UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20509
Form 20-F
(Mark One)

| ☐ | REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020
OR

| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

OR

| ☐ | SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report__________
For the transition period from_________to_________
Commission file number: 001-36487
Atlantica Sustainable Infrastructure plc
(Exact name of Registrant as specified in its charter)
Not applicable
(Translation of Registrant’s name into English)
England and Wales
(Jurisdiction of incorporation or organization)
Great West House, GW1, 17th floor
Great West Road
Brentford, United Kingdom TW8 9DF
Tel: +44 203 499 0465
(Address of principal executive offices)
Santiago Seage
Great West House, GW1, 17th floor
Great West Road
Brentford, United Kingdom TW8 9DF
Tel: +44 203 499 0465
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act.

Title of each class | Trading Symbol |  | Name of each exchange on which registered
Ordinary Shares, nominal value $0.10 per share | AY |  | NASDAQ Global Select Market

Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 106,670,862 ordinary shares, nominal value $0.10 per share.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒Yes ☐ No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐Yes ☒ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer, “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ | Accelerated filer ☐ | Non-accelerated filer ☐
|  | Emerging growth company ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ☐ | International Financial Reporting Standards as issued by the International Accounting Standards Board ☒ | Other ☐

If “Other” has been checked in response to the previous question indicate by check mark which financial statement item, the registrant has elected to follow. ☐ Item 17 ☐ Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐Yes ☒No
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ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC
TABLE OF CONTENTS

|  | Page
CURRENCY PRESENTATION AND DEFINITIONS | 6
PRESENTATION OF FINANCIAL INFORMATION | 9
PRESENTATION OF INDUSTRY AND MARKET DATA | 10
ITEM 1. | IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS | 11
ITEM 2. | OFFER STATISTICS AND EXPECTED TIMETABLE | 11
ITEM 3. | KEY INFORMATION | 11
B. | Capitalization and Indebtedness | 11
C. | Reasons for the Offer and Use of Proceeds | 11
D. | Risk Factors | 11
ITEM 4. | INFORMATION ON THE COMPANY | 41
A. | History and Development of the Company | 41
B. | Business Overview | 43
C. | Organizational Structure | 75
D. | Property, Plant and Equipment | 75
ITEM 4A. | UNRESOLVED STAFF COMMENTS | 75
ITEM 5. | OPERATING AND FINANCIAL REVIEW AND PROSPECTS | 76
A. | Operating Results | 76
B. | Liquidity and Capital Resources | 92
C. | Research and Development | 101
D. | Trend Information | 101
E. | Off-Balance Sheet Arrangements | 101
G. | Safe Harbor | 105
ITEM 6. | DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES | 106
A. | Directors and Senior Management | 106
B. | Compensation | 109
C. | Board Practices | 119
D. | Employees | 121
E. | Share Ownership | 121
ITEM 7. | MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS | 122
A. | Major Shareholders | 122
B. | Related Party Transactions | 123
C. | Interests of Experts and Counsel | 126
ITEM 8. | FINANCIAL INFORMATION | 126
A. | Consolidated Statements and Other Financial Information. | 126
B. | Significant Changes | 128
ITEM 9. | THE OFFER AND LISTING | 128
A. | Offering and Listing Details. | 128
B. | Plan of Distribution | 129
C. | Markets | 129
D. | Selling Shareholders | 129
E. | Dilution | 129
F. | Expenses of the Issue | 129
ITEM 10. | ADDITIONAL INFORMATION | 129
A. | Share Capital | 129
B. | Memorandum and Articles of Association | 129
C. | Material Contracts | 129
D. | Exchange Controls | 129
E. | Taxation | 129
F. | Dividends and Paying Agents | 133
G. | Statement by Experts | 133
H. | Documents on Display | 133
I. | Subsidiaries Information | 133
ITEM 11. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 134

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ITEM 12. | DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES | 135
A. | Debt Securities | 135
B. | Warrants and Rights | 135
C. | Other Securities | 135
D. | American Depositary Shares | 136
ITEM 13. | DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES | 136
ITEM 14. | MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS | 136
ITEM 15. | CONTROLS AND PROCEDURES | 136
ITEM 16. | [RESERVED] | 137
ITEM 16A. | AUDIT COMMITTEE FINANCIAL EXPERT | 137
ITEM 16B. | CODE OF ETHICS | 137
ITEM 16C. | PRINCIPAL ACCOUNTANT FEES AND SERVICES | 137
ITEM 16D. | EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES | 139
ITEM 16E. | PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS | 139
ITEM 16F. | CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT | 139
ITEM 16G. | CORPORATE GOVERNANCE | 139
ITEM 16H. | MINE SAFETY DISCLOSURE | 139
ITEM 17. | FINANCIAL STATEMENTS | 139
ITEM 18. | FINANCIAL STATEMENTS | 139
ITEM 19. | EXHIBITS | 140

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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS
This report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, strategies, future events or performance (often, but not always, through the use of words or phrases such as may result, are expected to, will continue, is anticipated, believe, will, could, should, would, estimated, may, plan, potential, future, projection, goals, target, outlook, predict and intend or words of similar meaning) are not statements of historical facts and may be forward looking. Such statements occur throughout this report and include statements with respect to our expected trends and outlook, potential market and currency fluctuations, occurrence and effects of certain trigger and conversion events, our capital requirements, changes in market price of our shares, future regulatory requirements, the ability to identify and/or consummate future investments and acquisitions on favorable terms, reputational risks, divergence of interests between our company and that of our largest shareholder, tax and insurance implications, and more. Forward-looking statements involve estimates, assumptions and uncertainties. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, important factors included in Part I, Item 3D. Risk Factors (in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements) that could have a significant impact on our operations and financial results, and could cause our actual results to differ materially from those contained or implied in forward-looking statements made by us or on our behalf in this Form 20-F, in presentations, on our website, in response to questions or otherwise. These forward-looking statements include, but are not limited to, statements relating to:

| • | the condition of the debt and equity capital markets and our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward;

| • | the ability of our counterparties, including Pemex, to satisfy their financial commitments or business obligations and our ability to seek new counterparties in a competitive market;

| • | government regulation, including compliance with regulatory and permit requirements and changes in tax laws, market rules, rates, tariffs, environmental laws and policies affecting renewable energy;

| • | changes in tax laws and regulations;

| • | risks relating to our activities in areas subject to economic, social and political uncertainties;

| • | our ability to finance and consummate new investments and acquisitions on favorable terms or to close outstanding acquisitions, including PTS;

| • | risks relating to new assets and businesses which have a higher risk profile and our ability to transition these successfully;

| • | potential environmental liabilities and the cost and conditions of compliance with applicable environmental laws and regulations;

| • | risks related to our reliance on third-party contractors or suppliers;

| • | risks related to our ability to maintain appropriate insurance over our assets;

| • | risks related to our exposure in the labor market;

| • | potential issues arising with our operators’ employees including disagreement with employees’ unions and subcontractors;

| • | risks related to extreme weather events related to climate change could damage our assets or result in significant liabilities and cause an increase in our operation and maintenance costs;

| • | the effects of litigation and other legal proceedings (including bankruptcy) against us and our subsidiaries;

| • | price fluctuations, revocation and termination provisions in our off-take agreements and power purchase agreements;

| • | our electricity generation, our projections thereof and factors affecting production, including those related to the COVID-19 outbreak;

| • | our targets or expectations with respect to Adjusted EBITDA derived from low-carbon footprint assets;

| • | risks related to our relationship with Abengoa, our former largest shareholder and currently one of our operation and maintenance suppliers, including bankruptcy and particularly the potential impact of Abengoa S.A.’s insolvency filing and Abenewco1, S.A.’s potential insolvency filing;

| • | risks related to our relationship with our shareholders, including Algonquin, our major shareholder;

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| • | potential impact of the COVID-19 outbreak on our business, financial condition, results of operations and cash flows;

| • | reputational and financial damage caused by our off-taker PG&E and Pemex;

| • | sale of electricity to the Mexican market;

| • | guidance related to amount of Adjusted EBITDA from low carbon footprint assets and

| • | other factors discussed under “Risk Factors”.

Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances, including, but not limited to, unanticipated events, after the date on which such statement is made, unless otherwise required by law. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement.
CURRENCY PRESENTATION AND DEFINITIONS
In this annual report, all references to “U.S. dollar,” “$” and “USD” are to the lawful currency of the United States, all references to “euro,” “€” or “EUR” are to the single currency of the participating member states of the European and Monetary Union of the Treaty Establishing the European Community, as amended from time to time and all references to “South African rand,” “R” and “ZAR” are to the lawful currency of the Republic of South Africa.
Unless otherwise specified or the context requires otherwise in this annual report:

| • | references to “2019 Notes” refer to the 7.000% Senior Notes due 2019 in an aggregate principal amount of $255 million issued on November 17, 2014, as further described in “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2019 Notes”;

| • | references to “2020 Green Private Placement” refer to the €290 million (approximately $354 million) senior secured notes maturing in June 20, 2026 which were issued under a senior secured note purchase agreement entered with a group of institutional investors as purchasers of the notes issued thereunder as further described in “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2020 Green Private Placement;

| • | references to “AAGES” refer to the joint venture between Algonquin and Abengoa to invest in the development and construction of clean energy and water infrastructure contracted assets;

| • | references to “AAGES ROFO Agreement” refer to the agreement we entered into with AAGES on March 5, 2018, which became effective upon completion of the Share Sale, that provides us a right of first offer to purchase any of the AAGES ROFO Assets, as amended and restated from time to time;

| • | references to “Abengoa” refer to Abengoa, S.A., together with its subsidiaries, or Abenewco1, S.A. together with its subsidiaries, unless the context otherwise requires;

| • | references to “ACS” refer to ACS Group;

| • | references to “ACT” refer to the gas-fired cogeneration facility located inside the Nuevo Pemex Gas Processing Facility near the city of Villahermosa in the State of Tabasco, Mexico;

| • | references to “Algonquin” refer to, as the context requires, either Algonquin Power & Utilities Corp., a North American diversified generation, transmission and distribution utility, or Algonquin Power & Utilities Corp. together with its subsidiaries;

| • | references to “Algonquin ROFO Agreement” refer to the agreement we entered into with Algonquin on March 5, 2018, which became effective upon completion of the Share Sale, under which Algonquin granted us a right of first offer to purchase any of the assets offered for sale located outside of the United States or Canada as amended from time to time. See “Item 7.B—Related Party Transactions—Algonquin drop down agreement and Right of First Offer on assets outside the United States or Canada”;

| • | references to “Amherst Island Partnership” or AIP refer to the holding company of Windlectric Inc;

| • | references to “Annual Consolidated Financial Statements” refer to the audited annual consolidated financial statements as of December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018, including the related notes thereto, prepared in accordance with IFRS as issued by the IASB (as such terms are defined herein), included in this annual report;

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| • | references to “ASI Operations” refer to ASI Operations LLC;

| • | references to “Atlantica” refer to Atlantica Sustainable Infrastructure plc and, where the context requires, Atlantica Sustainable Infrastructure plc together with its consolidated subsidiaries;

| • | references to “Atlantica Jersey” refer to Atlantica Sustainable Infrastructure Jersey Limited, a wholly-owned subsidiary of Atlantica;

| • | references to “ATN” refer to ATN S.A., the operational electronic transmission asset in Peru, which is part of the Guaranteed Transmission System;

| • | references to “ATS” refer to ABY Transmision Sur S.A.;

| • | references to “AYES Canada” refer to Atlantica Sustainable Infrastructure Energy Solutions Canada Inc., a vehicle formed by Atlantica and Algonquin to channel co-investment opportunities;

| • | references to “Befesa Agua Tenes” refer to Befesa Agua Tenes, S.L.U;

| • | references to “cash available for distribution” or CAFD refer to the cash distributions received by the Company from its subsidiaries minus cash expenses of the Company, including third-party debt service and general and administrative expenses;

| • | references to “Calgary District Heating” refer to the district heating asset in Canada, which we agreed to acquire in the fourth quarter of 2020 for a total equity investment of approximately $20 million, subject to conditions precedent and regulatory approvals;

| • | references to “Chile PV 1” refer to the solar PV plant of 55 MW located in Chile;

| • | references to “Chile PV 2” refer to the solar PV plant of 40 MW located in Chile;

| • | references to “CNMC” refer to Comision Nacional de los Mercados y de la Competencia, the Spanish state-owned regulator;

| • | references to “COD” refer to the commercial operation date of the applicable facility;

| • | references to “Coso” refer to the 135 MW geothermal plant located in California, which we agreed to acquire in December 2020, subject to customary conditions.;

| • | references to “DOE” refer to the U.S. Department of Energy;

| • | references to “DTC” refer to The Depository Trust Company;

| • | references to “EMEA” refer to Europe, Middle East and Africa;

| • | references to “EPACT” refer to the Energy Policy Act of 2005;

| • | references to “EPC” refer to engineering, procurement and construction;

| • | references to “EURIBOR” refer to Euro Interbank Offered Rate, a daily reference rate published by the European Money Markets Institute, based on the average interest rates at which Eurozone banks offer to lend unsecured funds to other banks in the euro wholesale money market;

| • | references to “EU” refer to the European Union;

| • | references to “Exchange Act” refer to the U.S. Securities Exchange Act of 1934, as amended, or any successor statute, and the rules and regulations promulgated by the SEC thereunder;

| • | references to “Federal Financing Bank” refer to a U.S. government corporation by that name;

| • | references to “Fitch” refer to Fitch Ratings Inc.;

| • | references to “FPA” refer to the U.S. Federal Power Act;

| • | references to “Adjusted EBITDA” have the meaning set forth in “Presentation of Financial Information—Non-GAAP Financial Measures” in the section below;

| • | references to “Green Project Finance” refer to the green project financing agreement entered into between Logrosan, the sub-holding company of Solaben 1 & 6 and Solaben 2 & 3, as borrower, and ING Bank, B.V. and Banco Santander S.A., as lenders, as further described in “Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources of Liquidity—Green Project Finance”;

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| • | references to “gross capacity” refers to the maximum, or rated, power generation capacity, in MW, of a facility or group of facilities, without adjusting for the facility’s power parasitics’ consumption, or by our percentage of ownership interest in such facility as of the date of this annual report;

| • | references to “GWh” refer to gigawatt hour;

| • | references to “IFRIC 12” refer to International Financial Reporting Interpretations Committee’s Interpretation 12—Service Concessions Arrangements;

| • | references to “IFRS as issued by the IASB” refer to International Financial Reporting Standards as issued by the International Accounting Standards Board;

| • | references to “IPO” refer to our initial public offering of ordinary shares in June 2014;

| • | references to “IRC” refer to the Internal Revenue Code of 1986;

| • | references to “ITC” refer to investment tax credits;

| • | references to “JIBAR” refer to Johannesburg Interbank Average Rate;

| • | references to “La Sierpe” refer to the 20MW solar asset in Colombia to be acquired from Algonquin. by mid-2021, subject to customary conditions;

| • | references to “LIBOR” refer to London Interbank Offered Rate;

| • | references to “Logrosan” refer to Logrosan Solar Inversiones, S.A.;

| • | references to “Lost time injury rate” refer to the total number of recordable accidents with leave (lost time injury) recorded in the last 12 months per two hundred thousand worked hours;

| • | references to “LTIP” refer to the long-term incentive plans approved by the Board of Directors.

| • | references to “MACRS” refer to the Modified Accelerated Cost Recovery System;

| • | references to “Monterrey” refer to the 142 MW gas-fired engine facility including 130 MW installed capacity and 12 MW battery capacity, located in, Monterrey, Mexico;

| • | references to “Multinational Investment Guarantee Agency” refer to Multinational Investment Guarantee Agency, a financial institution member of the World Bank Group which offers political insurance and credit enhancement guarantees;

| • | references to “MW” refer to megawatts;

| • | references to “MWh” refer to megawatt hour;

| • | references to “Moody’s” refer to Moody’s Investor Service Inc.;

| • | references to “NEPA” refer to the National Environment Policy Act;

| • | references to “NOL” refer to net operating loss;

| • | references to “Note Issuance Facility 2017” refer to the senior secured note facility dated February 10, 2017, of €275 million (approximately $336 million), with Elavon Financial Services DAC, UK Branch, as facility agent and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder;

| • | references to “Note Issuance Facility 2020” refer to the senior unsecured note facility dated July 8, 2020, of €140 million (approximately $171 million), with Lucid Agency Services Limited, as facility agent and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder;

| • | references to “O&M” refer to operation and maintenance services provided at our various facilities;

| • | references to “operation” refer to the status of projects that have reached COD (as defined above);

| • | references to “Pemex” refer to Petróleos Mexicanos;

| • | references to “PFIC” refer to passive foreign investment company within the meaning of Section 1297 of the IRC;

| • | references to “PG&E” refer to PG&E Corporation and its regulated utility subsidiary, Pacific Gas and Electric Company collectively;

| • | references to “PPA” refer to the power purchase agreements through which our power generating assets have contracted to sell energy to various off-takers;

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| • | references to “PTC” refer to production tax credits;

| • | references to “PTS” refer to Pemex Transportation System;

| • | references to “Registrar” refer to The Bank of New York Mellon;

| • | references to “Revolving Credit Facility” refers to the credit and guaranty agreement with a syndicate of banks entered into on May 10, 2018 and amended on January 24, 2019, August 2, 2019, December 17, 2019 and August 28, 2020, providing for a senior secured revolving credit facility in an aggregate principal amount of $425 million;

| • | references to “Rioglass” refer to Rioglass Solar Holding, S.A.;

| • | references to “ROFO” refer to a right of first offer;

| • | references to “ROFO agreements” refer to the AAGES ROFO Agreement and Algonquin ROFO Agreement;

| • | references to “RPS” refer to renewable portfolio standards adopted by 29 U.S. states and the District of Columbia that require a regulated retail electric utility to procure a specific percentage of its total electricity delivered to retail customers in the respective state from eligible renewable generation resources, such as solar or wind generation facilities, by a specific date;

| • | references to “RRRE” refer to the Specific Remuneration System Register in Spain;

| • | references to “Share Sale” refer to the sale by Abengoa to Algonquin of 25% of our ordinary shares pursuant to an agreement for the sale that was entered into in November 2017;

| • | references to the “Shareholders’ Agreement” refer to the agreement by and among Algonquin Power & Utilities Corp., Abengoa-Algonquin Global Energy Solutions and Atlantica Sustainable Infrastructure plc, dated March 5, 2018, as amended, which became effective upon completion of the Share Sale;

| • | references to “Solaben Luxembourg” refer to Solaben Luxembourg S.A;

| • | references to “Solnova 1, 3 & 4” refer to a 150 MW concentrating solar power facility wholly owned by Atlantica Sustainable Infrastructure, located in the municipality of Sanlucar la Mayor, Spain;

| • | references to “S&P” refer to S&P Global Rating;

| • | references to “Tenes” refer to the water desalination plant in Algeria, which is 51% owned by Befesa Agua Tenes;

| • | references to “Total-Record Incident” refer to the total number of recordable accidents with and without leave (lost time injury) recorded in the last 12 months per two hundred thousand worked hours;

| • | references to “U.K.” refer to the United Kingdom;

| • | reference to “U.S.” or “United States” refer to the United States of America;

| • | references to “we,” “us,” “our,” “Atlantica” and the “Company” refer to Atlantica Sustainable Infrastructure plc and its subsidiaries, unless the context otherwise requires.

PRESENTATION OF FINANCIAL INFORMATION
The financial information as of December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018 is derived from, and qualified in its entirety by reference to, our Annual Consolidated Financial Statements, which are included elsewhere in this annual report and prepared in accordance with IFRS as issued by the IASB.
Certain numerical figures set out in this annual report, including financial data presented in millions or thousands and percentages describing market shares, have been subject to rounding adjustments, and, as a result, the totals of the data in this annual report may vary slightly from the actual arithmetic totals of such information. Percentages and amounts reflecting changes over time periods relating to financial and other data set forth in “Item 5.A—Operating and Financial Review and Prospects—Operating Results” are calculated using the numerical data in our Annual Consolidated Financial Statements or the tabular presentation of other data (subject to rounding) contained in this annual report, as applicable, and not using the numerical data in the narrative description thereof.
Non-GAAP Financial Measures
This annual report contains non-GAAP financial measures including Adjusted EBITDA.
Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements.
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Until December 31, 2019, we reported Further Adjusted EBITDA as one of our key metrics. Further Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and dividends received from our preferred equity investment in ACBH until 2017. We no longer report Further Adjusted EBITDA because the Company has not received dividends from our preferred equity investment in ACBH during the period under review or in any of the comparable periods. ACBH was Abengoa Concessões Brasil Holding, a subsidiary holding company of Abengoa that was engaged in the development, construction, investment and management of concessions in Brazil, comprised mostly of transmission lines and which is currently undergoing a restructuring process in Brazil.
Our management believes Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. This measure is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. This measure is widely used by other companies in our industry.
Our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.
We present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity. The non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under IFRS as issued by the IASB. Non-GAAP financial measures and ratios are not measurements of our performance or liquidity under IFRS as issued by the IASB and should not be considered as alternatives to operating profit or profit for the year or any other performance measures derived in accordance with IFRS as issued by the IASB or any other generally accepted accounting principles or as alternatives to cash flow from operating, investing or financing activities.
Some of the limitations of these non-GAAP measures are:

| • | they do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

| • | they do not reflect changes in, or cash requirements for, our working capital needs;

| • | they may not reflect the significant interest expense, or the cash requirements necessary, to service interest or principal payments, on our debts;

| • | although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often need to be replaced in the future and Adjusted EBITDA does not reflect any cash requirements that would be required for such replacements; and

| • | the fact that other companies in our industry may calculate Adjusted EBITDA differently than we do, which limits their usefulness as comparative measures.

PRESENTATION OF INDUSTRY AND MARKET DATA
In this annual report, we rely on, and refer to, information regarding our business and the markets in which we operate and compete. The market data and certain economic and industry data and forecasts used in this annual report were obtained from internal surveys, market research, governmental and other publicly available information, independent industry publications and reports prepared by industry consultants. We believe that these industry publications, surveys and forecasts are reliable, but we have not independently verified them, and there can be no assurance as to the accuracy or completeness of the included information.
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Certain market information and other statements presented herein regarding our position relative to our competitors are not based on published statistical data or information obtained from independent third parties but reflect our best estimates. We have based these estimates upon information obtained from our customers, trade and business organizations and associations and other contacts in the industries in which we operate.
Elsewhere in this annual report, statements regarding our contracted assets and concessions activities, our position in the industries and geographies in which we operate are based solely on our experience, our internal studies and estimates and our own investigation of market conditions.
All of the information set forth in this annual report relating to the operations, financial results or market share of our competitors has been obtained from information made available to the public in such companies’ publicly available reports and independent research, as well as from our experience, internal studies, estimates and investigation of market conditions. We have not funded, nor are we affiliated with, any of the sources cited in this annual report. We have not independently verified the information and cannot guarantee its accuracy.
All third-party information, as outlined above, has to our knowledge been accurately reproduced and, as far as we are aware and are able to ascertain, no facts have been omitted which would render the reproduced information inaccurate or misleading, but there can be no assurance as to the accuracy or completeness of the included information.
PART I

ITEM 1. | IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.

ITEM 2. | OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3 | KEY INFORMATION

B. | Capitalization and Indebtedness

Not applicable.

C. | Reasons for the Offer and Use of Proceeds

Not applicable.
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D. | Risk Factors

Investing in our securities involves a high degree of risk. You should carefully consider the risks and uncertainties described below, together with the other information contained in this annual report, including our Annual Consolidated Financial Statements and related notes, included elsewhere in this annual report, before making any investment decision. The risks described below may not be the only risks we face. We have described only those risks that we currently consider to be material and there may be additional risks that we do not currently consider to be material or of which we are not currently aware. Any of the following risks and uncertainties could have a material adverse effect on our business, prospects, results of operations and financial condition. The market price of our securities could decline due to any of these risks and uncertainties, and you could lose all or part of your investment.
Risk Factor Summary
Set forth below is only a summary of the principal risks associated with an investment in our shares:
Risks Related to Our Business and Our Assets

• | Our failure to maintain safe work environments may expose us to significant financial losses, as well as civil and criminal liabilities.

• | Our off-takers may not fulfill their obligations and, as our off-take agreements expire, we may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which we operate.

• | The concession agreements or power purchase agreements under which we conduct some of our operations are subject to revocation, termination or tariff reduction.

• | The performance of our assets under our PPAs or concession contracts may be adversely affected by problems, mainly including those related to our reliance on third-party contractors and suppliers.

• | Supplier concentration may expose us to significant financial credit or performance risk.

• | Certain of our facilities may not perform as expected.

• | Maintenance, expansion and refurbishment of our electric generation and other facilities involve significant risks that could result in unplanned power outages or reduced output or availability.

• | Our business may be adversely affected by an increased number of extreme and chronic weather events related to climate change.

• | The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.

• | Our business may be adversely affected by catastrophes, natural disasters, unexpected geological or other physical conditions, or criminal or terrorist acts at one or more of our plants, facilities and electric transmission lines.

Risks Related to the COVID-19 Pandemic

• | The outbreak of COVID-19 could have a material adverse impact on our business, financial condition, liquidity, results of operations, cash flows, cash available for distribution and ability to make cash distributions to our shareholders.

Risks Related to Our Relationship with Algonquin and Abengoa

• | Algonquin is our largest shareholder and exercises substantial influence over us.

• | Our ownership structure and certain service agreements may create significant conflicts of interest that may be resolved in a manner that is not in our best interests.

• | If Abengoa defaults on certain of its debt obligations, including as a result of the recent insolvency filing by their holding company Abengoa S.A., we could potentially be in default of certain of our project financing agreements.

• | Abengoa’s financial condition, including the insolvency filing of Abengoa, S.A., could affect its ability to satisfy its obligations with us under different agreements, including operation and maintenance agreements as well as indemnities and other contracts in place, and may affect our reputation.

• | Abengoa S.A. (the holding company) has filed for insolvency and it or any of its subsidiaries may be forced to file for bankruptcy under the Spanish Insolvency Act and, as a result, it may be subject to insolvency claw-back actions, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks Related to Our Indebtedness

• | Our indebtedness could limit our ability to react to changes in the economy or our industry, expose us to the risk of increased interest rates and limit our activities due to covenants in existing financing agreements. It could also adversely affect our ability to make distributions from the project subsidiaries to Atlantica, and our ability to fund operations, pay dividends or raise additional capital.

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• | We may be unable to refinance or replace our existing indebtedness or repay our existing debt as it becomes due.

• | We may not be able to arrange the required or desired financing for acquisitions and for the successful refinancing of the Company’s project level and corporate level indebtedness.

• | We may be subject to increased finance expenses if we do not effectively manage our exposure to interest rate and foreign currency exchange rate risks.

• | Potential future defaults by our subsidiaries, our off-takers, our suppliers, Abengoa or other persons could adversely affect us.

• | Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR in the future may adversely affect the value of any outstanding debt instruments.

• | A change of control or a delisting of our shares may have negative implications for us.

Risks Related to Our Growth Strategy

• | We may not be able to identify or consummate future investments and acquisitions on favorable terms, or at all.

• | In order to grow our business, we may invest in or acquire assets or businesses which have a higher risk profile or are less ESG-friendly than certain assets in our current portfolio.

• | We cannot guarantee the success of our recent and future acquisitions.

• | Our cash dividend policy may limit our ability to grow and make acquisitions through cash on hand.

Risks Related to the Markets in Which We Operate

• | Difficult conditions in the global economy and in the global capital markets have caused, and may continue to cause, a sharp reduction in worldwide demand for our products and services

• | We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.

• | We are exposed to political, social and macroeconomic risks relating to the United Kingdom’s exit from the European Union.

Risks Related to Regulation

• | We are subject to extensive governmental regulation in a number of different jurisdictions, and our inability to comply with existing regulations or requirements or changes in applicable regulations or requirements may have a negative impact on our business, financial condition, results of operations and cash flows.

• | Our business is subject to stringent environmental regulation.

• | Government regulations could change at any time and such changes may negatively impact our current business and our growth strategy.

• | Revenues in certain of our assets are mainly defined by regulation and some of the parameters defining the remuneration are subject to review.

• | Our international operations require us to comply with anti-corruption and other laws and regulations of the United States government and various non-U.S. jurisdictions.

Risks Related to Ownership of Our Shares

• | We may not be able to pay a specific or increasing level of cash dividends to holders of our shares in the future.

• | Future sales of our shares by Algonquin or its lenders or by other substantial shareholders may cause the price of our shares to fall.

Risks Related to Taxation

• | Changes in our tax position can significantly affect our reported earnings and cash flows.

• | Our future tax liability may be greater than expected if we do not use sufficient NOLs to offset our taxable income.

• | Our ability to use U.S. NOLs to offset future income may be limited.

• | Distributions to U.S. Holders of our shares may be fully taxable as dividends.

• | If we are a passive foreign investment company for U.S. federal income tax purposes for any taxable year, U.S. Holders of our shares could be subject to adverse U.S. federal income tax consequences.

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| I. | Risks Related to Our Business and Our Assets

Our failure to maintain safe work environments may expose us to significant financial losses, as well as civil and criminal liabilities.
The facilities we operate often put our employees and others, including those of our subcontractors, in close proximity with large pieces of mechanized equipment, moving vehicles, manufacturing or industrial processes, heat or liquids stored under pressure and highly regulated materials. On most projects and at most facilities, we, together in some cases with the operation and maintenance supplier, are responsible for safety. Accordingly, we must implement safe practices and safety procedures, which are also applicable to on-site subcontractors. If we or the operation and maintenance supplier fail to design and implement such practices and procedures or if the practices and procedures are ineffective or if our operation and maintenance service providers or other suppliers do not follow them, our employees and others may become injured, and we may incur civil or criminal liabilities. Unsafe work sites also have the potential to increase employee turnover, increase the cost of a project to our customers or the operation of a facility, and raise our operating costs. Any of the foregoing could result in reputational damage and/or financial losses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, our projects and the operation of our facilities can involve the handling of hazardous and other highly regulated materials, which, if improperly handled or disposed of, could subject us or our suppliers to civil and criminal liabilities. We are also subject to regulations dealing with occupational health and safety. Although we maintain divisions whose primary purpose is to ensure we implement effective health, safety and environmental work procedures throughout our organization, the failure to comply with such regulations could subject us to reputational damage and/or liability. In addition, we may incur liability based on allegations of illness or disease resulting from exposure of employees or other persons to hazardous materials or equipment that we handle or are present in our workplaces.
Counterparties to our off-take agreements may not fulfill their obligations and, as our contracts expire, we may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which we operate.
A significant portion of the electric power we generate, the transmission capacity we have, and our desalination capacity is sold under long-term off-take agreements with public utilities, industrial or commercial end-users or governmental entities, with a weighted average remaining duration of approximately 17 years as of December 31, 2020.
If, for any reason, including, but not limited to, a deterioration in their financial situation or bankruptcy, any of our clients are unable or unwilling to fulfill their related contractual obligations or if they refuse to accept delivery of power delivered thereunder or if they otherwise terminate such agreements prior to the expiration thereof, or if prices were re-negotiated under a bankruptcy situation, or if they delayed payments, our assets, liabilities, business, financial condition, results of operations and cash flow may be materially adversely affected. Furthermore, to the extent any of our power, transmission capacity or desalination capacity purchasers are, or are controlled by, governmental entities, our facilities may be subject to sovereign risk or legislative or other political action that may hamper their contractual performance.
On January 29, 2019, PG&E, the off-taker for Atlantica with respect to the Mojave plant, filed for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of California. PG&E paid all invoices corresponding to the electricity delivered after January 28, 2019. Since PG&E failed to assume the PPA within 180 days from the commencement of PG&E’s Chapter 11 proceeding, a technical event of default was triggered under our Mojave project finance agreement in July 2019. On July 1, 2020, PG&E emerged from Chapter 11 and in accordance with the plan of reorganization, assumed the Mojave PPA and paid to Mojave the portion of the invoice corresponding to the electricity delivered for the period between January 1 and January 28, 2019. This invoice was overdue because the services related to the prepetition period and any payment therefore required the approval by the Bankruptcy Court. Therefore, the technical event of default under our Mojave project finance agreement, which was preventing cash distributions from Mojave to Atlantica, was cured and we can make distributions from Mojave.
The credit rating of Eskom has weakened and is currently CCC+ from S&P Global Rating (“S&P”), Caa1 from Moody’s Investor Service Inc. (“Moody’s”) and B from Fitch Ratings Inc. (“Fitch”). Eskom is the off-taker of our Kaxu solar plant, a state-owned, limited liability company, wholly owned by the government of the Republic of South Africa. Eskom’s payment guarantees to our Kaxu solar plant are underwritten by the South African Department of Energy, under the terms of an implementation agreement. The credit ratings of the Republic of South Africa have also weakened and as of the date of this report are BB/Ba2/BB- by S&P, Moody’s and Fitch, respectively.
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In addition, Pemex’s credit rating has also weakened and is currently BBB from S&P, Ba2 from Moody’s and BB- from Fitch. We have been experiencing significant delays from Pemex in collections since the second half of 2019.
The cost of renewable energy has considerably decreased over the past years, becoming a consistently competitive source of power generation compared to traditional fossil fuels in many regions, and it is expected to continue falling in the future. In addition, there has been an increase in the number of players and competition in the renewable energy space in the last few years, industrial companies and other independent power producers as well as large infrastructure funds and other financial players. The reduction in the cost of renewable energy and the intense competition has contributed to a reduction in electricity prices paid by the off-takers. In light of these market conditions, our off-takers may try to renegotiate or terminate our PPAs, most of which were signed several years ago and may be more expensive than recent PPAs or than current market prices. In addition, we may not be able to replace an expiring or terminated agreement with an agreement on equivalent terms and conditions, including at prices that permit operation of the related facility on a profitable basis. In addition, we believe that many of our competitors have well-established relationships with our current and potential suppliers, lenders and customers and have extensive knowledge of our target markets. As a result, these competitors may be able to respond more quickly to evolving industry standards and changing customer requirements than us. Adoption of technology more advanced than our own could reduce the power production costs of our competitors, resulting in their having a lower cost structure than is achievable with the technologies we currently employ and adversely affect our ability to compete for off-take agreement renewals. If we are unable to replace an expiring or terminated off-take agreement, the affected facility may temporarily or permanently cease operations.
Our inability to enter into new or replacement off-take agreements or to compete successfully against current and future competitors in the markets in which we operate may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The concession agreements or power purchase agreements under which we conduct some of our operations are subject to revocation, termination or tariff reduction.
Certain of our operations are conducted pursuant to contracts and concessions granted by various governmental bodies and others are pursuant to power purchase agreements signed with governmental entities and private clients. Generally, these contracts and concessions give us rights to provide services for a limited period, subject to various governmental regulations. The governmental bodies or private clients responsible for regulating and monitoring these services often have broad powers to monitor our compliance with the applicable concession and power purchase contracts and can require us to supply them with technical, administrative and financial information. Among other obligations, we may be required to comply with operating targets and efficiency and safety standards established in the concession. Such commitments and standards may be amended in certain cases by the governmental bodies. Our failure to comply with the concession agreements and power purchase agreements or other regulatory requirements may result in contracts and concessions being revoked, not being granted, upheld or renewed in our favor, or, if granted, upheld or renewed, may not be done on as favorable terms as currently applicable. In addition, in some cases our off-takers have an option to acquire the asset or to terminate the concession agreement in exchange for a compensation. All the above could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, in some cases, if we fail to comply with certain pre-established conditions, the government or customer (as applicable) may reduce the tariffs or rates payable to us. In addition, during the life of a concession, the relevant government authority may in some cases unilaterally impose additional restrictions on our tariff rates, subject to the regulatory frameworks applicable in each jurisdiction. In some cases, governments may also postpone annual tariff increases until a new tariff structure is approved without compensating us for lost revenue. Furthermore, changes in laws and regulations may, in certain cases, have retroactive effect and expose us to additional compliance costs or interfere with our existing financial and business planning.
The performance of our assets under our PPAs or concession contracts may be adversely affected by problems including those related to our reliance on third-party contractors and suppliers.
Our projects rely on the supply of services, equipment, including technologically complex equipment and software which we subcontract in some cases to third-party suppliers in order to meet our contractual obligations under our concessions. In circumstances where key components of our equipment, including but not limited to turbines, water pumps, heat exchangers, transformers or electrical generators fail because of design failures or faulty operation or for any other reason, we rely on third parties to continue operating our assets. Equipment may not last as long as expected and we may need to replace it earlier than planned. Damages to our equipment may not be covered by insurance in place. In some cases, the replacement of damaged equipment can take a long period of time, which can cause our plants to curtail or cease operations during such time, which could have a negative impact on our business, financial condition, results of operations and cash flows.
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For example, Solana and Kaxu have experienced technical issues in their storage systems. Repairs have been carried out in both assets. In Solana, availability in the storage system was lower than expected in 2020 due to certain leaks identified in the storage system in the first quarter of 2020. Improvements and equipment replacements are required over time, have impacted production in 2020 and will continue to impact production in 2021, with the exact scope and timing of repairs subject to review. Solana has a cash repair reserve account funded with approximately $54 million that we expect to use partially or totally for this purpose. However, we cannot guarantee that the repairs will be effective or that additional repairs will not be required. Similar interruptions could happen again at our plants due to failures in key equipment. Design failures, technical inspections by suppliers or the need to replace key equipment can require unexpected capital expenditures and/or outages in our plants, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, the delivery of products or services which are not in compliance with the requirements of the subcontract, or the late supply of products and services, can cause us to be in default under our contracts with our concession counterparties. To the extent we are not able to transfer all of the risk or be fully indemnified by third-party contractors and suppliers, we may be subject to a claim by our customers as a result of a problem caused by a third party that could have a material adverse effect on our reputation, business, results of operations, financial condition and cash flows.
Supplier concentration may expose us to significant financial credit or performance risk.
We often rely on a single contracted supplier or a small number of suppliers for the provision of certain personnel, spare parts, equipment, technology, fuel, transportation of fuel, and/or other services required for the operation of certain of our facilities. If any of these suppliers, including Abengoa, Siemens, GE, Rioglass or Nordex, cannot or will not perform under their operation and maintenance and other agreements with us, or satisfy their related warranty obligations, including as a result of insolvency or bankruptcy, we will need to access the marketplace to provide or repair these products and services. There can be no assurance that the marketplace can provide these products and services as, when and where required. We may not be able to enter into replacement agreements on favorable terms or at all. If we are unable to enter into replacement agreements to provide for equipment, technology or fuel and other required services, we may be required to seek to purchase the related goods or services at higher prices. We may also be required to make significant capital contributions to remove, replace or redesign equipment that cannot be supported or maintained by replacement suppliers, which may have a material adverse effect on our credit support terms, business, financial condition, results of operations, and cash flows.
The failure of any supplier or customer to fulfill its contractual obligations to us may have a material adverse effect on our business, financial condition, results of operations and cash flows. Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, our suppliers and vendors.
Certain of our facilities may not perform as expected.
Our expectations regarding the operating performance of certain assets in our portfolio, particularly Solana and Kaxu, assets recently acquired such as Chile PV 2, Chile PV 1, Tenes and assets for which acquisition has recently been announced and closing is still pending such as Calgary District Heating, La Sierpe and Coso, are based on assumptions, estimates and past experience, and without the benefit of a substantial operating history under our control. Our projections regarding our ability to generate cash available for distribution assumes facilities perform in accordance to our expectations. However, the ability of these facilities to meet our performance expectations is subject to the risks inherent in power generation facilities and the construction of such facilities, including, but not limited to, degradation of equipment in excess of our expectations, system failures and outages. The failure of these facilities to perform as we expect may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Maintenance, expansion and refurbishment of electric generation and other facilities involve significant risks that could result in unplanned power outages or reduced output or availability.
The facilities in our portfolio may require periodic upgrading and improvement in the future. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce the performance and availability of our facilities below expected levels, reducing our revenues. Degradation of the performance of our solar facilities above levels provided for in the related off-take agreements may also reduce its revenues. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facilities may also reduce profitability.
If we make any major modifications to our efficient natural gas or renewable power generation facilities or electric transmission lines, we may be required to comply with more stringent environmental regulations, which would likely result in substantial additional capital expenditures. We may also choose to repower, refurbish or upgrade our facilities based on our assessment that such activity will provide adequate financial returns. Such facilities require time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. This may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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Our business may be adversely affected by an increased number of extreme and chronic weather events related to climate change.
Climate change is causing an increasing number of severe and extreme weather events which are a risk to our facilities, including days of extremely high temperatures, severe winds and rains, hurricanes, droughts, fires, cyclones, hail and floods, among others. These risks include:

| • | Rising temperatures are also increasing the frequency and intensity of droughts and risk of fire. For example, in California, the size and ferocity of fires has increased significantly in the past 20 years, which have also been very hot and dry years. California wildfires have been especially catastrophic, causing human fatalities and significant material losses. Our transmission lines, including transmission lines and substations which are part of our solar assets, could cause fires. Therefore, they could create significant liabilities if the fire damaged third parties.

| • | Severe floods could damage our plants, especially our transmission lines or our generation assets. If an unexpected flood runs close to an existing transmission tower it could cause the fall of one or more transmission towers. Similarly, floods can damage the solar field in our solar plants.

| • | Severe winds could cause damage in the solar fields at our solar assets. In 2016, the solar field of Solana was damaged by a wind micro-burst and similar events could happen in the future in our assets.

| • | Severe droughts could result in water restrictions or in a deterioration to the properties of water. Droughts may affect the cooling capacity of our power projects. A deterioration of the quality of the water would have an impact on chemical costs in our water treatment plants within our generation facilities.

| • | Changes in temperature extremes could also affect the water quality in desalination plants, causing an increase of the chemical products consumption and generating a risk of growth of algae and mollusks within the facilities.

| • | Storms with intense lightning activity could damage our plants, especially our wind assets. Our wind farms in Uruguay have already experienced some damage in the past and our assets could be affected again.

Furthermore, components of our system, such as structures, mirrors, absorber tubes, blades, PV panels or transformers are susceptible to being damaged by severe weather, including for example by hail or lightning. In addition, replacement and spare parts for key components may be difficult or costly to acquire or may be unavailable and may have long lead times.
In addition, our business may be adversely affected by rising mean temperatures caused by climate change. Rising temperatures could cause an increase in our operation and maintenance costs. Rising temperatures are associated to the reduction of the cycle efficiency of our turbines. A temperature rise above a certain threshold would also reduce the efficiency of our solar photovoltaic modules. When the temperature of the solar panel increases, its output current slightly increases while the voltage output is reduced on a linear basis, and therefore panel power production decreases. Likewise, a temperature rise would also have an impact in our wind facilities. Wind energy component is dependent on the air density among other factors. Our desalination plants could also be affected by a temperature increase that would imply higher consumption of chemicals used for operational purposes.
If any of these events were to occur at any of our plants, facilities or electric transmission lines, we may not be able to carry out our business activities at that location or such operations could be significantly reduced. Any of these circumstances could result in lost revenue at these sites during the period of disruption and costly remediation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.
The electricity produced, and revenues generated by a renewable energy generation facility are highly dependent on suitable solar or wind conditions, as applicable, and associated weather conditions, which are beyond our control.
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Unfavorable weather and atmospheric conditions could impair the effectiveness of our assets or reduce their output beneath their rated capacity or require shutdown of key equipment, hampering operation of our renewable assets and our ability to achieve forecasted revenues and cash flows.
We base our investment decisions with respect to each renewable generation facility on the findings of related wind and solar studies conducted on-site by third parties prior to construction or based on historical conditions at existing facilities. However, actual climatic conditions at a facility site, particularly wind conditions, which are sometimes severe, may not conform to the findings of these studies and therefore, our solar and wind energy facilities may not meet anticipated production levels or the rated capacity of its generation assets, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, in the case of Coso, the electricity produced, and revenues generated are dependent on the geothermal resource available. In December 2020 we reached an agreement to acquire Coso and closing is expected in the first half of 2021, subject to conditions precedent and regulatory approvals. Our investment decision was made based on the geothermal resource assessed and estimated by a geologist. Geothermal resource may not meet our expectations, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our business may be adversely affected by catastrophes, natural disasters, unexpected geological or other physical conditions, or criminal or terrorist acts at one or more of our plants, facilities and electric transmission lines.
If one or more of our plants, facilities or electric transmission lines were to be subject in the future to fire, flood, extreme weather conditions (including severe wind), earthquakes or other natural disaster, adverse weather conditions, drought, terrorism, power loss or other catastrophe, or if unexpected geological or other adverse physical conditions (including earthquakes) were to occur at any of our plants, facilities or electric transmission lines, we may not be able to carry out our business activities at that location or such operations could be significantly reduced. We own two assets in Southern California, which is an area classified as high seismic risk. Any of these circumstances could result in lost revenue at these sites during the period of disruption and costly remediation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, it is possible that our sites and assets could be affected by criminal or terrorist acts. There are also certain risks for which we may not be able to acquire adequate insurance coverage, including earthquakes. Any such events could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our insurance may be insufficient to cover relevant risks or the cost of our insurance may increase.
We cannot guarantee that our insurance coverage is, or will be, sufficient to cover all the possible losses we may face in the future. Our property damage and business interruption policy have significant deductibles and exclusions with respect to some key equipment which, if damaged, could result in financial losses and business interruptions. Moreover, insurance market terms and conditions have been becoming more and more onerous over the last few years and insurance companies are requiring some companies in our sector to retain a portion of the overall risks instead of transferring 100% of those risks to the insurers. As a result, we have self-retained a portion of our own risks and may need to increase this percentage in the future. If equipment failed in one of our assets and this equipment was part of the insurance exclusions or if the event was part of the risks that we have retained, we would need to assume the repairs and business interruption costs, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Furthermore, in some of our project finance arrangements and PPAs include specific conditions regarding insurance coverage that we may need to modify. If we did not obtain a waiver from our project finance lenders accepting these modifications, an event of default could be triggered by our lenders due to non-compliance with the terms of the project finance agreement. If we were to incur a serious uninsured loss or a loss that significantly exceeded the coverage limits established in our insurance policies or we were not able to modify coverage conditions, this could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, our insurance policies are subject to periodic renewals and the terms of the renewal are reviewed by our counterparties. If we were unable to renew our insurance, we would not be in compliance with the requirements of our project finance agreements and our PPAs, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. If insurance premiums were to increase in the future and/or if certain types of insurance coverage were to become unavailable or there was a further increase in deductibles for damages and/or loss of production, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Also, our insurance policies are subject to review by our counterparties. We may not be able to renew our insurance policies in the terms required by our power purchase agreements and project financing agreements, which could require a waiver from those parties. If insurance premiums were to increase in the future, if certain types of insurance coverage were to become unavailable or there was an increase in deductibles for damages and/or loss of production, it could have a material adverse effect on our ability to comply with our obligations to off-takers and lenders in our project finance agreements. In addition, we might not be able to maintain insurance coverage comparable to those that are currently in effect at comparable cost, or at all. If we were unable to pass any increase in insurance premiums on to our customers, such additional costs could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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We may have joint venture partners or other co-investors with whom we have material disagreements.
We have made and may continue to make equity investments in certain strategic assets managed by or together with third parties, including governmental entities and private entities. In certain cases, we may only have partial or joint control over a particular asset. We hold a minority stake in Honaine (Algeria), Monterrey (Mexico), Amherst (Canada) and Ten West Link (United States) and do not have control over the operation of these assets. In addition, we have partners in Seville PV, Solacor 1 & 2, Solaben 2 & 3, Skikda, Kaxu, Tenes, Chile PV 1 and Chile PV 2. Investments in assets over which we have no, partial or joint control are subject to the risk that the other shareholders of the assets, who may have different business or investment strategies than us or with whom we may have a disagreement or dispute, may have the ability to independently make or block business, financial or management decisions, such as appoint members of management, which may be crucial to the success of the project or our investment in the project, or otherwise implement initiatives which may be contrary to our interests. Additionally, the approval of other shareholders or partners may be required to sell, pledge, transfer, assign or otherwise convey our interest in such assets. Alternatively, other shareholders may have rights of first refusal or rights of first offer in the event of a proposed sale or transfer of our interests in such assets or in the event we acquire an interest in new assets pursuant to ROFO agreements with third parties. These restrictions may limit the price or interest level for our interests in such assets, in the event we want to sell such interests.
Finally, our partners in existing or future projects may be unable, or unwilling, to fulfill their obligations under the relevant shareholder agreements, may experience financial or other difficulties or might sell their position to third parties that we did not choose, which may adversely affect our investment in a particular joint venture or adversely affect us. In certain of our joint ventures, we may also rely on the expertise of our partners and, as a result, any failure to perform its obligations in a diligent manner could also adversely affect the joint venture. If any of the foregoing were to occur, our business, financial condition, results of operations and cash flows may be materially adversely affected.
The operation and maintenance of most of our assets is labor intensive, and therefore work stoppages by employees could harm our business.
The operation and maintenance of most of our assets is labor intensive and our operators’ employees and some of our employees in assets where we perform the operation and maintenance services are covered by collective bargaining agreements. A dispute with a union or employees represented by a union could result in production interruptions caused by work stoppages. In addition, we subcontract the operation and maintenance services in some of our assets. Abengoa is the operation and maintenance supplier in most of the assets for which we subcontract operation and maintenance services and Abengoa’s financial situation, including their recent insolvency filing, could cause a higher risk of dispute with their employees. If our operators’ employees were to initiate a work stoppage, they may not be able to reach an agreement with them as fast as in the case where we were negotiation with our own employees. If a strike or work stoppage or disruption were to occur, our business, financial conditions, results of operations and cash flows may be materially adversely affected.
Revenue from our renewable energy and efficient natural gas facilities is or may be partially exposed to market electricity prices.
Revenue and operating costs from certain of our existing or future projects depend to some extent on market prices for sale of electricity. Market prices may be volatile and are affected by various factors, including the cost of raw materials, user demand, and if applicable, the price of greenhouse gas emission rights. In several of the jurisdictions in which we operate, we are exposed to remuneration schemes which contain both regulated incentive and market price components. In such jurisdictions, the regulated incentive component may not compensate for fluctuations in the market price component, and, consequently, total remuneration may be volatile. There can be no assurance that market prices will remain at levels which enable us to maintain profit margins and desired rates of return on investment. A decline in market prices below anticipated levels could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Lack of electric transmission capacity availability, potential upgrade costs to the electric transmission grid, and other systems constraints could significantly impact our ability to generate electricity power sales and develop new projects.
We depend on electric interconnection and transmission facilities owned and operated by others to deliver the wholesale power we sell from our electric generation assets to our customers. A failure or delay in the operation or development of these interconnection or transmission facilities or a significant increase in the cost of the development of such facilities could result in the loss of revenues. Such failures or delays could limit the amount of power our operating facilities deliver or delay the completion of our construction projects, as the case may be. Additionally, such failures, delays or increased costs may have a material adverse effect on our business, financial condition, results of operations and cash flows. If a region’s electric transmission infrastructure is inadequate, our ability to generate electricity may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have a sufficient incentive to invest in expansion of transmission infrastructure. We cannot predict whether interconnection and transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. Certain of our operating facilities’ generation of electricity may be curtailed without compensation due to transmission limitations or limitations on the electricity grid’s ability to accommodate intermittent electricity generating sources, reducing our revenues and impairing our ability to fully capitalize on a particular facility’s generating potential. Such curtailments may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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We use information technology and communications systems to run our business, the failure of which could significantly impact our operations and business.
We are dependent upon information technology systems to run our operations. Our information technology systems are subject to disruption, damage or failure from a variety of sources, including, without limitation, computer viruses, security breaches, cyber-attacks, phishing attacks, natural disasters and design defects. Recently, energy facilities worldwide have been experiencing an increased number of cyber-attacks. Cybersecurity incidents, in particular, are constantly evolving and include malicious software, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in systems, unauthorized release of confidential or otherwise protected information and to the corruption of data. Various measures have been implemented to minimize our risks related to information technology systems and network disruptions. However, given the unpredictability of the timing, nature and scope of information technology disruptions, we could potentially be subject to production downtimes, operational delays, the compromising of confidential or otherwise protected information, destruction or corruption of data, security breaches, other manipulation or improper use of our systems and networks or financial losses from remedial actions, any of which could have a material adverse effect on our competitive position, financial condition, results of operations or cash flows.
We maintain global information technology and communication networks and applications to support our business activities. Information technology security processes may not prevent future malicious actions, denial-of-service attacks, or fraud, resulting in corruption of operating systems, theft of commercially sensitive data, misappropriation of funds and businesses (also known as phishing) and operational disruption. Material system breaches and failures could result in significant interruptions that could in turn affect our operating results and reputation.
Negative impacts on biodiversity, including harming of protected species or other environmental hazards can result in curtailment of power plant operations, monetary fines and negative publicity.
Managing and operating large infrastructure assets may have a negative impact on biodiversity in the regions where we operate. In particular, the operation of wind and solar power plants can adversely affect endangered, threatened or otherwise protected animal species. Wind power plants involve a risk that protected species will be harmed, as the turbine blades travel at a high rate of speed and may strike flying animals (such as birds or bats) that happen to travel into the path of spinning blades. Solar power plants can also present a risk to animals.
Excessive killing of protected species or other environmental accidents or hazards could result in requirements to implement mitigation strategies, including curtailment of operations, and/or substantial monetary fines and negative publicity. We cannot guarantee that any curtailment of operations, monetary fines that are levied or negative publicity as a result of incidental killing of protected species and other environmental hazards will not have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may be subject to litigation, other legal proceedings and tax inspections.
We are subject to the risk of legal claims and proceedings (including bankruptcy proceeding), requests for arbitration, tax inspections as well as regulatory enforcement actions in the ordinary course of our business and otherwise, including claims against our subsidiaries related to Abengoa or our subsidiaries not meeting their obligations. See “Item 4.B—Business Overview—Legal Proceedings.” The results of legal and regulatory proceedings or tax inspections cannot be predicted with certainty. We cannot guarantee that the results of current or future legal or regulatory proceedings, tax inspections or actions will not materially harm our operations, business, financial condition or results of operations, nor can we guarantee that we will not incur losses in connection with current or future legal or regulatory proceedings, tax inspections or actions that exceed any provisions we may have set aside in respect of such proceedings or actions or that exceed any available insurance coverage, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Item 4.B—Business Overview—Legal Proceedings.”
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If we are deemed to be an investment company, we may be required to institute burdensome compliance requirements and our activities may be restricted, which may make it difficult for us to complete strategic acquisitions or effect combinations.
If we were deemed to be an investment company under the Investment Company Act of 1940 (the “Investment Company Act”) our business would be subject to applicable restrictions under the Investment Company Act, which could make it impractical for us to continue our business as contemplated. We believe our company is not an investment company under Section 3(b)(1) of the Investment Company Act because we are primarily engaged in a noninvestment company business, and we intend to conduct our operations so that we will not be deemed an investment company. However, if we were to be deemed an investment company, restrictions imposed by the Investment Company Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated.

| II. | Risks Related to the COVID-19 Pandemic

The outbreak of COVID-19 could have a material adverse impact on our business, financial condition, liquidity, results of operations, cash flows, cash available for distribution and ability to make cash distributions to our shareholders.
The COVID-19 outbreak was declared a pandemic by the World Health Organization in March 2020 and continues to spread in our key markets. The COVID-19 virus continues to evolve rapidly, and its ultimate impact is uncertain and subject to change. The geographies where Atlantica is present are going through subsequent waves of virus incidence. Governmental authorities have imposed or recommended measures or responsive actions, including quarantines of certain geographic areas and travel restrictions.
We cannot guarantee that the COVID-19 outbreak will not affect our operation and maintenance employees. Our operation and maintenance suppliers may also be affected by COVID-19 and the broader economic downturn. In addition, we may experience delays in certain operation and maintenance activities or certain activities may take longer than usual, or, in a worst case scenario, a potential outbreak at one of our assets may prevent our employees or our operation and maintenance suppliers’ employees from operating the plant. All these can hamper or prevent the operation and maintenance of our assets, which may result in a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, COVID-19 has caused and may continue to cause travel restrictions and significant disruptions to global supply chains. A prolonged disruption could limit the availability of certain parts required to operate our facilities and adversely impact the ability of our operation and maintenance suppliers. If we were to experience a shortage of or inability to acquire critical spare parts, we could incur significant delays in returning facilities to full operation, which could negatively impact our business, financial condition, results of operations and cash flows.
Further, we have adopted additional precautionary measures intended to mitigate potential risks to our employees, including temporarily requiring all employees to work remotely when their work can be done from home, and suspending all non-essential travel. We have implemented protocols to decide which offices to maintain open and with what limitations, depending on the number of cases and other health indicators in each specific region.
In addition, COVID-19 and measures taken by governments are causing a slowdown of broad sectors of the economy, a general reduction in demand, including demand for commodities and a negative impact on prices of commodities, including electricity, oil and gas. In Spain, revenue received by our assets under the existing regulation depend to some extent on market prices for sale of electricity. During 2020, electricity market prices have been lower than in previous years. If this decline in market prices persisted over time, it could have a material adverse effect on our business, financial condition, results of operations and cash flows and the value of our renewable energy facilities may be impaired, or their useful life may be shortened.
The global outbreak also caused significant disruption and volatility in the global financial markets, including the market price of our shares, especially in March and April 2020. Debt markets have also been affected and there have been weeks with a very low number of new debt issuance transactions. Interest rates for new issuances and spreads with respect to treasury yields increased significantly in March until the beginning of May. Debt and equity markets could continue experiencing similar disruptions in the upcoming months since COVID-19 continues to have an impact on markets. A prolonged period of illiquidity and disruptions in the equity and credit markets could limit our ability to refinance our debt maturities and to finance our potential investments and acquisitions and execute on our growth strategy. Any prolonged and uncontained outbreak could result in further disruptions in the general economy and illiquidity in the credit markets. In addition, the progression of and global response to the COVID-19 outbreak could increase the risk of delays in such plans or in obtaining the financing required to close the acquisitions that we have announced.
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Although our revenue is generally contracted or regulated, our clients may be affected by a reduced demand, lower commodity prices and the turmoil in the credit markets. A reduced demand and low prices persisting over time could cause delays in collections, a deterioration in the financial situation of our clients or their bankruptcy. For example, Pemex’s credit rating has weakened and is currently BBB from S&P, Ba2 from Moody’s and BB- from Fitch and its financial situation could worsen considering low oil prices in the past few months. We have been experiencing significant delays in collections in ACT since the second half of 2019 and we continue to monitor the situation closely. Our clients, including utilities, may face reduced revenue and may experience delays in collections from their own clients, as well as bad debt costs. Delays in collections from our clients can cause delays in distributions from our assets, which can cause a negative impact on our cash available for distributions and on our business, financial condition, results of operations, and cash flows. If our off-takers are unable or unwilling to fulfill their related contractual obligations, if they refuse to accept delivery of power delivered thereunder, if they otherwise terminate such agreements prior to the expiration thereof, if prices were re-negotiated under a bankruptcy situation, or if they delay payments, then our business, financial condition, results of operations and cash flows may be materially adversely affected.
We could also experience commercial disputes with our clients, suppliers and partners related to implications of COVID-19 in contractual relations. All the risks referred to can cause delays in distributions from our assets to the holding company level. In addition, we may experience delays in distributions due to logistic and bureaucratic difficulties to approve those distributions, which can negatively affect our cash available for distributions, our business, financial condition and cash flows. If we were to experience delays in distributions due to the risks described above and this situation persisted over time, we may fail to comply with financial covenants in our credit facilities and other financing agreements.
Additionally, many governments have implemented and will continue to implement stimulus measures to reduce the negative impact of COVID-19 in the economy. In many cases, these measures will increase government spending which may translate into increased tax pressure on companies in the countries where we operate. Changes in corporate tax rates and/or other relevant tax laws may have a material adverse effect on our business, financial condition, results of operations and cash flows.
There are various uncertainties associated with the COVID-19 outbreak. We do not yet have sight over the full extent of the virus’ potential effects on our business or the global economy as a whole, or the effectiveness of the vaccines that have recently been become available in the EU, the United States or the United Kingdom. We continue to monitor the situation and adjust our current policies and practices as more information and guidance become available.

| III. | Risks Related to Our Relationship with Algonquin and Abengoa

Algonquin is our largest shareholder and exercises substantial influence over us.
Currently, Algonquin beneficially owns 44.2% of our ordinary shares and is entitled to vote approximately 41.5% of our ordinary shares. As a result of this ownership, Algonquin has substantial influence on our affairs and their ownership interest and voting power constitute a significant percentage of the shares eligible to vote on any matter requiring the approval of our shareholders. Such matters include the election of directors, the adoption of amendments to our articles of association and approval of mergers or sale of all or a high percentage of our assets.
Further, our reputation is closely related to that of Algonquin. Any damage to the public image or reputation of Algonquin as a result of adverse publicity, poor financial or operating performance, changes in financial condition, decline in the price of its shares or otherwise could have a material adverse effect on our business, financial condition, results of operations and cash flows.
This concentration of ownership may also have the effect of discouraging others from making tender offers for our shares. There can be no assurance that the interests of Algonquin will coincide with the interests of the purchasers of our shares or that Algonquin will act in a manner that is in our best interests. If Algonquin sells its shares to a single shareholder, that new shareholder could continue to exercise substantial influence and could seek to influence or change our strategy or corporate governance or could take effective control of us. In addition, we have limited knowledge and visibility of Algonquin’s operations and plans.
Our ownership structure and certain service agreements may create significant conflicts of interest that may be resolved in a manner that is not in our best interests.
Our ownership structure involves several relationships that may give rise to certain conflicts of interest between us, Algonquin, and the rest of our shareholders. Currently, two of our directors are officers of Algonquin.
Currently, AAGES and Algonquin are related parties and may have interests that differ from our interests, including with respect to the types of investments and acquisitions made, the timing and amount of dividends paid by us, the reinvestment of returns generated by our operations, the use of leverage when making acquisitions and the appointment of outside advisors and service providers. Any transaction between us and AAGES or Algonquin (including the acquisition of any ROFO assets or any co-investment with AAGES or Algonquin or any investment on an Algonquin asset) is subject to our related party transactions policy, which requires prior approval of such transaction by the related party transactions committee, which is composed of independent directors. The existence of our related party transactions approval policy may not insulate us from derivative claims related to related party transactions and the conflicts of interest described in this risk factor. Regardless of the merits of such claims, we may be required to spend significant management time and financial resources in the defense thereof. Additionally, to the extent we fail to appropriately deal with any such conflicts, it could negatively impact our reputation and ability to raise additional funds and the willingness of counterparties to do business with us, all of which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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If Abengoa defaults on certain of its debt obligations, including as a result of the recent insolvency filing by their holding company Abengoa S.A., we could potentially be in default of certain of our project financing agreements.
Abengoa, which is currently our largest supplier and used to be our largest shareholder, went through a restructuring process which started in November 2015 and ended in March 2017, obtained approval for a second restructuring in July 2019 and Abengoa S.A. has recently filed for insolvency again. On May 19, 2020, Abengoa announced that it was working on a new viability plan that would include new financing under a COVID-19 mitigation program in Spain, as well as renegotiation of certain existing debt with suppliers and lenders. Within this process on August 18, 2020 Abengoa filed pre-insolvency proceedings for the individual company Abengoa, S.A(the holding company). According to public communications to the Spanish securities market regulator, Abengoa believed this filing should not affect the restructuring plan for which Abengoa is currently seeking approval from its creditors. On February 22, 2021, Abengoa, S.A. filed for insolvency proceedings in Spain. Based on the public information filed in connection with these proceedings, such insolvency proceedings do not include other Abengoa companies, including Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services for us.
The project financing arrangement for Kaxu contains cross-default provisions related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. In March 2017, Atlantica obtained a waiver with respect to its Kaxu project financing arrangement which waives any potential cross-defaults by Abengoa up to that date, but the waiver did not cover potential future cross-default events. The restructuring process and the pre-insolvency filing by the individual company Abengoa S.A. in August 2020 represent a theoretical event of default under the Kaxu project finance agreement. In December 2020, we obtained a waiver from Kaxu’s project debt lenders in which they commit not to take any action until December 31, 2021 with respect to any potential cross-defaults with Abengoa for the pre-insolvency filing of August 2020. The insolvency filing by the individual company Abengoa S.A. in February 2021 represents a theoretical event of default under the Kaxu project finance agreement for which we do not yet have a waiver. Although we do not expect the Kaxu’s project debt lenders to accelerate the debt or take any other action, a cross-default scenario, if not cured or waived, may entitle lenders to demand repayment, limit distributions from the asset or enforce on their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. We are negotiating a waiver from the creditors and/or contractual modifications to permanently remove the cross-default provision.
Abengoa’s financial condition including the recent insolvency filing by Abengoa S.A. could affect its ability to satisfy its obligations with us under different agreements, such as operation and maintenance agreements as well as indemnities and other contracts in place, and may affect our reputation.
We have current and future collection rights with certain subsidiaries of Abengoa. Moreover, Abengoa has several obligations and indemnities which have resulted or could result in additional liability obligations to us or to our assets. Inability of Abengoa to pay their obligations when due, including as a result of insolvency, would have a negative impact on our current or future cash position.
The insolvency filing by the individual company Abengoa, S.A. in February 2021 may cause an insolvency filing of Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services, or insolvency filings of subsidiaries of Abenewco1, S.A. There may be unanticipated consequences of Abengoa S.A. insolvency filings, Abenewco1 potential filing, further restructurings by Abengoa or ongoing bankruptcy proceedings by Abengoa’s subsidiaries that we have not yet identified. There are uncertainties as to how any further bankruptcy proceedings would be resolved and how our relationship with Abengoa would be affected following the initiation or resolution of any such proceedings.
A deterioration in the financial position of Abengoa and of certain of its subsidiaries may result in a material adverse effect on certain of our operation and maintenance agreements. Abengoa and its subsidiaries provide operation and maintenance services for some of our assets. We cannot guarantee that Abengoa and/or its subcontractors will be able to continue performing with the same level of service (or at all) and under the same terms and conditions, and at the same prices.
Because we have long-term operation and maintenance agreements with Abengoa for many of our assets, if Abengoa cannot continue performing current services at the same prices, we may need to renegotiate contracts and pay higher prices or change the scope of the contracts. This could also cause us to change suppliers or to pay higher prices or change the level of services. This may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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The insolvency filing by Abengoa S.A. in February 2021, the potential insolvency filing by Abenewco1, S.A. (or any of its subsidiaries), a deterioration in the financial situation of Abengoa or the implementation of a new viability plan may also result in a material adverse effect on Abengoa’s and its subsidiaries’ obligations, warranties and guarantees, and indemnities covering, for example, potential tax liabilities for assets acquired from Abengoa, or any other agreement. In addition, Abengoa has represented that we would not be a guarantor of any obligation of Abengoa with respect to third parties. Abengoa agreed to indemnify us for any penalty claimed by third parties resulting from any breach in Abengoa’s representations. Certain of these indemnities and obligations are no longer valid after the insolvency filing by Abengoa, S.A. in February 2021. A potential insolvency of Abenewco1, S.A. may also terminate the remaining obligations, indemnities and guarantees. In addition, in Mexico, Abengoa owns a power plant that shares certain infrastructure and has certain back-to-back obligations with ACT. A deterioration in Abengoa’s or this asset’s financial situation may also result in a material adverse effect on ACT and on our business, financial condition, results of operations and cash flows.
In January 2019, we entered into an agreement with Abengoa under the Abengoa ROFO Agreement for the acquisition of Tenes and paid $19.9 million as an advance payment. Closing of the acquisition was subject to conditions precedent which were not fulfilled. In accordance with the terms of the share purchase agreement, the advance payment was converted into a secured loan to be reimbursed by Befesa Agua Tenes, together with 12% per annum interest, through a full cash-sweep of all the dividends to be received from the asset. In October 2019, we received a first payment of $7.8 million through the cash sweep mechanism. On May 31, 2020, we entered into a new $4.5 million secured loan agreement with Befesa Agua Tenes. This new loan is expected to be reimbursed no later than May 31, 2032, together with 12% interest per annum, through a full cash-sweep of all the dividends to be received from the asset. Although our investment was structured to survive Abengoa’s potential bankruptcy, we cannot guarantee this will be the case, which may have an adverse effect on our results of operations and cash flows.
In addition, although Abengoa has not been our shareholder since the end of 2018, in some geographies our reputation continues to be related to that of Abengoa. Any damage to the public image or reputation of Abengoa as a result of bankruptcy, adverse publicity, poor financial or operating performance, changes in financial condition, or otherwise could have a material adverse effect on our business, financial condition, results of operations and cash flows.
By virtue of initiating a bankruptcy filing under the Spanish Insolvency Act, Abengoa may be subject to insolvency claw-back actions in which transactions may be set aside.
Under the Spanish Insolvency Act, the transactions a company has entered into during the two years prior to the opening of insolvency proceedings can be set aside, irrespective of whether there was intent to defraud, if those transactions are considered materially damaging to the insolvency estate. Material damage is assessed on the basis of the circumstances at the time the transaction was carried out, without the benefit of hindsight and without considering subsequent events or occurrences, including events in relation to insolvency proceedings or the request to set-aside the transaction. Transactions we have entered into with Abengoa in the previous two years before it may be declared insolvent (if such action were to take place) could be set aside. The court would consider if the transactions were detrimental to Abengoa on the terms on which they were made and the suitability of the transactions at the time they were entered into, if the transaction followed market standards and prices and if it had real economic value.
In practice, transactions that are subject to claw-back relate to: (a) unjustified payments or advances from the insolvent company to another group company, (b) transfers of assets or rights by the insolvent company to another group company at below market value, (c) payment-in-kind arrangements in which the property another group company receives in payment is higher in value than the debt owed to it, and (d) security provided by the insolvent company for another group company’s obligations. This determination will be a question of fact before a Spanish court if Abengoa initiates a bankruptcy filing in Spain, however if any of the transactions entered into between us and Abengoa, including those related to drop-downs assets, were declared invalid by a Spanish court, unless it is determined we acted in bad faith, such transaction would be unwound and we would receive back the cash paid, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
On February 22, 2021, Abengoa, S.A. filed for insolvency proceedings in Spain. Based on the public information filed in connection with these proceedings, such insolvency proceedings do not include other Abengoa companies, including Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services for us. The outcome of any bankruptcy proceedings initiated by Abengoa would be difficult to predict given that Abengoa is incorporated in Spain and has assets and operations in several countries around the world. Bankruptcy laws other than those of Spain could apply. The rights of Abengoa’s creditors may be subject to the laws of a number of jurisdictions and such multi-jurisdictional proceedings are typically complex and often result in substantial uncertainty. In addition, the bankruptcy and other laws of such jurisdictions may be materially different from, or in conflict with, one another. If Abengoa is subject to U.S. bankruptcy law, bankruptcy courts in the United States may seek to assert jurisdiction over all of its assets, wherever located, including property situated in other countries.
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A bankruptcy filing by Abengoa may permanently affect Abengoa’s operations. We cannot predict how any bankruptcy proceeding would be resolved or how our relationship with Abengoa will be affected following the initiation of any such proceedings or after the resolution of any such proceedings. Any bankruptcy proceedings initiated by Abengoa may have a material adverse effect on our business, financial condition, results of operations and cash flows.

| IV. | Risks Related to Our Indebtedness

Our indebtedness could limit our ability to react to changes in the economy or our industry, expose us to the risk of increased interest rates and limit our activities due to covenants in existing financing agreements. It could also adversely affect our ability to make distributions from the project subsidiaries to Atlantica Sustainable Infrastructure plc, our ability to fund our operations, pay dividends or raise additional capital.
As of December 31, 2020, we had (i) $5,237.6 million of total indebtedness under various project-level debt arrangements and (ii) $993.7 million of total indebtedness under our corporate arrangements, which include the Note Issuance Facility 2019, the Note Issuance Facility 2020, the 2020 Green Private Placement, the Green Exchangeable Notes and drawdowns under the Revolving Credit Facility. In addition, we may incur in the future additional project-level debt and corporate debt.
Our substantial debt could have important negative consequences on our business financial condition, results of operation and cash flows including:

| • | increasing our vulnerability to general economic and industry conditions;

| • | requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our shares or to use our cash flow to fund our operations, capital expenditures and future business opportunities;

| • | limiting our ability to enter into long-term power sales, fuel purchases and swaps which require credit support;

| • | limiting our ability to fund operations or future investments and acquisitions;

| • | restricting our ability to make certain distributions with respect to our shares and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements;

| • | exposing us to the risk of increased interest rates because a portion of some of our borrowings (below 10% as of December 31, 2020 after giving effect to hedging agreements) are at variable rates of interest;

| • | limiting our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, investments and acquisitions and general corporate or other purposes, and limiting our ability to post collateral to obtain such financing; and

| • | limiting our ability to adjust to changing market conditions and placing us at a disadvantage compared to our competitors who have less debt.

The operating and financial restrictions and covenants in the Revolving Credit Facility, the Note Issuance Facility 2019, the Green Private Placement and the Note Issuance Facility 2020 may adversely affect our ability to finance our future operations or capital needs, to engage in other business activities that may be in our interest and to execute our business strategy as we intend to do so. Each contains covenants that limit certain of our, the guarantors’ and other subsidiaries’ activities. If we breach any of these covenants (including as a result of our inability to satisfy certain financial covenants), a default may result which may entitle the related noteholders or lenders, as applicable to demand repayment and accelerate all such debt or to enforce their security interests, which would have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Item 5.B—Operating and Financial Review and Prospects—Liquidity and Capital Resources—Financing Arrangements.”
In addition, our inability to satisfy certain financial covenants may prevent cash distributions by the particular project(s) and other subsidiaries to us. If our project-level and other subsidiaries are unable to make distributions, it would likely have a material adverse effect on our ability to serve debt at the corporate level or pay dividends to holders of our shares. Our failure to comply with those and other covenants could result in an event of default which, if not cured or waived, may entitle the related noteholders or lenders, as applicable to demand repayment or to enforce their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, failure to comply with such covenants, may entitle the related noteholders or lenders, as applicable, to demand repayment and accelerate all such indebtedness.
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Letter of credit facilities or bank guarantees to support project-level contractual obligations generally need to be renewed, at which time we will need to satisfy applicable financial ratios and covenants. If we are unable to renew the letters of credit as expected or replace them with letters of credit under different facilities on favorable terms or at all, we may experience a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, such inability may constitute a default under certain project-level financing arrangements, restrict the ability of the project-level subsidiary to make distributions to us and/or reduce the amount of cash available at such subsidiary to make distributions to us.
We may not be able to refinance our existing indebtedness.
Our ability to arrange financing, either at corporate level or at a project-level, and the costs of such capital, are dependent on numerous factors, including:

| • | general economic and capital market conditions;

| • | credit availability from banks and other financial institutions;

| • | investor confidence in us and Algonquin as our largest shareholder

| • | our financial performance, cash flow generation and the financial performance of our subsidiaries;

| • | our level of indebtedness and compliance with covenants in debt agreements;

| • | maintenance of acceptable project and corporate credit ratings or credit quality; and

| • | tax and securities laws that may impact raising capital.

We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace project-level financing arrangements or other credit facilities on favorable terms or at all upon the expiration or termination thereof. We may be unable to repay our existing debt as it becomes due if we fail, or any of our projects fails, to obtain additional capital or enter into new or replacement financing arrangements, which would have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may not be able to arrange the required or desired financing for investments and acquisitions and for the successful refinancing of the Company’s project level and corporate level indebtedness.
The global capital and credit markets have experienced in the past and may continue to experience periods of extreme volatility and disruption. In recent years, capital markets have experienced periods of high volatility, particularly in the United States and Europe. At times, our access to financing was curtailed by market conditions and other factors. Continued disruptions, uncertainty or volatility in the global capital and credit markets may limit our access to additional capital required to refinance our debt on satisfactory terms or at all, may limit our ability to replace, in a timely manner, maturing liabilities, and may limit our access to new debt and equity capital to make further investments acquisitions. Volatility in debt markets may also limit our ability to fund or refinance many of our projects and corporate level debt, even in cases where such capital has already been committed. As a result, we may be forced to delay raising capital, issue shorter-term securities than we prefer, or bear a higher cost of capital which could decrease our profitability and significantly reduce our financial flexibility or even require us to modify our dividend policy. In the event we are required to replace previously committed financing to certain projects that subsequently becomes unavailable, we may have to postpone or cancel planned acquisitions, investments or capital expenditures. The inability to raise capital, higher costs of capital or postponement or cancellation of planned acquisitions, investments or capital expenditures may have a materially adverse effect on our business, financial condition, results of operations and cash flows. If financing is available, utilization of our credit facilities, debt securities or project level financing for all or a portion of the purchase price of an acquisition, as applicable, could significantly increase our interest expense and debt repayment, impose additional or more restrictive covenants, and reduce cash available for distribution.
We may be subject to increased finance expenses if we do not effectively manage our exposure to interest rate and foreign currency exchange rate risks.
We are exposed to various types of market risk in the normal course of business, including the impact of interest rate changes and foreign currency exchange rate fluctuations. Some of our indebtedness (including project-level indebtedness) bears interest at variable rates, generally linked to market benchmarks such as EURIBOR and U.S. LIBOR. Any increase in interest rates would increase our finance expenses relating to our variable rate indebtedness and increase the costs of refinancing our existing indebtedness and issuing new debt.
In addition, although most of our long-term contracts are denominated in, indexed or hedged to U.S. dollars, we conduct our business and incur certain costs in the local currency of the countries in which we operate. In addition, the revenues, costs and debt of our solar assets in Spain are denominated in euros. Since the beginning of 2017, we have maintained euro-denominated debt at the corporate level. Interest payments in euros and our euro denominated general and administrative expenses create a natural hedge for a portion of the distributions from Spanish assets. Our strategy is to hedge the exchange rate for the distributions from our Spanish assets after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, we hedge on a rolling basis 100% of the net euro net exposure for the next 12 months and 75% of the net euro net exposure for the following 12 months. See “Item 5.A—Operating and Financial Review—Results of Operations—Factors Affecting our Results of Operations.”
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As we continue expanding our business, an increasing percentage of our revenue and cost of sales may be denominated in currencies other than our reporting currency, the U.S. dollar. Under that scenario, we would become subject to increasing currency exchange risk, whereby changes in exchange rates between the U.S. dollar and the other currencies in which we do business could result in foreign exchange losses.
In addition, we seek to actively work with lending financial institutions to mitigate our interest rate risk exposure and to secure lower interest rates by entering into interest rate options and swaps. As a matter of policy, we seek to cover at least 70% of our outstanding long-term project debt interest rate risk. We estimate that approximately 93% of our total interest risk exposure was fixed or hedged as of December 31, 2020.
If our risk-management strategies are not successful in limiting our exposure to changes in interest rates and foreign currency exchange rates our business, financial condition, results of operations and cash flows maybe materially adversely affected.
Potential future defaults by our subsidiaries, our off-takers, our suppliers, Abengoa or other persons could adversely affect us.
The financing agreements of our project subsidiaries are primarily loan agreements which provide that the repayment of the loans (and interest thereon) is secured solely by the shares, physical assets, contracts and cash flow of that project company. This type of financing is usually referred to herein as “project debt.” As of December 31, 2020, we had $5,237.6 million of outstanding indebtedness under various project-level debt arrangements.
While the lenders under our project debt do not have direct recourse to us or our subsidiaries (other than the letter of credit and bank guarantee facilities), defaults by the project borrowers under such financings can still have important consequences for us and our subsidiaries, including, without limitation:

| • | reducing our receipt of dividends, fees, interest payments, loans and other sources of cash, since the project company will typically be prohibited from distributing cash to us and our subsidiaries until the event of default is cured or waived;

| • | default under our other debt instruments;

| • | causing us to record a loss in the event the lender forecloses on the assets of the project company; and

| • | the loss or impairment of investors’ and project finance lenders’ confidence in us.

