and
- the transfer to EECL by December 2021 of 40% of Inversiones Hornitos's shares, which up to the date of this agreement belonged to Inversiones Punta de Rieles Limitada, an affiliate of Antofagasta Minerals S.A. The objective of this new contract structure is to support our client in its own transformation by gradually replacing conventional power sources with renewable energy. Under the agreement, EECL will control 100% of Inversiones Hornitos S.A. and, as a result, no minority interest has been reported since March 31, 2020.
- Annual Ordinary Shareholders' Meeting: On April 28, 2020, the Company's shareholders agreed the following:
- Definitive Dividends: No final dividends will be paid on account of 2019's net income, and any undistributed earnings will be retained in the company. This decision takes into account that the sum of provisional dividends paid on June 21, 2019 and December 13, 2019, equivalent to US$90 million, accounts for approximately 81% of 2019's net earnings. This largely exceeds the 30% regulatory minimum distribution established by Law and the company's dividend policy.
- Auditors: To appoint EY Servicios Profesionales de Auditoría y Asesorías SpA as the Company's external auditors.
- Local Rating Agencies: To confirm "Feller Rate Clasificadora de Riesgo" and "Fitch Chile Clasificadora de Riesgo Ltda." as the agencies that will rate the company's shares according to the national rating scale.
1Q20
- Price stabilization fund: On March 11, 2020, the National Energy Commission ("CNE") published Exempt Resolution #72 setting the rules for the implementation of the temporary price stabilization mechanism for clients subject to regulated tariffs, as established in Law #21,185 dated November 2, 2019. This price stabilization mechanism froze electricity tariffs at the levels prevailing in the first half of 2019 until year-end 2027, subject to certain adjustments, from time to time, as provided by the law. The mechanism has therefore produced a differential between the tariffs that generation companies are entitled to charge according to the terms of their contracts with distribution companies and the tariffs actually collected from regulated end-consumers. As a result of this price differential, generation companies have begun to build up an account receivable from distribution companies, which taken as a whole, gives birth to the so-called price stabilization fund. According to Law #21,185 this fund may increase until the first to occur between July 2023 or until it reaches a global amount of US$1,350 million. The authority expects that once lower-priced power supply agreements awarded in more recent auctions become effective, the average prices in the contract between generation and distribution companies will begin to decrease gradually starting 2021. At some point, average contract prices will fall below the stabilized price and, distribution companies will begin repaying the accounts with generation companies that form part of the stabilization fund. As of September 30, 2020, EECL, including its subsidiary Eólica Monte Redondo, reported approximately US$130.9 million in accounts receivable related to the price stabilization mechanism.
- Annual expansion plan for the transmission system: The CNE started the process for the annual expansion plan for the transmission system in the national electric system ("SEN"). The first phase of the process consists of the presentation of the companies' proposals, which will be analyzed considering their contribution to the system's safety and economic benefits.
- National valuation process report: The CNE published the first draft of the valuation report for national transmission systems for the four-year period running between 2020 and 2023. This report provides the basis on which the remuneration for national transmission systems is determined.
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- New 144-A/RegS bond: On January 23, 2020, following a series of investor meetings in Santiago, London, Boston, Los Angeles and New York, ENGIE Energía Chile successfully issued 10-year 144- A/Reg S notes in an amount of US$500 million at a 3.484% yield and a 3.4% annual coupon rate. The proceeds of the new issue were used primarily to fully refinance the US$400 million notes due on January 15, 2021 through a tender offer, followed by the redemption of the notes that were not tendered. The Global Coordinators and Joint Bookrunning Managers were BofA Securities, Inc. Citigroup Global Markets Inc. and Scotia Capital (USA) Inc., while MUFG Securities Americas Inc. and Santander Investment Securities Inc. acted as Co-Managers. In addition, the company prepaid US$80 million in short-term debt with Scotiabank and Banco Estado. This bond placement, combined with the prepayment of existing bond and bank debt, allowed the company to extend the average maturity and significantly lower the average coupon rate of its financial debt.
INDUSTRY OVERVIEW
The SING and SIC power grids operated independently until November 24, 2017, when the interconnection of both grids was perfected through EECL's 50%-owned TEN project, giving birth to the SEN ("Sistema Eléctrico Nacional"). Currently, the company's generation assets are predominantly located in the northern segment of the SEN, in the area that used to be covered by the so-called SING Grid ("Sistema Interconectado del Norte Grande"), which serves a major portion of the country's mining industry. Given local conditions, the northern segment of the SEN is predominantly a thermoelectric system, with generation based on coal and LNG, with growing penetration of renewable sources, including wind, solar, and geothermal. Energy flows through the interconnection are variable, and until the full commissioning of the Interchile project, used to be predominantly in the south-north direction comprising inflows of renewable power generated in the area known as Norte Chico into the SING grid.
Following the commissioning of the last tranche of Interchile's Cardones-Polpaico transmission project on May 30, 2019, marginal costs in the different nodes of the SEN have reported greater stability and lower average levels due to the coupling of transmission bars at different substations and the injection into the grid of renewable power generation, which was previously being lost due to insufficient transmission capacity.
In addition to the interconnection, other factors contributed to the reduction and stabilization of marginal costs, including (i) hydraulic sources; (ii) greater volumes of Argentine gas supply; and (iii) greater LNG availability, which has caused some combined-cycle units to operate in an inflexible manner at zero marginal cost.
Marginal Costs
2019 | Minimum | Average | Maximum | |||||||||
Month | A. Jahuel 220 | Charrúa 220 | Crucero 220 | P. Azúcar 220 | A. Jahuel 220 | Charrúa 220 | Crucero 220 | P. Azúcar 220 | A. Jahuel 220 | Charrúa 220 | Crucero 220 | P. Azúcar 220 |
Jan | 15.0 | 14.7 | - | - | 63.1 | 61.5 | 51.5 | 55.1 | 166.6 | 161.3 | 148.0 | 161.4 |
Feb | 41.5 | 40.8 | - | - | 64.0 | 62.6 | 51.2 | 55.8 | 162.1 | 157.2 | 155.0 | 155.6 |
Mar | 45.4 | 44.7 | - | - | 63.5 | 62.1 | 49.2 | 53.0 | 152.2 | 148.9 | 118.1 | 123.5 |
Apr | 45.3 | 44.5 | - | - | 71.6 | 70.1 | 49.3 | 56.4 | 178.0 | 173.3 | 168.8 | 172.1 |
May | 40.7 | 39.6 | 34.6 | - | 68.5 | 66.7 | 51.9 | 55.2 | 198.0 | 192.2 | 148.9 | 145.0 |
Jun | 37.5 | 36.5 | 32.5 | 32.5 | 53.0 | 51.3 | 48.2 | 50.0 | 83.3 | 80.6 | 78.8 | 79.9 |
Jul | 36.1 | 35.4 | 30.3 | 6.5 | 49.6 | 48.1 | 46.3 | 47.7 | 73.1 | 69.9 | 72.1 | 72.6 |
Aug | 37.5 | 36.6 | 29.7 | - | 52.5 | 50.3 | 50.7 | 50.2 | 106.1 | 100.4 | 106.7 | 105.5 |
Sep | 28.0 | 27.3 | 25.9 | 26.8 | 42.9 | 41.3 | 40.8 | 42.0 | 69.1 | 65.4 | 69.9 | 69.2 |
Oct | 23.5 | 23.1 | 21.6 | - | 37.8 | 36.2 | 38.8 | 36.5 | 80.2 | 75.6 | 403.2 | 81.3 |
Nov | 23.3 | 23.1 | 21.7 | - | 35.1 | 34.2 | 34.0 | 32.5 | 70.3 | 67.4 | 140.3 | 69.8 |
Dic | 26.6 | 26.1 | 26.0 | - | 35.0 | 34.2 | 34.0 | 31.7 | 40.0 | 38.5 | 41.2 | 41.5 |
2020 | Minimun | Average | Maximum | |||||||||
Mes | A. Jahuel 220 | Charrúa 220 | Crucero 220 | P. Azúcar 220 | A. Jahuel 220 | Charrúa 220 | Crucero 220 | P. Azúcar 220 | A. Jahuel 220 | Charrúa 220 | Crucero 220 | P. Azúcar 220 |
Jan | 18.9 | 18.5 | 18.8 | - | 41.6 | 40.4 | 41.9 | 39.9 | 151.8 | 147.8 | 149.9 | 148.5 |
Feb | 25.1 | 24.8 | 23.7 | - | 43.1 | 42.1 | 40.1 | 40.4 | 148.7 | 146.6 | 140.3 | 143.4 |
Mar | 28.0 | 27.7 | 26.9 | - | 68.7 | 67.6 | 64.3 | 67.2 | 182.4 | 178.1 | 180.2 | 179.4 |
Abr | 25.3 | 25.0 | 24.3 | 24.4 | 44.8 | 44.2 | 43.4 | 43.4 | 106.3 | 104.6 | 106.2 | 104.9 |
May | 27.5 | 27.1 | - | - | 45.2 | 44.1 | 40.9 | 41.0 | 99.5 | 96.4 | 100.1 | 99.4 |
Jun | 26.7 | 26.2 | 25.6 | 26.0 | 43.7 | 42.8 | 41.6 | 42.2 | 107.6 | 104.9 | 108.2 | 106.2 |
Jul | - | - | - | - | 31.5 | 30.5 | 31.6 | 30.8 | 90.2 | 86.3 | 93.9 | 90.2 |
Aug | - | - | - | - | 31.5 | 30.4 | 30.4 | 28.9 | 126.3 | 121.0 | 133.1 | 126.1 |
Sep | - | - | - | - | 29.3 | 28.2 | 29.2 | 28.4 | 66.1 | 62.9 | 74.1 | 67.3 |
Source: Coordinador Eléctrico Nacional
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In the third quarter of 2020, marginal energy costs remained relatively low and stable. In July, marginal costs were stable due to increased hydraulic generation and the operation of gas plants in inflexible mode. In August marginal costs exhibited occasional peaks due to plant outages and works at the Nueva Cardones - Nueva Maitencillo 500 kV transmission line; however, average costs remained below the average observed in previous quarters. In September, marginal costs remained stable due to increased hydraulic generation and ENEL's increased imports of natural gas from Argentina.
In the second quarter, marginal energy costs at the Crucero node recorded a US$42/MWh average, attributed to lower demand due to the COVID-19 effect and abundant LNG and Argentine gas supply, which translated into the operation of combined-cycle units in an inflexible mode. In April, marginal costs at the Crucero node averaged US$43/MWh, in May, they averaged US$41/MWh, while in June average marginal costs reached US$42/MWh with a declining trend due to the operation of gas units in an inflexible mode in the center-south region, increased rainfall in the third half of the month and lower demand owing to COVID-19.
In the first quarter, particularly in March, marginal costs increased as compared to previous months due to the unavailability of some power plants, plant trips and lower reservoir levels. Therefore, marginal costs at the Crucero node averaged US$64/MWh vs. US$42/MWh in January and US$40/MWh in February. The unavailability of some large, cost-efficient power plants in March led to the dispatch of higher-cost plants to meet the shortfall. Towards the end of the month, marginal energy costs began to return to previous levels and demand started to fall due to the COVID-19 outbreak.