If we fail to satisfy any of our debt service obligations or breach any related financial or operating covenants, the applicable lender could declare the full amount of the relevant project debt to be immediately due and payable and could foreclose on any assets pledged as collateral.
In addition, the project financing arrangement for Kaxu contains cross-default provisions related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. The insolvency filing by the individual company Abengoa, S.A. in February 2021 represents a theoretical event of default under the Kaxu project finance agreement for which we do not yet have a waiver. Although we do not expect the Kaxu’s project debt lenders to accelerate the debt or take any other action, a cross-default scenario, if not cured or waived, may entitle lenders to demand repayment, limit distributions from the asset or enforce on their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. See “If Abengoa defaults on certain of its debt obligations, we could potentially be in default of certain of our project financing agreements.”
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Under the Revolving Credit Facility, the Note Issuance Facility 2019, the Green Private Placement and the Note Issuance Facility 2020, a payment default with respect to indebtedness having an aggregate principal amount above certain thresholds by us, any guarantor thereof or one or more of our non-recourse subsidiaries representing more than 25% of the cash available for distribution distributed in the previous four fiscal quarters could trigger a default.
Any of these events may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR in the future may adversely affect the value of any outstanding debt instruments.
National and international regulators and law enforcement agencies have conducted investigations into a number of rates or indices known as “reference rates.” Actions by such regulators and law enforcement agencies may result in changes to the manner in which certain reference rates are determined, their discontinuance, or the establishment of alternative reference rates. In particular, on July 27, 2017, the Chief Executive of the U.K. Financial Conduct Authority (the “FCA”), which regulates LIBOR, announced that the FCA will no longer persuade or compel banks to submit rates for the calculation of LIBOR after 2021. Such announcement indicates that the continuation of LIBOR on the current form cannot and will not be guaranteed after 2021. As a result, it appears highly likely that LIBOR will be discontinued or modified by 2021. On May 31, 2019, the Alternative Reference Rates Committee (“ARRC”) published their final recommendations for new guidelines for LIBOR securitizations, which has been well-received by the securities market. The ARRC proposed that the Secured Overnight Financing Rate (“SOFR”) is the rate that represents best practice as the alternative to USD-LIBOR for use in derivatives and other financial contracts that are currently indexed to USD-LIBOR. SOFR is a more generic measure than LIBOR and considers the cost of borrowing cash overnight, collateralized by U.S. Treasury securities. Whether or not SOFR will attain market traction as a LIBOR replacement tool remains in question. As such, the future of LIBOR at this time is uncertain, including whether the COVID-19 pandemic will have further effect on LIBOR transition plans. In preparation for the potential phase out of LIBOR starting in 2021, we may need to renegotiate our financial obligations and derivative instruments linked to LIBOR.
Given the inherent differences between LIBOR and SOFR or any other alternative benchmark rate that may be established, there are many uncertainties regarding a transition from LIBOR. At this time, it is not possible to predict the effect that these developments, any discontinuance, modification or other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates may have on LIBOR, other benchmarks, or LIBOR-based debt instruments. Furthermore, the use of alternative reference rates, including SOFR, or other reforms could cause the interest rate calculated for the LIBOR-based debt instruments to be materially different than expected. As of December 31, 2020, total notional amount of debt referenced to LIBOR was approximately $1,165.8 million and total notional amount of derivatives hedging this debt, thus indexed to LIBOR as well was approximately $618.8 million.
A change of control or a delisting of our shares may have negative implications for us.
If any investor acquires over 50.0% of our shares or if our ordinary shares cease to be listed on the NASDAQ or a similar stock exchange, we may be required to refinance all or part of our corporate debt or obtain waivers from the related noteholders or lenders, as applicable, due to the fact that all of our corporate financing agreements contain customary change of control provisions and delisting restrictions. If we fail to obtain such waivers and the related noteholders or lenders, as applicable, elect to accelerate the relevant corporate debt, we may not be able to repay or refinance such debt (on favorable terms or at all), which may have a material adverse effect on our business, financial condition results of operations and cash flows. Additionally, in the event of a change of control we could see an increase in the yearly state property tax payment in Mojave, which would be reassessed by the tax authority at the time the change of control potentially occurred. Our best estimate with current information available and subject to further analysis is that we could have an incremental annual payment of property tax of approximately $12 million to $14 million, which could potentially decrease progressively over time as the asset depreciates.

| V. | Risks Related to Our Growth Strategy

We may not be able to identify or consummate future investments and acquisitions on favorable terms, or at all.
Our business strategy includes growth through the acquisition of additional revenue-generating assets and investments in projects under development or construction. This strategy depends on our ability to successfully identify and evaluate investment opportunities and consummate acquisitions on favorable terms. The number of investment opportunities may be limited.
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Our ability to acquire future renewable energy projects or businesses depends on the viability of renewable energy projects generally. These projects are in some cases contingent on public policy mechanisms including, among others, ITCs, cash grants, loan guarantees, accelerated depreciation, expensing for certain capital expenditures, carbon trading plans, environmental tax credits and research and development incentives. See “—Government regulations could change at any time and such changes may negatively impact our current business and our growth strategy.” Our ability to consummate future investments and acquisitions may also depend on our ability to obtain any required government or regulatory approvals for such investments, including, but not limited to, the Federal Energy Regulatory Commission, or FERC, approval under Section 203 of the FPA in respect of investments in the United States; or any other approvals in the countries in which we may purchase assets in the future. We may also be required to seek authorizations, waivers or notifications from debt and/or equity financing providers at the project or holding company level; local or regional agencies or bodies; and/or development agencies or institutions that may have a contractual right to authorize a proposed acquisition.
Furthermore, we will compete with other local and international companies for acquisition opportunities from third parties, which may increase our cost of making investments or cause us to refrain from making acquisitions from third parties. Some of our competitors for investments and acquisitions are much larger than us, with substantially greater resources. These companies may be able to pay more for acquisitions due to cost of capital advantages, potential synergies or other drivers, and may be able to identify, evaluate, bid for and purchase a greater number of assets than our financial or human resources permit. If we are unable to identify and consummate future acquisitions, it will impede our ability to execute our growth strategy and limit our ability to increase the amount of dividends paid to holders of our shares.
Our ability to consummate future investments and acquisitions also depends on the availability of financing. See “—We may not be able to arrange the required or desired financing for acquisitions.”
Finally, demand for renewable energy may be affected by the cost of other energy sources. To the extent renewable energy becomes less cost-competitive, demand for renewable energy could decrease. Slow growth or a long-term reduction in the energy demand could cause a reduction in the development of renewable energy programs projects. Decreases in the prices of electricity could affect our ability to acquire assets, as renewable energy developers may not be able to compete with providers of other energy sources at such lower prices. Our inability to acquire assets could have a material adverse effect on our ability to execute our growth strategy.
Our ability to grow organically is limited to some assets which have inflation indexation mechanisms in its revenues, to our transmission lines and to some renewable assets. We may not be able to deliver organic growth.
Our ability to grow through investments and acquisitions depends, in part, on AAGES’ and Algonquin’s ability to present us with investment opportunities. AAGES and Algonquin may not offer us assets at all or may not offer us assets that fit within our portfolio or contribute to our growth strategy. Only certain assets outside the United States and Canada are included in the Algonquin ROFO Agreement. AAGES and Algonquin may decide to keep assets subject to our ROFO Agreements in their portfolios and not offer them to us for acquisition. Algonquin can terminate its ROFO agreement with us with a 180-day notice. Additionally, we may not reach an agreement on the price of assets offered by AAGES or Algonquin. For these reasons, we may not be able to consummate future investments from AAGES or Algonquin, which may restrict our ability to grow.
Furthermore, AAGES or Algonquin may have financial and resource constraints limiting or eliminating their ability to continue building the contracted assets which are currently under construction and may have financial and resource constraints limiting or eliminating their ability to develop and build new contracted assets. In addition, AAGES or Algonquin may sell assets under development, before they reach their commercial operation date. Some of the assets subject to the ROFO Agreements may not be attractive enough to us for different reasons.
We have reached agreements with new partners that develop assets in the geographies in which we operate. We expect that these agreements will be a source of growth in addition to AAGES and Algonquin, however we cannot guarantee that our investments will be successful and that our growth expectations will materialize. Additionally, we cannot guarantee that we will be successful in identifying new potential partners or that we will be able to acquire additional assets from those partners in the future. If we are unable to identify and reach new agreements on favorable terms with new partners with suitable assets, or unable to consummate future acquisitions from any such sponsor, it may limit our ability to execute our growth strategy and may have a materially adverse effect on our business, financial condition, results of operation and cash flows.
Furthermore, development and construction activities are subject to failure rate and different types of risks. If we co-invest with partners, or on our own, in assets under development or construction, we cannot guarantee that the development and construction of the asset will be successful and that we end up owning an operational asset.
All the above could limit our ability to grow, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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In order to grow our business, we may invest in or acquire assets or businesses which have a higher risk profile or are less ESG-friendly than certain assets in our current portfolio.
In order to grow our business, we may acquire assets and businesses which may have a higher risk profile than certain of the assets we currently own. Competition to acquire contracted assets in operation has been high in recent years and is expected to continue being so. As a result, we have announced investments with exposure to development and construction risk. We intend to continue investing in assets which are not currently in operation and which are subject to development and construction risk. Construction of renewable assets, among others, is subject to risk of cost overruns and delays. There can be no assurances that assets under development and construction will perform as expected or that the returns will be as expected. In addition, we may consider acquiring business which are not contracted, including regulated businesses, which are subject to demand risk. We may also consider acquiring assets which are not contracted or not fully contracted, for which revenues will depend on the price of the electricity and which are subject to merchant risk. We have recently invested and may consider investing in business sectors where we do not have previous experience and may not be able to achieve the expected returns. We may also consider investing with partners or on our own in new technologies which do not have for the moment a track record as proven as our current assets, such as storage, district heating or geothermal. Furthermore, we may consider acquiring assets with revenues not denominated in US dollars or euros, which would increase our exposure to local currency, and which could generate higher volatility in the cash flows we generate. In all these types of assets and businesses, the risk of not meeting the expected cash flow generation and expected returns is higher than in contracted assets. In addition, these type of assets and businesses could present a higher variability in the cash flows they generate. In addition, we may acquire assets which may be considered as less ESG-friendly than certain assets in our current portfolio by current and potential investors. For example, considering the competitive landscape for renewable assets in recent years, we may acquire additional natural gas assets. Although we have set a target to maintain at least 80% of our Adjusted EBITDA generated by low carbon footprint assets, some investors with a focus on ESG may consider this target insufficient, which could cause us to become less attractive to investors.
As a result, the consummation of investments and acquisitions may have a material adverse effect on our ability to grow, our business, financial condition, results of operations and cash flows.
We cannot guarantee the success of our recent and future investments and acquisitions.
Acquisitions of and investments in companies and assets are subject to substantial risks, including the failure to identify material problems during due diligence (for which we may not be indemnified post-closing), the risk of over-paying for assets (or not making acquisitions on an accretive basis) and the ability to retain customers. Furthermore, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, our acquisitions may divert management’s attention from our existing business concerns, disrupt our ongoing business or not be successfully integrated at all. There can be no assurances that any future acquisitions will perform as expected or that the returns will be as expected. As a result, the consummation of acquisitions may have a material adverse effect on our ability to grow, our business, financial condition, results of operations and cash flows.
We may be unable to complete all, or any, such transactions that we may analyze. Even where we consummate acquisitions, we may be unable to achieve projected cash flows; recognize unexpected liabilities or costs; or encounter regulatory complications arising from such transactions. Furthermore, the terms and conditions of financing for such acquisitions or financial investments could restrict the manner in which we conduct our business. These risks could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may not be able to close some of the acquisitions that we have recently announced. In some of these acquisitions, we have signed a share purchase agreement, but closing of the acquisition is subject to closing conditions and authorizations. For example, in the acquisition of PTS, we initially acquired a 5% ownership in the project and have an agreement to acquire an additional 65% stake subject to the asset entering into commercial operation, non-recourse project financing being closed and final approvals and customary conditions, including the absence of material adverse effects. In addition, our partner in this asset is negotiating to sell part of its business, which may include the company that renders operation and maintenance services to PTS. This sale may require change of control waivers and may make closing of the acquisition more difficult. We cannot guarantee that we will close this acquisition or that closing will occur on the terms originally agreed. In the acquisitions of PTS, Calgary District Heating and Coso, closing is also subject to regulatory approvals.
In addition, some of the transactions we have announced are acquisitions of assets under development or construction. Although our construction risk is limited, taking into account the nature of the assets and protection clauses in the share purchase agreements, there could be delays in construction and cost overruns not covered by the protection clauses in the relevant share purchase agreement, which may restrict us to get to the expected CAFD in the assets we are acquiring.
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We may also make acquisitions or investments in assets that are located in different jurisdictions and are different from, and may be riskier than, those jurisdictions in which we currently operate (Canada, the United States, Mexico, Peru, Chile, Uruguay, Spain, South Africa and Algeria). See “—We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.” These changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our cash dividend policy may limit our ability to grow and make acquisitions and investments through cash on hand.
Our dividend policy is to distribute a high percentage of our cash available for distribution, after corporate general and administrative expenses and cash interest payments and less reserves for the prudent conduct of our business, each quarter and to rely primarily upon external financing sources, including the issuance of debt and equity securities as well as borrowings under credit facilities to fund our acquisitions, investments and potential growth capital expenditures. We may be precluded from pursuing otherwise attractive investments if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund the investment, after giving effect to our available cash reserves.
Because of our dividend policy, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional equity securities in connection with any acquisitions or growth capital expenditures, the payment of dividends on these additional equity securities may increase the risk that we will be unable to maintain or increase our per share dividend. There are no limitations in our articles of association on our ability to issue equity securities, including convertible bonds, preferred shares or other securities ranking senior to our shares.

| VI. | Risks Related to the Markets in Which We Operate

Difficult conditions in the global economy and in the global capital markets have caused, and may continue to cause, a sharp reduction in worldwide demand for our products and services
Our results of operations have been, and continue to be, materially affected by conditions in the global economy. In the United States, capital markets have been experiencing some volatility recently. Concerns over the COVID-19 pandemic and its effects on the global economy, volatile oil and gas prices, geopolitical issues, the availability and cost of credit, sovereign debt and the instability of the euro have contributed to increased volatility in capital markets and worsened expectations for the economy. Adverse events and continuing disruptions in the global economy and capital markets may have a material adverse effect on our business, financial condition, results of operations and cash flows. Moreover, even in the absence of a market downturn, we are exposed to risk of loss due to market volatility and other factors, including volatile oil prices, interest rates, consumer spending, business investment, government spending, or inflation, among others, that could affect the economic and financial situation of our concession contracts’ counterparties and, ultimately, the profitability and growth of our business.
Generalized or localized downturns or inflationary or deflationary pressures in our key geographical areas could also have a material adverse effect on our business, financial condition, results of operations and cash flows. A significant portion of our business activity is concentrated in the United States, Mexico, Peru and Spain. Consequently, we are significantly affected by the general economic conditions in these countries. Spain, for instance, is facing a recession in the last quarters caused by the COVID-19 pandemic that is worsening high unemployment and significant government debt. The effects on the European and global economy of the COVID-19 pandemic, or the exit of the United Kingdom from the European Union or of any other member states from the Eurozone, the dissolution of the euro, or the perception that any of these events are imminent, are inherently difficult to predict and could give rise to operational disruptions or other risks of contagion to our business and have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, to the extent uncertainty regarding the European economic recovery continues to negatively affect government or regional budgets, our business, financial condition, results of operations and cash flows could be materially adversely affected.
We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.
We operate our activities in a range of international locations, including North America (Canada, the United States and Mexico), South America (Peru, Chile and Uruguay), and EMEA (Spain, Algeria and South Africa), and we may expand our operations to certain core countries within these regions. Accordingly, we face several risks associated with operating and investing in different countries that may have a material adverse effect on our business, financial condition, results of operations and cash flows. These risks include, but are not limited to, adapting to the regulatory requirements of such countries, compliance with changes in laws and regulations applicable to foreign corporations, the uncertainty of judicial processes, and the absence, loss or non-renewal of favorable treaties, or similar agreements, with local authorities, or political, social and economic instability, all of which can place disproportionate demands on our management, as well as significant demands on our operational and financial personnel and business. As a result, we can provide no assurance that our future international operations and investments will remain profitable.
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A significant portion of our current and potential future operations and investments are conducted in various emerging countries worldwide. Our activities and investments in these countries involve a number of risks that are more prevalent than in developed markets, such as economic and governmental instability, the possibility of significant amendments to, or changes in, the application of governmental regulations, the nationalization and expropriation of private property, payment collection difficulties, social unrest or protests, substantial fluctuations in interest and exchange rates, changes in the tax framework or the unpredictability of enforcement of contractual provisions, currency control measures, limits on the repatriation of funds and other unfavorable interventions or restrictions imposed by public authorities. In countries such as Mexico political changes could generate changes in regulation which could affect our business. Likewise, in countries such as Algeria or South Africa, a change in government can cause instability in the country and a new government may decide to change laws and regulations affecting our assets or may decide to expropriate such assets, all of which may have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, in Chile violent social protests took place mainly between October 2019 and February 2020. Several social measures were approved. Protests could have an adverse effect on our business, financial condition, results of operations and cash flows. In addition, potential social measures could also have an adverse effect in our business, for example, if the government decided to increase taxation on our assets.
Our U.S. dollar-denominated contracts in several assets are payable in local currency at the exchange rate of the payment date and in some cases include portions in local currency. Likewise, our contract for Kaxu in South Africa is denominated and payable in South African rands. In the event of a rapid devaluation or implementation of exchange or currency controls, we may not be able to exchange the local currency for the agreed dollar amount, which could affect our cash available for distribution. Governments in Latin America and Africa frequently intervene their economies and occasionally make significant changes in policy and regulations. Governmental actions aimed to control inflation and other similar policies and regulations have often involved, among other measures, price controls, currency devaluations, capital or exchange controls and limits on imports. Such devaluation, implementation of exchange or currency controls or governmental involvement may have a material adverse effect on our business, financial condition, results of operations and cash flows.
We are exposed to political, social and macroeconomic risks relating to the United Kingdom’s exit from the European Union.
On January 31, 2020, the U.K. ceased to be part of the European Union and entered into a transition period to, among other things, negotiate an agreement with the EU on the future terms of the United Kingdom’s relationship with the European Union. On December 24, 2020, both parties announced that a trade agreement had been reached (the “Trade Agreement”), which was passed by both houses of the British parliament on December 30 and given Royal Assent on December 31, 2020, which ended the transition period.
On January 1, 2021, the U.K. left the EU Single Market and Customs Union, as well as all EU policies and international agreements. As a result,, the free movement of persons, goods, services and capital between the U.K. and the EU ended, with the EU and the U.K. forming two separate markets and two distinct regulatory and legal frameworks. The Trade Agreement offers U.K. and EU companies preferential access to each other’s markets, ensuring imported goods will be free of tariffs and quotas; however, economic relations between the U.K. and the EU will now be on more restricted terms than existed previously. Moreover, the Trade Agreement does not incorporate the full scope of the services sector, and certain businesses such as banking and finance face a more uncertain future. At this time, we cannot predict the impact that the Trade Agreement and any future agreements between the U.K. and the EU will have on our business. We continue to evaluate our own risks and uncertainty related to Brexit to better navigate the changes in the U.K.-EU market. The terms of the Trade Agreement once implemented, and other possible terms we cannot anticipate, could adversely affect our business, financial condition, results of operations and cash flows.

| VII. | Risks Related to Regulation

We are subject to extensive governmental regulation in a number of different jurisdictions, and our inability to comply with existing regulations or requirements or changes in applicable regulations or requirements may have a negative impact on our business, financial condition, results of operations and cash flows.
We are subject to extensive regulation of our business in the countries in which we operate. Such laws and regulations require licenses, permits and other approvals to be obtained in connection with the operations of our activities. This regulatory framework imposes significant actual, day-to-day compliance burdens, costs and risks on us. In particular, the power plants and transmission lines that we own are subject to strict international, national, state and local regulations relating to their operation and expansion (including, among other things, leasing and use of land, and corresponding building permits, landscape conservation, noise regulation, environmental protection and environmental permits and electric transmission and distribution network congestion regulations). Non-compliance with such regulations could result in reputational damage, the revocation of permits, sanctions, fines, criminal penalties or lower our ESG ratings. Compliance with regulatory requirements may result in substantial costs to our operations that may not be recovered. In addition, we cannot predict the timing or form of any future regulatory or law enforcement initiatives. Changes in existing energy, environmental and administrative laws and regulations may have a material adverse effect on our business, financial condition, results of operations and cash flows, including on our growth plan and investment strategy. Our business may also be affected by additional taxes imposed on our activities, reduction of regulated tariffs and other cuts or measures.
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Further, similar changes in laws and regulations could increase the size and number of claims and damages asserted against us or subject us to enforcement actions, fines and even criminal penalties. In addition, changes in laws and regulations may, in certain cases, have retroactive effect and may cause the result of operations to be lower than expected. In particular, our activities in the energy sector are subject to regulations applicable to the economic regime of generation of electricity from renewable sources and to subsidies or public support in the benefit of our production of energy from renewable energy sources, which vary by jurisdiction, and are subject to modifications that may be more restrictive or unfavorable to us.
Our business is subject to stringent environmental regulation.
We are subject to significant environmental regulation, which, among other things, requires us to obtain and maintain regulatory licenses, permits and other approvals and comply with the requirements of such licenses, permits and other approvals and perform environmental impact studies on changes to projects. In addition, our assets need to comply with strict environmental regulation on air emissions, water usage and contaminating spills, among others. As a company with a focus on ESG and most of the business in renewable energy, environmental incidents can also significantly harm our reputation. There can be no assurance that:

| • | public opposition will not result in delays, modifications to or cancellation of any project or license;

| • | laws or regulations will not change or be interpreted in a manner that increases our costs of compliance or require new investments and may have a material adverse effect on our business, financial condition, results of operations and cash flows, including preventing us from operating an asset if we are not in compliance; or

| • | governmental authorities will approve our environmental impact studies where required to implement proposed changes to operational projects.

We believe that we are currently in material compliance with all applicable regulations, including those governing the environment. In the past, we have experienced some environmental accidents and we have been found not to be in compliance with certain environmental regulations and have incurred fines and penalties associated with such violations which, to date, have not been material in amount. We can give no assurance, however, that we will continue to be in compliance or avoid material fines, penalties, sanctions and expenses associated with compliance issues in the future. Violation of such regulations may give rise to significant liability, including fines, damages, fees and expenses, and site closures. Generally, relevant governmental authorities are empowered to clean up and remediate releases of environmental damage and to charge the costs of such remediation and clean-up to the owners or occupiers of the property, the persons responsible for the release and environmental damage, the producer of the contaminant and other parties, or to direct the responsible parties to take such action. These governmental authorities may also impose a tax or other liens on the responsible parties to secure the parties’ reimbursement obligations.
Environmental regulation has changed rapidly in recent years, and it is possible that we will be subject to even more stringent environmental standards in the future, including in relation to climate change. We cannot predict the amounts of any increased capital expenditures or any increases in operating costs or other expenses that we may incur to comply with applicable environmental, or other regulatory, requirements, or whether these costs can be passed on to its concession contract counterparties through price increases. The costs of compliance as well as non-compliance may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Government regulations could change at any time and such changes may negatively impact our current business and our growth strategy.
In some of our assets such as the Spanish solar plants and one of our transmission lines in Chile, revenues are based on existing regulation. We may also acquire in the future additional assets or businesses with regulated revenues. For these types of assets and businesses, if regulation changes, it may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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In addition, our strategy to grow our business through the acquisition of renewable energy projects partly depends on current government policies that promote and support renewable energy and enhance the economic viability of owning solar and wind energy projects. Renewable energy projects currently benefit from various U.S. federal, state and local governmental incentives, such as ITCs, PTCs, loan guarantees, RPS programs, or MACRS along with other incentives. These incentives make the development of renewable energy projects more competitive by providing tax credits, accelerated depreciation and expensing for a portion of the development costs, decreasing the costs associated with developing such projects or creating demand for renewable energy assets through RPS programs. These policies have had a significant impact on the development of renewable energy, and they could change at any time. Additionally, many of these government incentives, including the ITCs and the PTCs, are subject to phase-out and/or expiration. A loss or reduction in such incentives or the value of such incentives, a change in policy away from limitations on coal and gas electric generation, mining and exploration, or a reduction in the capacity of potential investors to benefit from such incentives could decrease the attractiveness of solar or renewable energy projects to project developers, and the attractiveness of solar energy systems to utilities, retailers and customers. A reduction or removal of incentives may diminish the market for future renewable energy off-take agreements and reduce the ability for renewable developers to compete for future energy off-take agreements, which may reduce incentives for project developers to invest in the development and construction of clean energy and water infrastructure contracted assets. This could cause reduced economic returns, resulting in increased financing costs and difficulty in obtaining financing. Such a loss or reduction could also reduce our acquisition opportunities and our willingness to pursue renewable energy projects due to higher operating costs or lower revenues from off-take agreements. See also “—Risks Related to Taxation.”
Additionally, some U.S. states with RPS targets have met, or in the near future will meet, their renewable energy targets. For example, California, which has among the most aggressive RPS laws in the United States, is poised to meet its current mandate of 33.0% renewable energy by 2020 with already-proposed new renewable energy projects, though significant additional investments will be required to meet the higher renewable energy mandate of 60.0% by 2030 and 100% by 2045 that was adopted in 2018. If, as a result of achieving these targets, these and other U.S. states do not increase their targets in the near future, demand for additional renewable energy could decrease. In addition, the substantial increase of grid connected intermittent solar and wind generation assets resulting from the adoption of RPS targets has created significant technical challenges for grid operators. As a result, RPS targets may need to be scaled back or delayed in order to develop technologies or infrastructure to accommodate this increase in intermittent generation assets.
We rely, in a significant part, on environmental and other regulations of industrial and local government activities, including regulations mandating, among other things, reductions in carbon or other greenhouse gas emissions or use of energy from renewable sources. If the businesses to which such regulations relate were deregulated or if such regulations were materially changed or weakened, the profitability of our current and future projects could suffer, which could in turn have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, uncertainty regarding possible changes to any such regulations has adversely affected us in the past, and may adversely affect in the future, our ability to refinance a project or to satisfy other financing needs.
Subsidy regimes for renewable energy generation have been challenged in the past on constitutional and other grounds (including that such regimes constitute impermissible European Union state aid) in certain jurisdictions. In addition, certain loan-guarantee programs in the United States, including those which have enabled the DOE to provide loan guarantees to support our Solana and Mojave projects in the United States, have been challenged on grounds of failure by the appropriate authorities to comply with applicable U.S. federal administrative and energy law. If all or part of the subsidy and incentive regimes for renewable energy generation in any jurisdiction in which we operate were found to be unlawful and, therefore, reduced or discontinued, we may be unable to compete effectively with conventional and other renewable forms of energy. We currently have two financing arrangements with the Federal Financing Bank for the Solana and Mojave assets, repayment of which to the Federal Financing Bank by those projects is with a guarantee by the DOE. Additionally, these projects benefit from the ITCs. Unilateral changes to these agreements or the ITC regime may have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, there are some proposed changes in regulation in Mexico. On February 1st, 2021, Mexico´s President proposed a preferential reform to the Electricity Industry Act, meaning that the Congress shall vote on it no later than April 30th. The reform proposes several measures aimed at increasing preponderance of the CFE in different areas. Although we do not expect a direct impact on our existing contracts, we cannot guarantee that the new regulation will not have any impact on our business, financial condition, results of operations and cash flows. The new regulation could also limit our growth prospects in the region. Additionally, there is a proposed change in regulation on sub-contracting activities. We cannot guarantee that we will not have a negative impact on our business, financial condition, results of operations and cash flows.
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Revenues in our solar assets in Spain are mainly defined by regulation and some of the parameters defining the remuneration are subject to review every six years. Revenues in Chile TL3 are also mainly defined by regulation.
According to Royal Decree 413/2014, solar electricity producers in Spain receive: (i) the pool price for the power they produce, (ii) a payment based on the standard investment cost for each type of plant (without any relation whatsoever to the amount of power they generate) and (iii) an “operating payment” (in €/MWh produced).
The principle driving this economic regime is that the payments received by a renewable energy producer should be equivalent to the costs that they are unable to recover on the electricity pool market where they compete with non-renewable technologies. This economic regime seeks to allow a “well-run and efficient enterprise” to recover the costs of building and running a plant, plus a reasonable return on investment (project investment rate of return). The rate applicable during the first regulatory period was 7.398%.
On July 27, 2018, CNMC (the regulator for the electricity system in Spain) issued a draft proposal for the calculation of the reasonable rate of return for the regulatory period 2020-2025. On November 2, 2018, CNMC issued its final report with a proposed reasonable rate of return of 7.09%. In December 2018 the government issued a draft project law proposing a reasonable rate of return of 7.09%, with the possibility of maintaining the 7.398% reasonable rate of return under certain circumstances. On November 24, 2019, the Spanish government approved Royal Decree-law 17/2019 setting out a 7.09% rate of reasonable return applicable from January 1, 2020 until December 31, 2025 as a general rule and the possibility, under certain circumstances including not having any ongoing legal proceeding against the Kingdom of Spain ongoing, of maintaining the 7.398% reasonable rate of return for two consecutive regulatory periods. The reasonable return was calculated by reference to the weighted average cost of capital (WACC), the calculation method that most of the European regulators apply to determine the return rates applicable to regulated activities within the energy sector. As a result, some of the assets in our Spanish portfolio are receiving a remuneration based on a 7.09% reasonable rate of return until December 31, 2025 while others are receiving a remuneration based on a 7.398% reasonable rate of return until December 31, 2031.
If the payments for renewable energy plants are revised to lower amounts in the next regulatory period starting on January 1, 2026 until December 31, 2031 or starting on January 1, 2032, depending on each asset, this could have a material adverse effect on our business, financial condition, results of operations and cash flows. As a reference, assuming our Spanish assets continue to perform as expected and assuming no additional changes of circumstances, with the information currently available, Atlantica estimates that a reduction of 100 basis points in the reasonable rate of return on investment set by the Spanish government could cause a reduction in its cash available for distribution of approximately €18 million per year. This estimate is subject to certain assumptions, which may change in the future.
Our international operations require us to comply with anti-corruption and other laws and regulations of the United States government and various non-U.S. jurisdictions.
Doing business in multiple countries requires us and our subsidiaries to comply with the laws and regulations of the United States government and various non-U.S. jurisdictions. Our failure to comply with these rules and regulations may expose us to liabilities. These laws and regulations may apply to us, our subsidiaries, individual directors, officers, employees and agents, and may restrict our operations, trade practices, investment decisions and partnering activities.
In particular, our non-U.S. operations are subject to United States and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, as amended (“FCPA”), and similar laws and regulations. The FCPA prohibits United States companies and their officers, directors, employees and agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. The FCPA also requires companies to make and keep books, records and accounts that accurately and fairly reflect transactions and dispositions of assets and to maintain a system of adequate internal accounting controls. As part of our business, we deal with state-owned business enterprises, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. As a result, business dealings between our employees and any such foreign official could expose us to the risk of violating anti-corruption laws even if such business practices may be customary or are not otherwise prohibited between the us and a private third party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civil penalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures.
We have established policies and procedures designed to assist us and our personnel in complying with applicable United States and non-U.S. laws and regulations; however, we cannot assure you that these policies and procedures will completely eliminate the risk of a violation of these legal requirements, and any such violation (inadvertent or otherwise) could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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| VIII. | Risks Related to Ownership of Our Shares

We may not be able to pay a specific or increasing level of cash dividends to holders of our shares in the future.
The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

| • | operational performance of our assets;

| • | potential capital expenditure requirements in our assets in the case there were technical problems environmental or regulatory requirements not covered by the EPC contractor guarantee or O&M contractor guarantee or by insurance;

| • | our debt service requirements and other liabilities;

| • | fluctuations in our working capital needs;

| • | fluctuations in foreign exchange rates;

| • | the level of our operating and general and administrative expenses,

| • | seasonal variations in revenues generated by the business;

| • | restrictions contained in our debt agreements (including our project-level financing);

| • | our ability to borrow funds, including intercompany loans;

| • | changes in our revenues and/or cash generation in our assets due to delays in collections from our off-takers, legal disputes regarding contact terms, adjustments contemplated in existing regulation or changes in regulation or taxes in the countries in which we operate, or adverse weather conditions;

| • | potential restrictions on payment of dividends arising from cross-default provisions with Abengoa in our Kaxu project financing agreements; and

| • | other business risks affecting our cash levels.

As a result of all these factors, we cannot guarantee that we will have sufficient cash generated from operations to pay a specific or increasing level of cash dividends to holders of our shares. Furthermore, holders of our shares should be aware that the amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items. We may incur other expenses or liabilities during a period that could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay dividends to shareholders during the period.
We are a holding company whose sole material assets consist of our interests in our subsidiaries. We do not have any independent means of generating revenue. We intend to cause our operating subsidiaries to make distributions to us in an amount sufficient to cover our corporate debt service, corporate general and administrative expenses, all applicable taxes payable and dividends, if any, declared by us. To the extent that we need funds for a quarterly cash dividend to holders of our shares or otherwise, and one or more of our operating subsidiaries is restricted from making such distributions under the terms of its financing or other agreements or applicable law and regulations or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition and limit our ability to pay dividends to shareholders. Our project-level financing agreements generally prohibit distributions to us unless certain specific conditions are met, including the satisfaction of financial ratios.
Because we are a holding company, our ability to pay dividends on our shares is limited by restrictions under the Revolving Credit Facility, the Note Issuance Facility 2019, the Green Private Placement and the Note Issuance Facility 2020 or legal, regulatory or other restrictions or limitations applicable in the various jurisdictions in which we operate, such as exchange controls or similar matters or corporate law limitations, any of which could change from time to time and thereby limit our subsidiaries’ ability to pay dividends or make other distributions to us.
Our cash available for distribution will likely fluctuate from quarter to quarter, in some cases significantly, due to seasonality. See “Item 4.B—Business Overview—Seasonality.” As result, we may reduce the amount of cash we distribute in a particular quarter to establish reserves to fund distributions to shareholders in future periods for which the cash distributions we would otherwise receive from our subsidiary project companies would otherwise be insufficient to pay our quarterly dividend. If we fail to establish sufficient reserves, we may not be able to maintain our quarterly dividend with a respect to a quarter adversely affected by seasonality.
Dividends to holders of our shares will be paid at the discretion of our Board of Directors. Our Board of Directors may decrease the level of or entirely discontinue payment of dividends. Our Board of Directors may change our dividend policy at any point in time or modify the dividend for specific quarters following prevailing conditions. For a description of additional restrictions and factors that may affect our ability to pay cash dividends, please see “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy.”
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Future sales of our shares by Algonquin or its lenders or by other substantial shareholders may cause the price of our shares to fall.
The market price of our shares could decline as a result of future sales by Algonquin of its shares in the market, or the perception that these sales could occur. Algonquin is the beneficial owner of approximately 44.2% of our ordinary shares. On November 28, 2018, AAGES obtained a secured credit facility in the amount of $306,500,000. The AAGES secured credit facility is collateralized through a pledge of the Atlantica shares held by a company participated by Algonquin. A collateral shortfall would occur if the net obligation as defined in the agreement would equal or exceed 50% of the market value of the Atlantica shares in which case the AAGES Credit Facility lenders would have the right to sell Atlantica shares to eliminate the collateral shortfall.
If AAGES defaulted on any of these financing arrangements, its lenders may foreclose on the shares and sell the shares in the market. Future sales of substantial amounts of the shares and/or equity-related securities in the public market, or the perception that such sales could occur, could adversely affect prevailing trading prices of the shares and could impair our ability to raise capital through future offerings of equity or equity-related securities. The price of the shares could be depressed by investors’ anticipation of the potential sale in the market of substantial additional amounts of shares. Disposals of shares could increase the number of shares being offered for sale in the market and depress the trading price of our shares.
As a “foreign private issuer” in the United States, we are exempt from certain rules under the U.S. securities laws and are permitted to file less information with the SEC than U.S. companies.
As a “foreign private issuer,” we are exempt from certain rules under the Exchange Act that impose certain disclosure obligations and procedural requirements for proxy solicitations under Section 14 of the Exchange Act. In addition, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules under the Exchange Act with respect to their purchases and sales of our shares. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act. In addition, we are not required to comply with Regulation FD, which restricts the selective disclosure of material information.
If we were to lose our “foreign private issuer” status, we would no longer be exempt from certain provisions of the U.S. securities laws we would be required to commence reporting on forms required of U.S. companies, and we could incur increased compliance and other costs, among other consequences.
The rights of our shareholders may differ from the rights typically offered to shareholders of a U.S. corporation organized in Delaware.
We are incorporated under English law. The rights of holders of our shares are governed by English law, including the provisions of the UK Companies Act 2006, and by our articles of association. These rights differ in certain respects from the rights of shareholders in typical U.S. corporations organized in Delaware. The principal differences are set forth in “Item 10.B—Memorandum and Articles of Association.”
There are limitations on enforceability of civil liabilities against us.
We are incorporated under the laws of England and Wales. Most of our officers and directors reside outside of the United States. In addition, a portion of our assets and the majority of the assets of our directors and officers are located outside the United States. As a result, it may be difficult or impossible to serve legal process on persons located outside the United States and to force them to appear in a U.S. court. It may also be difficult or impossible to enforce a judgment of a U.S. court against persons outside the United States, or to enforce a judgment of a foreign court against such persons in the United States. We believe that there may be doubt as to the enforceability against persons in England and Wales and in Spain, whether in original actions or in actions for the enforcement of judgments of U.S. courts, of civil liabilities predicated solely upon the laws of the United States, including its federal securities laws. Because we are a foreign private issuer, our directors and officers will not be subject to rules under the Exchange Act that under certain circumstances would require directors and officers to forfeit to us any “short-swing” profits realized from purchases and sales, as determined under the Exchange Act and the rules thereunder, of our equity securities. In addition, punitive damages in actions brought in the United States or elsewhere may be unenforceable in England and Wales or in Spain.
Shareholders in certain jurisdictions may not be able to exercise their pre-emptive rights if we increase our share capital.
Under our articles of association, holders of our shares generally have the right to subscribe and pay for a sufficient number of our shares to maintain their relative ownership percentages prior to the issuance of any new shares in exchange for cash consideration. Holders of shares in certain jurisdictions may not be able to exercise their pre-emptive rights unless securities laws have been complied with in such jurisdictions with respect to such rights and the related shares, or an exemption from the requirements of the securities laws of these jurisdictions is available. To the extent that such shareholders are not able to exercise their pre-emptive rights, the pre-emptive rights would lapse, and the proportional interests of such holders would be reduced.
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In addition, under the Shareholders Agreement, AAGES or Algonquin or both of them may subscribe to capital increases in cash for (i) up to 100.0% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under the AAGES or Algonquin ROFO Agreement; and (ii) up to 66.0% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under the Abengoa ROFO Agreement. If we issue ordinary shares for any other purpose, AAGES or Algonquin may subscribe in cash for our ordinary shares in a pro rata amount of such AAGES’ or Algonquin’s aggregate holding of voting rights in us. The Shareholders Agreement may be terminated or modified in the future.
Provisions in the UK City Code on Takeovers and Mergers may have anti-takeover effects that could discourage an acquisition of us by others, even if an acquisition would be beneficial to our shareholders.
The UK City Code on Takeovers and Mergers, or the Takeover Code, applies, among other things, to an offer for a public company whose registered office is in the United Kingdom and whose securities are not admitted to trading on a regulated market in the United Kingdom if the company is considered by the Panel on Takeovers and Mergers, or the Takeover Panel, to have its place of central management and control in the United Kingdom. This is known as the “residency test.” The test for central management and control under the Takeover Code is different from that used by the UK tax authorities. Under the Takeover Code, the Takeover Panel will determine whether we have our place of central management and control in the United Kingdom by looking at various factors, including the structure of our Board of Directors, the functions of the directors and where they are resident.
If at the time of a takeover offer the Takeover Panel determines that we have our place of central management and control in the United Kingdom, we would be subject to a number of rules and restrictions, including but not limited to the following: (1) our ability to enter into deal protection arrangements with a bidder would be extremely limited; (2) we may not, without the approval of our shareholders, be able to perform certain actions that could have the effect of frustrating an offer, such as issuing shares or carrying out acquisitions or disposals; and (3) we would be obliged to provide equality of information to all bona fide competing bidders.

| IX. | Risks Related to Taxation

Changes in our tax position can significantly affect our reported earnings and cash flows.
We have assets in different jurisdictions, which are subject to different tax regimes. Changes in tax regimes such as the reduction or elimination of tax benefits, or the reduction of tax rates overall in markets where we operate could adversely affect the market for investments in our projects by third parties. A reduction in corporate tax rates could make investments in renewable projects less attractive to potential tax equity investors, in which case we may not be able to obtain third-party financing on terms as beneficial as in the past, or at all, which could limit our ability to grow our business. Limitations on the deductibility of interest expense could reduce our ability to deduct the interest we pay on our debt. These and other potential changes in tax regulations could have a material adverse effect on our results and cash flows.
Changes in corporate tax rates and/or other relevant tax laws in the United Kingdom, the United States, Spain, Mexico or the other countries in which our assets are located may have a material impact on our future tax rate and/or our required tax payments. Such changes may include measures enacted in response to the ongoing initiatives in relation to fiscal legislation at an international level, such as the Action Plan on Base Erosion and Profit Shifting of the Organization for Economic Co-operation and Development. The final determination of our tax liability could be different from the forecasted amount, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. Changes to the U.K. controlled foreign company rules or adverse interpretations of them, could have an impact on our future tax rate and/or our required tax payments. With respect to some of our projects, we must meet defined requirements to apply favorable tax treatment, such as lower tax rates or exemptions. We intend to meet these requirements in order to benefit from the favorable tax treatment; however, there can be no assurance that we will be able to comply with all of the necessary requirements in the future, or the requirements could change or be interpreted in another manner, which could give rise to a greater tax liability and which may have a material adverse effect on our business, results of operations, financial condition and cash flows.
On December 31, 2020, the congress of Spain approved the General Budget Law for 2021. The new Law has introduced new limitations in certain incentives and deductions of the Corporate Income Tax for 2021 onwards. The most relevant modification contemplates a reduction in the tax exemption on dividends and capital gains received from affiliates from 100% to 95%. Despite the new limitation, we do not expect a significant impact in cash flows from our Spanish solar assets in the upcoming years.
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On June 29, 2020, California’s Governor signed AB 85, suspending California Net Operating Losses (“NOL”) utilization and imposing a cap on the amount of business incentive tax credits companies can utilize, effective for tax years 2020, 2021 and 2022. During these years, Mojave will not be able to use its NOLs to offset its state tax, which is set at approximately 8.9%. The years 2020 to 2022 will not be considered in the calculation of NOLs expiration, resulting in a suspension rather than a cancellation or shortening of the period of utilization of such NOLs. We expect to utilize the accumulated NOLs from 2022 onwards. However, we expect AB 85 will have a negative impact, which we estimate in the range of $6 to $7 million per year in distributions expected from Mojave from 2021 to 2023.
In addition, some countries where we operate, including the U.S. and South Africa, could implement tax reforms the content of which is largely unknown currently. These potential tax reforms could have a negative impact on our financial condition, results of operations and cash flows. Furthermore, tax laws and regulations are subject to interpretation. Our tax returns in each country are subject to inspection and even if we believe that we are complying with all regulations in each country, a tax inspector could have a different view, which may result in additional tax liabilities and may have a negative impact on our financial condition, results of operations and cash flows.
Our future tax liability may be greater than expected if we do not use sufficient NOLs to offset our taxable income.
We have NOLs that we can use to offset future taxable income. Based on our current portfolio of assets, which include renewable assets that benefit from an accelerated tax depreciation schedule, and subject to potential tax audits, which may result in income, sales, use or other tax obligations, we do not expect to pay significant taxes in the upcoming years.
Although we expect these NOLs will be available as a future benefit, in the event that they are not generated as expected, or are successfully challenged by the local tax authorities, such as the IRS or Her Majesty’s Revenue and Customs among others, by way of a tax audit or otherwise, or are subject to future limitations as discussed below, our ability to realize these benefits may be limited. A reduction in our expected NOLs, a limitation on our ability to use such NOLs or the occurrence of future tax audits may result in a material increase in our estimated future income tax liability and may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our ability to use U.S. NOLs to offset future income may be limited.
We have generated significant NOLs. For purposes of U.S. federal income taxation, NOLs generated on or before December 31, 2017 can generally be carried back two years and carried forward for up to twenty years and can be applied to offset 100% of taxable income in such years. As a result of the CARES Act, NOLs incurred between January 1, 2018 and December 31, 2020 may be carried forward indefinitely and carried back five years. Losses arising after December 31, 2020, cannot be carried back and are subject to limitations on their deductibility that may prevent us from using the NOLs to offset all taxable income in future years.
In addition, our ability to use U.S. NOLs generated is subject to the rules of Sections 382 of the IRC. This section generally restricts the use of U.S. NOLs if we were to experience an “ownership change” as defined under Section 382 of the IRC, and similar state rules. In general, an “ownership change” would occur if our “5-percent shareholders,” as defined under Section 382 of the IRC, collectively increased their ownership in us to more than 50 percentage points over a rolling three-year period. A corporation that experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change U.S. NOLs equal to the equity value of the corporation immediately before the ownership change, multiplied by the long-term tax-exempt rate for the month in which the ownership change occurs, and increased by a certain portion of any “built-in-gains.”
We have experienced ownership changes in the past. Future sales by our largest shareholder, future equity issuances and in general the activity of our direct or indirect shareholders may limit further our ability to use net operating loss carryforwards in the United States, which could have a potential adverse effect on cash flows from U.S. assets expected in the future. In addition, changes in our shareholder base during 2019 may have triggered an ownership change under Section 382 of the IRC. In addition, the Internal Revenue Service recently issued proposed regulations for the calculation of built-in gains and losses under Section 382. If enacted and depending on its final outcome, this new regulation may significantly limit our annual use of pre-ownership change U.S. NOLs in the event a new ownership change occurs after the new rule is in place.
In addition, because we have recorded tax credits for the U.S. tax losses carryforwards in the past, a limit to our ability to use U.S. NOLs could result in writing off tax credits, which could cause a substantial non-cash income tax expense in our financial statements.
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Distributions to U.S. Holders of our shares may be fully taxable as dividends.
It is difficult to predict whether or to what extent we will generate earnings or profits as computed for U.S. federal income tax purposes in any given tax year. If we make distributions on the shares from current or accumulated earnings and profits as computed for U.S. federal income tax purposes, such distributions generally will be taxable to U.S. Holders of our shares as ordinary dividend income for U.S. federal income tax purposes. Under current law, if certain requirements are met, such dividends would be eligible for the lower tax rates applicable to qualified dividend income of certain non-corporate U.S. Holders. While we expect that a portion of our distributions to U.S. Holders of our shares may exceed our current and accumulated earnings and profits as computed for U.S. federal income tax purposes, and therefore may constitute a non-taxable return of capital to the extent of a U.S. Holder’s basis in our shares, no assurance can be given that this will occur. We intend to calculate our earnings and profits annually in accordance with U.S. federal income tax principles. See “Item 10.E—Taxation—Material U.S. Federal Income Tax Considerations.”
If we are a passive foreign investment company for U.S. federal income tax purposes for any taxable year, U.S. Holders of our shares could be subject to adverse U.S. federal income tax consequences.
If we were a PFIC for any taxable year during which a U.S. Holder held our shares, certain adverse U.S. federal income tax consequences may apply to the U.S. Holder. We do not believe that we were a PFIC for our 2019 taxable year and do not expect to be a PFIC for U.S. federal income tax purposes for the current taxable year or in the foreseeable future. However, PFIC status depends on the composition of a company’s income and assets and the fair market value of its assets (including certain equity investments) from time to time, as well as on the application of complex statutory and regulatory rules that are subject to potentially varying or changing interpretations. Accordingly, there can be no assurance that we will not be considered a PFIC for any taxable year.
If we were a PFIC, U.S. Holders of our shares may be subject to adverse U.S. federal income tax consequences, such as taxation at the highest marginal ordinary income tax rates on capital gains and on certain actual or deemed distributions, interest charges on certain taxes treated as deferred, and additional reporting requirements. See “Item 10.E—Taxation—Material U.S. Federal Income Tax Considerations—Passive foreign investment company rules.”

| X. | General Risk Factors

The loss of one or more of our executive officers or key employees may adversely affect our ability to effectively manage our projects.
We depend on our experienced management team and the loss of one or more key executives may negatively affect our business. We also depend on our ability to retain and motivate key employees and attract qualified new employees. We may not be able to replace departing members of our management team or key employees. Integrating new executives into our management team and training new employees with no prior experience in our industry could prove disruptive to our projects, require a disproportionate amount of resources and management attention and ultimately prove unsuccessful. An inability to attract and retain sufficient technical and managerial personnel could limit our ability to effectively manage our projects, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
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ITEM 4 | INFORMATION ON THE COMPANY

A. | History and Development of the Company

We are a sustainable infrastructure company that owns and manages renewable energy, storage, efficient natural gas, transmission and transportation infrastructure and water assets. We currently have operating facilities in North America (United States, Canada and Mexico), South America (Peru, Chile and Uruguay) and EMEA (Spain, Algeria and South Africa). Our portfolio consists of 28 assets with 1,591 MW of aggregate renewable energy installed generation capacity (of which approximately 90% is solar), 343 MW of efficient natural gas-fired power generation capacity, 1,166 miles of electric transmission lines and 17.5 M ft3 per day of water desalination. In 2020, our renewable sector represented approximately 74% of our revenue with solar energy representing approximately 70%.
We were incorporated in England and Wales as a private limited company on December 17, 2013. On June 18, 2014, we completed our IPO and our shares are listed on the NASDAQ Global Select Market under the symbol “AY.” The address of our principal executive offices is Great West House, GW1, 17th floor, Great West Road, Brentford, TW8 9DF, United Kingdom, and our phone number is +44 203 499 0465. Our current agent in the U.S. is ASHUSA, Inc., a Delaware company with its principal office located at 1553 W. Todd Drive, Suite 204, Tempe, Arizona 85283, United States.
Prior to the consummation of our IPO, Abengoa transferred ten assets to us and since then our portfolio has grown through acquisitions and investments. On November 1, 2017, Algonquin agreed to acquire 25.0% of our shares from Abengoa and upon completion of the Share Sale, became our largest shareholder. On November 27, 2018, Algonquin acquired from Abengoa the remaining 16.5% of our shares previously held by Abengoa and in 2019, Algonquin progressively increased its stake in our shares up to 44.2%.
Acquisitions
Historical acquisitions
Following our IPO in 2014, we completed a series of four dropdown asset acquisitions with Abengoa including Solacor 1 & 2, PS 10 & 20, Cadonal, Honaine, Skikda, Helioenergy 1 & 2, Helios 1 & 2, Solnova 1, 3 & 4, Kaxu, ATN2 and Solaben 1 & 6. In 2016 and 2017, we acquired a stake in a transmission line in the United States from Abengoa and in Seville PV. In 2018, we acquired Mini-Hydro, ATN Expansion 1, Chile TL3 and Melowind from third parties. See “—Business Overview—Our Operations”.
2019 acquisitions
In January 2019, we entered into an agreement with Abengoa under the Abengoa ROFO Agreement for the acquisition of Tenes and paid $19.9 million as an advance payment. Closing of the acquisition was subject to certain conditions precedent, which were not fulfilled. In accordance with the terms of the share purchase agreement, the advance payment was converted into a secured loan to be reimbursed by Befesa Agua Tenes, together with 12% per annum interest, through a full cash-sweep of all the dividends to be received from the asset. In October 2019, we received a first payment of $7.8 million through the cash sweep mechanism. On May 31, 2020, we entered into a new $4.5 million secured loan agreement with Befesa Agua Tenes. This new loan is expected to be reimbursed no later than May 31, 2032, together with 12% interest per annum, through a full cash-sweep of all the dividends to be received from the asset. In addition, the new agreement provides us with certain additional decision rights, a call option over the shares of Befesa Agua Tenes at a price of $1 and a majority at the Board of Directors of Befesa Agua Tenes. Therefore, we have concluded that we have had control over Tenes since May 31, 2020 and as a result we have fully consolidated the asset from that date.
On May 31, 2019, we entered into an agreement with Abengoa to acquire a 15% stake in Rioglass, a multinational manufacturer of solar components in order to secure certain Abengoa obligations. The investment was $7 million and is classified as held for sale.
On August 2, 2019 we acquired a 30% stake in Monterrey, a 142 MW gas-fired engine facility including 130 MW installed capacity and 12 MW battery capacity. We paid $42 million for the total equity investment. The asset, located in Mexico, has been in operation since 2018 and represents our first investment in electric batteries. It has a U.S. dollar-denominated 20-year PPA with two international large corporations engaged in the car manufacturing industry as well as a 20-year contract for the natural gas transportation from Texas with a U.S. energy company. The PPA also includes price escalation factors. The asset has no commodity risk and may have the possibility to sell excess energy to the North-East region of the country. We also entered into a ROFO agreement with the seller of the shares for the remaining 70% stake in the asset.
On August 2, 2019, we closed the acquisition of ASI Operations, the company that performs the operation and maintenance services to Solana and Mojave plants. The consideration paid was $6 million.
In October 2019, we closed the acquisition of ATN Expansion 2, for a total equity investment of approximately $20 million. The off-taker is Enel Green Power Peru.
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2020 and 2021 acquisitions
On April 3, 2020 we made an investment in the creation of a renewable energy platform in Chile, together with financial partners, in which we now own approximately a 35% stake and have a strategic investor role. The first investment was the acquisition of a 55 MW solar PV plant in an area with excellent solar resource (Chile PV 1). This asset, has been in operation since 2016, demonstrating a good operating track record during that period while selling its production to the Chilean power market. Our initial contribution was approximately $4 million. On January 6, 2021 we also closed our second investment through the platform with the acquisition of Chile PV 2, a 40 MW PV plant. This asset started commercial operation in 2017 and its revenue is partially contracted. Total equity investment in this new asset was approximately $5.0 million. We have concluded that we have control over these assets, and we are fully consolidating it since each acquisition date. The platform intends to make further investments in renewable energy in Chile and sign PPAs with creditworthy off-takers.
On August 17, 2020 we closed the acquisition of the Liberty ownership interest in Solana. Liberty was the tax equity investor in Solana. Total equity investment is expected to be up to $290 million of which $272 million has already been paid. The total price includes a deferred payment and a performance earn-out based on the average annual net production of the asset in the four calendar years with the highest annual net production during the five calendar years of 2020 through 2024.
In October 2020 we reached an agreement to acquire Calgary District Heating, a district heating asset in Canada for a total equity investment of approximately $20 million. Calgary District Heating has been in operation since 2010 and represents our first investment in this sector, a sector which has been recognized by the UN Environment Program as being a key measure for cities to reduce their emissions. The asset provides heating services to a diverse range of government, institutional and commercial customers in the city of Calgary. It has availability-based revenue with inflation indexation and 20 years of weighted average contract life. Contracted capacity and volume payments represent approximately 80% of the total revenue. Closing is expected by mid-2021 subject to customary conditions precedent and regulatory approvals.
In December 2020 we reached an agreement with Algonquin to acquire La Sierpe, a 20 MW solar asset in Colombia for a total equity investment of approximately $20 million. Closing is expected to occur after the asset reaches commercial operation, currently expected to occur by mid-2021. Closing is subject to customary conditions precedent and regulatory approvals. Additionally, we agreed to potentially co-invest with Algonquin in additional solar plants in Colombia with a combined capacity of approximately 30 MW to be developed and built by AAGES.
In December 2020, we reached an agreement to acquire Coso, a 135 MW renewable asset in California. Coso is the third largest geothermal plant in the United States and provides base load renewable energy to the California ISO. It has PPAs signed with three investment grade offtakers, with a 19-year average contract life. Closing is subject to customary regulatory approvals and is expected to occur in the first half of 2021. The total investment is expected to be approximately $170 million, including approximately $130 million for the equity and $40 million expected to be invested in reducing project debt.
In January 2021 we reached an agreement to increase our equity stake from 15% up to 100% in Rioglass, a multinational manufacturer of solar components. We have closed the acquisition of 42.5% equity stake, for which we paid $7 million. In addition, we have an option to acquire the remaining 42.5% in the same conditions until September 2021, and after that date the seller has an option to sell the 42.5% also in the same conditions. We intend to find partners to co-invest in the company, as such we expect to classify the investment as held for sale in our consolidated financial statements.
In October 2018, we reached an agreement to acquire PTS, a natural gas transportation platform located in Mexico, close to ACT. PTS has a service agreement signed in October 2017, which is a “take-or-pay” 11-year term contract starting in 2020. We initially acquired a 5% ownership in the project and have an agreement to acquire an additional 65% stake subject to the asset entering into commercial operation, non-recourse project financing being closed and final approvals and customary conditions, including the absence of material adverse effects. Our partner in this asset is also negotiating to sell part of its business, which may include the company that provides operation and maintenance services to PTS. This sale may require change of control waivers and may make the closing of the acquisition more difficult. Additionally, our partner has proposed a number of modifications to the project and in the financing agreements. We are currently monitoring the situation in order to decide if we will proceed with the investment or not. We therefore cannot guarantee that we will close this acquisition or that closing will occur on the terms originally agreed.
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B. | Business Overview

Overview
We are a sustainable infrastructure company with a majority of our business in renewable energy assets. In 2020, our renewable sector represented approximately 74% of our revenue with solar energy representing approximately 70%. We complement our renewable assets portfolio with storage, efficient natural gas and transmission infrastructure assets, as enablers of the transition towards a clean energy mix. We are also present in water infrastructure assets, a sector at the core of sustainable development. Our purpose is to support the transition towards a more sustainable world by investing in and managing sustainable infrastructure, while creating long-term value for our investors and the rest of our stakeholders.
As of the date of this annual report, we own or have an interest in a portfolio of diversified assets in terms of business sector and geographic footprint. Our portfolio consists of 28 assets with 1,591 MW of aggregate renewable energy installed generation capacity (of which approximately 90% is solar), representing 74.3% out of our total revenue, 343 MW of efficient natural gas-fired power generation capacity, 1,166 miles of electric transmission lines and 17.5 M ft3 per day of water desalination.
We currently own and manage operating facilities in North America (United States, Canada and Mexico), South America (Peru, Chile, and Uruguay) and EMEA (Spain, Algeria and South Africa). We intend to expand our portfolio, while maintaining North America, South America and Europe as our core geographies.
Our assets generally have contracted revenue (regulated revenue in the case of our Spanish assets and one transmission line in Chile). We focus on long-life facilities as well as long-term agreements that we expect to produce stable, long-term cash flows. As of December 31, 2020, our assets had a weighted average remaining contract life of approximately 17 years. Most of the assets we own, or which we hold an interest in have project-finance agreements in place. We intend to grow our cash available for distribution and our dividend to shareholders through organic growth and by acquiring new assets and/or businesses where revenue may not be fully contracted.
We intend to take advantage of, and leverage our growth strategy on, favorable trends in clean power generation, energy scarcity and the focus on the reduction of carbon emissions. Our portfolio of operating assets and our strategy focus on sustainable technology including renewable energy, storage, efficient natural gas, and transmission networks as enablers of a sustainable power generation mix and on water infrastructure. Renewable energy is expected to represent, in most markets, the majority of new investments in the power sector, according to Bloomberg New Energy Finance 2020. Approximately 68% of the world’s power generation by 2050 is expected to come from renewable energy sources, which indicates that renewable energy is becoming mainstream. Global installed capacity is expected to shift from 56% fossil fuels today to approximately two-thirds renewables by 2050. A 14-terawatt expansion of generating capacity is estimated to require approximately $15.1 trillion of new investment between now and 2050 – of which approximately 73% is expected to go to renewables. Another approximately $1 trillion of investment is expected in batteries along with an estimated $14 trillion expected to go to transmission and distribution during that same period. Regions will need to complement investments in renewable energy with investments in storage, efficient natural gas and in transmission networks. Atlantica is well positioned to benefit from the expected transition towards a more sustainable power generation mix. In addition, we believe that water is going to be the next frontier in a transition towards a more sustainable world. New sources of water are needed worldwide, and thus water desalination and transportation infrastructure should help make that possible. We currently participate in three water desalination plants with a total capacity of 17.5 million cubic feet per day.
We believe we can achieve organic growth through the optimization of the existing portfolio, escalation factors at many of our assets and the expansion of current assets, particularly our transmission lines, to which new assets can be connected. We currently own three transmission lines in Peru and four in Chile. We believe that current regulations in Peru and Chile should provide an opportunity for growth via the expansion of transmission lines to connect new clients. Additionally, we should have repowering opportunities in certain existing renewable energy assets.
Additionally, we expect to acquire assets from third parties leveraging the local presence and network we have in geographies and sectors in which we operate. We have also entered into and intend to enter into agreements or partnerships with developers and asset owners to acquire assets. We also invest directly and through investment vehicles with partners in assets under development or construction.
We have signed a ROFO agreement with AAGES, a joint venture designed to invest in the development and construction of contracted clean energy and water infrastructure contracted assets, created by Algonquin, a North American diversified generation, transmission and distribution utility company that owns a 44.2% stake in our capital stock.
With this business model, our objective is to pay a consistent and growing cash dividend to shareholders that is sustainable on a long-term basis. We expect to distribute a significant percentage of our cash available for distribution as cash dividends and we will seek to increase such cash dividends over time through organic growth and through the acquisition of assets. Pursuant to our cash dividend policy, we intend to pay a cash dividend each quarter to holders of our shares.
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Current Operations
Our assets are organized into the following four business sectors: Renewable Energy, Efficient Natural Gas, Electric Transmission and Water. The following table provides an overview of our current assets:

Assets | Type | Ownership | Location | Currency(9) | Capacity (Gross) | Counterparty Credit Ratings(10) | COD* | Contract Years Left(14)
Solana | Renewable (Solar) | 100% | Arizona (USA) | USD | 280 MW | A-/A2/A- | 2013 | 23
Mojave | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB-/WR/BB | 2014 | 19
Chile PV 1 | Renewable (Solar) | 35%(8) | Chile | USD | 55 MW | N/A | 2016 | N/A
Chile PV 2 | Renewable (Solar) | 35%(8) | Chile | USD | 40 MW | N/A | 2017 | N/A
Solaben 2 & 3 | Renewable (Solar) | 70%(1) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 17/17
Solacor 1 & 2 | Renewable (Solar) | 87%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 16/16
PS10 & PS20 | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007& 2009 | 11/13
Helioenergy 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 16/16
Helios 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 16/17
Solnova 1, 3 & 4 | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 14/14/15
Solaben 1 & 6 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 18/18
Seville PV | Renewable (Solar) | 80%(6) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 15
Kaxu | Renewable (Solar) | 51%(3) | South Africa | Rand | 100 MW | BB/Ba2/ BB-(11) | 2015 | 14
Palmatir | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 13
Cadonal | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 14
Melowind | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB- | 2015 | 15
Mini-Hydro | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB+/A3/BBB+ | 2012 | 12
ACT | Efficient natural gas | 100% | Mexico | USD | 300 MW | BBB/ Ba2/ BB- | 2013 | 12
Monterrey | Efficient natural gas | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 18
ATN (13) | Transmission line | 100% | Peru | USD | 379 miles | BBB+/A3/BBB+ | 2011 | 20
ATS | Transmission line | 100% | Peru | USD | 569 miles | BBB+/A3/BBB+ | 2014 | 23
ATN 2 | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 12
Quadra 1 & 2 | Transmission line | 100% | Chile | USD | 49 miles/ 32 miles | Not rated | 2014 | 14/14
Palmucho | Transmission line | 100% | Chile | USD | 6 miles | BBB+/Baa1/ A- | 2007 | 17

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Chile TL3 | Transmission line | 100% | Chile | USD | 50 miles | A+/A1/A- | 1993 | Regulated
Skikda | Water | 34.2%(4) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 13
Honaine | Water | 25.5%(5) | Algeria | USD | 7 M ft3/ day | Not rated | 2012 | 17
Tenes | Water | 51%(7) | Algeria | USD | 7 M ft3/ day | Not rated | 2015 | 19

Notes:

(1) | Itochu Corporation, a Japanese trading company, holds 30% of the shares in both Solaben 2 and Solaben 3.

(2) | JGC, a Japanese engineering company, holds 13% of the shares in each of Solacor 1 and Solacor 2.

(3) | Kaxu is owned by the Company (51%), Industrial Development Corporation of South Africa (29%) and Kaxu Community Trust (20%).

(4) | Algerian Energy Company, SPA owns 49% of Skikda and Sacyr Agua, S.L. owns the remaining 16.83%.

(5) | Algerian Energy Company, SPA owns 49% of Honaine and Sacyr Agua, S.L. owns the remaining 25.5%.

(6) | Instituto para la Diversificación y Ahorro de la Energía (“Idae”), a Spanish state-owned company, holds 20% of the shares in Seville PV.

(7) | Algerian Energy Company, SPA owns 49% of Tenes.

(8) | 65% of the shares in Chile PV 1 and Chile PV 2 are held by financial partners at our renewable energy platform in Chile.

(9) | Certain contracts denominated in U.S. dollars are payable in local currency.

(10) | Reflects the counterparty’s credit ratings issued by Standard & Poor’s Ratings Services, or S&P, Moody’s Investors Service Inc., or Moody’s, and Fitch Ratings Ltd, or Fitch.

(11) | Refers to the credit rating of the Republic of South Africa. The offtaker is Eskom, which is a state-owned utility company in South Africa.

(12) | Refers to the credit rating of Uruguay, as UTE (Administración Nacional de Usinas y Transmisoras Eléctricas) is unrated.

(13) | Including the acquisition of ATN Expansion 1 & 2.

(14) | As of December 31, 2020.

(*) | Commercial Operation Date.

Our Business Strategy
Our strategy focuses on climate change solutions in the power and water sectors. We intend to provide clean electricity, transmission capacity and desalinated water in a safe, reliable and environmentally responsible way. We believe that by investing in sustainable sectors and managing our assets in a sustainable manner we will create more value over time to our shareholders and to the rest of our stakeholders.
We manage and efficiently operate our portfolio of renewable energy, storage, efficient natural gas, transmission and transportation infrastructure and water assets to generate stable cash flows. Our assets generally have long-term contracts or regulation in place. We intend to distribute a stable cash dividend to our shareholders.
We seek to grow our cash available for distribution and our dividend to shareholders through organic growth and by investing in new assets, while ensuring the ongoing stability and sustainability of our business. We believe that our diversification by business sector and geography provides us with access to different sources of growth. We intend to grow our business maintaining renewable energy as our main segment and with a focus in North and South America.
We expect to deliver organic growth through the optimization of the existing portfolio and through investments in the expansion of our current assets, particularly in our transmission lines and renewable energy sectors. In addition, we expect to acquire assets from third parties leveraging the local presence and network we have in geographies and sectors in which we operate. We have also entered into and intend to enter into agreements or partnerships with developers or asset owners to acquire assets. We also invest directly and through investment vehicles with partners in assets under development or construction. We also expect to acquire assets through our ROFO agreement with AAGES. AAGES is a development company created by Algonquin and designed to invest in the development and construction of contracted clean energy and contracted water infrastructure assets, with whom we have signed a ROFO agreement.
Our plan for executing this strategy includes the following key components:
Focus on stable, long-term contracted or regulated assets in the power and water sectors, including renewable energy, storage, efficient natural gas generation, transmission and transportation infrastructure, district heating assets as well as water assets
We intend to focus on owning and operating stable, sustainable infrastructures, with long useful lives, generally contracted, for which we believe we have extensive experience and proven systems and management processes, as well as the critical mass to benefit from operating efficiencies and scale. We expect this to allow us to maximize value and cash flow generation. We intend to maintain a diversified portfolio with a large majority of our Adjusted EBITDA generated from low-carbon footprint assets, as we believe these technologies will see significant growth in our targeted geographies.
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Maintain diversification across three core geographic areas
Our focus on three core geographies, North America, South America and Europe, helps to ensure exposure to markets in which we believe the renewable energy, storage, efficient natural gas and transmission and transportation sectors will continue to grow significantly.
Increase cash available for distribution through the optimization of the existing portfolio and through the investments in the expansion of our current assets, particularly in our transmission lines, to which new assets can be connected and in our renewable energy assets.
We intend to grow our cash available for distribution to shareholders through organic growth that we expect to deliver through the optimization of the existing portfolio, price escalation factors in many of our assets as well as through investments in the expansion of our current assets, particularly in our transmission lines and renewable energy assets.
We currently own three transmission lines in Peru and four in Chile. Current regulations in Peru and Chile provide growth opportunities via the expansion of transmission lines to connect new clients.
We have identified several opportunities to grow organically in Peru and Chile by expanding our existing assets. These opportunities consist of (i) new clients that need to use our assets, in situations where virtually no investment is required from us, while we will gain additional revenue from these new business opportunities and (ii) expansion of existing transmission lines to grant access to new clients. In this case, certain investments are required to build new assets that enable new clients to connect to our current backbone transmission lines. We would expect that in some cases these new assets would become part of our concession asset contracts, for which we would be remunerated.
In renewable energy we expect to find opportunities to expand some of our assets or to repower them.
Increase cash available for distribution by investing in new sustainable infrastructure, including renewable energy, storage, efficient natural gas, transmission and transportation infrastructure, district heating as well as water assets
We will seek to grow our cash available for distribution to shareholders by investing in new assets, generally contracted or regulated. We expect to acquire assets from third parties leveraging the local presence and network we have in the geographies and sectors in which we operate. We have also entered into and intend to enter into agreements or partnerships with developers or asset owners to acquire assets. We also invest in assets under development or construction either directly or with partners via investment vehicles. We also have a ROFO agreement with AAGES. We believe that our know-how and operating expertise in our key markets together with a critical mass of assets in several geographic areas as well as our access to capital provided by being a listed company will assist us in achieving our growth plans.
Foster a low-risk approach
We intend to maintain a portfolio of contracted assets with a low-risk profile for a significant part of our revenue. A large majority of our revenue is contracted or regulated. We mitigate the risk of our investments by pursuing proven technologies in which we generally have significant experience, located in countries where we believe conditions to be stable and safe. In certain situations, we could invest, or co-invest with partners, in assets under development, in assets with shorter or partially contracted revenue period, or subject to regulation, or in assets with revenue in currencies other than U.S. dollar or euro.
Additionally, our policies and management systems include thorough risk analysis and risk management processes that we apply whenever we acquire an asset, and which we are obligated to review periodically throughout the life of the asset. Our policy is to insure all of our assets whenever economically feasible, retaining in some cases part of the risk in house.
Maintain a prudent financial policy and financial flexibility
Project debt is an important principle for us. We intend to finance our assets with project debt progressively amortized using the cash flows from each asset and where lenders do not have recourse to the holding company assets. The majority of our consolidated debt is project debt.
In addition, we hedge a significant portion of our interest rate risk exposure. We estimate that as of December 31, 2020, approximately 93% of our total interest risk exposure was fixed or hedged, generally for the long-term. We also intend to limit our foreign exchange exposure. We intend to ensure that at least 80% of our cash available for distribution is always in U.S. dollars and euros. Furthermore, we hedge net distributions in euros for the upcoming 24 months on a rolling basis.
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We intend to maintain a solid financial position through a combination of cash on hand and undrawn credit facilities. In order to maintain financial flexibility, we use diversified sources of financing in our project and corporate debt including banks, capital markets and private investor financing. In recent years we have been active in green financing initiatives, improving our access to new debt investors.
Our Competitive Strengths
We believe that we are well-positioned to execute our business strategies thanks to the following competitive strengths:
Stable and predictable long-term cash flows
We believe that our portfolio of sustainable infrastructure has a stable cash flow profile. The off-take agreements or regulation in place at our assets have a weighted average remaining term of approximately 17 years as of December 31, 2020, providing long-term cash flow visibility. In 2020, approximately 55% of our revenue was related to availability payments in the different business sectors in which we operate, which includes our transmission lines, our efficient natural gas plant ACT, our water assets and approximately 70% of the revenue received from our Spanish solar assets. In these assets, our revenue does not depend (or has low dependence) on solar or wind resources, which translates in a more stable cash-flow generation. Additionally, our facilities have minimal or no fuel risk.
Our diversification by geography and business sector also strengthens the stability of our cash flow generation. We expect our well-diversified asset portfolio, in terms of business sector and geography to maintain cash flow stability.
Furthermore, due to the fact that we are a U.K. registered company, we should benefit from a more favorable treatment than would apply if we were a corporation based in the United States when receiving dividends from our subsidiaries that hold our international assets because they should generally be exempt from U.K. taxation due to the U.K.’s distribution exemption. Based on our current portfolio of assets, which includes renewable assets that benefit from an accelerated tax depreciation schedule, and tax regulations benefits permitted in the jurisdictions in which we operate, we do not expect to pay significant income tax in the upcoming years in most of our geographies due to existing net operating losses, or NOLs. See “Item 3.D—Risk Factors—Risks Related to Taxation—Our future tax liability may be greater than expected if we do not use NOLs sufficient to offset our taxable income,” “Item 3.D—Risk Factors—Risks Related to Taxation—Our ability to use U.S. NOLs to offset future income may be limited” and “Item 3.D—Risk Factors—Risks Related to Taxation—Changes in our tax position can significantly affect our reported earnings and cash flows.” Furthermore, based on our existing portfolio of assets, we believe that there is limited repatriation risk in the jurisdictions in which we operate. See “Item 3.D—Risk Factors—Risks Related to Our Business and the Markets in Which We Operate—We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.”
Positioned in business sectors with high growth prospects
The renewable energy industry has grown significantly in recent years and it is expected to continue to grow in the coming decades. According to Bloomberg New Energy Finance 2020, renewable energy is expected to account for the majority of new investments in the power sector in most markets. By 2050, approximately 68% of the world’s power generation is expected to come from renewable energy sources, demonstrating that renewable energy is becoming mainstream. Global installed capacity is expected to shift from 56% fossil fuels today to approximately two-thirds renewables by 2050. A 14-terawatt expansion of generating capacity is estimated to require approximately $15.1 trillion of new investment between now and 2050 – of which approximately 73% is expected to go to renewables. Another approximately $1 trillion of investment is expected in batteries along with an estimated $14 trillion in transmission and distribution during that same period. The significant increase expected in the renewable energy space over the coming decades also requires significant new investments in electric transmission and distribution lines for power supply, as well as storage and natural gas generation for dispatchability, with each becoming key elements to support wind and solar energy generation. We believe that we are well positioned in sectors with solid growth expectations.
We also believe that our exposure to international markets will allow us to pursue improved growth opportunities and achieve higher returns than we would have if we had a narrow geographic or technological focus. If certain geographies and business sectors become more competitive for asset acquisitions for some time, we believe we can continue to execute on our growth strategy investing in other regions or in other business sectors where we are present.
Well positioned in ESG
In 2020, 73.6% of our Adjusted EBITDA related to renewable energy and 69.4% of our Adjusted EBITDA corresponded to solar energy production. Adjusted EBITDA including unconsolidated affiliates from low carbon footprint represented 87.3%, including renewable energy, transportation and transmission infrastructure, district heating as well as water assets. We have set a target to maintain over 80% of our Adjusted EBITDA including unconsolidated affiliates generated from low-carbon footprint. We have also set a target to reduce our Greenhouse Gas Emissions per unit of energy generated by 10% by 2030.
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In terms of the social dimension of ESG, health and safety is our number one priority and we have continued to improve our key metrics. 2020 was the sixth consecutive year we have improved our key health and safety indicators, achieving a Lost Time Injury Rate of 0.3 and a Total-Record Incident Rate of 1.0. During the last few months we proactively donated protective equipment and basic goods to some of the COVID-19 affected local communities where we operate.
In terms of governance, we maintain a simple structure with one class of shares. The majority of our Directors are independent, and all the board committees are formed exclusively by independent directors. In 2020, the Board approved a board diversity policy. 25% of our directors are women.
We have been rated by various ESG rating agencies, which we believe can provide relevant information for investors.
A sustainable growth strategy
We expect to acquire assets from third parties leveraging the local presence and network we have in geographies and sectors in which we operate. We have also entered into and intend to enter into agreements or partnerships with developers or asset owners to acquire assets that are either in operation, or under construction or development. We also invest in assets under development or construction either directly, or with partners via investment vehicles. We also have a ROFO agreement with AAGES.
Our Operations
Renewable energy
Solana
Overview. Solana is a 250 MW net (280 MW gross) solar plant located in Maricopa County, Arizona, approximately 70 miles southwest of Phoenix. Solana uses a conventional parabolic trough solar power system to generate electricity, including a 22-mile 230kV transmission line and a molten salt thermal energy storage system. Solana reached COD on October 9, 2013.
PPA. Solana has a 30-year, fixed-price PPA with Arizona Public Service Company, or APS, for at least 110% of the output of the project. The PPA provides for the sale of electricity at a fixed base price approved by the Arizona Corporation Commission with annual increases of 1.84% per year. The PPA includes on-going performance obligations. The PPA expires in 2043.
O&M. ASI Operations, one of our subsidiaries, provides O&M services for Solana.
Operations. Solana has not yet achieved its technical capacity on a continuous basis. During the last few years, repairs and improvements were conducted on the steam generator, the water plant and the storage system. In 2020, availability in the storage system was lower than expected due to certain leaks in the storage system in the first quarter of 2020. Improvements and equipment replacements are required over time, which have impacted production in 2020 and will continue to impact production in 2021, with the exact scope and timing of repairs subject to review. Solana has a cash repair reserve account funded with approximately $54 million that we expect to use partially or totally for this purpose. We cannot assure that the improvements and equipment replacements made will be effective or sufficient.
Project Level Financing. Solana received a loan from the FFB in December 2010, with a guarantee from the DOE. The long-term tranche is payable over a 29-year term and has an average fixed interest rate of 3.67%. The principal balance was $777 million as of December 31, 2020. The FFB loan permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.2x.
Partnerships. In 2013, Abengoa entered into an agreement with Liberty, pursuant to which Liberty agreed to invest $300 million for all of the Class A membership interests of ASO Holdings Company LLC, the parent of Arizona Solar, as a tax equity investor. On August 17, 2020, we closed the acquisition of the Liberty Ownership Interest in Solana (See “—Acquisitions—2020 and 2021 acquisitions”). Since then we are the sole owner of the asset.
Mojave
Overview. Mojave is a 250 MW net (280 MW gross) solar plant wholly-owned by us located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Mojave relies on a conventional parabolic trough solar power system to generate electricity. Mojave reached COD in December 2014.
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PPA. Mojave has a 25-year, fixed-price PPA with Pacific Gas & Electric Company, or PG&E, for 100% of the output of Mojave which began on COD. The PPA provides for the sale of electricity at a fixed base price with seasonal adjustments and adjustments for time of delivery. Mojave can deliver and receive payment for at least 110% of contracted capacity under the PPA. The PPA expires in 2039.
On January 29, 2019, PG&E filed for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of California and on July 1, 2020 PG&E emerged from Chapter 11. See “Item 3.D—Risk Factors— Counterparties to our off-take agreements may not fulfill their obligations and, as our contracts expire, we may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which we operate.”
PG&E has senior unsecured credit ratings of BB- from S&P, WR from Moody’s and BB from Fitch.
O&M. ASI Operations, one of our subsidiaries, provides O&M services for Mojave.
Project Level Financing. Mojave received a loan from the FFB in September 2011, with a guarantee from the DOE. The long-term tranche is payable over a 25-year term. The FFB loan has an average fixed interest rate of 2.75%. The principal balance of this tranche was $694 million as of December 31, 2020. The financing arrangement permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.20x. As a result of the PG&E Chapter 11, a technical event of default was triggered under our Mojave project finance agreement in July 2019 and the asset was not able to make distributions in 2019. The technical event of default was cured in 2020 after PG&E emerged from Chapter 11 and we made distributions from Mojave in 2020.
Chile PV 1 and Chile PV 2
In April 2020 we made an investment in the creation of a renewable energy platform in Chile, together with financial partners, where we now own approximately a 35% stake and have a strategic investor role. The platform intends to make further investments in renewable energy in Chile and sign PPAs with credit worthy off-takers.
Overview: Chile PV 1 and Chile PV 2 are two solar plants with 55 MW and 40 MW respectively. Both assets are owned through the renewable energy platform created in Chile in 2020. Chile PV 1 reached COD in 2016 and Chile PV 2 reached COD in 2017.
PPA: Chile PV 1 sells its production in the Chilean power market. Chile PV 2 has a PPA signed for part of its production.
O&M: Chile PV 1 and Chile PV 2 have O&M agreements with third parties.
Project Level Financing: The renewable energy platform has long-term project finance agreements in place in US$ for approximately $100 million. Payments are made semi-annually. The debt bears interest based on six-month LIBOR and more than 75% has been hedged. The financing arrangements permit dividend distributions at least once per year subject to meeting the debt service coverage ratios required by contract.
Spanish Solar Assets
We own a portfolio of solar assets in Spain which are all subject to the same regulation. Renewable assets in Spain sell the power they produce into the wholesale electricity market and receive additional payments from the CNMC, the Spanish state-owned regulator. Solar power plants receive, in addition to the revenue from the sale of electricity in the market, two monthly payments. These payments consist of: (i) a fixed monthly payment based on installed capacity, and (ii) a variable payment based on net electricity produced.
There is a maximum number of production hours per year beyond which no variable payment is received. The regulation also includes a minimum number of yearly hours of generation, under which the plant would receive no regulated payments for that year and another higher threshold below which regulated payments would be reduced for a certain year. Those numbers are 35.0% and 60.0% of the maximum yearly hours, respectively. None of our plants has failed to meet these thresholds since our IPO in 2014. See “—Regulation—Regulation in Spain.”
The portfolio of solar assets in Spain consist of solar platforms generally of two 50 MW solar plants, with the exception of Solnova 1, 3 & 4, (which has three 50 MW solar plants) and PS10 & 20 (which is a 31 MW solar power complex). Except for PS10 & PS20, all the assets rely on a conventional parabolic trough solar power system to generate electricity, which is similar to the technology used in other solar power plants that we own in the United States.
O&M services are provided by Abengoa through all-in contracts, except for Seville PV, where O&M services are provided by Prodiel.
These assets benefit from the tax accelerated depreciation regime established by the Spanish Corporate Income Tax Act.
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Solaben 2 & 3
Overview. Solaben 2 and Solaben 3 are two 50 MW solar plants located in Extremadura, Spain. Atlantica owns 70% of each asset and Itochu, a Japanese trading company, owns the remaining 30%. The assets reached COD in 2012.
O&M. Abengoa provides O&M services under an all-in contract that we could terminate every third year starting in December 2015.
Project Level Financing. In December 2010, Solaben 2 and Solaben 3 each entered into a euro denominated 20-year loan agreement with a syndicate of banks. The loan for Solaben 2 was for €169.3 million and the loan for Solaben 3 was for €171.5 million. The interest rate for each loan is a floating rate based on six-month EURIBOR plus a margin of 1.5%. We hedged our EURIBOR exposure:

| - | 40% through a swap set at approximately 3.7% for the duration of the loans.

| - | 60% through a cap set at approximately 1% until 2025.

| - | From January 2026 40% through a cap with approximately 3.75% strike for the duration of the loans.

The outstanding amount of these loans as of December 31, 2020 was $138 million for Solaben 2 and $141 million for Solaben 3. The financing arrangements permit cash distribution to shareholders twice per year if the debt service coverage ratio is at least 1.10x.
In addition, on April 8, 2020, Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 2 & 3 and Solaben 1 & 6 entered into the Green Project Finance with ING Bank, B.V. and Banco Santander S.A. The facility is a green project financing euro-denominated agreement that has a notional of €140 million of which 25% is progressively amortized over its 5-year term and the remaining 75% is expected to be refinanced at maturity. The Green Project Finance is guaranteed by the shares of Logrosan and its lenders have no recourse to Atlantica corporate level. Interest accrue at a rate per annum equal to the sum of 6-month EURIBOR plus a margin of 3.25% and we hedged the EURIBOR with a 0% cap for the total amount and the entire life of the loan. The outstanding amount of this facility as of December 31, 2020, was $165 million. The Green Project Finance permits cash distribution to shareholders twice per year if Logrosan sub-holding company debt service coverage ratio is at least 1.60x and the debt service coverage ratio of the sub-consolidated group of Logrosan and the Solaben 1 & 6 and Solaben 2 & 3 assets is at least 1.20x.
Solacor 1 & 2
Overview. Solacor 1 and Solacor 2 are two 50 MW solar plants located in Andalusia, Spain. Atlantica owns 87% and JGC Corporation, a Japanese engineering company, holds the remaining 13%. The assets reached COD in 2012.
O&M. Abengoa provides O&M services under an all-in contract that we could terminate every third year starting in December 2015.
Project Level Financing. In August 2010, Solacor 1 & 2 entered into 20-year loan agreements with a syndicate of banks for a total amount of €353 million. The interest rate for the loans is a floating rate based on six-month EURIBOR plus a margin of 1.5%. We hedge our EURIBOR exposure:

| - | 53% through a swap set at approximately 3.20% for the life of the financing.

| - | 28% through a cap with a 3.25% strike for the life of the financing.

| - | In addition, we contracted caps with a 1% strike covering 19.3% of the principal of Solacor 1 and 18.2% of the principal of Solacor 2. Both caps hedge the interest rate through 2025.

The total outstanding amount of these loans as of December 31, 2020 was €275 million. These financing arrangements permit cash distribution to shareholders twice per year if the debt service coverage ratio is at least 1.10x.
PS10 & 20
Overview. PS10 & 20 is a 31 MW solar complex wholly owned by us located in Andalusia, Spain. PS10 reached COD in 2007 and PS20 reached COD in 2009.
O&M. Abengoa provides O&M services through a 21-year all-in contract.
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Project Level Financing. In 2006, PS10 and PS20 entered into a 21.5-year loan agreement and 24.5-year loan agreement respectively, which were subsequently increased in 2007 to €43.4 million for PS10 and €94.6 million for PS20. The interest rate for each loan is a floating rate based on six-month EURIBOR plus a margin of 1.0% to 1.10% (depending on the level of the debt service coverage ratio). We hedged 100% of our EURIBOR exposure for the life of the financing:

| - | 30% for both loans through a swap set at approximately 4.07%

| - | 70% for both loans through a cap set at approximately 1% until 2025

| - | From January 2026 70% through a cap with a 4.25% strike for PS10 and 4.5% for PS20

The outstanding amount of these loans as of December 31, 2020 were $25 million for PS10 and $66 million for PS20. These financing arrangements permit cash distribution to shareholders once per year if the debt service coverage ratio is at least 1.10x.
Helios 1 & 2
Overview. Helios 1 and Helios 2 are two 50 MW solar plants wholly owned by us located in Castilla la Mancha, Spain. The assets reached COD in 2012.
O&M. Abengoa provides O&M services through a 25-year all-in contract.
Project Level Financing. On July 14, 2020, we refinanced Helios 1 & 2. We entered into a senior secured note facility with a group of institutional investors as purchasers of the notes issued thereunder for a total amount of €325.6 million ($397.7 million approximately). The notes were issued on July 23, 2020 and have a 17-year maturity. Interest accrue at a fixed rate per annum equal to 1.90%. Debt repayment is semiannual over the 17-year tenor of the debt. The outstanding amount of the debt as of December 31, 2020 was $369 million. The note facility permits cash distributions to shareholders if the debt service coverage ratio is at least 1.15x.
Helioenergy 1 & 2
Overview. Helioenergy 1 and Helioenergy 2 are two 50 MW solar plants wholly owned by us located in Andalusia, Spain. They reached COD in 2011.
O&M. Abengoa provides O&M services through a 20-year all-in contract.
Project Level Financing. On June 26, 2018, Helioenergy 1 & 2 entered into:

| - | a 15-year loan agreement of €218.5 million with a syndicate of banks. The interest rate for the loans is a floating rate based on six-month EURIBOR plus a margin of 2.25% until December 2025 and 2.50% until maturity. The banking tranche is 97% hedged through a swap set at approximately 3.8% strike and 3% hedged through a cap with a 1% strike.

| - | a 17-year, fully amortizing loan agreement with an institutional investor for a €45 million with a fixed interest rate of 4.37%. In July 2020, we added a new $43 million notional amount long dated tranche of debt from the same institutional investor with 15-year maturity and with a fixed interest rate of 3.00%.

The outstanding amount of these loans as of December 31, 2020 was $308 million. The financing arrangements permit cash distributions to shareholders semi-annually based on a debt service coverage ratio of at least 1.15x.
Solnova 1, 3 & 4
Overview. Solnova 1, Solnova 3 and Solnova 4 are three 50 MW solar plants wholly owned by us located in Andalusia, Spain, in the same complex as PS-10 and PS-20. Solnova 1, 3 & 4 projects reached COD in 2010.
O&M. Abengoa provides O&M services through a 25-year all-in contract.
Project Level Financing. In December 2007, Solnova 1 entered into a 22-year loan agreement for €233.4 million with a syndicate of banks. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin in the range of 1.15% up to 1.25%, depending on the debt service coverage ratio. The principal is hedged:

| - | 78% through a swap set at approximately 4.76% strike for the life of the debt.

| - | 22% through a cap with a 1% strike covering the principal through 2025.

In January 2008, Solnova 3 entered into a 22-year loan agreement for €227.5 million with a syndicate of banks. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin in the range from 1.15% up to 1.25%, depending on the debt service coverage ratio. The principal is hedged:

| - | 23% through a swap set at approximately 4.34% strike for the life of the debt.

| - | 77% through a cap with a 1% strike covering the principal through 2025.

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In August 2008, Solnova 4 entered into a 22-year loan agreement for €217.1 million with a syndicate of banks. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin in the range from 1.50% up to 1.60%, depending on the debt service coverage ratio. The principal is hedged:

| - | 83% through a swap set at approximately 4.87% strike for the life of the debt.

| - | 17% through a cap with a 1% strike covering the principal through 2025.

As of December 31, 2020, the outstanding amount of these loans was $509 million. The financing arrangements of the three plants permit cash distributions to shareholders once per year if the debt service coverage ratio is at least 1.15x.
Solaben 1 & 6
Overview. Solaben 1 and Solaben 6 are two 50 MW solar plants wholly owned by us located in Extremadura, Spain, in the same complex as Solaben 2 & 3. Solaben 1 & 6 reached COD in the third quarter of 2013.
O&M. Abengoa provides O&M services through a 25-year all-in contract.
Project Level Financing. On September 30, 2015, Solaben Luxembourg S.A., a holding company of the two project companies, issued a project bond for €285 million. The bonds mature in December 2034. The bonds have a coupon of 3.758% and interest are payable in semi-annual instalments on June 30 and December 31 of each year. The principal of the bonds is amortized over the life of the bonds. The outstanding amount of the project bonds as of December 31, 2020 was $246 million. The financing arrangements of the plants permit cash distributions to shareholders once per year if the debt service coverage ratio is at least 1.650x.
Seville PV
Overview. Seville PV is a 1 MW photovoltaic farm located alongside PS 10 & 20 and Solnova 1, 3 & 4, in Andalusia, Spain. Seville PV reached COD in 2006.
O&M. Seville PV has an O&M agreement in place with Prodiel.
Project Level Financing. Seville PV does not have any project level financing.
Kaxu
Overview. Kaxu is a 100 MW net solar plant located in Pofadder, Northern Cape Province, South Africa. The project company is currently owned by us through ABY Solar South Africa (Pty) Ltd (51%), Industrial Development Corporation of South Africa (29%) and Kaxu Community Trust (20%). Kaxu relies on a conventional parabolic trough solar power system to generate electricity. This technology is similar to the technology used in solar power plants that we own in the U.S. and Spain. It also has a molten salt thermal energy storage system. The asset reached COD in January 2015.
PPA. Kaxu has a 20-year PPA with Eskom, under a take–or-pay contract for the purchase of electricity up to the contracted capacity from the facility. The PPA expires in February 2035. Eskom purchases all the output of the Kaxu plant under a fixed-price formula in South African Rand subject to indexation to local inflation.
Eskom is a state-owned, limited liability company, wholly owned by the government of the Republic of South Africa. Eskom’s payment guarantees are underwritten by the South African Department of Energy, under the terms of an implementation agreement. Eskom’s credit ratings are currently CCC+ from S&P, Caa1 from Moody’s and B from Fitch. The Republic of South Africa’s credit ratings are currently BB from S&P, Ba2 from Moody’s and BB- from Fitch.
In addition, in 2019 we entered into a political risk insurance agreement with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $89.9 million in the event the South African Department of Energy does not comply with its obligations as guarantor. This insurance policy does not cover credit risk.
O&M. O&M services are provided by Abengoa under a 20-year contract.
Project Level Financing. Kaxu entered into a long-term financing agreement with a lenders’ group for a total initial amount of approximately ZAR 5,860.0 million. The loan consists of senior and subordinated long-term loans payable in South African rand over an 18-year term with the cash generated by the project. The interest rate exposure was initially 100% hedged through a swap with the same banks providing the financing, and the coverage progressively reduces over the life of the loan. Current effective annual interest rate is approximately 9.5% considering the hedge in place. As of December 31, 2020, the outstanding amount of these loans was ZAR 5,222 million, or approximately $355 million.
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The financing arrangement permits dividend distributions on a semi-annual basis after the first repayment of debt has occurred, as long as the historical and projected debt service coverage ratios are at least 1.2x.
The project financing arrangement for Kaxu contains cross-default provisions related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. In December 2020, we obtained a waiver from Kaxu’s project debt lenders in which they commit not to take any action until December 31, 2021 with respect to any potential cross-defaults with Abengoa for the pre-insolvency filing of August 2020. The insolvency filing by the individual company Abengoa, S.A. in February 2021 represents a theoretical event of default under the Kaxu project finance agreement for which we do not yet have a waiver. Although we do not expect the Kaxu’s project debt lenders to accelerate the debt or take any other action, a cross-default scenario, if not cured or waived, may entitle lenders to demand repayment, limit distributions from the asset or enforce on their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Item 3.D — Risk Factors— Risks Related to Our Relationship with Algonquin and Abengoa— If Abengoa defaults on certain of its debt obligations, we could potentially be in default of certain of our project financing agreements.”
Palmatir
Overview. Palmatir is an onshore, 50 MW wind farm facility wholly owned by us, located in Tacuarembo, 170 miles north of the city of Montevideo, Uruguay. Palmatir has 25 wind turbines supplied by Siemens, a global leader in the manufacture and maintenance of wind turbines, and each turbine has a nominal capacity of 2 MW. The plant reached COD in May 2014.
PPA. Palmatir signed a PPA with UTE in September 2011 for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and will be partially adjusted annually based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have a turbine O&M agreement with Siemens that covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services.
Project Level Financing. On April 11, 2013, Palmatir entered into a financing agreement for a 20-year loan in two tranches in connection with the project, denominated in USD. The first tranche is a $73 million loan with a fixed interest rate of 3.16%. The second tranche is a $40 million loan with a floating interest rate of six-month U.S. LIBOR plus 4.125%, which was 80% hedged with a swap at a rate of 2.22%. The combined principal balance of both tranches as of December 31, 2020 was $82 million.
The financing arrangements of the plant permits cash distributions to shareholders once per year subject to, among other things, a historical debt service coverage ratio for the previous twelve-month period of at least 1.25x and a projected debt service coverage ratio of at least 1.30x for the following twelve-month period.
Cadonal
Overview. Cadonal is an onshore, 50 MW wind farm facility wholly owned by us, located in Flores, 105 miles north of the city of Montevideo, Uruguay. Cadonal has 25 wind turbines of 2 MW each which were supplied by Siemens. Cadonal reached COD in December 2014.
PPA. Cadonal signed a PPA with UTE on December 28, 2012, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted annually based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have a turbine O&M agreement with Siemens that covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services.
Project Level Financing. In June 2020 we refinanced Cadonal’s debt for a total amount of $77.6 million:

| - | Tranche A is a $36.0 million loan with maturity in 2034 and a floating interest rate of six-month LIBOR plus 2.9%, 81% hedged with a swap set at approximately 3.29% strike.

| - | Tranche B is a $33.5 million loan with maturity in 2032 and a floating interest rate of six-month LIBOR plus 2.65%, 81% hedged with a swap set at approximately 3.16% strike.

| - | Subordinated tranche for $8.1 million with maturity in 2034 and a floating interest rate of six-month LIBOR plus 5.5%.

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The combined principal balance of these loans was $63 million as of December 31, 2020. The financing arrangements of the plant permits cash distributions to shareholders twice a year subject to, among other things, a senior debt service coverage ratio for the previous twelve-month period of at least 1.20x and a total debt service coverage ratio for the previous twelve-month period being at least 1.10x.
Melowind
Overview. Melowind is an onshore 50 MW wind farm facility wholly owned by us, located in Cerro Largo, 200 miles north of the city of Montevideo, Uruguay. Melowind has 20 wind turbines supplied by Nordex, each with a capacity of 2.5 MW. The asset reached COD in November 2015.
PPA. Melowind signed a PPA with UTE in 2015, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted every year based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have a turbine O&M agreement with Nordex that covers scheduled and unscheduled turbine maintenance.
Project Level Financing. On December 13, 2018, Melowind entered into a financing agreement payable over a period of 16 years. The financing consists of a $76 million loan with a floating interest rate based on six-month LIBOR plus a margin of 2.25% until December 2021, 2.5% from January 2022 to December 2024, 2.75% from January 2025 to December 2027 and 3.0% from January 2028 to December 2034. LIBOR exposure was 75% hedged with a swap at a rate of 3.26% with the financing bank. As of December 31, 2020, the outstanding amount of the loan was $73 million.
The financing arrangement permits cash distributions to shareholders semi-annually subject, among other things, to a historical debt service coverage ratio for the previous twelve-month period of at least 1.15x.
Mini-hydro Peru
Overview. Mini-hydro Peru is a 4 MW mini-hydroelectric power plant located approximately 99 miles from Lima. The plant reached COD in April 2012.
Concession Agreement. It has a 20-year fixed-price concession agreement denominated in U.S. dollars with the Ministry of Energy of Peru and the price is adjusted annually in accordance with the U.S. Consumer Price Index.
O&M. The operation and maintenance service is performed internally.
Project Level Financing. The asset has a 17-year, non-recourse project financing with Inter-American Investment Corporation. As of December 31, 2020, the outstanding amount on the loan was $5 million.
Efficient Natural Gas
ACT
Overview. ACT is a gas-fired cogeneration facility 99.99% owned by us through ACT Energy Mexico, S. de R.L. de C.V., or ACT Energy Mexico, is located inside the Nuevo Pemex Gas Processing Facility near the city of Villahermosa in the State of Tabasco, Mexico. It has a rated capacity of approximately 300 MW and between 550 and 800 metric tons per hour of steam. ACT reached COD in 2013. Pemex has the possibility to terminate the CSA under certain circumstances paying an indemnity.
Conversion Services Agreement. On September 18, 2009, ACT entered into the Pemex CSA, with Pemex, under which ACT is required to sell all of the plant’s thermal and electrical output to Pemex. The Pemex CSA has an initial term of 19 years from the in-service date and will expire on March 31, 2033. The Pemex CSA requires Pemex to supply the facility, free of charge, with the fuel and water necessary to operate ACT, and the latter has to produce electrical energy and steam requested by Pemex based on the expected levels of efficiency. The Pemex CSA is denominated in U.S. dollars. The price is fixed and will be adjusted annually, adjustments will be made according to a mechanism agreed in the contract that establishes that the average adjustments over the life of the contract should reflect the expected inflation.
In recent years, Pemex’s credit rating has weakened and is currently BBB from S&P, Ba2 from Moody’s and BB- from Fitch. We have been experiencing significant delays in collections from Pemex since the second half of 2019.
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O&M. GE provides services for the maintenance, service and repair of the gas turbines NAES is responsible for the O&M. The O&M agreement with NAES expires upon the expiration of the Pemex CSA, although we may cancel it with no penalty at any time.
We own all of the shares of ACT except for two ordinary shares, which represent less than 0.01% of the total capital of ACT and which are owned by wholly owned subsidiaries of Abengoa.
Project Level Financing. In January 2014, ACT Energy Mexico entered into a $675 million senior loan agreement with a syndicate of banks. The financing consists of a $205.4 million tranche one with 10-year maturity and a $450.0 million tranche two with an 18-year maturity. The interest rate on each tranche is a floating rate based on the three-month U.S. LIBOR plus a margin of 3.5% from January 2019 to December 2024 and 3.75% from January 2025 to December 2031. The loan is 75% hedged at a weighted average rate of 3.94%.
The outstanding amount of these loans as of December 31, 2020 was $504 million. The senior loan agreement permits cash distributions to shareholders provided that the debt service coverage ratio is at least 1.20x.
Monterrey
Overview. Monterrey is a 142 MW gas-fired engine facility including 130 MW installed capacity and 12 MW battery capacity. We own 30% of Monterrey through Pemcorp S.A.P.I. de C.V., while Arroyo Energy owns the remaining 70%. The asset is located in Mexico and reached COD in 2018. The power plant is configured with seven Wärtsilä natural gas internal combustion engines.
We entered into a ROFO agreement with Arroyo Energy for the remaining 70% stake in Monterrey, currently owned by them.
PPA. It is a U.S. dollar-denominated 20-year PPA with two international large corporations engaged in the car manufacturing industry. The PPA also includes price escalation factors. The asset also has a 20-year contract for the natural gas transportation from Texas with a U.S. energy company. It has no commodity risk. Additionally, the asset expects to be able to sell electricity to the Mexican market if and when it is connected to the grid.
O&M. Wärtsilä performs the O&M for Monterrey. The term of the contract is three years from COD. In addition, the asset has in place a Generator Maintenance Agreement with Wärtsilä for the seven generators for a period of 15 years from COD.
Project Level Financing. Monterrey has a loan of approximately $169 million which matures in September 2027 and a credit line of $14 million available until September 2022, subject to certain conditions. The interest rate of the loan is a floating rate based on the three-month U.S. LIBOR plus a margin of 2.75% with a 0.25% increase after three years. The LIBOR exposure was 75% hedged with a swap rate of 2.34% with the financing bank. The loan agreement permits cash distributions after the asset reached COD provided that the debt service coverage ratio is at least 1.20x.
Electric Transmission
ATN
Overview. ATN is a 365 miles transmission line located in Peru wholly owned by us, which is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATN reached COD in 2011. On December 28, 2018, ATN S.A. completed the acquisition of a power substation and two small transmission to connect our line to the Shahuindo (ATN expansion 1) mine located nearby. In October 2019, we also closed the acquisition of ATN Expansion 2.
Concession Agreement. Pursuant to the initial concession agreement, the Peruvian Ministry of Energy, on behalf of the Peruvian Government, granted ATN a concession to construct, develop, own, operate and maintain ATN. ATN owns all assets that it has acquired to construct and operate ATN for the duration of the concession. The ownership of these assets will revert to the Peruvian Ministry of Energy upon termination of the initial concession agreement.
ATN has a 30-year fixed-price tariff base denominated in U.S. dollars that is adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations. In addition, both ATN Expansion 1 and ATN Expansion 2 have 20-year PPAs denominated in US $.
O&M. ATN has a 27-year term O&M agreement with a subsidiary of Abengoa.
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Project Level Financing. On September 26, 2013, ATN completed the issue of a project bond in four tranches denominated in USD:

| - | 1st tranche, currently repaid, had a principal amount of $15 million with interest of 3.84% per year.

| - | 2nd tranche has a principal amount of $50 million with a 15-year term with quarterly amortization and bears interest at a rate of 6.15% per year.

| - | 3rd tranche has a principal amount of $45 million with a 26-year term and bears interest at a rate of 7.53% per year. The third tranche has a 15-year grace period for principal repayments.

| - | 4th tranche has a principal amount of $10 million with a 15-year term and bears interest at a rate of 6.88% per year.

As of December 31, 2020, $98 million in aggregate principal amount was outstanding. The project bond agreement permits cash distributions subject to a debt service coverage ratio for the last six months of at least 1.10x.
ATS
Overview. ATS is a 569 miles transmission line located in Peru wholly owned by us. ATS is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATS reached COD in 2014.
Concession Agreement. The initial concession agreement became effective on July 22, 2010 and will expire 30 years after achieving COD. Pursuant to the initial concession agreement, ATS will own all assets it has acquired to construct and operate the ATS Project for the duration of the concession. These assets will revert to the Peruvian Ministry of Energy upon termination of the initial concession agreement.
The concession agreement has a fixed-price tariff base denominated in U.S. dollars and is adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to the ATS Project.
O&M. ATS has a five-year term O&M agreement with a subsidiary of Abengoa.
Project Level Financing. On April 8, 2014, ATS issued a project bond denominated in U.S. dollars with a 29-year term with semi-annual amortization and which bears a fixed interest rate of 6.875%. As of December 31, 2020, $402 million was outstanding. The project bond agreement permits cash distributions every six months subject to a trailing historical debt service coverage ratio for the previous two quarters of at least 1.20x.
ATN2
Overview. ATN2, is an 81 miles transmission line located in Peru wholly owned by us, which is part of the Complementary Transmission System. ATN2 reached COD in June 2015.
ATN2 has an 18-year, fixed-price tariff base contract denominated in U.S. dollars with Minera Las Bambas. The tariff is partially adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to ATN2.
Minera Las Bambas is owned by a partnership consisting of a China Minmetals Corporation subsidiary (62.5%), a wholly owned subsidiary of Guoxin International Investment Co. Ltd (22.5%) and CITIC Metal Co. Ltd (15.0%).
Maintenance & Monitoring. ATN 2 has a 6 year-term O&M agreement with a subsidiary of Abengoa,
Project Level Financing. In 2011 and 2014, a 15-year loan agreement was executed for a commitment of $50.0 million and $31.0 million, respectively. All debt has a fixed interest rate amounting to 5.8% on a weighted average basis and matures in 2031. As of December 31, 2020, the outstanding amount of the ATN2 project loan was $54 million. The loan agreement permits cash distributions subject to a debt service coverage ratio of at least 1.15x.
Quadra 1 & Quadra 2
Overview. Quadra 1 is a 49-mile transmission in Chile. Quadra 1 connects to the Sierra Gorda substation owned by Sierra Gorda SCM, a mining company and is located in the commune of Sierra Gorda. Quadra 2 is a 32-mile transmission asset that provides electricity to the seawater pump stations owned by the Sierra Gorda SCM in Chile. Quadra 1 and Quadra 2 reached COD in 2014.
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Concession Agreement. Both projects have concession agreements with the Sierra Gorda SCM mining company, which is owned by Sumitomo Corporation, Sumitomo Metal Mining and KGHM Polska Mietz. The concession agreement is denominated in U.S. dollars and has a 21-year term that began on the COD. The contract price is indexed mainly to the U.S. CPI.
The concession agreement grants in favor of Sierra Gorda a call option over the transmission lines, exercisable at any time during the life of the contract. According to the call option, Sierra Gorda is entitled to purchase the transmission line at an agreed price and with a six-month prior written notice.
O&M. Enor performs operations services at Quadra 1 under a 10-year contract expiring in 2027. Gas Atacama provides operations services at Quadra 2 under a 12-year contract expiring in 2029. Cobra performs maintenance services at Quadra 1 and Quadra 2 under 6-year contracts expiring in 2023.
Project Level Financing. In June 2019, we refinanced the project debt of our Chilean assets Palmucho, Chile TL3, Quadra 1 and Quadra 2. This financing agreement consists of a single loan agreement for all these assets for a total amount of $75 million with a syndicate of local banks. The loan is denominated in U.S. dollars and matures on September 30, 2031. It has a semi-annual amortization schedule and accrues interest at a variable rate based on the six-month U.S. LIBOR plus 3.60%. We contracted an interest rate swap at an approximate fixed rate of 2.25% to hedge 75% of the amount nominal during the entire debt term. As of December 31, 2020, the outstanding amount was $71 million. The financing agreement is cross collateralized jointly between the Chilean assets and permits cash distributions twice per year if the combined debt service coverage ratio for the three assets is at least 1.20x.
Palmucho
Palmucho is a transmission line in Chile of approximately 6 miles. Palmucho has a 14-year concession contract with Enel Generacion Chile, whereby both parties are obliged to enter into a four-year valid toll contract at the end of the term of the concession contract and the valid toll contract will be renewed for three periods of four years each until one of the parties decides not to renew. O&M services are provided by Cobra.
Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.
Chile TL3
Overview. Chile TL3 is a 50-mile transmission line in operation in Chile which reached COD in 1993. It generates revenue under the current regulation in Chile. The asset has a fixed-price tariff based on the return to the investment and the operating and maintenance costs denominated in U.S. dollars, and is partially adjusted annually in accordance with the U.S. and Chilean Consumer Price Indexes and currency exchange rates.
O&M. Operation services are performed internally. Cobra performs maintenance services at Chile TL3 under a 4-year contract expiring in 2022.
Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.
Water
Honaine
Overview. Honaine is a water desalination plant of 7 M ft3 per day capacity located in Taffsout, Algeria. We indirectly own 25.5% through Myah Bahr Honaine Spa (“MBH”), Algerian Energy Company, or AEC, owns 49% and Sacyr owns the remaining 25.5% of Honaine. Honaine reached COD in July 2012. AEC is the Algerian agency in charge of delivering Algeria’s large-scale desalination program.
The technology used in the Honaine plant is currently the most commonly used in this kind of asset. It consists of desalination using membranes by reverse osmosis.
Honaine has a corporate income tax exemption until 2021. After that period, in case the exemption is not extended, a claim may be made under the water purchase agreement for compensation in the tariff.
Concession Agreement. The water purchase agreement is a 30-year take-or-pay contract with Sonatrach/Algerienne des Eaux, or ADE, from the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
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Operations & Maintenance. Honaine has a 30-year contract with a joint venture between Abengoa (50%) and Sacyr (50%) from the date of the execution (or 25-year term from COD).
Project Level Financing. In May 2007, MBH signed a financing agreement for $233 million which accrues interest at a fixed-rate of 3.75%. The repayment of the Honaine facility agreement consists of quarterly payments, ending in April 2027. The financing arrangement permits cash distribution to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.
Skikda
Overview. The Skikda project is a 3.5 M ft3 per day capacity water desalination plant located in Skikda, Algeria. Skikda is located 510 km east of Algiers. We indirectly own 34.2% of Skikda through Aguas de Skikda, or ADS, AEC owns 49% and Sacyr owns the remaining 16.8%. Skikda reached COD in 2009 and uses the same technology as Honaine.
Skikda had a corporate income tax exemption until 2019. After that period, the exemption was not extended, and the project has been compensated under the water purchase agreement in the tariff.
Concession Agreement. The water purchase agreement is a 30-year take-or-pay contract with Sonatrach/ADE from the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
O&M. Skikda has a 25-year contract from COD with a joint venture between Abengoa (67%) and Sacyr (33%).
Project Level Financing. In July 2005, ADS signed a financing agreement for $108.9 million which accrues interest at a fixed-rate of 3.75%. The repayment of the Skikda facility agreement consists of sixty quarterly payments, ending in May 2024. As of December 31, 2020, the outstanding amount of the Skikda project loan was $17 million. The financing arrangement permits cash distribution to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.
Tenes
Overview. Tenes is a 7 M ft3 per day capacity water desalination plant located 208 km west of Algiers, in Algeria. Tenes uses the same technology as Honaine and Skikda, and has been in operation since 2015. Befesa Agua Tenes has a 51.0% stake in Ténès Lilmiyah SpA and we have a majority at the Board of Directors of Befesa Agua Tenes, the remaining 49% is owned by AEC.
Since January 2019, we have an investment in Tenes through a secured loan to be reimbursed by Befesa Agua Tenes, together with 12% per annum interest, through a full cash-sweep of all the dividends to be received from the asset. On May 31, 2020, we entered into a new agreement which provides us with certain additional decision rights, and a majority at the Board of Directors of Befesa Agua Tenes. Therefore, we have concluded that we have control over Tenes since May 31, 2020 and as a result we have fully consolidated the asset from that date.
Tenes had a corporate income tax exemption until 2025. After that period, in case the exemption is not extended, a claim may be made under the water purchase agreement for compensation in the tariff.
Concession Agreement. The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/ADE from the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the exchange rate between the U.S. dollar and local currency and yearly based on indexation mechanisms that include local inflation and U.S. inflation.
O&M. Tenes has a 25-year contract from COD with Abengoa.
Project Level Financing. Tenes signed a financing agreement for $211 million. The loan accrues a fixed interest rate of 3.75%. The repayment of the facility agreement consists of sixty quarterly payments, ending in August 2031. As of December 31, 2020, the outstanding amount of the Tenes project loan was $98 million. The financing arrangements permit cash distribution to shareholders subject to a debt service coverage ratio of at least 1.10x.
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Customers
We derive our revenue from selling electricity, electric transmission capacity and water desalination capacity. Our customers are mainly comprised of electrical utilities and corporations, with which we typically have entered into PPAs. We also employ concession contracts, typically ranging from 20 to 30 years. We also have regulated assets in Spain and Chile (Chile TL3). We have one asset, Chile PV1, representing a very small percentage of our revenue, which sells electricity at market prices. See the description of each asset under “—Our Operations” for more detail on each concession contract.
Our main contracts in our business also include the project finance contracts with banks or financial institutions and the operation and maintenance contracts of each of our assets. See description of financing and operation and maintenance contracts under “—Our Operations.”
Competition
Renewable energy, storage, efficient natural gas and electric transmission are all capital-intensive and commodity-driven businesses with numerous industry participants. We compete based on the location of our assets in various countries and regions; however, because our assets typically have long-term contracts, competition with other asset operations is limited with respect to existing assets until the expiration of the PPAs. Power generation and transmission are highly regulated businesses in each country in which we operate and are currently highly fragmented and have a diverse industry structure. Our competitors have a wide variety of capabilities and resources. Our competitors include, among others, regulated utilities and transmission companies, other independent power producers and power marketers or trading companies and state-owned monopolies.
We also compete to acquire new projects with developers, independent power producers and financial investors, including pension funds and infrastructure funds and other dividend growth-oriented companies. Competitive conditions may vary over time depending on capital market conditions and regulation, which may affect the costs of constructing and operating projects.
Seasonality
Our operating results and cash flows can be significantly affected by weather in some of our most relevant projects, such as the solar power plants. We expect to derive a majority of our annual revenue in the months of May through September, when solar generation is the highest in the majority of our markets and when some of our off-take arrangements provide for higher payments to us. See “Item 3.D — Risk Factors—Risks Related to Our Business and Our Assets— The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.”
Environment and Sustainability
Environmental management is a key priority in our business and operations. Our facilities and operations are subject to significant government regulation, including stringent and comprehensive federal, provincial and local laws, statutes, regulations, guidelines, policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; storage, handling, use, disposal, transportation and distribution of dangerous materials and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the presence and remediation of hazardous materials in soil and groundwater, both on and offsite; the protection of natural resources; land use and zoning matters; and workers’ health and safety matters. We consider environmental protection as an area of performance and as such, environmental issues are included among the responsibilities of our key executives.
Employees and Human Resources
As December 31, 2020, we had 456 employees (including both operation and maintenance and general and administrative staff). Following our acquisition of ASI Operations, the subsidiary which provides operation and maintenance services in the U.S., certain of our employees now belong to a labor union. We believe that the relationship between the Company and its labor union is good. We have not experienced any strikes or work stoppages amongst our workforce. One of our plants has experienced strikes by employees working for one of our operation and maintenance suppliers in the past.
Health & Safety
Within our values, the first one is “Integrity, Compliance and Safety”. We are committed to prioritizing and actively promoting health and safety as a tool to protect the integrity and health of our employees, subcontractors and partners involved in our business activity. We promote a safe operating culture across Atlantica and encourage a preventive culture in the operation and maintenance (“O&M”) activities of our subcontractors as reflected in our corporate health and safety policy.
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Annually, we conduct internal and external audits to evaluate our health and safety management system in accordance with the OHSAS:18001 standard requirements. The external audit is carried out by an independent third party. These efforts have resulted in the continuation of the certification of the Occupational Health and Safety Management System in OHSAS: 18001 obtained in 2015. This certification has been successfully renewed during the last four years. Additionally, we perform periodic health and safety audits to our asset contractors to monitor the compliance with legal regulations, contractual requirements and our safety best practices. We also develop an annual training program to train managers and employees on safety awareness. This annual plan is designed in accordance with local regulations and risk assessment at every work position and work center.
On an annual basis, we establish safety key metrics targets in all our assets which include both Atlantica and subcontractor employees.
Our Total Recordable Incident Rate (TRIR) has been calculated following Sustainable Accounting Standards IF-EU-320a.1. It represents the total number of recordable accidents with and without leave (lost time injury) recorded in the last 12 months on 200 thousand worked hours. We ended 2020 at 1.0, representing a 17% improvement versus 2019.
Our Lost Time Injury Rate (LTIR) represents the total number of recordable accidents with leave (lost time injury) recorded in the last 12 months on 200 thousand of worked hours. LTIR for the year 2020 remained stable at 0.3 versus 2019.
Operation and Maintenance
In terms of operational efficiency, we focus on ensuring long-term availability, reliability and asset integrity with maintenance and monitoring. We, or the original owner of the asset, selected the suppliers of our solar panels, turbines, transmission towers and equipment through a detailed evaluation process, focusing on their commercial track record and regular availability of components and replacement parts for the proper functioning and maintenance of our assets and facilities. Our corporate operations team identifies best practices and controls which are implemented in all the assets. Additionally, we require all our suppliers to comply with our Suppliers’ Code of Conduct.
Operation and maintenance services for certain of our assets are provided by subsidiaries of Abengoa, S.A. On February 22, 2021, Abengoa, S.A. filed for insolvency proceedings in Spain. Based on the public information filed in connection with these proceedings, such insolvency proceedings do not include other Abengoa companies, including Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services for us. Although we have contingency plans in place, including a potential change of supplier and/or internalization, in the short term we expect the operation and maintenance services to continue to be provided by our current supplier. See “Item 3.D—Risk Factors—If Abengoa defaults on certain of its debt obligations, we could potentially be in default of certain of our project financing agreements”
Legal Proceedings
A number of Abengoa’s subcontractors and insurance companies that issued bonds covering Abengoa’s obligations under such contracts in the U.S included some of the non-recourse subsidiaries of Atlantica in the U.S. at the time of the construction of the plants we currently own as co-defendants in claims against Abengoa. Generally, the subsidiaries of Atlantica were dismissed as defendants at early stages of the processes. With respect to a claim addressed by a group of insurance companies to a number of Abengoa’s subsidiaries and to Solana (Arizona Solar One) for Abengoa related losses of approximately $20 million that could increase, according to the insurance companies, up to a maximum of approximately $200 million if all their exposure resulted in losses. Atlantica reached an agreement with all but one of the above-mentioned insurance companies, under which they agreed to dismiss their claims in exchange for payments of approximately $4.3 million, which were paid in 2018. The insurance company that did not join the agreement has temporarily stopped legal actions against Atlantica, and Atlantica does not expect this particular claim to have a material adverse effect on its business.
In addition, an insurance company covering certain Abengoa obligations in Mexico claimed certain amounts related to a potential loss. Atlantica reached an agreement under which Atlantica´s maximum theoretical exposure would in any case be limited to approximately $35 million, including $2.5 million to be held in an escrow account. In January 2019, the insurance company executed $2.5 million from the escrow account and Abengoa reimbursed such amount according to the indemnities in force between Atlantica and Abengoa. The payments by Atlantica would only happen if and when the actual loss has been confirmed and after arbitration if the Company initiates it. We used to have indemnities from Abengoa for certain potential losses, but such indemnities are no longer valid following the insolvency filing by Abengoa S.A. in February 2021.
Atlantica is not a party to any other significant legal proceedings other than legal proceedings arising in the ordinary course of its business. Atlantica is party to various administrative and regulatory proceedings that have arisen in the ordinary course of business.
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While Atlantica does not expect these proceedings, either individually or in the aggregate, to have a material adverse effect on its financial position or results of operations, because of the nature of these proceedings Atlantica is not able to predict their ultimate outcomes, some of which may be unfavorable to Atlantica.
Regulation
Overview
We operate in a significant number of highly regulated markets. The degree of regulation to which our activities are subject varies by country. In a number of the countries in which we operate, regulation is carried out mainly by national regulatory authorities. In others, such as the United States and, to a certain degree, Spain, there are various additional layers of regulation at the state, regional and/or local level. In countries with these additional layers of regulatory agencies, the scope, nature and extent of regulation may differ among the various states, regions and/or localities.
While we believe the requisite authorizations, permits and approvals for our assets have been obtained and that our activities are operated in substantial compliance with applicable laws and regulations, we remain subject to a varied and complex body of laws and regulations that both public officials and private parties may seek to enforce. The following is a description of the primary industry-related regulations applicable to our assets that are currently in force in the principal markets in which we operate.
Regulation in the United States
In the United States, our electricity generation project companies are subject to extensive federal, state and local laws and regulations that govern the development, ownership, business organization and operation of power generation facilities. The federal government regulates wholesale sales, operation and interstate transmission of electric power through the Federal Energy Regulatory Commission (“FERC”) and through other federal agencies, and certain environmental, health and safety matters. State and local governments regulate the siting, permitting, construction and operation of power generation facilities, the retail sale of electricity and certain other environmental, health, safety and permitting matters.
United States Federal Regulation of the Power Generation Facilities and Electric Transmission
The United States federal government regulates the wholesale sale of electric power and the transmission of electricity in interstate commerce through FERC, which draws its jurisdiction from the FPA, as amended, and from other federal legislation.
Federal Regulation of Electricity Generators
The FPA provides FERC with exclusive ratemaking jurisdiction over all public utilities that engage in wholesale sales of electricity and/or the transmission of electricity in interstate commerce. The owners of renewable energy facilities selling at wholesale are therefore generally subject to FERC’s ratemaking jurisdiction. FERC may authorize a public utility to make wholesale sales of electric energy and related products at negotiated or market-based rates if the public utility can demonstrate that it does not have, or that it has adequately mitigated, horizontal and vertical market power and that it cannot otherwise erect barriers to market entry. Entities granted market-based rate approval face ongoing filing and compliance requirements. Failure to comply with such requirements may result in a revocation of market-based rate authority, disgorgement of profits, civil penalties or other remedies that FERC finds appropriate based on the specific underlying facts and circumstances.
FERC also implements the requirements of PUHCA applicable to “holding companies” having direct or indirect voting interests of 10% or more in companies that (among other activities) own or operate facilities used for the generation of electricity for sale, which includes renewable energy facilities. PUHCA imposes certain record-keeping, reporting and accounting obligations on such holding companies and certain of their affiliates, subject to certain exceptions.
Federal Reliability Standards
EPACT 2005 amended the FPA to grant FERC jurisdiction over all users, owners and operators of the bulk power system for the purpose of enforcing compliance with certain standards for the reliable operation of the bulk power system. Pursuant to its authority under the FPA, FERC certified the North American Electric Reliability Corporation (“NERC”) as the entity responsible for developing reliability standards, submitting them to FERC for approval, and overseeing and enforcing compliance with them, subject in each case to FERC review. NERC, in turn, has delegated certain monitoring and enforcement powers to regional reliability organizations. Users, owners, and operators of the bulk power system meeting certain materiality thresholds are required to register with the NERC compliance registry and comply with FERC-approved reliability standards.
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Federal Environmental Regulation, Permitting and Compliance
Construction and operation of power generation facilities, including solar power plants, and the generation and electric transmission of renewable energy from such facilities are subject to environmental regulation at the federal, state and local level. At the federal level, environmental laws and regulations typically require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a generation project or electric transmission facilities. Prior to development, permitting authorities may require that project developers consider and address, among other things, the impact on water resources and water quality, endangered species and other biological resources, compatibility with existing land uses and zoning, agricultural resources, archaeological, paleontological, recreational and cultural considerations, environmental justice and cumulative and visual impacts. In an effort to identify and minimize the potential impacts to these resources, power generation facilities may be required to comply with a myriad of federal regulatory programs and applicable federal permits under various federal laws.
In addition, various federal environmental, health and safety regulations applicable during the construction phase are also applicable to the operational phase of power generation facilities. During the operational phase, obtaining certain federal permits or federal approval of certain operating documents (e.g., O&M plans, the spill prevention, control and countermeasure plan, and an emergency and preparedness response plan), as well as maintaining strict compliance with such permits or operating documents, is mandatory. Failure to maintain compliance may result in the revocation of any applicable permit or authorization, civil and criminal charges and fines or potentially the closure of the plant.
U.S. Federal Considerations for Renewable Energy Generation Facilities
The United States provides various federal, state and local tax incentives to stimulate investment in renewable energy generation capacity, including solar power. These tax incentives are subject to change and, possibly, elimination in the future. Certain U.S. federal income tax incentives are described below.
Section 1603 U.S. Treasury Grant Program
In lieu of claiming certain U.S. federal income tax credits, in particular, the ITC, owners of eligible solar energy property were eligible for a period of time to receive a cash grant from U.S. Treasury equal to 30% of the tax basis of the eligible property. Solana received its 1603 Cash Grant final award from the U.S. Treasury in October 2014 and Mojave received its 1603 its 1603 Cash Grant final award from the U.S. Treasury in September 2015.
Federal Loan Guarantee Program
The DOE was authorized to grant guarantees with respect to certain loans to renewable energy projects and related manufacturing facilities and electric power transmission projects under Section 1703 of EPACT 2005. The senior debt for Solana and Mojave is guaranteed by the DOE pursuant to the Section 1705 loan guarantee program.
State and Local Regulation of the Electricity Industry in the United States
State regulatory agencies in the United States have jurisdiction over the rates and terms of electricity service to retail customers. Regulated investor-owned utilities often must obtain state approval for the contracts through which they purchase electricity, including renewable energy, if they seek to pass along the costs of these contracts to their retail ratepayers. Different states apply different standards for determining acceptable prices for utility procurement contracts, including PPAs. Our electricity generation project companies operate in Arizona and California. Information about the regulatory frameworks in Arizona and California is provided below.
United States State-Level Incentives
In addition to federal legislation, many states have enacted legislation, principally in the form of renewable portfolio standards, or RPS, which generally require electric utilities to generate or purchase a certain percentage of their electricity supplied to consumers from renewable resources. In certain states, it is not only mandatory to meet these percentages, which in general are on the increase from renewable resources, but also electric utilities may be required to generate or purchase a percentage of their electricity supplied to consumers from specific renewable energy technologies, including solar technology.
Arizona
The Arizona Corporation Commission (“ACC”) has complete and exclusive jurisdiction over the rates and terms under which regulated utilities may provide electricity service to retail customers in Arizona. Under Arizona’s Renewable Energy Standard & Tariff (“REST”) regulated electric utilities must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement is 10% of retail electric sales in 2020 and increases annually until it reaches 15% in 2025.
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Unlike many other state regulatory commissions, the ACC does not approve PPAs executed by regulated utilities, nor does it issue rulings of “prudency” regarding PPAs. In the case of Solana, however, the power purchaser, Arizona Public Service Company, or APS, voluntarily sought a hearing before the ACC to request its informal opinion of the prudency of the Solana PPA and the ACC affirmed that the PPA should be deemed “a reasonable means” by which APS could meet its requirements under the REST, thereby providing greater assurance of APS’s successful rate recovery request.
Various state and county regulations, mostly related to the environment and public health and safety are applicable during the operational phase of a solar power plant located in Maricopa County, Arizona. Obtaining a permit or requesting the approval of certain operating plans, as well as strict compliance with such permits and plans, is mandatory. Failure to comply may result in the revocation of the permit or authorization, civil and criminal charges and fines, or potentially the closure of Solana.
In addition, in accordance with the NEPA designation of a Finding of No Significant Impact (FONSI) issued by the DOE, Solana must comply with certain water requirements due to the reduction in tail water runoff being contributed to a wash located near the site. Failure to comply with the regulation in place could cause temporary closure of the plant until the non-compliance condition is cured.
Many of the permits obtained for Solana carry specific conditions that must be complied and which are continuously monitored, measured, and documented by the Solana plant operators, including those related to reliability, emergency response, potential hazards of waste disposal, and human health and safety. These requirements originate with federal laws, and in many cases are enforced via delegated authority from the appropriate federal agency to a state or county agency.
California
The California Public Utilities Commission, or CPUC, governs, among other entities, California’s investor-owned utilities, including Pacific Gas & Electric Company, or PG&E. The CPUC reviewed Mojave’s PPA and approved the contract by issuing a formal decision in November 2011.
Mojave must maintain compliance with the CEC decision conditions of certification. These conditions of certification address, among others, biological resources, health and safety, cultural resources, fire safety, and water. The conditions require Mojave to provide plans, notifications, and other reports on an ongoing basis. Such compliance is monitored by CEC staff. Per the CEC decision, “failure to comply with any of the Conditions of Certification or the compliance conditions may result in reopening of the case and revocation of Energy Commission certification; an administrative fine; or other action as appropriate.” Additional regulations are administered by the California Independent System Operator and under the terms of the federally administered Large Generator Interconnection Agreement.
Regulation in Mexico
Overview
Until December 2013, under the Electricity Public Service Law (Ley del Servicio Público de Energía Eléctrica) enacted in 1975 and amended in 1992, the electricity industry in Mexico was entirely controlled by the federal government, acting through the Federal Electricity Commission, or CFE, an entity wholly owned and controlled by the Mexican government, and legally independent from the Mexican Ministry of Energy, or Secretaría de Energía or SENER. CFE was the only entity authorized to provide electricity directly to the public and to supply services to the Mexican wholesale market. CFE was also responsible for the construction and maintenance of infrastructure necessary for the delivery of electricity, such as the national electric grid, the Sistema Eléctrico Nacional, or SEN.
Notwithstanding the foregoing, private entities were allowed to participate in the following activities not considered public utility services, as defined by the aforementioned law:

| • | Cogeneration. The electricity produced is used to supply power to the establishments associated with the cogeneration process and/or the shareholders of the cogeneration company;

| • | Self-Supply Generation. The electricity produced is used for the self-supply purposes of the holder of the relevant self-supply power generation permit and/or its shareholders;

| • | Independent Power Production. All the electricity produced is delivered to CFE;

| • | Small-Scale Production. The electricity produced does not exceed 30 MW and is used for export purposes or the supply of all power output is sold to CFE;

| • | Exports. The electricity produced is exported in its entirety and

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| • | Imports for Independent Consumption. The import of power is used for self-supply purposes.

Since the energy reform of December 2013 and the enactment of the Electric Industry Law (Ley de la Industria Eléctrica), the power generation sector has been more open to private participation and investment, creating a competitive spot market in power generation, although electric transmission and distribution remain public services to be provided exclusively by CFE. The national electric grid is a responsibility of the Centro Nacional de Control de Energía, or the CENACE, which became a decentralized public agency, an Independent System Operator, or ISO.
Since the energy reform process started, secondary legislation and regulation was enacted derived from such amendments to the Mexican Constitution as published in the Official Federal Gazette, or Diario Oficial de la Federacion, on August 11, 2014. The changes made by the energy reform were implemented through a profound modification of the legal framework that had governed the development of the energy industry in the country.
However, on February 1st, 2021, Mexico´s President proposed a preferential reform to the Electricity Industry Act, meaning that the Congress shall vote on it no later than April 30th. In broad terms, the reform aims for CFE to recover the preponderance that it lost in the energy generation sector with the constitutional reform of 2013 by, among others, (i) changing the dispatch criteria from economic merit to CFE´s assets; (ii) giving CFE the ability to force the termination of self-supply legacy contracts; (iii) allowing any renewable generator to get clean energy certificates (which will create a surplus and therefore will undermine their purpose); (iv) eliminating CFE´s obligation to buy energy through auctions; and (v) granting the Energy Ministry the possibility of deciding which generation permits are granted by the Federal Energy Regulatory Commission.
Conventional Electricity Generation in Mexico
Electric Industry Law
The Electric Industry Law regulates planning activities, the control of the national electric grid, the public services of transmission and distribution of electricity, and all other activities related to the Mexican energy industry, in order to promote the sustainable development of the industry and to ensure its continuous, efficient, and secure operation for the benefit of all users, as well as the fulfillment of the obligations to provide a general and public service of electricity, to develop clean energies, and to reduce contaminating emissions.
Pursuant to the Electric Industry Law, the government holds the operational control of the national electric grid, through the CENACE, and CENACE, as an ISO, indicates the elements for the national transmission grid and the related operations which may correspond to the wholesale market.
Regulations of the Electric Industry Law
The Regulations of the Electric Industry Law provide details for the application of the Electric Industry Law. These regulations expand on certain administrative procedures in the electric industry, such as the development of public bidding procedures by CFE, for private sector contracts for activities related to the national electric grid; the specific requirements for the application for power generation and power supply permits with CRE; the process for infrastructure contributions by the private sector to the State; and the registration of participants in the wholesale spot market with CENACE.
Permits and Authorizations
Pursuant to the Electric Industry Law, all power plants with a capacity greater than or equal to 0.5 MW require a generation permit granted by CRE. The Electric Industry Law also provides for several requirements which generators who represent power plants interconnected to the national electric grid have to comply with, including, among others, the execution of the corresponding interconnection agreements, issued by CRE.
CRE may also issue a supply permit for private parties, which will allow companies to participate in the MEM by carrying out transactions with final users, which are called “qualified users.” In this sense, private parties may supply power directly to consumers through bilateral long-term agreements, which will be partially regulated by the CRE.
Consequently, the Mexican power industry is divided into two main areas: (i) the public service of electricity under CFE’s control, and (ii) the activities where private parties may be involved (such as where CFE actively promoted private investment in the construction and operation of power plants for supplying CFE and private parties under self-supply and cogeneration schemes).
While power generated in Mexico is still predominantly generated by CFE, there is a large amount of electricity generated by private energy producers, which generally fall under the categories of independent power production and self-supply generation, although cogeneration has come to be a relevant source of power as a result of certain amendments enacted in 2006 which allowed Pemex to develop new cogeneration projects independently and in collaboration with CFE. These amendments allowed Pemex to enter into the Pemex conversion services agreement and to receive the power generated by ACT.
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As a consequence of the corresponding reforms the issuance of a new class of permit available to those interested in generating electricity is provided for pursuant to the Electric Industry Law. This permit expanded the ways in which entities are allowed to participate as energy producers under the Electric Industry Law and is within the scope of the CRE’s regulatory control.
The permits provided for in the Electric Industry Law are, as aforementioned, granted and issued by CRE, upon prior submission of the corresponding application, payment of the corresponding duties, all relevant legal and technical information, and project description. Such permits will be terminated or revoked pursuant to the different scenarios indicated in the Electric Industry Law and its regulations, and as determined by CRE.
Transmission and Distribution of Electricity in Mexico
Pursuant to the Electric Industry Law, regarding conventional energy generation, dispatchers and distributors are responsible for the national transmission grid and the general distribution grids and will operate their grids pursuant to the instruction provided by CENACE.
CFE is required by law to provide its wheeling (the transfer of electrical power through transmission and distribution lines to another utility), dispatch and backup services to all permit holders whenever the requested service is technically feasible on a first-come, first-served basis. CFE’s wheeling services are provided pursuant to an interconnection agreement and a transmission services agreement entered into between CFE and the relevant permit holder (in ACT’s case, these were executed by Pemex). Those agreements follow model contracts approved by the CRE, which also approves the methodology used to calculate the applicable tariffs. The permit holders must build their own transmission lines for self-use in order to connect to the power grid. In addition, permit holders are required to enter into a back-up services agreement with CFE, which also follow a model agreement approved by the CRE.
The Electric Industry Law incorporates requirements to carry out the sale and purchase of electricity. Aside from being classified as a generator or qualified user, along with the need to comply with the rules issued by CRE for the execution of the corresponding agreements, there are requirements for the interconnection to the transmission grid owned by CFE.
Open Access
Both the Electric Industry Law and in the regulations thereunder establish that CFE is obligated to grant non-discriminatory open access to all users of the national electric grid. Open access is a crucial component of the electric industry since CFE, as owner of the grid, competes directly with other private sector participants in several activities of the industry, which could lead to a monopoly by CFE. In order to avoid such situation, the CENACE, as an independent system operator, will ensure competitive conditions for all users who want to use CFE’s infrastructure.
Pursuant to the regulations, CRE issued the general guidelines regarding open access conditions, the procedure for users to request such open access and the procedure to which the CENACE will be subject to grant this open access, among others.
Wholesale Spot Market, Mercado Eléctrico Mayorista
MEM participants can be (i) generators, (ii) provider-traders, (iii) non-provider traders, or (iv) qualified users, prior to execution of the corresponding agreement with CENACE. Transactions carried out within the MEM must be formalized through “electric coverage agreements” executed by and between such MEM participants. Generators, as MEM participants may, sell their generated energy and both traders and qualified users may purchase such energy through CENACE, which is the independent operator of the electric system.
CENACE is responsible for managing the supply and demand of MEM participants, conducting transactions and continuously generating prices. The price to be paid in MEM transactions has to be a “competition price” in terms of the Electric Industry Law and has to reflect elements such as electricity generation costs and other operating costs, as well as the amount of electricity demanded by and supplied within the MEM. Such competition price serves as a reference for long-term supply agreements between providers and qualified users, partially replacing the CFE-published tariffs.
Even though the Electric Industry Law provides the general guidelines to which the operation of the MEM is subject, on September 8, 2015, the Mexican Ministry of Energy published the Guidelines of the Market (Bases del Mercado Eléctrico), as the general administrative provisions which establish the principles for the design and operation of the MEM. The regulations list certain topics which are described in depth in the Rules of the Market (Reglas del Mercado), such as the methodology that is used to forecast the level of demand in the spot market, information on market participants, and the methodology to determine the price of the electricity sold and purchased within the spot market.
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The Guidelines are part of the Rules of the Market, which are administrative provisions of general application that specifically detail different aspects of the operation of the MEM, and determine the rules that all market participants, such as generators, traders, suppliers, non-supplier traders or qualified users, as well as the competent authorities must comply with.
Current Regulatory Framework
The following laws and regulations are among the main provisions that include constitutional, legal and regulatory provisions applying to the development of cogeneration projects in Mexico, according to the recently enacted regulatory framework:

| • | Political Constitution of the United Mexican States (Constitución Política de los Estados Unidos Mexicanos).

| • | Electric Industry Law (Ley de la Industria Eléctrica).

| • | Regulation of the Electric Industry Law (Reglamento de la Ley de la Industria Eléctrica)

| • | Energy Regulatory Bodies Law (Ley de los Órganos Reguladores Coordinados en Materia Energética).

| • | Energy Transition Law (Ley de Transición Energética).

| • | Federal Electricity Commission Law (Ley de la Comisión Federal de Electricidad).

| • | Regulations of the Federal Electricity Commission Law (Reglamento de la Ley de la Comisión Federal de Electricidad).

| • | Terms for the strict legal segregation of the Federal Electricity Commission (Términos para la estricta separación legal de la Comisión Federal de Electricidad).

| • | Geothermal Energy Law (Ley de Energía Geotérmica).

| • | Guidelines that regulate the criteria for granting clean energy certificates (Lineamientos que establecen los criterios para el otorgamiento de certificados de energía limpia) which have been recently amended and which relevant implications will be further mentioned below.

| • | Guidelines of the Market (Bases del Mercado Eléctrico).

| • | Network’s Code (Código de Red).

| • | General Administrative Provisions that establish the terms for the operation of the Register of Qualified Users (Disposiciones administrativas de carácter general que establecen los términos para la operación y funcionamiento del registro de Usuarios Calificados).

| • | Resolution by means of which the Energy Regulatory Commission issues the general administrative provisions that establish the general conditions for the provision of the energy supply (Resolución por la que la Comisión Reguladora de Energía expide las Disposiciones administrativas de carácter general que establecen las condiciones generales para la prestación del suministro eléctrico).

| • | Mechanism to request the modification of the permits granted under the Electricity Public Service Law for generation permits, as well as the criteria under which the permit holders of such regime may execute an interconnection contract while the Wholesale Electricity Market becomes effective (Mecanismo para solicitar la modificación de los permisos otorgados bajo la Ley del Servicio Público de Energía Eléctrica por permisos con carácter único de generación, así como los criterios bajo los cuales los permisionarios de dicho régimen podrán celebrar un contrato de interconexión en tanto entra en operación el mercado eléctrico mayorista).

| • | General administrative provisions for the operation of the certificate procurement system and the compliance with the clean energy obligations (Disposiciones administrativas de carácter general para el funcionamiento del sistema de gestión de certificados y cumplimiento de obligaciones de energías limpias).

| • | General administrative provisions that establish the minimum requirement to be met by suppliers and qualified users participating in the Electricity Market to acquire energy demand in terms of article 12, section XXI, of the Electricity Industry Law (Disposiciones administrativas de carácter general que establecen el Requisito mínimo que deberán cumplir los suministradores y los usuarios calificados participantes del mercado para adquirir potencia en términos del artículo 12, fracción XXI, de la Ley de la Industria Eléctrica).

| • | General administrative provisions regarding open access and provision of services in the National Transmission Network and the General Distribution Networks (Disposiciones administrativas de carácter general en materia de acceso abierto y prestación de los servicios en la Red Nacional de Transmisión y las Redes Generales de Distribución de Energía Eléctrica).

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| • | General administrative provisions that establish the requirements and minimum amounts of electricity coverage contracts that suppliers must hold regarding electric power, energy demand and clean energy certificates that they will supply to the represented load centers and their verification (Disposiciones administrativas de carácter general que establecen los requisitos y montos mínimos de contratos de cobertura eléctrica que los suministradores deberán celebrar relativos a la energía eléctrica, potencia y certificados de energía limpia que suministrarán a los centros de carga que representen y su verificación).

| • | Policy on Reliability, Safety, Continuity and Quality on the National Electric System (Política de Confiabilidad, Seguridad, Continuidad y Calidad en el Sistema Eléctrico Nacional).

| • | Decree to guarantee the Efficiency, Quality, Reliability, Continuity and Safety of the NationalElectric System, due to the recognition of the epidemic of the SARS-CoV2 virus disease (COVID-19) (Decreto para garantizar la Eficiencia, Calidad, Confiabilidad, Continuidad ySeguridad del Sistema Eléctrico Nacional, con motivo del reconocimiento de la epidemia de la enfermedad por el virus SARS-CoV2 (COVID-19)).

| • | Resolution by means of which CFE announced the new wheeling tariffs to owners of Legacy Interconnection Agreements with renewable energy sources (Resolución por medio de la cual CFE dio a conocer las nuevas tarifas de transmisión a los titulares de Contratos de Interconexión Legados con fuentes de energía renovable).

Regulation in Peru
The Electric Transmission Sector
The Peruvian electric system serves energy to a large area of the country through its national grid, the SEIN (the Sistema Eléctrico Interconectado Nacional).
Pursuant to Law 28832, which is applicable to any transmission project commissioned after July 2006, the transmission facilities integrating the transmission grid are classified as those belonging to: either (i) the Guaranteed Transmission System, or Sistema Garantizado de Transmisión (SGT), for transmission facilities that are included in the transmission plan and developed pursuant to a concession agreement granted by the Peruvian government to the winner of a public tender, or (ii) the Complementary Transmission System, or Sistema Complementario de Transmisión (SCT), for transmission facilities that are either (a) included in the transmission plan and developed by the private entity that was awarded a concession as a result of the successful review of a private initiative proposal, or (b) not included in the transmission plan. ATN and ATS are part of the Guaranteed Transmission System. ATN2 is part of the Complementary Transmission System,
Under Law 28832, the projected expansions of the transmission system identified in the Peruvian transmission plan are part of the SGT. The government organizes tender procedures to call private investors interested in building the projected lines of the SGT. Under SGT Concession Agreements, the concessionaire shall build the lines and be responsible for their operation and maintenance. Recovery of the investment during the term of the contract (up to 30 years) is guaranteed thereunder. The concessionaire owns the transmission assets during the term of the contract. Upon expiry of the contract the assets return to the State which shall call a new tender if the lines are required at such time for the operation of the system.
Transmission lines of interest to generation plants, distribution networks or large consumers are part of the SCT. The lines of the SCT included in the Peruvian transmission plan and certain projects that exclusively serve the demand, as defined by the government, may be subject to tenders for the granting of SCT Concession Agreements up to 30 years. The rest of the SCT projects are subject to the general regime in which the owners of the SCT lines (for example, the generation companies building them to connect their plants to the system) are the holders of the respective Definitive Transmission Concession and own the transmission assets through the term of the concession.
Tariff Regime
The SGT is compensated through the tariff base, which is the authorized annual remuneration for facilities belonging to the SGT. The tariff base is established in annual amounts and includes the following: (i) remuneration of investments (including adjustments), which is calculated based on a 30-year recovery period applying a 12% rate of return, (ii) efficient operating and maintenance costs, and (iii) the liquidation of imbalances between the authorized tariff base for the previous year and the proceeds obtained during that year.
The tariff base will be paid through the (i) tariff income and (ii) the transmission toll. The tariff income is paid monthly by the electricity generation companies in proportion to their respective capacity income. The transmission toll is paid by the electricity generation companies based on their collection of the transmission toll paid by their respective customers pursuant to Article 26 of Law 28832 and Article 27 of the Transmission Rules, or Reglamento de Transmision, approved by the Supreme Decree No. 027-2007-EM.
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The SCT is remunerated on the basis of the annual average cost of the corresponding facilities approved by OSINERGMIN. The applicable tariffs and their respective actualization formulas are approved by OSINERGMIN every four years.
Penalties
The concessionaires must maintain certain quality, safety and maintenance standards of the facilities. The failure to meet the quality standards established by applicable industry regulations, such as the technical rules of quality for power services, approved by Supreme Decree No. 020-97-EM, and the National Power Code, may result in the imposition of penalties, fines and restrictions. In addition to these penalties, fines and restrictions, if our concession is terminated due to the breach of obligations under the Concession Agreements, the Peruvian Ministry of Energy may appoint an intervenor to supervise the operations related to the concession to ensure the continuity in the provision of the service, and the compliance with applicable laws and regulations.
If a concessionaire suspends or interrupts the service for reasons other than regular maintenance and repairs, force majeure events, or failures caused by third parties, such concessionaire may be required to indemnify those who were affected for the damages caused by any such service interruption, in accordance with applicable regulations.
Electricity Legal Framework
The principal laws and regulations governing the Peruvian power sector, or the Power Legal Framework, are: (i) the Power Concessions Law (or Ley de Concesiones Electricas, PCL), approved by Law No. 25844, and its implementing rules (Supreme Decree No. 09-93-EM); (ii) the Law to Ensure the Efficient Development of Electricity Generation (or Ley para Asegurar el Desarrollo Eficiente de la Generacion Electrica), approved by Law No. 28832, or Law No. 28832; (iii) the Transmission Rules (or Reglamento de Transmision), approved by the Supreme Decree No. 027-2007-EM, or the Transmission Rules; (iv) the General Environmental Law (Law No. 28611); (v) the new Regulations for the Environmental Protection in Power Activities, approved by Supreme Decree No. 014-2019-EM, published on July 7, 2019; (vi) the Power Sector Antitrust Law (Law No. 26876) and its regulations (Supreme Decree No. 017-98-ITINCI); (vii) the Laws creating OSINERGMIN (Law No. 26734 and Law No. 28964); (viii) the OSINERGMIN Rules (Supreme Decree No. 054-2001-PCM); (ix) the Regulatory Agencies of Private Investment in Public Services Framework Law (Law No. 27332); and (x) the Legislative Decree that promotes investment in the generation of power through renewable resources (Legislative Decree No. 1002) and its regulations (Supreme Decree No. 012-2011-EM).
These laws regulate how to enter the electricity sector (applicable permits and licenses); the main obligations of the different participants of the electricity market (generators, transmission companies and distribution companies); remuneration systems for the different market participants; rights of electricity consumers and the attributions of the competent authorities.
Some of the main aspects of Peru’s regulatory framework concerning its power sector are: (i) the separation between the power generation, transmission and distribution activities; (ii) unregulated prices for the generation of power supplied to unregulated customers; (iii) regulated prices for the generation of power supplied to regulated customers; (iv) regulated prices applicable to transmission and distribution of power for both regulated and unregulated customers; and (v) the private administration of the SEIN, according to the principles of efficiency, cost reduction, guaranty of quality and reliability in the provision of services.
Regulation for Environmental Protection in Electrical Activities
In accordance with the current environmental legal framework, as a general rule, prior to the construction and beginning of the electrical activities (i.e. generation, transmission or distribution) the holder must obtain from the Ministry of Energy and Mines (hereinafter, “MINEM”) the Instrument for Environmental Management (hereinafter, “IEM”), which after its approval is mandatory for implementation.
By Supreme Decree No. 014-2019-EM, published on July 7, 2019, the MINEM approved the new Regulation for Environmental Protection in Electrical Activities (hereinafter, the “REPEA”).
The Guaranteed Transmission System—SGT Concession Agreement
ATN and ATS, as concessionaires, have SGT Concession Agreements granted by the Peruvian government as a result of a public tender. Under the SGT Concession Agreement, the Peruvian Ministry of Energy grants the concession necessary to construct, develop, own, operate, and maintain the transmission lines and substations comprising a project to provide electricity transmission services that has been included in the Peruvian transmission plan.
The SGT Concession Agreement must specify the works schedule of the project and the corresponding guaranties of compliance. It also specifies the causes of termination of the agreement. The SGT concessionaires are not obliged to pay the grantor any consideration for the SGT Concession Agreement.
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Under the SGT Concession Agreement, the concessionaire shall build the lines and be responsible for their operation and maintenance. The recovery of the investment during the term of the contract (30 years) is guaranteed thereunder. The concessionaire owns the transmission assets during the term of the contract. Upon expiry of the contract the assets return to the state, which shall call a new tender if the lines are required at such time for the operation of the system.
The revenues of the project are established under the terms of the SGT Concession Agreement. In addition, the revenues of the project are funded by the users of electricity system. The SGT will receive monthly compensation from the generation companies that collect the tariff base from their customers. Their compensation will be paid on a monthly basis and these monthly payments are liquidated by the COES, following the tariffs established annually by OSINERGMIN.
Regulation in Spain
Primary Rights and Obligations under the Electricity Act
The Electricity Act recognizes the following rights for producers with facilities that use renewable energy sources:

| • | Priority off-take. Producers of electricity from renewable sources have priority over conventional generators in transmitting to off takers the energy they produce under equal market conditions, without prejudice to the requirements relating to the maintenance of the reliability and safety of the national electricity system and based on transparent and non-discriminatory criteria, in terms to be determined by the Government in a regulatory manner.

| • | Priority of access and connection to transmission and distribution networks. Without prejudice to the security of supply and the efficient development of the system, producers of electricity from renewable energy sources have priority in obtaining access and connecting to the grid, subject to the terms set forth in the regulations, on the basis of objective, transparent and non-discriminatory criteria.

| • | Entitlement to a specific payment scheme: In the case of existing facilities for the production of energy from renewable energy sources for which the specific remuneration system is recognized it is stablished a remuneration system based on the necessary participation in the market of these facilities, complemented by market income with a specific regulated remuneration that allows these technologies to compete on an equal conditions with the rest of the technologies on the market. This specific complementary remuneration will be sufficient to reach the minimum level necessary to cover the costs and enables them to compete on a level playing field with the other, non-renewable technologies on the market while achieving a reasonable return on investment. In case of new facilities, the Government can establish a specific remuneration and the granting of it would be via auction.

The significant obligations of the renewable energy electricity producers under the Electricity Act include, inter alia, a requirement to:

| • | Offer to sell the energy they produce through the market operator even when they have not entered into a bilateral or forward contract and are consequently excluded from the bidding system managed by the market operator.

| • | Maintain the plant’s planned production capacity. Power lines, which include connections with the transmission or distribution network and transformers are considered part of the production facility.

Additionally, the Royal Decree 413/2004 establishes the following relevant obligations for the renewable energy electricity facilities:

| • | Having, prior to the beginning of discharge into the grid, the equipment for measuring electrical energy.

| • | The facilities must be registered in the Administrative Register of Electrical Energy Production Facilities under the Ministry of Industry.

| • | Voltage dips: all facilities or groupings of photovoltaic facilities with an installed power greater than 2 MW, in accordance with the definition of grouping, shall be obliged to comply with the requirements for responding to voltage dips established by means of the corresponding operating procedure.

| • | Control centers: all facilities with installed power greater than 5 MW, and those with installed power less than or equal to 5 MW but which form part of a grouping of the same subgroup of article 2 whose total sum of installed powers is greater than 5 MW, must be attached to a generation control center.

| • | Send of telemetric measurements: all facilities producing from renewable energy sources, cogeneration and waste with installed capacity greater than 1 MW, or less than or equal to 1 MW but which form part of a grouping of the same subgroup whose total installed capacity is greater than 1 MW, must send telemetric measurements to the system operator in real time.

Compliance with these last three obligations will be a necessary condition for the receipt of the specific retribution regime and must be accredited to the body in charge of carrying out the settlements. Otherwise, only market revenues will be received, without prejudice to the applicable sanctioning regime.
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Permits and authorizations
The Electricity Act and the Royal Decree 1955/2000 generally require facilities producing renewable electricity to obtain the following administrative authorizations:

| • | Prior Administrative authorization (Autorización Administrativa Previa), which refers to the preliminary project of the installation as a technical document that will be processed, where appropriate, together with the environmental impact study.

| • | Approval of the execution project (Autorización Administrativa de Construcción), which refers to the specific project of the facility and allows its owner to construct or establish it.

| • | Operating permit (Autorización Administrativa de Explotación), which, once the project has been executed, allows the facilities to be energized and to proceed with their commercial exploitation.

Registration on Public Registers
The Electricity Act and Royal Decree 413/2014 require electricity generation facilities to be entered on the official register of electricity production plants maintained by the Ministry for Ecological Transition and the Demographic Challenge.
The autonomous regions may keep their own registers of electricity generation plants they have authorized if such plants have a capacity of 50 MW or less. The registration details of these plants must be provided to the Ministry for Ecological Transition and the Demographic Challenge.
To receive their facility-specific reimbursement, renewable energy facilities are required under the Electricity Act and Royal Decree 413/2014 to be recorded on a new register , known as the registry of the specific remuneration regime (“Registro de régimen retributivo específico” or “RRRE”). Unregistered plants will only receive the pool price.
The first transitional provision of Royal Decree 413/2014 states that power plants based on renewable sources recognized under the previous economic regime, as in the case of Solaben 2 & 3, Solacor 1 & 2, PS10 & 20 were automatically included in the RRRE.
Remuneration System for Renewable Plants
According to Royal Decree 413/2014, producers receive (i) the pool price for the power they produce and (ii) a specific remuneration.
A specific remuneration system applies to production facilities using renewable energy sources, high-efficiency cogeneration and waste that do not reach the minimum level necessary to cover the costs. It allows them to compete on an equal footing with the rest of the technologies on the market, obtaining a reasonable return. In order to determine the specific remuneration system applicable in each case, each installation, depending on its characteristics, will be assigned a standard installation which will be established according to technology, installed power, age, electrical system, etc. The specific remuneration of each installation will be obtained from the remuneration parameters of the corresponding standard installation and from the characteristics of the installation itself. For the calculation of the remuneration parameters of the standard installation, the values resulting from the competitive competition procedure shall be applied.
This specific remuneration system shall consist of:

| a) | A remuneration per unit of installed power, which shall be called investment remuneration (Rinv) and shall be expressed in €/MW. To determine this parameter, the standard value of the initial investment resulting from the competitive tendering procedure established to grant the specific remuneration system to each installation will be considered. For the calculation of the annual income from the remuneration for the investment of an installation, the remuneration for the investment (Rinv) of the associated typical installation shall be multiplied by the power entitled to the specific remuneration system, without prejudice to the correction according to the number of equivalent hours of operation.

| b) | A remuneration for the operation (Ro) which shall be calculated in accordance with the provisions of Article 17 of the Royal Decree 413/2014, expressed in €/MWh. In order to calculate the income from the remuneration for the operation of an installation, the remuneration for the operation (Ro) of the associated typical installation shall be multiplied, for each settlement period, by the energy sold on the production market in any of its forms of contracting in said period, attributable to the fraction of power entitled to a specific remuneration system, without prejudice to the correction based on the number of equivalent hours of operation.

For solar thermal plants, electrical energy attributable to the use of other fuels shall be excluded. The production of energy from the support fuel of solar thermal plants may not exceed 12 per cent of the total electricity production to be entitled to receive the specific remuneration system. The repetition of this non-compliance is reason for the cancellation of the inscription in the RRRE.
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To calculate the energy attributable to the fraction of power entitled to a specific remuneration system, the corresponding energy shall be multiplied by the ratio resulting from dividing the power entitled to a specific remuneration system by the installed power. In order to determine the power entitled to the specific remuneration system of a facility, the value of the power registered for this purpose in the register of the specific remuneration system in operation for said facility shall be taken as the value of the power registered for this purpose in the register of the specific remuneration system in operation for said facility.
For the granting of the specific remuneration system, the conditions, technologies or group of specific facilities that may participate in the competitive competition mechanism shall be established by royal decree. Subsequently, by order of the relevant Minister, with the prior agreement of the Government’s Delegate Committee for Economic Affairs, the remuneration parameters corresponding to the type of reference facilities that are the object of the competitive bidding mechanism shall be established, as well as the terms in which it shall be developed. The granting of this specific remuneration system for existing facilities is regulated in the first transitory provision of RD 413/2014, that establishes that they will be automatically registered on a date to be determined by order of the Minister for Ecological Transition and Demographic Challenge. In any case, it contemplates the possibility of requesting the modification of the inaccuracies that could contain the data of the registry after the referred automatic inscription.
As established in Order IET/1168/2014, of 3 July, the existing facilities were automatically registered in the RRRE on 9 July 2014. In order to determine the information required for automatic registration in the RRRE, the information included in the “Settlement System” at the time of registration was taken into account or, for those facilities not yet included in said System, that of the remuneration pre-allocation register.
Renewable facilities must be registered in the liquidation system of the CNMC. In order for an installation to be registered in said Settlement System, it must be operating and registered in the well-deserved Register.
Payment Factors for Solar Power Plants
The payment system applicable for each plant is based on various criteria considered by the Ministry for Ecological Transition and includes the specific technology used, amount of power produced relative to operating costs, age of the facility and any other differentiating factor deemed necessary to consider in applications of the payment system.
Revenue Order recognizes six types of solar thermal plants: (i) parabolic trough collectors without a storage system, (ii) parabolic trough collectors with a storage system, (iii) central or tower receivers without a storage system, (iv) central or tower receivers with a storage system, (v) linear collectors and (vi) solar-biomass hybrids.
To determine the payment system applicable to each plant, the following factors are considered:

| • | Net investment value. This consists of a standard amount per MW for each type of plant, calculated by the method set out in Royal Decree 413/2014, which is the amount invested in the plant and not depreciated as of July 14, 2013.

| • | Useful life of the plant. For solar thermal plants this is 25 years and for photovoltaic plants this is 30 years.

| • | Return on investment. Considering the net asset value determined on the basis of a standard cost per MW built, an amount is set per unit of power, which enables investment costs that cannot be recovered through the pool price to be recouped over the useful life of the plant.

| • | Operating remuneration. An amount is set per unit of power and hour that, added to the pool price, enables the producer to recoup all the plant’s operating and maintenance costs. Operating expenses include the cost of land, electricity, gas and water bills, management, security, corrective and preventive maintenance, representation costs, the Spanish tax on special immovable properties, insurance, applicable generation charges and a generation tax which is equal to 7% of total revenue.

| • | Maximum number of operating hours. A maximum number of hours is set for which each plant type can receive the operating remuneration

| • | Operating threshold. Plants must operate for more than a set number of hours per year to receive the return on investment and operating remuneration.

| • | Minimum operating hours. Plants that cross the operating threshold but operate for fewer hours than the annual minimum hours receive a lower remuneration.

Regulatory Periods
Payment criteria are based on prevailing economic conditions in Spain, demand for electricity and reasonable profits for electricity generation activities and can be revised every three or six years. The Royal Decree 413/2014 establishes statutory periods of six years, with the first statutory period running from July 14, 2013 to December 31, 2019 and the second regulatory period beginning in January 2020. Each statutory period is divided into two statutory half-periods of three years.
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This “statutory period” mechanism aims to set forth how and when the Ministry for Ecological Transition and Demographic Challenge is entitled to revise the different payment factors used to determine the specific remuneration to be received by the standard facilities.
At the end of each statutory half-period (three years) the Ministry for Ecological Transition and Demographic Challenge may revise (i) the electricity market price estimates and (ii) the adjustment value for electricity market price deviations in the preceding statutory half-period.
Reasonable Rate of Return
According to article 14 of the Electricity Act, the remuneration shall not exceed the minimum level necessary to cover the costs that allow production facilities from renewable energy sources, high-efficiency cogeneration and waste to compete on an equal level with the other technologies on the market and that allows reasonable return to be obtained in relation to the standard installation in each applicable case.
The first regulatory period began on January 1, 2013. For this period, the value of the return of the reference rate projects was set, before taxes, as the average secondary market yield for the three months prior to the entry into force of Royal Decree-Law 9/2013, of 12 July, of the 10-year State Obligations increased by 300 basis points. This spread is based on:

| • | Appropriate profit for this specific type of renewable electricity generation and electricity generation as a whole, considering the financial condition of the Spanish electricity system and Spanish prevailing economic conditions; and

| • | Borrowing costs for electricity generation companies using renewable energy sources with regulated payment systems, which are efficient and well run, within Europe.

The second regulatory period began on January 1, 2020. On July 27, 2018, CNMC (the regulator for the electricity system in Spain) issued a draft proposal for the calculation of the reasonable rate of return for the regulatory period 2020-2025. The reasonable return is no longer calculated by reference to the Spanish government 10-year bonds but by reference to the weighted average cost of capital (WACC). The WACC is the calculation method that most of the European regulators apply in most of the cases to determine the return rates applicable to regulated activities within the energy sector.
Following the recommendations of the CNMC, the Government adopted the Royal Decree-Law 17/2019, which came into force on November 24, 2020 and was validated by the Permanent Delegation of the Congress on November 27, 2020, and which is aimed to update the reasonable rate of return that applies to standard renewable energy facilities in the period 2020-2025. In accordance with the sole article of this Royal Decree-Law, the reasonable return applicable over the remaining regulatory life of standard facilities, which was used to review and update the remuneration parameters applicable during the second regulatory period, is 7.09%. The measure was intended to create certainty for investors, since it established by means of a regulation with the rank of law the new value of reasonable return for the following regulatory period.
In addition, the Royal Decree-Law introduced a third final provision in Law 24/2013, of 26 December, on the Electricity Sector, which exceptionally, gave the option to the owners of renewable facilities that were recognized as having primary remuneration before the entry into force of Royal Decree-Law 9/2013, to maintain the value of the reasonable return fixed for the first regulatory period for two consecutive regulatory periods starting on January 1, 2020. In other words, these owners are able to maintain a reasonable return for their facilities of 7.398% until 2031. However, this new measure shall not be applicable when an arbitration or judicial proceeding based on the modification of the special remuneration system after Royal Decree 661/2007 is initiated or has previously been initiated by any current or previous shareholders unless it is proven that the arbitration or legal proceedings have been early terminated and the resumption or continuation of the proceedings and the receipt of compensation or indemnification has been duly waived. According to public information, current minority shareholders and previous shareholders of six of our solar plants have arbitration process outstanding.
The final parameters were finally approved by the Order TED/171/2020, of 24 February were that was published on February 28, 2020. The Order takes as a starting point the new reasonable rate of return approved by Royal Decree-Law 17/2019. These remuneration parameters shall be applicable with retroactive effect from the start of the regulatory period (i.e. from January 1, 2020), for the period 2020-2025. The estimated market price for each year of said half-period was set at 54.42 €/MWh, 52.12 €/MWh and 48.82 €/MWh, respectively, for the years 2020, 2021 and 2022.
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The Annex II of the referred Order TED/1717/2020 establishes the remuneration parameters for standard installations applicable to the years 2020, 2021 and 2022: return on investment, number of equivalent operating hours minimum, operating threshold and other remuneration parameters. The parameters applicable to our plants for 2021 are as follows:

| Useful Life |  | Return on Investment 2020-2022 (euros/MW) |  |  | Operating Remuneration 2021 (euros/GWh) |  |  | Maximum Hours |  |  | Minimum Hours |  |  | Operating Threshold |
Solaben 2 | 25 years |  |  | 398,174 |  |  |  | 41,635 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Solaben 3 | 25 years |  |  | 398,174 |  |  |  | 41,635 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Solacor 1 | 25 years |  |  | 398,174 |  |  |  | 41,635 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Solacor 2 | 25 years |  |  | 398,174 |  |  |  | 41,635 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
PS 10 | 25 years |  |  | 550,263 |  |  |  | 63,907 |  |  |  | 1,848 |  |  |  | 1,109 |  |  |  | 647 |
PS 20 | 25 years |  |  | 407,269 |  |  |  | 58,070 |  |  |  | 1,848 |  |  |  | 1,109 |  |  |  | 647 |
Helioenergy 1 | 25 years |  |  | 393,071 |  |  |  | 41,444 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Helioenergy 2 | 25 years |  |  | 393,071 |  |  |  | 41,444 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Helios 1 | 25 years |  |  | 407,037 |  |  |  | 41,635 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Helios 2 | 25 years |  |  | 407,037 |  |  |  | 41,635 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Solnova 1 | 25 years |  |  | 413,423 |  |  |  | 42,332 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Solnova 3 | 25 years |  |  | 413,423 |  |  |  | 42,332 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Solnova 4 | 25 years |  |  | 413,423 |  |  |  | 42,332 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Solaben 1 | 25 years |  |  | 403,599 |  |  |  | 41,838 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Solaben 6 | 25 years |  |  | 403,599 |  |  |  | 41,838 |  |  |  | 2,016 |  |  |  | 1,210 |  |  |  | 706 |
Seville PV | 30 years |  |  | 709,200 |  |  |  | 28,982 |  |  |  | 2,061 |  |  |  | 1,237 |  |  |  | 721 |

Access Fee
Royal Decree-law 14/2010 was passed in order to eliminate the shortfalls between electricity system revenues and costs, referred to as the tariff deficit in the electricity sector.
The First Transitional Provision of Royal Decree-law 14/2010 provided that the owners of electricity production facilities pay a fee for access to the grid to the transmission and distribution companies (this access previously having been provided at no cost) from January 1, 2011. During the interim period, the access fee payable is: (i) calculated at €0.5 per MWh delivered to the network or (ii) any other amount that the Ministry of Ecological Transition and Demographic Challenge establishes.
Royal Decree 1544/2011 implemented the Sole Transitional Provision of Royal Decree 14/2010 and confirmed the interim access fee imposed on electricity producers (€0.5 per MWh), subject to the adoption of a final method for calculating the access fee.
Electricity Sales Tax
On December 27, 2012, the Spanish Parliament approved Law 15/2012, which became effective on January 1, 2013. The aim of Law 15/2012 was to try to combat the problem of the so-called tariff deficit. Law 15/2012, as amended, provides for an electricity sales tax which is levied on activities related to electricity production. The tax is triggered by the sale of electricity and affects ordinary energy producers and those generating power from renewable sources. The tax, a flat rate of 7%, is levied on the total income received from the power produced at each of the facilities, which means that every calendar year, solar power plants will be required to pay 7% of the total amount which they are entitled to receive for production and incorporation into the electricity system of electric power, measured as the net output generated.
In January 2021, the Spanish Courts referred a preliminary ruling to the Court of Justice of the EU related to the validity of the electricity sales tax. The preliminary ruling is expected to be resolved by the Court of Justice of the EU in March 2021. Additionally, the Spanish Parliament has officially proposed an amendment to Law 15/2012 to include a permanent exemption of the electricity sales tax. In case of positive ruling by the Supreme Court of the EU declaring the non-conformity of this tax to EU legislation or approval of a permanent exemption of this tax by the Spanish Parliament, the electricity sales tax could be revoked. In any case, in this situation we expect that the remuneration received by our assets in Spain would be adjusted for the same amount, as a result we do not expect any impact.
Tax Incentive of Accelerated Depreciation of New Assets
Under provisions of the Spanish Corporate Income Tax Act, tax-free depreciation is permitted on investments in new material assets and investment properties used for economic activities acquired between January 1, 2009 and March 31, 2012. Taxpayers who made investments during such period and have amounts pending to be deducted for this concept may apply such amounts with certain limitations.
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Taxpayers who made investments from March 31, 2012 through March 31, 2015 in new material assets and investment properties used for economic activities are permitted to take accelerated depreciation for those assets subject to certain limitations. The accelerated depreciation is permitted if:

| • | 40% of the tax base before the amortization or depreciation and before the offset of tax loss carryforwards for taxpayers (subject to requirements to keep up employment levels); or

| • | 20% of the tax base before the amortization or depreciation and before the offset of tax loss carryforwards for taxpayers (without employment requirements).

Most of the investment in our Spanish assets was undertaken within the regime that applied between January 1, 2009 and March 31, 2012.
These limitations do not apply in respect of companies that meet the requirements set forth in article 108.1 of the Spanish Corporate Income Tax Act related to the special rules for enterprises of a reduced size.
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C. | Organizational Structure

The following summary chart sets forth our ownership structure as of the date of this annual report:
Notes:—
(1) Atlantica Sustainable Infrastructure plc directly holds one share in Palmucho and 10 shares in each of Quadra 1 and Quadra 2
(2) ATIS directly holds one share in each of Atlantica Peru S.A. (AP), ATN S.A. and ATS S.A.
(3) 30% owned by Itochu, a Japanese company
(4) 13% owned by JGC, a Japanese company
(5) AEC holds 49% of Honaine and Skikda. Valoriza Agua, S.L. holds 25.5% of Honaine and 16.9% of Skikda
(6) 20% of Seville PV owned by Instituto de Diversificacion y Ahorro de la Energia, or IDEA, a Spanish state-owned company
(7) ATN holds a 75% stake in ATS
(8) ATN holds a 25% stake in ATN2
(9) 87.5% owned by Starwood
(10) 29% owned by Industrial Development Corporation, a South African Government company and 20% owned by Kaxu Community Trust
(11) 70% owned by Arroyo Energy
(12) 100% indirectly owned by Arroyo Energy Netherlands II
(13) 70% held by Algonquin
(14) Solar project under development in the U.S.
(15) Solar and wind projects under development
(16) 65% held by financial partners
(17) Solar project 100% owned by Chile Platform
(18) Company expected to acquire Calgary District Heating. Closing of the acquisition is subject to conditions precedent and regulatory approvals

D. | Property, Plant and Equipment

See “Item 4.B—Business Overview.”

ITEM 4A. | UNRESOLVED STAFF COMMENTS

Not applicable.
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ITEM 5. | OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion should be read together with, and is qualified in its entirety by reference to, our Annual Consolidated Financial Statements. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs, which are based on assumptions we believe to be reasonable. Our actual results could differ materially from those discussed in these forward-looking statements as a result of various factors, including those set forth under “Item 3.D—Risk Factors” and elsewhere in this annual report.