Given the renewable production intermittency, a number of thermoelectric power plants have been required to lower their load. The operating costs reported by plants operating at their technical minimum are remunerated through the over-cost mechanism pursuant to Supreme Decree 130. System over-costs reached US$21.2 million in the third quarter of 2020, an increase from US$6.5 million in the second quarter. EECL's pro-rata was US$6.3 million in the first nine month of 2020, approximately 73% of which was passed through to energy prices.
Fuel prices
International Fuel Prices Index | ||||||||||||
WTI | Brent | Henry Hub | European coal (API 2) | |||||||||
(US$/Barrel) | (US$/Barrel) | (US$/MMBtu) | (US$/Ton) | |||||||||
2019 | 2020 % Variation | 2019 | 2020 % Variation | 2019 | 2020 % Variation | 2019 | 2020 % Variation | |||||
YoY | YoY | YoY | YoY | |||||||||
Jan | 52.3 | 57.0 | 9% | 60.3 | 63.2 | 5% | 3.15 | 2.01 | -36% | 81.8 | 50.4 | -38% |
Feb | 55.0 | 50.5 | -8% | 64.1 | 55.7 | -13% | 2.72 | 1.91 | -30% | 74.4 | 48.3 | -35% |
March | 58.3 | 30.4 | -48% | 66.3 | 33.5 | -49% | 2.94 | 1.80 | -39% | 69.6 | 47.9 | -31% |
April | 63.7 | 15.4 | -76% | 71.3 | 18.1 | -75% | 2.67 | 1.76 | -34% | 58.3 | 45.0 | -23% |
May | 60.6 | 29.0 | -52% | 71.3 | 30.0 | -58% | 2.63 | 1.75 | -34% | 56.5 | 38.6 | -32% |
June | 54.7 | 38.5 | -30% | 64.2 | 41.1 | -36% | 2.40 | 1.63 | -32% | 48.9 | 45.6 | -7% |
July | 57.1 | 40.6 | -29% | 63.8 | 43.3 | -32% | 2.36 | 1.76 | -25% | 58.4 | 49.9 | -14% |
August | 54.8 | 42.2 | -23% | 58.7 | 44.5 | -24% | 2.22 | 2.30 | 4% | 54.2 | 49.0 | -10% |
September | 56.3 | 39.0 | -31% | 62.2 | 40.3 | -35% | 2.52 | 1.90 | -24% | 60.4 | 52.3 | -13% |
October | 54.3 | 59.9 | 2.34 | 59.8 | ||||||||
November | 57.0 | 63.4 | 2.67 | 56.1 | ||||||||
December | 59.7 | 67.1 | 2.22 | 53.6 | ||||||||
Source: Bloomberg, IEA |
Lower international fuel prices can be observed across the board when comparing 2020 with 2019, with variations between 10% and 35% in the third quarter. This is primarily due to oversupply of coal, as evidenced by a global surplus of 28 million tons at year-end 2019. Moreover, in the specific case of API2, the index was further affected by the decarbonization process in Europe, and gas supply surpluses, which have turned gas more competitive than coal and led coal to reach a 5-year low price in May 2020. A subsequent decline in coal supply,
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further aggravated by supply shortages in Colombia given Glencore's production halt and Cerrejón's over 50 -day strike, have explained the recovery in prices through the third quarter. With the exception of August, Henry Hub has steadily remained below 2019's levels.
Generation
The following table provides a breakdown of generation in the northern segment of the SEN (ex - SING) by fuel type:
Total North SEN Generation by Fuel Type (in GWh) | ||||||||||
2019 | ||||||||||
1Q 2019 | 2Q 2019 | 3Q 2019 | 4Q 2019 | 12M 2019 | ||||||
Fuel Type | GWh | % of total | GWh | % of total | GWh | % of total | GWh | % of total | GWh | % of total |
Coal | 2,878 | 66% | 3,148 | 65% | 3,137 | 62% | 3,304 | 69% | 12,466 | 66% |
LNG | 810 | 19% | 1,072 | 22% | 1,272 | 25% | 721 | 15% | 3,876 | 20% |
Diesel / Fuel oil | 4 | 0% | 12 | 0% | 0 | 0% | 1 | 0% | 18 | 0% |
Renewable | 670 | 15% | 591 | 12% | 652 | 13% | 755 | 16% | 2,668 | 14% |
Total gross generation N-SEN | 4,362 | 100% | 4,823 | 100% | 5,061 | 100% | 4,781 | 100% | 19,027 | 100% |
2020 | ||||||||||
1Q 2020 | 2Q 2020 | 3Q 2020 | ||||||||
Fuel Type | GWh | % of total | GWh | % of total | GWh | % of total | ||||
Coal | 3,036 | 61% | 3,139 | 64% | 2,627 | 53% | ||||
LNG | 1,214 | 25% | 1,311 | 27% | 1,052 | 21% | ||||
Diesel / Fuel oil | 11 | 0% | 174 | 4% | 1 | 0% | ||||
Renewable | 679 | 14% | 615 | 12% | 655 | 13% | ||||
Total gross generation N-SEN | 4,940 | 100% | 5,239 | 106% | 4,336 | 88% |
Source: Coordinador Eléctrico Nacional
In the third quarter, gross electricity generation dropped by 14% as compared to the third quarter of 2019 as generation was affected by lower gas availability as well as by maintenance schedules and outages of thermal power plants. The generation mix showed a decrease in thermal generation and an increase in renewables output.
Gross electricity generation in the northern segment of the SEN recovered by 8.6% in the second quarter of 2020, since the second quarter of 2019 had been affected by a 14-day strike at the Chuquicamata mine. The generation mix showed increases in gas generation due to more abundant gas supply.
In the first quarter of 2020, gross power generation in the northern segment of the SEN increased 13% compared to the first quarter of 2019. At that time, power demand decreased due to temporary stoppages at mining operations due to floods caused by the altiplanic winter and environmental upgrade works at smelters to comply with new gas capture norms.
In the first quarter, the generation mix showed an increase in coal generation, mainly due to the operation of the IEM plant, which in the first quarter of 2019 was operating in test mode. Gas-based generation and renewable generation also increased in the first quarter of 2020.
Peak demand in the northern segment of the SEN reached 3,360 MW in the first nine months of 2020, up from a maximum demand of 3,031 MW in the first nine months of 2019.
Electricity production in the northern segment of the SEN (ex-SING), broken down by company, was as
follows:
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Generation by Company (in GWh) | ||||||||||
2019 | ||||||||||
1Q 2019 | 2Q 2019 | 3Q 2019 | 4Q 2019 | 12M2019 | ||||||
GWh | % of total | GWh | % of total | GWh | % of total | GWh | % of total | GWh | % of total | |
Company | ||||||||||
AES Gener | 2,094 | 48% | 2,226 | 46% | 2,454 | 48% | 2,573 | 54% | 9,347 | 49% |
EECL (with 100% of CTH) | 966 | 22% | 1,129 | 23% | 1,216 | 24% | 955 | 20% | 4,266 | 22% |
Enel Generación | 249 | 6% | 264 | 5% | 236 | 5% | 176 | 4% | 925 | 5% |
Other | 1,054 | 24% | 1,204 | 25% | 1,154 | 23% | 1,076 | 23% | 4,488 | 24% |
Total gross generation N-SEN | 4,362 | 100% | 4,823 | 100% | 5,061 | 100% | 4,781 | 100% | 19,027 | 100% |
2020 | ||||||||||
1Q 2020 | 2Q 2020 | 3Q 2020 | ||||||||
GWh | % of total | GWh | % of total | GWh | % of total | |||||
Company | ||||||||||
AES Gener | 2,421 | 49% | 2,360 | 48% | 2,205 | 45% | ||||
EECL (with 100% of CTH) | 1,188 | 24% | 1,363 | 28% | 1,072 | 22% | ||||
Enel Generación | 97 | 2% | 157 | 3% | 66 | 1% | ||||
Other | 1,234 | 25% | 1,358 | 27% | 993 | 20% | ||||
Total gross generation N- SEN | 4,940 | 100% | 5,239 | 106% | 4,336 | 88% |
Source: Coordinador Eléctrico Nacional
During the third quarter of 2020, EECL's generation decreased by 13% as compared to the third quarter of 2019, accounting for 22% of generation in the northern segment of the SEN. Several units were not dispatched, either because of their higher variable cost or because they were unavailable due to maintenance. As discussed above, a systemwide drop in generation was observed in the northern segment of the SEN due to lower demand and greater flows of power from the southern segment of the SEN transported through the interconnection. Tamakaya, owner of the Kelar CCGT reported a decrease in energy production, while other smaller renewable operators increased their generation and together with Tamakaya accounted for 20% of generation in the north SEN during the third quarter.
EECL's generation increased by 21% in the second quarter of 2020, as compared to the same period the year before, accounting for 28% of generation in the northern segment of the SEN. AES Gener maintained its leading position, while non-traditional players, including the Tamakaya (Kelar) CCGT plant, which reported inflexible gas supply in certain periods, and renewable producers, reported a combined 27% share of total generation in the area.
During the first quarter of 2020, EECL reported a 23% increase in electricity generation, as compared to the first quarter of 2019, and it accounted for 24% of total power production in the north SEN. AES Gener continued being the leading contributor with 49%, while other non-traditional players reported a combined 25% share of total generation in the area.
Regarding EECL's maintenance schedule, the U-16 CCGT was out of service for an overhaul since October 15, 2019. It resumed operations on February 8, but had to be taken out of dispatch during part of March. Other cost-efficientcoal-based plants, CTA, CTH, and CTM1/2, reported dispatch limitations or were temporarily unavailable from time to time. IEM was out of service from May 7 to 10, and the U16 CCGT was out for maintenance between June 14 and 20. CTH was out for a planned maintenance between September 9 and 29.
9
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL RESULTS
The following discussion is based on our consolidated financial statements for the 9-month periods ended September 30, 2020, and September 30, 2019. These financial statements have been prepared in U.S. dollars in accordance with IFRS. The information below should be read in conjunction with the financial statements and the notes thereto published by the Comisión para el Mercado Financiero (www.cmfchile.cl).