A. | Operating Results

Overview
We are a sustainable infrastructure company with a majority of our business in renewable energy assets. We complement our portfolio of renewable assets with storage, efficient natural gas and transmission infrastructure assets, as enablers of the transition towards a clean energy mix. We are also present in water infrastructure assets, a sector at the core of sustainable development. Our purpose is to support the transition towards a more sustainable world by investing in and managing sustainable infrastructure, while creating long-term value for our investors and the rest of our stakeholders.
As of the date of this annual report, we own or have an interest in a portfolio of diversified assets in terms of business sector and geographic footprint. Our portfolio consists of 28 assets with 1,591 MW of aggregate renewable energy installed generation capacity (of which approximately 90% is solar), representing 74.3% out of our total revenue, 343 MW of efficient natural gas-fired power generation capacity, 1,166 miles of electric transmission lines and 17.5 M ft3 per day of water desalination.
We currently own and manage operating facilities in North America (United States, Canada and Mexico), South America (Peru, Chile and Uruguay) and EMEA (Spain, Algeria and South Africa). We intend to expand our portfolio, maintaining North America, South America and Europe as our core geographies.
Our assets generally have contracted revenue (regulated revenue in the case of our Spanish assets and one transmission line in Chile). We are focused on long-life facilities as well as long-term agreements that we expect to produce stable, long-term cash flows. As of December 31, 2020, our assets had a weighted average remaining contract life of approximately 17 years. Most of the assets we own, or in which we have an interest have project-finance agreements in place. We intend to grow our cash available for distribution and our dividend to shareholders through organic growth and by acquiring new assets and/or businesses where revenue may not be fully contracted.
We intend to take advantage of, and leverage our growth strategy on, favorable trends in clean power generation, energy scarcity and the focus on the reduction of carbon emissions. Our portfolio of operating assets and our strategy focus on sustainable technology including renewable energy, storage, efficient natural gas, and transmission networks as enablers of a sustainable power generation mix and on water infrastructure. Renewable energy is expected to represent in most markets the majority of new investments in the power sector, according to Bloomberg New Energy Finance 2020, approximately 68% of the world’s power generation by 2050 is expected to come from renewable energy sources, which indicates that renewable energy is becoming mainstream. Global installed capacity is expected to shift from 56% fossil fuels today to approximately two-thirds renewables by 2050. A 14-terawatt expansion of generating capacity is estimated to require approximately $15.1 trillion of new investment between now and 2050 – of which approximately 73% is expected to go to renewables. Another approximately $1 trillion of investment is expected in batteries along with an estimated $14 trillion in expected to go to transmission and distribution during that same period. We believe regions will need to complement investments in renewable energy with investments in storage, efficient natural gas and in transmission networks. We believe that we are well positioned to benefit from the expected transition towards a more sustainable power generation mix. In addition, we believe that water is going to be the next frontier in a transition towards a more sustainable world. New sources of water are needed worldwide, and water desalination and water transportation infrastructure should help make that possible. We currently participate in three water desalination plants with a total capacity of 17.5 million cubic feet per day.
We believe we can achieve organic growth through the optimization of the existing portfolio, escalation factors in many of our assets and the expansion of current assets, particularly our transmission lines, to which new assets can be connected. We currently own three transmission lines in Peru and four in Chile. We believe that current regulations in Peru and Chile provide a growth opportunity by expanding transmission lines to connect new clients. Additionally, we should have repowering opportunities in certain existing renewable energy assets.
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Additionally, we expect to acquire assets from third parties leveraging the local presence and network we have in geographies and sectors in which we operate. We have also entered into and intend to enter into agreements or partnerships with developers and asset owners to acquire assets. We also invest directly and through investment vehicles with partners in assets under development or construction.
We have signed a ROFO agreement with AAGES, a joint venture designed to invest in the development and construction of contracted clean energy and water infrastructure contracted assets, created by Algonquin, a North American diversified generation, transmission and distribution utility company that owns a 44.2% stake in our capital stock
With this business model, our objective is to pay a consistent and growing cash dividend to shareholders that is sustainable on a long-term basis. We expect to distribute a significant percentage of our cash available for distribution as cash dividends and we will seek to increase such cash dividends over time through organic growth and through the acquisition of assets. Pursuant to our cash dividend policy, we intend to pay a cash dividend each quarter to holders of our shares.
Significant Events in 2020
COVID-19 Pandemic
The outbreak of the COVID-19 coronavirus disease (“COVID-19”) declared a pandemic by the World Health Organization in March 2020 continues to spread in our key markets, which have already experienced several waves of the virus. The COVID-19 virus continues to evolve rapidly, and its impact is still uncertain and subject to change. In a bid to combat the spread of the virus, governmental authorities have both taken and recommended a wide variety of measures, including lockdowns and travel restrictions. We have reinforced safety measures at all our assets while still continuing to provide a reliable service to our clients. Since March 2020, we have implemented the use of additional personal protection equipment, reinforced access control to our plants, reduced contact between employees, changed shift and, tested employees. We have also identified and isolated cases and potential cases together with their close contacts and taken additional measures to increase safety procedures for our employees and operation and maintenance suppliers’ employees working at our assets. We have also purchased additional spare parts and equipment required for operations, to safeguard against any potential supply chain disruptions. Although we have not experienced any material impacts, we are seeing some delays in certain maintenance activities. Furthermore, we have adopted additional precautionary measures intended to mitigate potential risks to our employees, including temporarily requiring employees when possible to work remotely in geographies with higher incidence, and suspending all non-essential travel. We have also reinforced our physical and cyber-security measures. We have implemented protocols to decide which offices to keep open and under what limitations, depending on the number of cases and other health indicators in each specific region. We continue to monitor the situation closely at all assets and offices and are ready to take additional action if and when required.
To date, we have not experienced material operational or financial impacts as a result of COVID-19. We have not experienced any disruptions in availability or production in our assets due to COVID-19. Our businesses are considered an essential and critical activity in all our geographies, so we have continued operating our assets even in those countries where economic activity has been limited only to essential business for a certain period of time. In addition, our assets generally have long-term contracts or regulated revenue.
Despite all the above, we cannot guarantee that our operations and financial situation will remain unaffected by the COVID-19 outbreak. (see “Part II—Item 1.A —Risk Factors—Risks Related to the COVID-19 Pandemic”).
Conclusion of the Special Committee
On March 23, 2020 we announced that our special committee concluded the review of the strategic alternatives by reaffirming our current strategy.
Acquisitions during the year
On April 3, 2020 we made an investment in the creation of a renewable energy platform in Chile, together with financial partners, in which we now own approximately a 35% stake and have a strategic investor role. The first investment was the acquisition of a 55 MW solar PV plant in an area with excellent solar resource (Chile PV 1). This asset, has been in operation since 2016, demonstrating a good operating track record during that period while selling its production in the Chilean power market. Our initial contribution was approximately $4 million. On January 6, 2021 we also closed our second investment through the platform with the acquisition of Chile PV 2, a 40 MW PV plant. This asset started commercial operation in 2017 and its revenue is partially contracted. Total equity investment in this new asset was approximately $5.0 million. We have concluded that we have control over these assets, and we are fully consolidating it since each acquisition date. The platform intends to make further investments in renewable energy in Chile and sign PPAs with creditworthy off-takers.
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On August 17, 2020 we closed the acquisition of the Liberty ownership interest in Solana. Liberty was the tax equity investor in Solana. Total equity investment is expected to be up to $290 million of which $272 million has already been paid. The total price includes a deferred payment and a performance earn-out based on the average annual net production of the asset in the four calendar years with the highest annual net production during the five calendar years from 2020 through 2024.
In October 2020 we reached an agreement to acquire Calgary District Heating, a district heating asset in Canada for a total equity investment of approximately $20 million. Calgary District Heating has been in operation since 2010 and represents our first investment in this sector, a sector which has been recognized by the UN Environment Program as being a key measure for cities to reduce their emissions. The asset provides heating services to a diverse range of government, institutional and commercial customers in the city of Calgary. It has availability-based revenue with inflation indexation and 20 years of weighted average contract life. Contracted capacity and volume payments represent approximately 80% of total revenue. Closing is expected by mid-2021 subject to customary conditions precedent and regulatory approvals.
In December 2020 we reached an agreement with Algonquin to acquire La Sierpe, a 20 MW solar asset in Colombia for a total equity investment of approximately $20 million. Closing is expected to occur after the asset reaches commercial operation, currently expected to occur by mid-2021. Closing is subject to customary conditions precedent and regulatory approvals. Additionally, we agreed to potentially co-invest with Algonquin in additional solar plants in Colombia with a combined capacity of approximately 30 MW to be developed and built by AAGES.
In December 2020, we reached an agreement to acquire Coso, a 135 MW renewable asset in California. Coso is the third largest geothermal plant in the United States and provides base load renewable energy to the California ISO. It has PPAs signed with three investment grade offtakers, with a 19-year average contract life. Closing is subject to customary regulatory approvals and is expected to occur in the first half of 2021. The total investment is expected to be approximately $170 million, including approximately $130 million for the equity and $40 million expected to be invested in reducing project debt.
In January 2021 we reached an agreement to increase our equity stake from 15% up to 100% in Rioglass, a multinational manufacturer of solar components. We have closed the acquisition of a 42.5% equity stake, for which we paid $7 million. In addition, we have an option to acquire the remaining 42.5% in the same conditions until September 2021, and after that date the seller has an option to sell the 42.5% also in the same conditions. We intend to find partners to co-invest in the company, as such we expect to classify the investment as held for sale in our consolidated financial statements.
In October 2018, we reached an agreement to acquire PTS, a natural gas transportation platform located in Mexico, close to ACT. PTS has a service agreement signed in October 2017, which is a “take-or-pay” 11-year term contract starting in 2020. We initially acquired a 5% ownership in the project and have an agreement to acquire an additional 65% stake subject to the asset entering into commercial operation, non-recourse project financing being closed and final approvals and customary conditions, including the absence of material adverse effects. Our partner in this asset is also negotiating to sell part of its business, which may include the company that provides operation and maintenance services to PTS. This sale may require change of control waivers and may make the closing of the acquisition more difficult. Additionally, our partner has proposed a number of modifications to the project and the financing agreements. We are currently monitoring the situation in order to decide if we will proceed with the investment or not. We therefore cannot guarantee that we will close this acquisition or that closing will occur on the terms originally agreed.
Corporate Financing Activities
On April 1, 2020 we closed the secured 2020 Green Private Placement for €290 million (approximately $354 million). The private placement accrues an annual rate of 1.96%, payable quarterly and matures in June 2026. Net proceeds were primarily used to repay the Note Issuance Facility 2017.
On July 8, 2020, we entered into the Note Issuance Facility 2020, a senior unsecured financing with Lucid Agency Services Limited, as agent, and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of approximately $171 million which is denominated in euros (€140 million). The notes under the Note Issuance Facility 2020 were issued on August 12, 2020 and have a maturity of seven years from the closing date. We expect to use the proceeds from the Note Issuance Facility 2020 to finance acquisitions and for general corporate purposes.
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On July 17, 2020, we issued $100 million aggregate principal amount of 4.00% Green Exchangeable Notes due 2025. On July 29, 2020, we issued additional $15 million aggregate principal amount of the Green Exchangeable Notes. The notes mature on July 15, 2025. The initial exchange rate of the notes is 29.1070 ordinary shares per $1,000 principal amount of notes, which is equivalent to an initial exchange price of $34.36 per ordinary share. Noteholders may exchange their notes at their option at any time prior to the close of business on the scheduled trading day immediately preceding April 15, 2025, only during certain periods and upon satisfaction of certain conditions. On or after April 15, 2025, noteholders may exchange their notes at any time. Upon exchange, the notes may be settled, at our election, into ordinary shares of Atlantica, cash or a combination of both. The exchange rate is subject to adjustment upon the occurrence of certain events. The proceeds from the Green Exchangeable Notes were used to finance the acquisition of new or existing assets or projects which meet certain eligibility criteria in accordance with our Green Finance Framework.
On December 11, 2020 we closed an underwritten public offering of 5,069,200 ordinary shares, including 661,200 ordinary shares sold pursuant to the full exercise of the underwriters’ over-allotment option, at a price of $33 per new share. Additionally, Algonquin purchased 4,020,860 ordinary shares in a private placement in order to maintain its equity interest in the Company. The private placement closed on January 7, 2021. Gross proceeds of the public offering and the private placement were approximately $300 million, which we intend to use to finance growth opportunities and for general corporate purposes after deducting underwriting discounts and commissions and offering expenses
Project Financing Activities
On April 8, 2020, Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 1 & 6 and Solaben 2 & 3 entered into the Green Project Finance, a green project financing euro-denominated agreement with ING Bank, B.V. and Banco Santander S.A. The lenders of the new facility have no recourse to Atlantica at the corporate level. After considering transaction costs and reserves, the Green Project Finance resulted in a net recap of $143 million that was used to finance new investments in renewable assets. The Green Project Finance was issued in compliance with the 2018 Green Loan Principles and have a Second Party Opinion delivered by Sustainalytics.
On July 10, 2020, we entered into a non-recourse project debt refinancing of Helioenergy, one of the Spanish solar assets, by adding a new long dated tranche of debt from an institutional investor. The new tranche bears interest at a fixed rate of approximately 3% per annum and has a 15-year maturity. After transaction costs, net refinancing proceeds (net “recap”) were approximately $43 million.
In addition, on July 14, 2020, we entered into a non-recourse project debt financing for approximately €326 million in relation to Helios, pursuant to a monoline guarantee. Lenders are institutional investors. The new debt has a 17-year maturity and bears interest at a rate of approximately 2% per annum. The proceeds were used to repay the outstanding project debt of approximately €250 million and cancel legacy interest rate swaps. After transaction costs and the cancelation of legacy swaps, net refinancing proceeds (net “recap”) were approximately $30 million.
Factors Affecting the Comparability of Our Results of Operations
Acquisitions
The results of operations of ATN Expansion 2 have been fully consolidated since October 2019, the results of operations of Tenes have been fully consolidated since May 2020 and the results of operations of Chile PV 1 have been fully consolidated since April 2020. In addition, Monterrey has been recorded under the equity method since August 2019 and Tenes was recorded under the equity method since January 2019 until May 2020, when we gained control over the asset and started to fully consolidate it.
In addition, in August 2020, we acquired out tax equity investor interest in Solana. Despite Liberty’s investment was in shares, it did not qualify as equity and was recorded as liability under IFRS. The acquisition resulted in a non-cash financial gain of approximately $145 million which arose from the difference between the total purchase price and the liability previously recorded. The gain was recognized in the line “Other Financial Income”.
Impairment
In 2020, the availability at the Solana storage system was lower than expected due to certain leaks identified in this system in the first quarter. Improvements and equipment replacements are required over time, which have impacted production in 2020 and will continue to impact production in 2021, with the exact scope and timing of the works subject to review. Based on our preliminary plan, we expect that we will need to replace some elements of the storage system, which have been written off in these consolidated financial statements through profit and loss in the line “Depreciation, amortization, and impairment charges” for an estimated net book value of approximately $48 million. Solana has a cash repair reserve account funded with approximately $54 million that we expect to partially or totally use for this purpose.
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Additionally, IFRS 9 requires impairment provisions to be based on expected credit losses on financial assets rather than on actual credit losses. For the year ended December 31, 2020 we recorded a $26.6 million impairment provision in ACT following a worsening of its client’s credit risk metrics, impairment was recognized in the line “Depreciation, amortization, and impairment charges”. We recorded a reversal of the impairment provision for $3.2 million for the year ended December 31, 2019.
In addition, in 2020 we accounted for an impairment reversal in our wind assets in Uruguay for approximately $18.8 million in Cadonal and Palmatir (see Note 6 to our Annual Consolidated Financial Statements). The reversal was recognized in the line “Depreciation, amortization, and impairment charges”.
Change in the useful life of the solar plants in Spain
In September 2020, following a thorough analysis of recent developments in the Energy and Climate Policy Framework adopted by Spain in 2020, we decided to reduce the useful life of the solar plants in Spain from 35 years to 25 years after COD effective from September 1, 2020 (see Note 6 to our Annual Consolidated Financial Statements). This change in the estimated useful life is accounted for as a change in accounting estimates in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors. As a result, we recorded an approximately $23.2 million increase in “Depreciation and amortization and impairment charges” in 2020 compared with the previous year.
Project debt refinancing
On July 14, 2020, as previously explained, we entered into a non-recourse project debt financing in Helios 1 & 2 for approximately €326 million. The notes were issued on July 23, 2020 and have a 17-year maturity. Under this refinancing we canceled the interest rate swaps hedging the old debt, which caused the reclassification from equity to the income statement of the accumulated impact of the mark-to-market of such derivatives for approximately $44.7 million. In addition, we recorded a $28.4 million loss for the difference between the accounting value and nominal value of the old debt. In total, we recorded a one-time loss of approximately $73.1 million in the third quarter of 2020, mostly non-cash, that is recognized in “Other financial expenses”.
Significant Trends Affecting Results of Operations
Acquisitions
If the acquisitions recently announced close as expected after the fulfillment of conditions precedent and obtain all required regulatory approvals, including Coso, Calgary District Heating and La Sierpe we expect these assets to impact our results of operations in 2021 and upcoming years, once we start consolidating them upon closing. See “Item 4—Information on the Company—Acquisitions—2020 and 2021 acquisitions”.
Solar, wind and geothermal resources
The availability of solar, wind and, once we close the Coso acquisition, geothermal resources affects the financial performance of our renewable assets, which may impact our overall financial performance. Due to the variable nature of solar, wind and geothermal resources, we cannot predict future availabilities or potential variances from expected performance levels from quarter to quarter. To the extent the solar, wind and geothermal resources are not available at expected levels, it could have negative impact on our results of operations.
Capital markets conditions
The capital markets in general are subject to volatility that is unrelated to the operating performance of companies. Our growth strategy depends on our ability to close acquisitions, which often requires access to debt and equity financing to complete such acquisitions. Fluctuations in capital markets may affect our ability to access to such capital through debt or equity financings.
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Exchange rates
Our functional currency is the U.S. dollar, as most of our revenue and expenses are denominated or linked to U.S. dollars. All our companies located in North America and most of our companies in South America have their revenue and financing contracts signed in, or indexed totally or partially to, U.S. dollars. Our solar power plants in Spain have their revenue and expenses denominated in euros, and Kaxu, our solar plant in South Africa, has its revenue and expenses denominated in South African rand. Financing of projects is typically denominated in the same currency as that of the contracted revenue agreement. This policy seeks to ensure that the main revenue and expenses in foreign companies are denominated in the same currency, limiting our risk of foreign exchange differences in our financial results.
Our strategy is to hedge cash distributions from our Spanish assets. We hedge the exchange rate for the distributions from our Spanish assets after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, we have hedged 100% of our euro-denominated net exposure for the next 12 months and 75% of our euro-denominated net exposure for the following 12 months. We expect to continue with this hedging strategy on a rolling basis.
Although we hedge cash-flows in euros, fluctuations in the value of the euro in relation to the U.S. dollar may affect our operating results. Impacts associated with fluctuations in foreign currency are discussed in more detail under “Item 3—Quantitative and Qualitative Disclosure about Market Risk—Foreign exchange risk”. Fluctuations in the value of the South African rand in relation to the U.S. dollar may also affect our operating results.
Interest rates
We incur significant indebtedness at the corporate and asset level. The interest rate risk arises mainly from indebtedness at variable interest rates. To mitigate interest rate risk, we primarily use long-term interest rate swaps and interest rate options which, in exchange for a fee, offer protection against a rise in interest rates. As of December 31, 2020, approximately 92% of our project debt and approximately 100% of our corporate debt either has fixed interest rates or has been hedged with swaps or caps. Nevertheless, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates, which typically bear a spread over EURIBOR or LIBOR.
Key Financial Measures
Our revenue and Adjusted EBITDA by geography and business sector for the years ended December 31, 2020, 2019 and 2018 are set forth in the following tables:
Revenue by geography

| Year ended December 31, |
| 2020 |  | 2019 |  | 2018 |
| $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
North America |  | $ | 330.9 |  |  |  | 32.6 | % |  | $ | 333.0 |  |  |  | 32.9 | % |  | $ | 357.2 |  |  |  | 34.2 | %
South America |  |  | 151.5 |  |  |  | 15.0 | % |  |  | 142.2 |  |  |  | 14.1 | % |  |  | 123.2 |  |  |  | 11.8 | %
EMEA |  |  | 530.9 |  |  |  | 52.4 | % |  |  | 536.3 |  |  |  | 53.0 | % |  |  | 563.4 |  |  |  | 54.0 | %
Total revenue |  | $ | 1,013.3 |  |  |  | 100.0 | % |  | $ | 1,011.5 |  |  |  | 100.0 | % |  | $ | 1,043.8 |  |  |  | 100 | %

Revenue by business sector

| Year ended December 31, |
| 2020 |  | 2019 |  | 2018 |
| $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
Renewable Energy |  | $ | 753.1 |  |  |  | 74.3 | % |  | $ | 761.1 |  |  |  | 75.2 | % |  | $ | 793.5 |  |  |  | 76.0 | %
Efficient Natural Gas |  |  | 111.0 |  |  |  | 11.0 | % |  |  | 122.3 |  |  |  | 12.1 | % |  |  | 130.8 |  |  |  | 12.5 | %
Electric Transmission |  |  | 106.1 |  |  |  | 10.5 | % |  |  | 103.5 |  |  |  | 10.2 | % |  |  | 96.0 |  |  |  | 9.2 | %
Water |  |  | 43.1 |  |  |  | 4.2 | % |  |  | 24.6 |  |  |  | 2.4 | % |  |  | 23.5 |  |  |  | 2.3 | %
Total revenue |  | $ | 1,013.3 |  |  |  | 100.0 | % |  | $ | 1,011.5 |  |  |  | 100.0 | % |  | $ | 1,043.8 |  |  |  | 100 | %

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Adjusted EBITDA by geography

| Year ended December 31, |
| 2020 |  | 2019 |  | 2018 |
| $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
North America |  | $ | 272.9 |  |  |  | 82.5 | % |  | $ | 305.1 |  |  |  | 91.6 | % |  | $ | 308.8 |  |  |  | 86.4 | %
South America |  |  | 120.0 |  |  |  | 79.2 | % |  |  | 115.3 |  |  |  | 81.1 | % |  |  | 100.2 |  |  |  | 81.3 | %
EMEA |  |  | 388.7 |  |  |  | 73.1 | % |  |  | 390.8 |  |  |  | 72.9 | % |  |  | 441.6 |  |  |  | 78.4 | %
Adjusted EBITDA(1) |  | $ | 781.6 |  |  |  | 77.1 | % |  | $ | 811.2 |  |  |  | 80.2 | % |  | $ | 850.6 |  |  |  | 81.5 | %

Adjusted EBITDA by business sector

| Year ended December 31, |
| 2020 |  | 2019 |  | 2018 |
| $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
Renewable Energy |  | $ | 575.6 |  |  | $ | 76.4 | % |  | $ | 603.7 |  |  | $ | 79.3 | % |  | $ | 664.4 |  |  |  | 83.7 | %
Efficient Natural Gas |  |  | 97.9 |  |  |  | 88.2 | % |  |  | 107.5 |  |  |  | 87.9 | % |  |  | 93.9 |  |  |  | 71.8 | %
Electric Transmission |  |  | 84.6 |  |  |  | 79.7 | % |  |  | 85.6 |  |  |  | 82.7 | % |  |  | 78.4 |  |  |  | 81.7 | %
Water |  |  | 23.5 |  |  |  | 54.5 | % |  |  | 14.4 |  |  |  | 58.5 | % |  |  | 13.9 |  |  |  | 59.1 | %
Adjusted EBITDA(1) |  | $ | 781.6 |  |  | $ | 77.1 | % |  | $ | 811.2 |  |  | $ | 80.2 | % |  | $ | 850.6 |  |  |  | 81.5 | %

Note:—
(1) Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements. Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”
Reconciliation of profit/(loss) for the year to Adjusted EBITDA

|  | Year ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
|  | ($ in millions) |
Profit/(loss) for the year attributable to the parent company |  | $ | 11.9 |  |  | $ | 62.1 |  |  | $ | 41.6 |
Profit/(loss) attributable to non-controlling interest from continued operations |  |  | 4.9 |  |  |  | 12.5 |  |  |  | 13.7 |
Income tax expense |  |  | 24.9 |  |  |  | 30.9 |  |  |  | 42.6 |
Share of (profit)/loss of associates carried under the equity method |  |  | (0.5 | ) |  |  | (7.5 | ) |  |  | (5.2 | )
Financial expense, net |  |  | 331.8 |  |  |  | 402.3 |  |  |  | 395.2 |
Operating profit /(loss) |  | $ | 373.0 |  |  | $ | 500.4 |  |  | $ | 487.9 |
Depreciation, amortization and impairment charges |  |  | 408.6 |  |  |  | 310.8 |  |  |  | 362.7 |
Adjusted EBITDA |  | $ | 781.6 |  |  | $ | 811.2 |  |  | $ | 850.6 |

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The following table sets forth a reconciliation of Adjusted EBITDA to our net cash generated by or used in operating activities:
Reconciliation of net cash generated by operating activities to Adjusted EBITDA

| Year ended December 31, |
| 2020 |  |  | 2019 |  |  | 2018 |
| ($ in millions) |
Net cash flow provided by operating activities |  | $ | 438.2 |  |  | $ | 363.5 |  |  | $ | 401.0 |
Net interest /taxes paid |  |  | 287.2 |  |  |  | 299.5 |  |  |  | 333.5 |
Variations in working capital |  |  | 33.2 |  |  |  | 113.4 |  |  |  | 18.4 |
Other non-cash adjustments and other |  |  | 23.0 |  |  |  | 34.8 |  |  |  | 97.7 |
Adjusted EBITDA |  | $ | 781.6 |  |  | $ | 811.2 |  |  | $ | 850.6 |

Operational Metrics
In addition to the factors described above, we closely monitor the following key drivers of our business sectors’ performance to plan for our needs, and to adjust our expectations, financial budgets and forecasts appropriately.

| • | MW in operation in the case of Renewable Energy and Efficient Natural Gas assets, miles in operation in the case of Electric Transmission and Mft3 in operation in the case of Water assets are indicators which provide information about the installed capacity or size of our portfolio of assets.

| • | Production measured in GWh in our Renewable Energy and Efficient Natural Gas assets provides information about the performance of these assets.

| • | Availability in the case of our Efficient Natural Gas assets, Electric Transmission and Water assets also provides information on the performance of the assets. In these business segments revenues are based on availability, which is the time during which the asset was available to our client totally or partially divided by contracted availability or budgeted availability, as applicable.

|  | As of and for the year ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Renewable Energy |  |  |  |  |  |  |  |  |
MW in operation(1) |  |  | 1,551 |  |  |  | 1,496 |  |  |  | 1,496 |
GWh produced(2) |  |  | 3,244 |  |  |  | 3,236 |  |  |  | 3,058 |
Efficient Natural Gas |  |  |  |  |  |  |  |  |  |  |  |
MW in operation(3) |  |  | 343 |  |  |  | 343 |  |  |  | 300 |
GWh produced(4) |  |  | 2,574 |  |  |  | 2,090 |  |  |  | 2,318 |
Availability (%)(4) |  |  | 102.1 | % |  |  | 95.0 | % |  |  | 99.8 | %
Electric Transmission |  |  |  |  |  |  |  |  |  |  |  |
Miles in operation |  |  | 1,166 |  |  |  | 1,166 |  |  |  | 1,152 |
Availability (%) |  |  | 100.0 | % |  |  | 100.0 | % |  |  | 99.9 | %
Water |  |  |  |  |  |  |  |  |  |  |  |
Mft3 in operation(1) |  |  | 17.5 |  |  |  | 10.5 |  |  |  | 10.5 |
Availability (%) |  |  | 100.1 | % |  |  | 101.2 | % |  |  | 102.0 | %

Note:

(1) | Represents total installed capacity in assets owned or consolidated at the end of the year, regardless of our percentage of ownership in each of the assets.

(2) | Includes curtailment in wind assets for which we receive compensation

(3) | Includes 43MW corresponding to our 30% share in Monterrey since August 2, 2019

(4) | Major maintenance overhaul held in Q1 and Q2 2019 in ACT, as scheduled, which reduced production and electric availability as per the contract. GWh produced includes 30% of the production from Monterrey since August 2019.

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Results of Operations
The table below illustrates our results of operations for the years ended December 31, 2020, 2019 and 2018.

|  | Year ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
|  | $ in millions |
Revenue |  | $ | 1,013.3 |  |  | $ | 1,011.5 |  |  | $ | 1,043.8 |
Other operating income |  |  | 99.5 |  |  |  | 93.8 |  |  |  | 132.5 |
Employee benefit expenses |  |  | (54.4 | ) |  |  | (32.2 | ) |  |  | (15.1 | )
Depreciation, amortization and impairment charges |  |  | (408.6 | ) |  |  | (310.8 | ) |  |  | (362.7 | )
Other operating expenses |  |  | (276.7 | ) |  |  | (261.8 | ) |  |  | (310.6 | )
Operating profit/(loss) |  | $ | 373.1 |  |  | $ | 500.4 |  |  | $ | 487.9 |
Financial income |  |  | 7.1 |  |  |  | 4.1 |  |  |  | 36.4 |
Financial expense |  |  | (378.4 | ) |  |  | (408.0 | ) |  |  | (425.0 | )
Net exchange differences |  |  | (1.4 | ) |  |  | 2.7 |  |  |  | 1.6 |
Other financial income/(expense), net |  |  | 40.9 |  |  |  | (1.1 | ) |  |  | (8.2 | )
Financial expense, net |  | $ | (331.8 | ) |  | $ | (402.3 | ) |  | $ | (395.2 | )
Share of profit/(loss) of associates carried under the equity method |  |  | 0.5 |  |  |  | 7.4 |  |  |  | 5.2 |
Profit/(loss) before income tax |  | $ | 41.8 |  |  | $ | 105.6 |  |  | $ | 97.9 |
Income tax expense |  |  | (24.9 | ) |  |  | (30.9 | ) |  |  | (42.6 | )
Profit/(loss) for the year |  | $ | 16.9 |  |  | $ | 74.6 |  |  | $ | 55.3 |
Profit/(loss) attributable to non-controlling interests |  |  | (4.9 | ) |  |  | (12.5 | ) |  |  | (13.7 | )
Profit / (loss) for the year attributable to the parent company |  | $ | 12.0 |  |  | $ | 62.1 |  |  | $ | 41.6 |

Comparison of the Years Ended December 31, 2020 and 2019
The significant variances or variances of the significant components of the results of operations are discussed in the following section.
Revenue
Revenue remained stable at $1,013.3 million for the year ended December 31, 2020, compared to $1,011.5 million for the year ended December 31, 2019. Revenue increased mainly due to the additional revenue generated by the transmission, water and solar assets we recently acquired, and an increase in our revenue from solar assets in North America, due to a higher production at Mojave. These effects were largely offset by lower production at Kaxu caused by the unscheduled outage that occurred in the first quarter of 2020. Repair costs and business interruption were covered by insurance, after customary deductibles, and insurance proceeds are recognized in “Other operating income”. Revenue also decreased in ACT mainly due to a positive accounting impact recorded in 2019. In the first quarter of 2019 we recorded a one-time increase in revenue and Adjusted EBITDA of approximately $6 million in ACT with no impact on cash and no corresponding amount in 2020. Revenue also decreased in ACT due to lower revenue in the portion of the tariff related to the operation and maintenance services, driven by lower operation and maintenance costs in 2020 and due to the progressive decrease in accounting revenue under IFRIC 12 financial model.
Other operating income
The following table sets forth our other operating income for the years ended December 31, 2020 and 2019:

| Year ended December 31, |
| 2020 |  |  | 2019 |
Other operating income | $ in millions |
Grants |  | $ | 59.0 |  |  | $ | 59.1 |
Income from various services |  |  | 40.5 |  |  |  | 34.7 |
Total |  | $ | 99.5 |  |  | $ | 93.8 |

Other operating income increased by 6.1% to $99.5 million for the year ended December 31, 2020, compared to $93.8 million for the year ended December 31, 2019.
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“Grants” represent the financial support provided by the U.S. government to Solana and Mojave and consist of an ITC Cash Grant and an implicit grant related to the below market interest rates of the project loans with the Federal Financing Bank. Grants were stable for the year ended December 31, 2020 compared to the previous year.
“Income from various services” for the year ended December 31, 2020 included $18.4 million in insurance income in Kaxu in compensation for the unscheduled outage previously explained, as well as $5.7 million in insurance income received at Solana in compensation for events from prior years and $6.4 million in income for the acquisition of a discounted long-term payable. In 2020 we purchased a long-term operation and maintenance payable from Abengoa of approximately $14.4 million and paid approximately $8.0 million, recording a $6.4 million gain. For the year ended December 31, 2019, this account included approximately $11 million received from the EPC contractor in our U.S. solar assets under their obligations and amounts received from insurance claims in compensation for events from prior years. Income from various services also includes other minor amounts received from Abengoa under their obligations for the years ended December 31, 2020 and 2019.
Employee benefit expenses
Employee benefit expenses increased by 69.3% to $54.5 million for the year ended December 31, 2020, compared to $32.2 million for the year ended December 31, 2019. This increase was primarily due to the internalization of operation and maintenance services at our U.S. solar assets, following the acquisition of ASI Operations on July 30, 2019. The operation and maintenance costs for these assets were mainly recognized as “Other operating expenses” until July 30, 2019.
Depreciation, amortization and impairment charges
Depreciation, amortization and impairment charges increased by 31.5% to $408.6 million for the year ended December 31, 2020, compared to $310.8 million for the year ended December 31, 2019. Certain leaks were identified in the storage system of Solana in the first quarter of 2020. Based on our preliminary plan, we expect that we will need to replace some elements of the storage system, which have been written off and had an estimated net book value of approximately $48 million. Improvements and equipment replacements are expected to be required over time, with the exact scope and timing of works subject to review. The increase was also due to the increase in the impairment provision of ACT following IFRS 9. IFRS 9 requires impairment provisions to be based on the expected credit losses on financial assets rather than on actual credit losses. ACT recorded an additional $26.6 million impairment provision for the year ended December 31, 2020, following a worsening in its client’s credit risk metrics, while for the year ended December 31, 2019 there was an impairment reversal of $3.1 million. In addition, in September 2020 we reduced the useful life of our Spanish solar assets from 35 to 25 years after COD, which increased our depreciation and amortization charges for the year ended December 31, 2020 by approximately $23.2 million compared to the same period from the previous year. These effects were partially offset by an impairment reversal in our wind assets in Uruguay for approximately $18.8 million after an impairment test in Cadonal and Palmatir.
Other operating expenses
The following table sets forth our other operating expenses for the years ended December 31, 2020 and 2019:

|  | Year ended December 31, |
|  | 2020 |  |  | 2019 |
Other operating expenses |  | $ in millions |  |  | % of revenue |  |  | $ in millions |  |  | % of revenue |
Raw Materials |  | $ | 7.8 |  |  |  | 0.8 | % |  | $ | 9.7 |  |  |  | 1.0 | %
Leases and fees |  |  | 2.6 |  |  |  | 0.3 | % |  |  | 1.9 |  |  |  | 0.2 | %
Operation and maintenance |  |  | 110.9 |  |  |  | 10.9 | % |  |  | 116.0 |  |  |  | 11.5 | %
Independent professional services |  |  | 40.2 |  |  |  | 4.0 | % |  |  | 41.6 |  |  |  | 4.1 | %
Supplies |  |  | 27.9 |  |  |  | 2.8 | % |  |  | 25.8 |  |  |  | 2.6 | %
Insurance |  |  | 37.6 |  |  |  | 3.7 | % |  |  | 24.0 |  |  |  | 2.4 | %
Levies and duties |  |  | 39.8 |  |  |  | 3.9 | % |  |  | 34.8 |  |  |  | 3.4 | %
Other expenses |  |  | 9.9 |  |  |  | 1.0 | % |  |  | 8.0 |  |  |  | 0.8 | %
Total |  | $ | 276.7 |  |  |  | 27.3 | % |  | $ | 261.8 |  |  |  | 26.0 | %

Other operating expenses increased by 5.7% to $276.7 million for the year ended December 31, 2020, compared to $261.8 million for the year ended December 31, 2019. The increase was mainly due to higher insurance premiums. Other operating expenses also increased due to the consolidation of new assets acquired, Chile PV 1 and Tenes. In addition, levies and duties have increased because at the end of 2018, the Spanish government granted a six-month exemption from the 7% electricity sales tax in our Spanish assets until April 2019, which reduced our costs in the first quarter of 2019. The increase was partially offset by lower operation and maintenance costs due to the internalization of the operation and maintenance services at our U.S. solar assets since August 2, 2019, as most of these expenses have been recorded in “Employee benefit expenses” since that date.
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Operating profit
As a result of the above-mentioned factors, operating profit decreased by 25.4% to $373.1 million for the year ended December 31, 2020, compared with $500.4 million for the year ended December 31, 2019.
Financial income and financial expense

|  |  | Year ended December 31, |
Financial income and financial expense |  |  | 2020 |  |  | 2019 |
|  |  | $ in millions |
Financial income |  | $ | 7.1 |  |  | $ | 4.1 |
Financial expense |  |  | (378.4 | ) |  |  | (408.0 | )
Net exchange differences |  |  | (1.4 | ) |  |  | 2.7 |
Other financial income/(expense), net |  |  | 40.9 |  |  |  | (1.1 | )
Financial expense, net |  | $ | (331.8 | ) |  | $ | (402.3 | )

Financial income
Financial income increased to $7.1 million for the year ended December 31, 2020, compared to $4.1 million for the year ended December 31, 2019, primarily due to a $3.8 million of non-monetary financial income resulting from the refinancing of the Cadonal project debt in the second quarter of 2020 (see Note 21 to our Consolidated Condensed Financial Statements).
Financial expense
The following table sets forth our financial expense for the years ended December 31, 2020 and 2019:

|  | Year ended December 31, |
Financial expense |  | 2020 |  | 2019 |
|  | $ in millions |
Expenses due to interest: |  |  |  |  |
Loans with credit entities |  | $ | (246.7 | ) |  | $ | (259.4 | )
Other debts |  |  | (69.6 | ) |  |  | (89.3 | )
Interest rates losses derivatives: cash flow hedges |  |  | (62.1 | ) |  |  | (59.3 | )
Total |  | $ | (378.4 | ) |  | $ | (408.0 | )

Financial expense decreased by 7.3% to $378.4 million for the year ended December 31, 2020, compared to $408.0 million for the year ended December 31, 2019.
Expenses due to interest on loans with credit entities decreased mainly due to a decrease in interest expenses on loans indexed to LIBOR and JIBAR, since the rates of reference were lower for the year ended December 31, 2020 compared to the previous year. This decrease was of approximately $24.5 million. Interest at Kaxu was also lower due to the depreciation of the South African rand against the US dollar. This decrease was partially offset by breakage costs in one of our corporate refinancings.
Expenses due to interest on other debt corresponds mainly to interest expense on the notes issued by ATS, ATN, Solaben Luxembourg, Helios, interest on the 2019 Notes until May 2019, interest on the Green Exchangeable Notes and interest on Liberty’s investment in Solana until August 2020. The decrease was due to the acquisition of Liberty’s equity interest in Solana in August 2020. From an accounting perspective, Liberty’s equity investment in Solana was recorded as a liability with interest accruing in Interest on other debt. The decrease was also due to the refinancing of the 2019 Notes with the proceeds of the Note Issuance Facility 2019, since interest for this facility is recorded under Loans from credit entities.
Interest rate losses on derivatives designated as cash flow hedges correspond primarily to transfers from equity to financial expense when the hedged item impacts profit and loss. The increase was due to the decrease in LIBOR which offset the decrease in interest on Loans from credit entities. This was partially offset by the cancelation of the legacy interest rate swaps which hedged the project debt from Helios 1 & 2 which was refinanced this year.
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Other financial income/(expense), net

|  |  | Year ended December 31, |
Other financial income/(expense), net |  |  | 2020 |  |  | 2019 |
|  |  | $ in millions |
Other financial income |  | $ | 162.3 |  |  | $ | 14.2 |
Other financial losses |  |  | (121.4 | ) |  |  | (15.3 | )
Total |  | $ | 40.9 |  |  | $ | (1.1 | )

Other financial income/(expense), net increased to a net income of $40.9 million for the year ended December 31, 2020 compared to a net expense of $1.1 million for the year ended December 31, 2019. For the year ended December 31, 2020, Other financial income includes a non-cash gain of approximately $145 million resulting from the acquisition of Liberty’s equity interest in Solana, which was the primary reason for the increase. Liberty was the tax equity investor in Solana and although Liberty’s investment was in shares, under IFRS it was recorded as a liability. In August 2020, we acquired Liberty’s equity interest in Solana and recorded a gain corresponding to the difference between book value of Liberty’s equity interest in Solana and the total price expected to be paid to Liberty.
The increase in other financial expenses was primarily due to a one-time loss of approximately $73.1 million, mostly non-cash, caused by the refinancing of Helios 1 & 2. In the third quarter of 2020, we entered into a non-recourse, project debt financing for approximately €326 million, which refinanced the previous bank project debt with approximately €250 million outstanding. We canceled the interest rate swaps hedging the old debt, which caused the reclassification from equity to the income statement of the accumulated impact of the mark-to-market of such derivatives for approximately $44.7 million. In addition, we recorded a $28.4 million loss for the difference between the accounting value and the nominal value of the old debt.
The increase in other financial expenses was also due to the mark-to-market of the derivative liability embedded in the Green Exchangeable Notes for approximately $16 million. Since we have the option to settle the Green Exchangeable Notes in shares or in cash, the conversion option is recorded under IFRS as a derivative liability with changes in profit/(loss).
Other financial expenses also include expenses for guarantees and letters of credit, wire transfers, other bank fees and other minor financial expenses.
Share of profit of associates carried under the equity method
Share of profit of associates carried under the equity method decreased to $0.5 million in the year ended December 31, 2020 compared to $7.5 million in the year ended December 31, 2019. The decrease was primarily due to a decrease in Honaine’s profits caused by higher deferred income taxes compared to the previous year.
Profit/(loss) before income tax
As a result of the previously mentioned factors, we reported a profit before income tax of $41.8 million for the year ended December 31, 2020, compared to a profit before income tax of $105.6 million for the year ended December 31, 2019.
Income tax
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The reconciliation between the theoretical income tax resulting from applying an average statutory tax rate to profit before income tax and the actual income tax expense recognized in the consolidated income statements for the years ended December 31, 2020, 2019 and 2018, are as follows:

|  | For the year ended December 31, |
|  | 2020 |  |  | 2019 |
|  | $ in millions |
Consolidated income before taxes |  |  | 41.8 |  |  |  | 105.6 |
Average statutory tax rate |  |  | 25 | % |  |  | 25 | %
Corporate income tax at average statutory tax rate |  |  | (10.4 | ) |  |  | (26.4 | )
Income tax of associates, net |  |  | 0.1 |  |  |  | 1.8 |
Differences in statutory tax rates |  |  | (0.1 | ) |  |  | (7.1 | )
Unrecognized NOLs and deferred tax assets |  |  | (37.1 | ) |  |  | (14.2 | )
Purchase of Liberty´s equity interest in Solana |  |  | 36.4 |  |  |  | - |
Other Permanent Differences |  |  | (8.9 | ) |  |  | 11.2 |
Other non-taxable income/(expense) |  |  | (4.7 | ) |  |  | 3.7 |
Corporate income tax |  |  | (24.9 | ) |  |  | (31,0 | )

For the year ended December 31, 2020, the overall effective tax rate was different than the statutory rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in the UK entities, partially offset by the non-taxable gain recorded in the consolidated financial statements on the purchase of Liberty´s equity interest in Solana (see Note 16 of our Annual Consolidated Financial Statements).
For the years ended December 31, 2019 the overall effective tax rate was different than the statutory rate of 25% and 30%, respectively, primarily due to unrecognized tax losses carryforwards, mainly in the UK entities and US entities.
Profit attributable to non-controlling interests
Profit attributable to non-controlling interests was $4.9 million for the year ended December 31, 2020 compared to $12.5 million for the year ended December 31, 2019. Profit attributable to non-controlling interest corresponds to the portion attributable to our partners in the assets that we consolidate (Kaxu, Skikda, Solaben 2 & 3, Solacor 1 & 2, Seville PV, Chile PV 1 and Tenes). The decrease in profit attributable to non-controlling interest was mainly due to lower income in Skikda as a result of higher deferred income taxes compared to the previous year and a loss reported in Kaxu resulting from the unscheduled outage previously explained.
Profit/(loss) attributable to the parent company
As a result of the previously mentioned factors, profit attributable to the parent company was $12.0 million for the year ended December 31, 2020, compared to a profit of $62.1 million for the year ended December 31, 2019.
Comparison of the Years Ended December 31, 2019 and 2018
The significant variances or variances of the significant components of the results of operations between the years ended December 31, 2019 and December 31, 2018, are discussed in the Form 20-F filed with the SEC on February 27, 2020.
Segment Reporting
We organize our business into the following three geographies where the contracted assets and concessions are located: North America, South America and EMEA. In addition, we have identified four business sectors based on the type of activity: Renewable energy, Efficient natural gas, Electric transmission and Water. We report our results in accordance with both criteria.
Comparison of the Years Ended December 31, 2020 and 2019
Revenue and Adjusted EBITDA by geography
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The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 2020 and 2019, by geographic region:
Revenue by geography

|  |  | Year ended December 31, |
|  |  | 2020 |  | 2019 |
Revenue by geography |  |  | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
North America |  | $ | 330.9 |  |  |  | 32.6 | % |  | $ | 333.0 |  |  |  | 32.9 | %
South America |  |  | 151.5 |  |  |  | 15.0 | % |  |  | 142.2 |  |  |  | 14.1 | %
EMEA |  |  | 530.9 |  |  |  | 52.4 | % |  |  | 536.3 |  |  |  | 53.0 | %
Total revenue |  | $ | 1,013.3 |  |  |  | 100.0 | % |  | $ | 1,011.5 |  |  |  | 100.0 | %

Adjusted EBITDA by geography

|  |  | Year ended December 31, |
|  |  | 2020 |  | 2019 |
Adjusted EBITDA by geography |  |  | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
North America |  | $ | 272.9 |  |  |  | 82.5 | % |  | $ | 305.1 |  |  |  | 91.6 | %
South America |  |  | 120.0 |  |  |  | 79.2 | % |  |  | 115.3 |  |  |  | 81.1 | %
EMEA |  |  | 388.7 |  |  |  | 73.1 | % |  |  | 390.8 |  |  |  | 72.9 | %
Adjusted EBITDA(1) |  | $ | 781.6 |  |  |  | 77.1 | % |  | $ | 811.2 |  |  |  | 80.2 | %

Note:
(1) Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements. Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB, and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”
Volume by geography

| Volume produced/availability |
| Year ended December 31, |
Volume by geography | 2020 |  |  | 2019 |
North America (GWh) (1) |  |  | 3,908 |  |  |  | 3,397 |
North America availability(1) |  |  | 102.1 | % |  |  | 95.0 | %
South America (GWh) (2) |  |  | 667 |  |  |  | 516 |
South America availability |  |  | 100.0 | % |  |  | 100.0 | %
EMEA (GWh) |  |  | 1,243 |  |  |  | 1,413 |
EMEA availability |  |  | 100.1 | % |  |  | 101.2 | %

Note:

(1) | Major maintenance overhaul held in Q1 and Q2 2019 in ACT, as scheduled, which reduced availability and electric production, as per the contract. GWh produced includes 30% of the production from Monterrey since August 2019

(2) | Includes curtailment production in wind assets for which we receive compensation

North America
Revenue remained stable at $330.9 million for the year ended December 31, 2020, compared to $333.0 million for the year ended December 31, 2019. Revenue decreased in our Efficient Natural Gas segment, primarily due to a one-time adjustment of approximately $6 million with no impact in cash recorded in ACT in the first quarter of 2019. Our ACT asset is accounted for under IFRIC 12 following the financial asset model, and a change in future operation and maintenance costs in 2019 increased the value of the asset, resulting in a one-time increase in revenue and Adjusted EBITDA of approximately $6 million. Revenue also decreased in ACT due to lower revenue in the portion of the tariff related to the operation and maintenance services, driven by lower operation and maintenance costs in 2020 and the progressive decrease in accounting revenue under the IFRIC 12 financial model. Revenue in our solar assets in North America increased by 4.2% mainly due to a higher production in Mojave, compared to the year ended December 31, 2019. Adjusted EBITDA decreased by 10.6% to $272.9 million for the year ended December 31, 2020, compared to $305.1 million for the year ended December 31, 2019. The decrease was mainly driven by a decrease in Adjusted EBITDA in our solar assets in North America. In the third quarter of 2019 we received $10 million from the EPC contractor under their contractual obligations with no corresponding amount in 2020. In addition, in 2020 operating expenses were higher in the U.S. mainly due to higher insurance premiums and larger operation and maintenance costs resulting mainly from higher major maintenance overhaul costs. Adjusted EBITDA in our Efficient Natural Gas segment also decreased mainly due to the decrease in revenue as previously explained. Adjusted EBITDA margin decreased to 82.5% for the year ended December 31, 2020, compared to 91.6% for the year ended December 31, 2019 due to the events described above.
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South America
Revenue increased by 6.6% to $151.5 million for the year ended December 31, 2020, compared to $142.2 million for the year ended December 31, 2019. The revenue increase was primarily due to the contribution of Chile PV 1, a solar asset recently acquired through the Chilean renewable energy platform created in the second quarter of 2020 and ATN Expansion 2, acquired in October 2019. Revenue also increased due to higher production in our wind assets. Adjusted EBITDA increased by 4.1% to $120.0 million for the year ended December 31, 2020, compared to $115.3 million for the year ended December 31, 2019 for the same reasons. Adjusted EBITDA margin decreased to 79.2% for the year ended December 31, 2020, compared to 81.1% for the year ended December 31, 2019 mainly due to lower than usual operation and maintenance expenses in our transmission lines in the first quarter of 2019.
EMEA
Revenue decreased by 1.0% to $530.9 million for the year ended December 31, 2020, compared to $536.3 million for the year ended December 31, 2019. This decrease was primarily due to lower production in Kaxu resulting from the unscheduled outage explained above. Repair costs and business interruption were covered by insurance, after customary deductibles and insurance proceeds are recorded in “Other operating income”. The decrease in revenue was partially offset thanks to the contribution from Tenes, the water desalination plant that we started to fully consolidate on May 31, 2020. Adjusted EBITDA decreased by 0.6% to $388.7 for the year ended December 31, 2020 compared to $390.8 million for the year ended December 31, 2019 mostly due to the same reasons. Adjusted EBITDA margin remained stable at 72.9% for the year ended December 31, 2020 and 73.1% for the year ended December 31, 2019.
Revenue and Adjusted EBITDA by business sector
The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 2020 and 2019, by business sector:

| Year ended December 31, |
| 2020 |  | 2019 |
Revenue by business sector | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
Renewable energy |  | $ | 753.1 |  |  |  | 74.3 | % |  | $ | 761.1 |  |  |  | 75.2 | %
Efficient natural gas |  |  | 111.0 |  |  |  | 11.0 | % |  |  | 122.3 |  |  |  | 12.1 | %
Electric transmission lines |  |  | 106.1 |  |  |  | 10.5 | % |  |  | 103.5 |  |  |  | 10.2 | %
Water |  |  | 43.1 |  |  |  | 4.2 | % |  |  | 24.6 |  |  |  | 2.4 | %
Total revenue |  | $ | 1,013.3 |  |  |  | 100.0 | % |  | $ | 1,011.5 |  |  |  | 100.0 | %

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| Year ended December 31, |
| 2020 |  | 2019 |
Adjusted EBITDA by business sector | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
Renewable energy |  | $ | 575.6 |  |  |  | 76.4 | % |  | $ | 603.7 |  |  |  | 79.3 | %
Efficient natural gas |  |  | 97.9 |  |  |  | 88.2 | % |  |  | 107.5 |  |  |  | 87.9 | %
Electric transmission lines |  |  | 84.6 |  |  |  | 79.7 | % |  |  | 85.6 |  |  |  | 82.7 | %
Water |  |  | 23.5 |  |  |  | 54.5 | % |  |  | 14.4 |  |  |  | 58.5 | %
Adjusted EBITDA(1) |  | $ | 781.6 |  |  |  | 77.1 | % |  | $ | 811.2 |  |  |  | 80.2 | %

Note:
(1) Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements. Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB, and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”
Volume by business sector

| Volume produced/availability |
| Year ended December 31, |
Volume by business sector | 2020 |  | 2019 |
Renewable energy (GWh) (1) |  |  | 3,244 |  |  |  | 3,235 |
Efficient natural gas Power (GWh) (2) |  |  | 2,574 |  |  |  | 2,090 |
Efficient natural gas Power availability(3) |  |  | 102.1 | % |  |  | 95.0 | %
Electric transmission availability |  |  | 100.0 | % |  |  | 100.0 | %
Water availability |  |  | 100.1 | % |  |  | 101.2 | %

Note:

(1) | Includes curtailment production in wind assets for which we receive compensation

(2) | Major maintenance overhaul held in Q1 and Q2 2019 in ACT, as scheduled, which reduced electric production, as per the contract. GWh produced includes 30% of the production from Monterrey since August 2, 2019

(3) | Major overhaul held in Q1 and Q2 2019 in ACT, as scheduled, which reduced the electric availability as per the contract with Pemex

Renewable energy
Revenue decreased by 1.1% to $753.1 million for the year ended December 31, 2020, compared to $761.1 million for the year ended December 31, 2019. Adjusted EBITDA decreased by 4.7% to $575.6 million for the year ended December 31, 2020, compared to $603.7 million for the year ended December 31, 2019. The decrease in revenue was primarily due to lower production in Kaxu, as previously explained. This decrease was partially offset by an increase in revenue from our solar assets in North America mainly due to a higher production in Mojave and by the contribution of the recently acquired Chile PV 1. The decrease in Adjusted EBITDA was mainly due to the decrease in revenue and to a decrease of Adjusted EBITDA in our solar assets in North America mostly due to a one-off income received in 2019 and to higher operating expenses, as we previously discuss in our discussion for North America. Adjusted EBITDA margin decreased mainly due to the lower Adjusted EBITDA in our North American solar assets.
Efficient natural gas
Revenue decreased by 9.2% to $111.0 million for the year ended December 31, 2020, compared to $122.3 million for the year ended December 31, 2019, while Adjusted EBITDA decreased by 8.9% to $97.9 million for the year ended December 31, 2020, compared to $107.5 million for the year ended December 31, 2019. Adjusted EBITDA margin remained stable at 88.2% in the year ended December 31, 2020 compared to 87.9% in the year ended December 31, 2019. Revenue and Adjusted EBITDA decreased mainly due to a one-time adjustment recorded in the first quarter of 2019 of approximately $6 million, with no impact on cash in 2019 and with no corresponding amount in 2020. Our ACT asset is accounted for under IFRIC 12 following the financial asset model, and a decrease in 2019 in future operation and maintenance costs increased the value of the asset, causing a one-time increase in revenue and Adjusted EBITDA in the first quarter of 2019. Revenue also decreased in ACT due to lower revenue in the portion of the tariff related to the operation and maintenance services, driven by lower operation and maintenance costs in 2020 and due to the progressive decrease in accounting revenue under IFRIC 12 financial model.
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Electric transmission lines
Revenue increased by 2.6% to $106.1 million for the year ended December 31, 2020, compared to $103.5 million for the year ended December 31, 2019, while Adjusted EBITDA decreased by 1.1% to $84.6 million for the year ended December 31, 2020, compared to $85.6 million for the year ended December 31, 2019. The increase in revenue was mainly due to the contribution of ATN Expansion 2 acquired in 2019. The decrease in Adjusted EBITDA was mainly due to lower than usual operation and maintenance expenses in our transmission lines in the first quarter of 2019. Adjusted EBITDA margin decreased to 79.7% for year ended December 31, 2020 compared to 82.7% for the year ended December 31, 2019 for the same reason.
Water
Revenue increased by 75.2% to $43.1 million for the year ended December 31, 2020, compared to $24.6 million for the year ended December 31, 2019. Adjusted EBITDA increased by 63.2% to $23.5 million for the year ended December 31, 2020, compared to $14.4 million for the year ended December 31, 2019. The increases were mainly due to the contribution from Tenes, the water desalination plant that we started to consolidate on May 31, 2020. Adjusted EBITDA margin decreased to 54.5% for the year ended December 31, 2020 from 58.5% for the year ended December 31, 2019 mainly due to the slightly lower Adjusted EBITDA margin in Tenes compared to Skikda.
Comparison of the Years Ended December 31, 2019 and 2018
The significant variances in the revenue and volume, by geographic region and business sector, between the years ended December 31, 2019 and December 31, 2018, are discussed in the Form 20-F filed with the SEC on February 27, 2020.

B. | Liquidity and Capital Resources

Our principal liquidity and capital requirements consist of the following:

| • | debt service requirements on our existing and future debt;

| • | cash dividends to investors; and

| • | acquisitions of new companies, investments and operations (see “Item 4.B—Business Overview—Our Business Strategy”).

As a normal part of our business, depending on market conditions, we will from time to time consider opportunities to repay, redeem, repurchase or refinance our indebtedness. Changes in our operating plans, lower than anticipated sales, increased expenses, acquisitions or other events may cause us to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all. Debt financing, if available, could impose additional cash payment obligations and additional covenants and operating restrictions. In addition, any of the items discussed in detail under “Item 3.D—Risk Factors” and other factors may also significantly impact our liquidity.
Liquidity position

|  | Year ended December 31, |
|  | 2020 |  |  | 2019 |
|  | $ in millions |
Corporate Liquidity |  |  |  |  |  |
Cash and cash equivalents at Atlantica Sustainable Infrastructure, plc, excluding subsidiaries |  | $ | 335.2 |  |  | $ | 66.0 |
Revolving Credit Facility availability |  |  | 415.0 |  |  |  | 341.0 |
Total Corporate Liquidity |  | $ | 750.2 |  |  | $ | 407.0 |
Liquidity at project companies |  |  |  |  |  |  |  |
Restricted Cash (1) |  |  | 279.8 |  |  |  | 373.6 |
Non-restricted cash |  |  | 253.5 |  |  |  | 157.9 |
Total cash at project companies |  | $ | 533.3 |  |  | $ | 531.5 |

Note:

| (1) | Restricted Cash as of December 31, 2019 included cash classified as short-term financial investments for an approximately amount of $34.6 million.

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Cash at the project level includes $279.8 million and $373.6 million restricted cash balances as of December 31, 2020 and 2019 respectively. Restricted cash consists primarily of funds required to satisfy the requirements of certain project debt arrangements. In the case of Solana, part of the restricted cash is expected to the used for equipment replacements.
As of December 31, 2020, we had no borrowings under the Revolving Credit Facility and $10 million of letters of credit were outstanding under the Revolving Credit Facility. Approximately $415 million were available under our Revolving Credit Facility. As of December 31, 2019, we had approximately $84 million outstanding and $341 million available under the Revolving Credit Facility.
Management believes that the Company's liquidity position, cash flows from operations and availability under its revolving credit facility will be adequate to meet the Company's financial commitments and debt obligations; growth, operating and maintenance capital expenditures; and dividend distributions to shareholders. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management
Credit Ratings
Credit rating agencies rate us and part of our debt securities. These ratings are used by the debt markets to evaluate a firm's credit risk. Ratings influence the price paid to issue new debt securities as they indicate to the market our ability to pay principal, interest and dividends.
The following table summarizes our credit ratings as of December 31, 2020. The ratings outlook is positive for S&P and stable in the case of Fitch.

| S&P | Fitch
Atlantica Sustainable Infrastructure Corporate Rating | BB | BB
Senior Secured Debt | BBB- | BBB-
Senior Unsecured Debt | BB | BB+

Sources of liquidity
We expect our ongoing sources of liquidity to include cash on hand, cash generated from our operations, project debt arrangements, corporate debt and the issuance of additional equity securities, as appropriate, and given market conditions. Our financing agreements consist mainly of the project-level financings for our various assets and our corporate debt financings, including our Green Exchangeable Notes, the Note Issuance Facility 2020, the 2020 Green Private Placement, the Note Issuance Facility 2019, the Revolving Credit Facility, a credit line with a local bank and our commercial paper program.

|  |  |  | Year ended December 31, |
|  |  |  |  | 2020 |  |  | 2019 |
|  | Maturity |  | ($ in millions) |
Revolving Credit Facility |  | 2022 |  |  |  | - |  |  |  | 81.9 |
Other Facilities |  |  | 2021-2025 |  |  | $ | 29.7 |  |  | $ | 38.0 |
2019 Note Issuance Facility |  |  | 2025 |  |  |  | 344.0 |  |  |  | 301.6 |
Green Exchangeable Bond |  |  | 2025 |  |  |  | 102.1 |  |  |  | - |
Green Senior Secured Notes |  |  | 2026 |  |  |  | 351.0 |  |  |  | - |
2020 Note Issuance Facility |  |  | 2027 |  |  |  | 166.9 |  |  |  | - |
2017 Note Issuance Facility |  | Repaid in April 2020 |  |  |  | - |  |  |  | 302.3 |
Total Corporate Debt |  |  |  |  |  | $ | 993.7 |  |  | $ | 723.8 |
Total Project Debt |  |  |  |  |  | $ | 5,237.6 |  |  | $ | 4,852.3 |

| A) | Corporate debt agreements

Green Exchangeable Notes
On July 17, 2020, we issued $100 million aggregate principal amount of 4.00% Green Exchangeable Notes due 2025. On July 29, 2020, we issued an additional $15 million aggregate principal amount of the Green Exchangeable Notes. The Green Exchangeable Notes are the senior unsecured obligations of Atlantica Jersey, a wholly owned subsidiary of Atlantica, and fully and unconditionally guaranteed by Atlantica on a senior, unsecured basis. The notes mature on July 15, 2025, unless earlier repurchased or redeemed by Atlantica or exchanged for Atlantica’s ordinary shares (or a combination of cash and Atlantica’s ordinary shares) at Atlantica’s election, and bear interest at a rate of 4.00% per annum.
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Noteholders may exchange all or any portion of their notes at their option at any time prior to the close of business on the scheduled trading day immediately preceding April 15, 2025, only during certain periods and upon satisfaction of certain conditions. Noteholders may exchange all or any portion of their notes during any calendar quarter if the last reported sale price of Atlantica’s ordinary shares for at least 20 trading days during a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than 120% of the exchange price on each applicable trading day. On or after April 15, 2025, until the close of business on the second scheduled trading day immediately preceding the maturity date thereof, noteholders may exchange any of their notes at any time, in multiples of $1,000 principal amount, at the option of the noteholder. Upon exchange, the notes may be settled, at our election, into ordinary shares of Atlantica, cash or a combination of both. The initial exchange rate of the notes is 29.1070 ordinary shares per $1,000 principal amount of notes (which is equivalent to an initial exchange price of $34.36 per ordinary share). The exchange rate is subject to adjustment upon the occurrence of certain events.
Our obligations under the Green Exchangeable Notes rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the Note Issuance Facility 2019, the 2020 Green Private Placement and the Note Issuance Facility 2020.
The proceeds from the Green Exchangeable Notes were primarily used to finance the acquisition of new or ongoing assets or projects which meet certain eligibility criteria in accordance with our Green Finance Framework. The Green Exchangeable Notes comply with the Green Bond Principles and have a second party opinion by Sustainalytics.
Note Issuance Facility 2020
On July 8, 2020, we entered into the Note Issuance Facility 2020, a senior unsecured euro-denominated financing with Lucid Agency Services Limited and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of approximately $171 million (€140 million). The notes under the Note Issuance Facility 2020 were issued on August 12, 2020 and are due on August 12, 2027. Interest on the notes issued under the Note Issuance Facility 2020 accrues at a rate per annum equal to the sum of 3-month EURIBOR plus a margin of 5.25% with a floor of 0% for the EURIBOR. We have entered into a cap at 0% for the EURIBOR with 3.5 years maturity to hedge such variable interest rate risk.
Our obligations under the Note Issuance Facility 2020 rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the Note Issuance Facility 2019, the 2020 Green Private Placement and the Green Exchangeable Notes. The notes issued under the Note Issuance Facility 2020 are guaranteed on a senior unsecured basis by our subsidiaries Atlantica Infrastructures, S.L.U., ABY Concessions Peru S.A., ACT Holding, S.A. de C.V., ASHUSA Inc., ASUSHI Inc. and Atlantica Investments Limited.
The proceeds from the notes issued under the Note Issuance Facility 2020 are expected to be used to finance the acquisition of new or ongoing assets or projects.
2020 Green Private Placement
On March 20, 2020 we entered into a senior secured, euro-denominated note purchase agreement with a group of institutional investors as purchasers providing for the 2020 Green Private Placement. The transaction closed on April 1, 2020 and we issued notes for a total principal amount of €290 million (approximately $354 million), maturing in June 20, 2026. Interest on the notes issued under the 2020 Green Private Placement accrues at a rate per annum equal to 1.96%. If at any time the rating of such senior secured notes is below investment grade, the interest rate thereon would increase by 100 basis points until such notes are rated again investment grade.
Our obligations under the 2020 Green Private Placement rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the Note Issuance Facility 2019 and the Note Issuance Facility 2020. Our payment obligations under the 2020 Green Private Placement are guaranteed on a senior unsecured basis by our subsidiaries Atlantica Infrastructures, S.L.U., ABY Concessions Peru S.A., ACT Holding, S.A. de C.V., ASHUSA Inc., ASUSHI Inc. and Atlantica Investments Limited. The 2020 Green Private Placement is also secured with a pledge over the shares of the subsidiary guarantors, which collateral is shared with the lenders under the Revolving Credit Facility.
The proceeds of the 2020 Green Private Placement were primarily used to repay in full and cancel all series of notes issued under the Note Issuance Facility 2017. The 2020 Green Private Placement complies with the Green Bond Principles and has a second party opinion by Sustainalytics.
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Note Issuance Facility 2019
On April 30, 2019, we entered into the Note Issuance Facility 2019, a senior unsecured financing with Lucid Agency Services Limited, as agent, and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of the euro equivalent of $300 million. The notes under the Note Issuance Facility 2019 were issued in May 2019 and are due on April 30, 2025. Starting January 1, 2020, interest on the notes issued under the Note Issuance Facility 2019 accrues at a rate per annum equal to the sum of 3-month EURIBOR plus a margin of 4.50%. The principal amount of the notes issued under the Note Issuance Facility 2019 was hedged with an interest rate swap, resulting in an all-in interest cost of 4.24%. The Note Issuance Facility 2019 provided that we may elect to, subject to the satisfaction of certain conditions, capitalize interest on the notes issued thereunder for a period of up to two years from closing at our discretion and we elected to capitalize such interest.
Our obligations under the Note Issuance Facility 2019 rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the Note Issuance Facility 2020, the 2020 Green Private Placement and the Green Exchangeable Notes. The notes issued under the Note Issuance Facility 2019 are guaranteed on a senior unsecured basis by our subsidiaries Atlantica Infrastructures, S.L.U., ABY Concessions Peru S.A., ACT Holding, S.A. de C.V., ASHUSA Inc., ASUSHI Inc. and Atlantica Investments Limited. The proceeds of the notes issued under the Note Issuance Facility 2019 were used to prepay and subsequently cancel in full the 2019 Notes and for general corporate purposes.
Revolving Credit Facility
On May 10, 2018, we entered into a Revolving Credit Facility with a syndicate of banks and Royal Bank of Canada acting as administrative agent. Total limit is currently $425 million with maturity on December 31, 2022. As of December 31, 2020, we had no borrowings under the Revolving Credit Facility, $10 million of letters of credit were outstanding and $415 million were available.
Loans under the Revolving Credit Facility accrue interest at a rate per annum equal to: (A) for Eurodollar rate loans, LIBOR plus a percentage determined by reference to our leverage ratio, ranging between 1.60% and 2.25% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. Federal funds brokers on such day plus 1 /2 of 1.00%, (ii) the prime rate of the administrative agent under the Revolving Credit Facility and (iii) LIBOR plus 1.00%, in any case, plus a percentage determined by reference to our leverage ratio, ranging between 0.60% and 1.00%.
Our obligations under the Revolving Credit Facility rank equal in right of payment with our outstanding obligations under the, the Note Issuance Facility 2019, the 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Exchangeable Notes. Our payment obligations under the Revolving Credit Facility are guaranteed on a senior unsecured basis by our subsidiaries Atlantica Infrastructures, S.L.U., ABY Concessions Peru S.A., ACT Holding, S.A. de C.V., ASHUSA Inc., ASUSHI Inc. and Atlantica Investments Limited. The Revolving Credit Facility is also secured with a pledge over the shares of the subsidiary guarantors, which collateral is shared with the holders of the notes issued under the 2020 Green Private Placement.
Note Issuance Facility 2017
On February 10, 2017, we entered into the Note Issuance Facility 2017, a senior secured note facility with a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of €275 million (approximately $336 million). On April 1, 2020, all series of notes issued under the Note Issuance Facility 2017 were repaid in full and canceled with the proceeds of the 2020 Green Private Placement.
Other Credit Lines
In July 2017, we signed a line of credit with a bank for up to €10.0 million (approximately $12.2 million) which is available in euros or U.S. dollars. On December 13, 2019, the maturity date was extended to December 13, 2021. Amounts drawn accrue interest at a rate per annum equal to the sum of 3-month EURIBOR plus a margin of 2% or LIBOR plus a margin of 2%. As of December 31, 2020, €9.9 million (approximately $12.2 million) were drawn under this facility.
In addition, in December 2020, we entered into a credit facility with a local bank for up to €5 million (approximately $6.1 million). The maturity date is December 4, 2025. Amounts drawn down accrue interest at a rate per year equal to 2.50%. As of December 31, 2020, the total amount of the credit line was drawn down.
Commercial Paper Program
On October 8, 2019, we filed a euro commercial paper program with the Alternative Fixed Income Market (MARF) in Spain. The program had an original maturity of twelve months and was extended for another twelve-month period on October 8, 2020. The program allows Atlantica to issue short term notes for up to €50 million, with such notes having a tenor of up to two years. As of December 31, 2020, we had €17.4 million (approximately $21.3 million) issued and outstanding under the Commercial Paper Program at an average cost of 0.69%.
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Covenants, restrictions and events of default
The Note Issuance Facility 2020, the 2020 Green Private Placement, the Note Issuance Facility 2019 and the Revolving Credit Facility contain covenants that limit certain of our and the guarantors’ activities. They also contain customary events of default, including a cross-default, with respect to our indebtedness, indebtedness of the guarantors thereunder and indebtedness of our material non-recourse subsidiaries (project-subsidiaries) representing more than 25% of the cash available for distribution distributed in the previous four fiscal quarters in excess of certain thresholds could trigger a default under the Note Issuance Facility 2020, the 2020 Green Private Placement, the Note Issuance Facility 2019, the Revolving Credit Facility and the Green Exchangeable Notes. Additionally, we are required to comply with a leverage ratio of our indebtedness to our cash available for distribution of 5.00:1.00 (which may be increased under certain conditions to 5.50:1.00 for a limited period in the event we consummate certain acquisitions).

| B) | Project debt refinancing

In addition to our corporate debt, in 2020 we have closed three project debt financings or refinancings at the project level which represent additional sources of liquidity.
Green Project Finance
On April 8, 2020, Logrosan entered into the Green Project Finance with ING Bank, B.V. and Banco Santander S.A. The new facility has a notional of €140 million of which 25% is progressively amortized over its 5-year term and the remaining 75% is expected to be refinanced at maturity. After considering transaction costs and reserves, the Green Project Finance resulted in a net recap of approximately $143 million that was used to finance new investments in renewable assets (see “—Significant Events in 2020—Project Financing Activities”)
Helioenergy 1 & 2
On July 10, 2020, we entered into a non-recourse project debt refinancing of Helioenergy by adding a new euro-denominated long dated tranche of debt from an institutional investor. After transaction costs, net refinancing proceeds (net “recap”) were approximately $43 million (see “Significant Events in 2020—Project Financing Activities”).
Helios 1& 2
On July 14, 2020, we entered into a senior secured note facility with a group of institutional investors for a total amount of €325.6 million ($397.7 million approximately). The proceeds of the new Helios project financing were used to fully prepay and cancel the previous bank mini-perm project debt with approximately €250 million outstanding and to cancel legacy interest rate swaps. After transaction costs and the cancelation of legacy swaps, net refinancing proceeds (net “recap”) were approximately $30 million. The refinancing has permitted an improvement in both cost and tenor. Interest has decreased from approximately 4.2% with spread step-ups to 1.90% and maturity has been extended from 2027 to 2037(see “—Significant Events in 2020—Project Financing Activities”).
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Uses of liquidity and capital requirements

| A) | Debt service

Principal payments on debt as of December 31, 2020, are due in the following periods according to their contracted maturities:

Repayment schedule by geography |  | Total |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | 2025 |  |  | Subsequent years |
|  | $ in millions |  |  |  |
North America |  | $ | 1,623.3 |  |  |  | 80.1 |  |  |  | 90.9 |  |  |  | 97.5 |  |  |  | 98.7 |  |  |  | 107.2 |  |  |  | 1,148.9 |
South America |  |  | 902.5 |  |  |  | 40.1 |  |  |  | 33.8 |  |  |  | 37.1 |  |  |  | 40.4 |  |  |  | 43.1 |  |  |  | 708.0 |
EMEA |  |  | 2,711.8 |  |  |  | 192.2 |  |  |  | 203.6 |  |  |  | 221.2 |  |  |  | 232.4 |  |  |  | 358.5 | (1) |  |  | 1,503.8 |
Total project debt |  | $ | 5,237.6 |  |  |  | 312.4 |  |  |  | 328.4 |  |  |  | 355.8 |  |  |  | 371.5 |  |  |  | 508.8 |  |  |  | 3,360.7 |
Corporate debt |  | $ | 993.7 |  |  |  | 23.6 |  |  |  | 0.0 |  |  |  | 2.0 |  |  |  | 2.0 |  |  |  | 448.1 |  |  |  | 517.9 |
Total |  | $ | 6,231.3 |  |  |  | 336.0 |  |  |  | 328.4 |  |  |  | 357.8 |  |  |  | 373.5 |  |  |  | 956.9 |  |  |  | 3,878.6 |

Note:

| (1) | Includes the outstanding amount of the Green Project Finance from the sub-holding company of Solaben 1 & 6 and Solaben 2 & 3. This facility is 25% progressively amortized over its 5-year term and the remaining 75% is expected to be refinanced before maturity.

Repayment schedule by business sector |  | Total |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | 2025 |  |  | Subsequent years |
|  | $ in millions |
Renewable energy |  | $ | 3,992.5 |  |  |  | 241.2 |  |  |  | 257.5 |  |  |  | 279.2 |  |  |  | 298.8 |  |  |  | 431.8 | (1) |  |  | 2,484.1 |
Efficient natural gas |  |  | 504.3 |  |  |  | 32.9 |  |  |  | 36.9 |  |  |  | 39.9 |  |  |  | 37.6 |  |  |  | 42.3 |  |  |  | 314.7 |
Electric transmission |  |  | 625.2 |  |  |  | 25.6 |  |  |  | 21.3 |  |  |  | 23.5 |  |  |  | 24.1 |  |  |  | 26.1 |  |  |  | 504.6 |
Water |  |  | 115.6 |  |  |  | 12.7 |  |  |  | 12.7 |  |  |  | 13.2 |  |  |  | 11.0 |  |  |  | 8.7 |  |  |  | 57.3 |
Total project debt |  | $ | 5,237.6 |  |  |  | 312.4 |  |  |  | 328.4 |  |  |  | 355.8 |  |  |  | 371.5 |  |  |  | 508.8 |  |  |  | 3,360.7 |
Corporate debt |  | $ | 993.7 |  |  |  | 23.6 |  |  |  | 0.0 |  |  |  | 2.0 |  |  |  | 2.0 |  |  |  | 448.1 |  |  |  | 517.9 |
Total |  | $ | 6,231.3 |  |  |  | 336.0 |  |  |  | 328.4 |  |  |  | 357.8 |  |  |  | 373.5 |  |  |  | 956.9 |  |  |  | 3,878.6 |

Note:

(1) | Includes Green Project Finance from Logrosan Solar Inversiones S.A. the subsidiary-holding company of Solaben 1 & 6 and Solaben 2 & 3. This facility is 25% progressively amortized over its 5-year term and the remaining 75% is expected to be refinanced at maturity.

The project debt maturities will be repaid with cash flows generated from the projects in respect of which that financing was incurred.

| B) | Contractual obligations

In addition to the principal repayment debt obligations detailed above, we have other contractual obligations to make future payments. The material obligations consist of interest related to our project debt and corporate debt and agreements in which we enter in the normal course of business.

| Total |  |  | Up to one year |  |  | Between one and three years |  |  | Between three and five years |  |  | Subsequent years |
| $ in millions |
Purchase commitments |  |  | 1,709.7 |  |  |  | 93.8 |  |  |  | 160.2 |  |  |  | 172.8 |  |  |  | 1,282.9 |
Accrued interest estimate during the useful life of loans |  |  | 2,309.6 |  |  |  | 286.7 |  |  |  | 541.6 |  |  |  | 468.1 |  |  |  | 1,013.2 |

Purchase obligations include agreements for the purchase of goods or services that are enforceable and legally binding on the combined group and that specify all significant terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions and the appropriate timing of the transactions.
Accrued interest estimate during the useful life of loans represents the estimation for the total amount of interest to be paid or accumulated over the useful life of the loans, notes and bonds, taking into consideration the hedging contracts.
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| C) | Cash dividends to investors

We intend to distribute a significant portion of our cash available for distribution to shareholders on an annual basis less all cash expenses including corporate debt service and corporate general and administrative expenses and less reserves for the prudent conduct of our business (including, among other things, dividend shortfall as a result of fluctuations in our cash flows), on an annual basis. We intend to distribute a quarterly dividend to shareholders. Our Board of Directors may, by resolution, amend the cash dividend policy at any time. The determination of the amount of the cash dividends to be paid to shareholders will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant.
Our cash available for distribution is likely to fluctuate from quarter to quarter and, in some cases, significantly as a result of the seasonality of our assets, the terms of our financing arrangements, maintenance and outage schedules, among other factors. Accordingly, during quarters in which our projects generate cash available for distribution in excess of the amount necessary for us to pay our stated quarterly dividend, we may reserve a portion of the excess to fund cash distributions in future quarters. During quarters in which we do not generate sufficient cash available for distribution to fund our stated quarterly cash dividend, if our Board of Directors so determines, we may use retained cash flow from other quarters, and other sources of cash.

Declared |  | Record Date |  | Payment Date |  | $ per share |
February 26, 2020 |  | March 12, 2020 |  | March 23, 2020 |  |  | 0.41 |
May 6, 2020 |  | June 1, 2020 |  | June 15, 2020 |  |  | 0.41 |
July 31, 2020 |  | August 31, 2020 |  | September 15, 2020 |  |  | 0.42 |
November 4, 2020 |  | November 30, 2020 |  | December 15, 2020 |  |  | 0.42 |
February 26, 2021 |  | March 12, 2021 |  | March 22, 2021 |  |  | 0.42 |

| D) | Acquisitions

The acquisitions detailed below have been part of our use of liquidity in 2020 and are expected to be part of our use of liquidity in 2021:
On April 3, 2020 we made an investment in the creation of a renewable energy platform in Chile, together with financial partners, in which we now own approximately a 35% stake and have a strategic investor role. The first investment was the acquisition of Chile PV 1, a 55 MW solar PV. Our initial contribution was approximately $4 million. In addition, on January 6, 2021 we closed our second investment through the platform with the acquisition of Chile PV 2, a 40 MW PV plant. Total equity investment for this new asset was approximately $5.0 million.
On August 17, 2020 we closed the acquisition of the Liberty ownership interest in Solana. Liberty was the tax equity investor in Solana. The total equity investment is expected to be up to $290 million of which $272 million has already been paid. Total price includes a deferred payment and a performance earn-out based on the average annual net production of the asset in the four calendar years with the highest annual net production during the five calendar years of 2020 through 2024.
In October 2020 we reached an agreement to acquire Calgary District Heating a district heating asset in Canada for a total equity investment of approximately $20 million. Closing is expected in 2021 subject to customary conditions precedent and regulatory approvals.
In December 2020 we reached an agreement with Algonquin to acquire La Sierpe, a 20 MW solar asset in Colombia for a total equity investment of approximately $20 million. Closing is expected to occur after the asset reaches commercial operation, currently expected by mid-2021. Closing is subject to customary conditions precedent and regulatory approvals. Additionally, we agreed to potentially co-invest with Algonquin in additional solar plants in Colombia with a combined capacity of approximately 30 MW to be developed and built by AAGES.
In December 2020, we reached an agreement to acquire Coso, a 135 MW geothermal asset in California. Closing is subject to customary regulatory approvals and is expected to occur in the first half of 2021. The total investment is expected to be approximately $170 million, including approximately $130 million for the equity and $40 million expected to be invested in reducing project debt.
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In January 2021 we reached an agreement to increase our equity stake from 15% up to 100% in Rioglass, a multinational manufacturer of solar components. We have closed the acquisition of a 42.5% equity stake, for which we paid $7 million. In addition, we have an option to acquire the remaining 42.5% in the same conditions until September 2021, and after that date the seller has an option to sell the 42.5% also in the same conditions. We intend to find partners to co-invest in the company, as such we expect to classify the investment as held for sale in our consolidated financial statements.
In October 2018, we reached an agreement to acquire PTS, a natural gas transportation platform in Mexico. We initially acquired a 5% ownership in the project and have an agreement to acquire an additional 65% stake subject to the asset entering into commercial operation, non-recourse project financing being closed and final approvals and customary conditions, including the absence of material adverse effects. Our partner in this asset is also negotiating to sell part of its business, which may include the company that provides operation and maintenance services to PTS. This sale may require change of control waivers and may make the closing of the acquisition more difficult. Additionally, our partner has proposed a number of modifications to the project and in the financing agreements. We are currently monitoring the situation in order to decide if we will proceed with the investment or not. We therefore cannot guarantee that we will close this acquisition or that closing will occur on the terms originally agreed.
In addition, we have made investments in assets which are currently under development or construction, such as Ten West Link, the transmission line in the United States where we have a 12.5% ownership. We expect to continue making investments in assets in operation or under construction or development.

| E) | Capital Expenditures

In some cases, maintenance capex is included in the operation and maintenance agreement, therefore it is included in operating expenses within our Income Statement.
Cash flow
The following table sets forth cash flow data for the years ended December 31, 2020, 2019 and 2018:

|  | Year ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
|  | $ in millions |
Gross cash flows from operating activities |  |  |  |  |  |  |  |  |
Profit/(loss) for the year |  | $ | 16.9 |  |  | $ | 74.6 |  |  | $ | 55.3 |
Adjustments to reconcile after-tax profit to net cash generated by operating activities |  |  | 741.8 |  |  |  | 701.9 |  |  |  | 697.6 |
Profit for the year adjusted by non-monetary items |  | $ | 758.7 |  |  | $ | 776.5 |  |  | $ | 752.9 |
Net interest/taxes paid |  |  | (287.3 | ) |  |  | (299.5 | ) |  |  | (333.5 | )
Variations in working capital |  |  | (33.2 | ) |  |  | (113.4 | ) |  |  | (18.4 | )
Total net cash flow provided by/ (used in) operating activities |  | $ | 438.2 |  |  | $ | 363.6 |  |  | $ | 401.0 |
Net cash flows from investing activities |  |  |  |  |  |  |  |  |  |  |  |
Acquisitions of subsidiaries and entities under equity method |  |  | 2.5 |  |  |  | (173.4 | ) |  |  | (70.6 | )
Investments in contracted concessional assets(1) |  |  | (1.4 | ) |  |  | 22.0 |  |  |  | 68.0 |
Distributions from entities under the equity method |  |  | 22.2 |  |  |  | 30.5 |  |  |  | 4.4 |
Other non-current assets/liabilities |  |  | (29.2 | ) |  |  | 2.7 |  |  |  | (16.7 | )
Total net cash flows (used in)/ provided by investing activities |  | $ | (5.9 | ) |  | $ | (118.2 | ) |  | $ | (14.9 | )
Net cash flows used in financing activities |  | $ | (137.3 | ) |  | $ | (310.2 | ) |  | $ | (405.2 | )
Net increase / (decrease) in cash and cash equivalents |  |  | 295.0 |  |  |  | (64.8 | ) |  |  | (19.1 | )
Cash, cash equivalents and bank overdraft at beginning of the year |  |  | 562.8 |  |  |  | 631.5 |  |  |  | 669.4 |
Translation differences cash or cash equivalents |  |  | 10.7 |  |  |  | (3.9 | ) |  |  | (18.8 | )
Cash and cash equivalents at the end of the period |  | $ | 868.5 |  |  | $ | 562.8 |  |  | $ | 631.5 |

Note:
(1) Includes proceeds for $7.4 million and $22.2 million in 2020 and 2019 respectively, see Note 6 of the Annual Consolidated Financial Statements.
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Net cash flows provided by/ (used in) operating activities
Net cash provided by operating activities in the year ended December 31, 2020 was $438.2 million, a 20.5% increase compared to $363.6 million for the previous year. The increase in net cash flows provided by operating activities was mainly due to a lower variation in working capital resulting from better collection periods in 2020, particularly in Mexico where we have been experiencing significant delays in collections since the second half of 2019. In addition, interest payment was lower in the year ended December 31, 2020 compared to the year ended December 31, 2019 mainly due to lower interest at the corporate level and to the interest capitalization in one of our corporate debt financings.
The significant variances in the net cash flows provided by or used in operating activities for the year ended December 31, 2019 compared to the year ended December 31, 2018 are discussed in the Form 20-F filed with the SEC on February 27.
Net cash provided by/ (used in) investing activities
For the year ended December 31, 2020, net cash provided by investing activities was $5.9 and included $22.2 million of dividends received from associates under equity method, of which $16.4 million corresponds to dividends received from Amherst Island Partnership and should be considered together with the $15.7 million paid to non-controlling interest and classified as Net cash provided by financing activities. Net cash provided by investing activities also included $11.1 million positive amount from the acquisition of Tenes, since the cash consolidated at the acquisition date is higher than the payment made under the agreement signed in May 2020. These effects were partially offset by $8.7 million paid in investments, $21.6 million transferred to financial investments for potential equipment replacements in Solana and other minor maintenance capex.
For the year ended December 31, 2019, net cash used in investing activities was $118.3 million and corresponded mainly to the investment in Amherst Island. Atlantica and Algonquin formed AYES Canada, a vehicle to channel co-investment opportunities and the first investment was in Amherst Island, a 75 MW wind plant in Canada. Atlantica invested $4.9 million and Algonquin invested $92.3 million, both through AYES Canada. Since Atlantica controls AYES Canada under IFRS 10, we show in Net cash used in investing activities the total $97.2 million invested by AYES Canada in the project company and in Net cash provided by financing activities the $92.3 million received from Algonquin by AYES Canada. In addition, net cash used in investing activities includes $42 million payment for the acquisition of Monterrey, $19.9 million payment for Tenes, which became a financial investment after the conditions precedent were not fulfilled and $20 million payment for the acquisition of ATN Expansion 2. Net cash used in investing activities also included $22.2 million related to amounts received by Solana from Abengoa in relation to the DOE consents to decrease Abengoa’s ownership in Atlantica to 16.5% and to allow Abengoa to sell entirely its stake in Atlantica. From an accounting perspective, because the payment resulted from Abengoa’s obligations under the EPC contract, most of the amount received in 2019 was recorded as reducing the asset value and was therefore classified as cash provided by investing activities.
The significant variances in the net cash flows provided by or used in investing activities for the year ended December 31, 2018 are discussed in the Form 20-F filed with the SEC on February 28, 2019.
Net cash provided by/ (used in) financing activities
For the year ended December 31, 2020, net cash used in financing activities was $137.3 million and corresponded mainly to the proceeds from the 2020 Green Private Placement, the Note Issuance Facility 2020, the Green Project Finance, the Green Exchangeable Notes and the project debt refinancings of Helios and Helioenergy, for a total amount of $827.1 million and to the withdrawal of approximately $90.0 million under the Revolving Credit Facility in the first quarter of 2020. Net cash used in financing activities also includes $162.2 million from the underwritten public offering closed in December 2020. These cash inflows were partially offset by the repayment of $308.8 million of the Note Issuance Facility 2017, the repayment of $174.0 million of our Revolving Credit Facility in the third quarter, the scheduled repayment of principal of our project financing agreements for an approximate amount of $298.7 million and $191.6 million of dividends paid to shareholders and non-controlling interest. Net cash used in financing activities also includes $266.8 million paid for the acquisition of the Liberty Ownership Interest Solana.
For the year ended December 31, 2019, net cash used in financing activities was $310.2 million and corresponded principally to $603.1 million of principal debt repayments, of which $259.7 million corresponded to the prepayment of the 2019 Notes, $281.8 million of project debt repayments and $60 million of Revolving Credit Facility repayment. We also received $293.1 million net proceeds under the Note Issuance Facility 2019, net of fees, commercial paper for a total amount of $27.2 million and $32.6 million net of fees under our Revolving Credit Facility. In addition, we paid $159.0 million of dividends to shareholders and $29.2 million to non-controlling interest. As explained above, we also include $92.3 million corresponding to Algonquin’s participation in Amherst.
The significant variances in the net cash flows provided by or used in investing activities for the year ended December 31, 2018 are discussed in the Form 20-F filed with the SEC on February 28, 2019.
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C. | Research and Development

Not applicable.

D. | Trend Information

Other than as disclosed elsewhere in this annual report, we are not aware of any trends, uncertainties, demands, commitments or events for the year ended December 31, 2020 that are reasonably likely to have a material adverse effect on our revenues, income, profitability, liquidity or capital resources, or that caused the disclosed financial information to be not necessarily indicative of future operating results or financial conditions.

E. | Off-Balance Sheet Arrangements

As of December 31, 2020, the overall sum of the Bank and Surety Insurances Bonds directly deposited by subsidiaries of Atlantica as a guarantee to third parties (clients, financial entities and other third parties) was $36.3 million and corresponded to operations of technical nature ($38.2 million as of December 31, 2019). In addition, the outstanding amount of guarantees issued by Atlantica Sustainable Infrastructure plc as of December 31, 2020 was $159.8 million ($130.1 million as of December 31, 2019). Guarantees issued by Atlantica correspond mainly to guarantees provided to off-takers in our PPAs, guarantees issued to cover debt service reserve accounts and guarantees for points of access for renewable energy projects. For further discussion, see note 19 to our Annual Consolidated Financial Statements included elsewhere in this annual report.
Critical Accounting Policies and Estimates
The preparation of our Annual Consolidated Financial Statements in conformity with IFRS requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions we believe to be reasonable under the specific circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
An understanding of the accounting policies for these items is important to understand the Annual Consolidated Financial Statements. The following discussion provides more information regarding the estimates and assumptions used for these items in accordance with IFRS and should be considered in conjunction with the Annual Consolidated Financial Statements.
The most critical accounting policies, which reflect significant management estimates and judgment to determine amounts in our Annual Consolidated Financial Statements, are as follows:

| - | Contracted concessional assets and PPAs;

| - | Impairment of intangible assets and property, plants and equipment;

| - | Assessment of control;

| - | Derivative financial instruments and fair value estimates; and

| - | Income taxes and recoverable amount of deferred tax assets.

Some of the accounting policies applied require the application of significant judgment by management to select the appropriate assumptions to determine these estimates. These assumptions and estimates are based on our historical experience, advice from experienced consultants, forecasts and other circumstances and expectations as of the close of the financial period. The assessment is considered in relation to the global economic situation of the industries and regions where we operate, considering future development of our businesses. By their nature, these judgments are subject to an inherent degree of uncertainty; therefore, actual results could materially differ from the estimates and assumptions used. In such cases, the carrying values of assets and liabilities are adjusted.
As of the date of preparation of our Annual Consolidated Financial Statements, no relevant changes in the estimates made are anticipated and, therefore, no significant changes in the value of the assets and liabilities recognized at December 31, 2020, are expected.
Although these estimates and assumptions are being made using all available facts and circumstances, it is possible that future events may require management to amend such estimates and assumptions in future periods. Changes in accounting estimates are recognized prospectively, in accordance with IAS 8, in the consolidated income statement of the year in which the change occurs. Our significant accounting policies are more fully described in note 2 to our Annual Consolidated Financial Statements, presented elsewhere in this annual report.
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Contracted concessional assets
Contracted concessional assets include fixed assets financed through project debt, related to service concession arrangements recorded in accordance with IFRIC 12, except for Palmucho, which is recorded in accordance with IFRS 16 and PS10, PS20, Mini-Hydro, Chile TL 3, Seville PV, ATN Expansion 2 and Chile PV 1, which are recorded as tangible assets in accordance with IAS 16. The infrastructures accounted for as concessions are related to the activities concerning electric transmission lines, solar electricity generation plants, cogeneration plants, wind farms and water desalination plants. The useful life of these assets is approximately the same as the length of the concession arrangement. The infrastructure used in a concession can be classified as an intangible asset or a financial asset, depending on the nature of the payment entitlements established in the agreement.
The application of IFRIC 12 requires extensive judgement in relation with, among other factors, (i) the identification of certain infrastructures and contractual agreements in the scope of IFRIC 12, (ii) the understanding of the nature of the payments in order to determine the classification of the infrastructure as a financial asset or as an intangible asset and (iii) the timing and recognition of the revenue from construction and concessionary activity.
Under the terms of contractual arrangements within the scope of this interpretation, the operator shall recognize and measure revenue in accordance with IFRS 15 for the services it performs.

a) | Intangible assets

We recognize an intangible asset to the extent that we receive a right to charge final customers for the use of the infrastructure. This intangible asset is subject to the provisions of IAS 38 and is amortized linearly, taking into account the estimated period of commercial operation of infrastructure, which generally coincides with the concession period.
Once the infrastructure is in operation, the treatment of income and expenses is as follows:

| - | Revenues from the updated annual revenue for the contracted concession, as well as operation and maintenance services are recognized in each period according to IFRS 15 “Revenue from contracts with customers”

| - | Operating and maintenance costs and general overheads and administrative costs are recorded in accordance with the nature of the cost incurred (amount due) in each period.

b) | Financial assets

We recognize a financial asset when demand risk is assumed by the grantor, to the extent that the contracted concession holder has an unconditional right to receive payments for the asset. This asset is recognized at the fair value of the construction services provided, considering upgrade services in accordance with IFRS 15, if any.
The financial asset is subsequently recorded at amortized cost calculated according to the effective interest method. Revenue from operation and maintenance services is recognized in each period according to IFRS 15 “Revenue from contracts with Customers.” The income from managing and operating the asset resulting from the valuation at amortized cost is also recorded in revenue.
According to IFRS 9, we recognize an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that we expect to receive.
There are two main approaches to applying the ECL model according to IFRS 9: the general approach which involves a three-stage approach, and the simplified approach, which can be applied to trade receivables, contract assets and lease receivables. We have elected to apply the simplified approach. Under this approach, there is no need to monitor for significant increases in credit risk and entities will be required to measure lifetime expected credit losses at each end of reporting period.
The key elements of the ECL calculations, based on external source of information, are the following:

| - | the Probability of Default (“PD”) is an estimate of the likelihood of default over a given time horizon. We calculate PD based on Credit Default Swaps spreads (“CDS”);

| - | the Exposure at Default (“EAD”) is an estimate of the exposure at a future default date;

| - | the Loss Given Default (“LGD”) is an estimate of the loss arising in the case where a default occurs at a given time. It is based on the difference between the contractual cash flows due and those that we would expect to receive. It is expressed as a percentage of the EAD.

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c) | Property, plant and equipment

Assets recorded as property, plant and equipment are measured at historical cost, including all expenses directly attributable to the acquisition, less depreciation and impairment losses, with the exception of land, which is presented net of any impairment losses. Once the infrastructure is in operation, the treatment of income and expenses is equal to intangible assets.

d) | Right-of-use assets

Main right of use agreements corresponds to land rights. The Company recognizes right-of-use assets at the commencement date of the lease (i.e., the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities (see Note 2.3 to our Annual Consolidated Financial Statements). The cost of right-of-use assets includes the amount of lease liabilities recognized, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets.
Impairment of intangible assets and property, plant and equipment
We review our contracted revenue assets to identify any indicators of impairment at least annually. When impairment indicators exist, the company calculates the recoverable amount of the asset.
The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, we calculate the recoverable amount of the cash generating unit, or CGU to which the asset belongs.
When the carrying amount of the CGU to which these assets belong is higher than its recoverable amount, the assets are impaired.
Assumptions used to calculate value in use include a discount rate and projections considering real data based on the contract terms and projected changes in both selling prices and costs. The discount rate is estimated by management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.
For contracted or concession revenue assets with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no terminal value is assumed. Contracted revenue assets have a contractual structure that permits to estimate quite accurately the costs of the project and revenue during the life of the project.
Projections take into account real data based on the contract terms and fundamental assumptions based on part in specific reports prepared internally and supported by third-party reports, assumptions on demand and assumptions on production. Additionally, assumptions on macroeconomic conditions are also considered, such as inflation rates, future interest rates and sensitivity analysis are performed over all major assumptions, which can have a significant impact on the value of the asset.
Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.
Taking into account that in most CGUs the specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash-flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is performed.
In any case, sensitivity analyses are performed, especially in relation with the discount rate used and fair value changes in the main business variables, in order to ensure that possible changes in the estimates of these items do not impact the recovery of recognized assets.
Accordingly, the following table provides a summary of the discount rates used (WACC) to calculate the recoverable amount for CGUs with the operating segment to which it pertains:

Operating segment |  | Discount rate Post tax |
EMEA |  |  | 3% - 5 | %
North America |  |  | 4% - 5 | %
South America |  |  | 5% - 7 | %

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The discount rates applied in 2020 are consistent with the ones applied in 2019
In the event that the recoverable amount of an asset is lower than its carrying amount, an impairment charge for the difference would be recorded in the income statement under the item “Depreciation, amortization and impairment charges”.
An assessment is made at each reporting date to determine whether there is an indication that previously recognized impairment losses no longer exist or have decreased. If such indication exists, the Company estimates the CGU’s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the income statement.
Assessment of control
Control over an investee is achieved when we have power over the investee, we are exposed, or have rights, to variable returns from our involvement with the investee and have the ability to use its power to affect its returns. We reassess whether or not we control an investee when facts and circumstances indicate that there are changes to one or more of these three elements of control.
We use the acquisition method to account for business combinations of companies controlled by a third party. According to this method, identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Any contingent consideration is recognized at fair value at the acquisition date and subsequent changes in its fair value are recognized in accordance with IFRS 9 either in profit or loss or as a change to other comprehensive income. Acquisition-related costs are expensed as incurred. We recognize any non-controlling interest in the acquired entity either at fair value or at the non-controlling interest’s proportionate share of the acquirer’s net assets on an acquisition-by-acquisition basis.
All assets and liabilities between entities within the group, equity, income, expenses and cash flows relating to transactions between entities of the group are eliminated in full.
Derivative financial instruments and fair value estimates
Derivatives are recognized at fair value in the statement of financial position. The Company maintains both derivatives designated as hedging instruments in hedging relationships, and derivatives to which hedge accounting is not applied.
When hedge accounting is applied, hedging strategy and risk management objectives are documented at inception, as well as the relationship between hedging instruments and hedged items. Effectiveness of the hedging relationship needs to be assessed on an ongoing basis. Effectiveness tests are performed prospectively at inception and at each reporting date. We analyze on each date if all these requirements are met:

- | there is an economic relationship between the hedged item and the hedging instrument;

- | the effect of credit risk does not dominate the value changes that result from that economic relationship; and

- | the hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that we actually hedge and the quantity of the hedging instrument that we use to hedge that quantity of hedged item.

Ineffectiveness is measured following accumulated dollar offset method.
In all cases, current Company´s hedging relationships are considered cash flow hedges. Under this model, the effective portion of changes in fair value of derivatives designated as cash flow hedges are recorded temporarily in equity and are subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffective portion of the hedged transaction is recorded in the consolidated income statement as it occurs.
When interest rate options are designated as hedging instruments, the time value is excluded from the hedging instrument as permitted by IFRS 9. Changes in the effective portion of the intrinsic are recorded in equity and subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffectiveness is recorded as financial income or expense as it occurs. Changes in options time value is recorded as cost of hedging. More precisely, considering that the hedged items are, in all cases, time period hedged item, changes in time value is recognized in other comprehensive income to the extent that it relates to the hedged item. The time value at the date of designation of the option as a hedging instrument, to the extent that it relates to the hedged item, is amortized on a systematic and rational basis over the period during which the hedge adjustment for the option’s intrinsic value could affect profit or loss.
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When the hedging instrument matures or is sold, or when it no longer meets the requirements to apply hedge accounting, accumulated gains and losses recorded in equity remain as such until the forecast transaction is ultimately recognized in the income statement. However, if it becomes unlikely that the forecast transaction will actually take place, the accumulated gains and losses in equity are recognized immediately in the income statement.
Any change in fair value of derivatives instruments to which hedge accounting is not applied is directly recorded in the income statement.
The inputs used to calculate fair value of our derivatives are based on inputs other than quoted prices that are observable for the asset or liability, either directly (i.e., as prices) or indirectly (i.e., derived from prices), through the application of valuation models (Level 2). The valuation techniques used to calculate fair value of our derivatives include discounting estimated future cash flows, using assumptions based on market conditions at the date of valuation or using market prices of similar comparable instruments, amongst others. The valuation of derivatives requires the use of considerable professional judgment. These determinations were based on available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Income taxes and recoverable amount of deferred tax assets
The current income tax provision is calculated on the basis of relevant tax laws in force at the date of the statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.
Determining income tax provision requires judgment in assessing the timing and the amount of deductible and taxable items, as well as the interpretation and application of tax laws in different jurisdictions. Due to this fact, contingencies or additional tax expenses could arise as a result of tax inspections or different interpretations of certain tax laws by the corresponding tax authorities.
We recognize deferred tax assets for all deductible temporary differences and all unused tax losses and tax credits to the extent that it is probable that future taxable profit will be available against which they can be utilized. We consider it probable that we will have sufficient taxable profit available in the future to enable a deferred tax asset to be recovered when:

| - | There are sufficient taxable temporary differences relating to the same tax authority, and the same taxable entity is expected to reverse either in the same period as the expected reversal of the deductible temporary difference or in periods into which a tax loss arising from the deferred tax asset can be carried back or forward.

| - | It is probable that the taxable entity will have sufficient taxable profit, relating to the same tax authority and the same taxable entity, in the same period as the reversal of the deductible temporary difference (or in the periods into which a tax loss arising from the deferred tax asset can be carried back or forward).

| - | Tax planning opportunities are available to the entity that will create taxable profit in appropriate periods.

Our management assesses the recoverability of deferred tax assets on the basis of estimates of future taxable profit. These estimates are derived from the projections of each of our assets. Based on our current estimates, we expect to generate sufficient future taxable income to achieve the realization of our current tax credits and tax loss carryforwards, supported by our historical trend of business performance.
In assessing the recoverability of our deferred tax assets, our management also considers the foreseen reversal of deferred tax liabilities and tax planning strategies. To the extent management relies on deferred tax liabilities for the readability of our deferred tax assets, such deferred tax liabilities are expected to reverse in the same period and jurisdiction and are of the same character as the temporary differences giving rise to the deferred tax assets. We consider that the recovery of our current deferred tax assets is probable without counting on potential tax planning strategies that we could use in the future.

G. | Safe Harbor

This annual report contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act and as defined in the Private Securities Litigation Reform Act of 1995. See “Cautionary Statements Regarding Forward-Looking Statements.”
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ITEM 6. | DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A. | Directors and Senior Management

Board of Directors of Atlantica
The Board of Directors of Atlantica comprises the following eight members:

Name |  | Position |  | Year of birth
William Aziz |  | Director, Independent |  | 1956
Arun Banskota |  | Director |  | 1961
Brenda Eprile |  | Director, Independent |  | 1954
Debora Del Favero |  | Director, Independent |  | 1964
Michael Forsayeth |  | Director, Independent |  | 1954
Santiago Seage |  | Chief Executive Officer and Director |  | 1969
George Trisic |  | Director |  | 1960
Michael Woollcombe |  | Director and Chair of the Board, independent |  | 1968

The business address of the members of the Board of Directors of Atlantica is Great West House, GW1, 17th floor, Great West Road, Brentford, TW8 9DF, United Kingdom.
There are no family relationships among any of our executive officers or directors. There are no potential conflicts of interest between the private interests or other duties of the members of the Board of Directors listed above and their duties to Atlantica, except in the case of Mr. Arun Banskota and Mr. George Trisic who serve on Algonquin’s board as Chief Executive Officer and Chief Governance Officer and Corporate Secretary of Algonquin, respectively.
The following is the biographical information of members of our Board of Directors.
William Aziz, Director
William Aziz is the President and Chief Executive Officer of BlueTree Advisors Inc., a private management advisory firm focused on improving the performance of global client companies by providing expertise to manage operational, financial and organizational challenges. Mr. Aziz is a director and Chair of the Audit Committee of TSX-listed Maple Leaf Foods Inc. and a member of the Advisory Board for Fengate Real Assets. From 2009 to 2019, Mr. Aziz was a Director of the Cdn. $100 billion Ontario Municipal Employees’ Retirement System, where he was Chair of its Investment Committee and a member of its Human Resources Committee. Mr. Aziz has served as a director of a number of publicly-traded companies. Mr. Aziz is a graduate of the Ivey School of Business at Western University in Honors Business Administration and is a Chartered Professional Accountant. Mr. Aziz has also completed the Institute of Corporate Directors Governance College at the Rotman School of Business, University of Toronto and holds the ICD.D designation and is a member of the Insolvency Institute of Canada.
Arun Banskota, Director
Mr. Banskota is the President of Algonquin and its incoming Chief Executive Officer. Mr. Banskota joined Algonquin in February 2020 and has 30 years of experience in senior roles from a combination of industries such as renewable energy development, construction, financing, and operations. He has also served as manager of multiple large business units and three start-ups in the clean-tech space. Mr. Banskota holds a Master of Arts (University of Denver) and a Master of Business Administration (University of Chicago).
Brenda Eprile, Director
Brenda Eprile is a director and Chair of the Audit Committee of Westport Fuel Systems Inc., a TSX and NASDAQ-listed company that invents, engineers, builds and supplies clean alternative fuel systems and components. Ms. Eprile has been a director of Westport since 2013, and previously served as Chair of the Board from February 2017 to April 2020, where she oversaw a major transformation of Westport’s business, and as Chair of the HRC committee. Ms. Eprile is also a director and Chair of the Governance Committee of TSX-listed Olympia Financial Group, and a director of its subsidiary Olympia Trust Company, a western Canadian trust company. From 2016 to 2018, Ms. Eprile also served as a director TSX-listed alternative mortgage lender Home Capital Group Ltd., where she became Chair of the Board in 2017 and was part of leading Home Capital’s efforts in responding to a severe liquidity and regulatory crisis and in obtaining the support of Berkshire Hathaway Inc. as a major strategic investor. From 2000 to 2012, Ms. Eprile was a Senior Partner at PricewaterhouseCoopers and led its Canadian Risk Advisory Services practice. From 1998 to 2000, Ms. Eprile led the Canadian Regulatory Risk practice at Deloitte LLP. From 1985 to 1997, Ms. Eprile had a distinguished career as a securities regulator in Canada, holding the positions of both Executive Director and Chief Accountant at the Ontario Securities Commission. Ms. Eprile is a Fellow Chartered Professional Accountant and holds the ICD.D designation. Ms. Eprile also holds an MBA from the Schulich School of Business at York University.
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Debora Del Favero, Director
Debora Del Favero is a senior executive with deep international mergers and acquisition and corporate finance experience including in the renewables sector. She is a Co-Founder of CMC Capital Limited, a U.K.-based corporate finance advisory boutique established in 2011 that specializes in M&A and corporate advice. Previously, for over 17 years, Ms. Del Favero held progressively senior roles in both the London and New York offices of the Investment Banking Division of Credit Suisse. This included approximately seven years as a Managing Director and member of the Energy Group and M&A Group of Credit Suisse in London. Ms. Del Favero also served on the European Investment Banking Committee of Credit Suisse. Prior to joining Credit Suisse, Ms. Del Favero was a Senior Analyst at Analitica based in Milan, Italy, a start-up specializing in equity research on Italian publicly-listed companies. Ms. Del Favero holds a Masters of Arts in Economics and Business Administration from Bocconi University in Milan, Italy, with a focus on corporate finance and commercial law and a dissertation on international taxation.
Michael Forsayeth, Director
Michael Forsayeth is an experienced business leader having held Chief Executive Officer, Chief Financial Officer and other senior executive positions in several large public and private real estate, hospitality, foodservice and other businesses over his career. Most recently, Mr. Forsayeth was Chief Executive Officer and a director of TSX and NYSE-listed Granite Real Estate Investment Trust, a large Canadian-based REIT with industrial, warehouse and logistics properties in North America and Europe. Prior to being appointed as Granite’s CEO, Mr. Forsayeth served as Granite’s Chief Financial Officer from 2011 to 2015. From 2007 to 2011, Mr. Forsayeth was Chief Financial Officer of Intrawest ULC, a significant developer and manager of resort properties in North America and Europe, following its $3 billion privatization by a private equity group. From 1999 to 2007, Mr. Forsayeth was the Chief Financial Officer of Cara Operations Limited (now Recipe Unlimited), a leading Canadian foodservice business, where Mr. Forsayeth played a key leadership role in Cara Operation’s successful going-private transaction. Previously, Mr. Forsayeth held senior executive positions with TSX and NYSE-listed Laidlaw Inc., and TSX-listed Derlan Industries Limited. Mr. Forsayeth is a CPA and CA and spent nine years with Coopers & Lybrand (now PricewaterhouseCoopers) in various areas including the audit practice and a secondment in its London, England office. Mr. Forsayeth holds a Bachelor of Commerce (Honours) from Queen’s University.
Santiago Seage, Chief Executive Officer and Director
Mr. Seage has served as a director since our formation in 2014 until March 2018 and from December 2018. Mr. Seage has served as our Chief Executive Officer since our formation, except for the six-month period between May and November 2015, while he was Chair of our Board and Chief Executive Officer of Abengoa. Prior to the foregoing, he served as Abengoa Solar’s CEO beginning in 2006. Before joining Abengoa, he was a partner with McKinsey & Company. Mr. Seage holds a degree in Business Management from ICADE University in Madrid.
George Trisic, Director
Mr. Trisic is the Chief Governance Officer and Corporate Secretary of Algonquin. In his role, Mr. Trisic is responsible for leading the sustainability, government affairs and governance functions. He has broad experience managing high growth, start up and expanding businesses across multiple sites and regions. His skill set includes leading multi-functional groups in finance, human resources, legal and information technology in a senior executive role. Mr. Trisic holds a Bachelor of Laws Degree from the University of Western Ontario. Additionally, he holds a Chartered Director certification from the Directors College (McMaster University).
Michael Woollcombe, Director and Chair of the Board
Michael Woollcombe has been a Partner of Voorheis & Co. LLP and Executive Vice-President of VC & Co. Incorporated for more than 20 years. Since 2011, Mr. Woollcombe has also been President of VWK Capital Management Inc., the investment manager for VWK Partners Fund LP, a long-short investment fund. Mr. Woollcombe is one of the leading special situations advisors in Canada and has been centrally involved in directing numerous high-profile shareholder disputes, proxy contests, M&A transactions, special committee mandates, internal and independent corporate investigations and complex restructurings. Mr. Woollcombe regularly serves as a trusted strategic advisor to institutional and other significant shareholders, boards of directors and chief executive officers to address their most important opportunities and crisis situations. Mr. Woollcombe has acted as a director and as member of special board committees of a number of publicly-traded companies. Previously, Mr. Woollcombe practiced corporate and securities law at a major law firm in Toronto, Canada. Mr. Woollcombe holds a Bachelor of Commerce (Honours) from Queen’s University and an LLB from the University of Western Ontario.
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Senior Management of Atlantica
We have a senior management team with extensive experience in developing, financing, managing and operating contracted assets.
Our senior management is made up of the following members:

Name |  | Position |  | Year of birth
David Esteban |  | Vice President EMEA |  | 1979
Emiliano Garcia |  | Vice President North America |  | 1968
Irene M. Hernandez |  | General Counsel and Chief of Compliance |  | 1980
Francisco Martinez-Davis |  | Chief Financial Officer |  | 1963
Antonio Merino |  | Vice President South America |  | 1967
Stevens C. Moore |  | Vice President Strategy and Corporate Development |  | 1973
Santiago Seage |  | Chief Executive Officer and Director |  | 1969

The business address of the members of the senior management of Atlantica is Great West House, GW1, 17 floor, Great West Road, Brentford, TW8 9DF, United Kingdom.
There are no potential conflicts of interest between the private interests or other duties of the members of the senior management listed above and their duties to Atlantica. There are no family relationships among any of our executive officers or directors.
Below are the biographies of those members of the senior management of Atlantica Sustainable Infrastructure who do not also serve on our Board of Directors.
David Esteban, Vice President EMEA
Mr. Esteban has served as Vice President of our operations in EMEA since July 2014. He had previously served at Abengoa’s Corporate Concession department for two years. Before joining Abengoa, David worked for the management consulting firm Arthur D. Little for seven years in the industries of Telecoms & Energy and then moved to a private equity firm specialized in renewable investments in Europe for three years.
Emiliano Garcia, Vice President North America
Mr. Garcia serves as Vice President of our North American business. Based in Phoenix, Arizona, he is responsible for managing two of our key assets, Solana and Mojave. Mr. Garcia was previously the General Manager of Abengoa Solar in the United States and of the Solana Power Plant. Before that, he held a number of managerial positions in various Abengoa companies over two decades. Mr. Garcia holds a Bachelor’s degree in Engineering from Madrid Technical University.
Irene M. Hernandez, General Counsel
Ms. Hernandez has served as our General Counsel since June 2014. Prior to that, she served as head of our legal department since the date of our formation. Before that, Ms. Hernandez served as Deputy Secretary General at Abengoa Solar since 2012. Before joining Abengoa, she worked for several law firms. Ms. Hernandez holds a law degree from Complutense Madrid University and a Master’s degree in law from the Madrid Bar Association (Colegio de Abogados de Madrid (ICAM)).
Francisco Martinez-Davis, Chief Financial Officer
Mr. Martinez-Davis was appointed as our Chief Financial Officer on January 11, 2016. Mr. Martinez-Davis has more than 30 years of experience in senior finance positions both in the United States and Spain. He has served as Chief Financial Officer of several large industrial companies. Most recently, he was Chief Financial Officer for the company responsible for the management and operation of metropolitan rail service of the city of Madrid where he was also member of the Executive Committee. He has also worked as CFO for a retailer and as Deputy General Manager in Finance and Treasury for Telefonica Moviles. Prior to that, he worked for different investment banks in New York City and London for more than 10 years, including J.P. Morgan Chase & Co. and BNP Paribas. Mr. Martinez-Davis holds a Bachelor of Science, cum laude, in Business Administration from Villanova University in Philadelphia and an MBA from The Wharton School at the University of Pennsylvania.
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Antonio Merino, Vice President South America
Mr. Merino serves as Vice President of our South American business. Previously, he was the Vice President of Abengoa’s Brazilian business, as well as the head of Abengoa’s commercial activities and partnerships in South America. Mr. Merino holds an MBA from San Telmo International Institute.
Stevens C. Moore, Vice President Strategy & Corporate Development
Mr. Moore has more than 25 years of experience in finance positions in Spain, the United Kingdom and the United States. He has worked in various positions in structured and leveraged finance at Citibank and Banco Santander, and vice president of M&A at GBS Finanzas. Most recently, he was director of corporate development and investor relations at Codere, the Madrid stock exchange listed international gaming company. He holds a B.A. degree in history from Tulane University of New Orleans, Louisiana.
Lead Independent Director
Our corporate governance guidelines provide that one of our independent directors shall serve as a lead independent director at any time when an independent director is not serving as the chair of our Board of Directors.

B | Compensation

Compensation of the Board of Directors and Chief Executive Officer
Since April 2019 each independent non-executive director is entitled to receive annual compensation of $150.0 thousand. In addition, Chair of the Board and Chairs of the committees of the board are entitled to receive additional compensation as detailed in the table below. Furthermore, since May 2020 non-independent non-executive directors are also entitled to be compensated on the same terms as we compensate independent non-executive directors. In 2020, non-independent non-executive directors declined compensation.
The following table sets out the fee schedule for 2020 and 2019:

$ in thousand |  | 2020 |  |  | From April 2019 to December 2019 |  |  | From January 2019 to March 2019 |
Annual Director Retainer |  |  |  |  |  |  |  |  |
Non-Executive Director |  |  | 150.0 |  |  |  | 150.0 |  |  |  | 134.0 |
Annual Committee Chair Retainer |  |  |  |  |  |  |  |  |  |  |  |
Chair of the Board |  |  | 75.0 |  |  |  | 75.0 |  |  |  | 61.0 |
Chair of the Audit Committee |  |  | 15.0 |  |  |  | 15.0 |  |  |  | 15.0 |
Chair of the Nominating and Corporate Governance Committee |  |  | 10.0 |  |  |  | 10.0 |  |  |  | 10.0 |
Chair of the Compensation Committee |  |  | 10.0 |  |  |  | 10.0 |  |  |  | 10.0 |

The table below summarizes the directors who received remuneration during the year ended December 31, 2020 as well as the prior year, for comparison. The compensation of the Chief Executive Officer is defined in euros. Amounts have been converted to US $ for presentation purposes.
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|  | Salary and Fees |  |  | Annual Bonuses |  |  | LTIP1 |  |  | Total Fixed Remuneration |  |  | Total Variable remuneration |  |  | Total
|  | 2020 |  |  | 2019 |  |  | 2020 |  |  | 2019 |  |  | 2020 |  |  | 2019 |  |  | 2020 |  |  | 2019 |  |  | 2020 |  |  | 2019 |  |  | 2020 |  |  |  | 2019 |
|  | (in thousands of U.S. dollars)
William Aziz2 |  |  | 106.7 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 106.7 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 106.7 |  |  |  | - |
Debora Del Favero2 |  |  | 106.7 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 106.7 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 106.7 |  |  |  | - |
Brenda Eprile2 |  |  | 110.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 110.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 110.0 |  |  |  | - |
Michael Forsayeth2 |  |  | 100.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 100.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 100.0 |  |  |  | - |
Santiago Seage3 |  |  | 756.8 |  |  |  | 727.7 |  |  |  | 996.4 |  |  |  | 957.7 |  |  |  | 770.9 |  |  |  | - |  |  |  | 756.8 |  |  |  | 727.7 |  |  |  | 1,767.3 |  |  |  | 957.7 |  |  |  | 2,524.1 |  |  |  | 1,685.4 |
Michael Woollcombe2 |  |  | 150.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 150.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 150.0 |  |  |  | - |
Andrea Brentan4 |  |  | 56.3 |  |  |  | 146.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 56.3 |  |  |  | 146.0 |  |  |  | - |  |  |  | - |  |  |  | 56.3 |  |  |  | 146.0 |
Robert Dove4 |  |  | 60.0 |  |  |  | 155.9 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 60.0 |  |  |  | 155.9 |  |  |  | - |  |  |  | - |  |  |  | 60.0 |  |  |  | 155.9 |
Francisco J. Martinez4 |  |  | 61.9 |  |  |  | 161.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 61.9 |  |  |  | 161.0 |  |  |  | - |  |  |  | - |  |  |  | 61.9 |  |  |  | 161.0 |
Jackson Robinson4 |  |  | 60.0 |  |  |  | 155.9 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 60.0 |  |  |  | 155.9 |  |  |  | - |  |  |  | - |  |  |  | 60.0 |  |  |  | 155.9 |
Daniel Villalba4 |  |  | 84.4 |  |  |  | 217.5 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 84.4 |  |  |  | 217.5 |  |  |  | - |  |  |  | - |  |  |  | 84.4 |  |  |  | 217.5 |
Total |  |  | 1,652.8 |  |  |  | 1,564.0 |  |  |  | 996.4 |  |  |  | 957.7 |  |  |  | 770.9 |  |  |  | - |  |  |  | 1,652.8 |  |  |  | 1,564.0 |  |  |  | 1,767.3 |  |  |  | 957.7 |  |  |  | 3,420.1 |  |  |  | 2,521.7 |

Notes:

| (1) | Long-term Incentive Awards includes Long-term Incentive Plan (LTIP) and Special One-Off Plan

| (2) | Mr. William Aziz, Mrs. Debora Del Favero, Mrs. Brenda Eprile, Mr. Michael Forsayeth, Mr. Michael Woollcombe, joined the Board of Directors on May 5, 2020 as independent non-executive Directors and were appointed as Chair of the Compensation Committee, Chair of the Nominating and Corporate Governance Committee, Chair of the Audit Committee, Chair of the Related Parties Transactions Committee and Interim Chair of the Board, respectively.

| (3) | The CEO’s compensation is approved in Euros. It has been converted to U.S. dollars for presentation purposes, at the average exchange rate of each year, which is 1.14 $/€ in 2020 and 1.12 $/€ in 2019.

In 2020, the CEO’s total pay amounted to €2,222.2 thousand ($2,524.1 thousand). Fix salary amounted to €663.0 thousand ($756.8 thousand), annual bonus to €873.0 thousand ($996.4 thousand) and long-term incentive awards to €686.3 thousand ($770.9 thousand). In 2019, the CEO’s total pay amounted to €1,505.5 thousand ($1,685.4 thousand). Fix salary amounted to €650.0 thousand ($727.7 thousand) and annual bonus to €855.5 thousand ($957.7 thousand). In 2019 no amount vested under long-term incentive awards.

| (4) | Mr. Daniel Villalba, Mr. Robert Dove, Mr. Francisco J. Martinez and Mr. Jackson Robinson served as directors until May 5, 2020, and were Chair of the Board of Directors, Chair of the Nominating and Corporate Governance Committee, Chair of the Audit Committee, and Chair of the Compensation Committee, respectively, until such date. Mr. Andrea Brentan was a director until May 5, 2020.

Except for Santiago Seage, all directors served only part of 2020. None of the directors received any pension entitlement and/or taxable benefits in 2020 or 2019. Only directors who received remuneration are included in the table above. Non-independent, non-executive directors were entitled, following the Annual General Meeting held on May 5, 2020, to the same compensation as independent non-executive directors, but declined any compensation. In 2019, non-independent, non-executive directors were not entitled to receive compensation.
In June 2020, one-third of the CEO’s one-off plan share units vested and were paid in cash in accordance with the terms of the plan using the share price at the date of vesting (June 20, 2020). The cash payment has been included in the Single Total Figure of Remuneration table above.

| One-Third of Restricted Stock Units (RSUs) |  |  | Price on Vesting Date |  | Total Cash Payment ($ thousand)
One-Off Plan | 14,535 |  | $ | 27.97 |  | 430.3

In addition, on June 20, 2020, one-third of the CEO’s share options awarded under the LTIP vested. These options were not exercised, hence not paid. The vested options have been included in the Single Total Figure of Remuneration table above, valued at the share price on the vesting date.
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LTIP |  | One- Third of Share Options |  |  | Price on Vesting Date |  |  | LTIP Exercise Price per Option |  | Amount Vested ($ thousand) |
2019 |  | 40,693 |  |  | $ | 27.97 |  |  | $ | 19,60 |  |  |  | 340.7 |

Each member of our Board of Directors will be indemnified for his or her actions associated with being a director to the extent permitted by law.
In 2020, most of the objectives defined for the Chief Executive Officer's variable bonus were met or exceeded and the Compensation Committee decided to approve a bonus corresponding to 102.7% of the target variable compensation, which will be payable in 2021.

| Percentage weight | Achievement
CAFD (cash available for distribution) – Equal or higher than the CAFD budgeted in the 2020 budget | 40% | 96%
EBITDA– Equal or Higher than the EBITDA budgeted in the 2020 budget | 15% | 102%
Close accretive acquisitions for the Company | 20% | 110%
Achieve health and safety targets - (Frequency with Leave / Lost Time Index below 3.5 and General Frequency Index below 11.0) based on reliable targets and consistent measure metrics | 10% | 110.03%
Implement the succession plan | 15% | 100%

In 2019, most of the objectives defined for the Chief Executive Officer's variable bonus were met or exceeded and the Compensation Committee decided to approve a bonus corresponding to 100.7% of the target variable compensation, which was paid in 2020.
The Chief Executive Officer’s maximum potential bonus could be 120% of such bonus, approximately $1,164 thousand. No element of the Chief Executive Officer’s annual bonus is deferred.
Scheme interests awarded during 2020:

LTIP |  | Number of Restricted Stock Units |  | Number of Share Options |  | Face Value(*) ($ thousand) |  | Performance Criteria
2020 |  | 33,641 |  | 103,842 |  | $ | 1,180 |  | RSU: 5% minimum Total Shareholder Return Performance Stock Unit Share Options: Time-Based Vesting

Note:
(*) Face Value means the maximum number of shares that would vest if performance measures are met using the share price at the grant date. The face value for the Share Options are calculated using the Option price at the grant date.
In 2020, under the LTIP, 33,641 restricted stock units were awarded to the CEO, which will vest on the third anniversary of the grant date. In addition, 103,842 stock options were awarded, which vest one third per year, starting on the first anniversary of the grant date.
If the TSR performance condition has not been met during the vesting period, the participant's restricted stock units will lapse on the vesting date. The stock options are not subject to performance vesting.
A description of type of interest awarded and the basis on which the award is made is provided in the Remuneration Policy section below.
Total Shareholder Return and Chief Executive Officer Pay
The chart below shows the Company’s total shareholder return since June 2014, the date of our Initial Public Offering (“IPO”), until the end of 2020 compared with the total shareholder return of the companies in the Russell 2000 Index. The chart represents the progression of the return, including investment, starting from the time of the IPO at a 100%-point. In addition, dividends are assumed to have been re-invested at the closing price of each dividend payment date.
We believe the Russell 2000 Index is an adequate benchmark as it represents a broad range of companies of similar size.
Total shareholders return (TSR) is calculated in U.S. dollars.
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The table below shows the total remuneration of the Chief Executive Officer, his bonus and his long-term incentive awards expressed as a percentage of the maximum he is likely to be awarded.

|  |  |  |  | Bonus |  |  | LTIP awards(1) |
|  | (In thousands of U.S. Dollars) |
Year |  | Total Pay |  |  | Percentage of target |  |  | Amount of Bonus(3) |  |  | Percentage of maximum |  |  | Value |
2020 |  |  | 2,524.1 |  |  |  | 102.7 | % |  |  | 996.4 |  |  |  | 100 | % |  |  | 770.9 |
2019 |  |  | 1,685.4 |  |  |  | 100.7 | % |  |  | 957.7 |  |  |  | - |  |  |  | - |
2018 |  |  | 2,511.1 |  |  |  | 101.8 | % |  |  | 992.2 |  |  |  | 21.95 | % |  |  | 751.1 |
2017 |  |  | 1,602.0 |  |  |  | 96.25 | % |  |  | 924.2 |  |  |  | - |  |  |  | - |
2016 |  |  | 1,499.4 |  |  |  | 100 | % |  |  | 940.5 |  |  |  | - |  |  |  | - |
2015 |  |  | 1,597.6 | (2) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
2014 |  |  | 174.1 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |

Notes:

| (1) | Long-Term Incentive Awards includes LTIP and Special One-Off Plan

| (2) | Includes €1,189.50 thousand (approximately $1,319.6 thousand) termination payment received by Mr. Garoz after leaving the Company in November 25, 2015.

| (3) | Amount of bonus accrued by the Company at year-end and paid the next year. For example: In 2019, the Company accrued $957.7 thousand of the bonus paid to the Chief Executive Officer in 2020.

The Chief Executive Officer did not receive any variable remuneration for service provided to the Company for the years ended December 31, 2015 and 2014. Santiago Seage occupied that office between January and May 2015, and again since late November 2015. Meanwhile, Mr. Garoz held that position between May and November 2015, when he left the Company.
Chief Executive Officer Director’s and Employee’s Pay
The table below sets out the percentage change between 2019 and 2020 in salary, bonus and long-term incentive awards for independent non-executive directors, executive director, and the average per capita change for employees of the Group as a whole, excluding the Chief Executive Officer.
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|  | 2020 |
Name |  | Salary |  |  | Bonus |  |  | Long-Term Incentive Awards(1) |
Independent, non-executive directors |  |  |  |  |  |  |  |  |
William Aziz(2) |  |  | n/a |  |  |  | n/a |  |  |  | n/a |
Debora Del Favero(2) |  |  | n/a |  |  |  | n/a |  |  |  | n/a |
Brenda Eprile(2) |  |  | n/a |  |  |  | n/a |  |  |  | n/a |
Michael Forsayeth(2) |  |  | n/a |  |  |  | n/a |  |  |  | n/a |
Michael Woollcombe(2) |  |  | n/a |  |  |  | n/a |  |  |  | n/a |
Andrea Brentan(3) |  |  | 3 | % |  |  | n/a |  |  |  | n/a |
Robert Dove(3) |  |  | 3 | % |  |  | n/a |  |  |  | n/a |
Francisco J. Martinez(3) |  |  | 3 | % |  |  | n/a |  |  |  | n/a |
Jackson Robinson(3) |  |  | 3 | % |  |  | n/a |  |  |  | n/a |
Daniel Villalba(3) |  |  | 3 | % |  |  | n/a |  |  |  | n/a |
Executive director |  |  |  |  |  |  |  |  |  |  |  |
Santiago Seage (CEO) |  |  | 2 | %(5) |  |  | 2 | %(5) |  |  | n/a | (6)
Employees (excluding CEO) (4) |  |  | 5 | % |  |  | 8 | % |  |  | n/a | (6)

Notes:
This is the first year in which this reporting requirement is applicable for the Company. Over subsequent years this will build up to a rolling five-year period. Except for Santiago Seage, all directors served only part of 2020 (see Directors’ Report). None of the directors received any pension entitlement and/or taxable benefits in 2020 or 2019. Only directors who received remuneration are included in the table above.
n/a: Non-applicable
(1) Long-term Incentive Awards includes Long-term Incentive Plan (LTIP) and Special One-Off Plan.
(2) Mr. William Aziz, Mrs. Debora Del Favero, Mrs. Brenda Eprile, Mr. Michael Forsayeth and Mr. Michael Woollcombe joined the Board of Directors on May 5, 2020 as independent non-executive Directors, hence there is no percentage change between 2019 and 2020.
(3) Mr. Daniel Villalba, Mr. Robert Dove, Mr. Francisco J. Martinez and Mr. Jackson Robinson were directors until May 5, 2020, and were Chair of the Board of Directors, Chair of the Nominating and Corporate Governance Committee, Chair of the Audit Committee, and Chair of the Compensation Committee, respectively, until such date. Their percentage of salary change has been calculated on a full-time equivalent basis, hence based on their total remuneration received in 2019 compared to their 2020 entitled compensation as shown in the Single Total Figure of Remuneration section.
(4) The salary and bonus percentage change for employees (excluding the CEO) has been calculated considering the same average number of employees and the same average exchange rate in both 2020 and 2019. This is the most appropriate methodology to reflect how much the salary and potential bonus changed on a year-to-year basis as it excludes the effect of employee hires and turnover.
(6) The Compensation Committee approved a (i) fixed remuneration of €663 thousand ($757 thousand) for the Chief Executive Officer for 2020 compared to €650 thousand ($728 thousand) for 2019, representing a 2% increase in Euros on a year-to-year basis and (ii) variable remuneration of €873 thousand ($996 thousand) for 2020 compared to €856 thousand ($958 thousand) for 2019, representing a 2% increase in Euros on a year-to-year basis. .
(5) In 2019 no amount vested under long-term incentive awards for the CEO or Management.
Relative Importance of Spend on Pay
The following table sets out the change in overall employee costs, directors’ compensation and dividends.

$ in million |  | Amount in 2020 |  |  | Amount in 2019 |  |  | Difference |
Spend on pay for all employees(*) |  |  | 54.5 |  |  |  | 32.2 |  |  |  | 22.3 |
Total remuneration of Directors |  |  | 3.4 |  |  |  | 2.5 |  |  |  | 0.9 |
Dividends paid |  |  | 168.8 |  |  |  | 159.0 |  |  |  | 9.8 |

(*) 2019 Spend on Pay for All Employees has been revised to include wages and salaries, social security costs and other staff costs (see Note 24 to our Annual Consolidated Financial Statements).
The Company has not made any share repurchases during 2020 nor 2019.
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The average number of employees in 2020 in Atlantica was 441 employees, compared to 306 employees in 2019. The $22.3 million increase in spend on pay and the increase in the average number of employees is mostly due to the acquisition of ASI Operations in August 2019. This subsidiary, that performs the operation and maintenance services to the Solana and Mojave plants, added 199 new employees. 2020 was the first complete year with these U.S. employees in our workforce.
The $0.9 million increase in total remuneration of directors is mainly due to the vesting in June 2020 of one-third of the CEO’s One-Off Plan and one third of his share options awarded under the LTIP. No units or shares vested in 2019 under our LTIP.
Statement of Implementation of Policy in 2020
The targets for bonusses are detailed under the “Remuneration Policy”. The current policy was approved at our 2020 Annual General Meeting, held in May 2020.
For 2021, the bonus measures for the remuneration of the Chief Executive Officer, will focus on four areas: financial targets, value creating growth/investment, health and safety and management of relationships with key shareholders and partners.
This approach is intended to provide a balanced assessment on how the business has performed over the course of the year against stated objectives. Targets are aligned with the annual plan and strategic and operational priorities for the year.
For 2021 the bonus objectives are:

| Percentage weight
CAFD (cash available for distribution) – Equal or higher than the CAFD budgeted in the 2021 budget | 40%
EBITDA– Equal or Higher than the EBITDA budgeted in the 2021 budget | 15%
Close accretive acquisitions for the Company | 20%
Achieve health and safety targets - (Frequency with Leave / Lost Time Index below 3.5 and General frequency index below 10.0) based on reliable targets and consistent measure metrics | 10%
Management of relationships with key shareholders and partners | 15%

Remuneration Policy
The current policy was approved at our 2020 Annual General Meeting, held in May 2020. Shareholders will be asked to approve the remuneration policy at our 2021 Annual General Meeting to be held in May 2021.
Changes to the current remuneration policy:

| a) | Share Ownership Requirements

On February 26, 2021, the Board approved a share ownership requirement applicable to directors receiving remuneration from the Company and executives (see the Directors’ Shareholdings section). Within a period of five years, directors receiving remuneration from the Company should have a minimum share ownership in the Company of 3 times their annual compensation. In the case of the CEO, this requirement is 6 times his fixed compensation.

| b) | Deferred Restricted Share Unit Plan (DRSU Plan) for Non-Executive Directors

The Company is seeking shareholder approval to establish a DRSU Plan for non-executive directors to promote a greater alignment of interests between directors and shareholders, by providing a means for directors to accumulate a financial interest in the Company and to enhance Atlantica’s ability to attract and retain qualified individuals with the experience and ability to serve as directors. Pursuant to the plan, on an annual basis and prior to commencement of the remuneration period, the Company shall determine the amount or percentage of the director’s annual fee payable through DRSUs.
The number of DRSUs credited to a participant’s account is determined by dividing the amount of the annual compensation to be received in DRSUs by the market value of the ordinary shares. Upon a participant ceasing to be a member of the Board, for any reason whether voluntary or involuntary, the DRSUs will vest. The Company shall transfer to the director a number of shares equal to the number of vested DRSUs and a number of shares equal in value to any dividends which would have been paid or payable on such number of ordinary shares equal to the vested DRSUs from the grant date until the vesting date. The director shall not have any shareholders’ rights other than the dividend equivalent rights until the DRSUs vest and are settled by the issuance of shares.
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| c) | Clawback Policy

The Company is seeking shareholder approval to implement an incentive compensation recoupment, or clawback policy. The policy is aimed at allowing the Company to recover performance-based compensation for three years after short-term variable compensation and/or long-term compensation awards are granted. The clawback policy is applicable from 2021 to all executives who participate in long term incentive arrangements.
The clawback policy is applicable in the event of the occurrence of either of the following triggering events: material financial restatement, including a restatement resulting from employee misconduct, or in the case of fraud, embezzlement or other serious misconduct that is materially detrimental to the Company. The Compensation Committee shall retain discretion regarding application of the policy. The policy is incremental to other remedies that are available to the Company.
If a triggering event occurs, unless otherwise determined by the Compensation Committee and/or if the Company is required to prepare a material restatement of its financial statements as a result of misconduct, and the Compensation Committee determines that the executive knowingly engaged in the misconduct or acted knowingly or with gross negligence in failing to prevent the misconduct, or the Compensation Committee concludes that the participant engaged in fraud, embezzlement or other similar activity (including acts of omission) that the Compensation Committee considers was materially detrimental to the Company, the Company may require the participant (or the participant’s beneficiary) to reimburse the Company for, or forfeit all, or any portion of any short or long term variable compensation awards.
The application of this clawback policy to our CEO is a change to our remuneration policy approved by the Compensation Committee.

| d) | Stock Units

The Company is seeking shareholder approval to modify the Long Term Incentive Plan so that awards are granted as restricted stock units only. Prior to the 2021 Annual General Meeting, awards under the LTIP have been granted in restricted stock units representing 75% of the Award Value and share options representing 25% of the Award Value. If shareholder approval is obtained for the amendment of the Long Term Incentive Plan, awards will be granted as restricted stock units, and the restricted stock units will be granted with the same vesting conditions as they are currently: units vest on the third anniversary of the grant date, subject to an annual TSR of at least a 5% yearly average over such 3-year period.
The current remuneration policy is as follows:
Non-Executive Directors:
For non-executive directors, independent and non-independent directors, the Company’s policy is to compensate in cash for the time dedicated, subject to a maximum total annual compensation for non-executive directors in aggregate of two million dollars. Once a year, the Compensation Committee reviews compensation practices for non-executive directors in similar companies and the skills and experience required and may propose an adjustment in the current compensation.
None of the non-executive directors receive bonuses, long-term incentive awards, pension or other benefits in respect of their services to the Company.
Executive Directors:
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The policy for executive directors, only applicable to the Chief Executive Officer as the only executive director, is as follows:

Name of Component |  | Description of Component |  | How Does This Component Support the Company’s (or Group’s) Short and Long-Term Objectives? |  | What is the Maximum That May Be Paid in Respect of The Component? |  | Framework Used to Assess Performance
Salary/fees |  | Fixed remuneration payable monthly. |  | Helps to recruit and retain executive directors and forms the basis of a competitive remuneration package. |  | Maximum amount €800 thousand (approximately $976 thousand), may be increased by 5% per year Salary levels for peers are considered. |  | Not applicable. No retention or clawback.
Benefits |  | Opportunity to join existing plans for employees but without any increase in remuneration. |
Annual Bonus |  | Annual bonus is paid following the end of the financial year for performance over the year. There are no retention or forfeiture provisions. |  | Helps to offer a competitive remuneration package and align it with the company’s objectives. |  | 200% of base salary. |  | 40%-50% of CAFD. 10%-15% of EBITDA. 40%-50% of other operational or qualitative objectives. No retention. Clawback policy.
Long Term Incentive Awards |  | Restricted stock units subject to certain vesting periods and minimum TSR. |  | Align executive directors and shareholders interests. |  | 70% of target annual salary + bonus. Special one-off plan in 2019 for 50% of 2019 salary + bonus. |  | Granted as restricted stock units subject to 5% average annual TSR. If the TSR performance condition has not been met during the vesting period, the participant's restricted stock units will lapse on the vesting date. Share units. Clawback policy.

CAFD, EBITDA and TSR have been selected as key parameters to measure company’s performance due to their importance for our shareholders. These measures are considered standard indicators of financial performance in our sector.
Long-Term Incentive Awards
In April 2018, the Board of Directors approved the implementation of a new remuneration policy including LTIP awards. The long-term incentive plan permits the grant of share options and restricted stock units to the executive team of the Company. The LTIP applies to approximately 13 executives and the Board of Directors also proposed to include the Chief Executive Officer, who is also a director. The Chief Executive Officer’s participation in the LTIP was approved by shareholders at the 2019 Annual General Meeting in June 2019.
The purpose of this LTIP is to attract and retain the best talent for positions of substantial responsibility in the Company, to encourage ownership in the Company by the executive team whose long-term service the Company considers essential to its continued progress and, thereby, encourage recipients to act in the shareholders’ interest and to promote the success of the Company.
The long-term incentive plan permits the granting of restricted stock units (“Awards”) to the executive team of the Company (the “Executives”). The LTIP applies to approximately 13 Executives and the Chief Executive Officer.
The aggregate number of shares which may be reserved for issuance under the LTIP must not exceed 2% of the number of the shares outstanding at the time of the Awards are granted but is expected to be significantly less. In addition, total equity-based awards will be limited to 10% of the Company's issued share capital over a 10-year rolling period, in order to assure shareholders that dilution will remain within a reasonable range. In any case, the Compensation Committee may decide that, instead of issuing or transferring shares, the Executives may be paid in cash.
The value of the Awards will be defined as 50% of the Executives’ total annual compensation for the year closed before the date upon which an Award is granted and, in the case of the Chief Executive Officer, would be 70% of the same previous year total annual compensation at the grant date (in each case, "Award Value"). The award will be granted in restricted stock units.
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Main terms of the LTIP

| Restricted Stock Units
Nature | Conditions shall be based on continuing employment (or other service relationship) and achievement of a minimum 5% average annual TSR.
Exercisability and vesting period | The shares will vest on the third anniversary of the grant date but only if the annual TSR has been at least a 5% yearly average over such 3-year period. If the TSR has not met such threshold during the period, the participant's relevant restricted stock units will lapse on the vesting date. The Company will decide at vesting if cash or shares are given as payment.
Ownership and dividends | The participant will be entitled to receive, for each restricted stock unit held, a payment equivalent to the amount of any dividend or distribution paid on one share between the grant date and the date on which the restricted stock unit vests.

If a participant’s employment terminates by reason of involuntary termination (death, disability, redundancy, constructive dismissal or retirement dismissal rendered unfair), any portion of his/her Award shall thereafter continue to vest and become exercisable according to the terms of the LTIP but such participant shall no longer be entitled to be granted Awards under the LTIP.
If a participant incurs a termination of employment for cause or voluntary resignation or withdrawal, share options that have vested at the termination date will be exercisable within the period of 30 days from such termination date (after which they will lapse) but any unvested Awards (options or restricted stock units) shall lapse.
If there is a change of control, all Awards shall vest in full on the date of the change in control. The participants must exercise their share options within a period of 30 days following receipt of a change of control notice from the Company without which, the options will lapse.
If the Company is delisted, all outstanding Awards shall vest in full on the date of delisting and will be settled in cash. The cash payment for restricted stock units will be the last quoted share price of the Company and the cash payment for any outstanding share options will be the difference between the last quoted share price and the exercise price for the applicable option. Such cash payments will be made after applicable tax deductions within 30 days of the delisting.
There is a special one-off plan in-place that grants stock units to certain members of the management and certain members of the middle management, consisting of approximately 25 managers including the Chief Executive Officer. The value of the award was defined as 50% of 2019 target remuneration (including salary and variable bonus). The share units vest over 3 years, one third each year starting in 2020, provided that the manager is still an employee of the company. This was approved by shareholders at the 2019 Annual General Meeting. Middle Management consists of employees who: (i) manage a specific area, (ii) supervise a group of employees, or (iii) are considered key personnel within the organization.
The executive director does not receive any pension contributions.
None of the non-executive directors receive bonuses, long-term incentive awards, pension or other benefits in respect of their services to the Company.
There are no provisions for the recovery of sums paid or the withholding of any sum, except for those potentially derived from the application of the clawback provision. The clawback policy is a change to the current remuneration policy, hence subject to approval at our 2021 Annual General Meeting to be held in May 2021.
Chief Executive Officer Remuneration Policy
The Compensation Committee approved a fixed remuneration of $838 thousand for the Chief Executive Officer for 2021, a 4% increase versus 2020.
Total remuneration of the only executive director for a minimum, target and maximum performance in 2021 is presented in the chart below.
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* Minimum, target and maximum performance has been converted to U.S. dollars for presentation purposes, at the exchange rate as of February 23, 2021, which was 1.22 $/€.
Assumptions made for each scenario are as follows:

| ◾ | Minimum: | fixed remuneration only, assuming performance targets are not met for the annual bonus nor for the DRSU and assuming no value for the options vesting in the year.
| ◾ | Target: | fixed remuneration, plus half of target annual bonus and LTIP and one-off plans vesting in 2021 at face value, using share price at grant date for units and option value at grant date for options.
| ◾ | Maximum: | fixed remuneration, plus maximum annual bonus and LTIP and one-off plans vesting in 2021 at face value, using share price at grant date for units and option value at grant date for options.

In addition, if we assume a 50% appreciation of the share price with respect to the grant date, maximum remuneration for 2021 including vesting long-term awards would be approximately $ 3,059 thousand.
For 2021, the bonus measures for the remuneration of the Chief Executive Officer, will focus on four areas: financial targets, value creating growth/investments, health and safety and management of relationships with key shareholders and partners.
This approach is intended to provide a balanced assessment of how the business has performed over the course of the year against stated objectives. Targets are aligned with the annual plan and strategic and operational priorities for the year.
Summary of Policy for Non-Executive Directors

Name of component | How does the Component Support the Company’s Objective? | Operation | Maximum
Fees and/or Deferred Restricted Share Units (DRSU) | Attract and retain the high-performing independent non-executive directors. Align interests of non-executive independent directors with interests of shareholders. | Reviewed annually by the Compensation Committee and Board. The lead independent director/chair of the Board and the chair of each committee receive additional fees. | Annual total compensation for -independent non-executive directors, in any case, the fees or DRSUs will not exceed two million dollars.
Benefits | Reasonable travel expenses to the Company’s registered office or venues for meetings. | Customary control procedures. | Real costs of travel with a maximum of one million dollars for all directors.

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Non-independent, non-executive directors are entitled, following the Annual General Meeting held on May 5, 2020, to the same compensation as independent non-executive directors.
Key Management Compensation for 2021

$ thousand |  | 2020 |  |  | 2019 |
Short-term employee benefits |  |  | 4,792.5 |  |  |  | 4,494.6 |
LTIP Awards |  |  | 1,349.1 |  |  |  | - |
Post-employment benefits |  |  | - |  |  |  | - |
Other long-term benefits |  |  | - |  |  |  | - |
Termination benefits |  |  | - |  |  |  | - |
Share-based payment |  |  | - |  |  |  | - |
Total |  |  | 6,141.6 |  |  |  | 4,494.6 |

Key management includes Directors, Chief Executive Officer, CFO and 5 key executives. Short-term employee benefits to management are paid in Euros and have been converted to US$ using the average foreign exchange rate for each period.
“LTIP Awards” include one third of the one-off plan share units which vested in 2020 and were paid and one-third of the share options awarded under the LTIP which vested in 2020, irrespectively if the options were exercised or not by the executive. The vested options have been included in the remuneration table above valued using the share price at the vesting date.
Directors’ Shareholding
The following table includes information with respect to beneficial ownership of our ordinary shares as of December 31, 2020 and by each of our current directors and executive officers as well as their connected persons.
Directors not included in the table below do not hold shares and are not required to comply with minimum share ownership requirements as they do not receive remuneration from the Company.

|  | Shares |  | Share Units(1) |  | Investment Value $ in thousands(2) |  | Minimum Share Ownership Requirements |  | Compliance with Policy(3)
Santiago Seage |  |  | 20,000 |  | 109,700 |  |  | 4,926 |  | 6 times fixed compensation |  | ✔
William Aziz |  |  | 2,500 |  |  |  |  | 95 |  | 3 times annual compensation |  | On track
Brenda Eprile |  |  | 2,500 |  |  |  |  | 95 |  | 3 times annual compensation |  | On track
Michael Forsayeth |  |  | 1,600 |  |  |  |  | 61 |  | 3 times annual compensation |  | On track
Michael Woollcombe |  |  | - |  |  |  |  | - |  | 3 times annual compensation |  | On track
Debora Del Favero |  |  | - |  |  |  |  | - |  | 3 times annual compensation |  | On track

Notes:

| (1) | Includes vested and non-vested Share Units as of December 31, 2020. LTIP share units subject to 5% minimum Total Shareholder Return Performance Stock Unit.

| (2) | Assuming a share price of $37.98 as of December 31, 2020.

| (3) | 5-year window to comply with this policy.

C. | Board Practices

Our Board of Directors consists of eight directors, five of whom are independent. Under our articles of association, our board may consist of 7 to 13 members. All the Board Committees are formed exclusively by independent directors. Additionally, our articles of association established an office term of up to 3 years or lower, as decided by the Board. In December 2020, the Board decided to establish a 1-year office term for all the directors. After this period, our board members are eligible for reelection by the Annual General Meeting.
Directors will not vote on matters that represent or could represent a conflict of interests. Directors affiliated with Algonquin do not vote on matters that represent or could represent a conflict of interests, including the evaluation of assets offered to us under the AAGES and Algonquin ROFO Agreements. See “Item 7.B—Related Party Transactions—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest.”
Our Board of Directors is responsible for, among other things, overseeing the conduct of our business; reviewing and, where appropriate, approving, our long-term strategic, financial and organizational goals and plans; and reviewing the performance of our chief executive officer and other members of senior management.
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Under English law, the Board of Directors of an English company is responsible for the management, administration and representation of all matters concerning the relevant business, subject to the company’s corporate constitution. Under English law and our constitution, the Board of Directors may delegate its powers to an executive committee or other delegated committee or to one or more persons.
None of our non-executive directors have service contracts with us or any of our businesses providing for benefits upon termination of employment.
Audit Committee
Our Audit Committee is responsible for monitoring and informing the Board of Directors on the work of external and internal auditors, control systems, key processes and procedures, security and risks. The committee comprises the following three members, each of whom is an independent director:

Name |  | Position
Brenda Eprile |  | Chair
William Aziz |  | Member
Michael Forsayeth |  | Member

The committee will meet as many times as required and a minimum of two times per year.
Our Audit Committee is directly responsible for overseeing the work of the external auditor engaged for the purpose of preparing or issuing an auditor’s report or performing other audit, review or attest services, including the resolution of disagreements between the external auditor and management. The external auditor will report directly to our Audit Committee. Our Audit Committee is also responsible for reviewing and approving our hiring policies regarding former employees of the external auditor. In addition, the Audit Committee preapproves all non-audit services undertaken by the external auditor.
Our Audit Committee is responsible for reviewing the adequacy and security of procedures for the confidential, anonymous submission by our employees or contractors regarding any possible wrongdoing in financial reporting or other matters. Our Audit Committee is accountable to our Board of directors and will provide a report to our Board of directors after each regularly scheduled Audit Committee meeting outlining the results of the Audit Committee’s activities and proceedings.
Nominating and Corporate Governance Committee
Our Nominating and Corporate Governance Committee comprises the following two members, each of whom is an independent director.

Name |  | Position
Debora Del Favero |  | Chair
Michael Forsayeth |  | Member

The duties and functions of our Nominating and Corporate Governance Committee include, among others, regularly reviewing the structure, size and composition (including the skills, knowledge, experience and diversity) of the board of directors and make recommendations to the Board of Directors with regard to any changes, and keep under review corporate governance rules and developments (including ethics-related matters) that might affect us, with the aim of ensuring that our corporate governance policies and practices continue to be in line with best practices. Our Nominating and Corporate Governance Committee meets at least twice a year at appropriate intervals in the financial reporting and audit cycle and otherwise as required. The committee informs and makes proposals to the board of directors.
Compensation Committee
Our Compensation Committee comprises the following two members, each of whom is an independent director.

Name |  | Position
William Aziz |  | Chair
Debora Del Favero |  | Member

The duties and functions of our Compensation Committee include, among others, analyze, discuss and make recommendations to the Board of Directors regarding the setting of the remuneration policy for all directors as well as senior management, including pension rights and any compensation. The committee meets at least twice a year at appropriate intervals in the financial reporting and audit cycle and otherwise as required. The committee informs and makes proposals to the Board of Directors.
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Related Party Transactions Committee
Our Related Party Transactions Committee comprises the following three members, each of whom is an independent director:

Name |  | Position
Michael Forsayeth |  | Chair
William Aziz |  | Member
Brenda Eprile |  | Member

The duties and functions of our Related Party Transactions Committee include, among others, evaluating on an ongoing basis existing relationships between and among businesses and counterparties to ensure that all related parties are identified, monitoring related-party transactions, identifying changes in relationships with counterparties and overseeing the implementation of a system for identifying, monitoring and reporting related-party transactions, including a periodic review of such transactions, applicable policies and procedures.
The Related Party Transactions Committee shall meet at such times as required and where it considers appropriate. The Related Party Transactions Committee will report to the Board of Directors on the decisions and recommendations made by the committee, including but not limited to any conflict of interest and any procedure to manage such conflict of interest.
Special Committee
On February 13, 2019, we announced that our Board of Directors had formed a strategic review committee with the purpose of evaluating a wide range of strategic alternatives available to us to optimize our value and to improve returns to shareholders. The role of the strategic review committee was subsumed by a special committee of the Board formed in September 2019. On March 23, 2020 we announced that our special committee concluded the review of the strategic alternatives by reaffirming our current strategy and the Special Committee was terminated.

D. | Employees

The following table shows the number of employees as of December 31, 2020, 2019 and 2018, on a consolidated basis:

|  | Year ended December 31, |
Geography |  | 2020 |  |  | 2019 |  |  | 2018 |
EMEA |  |  | 55 |  |  |  | 50 |  |  |  | 53 |
North America |  |  | 243 |  |  |  | 229 |  |  |  | 31 |
South America |  |  | 51 |  |  |  | 43 |  |  |  | 37 |
Corporate |  |  | 107 |  |  |  | 103 |  |  |  | 96 |
Total |  |  | 456 |  |  |  | 425 |  |  |  | 217 |

The increase in the number of employees for the year ended December 31, 2020 as compared to the year ended December 31, 2019 is mainly due to the reinforcement of our North American structure following the acquisition of ASI Operations in 2019.

E. | Share Ownership

None of our directors or members of our senior management is the owner of more than one percent of our ordinary shares, and no director or member of our senior management has voting rights with respect to our ordinary shares that are different from any other holder of our ordinary shares.
On February 26, 2021, the Board of Directors adopted minimum share ownership guidelines for directors receiving remuneration from the Company and for the executives participating in the LTIP to further align, executive and shareholder interests. Directors and executives subject to these guidelines shall achieve, within a period of five years, a minimum share ownership in the Company. In calculating the value of shares owned, shares that are issuable pursuant to the LTIP and Deferred Restricted Shares Units Plan (DRSU) vested and non-vested, are counted. Directors receiving remuneration and executives participating in the LTIP shall achieve a minimum share ownership in the Company equal in value to:

- | Directors receiving remuneration from the Company: 3 times their annual compensation;

- | CEO: 6 times his fixed compensation;

- | CFO: 3 times his fixed compensation;

- | Other executives: 2 times their fixed compensation.

The directors receiving remuneration from the Company and executives have a 2-year window to amend non-compliances with minimum share ownership requirements derived from a stock price decrease.
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The Directors not receiving remuneration from the Company are not required to comply with minimum share ownership requirements.

ITEM 7. | MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A. | Major Shareholders

The following table sets forth information with respect to beneficial ownership of our ordinary shares as of the date of this annual report by:

| • | each of our directors and executive officers;

| • | our directors and executive officers as a group; and

| • | each person known to us to beneficially own 5% and more of our ordinary shares.

Beneficial ownership is determined in accordance with the rules and regulations of the SEC. It includes the sole or shared power to direct the voting or the disposition of the securities or to receive the economic benefit of the ownership of the securities. In computing the number of shares beneficially owned by a person and the percentage ownership of that person, we have included shares that the person has the right to acquire within 60 days of this annual report, including through the exercise of any option or other right and the vesting of restricted shares. These shares, however, are not included in the computation of the percentage ownership of any other person. The calculations of percentage ownership in the table below is based on 110,691,722 ordinary shares outstanding as of the date of this annual report.

Name |  | Ordinary Shares Beneficially Owned |  |  | Percentage |
Directors and Officers |  |  |  |  |  |
Santiago Seage |  |  | 20,000 |  |  |  | - |
William Aziz |  |  | 2,500 |  |  |  | - |
Brenda Eprile |  |  | 2,500 |  |  |  | - |
Michael Forsayeth |  |  | 1,600 |  |  |  | - |
Michael Woollcombe |  |  | - |  |  |  | - |
Debora Del Favero |  |  | - |  |  |  | - |
5% Beneficial Owners |  |  |  |  |  |  |  |
Algonquin (AY Holdco) B.V. (1) |  |  | 48,962,925 |  |  |  | 44.2 | %
Morgan Stanley (2) |  |  | 5,918,853 |  |  |  | 5.5 | %
BlackRock Inc.(3) |  |  | 5,864,325 |  |  |  | 5.5 | %

| (1) | This information is based solely on the Schedule 13D filed on January 7, 2021 by Algonquin Power & Utilities Corp., a corporation incorporated under the laws of Canada, Algonquin (AY Holdco) B.V., a corporation incorporated under the laws of the Netherlands, and AAGES (AY Holdings) B.V., a corporation incorporated under the laws of the Netherlands.

| (2) | This information is based solely on the Schedule 13G filed on February 10, 2021 by Morgan Stanley, corporation incorporated under the laws of Delaware. The registered address of Morgan Stanley is 1585 Broadway New York, NY 10036.

| (3) | This information is based solely on the Schedule 13G filed on February 2, 2021 by BlackRock Inc., a corporation incorporated under the laws of Delaware. The registered address of BlacRock is 55 East 52nd Street, New York, NY 10055.

As of December 31, 2020, the CEO holds 109,700 units convertible into shares in the future and 225,562 options under the LTIP and the one-off plan.
We have one class of ordinary shares, and each holder of our ordinary shares is entitled to one vote per share.
As of the date of this annual report, 110,691,722 of our ordinary shares were outstanding. Because some of our ordinary shares are held by brokers and other nominees, the number of shares held by and the number of beneficial holders with addresses in the United States is not fully ascertainable. As of the date of this annual report, to the best of our knowledge, one of our shareholders of record was located in the United States and held in the aggregate 103,286,415 ordinary shares representing approximately 93.3% of our outstanding shares. However, the United States shareholders of record include Cede & Co., which, as nominee for The Depositary Trust Company, is the record holder of all such ordinary shares. Accordingly, we believe that the shares held by Cede & Co. include ordinary shares beneficially owned by both United States and non-United States beneficial owners. As a result, these numbers may not accurately represent the number of beneficial owners in the United States.
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B. | Related Party Transactions

Arrangements for Change in Control of the Company
On March 9, 2018, Algonquin completed an acquisition of a 25.0% stake in us from Abengoa with the option to acquire the remaining 16.5% stake. On November 27, 2018, Algonquin announced that they had completed the purchase of a 16.5% equity interest in Atlantica from Abengoa. Following this purchase, Abengoa no longer had an equity interest in Atlantica. On May 9, 2019, Algonquin, AAGES and the Company entered into the Enhanced Cooperation Agreement, and Algonquin and the Company entered into a subscription agreement pursuant to which, among other things, the Company agreed to permit Algonquin to acquire, and Algonquin agreed to purchase, 1,384,402 ordinary shares, representing approximately 1.4% of the issued and outstanding ordinary shares. On May 22, 2019, Algonquin announced that they had completed the purchase of the 1.4% stake. After giving effect to such purchase, Algonquin was the beneficial owner of 42,942,065 ordinary shares, representing approximately 42.3% of the issued and outstanding ordinary shares. On May 31, 2019, AAGES (AY Holdings) B.V. entered into an accelerated share purchase transaction with Morgan Stanley & Co. LLC, pursuant to which on the same date AAGES acquired 2,000,000 ordinary shares for a total price of $53,750,000. On December 11, 2020 Atlantica closed an underwritten public offering of 5,069,200 ordinary shares (including those sold pursuant to the underwriters’ over-allotment option) at a price of $33 per new share. Additionally, Algonquin Power & Utilities Corp. purchased 4,020,860 ordinary shares of the Company in a private placement, which closed on January 7, 2021, which represents the pro-rata number of shares required to maintain their previous equity ownership in the Company. As a result, as of the date of this report Algonquin is the beneficial owner of 48,962,925 ordinary shares, representing 44.2% of the issued and outstanding ordinary shares.
Agreements with Current Shareholders
We entered into the AAGES ROFO Agreement and Algonquin ROFO Agreement with AAGES and Algonquin, respectively. In addition, Algonquin, AAGES and the Company entered into the Enhanced Cooperation Agreement, and Algonquin and the Company entered into the Subscription Agreement.
AAGES Right of First Offer
Pursuant to the AAGES ROFO Agreement, which we and AAGES entered into on March 5, 2018 and which became effective upon completion of the 25% Share Sale, AAGES granted us a right of first offer on any proposed sale, transfer or other disposition of the AAGES’ ROFO Assets.
If AAGES transfers interests in any AAGES ROFO Asset, then AAGES must require such transferee to acquire the AAGES ROFO Asset subject to our right of first offer except under certain circumstances summarized below. The AAGES ROFO Agreement has an initial term of ten years. AAGES ROFO Asset refers to the contracted assets or proposed contracted assets that we expect to evaluate for future acquisition, with certain exceptions, for which AAGES has provided us a right of first offer to purchase if offered for sale by AAGES.
Prior to engaging in any negotiation regarding any disposition, sale or other transfer of any asset, AAGES will deliver a written notice to us thereof, including a predefined set of information that is relevant for us to make a determination regarding the AAGES ROFO Asset, including the indicative price at which AAGES proposes to sell it to us. Once that information is received, a 60-day negotiation period will start. If an agreement is not reached, AAGES, during the following 30 months, may only sell, transfer, dispose or recontract such asset to a third party for an aggregate purchase price that is not less than 105% of the last purchase price we offered during the negotiation period for assets located outside Canada and the US. For U.S. or Canadian assets, the purchase price must not be less than 100% of the last purchase price we offered during the negotiation period.
Under the AAGES ROFO Agreement, AAGES is not obligated to sell any asset and, therefore, we do not know when, if ever, these assets will be offered to us. In addition, in some of the assets under the AAGES ROFO Agreement, AAGES may have equity partners with rights regulating divestitures by AAGES of its stake such as drag-along and tag-along clauses, and rights of first refusal, among others. We will consider and take into account all these clauses when deciding whether to present an offer.
Any material transaction between AAGES and us (including the proposed acquisition of any AAGES ROFO Asset) will be subject to our related party transactions policy, which will require prior approval of such transaction by the related party transactions committee, which is composed of independent directors. See “—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest,” “Item 3.D—Risk Factors—Risks Related to Our Relationship with Abengoa—We may not be able to consummate future acquisitions from AAGES, Algonquin or Abengoa” and “Item 3.D—Risk Factors.”
AAGES may enter into agreements with other companies with the objective of jointly developing the construction of new projects consisting of concessional assets which are included in AAGES’ current or future portfolio. Pursuant to the terms of the AAGES ROFO Agreement, AAGES may sell equity in these assets to third parties without being subject to the AAGES ROFO Agreement under certain circumstances in order to enhance the likelihood of success or financial prospects of such asset.
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Acquisition and investment in Colombia
In December 2020 we reached an agreement with Algonquin to acquire La Sierpe, a 20 MW solar asset in Colombia for a total equity investment of approximately $20 million. Closing is expected to occur after the asset reaches commercial operation, currently expected to occur by mid-2021. Closing is subject to customary conditions precedent and regulatory approvals. Additionally, we agreed to potentially co-invest with Algonquin in additional solar plants in Colombia with a combined capacity of approximately 30 MW to be developed and built by AAGES.
Algonquin Shareholders Agreement
In connection with the acquisition of 25.0% of our ordinary shares by Algonquin (indirectly through a subsidiary of AAGES), which completed in March 2018, we entered into a Shareholders Agreement with Algonquin and AAGES, which became effective upon completion of the 25% Share Sale. The Shareholders Agreement, among other things, sets forth certain rights and restrictions with respect to our ordinary shares, the main terms of which are summarized below.
On May 9, 2019, we signed a new enhanced collaboration agreement with Algonquin. Under this agreement, Atlantica had a right to acquire stakes or make investments in two Algonquin assets in the U.S., subject to the parties acting reasonably and in good faith agreeing price and terms of such transfers. Additionally, we agreed with Algonquin to analyze jointly during the next six months Algonquin’s contracted assets portfolio in the U.S. and Canada to identify assets where a drop down could add value for both parties, according to each company’s key metrics. After the analysis, the parties did not reach an agreement and therefore there was no consummation of any asset acquisition or investment in any asset.
Director Appointment Rights
The Shareholders Agreement provides that, if and to the extent provided in our articles, AAGES or Algonquin will have the right to appoint to our board the maximum number of directors that corresponds to AAGES’ and Algonquin’s holding of voting rights, as per articles of association but in any event no more than (i) such number of directors as corresponds to 41.5% of our voting securities; and (ii) 50% of our board less one, and if the resulting number is not a whole number, it shall be rounded up to the next whole number.
Furthermore, the Shareholders Agreement has been amended to allow Algonquin to increase its shareholding in Atlantica up to a 48.5% without any change in corporate governance. Algonquin’s voting rights and rights to appoint directors are still limited to a 41.5% and the additional shares (the difference between the actual shares beneficially owned by Algonquin and shares representing a 41.5% voting rights) will vote replicating non-Algonquin’s shareholder’s vote.
One of the directors appointed by AAGES and Algonquin holding in the aggregate at least 25.0% of our voting securities will have the right to be elected to any committee of our directors (except for the audit committee and related party transactions committee, and in those in which they are conflicted, or it is against the applicable law). In addition, so long as AAGES and Algonquin have the right to appoint a director and no such director is then serving on our Board of Directors, AAGES and Algonquin may appoint an observer to our Board of Directors and any committee thereof (except for the audit committee and related party transactions committee, and in those in which they are conflicted, or it is against the applicable law).
Dividends Distribution
We agreed that AAGES and Algonquin may terminate the Shareholders Agreement with respect to itself and its affiliates if, among others, our Board of Directors confirms a dividend payment objective that is lower than 80% of the cash available for distribution or our Board of Directors does not confirm any dividend payment objective at least once during any period of more than 14 consecutive months.
As of December 31, 2020, our dividend payout objective was 80%. This objective can be modified by our Board of Directors in the future.
Pre-emption rights
AAGES and Algonquin may subscribe in cash for (i) up to 100% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under the AAGES ROFO Agreement and Algonquin ROFO Agreement; and (ii) up to 66% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under the Abengoa ROFO Agreement. If we issue ordinary shares for any other purpose, AAGES and Algonquin may subscribe in cash for ordinary shares in the amount pro rata to such AAGES’ and Algonquin’s aggregate holding of voting rights.
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In addition, if AAGES and Algonquin elect to subscribe for at least 50% of an offering of our ordinary shares that will be listed, the price per ordinary share for all persons that participate in such offering will be equal to 97% of the USD volume-weighted average closing price per ordinary share on NASDAQ (or other applicable stock exchange) over the 20 trading days immediately preceding the date of AAGES’ and Algonquin’s receipt of notice of such proposed offering from us.
Standstill
Algonquin will not acquire any of our voting securities which may result in AAGES and Algonquin holding in the aggregate more than 48.5% of the total voting rights. The exercise of subscription rights as part of the Shareholders Agreement (as amended by the Enhanced Cooperation Agreement) further provides that in any case AAGES and Algonquin cannot acquire 48.5% or more of our voting securities or otherwise acquire control over us.
Also, AAGES and Algonquin will not be in breach of the standstill restriction if the shareholding of AAGES and Algonquin has increased in connection with our action to reduce the number of our outstanding shares.
Termination
The Shareholders Agreement will terminate if, among others, AAGES and Algonquin and/or their affiliates cease to hold in the aggregate at least 10% of the total voting rights attached to our voting securities. In addition, Shareholders Agreement could terminate if, among others, the (i) our articles are amended in a manner that adversely affects the rights of AAGES and Algonquin to appoint directors, as such rights exist under our articles as of the date of the Shareholders Agreement; or (ii) we give notice to AAGES and Algonquin if: (a)(with respect to Algonquin and its affiliates only) a change of control over Algonquin occurs; or (b)(with certain exceptions) on three occasions AAGES and Algonquin have not subscribed for our ordinary shares in the amount of at least its pro rata share, or have not fully paid for subscribed ordinary shares; or (c)(with respect to Algonquin only) if the Algonquin ROFO Agreement terminates other than in connection with its breach by us.
AYES Shareholder Agreement
On May 24, 2019, Atlantica and Algonquin formed AYES Canada, a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. AYES Canada’s first investment was in Amherst Island, a 75 MW wind plant in Canada owned by the project company Windlectric, Inc. (“Windlectric”). Atlantica invested $4.9 million and Algonquin invested $92.3 million, both through AYES Canada, which in turn invested those funds in Amherst Island Partnership, the holding company of Windlectric. Since Atlantica has control over AYES Canada under IFRS 10 “Consolidated Financial Statements”, its consolidated financial statements show a total investment in the Amherst Island project of $97.2 million, accounted for as “Investments carried under the equity method” (Note 7 of the 2020 Consolidated Financial Statements) and Algonquin’s portion of that investment of $92.3 million as “Non-controlling interest”. In addition, and under certain circumstances considered remote by both companies, Atlantica and Algonquin have options to convert shares of AYES Canada currently owned by Algonquin into Atlantica ordinary shares in exchange for a higher stake in the plant, subject to the provisions of the standstill and enhanced collaboration agreements with Algonquin.
Algonquin drop down agreement and Right of First Offer on assets outside the United States or Canada
Under the Algonquin ROFO Agreement, Algonquin agreed to periodically discuss with us the possibility of offering for sale interests in certain assets owned by Algonquin companies in Canada or the United States.
Pursuant to the Algonquin ROFO Agreement, which we and Algonquin entered into on March 5, 2018 and that became effective upon completion of the Share Sale, Algonquin granted us a right of first offer on any proposed sale, transfer or other disposition of any of their contracted facilities or infrastructure facilities located outside of the United States or Canada which are developed under expected long-term revenue agreements or concession agreements.
If Algonquin transfers interests in any asset under the Algonquin ROFO Agreement, then Algonquin must require such transferee to acquire any asset under the Algonquin ROFO Agreement subject to our right of first offer except under certain circumstances summarized below. The Algonquin ROFO Agreement has an initial term of ten years.
Prior to engaging in any negotiation regarding any disposition, sale or other transfer of any asset under the Algonquin ROFO Agreement, Algonquin will deliver a written notice to us thereof, including a set of predefined information that is relevant for us to make a determination regarding any asset under the Algonquin ROFO Agreement, including the indicative price at which Algonquin proposes to sell it to us. Once that information is received, a 60-day negotiation period will start. If an agreement is not reached, Algonquin, during the following 30 months, may only sell, transfer, dispose or recontract such asset under the Algonquin ROFO Agreement to a third party for an aggregate purchase price that is not less than 105% of the last purchaser price we offered during the negotiation period.
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Under the Algonquin ROFO Agreement, Algonquin is not obligated to sell any assets under the Algonquin ROFO Agreement and, therefore, we do not know when, if ever, these assets will be offered to us. In addition, in some of the assets under the Algonquin ROFO Agreement, Algonquin may have equity partners with rights regulating divestitures by Algonquin of its stake such as drag-along and tag-along clauses, and rights of first refusal, among others. We will consider and take into account all these clauses when deciding whether to present an offer.
Any material transaction between Algonquin and us (including the proposed acquisition of any asset under the Algonquin ROFO Agreement) will be subject to our related party transactions policy, which will require prior approval of such transactions by the related party transactions committee which is composed of independent directors. See “—Procedures for Review, Approval and Ratification of Related Party Transactions Policy; Conflicts of Interest,” “Item 3.D—Risk Factors—Risks Related to Our Relationship with Abengoa—We may not be able to consummate future acquisitions from AAGES, Algonquin or Abengoa” and “Item 3.D—Risk Factors.” In addition, Algonquin may terminate the Algonquin ROFO Agreement with us with a 180-day notice.
Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest
Our policy for the review, approval and ratification of related party transactions was updated and approved by the Board of Directors on February 28, 2018. Our policy requires that all transactions with related parties are subject to approval or ratification in accordance with the procedures set forth in the policy by the non-conflicted directors at the Board of Directors. With respect of any transaction with AAGES and Algonquin or its affiliates (other than our subsidiaries), including transactions pursuant to the ROFO agreements, the Related Party Transactions Committee is required to review all of the relevant facts and circumstances and report its conclusions to the board. A majority of non-conflicted directors are required to either approve or disapprove of the entry into the transaction. In determining whether to approve or ratify a transaction with AAGES, Algonquin or Abengoa, the directors unaffiliated with such entity are to consider, among other factors they may deem appropriate, whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and the extent of AAGES’, Algonquin’s or Abengoa’s interest in the transaction. Our Related Party Transactions Policy is available on our website at www.atlantica.com.
Code of Conduct
We have adopted a code of conduct applicable all directors, officers and employees of Atlantica and our subsidiaries. The Code of Conduct is available on our website at www.atlantica.com, is communicated to all employees and is reviewed at least annually. All employees acknowledge the Code of Conduct annually.

C. | Interests of Experts and Counsel

Not applicable.

ITEM 8. | FINANCIAL INFORMATION

A. | Consolidated Statements and Other Financial Information.

We have included the Annual Consolidated Financial Statements as part of this annual report. See “Item 18—Financial Statements.”
Dividend Policy
Our Cash Dividend Policy
We expect to pay a quarterly dividend on or about the 75th day following the expiration of the first, second and third fiscal quarters to our shareholders of record on or about the 60th day following the last day of such fiscal quarters. A quarterly dividend corresponding to the fourth quarter is usually declared in the first quarter of the following year. We expect to pay this dividend on or about the 82nd day following the expiration of the corresponding fourth fiscal quarter to our shareholders of record in general on or about the 72nd day following the last day of such fiscal quarter. However, there might be exceptions to these dates. Additionally, our Board of Directors may change our dividend policy at any point in time or modify the dividend for specific quarters following prevailing conditions.
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The table below included our historical quarterly dividends since the beginning of 2018:

Declared | Record | Payable | Amount ($) per share
February 26, 2021 | March 12, 2021 | March 22, 2021 | 0.42
November 4, 2020 | November 30, 2020 | December 15, 2020 | 0.42
July 31, 2020 | August 31, 2020 | September 15, 2020 | 0.42
May 6, 2020 | June 1, 2020 | June 15, 2020 | 0.41
February 26, 2020 | March 12, 2020 | March 23, 2020 | 0.41
November 5, 2019 | November 29, 2019 | December 13, 2019 | 0.41
August 2, 2019 | August 30, 2019 | September 13, 2019 | 0.40
May 7, 2019 | June 3, 2019 | June 14, 2019 | 0.39
February 26, 2019 | March 12, 2019 | March 22, 2019 | 0.37
October 31, 2018 | November 30, 2018 | December 14, 2018 | 0.36
August 6, 2018 | August 31, 2018 | September 15, 2018 | 0.34
May 14, 2018 | May 31, 2018 | June 15, 2018 | 0.32
March 7, 2018 | March 19, 2018 | March 27, 2018 | 0.31

We declared our first quarterly dividend in November 2014 and paid it on December 15, 2014. Recently, on February 26, 2021, our Board of Directors approved a dividend of $0.42 per share corresponding to the fourth quarter of 2020, which is expected to be paid on March 23, 2021.
We intend to distribute a significant portion of our cash available for distribution as dividend, after considering the cash available for distribution that we expect our assets will be able to generate, less reserves for the prudent conduct of our business (including reserves for, among other things, dividend shortfalls as a result of fluctuations in our cash flows), on an annual basis. We intend to distribute a quarterly dividend to shareholders. Our Board of Directors may, by resolution, amend the cash dividend policy at any time. We intend to grow our business via organic growth through the optimization of the existing portfolio and expansion of our current assets and through investments in and acquisitions of new assets. We believe this will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share over time. However, the determination of the amount of cash dividends to be paid to holders of our shares will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant.
Our cash available for distribution is likely to fluctuate from quarter to quarter, in some cases significantly, as a result of the seasonality of our assets, the terms of our financing arrangements and maintenance and outage schedules, among other factors. Accordingly, during quarters in which our assets generate cash available for distribution in excess of the amount necessary for us to pay our stated quarterly dividend, we may reserve a portion of the excess to fund cash distributions in future quarters. In quarters in which we do not generate sufficient cash available for distribution to fund our stated quarterly cash dividend, if our Board of Directors so determines, we may use retained cash flow from other quarters, as well as other sources of cash, to pay dividends to our shareholders.
Risks Regarding Our Cash Dividend Policy
There is no guarantee that we will pay quarterly cash dividends to our shareholders. We do not have a legal obligation to pay any dividend. While we currently intend to grow our business and increase our dividend per share over time, our cash dividend policy is subject to all the risks inherent in our business and may be changed at any time as a result of certain restrictions and uncertainties, including the following:

| • | The amount of our quarterly cash available for distribution could be impacted by restrictions on cash distributions contained in our project-level financing arrangements, which require that our project-level subsidiaries comply with certain financial tests and covenants in order to make such cash distributions. Generally, these restrictions limit the frequency of permitted cash distributions to semi-annual or annual payments, and prohibit distributions unless specified debt service coverage ratios, historical and/or projected, are met. See the sub-sections entitled “—Project Level Financing” under the individual project descriptions in “Item 4.B—Business Overview—Our Operations.” When forecasting cash available for distribution and dividend payments we have aimed to take these restrictions into consideration, but we cannot guarantee future dividends. In addition, restrictions or delays on cash distributions could also happen if our project finance arrangements are under an event of default.

| • | Additionally, indebtedness we have incurred under the Note Issuance Facility 2019, the Note Issuance Facility 2020, the 2020 Green Private Placement and the Revolving Credit Facility contain, among other covenants, certain financial incurrence and maintenance covenants, as applicable. See “Item 5.B—Liquidity and Capital Resources—Financing Arrangements.”

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| • | We and our Board of Directors have the authority to establish cash reserves for the prudent conduct of our business and for future cash dividends to our shareholders, and the establishment of or increase in those reserves could result in a reduction in cash dividends from levels we currently anticipate pursuant to our stated cash dividend policy. These reserves may account for the fact that our project-level cash flows may vary from year to year based on, among other things, changes in the operating performance of our assets, operational costs, capital expenditures required in the assets, collections from our off-takers, compliance with the terms of project debt including debt repayment schedules and cash reserve accounts requirements, compliance with the terms of corporate debt, compliance with all the applicable laws and regulations and working capital requirements. Our Board of Directors may increase reserves to account for the seasonality that has historically existed in our assets’ cash flows and the variances in the pattern and frequency of distributions to us from our assets during the year.

| • | We may lack sufficient cash to pay dividends to our shareholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors, including low availability, low production, unexpected operating interruptions, legal liabilities, costs associated with governmental regulation, changes in governmental subsidies, delays in collections from our off-takers, changes in regulation, as well as increases in our operating and/or general and administrative expenses, principal and interest payments on our and our subsidiaries’ outstanding debt, income tax expenses, failure of Abengoa to comply with its obligations under the agreements in place, working capital requirements or anticipated cash needs at our project-level subsidiaries. See “Item 3.D—Risk Factors” for more information on the risks to which our business is subject.

| • | We may pay cash to our shareholders via capital reduction in lieu of dividends in some years.

| • | Our project companies’ cash distributions to us (in the form of dividends or other forms of cash distributions such as shareholder loan repayments) and, as a result, our ability to pay or grow our dividends, are dependent upon the performance of our subsidiaries and their ability to distribute cash to us. The ability of our project-level subsidiaries to make cash distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable corporation laws and other laws and regulations.

| • | Our Board of Directors may, by resolution, amend the cash dividend policy at any time. Our Board of Directors may elect to change the amount of dividends, suspend any dividend or decide to pay no dividends even if there is ample cash available for distribution.

Our Ability to Grow our Business and Dividend
We intend to grow our business via organic growth through the optimization of the existing portfolio and expansion of our current assets and through investments in and acquisitions of new assets. We believe this will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share over time.
Our policy is to distribute a significant portion of our cash available for distribution as a dividend. We expect we will rely primarily upon external financing sources, including commercial bank borrowings and issuances of debt and equity securities in capital markets, to fund any future growth capital expenditures. To the extent we are unable to finance growth externally, our cash dividend policy could significantly impair our ability to grow because we do not currently intend to reserve a substantial amount of cash generated from operations to fund growth opportunities. If external financing is not available to us on acceptable terms, our Board of Directors may decide to finance investments with cash from operations, which would reduce or impair our ability to pay dividends to our shareholders. To the extent we issue additional shares to fund our business, our growth or for any other reason, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. Additionally, the incurrence of additional commercial bank borrowings or other debt to finance our growth would result in increased interest expense, which in turn may impact our cash available for distribution and, in turn, our ability to pay dividends to our shareholders.

B. | Significant Changes

There have been no significant changes since the date of the Annual Consolidated Financial Statements included in this annual report.

ITEM 9 | THE OFFER AND LISTING

A. | Offering and Listing Details.

Our ordinary shares trade on the NASDAQ Global Select Market under the symbol “AY.”
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B. | Plan of Distribution

Not applicable.

C. | Markets

Our ordinary shares are traded on the NASDAQ Global Select Market under the symbol “AY.”

D. | Selling Shareholders

Not applicable.

E. | Dilution

Not applicable.

F. | Expenses of the Issue

Not applicable.

ITEM 10. | ADDITIONAL INFORMATION

A. | Share Capital

Not applicable.

B. | Memorandum and Articles of Association

The information called for by this item has been reported previously in our Articles of Association on Form 6-K (File No. 001-36487), filed with the SEC on May 21, 2018 as exhibit 3.1 and is incorporated by reference into this annual report.

C. | Material Contracts

See “Item 4.B—Business Overview,” “Item 5.B—Liquidity and Capital Resources—Financing Arrangements” and “Item 7.B—Related Party Transactions.”

D. | Exchange Controls

See “Item 5.A—Operating Results—Factors Affecting Our Results of Operations—Regulation.”

E. | Taxation

Material UK Tax Considerations
The following is a general summary of material UK tax considerations relating to the ownership and disposal of our shares. The comments set out below are based on current UK tax law as applied in England and Wales and HM Revenue & Customs, or HMRC, practice (which may not be binding on HMRC) as at the date of this summary, both of which are subject to change, possibly with retrospective effect. They are intended as a general guide and apply to you only if you are a “U.S. Holder” (as defined in the section below entitled “U.S. Federal Income Tax Considerations”) and if:

| • | you hold Atlantica Sustainable Infrastructure shares as an investment for tax purposes, as capital assets and you are the absolute beneficial owner thereof for UK tax purposes; and

| • | you are an individual, you are not resident in the United Kingdom for UK tax purposes and do not hold Atlantica Sustainable Infrastructure shares for the purposes of a trade, profession, or vocation that you carry on in the United Kingdom through a branch or agency, or if you are a corporation, you are not resident in the UK for UK tax purposes and do not hold the securities for the purpose of a trade carried on in the United Kingdom through a permanent establishment in the United Kingdom.