3Q2020 compared to 2Q2020 and 3Q2019
Operating Revenues
Quarterly Information (In US$ millions) | ||||||||
3Q 2019 | 2Q 2020 | 3Q 2020 | % Variation | |||||
Operating Revenues | Amount | % of total | Amount | % of total | Amount | % of total | QoQ | YoY |
Unregulated customers sales………………….. | 152.7 | 50% | 142.9 | 53% | 142.5 | 50% | 0% | -7% |
Regulated customers sales……………………. | 146.1 | 48% | 127.5 | 47% | 139.5 | 49% | 9% | -5% |
Spot market sales……………………………….. | 6.3 | 2% | 1.5 | 1% | 5.2 | 2% | 255% | -18% |
Total revenues from energy and capacity sales | 305.1 | 86% | 271.9 | 84% | 287.2 | 85% | 6% | -6% |
Gas sales………………………….. | 4.4 | 1% | 7.6 | 2% | 10.9 | 3% | 45% | 148% |
Other operating revenue………………………. | 43.7 | 12% | 42.6 | 13% | 40.6 | 12% | -5% | -7% |
Total operating revenues…………………. | 353.2 | 100% | 322.0 | 100% | 338.7 | 100% | 5% | -4% |
Physical Data (in GWh) | ||||||||
Sales of energy to unregulated customers (1)…… | 1,610 | 56% | 1,662 | 60% | 1,493 | 54% | -10% | -7% |
Sales of energy regulated customers…… | 1,232 | 43% | 1,122 | 40% | 1,283 | 46% | 14% | 4% |
Sales of energy to the spot market……………. | 31 | 1% | 3 | 0% | 6 | 0% | n.a | - |
Total energy sales…………………………. | 2,873 | 100% | 2,788 | 100% | 2,783 | 100% | 0% | -3% |
Average monomic price unregulated | ||||||||
customers(U.S.$/MWh)(2) | 96.8 | 86.7 | 98.5 | 14% | 2% | |||
Average monomic price regulated customers | ||||||||
(U.S.$/MWh)(3) | 118.7 | 113.6 | 108.7 | -4% | -8% |
Energy and capacity sales reached US$287.2 million in the third quarter of 2020, representing a US$17.9 million, or 6% decrease, compared to the third quarter of 2019. This was mainly due to lower average monomic prices, in turn explained by the drop in Henry Hub and coal prices used in the tariff indexation formulas, and the PPA tariff renegotiations. Regarding physical sales, these increased by 4% in the regulated segment as compared to the third quarter of 2019 due to EECL's higher pro-rata of regulated contracts in the south SEN and the addition of EMR's sales. Physical sales to unregulated clients decreased due to the end of the Minera Zaldívar contract (~37 GWh/month) at the end of June, which was partially offset by demand recovery from Chuquicamata, Centinela and Glencore. Volume sales reported a similar behavior as compared to the second quarter: sales to regulated clients recovered by 14% due to the gradual relaxation in COVID-driven lockdowns, while physical sales to unregulated clients were affected by the end of the Zaldívar contract.
Sales to distribution companies reached US$139.5 million in the third quarter of 2020; that is, a 9% increase compared to the second quarter. This was a result of the recovery in physical sales, which offset an almost US$5/MWh average price decrease explained by lower fuel prices.
In the third quarter of 2020, physical energy sales to the spot market reached 6 GWh, higher than those of the second quarter, but lower than those of the third quarter of 2019.
During the third quarter of 2020, gas sales amounted to US$10.9 million, above those reported in the third quarter of 2019 and the second quarter of 2020. The 'Other operating revenue' item regularly includes sub- transmission tolls and regulatory transmission revenues, as well as port and maintenance services. In the third
10
quarter of 2020, this item also included an US$8 million financial income from the acquisition of a 40% equity share in Inversiones Hornitos, which is being paid by EECL through the price discount granted to Minera Centinela, pursuant to the terms of the PPA renegotiation.
Operating Costs
Quarterly Information (In US$ millions) | ||||||||
3Q 2019 | 2Q 2020 | 3Q 2020 | % Variation | |||||
Operating Costs | Amount | % of total | Amount | % of total | Amount | % of total | QoQ | YoY |
Fuel and lubricants……………………………… | (78.4) | 31% | (83.6) | 32% | (59.9) | 24% | -28% | -24% |
Energy and capacity purchases on the spot | (72.1) | 29% | (69.2) | 26% | (71.7) | 28% | 4% | -1% |
market…………………………… | ||||||||
Depreciation and amortization attributable to cost of goods | (40.0) | 16% | (41.7) | 16% | (48.1) | 19% | 15% | 20% |
sold……………………………. | ||||||||
Other costs of goods sold……………………. | (54.8) | 22% | (62.5) | 24% | (64.8) | 26% | 4% | 18% |
Total cost of goods sold……………….. | (245.3) | 98% | (257.0) | 98% | (244.5) | 97% | -5% | 0% |
Selling, general and administrative expenses… | (8.2) | 3% | (8.7) | 3% | (8.3) | 3% | -4% | 1% |
Depreciation and amortization in selling, general and | ||||||||
administrative expenses………… | (1.2) | 0% | (1.5) | 1% | (0.8) | 0% | -47% | -32% |
Other operating revenue/costs………………………. | 4.7 | -2% | 4.9 | -2% | 1.9 | -1% | ||
Total operating costs….………………. | (250.0) | 100% | (262.3) | 100% | (251.8) | 100% | -4% | 1% |
Physical Data (in GWh) | ||||||||
Gross electricity generation | ||||||||
Coal…………………………………………. | 867 | 52% | 1,276 | 63% | 1,046 | 59% | -18% | 21% |
Gas………………………………………….. | 764 | 45% | 705 | 35% | 620 | 35% | -12% | -19% |
Diesel Oil and Fuel Oil……………………. | 8 | 0% | 1 | 0% | 0 | 0% | -73% | -97% |
Hydro/Solar………………………………………. | 41 | 2% | 35 | 2% | 112 | 6% | 217% | 171% |
Total gross generation…………………. | 1,680 | 100% | 2,017 | 100% | 1,779 | 100% | -12% | 6% |
Minus Own consumption……………….. | (131) | -8% | (148) | -7% | (122) | -7% | -17% | -7% |
Total net generation……………………. | 1,549 | 55% | 1,869 | 66% | 1,657 | 55% | -11% | 7% |
Energy purchases on the spot market……….. | 1,128 | 40% | 821 | 29% | 1,220 | 41% | 49% | 8% |
Energy purchases- bridge……….. | 127 | 5% | 125 | 4% | 127 | 4% | n.a | n.a |
Total energy available for sale before transmission | ||||||||
losses……………………… | 2,804 | 100% | 2,815 | 100% | 3,004 | 100% | 7% | 7% |
Gross electricity generation increased 6% in the third quarter of 2020, as compared to the same quarter of 2019, while it declined by 12% when compared to the second quarter of 2020. During the third quarter, some of our coal plants were not dispatched because of their relatively higher variable cost (U14/15+CTM1/2) and we also reported lower gas availability to run our CCGTs. The entire north-SEN system reported a decrease in coal and gas generation for the following main reasons: (i) greater power inflows through the interconnection given the higher hydraulic generation in the center-south segment of the SEN; (ii) lower gas availability in part due to the cancellation of an LNG shipment as a result of the storms in Louisiana; and, (iii) maintenance of coal-fired plants. Our coal generation increased as compared to the third quarter of 2019 mainly due to the IEM plant, which began commercial operations on May 16, 2019. Gas generation decreased as compared to both the second quarter of 2020 and the third quarter of 2019 due to lower gas availability owing to the cancellation of an LNG shipment in September.
In the third quarter, fuel costs decreased as compared to the second quarter due to the decrease in our own generation. Fuel costs decreased by 24% (US$18.5 million) when compared to the third quarter of 2019 mainly due to lower fuel prices across the board.
The spot electricity purchase cost item increased by 4% (US$2.5 million), as compared to the second quarter of 2020, mainly due to larger volumes purchased owing to the decrease in generation. However, spot energy purchases were made at lower average prices. The slight decrease in the spot electricity purchase cost item as compared to the third quarter of 2019 was also explained by an increase in volumes combined with a decrease in prices. This was mainly explained by the higher contribution of hydraulic generation, the dispatch of certain gas plants under inflexible mode and the increased generation from renewables, especially in the center-south zone of
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the SEN. All this translated into lower average marginal costs in the range of US$30/MWh in the third quarter, down from the US$47/MWh average in the third quarter of 2019.
In the third quarter of 2020, our sales to distribution companies in the center-south zone, which normally require higher volumes of energy purchases for geographic reasons, reached 820 GWh, a 1.7% increase compared to the third quarter of 2019. This can be attributed to EECL's increased share of system-wide energy sales to distribution companies starting 2020 due to the end of some power supply contracts from other players, offset by the demand decrease resulting from the COVID-19 pandemic. Power demand from distribution companies began showing signs of recovery through the third quarter. Part of this contract was supplied with energy purchases under contracts with other generation companies (127 GWh). Our energy purchases, either through contracts or through the spot market, are accounted for under the same item labelled 'Energy and capacity purchases on the spot market'.
In the third quarter of 2020, depreciation costs in the costs-of-goods-sold item included IEM's depreciation as well as an asset increase explained by the U16 CCGT overhaul, which includes US$11 million in fixed assets to be depreciated over a three-year period and US$5.7 million over a 7-year period. Therefore, depreciation costs increased as compared to both the second quarter of 2020 and the third quarter of 2019.
Other direct operating costs included, among others, operating and maintenance costs, transmission tolls, insurance premiums and cost of fuels sold. The increase in this item as compared to the third quarter of 2019 is mainly explained by higher transmission tolls, higher maintenance costs and an increase in insurance premiums.
SG&A expenses were lower than those reported in the second quarter and very similar to those reported in the third quarter of 2019.
The Other operating revenue/cost item includes water sales and miscellaneous income as well as recoveries and provisions. It also includes a single regulatory transmission charge called "cargo único". EECL's share in TEN's net income, which amounted to US$1.5 million in the third quarter, is also included in this item.
Electricity Margin
Quarterly Information (In US$ millions) | |||||||||
2019 | 2020 | ||||||||
1Q19 | 2Q19 | 3Q19 | 4Q19 | 12M19 | 1Q20 | 2Q20 | 3Q20 | 9M20 | |
Electricity Margin | |||||||||
Total revenues from energy and capacity sales……… | 315.1 | 324.3 | 305.1 | 297.1 | 1,241.5 | 305.8 | 271.9 | 287.2 | 864.9 |
Fuel and lubricants………………….. | (66.5) | (72.8) | (78.4) | (72.2) | (290.0) | (80.8) | (83.6) | (59.9) | (224.4) |
Energy and capacity purchases on the spot market…… | (122.9) | (102.8) | (72.1) | (95.5) | (393.3) | (93.2) | (69.2) | (71.7) | (234.1) |
Gross Electricity Profit | 125.7 | 148.6 | 154.6 | 129.4 | 558.2 | 131.8 | 119.0 | 155.6 | 406.4 |
Electricity Margin | 40% | 46% | 51% | 44% | 45% | 43% | 44% | 54% | 47% |
In the third quarter, the electricity margin, or the gross profit from the electricity generation business, increased by US$1 million, when compared to the third quarter of 2019, and rose to 54% of energy and capacity revenues. On the one hand, we can observe a US$17 million revenue decrease mainly explained by lower average realized monomic prices. The price decrease was due to both the drop in the main tariff indexes (CPI, Henry Hub and coal prices) and tariff renegotiations, which in the case of the Centinela PPA includes a bigger discount in 2020 by which EECL is paying for the acquisition of a 40% stake in Inversiones Hornitos. On the other hand, fuel costs fell by US$18.5 million as a result of the decrease in our own generation, while energy purchase costs remained flat despite the increase in purchase volumes thanks to the decrease in fuel prices. All in all, the decrease in revenues was offset by an even more significant decrease in average energy supply costs.