This summary does not address all possible tax consequences relating to an investment in the shares. Certain categories of shareholders, including those falling outside the category described above, those carrying on certain financial activities, those subject to specific tax regimes or benefitting from certain reliefs or exemptions, those connected with us and those for whom the shares are employment-related securities may be subject to special rules and this summary does not apply to such shareholders and any general statements made in this disclosure do not take them into account.
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This summary is for general information only and is not intended to be, nor should it be considered to be, legal or tax advice to any particular investor. It does not address all of the tax considerations that may be relevant to specific investors in light of their particular circumstances or to investors subject to special treatment under UK tax law.
Potential investors should satisfy themselves prior to investing as to the overall tax consequences, including, specifically, the consequences under UK tax law and HMRC practice of the acquisition, ownership and disposal of the shares in their own particular circumstances by consulting their own tax advisors.
UK Taxation of Dividends
We will not be required to withhold amounts on account of UK tax at source when paying a dividend in respect of our shares to a U.S. Holder.
U.S. Holders who hold their shares as an investment and not in connection with any trade carried on by them will not be subject to United Kingdom tax in respect of any dividends.
UK Taxation of Capital Gains
An individual holder who is a U.S. Holder will generally not be liable to UK capital gains tax on capital gains realized on the disposal of his or her Atlantica Sustainable Infrastructure shares unless such holder carries on (whether solely or in partnership) a trade, profession or vocation in the United Kingdom through a branch or agency in the United Kingdom to which the shares are attributable.
A corporate holder of shares that is a U.S. Holder will generally not be liable for UK corporation tax on chargeable gains realized on the disposal of its Atlantica Sustainable Infrastructure shares unless it carries on a trade in the United Kingdom through a permanent establishment to which the shares are attributable.
An individual holder of shares who is temporarily a non-UK resident for UK tax purposes will, in certain circumstances, become liable to UK tax on capital gains in respect of gains realized while he or she was not resident in the United Kingdom.
Stamp Duty and Stamp Duty Reserve Tax
The stamp duty and stamp duty reserve tax, or SDRT, treatment of the issue and transfer of, and the agreement to transfer, Atlantica Sustainable Infrastructure shares outside a depositary receipt system or a clearance service are discussed in the paragraphs under ‘General’ below. The stamp duty and SDRT treatment of such transactions in relation to such systems are discussed in the paragraphs under “Depositary Receipt Systems and Clearance Services” below.
General
No stamp duty, or SDRT, will arise on the issue of shares in registered form by Atlantica Sustainable Infrastructure.
An agreement to transfer our shares will normally give rise to a charge to SDRT at the rate of 0.5% of the amount or value of the consideration payable for the transfer. SDRT is, in general, payable by the purchaser.
Transfers of our shares will generally be subject to stamp duty at the rate of 0.5% of the consideration given for the transfer (rounded up to the next £5). The purchaser normally pays the stamp duty.
If a duly stamped transfer completing an agreement to transfer is produced within six years of the date on which the agreement is made (or, if the agreement is conditional, the date on which the agreement becomes unconditional) any SDRT already paid is generally repayable, normally with interest, and any SDRT charge yet to be paid is cancelled.
Depositary Receipt Systems and Clearance Services
Following the Court of Justice of the European Union’s decision in C-569/07 HSBC Holdings Plc, Vidacos Nominees Limited v The Commissioners of Her Majesty’s Revenue & Customs and the First-tier Tax Tribunal decision in HSBC Holdings Plc and The Bank of New York Mellon Corporation v. The Commissioners of Her Majesty’s Revenue & Customs, HMRC has confirmed that 1.5% SDRT is no longer payable when new shares are issued to a clearance service or depositary receipt system. HMRC's published guidance confirms that this remains the case following the transition period which expired on December 31, 2020 after the withdrawal of the U.K. from the EU.
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Where our shares are transferred (i) to, or to a nominee or an agent for, a person whose business is or includes the provision of clearance services or (ii) to, or to a nominee or an agent for, a person whose business is or includes issuing depositary receipts, stamp duty or SDRT will generally be payable at the higher rate of 1.5% of the amount or value of the consideration given or, in certain circumstances, the value of the shares.
Except in relation to clearance services that have made an election under Section 97A(1) of the Finance Act of 1986 (to which the special rules outlined below apply), no stamp duty or SDRT is payable in respect of transfers or agreements to transfer within clearance services or depositary receipt systems. Accordingly, no stamp duty or SDRT should, in practice, be required to be paid in respect of transfers or agreements to transfer our shares within the facilities of The Depository Trust Company, or DTC.
There is an exception from the 1.5% charge on the transfer to, or to a nominee or agent for, a clearance service where the clearance service has made and maintained an election under section 97A(1) of the Finance Act 1986, which has been approved by HMRC. In these circumstances, SDRT at the rate of 0.5% of the amount or value of the consideration payable for the transfer will arise on any transfer of our shares into such an account and on subsequent agreements to transfer such shares within such account. It is our understanding that DTC has not made an election under section 97A(1) of the Finance Act of 1986.
Any liability for stamp duty or SDRT in respect of any other transfer into a clearance service or depositary receipt system, or in respect of a transfer within any clearance service or depositary receipt system, which does arise will strictly be accountable by the clearance service or depositary receipt system operator or their nominee, as the case may be, but will, in practice, be payable by the participants in the clearance service or depositary receipt system.
U.S. Federal Income Tax Considerations
The following is a summary of U.S. federal income tax considerations pertaining to the acquisition, ownership and disposition of shares by U.S. Holders (as defined below). This summary is based upon U.S. federal income tax laws (including the IRC, final, temporary and proposed Treasury regulations, rulings, judicial decisions and administrative pronouncements) all as of the date hereof and all of which are subject to changes in wording or administrative or judicial interpretation occurring after the date hereof, possibly with retroactive effect.
As used herein, the term “U.S. Holder” means a beneficial owner of shares:
(a) that is, for U.S. federal income tax purposes, (i) a citizen or resident of the United States, (ii) a corporation (or other entity taxable as a corporation) created or organized in or under the laws of the United States or any political subdivision thereof, (iii) an estate the income of which is subject to U.S. federal income taxation regardless of its source, or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust, or the trust has validly elected to be treated as a domestic trust for U.S. federal income tax purposes;
(b) that holds the shares as capital assets for U.S. federal income tax purposes; and
(c) that owns, directly, indirectly or by attribution, less than 5% both of the vote and value of the interest in Atlantica Sustainable Infrastructure.
This summary does not cover all aspects of U.S. federal income taxation that may be relevant to, or the actual tax effect that any of the matters described herein will have on, the acquisition, ownership or disposition of shares by particular investors, and does not address state, local, foreign or other tax laws. This summary does not address all of the U.S. federal income tax considerations that may apply to U.S. Holders that are subject to special tax rules, such as U.S. citizens or lawful permanent residents of the United States living abroad, insurance companies, tax-exempt organizations, certain financial institutions, persons subject to the alternative minimum tax or the net investment income tax, dealers and certain traders in securities or currencies, persons holding shares as part of a straddle, hedging, conversion or other integrated transaction, partners in entities classified as partnerships for U.S. federal income tax purposes, persons holding shares through an individual retirement account or other tax-deferred account, persons whose functional currency is not the U.S. dollar or persons that carry on a trade, business or vocation in the United Kingdom through a branch, agency or permanent establishment to which the shares are attributable.
If an entity classified as a partnership for U.S. federal income tax purposes holds shares, the U.S. federal income tax treatment of a partner in such an entity generally will depend upon the status of the partner and the activities of the partnership. An entity treated as a partnership for U.S. federal income tax purposes that holds shares and its partners are urged to consult their own tax advisors regarding the specific U.S. federal income tax consequences to the partnership and its partners of acquiring, owning and disposing of the shares.
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This discussion assumes that Atlantica Sustainable Infrastructure is not, was not for its 2020 taxable year, and will not become a PFIC for U.S. federal income tax purposes, as discussed below under “—Passive foreign investment company rules.”
Potential investors in shares should consult their own tax advisors concerning the specific U.S. federal, state and local tax consequences of the ownership and disposition of shares in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.
Taxation of distributions on the shares
Subject to the PFIC rules discussed below, distributions received by a U.S. Holder on shares generally will constitute dividends to the extent paid out of Atlantica Sustainable Infrastructure’s current or accumulated earnings and profits (as determined for U.S. federal income tax purposes). Atlantica Sustainable Infrastructure intends to annually calculate its earnings and profits in accordance with U.S. federal income tax principles. If distributions exceed Atlantica Sustainable Infrastructure’s current and accumulated earnings and profits, such excess distributions will constitute a non-taxable return of capital to the extent of the U.S. Holder’s tax basis in its shares and will result in a reduction of such tax basis. To the extent such excess exceeds a U.S. Holder’s tax basis in the shares, such excess will generally be taxed as capital gain.
Dividends received by certain non-corporate U.S. Holders of shares generally will be subject to U.S. federal income taxation at rates lower than those applicable to other ordinary income if the dividends are “qualified dividend income.” Distributions received by a U.S. Holder on shares will be qualified dividend income if: (i) shares are readily tradable on an established securities market in the United States (such as NASDAQ Global Select Market, where our shares are listed) and (ii) Atlantica Sustainable Infrastructure was not, for the year prior to the year in which the dividends are paid, and is not, for the year in which the dividends are paid, a PFIC. As discussed below under “—Passive foreign investment company rules,” although there can be no assurance that Atlantica Sustainable Infrastructure will not be considered a PFIC for any taxable year, Atlantica Sustainable Infrastructure does not believe that it was a PFIC for its 2020 taxable year and does not expect to be a PFIC for its current taxable year or in the foreseeable future. Non-corporate U.S. Holders should consult their own tax advisors to determine whether they are subject to any special rules that limit their ability to be taxed at these favorable rates. Corporate U.S. Holders will not be entitled to claim the dividends-received deduction with respect to dividends paid by Atlantica Sustainable Infrastructure. Dividends generally will be included in a U.S. Holder’s income on the date of the U.S. Holder’s receipt of the dividend.
Taxation upon sale or other disposition of shares
Subject to the PFIC rules described below, U.S. Holder generally will recognize U.S. source capital gain or loss on the sale or other disposition of shares, which will generally be long-term capital gain or loss if the U.S. Holder has owned shares for more than one year. The amount of the U.S. Holder’s gain or loss generally will be equal to the difference between such U.S. Holder’s adjusted tax basis in the shares sold or otherwise disposed of and the amount realized on the sale or other disposition. Net long-term capital gain recognized by certain non-corporate U.S. Holders will be taxed at a lower rate than the rate applicable to ordinary income. The deductibility of capital losses is subject to limitations.
Passive foreign investment company rules
If Atlantica Sustainable Infrastructure were a PFIC for any taxable year during which a U.S. Holder held shares, certain adverse U.S. federal income tax consequences may apply to the U.S. Holder. Atlantica Sustainable Infrastructure does not believe that it was a PFIC for its 2020 taxable year and does not expect to be a PFIC for its current taxable year or in the foreseeable future. However, PFIC status depends on the composition of a company’s income and assets and the fair market value of its assets (including, among others, certain equity investments) from time to time, as well as on the application of complex statutory and regulatory rules that are subject to potentially varying or changing interpretations. Accordingly, there can be no assurance that Atlantica Sustainable Infrastructure will not be considered a PFIC for any taxable year.
A non-U.S. corporation will be a PFIC in any taxable year in which, after taking into account the income and assets of the corporation and certain subsidiaries pursuant to applicable “look-through rules,” either: (i) at least 75% of its gross income is “passive income” or (ii) at least 50% of the average value of its assets is attributable to assets which produce passive income or are held for the production of passive income. For purposes of the PFIC rules, “passive income” includes, among other things, certain foreign currency gains, certain rents and the excess of gains over losses from certain commodities transactions. Gains from commodities transactions, however, are generally excluded from the definition of passive income if such gains are active business gains from the sale of commodities and the foreign corporation’s commodities meet specified criteria. The law is unclear as to what constitutes “active business gains” and there are also other uncertainties regarding the criteria that commodities must meet. Accordingly, there can be no assurance that Atlantica Sustainable Infrastructure is not, was not for its 2020 taxable year, or will not become a PFIC or that changes in the management or ownership structure of Atlantica Sustainable Infrastructure or its assets, including as a result of any acquisitions pursuant to the ROFO agreements, will not impact the determination of Atlantica Sustainable Infrastructure’s PFIC status.
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If Atlantica Sustainable Infrastructure were a PFIC for any taxable year during which a U.S. Holder held shares, gain recognized by a U.S. Holder on a sale or other disposition of the shares would generally be allocated ratably over the U.S. Holder’s holding period for the shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before Atlantica Sustainable Infrastructure became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to U.S. federal income tax at the highest rate in effect in that year for individuals or corporations, as appropriate, and an interest charge would be imposed on the resulting U.S. federal income tax liability. The same treatment would generally apply to any distribution in respect of shares to the extent the distribution exceeds 125% of the average of the annual distributions on shares received by the U.S. Holder during the preceding three years or the U.S. Holder’s holding period, whichever is shorter. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of the shares.
In addition, if Atlantica Sustainable Infrastructure were a PFIC for a taxable year in which it pays a dividend or in the prior taxable year, the favorable dividend rate discussed above with respect to dividends paid to certain non-corporate U.S. Holders would not apply.
U.S. Holders should consult their own tax advisors regarding the PFIC rules.
Information reporting and backup withholding
Payments of dividends and sales proceeds that are made within the United States or through certain U.S. financial intermediaries generally are subject to information reporting and to backup withholding unless the U.S. Holder is a corporation or other exempt recipient, or, in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability and may entitle such U.S. Holder to a refund, provided that the required information is timely furnished to the Internal Revenue Service. U.S. Holders should consult their own tax advisors about these rules and any other reporting obligations that may apply to the ownership or disposal of shares, including requirements related to the holding of certain “specified foreign financial assets.”

F. | Dividends and Paying Agents

Not applicable.

G. | Statement by Experts

Not applicable.

H. | Documents on Display

Our SEC filings are available to you on the SEC’s website at http://www.sec.gov. This site contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The information on that website is not part of this report. We also make available on our website free of charge, our annual reports on Form 20-F and the text of our reports on Form 6-K, including any amendments to these reports , as well as certain other SEC filings, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Our website address is www.atlantica.com. The information on that website is not part of this report.
As a foreign private issuer, we will be exempt from the rules under the Exchange Act related to the furnishing and content of proxy statements, and our officers, directors and principal shareholders will be exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act. In addition, we will not be required under the Exchange Act to file annual, quarterly and current reports and financial statements with the SEC as frequently or as promptly as United States companies whose securities are registered under the Exchange Act. However, for so long as we are listed on the NASDAQ, or any other U.S. exchange, and are registered with the SEC, we will file with the SEC, within 120 days after the end of each fiscal year, or such applicable time as required by the SEC, an annual report on Form 20-F containing financial statements audited by an independent registered public accounting firm. We also submit to the SEC on Form 6-K the interim financial information that we publish.

I. | Subsidiaries Information

Not applicable.
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ITEM 11. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Quantitative and Qualitative Disclosure about Market Risk
Our activities are undertaken through our segments and are exposed to market risk, credit risk and liquidity risk. Risk is managed by our Risk Management and Finance Departments in accordance with mandatory internal management rules. The internal management rules provide written policies for the management of overall risk, as well as for specific areas, such as exchange rate risk, interest rate risk, credit risk, liquidity risk, use of hedging instruments and derivatives and the investment of excess cash.
Market risk
We are exposed to market risk, such as movement in foreign exchange rates and interest rates. All of these market risks arise in the normal course of business and we do not carry out speculative operations. For the purpose of managing these risks, we use swaps and options on interest rates and foreign exchange rates. None of the derivative contracts signed has an unlimited loss exposure.
Foreign exchange risk
The main cash flows from our subsidiaries are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Given that financing of the projects is generally denominated in the same currency in which the contract with the client is signed, a natural hedge exists for our main operations.
Our functional currency is the U.S. dollar, as most of our revenues and expenses are denominated or linked to U.S. dollars. Our assets located in North America and most of our assets in South America have their PPAs, or concessional agreements, and financing contracts signed in, or indexed totally or partially to, U.S. dollars. Our solar power plants in Spain have their revenues and expenses denominated in euros, and Kaxu, our solar plant in South Africa, has its revenues and expenses denominated in South African rand.
Our strategy is to hedge cash distributions from our Spanish assets. We hedge the exchange rate for the distributions from our Spanish assets after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, we have hedged 100% of our euro-denominated net exposure for the next 12 months and 75% of our euro-denominated net exposure for the following 12 months. We expect to continue with this hedging strategy on a rolling basis.
Although we hedge cash-flows in euros, fluctuations in the value of the euro in relation to the U.S. dollar may affect our operating results. In subsidiaries with functional currency other than the U.S. dollar, assets and liabilities are translated into U.S. dollars using end-of-period exchange rates. Revenue, expenses and cash flows are translated using average rates of exchange. Fluctuations in the value of the South African rand in relation to the U.S. dollar may also affect our operating results.
Interest rate risk
Interest rate risk arises mainly from our financial liabilities at variable interest rate (less than 10% of our total project debt financing). We use interest rate swaps and interest rate options (caps) to mitigate interest rate risk.
As a result, the notional amounts hedged as of December 31, 2020, contracted strikes and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, are very diverse, including the following:

| • | Project debt in euro: 100% of the notional amount, maturities until 2030 and average strike interest rates of between 0.00% and 4.87%

| • | Project debt in U.S. dollars: between 72% and 100% of the notional amount, maturities until 2034 and average strike interest rates of between 1.98% and 5.27%

The most significant impact on our Annual Consolidated Financial Statements related to interest rates corresponds to the potential impact of changes in EURIBOR or LIBOR on the debt with interest rates based on EURIBOR or LIBOR and on derivative positions.
In relation to our interest rate swaps positions, an increase in EURIBOR or LIBOR above the contracted fixed interest rate would create an increase in our financial expense which would be positively mitigated by our hedges, reducing our financial expense to our contracted fixed interest rate. However, an increase in EURIBOR or LIBOR that does not exceed the contracted fixed interest rate would not be offset by our derivative position and would result in a net financial loss recognized in our consolidated income statement. Conversely, a decrease in EURIBOR or LIBOR below the contracted fixed interest rate would result in lower interest expense on our variable rate debt, which would be offset by a negative impact from the mark-to-market of our hedges, increasing our financial expense up to our contracted fixed interest rate, thus likely resulting in a neutral effect.
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In relation to our interest rate options positions, an increase in EURIBOR or LIBOR above the strike price would result in higher interest expenses, which would be positively mitigated by our hedges, reducing our financial expense to our capped interest rate, whereas a decrease of EURIBOR or LIBOR below the strike price would result in lower interest expenses.
In addition to the above, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates.
In the event that EURIBOR and LIBOR had risen by 25 basis points as of December 31, 2020, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $2.9 million (a loss of $2.7 million in 2019 and a loss of $2.7 million in 2018) and an increase in hedging reserves of $22.1 million ($27.6 million in 2019 and $32.9 million in 2018). The increase in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.
Credit risk
On July 1, 2020, PG&E, the off-taker for Atlantica with respect to the Mojave plant, which had filed for reorganization under the U.S. Bankruptcy Code in January 2019, emerged from Chapter 11. See “Item 3.D— Risk Factor— Counterparties to our off-take agreements may not fulfill their obligations and, as our contracts expire, we may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which we operate.”.
The credit rating of Eskom has weakened and is currently CCC+ from S&P , Caa1 from Moody’s and B from Fitch. Eskom is the off-taker of our Kaxu solar plant, a state-owned, limited liability company, wholly owned by the government of the Republic of South Africa. Eskom’s payment guarantees to our Kaxu solar plant are underwritten by the South African Department of Energy, under the terms of an implementation agreement. The credit ratings of the Republic of South Africa have also weakened and as of the date of this report are BB/Ba2/BB- by S&P, Moody’s and Fitch, respectively.
In addition, Pemex’s credit rating has also weakened and is currently BBB from S&P, Ba2 from Moody’s and BB- from Fitch. We have been experiencing significant delays in collections from Pemex since the second half of 2019.
In addition, in 2019 we entered into a political risk insurance agreement with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $89.9 million in the event the South African Department of Energy does not comply with its obligations as guarantor. We have also increased coverage in our political risk insurance for our assets in Algeria up to $38.2 million, including 2 years dividend coverage. These insurance policies do not cover credit risk.
Liquidity risk
The objective of our financing and liquidity policy is to ensure that we maintain sufficient funds to meet our financial obligations as they fall due.
Project finance borrowing permits us to finance projects through project debt and thereby insulate the rest of our assets from such credit exposure. We incur project finance debt on a project-by-project basis.
The repayment profile of each project is established based on the projected cash flow generation of the business. This ensures that sufficient financing is available to meet deadlines and maturities, which mitigates the liquidity risk

ITEM 12. | DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A. | Debt Securities

Not applicable.

B. | Warrants and Rights

Not applicable.

C. | Other Securities

Not applicable.
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D. | American Depositary Shares

Not applicable.
PART II

ITEM 13. | DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14. | MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

Not applicable.

ITEM 15. | CONTROLS AND PROCEDURES

| (a) | Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the U.S. Exchange Act, that are designed to ensure that information required to be disclosed by the Company in reports that we file or submit under the U.S. Exchange Act is (i) recorded, processed, summarized and reported within the time period specified in the SEC’s rules and forms; and (ii) accumulated and communicated to our management, including our Chief Executive Officer (principal executive officer) and Chief Financial Officer (principal financial officer), as appropriate, to allow timely decisions regarding required disclosure. Disclosure controls and procedures, no matter how well designed, can provide only reasonable assurance of achieving the desired control objectives.
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has performed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a-15 (e) under the Exchange Act) as of December 31, 2020. There are inherent limitations to the effectiveness of any control system, including disclosure controls and procedures.
Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective.
Management’s Report on Internal Control over Financial Reporting
Pursuant to Section 404 of the United States Sarbanes-Oxley Act, management is responsible for establishing and maintaining effective internal control over financial reporting. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2020, based on the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO, in Internal Control—Integrated Framework (2013). Based on this assessment, management concluded that, as of December 31, 2020, its internal control over financial reporting was effective based on those criteria.
Our internal control over financial reporting as of December 31, 2020, has been audited by Ernst & Young S.L., an independent registered public accounting firm, as stated in their report which follows below.
Attestation Report of the Independent Registered Public Accounting Firm
The report of Ernst & Young , S.L., our Independent Registered Public Accounting Firm, on our internal control over financial reporting is included herein at page F-2 of our Annual Consolidated Financial Statements.
Changes in Internal Controls over Financial Reporting
There has been no change in our internal control over financial reporting that occurred during 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
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Inherent Limitations of Disclosure Controls and Procedures in Internal Control over Financial Reporting
It should be noted that any system of controls, however well-designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events. Projections regarding the effectiveness of a system of controls in future periods are subject to the risk that such controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the policies or procedures.

ITEM 16. | [RESERVED]

ITEM 16A. | AUDIT COMMITTEE FINANCIAL EXPERT

See “Item 6.C—Board Practices—Audit Committee.” Our Board of Directors has determined that the three members of the Audit Committee, Ms. Brenda Eprile, Mr. William Aziz and Mr. Michael Forsayeth qualify as “audit committee financial experts” under applicable SEC rules.

ITEM 16B. | CODE OF ETHICS

Our Board of Directors has adopted a code of conduct for our employees, officers and directors to govern their relations with current and potential customers, fellow employees, competitors, government and self-regulatory agencies, the media, and anyone else with whom we have contact. Our code of conduct is publicly available on our website at www.atlantica.com and it is under review on yearly basis.

ITEM 16C. | PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table provides information on the aggregate fees billed by our principal accountants, Ernst & Young, S.L. (“EY”) classified by type of service rendered in 2020:

|  | EY |  |  | Other Auditors |  |  | Total |
|  | ($ in thousands) |
Audit Fees |  |  | 1,391 |  |  |  | 54 |  |  |  | 1,445 |
Audit-Related Fees |  |  | 516 |  |  |  | - |  |  |  | 516 |
Tax Fees |  |  | 502 |  |  |  | - |  |  |  | 502 |
All Other Fees |  |  | 15 |  |  |  | - |  |  |  | 15 |
Total |  |  | 2,424 |  |  |  | 54 |  |  |  | 2,478 |

The following table provides information on the aggregate fees billed by our principal accountants, Ernst & Young, S.L. (“EY”) classified by type of service rendered in 2019:

|  | EY |  |  | Other Auditors |  |  | Total |
|  | ($ in thousands) |
Audit Fees |  |  | 1,293 |  |  |  | 61 |  |  |  | 1,354 |
Audit-Related Fees |  |  | 481 |  |  |  | - |  |  |  | 481 |
Tax Fees |  |  | 406 |  |  |  | - |  |  |  | 406 |
All Other Fees |  |  | 271 |  |  |  | - |  |  |  | 271 |
Total |  |  | 2,451 |  |  |  | 61 |  |  |  | 2,512 |

“Audit Fees” are the aggregate fees billed for professional services in connection with the audit of our Annual Consolidated Financial Statements, quarterly reviews of our interim financial statements and statutory audits of our subsidiaries’ financial statements under the rules of England and Wales and the countries in which our subsidiaries are organized. The increase in audit fees is mainly due to new companies being under scope and exchange rates variations.
“Audit-Related Fees” include fees charged for services that can only be provided by our auditor, such as consents and comfort letters of non-recurring transactions, assurance and related services that are reasonably related to the performance of the audit or review of our financial statements. Fees paid during 2020 and 2019 related to comfort letters and consents required for capital market transactions of our major shareholder are also included in this category. These fees were re-invoiced and paid by our major shareholder.
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“Tax Fees” include mainly fees charged for transfer pricing services and tax compliance services in our US subsidiaries.
“All Other Fees” comprises fees billed in relation to financial advisory and due diligence services and other services which cannot be comprised under other categories.
The Audit Committee approved all of the services provided by EY and by its affiliated member firms.
Audit Committee’s Policy on Pre-Approval of Audit and Permissible Non-Audit Services of the Independent Auditor
The terms of reference of Atlantica’s Audit Committee state that the Audit Committee has responsibility for overseeing the relationship with the external auditor, which includes regular assessment of the auditor’s independence and objectivity. The Audit Committee approved a new policy on the independence and objectivity of the external auditor. The policy deals with the relationships between the external auditor and Atlantica and it also relates to Audit Committee Pre-Approval of services provided by the external auditor.
Subject to the approval of the independent auditor by our shareholders, the Audit Committee has the sole authority to appoint, retain or replace the independent auditor. The Audit Committee is also directly responsible for the compensation and oversight of the work of the independent auditor. These policies generally provide that we will not engage our independent auditors to render audit or non-audit services unless the service is specifically approved in advance by the Audit Committee. The Audit Committee’s pre-approval policy, which covers audit and non-audit services provided to us or to any of our subsidiaries, is as follows:

| • | The Audit Committee shall review and approve in advance the annual plan and scope of work of the independent external auditor, including staffing of the audit, and shall (i) review with the independent external auditor any audit-related concerns and management’s response and (ii) confirm that any examination is performed in accordance with the relevant accounting standards;

| • | The Audit Committee shall pre-approve all audit services, and all permitted non-audit services (including the fees and terms thereof) to be performed for us by the independent auditors, to the extent required by law. The Audit Committee may delegate to one or more Committee members the authority to grant pre-approvals for audit and permitted non-audit services to be performed for us by the independent auditor, provided that decisions of such members to grant pre-approvals shall be presented to the full Audit Committee at its next regularly scheduled meeting;

| • | The policy categorizes the audit and permitted non-audit services that are pre-approved by the Audit Committee in the following way:

| o | Audit services, including audit of financial statements, limited reviews, comfort letters, other verification works requested by regulator or supervisors;

| o | Audit-related services, including due diligence services, verification of corporate social responsibility report, accounting or internal control advisory and preparation courses on these topics;

| o | Tax services;

| o | Other specific services, such as evaluation of the design, implementation and operation of a financial information system or control over financial reporting;

| • | Courses or seminars.

| • | For non-audit services, the accumulated fees must remain below the threshold of 70% of the audit services fees, excluding fees reinvoiced to our major shareholder; and

| • | The policy also includes a list of those services that are expressly prohibited.

Only for information purposes, all audit and non-audit services will be reported to the Audit Committee on a quarterly basis.
Any other service shall be pre-approved by the Audit Committee. However, when for reasons of urgency, it is necessary to start the provision of services prior to the next meeting of the Audit Committee, the Chair of the Audit Committee is authorized to provide such approval, which shall be communicated to the Audit Committee subsequently.
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In accordance with the above pre-approval policy, all audit and permitted non-audit services performed for us by our principal accountants, or any of its affiliates, were approved by the Audit Committee of our Board of Directors, who concluded that the provision of such services by the independent accountants was compatible with the maintenance of that firm’s independence in the conduct of its auditing functions: an auditor may not function in the role of management; an auditor may not audit his or her own work; and an auditor may not serve in an advocacy role for his or her client.
The Audit Committee approved all the services provided by Ernst & Young S.L and by other member firms of EY.

ITEM 16D. | EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.

ITEM 16E. | PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

On December 11, 2020 we closed an underwritten public offering of 5,069,200 ordinary shares, including 661,200 ordinary shares sold pursuant to the full exercise of the underwriters’ over-allotment option, at a price of $33.0 per new share. To maintain its approximately 44.2% equity ownership in Atlantica after the public offering, on January 7, 2021, Algonquin, our major shareholder, purchased 4,020,860 ordinary shares in a private placement pursuant to a subscription agreement with Atlantica, dated as of December 9, 2020, at a per share price of $33.0. Pursuant to the subscription agreement, Atlantica has paid Algonquin a commitment fee of 1.25% of the purchase price. After giving effect to such purchase, as of the date of this report, Algonquin is the beneficial owner of 48,962,925 Ordinary Shares, representing approximately 44.2% of the issued and outstanding Ordinary Shares

ITEM 16F. | CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. | CORPORATE GOVERNANCE

Under U.S. federal securities laws and NASDAQ rules we are a “foreign private issuer.” Under NASDAQ Stock Market Rule 5615(a)(3), a foreign private issuer may follow home country corporate governance practices instead of certain of NASDAQ’s requirements, provided that such foreign private issuer discloses in its annual report filed with the SEC each requirement of Rule 5600 that it does not follow and describes the home country practice followed in lieu of such requirement. In addition, a foreign private issuer that elects to follow a home country practice instead of NASDAQ’s requirements must submit to NASDAQ a written statement from an independent counsel in such issuer’s home country certifying that the issuer’s practices are not prohibited by the home country’s laws.
As a foreign private issuer and as a UK company, we are not required to and we do not have: (i) a nominating/corporate governance committee composed entirely of independent directors and (ii) a compensation committee composed entirely of independent directors or (iii) an annual performance evaluation of the nominating/corporate governance and compensation committees. These exemptions do not modify the independence requirements for the audit committee, and we currently comply with the requirements of the Sarbanes-Oxley Act and the NASDAQ rules with respect to the audit committee.
Other than the matters described above, there are no significant differences between our corporate governance practices and those followed by U.S. domestic companies under NASDAQ Stock Market Rules.

ITEM 16H. | MINE SAFETY DISCLOSURE

Not applicable.
PART III

ITEM 17. | FINANCIAL STATEMENTS

We have elected to provide financial statements pursuant to Item 18.

ITEM 18. | FINANCIAL STATEMENTS

Our Annual Consolidated Financial Statements are included at the end of this annual report.
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ITEM 19. | EXHIBITS

The following exhibits are filed as part of this annual report:

Exhibit No. |  | Description
1.1 |  | Amended and restated Articles of Association of Atlantica Yield plc (incorporated by reference from Exhibit 3.1 to Atlantica Yield plc’s Form 6-K, as amended, filed with the SEC on May 21, 2018 – SEC File No. 001-36487).
2.1 |  | Description of Securities Registered under Section 12 of the Exchange Act
4.1 |  | Amended and Restated Right of First Offer Agreement by and between Abengoa Yield plc (now Atlantica Yield plc) and Abengoa, S.A., dated December 9, 2014 (incorporated by reference from Exhibit 10.1 to Atlantica Yield plc’s Registration Statement on Form F-1 filed with the SEC on December 11, 2014 – SEC File No. 333-200848).
4.5 |  | Operation and Maintenance Agreement between Abengoa Solar Espana, S.A. and Solaben Electricidad Dos, S.A., dated December 10, 2012 (incorporated by reference from Exhibit 10.8 to Atlantica Yield plc’s draft registration statement on Form F-1 submitted to the SEC on February 28, 2014 – SEC File No. 377-00503).
4.6 |  | Operation and Maintenance Agreement between Abengoa Solar Espana, S.A. and Solaben Electricidad Tres, S.A., dated December 10, 2012 (incorporated by reference from Exhibit 10.9 to Atlantica Yield plc’s draft registration statement on Form F-1 submitted to the SEC on February 28, 2014 – SEC File No. 377-00503).
4.7 |  | Credit and Guaranty Agreement dated May 10, 2018 (incorporated by reference from Exhibit 99.1 from Atlantica Yield plc’s Form 6-K filed with the SEC on September 5, 2018– SEC File No. 001-36487).
4.8 |  | The Note Issuance Facility, dated February 10, 2017, among Atlantica Yield plc, HSBC Corporate Trust Company (UK) Limited as collateral agent, Elavon Financial Services DAC, UK Branch as agent, and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder (incorporated by reference from Exhibit 4.10 to Atlantica Yield plc’s amendment to the annual report on Form 20-F/A submitted to the SEC on March 29, 2017 – SEC File No. 001¬36487).
4.9 |  | Amendment No. 1 to the Note Issuance Facility Agreement among Atlantica Yield plc, HSBC Corporate Trust Company (UK) Limited as collateral agent, Elavon Financial Services DAC, UK Branch as agent and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder, dated March 28, 2017 (incorporated by reference from Exhibit 4.11 to Atlantica Yield plc’s amendment to the annual report on Form 20-F/A submitted to the SEC on March 29, 2017 – SEC File No. 001-36487).
4.10 |  | Registration Rights Agreement dated March 28, 2017 among Atlantica Yield plc, Abengoa S.A., ACIL Luxco1 S.A. and GLAS Trust Corporation Limited as security agent (incorporated by reference from Exhibit 4.12 from Atlantica Yield plc’s Form 6-K filed with the SEC on April 12, 2017 – SEC File No. 001-36487).
4.11 |  | Shareholder’s Agreement dated March 5, 2018 among Atlantica Yield, AAGES and Algonquin Power & Utilities Corp. (incorporated by reference from Exhibit 4.13 from Atlantica Yield plc’s Form 6-K filed with the SEC on March 12, 2018– SEC File No. 001-36487).
4.12 |  | First Amendment and Joinder to Credit and Guaranty Agreement, dated January 24, 2019 (incorporated by reference from Exhibit 4.14 from Atlantica Yield plc’s Form 20-F filed with the SEC on February 28, 2019 – SEC File No. 001-36487).
4.13 |  | Right of First Offering Agreement dated March 5, 2018 between Atlantica Yield and Algonquin Power and Utilities Corp. (incorporated by reference from Exhibit 4.15 from Atlantica Yield plc’s Form 6-K filed with the SEC on March 12, 2018– SEC File No. 001-36487).
4.14 |  | The Note Issuance Facility, dated April 30, 2019, among Atlantica Yield plc, the guarantors named therein, FSS Trustee Corporation, as trustee, Lucid Agency Services, as agent, and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder (incorporated by reference from Exhibit 99.1 from Atlantica Yield plc’s Form 6-K filed with the SEC on May 10, 2019 – SEC File No. 001-36487).
4.15 |  | Second Amendment to Credit and Guaranty Agreement, dated August 2, 2019 (incorporated by reference from Exhibit 4.18 from Atlantica Yield plc’s Form 6-K filed with the SEC on November 7, 2019 – SEC File No. 001-36487).
4.16 |  | Enhanced Cooperation Agreement, dated May 9, 2019, by and among Algonquin Power & Utilities, Corp., Atlantica Yield plc and Abengoa-Algonquin Global Energy Solutions B.V(incorporated by reference from Exhibit 99.1 from Atlantica Yield plc’s Form 6-K filed with the SEC on August 7, 2019 – SEC File No. 001-36487).
4.17 |  | Subscription Agreement, dated May 9, 2019, by and between Algonquin Power & Utilities, Corp. and Atlantica Yield plc (incorporated by reference from Exhibit 99.2 from Atlantica Yield plc’s Form 6-K filed with the SEC on August 7, 2019 – SEC File No. 001-36487).
4.18 |  | AYES Shareholder Agreement, dated May 24, 2019, by and among Algonquin Power & Utilities, Corp., Atlantica Yield plc and Atlantica Yield Energy Solutions Canada Inc. (incorporated by reference from Exhibit 99.3 from Atlantica Yield plc’s Form 6-K filed with the SEC on August 7, 2019 – SEC File No. 001-36487).
4.19 |  | Third Amendment to Credit and Guaranty Agreement, dated December 17, 2019 (incorporated by reference from Exhibit 4.19 from Atlantica Yield plc’s Form 20-F filed with the SEC on February 28, 2020 – SEC File No. 001-36487).

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4.20 |  | Note Purchase Agreement, dated March 20, 2020, between Atlantica Yield plc and a group of institutional investors as purchasers of the notes issued thereunder (incorporated by reference from Exhibit 4.20 from Atlantica Yield plc’s Form 6-K filed with the SEC on May 7, 2020 – SEC File No. 001-36487).
4.21 |  | Memorandum and Articles of Association of Atlantica Sustainable Infrastructure Jersey Limited (incorporated by reference from Exhibit 4.21 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2020 – SEC File No. 001-36487).
4.22 |  | Indenture (including Form of Global Note) relating to Atlantica Sustainable Infrastructure Jersey Limited’s 4.00% Green Exchangeable Senior Notes due 2025, dated July 17, 2020, by and among Atlantica Sustainable Infrastructure Jersey Limited, as Issuer, Atlantica Sustainable Infrastructure plc, as Guarantor, BNY Mellon Corporate Trustee Services Limited, as Trustee, The Bank of New York Mellon, London Branch, as Paying and Exchange Agent, and The Bank of New York Mellon SA/NV, Luxembourg Branch, as Note Registrar and Transfer Agent (incorporated by reference from Exhibit 4.22 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2020 – SEC File No. 001-36487).
4.23 |  | Deed Poll granted by Atlantica Sustainable Infrastructure plc, as Guarantor, in favor of Atlantica Sustainable Infrastructure Jersey Limited, as Issuer, dated July 17, 2020, in connection with the 4.00% Green Exchangeable Senior Notes due 2025 (incorporated by reference from Exhibit 4.23 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2020 – SEC File No. 001-36487).
4.24 |  | The Note Issuance Facility for an amount of €140 million, dated July 8, 2020, among Atlantica Sustainable Infrastructure plc, the guarantors named therein, Lucid Agency Services Limited, as facility agent, and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder (incorporated by reference from Exhibit 4.24 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2020 – SEC File No. 001-36487).
4.25 |  | Fourth Amendment to Credit and Guaranty Agreement, dated August 28, 2020 (incorporated by reference from Exhibit 4.25 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on November 6, 2020 – SEC File No. 001-36487).
4.26 |  | Amendment No. 2 to Note Issuance Facility Agreement, dated October 23, 2020 (incorporated by reference from Exhibit 4.26 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on November 6, 2020 – SEC File No. 001-36487).
4.27 |  | Underwriting Agreement, dated December 9, 2020, between Atlantica Sustainable Infrastructure plc, as issuer, and BofA Securities, Inc., CIBC World Markets Corp. and MUFG Securities Americas Inc., as underwriters (incorporated by reference from Exhibit 1.1 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on December 10, 2020 – SEC File No. 001-36487)
8.1 |  | Subsidiaries of Atlantica Sustainable Infrastructure plc
12.1 |  | Certification of Santiago Seage, Chief Executive Officer of Atlantica Sustainable Infrastructure plc, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
12.2 |  | Certification of Francisco Martinez-Davis, Chief Financial Officer of Atlantica Sustainable Infrastructure plc, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
13.1 |  | Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1 |  | Consent of EY
15.2 |  | Consent of Deloitte
101.INS |  | XBRL Instance Document
101.SCH |  | XBRL Taxonomy Extension Schema Document
101.CAL |  | XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF |  | XBRL Taxonomy Extension Definition Linkbase Document
101.LAB |  | XBRL Taxonomy Extension Label Linkbase Document
101.PRE |  | XBRL Taxonomy Extension Presentation Linkbase Document |

SIGNATURE
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
Date: March 1, 2021

| ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC
| By: | /s/ Santiago Seage
|  | Name: | Santiago Seage
|  | Title: | Chief Executive Officer

| ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC
| By: | /s/ Francisco Martinez-Davis
|  | Name: | Francisco Martinez-Davis
|  | Title: | Chief Financial Officer

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ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC
INDEX TO FINANCIAL STATEMENTS
Annual Consolidated Financial Statements as of December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018

Report of Ernst and Young, S.L. | F-1
Report of Deloitte, S.L. | F-6
Consolidated statements of financial position as of December 31, 2020 and 2019 | F-7
Consolidated income statements for the years ended December 31, 2020, 2019 and 2018 | F-9
Consolidated financial statements of comprehensive income for the years ended December 31, 2020, 2019 and 2018 | F-10
Consolidated statements of changes in equity for the years ended December 31, 2020, 2019 and 2018 | F-11
Consolidated cash flow statements for the years ended December 31, 2020, 2019 and 2018 | F-14
Notes to the annual consolidated financial statements | F-15
Appendix I: Entities included in the Group as subsidiaries as of December 31, 2020 and 2019 | F-57
Appendix II: Investments recorded under the equity method as of December 31, 2020 | F-61
Appendix III-1 and Appendix III-2: Projects subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2020 and 2019 | F-63
Appendix IV: Additional Information of Subsidiaries including material Non-controlling interest as of December 31, 2020 | F-80
Appendix V (Schedule I): Condensed Financial Statements of Atlantica Sustainable Infrastructure plc | F-82

Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atlantica Sustainable Infrastructure plc:
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of Atlantica Sustainable Infrastructure plc (the “Company”) as of December 31, 2020 and 2019, the related consolidated income statement, the consolidated statement of comprehensive income, the consolidated statement of changes in equity and the consolidated cash flows statement, for each of the two years in the period ended December 31, 2020, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2020, in conformity with International Financial Reporting Standards as issued by International Accounting Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 27, 2021 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
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Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Recoverability assessment of contracted concessional assets

Description of the Matter | At December 31, 2020, the Company's revenues, totaling $ 1,013 million, were derived exclusively from its assets across a range of different geographies. The most significant assets and technologies of the Company are renewable energy, efficient natural gas, transmission lines and water assets. As described in Note 6 to the consolidated financial statements, these assets are referred to as “contracted concessional assets”, totaling $ 8,155 million at December 31, 2020, which are primarily classified as intangible assets or as financial assets, depending on the nature of the payment entitlements established in the agreement. Revenue derived from the Company's contracted concessional assets are governed by power purchase agreements (“PPAs”) with the Company's customers, known as “off-takers” or by regulation. As indicated in Note 2 to the consolidated financial statements, the Company reviews its contracted concessional assets for impairment indicators whenever events or changes in circumstances (“triggering events”) indicate that the carrying amounts of the assets or group of assets may not be recoverable, or previous impairment losses are no longer adequate. As discussed in Note 6, management identified triggering events at the Solana asset located in the United States along with certain assets located in Uruguay and Spain. Auditing the Company’s recoverability assessment related to the contracted concessional assets involves significant judgment in determining whether a triggering event occurred and, if an event did occur, in the assumptions used by management in the determination if an impairment should be recorded or reversed. The main inputs considered when evaluating the triggering events include the performance of the plants in relation to external conditions such as weather and technology changes, as well as legal and tax changes and financial conditions, among others. As indicated in Note 6, significant assumptions which required substantial judgement or estimation used in the impairment calculations of the assets referred above, include: discount rates and projections considering real data based on energy generation, contract terms, and changes in both, projected energy selling prices and costs.

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How We Addressed the Matter in Our Audit | We obtained an understanding of the Company's process related to the recoverability assessment of the Company's contracted concessional assets. We evaluated the design and tested the operating effectiveness of the controls for identifying and evaluating potential impairment indicators or triggering events. To test the Company’s impairment indicators identified for all contracted concessional assets, our audit procedures included, among others, validating the inputs and assumptions used by management by comparing actual energy generated versus budget, obtaining updates on regulatory matters on all significant locations and evaluating the financial situation of the off-takers. For those assets where triggering events were present (Solana (US Asset) and certain assets in Spain and Uruguay), we evaluated the design and tested the operating effectiveness of controls over the current year impairment calculation, including management’s review of the significant assumptions used. As part of our audit procedures, we assessed the appropriateness of the main inputs used in the cash ﬂow projections by comparing the future performance of the assets to their historical production and evaluating the consistency of the actual incomes and costs versus budget for the year 2020, as well as the adequacy of the related disclosures in the Company’s financial statements. For the discount rate, we involved our specialists to assist us in recalculating and developing a range of discount rates, which we compared to those used by the Company. Finally, we also developed an independent sensitivity analysis through the performance of various stress tests on the primary assumptions used by management, including energy generation and discount rates used in the models.

/s/ ERNST & YOUNG, S.L. |
We have served as the Company's auditor since 2019 |
Madrid, Spain |
February 27, 2021 |

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atlantica Sustainable Infrastructure plc:
Opinion on Internal Control over Financial Reporting
We have audited Atlantica Sustainable Infrastructure plc’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Atlantica Sustainable Infrastructure plc (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2020 consolidated financial statements of the Company and our report dated February 27, 2021, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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Definition and Limitations of Internal Control Over Financial Reporting section
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ ERNST & YOUNG, S.L. |
Madrid, Spain |
February 27, 2021 |

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Atlantica Sustainable Infrastructure plc:
Opinion on the Financial Statements
We have audited the accompanying consolidated income statement, consolidated statement of comprehensive income, consolidated statement of changes in equity and consolidated cash flow statement of Atlantica Sustainable Infrastructure plc and subsidiaries (the "Company") for the year ended December 31, 2018 and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the results of the Company’s operations and its cash flows for the year ended December 31, 2018 in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

/s/ Deloitte, S.L. |
Madrid, Spain |
February 26, 2019 |

We began serving as the Company’s auditor in 2014. In 2019, we became the predecessor auditor.
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Consolidated statements of financial position as of December 31, 2020 and 2019
Amounts in thousands of U.S. dollars

|  |  |  |  | As of December 31, |
|  | Note (1) |  |  | 2020 |  |  | 2019 |
Assets |  |  |  |  |  |  |  |  |
Non-current assets |  |  |  |  |  |  |  |  |
Contracted concessional assets |  |  | 6 |  |  |  | 8,155,418 |  |  |  | 8,161,129 |
Investments carried under the equity method |  |  | 7 |  |  |  | 116,614 |  |  |  | 139,925 |
Other receivables accounts |  |  | 8 |  |  |  | 88,655 |  |  |  | 88,405 |
Derivative assets |  |  | 8&9 |  |  |  | 1,099 |  |  |  | 3,182 |
Financial investments |  |  | 8 |  |  |  | 89,754 |  |  |  | 91,587 |
Deferred tax assets |  |  | 18 |  |  |  | 152,290 |  |  |  | 147,966 |
Total non-current assets |  |  |  |  |  |  | 8,514,076 |  |  |  | 8,540,607 |
Current assets |  |  |  |  |  |  |  |  |  |  |  |
Inventories |  |  |  |  |  |  | 23,958 |  |  |  | 20,268 |
Trade receivables |  |  | 11 |  |  |  | 258,087 |  |  |  | 242,008 |
Credits and other receivables |  |  | 11 |  |  |  | 73,648 |  |  |  | 75,560 |
Trade and other receivables |  |  | 8&11 |  |  |  | 331,735 |  |  |  | 317,568 |
Financial investments |  |  | 8 |  |  |  | 200,084 |  |  |  | 218,577 |
Cash and cash equivalents |  |  | 8&12 |  |  |  | 868,501 |  |  |  | 562,795 |
Total current assets |  |  |  |  |  |  | 1,424,278 |  |  |  | 1,119,208 |
Total assets |  |  |  |  |  |  | 9,938,354 |  |  |  | 9,659,815 |

(1) | Notes 1 to 23 are an integral part of the consolidated financial statements

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Consolidated statements of financial position as of December 31, 2020 and 2019
Amounts in thousands of U.S. dollars

|  |  |  |  | As of December 31, |
|  | Note (1) |  |  | 2020 |  |  | 2019 |
Equity and liabilities |  |  |  |  |  |  |  |  |
Equity attributable to the Company |  |  |  |  |  |  |  |  |
Share capital |  |  | 13 |  |  |  | 10,667 |  |  |  | 10,160 |
Share premium |  |  | 13 |  |  |  | 1,011,743 |  |  |  | 1,011,743 |
Capital reserves |  |  | 13 |  |  |  | 881,745 |  |  |  | 889,057 |
Other reserves |  |  | 9 |  |  |  | 96,641 |  |  |  | 73,797 |
Accumulated currency translation differences |  |  | 13 |  |  |  | (99,925 | ) |  |  | (90,824 | )
Accumulated deficit |  |  | 13 |  |  |  | (373,489 | ) |  |  | (385,457 | )
Non-controlling interest |  |  | 13 |  |  |  | 213,499 |  |  |  | 206,380 |
Total equity |  |  |  |  |  |  | 1,740,881 |  |  |  | 1,714,856 |
Non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Long-term corporate debt |  |  | 14 |  |  |  | 970,077 |  |  |  | 695,085 |
Borrowings |  |  |  |  |  |  | 3,862,068 |  |  |  | 3,351,780 |
Notes and bonds |  |  |  |  |  |  | 1,063,200 |  |  |  | 718,129 |
Long-term project debt |  |  | 15 |  |  |  | 4,925,268 |  |  |  | 4,069,909 |
Grants and other liabilities |  |  | 16 |  |  |  | 1,229,767 |  |  |  | 1,658,867 |
Derivative liabilities |  |  | 9 |  |  |  | 328,184 |  |  |  | 298,744 |
Deferred tax liabilities |  |  | 18 |  |  |  | 260,923 |  |  |  | 248,996 |
Total non-current liabilities |  |  |  |  |  |  | 7,714,219 |  |  |  | 6,971,601 |
Current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Short-term corporate debt |  |  | 14 |  |  |  | 23,648 |  |  |  | 28,706 |
Borrowings |  |  |  |  |  |  | 261,788 |  |  |  | 754,135 |
Notes and bonds |  |  |  |  |  |  | 50,558 |  |  |  | 28,304 |
Short-term project debt |  |  | 15 |  |  |  | 312,346 |  |  |  | 782,439 |
Trade payables and other current liabilities |  |  | 17 |  |  |  | 92,557 |  |  |  | 128,062 |
Income and other tax payables |  |  |  |  |  |  | 54,703 |  |  |  | 34,151 |
Total current liabilities |  |  |  |  |  |  | 483,254 |  |  |  | 973,358 |
Total equity and liabilities |  |  |  |  |  |  | 9,938,354 |  |  |  | 9,659,815 |

(1) | Notes 1 to 23 are an integral part of the consolidated financial statements

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Consolidated income statements for the years ended December 31, 2020, 2019 and 2018
Amounts in thousands of U.S. dollars

|  | Note (1) |  |  | For the year ended December 31, |
|  |  |  |  | 2020 |  |  | 2019 |  |  | 2018 |
Revenue |  |  | 4 |  |  |  | 1,013,260 |  |  |  | 1,011,452 |  |  |  | 1,043,822 |
Other operating income |  |  | 20 |  |  |  | 99,525 |  |  |  | 93,774 |  |  |  | 132,557 |
Employee benefit expenses |  |  | 20 |  |  |  | (54,464 | ) |  |  | (32,246 | ) |  |  | (15,130 | )
Depreciation, amortization, and impairment charges |  |  | 6 |  |  |  | (408,604 | ) |  |  | (310,755 | ) |  |  | (362,697 | )
Other operating expenses |  |  | 20 |  |  |  | (276,666 | ) |  |  | (261,776 | ) |  |  | (310,642 | )
Operating profit |  |  |  |  |  |  | 373,051 |  |  |  | 500,449 |  |  |  | 487,910 |
Financial income |  |  | 21 |  |  |  | 7,052 |  |  |  | 4,121 |  |  |  | 36,444 |
Financial expense |  |  | 21 |  |  |  | (378,386 | ) |  |  | (407,990 | ) |  |  | (425,019 | )
Net exchange differences |  |  | 21 |  |  |  | (1,351 | ) |  |  | 2,674 |  |  |  | 1,597 |
Other financial income/(expense), net |  |  | 21 |  |  |  | 40,875 |  |  |  | (1,153 | ) |  |  | (8,235 | )
Financial expense, net |  |  |  |  |  |  | (331,810 | ) |  |  | (402,348 | ) |  |  | (395,213 | )
Share of profit of associates carried under the equity method |  |  | 7 |  |  |  | 510 |  |  |  | 7,457 |  |  |  | 5,231 |
Profit before income tax |  |  |  |  |  |  | 41,751 |  |  |  | 105,558 |  |  |  | 97,928 |
Income tax expense |  |  | 18 |  |  |  | (24,877 | ) |  |  | (30,950 | ) |  |  | (42,659 | )
Profit for the year |  |  |  |  |  |  | 16,874 |  |  |  | 74,608 |  |  |  | 55,269 |
Profit attributable to non-controlling interests |  |  |  |  |  |  | (4,906 | ) |  |  | (12,473 | ) |  |  | (13,673 | )
Profit for the year attributable to the Company |  |  |  |  |  |  | 11,968 |  |  |  | 62,135 |  |  |  | 41,596 |
Weighted average number of ordinary shares outstanding (thousands) - basic |  |  | 22 |  |  |  | 101,879 |  |  |  | 101,063 |  |  |  | 100,217 |
Weighted average number of ordinary shares outstanding (thousands) - diluted |  |  | 22 |  |  |  | 103,392 |  |  |  | 101,063 |  |  |  | 100,217 |
Basic earnings per share (U.S. dollar per share) |  |  | 22 |  |  |  | 0.12 |  |  |  | 0.61 |  |  |  | 0.42 |
Diluted earnings per share (U.S. dollar per share) |  |  | 22 |  |  |  | 0.12 |  |  |  | 0.61 |  |  |  | 0.42 |

(1) | Notes 1 to 23 are an integral part of the consolidated financial statements

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Consolidated statements of comprehensive income for the years ended December 31, 2020, 2019 and 2018
Amounts in thousands of U.S. dollars

|  |  |  |  | For the year ended December 31, |
|  | Note (1) |  |  | 2020 |  |  | 2019 |  |  | 2018 |
Profit for the year |  |  |  |  |  | 16,874 |  |  |  | 74,608 |  |  |  | 55,269 |
Items that may be subject to transfer to income statement |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of cash flow hedges |  |  |  |  |  | (26,272 | ) |  |  | (81,713 | ) |  |  | (40,220 | )
Currency translation differences |  |  |  |  |  | (9,947 | ) |  |  | (22,284 | ) |  |  | (57,628 | )
Tax effect |  |  |  |  |  | 5,897 |  |  |  | 20,088 |  |  |  | 6,195 |
Net expenses recognized directly in equity |  |  |  |  |  | (30,322 | ) |  |  | (83,909 | ) |  |  | (91,653 | )
Cash flow hedges |  |  | 9 |  |  |  | 58,381 |  |  |  | 55,765 |  |  |  | 67,519 |
Tax effect |  |  |  |  |  |  | (14,595 | ) |  |  | (13,941 | ) |  |  | (16,880 | )
Transfers to income statement |  |  |  |  |  |  | 43,786 |  |  |  | 41,824 |  |  |  | 50,639 |
Other comprehensive income/(loss) |  |  |  |  |  |  | 13,464 |  |  |  | (42,085 | ) |  |  | (41,014 | )
Total comprehensive income for the year |  |  |  |  |  |  | 30,338 |  |  |  | 32,523 |  |  |  | 14,255 |
Total comprehensive income attributable to non-controlling interest |  |  |  |  |  |  | (4,627 | ) |  |  | (12,429 | ) |  |  | (11,954 | )
Total comprehensive income attributable to the Company |  |  |  |  |  |  | 25,711 |  |  |  | 20,094 |  |  |  | 2,301 |

(1) | Notes 1 to 23 are an integral part of the consolidated financial statements

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Consolidated statements of changes in equity for the years ended December 31, 2020, 2019 and 2018
Amounts in thousands of U.S. dollars

|  | Share capital |  |  | Share premium |  |  | Capital reserves |  |  | Other reserves |  |  | Accumulated Deficit |  |  | Accumulated currency translation differences |  |  | Total equity attributable to the Company |  |  | Non- controlling interest |  |  | Total equity |
Balance as of January 1, 2018 |  |  | 10,022 |  |  |  | 1,981,881 |  |  |  | 181,348 |  |  |  | 82,294 |  |  |  | (489,026 | ) |  |  | (18,147 | ) |  |  | 1,748,372 |  |  |  | 136,595 |  |  |  | 1,884,967 |
Profit for the year after taxes |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 41,596 |  |  |  | - |  |  |  | 41,596 |  |  |  | 13,673 |  |  |  | 55,269 |
Change in fair value of cash flow hedges |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 21,474 |  |  |  | (236 | ) |  |  | - |  |  |  | 21,238 |  |  |  | 6,061 |  |  |  | 27,299 |
Currency translation differences |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (50,168 | ) |  |  | (50,168 | ) |  |  | (7,460 | ) |  |  | (57,628 | )
Tax effect |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (8,757 | ) |  |  | (1,608 | ) |  |  | - |  |  |  | (10,365 | ) |  |  | (320 | ) |  |  | (10,685 | )
Other comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 12,717 |  |  |  | (1,844 | ) |  |  | (50,168 | ) |  |  | (39,295 | ) |  |  | (1,719 | ) |  |  | (41,014 | )
Total comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 12,717 |  |  |  | 39,752 |  |  |  | (50,168 | ) |  |  | 2,301 |  |  |  | 11,954 |  |  |  | 14,255 |
Distributions (Note 13) |  |  | - |  |  |  | - |  |  |  | (133,289 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (133,289 | ) |  |  | (9,821 | ) |  |  | (143,110 | )
Balance as of December 31, 2018 |  |  | 10,022 |  |  |  | 1,981,881 |  |  |  | 48,059 |  |  |  | 95,011 |  |  |  | (449,274 | ) |  |  | (68,315 | ) |  |  | 1,617,384 |  |  |  | 138,728 |  |  |  | 1,756,112 |

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|  | Share capital |  |  | Share premium |  |  | Capital reserves |  |  | Other reserves |  |  | Accumulated Deficit |  |  | Accumulated currency translation differences |  |  | Total equity attributable to the Company |  |  | Non- controlling interest |  |  | Total equity |
Balance as of January 1, 2019 |  |  | 10,022 |  |  |  | 1,981,881 |  |  |  | 48,059 |  |  |  | 95,011 |  |  |  | (449,274 | ) |  |  | (68,315 | ) |  |  | 1,617,384 |  |  |  | 138,728 |  |  |  | 1,756,112 |
Profit for the year after taxes |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 62,135 |  |  |  | - |  |  |  | 62,135 |  |  |  | 12,473 |  |  |  | 74,608 |
Change in fair value of cash flow hedges |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (27,947 | ) |  |  | 1,682 |  |  |  | - |  |  |  | (26,265 | ) |  |  | 317 |  |  |  | (25,948 | )
Currency translation differences |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (22,509 | ) |  |  | (22,509 | ) |  |  | 225 |  |  |  | (22,284 | )
Tax effect |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 6,733 |  |  |  | - |  |  |  | - |  |  |  | 6,733 |  |  |  | (586 | ) |  |  | 6,147 |
Other comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (21,214 | ) |  |  | 1,682 |  |  |  | (22,509 | ) |  |  | (42,041 | ) |  |  | (44 | ) |  |  | (42,085 | )
Total comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (21,214 | ) |  |  | 63,817 |  |  |  | (22,509 | ) |  |  | 20,094 |  |  |  | 12,429 |  |  |  | 32,523 |
Capital increase (Note 13) |  |  | 138 |  |  |  | 29,862 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 30,000 |  |  |  | - |  |  |  | 30,000 |
Amherst Island (Note 7) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 92,303 |  |  |  | 92,303 |
Reduction of Share Premium (Note 13) |  |  | - |  |  |  | (1,000,000 | ) |  |  | 1,000,000 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Distributions (Note 13) |  |  | - |  |  |  | - |  |  |  | (159,002 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (159,002 | ) |  |  | (37,080 | ) |  |  | (196,082 | )
Balance as of December 31, 2019 |  |  | 10,160 |  |  |  | 1,011,743 |  |  |  | 889,057 |  |  |  | 73,797 |  |  |  | (385,457 | ) |  |  | (90,824 | ) |  |  | 1,508,476 |  |  |  | 206,380 |  |  |  | 1,714,856 |

Notes 1 to 23 are an integral part of the consolidated financial statements
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|  | Share capital |  |  | Share premium |  |  | Capital reserves |  |  | Other reserves |  |  | Accumulated Deficit |  |  | Accumulated currency translation differences |  |  | Total equity attributable to the Company |  |  | Non- controlling interest |  |  | Total equity |
Balance as of January 1, 2020 |  |  | 10,160 |  |  |  | 1,011,743 |  |  |  | 889,057 |  |  |  | 73,797 |  |  |  | (385,457 | ) |  |  | (90,824 | ) |  |  | 1,508,476 |  |  |  | 206,380 |  |  |  | 1,714,856 |
Profit for the year after taxes |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 11,968 |  |  |  | - |  |  |  | 11,968 |  |  |  | 4,906 |  |  |  | 16,874 |
Change in fair value of cash flow hedges |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 31,353 |  |  |  | - |  |  |  | - |  |  |  | 31,353 |  |  |  | 756 |  |  |  | 32,109 |
Currency translation differences |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (9,101 | ) |  |  | (9,101 | ) |  |  | (846 | ) |  |  | (9,947 | )
Tax effect |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (8,509 | ) |  |  | - |  |  |  | - |  |  |  | (8,509 | ) |  |  | (189 | ) |  |  | (8,698 | )
Other comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 22,844 |  |  |  | - |  |  |  | (9,101 | ) |  |  | 13,743 |  |  |  | (279 | ) |  |  | 13,464 |
Total comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 22,844 |  |  |  | 11,968 |  |  |  | (9,101 | ) |  |  | 25,711 |  |  |  | 4,627 |  |  |  | 30,338 |
Capital increase (Note 13) |  |  | 507 |  |  |  | - |  |  |  | 161,347 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 161,854 |  |  |  | - |  |  |  | 161,854 |
Business combinations (Note 5) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 25,308 |  |  |  | 25,308 |
Distributions (Note 13) |  |  | - |  |  |  | - |  |  |  | (168,659 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (168,659 | ) |  |  | (22,816 | ) |  |  | (191,475 | )
Balance as of December 31, 2020 |  |  | 10,667 |  |  |  | 1,011,743 |  |  |  | 881,745 |  |  |  | 96,641 |  |  |  | (373,489 | ) |  |  | (99,925 | ) |  |  | 1,527,382 |  |  |  | 213,499 |  |  |  | 1,740,881 |

Notes 1 to 23 are an integral part of the consolidated financial statements
F-13

Table of Contents
Consolidated cash flow statements for the years ended December 31, 2020, 2019 and 2018
Amounts in thousands of U.S. dollars

|  |  |  |  | For the year ended |
|  | Note (1) |  |  | 2020 |  |  | 2019 |  |  | 2018 |
I. Profit for the year |  |  |  |  |  | 16,874 |  |  |  | 74,608 |  |  |  | 55,269 |
Non-monetary adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation, amortization and impairment charges |  |  | 6 |  |  |  | 408,604 |  |  |  | 310,755 |  |  |  | 362,697 |
Financial (income)/expenses |  |  | 21 |  |  |  | 315,151 |  |  |  | 405,634 |  |  |  | 396,411 |
Fair value (gains)/losses on derivative financial instruments |  |  | 21 |  |  |  | 15,308 |  |  |  | (613 | ) |  |  | 399 |
Shares of (profits)/losses from associates |  |  | 7 |  |  |  | (510 | ) |  |  | (7,457 | ) |  |  | (5,231 | )
Income tax |  |  | 18 |  |  |  | 24,877 |  |  |  | 30,950 |  |  |  | 42,659 |
Other non-monetary items |  |  |  |  |  |  | (21,633 | ) |  |  | (37,432 | ) |  |  | (99,280 | )
II. Profit for the year adjusted by non monetary items |  |  |  |  |  |  | 758,671 |  |  |  | 776,445 |  |  |  | 752,924 |
Variations in working capital |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Inventories |  |  |  |  |  |  | (4,590 | ) |  |  | (1,343 | ) |  |  | (1,991 | )
Trade and other receivables |  |  | 11 |  |  |  | (790 | ) |  |  | (71,505 | ) |  |  | 5,564 |
Trade payables and other current liabilities |  |  | 17 |  |  |  | (9,771 | ) |  |  | (36,533 | ) |  |  | (4,898 | )
Financial investments and other current assets/liabilities |  |  |  |  |  |  | (18,061 | ) |  |  | (3,970 | ) |  |  | (17,019 | )
III. Variations in working capital |  |  |  |  |  |  | (33,212 | ) |  |  | (113,351 | ) |  |  | (18,344 | )
Income tax received/(paid) |  |  |  |  |  |  | (16,425 | ) |  |  | (23 | ) |  |  | (12,525 | )
Interest received |  |  |  |  |  |  | 5,148 |  |  |  | 10,135 |  |  |  | 6,726 |
Interest paid |  |  |  |  |  |  | (275,961 | ) |  |  | (309,625 | ) |  |  | (327,738 | )
A. Net cash provided by operating activities |  |  |  |  |  |  | 438,221 |  |  |  | 363,581 |  |  |  | 401,043 |
Acquisitions of subsidiaries and entities under equity method |  |  | 5&7 |  |  |  | 2,453 |  |  |  | (173,366 | ) |  |  | (70,672 | )
Investments in contracted concessional assets* |  |  | 6 |  |  |  | (1,361 | ) |  |  | 22,009 |  |  |  | 68,048 |
Distributions from entities under the equity method |  |  | 7 |  |  |  | 22,246 |  |  |  | 30,443 |  |  |  | 4,432 |
Other non-current assets/liabilities |  |  |  |  |  |  | (29,198 | ) |  |  | 2,703 |  |  |  | (16,668 | )
B. Net cash (used in)/provided by investing activities |  |  |  |  |  |  | (5,860 | ) |  |  | (118,211 | ) |  |  | (14,860 | )
Proceeds from Project debt |  |  | 15 |  |  |  | 603,949 |  |  |  | 5,860 |  |  |  | 16,266 |
Proceeds from Corporate debt |  |  | 14 |  |  |  | 678,651 |  |  |  | 352,966 |  |  |  | 107,501 |
Repayment of Project debt |  |  | 15 |  |  |  | (621,691 | ) |  |  | (282,255 | ) |  |  | (331,964 | )
Repayment of Corporate debt |  |  | 14 |  |  |  | (502,042 | ) |  |  | (320,815 | ) |  |  | (54,000 | )
Dividends paid to Company´s shareholders |  |  | 13 |  |  |  | (168,659 | ) |  |  | (159,002 | ) |  |  | (133,289 | )
Dividends paid to Non-controlling interests |  |  | 13 |  |  |  | (22,944 | ) |  |  | (29,239 | ) |  |  | (9,745 | )
Purchase of Liberty´s equity interests in Solana |  |  | 16 |  |  |  | (266,850 | ) |  |  | - |  |  |  | - |
Non-controlling interests capital contribution |  |  | 7 |  |  |  | - |  |  |  | 92,303 |  |  |  | - |
Capital increase |  |  | 13 |  |  |  | 162,246 |  |  |  | 30,000 |  |  |  | - |
C. Net cash used in financing activities |  |  |  |  |  |  | (137,340 | ) |  |  | (310,182 | ) |  |  | (405,231 | )
Net increase/(decrease) in cash and cash equivalents |  |  |  |  |  |  | 295,021 |  |  |  | (64,812 | ) |  |  | (19,048 | )
Cash and cash equivalents at beginning of the year |  |  | 12 |  |  |  | 562,795 |  |  |  | 631,542 |  |  |  | 669,387 |
Translation differences cash and cash equivalents |  |  |  |  |  |  | 10,685 |  |  |  | (3,935 | ) |  |  | (18,797 | )
Cash and cash equivalents at the end of the year |  |  | 12 |  |  |  | 868,501 |  |  |  | 562,795 |  |  |  | 631,542 |

* | Includes proceeds for $7.4 million, $22.2 million and $72.6 million in 2020, 2019 and 2018 respectively (Note 6).

(1) | Notes 1 to 23 are an integral part of the consolidated financial statements

F-14

Table of Contents
Contents

Note 1.- Nature of the business | F-16
Note 2.- Significant accounting policies | F-20
Note 3.- Financial risk management | F-30
Note 4.- Financial information by segment | F-31
Note 5.- Business combinations | F-36
Note 6.- Contracted concessional assets | F-37
Note 7.- Investments carried under the equity method | F-40
Note 8.- Financial instruments by category | F-42
Note 9.- Derivative financial instruments | F-43
Note 10.- Related parties | F-44
Note 11.- Trade and other receivables | F-45
Note 12.- Cash and cash equivalents | F-45
Note 13.- Equity | F-46
Note 14.- Corporate debt | F-47
Note 15.- Project debt | F-49
Note 16.- Grants and other liabilities | F-51
Note 17.-Trade payables and other current liabilities | F-52
Note 18.- Income tax | F-52
Note 19.- Commitments, third-party guarantees, contingent assets and liabilities | F-55
Note 20.- Employee benefit expenses and other operating income and expenses | F-56
Note 21.- Financial expense, net | F-57
Note 22.- Earnings per share | F-58
Note 23.- Other information | F-58
Appendices(1) | F-60

The Appendices are an integral part of the notes to the consolidated financial statements
F-15

Table of Contents
Note 1.- Nature of the business
Atlantica Sustainable Infrastructure plc (“Atlantica” or the “Company”) is a sustainable infrastructure company that owns, manages and invests in renewable energy, storage, efficient natural gas, electric transmission lines and water assets focused on North America (the United States, Mexico and Canada), South America (Peru, Chile and Uruguay) and EMEA (Spain, Algeria and South Africa).
Atlantica’s shares began trading on the NASDAQ Global Select Market under the symbol “ABY” on June 13, 2014. The symbol changed to “AY” on November 11, 2017.
Algonquin Power & Utilities (“Algonquin”) is the largest shareholder of the Company and currently owns a 44.2% stake in Atlantica. Algonquin’s voting rights and rights to appoint directors are limited to 41.5% and the difference between Algonquin´s ownership and 41.5% will vote replicating non-Algonquin’s shareholders vote.
During the year 2019, the Company completed the following acquisitions:

| - | On May 24, 2019, Atlantica and Algonquin formed Atlantica Yield Solutions Canada Inc. (“AYES Canada”), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. AYES Canada’s first investment was in Amherst Island, a 75 MW wind plant in Canada owned by the project company Windlectric, Inc. (“Windlectric”). Atlantica invested $4.9 million and Algonquin invested $92.3 million, both through AYES Canada, which in turn invested those funds in Amherst Island Partnership (“AIP), the holding company of Windlectric.

| - | On August 2, 2019, the Company closed the acquisition of ASI Operations LLC (“ASI Ops”), the company that performs the operation and maintenance services to Solana and Mojave plants. The consideration paid was $6 million.

| - | On August 2, 2019, the Company closed the acquisition of a 30% stake in Monterrey, a 142 MW gas-fired engine facility (“Monterrey”) and paid $42 million for the total investment.

| - | On October 22, 2019, the Company closed the acquisition of ATN Expansion 2 from Enel Green Power Perú, for a total equity investment of approximately $20 million, controlling the asset from this date.

On April 3, 2020, the Company made an initial investment in the creation of a renewable energy platform in Chile, together with financial partners, where it owns approximately a 35% stake and has a strategic investor role. The first investment was the acquisition of a 55 MW solar PV plant in an area with excellent solar resource (“Chile PV I”). This asset has been in operation since 2016 demonstrating a good operating track record while selling its production in the Chilean power market. The Company’s initial contribution was approximately $4 million. In addition, on January 6, 2021, the Company closed its second investment through the platform with the acquisition of a 40 MW solar PV plant (“Chile PV 2”). This asset started commercial operation in 2017 and its revenue is partially contracted. Total equity investment for this new asset was approximately $5.0 million. The platform intends to make further investments in renewable energy in Chile and to sign PPAs with credit worthy off-takers.
In January 2019, the Company entered into an agreement with Abengoa (references to “Abengoa” refer to Abengoa, S.A., together with its subsidiaries, or Abenewco1, S.A. together with its subsidiaries, unless the context otherwise requires) under the Abengoa ROFO Agreement for the acquisition of Befesa Agua Tenes, a holding company which owns a 51% stake in Ténès Lilmiyah SpA (“Tenes”), a water desalination plant in Algeria. The Company paid in January 2019 an advance payment of $19.9 million. Closing of the acquisition was subject to conditions precedent which were not fulfilled. In accordance with the terms of the share purchase agreement, the advance payment was converted into a secured loan to be reimbursed by Befesa Agua Tenes, together with 12% per annum interest, through a full cash-sweep of all the dividends to be received from the asset. In October 2019, the Company received a first payment of $7.8 million through the cash sweep mechanism. On May 31, 2020, the Company entered into a new $4.5 million secured loan agreement with Befesa Agua Tenes, in addition to the initial one granted in 2019. The aggregate amount owed at that date, including interest accrued, was $14.0 million. This new loan agreement is expected to be reimbursed by Befesa Agua Tenes, together with 12% per annum interest, through a full cash-sweep of all the dividends to be received from the Tenes asset. The new agreement signed with Abengoa provides Atlantica with a majority at the board of directors of Befesa Agua Tenes and control over the asset.
On August 17, 2020, the Company closed the acquisition of Liberty’s equity interest in Solana. Liberty was the tax equity investor in the Solana project. Total equity investment is expected to be up to $290 million of which $272 million has already been paid. Total price includes a deferred payment and a performance earn-out based on the average annual net production of the asset in the four calendar years with the highest annual net production during the five calendar years of 2020 through 2024 (Note 16).
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In October 2020, the Company reached an agreement to acquire Calgary District Heating (Calgary District Energy Center), an approximately 55 MWt district heating asset in Canada for a total equity investment of approximately $20 million. Calgary District Heating has been in operation since 2010 and represents the first investment of the Company in this sector, which is recognized as a key measure for cities to reduce emissions by the UN Environment Program. The asset provides heating services to a diverse range of government, institutional and commercial customers in the city of Calgary. Closing is subject to customary conditions precedent and regulatory approvals and is expected by mid-2021.
In December 2020, the Company reached an agreement with Algonquin to acquire La Sierpe, a 20 MW solar asset in Colombia for a total equity investment of approximately $20 million. Closing is expected to occur after the asset reaches commercial operation, currently expected to occur by mid-2021. Closing is subject to customary conditions precedent and regulatory approvals. Additionally, the Company agreed to potentially co-invest with Algonquin in additional solar plants in Colombia with a combined capacity of approximately 30 MW to be developed and built by AAGES, a joint venture between Algonquin and Abengoa designed to invest in the development and construction of contracted clean energy and water infrastructure contracted assets.
In December 2020, the Company reached an agreement to acquire Coso, a 135 MW renewable asset in California. Coso is the third largest geothermal plant in the US and provides base load renewable energy to the California ISO. Coso has signed PPAs with three investment grade offtakers, with a 19-year average contract life. Closing is subject to customary regulatory approvals and is expected to occur in the first half of 2021. Total investment is expected to be approximately $170 million, including approximately $130 million for the equity and $40 million that would be invested to reduce project debt.
In January 2021, the Company reached an agreement to increase its equity stake from 15% to 100% in Rioglass, a multinational manufacturer of solar components. The Company has closed the acquisition of 42.5% of the equity for $7 million. In addition, the Company has an option to acquire the remaining 42.5% in the same conditions until September 2021, and after that date the seller has an option to sell the 42.5% also in the same conditions. The Company intends to find partners that would co-invest in Rioglass.
The following table provides an overview of the main concessional assets the Company owned or had an interest in as of December 31, 2020:

Assets | Type | Ownership | Location | Currency(9) | Capacity (Gross) | Counterparty Credit Ratings(10) | COD* | Contract Years Left(14)
Solana | Renewable (Solar) | 100% | Arizona (USA) | USD | 280 MW | A-/A2/A- | 2013 | 23
Mojave | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB-/WR/BB | 2014 | 19
Chile PV I | Renewable (Solar) | 35%(8) | Chile | USD | 55 MW | N/A | 2016 | N/A
Solaben 2 & 3 | Renewable (Solar) | 70%(1) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 17/16
Solacor 1 & 2 | Renewable (Solar) | 87%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 16/16
PS10 & PS20 | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007& 2009 | 11/13

Helioenergy 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 16/16
Helios 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 16/17

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Solnova 1, 3 & 4 | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 14/14/15
Solaben 1 & 6 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 18/18
Seville PV | Renewable (Solar) | 80%(6) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 15
Kaxu | Renewable (Solar) | 51%(3) | South Africa | Rand | 100 MW | BB-/Ba2/ BB-(11) | 2015 | 14
Palmatir | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 13

Cadonal | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 14

Melowind | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB- | 2015 | 15
Mini-Hydro | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB+/A3/BBB+ | 2012 | 12
ACT | Efficient natural gas | 100% | Mexico | USD | 300 MW | BBB/ Ba2/ BB- | 2013 | 12

Monterrey | Efficient natural gas | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 18
ATN (13) | Transmission line | 100% | Peru | USD | 379 miles | BBB+/A3/BBB+ | 2011 | 20
ATS | Transmission line | 100% | Peru | USD | 569 miles | BBB+/A3/BBB+ | 2014 | 23
ATN 2 | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 12
Quadra 1 & 2 | Transmission line | 100% | Chile | USD | 49 miles/ 32 miles | Not rated | 2014 | 14/14
Palmucho | Transmission line | 100% | Chile | USD | 6 miles | BBB+/Baa1/ A- | 2007 | 17
Chile TL3 | Transmission line | 100% | Chile | USD | 50 miles | A+/A1/A- | 1993 | Regulated
Skikda | Water | 34.2%(4) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 13
Honaine | Water | 25.5%(5) | Algeria | USD | 7 M ft3/ day | Not rated | 2012 | 17
Tenes | Water | 51%(7) | Algeria | USD | 7 M ft3/ day | Not rated | 2015 | 19

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Table of Contents
(1) Itochu Corporation, a Japanese trading company, holds 30% of the shares in each of Solaben 2 and Solaben 3.
(2) JGC, a Japanese engineering company, holds 13% of the shares in each of Solacor 1 and Solacor 2.
(3) Kaxu is owned by the Company (51%), Industrial Development Corporation of South Africa (29%) and Kaxu Community Trust (20%).
(4) Algerian Energy Company, SPA owns 49% of Skikda and Sacyr Agua, S.L. owns the remaining 16.83%.
(5) Algerian Energy Company, SPA owns 49% of Honaine and Sacyr Agua, S.L. owns the remaining 25.5%.
(6) Instituto para la Diversificación y Ahorro de la Energía (“Idae”), a Spanish state-owned company, holds 20% of the shares in Seville PV.
(7) Algerian Energy Company, SPA owns 49% of Tenes.
(8) 65% of the shares in Chile PV I is indirectly held by financial partners through the renewable energy platform of the Company in Chile.
(9) Certain contracts denominated in U.S. dollars are payable in local currency.
(10) Reflects the counterparty’s credit ratings issued by Standard & Poor’s Ratings Services, or S&P, Moody’s Investors Service Inc., or Moody’s, and Fitch Ratings Ltd, or Fitch.
(11) Refers to the credit rating of the Republic of South Africa. The offtaker is Eskom, which is a state-owned utility company in South Africa.
(12) Refers to the credit rating of Uruguay, as UTE (Administración Nacional de Usinas y Transmisoras Eléctricas) is unrated.
(13) Including the acquisition of ATN Expansion 1 & 2.
(14) As of December 31, 2020.
(*) Commercial Operation Date.
The project financing arrangement of Kaxu contains cross-default provisions related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. The restructuring process and the pre-insolvency filing by the individual company Abengoa S.A. in August 2020 represented a theoretical event of default under the Kaxu project finance agreement. In December 2020, the Company obtained a waiver from Kaxu’s project debt lenders, which waived any potential cross-defaults with Abengoa for the pre-insolvency filing of August 2020, until December 31, 2021, but the waiver did not cover potential future cross-default events. The insolvency filing by the individual company Abengoa S.A. on February 22, 2021 represents a theoretical event of default under the Kaxu project finance agreement (Note 23.3). Although the Company does not expect the acceleration of debt to be declared by the credit entities, Kaxu does not have contractually from this date, what International Accounting Standards define as an unconditional right to defer the settlement of the debt for at least twelve months, as the cross-default provisions make that right not unconditional. Thus, the total debt of Kaxu, which amounts to $355 million as of December 31, 2020 (Note 15), may be presented as current in the consolidated financial statements of the Company as of March 31, 2021 in accordance with International Accounting Standards 1 (“IAS 1”), “Presentation of Financial Statements”, if the cross-default is not cured or waived. The Company is negotiating a waiver from the creditors and/or contractual modifications to permanently remove the cross-default provision.
Outbreak of COVID-19
The outbreak of the COVID-19 coronavirus disease (“COVID-19”) was declared a pandemic by the World Health Organization in March 2020 and continues to spread in key markets of the Company. The COVID-19 virus continues to evolve rapidly, and its ultimate impact is uncertain and subject to change. Governmental authorities have imposed or recommended measures or responsive actions, including quarantines of certain geographic areas and travel restrictions.
F-19

Table of Contents
Main risks and uncertainties identified by the Company, which may result in a material adverse effect on its business, financial condition, results of operations and cash flows, are:

| - | COVID-19 may affect the operation and maintenance employees of the Company as well as suppliers of operation and maintenance. Furthermore, COVID-19 has caused travel restrictions and significant disruptions to global supply chains. A prolonged disruption could limit the availability of certain parts required to operate the facilities of the Company and adversely impact the ability of its operation and maintenance suppliers. If the Company were to experience a shortage of or inability to acquire critical spare parts, it could incur significant delays in returning facilities to full operation.

| - | Slowdown of broad sectors of the economy, a general reduction in demand, including demand for commodities and a negative impact on prices of commodities, including electricity, oil and gas. The global outbreak also caused significant disruption and volatility in the global financial markets, especially from the end of February until the end on May 2020, including the market price of the shares of the Company. Debt and equity markets have also been affected and there have been weeks with a very low number of new debt and equity issuance transactions. Interest rates for new issuances and spreads with respect to treasury yields increased significantly. Although the revenue of the Company is generally contracted or regulated, clients may be affected by a reduced demand, lower commodity prices and the turmoil in the credit markets. A reduced demand and low prices persisting over time could cause delays in collections, a deterioration in the financial situation of the clients of the Company or their bankruptcy.

Measures taken by the Company so far have focused on reinforcing safety measures in all its assets while it continues to provide a reliable service to its clients. For example, the Company has implemented the use of additional protection equipment, reinforced access control to its plants, reduced contact between employees, changed shifts, tested employees, identified and isolated potential cases together with their close contacts and taken additional measures to increase safety measures for its employees and operation and maintenance suppliers’ employees working at its assets. Furthermore, the Company has adopted additional precautionary measures intended to mitigate potential risks to its employees, including temporarily requiring all employees to work remotely when their work can be done from home, and suspending all non-essential travel. The Company has also reinforced its physical and cyber-security measures. The Company has implemented a protocol to decide when to maintain offices open and with what limitation depending on the number of cases and other health indicators. In addition, the Company has increased the purchase of spare parts and equipment required for operations, to manage potential disruptions in the supply chain. The Company continues to monitor the situation closely in all assets and offices to take additional action if required.
COVID-19 did not have any material impact on the business disclosed in these consolidated financial statements.
The consolidated financial statements were approved by the Board of Directors of the Company on February 26, 2021.
Note 2.- Significant accounting policies
2.1 Basis of preparation
These consolidated financial statements are presented in accordance with the International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
The consolidated financial statements are presented in U.S. dollars, which is the Company’s functional and presentation currency. Amounts included in these consolidated financial statements are all expressed in thousands of U.S. dollars, unless otherwise indicated.
The Company presents assets and liabilities in the statement of financial position based on current/non-current classification. An asset or liability is current when it is expected or due to be realized within twelve months after the reporting period.
Application of new accounting standards
a) Standards, interpretations and amendments effective from January 1, 2020 under IFRS-IASB, applied by the Company in the preparation of these consolidated financial statements:

| - | IFRS 3 (Amendment). Definition of Business. This amendment is mandatory for annual periods beginning on or after January 1, 2020 under IFRS-IASB, earlier application is permitted.

| - | IAS 1 and IAS 8 (Amendment). Definition of Material. This amendment is mandatory for annual periods beginning on or after January 1, 2020 under IFRS-IASB, earlier application is permitted.

| - | IFRS 7 and IFRS 9. Amendments regarding pre-replacement issues in the context of the IBOR reform. These amendments are mandatory for annual periods beginning on or after January 1, 2020 under IFRS-IASB.

| - | IFRS 16. Amendment to provide lessees with an exemption from assessing whether a COVID-19-related rent concession is a lease modification. This amendment is mandatory for annual periods beginning on or after June 1, 2020 under IFRS-IASB.

| - | IAS 41. Amendments resulting from Annual Improvements to IFRS Standards 2018–2020 (taxation in fair value measurements) These amendments are mandatory for annual periods beginning on or after January 1, 2020 under IFRS-IASB.

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| - | Amendments to References to the Conceptual Frameworks in IFRS Standards. This Standard is applicable for annual periods beginning on or after January 1, 2020 under IFRS-IASB.

The applications of these amendments have not had any material impact on these financial statements.
b) Standards, interpretations and amendments published by the IASB that will be effective for periods beginning on or after January 1, 2021:

| - | IAS 1 (Amendment). Classification of liabilities. This amendment is mandatory for annual periods beginning on or after January 1, 2023 under IFRS-IASB.

| - | IAS 37. Amendments regarding the costs to include when assessing whether a contract is onerous. This amendment is mandatory for annual periods beginning on or after January 1, 2022 under IFRS-IASB.

| - | IFRS 1. Amendments resulting from Annual Improvements to IFRS Standards 2018–2020 (subsidiary as a first-time adopter). This amendment is mandatory for annual periods beginning on or after January 1, 2022 under IFRS-IASB.

| - | IFRS 3. Amendments updating a reference to the Conceptual Framework. This amendment is mandatory for annual periods beginning on or after January 1, 2022 under IFRS-IASB.

| - | IFRS 4. Amendments regarding the expiry date of the deferral approach. The fixed expiry date for the temporary exemption in IFRS 4 from applying IFRS 9 is now 1 January 2023.

| - | IFRS 4, IFRS 7, IFRS 16, IFRS 9 and IAS 39. Amendments regarding replacement issues in the context of the IBOR reform. This amendment is mandatory for annual periods beginning on or after January 1, 2021 under IFRS-IASB.

| - | IFRS 9. Amendments resulting from Annual Improvements to IFRS Standards 2018–2020. This amendment is mandatory for annual periods beginning on or after January 1, 2022 under IFRS-IASB.

| - | IFRS 17. Amendments to address concerns and implementation challenges that were identified after IFRS 17 was published. This amendment is mandatory for annual periods beginning on or after January 1, 2023 under IFRS-IASB.

| - | IAS 16. Amendments prohibiting a company from deducting from the cost of property, plant and equipment amounts received from selling items produced while the company is preparing the asset for its intended use. This amendment is mandatory for annual periods beginning on or after January 1, 2022 under IFRS-IASB.