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Operating Results
Quarterly Information (in US$ millions) | ||||||||
EBITDA | 3Q 2019 | 2Q 2020 | 3Q 2020 | % Variation | ||||
Amount | % of total | Amount | % of total | Amount | % of total | QoQ | YoY | |
Total operating revenues……………………… | 353.2 | 100% | 322.0 | 100% | 338.7 | 100% | 5% | -4% |
Total cost of goods sold…………………… | (245.3) | -69% | (257.0) | -80% | (244.5) | -72% | -5% | 0% |
Gross income…………………………. | 107.9 | 31% | 65.0 | 20% | 94.1 | 28% | 45% | -13% |
Total selling, general and administrative expenses and | ||||||||
other operating income/(costs). | (4.7) | -1% | (5.3) | -2% | (7.3) | -2% | 38% | 56% |
Operating income….………………. | 103.2 | 29% | 59.7 | 19% | 86.8 | 26% | 45% | -16% |
Depreciation and amortization……...………… | 41.2 | 12% | 43.2 | 13% | 48.9 | 14% | 13% | 19% |
EBITDA…………….….………………. | 144.4 | 40.9% | 103.0 | 32.0% | 135.8 | 40.1% | 32% | -6% |
Third-quarter EBITDA reached US$135.8 million, a 6% decrease compared to the same quarter of 2019 despite the electricity margin improvement. This was largely due to higher maintenance costs and transmission tolls. The comparison with the second quarter of 2020, however, shows a US$32.8 million EBITDA increase largely explained by the electricity margin improvement resulting from lower average energy supply costs.
Financial Results
Quarterly Information (In US$ millions) | ||||||||
3Q 2019 | 2Q 2020 | 3Q 2020 | % Variation | |||||
Non-operating results | Amount | % of total | Amount | % of total | Amount % of total | QoQ | YoY | |
Financial income………..……………………… | 0.6 | 0% | 1.0 | 0% | 0.5 | 0% | -46% | -6% |
Financial expense………….………………… | (13.7) | -4% | (10.6) | -3% | (10.5) | -3% | -2% | -24% |
Foreign exchange translation, net…………… | (3.1) | -1% | (0.9) | 0% | (1.7) | 0% | -46% | |
Other non-operating income/(expense) net… | 4.2 | 1% | - | 0% | (0.1) | 0% | -102% | |
Total non-operating results……………. | (12.0) | -3% | 0.2 | -3% | (11.7) | -3% | ||
Income before tax……………………. ……… | 91.1 | 27% | (10.4) | 15% | 75.2 | 22% | -826% | -18% |
Income tax……………………………………… | (23.1) | -7% | 49.4 | -3% | (18.1) | -5% | -137% | -22% |
Net income from continuing operations after taxes | ||||||||
… | 63.6 | 18% | (8.8) | 12% | 57.0 | 17% | -749% | -10% |
Net income attributed to controlling | ||||||||
shareholders……. | 62.4 | 18% | 40.6 | 12% | 57.0 | 17% | 40% | -9% |
Net income attributed to minority | ||||||||
shareholders………. | 1.2 | 0% | - | 0% | (0.0) | 0% | #DIV/0! | -100% |
Net income to EECL's shareholders | 62.4 | 18% | 40.6 | 12% | 57.0 | 17% | 40% | -9% |
Earnings per share…………………….. | 0.059 | 40.6 | 0% | 0.054 |
In the third quarter, interest expense remained unchanged as compared to the second quarter, but decreased, as compared to the first quarter of 2020, when the company recognized the costs related to the liability management transaction by which EECL prepaid a US$400 million 144A/RegS bond with the proceeds of a new US$500 million issue. In January, 2020, EECL launched an Any and All tender offer on its US$400 million bonds maturing in January 2021, subject to the results of a new 10-year bond issue, which was successfully placed on January 23 in an amount of US$500 million at a 3.4% annual coupon rate. Immediately following the new issue, the company announced a make-whole call to repay the remainder of the 2021 bond. Therefore, in February 2020, EECL completed the full repayment of the US$400 million bond and the payment of premiums in an amount of US$13.6 million, which were fully charged against first quarter results. In the third quarter of 2020, interest expense
13
decreased as compared to the third quarter of 2019 mainly due to the lower average coupon rate achieved after a liability management transaction in the first quarter. Of the interest paid in the third quarter, US$1.28 million was capitalized in renewable energy projects under construction.
Foreign-exchange losses reached US$1.7 million in the third quarter of 2020 due to greater volatility in foreign exchange rates. Foreign exchange variations affect the valuation of certain assets and liabilities denominated in currencies other than the US dollar --the company's functional currency--, such as accounts receivable and payable, advances to suppliers, and value-added tax credit.
In the third quarter of 2020, the 'Other net non-operating income' account decreased compared to the second quarter.
Net Earnings
In the third quarter of 2020, net after-tax profits reached US$57 million, a decrease compared with the same quarter of 2019. However, this result represented an improvement as compared to second quarter results given the improved operating performance in the third quarter.
9M2020 compared to 9M2019
Operating Revenues
For the 9-month period ended September 30 (in US$ millions)
9M19 | 9M20 | Variation | |||||
Operating Revenues | Amount | % of total | Amount | % of total | Amount | % | |
Unregulated customers sales………………….. | 489.3 | 52% | 449.4 | 52% | -39.9 | -8% | |
Regulated customers sales……………………. | 443.6 | 47% | 401.0 | 46% | -42.6 | -10% | |
Spot market sales……………………………….. | 11.5 | 1% | 14.5 | 2% | 3.0 | 26% | |
Total revenues from energy and capacity sales…… | 944.4 | 84% | 864.9 | 87% | -79.6 | -8% | |
Gas sales………………………….. | 12.6 | 1% | 24.4 | 2% | 11.8 | 93% | |
Other operating revenue………………………. | 162.4 | 15% | 106.7 | 11% | -55.7 | -34% | |
Total operating revenues…………………. | 1,119.5 | 100% | 996.0 | 100% | -123.5 | -11% | |
Physical Data (in GWh) | |||||||
Sales of energy to unregulated customers (1)…… | 4,584 | 55% | 4,828 | 57% | 244 | 5% | |
Sales of energy regulated customers…… | 3,635 | 44% | 3,691 | 43% | 56 | 2% | |
Sales of energy to the spot market……………. | 58 | 1% | 10 | 0% | -48 | -83% | |
Total energy sales…………………………. | 8,276 | 100% | 8,528 | 100% | 252 | 3% | |
Average monomic price unregulated | |||||||
customers(U.S.$/MWh)(2) | 107.9 | 95.9 | -12.0 | -11% | |||
Average monomic price regulated customers | |||||||
(U.S.$/MWh)(3) | 122.1 | 108.7 | -13.4 | -11% |
- Includes 100% of CTH sales.
- Calculated as the quotient between unregulated and spot revenues from energy and capacity sales and unregulated and spot physical energy sales.
- Calculated as the quotient between regulated revenues from energy and capacity sales and regulated physical energy sales.
Energy and capacity sales reached US$864.9 million in the first nine months of 2020, representing an 8% or a US$79.6 million decrease compared to the same period of 2019. The revenue decrease was primarily explained by a decrease in average monomic prices due to the drop in tariff indexes (CPI, gas and coal prices) and tariff renegotiations, which in the case of the Centinela PPA includes a larger discount in 2020 through which EECL is paying for the acquisition of a 40% interest in Inversiones Hornitos.
14
Physical energy sales to unregulated clients recovered from the lower demand observed in 2019, which was affected by temporary stoppages at mining operations caused by the Altiplanic Winter, environmental improvement works, and a 14-day strike at the Chuquicamata mine. Physical sales to regulated clients increased by 2% despite the COVID-19-driven decrease in demand. This was because starting 2020, EECL's share of the power supply contracts in the center-south segment of the SEN increased as older power supply contracts from other generation companies came due. In other words, the decrease in demand from regulated clients explained by the pandemic was offset by EECL's higher pro-rata of the pool of contracts in the area and the addition of EMR's sales beginning July 1, 2020.
Physical sales to the spot market decreased because of lower spot sales by Los Loros and CTA given the recovery in demand from its clients (Chuquicamata and Gaby), which were was partially offset by spot sales reported by EMR last August. However, the dollar amount of the spot sales item increased due to higher retroactive net capacity and energy re-liquidations.
While gas sales increased as compared to the first nine months of 2019, the Other operating revenue account decreased by 34%. Normally, this account includes transmission tolls and regulatory transmission revenues. However, this account included special items in both periods. In the first nine months of 2020, Other operating revenue included US$23.7 million in financial income associated to the acquisition of 40% of Inversiones Hornitos SpA, which is being paid monthly through the tariff discount in the Centinela PPA. In the first nine months of 2019, this account included US$74.9 million in liquidated damages paid by the IEM EPC contractor to compensate for past capacity revenue losses and higher energy supply costs attributed to the delayed start-up of the project.
Operating Costs
For the 9-month period ended september 30 (in US$ millions)
9M 2019 | 9M 2020 | Variation | |||||
Operating Costs | Amount | % of total | Amount | % of total | Amount | % | |
Fuel and lubricants……………………………… | (217.8) | 27% | (224.4) | 28% | 6.6 | 3% | |
Energy and capacity purchases on the spot market… | (297.8) | 37% | (234.1) | 30% | -63.7 | -21% | |
Depreciation and amortization attributable to cost of goods sold… | (111.6) | 14% | (131.0) | 17% | 19.4 | 17% | |
Other costs of goods sold……………………. | (156.9) | 19% | (180.2) | 23% | 23.3 | 15% | |
Total cost of goods sold……………….. | (784.1) | 97% | (769.6) | 97% | -14.4 | -2% | |
Selling, general and administrative expenses… | (26.2) | 3% | (24.7) | 3% | -1.5 | -6% | |
Depreciation and amortization in selling, general and administrative | |||||||
expenses… | (4.0) | 0% | (3.4) | 0% | -0.6 | -14% | |
Other operating revenue/costs………………………. | 8.4 | -1% | 5.2 | -1% | 3.2 | -38% | |
Total operating costs….………………. | (805.8) | 100% | (792.6) | 100% | -13.3 | -2% | |
Physical Data (in GWh) | |||||||
Gross electricity generation | |||||||
Coal…………………………………………. | 2,372 | 57% | 3,627 | 64% | 1,255 | 53% | |
Gas………………………………………….. | 1,689 | 41% | 1,818 | 32% | 129 | 8% | |
Diesel Oil and Fuel Oil……………………. | 10 | 0% | 19 | 0% | 8 | 81% | |
Hydro/Solar………………………………………. | 87 | 2% | 193 | 3% | 106 | 121% | |
Total gross generation…………………. | 4,158 | 100% | 5,657 | 100% | 1,499 | 36% | |
Minus Own consumption……………….. | (315) | -8% | (352) | -6% | -37 | 12% | |
Total net generation……………………. | 3,843 | 46% | 5,305 | 60% | 1,462 | 38% | |
Energy purchases on the spot market……….. | 4,164 | 50% | 3,105 | 35% | -1,059 | -25% | |
Energy purchases- bridge……….. | 373 | 4% | 377 | 4% | 3 | - | |
Total energy available for sale before transmission | |||||||
losses……………………… | 8,380 | 100% | 8,786 | 100% | 406 | 5% | |
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Gross electricity generation increased 36% compared to the first nine months of 2019, mainly due to commissioning of the IEM plant in May 2019. The generation mix revealed not only an increase in coal generation given the start-up of the IEM plant, but also an increase in gas generation given greater gas availability and gas plants' greater flexibility to cope with the intermittency of renewable output. Renewable generation also increased due to the acquisition of the Los Loros and Andacollo PV plants in April 2019 and the Eólica Monte Redondo wind farm and hydro plant in July 2020.
Despite the 36% increase in generation the fuel cost item increased by just 3% or US$6.6 million in the first nine months of 2020 due to lower coal and gas prices.
The electricity purchase costs item fell by US$63.7 million (21%) since physical purchases dropped due to the increase in generation. Average spot prices also decreased, in part due to the full interconnection of the country's main power grids on May 31, 2019, the increased hydro production in center-south Chile, and the operation of gas plants in inflexible mode due to more abundant gas supply. Demand under the contract with distribution companies in the center-south SEN reached 2,412 GWh in the first nine months of 2020 and was supplied with bridge contracts with other generation companies (377 GWh) and energy purchased from the spot market. Both types of purchases are included in the same accounting item.
The increase in depreciation costs is explained by the incorporation of IEM and an asset increase related to the U-16 CCGT overhaul, which were partially offset by the effect of the decommissioning and impairments of coal-based units.
Other direct operating costs included, among others, transmission tolls, operating and maintenance costs, cost of fuel sold, and insurance premiums. This item increased due to higher maintenance costs and, to a lesser extent, due to an increase in insurance premiums.
SG&A expenses decreased in part due to foreign-exchange effects.
The 'Other operating revenue/cost' item includes water sales, services and office rentals as well as the proportional result in TEN, which amounted to US$3.6 million in the first nine months of 2020.
Operating Results
For the 9-month period ended september 30 (in US$ millions) | ||||||
EBITDA | 9M 2019 | 9M 2020 | Variation | |||
Amount | % of total | Amount | % of total | Amount | % | |
Total operating revenues……………………… | 1,119.5 | 100% | 996.0 | 100% | -123.5 | -11% |
Total cost of goods sold…………………… | (784.1) | 70% | (769.6) | 77% | -14.4 | -2% |
Gross income…………………………. | 335.4 | 30% | 226.3 | 23% | -109.1 | -33% |
Total selling, general and administrative expenses and | ||||||
other operating income/(costs). | (21.8) | 2% | (22.9) | 2% | 1.1 | 5% |
Operating income….………………. | 313.6 | 28% | 203.4 | 20% | -110.2 | -35% |
Depreciation and amortization……...………… | 115.6 | 10% | 134.4 | 13% | 18.8 | 16% |
EBITDA…………….….………………. | 429.2 | 38.3% | 337.8 | 33.9% | -91.4 | -21% |
In the first nine months of 2020, EBITDA reached US$337.8 million, a 21%, or US$91.4 million, decrease compared to the same period of 2019, mainly due to one-off income received in 2019 consisting of liquidated damages paid by the IEM EPC contractor to compensate for the losses attributed to the delayed start-up of the project. This explains US$74.9 million of the EBITDA decrease in the first nine months of the year. The electricity margin decrease explains US$22 million of the EBITDA drop because of lower average realized tariffs, which were partially offset by lower energy procurement costs. The lower electricity margin was in turn partially offset by US$23.7 million in other income from the acquisition of a 40% ownership share in Inversiones Hornitos.
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Financial Results
For the 9-month period september 30 (in US$ millions) | ||||||
9M 2019 | 9M 2020 | Variation | ||||
Non-operating results | Amount | % of total | Amount % of total | Amount | % | |
Financial income………..……………………… | 3.3 | 0% | 3.1 | 0% | -0.2 | -7% |
Financial expense………….………………… | (25.4) | -2% | (49.6) | -5% | -24.2 | 95% |
Foreign exchange translation, net…………… | (2.0) | 0% | (2.9) | 0% | -0.9 | 43% |
Share of profit (loss) of associates accounted for using | - | - | 0.0 | |||
the equity method | 0% | 0% | ||||
Other non-operating income/(expense) net… | (85.5) | -8% | 1.8 | 0% | 87.3 | |
Total non-operating results……………. | (109.6) | -10% | (47.6) | -5% | ||
Income before tax……………………. ……… | 204.1 | 18% | 155.8 | 16% | -48.2 | -24% |
Income tax……………………………………… | (53.8) | -5% | (32.6) | -3% | 21.2 | |
Net income from continuing operations after taxes | ||||||
… | 150.3 | 13% | 123.3 | 12% | -27.0 | -18% |
Net income attributed to controlling | ||||||
shareholders……. | 143.0 | 13% | 123.3 | 12% | -19.8 | -14% |
Net income attributed to minority | ||||||
shareholders………. | 7.3 | 1% | (0.0) | 0% | -7.3 | -100% |
Net income to EECL's shareholders | 143.0 | 13% | 123.3 | 12% | -19.8 | -14% |
Earnings per share…………………….. | 0.136 | 0.117 | 0% |
Financial income decreased slightly due to lower interest rates.
The increase in interest expense in the first nine months of 2020 is explained by two main factors. First, the liability management transaction by which EECL prepaid a US$400 million 144A/RegS bond with the proceeds of a new US$500 million issue. In January, 2020, EECL launched an Any and All tender offer on its US$400 million bonds maturing in January 2021, subject to the results of a new 10-year bond issue, which was successfully placed on January 23 in an amount of US$500 million at a 3.4% annual coupon rate. Immediately following the new issue, the company announced a make-whole call to repay the remainder of the 2021 bond. Therefore, in February 2020, EECL completed the full repayment of the US$400 million bond and the payment of premiums in an amount of US$13.6 million, which were fully charged against first quarter results. Second, interest expense increased due to the lower interest capitalization following the completion of the IEM project in May 2019. While capitalized interest amounted to US$19.2 million in the first nine months of 2019, in the first nine months of 2020 it was just US$2.7 million corresponding to interest capitalized in renewable energy projects under construction.
Foreign-exchange differences resulted in a US$2.9 million loss in the first nine months of 2020, which compares to a US$2.0 million loss in the first nine months of 2019.
In the first nine months of 2020, Other net non-operating income recorded a minor US$1.8 million profit, a turnaround compared to the US$85.5 million loss in the first nine months of 2019, which was primarily explained by the asset impairment related to the future closure of the coal-fired units N°14 and N°15 in Tocopilla. The impairment represented an after-tax loss of US$63 million (US$87.4 million before-tax loss).
Net Earnings
The applicable income tax rate for both periods is 27%.
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In the first nine months of 2020, net income after taxes reached US$123.3 million, down from US$143 million in the first nine months of 2019. As explained earlier, in the first nine months of 2019, the impairment of Units 14 and 15 negatively impacted net results, but it was offset by the liquidated damages paid by IEM's EPC contractor.
In the first nine months of 2020, the company also reported non-recurring losses related to the make-whole paid to the bond holders for the early bond redemption. These had a US$9.9 million post-tax impact. Excluding non- recurring impacts in both periods and the one-off compensation paid by the IEM EPC contractor, which had a positive after-tax impact of US$54.7 million in 2019, net income would have been US$133 million in the first nine months of 2020, down from US$152 million in the first nine months of 2019.
Liquidity and Capital Resources
As of September 30, 2020, EECL reported consolidated cash balances of US$187.8 million, while its total nominal financial debt1 amounted to US$900 million, with only US$50 million maturing within one year and no other scheduled principal payments until January 2025.
For the 9-month period ended september 30 (in US$ millions) | ||
Cash Flow | 2019 | 2020 |
Net cash flows provided by operating activities… | 333.9 | 71.1 |
Net cash flows used in investing activities……… | (140.1) | (193.8) |
Net cash flows provided by financing activities.. | (91.2) | 68.1 |
Change in cash………………...…………. | 102.6 | (54.6) |
Cash Flow from Operating Activities
In the first nine months of 2020, cash flow generated from operating activities reached approximately US$200 million. However, the cash flow statement shows cash flow from operating activities of US$71.2 million since this figure is presented after income taxes (US$51.7 million), green taxes (US$21.2 million) and interest payments (US$55.7 million), which in turn include the US$13.6 million loss related to premiums paid on the early redemption of the US$400 million 144A bonds with original maturity in January 2021.
Cash Flow Used in Investing Activities
In the first nine months of 2020, cash flows from investing activities resulted in a net cash expenditure of US$193.8 million, mainly due to (i) the acquisition of Eólica Monte Redondo, which represented a US$53 million cash outflow; (ii) investments in the Capricornio and Tamaya solar PV projects (US$79.3 million) and the Calama windfarm project (US$32.0 million); and (iii) expenditures in plant maintenance and transmission assets (US$24 million). This item also shows a US$7.5 million cash inflow corresponding to debt repayments from the related company, TEN, in January 2020, and a US$3.4 million reimbursement of an advanced payment made in the past to the main contractor of the IEM project.
- Nominal amounts differ from the debt amounts recorded under the IFRS methodology in the Financial Statements, which considers deferred financial expenses and mark-to-market valuations on derivative transactions. The above amount excludes the financial leases related to the long-term tolling agreement with TEN and transactions qualified as financial leases under IFRS 16.
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Capital Expenditures
Our capital expenditures in the first nine months of 2020 and 2019 amounted to US$138.5 million and US$126.1 million, respectively, as shown in the following table. These amounts include VAT payments and capitalized interest. In the first nine months of 2020, capitalized interest in our renewable projects under construction amounted to US$2.7 million, while in the first nine months of 2019, these amounted to US$19.2 million.
For the 9-month period ended september 30 (in US$ millions)
CAPEX | 2019 | 2020 | ||||
CTA (New Port) …………………………………….. | 1.0 | - | ||||
IEM …………………………………………………… | 75.8 | - | ||||
Substation………………… | 2.2 | 13.0 | ||||
Overhaul power plants & equipment maintenance and | 8.6 | |||||
refurbishing………………… | 6.7 | |||||
Environmental improvement works……………… | 0.3 | - | ||||
Overhaul equipment & transmission lines | 7.8 | 2.9 | ||||
PV Power Plant…………… | 2.5 | 79.3 | ||||
Wind farm…………….. | 22.1 | 32.0 | ||||
Others…………………………………………… | 7.8 | 2.8 | ||||
Total capital expenditures………………………. | 126.1 | 138.5 |
Cash Flow from Financing Activities
In the first nine months of 2020 cash from financing activities resulted in a net cash inflow of US$68.1 million, an increase compared to an US$91.2 million net cash outflow reported in the first nine months of 2019. The main financing cash flows in the first nine months of 2020 were those related to the new 144A/RegS issue in an amount of US$500 million payable in a single principal installment in January 2030 with a 3.484% yield and a 3.4% coupon rate. The proceeds were used to prepay the US$400 million 144A/RegS bond with original maturity in January 2021, plus accrued interest, financial costs, stamp taxes and early redemption premiums. The company also prepaid two short-term loans with Scotiabank and Banco Estado for an aggregate amount of US$80 million. Subsequently, in May 2020, the company took a new US$50 million one-year loan with Banco Estado.