The Company does not anticipate any significant impact on the consolidated financial statements derived from the application of the new standards and amendments that will be effective for annual periods beginning on or after January 1, 2021, although it is currently still in the process of evaluating such application.
Effect of IBOR reform
Following the financial crisis, the reform and replacement of benchmark interest rates such as LIBOR and other inter-bank offered rates (‘IBORs’) has become a priority for global regulators. There remains some uncertainty around the timing and precise nature of these changes. The Company currently has several contracts which reference LIBOR and extend beyond 2021. These contracts are disclosed within the tables below.
It is currently expected that alternative risk-free rates (“RFRs”) will replace LIBOR. There remain key differences between LIBOR and RFRs. LIBOR is a ‘term rate’, which means that it is published for a borrowing period (such as three months or six months) and is ‘forward looking’, because it is published at the beginning of the borrowing period. RFRs may be based on overnight rates from actual transactions and published at the end of the overnight borrowing period. Furthermore, LIBOR includes a credit spread over the risk-free rate, which RFRs currently may not. To transition existing contracts and agreements that reference LIBOR to RFRs, adjustments for term differences and credit differences might need to be applied to RFRs, to enable the two benchmark rates to be economically equivalent on transition. At the time of reporting, industry working groups are reviewing methodologies for calculating adjustments between LIBOR and RFRs.
Risks arising from the transition relate principally to the potential impact of rate differences if the debt and related hedging instruments do not transition to the new benchmark interest rate at the same time and/or the rates move by different amounts. This could result in hedge ineffectiveness and a net cash expense to the Company as a result of the IBOR transition.
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The following table contains details of the financial instruments that the Company holds as of December 31, 2020 which reference LIBOR and have not yet transitioned to RFRs:

|  | Carrying amount as of December 31, 2020 |
|  | Assets |  |  | Liabilities |
Non-derivative assets and liabilities referenced to LIBOR |  |  |  |  |  |
Measured at amortized cost |  |  |  |  |  |
Project debt |  |  | - |  |  |  | 1,143,815 |
Total non-derivatives items |  |  | - |  |  |  | 1,143,815 |
Derivatives |  |  | - |  |  |  | 105,742 |
Total assets and liabilities referenced to LIBOR |  |  | - |  |  |  | 1,249,557 |

The following table contains details of only the hedging instruments used in the Company's hedging strategies which reference LIBOR and have not yet transitioned to RFRs, such that relief(s) of phase 1 amendments to IFRS 9 and IFRS 7 for IBOR reform, effective January 1st, 2020, have been applied to the hedging relationship:

|  | Carrying amount as of December 31, 2020 |  |  |  |  |
|  | Notional |  |  | Assets |  |  | Liabilities |  | Balance sheet line item(s) |  | 2020 changes in fair value used for calculating hedge ineffectiveness |
Cash flow hedge |  |  |  |  |  |  |  |  |  |  |  |  |
Interest rate swaps |  |  | 618,806 |  |  |  | - |  |  |  | 105,742 |  | Derivative liabilities |  |  | 36,172 |
Total cash flow hedges |  |  | 618,806 |  |  |  | - |  |  |  | 105,742 |  |  |  |  | 36,172 |

In calculating the change in fair value attributable to the hedged risk of floating-rate debt, the Company has made the following assumptions that reflect its current expectations:

| - | The floating-rate debt will move to RFRs during 2022, and the spread will be similar to the spread included in the interest rate swap used as the hedging instrument;

| - | No other changes to the terms of the floating-rate debt are anticipated;

| - | The Company has incorporated the uncertainty over when the floating-rate debt will move to RFRs, the resulting adjustment to the spread, and the other aspects of the reform that have not yet been finalized, by adding an additional spread to the discount rate used in the calculation.

2.2. Principles to include and record companies in the consolidated financial statements
Companies included in these consolidated financial statements are accounted for as subsidiaries as long as Atlantica has had control over them and are accounted for as investments under the equity method as long as Atlantica has had significant influence over them, in the periods presented.

a) | Controlled entities

Control is achieved when the Company:

• | Has power over the investee;

• | Is exposed, or has rights, to variable returns from its involvement with the investee; and

• | Has the ability to use its power to affect its returns.

The Company reassesses whether or not it controls an investee when facts and circumstances indicate that there are changes to one or more of the three elements of control listed above.
The Company uses the acquisition method to account for business combinations of companies controlled by a third party. According to this method, identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Any contingent consideration is recognized at fair value at the acquisition date and subsequent changes in its fair value are recognized in accordance with IFRS 9 either in profit or loss or as a change to other comprehensive income. Acquisition related costs are expensed as incurred. The Company recognizes any non-controlling interest in the acquiree either at fair value or at the non-controlling interest’s proportionate share of the acquirer’s net assets on an acquisition by acquisition basis.
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All assets and liabilities between entities of the group, equity, income, expenses, and cash flows relating to transactions between entities of the group are eliminated in full.

b) | Investments accounted for under the equity method

An associate is an entity over which the Company has significant influence. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.
The results and assets and liabilities of associates are incorporated in these financial statements using the equity method of accounting. Under the equity method, an investment in an associate is initially recognized in the statement of financial position at cost and adjusted thereafter to recognize the Company share of the profit or loss and other comprehensive income of the associate.
Controlled entities and associates included in these financial statements as of December 31, 2020 and 2019 are set out in appendices.
2.3. Contracted concessional assets
Contracted concessional assets include fixed assets, related to service concession arrangements recorded in accordance with IFRIC 12, except for Palmucho, which is recorded in accordance with IFRS 16 and PS10, PS20, Sevilla PV, Mini-Hydro, Chile TL 3, ATN Expansion 2 and Chile PV I which are recorded as tangible assets in accordance with IAS 16. The infrastructures accounted for by the Company as concessions are related to the activities concerning renewable energy assets, transmission lines, efficient natural gas assets and water plants. The useful life of these assets is approximately the same as the length of the concession arrangement. The infrastructure used in a concession can be classified as an intangible asset or a financial asset, depending on the nature of the payment entitlements established in the agreement.
The application of IFRIC 12 requires extensive judgement in relation with, among other factors, (i) the identification of certain infrastructures and contractual agreements in the scope of IFRIC 12, (ii) the understanding of the nature of the payments in order to determine the classification of the infrastructure as a financial asset or as an intangible asset and (iii) the timing and recognition of the revenue from construction and concessionary activity.
Under the terms of contractual arrangements within the scope of this interpretation, the operator shall recognize and measure revenue in accordance with IFRS 15 for the services it performs.

a) | Intangible asset

The Company recognizes an intangible asset to the extent that it receives a right to charge final customers for the use of the infrastructure. This intangible asset is subject to the provisions of IAS 38 and is amortized linearly, taking into account the estimated period of commercial operation of the infrastructure which coincides with the concession period.
Once the infrastructure is in operation, the treatment of income and expenses is as follows:

- | Revenues from the updated annual revenue for the contracted concession, as well as operations and maintenance services are recognized in each period according to IFRS 15 “Revenue from contracts with Customers”.

- | Operating and maintenance costs and general overheads and administrative costs are recorded in accordance with the nature of the cost incurred (amount due) in each period.

b) | Financial asset

The Company recognizes a financial asset when demand risk is assumed by the grantor, to the extent that the concession holder has an unconditional right to receive payments for the asset. This asset is recognized at the fair value of the construction services provided, considering upgrade services in accordance with IFRS 15, if any.
The financial asset is subsequently recorded at amortized cost calculated according to the effective interest method. Revenue from operations and maintenance services is recognized in each period according to IFRS 15 “Revenue from contracts with Customers”. The income from managing and operating the asset resulting from the valuation at amortized cost is also recorded in revenue.
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According to IFRS 9, Atlantica recognises an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Company expects to receive.
There are two main approaches to applying the ECL model according to IFRS 9: the general approach which involves a three stage approach, and the simplified approach, which can be applied to trade receivables, contract assets and lease receivables. Atlantica has elected to apply the simplified approach. Under this approach, there is no need to monitor for significant increases in credit risk and entities will be required to measure lifetime expected credit losses at the end of each reporting period.
The key elements of the ECL calculations, based on external sources of information, are the following:

| - | the Probability of Default (“PD”) is an estimate of the likelihood of default over a given time horizon. Atlantica calculates PD based on Credit Default Swaps spreads (“CDS”);

| - | the Exposure at Default (“EAD”) is an estimate of the exposure at a future default date;

| - | the Loss Given Default (“LGD”) is an estimate of the loss arising in the case where a default occurs at a given time. It is based on the difference between the contractual cash flows due and those that the Company would expect to receive. It is expressed as a percentage of the EAD.

c) | Property, plant and equipment

Property, plant and equipment is measured at historical cost, including all expenses directly attributable to the acquisition, less depreciation and impairment losses, with the exception of land, which is presented net of any impairment losses.
Once the infrastructure is in operation, the treatment of income and expenses is the same as the one described above for intangible asset.

d) | Right-of-use assets

Main right of use agreements correspond to land rights. The Company recognizes right-of-use assets under IFRS 16, at the commencement date of the lease (i.e., the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities (Note 2.11). The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets.
The right-of-use assets are also subject to assets impairment (Note 2.4).
2.4. Asset impairment
Atlantica reviews its contracted concessional assets to identify any indicators of impairment at least annually. When impairment indicators exist, the company calculates the recoverable amount of the asset.
The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, the Company calculates the recoverable amount of the Cash Generating Unit (‘CGU’) to which the asset belongs.
When the carrying amount of the CGU to which these assets belong is higher than its recoverable amount, the assets are impaired.
Assumptions used to calculate value in use include a discount rate and projections considering real data based in the contracts terms and projected changes in both selling prices and costs. The discount rate is estimated by Management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.
For contracted concessional assets, with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no relevant terminal value is assumed.
Contracted concessional assets have a contractual structure that permits the Company to estimate quite accurately the costs of the project and revenue during the life of the project.
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Projections take into account real data based on the contract terms and fundamental assumptions based on specific reports prepared internally and third-party reports, assumptions on demand and assumptions on production. Additionally, assumptions on macro-economic conditions are taken into account, such as inflation rates, future interest rates, etc. and sensitivity analyses are performed over all major assumptions which can have a significant impact in the value of the asset.
Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.
Taking into account that in most CGUs the specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash-flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is performed.
In any case, sensitivity analyses are performed, especially in relation with the discount rate used and fair value changes in the main business variables, in order to ensure that possible changes in the estimates of these items do not impact the recovery of recognized assets.
Accordingly, the following table provides a summary of the discount rates used (WACC) to calculate the recoverable amount for CGUs with the operating segment to which it pertains:

Operating segment |  |  | Discount rate | (*)
EMEA |  |  | 3%-5 | %
North America |  |  | 4%-5 | %
South America |  |  | 5%-7 | %

(*) post tax
The discount rates applied in 2020 are consistent with the ones applied in 2019.
In the event that the recoverable amount of an asset is lower than its carrying amount, an impairment charge for the difference would be recorded in the income statement under the item “Depreciation, amortization and impairment charges”.
An assessment is made at each reporting date to determine whether there is an indication that previously recognized impairment losses no longer exist or have decreased. If such indication exists, the Company estimates the CGU’s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the income statement.
2.5. Loans and accounts receivable
Loans and accounts receivable are non-derivative financial assets with fixed or determinable payments, not listed on an active market.
In accordance with IFRIC 12, certain assets under concessions qualify as financial assets and are recorded as is described in Note 2.3.
Pursuant to IFRS 9, an impairment loss is recognized if the carrying amount of these assets exceeds the present value of future cash flows discounted at the initial effective interest rate.
Loans and accounts receivable are initially recognized at fair value plus transaction costs and are subsequently measured at amortized cost in accordance with the effective interest rate method. Interest calculated using the effective interest rate method is recognized under other financial income within financial income.
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2.6. Derivative financial instruments and hedging activities
Derivatives are recognized at fair value in the statement of financial position. The Company maintains both derivatives designated as hedging instruments in hedging relationships, and derivatives to which hedge accounting is not applied.
When hedge accounting is applied, hedging strategy and risk management objectives are documented at inception, as well as the relationship between hedging instruments and hedged items. Effectiveness of the hedging relationship needs to be assessed on an ongoing basis. Effectiveness tests are performed prospectively at inception and at each reporting date. The Company analyses on each date if all these requirements are met:

| - | there is an economic relationship between the hedged item and the hedging instrument;

| - | the effect of credit risk does not dominate the value changes that result from that economic relationship; and

| - | the hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Company actually hedges and the quantity of the hedging instrument that the Company uses to hedge that quantity of hedged item.

Ineffectiveness is measured following accumulated dollar offset method.
In all cases, current Company´s hedging relationships are considered cash flow hedges. Under this model, the effective portion of changes in fair value of derivatives designated as cash flow hedges are recorded temporarily in equity and are subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffective portion of the hedged transaction is recorded in the consolidated income statement as it occurs.
When interest rate options are designated as hedging instruments, the time value is excluded from the hedging instrument as permitted by IFRS 9. Changes in the effective portion of the intrinsic are recorded in equity and subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffectiveness is recorded as financial income or expense as it occurs. Changes in options time value is recorded as cost of hedging. More precisely, considering that the hedged items are, in all cases, time period hedged item, changes in time value is recognized in other comprehensive income to the extent that it relates to the hedged item. The time value at the date of designation of the option as a hedging instrument, to the extent that it relates to the hedged item, is amortized on a systematic and rational basis over the period during which the hedge adjustment for the option’s intrinsic value could affect profit or loss.
When the hedging instrument matures or is sold, or when it no longer meets the requirements to apply hedge accounting, accumulated gains and losses recorded in equity remain as such until the forecast transaction is ultimately recognized in the income statement. However, if it becomes unlikely that the forecast transaction will actually take place, the accumulated gains and losses in equity are recognized immediately in the income statement.
Any change in fair value of derivatives instruments to which hedge accounting is not applied is directly recorded in the income statement.
2.7. Fair value estimates
Financial instruments measured at fair value are presented in accordance with the following level classification based on the nature of the inputs used for the calculation of fair value:

| - | Level 1: Inputs are quoted prices in active markets for identical assets or liabilities.

| - | Level 2: Fair value is measured based on inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices).

| - | Level 3: Fair value is measured based on unobservable inputs for the asset or liability.

In the event that prices cannot be observed, management shall make its best estimate of the price that the market would otherwise establish based on proprietary internal models which, in the majority of cases, use data based on observable market parameters as significant inputs (Level 2) but occasionally use market data that is not observed as significant inputs (Level 3). Different techniques can be used to make this estimate, including extrapolation of observable market data. The best indication of the initial fair value of a financial instrument is the price of the transaction, except when the value of the instrument can be obtained from other transactions carried out in the market with the same or similar instruments, or valued using a valuation technique in which the variables used only include observable market data, mainly interest rates. Differences between the transaction price and the fair value based on valuation techniques that use data that is not observed in the market, are not initially recognized in the income statement.
Atlantica derivatives correspond primarily to the interest rate swaps designated as cash flow hedges, which are classified as Level 2.
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Description of the valuation method
Interest rate swap valuations consist in valuing separately the swap part of the contract and the credit risk. The methodology used by the market and applied by Atlantica to value interest rate swaps is to discount the expected future cash flows according to the parameters of the contract. Variable interest rates, which are needed to estimate future cash flows, are calculated using the curve for the corresponding currency and extracting the implicit rates for each of the reference dates in the contract. These estimated flows are discounted with the swap zero curve for the reference period of the contract.
The effect of the credit risk on the valuation of the interest rate swaps depends on the future settlement. If the settlement is favorable for the Company, the counterparty credit spread will be incorporated to quantify the probability of default at maturity. If the expected settlement is negative for the Company, its own credit risk will be applied to the final settlement.
Classic models for valuing interest rate swaps use deterministic valuation of the future of variable rates, based on future outlooks. When quantifying credit risk, this model is limited by considering only the risk for the current paying party, ignoring the fact that the derivative could change sign at maturity. A payer and receiver swaption model is proposed for these cases. This enables the associated risk in each swap position to be reflected. Thus, the model shows each agent’s exposure, on each payment date, as the value of entering into the ‘tail’ of the swap, i.e. the live part of the swap.
Variables (Inputs)
Interest rate derivative valuation models use the corresponding interest rate curves for the relevant currency and underlying reference in order to estimate the future cash flows and to discount them. Market prices for deposits, futures contracts and interest rate swaps are used to construct these curves. Interest rate options (caps and floors) also use the volatility of the reference interest rate curve.
To estimate the credit risk of the counterparty, the credit default swap (CDS) spreads curve is obtained in the market for important individual issuers. For less liquid issuers, the spreads curve is estimated using comparable CDSs or based on the country curve. To estimate proprietary credit risk, prices of debt issues in the market and CDSs for the sector and geographic location are used.
The fair value of the financial instruments that results from the aforementioned internal models takes into account, among other factors, the terms and conditions of the contracts and observable market data, such as interest rates, credit risk and volatility. The valuation models do not include significant levels of subjectivity, since these methodologies can be adjusted and calibrated, as appropriate, using the internal calculation of fair value and subsequently compared to the corresponding actively traded price. However, valuation adjustments may be necessary when the listed market prices are not available for comparison purposes.
2.8. Trade and other receivables
Trade and other receivables are amounts due from customers for sales in the normal course of business. They are recognized initially at fair value and subsequently measured at amortized cost using the effective interest rate method, less allowance for doubtful accounts. Trade receivables due in less than one year are carried at their face value at both initial recognition and subsequent measurement, provided that the effect of not discounting flows is not significant.
An allowance for doubtful accounts is recorded when there is objective evidence that the Company will not be able to recover all amounts due as per the original terms of the receivables. The Company has established a provision matrix that is based on its historical credit loss experience, adjusted for forward-looking factors specific to the debtors and the economic environment.
2.9. Cash and cash equivalents
Cash and cash equivalents include cash in hand, cash in bank and other highly-liquid current investments with an original maturity of three months or less which are held for the purpose of meeting short-term cash commitments.
2.10. Grants
Grants are recognized at fair value when it is considered that there is a reasonable assurance that the grant will be received and that the necessary qualifying conditions, as agreed with the entity assigning the grant, will be adequately complied with.
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Grants are recorded as liabilities in the consolidated statement of financial position and are recognized in “Other operating income” in the consolidated income statement based on the period necessary to match them with the costs they intend to compensate.
In addition, as described in Note 2.11 below, grants correspond also to loans with interest rates below market rates, for the initial difference between the fair value of the loan and the proceeds received.
2.11. Loans and borrowings
Loans and borrowings are initially recognized at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortized cost and any difference between the proceeds initially received (net of transaction costs incurred in obtaining such proceeds) and the repayment value is recognized in the consolidated income statement over the duration of the borrowing using the effective interest rate method.
Loans with interest rates below market rates are initially recognized at fair value in liabilities and the difference between proceeds received from the loan and its fair value is initially recorded within “Grants and Other liabilities” in the consolidated statement of financial position, and subsequently recorded in “Other operating income” in the consolidated income statement when the costs financed with the loan are expensed.
Lease liabilities are recognized by the Company at the commencement date of the lease at the present value of lease payments to be made over the lease term. The lease payments include the exercise price of a purchase option reasonably certain to be exercised by the Company and payments of penalties for terminating the lease, if the lease term reflects the Company exercising the option to terminate. In calculating the present value of lease payments, the Company uses its incremental borrowing rate at the lease commencement date considering that the interest rate implicit in the lease is not readily determinable.
2.12. Bonds and notes
The Company initially recognizes ordinary notes at fair value, net of issuance costs incurred. Subsequently, notes are measured at amortized cost until settlement upon maturity. Any other difference between the proceeds obtained (net of transaction costs) and the redemption value is recognized in the consolidated income statement over the term of the debt using the effective interest rate method.
Convertible bonds or notes or debt issued with conversion features must be separated into liability and equity components if the feature meets the equity classification conditions in IAS 32. The issuer separates the instrument into its components by determining the fair value of the liability component and then deducting that amount from the fair value of the instrument as a whole; the residual amount is allocated to the equity component. If the equity conversion feature does not satisfy the equity classification conditions in IAS 32, it is bifurcated as an embedded derivative unless the issuer elects to apply the fair value option to the convertible debt. The embedded derivative is initially recognized at fair value and classified as derivatives in the statement of financial position. Changes in the fair value of the embedded derivatives are subsequently accounted for directly through the income statement. The debt element of the bond or note (the host contract), will be initially valued as the difference between the consideration received from the holders for the instrument and the value of the embedded derivative, and thereafter at amortized cost using the effective interest method.
2.13. Income taxes
Current income tax expense is calculated on the basis of the tax laws in force as of the date of the consolidated statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.
Deferred income tax is calculated in accordance with the liability method, based upon the temporary differences arising between the carrying amount of assets and liabilities and their tax base. Deferred income tax is determined using tax rates and regulations which are expected to apply at the time when the deferred tax is realized.
Deferred tax assets are recognized only when it is probable that sufficient future taxable profit will be available to use deferred tax assets.
2.14. Trade payables and other liabilities
Trade payables are obligations arising from purchases of goods and services in the ordinary course of business and are recognized initially at fair value and are subsequently measured at their amortized cost using the effective interest method. Other liabilities are obligations not arising in the normal course of business and which are not treated as financing transactions. Advances received from customers are recognized as “Trade payables and other current liabilities”.
2.15. Foreign currency transactions
The consolidated financial statements are presented in U.S. dollars, which is Atlantica’s functional and presentation currency. Financial statements of each subsidiary within the Company are measured in the currency of the principal economic environment in which the subsidiary operates, which is the subsidiary’s functional currency.
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Transactions denominated in a currency different from the subsidiary’s functional currency are translated into the subsidiary’s functional currency applying the exchange rates in force at the time of the transactions. Foreign currency gains and losses that result from the settlement of these transactions and the translation of monetary assets and liabilities denominated in foreign currency at the year-end rates are recognized in the consolidated income statement, unless they are deferred in equity, as occurs with cash flow hedges and net investment in foreign operations hedges.
Assets and liabilities of subsidiaries with a functional currency different from the Company’s reporting currency are translated to U.S. dollars at the exchange rate in force at the closing date of the financial statements. Income and expenses are translated into U.S. dollars using the average annual exchange rate, which does not differ significantly from using the exchange rates of the dates of each transaction. The difference between equity translated at the historical exchange rate and the net financial position that results from translating the assets and liabilities at the closing rate is recorded in equity under the heading “Accumulated currency translation differences”.
Results of companies carried under the equity method are translated at the average annual exchange rate.
2.16. Equity
The Company has recyclable balances in its equity, corresponding mainly to hedge reserves and translation differences arising from currency conversion in the preparation of these consolidated financial statements. These balances have been presented separately in Equity.
Non-controlling interest represents interest from other partners in entities included in these consolidated financial statements which are not fully owned by Atlantica as of the dates presented.
Share Capital, Share Premium and Capital Reserves represent the Parent’s net investment in the entities included in these consolidated financial statements.
The costs of issuing equity instruments are accounted for as a deduction from equity.
2.17. Provisions and contingencies
Provisions are recognized when:

- | there is a present obligation, either legal or constructive, as a result of past events;

- | it is more likely than not that there will be a future outflow of resources to settle the obligation; and the amount has been reliably estimated.

Provisions are measured at the present value of the expected outflows required to settle the obligation. The discount rate used is a current pre-tax rate that reflects, when appropriate, the risks specific to the liability. The increase in the provision due to the passage of time is then recognized as a financial expense. The balance of provisions disclosed in the Notes reflects management’s best estimate of the potential exposure as of the date of preparation of the consolidated financial statements.
Contingent liabilities are possible obligations, existing obligations with low probability of a future outflow of economic resources and existing obligations where the future outflow cannot be reliably estimated. Contingences are not recognized in the consolidated statements of financial position unless they have been acquired in a business combination.
Some companies included in the group have dismantling provisions, which are intended to cover future expenditures related to the dismantlement of the plants and it will be likely to be settled with an outflow of resources in the long term (over 5 years).
Such provisions are accrued when the obligation for dismantling, removing and restoring the site on which the plant is located, is incurred, which is usually during the construction period. The provision is measured in accordance with IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” and is recorded as a liability under the heading “Grants and other liabilities” of the Financial Statements, and the corresponding entry as part of the cost of the plant under the heading “Contracted concessional assets.” The estimated future costs of dismantling are reviewed annually if conditions have changed and adjusted appropriately. The impact of changes in the estimate of future costs or in the timing of when such costs will be incurred, on the dismantling provision, is recorded against an increase or decrease of the cost of the plant.
2.18. Earnings per share
Basic earnings per share is calculated by dividing the profit for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the period.
Diluted earnings per share is calculated by dividing the profit for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the period plus the weighted average number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares into ordinary shares.
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2.19. Significant judgements and estimates
Some of the accounting policies applied require the application of significant judgement by management to select the appropriate assumptions to determine these estimates. These assumptions and estimates are based on the historical experience, advice from experienced consultants, forecasts and other circumstances and expectations as of the close of the financial period. The assessment is considered in relation to the global economic situation of the industries and regions where the Company operates, taking into account future development of the businesses of the Company. By their nature, these judgements are subject to an inherent degree of uncertainty; therefore, actual results could materially differ from the estimates and assumptions used. In such cases, the carrying values of assets and liabilities are adjusted.
The most critical accounting policies, which reflect significant management estimates and judgement to determine amounts in these consolidated financial statements, are as follows:

| - | Contracted concessional agreements and PPAs.

| - | Impairment of intangible assets and property, plant and equipment.

| - | Assessment of control.

| - | Derivative financial instruments and fair value estimates.

| - | Income taxes and recoverable amount of deferred tax assets.

As of the date of preparation of these consolidated financial statements, no relevant changes in the estimates made are anticipated and, therefore, no significant changes in the value of the assets and liabilities recognized at December 31, 2020, are expected.
Although these estimates and assumptions are being made using all available facts and circumstances, it is possible that future events may require management to amend such estimates and assumptions in future periods. Changes in accounting estimates are recognized prospectively, in accordance with IAS 8, in the consolidated income statement of the year in which the change occurs.
Note 3.- Financial risk management
Atlantica’s activities are exposed to various financial risks: market risk (including currency risk and interest rate risk), credit risk and liquidity risk. Risk is managed by the Company’s Risk Finance and Compliance Departments, which are responsible for identifying and evaluating financial risks quantifying them by project, region and company, in accordance with mandatory internal management rules. Written internal policies exist for global risk management, as well as for specific areas of risk. In addition, there are official written management regulations regarding key controls and control procedures for each company and the implementation of these controls is monitored through internal audit procedures.

a) | Market risk

The Company is exposed to market risk, such as movement in foreign exchange rates and interest rates. All of these market risks arise in the normal course of business and the Company does not carry out speculative operations. For the purpose of managing these risks, the Company uses a series of interest rate swaps and options, and currency options. None of the derivative contracts signed has an unlimited loss exposure.

| - | Interest rate risk

Interest rate risk arises when the Company’s activities are exposed to changes in interest rates, which arises from financial liabilities at variable interest rates. The main interest rate exposure for the Company relates to the variable interest rate with reference to the Libor and Euribor. To minimize the interest rate risk, the Company primarily uses interest rate swaps and interest rate options (caps), which, in exchange for a fee, offer protection against an increase in interest rates. The Company does not use derivatives for speculative purposes.
As a result, the notional amounts hedged, strikes contracted and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, are very diverse, including the following:

| o | Project debt in Euros: the Company hedges 100% of the notional amount, maturities until 2030 and average guaranteed strike interest rates of between 0.00% and 4.87%.

| o | Project debt in U.S. dollars: the Company hedges between 72% and 100% of the notional amount, including maturities until 2034 and average guaranteed strike interest rates of between 1.98% and 5.27%.

In connection with the interest rate derivative positions of the Company, the most significant impacts on these consolidated financial statements are derived from the changes in EURIBOR or LIBOR, which represent the reference interest rate for most of the debt of the Company. In the event that Euribor and Libor had risen by 25 basis points as of December 31, 2020, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $2,897 thousand (a loss of $2,745 thousand in 2019 and a loss of $2,731 thousand in 2018) and an increase in hedging reserves of $22,130 thousand ($27,570 thousand in 2019 and $32,928 thousand in 2018). The increase in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.
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A breakdown of the interest rates derivatives as of December 31, 2020 and 2019, is provided in Note 9.

| - | Currency risk

The main cash flows in the entities included in these consolidated financial statements are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Given that financing of the projects is always closed in the same currency in which the contract with client is signed, a natural hedge exists for the main operations of the Company.
In addition, the Company policy is to contract currency options with leading financial institutions, which guarantee a minimum Euro-U.S. dollar exchange rate on the net distributions expected from Spanish solar assets. The net Euro exposure is 100% hedged for the coming 12 months and 75% for the following 12 months on a rolling basis.

b) | Credit risk

The Company considers that it has a limited credit risk with clients as revenues derive from power purchase agreements with electric utilities and state-owned entities.

c) | Liquidity risk

Atlantica’s liquidity and financing policy is intended to ensure that the Company maintains sufficient funds to meet our financial obligations as they fall due.
Project finance borrowing permits the Company to finance the project through project debt and thereby insulate the rest of its assets from such credit exposure. The Company incurs in project-finance debt on a project-by-project basis.
The repayment profile of each project is established on the basis of the projected cash flow generation of the business. This ensures that sufficient financing is available to meet deadlines and maturities, which mitigates the liquidity risk significantly.
Corporate and Project debt repayment schedules are disclosed in Note 14 and 15, respectively.
Note 4.- Financial information by segment
Atlantica’s segment structure reflects how management currently makes financial decisions and allocates resources. Its operating and reportable segments are based on the following geographies where the contracted concessional assets are located:

| - | North America

| - | South America

| - | EMEA

Based on the type of business, as of December 31, 2020 the Company had the following business sectors:

| - | Renewable energy

| - | Efficient natural gas

| - | Electric transmission lines

| - | Water

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Atlantica’s Chief Operating Decision Maker (CODM), which is the CEO, assesses the performance and assignment of resources according to the identified operating segments. The CODM considers the revenues as a measure of the business activity and the Adjusted EBITDA as a measure of the performance of each segment. Adjusted EBITDA is calculated as profit/(loss) for the period attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interests from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in these consolidated financial statements.
In order to assess performance of the business, the CODM receives reports of each reportable segment using revenues and Adjusted EBITDA. Net interest expense evolution is assessed on a consolidated basis. Financial expense and amortization are not taken into consideration by the CODM for the allocation of resources.
In the years ended December 31, 2020 and December 31, 2019 Atlantica had four customers with revenues representing more than 10% of the total revenues, three in the renewable energy and one in the efficient natural gas business sectors.

a) | The following tables show Revenues and Adjusted EBITDA by operating segments and business sectors for the years 2020, 2019 and 2018:

|  | Revenue |  |  | Adjusted EBITDA |
|  | For the year ended December 31, |  |  | For the year ended December 31, |
Geography |  | 2020 |  |  | 2019 |  |  | 2018 |  |  | 2020 |  |  | 2019 |  |  | 2018 |
North America |  |  | 330,921 |  |  |  | 332,965 |  |  |  | 357,177 |  |  |  | 272,909 |  |  |  | 305,085 |  |  |  | 308,748 |
South America |  |  | 151,460 |  |  |  | 142,207 |  |  |  | 123,214 |  |  |  | 120,023 |  |  |  | 115,346 |  |  |  | 100,234 |
EMEA |  |  | 530,879 |  |  |  | 536,280 |  |  |  | 563,431 |  |  |  | 388,723 |  |  |  | 390,774 |  |  |  | 441,625 |
Total |  |  | 1,013,260 |  |  |  | 1,011,452 |  |  |  | 1,043,822 |  |  |  | 781,655 |  |  |  | 811,204 |  |  |  | 850,607 |

|  | Revenue |  |  | Adjusted EBITDA |
|  | For the year ended December 31, |  |  | For the year ended December 31, |
Business sectors |  | 2020 |  |  | 2019 |  |  | 2018 |  |  | 2020 |  |  | 2019 |  |  | 2018 |
Renewable energy |  |  | 753,089 |  |  |  | 761,090 |  |  |  | 793,557 |  |  |  | 575,660 |  |  |  | 603,666 |  |  |  | 664,428 |
Efficient natural gas |  |  | 111,030 |  |  |  | 122,281 |  |  |  | 130,799 |  |  |  | 97,864 |  |  |  | 107,457 |  |  |  | 93,858 |
Electric transmission lines |  |  | 106,042 |  |  |  | 103,453 |  |  |  | 95,998 |  |  |  | 84,584 |  |  |  | 85,657 |  |  |  | 78,461 |
Water |  |  | 43,099 |  |  |  | 24,629 |  |  |  | 23,468 |  |  |  | 23,548 |  |  |  | 14,424 |  |  |  | 13,860 |
Total |  |  | 1,013,260 |  |  |  | 1,011,452 |  |  |  | 1,043,822 |  |  |  | 781,655 |  |  |  | 811,204 |  |  |  | 850,607 |

The reconciliation of segment Adjusted EBITDA with the profit attributable to the parent company is as follows:

|  | For the year ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Profit attributable to the Company |  |  | 11,968 |  |  |  | 62,135 |  |  |  | 41,596 |
Profit attributable to non-controlling interests |  |  | 4,906 |  |  |  | 12,473 |  |  |  | 13,673 |
Income tax |  |  | 24,877 |  |  |  | 30,950 |  |  |  | 42,659 |
Share of profit of associates |  |  | (510 | ) |  |  | (7,457 | ) |  |  | (5,231 | )
Financial expense, net |  |  | 331,810 |  |  |  | 402,348 |  |  |  | 395,213 |
Depreciation, amortization, and impairment charges |  |  | 408,604 |  |  |  | 310,755 |  |  |  | 362,697 |
Total segment Adjusted EBITDA |  |  | 781,655 |  |  |  | 811,204 |  |  |  | 850,607 |

b) | The assets and liabilities by operating segments (and business sector) at the end of 2020 and 2019 are as follows:

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Assets and liabilities by geography as of December 31, 2020:

|  | North America |  |  | South America |  |  | EMEA |  |  | Balance as of December 31, 2020 |
Assets allocated |  |  |  |  |  |  |  |  |  |  |  |
Contracted concessional assets |  |  | 3,073,785 |  |  |  | 1,211,952 |  |  |  | 3,869,681 |  |  |  | 8,155,418 |
Investments carried under the equity method |  |  | 74,660 |  |  |  | - |  |  |  | 41,954 |  |  |  | 116,614 |
Current financial investments |  |  | 129,264 |  |  |  | 27,836 |  |  |  | 42,984 |  |  |  | 200,084 |
Cash and cash equivalents (project companies) |  |  | 206,344 |  |  |  | 70,861 |  |  |  | 255,530 |  |  |  | 532,735 |
Subtotal allocated |  |  | 3,484,053 |  |  |  | 1,310,649 |  |  |  | 4,210,149 |  |  |  | 9,004,851 |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 242,044 |
Other current assets (including cash and cash equivalents at holding company level) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 691,459 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 933,503 |
Total assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,938,354 |

|  | North America |  |  | South America |  |  | EMEA |  |  | Balance as of December 31, 2020 |
Liabilities allocated |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term project debt |  |  | 1,623,284 |  |  |  | 902,500 |  |  |  | 2,711,830 |  |  |  | 5,237,614 |
Grants and other liabilities |  |  | 1,078,974 |  |  |  | 11,355 |  |  |  | 139,438 |  |  |  | 1,229,767 |
Subtotal allocated |  |  | 2,702,258 |  |  |  | 913,855 |  |  |  | 2,851,268 |  |  |  | 6,467,381 |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term corporate debt |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 993,725 |
Other non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 589,107 |
Other current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 147,260 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,730,092 |
Total liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 8,197,473 |
Equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,740,881 |
Total liabilities and equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,470,973 |
Total liabilities and equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,938,354 |

Assets and liabilities by geography as of December 31, 2019:

|  | North America |  |  | South America |  |  | EMEA |  |  | Balance as of December 31, 2019 |
Assets allocated |  |  |  |  |  |  |  |  |  |  |  |
Contracted concessional assets |  |  | 3,299,198 |  |  |  | 1,186,552 |  |  |  | 3,675,379 |  |  |  | 8,161,129 |
Investments carried under the equity method |  |  | 90,847 |  |  |  | - |  |  |  | 49,078 |  |  |  | 139,925 |
Current financial investments |  |  | 159,267 |  |  |  | 29,190 |  |  |  | 20,673 |  |  |  | 209,131 |
Cash and cash equivalents (project companies) |  |  | 181,458 |  |  |  | 80,909 |  |  |  | 234,097 |  |  |  | 496,464 |
Subtotal allocated |  |  | 3,730,771 |  |  |  | 1,296,652 |  |  |  | 3,979,227 |  |  |  | 9,006,649 |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 239,553 |
Other current assets (including cash and cash equivalents at holding company level) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 413,613 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 653,166 |
Total assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,659,815 |

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|  | North America |  |  | South America |  |  | EMEA |  |  | Balance as of December 31, 2019 |
Liabilities allocated |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term project debt |  |  | 1,676,251 |  |  |  | 884,835 |  |  |  | 2,291,262 |  |  |  | 4,852,348 |
Grants and other liabilities |  |  | 1,490,661 |  |  |  | 12,864 |  |  |  | 155,342 |  |  |  | 1,658,867 |
Subtotal allocated |  |  | 3,166,912 |  |  |  | 897,699 |  |  |  | 2,446,604 |  |  |  | 6,511,215 |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term corporate debt |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 723,791 |
Other non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 547,740 |
Other current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 162,213 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,433,744 |
Total liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,944,959 |
Equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,714,856 |
Total liabilities and equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,148,600 |
Total liabilities and equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,659,815 |

Assets and liabilities by business sectors as of December 31, 2020:

|  | Renewable energy |  |  | Efficient natural gas |  |  | Electric transmission lines |  |  | Water |  |  | Balance as of December 31, 2020 |
Assets allocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contracted concessional assets |  |  | 6,632,611 |  |  |  | 502,285 |  |  |  | 842,595 |  |  |  | 177,927 |  |  |  | 8,155,418 |
Investments carried under the equity method |  |  | 61,866 |  |  |  | 15,514 |  |  |  | 30 |  |  |  | 39,204 |  |  |  | 116,614 |
Current financial investments |  |  | 6,530 |  |  |  | 124,872 |  |  |  | 27,796 |  |  |  | 40,886 |  |  |  | 200,084 |
Cash and cash equivalents (project companies) |  |  | 397,465 |  |  |  | 67,955 |  |  |  | 46,045 |  |  |  | 21,270 |  |  |  | 532,735 |
Subtotal allocated |  |  | 7,098,472 |  |  |  | 710,626 |  |  |  | 916,466 |  |  |  | 279,287 |  |  |  | 9,004,851 |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 242,044 |
Other current assets (including cash and cash equivalents at holding company level) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 691,459 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 933,503 |
Total assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,938,354 |

|  | Renewable energy |  |  | Efficient natural gas |  |  | Electric transmission lines |  |  | Water |  |  | Balance as of December 31, 2020 |
Liabilities allocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term project debt |  |  | 3,992,512 |  |  |  | 504,293 |  |  |  | 625,203 |  |  |  | 115,606 |  |  |  | 5,237,614 |
Grants and other liabilities |  |  | 1,221,176 |  |  |  | 108 |  |  |  | 6,040 |  |  |  | 2,443 |  |  |  | 1,229,767 |
Subtotal allocated |  |  | 5,213,688 |  |  |  | 504,401 |  |  |  | 631,243 |  |  |  | 118,049 |  |  |  | 6,467,381 |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term corporate debt |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 993,725 |
Other non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 589,107 |
Other current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 147,260 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,730,092 |
Total liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 8,197,473 |
Equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,740,881 |
Total liabilities and equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,470,973 |
Total liabilities and equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,938,354 |

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Assets and liabilities by business sectors as of December 31, 2019:

|  | Renewable energy |  |  | Efficient natural gas |  |  | Electric transmission lines |  |  | Water |  |  | Balance as of December 31, 2019 |
Assets allocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contracted concessional assets |  |  | 6,644,024 |  |  |  | 559,069 |  |  |  | 872,757 |  |  |  | 85,280 |  |  |  | 8,161,129 |
Investments carried under the equity method |  |  | 77,549 |  |  |  | 17,154 |  |  |  | - |  |  |  | 45,222 |  |  |  | 139,925 |
Current financial investments |  |  | 13,798 |  |  |  | 148,723 |  |  |  | 28,237 |  |  |  | 18,373 |  |  |  | 209,131 |
Cash and cash equivalents (project companies) |  |  | 421,198 |  |  |  | 11,850 |  |  |  | 53,868 |  |  |  | 9,548 |  |  |  | 496,464 |
Subtotal allocated |  |  | 7,156,568 |  |  |  | 736,796 |  |  |  | 954,862 |  |  |  | 158,423 |  |  |  | 9,006,649 |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 239,553 |
Other current assets (including cash and cash equivalents at holding company level) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 413,613 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 653,166 |
Total assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,659,815 |

|  | Renewable energy |  |  | Efficient natural gas |  |  | Electric transmission lines |  |  | Water |  |  | Balance as of December 31, 2019 |
Liabilities allocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term project debt |  |  | 3,658,507 |  |  |  | 529,350 |  |  |  | 640,160 |  |  |  | 24,331 |  |  |  | 4,852,348 |
Grants and other liabilities |  |  | 1,651,476 |  |  |  | 146 |  |  |  | 6,517 |  |  |  | 728 |  |  |  | 1,658,867 |
Subtotal allocated |  |  | 5,309,983 |  |  |  | 529,495 |  |  |  | 646,677 |  |  |  | 25,059 |  |  |  | 6,511,215 |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term corporate debt |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 723,791 |
Other non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 547,740 |
Other current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 162,213 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,433,744 |
Total liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,944,959 |
Equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,714,856 |
Total liabilities and equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,148,600 |
Total liabilities and equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,659,815 |

c) | The amount of depreciation, amortization and impairment charges recognized for the years ended December 31, 2020, 2019 and 2018 are as follows:

|  | For the year ended December 31, |
Depreciation, amortization and impairment by geography |  | 2020 |  |  | 2019 |  |  | 2018 |
North America |  |  | (197,643 | ) |  |  | (116,232 | ) |  |  | (166,046 | )
South America |  |  | (39,191 | ) |  |  | (47,844 | ) |  |  | (42,368 | )
EMEA |  |  | (171,770 | ) |  |  | (146,679 | ) |  |  | (154,283 | )
Total |  |  | (408,604 | ) |  |  | (310,755 | ) |  |  | (362,697 | )

|  | For the year ended December 31, |
Depreciation, amortization and impairment by business sectors |  | 2020 |  |  | 2019 |  |  | 2018 |
Renewable energy |  |  | (350,785 | ) |  |  | (286,907 | ) |  |  | (323,538 | )
Electric transmission lines |  |  | (30,889 | ) |  |  | (27,490 | ) |  |  | (28,925 | )
Efficient natural gas |  |  | (26,563 | ) |  |  | 3,102 |  |  |  | (10,334 | )
Water |  |  | (367 | ) |  |  | 541 |  |  |  | 100 |
Total |  |  | (408,604 | ) |  |  | (310,755 | ) |  |  | (362,697 | )

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Note 5.- Business combinations
For the year ended December 31, 2020
On April 3, 2020, the Company completed the investment in a 35% stake in a renewable energy platform in Chile for approximately $4 million. The first investment made by the platform has been in a 55 MW solar PV plant, Chile PV I, located in Chile. Atlantica has control over Chile PV I under IFRS 10, Consolidated Financial Statements. The acquisition of Chile PV I has been accounted for in these consolidated financial statements in accordance with IFRS 3, Business Combinations, showing 65% of Non-Controlling interest.
On May 31, 2020, the Company obtained control over the Board of Directors of Befesa Agua Tenes which owns a 51% stake in Tenes and therefore controls the asset, a water desalination plant in Algeria. The total investment, in the form of a secured loan agreement to be reimbursed through a full cash-sweep of all the dividends to be received from the asset, amounted to approximately $19 million as of May 31, 2020. The acquisition has been accounted for in the consolidated financial statements of Atlantica, in accordance with IFRS 3, Business Combinations, showing 49% of Non-Controlling interest.
The amount of assets and liabilities consolidated at the effective acquisition date is shown in the following table:

|  | Business combinations for the year-ended December 31, 2020 |
Contracted concessional assets (Note 6) |  |  | 163,064 |
Other non-current assets |  |  | 356 |
Cash & cash equivalents |  |  | 17,646 |
Other current assets |  |  | 29,998 |
Non-current Project debt (Note 15) |  |  | (149,585 | )
Current Project debt (Note 15) |  |  | (8,680 | )
Other current and non-current liabilities |  |  | (4,881 | )
Non-controlling interests |  |  | (25,308 | )
Total net assets acquired at fair value |  |  | 22,610 |
Asset acquisition - purchase price |  |  | (22,610 | )
Net result of business combinations |  |  | - |

The purchase price equals the fair value of the net assets acquired.
The allocation of the purchase prices is provisional as of December 31, 2020 and the amounts indicated above may be adjusted during the measurement period to reflect new information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the amounts recognized as of December 31, 2020. The measurement period will not exceed one year from the acquisition dates.
The amount of revenue contributed by the acquisitions performed during 2020 to the consolidated financial statements of the Company for the year 2020 is $22.5 million, and the amount of profit after tax is $6.3 million. Had the acquisitions been consolidated from January 1, 2020, the consolidated statement of comprehensive income would have included additional revenue of $14.7 million and additional profit after tax of $3.7 million.
For the year ended December 31, 2019
On August 2, 2019, the Company closed the acquisition of a 100% stake in ASI Operations LLC (“ASI Ops”), the company that performs the operation and maintenance services for the Solana and Mojave plants. The total equity investment amounted to $6 million. The acquisition has been accounted for in the consolidated financial statements of Atlantica, in accordance with IFRS 3, Business Combinations.
On October 22, 2019, the Company closed the acquisition of ATN Expansion 2 from Enel Green Power Peru, for a total equity investment of $20 million, controlling the asset from this date. The purchase has been accounted for in the consolidated accounts of Atlantica, in accordance with IFRS 3, Business Combinations.
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The amount of assets and liabilities consolidated at the effective acquisition date is shown in the following table:

|  | Business combinations for the year ended December 31, 2019 |
Concessional assets (Note 6) |  |  | 28,738 |
Current assets |  |  | 1,503 |
Deferred tax liabilities (Note 18) |  |  | (2,539 | )
Other current and non-current liabilities |  |  | (1,512 | )
Total net assets acquired at fair value |  |  | 26,190 |
Asset acquisition - purchase price |  |  | (26,190 | )
Net result of business combinations |  |  | - |

The purchase price was equal to the fair value of the net assets acquired.
The allocation of the purchase prices was provisional as of December 31, 2019 for some of the acquisitions that were made effective near to year end. No significant adjustments were made in 2020 to the amounts indicated in the table above during the measurement period (one year from the acquisition dates).
The amount of revenue contributed by the acquisitions performed during 2019 to the consolidated financial statements of the Company for the year 2019 was $0.3 million, and the amount of profit after tax was nil. Had the acquisitions been consolidated from January 1, 2019, the consolidated statement of comprehensive income would have included additional revenue of $2.3 million and additional profit after tax of $1.2 million.
Note 6.- Contracted concessional assets
Contracted concessional assets include fixed assets financed through project debt, related to service concession arrangements recorded in accordance with IFRIC 12, except for Palmucho, which is recorded in accordance with IFRS 16, and PS10, PS20, Seville PV, Mini-Hydro, Chile TL3, ATN Expansion 2 and Chile PV I, which are recorded as property plant and equipment in accordance with IAS 16.
For further details on the application of IFRIC 12 to projects, see Appendix III.

a) | The following table shows the movements of assets included in the heading “Contracted Concessional assets” for 2020:

Cost |  |  | Financial assets under IFRIC 12 |  |  | Financial assets under IFRS 16 (Lessor) |  |  | Intangible assets under IFRIC 12 |  |  | Intangible assets under IFRS 16 (Lessee) |  |  | Other intangible assets |  |  | Property, plant and equipment |  |  | Total assets |
Total as of January 1, 2020 |  |  | 872,945 |  |  |  | 3,459 |  |  |  | 9,183,011 |  |  |  | 60,618 |  |  |  | 12,927 |  |  |  | 251,637 |  |  |  | 10,384,597 |
Additions |  |  | - |  |  |  | - |  |  |  | 29,213 |  |  |  | 1,832 |  |  |  | 557 |  |  |  | 3,753 |  |  |  | 35,355 |
Subtractions |  |  | - |  |  |  | - |  |  |  | (71,706 | ) |  |  | (954 | ) |  |  | - |  |  |  | (223 | ) |  |  | (72,883 | )
Business combinations (Note 5) |  |  | 102,560 |  |  |  | - |  |  |  | - |  |  |  | 385 |  |  |  | - |  |  |  | 63,916 |  |  |  | 166,861 |
Translation differences |  |  | (8,166 | ) |  |  | (163 | ) |  |  | 326,791 |  |  |  | 4,349 |  |  |  | 317 |  |  |  | 17,836 |  |  |  | 340,964 |
Reclassification and other movements |  |  | (30,502 | ) |  |  | (355 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (30,857 | )
Total cost |  |  | 936,837 |  |  |  | 2,941 |  |  |  | 9,467,309 |  |  |  | 66,230 |  |  |  | 13,801 |  |  |  | 336,919 |  |  |  | 10,824,037 |

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Depreciation, amortization and impairment |  | Financial assets under IFRIC 12 |  |  | Financial assets under IFRS 16 (Lessor) |  |  | Intangible assets under IFRIC 12 |  |  | Intangible assets under IFRS 16 (Lessee) |  |  | Other intangible assets |  |  | Property, plant and equipment |  |  | Total assets |
Total as of January 1, 2020 |  |  | (57,258 | ) |  |  | - |  |  |  | (2,055,946 | ) |  |  | (6,585 | ) |  |  | (3,653 | ) |  |  | (100,026 | ) |  |  | (2,223,468 | )
Additions |  |  | (27,111 | ) |  |  | - |  |  |  | (338,393 | ) |  |  | (3,527 | ) |  |  | (2,219 | ) |  |  | (13,739 | ) |  |  | (384,989 | )
Subtractions |  |  | - |  |  |  | - |  |  |  | 17,571 |  |  |  | 634 |  |  |  | - |  |  |  | 49 |  |  |  | 18,253 |
Reversal of impairment |  |  | - |  |  |  | - |  |  |  | 18,787 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 18,787 |
Business combinations (Note 5) |  |  | (3,797 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (3,797 | )
Translation differences |  |  | 476 |  |  |  | - |  |  |  | (84,538 | ) |  |  | (581 | ) |  |  | (238 | ) |  |  | (8,524 | ) |  |  | (93,405 | )
Total depreciation, amortization and impairment |  |  | (87,689 | ) |  |  | - |  |  |  | (2,442,520 | ) |  |  | (10,060 | ) |  |  | (6,111 | ) |  |  | (122,239 | ) |  |  | (2,668,619 | )

During 2020, the cost of contracted concessional assets increased primarily due to the effect of the appreciation of the Euro against the U.S. dollar for the year ended December 31,2020, compared to the year ended December 31, 2019, and to the acquisition of new concessional assets (Note 5)
This increase is mainly offset by the amortization charge for the year and the write-off registered in Solana (see below).
The decrease included in “Reclassification and other movements” is mainly due to the reclassification from the long to the short term of the current portion of the contracted concessional financial assets.
Solana storage system partial write-off
The availability in the storage system of Solana has been lower than expected in 2020 due to certain leaks identified in the storage system in the first quarter. The Company has a preliminary plan to replace some elements of the storage system, which have been written off in these consolidated financial statements through profit and loss in the line “Depreciation, amortization, and impairment charges” for an estimated net book value of approximately $48 million. The exact scope and timing of the improvements and repairs are currently under review and still need to be finalized.
Solana triggering event of impairment
The Company identified in 2020 a triggering event of impairment for Solana as a result of the underperformance of the plant in terms of production. The Company therefore performed an impairment test as of December 31, 2020, which resulted in the recoverable amount (value in use) exceeding the carrying amount of the asset by 10%. To determine the value in use of the asset, a specific discount rate has been used in each year considering changes in the debt/equity leverage ratio over the useful life of this project, resulting in the use of a range of discount rates between 3.8% and 4.3%.
An adverse change in the key assumptions which are individually used for the valuation would not lead to future impairment recognition; neither in case of a 5% decrease in generation over the entire remaining useful life (PPA) of the project nor in case of an increase of 50 basis points in the discount rate.
Change in the useful life of the solar plants in Spain
Further to the recent developments in the Energy and Climate Policy Framework adopted by Spain in 2020, the Company concluded that the expected deep transformation of the electricity sector in Spain would probably significantly reduce the market price at which the electricity is sold in the mid- to long-term. In particular, the Company believes this may impact the price captured by the Company’s solar plants in Spain after the end of the regulation in place (2035 to 2038 onwards). As a result, the price captured by the plants after 2035 to 2038 (the end of the 25 years regulatory period) would likely not be sufficient to cover operating costs. In this case, the plants would stop operating and be dismantled at that point in time.
The Company believes that it is possible that long-term price evolution and technology changes could result in scenarios where the plants may continue to operate after the end of the regulatory period. Nevertheless, given the information currently available, the Company decided to reduce the useful life of the CSP plants in Spain from 35 years to 25 years after COD. This change of estimate of the useful life, effective September 1st, 2020, is accounted for as a change in accounting estimate in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors.
The main impacts recorded prospectively in these consolidated financial statements are:

| - | an increased amortization charge from September 1st, 2020, considering the reduction in the residual useful life of the plants. The impact is approximately $23 million as of December 31, 2020, recorded within the line “Depreciation, amortization and impairment charges” in the profit and loss statement.

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| - | an increase in the discounted value of the dismantling provision, as the dismantling of the plants would occur earlier. The provision increased by approximately $13 million as of December 31, 2020 (Note 16).

In addition, reducing the useful life of the solar plants in Spain is a triggering event of impairment, given that the recoverable amount of the asset is negatively impacted if the plants stop operating in year 25 after COD.
The Company therefore performed an impairment test as of December 31, 2020, which resulted in the recoverable amount (value in use) exceeding the carrying amount of the assets by 6%. To determine the value in use of the assets, a specific discount rate has been used in each year considering changes in the debt/equity leverage ratio over the useful life of these projects, resulting in the use of a range of discount rates between 3.3% and 3.8%.
An adverse change in the key assumptions which are individually used for the valuation would not lead to future impairment recognition; neither in case of a 5% decrease in generation over the entire remaining useful life of the projects nor in case of an increase of 50 basis points in the discount rate.
Palmatir and Cadonal impairment reversals
As part of the triggering event analysis performed for Palmatir and Cadonal assets in 2020, the Company identified factors, such as a reduced discount rate according to favorable market conditions, increasing their recoverable amount (value in use). The Company therefore performed an impairment test as of December 31, 2020, which resulted in the reversal of impairments previously recorded, for an amount of $15.6 million and $3.1 million in Cadonal and Palmatir, respectively, recorded within the line “Depreciation, amortization and impairment charges” of the profit and loss statement.
No losses from impairment of contracted concessional assets, excluding any change in the provision for expected credit losses under IFRS 9, Financial instruments, were recorded during the years ended December 31, 2020 and 2019. The impairment provision based on the expected credit losses on contracted concessional financial assets increased by $29 million in the year ended December 31, 2020 (reversal of $6 million in the year ended December 31, 2019), primarily in ACT.

b) | The following table shows the movements of assets included in the heading “Contracted Concessional assets” for 2019:

Cost |  | Financial assets under IFRIC 12 |  |  | Financial assets under IFRS 16 (Lessor) |  |  | Intangible assets under IFRIC 12 |  |  | Intangible assets under IFRS 16 (Lessee) |  |  | Other intangible assets |  |  | Property, plant and equipment |  |  | Total assets |
Total as of January 1, 2019 |  |  | 902,508 |  |  |  | 4,068 |  |  |  | 9,265,742 |  |  |  | 60,808 |  |  |  | 4,008 |  |  |  | 238,694 |  |  |  | 10,475,828 |
Additions |  |  | - |  |  |  | - |  |  |  | 91 |  |  |  | - |  |  |  | 454 |  |  |  | 886 |  |  |  | 1,431 |
Subtractions |  |  | - |  |  |  | - |  |  |  | (22,391 | ) |  |  | (347 | ) |  |  | (15 | ) |  |  | (119 | ) |  |  | (22,872 | )
Business combinations (Note 5) |  |  | - |  |  |  | - |  |  |  | 2,067 |  |  |  | - |  |  |  | 8,548 |  |  |  | 18,123 |  |  |  | 28,738 |
Translation differences |  |  | (1,049 | ) |  |  | (295 | ) |  |  | (62,498 | ) |  |  | 157 |  |  |  | (68 | ) |  |  | (5,947 | ) |  |  | (69,700 | )
Reclassification and other movements |  |  | (28,514 | ) |  |  | (314 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (28,828 | )
Total cost |  |  | 872,945 |  |  |  | 3,459 |  |  |  | 9,183,011 |  |  |  | 60,618 |  |  |  | 12,927 |  |  |  | 251,637 |  |  |  | 10,384,597 |

Depreciation, amortization and impairment |  | Financial assets under IFRIC 12 |  |  | Financial assets under IFRS 16 (Lessor) |  |  | Intangible assets under IFRIC 12 |  |  | Intangible assets under IFRS 16 (Lessee) |  |  | Other intangible assets |  |  | Property, plant and equipment |  |  | Total assets |
Total as of January 1, 2019 |  |  | (63,285 | ) |  |  | - |  |  |  | (1,766,179 | ) |  |  | (3,341 | ) |  |  | (2,157 | ) |  |  | (91,684 | ) |  |  | (1,926,646 | )
Additions |  |  | - |  |  |  | - |  |  |  | (305,702 | ) |  |  | (3,294 | ) |  |  | (1,523 | ) |  |  | (10,147 | ) |  |  | (320,666 | )
Subtractions |  |  | 5,997 |  |  |  | - |  |  |  | 4,205 |  |  |  | - |  |  |  | - |  |  |  | 2 |  |  |  | 10,204 |
Translation differences |  |  | 30 |  |  |  | - |  |  |  | 11,730 |  |  |  | 50 |  |  |  | 27 |  |  |  | 1,803 |  |  |  | 13,640 |
Total depreciation, amortization and impairment |  |  | (57,258 | ) |  |  | - |  |  |  | (2,055,946 | ) |  |  | (6,585 | ) |  |  | (3,653 | ) |  |  | (100,026 | ) |  |  | (2,223,468 | )

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During 2019, contracted concessional assets decreased primarily due to the effect of the depreciation of the Euro against the U.S. dollar for the year ended December 31, 2019 compared to December 31, 2018 and to the amortization charge for the year.
Other relevant movements in the cost of contracted concessional assets were an increase for the acquisition of new concessional assets (Note 5), offset by a decrease for the payments received from Abengoa by Solana in January, June and December 2019 further to Abengoa´s obligation as EPC Contractor for a total amount of $22.2 million (Note 15), included in the line "Subtractions" in the table above.
The decrease included in “Reclassification and other movements” is mainly due to the reclassification from the long to the short term of the current portion of the contracted concessional financial assets.
The Company has not identified any triggering event of impairment for its contracted concessional assets, and consequently, no losses from impairment of contracted concessional assets were recorded during the year ended December 31, 2019.
Note 7.- Investments carried under the equity method
The table below shows the breakdown and the movement of the investments held in associates for 2020 and 2019:

Investments in associates |  | 2020 |  |  | 2019 |
Initial balance |  |  | 139,925 |  |  |  | 53,419 |
Share of (loss)/profit |  |  | 510 |  |  |  | 7,457 |
Distributions |  |  | (23,703 | ) |  |  | (36,780 | )
Acquisitions |  |  | - |  |  |  | 113,897 |
Others (incl. currency translation differences) |  |  | (118 | ) |  |  | 1,932 |
Final balance |  |  | 116,614 |  |  |  | 139,925 |

Decrease in investments carried under the equity method in 2020 is primarily due to distributions received from the projects Honaine for $4.5 million ($4.6 million in 2019) and Amherst for $16.1 million ($25.9 million in 2019). A significant portion of the distributions received from Amherst are distributed by the Company to Algonquin Power Co. (Note 13).
On May 24, 2019, Atlantica and Algonquin formed AYES Canada, a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. The first investment was in Amherst Island, a 75 MW wind plant in Canada owned by the project company Windlectric. Atlantica invested $4.9 million and Algonquin invested $92.3 million, both through AYES Canada, which in turn invested those funds in AIP, the holding company of Windlectric. Atlantica accounts for the investment in AIP and ultimately Windlectric under the equity method as per IAS 28, Investments in Associates and Joint Ventures. Since Atlantica has control over AYES Canada under IFRS 10 Consolidated Financial Statements, its consolidated financial statements initially showed a total investment in the Amherst Island project of $97.2 million, accounted for as “Investments carried under the equity method” and Algonquin’s portion of that investment of $92.3 million as “Non-controlling interest”.
On August 2, 2019, the Company closed the acquisition of a 30% stake in Monterrey, a 142 MW gas-fired engine facility with batteries. The total investment amounted to $42.0 million, out of which $16.7 million is an equity investment, and the rest is a shareholder loan classified as financial investments in these consolidated financial statements. The acquisition has been accounted for in the consolidated accounts of Atlantica, in accordance with IAS 28, Investments in Associates.
The tables below show a breakdown of stand-alone amounts of assets, revenues and profit and loss as well as other information of interest for the years 2020 and 2019 for the associated companies:

Company |  | % Shares |  |  | Non- current assets |  |  | Current assets |  |  | Non- current liabilities |  |  | Current liabilities |  |  | Revenue |  |  | Operating profit/ (loss) |  |  | Net profit/ (loss) |  |  | Investment under the equity method |
Evacuación Valdecaballeros, S.L. |  |  | 57.16 |  |  |  | 19,531 |  |  |  | 1,130 |  |  |  | 16,721 |  |  |  | 646 |  |  |  | 853 |  |  |  | (167 | ) |  |  | (194 | ) |  |  | 976 |
Myah Bahr Honaine, S.P.A.(*) |  |  | 25.50 |  |  |  | 165,688 |  |  |  | 57,808 |  |  |  | 71,867 |  |  |  | 12,742 |  |  |  | 50,739 |  |  |  | 30,519 |  |  |  | 12,402 |  |  |  | 39,204 |
Pectonex, R.F. Proprietary Limited |  |  | 50.00 |  |  |  | 2,743 |  |  |  | - |  |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | (168 | ) |  |  | (168 | ) |  |  | 1,587 |
Evacuación Villanueva del Rey, S.L |  |  | 40.02 |  |  |  | 3,201 |  |  |  | 134 |  |  |  | 1,861 |  |  |  | 257 |  |  |  | - |  |  |  | 52 |  |  |  | - |  |  |  | - |
Ca Ku A1, S.A.P.I de CV (PTS) |  |  | 5.00 |  |  |  | 468,131 |  |  |  | 156,528 |  |  |  | 604,986 |  |  |  | 25,773 |  |  |  | 80,240 |  |  |  | 17,415 |  |  |  | 1,615 |  |  |  | 30 |
Pemcorp SAPI de CV (**) |  |  | 30.00 |  |  |  | 127,429 |  |  |  | 121,468 |  |  |  | 258,295 |  |  |  | 4,725 |  |  |  | 28,832 |  |  |  | 3,068 |  |  |  | (6,237 | ) |  |  | 15,514 |
ABY Infraestructuras S.L.U. |  |  | 20.00 |  |  |  | 135 |  |  |  | 84 |  |  |  | - |  |  |  | 63 |  |  |  | - |  |  |  | (53 | ) |  |  | (53 | ) |  |  | 17 |
Windlectric Inc (***) |  |  | 30.00 |  |  |  | 316,251 |  |  |  | 7,229 |  |  |  | 216,765 |  |  |  | 31,403 |  |  |  | 23,663 |  |  |  | 10,451 |  |  |  | (493 | ) |  |  | 59,116 |
Other renewable energy joint ventures (****) |  |  | 50.00 |  |  |  | 323 |  |  |  | 210 |  |  |  | - |  |  |  | 19 |  |  |  | - |  |  |  | (66 | ) |  |  | (66 | ) |  |  | 169 |
As of December 31, 2020 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 116,614 |

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Company |  | % Shares |  |  | Non- current assets |  |  | Current assets |  |  | Non- current liabilities |  |  | Current liabilities |  |  | Revenue |  |  | Operating profit/ (loss) |  |  | Net profit/ (loss) |  |  | Investment under the equity method |
Evacuación Valdecaballeros, S.L. |  |  | 57.16 |  |  |  | 18,584 |  |  |  | 1,268 |  |  |  | 13,145 |  |  |  | 783 |  |  |  | 694 |  |  |  | (277 | ) |  |  | (303 | ) |  |  | 2,348 |
Myah Bahr Honaine, S.P.A.(*) |  |  | 25.50 |  |  |  | 184,332 |  |  |  | 63,148 |  |  |  | 71,614 |  |  |  | 13,562 |  |  |  | 51,504 |  |  |  | 33,372 |  |  |  | 30,186 |  |  |  | 45,222 |
Pectonex, R.F. Proprietary Limited |  |  | 50.00 |  |  |  | 3,074 |  |  |  | - |  |  |  | - |  |  |  | 2 |  |  |  | - |  |  |  | (190 | ) |  |  | (190 | ) |  |  | 1,391 |
Evacuación Villanueva del Rey, S.L |  |  | 40.02 |  |  |  | 2,946 |  |  |  | 107 |  |  |  | 1,841 |  |  |  | 225 |  |  |  | - |  |  |  | 47 |  |  |  | - |  |  |  | - |
Ca Ku A1, S.A.P.I de CV (PTS) |  |  | 5.00 |  |  |  | 486,179 |  |  |  | 55,423 |  |  |  | - |  |  |  | 543,077 |  |  |  | - |  |  |  | (39 | ) |  |  | (495 | ) |  |  | - |
Pemcorp SAPI de CV (**) |  |  | 30.00 |  |  |  | 125,301 |  |  |  | 72,669 |  |  |  | 197,324 |  |  |  | 5,090 |  |  |  | 32,302 |  |  |  | 5,737 |  |  |  | (10,073 | ) |  |  | 17,179 |
ABY Infraestructuras S.L.U. |  |  | 20.00 |  |  |  | - |  |  |  | 59 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (104 | ) |  |  | (101 | ) |  |  | 11 |
Windlectric Inc (***) |  |  | 30.00 |  |  |  | 319,041 |  |  |  | 10,655 |  |  |  | 232,938 |  |  |  | 22,424 |  |  |  | 24,867 |  |  |  | 11,125 |  |  |  | (6,537 | ) |  |  | 73,693 |
Other renewable energy joint ventures (****) |  |  | 50.00 |  |  |  | 47 |  |  |  | 146 |  |  |  | 6 |  |  |  | 70 |  |  |  | - |  |  |  | (46 | ) |  |  | (46 | ) |  |  | 81 |
As of December 31, 2019 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 139,925 |

The Company has no control over Evacuación Valdecaballeros, S.L. as all relevant decisions of this company require the approval of a minimum of shareholders accounting for more than 75% of the shares.
None of the associated companies referred to above are a listed company.
(*) Myah Bahr Honaine, S.P.A., the project entity, is 51% owned by Geida Tlemcen, S.L. which is accounted for using the equity method in these consolidated financial statements. Share of profit of Myah Bahr Honaine S.P.A. included in these consolidated financial statements amounts to $3.1 million in 2020 and $7.7 million in 2019.
(**) Pemcorp SAPI de CV, Monterrey´s project entity, is 100% owned by Arroyo Netherlands II B.V. which is accounted for under the equity method in these consolidated financial statements. Arroyo Netherlands II B.V. is 30% owned by Atlantica. Share of profit of Pemcorp SAPI de CV included in these consolidated financial statements amounts to a loss of $1.9 million in 2020 and a profit of $0.5 million in 2019.
(***) Windlectric Inc., the project entity, is 100% owned by Amherst Island Partnership which is accounted for under the equity method.
(****) Other renewable energy joint ventures correspond to investments made in the following entities: AC Renovables Sol 1 SAS Esp, PA Renovables Sol 1 SAS Esp, SJ Renovables Sun 1 SAS Esp and SJ Renovables Wind 1 SAS Esp.
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Note 8.- Financial instruments by category
Financial instruments, in addition to Contracted concessional assets disclosed in Note 6, are primarily deposits, derivatives, trade and other receivables and loans. Financial instruments by category (current and non-current), reconciled with the statement of financial position as of December 31, 2020 and 2019 are as follows:

|  | Notes |  |  | Amortized cost |  |  | Fair value through Other Comprehensive Income |  |  | Fair value through profit or loss |  |  | Balance as of December 31, 2020 |
Derivative assets |  |  | 9 |  |  |  | - |  |  |  | - |  |  |  | 1,559 |  |  |  | 1,559 |
Investment in Ten West Link |  |  |  |  |  |  | - |  |  |  | 12,896 |  |  |  | - |  |  |  | 12,896 |
Investment in Rioglass |  |  |  |  |  |  | - |  |  |  | - |  |  |  | 2,687 |  |  |  | 2,687 |
Financial assets under IFRIC 12 (short-term portion) |  |  |  |  |  |  | 178,198 |  |  |  | - |  |  |  | - |  |  |  | 178,198 |
Trade and other receivables |  |  | 11 |  |  |  | 331,735 |  |  |  | - |  |  |  | - |  |  |  | 331,735 |
Cash and cash equivalents |  |  | 12 |  |  |  | 868,501 |  |  |  | - |  |  |  | - |  |  |  | 868,501 |
Other financial investments |  |  |  |  |  |  | 94,497 |  |  |  | - |  |  |  | - |  |  |  | 94,497 |
Total financial assets |  |  |  |  |  |  | 1,472,931 |  |  |  | 12,896 |  |  |  | 4,246 |  |  |  | 1,490,073 |
Corporate debt |  |  | 14 |  |  |  | 993,725 |  |  |  | - |  |  |  | - |  |  |  | 993,725 |
Project debt |  |  | 15 |  |  |  | 5,237,614 |  |  |  | - |  |  |  | - |  |  |  | 5,237,614 |
Related parties – non-current |  |  | 10 |  |  |  | 6,810 |  |  |  | - |  |  |  | - |  |  |  | 6,810 |
Trade and other current liabilities |  |  | 17 |  |  |  | 92,557 |  |  |  | - |  |  |  | - |  |  |  | 92,557 |
Derivative liabilities |  |  | 9 |  |  |  | - |  |  |  | - |  |  |  | 328,184 |  |  |  | 328,184 |
Total financial liabilities |  |  |  |  |  |  | 6,330,707 |  |  |  | - |  |  |  | 328,184 |  |  |  | 6,658,891 |

|  | Notes |  |  | Amortized cost |  |  | Fair value through Other Comprehensive Income |  |  | Fair value through profit or loss |  |  | Balance as of December 31, 2019 |
Derivative assets |  |  | 9 |  |  |  | - |  |  |  | - |  |  |  | 5,230 |  |  |  | 5,230 |
Investment in Ten West Link |  |  |  |  |  |  | - |  |  |  | 9,874 |  |  |  | - |  |  |  | 9,874 |
Investment in Rioglass |  |  |  |  |  |  | - |  |  |  | - |  |  |  | 7,000 |  |  |  | 7,000 |
Financial assets under IFRIC 12 (short-term portion) |  |  |  |  |  |  | 160,624 |  |  |  | - |  |  |  | - |  |  |  | 160,624 |
Trade and other receivables |  |  | 11 |  |  |  | 317,568 |  |  |  | - |  |  |  | - |  |  |  | 317,568 |
Cash and cash equivalents |  |  | 12 |  |  |  | 562,795 |  |  |  | - |  |  |  | - |  |  |  | 562,795 |
Other financial investments |  |  |  |  |  |  | 127,436 |  |  |  | - |  |  |  | - |  |  |  | 127,436 |
Total financial assets |  |  |  |  |  |  | 1,168,423 |  |  |  | 9,874 |  |  |  | 12,230 |  |  |  | 1,190,527 |
Corporate debt |  |  | 14 |  |  |  | 723,791 |  |  |  | - |  |  |  | - |  |  |  | 723,791 |
Project debt |  |  | 15 |  |  |  | 4,852,348 |  |  |  | - |  |  |  | - |  |  |  | 4,852,348 |
Related parties – non-current |  |  | 10 |  |  |  | 17,115 |  |  |  | - |  |  |  | - |  |  |  | 17,115 |
Trade and other current liabilities |  |  | 17 |  |  |  | 128,062 |  |  |  | - |  |  |  | - |  |  |  | 128,062 |
Derivative liabilities |  |  | 9 |  |  |  | - |  |  |  | - |  |  |  | 298,744 |  |  |  | 298,744 |
Total financial liabilities |  |  |  |  |  |  | 5,721,316 |  |  |  | - |  |  |  | 298,744 |  |  |  | 6,020,060 |

Other financial investments as of December 31, 2020 include, among others, a loan to Monterrey (Note 7) and restricted cash for repairs or scheduled major maintenance work. As of December 31, 2019, Other financial investments additionally included a loan to Befesa Agua Tenes amounting to $13 million (Note 1).
Investment in Ten West Link is a 12.5% interest in a 114-mile transmission line in the U.S., currently under development.
Investment in Rioglass corresponds to 15.12% of the equity interest of Rioglass, a multinational solar power and renewable energy technology manufacturer, acquired in May 2019 by the Company (Note 1).
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Note 9.- Derivative financial instruments
The breakdowns of the fair value amount of the derivative financial instruments as of December 31, 2020 and 2019 are as follows:

|  | Balance as of December 31, 2020 |  |  | Balance as of December 31, 2019 |
|  | Assets |  |  | Liabilities |  |  | Assets |  |  | Liabilities |
Interest rate cash flow hedge |  |  | 898 |  |  |  | 302,302 |  |  |  | 1,619 |  |  |  | 298,744 |
Foreign exchange derivatives instruments |  |  | 661 |  |  |  | - |  |  |  | 3,610 |  |  |  | - |
Notes conversion option (Note 14) |  |  | - |  |  |  | 25,882 |  |  |  | - |  |  |  | - |
Total |  |  | 1,559 |  |  |  | 328,184 |  |  |  | 5,230 |  |  |  | 298,744 |

The derivatives are primarily interest rate cash-flow hedges. All are classified as non-current assets or non-current liabilities, as they hedge long-term financing agreements.
As stated in Note 3 to these consolidated financial statements, the general policy is to hedge variable interest rates of financing agreements using two types of hedging derivatives:

- | Interest rate swaps under which the Company receives the floating leg and pays the fixed leg; and

- | Purchased call options (cap), in exchange of a premium to fix the maximum interest rate cost.

The notional amounts hedged, strikes contracted and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, can be diverse:

- | Project debt in Euros: the Company hedges 100% of the notional amount, maturities until 2030 and average guaranteed interest rates of between 0.00% and 4.87%.

- | Project debt in U.S. dollars: the Company hedges between 72% and 100% of the notional amount, including maturities until 2034 and average guaranteed interest rates of between 1.98% and 5.27%.

The table below shows a breakdown of the maturities of notional amounts of interest rate cash flow hedge derivatives as of December 31, 2020 and 2019.

Notionals |  | Balance as of December 31, 2020 |  |  | Balance as of December 31, 2019 |
|  | Assets |  |  | Liabilities |  |  | Assets |  |  | Liabilities |
Up to 1 year |  |  | 61,364 |  |  |  | 120,874 |  |  |  | 43,266 |  |  |  | 117,574 |
Between 1 and 2 years |  |  | 296,828 |  |  |  | 249,785 |  |  |  | 45,955 |  |  |  | 124,908 |
Between 2 and 3 years |  |  | 257,548 |  |  |  | 276,111 |  |  |  | 49,259 |  |  |  | 240,570 |
Subsequent years |  |  | 292,011 |  |  |  | 852,696 |  |  |  | 455,235 |  |  |  | 1,697,033 |
Total |  | $ | 907,752 |  |  | $ | 1,499,466 |  |  | $ | 593,715 |  |  | $ | 2,180,085 |

The table below shows a breakdown of the maturity of the fair values of interest rate cash flow hedge derivatives as of December 31, 2020 and 2019:

Fair value |  | Balance as of December 31, 2020 |  |  | Balance as of December 31, 2019 |
|  | Assets |  |  | Liabilities |  |  | Assets |  |  | Liabilities |
Up to 1 year |  |  | 59 |  |  |  | (21,042 | ) |  |  | 118 |  |  |  | (18,721 | )
Between 1 and 2 years |  |  | 255 |  |  |  | (48,276 | ) |  |  | 128 |  |  |  | (19,787 | )
Between 2 and 3 years |  |  | 305 |  |  |  | (55,220 | ) |  |  | 140 |  |  |  | (21,802 | )
Subsequent years |  |  | 280 |  |  |  | (177,764 | ) |  |  | 1,234 |  |  |  | (238,434 | )
Total |  | $ | 898 |  |  | $ | (302,302 | ) |  | $ | 1,619 |  |  | $ | (298,744 | )

The net amount of the fair value of interest rate derivatives designated as cash flow hedges transferred to the consolidated income statement in 2020 is a loss of $58,381 thousand (loss of $55,765 thousand in 2019 and a loss of $67,519 thousand in 2018).
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The after-tax result accumulated in equity in connection with derivatives designated as cash flow hedges at the years ended December 31, 2020 and 2019, amount to a $96,641 thousand gain and a $73,797 thousand gain respectively.
Additionally, the Company owns following derivatives instruments:

| - | currency options with leading international financial institutions, which guarantee minimum Euro-U.S. dollar exchange rates. The strategy of the Company is to hedge the exchange rate for the net distributions from its Spanish assets after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, the strategy of the Company is to hedge 100% of its euro-denominated net exposure for the next 12 months and 75% of its euro denominated net exposure for the following 12 months, on a rolling basis. Change in fair value of these foreign exchange derivatives instruments are directly recorded in the consolidated income statement.

| - | the conversion option of notes issued in July 2020 (Note 14), which fair value is a liability of $26 million as of December 31, 2020.

Note 10.- Related parties
The related parties of the Company are primarily Algonquin and its subsidiaries, non-controlling interests (Note 13), entities accounted for under the equity method (Note 7) and directors and the senior management of the Company.
Details of balances with related parties as of December 31, 2020 and 2019 are as follows:

|  | Balance as of December 31, |
|  | 2020 |  |  | 2019 |
Credit receivables (current) |  |  | 23,067 |  |  |  | 13,350 |
Credit receivables (non-current) |  |  | 10,082 |  |  |  | 21,355 |
Total receivables from related parties |  |  | 33,149 |  |  |  | 34,705 |
Credit payables (current) |  |  | 18,477 |  |  |  | 23,979 |
Credit payables (non-current) |  |  | 6,810 |  |  |  | 17,115 |
Total payables to related parties |  |  | 25,287 |  |  |  | 41,094 |

Current credit receivables as of December 31, 2020 mainly correspond to the short-term portion of the loan to Arroyo Netherland II B.V., the holding company of Pemcorp SAPI de CV., Monterrey´s project entity (Note 7) for $15.5 million ($4.0 million as of December 31, 2019) and to a dividend to be collected from Amherst Island Partnership for $4.3 million ($5.5 million as of December 31, 2019).
Non-current credit receivables as of December 31, 2020 and December 31, 2019 correspond to the long-term portion of the loan to Arroyo Netherland II B.V.
Credit payables relate to debts with non-controlling interests partners in Kaxu, Solaben 2&3 and Solacor 1&2 for an amount of $21.1 million as of December 31, 2020 ($35.6 million as of December 31, 2019). Current credit payables also include the dividend to be paid from Atlantica Yield Energy Solutions Ltd to Algonquin for $4.2 million as of December 31, 2020 ($5.4 million as of December 31, 2019).
The transactions carried out by entities included in these consolidated financial statements with related parties not included in the consolidation perimeter of Atlantica, for the years ended December 31, 2020, 2019 and 2018 have been as follows:

|  | For the year ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Services received |  |  | - |  |  |  | - |  |  |  | (101,582 | )
Financial income |  |  | 2,017 |  |  |  | 978 |  |  |  | 3,721 |
Financial expenses |  |  | (155 | ) |  |  | (195 | ) |  |  | (398 | )

Services received in 2018 primarily included operation and maintenance services received by some assets from Abengoa and subsidiaries of Abengoa, which had been related parties during these years. Further to the sale of its remaining 16.47% stake in the Company to Algonquin on November 27, 2018, Abengoa ceased to fulfill the conditions to be a related party as per IAS 24 - Related Parties Disclosures.
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The total amount of the remuneration received by the Board of Directors of the Company, including the CEO, amounts to $3.4 million in 2020 ($2.5 million in 2019), including $1.0 million of annual bonus ($1.0 million in 2019). The increase of the total remuneration in 2020 is mainly due to the CEO having received a long-term award of $0.8 million in 2020. No long-term awards have vested in 2019. None of the directors received any pension remuneration in 2020 nor 2019.
Note 11.- Trade and other receivables
Trade and other receivable as of December 31, 2020 and 2019, consist of the following:

|  | Balance as of December 31, |
|  | 2020 |  |  | 2019 |
Trade receivables |  |  | 258,087 |  |  |  | 242,008 |
Tax receivables |  |  | 50,663 |  |  |  | 50,901 |
Prepayments |  |  | 12,074 |  |  |  | 5,150 |
Other accounts receivable |  |  | 10,911 |  |  |  | 19,508 |
Total |  |  | 331,735 |  |  |  | 317,568 |

As of December 31, 2020, and 2019, the fair value of trade and other accounts receivable does not differ significantly from its carrying value.
Trade receivables in foreign currency as of December 31, 2020 and 2019, are as follows:

|  | Balance as of December 31, |
|  | 2020 |  |  | 2019 |
Euro |  |  | 105,826 |  |  |  | 108,280 |
South African Rand |  |  | 24,121 |  |  |  | 24,289 |
Other |  |  | 6,929 |  |  |  | 4,001 |
Total |  |  | 136,876 |  |  |  | 136,570 |

Note 12.- Cash and cash equivalents
The following table shows the detail of Cash and cash equivalents as of December 31, 2020 and 2019:

|  | Balance as of December 31, |
|  | 2020 |  |  | 2019 |
Cash at bank and on hand - non restricted |  |  | 588,690 |  |  |  | 223,867 |
Cash at bank and on hand - restricted |  |  | 279,811 |  |  |  | 338,928 |
Total |  |  | 868,501 |  |  |  | 562,795 |

Cash includes funds held to satisfy the customary requirements of certain non-recourse debt agreements within the Company´s projects (Note 15) amounting to $280 million as of December 31, 2020 ($339 million as of December 31, 2019).
The following breakdown shows the main currencies in which cash and cash equivalent balances are denominated:

|  | Balance as of December 31, |
Currency |  | 2020 |  |  | 2019 |
U.S. dollar |  |  | 575,567 |  |  |  | 313,678 |
Euro |  |  | 196,431 |  |  |  | 181,961 |
South African Rand |  |  | 40,561 |  |  |  | 47,679 |
Mexican Peso |  |  | 23,570 |  |  |  | 64 |
Algerian Dinar |  |  | 21,114 |  |  |  | 9,301 |
Others |  |  | 11,258 |  |  |  | 10,176 |
Total |  |  | 868,501 |  |  |  | 562,795 |

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Note 13.- Equity
As of December 31, 2020, the share capital of the Company amounts to $10,667,087 represented by 106,670,866 ordinary shares completely subscribed and disbursed with a nominal value of $0.10 each, all in the same class and series. Each share grants one voting right.
Algonquin completed in 2018 the acquisition from Abengoa of its entire stake in Atlantica, 41.5% of the total shares of the Company, becoming the largest shareholder of the Company. On May 22, 2019, the Company issued an additional 1,384,402 ordinary shares, which were fully subscribed by Algonquin for a total amount of $30,000,000, increasing the stake of Algonquin to 42.3%. Additionally, Algonquin purchased 2,000,000 ordinary shares on May 31, 2019, increasing its stake in Atlantica to 44.2%.
On December 11, 2020 the Company closed an underwritten public offering of 5,069,200 ordinary shares, including 661,200 ordinary shares sold pursuant to the full exercise of the underwriters’ over-allotment option, at a price of $33 per new share. Gross proceeds were approximately $167 million. Given that the offering was issued through a subsidiary in Jersey, which became wholly owned by the Company at closing, and subsequently liquidated, premium on issuance was credited to a merger reserve account (Capital reserves), net of issuance costs, for $161 million. Additionally, Algonquin committed to purchase 4,020,860 ordinary shares in a private placement in order to maintain its previous equity ownership of 44.2% in the Company. The private placement closed on January 7, 2021. Gross proceeds were approximately $133 million.
Atlantica´s reserves as of December 31, 2020 are made up of share premium account and capital reserves. The share premium account reduction by $1,000,000 thousand during the year 2019, increasing capital reserves by the same amount, was made effective upon confirmation received from the High Court in the UK, pursuant to the Companies Act 2006.
Other reserves primarily include the change in fair value of cash flow hedges and its tax effect.
Accumulated currency translation differences primarily include the result of translating the financial statements of subsidiaries prepared in a foreign currency into the presentation currency of the Company, the U.S. dollar.
Accumulated deficit primarily includes results attributable to Atlantica.
Non-controlling interests fully relate to interests held by JGC in Solacor 1 and Solacor 2, by Idae in Seville PV, by Itochu Corporation in Solaben 2 and Solaben 3, by Algerian Energy Company, SPA and Sacyr Agua S.L. in Skikda , by Industrial Development Corporation of South Africa (IDC) and Kaxu Community Trust in Kaxu, by Algonquin Power Co. in AYES Canada, by Algerian Energy Company, SPA in Tenes and by our partners in the Chilean renewable energy platform in Chile PV I.
Additional information of subsidiaries including material non-controlling interests as of December 31, 2020 and 2019, are disclosed in Appendix IV.
Dividends declared during the year 2020 by the Board of Directors of the Company were:

- | On February 26, 2020, the Board of Directors declared a dividend of $0.41 per share corresponding to the fourth quarter of 2019. The dividend was paid on March 23, 2020 for a total amount of $41.7 million

- | On May 6, 2020, the Board of Directors of the Company approved a dividend of $0.41 per share corresponding to the first quarter of 2020. The dividend was paid on June 15, 2020 for a total amount of $41.7 million.

- | On July 31, 2020, the Board of Directors of the Company approved a dividend of $0.42 per share corresponding to the second quarter of 2020. The dividend was paid on September 15, 2020 for a total amount of $42.7 million.

- | On November 4, 2020, the Board of Directors declared a dividend of $0.42 per share corresponding to the third quarter of 2020. The dividend was paid on December 15, 2020 for a total amount of $42.7 million.