Contractual Obligations
The following table sets forth the maturity profile of our debt obligations as of September 30, 2020.
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Contractual Obligations as of 09/30/20
Payments Due by Period (in US$ millions)
More than 5 | |||||
Total | < 1 year | 1 - 3 years | 3 - 5 years | years | |
Bank debt…………………………………….…… | 50.0 | 50.0 | - | - | - |
Bonds (144 A/Reg S Notes)…………………….. | 850.0 | - | - | 350.0 | 500.0 |
Financial lease - Tolling Agreement TEN……… | 56.7 | 1.4 | 3.1 | 3.8 | 48.4 |
Financial lease - IFRS 16…………………………. | 51.5 | 3.1 | 7.2 | 5.0 | 36.3 |
Deferred financing cost………………………….. | (19.7) | - | (6.3) | (6.6) | (6.8) |
Accrued interest………………………………….. | 5.9 | 5.9 | - | - | - |
Mark-to-market swaps…………………………… | 2.1 | 2.1 | - | ||
Total | 996.5 | 62.4 | 4.0 | 352.2 | 577.8 |
Notes:
- The tolling contract signed with TEN for the use of dedicated transmission assets is considered a financial leasing operation and is accounted for under accounts payable to related companies.
- According to the IFRS16 Leasing rules, leasing obligations for land and vehicle rentals were accounted for as financial debt.
As of September 30, 2020, the company's short-term debt included a US$50 million loan with Banco Estado maturing on May 14, 2021. This loan is denominated in US dollars, accrues a fixed interest rate and is documented by a simple promissory note reflecting the repayment obligation on the agreed date, with no other operating or financial covenants, and a prepayment option at no cost for the company.
EECL has two bonds under the 144A/RegS format. The first one is a US$350 million issue with a single principal payment in January 2025 and a 4.5% p.a. coupon rate. On January 28, 2020, the company closed a new 144A/RegS issue to fully refinance the US$400 million notes originally due in January 2021. The new issue amounts to US$500 million, has a 3.4% coupon rate and is due on January 28, 2030. This bond allowed EECL to extend the average maturity of its total debt to a new average of 7.7 years and to lower the average coupon rate of its debt to a new average of 3.73% per annum.
Leasing obligations refer to a long-term tolling agreement signed with TEN for the use of dedicated transmission assets connecting EECL's plants in Mejillones with the national grid at the Los Changos substation. The tolling agreement is out to 20 years at which time EECL will take ownership of the asset. The agreement has a present value of US$57 million and is payable in monthly instalments totaling approximately US$7 million per year.
As of September 30, 2020, the company reported leasing obligations in respect to vehicles, land use concessions and other assets for a total of US$51.5 million, which qualified as financial debt under IFRS 16 accounting norm.
Dividend Policy
Our dividend policy consists of paying the minimum legal required amounts (30% of net income), although higher amounts may be approved if the company's conditions so allow. Our dividend payment for each year is proposed by our Board of Directors based on the year's financial performance, our available cash balance and anticipated financing requirements for capital expenditures and investments. As possible and subject to Board approval, the company will pay two provisional dividends based on the net results of the first three quarters plus the definitive dividend to be paid in May of each year.
The dividend policy proposed by our Board is subsequently approved at a Shareholders' Meeting as established by law.
On May 28, 2019, the company's Board of Directors approved the distribution of a provisional dividend on account of 2019's net earnings, in an amount of US$50 million or US$0.047469416 per share. The dividend was paid on June 21, 2019, in Chilean pesos using the peso-dollar observed rate published by the Official Gazette on
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June 19, 2019. Such dividend was approved in consideration to the company's cash generation and the fulfillment of an intensive investment period.
On December 13, 2019, the company paid its third provisional dividend on account of 2019 net profits in an amount of US$40 million, or US$0.03798 per share, as approved by the Board of Directors on November 26, 2019.
On April 28, 2020, at the Annual Ordinary Shareholders' Meeting our shareholders agreed not to distribute a final dividend on account of 2019's net income. Therefore, total dividends paid on account of 2019's net income amounted to US$90 million, equivalent to 81% of 2019's US$110.8 million net income.
The record of dividends paid since 2010 is shown in the following table:
Cash Dividends paid by Engie Energía Chile S.A. | |||
Payment Date | Dividend Type | Amount | US$ per share |
(in US$ millions) | |||
May 4, 2010 | Final (on account of 2009 net income) | 77.7 | 0.07370 |
May 4, 2010 | Additional (on account of 2009 net income) | 1.9 | 0.00180 |
May 5, 2011 | Final (on account of 2010 net income) | 100.1 | 0.09505 |
Aug 25 2011 | Provisional (on account of 2011 net income) | 25.0 | 0.02373 |
May 16 2012 | Final (on account of 2011 net income) | 64.3 | 0.06104 |
May 16 2013 | Final (on account of 2013 net income) | 56.2 | 0.05333 |
May 23 2014 | Final (on account of 2013 net income) | 39.6 | 0.03758 |
Sept 30,2014 | Provisional (on account of 2014 net income) | 7.0 | 0.00665 |
May 27 ,2015 | Final (on account of 2014 net income) | 19.7 | 0.01869 |
Oct 23 ,2015 | Provisional (on account of 2015 net income) | 13.5 | 0.01280 |
Jan 22, 2016 | Provisional (on account of 2015 net income) | 8.0 | 0.00760 |
May 26, 2016 | Final (on account of 2015 net income) | 6.8 | 0.00641 |
May 26, 2016 | Provisional (on account of 2016 net income) | 63.6 | 0.06038 |
May 18, 2017 | Final (on account of 2016 net income) | 12.8 | 0.01220 |
May 22,2018 | Final (on account of 2017 net income) | 30.4 | 0.02888 |
Oct 25 ,2018 | Provisional (on account of 2018 net income) | 26.0 | 0.02468 |
May 24 ,2019 | Final (on account of 2018 net income) | 22.1 | 0.02102 |
June 21 ,2019 | Provisional (on account of 2019 net income) | 50.0 | 0.04747 |
Dec 13 ,2019 | Provisional (on account of 2019 net income) | 40.0 | 0.03798 |
Nov 30 ,2020 | Provisional (on account of 2020 net income) | 66.6 | 0.06323 |
Risk management policy
In the normal course of business, EECL is exposed to several risk factors that may impact its operating and financial performance.
EECL has established risk management procedures, which include a description of the risk assessment methodology and a risk matrix. Additionally, the company established a Risk and Insurance Committee, responsible for the risk matrix review, analysis and approval as well as the proposal of risk mitigation measures. The risk matrix is updated and reviewed every year, while action plans are monitored on a permanent basis. Management presents the company's risk management performance to the board on an annual basis.
The company's financial risk management strategy seeks to safeguard EECL's operating stability and sustainability in a context of risk and uncertainty.
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Hedging Policy
Our hedging policy intends to protect the company against our exposure to certain risks, as follows:
Business Risk and Commodity Hedging
Our business is subject to the risk of variations in the availability of fuels and their prices. Our policy has been to hedge as much as possible against these risks through the indexation of the energy tariffs incorporated in our PPAs, and the fuel mix taken into consideration in the tariffs. However, given (i) the volume fluctuations that our PPAs may have; (ii) the variability that our plant dispatch profile may experience; (iii) our inability to perfectly match at all times our fuel cost mix with the tariff indexation in our PPAs; and (iv) the growing trend to dissociate PPA price indexation from fossil fuel price fluctuations, we maintain residual exposure to certain international commodity prices. For example, the tariff of our contract with distribution companies in the northern SEN, which became effective at the beginning of 2012, is readjusted semiannually according to the Henry Hub and the US CPI. However, there is a mismatch between the Henry Hub index used to define the contract tariff (four-month average prior to the tariff fixing, which takes place every six months) and the Henry Hub index prevailing at the time each LNG shipment is made. In the specific case of this contract, this risk is mitigated by an automatic tariff indexation triggered any time the price formula reports a fluctuation of 10% or more. Hence, we periodically execute financial hedging strategies to cover our residual exposure to international commodity price risks. Therefore, we have occasionally taken financial swap contracts to reduce our residual exposure to Brent and Henry Hub.
Currency Hedging
Given that most of our revenues and costs are denominated in US dollars and that we seek to incur debt in US dollars, we face limited exposure to foreign exchange risk. Our main costs denominated in Chilean pesos are personnel and administrative expenses, which account for 10% of our total operating costs as of June 30, 2020. In the specific case of regulated contracts, the price is calculated in US dollars and is then converted to Chilean pesos at the average monthly exchange rate observed in the invoiced month. In terms of the impact on the company's income statement, these contracts' exposure to foreign currency risk is limited as revenues are recognized at contract rates. However, delays in the publication of the Average Node Price decrees may impact the company's cash flow as monthly invoices are translated to Chilean pesos at exchange rates that remain fixed over the life of the tariff decree and differ from the monthly exchange rates considered in the contracts. Even though these differences are adjusted after the Average Node Price decrees are published, the uncertainty as to the timing and amount of these adjustments does not allow for an effective hedge through derivative instruments. The delay in the collection of foreign- exchange adjustments has significantly increased after the approval of the Price Stabilization law in November 2019. Per this law and resolution #72, by which the National Energy Commission set the terms of implementation of the law, accounts receivable from distribution companies will increase at a rate that is highly sensitive, among other variables, to the CLP/USD exchange rate. To face this risk and mitigate its effect on the company's cash flow and liquidity, the company is currently working with banks in the design and implementation of a monetization alternative for these accounts receivable.
Our main cost in Chilean pesos is personnel and certain operating and administrative costs, which account for approximately 10% of our operating costs. Given that most of our revenues are either in US dollars or in Chilean pesos adjusted for the exchange rate, our costs in Chilean pesos represent our main exposure to foreign-currency risks. Therefore, we have hedged a portion of our recurrent costs in Chilean pesos through forward contracts and zero-cost collars.
Furthermore, in the past we and our subsidiary CTA have signed foreign-currency derivative contracts to hedge the UF and EUR cash flows stemming from EPC, to avoid cash flow or investment value variations resulting from foreign currency fluctuations that are beyond management's control. As of September 30, 2020, there were no outstanding derivative contracts associated with such EPC contract cash flows.
Interest Rate Hedging
The stability and predictability of our cash flows is also exposed to interest rate risk, principally with respect to the portion of our indebtedness that bears interest at floating rates. We seek to maintain a significant
22
portion of our long-term debt at fixed rates to minimize interest-rate exposure. As of September 30, 2020, 100% of our financial debt, for a principal amount of US$900 million, was at fixed rates.
As of September 30, 2020 | |||||||
Contractual maturity date (in US$ millions) | |||||||
Average interest rate | 2020 | 2021 | 2022 | 2023 | Thereafter | Grand Total | |
Fixed Rate | |||||||
(US$) | 1.580% p.a. | - | 50.0 | - | - | - | 50.0 |
(US$) | 3.400% p.a. | - | - | - | - | 500.0 | 500.0 |
(US$) | 4.500% p.a. | - | - | - | - | 350.0 | 350.0 |
Total | - | 50.0 | - | - | 850.0 | 900.0 |
Credit Risk
In the normal course of business, and when investing our cash, we are exposed to credit risk. In our regular electricity generation business, we deal mostly with financially strong mining companies, which report low levels of credit risk. However, these companies are exposed to variations in commodity prices, particularly copper. Although our clients have demonstrated significant resilience to down-cycles, we closely monitor their exposure through our commercial counterparty risk policy. We also sell electricity to regulated clients, which provide electricity supply to residential and commercial clients and report low levels of credit risk.
Over the last years, the electricity generation business and its customer base have evolved. In particular, consumers with demand between 500 kW and 5 MW are allowed to contract their power supply directly with generation companies rather than through distribution companies. This disintermediation trend has led us to sign contracts with smaller commercial and industrial clients with potentially higher credit risk. To mitigate this risk, we have implemented a commercial counterparty risk policy, which among other considerations, requires the review of the credit risk of the client before entering into a power supply agreement. As of September 30, 2020, the contracts signed with smaller commercial and industrial clients represented a low percentage of our overall client portfolio.
The outbreak of the COVID-19 pandemic is leading to a world economic recession, with the consequential uncertainty about the behavior of power demand and the financial capacity of consumers of essential services to afford the timely payment of their bills. To face this situation the company has instructed its commercial areas to maintain close, direct contact with our customers to monitor the situation and take timely measures as necessary to both support our customers and mitigate the impact on the company's performance.
Our cash management policy is to invest in investment-grade institutions only, and only within the short term. We also measure our counterparty risk when dealing with derivatives and guarantees, and we have individual counterparty limits to manage our exposure.
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OWNERSHIP STRUCTURE AS OF SEPTEMBER 30, 2020
Number of shareholders: 1,823
9.24% | 0.42% |
14.89% | |
52.76% | |
22.69% | ENGIE |
Chilean pension funds | |
Chilean Inst. Inv. | |
Foreign Inst. inv. | |
Others |
TOTAL NUMBER OF SHARES: 1,053,309,776
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APPENDIX 1
PHYSICAL DATA AND SUMMARIZED QUARTERLY FINANCIAL STATEMENTS
Physical Sales
Physical Sales (in GWh) | ||||||||
2019 | 2020 | |||||||
1Q19 | 2Q19 | 3Q19 | 9M19 | 1Q20 | 2Q20 | 3Q20 | 9M20 | |
Physical Sales | ||||||||
Sales of energy to unregulated customers. | 1,423 | 1,550 | 1,610 | 4,584 | 1,672 | 1,662 | 1,493 | 4,828 |
Sales of energy to regulated customers | 1,220 | 1,183 | 1,232 | 3,635 | 1,285 | 1,122 | 1,283 | 3,691 |
Sales of energy to the spot market……… | 6 | 20 | 31 | 58 | - | 3 | 6 | 10 |
Total energy sales…………………………. | 2,649 | 2,754 | 2,873 | 8,276 | 2,957 | 2,788 | 2,783 | 8,528 |
Gross electricity generation | ||||||||
Coal…………………………………………. | 594 | 911 | 867 | 2,372 | 1,304 | 1,276 | 1,046 | 3,627 |
Gas………………………………………….. | 356 | 569 | 764 | 1,689 | 493 | 705 | 620 | 1,818 |
Diesel Oil and Fuel Oil……………………. | 2 | 1 | 8 | 10 | 17 | 1 | 0 | 19 |
Renewable………………………………………. | 14 | 32 | 41 | 87 | 46 | 35 | 112 | 193 |
Total gross generation…………………. | 965 | 1,513 | 1,680 | 4,158 | 1,861 | 2,017 | 1,779 | 5,657 |
Minus Own consumption……………….. | (78) | (106) | (131) | (315) | (82) | (148) | (122) | (352) |
Total net generation……………………. | 888 | 1,407 | 1,549 | 3,843 | 1,779 | 1,869 | 1,657 | 5,305 |
Energy purchases on the spot market……….. | 1,729 | 1,307 | 1,128 | 4,164 | 1,063 | 821 | 1,220 | 3,105 |
Energy purchases- bridge | 122 | 124 | 127 | 373 | 125 | 125 | 127 | 377 |
Total energy available for sale before | ||||||||
transmission losses……………………… | 2,739 | 2,838 | 2,804 | 8,380 | 2,967 | 2,815 | 3,004 | 8,786 |
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Quarterly Income Statement
Quarterly Income Statement (in US$ millions) | |||||||||
IFRS | |||||||||
Operating Revenues | 1Q19 | 2Q19 | 3Q19 | 9M19 | 1Q20 | 2Q20 | 3Q20 | 9M20 | |
Regulated customers sales……………………… | 150.6 | 146.9 | 146.1 | 443.6 | 134.1 | 127.5 | 139.5 | 401.0 | |
Unregulated customers sales………………….. | 163.0 | 173.7 | 152.7 | 489.3 | 164.0 | 142.9 | 142.5 | 449.4 | |
Spot market sales……………………………….. | 1.6 | 3.6 | 6.3 | 11.5 | 7.8 | 1.5 | 5.2 | 14.5 | |
sales………………… | 315.1 | 324.3 | 305.1 | 944.4 | 305.8 | 271.9 | 287.2 | 864.9 | |
Gas sales………………………….. | 4.1 | 4.2 | 4.4 | 12.6 | 5.9 | 7.6 | 10.9 | 24.4 | |
Other operating revenue………………………. | 24.6 | 94.1 | 43.7 | 162.4 | 23.5 | 42.6 | 40.6 | 106.7 | |
Total operating revenues…………………. | 343.8 | 422.5 | 353.2 | 1,119.5 | 335.3 | 322.0 | 338.7 | 996.0 | |
- | - | - | |||||||
Operating Costs | - | - | |||||||
Fuel and lubricants……………………………… | (66.5) | (72.8) | (78.4) | (217.8) | (80.8) | (83.6) | (59.9) | (224.4) | |
Energy and capacity purchases on the spot | (122.9) | (102.8) | (72.1) | (297.8) | (93.2) | (69.2) | (71.7) | (234.1) | |
Depreciation and amortization attributable to cost of goods sold.. | (33.2) | (38.4) | (40.0) | (111.6) | (41.2) | (41.7) | (48.1) | (131.0) | |
Other costs of goods sold……………………. | (52.9) | (49.2) | (54.8) | (156.9) | (52.9) | (62.5) | (64.8) | (180.2) | |
Total cost of goods sold……………….. | (275.5) | (263.2) | (245.3) | (784.1) | (268.1) | (257.0) | (244.5) | (769.6) | |
Selling, general and administrative expenses… | (9.0) | (8.9) | (8.2) | (26.2) | (7.7) | (8.7) | (8.3) | (24.7) | |
Depreciation and amortization in selling, general and | (0.9) | (1.9) | (1.2) | (4.0) | (1.1) | (1.5) | (0.8) | (3.4) | |
administrative expenses… | |||||||||
Other revenues………...………………………. | 3.9 | (0.2) | 4.7 | 8.4 | (1.6) | 4.9 | 1.9 | 5.2 | |
Total operating costs….………………. | (281.5) | (274.3) | (250.0) | (805.8) | (278.5) | (262.3) | (251.8) | (792.6) | |
0 | 0 | 0 | 0 | 0 | 0 | ||||
Operating income….………………. | 62.2 | 148.2 | 103.2 | 313.6 | 56.8 | 59.7 | 86.8 | 203.4 | |
0 | 0 | 0 | |||||||
EBITDA…………….….………………. | 96.3 | 188.5 | 144.4 | 429.2 | 99.1 | 103.0 | 135.8 | 337.8 | |
0 | 0 | ||||||||
Financial income………..……………………… | 1.2 | 1.5 | 0.6 | 3.3 | 1.6 | 1.0 | 0.5 | 3.1 | |
Financial expense………….………………… | (3.2) | (8.5) | (13.7) | (25.4) | (28.5) | (10.6) | (10.5) | (49.6) | |
Foreign exchange translation, net…………… | 1.1 | (0.1) | (3.1) | (2.0) | (0.4) | (0.9) | (1.7) | (2.9) | |
method | - | - | - | - | - | - | - | - | |
Other non-operating income/(expense) net……………………… | 0.9 | (90.6) | 4.2 | (85.5) | 1.7 | 0.2 | (0.1) | 1.8 | |
Total non-operating results…………… | 0.1 | (97.7) | (12.0) | (109.6) | (25.6) | (10.4) | (11.7) | (47.6) | |
Income before tax……………………..……… | 62.4 | 50.5 | 91.1 | 204.1 | 31.3 | 49.4 | 75.2 | 155.8 | |
Income tax……………………………………… | (16.8) | (13.9) | (23.1) | (53.8) | (5.6) | (8.8) | (18.1) | (32.6) | |
Net income from continuing operations after taxes ……. | 45.6 | 41.1 | 63.6 | 150.3 | 25.6 | 40.6 | 57.0 | 123.3 | |
Net income attributed to controlling | |||||||||
shareholders………………. | 42.9 | 37.7 | 62.4 | 143.0 | 25.6 | 40.6 | 57.0 | 123.3 | |
Net income attributed to minority shareholders………………. | 2.7 | 3.4 | 1.2 | 7.3 | - | - | (0.0) | (0.0) | |
Net income to EECL's shareholders……. | 42.9 | 37.7 | 62.4 | 143.0 | 25.6 | 40.6 | 57.0 | 123.3 | |
Earnings per share…………………….. (US$/share) | 0.041 | 0.036 | 0.059 | 0.136 | 0.024 | 0.039 | 0.054 | 0.117 |
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Quarterly Balance Sheet
Quarterly Balance Sheet (in U.S.$ millions) | |||
2019 | 2020 | ||
December | September | ||
Current Assets | |||
Cash and cash equivalents (1) | 239.1 | 187.8 | |
Other financial assets | |||
Accounts receivable | 108.6 | 122.3 | |
Recoverable taxes | 12.7 | 13.3 | |
Current inventories | 116.2 | 97.4 | |
Other non financial assets | 8.2 | 23.6 | |
Total current assets | 484.8 | 444.4 | |
Non-Current Assets | |||
Property, plant and equipment, net | 2,561.4 | 2,636.2 | |
Other non-current assets | 461.6 | 560.5 | |
TOTAL ASSETS | 3,507.8 | 3,641.1 | |
Current Liabilities | |||
Financial debt | 103.7 | 58.0 | |
Other current liabilities | 253.7 | 223.0 | |
Total current liabilities | 357.5 | 280.9 | |
Long-Term Liabilities | |||
Financial debt | 760.4 | 878.8 | |
Other long-term liabilities | 266.3 | 282.5 | |
Total long-term liabilities | 1,026.7 | 1,161.2 | |
Shareholders' equity | |||
2,059.3 | 2,198.9 | ||
Minority' equity | 64.4 | - | |
Equity | 2,123.6 | 2,198.9 | |
TOTAL LIABILITIES AND SHAREHOLDERS' | |||
EQUITY | 3,507.8 | 3,641.1 | |
(1) Includes short-term investments classified as available for sale. |
Main Balance Sheet Variations
The main balance-sheet variations between December 31, 2019, and September 30, 2020, are the following:
Cash and cash equivalents: The company's cash balances decreased by US$51 million to US$187.8 million mainly because of (i) capital expenditures for US$138.5 million, (ii) the EMR acquisition for US$53 million; (iii) interest and other financial expenses incurred in connection with financing activities (US$58.4 million including US$13.6 million in early bond redemption premiums), and (iv) income and green tax payments for US$72.8 million. These cash expenditures were financed with available cash (US$51 million), operating cash flow (US$200 million),
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a US$7.5 million payment received from TEN and a US$50 million short-term loan taken with Banco Estado. The proceeds of the new US$500 million 144A/RegS issue were entirely used to prepay the US$400 million bond and US$80 million in short-term bank debt, which the company reported as of year-end 2019. Cash balances were invested in time deposits with strongly rated banks.
Accounts receivable: The US$13.7 million increase comprises changes in two different accounts: On the one hand, accounts receivable from third parties reported a US$19 million increase. On the other hand, intercompany receivables decreased by US$5.4 million.
Current inventories: The US$18.8 million inventory decrease includes a US$20.6 million decrease in fuel stocks (LNG, hydrated lime and coal), mainly due to lower prices, partially offset by a US$1.5 million increase in materials and spare parts stocks.
Recoverable taxes: This item reported no significant changes and remained at US$13.3 million as of September 30, 2020.
Other non-financialassets - current: The US$15.5 million increase in these assets includes two principal
effects: (i) a US$9.4 million increase in fiscal VAT credit explained by capital expenditures and lower collection of revenues from distribution companies as a result of the price stabilization mechanism, and (ii) a US$6.1 million increase in insurance premiums paid in advance.
Property, plant and equipment, net: The US$99.1 million increase in this account is principally explained by (i) capital expenditures incurred in connection with plant overhauls and the construction of the Calama wind farm and the Capricornio and Tamaya solar PV plants and transmission projects, and (ii) the EMR acquisition (US$56.6 million), which were partially offset by depreciation, which amounted to US$118.5 in the first nine months of 2020.
Other non-currentassets: The US$75.1 million net increase in this item is explained by (i) a US$25.9 million increase in the acquisition of rights of use over land for the construction of renewable projects and other assets with rights of use associated to the implementation of IFRS16; (ii) a US$57.4 million increase in long-term accounts receivable associated to the enactment of the price stabilization law in the fourth quarter of 2019; (iii) an US$8.1 million increase in intangible assets due to expenses associated to generation projects in their development stage (Trigales and Coya); and (iv) a US$4.3 million deferred tax increase. These increases were partially offset by decreases in the following items: (i) US$2.7 million in the company's investment in TEN mainly due to the mark- to-market of financial derivatives, (ii) a US$6.3 million payment of intercompany receivables from TEN, and (iii) a US$12.2 million amortization of intangible assets.
Financial debt - current: This item reported a net US$45.7 million decrease due to the full prepayment of short-term debt (US$80.7 million including principal and interest) in the first quarter of 2020 and the new US$50 million loan taken in May with Banco Estado. In addition, accrued interest decreased by US$11.7 million due to lower interest rates and the cut-off dates of the balance sheets being compared. Since interest payments on both of our 144 A bonds are due in January, accrued interest at the end of December is larger than at the end of September.
Other current liabilities: The US$30.7 million decrease in this item is explained by four main factors: (i) a US$4.1 million decrease in accounts payable to suppliers, as invoices on fuel purchases outstanding at year-end 2019 were paid at the beginning of 2020; (ii) a lower income tax provision (US$14 million); (iii) a decrease in VAT payables (US$10.9 million) and (iv) a US$4.3 million decrease in intercompany payables, mainly GNL Mejillones.
Long-termfinancial debt: The US$118.4 million increase in this account is mainly explained by the new US$500 million bond issue, which proceeds were used to prepay the US$400 million bond originally maturing in January 2021. A US$25.8 million increase in lease liabilities, mainly referred to land use concessions acquired to develop generation projects also contributed to the financial debt increase. Lastly, there was a US$7.4 million increase in financial expenses that are discounted from liabilities and are expensed over the life of the respective liability.
Other long-termliabilities: This item increased by US$16.2 million due to asset dismantling provisions (US$13.4 million) and a US$3.9 million increase in deferred taxes.
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Shareholders' equity: The US$139.6 million increase in shareholders' equity is made up of (i) the net income reported in the first nine months of 2020 (US$123.3 million), plus (ii) the US$23.9 million corresponding to the difference between the absorption of the minority interest that Inversiones Punta de Rieles had in our subsidiary, Inversiones Hornitos, and the valuation of the investment of the 40% interest in Inversiones Hornitos pursuant to the agreement signed by its shareholders on March 31, 2020, and minus (iii) a US$7.5 million decrease in mark-to- market valuation of hedging instruments. According to the terms of the agreement signed last March and IFRS rules, EECL began to consolidate 100% of Inversiones Hornitos' results in its financial statements.
Minority interest: The elimination of minority interest is explained by the agreement between EECL and the minority shareholder of Inversiones Hornitos and its related companies, Minera Centinela and Antofagasta Minerals on March 31, 2020, as reported in a material fact notice filed with the CMF. As a result of this agreement, EECL took control over Inversiones Hornitos, consolidating 100% of its results in EECL's accounting records and eliminating minority interest, which as of year-end 2019 amounted to US$64 million.
APPENDIX 2
Financial information
2Q19 | 3Q19 | 4Q19 | 1Q20 | 2Q20 | 3Q20 | |
EBITDA* | 188.5 | 144.4 | 105.6 | 99.1 | 103.0 | 202.1 |
Net income attributed to the controller | 37.7 | 62.4 | -32.2 | 25.6 | 40.6 | 66.2 |
Interest expense | 8.5 | 13.7 | 12.5 | 28.5 | 10.6 | 39.1 |
* Operating income + Depreciation and Amortization for the period | ||||||
Sep/19 | Sep/20 | |||||
LTM EBITDA | 526.5 | 509.8 | ||||
LTM Net income attributed to the controller | 173.1 | 100.2 | ||||
LTM Interest expense | 28.7 | 90.7 | ||||
Financial debt | 899.4 | 936.8 | ||||
Current | 92.4 | 58.0 | ||||
Long-Term | 807.0 | 878.8 | ||||
Cash and cash equivalents | 166.1 | 187.8 | ||||
Net financial debt | 733.3 | 748.9 |
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Financial Ratios
FINANCIAL RATIOS | |||||
Dec/19 | Sep/20 | Var. | |||
LIQUIDITY | Current ratio | (times) | 1.36 | 1.58 | 16% |
(current assets / current liabilities) | |||||
Quick ratio | (times) | 1.03 | 1.24 | 20% | |
((current assets - inventory) / current liabilities) | |||||
Working capital | MMUS$ | 127.3 | 163.5 | 28% | |
(current assets - current liabilities) | |||||
LEVERAGE | Leverage | (times) | 0.65 | 0.66 | 1% |
((current liabilities + long-term liabilities) / networth) | |||||
Interest coverage * | (times) | 14.14 | 7.15 | -49% | |
((EBITDA / interest expense)) | |||||
Financial debt -to- LTM EBITDA* | (times) | 1.72 | 2.24 | 30% | |
Net financial debt - to - LTM EBITDA* | (times) | 1.28 | 1.82 | 42% | |
PROFITABILITY Return on equity* | % | 5.4% | 4.1% | -23% | |
(LTM net income attributed to the controller / net worth attributed to the controller) | |||||
Return on assets* | % | 3.2% | 2.5% | -22% | |
(LTM net income attributed to the controller / total assets) | |||||
*LTM = Last twelve months |
As of September 30, 2020, the current ratio and the quick ratio were 1.58x and 1.24x, respectively, an increase compared to year-end 2019's ratios. The main reason was the reduction of current liabilities due to the full repayment of the company's short-term debt (US$80 million) followed by a new loan for a lower amount (US$50 million). As a result, working capital, as measured by total current assets minus total current liabilities, increased. Liquidity remained strong due to the company's cash balances, strong cash generation ability, and low repayment commitments before January 2025.
The leverage ratio, as measured by total liabilities-to-equity remained unchanged as compared to December 31, 2019.
The interest coverage ratio for the 12-month period ending September 30, 2020 was 7.15x. Although this is a strong ratio, it represents a sharp decrease compared to exceptionally high levels at year-end 2019, due to (i) the increase in interest expense explained by the early redemption costs of the US$400 million bond, (ii) and the lower level of interest capitalization, and (iii) the decrease in EBITDA, which in 2019 was favorably impacted by the liquidated damages paid by the IEM EPC contractor.
The leverage ratio, as measured by Gross financial debt-to-EBITDA, increased to 2.2 times as a result of the EBITDA decrease in the first nine months of 2020 as compared to the first nine months of 2019. Net financial debt-to-EBITDA increased slightly to 1.83 times due to lower cash balances, which were still strong at US$188 million.
Return on equity and return on assets reached 4.1% and 2.5%, respectively, a decrease compared to the ratios reported at year-end 2019. Return on equity attributable to controlling shareholders decreased partly because of the absorption of the minority interest in Inversiones Hornitos, which caused an increase in shareholders' equity. Return on assets decreased mainly because of the lower net income reported in the first nine months of 2020 as compared to the first nine months of 2019, which was in turn due to higher interest expense including the premiums paid on the early redemption of the bonds originally due in January 2021.
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CONFERENCE CALL 9M2020
ENGIE Energía Chile is pleased to inform you that it will conduct a conference call to review its results
for the period ended September 30, 2020, on Thursday, October 29, 2020
at 12:00 p.m. (USA-NY) - 12:00 p.m. (Chile)
hosted by:
Eduardo Milligan, CFO ENGIE Energía Chile S.A.
To participate, please dial:
+1(412) 317-6378,international or +56 44 208 1274 Chile or +1(844) 686-3841(toll free US)
https://hd.choruscall.com/?calltype=2&info=company&r=true
To join the conference, please state the name of the conference (ENGIE ENERGIA; no other
Conference ID will be requested
. Please connect approximately 10 minutes prior to the scheduled starting time.
To access the phone replay, which will be available until November 6, 2020, please dial
+1 (877) 344-7529 /+1 (412) 317-0088
Passcode I.D.: 10145971
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Engie Energía Chile SA published this content on 28 October 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 28 October 2020 13:34:02 UTC