In addition, the Company declared dividends to non-controlling interests, primarily to Algonquin Power Co. for $14.7 million in 2020 ($25.6 million in 2019) and Algerian Energy Company, SPA for $5.6 million in 2020 ($4.1 million in 2019).
As of December 31, 2020, there was no treasury stock and there have been no transactions with treasury stock during the period then ended.
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Note 14.- Corporate debt
The breakdown of the corporate debt as of December 31, 2020 and 2019 is as follows:

|  | Balance as of December 31, |
Non-current |  | 2020 |  |  | 2019 |
Credit Facilities with financial entities |  |  | 867,933 |  |  |  | 695,085 |
Notes and Bonds |  |  | 102,144 |  |  |  | - |
Total Non-current |  |  | 970,077 |  |  |  | 695,085 |

|  | Balance as of December 31, |
Current |  | 2020 |  |  | 2019 |
Credit Facilities with financial entities |  |  | 342 |  |  |  | 789 |
Notes and Bonds |  |  | 23,306 |  |  |  | 27,917 |
Total Current |  |  | 23,648 |  |  |  | 28,706 |

On February 10, 2017, the Company issued Senior Notes due 2022, 2023, 2024 (the “Note Issuance Facility 2017”), in an aggregate principal amount of €275,000 thousand. The Note Issuance Facility 2017 was fully repaid on April 2, 2020.
On July 20, 2017, the Company signed a credit facility (the “2017 Credit Facility”) for up to €10 million, approximately $12.2 million, which is available in euros or U.S. dollars. Amounts drawn down accrue interest at a rate per year equal to EURIBOR plus 2% or LIBOR plus 2%, depending on the currency. As of December 31, 2020, the 2017 Credit Facility is fully available (€9 million drawn down as of December 31, 2019). The credit facility maturity is December 13, 2021.
On May 10, 2018, the Company entered into a $215 million revolving credit facility (the “Revolving Credit Facility”) with Royal Bank of Canada, as administrative agent and Royal Bank of Canada and Canadian Imperial Bank of Commerce, as issuers of letters of credit. Amounts drawn down accrue interest at a rate per year equal to (A) for Eurodollar rate loans, LIBOR plus a percentage determined by reference to the leverage ratio of the Company, ranging between 1.60% and 2.25% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. Federal funds brokers on such day plus ½ of 1.00%, (ii) the U.S. prime rate and (iii) LIBOR plus 1.00%, in any case, plus a percentage determined by reference to the leverage ratio of the Company, ranging between 0.60% and 1.00%. Letters of credit may be issued using up to $100 million of the Revolving Credit Facility. During the year 2019, the amount of the Revolving Credit Facility increased from $215 million to $425 million and the maturity was extended to December 31, 2022. On December 31, 2020, the Company had issued letter of credits for $10 million and, therefore, $415 million of the Revolving Credit Facility are available. On December 31, 2019 the Company had drawn down $84 million which were repaid in the third quarter of 2020.
On April 30, 2019, the Company entered into a senior unsecured note facility with a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of €268 million (the “Note Issuance Facility 2019”). The principal amount was issued on May 24, 2019. The Note Issuance Facility 2019 includes an upfront fee of 2% paid on drawdown and its maturity date is April 30, 2025. Interest accrue at a rate per annum equal to the sum of 3-month EURIBOR plus 4.50%. The interest rate on the Note Issuance Facility 2019 is fully hedged by an interest rate swap with effective date June 28, 2019 and maturity date June 30, 2022, resulting in the Company paying a net fixed interest rate of 4.24%. The Note Issuance Facility 2019 provides that the Company may capitalize interest on the notes issued thereunder for a period of up to two years from closing at the Company´s discretion, subject to certain conditions.
On October 8, 2019, the Company filed a euro commercial paper program (the “Commercial Paper”) with the Alternative Fixed Income Market (MARF) in Spain. The program had an original maturity of twelve months and was extended for another twelve-month period on October 8, 2020. The program allows Atlantica to issue short term notes over the next twelve months for up to €50 million, with such notes having a tenor of up to two years. As of December 31, 2020, the Company had €17.4 million issued and outstanding under the program at an average cost of 0.69% (€25 million as of December 31, 2019).
On April 1, 2020, the Company closed the secured 2020 Green Private Placement for €290 million (approximately $354 million). The private placement accrues interest at an annual 1.96% interest, payable quarterly and has a June 2026 maturity. Net proceeds were primarily used to fully repay the Note Issuance Facility 2017.
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On July 8, 2020, the Company entered into a senior unsecured financing (the “Note Issuance Facility 2020”) with Lucid Agency Services Limited, as agent, and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of approximately $171 million which is denominated in euros (€140 million). The Note Issuance Facility 2020 was issued on August 12, 2020, accrues interest at an annual 5.25% interest, payable quarterly and has a maturity of seven years from the closing date.
On July 17, 2020, the Company issued $100 million aggregate principal amount of 4.00% convertible bonds (the “Green Exchangeable Notes”) due 2025. On July 29, 2020, the Company closed an additional $15 million aggregate principal amount of the Green Exchangeable Notes. The notes mature on July 15, 2025 and bear interest at a rate of 4.00% per annum. The initial exchange rate of the notes is 29.1070 ordinary shares per $1,000 principal amount of notes, which is equivalent to an initial exchange price of $34.36 per ordinary share. Noteholders may exchange their notes at their option at any time prior to the close of business on the scheduled trading day immediately preceding April 15, 2025, only during certain periods and upon satisfaction of certain conditions. On or after April 15, 2025, noteholders may exchange their notes at any time. Upon exchange, the notes may be settled, at the election of the Company, into ordinary shares of Atlantica, cash or a combination thereof. The exchange rate is subject to adjustment upon the occurrence of certain events.
On December 4, 2020, the Company entered into a credit facility (the “2020 Credit Facility”) for up to €5 million, approximately $6.1 million. Amounts drawn down accrue interest at a rate per year equal to 2.50%. As of December 31, 2020, the total amount of the credit has been drawn down. The maturity date is December 4, 2025.
As per IAS 32, “Financial Instruments: Presentation”, the conversion option of the Green Exchangeable Notes is an embedded derivative classified within the line “Derivative liabilities” of these consolidated financial statements (Note 9). It was initially valued at transaction date for $10 million, and prospective changes to its fair value are accounted for directly through the profit and loss statement. The principal element of the Green Exchangeable Notes, classified within the line “Corporate debt” of these consolidated financial statements, is initially valued as the difference between the consideration received from the holders of the instrument and the value of the embedded derivative, and thereafter, at amortized cost using the effective interest method as per IFRS 9, “Financial Instruments”.
The repayment schedule for the corporate debt as of December 31, 2020 is as follows:

|  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | 2025 |  |  | Subsequent years |  |  | Total |
2017 Credit Facility |  |  | 41 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 41 |
Notes Issuance Facility 2019 |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 343,999 |  |  |  | - |  |  |  | 343,999 |
Commercial Paper |  |  | 21,224 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 21,224 |
2020 Green Private Placement |  |  | 289 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 351,026 |  |  |  | 351,315 |
Note Issuance Facility 2020 |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 166,846 |  |  |  | 166,846 |
Green Exchangeable Notes |  |  | 2,083 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 102,144 |  |  |  | - |  |  |  | 104,227 |
2020 Credit Facility |  |  | 11 |  |  |  | - |  |  |  | 2,036 |  |  |  | 2,036 |  |  |  | 1,990 |  |  |  | - |  |  |  | 6,073 |
Total |  |  | 23,648 |  |  |  | - |  |  |  | 2,036 |  |  |  | 2,036 |  |  |  | 448,133 |  |  |  | 517,872 |  |  |  | 993,725 |

The repayment schedule for the corporate debt as of December 31, 2019 was as follows:

|  | 2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | Subsequent years |  |  | Total |
Revolving Credit Facility |  |  | 701 |  |  |  | - |  |  |  | 81,164 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 81,865 |
Note Issuance Facility 2017 |  |  | 84 |  |  |  | - |  |  |  | 101,317 |  |  |  | 100,513 |  |  |  | 100,413 |  |  |  | - |  |  |  | 302,327 |
2017 Credit Facility |  |  | 4 |  |  |  | 10,085 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 10,089 |
Notes Issuance Facility 2019 |  |  | - |  |  |  | 7,938 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 293,655 |  |  |  | 301,593 |
Commercial Paper |  |  | 27,917 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 27,917 |
Total |  |  | 28,706 |  |  |  | 18,023 |  |  |  | 182,481 |  |  |  | 100,513 |  |  |  | 100,413 |  |  |  | 293,655 |  |  |  | 723,791 |

The following table details the movement in corporate debt for the years 2020 and 2019, split between cash and non-cash items:

Corporate Debt |  | 2020 |  |  | 2019 |
Initial balance |  |  | 723,791 |  |  |  | 684,073 |
Cash Flow |  |  | 171,182 |  |  |  | 6,620 |
Non-cash changes |  |  | 98,752 |  |  |  | 33,098 |
Final balance |  |  | 993,725 |  |  |  | 723,791 |

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The non-cash changes primarily relate to interests accrued and to currency translation differences.
Note 15.- Project debt
The main purpose of the Company is the long-term ownership and management of contracted concessional assets, such as renewable energy, storage, efficient natural gas, electric transmission lines and water assets, which are financed through project debt. This note shows the project debt linked to the contracted concessional assets included in Note 6 of these consolidated financial statements.
Project debt is generally used to finance contracted assets, exclusively using as a guarantee the assets and cash flows of the company or group of companies carrying out the activities financed. In most of the cases, the assets and/or contracts are set up as a guarantee to ensure the repayment of the related financing. In addition, the cash of the Company´s projects includes funds held to satisfy the customary requirements of certain non-recourse debt agreements and other restricted cash for an amount of $280 million as of December 31, 2020 ($339 million as of December 31, 2019).
Compared with corporate debt, project debt has certain key advantages, including a greater leverage and a clearly defined risk profile.
The variations in 2020 and 2019 of project debt have been the following:

|  | Project debt - long term |  |  | Project debt - short term |  |  | Total |
Balance as of December 31, 2019 |  |  | 4,069,909 |  |  |  | 782,439 |  |  |  | 4,852,348 |
Increases |  |  | 613,604 |  |  |  | 268,339 |  |  |  | 881,943 |
Decreases |  |  | (272,548 | ) |  |  | (552,770 | ) |  |  | (825,318 | )
Business combinations (Note 5) |  |  | 149,585 |  |  |  | 8,680 |  |  |  | 158,265 |
Currency translation differences |  |  | 150,506 |  |  |  | 19,869 |  |  |  | 170,375 |
Reclassifications |  |  | 214,211 |  |  |  | (214,211 | ) |  |  | - |
Balance as of December 31, 2020 |  |  | 4,925,268 |  |  |  | 312,346 |  |  |  | 5,237,614 |

The increase in total project debt as of December 31, 2020 is primarily due to:

| - | business combinations, being the acquisition of Chile PV I and Tenes for a total amount of $158 million (Note 5).

| - | a green project financing agreement entered into by Logrosán Solar Inversiones, S.A.U., the holding company of Spanish assets Solaben 1, 2, 3 and 6, closed on April 8, 2020 for a €140 million nominal amount.

| - | a non-recourse project debt refinancing of Helioenergy assets by adding a new long dated tranche of debt from an institutional investor closed on July 10, 2020, providing with a net refinancing proceeds (net “recap”) of approximately $43 million.

| - | a non-recourse, project debt financing closed on July 14, 2020 for approximately €326 million in relation to Helios, with institutional investors, which has refinanced the previous bank project debt with approximately €250 million outstanding and has canceled legacy interest rate swaps. After transaction costs and cancelation of legacy swaps, net refinancing proceeds (net “recap”) were approximately $30 million. The accumulated impact of the change in fair value of the interest rate swaps recorded in Other reserves and any difference between the nominal amount of the debt repaid and the amortized cost of the debt have been transferred to the profit and loss in line “Other financial income/(expense), net” on transaction date for a total amount of $73 million (Note 21).

| - | the higher value of debt denominated in Euro given the increase in the exchange rate of the Euro against the U.S. dollar since December 31, 2019.

The increase of Project debt during the year 2020 has been partially offset by the contractual payments of debt for the year. Interests accrued are offset by a similar amount of interests paid during the year.
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Additionally, on June 12, 2020 the Company refinanced the debt of Cadonal (Uruguay). The terms of the new debts are not substantially different from the original debts refinanced and therefore the exchange of debts instruments does not qualify for an extinguishment of the original debts under IFRS 9, ´Financial instruments´. When there is a refinancing with a non-substantial modification of the original debt, there is a gain or loss recorded in the income statement. This gain or loss is equal to the difference between the present value of the cash flows under the original terms of the former financing and the present value of the cash flows under the new financing, discounted both at the original effective interest rate. In this respect, the Company recorded a $3.8 million financial income in the profit and loss statement of the consolidated financial statements (Note 21).
Due to the PG&E Corporation and its regulated utility subsidiary, Pacific Gas and Electric Company (“PG&E”), Chapter 11 filings in January 2019, a default of the PPA agreement with PG&E occurred. Since PG&E failed to assume the PPA within 180 days from the commencement of the PG&E’s Chapter 11 proceedings, a technical event of default was triggered under the Mojave project finance agreement in July 2019. On July 1, 2020, PG&E emerged from Chapter 11. In addition, PG&E paid to Mojave the portion of the invoice corresponding to the electricity delivered for the period between January 1 and January 28, 2019. This invoice was overdue because the services relate to the pre-petition period and any payment therefore required the approval by the Bankruptcy Court. The technical event of default under the Mojave project finance agreement, which was preventing cash distributions from Mojave to Atlantica, was cured and the Company can make distributions from Mojave. As a result, as of December 31, 2020, the Company has again an unconditional right to defer the settlement of the debt for at least twelve months, and therefore the debt previously presented as current (during the year 2019) has been reclassified as non-current in accordance with the financing agreements in these consolidated financial statements.

|  | Project debt - long term |  |  | Project debt - short term |  |  | Total |
Balance as of December 31, 2018 |  |  | 4,826,659 |  |  |  | 264,455 |  |  |  | 5,091,114 |
Increases |  |  | 53,222 |  |  |  | 280,005 |  |  |  | 333,226 |
Decreases |  |  | (19,272 | ) |  |  | (516,147 | ) |  |  | (535,418 | )
Currency translation differences |  |  | (33,718 | ) |  |  | (2,855 | ) |  |  | (36,574 | )
Reclassifications |  |  | (756,981 | ) |  |  | 756,981 |  |  |  | - |
Balance as of December 31, 2019 |  |  | 4,069,909 |  |  |  | 782,439 |  |  |  | 4,852,348 |

The line “Increases” included primarily accrued interests for the year.
The decrease of Project debt during the year 2019 was primarily due to the contractual payments of debt for the year and the partial repayment of Solana debt using the indemnity received from Abengoa for $22.2 million (Note 6). Interests accrued were offset by a similar amount of interests paid during the year.
The repayment schedule for project debt in accordance with the financing arrangements as of December 31, 2020, is as follows and is consistent with the projected cash flows of the related projects:

2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | 2025 |  |  | Subsequent years |  |  | Total |
Interest repayment |  |  | Nominal repayment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| 19,287 |  |  |  | 293,059 |  |  |  | 328,364 |  |  |  | 355,806 |  |  |  | 371,548 |  |  |  | 508,843 |  |  |  | 3,360,707 |  |  |  | 5,237,614 |

The repayment schedule for project debt in accordance with the financing arrangements and assuming there would be no acceleration of the Mojave debt, as of December 31, 2019, was as follows and was consistent with the projected cash flows of the related projects:

2020 |  |  | 2021 |  |  | 2022 |  |  | 2023 |  |  | 2024 |  |  | Subsequent years |  |  | Total |
Interest repayment |  |  | Nominal repayment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| 12,799 |  |  |  | 256,620 |  |  |  | 262,787 |  |  |  | 293,642 |  |  |  | 319,962 |  |  |  | 335,067 |  |  |  | 3,371,724 |  |  |  | 4,852,348 |

Current and non-current loans with credit entities include amounts in foreign currencies for a total amount of $2,711,830 thousand as of December 31, 2020 ($2,291,262 thousand as of December 31, 2019).
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The following table details the movement in Project debt for the years 2020 and 2019, split between cash and non-cash items:

Project Debt |  | 2020 |  |  | 2019 |
Initial balance |  |  | 4,852,348 |  |  |  | 5,091,114 |
Cash Flow |  |  | (254,495 | ) |  |  | (531,726 | )
Non-cash changes |  |  | 639,763 |  |  |  | 292,960 |
Final balance |  |  | 5,237,614 |  |  |  | 4,852,348 |

The non-cash changes primarily relate to interests accrued, currency translation differences and the business combinations for the year.
The equivalent in U.S. dollars of the most significant foreign currency-denominated debts held by the Company is as follows:

|  | Balance as of December 31, |
Currency |  | 2020 |  |  | 2019 |
Euro |  |  | 2,240,811 |  |  |  | 1,882,618 |
South African Rand |  |  | 355,414 |  |  |  | 384,313 |
Algerian Dinar |  |  | 115,606 |  |  |  | 24,331 |
Total |  |  | 2,711,830 |  |  |  | 2,291,262 |

All of the Company’s financing agreements have a carrying amount close to its fair value.
Note 16.- Grants and other liabilities
Grants and other liabilities as of December 31, 2020 and December 31, 2019 are as follows:

|  | Balance as of December 31, |
|  | 2020 |  |  | 2019 |
Grants |  |  | 1,028,765 |  |  |  | 1,087,553 |
Other liabilities |  |  | 201,002 |  |  |  | 571,314 |
Grant and other non-current liabilities |  |  | 1,229,767 |  |  |  | 1,658,867 |

As of December 31, 2020, the amount recorded in Grants corresponds primarily to the ITC Grant awarded by the U.S. Department of the Treasury to Solana and Mojave for a total amount of $674 million ($707 million as of December 31, 2019), which was primarily used to fully repay the Solana and Mojave short-term tranche of the loan with the Federal Financing Bank. The amount recorded in Grants as a liability is progressively recorded as other income over the useful life of the asset.
The remaining balance of the “Grants” account corresponds to loans with interest rates below market rates for Solana and Mojave for a total amount of $352 million ($379 million as of December 31, 2019). Loans with the Federal Financing Bank guaranteed by the Department of Energy for these projects bear interest at a rate below market rates for these types of projects and terms. The difference between proceeds received from these loans and its fair value, is initially recorded as “Grants” in the consolidated statement of financial position, and subsequently recorded in “Other operating income” starting at the entry into operation of the plants. Total amount of income for these two types of grants for Solana and Mojave is $58.9 million and $59.0 million for the years ended December 31, 2020 and 2019, respectively.
Other liabilities included as of December 31, 2019, the investment from Liberty Interactive Corporation (”Liberty”) made on October 2, 2013 for an original amount of $300 million. The liability was recorded in Grants and other liabilities for a total amount of $380 million as of December 31, 2019 and its current portion was recorded in other current liabilities for $41 million (Note 17). The investment was made in the parent company of the project entity, in exchange for the right to receive a large part of taxable losses and distributions until such time when Liberty reaches a certain rate of return, or the Flip Date. According to the stipulations of IAS 32 and in spite of the fact that the investment of Liberty was in shares, it did not qualify as equity and had been classified as a liability as of December 31, 2019. This liability had been initially valued at fair value, calculated as the present value of expected cash-flows during the useful life of the concession, and was then measured at amortized cost in accordance with the effective interest method, considering the most updated expected future cash-flows.
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The Company acquired on August 17, 2020 Liberty´s equity interest in Solana for a total estimated purchase price of approximately $290 million, of which $272 million have already been paid. Total price includes a deferred payment and a performance earn-out based on the average annual net production of the asset in the four calendar years with the highest annual net production during the five calendar years of 2020 through 2024 (Note 1). The difference between the purchase price and the carrying amount of the liability previously recorded resulted in a $145 million gain recorded within the line “Other financial income/(expense), net” in the profit and loss statement (Note 21).
Additionally, other liabilities include $52 million of finance lease liabilities and $88 million of dismantling provision as of December 31, 2020 ($54 million and $60 million as of December 31, 2019, respectively). The increase in the dismantling provision since December 31, 2019 is primarily due to the reduction of the useful life of the CSP plants in Spain, effective September 1, 2020 (Note 6).
Note 17.- Trade payables and other current liabilities
Trade payables and other current liabilities as of December 31, 2020 and 2019 are as follows:

|  | Balance as of December 31, |
Item |  | 2020 |  |  | 2019 |
Trade accounts payables |  |  | 54,219 |  |  |  | 52,062 |
Down payments from clients |  |  | 416 |  |  |  | 565 |
Liberty (Note 16) |  |  | - |  |  |  | 41,032 |
Other accounts payables |  |  | 37,922 |  |  |  | 34,403 |
Total |  |  | 92,557 |  |  |  | 128,062 |

Trade accounts payables mainly relate to the operation and maintenance of the plants.
Nominal values of trade payables and other current liabilities are considered to approximately equal to fair values and the effect of discounting them is not significant.
Note 18.- Income Tax
All the companies of Atlantica file income taxes according to the tax regulations in force in each country on an individual basis or under consolidation tax regulations.
The consolidated income tax has been calculated as an aggregation of income tax expenses/income of each individual company. In order to calculate the taxable income of the consolidated entities individually, the accounting result is adjusted for temporary and permanent differences, recording the corresponding deferred tax assets and liabilities. At each consolidated income statement date, a current tax asset or liability is recorded, representing income taxes currently refundable or payable. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial statement and income tax purposes, as determined under enacted tax laws and rates.
Income tax payable is the result of applying the applicable tax rate in force to each tax-paying entity, in accordance with the tax laws in force in the country in which the entity is registered. Additionally, tax deductions and credits are available to certain entities, primarily relating to inter-company trades and tax treaties between various countries to prevent double taxation.
The Company offsets deferred tax assets and deferred tax liabilities in each entity where the latter has a legally enforceable right to set off current tax assets against current tax liabilities, and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.
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As of December 31, 2020, and 2019, the analysis of deferred tax assets and deferred tax liabilities is as follows:

Deferred tax assets |  | Balance as of December 31, |
from |  | 2020 |  |  | 2019 |
Net operating loss carryforwards (“NOL´s”) |  |  | 497,184 |  |  |  | 546,705 |
Temporary tax non-deductible expenses |  |  | 115,063 |  |  |  | 95,847 |
Derivatives financial instruments |  |  | 83,847 |  |  |  | 86,096 |
Other |  |  | 3,021 |  |  |  | - |
Total deferred tax assets |  |  | 699,115 |  |  |  | 728,648 |

Deferred tax liabilities |  | Balance as of December 31, |
from |  | 2020 |  |  | 2019 |
Accelerated tax amortization |  |  | 652,600 |  |  |  | 682,800 |
Other difference between tax and book value of assets |  |  | 154,969 |  |  |  | 137,192 |
Other |  |  | 179 |  |  |  | 9,686 |
Total deferred tax liabilities |  |  | 807,748 |  |  |  | 829,678 |

After offsetting deferred tax assets and deferred tax liabilities, where applicable, the resulting net amounts presented on the consolidated balance sheet are as follows:

Consolidated balance sheets classifications |  | Balance as of December 31, |
|  | 2020 |  |  | 2019 |
Deferred tax assets |  |  | 152,290 |  |  |  | 147,966 |
Deferred tax liabilities |  |  | 260,923 |  |  |  | 248,996 |
Net deferred tax liabilities |  |  | 108,633 |  |  |  | 101,030 |

Most of the NOL´s recognized as deferred tax assets corresponds to the entities in the U.S., South Africa, Perú, Chile and Spain as of December 31, 2020 and 2019.
As of December 31, 2020, deferred tax assets for non-deductible expenses are primarily due to the temporary limitation of financial expenses deductibles for tax purposes in the solar plants in Spain for $110 million ($83 million as of December 31, 2019).
Deferred tax assets for derivatives financial instruments as of December 31, 2020 mainly relate to ACT for $22 million and to solar plants in Spain for $51 million ($17 million and $61 million as of December 31, 2019, respectively).
As of December 31, 2020, deferred tax liabilities for accelerated tax amortization are primarily in Solana and Mojave for $361 million, the solar plants in Spain for $202 million and Kaxu for $90 million ($391 million, $182 million and $109 million as of December 31, 2019, respectively).
Deferred tax liabilities for other temporary differences between the tax and book value of contracted concessional assets relate primarily to ACT for $75 million, the Chilean entities for $29 million and the Peruvian entities for $32 million as of December 31, 2020 ($84 million, $29 million and $25 million as of December 31, 2019, respectively).
In relation to tax losses carryforwards and deductions pending to be used recorded as deferred tax assets, the entities evaluate their recoverability projecting forecasted taxable result for the upcoming years and taking into account their tax planning strategy. Deferred tax liabilities reversals are also considered in these projections, as well as any limitation established by tax regulations in force in each tax jurisdiction.
In addition, the Company has $329 million unrecognized net operating loss carryforwards as of December 31, 2020 ($180 million as of December 31, 2019), as it considers it is not probable that future taxable profits will be available against which these unused tax losses can be utilized.
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The movements in deferred tax assets and liabilities during the years ended December 31, 2020 and 2019 were as follows:

Deferred tax assets |  | Amount |
As of December 31, 2018 |  |  | 136,066 |
Increase/(decrease) through the consolidated income statement |  |  | 5,809 |
Increase/(decrease) through other consolidated comprehensive income (equity) |  |  | 6,147 |
Other movements |  |  | (56 | )
As of December 31, 2019 |  |  | 147,966 |
Increase/(decrease) through the consolidated income statement |  |  | 6,003 |
Increase/(decrease) through other consolidated comprehensive income (equity) |  |  | (8,698 | )
Other movements |  |  | 7,019 |
As of December 31, 2020 |  |  | 152,290 |

Deferred tax liabilities |  | Amount |
As of December 31, 2018 |  |  | 211,000 |
Increase/(decrease) through the consolidated income statement |  |  | 31,678 |
Business combinations (Note 5) |  |  | 2,539 |
Other movements |  |  | 3,779 |
As of December 31, 2019 |  |  | 248,996 |
Increase/(decrease) through the consolidated income statement |  |  | 9,675 |
Other movements |  |  | 2,252 |
As of December 31, 2020 |  |  | 260,923 |

Details of income tax for the years ended December 31, 2020, 2019 and 2018 are as follows:

|  | For the twelve-month period ended December 31, |
Item |  | 2020 |  |  | 2019 |  |  | 2018 |
Current tax |  |  | (21,205 | ) |  |  | (5,081 | ) |  |  | (468 | )
Deferred tax |  |  | (3,672 | ) |  |  | (25,869 | ) |  |  | (42,191 | )
- relating to the origination and reversal of temporary differences |  |  | (3,672 | ) |  |  | (25,869 | ) |  |  | (42,191 | )
Total income tax expense |  |  | (24,877 | ) |  |  | (30,950 | ) |  |  | (42,659 | )

The reconciliation between the theoretical income tax resulting from applying an average statutory tax rate to profit before income tax and the actual income tax expense recognized in the consolidated income statements for the years ended December 31, 2020, 2019 and 2018, are as follows:

|  | For the year ended December 31, |
Concept |  | 2020 |  |  | 2019 |  |  | 2018 |
Consolidated income before taxes |  |  | 41,751 |  |  |  | 105,558 |  |  |  | 97,928 |
Average statutory tax rate |  |  | 25 | % |  |  | 25 | % |  |  | 30 | %
Corporate income tax at average statutory tax rate |  |  | (10,438 | ) |  |  | (26,390 | ) |  |  | (29,378 | )
Income tax of associates, net |  |  | 128 |  |  |  | 1,808 |  |  |  | 1,639 |
Differences in statutory tax rates |  |  | (94 | ) |  |  | (7,076 | ) |  |  | 752 |
Unrecognized NOLs and deferred tax assets |  |  | (37,183 | ) |  |  | (14,161 | ) |  |  | (22,972 | )
Purchase of Liberty´s equity interest in Solana |  |  | 36,352 |  |  |  | - |  |  |  | - |
Other permanent differences |  |  | (8,895 | ) |  |  | 11,220 |  |  |  | 5,385 |
Other non-taxable income/(expense) |  |  | (4,747 | ) |  |  | 3,649 |  |  |  | 1,915 |
Corporate income tax |  |  | (24,877 | ) |  |  | (30,950 | ) |  |  | (42,659 | )

For the year ended December 31, 2020, the overall effective tax rate was different than the statutory rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in the UK entities, partially offset by the non-taxable gain recorded in the consolidated financial statements on the purchase of Liberty´s equity interest in Solana (Note 16).
For the years ended December 31, 2019 and 2018, the overall effective tax rate was different than the statutory rate of 25% and 30%, respectively, primarily due to unrecognized tax losses carryforwards, mainly in the UK and US entities.
The average statutory tax rate used by the Company changed in 2019 considering some changes in the statutory tax rate of some geographies over the past years.
The Company had no identified uncertain tax positions that require evaluation as of December 31, 2020 and 2019.
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Note 19.- Commitments, third-party guarantees, contingent assets and liabilities
Contractual obligations
The following tables show the breakdown of the third-party commitments and contractual obligations as of December 31, 2020 and 2019:

2020 |  | Total |  |  | 2021 |  |  | 2022 and 2023 |  |  | 2024 and 2025 |  |  | Subsequent |
Corporate debt |  |  | 993,725 |  |  |  | 23,648 |  |  |  | 2,036 |  |  |  | 450,169 |  |  |  | 517,872 |
Loans with credit institutions (project debt) |  |  | 4,123,856 |  |  |  | 261,800 |  |  |  | 583,259 |  |  |  | 770,507 |  |  |  | 2,508,290 |
Notes and bonds (project debt) |  |  | 1,113,758 |  |  |  | 50,558 |  |  |  | 100,911 |  |  |  | 109,884 |  |  |  | 852,405 |
Purchase commitments* |  |  | 1,709,660 |  |  |  | 93,791 |  |  |  | 160,211 |  |  |  | 172,776 |  |  |  | 1,282,881 |
Accrued interest estimate during the useful life of loans |  |  | 2,309,597 |  |  |  | 286,724 |  |  |  | 541,652 |  |  |  | 468,060 |  |  |  | 1,013,161 |

2019 |  | Total |  |  | 2020 |  |  | 2021 and 2022 |  |  | 2023 and 2024 |  |  | Subsequent |
Corporate debt |  |  | 723,791 |  |  |  | 28,706 |  |  |  | 200,504 |  |  |  | 200,926 |  |  |  | 293,655 |
Loans with credit institutions (project debt) |  |  | 4,105,915 |  |  |  | 241,116 |  |  |  | 504,921 |  |  |  | 598,837 |  |  |  | 2,761,041 |
Notes and bonds (project debt) |  |  | 746,433 |  |  |  | 28,304 |  |  |  | 51,508 |  |  |  | 56,192 |  |  |  | 610,429 |
Purchase commitments* |  |  | 1,758,147 |  |  |  | 84,881 |  |  |  | 186,222 |  |  |  | 173,622 |  |  |  | 1,313,422 |
Accrued interest estimate during the useful life of loans |  |  | 2,472,070 |  |  |  | 294,676 |  |  |  | 549,320 |  |  |  | 471,535 |  |  |  | 1,156,539 |

* Purchase commitments include lease commitments for $94.6 million as of December 31, 2020 ($93.0 million as of December 31, 2019), of which $5.3 million is due within one year and $89.3 million thereafter as of December 31, 2020 ($5.1 million due within one year and $87.9 million thereafter as of December 31, 2019).
Third-party guarantees
As of December 31, 2020, the overall sum of Bank Bond and Surety Insurance directly deposited by the subsidiaries of the Company as a guarantee to third parties (clients, financial entities and other third parties) amounted to $36.3 million attributed to operations of technical nature ($38.2 million as of December 31, 2019). In addition, Atlantica Sustainable Infrastructure plc issued guarantees amounting to $159.8 million as of December 31, 2020 ($130.1 million as of December 31, 2019). Guarantees issued by Atlantica Sustainable Infrastructure plc correspond mainly to guarantees provided to off-takers in PPAs, guarantees for debt service reserve accounts and guarantees for points of access for renewable energy projects.
Corporate debt guarantees
The payment obligations under the Revolving Credit Facility, the Note Issuance Facility 2020 and 2019, and the 2020 Green Private Placement are guaranteed on a senior unsecured basis by following subsidiaries of the Company: Atlantica Infrastructures, S.L.U., ABY Concessions Peru S.A., ACT Holding, S.A. de C.V., ASHUSA Inc., ASUSHI Inc. and Atlantica Investments Limited. The Revolving Credit Facility and the 2020 Green Private Placement are also secured with a pledge over the shares of the subsidiary guarantors.
Legal Proceedings
A number of Abengoa’s subcontractors and insurance companies that issued bonds covering Abengoa’s obligations under such contracts in the U.S. included some of the non-recourse subsidiaries of Atlantica in the U.S. at the time of the construction of the plants the Company currently owns as co-defendants in claims against Abengoa. Generally, the subsidiaries of Atlantica were dismissed as defendants at early stages of the processes. With respect to a claim addressed by a group of insurance companies to a number of Abengoa’s subsidiaries and to Solana for Abengoa related losses of approximately $20 million that could increase, according to the insurance companies, up to a maximum of approximately $200 million if all their exposure resulted in losses, Atlantica reached an agreement with all but one of the above-mentioned insurance companies, under which they agreed to dismiss their claims in exchange for payments of approximately $4.3 million, which were paid in 2018. The insurance company that did not join the agreement has temporarily stopped legal actions against Atlantica, and Atlantica does not expect this particular claim to have a material adverse effect on its business.
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In addition, an insurance company covering certain Abengoa’s obligations in Mexico claimed certain amounts related to a potential loss. This claim is covered by existing indemnities from Abengoa. Nevertheless, the Company reached an agreement under which Atlantica´s maximum theoretical exposure would in any case be limited to approximately $35 million, including $2.5 million to be held in an escrow account. On January 2019, the insurance company executed $2.5 million from the escrow account and Abengoa reimbursed such amount according to the indemnities in force between Atlantica and Abengoa. The payments by Atlantica would only happen if and when the actual loss has been confirmed, and after arbitration, if the Company initiates it. The Company used to have indemnities from Abengoa covering potential losses, but such indemnities are no longer valid following the insolvency filing by Abengoa S.A. in February 2021 (Note 23.3).
The Company is not a party to any other significant legal proceeding other than legal proceedings arising in the ordinary course of its business. The Company is party to various administrative and regulatory proceedings that have arisen in the ordinary course of business.
While the Company does not expect these proceedings, either individually or in the aggregate, to have a material adverse effect on its financial position or results of operations, because of the nature of these proceedings the Company is not able to predict their ultimate outcomes, some of which may be unfavorable to the Company.
Other matters
Abengoa maintains a number of obligations under EPC, O&M and other contracts, as well as indemnities covering certain potential risks. Certain of these indemnities and obligations are no longer valid after the insolvency filing by Abengoa S.A. in February 2021. In addition, a potential insolvency of Abenewco1, S.A. may also terminate the remaining obligations, indemnities and guarantees. Additionally, Abengoa represented that further to the accession to its restructuring agreement, Atlantica would not be a guarantor of any obligation of Abengoa with respect to third parties and agreed to indemnify the Company for any penalty claimed by third parties resulting from any breach in such representations. The Company has contingent assets, which have not been recognized as of December 31, 2020, related to the obligations of Abengoa referred above, which result and amounts will depend on the occurrence of uncertain future events.
Note 20.- Employee benefit expenses and other operating income and expenses
Employee benefit expenses
The table below shows employee benefit expenses and number of employees for the years ended December 31, 2020, 2019 and 2018:

|  | For the year ended December 31, |
|  | 2020 |  |  | 2019 |  |  | 2018 |
Employee benefit expenses |  |  | 54,464 |  |  |  | 32,246 |  |  |  | 15,130 |
Average monthly number of employees |  |  | 441 |  |  |  | 306 |  |  |  | 207 |

The increase in employee benefit expenses in 2020 and 2019 is primarily due to the internalization of operation and maintenance services in the U.S. solar assets of the Company, following the acquisition of ASI Operations in July 2019.
Other operating income and expenses
The table below shows the detail of Other operating income and expenses for the years ended December 31, 2020, 2019 and 2018:

|  | For the year ended December 31, |
Other operating income |  | 2020 |  |  | 2019 |  |  | 2018 |
Grants |  |  | 59,010 |  |  |  | 59,142 |  |  |  | 59,421 |
Income from various services and insurance proceeds |  |  | 40,515 |  |  |  | 34,632 |  |  |  | 34,181 |
Income from the purchase of the long-term operation and maintenance payable to Abengoa |  |  | - |  |  |  | - |  |  |  | 38,955 |
Total |  |  | 99,525 |  |  |  | 93,774 |  |  |  | 132,557 |

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|  | For the year ended December 31, |
Other operating expenses |  | 2020 |  |  | 2019 |  |  | 2018 |
Raw materials and consumables used |  |  | (7,792 | ) |  |  | (9,719 | ) |  |  | (10,648 | )
Leases and fees |  |  | (2,531 | ) |  |  | (1,850 | ) |  |  | (1,716 | )
Operation and maintenance |  |  | (110,873 | ) |  |  | (116,018 | ) |  |  | (145,857 | )
Independent professional services |  |  | (40,193 | ) |  |  | (41,579 | ) |  |  | (43,229 | )
Supplies |  |  | (27,926 | ) |  |  | (25,823 | ) |  |  | (25,947 | )
Insurance |  |  | (37,638 | ) |  |  | (23,971 | ) |  |  | (24,227 | )
Levies and duties |  |  | (39,820 | ) |  |  | (34,844 | ) |  |  | (37,439 | )
Other expenses |  |  | (9,891 | ) |  |  | (7,971 | ) |  |  | (21,579 | )
Total |  |  | (276,666 | ) |  |  | (261,776 | ) |  |  | (310,642 | )

Grants income mainly relate to ITC cash grants and implicit grants recorded for accounting purposes in relation to the FFB loans with interest rates below market rates in Solana and Mojave projects (Note 16).
Other operating income in 2018 includes a $39.0 million one-time gain in relation to the purchase from Abengoa of the long-term operation and maintenance payable accrued for the period up to December 31, 2017.
Note 21.- Financial expense, net
The following table sets forth financial income and expenses for the years ended December 31, 2020, 2019 and 2018:

|  | For the year ended December 31, |
Financial income |  | 2020 |  |  | 2019 |  |  | 2018 |
Interest income from loans and credits |  |  | 6,651 |  |  |  | 3,665 |  |  |  | 36,296 |
Interest rates benefits derivatives: cash flow hedges |  |  | 401 |  |  |  | 456 |  |  |  | 148 |
Total |  |  | 7,052 |  |  |  | 4,121 |  |  |  | 36,444 |

|  | For the year ended December 31, |
Financial expenses |  | 2020 |  |  | 2019 |  |  | 2018 |
Expenses due to interest: |  |  |  |  |  |  |  |  |
- Loans from credit entities |  |  | (246,676 | ) |  |  | (259,416 | ) |  |  | (256,736 | )
- Other debts |  |  | (69,561 | ) |  |  | (89,256 | ) |  |  | (100,057 | )
Interest rates losses derivatives: cash flow hedges |  |  | (62,149 | ) |  |  | (59,318 | ) |  |  | (68,226 | )
Total |  |  | (378,386 | ) |  |  | (407,990 | ) |  |  | (425,019 | )

Financial interest income from loans and credits primarily include a non-monetary financial income of $3.8 million resulting from the refinancing of the debt of Cadonal in the second quarter of 2020 (Note 15).
Financial interest income from loans and credits in 2018 primarily included a non-monetary financial income of $36.6 million resulting from the refinancing of the debts of Helios 1&2 and Helioenergy 1&2 in the second quarter of 2018.
Interests from other debts are primarily interests on the notes issued by ATS, ATN, Solaben Luxembourg, Hypesol Solar Inversiones and Atlantica Sustainable Infrastructure Jersey, and interests related to the investment from Liberty (Note 16). The decrease in 2020 is primarily due to the acquisition of Liberty’s equity interest in Solana in August 2020. The decrease in 2019 was primarily due to a lower increase of the amortized cost of the Liberty debt compared to the previous year.
Losses from interest rate derivatives designated as cash flow hedges correspond primarily to transfers from equity to financial expense when the hedged item is impacting the consolidated income statement.
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Net exchange differences
Net exchange differences primarily correspond to realized and unrealized exchange gains and losses on transactions in foreign currencies as part of the normal course of the business of the Company.
Other financial income/(expenses), net
The following table sets out Other financial income/(expenses), net for the years 2020, 2019 and 2018:

|  | For the year ended December 31, |
Other financial income/(expenses), net |  | 2020 |  |  | 2019 |  |  | 2018 |
Other financial income |  |  | 162,290 |  |  |  | 14,152 |  |  |  | 14,431 |
Other financial losses |  |  | (121,415 | ) |  |  | (15,305 | ) |  |  | (22,666 | )
Total |  |  | 40,875 |  |  |  | (1,153 | ) |  |  | (8,235 | )

Other financial income in 2020 include a $145 million gain further to the purchase of Liberty´s equity interest in Solana (Note 16). Residual items are primarily interests on deposits and loans, including non-monetary changes to the amortized cost of such loans. In 2019 and 2018, other financial income was primarily interests on deposits and on loans granted to third parties.
Other financial losses include in 2020 a $73 million expense further to the refinancing of the Helios 1&2 debts (Note 15) and a $16 million expense further to the change in the fair value of the conversion option of the Green Exchangeable Notes since July 2020 (Note 14). Residual items are primarily guarantees and letters of credit, other bank fees, non-monetary changes to the fair value of derivatives for which hedge accounting is not applied and of financial instruments recorded at fair value through profit and loss, and other minor financial expenses.
Note 22.- Earnings per share
Basic earnings per share for the year 2020 have been calculated by dividing the profit attributable to equity holders by the average number of shares outstanding.
Diluted earnings per share for the year 2020 have been calculated considering the potential issuance of 3,347,305 shares on settlement of the Green Exchangeable Notes (Note 14). Diluted earnings per share equal basic earnings per share for the years 2019 and 2018.

|  | For the year ended December 31, |
Item |  | 2020 |  |  | 2019 |  |  | 2018 |
Profit from continuing operations attributable to Atlantica |  |  | 11,968 |  |  |  | 62,135 |  |  |  | 41,596 |
Average number of ordinary shares outstanding (thousands) - basic |  |  | 101,879 |  |  |  | 101,063 |  |  |  | 100,217 |
Average number of ordinary shares outstanding (thousands) - diluted |  |  | 103,392 |  |  |  | 101,063 |  |  |  | 100,217 |
Earnings per share from continuing operations (US dollar per share) - basic and diluted |  |  | 0.12 |  |  |  | 0.61 |  |  |  | 0.42 |
Earnings per share from profit for the period (US dollar per share) - basic and diluted |  |  | 0.12 |  |  |  | 0.61 |  |  |  | 0.42 |

Note 23.- Other information
23.1 Restricted Net assets
Certain of the consolidated entities are restricted from remitting certain funds to Atlantica Sustainable Infrastructure plc. as a result of a number of regulatory, contractual or statutory requirements. These restrictions are mainly related to standard requirements to maintain debt service coverage ratios and other requirements from the financing arrangements. At December 31, 2020, the accumulated amount of the temporary restrictions for the entire restricted term of these affiliates was $324 million.
The Company performed a test on the restricted net assets of consolidated subsidiaries in accordance with Securities and Exchange Commission Regulation S-X Rule 12-04 and concluded the restricted net assets did not exceed 25% of the consolidated net assets of the Company as of December 31, 2020. Therefore, separate financial statements of Atlantica Sustainable Infrastructure, plc. do not have to be presented.
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23.2. United Kingdom’s exit from the European Union
On January 31, 2020, the United Kingdom (“UK”) ceased to be part of the European Union (“EU”) and entered into a transition period to, among other things, negotiate an agreement with the EU on the future terms of the UK’s relationship with the EU. On December 24, 2020, both parties announced that a trade agreement had been reached (the “Trade Agreement”), which was passed by both houses of the British parliament on December 30 and given Royal Assent on December 31, 2020, which ended the transition period.
On January 1, 2021, the UK left the EU Single Market and Customs Union, as well as all EU policies and international agreements. As a result, the free movement of persons, goods, services and capital between the UK and the EU ended, with the EU and the UK forming two separate markets and two distinct regulatory and legal frameworks. The Trade Agreement offers UK and EU companies preferential access to each other’s markets, ensuring imported goods will be free of tariffs and quotas; however, economic relations between the UK and the EU will now be on more restricted terms than existed previously. Moreover, the Trade Agreement does not incorporate the full scope of the services sector, and certain businesses such as banking and finance face a more uncertain future. At this time, the Company cannot predict the impact that the Trade Agreement and any future agreements between the UK and the EU will have on its business.
23.3 Subsequent events
On January 6, 2021, the Company closed its second investment through its renewable energy platform in Chile, with the acquisition of a 40 MW solar PV plant (“Chile PV 2”). This asset started commercial operation in 2017 and its revenue is partially contracted. Total equity investment for this new asset was approximately $5.0 million.
On January 7, 2021, Algonquin purchased 4,020,860 ordinary shares of the Company in a private placement in order to maintain its previous equity ownership of 44.2% in the Company. Gross proceeds were approximately $133 million.
In January 2021, the Company reached an agreement to increase its equity stake from 15% to 100% in Rioglass, a multinational manufacturer of solar components. The Company has closed the acquisition of 42.5% of the equity for $7 million. In addition, the Company has an option to acquire the remaining 42.5% in the same conditions until September 2021, and after that date the seller has an option to sell the 42.5% also in the same conditions. The Company intends to find partners that would co-invest in Rioglass.
On February 22, 2021, Abengoa S.A. (the holding company) filed for insolvency proceedings in Spain. Based on the public information filed in connection with these proceedings, such insolvency proceedings do not include other Abengoa companies, including Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services. Although the Company has contingency plans in place, including a potential change of supplier and/or internalization, in the short term it expects the operation and maintenance services being provided by Abengoa subsidiaries to continue to be provided by its current supplier. Currently, Atlantica does not expect any material impact in the accounting value of its contracted concessional assets as a result of the insolvency filing of Abengoa S.A. The insolvency filing by the individual company Abengoa S.A. represents a theoretical event of default under the Kaxu project finance agreement (Note 1).
On February 26, 2021, the Board of Directors of the Company approved a dividend of $0.42 per share, which is expected to be paid on March 22, 2021.
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Appendices | Appendix I

Entities included in the Group as subsidiaries as of December 31, 2020

Company name |  | Project name |  | Registered address |  | % of nominal share |  | Business
ACT Energy México, S. de R.L. de C.V. |  | ACT |  | Santa Barbara (Mexico) |  | 100.00 |  | (2)
Atlantica North America, LLC |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Atlantica Infraestructura Sostenible, S.L.U |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Atlantica Perú, S.A. |  |  |  | Lima (Peru) |  | 100.00 |  | (5)
Atlantica Sustainable Infrastructure Jersey, Ltd |  |  |  | Jersey (United Kingdom) |  | 100.00 |  | (5)
Atlantica Newco Limited |  |  |  | Brentford (United Kingdom) |  | 100.00 |  | (5)
Atlantica DCR, LLC |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
ASHUSA Inc. |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Atlantica South Africa (Pty) Ltd |  |  |  | Pretoria (South Africa) |  | 100.00 |  | (5)
ASUSHI, Inc. |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Atlantica Chile SpA |  |  |  | Santiago de Chile (Chile) |  | 100.00 |  | (5)
ATN, S.A. |  | ATN |  | Lima (Peru) |  | 100.00 |  | (1)
ATN 4, S.A |  |  |  | Lima (Peru) |  | 100.00 |  | (1)
Atlantica Transmisión Sur, S.A. |  | ATS |  | Lima (Peru) |  | 100.00 |  | (1)
ACT Holdings, S.A. de C.V. |  |  |  | Mexico D.F. (Mexico) |  | 100.00 |  | (5)
Aguas de Skikda S.P.A. |  | Skikda |  | Dely Ibrahim (Algeria) |  | 51.00 |  | (4)
Arizona Solar One, LLC. |  | Solana |  | Delaware (United States) |  | 100.00 |  | (3)
ASI Operations LLC |  |  |  | Delaware (United States) |  | 100.00 |  | (3)
ASO Holdings Company, LLC. |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Atlantica Investment Ltd. |  |  |  | Brentford (United Kingdom) |  | 100.00 |  | (5)
AYES International UK Ltd |  |  |  | Brentford (United Kingdom) |  | 100.00 |  | (5)
Atlantica Yield España S.L. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
ATN 2, S.A. |  | ATN 2 |  | Lima (Peru) |  | 100.00 |  | (1)
AY Holding Uruguay, S.A. |  |  |  | Montevideo (Uruguay) |  | 100.00 |  | (5)
Atlantica Yield Energy Solutions Canada Inc. |  |  |  | Vancouver (Canada) |  | 10.00* |  | (5)
Banitod, S.A. |  |  |  | Montevideo (Uruguay) |  | 100.00 |  | (5)
Befesa Agua Tenes |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Cadonal, S.A. |  | Cadonal |  | Montevideo (Uruguay) |  | 100.00 |  | (3)
Calgary District Heating, Inc |  |  |  | Vancouver (Canada) |  | 100.00 |  | (5)
Carpio Solar Inversiones, S.A. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Chile PV I |  | Chile PV I |  | Santiago de Chile (Chile) |  | 35.00 |  | (3)
Coropuna Transmisión, S.A |  |  |  | Lima (Peru) |  | 100.00 |  | (1)
Ecija Solar Inversiones, S.A. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
CKA1 Holding S. de R.L. de C.V. |  |  |  | Mexico D.F. (Mexico) |  | 100.00 |  | (5)
Estrellada, S.A. |  | Melowind |  | Montevideo (Uruguay) |  | 100.00 |  | (3)
Extremadura Equity Investments Sárl. |  |  |  | Luxembourg (Luxembourg) |  | 100.00 |  | (5)
Fotovoltaica Solar Sevilla, S.A. |  | Seville PV |  | Seville (Spain) |  | 80.00 |  | (3)
Geida Skikda, S.L. |  |  |  | Madrid (Spain) |  | 67.00 |  | (5)
Helioenergy Electricidad Uno, S.A. |  | Helioenergy 1 |  | Seville (Spain) |  | 100.00 |  | (3)
Helioenergy Electricidad Dos, S.A. |  | Helioenergy 2 |  | Seville (Spain) |  | 100.00 |  | (3)

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Helios I Hyperion Energy Investments, S.A. |  | Helios 1 |  | Seville (Spain) |  | 100.00 |  | (3)
Helios II Hyperion Energy Investments, S.A. |  | Helios 2 |  | Seville (Spain) |  | 100.00 |  | (3)
Hidrocañete S.A. |  | Mini-Hydro |  | Lima (Peru) |  | 100.00 |  | (3)
Hypesol Energy Holding, S.L. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Hypesol Solar Inversiones, S.A |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Kaxu Solar One (Pty) Ltd. |  | Kaxu |  | Gauteng (South Africa) |  | 51.00 |  | (3)
Logrosán Equity Investments Sárl. |  |  |  | Luxembourg (Luxembourg) |  | 100.00 |  | (5)
Logrosán Solar Inversiones, S.A. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Logrosán Solar Inversiones Dos, S.L. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Mojave Solar Holdings, LLC. |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Mojave Solar LLC. |  | Mojave |  | Delaware (United States) |  | 100.00 |  | (3)
Nesyla, S.A |  |  |  | Montevideo (Uruguay) |  | 100.00 |  | (3)
Overnight Solar LLC |  |  |  | Arizona (United States) |  | 100.00 |  | (3)
Palmatir S.A. |  | Palmatir |  | Montevideo (Uruguay) |  | 100.00 |  | (3)
Palmucho, S.A. |  | Palmucho |  | Santiago de Chile (Chile) |  | 100.00 |  | (1)
RRHH Servicios Corporativos, S. de R.L. de C.V. |  |  |  | Santa Barbara. (Mexico) |  | 100.00 |  | (5)
Sanlucar Solar, S.A. |  | PS-10 |  | Seville (Spain) |  | 100.00 |  | (3)
Solaben Electricidad Uno S.A. |  | Solaben 1 |  | Caceres (Spain) |  | 100.00 |  | (3)
Solaben Electricidad Dos S.A. |  | Solaben 2 |  | Caceres (Spain) |  | 70.00 |  | (3)
Solaben Electricidad Tres S.A. |  | Solaben 3 |  | Caceres (Spain) |  | 70.00 |  | (3)
Solaben Electricidad Seis S.A. |  | Solaben 6 |  | Caceres (Spain) |  | 100.00 |  | (3)
Solaben Luxembourg S.A. |  |  |  | Luxembourg (Luxembourg) |  | 100.00 |  | (5)
Solacor Electricidad Uno, S.A. |  | Solacor 1 |  | Seville (Spain) |  | 87.00 |  | (3)
Solacor Electricidad Dos, S.A. |  | Solacor 2 |  | Seville (Spain) |  | 87.00 |  | (3)
Atlantica Corporate Resources, S.L |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Solar Processes, S.A. |  | PS-20 |  | Seville (Spain) |  | 100.00 |  | (3)
Solnova Solar Inversiones, S.A. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Solnova Electricidad, S.A. |  | Solnova 1 |  | Seville (Spain) |  | 100.00 |  | (3)
Solnova Electricidad Tres, S.A. |  | Solnova 3 |  | Seville (Spain) |  | 100.00 |  | (3)
Solnova Electricidad Cuatro, S.A. |  | Solnova 4 |  | Seville (Spain) |  | 100.00 |  | (3)
Tenes Lilmiyah, S.P.A |  | Tenes |  | Dely Ibrahim (Algeria) |  | 51.00 |  | (4)
Sunshine Finance Jersey, Ltd |  |  |  | Jersey (United Kigdom) |  | 100.00 |  | (5)
Transmisora Mejillones, S.A. |  | Quadra 1 |  | Santiago de Chile (Chile) |  | 100.00 |  | (1)
Transmisora Baquedano, S.A. |  | Quadra 2 |  | Santiago de Chile (Chile) |  | 100.00 |  | (1)

(1) | Business sector: Electric transmission lines

(2) | Business sector: Efficient natural gas

(3) | Business sector: Renewable energy

(4) | Business sector: Water

(5) | Holding Company

* | Atlantica has control over AYES Canada Inc. under IFRS 10, Consolidated Financial Statements.

The Appendices are an integral part of the Notes to the financial statements.
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Appendices | Appendix I

Entities included in the Group as subsidiaries as of December 31, 2019

Company name |  | Project name |  | Registered address |  | % of nominal share |  | Business
ACT Energy México, S. de R.L. de C.V. |  | ACT |  | Santa Barbara (Mexico) |  | 100.00 |  | (2)
Atlantica North America LLC. |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Atlantica Infraestructura Sostenible, S.LU. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Atlantica Perú, S.A. |  |  |  | Lima (Peru) |  | 100.00 |  | (5)
Atlantica DCR LLC |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
ASHUSA Inc. |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Atlantica South Africa (Pty) Ltd |  |  |  | Pretoria (South Africa) |  | 100.00 |  | (5)
ASUSHI, Inc. |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Atlantica Chile SpA |  |  |  | Santiago de Chile (Chile) |  | 100.00 |  | (5)
ATN, S.A. |  | ATN |  | Lima (Peru) |  | 100.00 |  | (1)
Atlantica Transmisión Sur, S.A. |  | ATS |  | Lima (Peru) |  | 100.00 |  | (1)
ACT Holdings, S.A. de C.V. |  |  |  | Mexico D.F. (Mexico) |  | 100.00 |  | (5)
Aguas de Skikda S.P.A. |  | Skikda |  | Dely Ibrahim (Algeria) |  | 51.00 |  | (4)
Arizona Solar One, LLC. |  | Solana |  | Delaware (United States) |  | 100.00 |  | (3)
ASI Operations LLC |  |  |  | Delaware (United States) |  | 100.00 |  | (3)
ASO Holdings Company, LLC. |  |  |  | Delaware (United States) |  | 100.00* |  | (5)
Atlantica Investment Ltd. |  |  |  | Brentford (United Kingdom) |  | 100.00 |  | (5)
AYES International UK Ltd |  |  |  | Brentford (United Kingdom) |  | 100.00 |  | (5)
Atlantica Yield España S.L. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
ATN 2, S.A. |  | ATN 2 |  | Lima (Peru) |  | 100.00 |  | (1)
AY Holding Uruguay, S.A. |  |  |  | Montevideo (Uruguay) |  | 100.00 |  | (5)
Atlantica Yield Energy Solutions Canada Inc. |  |  |  | Vancouver (Canada) |  | 10.00** |  | (5)
Banitod, S.A. |  |  |  | Montevideo (Uruguay) |  | 100.00 |  | (5)
Cadonal, S.A. |  | Cadonal |  | Montevideo (Uruguay) |  | 100.00 |  | (3)
Carpio Solar Inversiones, S.A. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Ecija Solar Inversiones, S.A. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
CKA1 Holding S. de R.L. de C.V. |  |  |  | Mexico D.F. (Mexico) |  | 100.00 |  | (5)
Estrellada, S.A. |  | Melowind |  | Montevideo (Uruguay) |  | 100.00 |  | (3)
Extremadura Equity Investments Sárl. |  |  |  | Luxembourg (Luxembourg) |  | 100.00 |  | (5)
Fotovoltaica Solar Sevilla, S.A. |  | Seville PV |  | Seville (Spain) |  | 80.00 |  | (3)
Geida Skikda, S.L. |  |  |  | Madrid (Spain) |  | 67.00 |  | (5)
Helioenergy Electricidad Uno, S.A. |  | Helioenergy 1 |  | Seville (Spain) |  | 100.00 |  | (3)
Helioenergy Electricidad Dos, S.A. |  | Helioenergy 2 |  | Seville (Spain) |  | 100.00 |  | (3)
Helios I Hyperion Energy Investments, S.A. |  | Helios 1 |  | Seville (Spain) |  | 100.00 |  | (3)
Helios II Hyperion Energy Investments, S.A. |  | Helios 2 |  | Seville (Spain) |  | 100.00 |  | (3)
Hidrocañete S.A. |  | Mini-Hydro |  | Lima (Peru) |  | 100.00 |  | (3)
Hypesol Energy Holding, S.L. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Kaxu Solar One (Pty) Ltd. |  | Kaxu |  | Gauteng (South Africa) |  | 51.00 |  | (3)
Logrosán Equity Investments Sárl. |  |  |  | Luxembourg (Luxembourg) |  | 100.00 |  | (5)
Logrosán Solar Inversiones, S.A. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Logrosán Solar Inversiones Dos, S.L. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Mojave Solar Holdings, LLC. |  |  |  | Delaware (United States) |  | 100.00 |  | (5)
Mojave Solar LLC. |  | Mojave |  | Delaware (United States) |  | 100.00 |  | (3)
Palmatir S.A. |  | Palmatir |  | Montevideo (Uruguay) |  | 100.00 |  | (3)

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Palmucho, S.A. |  | Palmucho |  | Santiago de Chile (Chile) |  | 100.00 |  | (1)
RRHH Servicios Corporativos, S. de R.L. de C.V. |  |  |  | Santa Barbara. (Mexico) |  | 100.00 |  | (5)
Sanlucar Solar, S.A. |  | PS-10 |  | Seville (Spain) |  | 100.00 |  | (3)
Solaben Electricidad Uno S.A. |  | Solaben 1 |  | Caceres (Spain) |  | 100.00 |  | (3)
Solaben Electricidad Dos S.A. |  | Solaben 2 |  | Caceres (Spain) |  | 70.00 |  | (3)
Solaben Electricidad Tres S.A. |  | Solaben 3 |  | Caceres (Spain) |  | 70.00 |  | (3)
Solaben Electricidad Seis S.A. |  | Solaben 6 |  | Caceres (Spain) |  | 100.00 |  | (3)
Solaben Luxembourg S.A. |  |  |  | Luxembourg (Luxembourg) |  | 100.00 |  | (5)
Solacor Electricidad Uno, S.A. |  | Solacor 1 |  | Seville (Spain) |  | 87.00 |  | (3)
Solacor Electricidad Dos, S.A. |  | Solacor 2 |  | Seville (Spain) |  | 87.00 |  | (3)
Atlantica Corporate Resources, S.L. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Solar Processes, S.A. |  | PS-20 |  | Seville (Spain) |  | 100.00 |  | (3)
Solnova Solar Inversiones, S.A. |  |  |  | Seville (Spain) |  | 100.00 |  | (5)
Solnova Electricidad, S.A. |  | Solnova 1 |  | Seville (Spain) |  | 100.00 |  | (3)
Solnova Electricidad Tres, S.A. |  | Solnova 3 |  | Seville (Spain) |  | 100.00 |  | (3)
Solnova Electricidad Cuatro, S.A. |  | Solnova 4 |  | Seville (Spain) |  | 100.00 |  | (3)
Transmisora Mejillones, S.A. |  | Quadra 1 |  | Santiago de Chile (Chile) |  | 100.00 |  | (1)
Transmisora Baquedano, S.A. |  | Quadra 2 |  | Santiago de Chile (Chile) |  | 100.00 |  | (1)

(1) | Business sector: Electric transmission lines

(2) | Business sector: Efficient natural gas

(3) | Business sector: Renewable energy

(4) | Business sector: Water

(5) | Holding Company

* | 100% of Class A shares held by Liberty (US tax equity investor, non-related party) as of December 31, 2019.

** | Atlantica has control over AYES Canada Inc. under IFRS 10, Consolidated Financial Statements.

The Appendices are an integral part of the Notes to the financial statements.
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Appendices | Appendix II

Investments recorded under the equity method as of December 31, 2020

Company name |  | Project name |  | Registered address |  |  | % of nominal share |  |  | Business |
ABY Infraestructuras, S.L. |  |  |  | Seville (Spain) |  |  |  | 20.0 |  |  |  | (3 | )
AC Renovables Sol 1 S.A.S. E.S.P. |  |  |  | - |  |  |  | 50.0 |  |  |  | (3 | )
Amherst Island Partnership |  | Windlectric |  | Ontario (Canada) |  |  |  | 30.0 |  |  |  | (3 | )
Arroyo Energy Netherlands II B.V. |  | Monterrey |  | Amsterdam (Netherlands) |  |  |  | 30.0 |  |  |  | (2 | )
Ca Ku A1, S.A.P.I de CV |  |  |  | Mexico D.F. (Mexico) |  |  |  | 5.0 |  |  |  | (2 | )
Evacuacion Valdecaballeros, S.L. |  |  |  | Caceres (Spain) |  |  |  | 57.2 |  |  |  | (3 | )
Evacuación Villanueva del Rey, S.L. |  |  |  | Seville (Spain) |  |  |  | 40.0 |  |  |  | (3 | )
Geida Tlemcen S.L. |  | Honaine |  | Madrid (Spain) |  |  |  | 50.0 |  |  |  | (4 | )
PA Renovables Sol 1 S.A.S. E.S.P. |  |  |  | - |  |  |  | 50.0 |  |  |  | (3 | )
Pectonex R.F. |  |  |  | Pretoria (South Africa) |  |  |  | 50.0 |  |  |  | (3 | )
SJ Renovables Sun 1 S.A.S. E.S.P. |  |  |  | - |  |  |  | 50.0 |  |  |  | (3 | )
SJ Renovables Wind 1 S.A.S. E.S.P. |  |  |  | - |  |  |  | 50.0 |  |  |  | (3 | )

(1) | Business sector: Electric transmission lines

(2) | Business sector: Efficient natural gas

(3) | Business sector: Renewable energy

(4) | Business sector: Water

(5) | Holding Company

The Appendices are an integral part of the Notes to the consolidated financial statements.
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Investments recorded under the equity method as of December 31, 2019

Company name |  | Project name |  | Registered address |  |  | % of nominal share |  |  | Business |
ABY Infraestructuras, S.L. |  |  |  | Seville (Spain) |  |  |  | 20.0 |  |  |  | (3 | )
AC Renovables Sol 1 S.A.S. E.S.P. |  |  |  | - |  |  |  | 50.0 |  |  |  | (3 | )
Amherst Island Partnership |  | Windlectric |  | Ontario (Canada) |  |  |  | 30.0 |  |  |  | (3 | )
Arroyo Energy Netherlands II B.V. |  | Monterrey |  | Amsterdam (Netherlands) |  |  |  | 30.0 |  |  |  | (2 | )
Ca Ku A1, S.A.P.I de CV |  |  |  | Mexico D.F. (Mexico) |  |  |  | 5.0 |  |  |  | (2 | )
Evacuacion Valdecaballeros, S.L. |  |  |  | Caceres (Spain) |  |  |  | 57.2 |  |  |  | (3 | )
Evacuación Villanueva del Rey, S.L. |  |  |  | Seville (Spain) |  |  |  | 40.0 |  |  |  | (3 | )
Geida Tlemcen S.L. |  | Honaine |  | Madrid (Spain) |  |  |  | 50.0 |  |  |  | (4 | )
PA Renovables Sol 1 S.A.S. E.S.P. |  |  |  | - |  |  |  | 50.0 |  |  |  | (3 | )
Pectonex R.F. |  |  |  | Pretoria (South Africa) |  |  |  | 50.0 |  |  |  | (3 | )
SJ Renovables Sun 1 S.A.S. E.S.P. |  |  |  | - |  |  |  | 50.0 |  |  |  | (3 | )
SJ Renovables Wind 1 S.A.S. E.S.P. |  |  |  | - |  |  |  | 50.0 |  |  |  | (3 | )

(1) | Business sector: Electric transmission lines

(2) | Business sector: Efficient natural gas

(3) | Business sector: Renewable energy

(4) | Business sector: Water

(5) | Holding Company

The Appendices are an integral part of the Notes to the consolidated financial statements.
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Appendices | Appendix III-1

Projects subject to the application of IFRIC 12 interpretation based on the concession of
services as of December 31, 2020 and 2019
Description of the Arrangements
Solana
Solana is a 250 MW net (280 MW gross) solar electric generation facility located in Maricopa County, Arizona, approximately 70 miles southwest of Phoenix. Arizona Solar One LLC, or Arizona Solar, owns the Solana project. Solana includes a 22-mile 230kV transmission line and a molten salt thermal energy storage system. Solana reached COD on October 9, 2013.
Solana has a 30-year, PPA with Arizona Public Service, or APS, approved by the Arizona Corporation Commission (ACC). The PPA provides for the sale of electricity at a fixed price per MWh with annual increases of 1.84% per year. The PPA includes limitations on the amount and condition of the energy that is received by APS with minimum and maximum thresholds for delivery capacity that must not be breached.
Mojave
Mojave is a 250 MW net (280 MW gross) solar electric generation facility located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Mojave reached COD on December 1, 2014.
Mojave has a 25-year, PPA with Pacific Gas & Electric Company, or PG&E, approved by the California Public Utilities Commission (CPUC). The PPA began on COD. The PPA provides for the sale of electricity at a fixed base price per MWh without any indexation mechanism, including limitations on the amount and condition of the energy that is received by PG&E with minimum and maximum thresholds for delivery capacity that must not be breached.
Palmatir
Palmatir is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Palmatir has 25 wind turbines and each turbine has a nominal capacity of 2 MW. UTE, Uruguay’s state-owned electricity company, has agreed to purchase all energy produced by Palmatir pursuant to a 20-year PPA. UTE will pay a fixed-price tariff per MWh under the PPA, which is denominated in U.S. dollars and will be partially adjusted in January of each year according to a formula based on inflation.
Palmatir reached COD in May 2014.
Cadonal
Cadonal is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Cadonal has 25 wind turbines and each turbine has a nominal capacity of 2 MW each. UTE, Uruguay´s state-owned electricity company, has agreed to purchase all energy produced by Cadonal pursuant to a 20-year PPA.
Cadonal reached COD in December 2014.
Solaben 2 & Solaben 3
The Solaben 2 and Solaben 3 are two 50 MW Solar Power facilities and reached COD in 2012.
Renewable energy plants in Spain, like Solaben 2 and Solaben 3, are regulated through a series of laws and rulings which guarantee the owners of the plants a reasonable return for their investments. Solaben 2 and Solaben 3 sell the power they produce into the wholesale electricity market, where offer and demand are matched and the pool price is determined, and also receive additional payments from the CNMC, the Spanish state-owned regulator.
Solacor 1 & Solacor 2
The Solacor 1 and Solacor 2 are two 50 MW Solar Power facilities and reached COD in 2012. JGC Corporation holds 13% of Solacor 1 & Solacor 2, a Japanese engineering company.
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ACT
The ACT plant is a gas-fired cogeneration facility with a rated capacity of approximately 300 MW and between 550 and 800 metric tons per hour of steam. The plant includes a substation and an approximately 52 mile and 115-kilowatt transmission line.
On September 18, 2009, ACT entered into the Pemex Conversion Services Agreement, or the Pemex CSA, with Pemex. Pemex is a state-owned oil and gas company supervised by the (CRE), the Mexican state agency that regulates the energy industry. The Pemex CSA has a term of 20 years from the in-service date and will expire on March 31, 2033.
According to the Pemex CSA, ACT must provide, in exchange for a fixed price with escalation adjustments, services including the supply and transformation of natural gas and water into thermal energy and electricity. Part of the electricity is to be supplied directly to a Pemex facility nearby, allowing the (CFE) to supply less electricity to that facility. Approximately 90% of the electricity must be injected into the Mexican electricity network to be used by retail and industrial end customers of CFE in the region. Pemex is then entitled to receive an equivalent amount of energy in more than 1,000 of their facilities in other parts of the country from CFE, following an adjustment mechanism under the supervision of CFE.
The Pemex CSA is denominated in U.S. dollars. The price is a fixed tariff and will be adjusted annually, part of it according to inflation and part according to a mechanism agreed in the contract that on average over the life of the contract reflects expected inflation. The components of the price structure and yearly adjustment mechanisms were prepared by Pemex and provided to bidders as part of the request for proposal documents.
ATN
ATN is part of the Peruvian SGT (Sistema Garantizado de Transmision), which includes all transmission line concessions allocated by a bidding process by the government and is comprised of the following facilities:

(i) | the approximately 356 mile, 220kV line from Carhuamayo-Paragsha-Conococha-Kiman-Ayllu-Cajamarca Norte;

(ii) | the 4.3 mile, 138kV link between the existing Huallanca substation and Kiman Ayllu substations;

(iii) | the 1.9 mile, 138kV link between the 138kV Carhuamayo substation and the 220kV Carhuamayo substation;

(iv) | the Conococha and Kiman Ayllu substations; and

(v) | the expansion of the Cajamarca Norte, 220kV Carhuamayo, 138kV Carhuamayo and 220kV Paragsha substations.

Additionally, on December 28, 2018 ATN completed the acquisition of a 220-kV power substation and two small transmission lines to connect the lines of the Company to the Shahuindo mine located nearby (ATN Expansion 1) and, on October 22, 2019, the Company closed the acquisition of ATN Expansion 2.
Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATN a concession to construct, develop, own, operate and maintain the ATN Project. The initial concession agreement became effective on May 22, 2008 and will expire 30 years after COD of the first tranche of the line, which took place in January 2011. ATN is obliged to provide the service of transmission of electric energy through the operation and maintenance of the electric transmission line, according to the terms of the contract and the applicable law.
The laws and regulations of Peru establish the key parameters of the concession contract, the price indexation mechanism, the rights and obligations of the operator and the procedures that have to be followed in order to fix the applicable tariff, which occurs through a regulated bidding process. Once the bidding process is complete and the operator is granted the concession, the pricing of the power transmission service is established in the concession agreement. ATN has a 30-year concession agreement with a fixed-price tariff base denominated in U.S. dollars that is adjusted annually after COD of each line, in accordance with the U.S. Finished Goods Less Food and Energy Index published by the U.S. Department of Labor.
ATS
ATS is part of the Peruvian Guaranteed Transmission System, or (Sistema Garantizado de Transmisión) which includes all transmission line concessions allocated by a bidding process by the government, and is comprised of:

(i) | a 500kV electric transmission line and two short 220kV electric transmission lines, which are linked to existing substations;

(ii) | three 500kV substations; and

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(iii) | three existing substations (two existing 220kV substations and one existing 550/220kV substation), through the development of new transformers, line reactors, series reactive compensation and shunt reactions in some substations.

Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATS a concession to construct, develop, own, operate and maintain the ATS Project. The initial concession agreement became effective on July 22, 2010 and will expire 30 years after COD, which took place in January 2014. ATS is obliged to provide the service of transmission of electric energy through the operation and maintenance of the electric transmission line, according to the terms of the contract and the applicable law.
The laws and regulations of Peru establish the key parameters of the concession contract, the price indexation mechanism, the rights and obligations of the operator and the procedure that has to be followed in order to fix the applicable tariff, which occurs through a regulated bidding process. Once the bidding process is complete and the operator is granted the concession, the pricing of the power transmission service is established in the concession agreement. ATS has a 30-year concession agreement with fixed-price tariff base denominated in U.S. dollars that is adjusted annually after COD of each line, in accordance with the U.S. Finished Goods Less Food and Energy Index published by the U.S. Department of Labor.
Quadra 1 & Quadra 2
Quadra 1 is a 49-miles transmission line project and Quadra 2 is a 32-miles transmission line project, each connected to the Sierra Gorda substations.
Both projects have concession agreements with Sierra Gorda SCM. The agreements are denominated in U.S. dollars and are indexed mainly to CPI. The concession agreements each have a 21-year term that began on COD, which took place in April 2014 and March 2014 for Quadra 1 and Quadra 2, respectively.
Quadra 1 and Quadra 2 belong to the Northern Interconnected System (SING), one of the two interconnected systems into which the Chilean electricity market is divided and structured for both technical and regulatory purposes.
As part of the SING, Quadra 1 and Quadra 2 and the service they provide are regulated by several regulatory bodies, in particular: the Superintendent’s office of Electricity and Fuels (SEC), the Economic Local Dispatch Center (CDEC), the National Board of Energy CNE) and the National Environmental Board (CONAMA) and other environmental regulatory bodies.
In all these concession arrangements, the operator has all the rights necessary to manage, operate and maintain the assets and the obligation to provide the services defined above, which are clearly defined in each concession contract and in the applicable regulations in each country.
Helioenergy 1 & 2
The Helioenergy 1 and 2 solar plants are located in Ecija, Spain, and reached COD in 2011.
Renewable energy plants in Spain, like Helionergy 1 and Helionergy 2, are regulated through a series of laws and rulings which guarantee the owners of the plants a reasonable return for their investments. Helionergy 1 and Helionergy 2 sell the power they produce into the wholesale electricity market, where offer and demand are matched and the pool price is determined, and also receive additional payments from the CNMC, the Spanish state-owned regulator.
Helios 1 & 2
The Helios 1 and 2 solar plants are located in Spain and reached COD in 2012.
Solnova 1, 3 & 4
The Solnova 1, 3 and 4 solar plants are located in the municipality of Sanlucar la Mayor, Spain. The plants have 50 MW each and reached COD in 2010.
Honaine
The Honaine project is a water desalination plant located in Taffsout, Algeria. Myah Bahr Honaine Spa, or MBH, is the vehicle incorporated in Algeria for the purposes of owning the Honaine project. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua S.L., a subsidiary of Sacyr, S.A., owns indirectly the remaining 25.5% of the Honaine project.
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Honaine has a capacity of seven M ft3 per day of desalinated water and it is under operation since July 2012.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach / ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
Skikda
The Skikda project is a water desalination plant located in Skikda, Algeria. AEC owns 49% and Sacyr Agua S.L. owns indirectly the remaining 16.83% of the Skikda project.
Skikda has a capacity of 3.5 M ft3 per day of desalinated water and is in operation since February 2009. The project serves a population of 0.5 million.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach / ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
ATN 2
ATN 2, in Peru, is part of the Complementary Transmission System, or Sistema Complementario de Transmision, SCT, and is comprised of the following facilities:
(i) The approximately 130km, 220kV line from SE Cotaruse to Las Bambas;
(ii) The connection to the gate of Las Bambas Substation
(iii) The expansion of the Cotaruse 220kV substation (works assigned to Consorcio Transmantaro)
The Client is Las Bambas Mining Company.
The plant reached COD in May 2015.
The ATN2 Project has a 18-year contract period, after that, ATN2 assets will remain as property of the SPV allowing ATN2 to potentially sign a new contract. The ATN2 Project has a fixed-price tariff base denominated in U.S. dollars, partially adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. The receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to the ATN2 Project. The tariff base is intended to provide the ATN2 Project with consistent and predictable monthly revenues sufficient to cover the ATN2 Project’s operating costs and debt service and to earn an equity return. Peruvian law requires the existence of a definitive concession agreement to perform electricity transmission activities where the transmission facilities cross public land or land owned by third parties. On May 31, 2014, the Ministry of Energy granted the project a definitive concession agreement to the transmission lines of the ATN2 Project.
Kaxu
Kaxu Solar One, or Kaxu, is a 100 MW solar Conventional Parabolic Trough Project located in Paulputs in the Northern Cape Province of South Africa. Atlantica owns 51% of the Kaxu Project, while Industrial Development Corporation of South Africa owns 29% and Kaxu Community Trust owns 20%.
The project reached COD in February 2015.
Kaxu has a 20-year PPA with Eskom SOC Ltd., or Eskom, under a take or pay contract for the purchase of electricity up to the contracted capacity from the facility. Eskom purchases all the output of the Kaxu Plant under a fixed price formula in local currency subject to indexation to local inflation. The PPA expires in February 2035.
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Solaben 1 & 6
The Solaben 1&6 50 MW solar plants are located in the municipality of Logrosán, Spain and reached COD in 2013.
Melowind
Melowind is an on-shore wind farm facility wholly owned by the Company, located in Uruguay with a capacity of 50 MW. Melowind has 20 wind turbines of 2.5 MW each. The asset reached COD in November 2015.
Melowind signed a 20-year PPA with UTE in 2015, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted every year based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollars exchange rate.
Tenes
Tenes is a water desalination plant located in Algeria. Befesa Agua Tenes has a 51.0% stake in Ténès Lilmiyah SpA. The remaining 49% is owned by AEC.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the exchange rate between the U.S. dollar and local currency and yearly based on indexation mechanisms that include local inflation and U.S. inflation.
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Appendices | Appendix III-2

Projects subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2020

Project name |  | Country |  | Status(1) |  | % of Nominal Share(2) |  | Period of Concession (4)(5) | off-taker(7) | Financial/ Intangibl e(3) |  | Assets/ Investm ent |  |  | Accumulated Amortizat ion |  |  | Operating Profit/ (Loss)(8) |  | Arrangem ent Terms (price) |  | Descri ption of the Arrange ment
Renewable energy: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Solana |  | USA |  | (O) |  |  | 100.0 |  | 30 Years | APS | (I) |  |  | 1,830,148 |  |  |  | (468,323 | ) |  |  | (5,722 | ) | Fixed price per MWh with annual increases of 1.84% per year |  | 30-year PPA with APS regulated by ACC
Mojave |  | USA |  | (O) |  |  | 100.0 |  | 25 Years | PG&E | (I) |  |  | 1,557,559 |  |  |  | (374,193 | ) |  |  | 48,436 |  | Fixed price per MWh without any indexation mechanism |  | 25-year PPA with PG&E regulated by CPUC and CAEC
Palmatir |  | Uruguay |  | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 147,911 |  |  |  | (48,843 | ) |  |  | 7,971 |  | Fixed price per MWh in USD with annual increases based on inflation |  | 20-year PPA with UTE, Uruguay state-owned utility
Cadonal |  | Uruguay |  | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 121,986 |  |  |  | (37,315 | ) |  |  | 15,293 |  | Fixed price per MWh in USD with annual increases based on inflation |  | 20-year PPA with UTE, Uruguay state-owned utility
Melowind |  | Uruguay |  | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 135,977 |  |  |  | (29,598 | ) |  |  | 4,673 |  | Fixed price per MWh in USD with annual increases based on inflation |  | 20-year PPA with UTE, Uruguay state-owned utility

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Solaben 2 | Spain | (O) |  |  | 70.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 337,506 |  |  |  | (80,255 | ) |  |  | 10,222 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solaben 3 | Spain | (O) |  |  | 70.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 336,556 |  |  |  | (81,998 | ) |  |  | 10,802 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solacor 1 | Spain | (O) |  |  | 87.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 341,674 |  |  |  | (88,382 | ) |  |  | 9,359 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solacor 2 | Spain | (O) |  |  | 87.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 355,614 |  |  |  | (90,861 | ) |  |  | 9,248 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solnova 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 340,713 |  |  |  | (108,908 | ) |  |  | 14,090 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solnova 3 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 318,415 |  |  |  | (98,755 | ) |  |  | 14,331 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solnova 4 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 297,118 |  |  |  | (91,251 | ) |  |  | 13,865 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain

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Helios 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 344,533 |  |  |  | (84,144 | ) |  |  | 11,285 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Helios 2 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 335,550 |  |  |  | (80,361 | ) |  |  | 11,677 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Helioenergy 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 330,497 |  |  |  | (87,496 | ) |  |  | 11,149 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Helioenergy 2 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 331,206 |  |  |  | (84,360 | ) |  |  | 11,560 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solaben 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 332,537 |  |  |  | (70,486 | ) |  |  | 11,542 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solaben 6 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 329,203 |  |  |  | (69,659 | ) |  |  | 12,161 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Kaxu | South Africa | (O) |  |  | 51.0 |  | 20 Years | Eskom | (I) |  |  | 521,523 |  |  |  | (154,962 | ) |  |  | 41,483 |  | Take or pay contract for the purchase of electricity up to the contracted capacity from the facility. |  | 20-year PPA with Eskom SOC Ltd. With a fixed price formula in local currency subject to indexation to local inflation

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Efficient natural gas: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ACT | Mexico | (O) |  |  | 100.0 |  | 20 Years | Pemex | (F) |  |  | 580,141 |  |  |  | - |  |  |  | 75,349 |  | Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract |  | 20-year Services Agreement with Pemex, Mexican oil & gas state-owned company

Electric transmission lines: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ATS | Peru | (O) |  |  | 100.0 |  | 30 Years | Republic of Peru | (I) |  |  | 531,887 |  |  |  | (122,005 | ) |  |  | 29,339 |  | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index |  | 30-year Concession Agreement with the Peruvian Government
ATN | Peru | (O) |  |  | 100.0 |  | 30 Years | Republic of Peru | (I) |  |  | 359,912 |  |  |  | (105,618 | ) |  |  | 6,474 |  | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index |  | 30-year Concession Agreement with the Peruvian Government
Quadra I | Chile | (O) |  |  | 100.0 |  | 21 Years | Sierra Gorda | (F) |  |  | 40,381 |  |  |  | - |  |  |  | 5,362 |  | Fixed price in USD with annual adjustments indexed mainly to US CPI |  | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others

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Quadra II | Chile | (O) |  |  | 100.0 |  | 21 Years | Sierra Gorda | (F) |  |  | 55,417 |  |  |  | - |  |  |  | 4,922 |  | Fixed price in USD with annual adjustments indexed mainly to US CPI |  | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others
ATN 2 | Peru | (O) |  |  | 100.0 |  | 18 Years | Las Bambas Mining | (F) |  |  | 78,743 |  |  |  | - |  |  |  | 12,332 |  | Fixed-price tariff base denominated in U.S. dollars with Las Bambas |  | 18 years purchase agreement
Water: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Skikda | Argelia | (O) |  |  | 34.2 |  | 25 Years | Sonatrach & ADE | (F) |  |  | 77,702 |  |  |  | - |  |  |  | 13,909 |  | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE |  | 25 years purchase agreement
Honaine | Argelia | (O) |  |  | 25.5 |  | 25 Years | Sonatrach & ADE | (F) |  |  | N/A | (9) |  |  | N/A | (9) |  |  | N/A | (9) | U.S. dollar indexed take- or-pay contract with Sonatrach / ADE |  | 25 years purchase agreement
Tenes | Algeria | (O) |  |  | 51.0 |  | 25 Years | Sonatrach & ADE | (F) |  |  | 106,071 |  |  |  | - |  |  |  | 10,610 |  | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE |  | 25 years purchase agreement

(1) | In operation (O), Construction (C) as of December 31, 2020.

(2) | Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3. JGC Corporation holds 13% of the economic rights to each Solacor 1 and Solacor 2. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua, S.L., a subsidiary of Sacyr, S.A., owns the remaining 25.5% of the Honaine project. AEC owns 49% and Sacyr Agua S.L. owns the remaining 16.83% of the Skikda project. Industrial Development Corporation of South Africa (29%) & Kaxu Community Trust (20%) for the Kaxu Project. AEC owns 49% of the Tenes project.

(3) | Classified as concessional financial asset (F) or as intangible assets (I).

(4) | The infrastructure is used for its entire useful life. There are no obligations to deliver assets at the end of the concession periods, except for ATN and ATS.

(5) | Generally, there are no termination provisions other than customary clauses for situations such as bankruptcy or fraud from the operator, for example.

(6) | Sales to wholesale markets and additional fixed payments established by the Spanish government.

(7) | In each case the off-taker is the grantor.

(8) | Figures reflect the contribution to the consolidated financial statements of Atlantica Sustainable Infrastructure plc. as of December 31, 2020.

(9) | Recorded under the equity method.

The Appendices are an integral part of the Notes to the consolidated financial statements.
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Projects subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2019

Project name |  | Country |  | Status(1) |  | % of Nominal Share (2) |  | Period of Concession (4)(5) | off-taker(7) | Financial/ Intangible(3) |  | Assets/ Investm ent |  |  | Accumula ted Amortiza tion |  |  | Operati ng Profit/ (Loss)(8) |  | Arrangem ent Terms (price) |  | Descriptio n of the Arrangem ent
Renewable energy: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Solana |  | USA |  | (O) |  |  | 100.0 |  | 30 Years | APS | (I) |  |  | 1,916,268 |  |  |  | (424,627 | ) |  |  | 47,344 |  | Fixed price per MWh with annual increases of 1.84% per year |  | 30-year PPA with APS regulated by ACC
Mojave |  | USA |  | (O) |  |  | 100.0 |  | 25 Years | PG&E | (I) |  |  | 1,556,638 |  |  |  | (312,544 | ) |  |  | 49,939 |  | Fixed price per MWh without any indexation mechanism |  | 25-year PPA with PG&E regulated by CPUC and CAEC
Palmatir |  | Uruguay |  | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 148,043 |  |  |  | (43,967 | ) |  |  | 3,537 |  | Fixed price per MWh in USD with annual increases based on inflation |  | 20-year PPA with UTE, Uruguay state-owned utility
Cadonal |  | Uruguay |  | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 122,104 |  |  |  | (43,987 | ) |  |  | 2,650 |  | Fixed price per MWh in USD with annual increases based on inflation |  | 20-year PPA with UTE, Uruguay state-owned utility
Melowind |  | Uruguay |  | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 136,421 |  |  |  | (22,501 | ) |  |  | 3,826 |  | Fixed price per MWh in USD with annual increases based on inflation |  | 20-year PPA with UTE, Uruguay state-owned utility

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Solaben 2 | Spain | (O) |  |  | 70.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 308,407 |  |  |  | (63,275 | ) |  |  | 12,763 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solaben 3 | Spain | (O) |  |  | 70.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 307,174 |  |  |  | (65,072 | ) |  |  | 12,836 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solacor 1 | Spain | (O) |  |  | 87.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 311,963 |  |  |  | (70,393 | ) |  |  | 11,569 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solacor 2 | Spain | (O) |  |  | 87.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 324,834 |  |  |  | (72,228 | ) |  |  | 11,559 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solnova 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 311,759 |  |  |  | (89,172 | ) |  |  | 15,482 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solnova 3 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 292,904 |  |  |  | (80,829 | ) |  |  | 16,569 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solnova 4 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 271,943 |  |  |  | (74,523 | ) |  |  | 15,966 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain

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Helios 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 313,132 |  |  |  | (66,794 | ) |  |  | 14,095 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Helios 2 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 304,945 |  |  |  | (63,626 | ) |  |  | 14,346 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Helioenergy 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 303,316 |  |  |  | (68,486 | ) |  |  | 14,927 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Helioenergy 2 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 304,083 |  |  |  | (66,007 | ) |  |  | 16,130 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solaben 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 303,392 |  |  |  | (54,293 | ) |  |  | 12,603 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Solaben 6 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 300,209 |  |  |  | (53,641 | ) |  |  | 11,730 |  | Regulated revenue base(6) |  | Regulated revenue established by different laws and rulings in Spain
Kaxu | South Africa | (O) |  |  | 51.0 |  | 20 Years | Eskom | (I) |  |  | 543,761 |  |  |  | (132,849 | ) |  |  | 53,040 |  | Take or pay contract for the purchase of electricity up to the contracted capacity from the facility. |  | 20-year PPA with Eskom SOC Ltd. With a fixed price formula in local currency subject to indexation to local inflation

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Efficient natural gas: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ACT | Mexico | (O) |  |  | 100.0 |  | 20 Years | Pemex | (F) |  |  | 610,363 |  |  |  | - |  |  |  | 113,549 |  | Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract |  | 20-year Services Agreement with Pemex, Mexican oil & gas state-owned company

Electric transmission lines: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ATS | Peru | (O) |  |  | 100.0 |  | 30 Years | Republic of Peru | (I) |  |  | 531,779 |  |  |  | (104,201 | ) |  |  | 28,993 |  | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index |  | 30-year Concession Agreement with the Peruvian Government
ATN | Peru | (O) |  |  | 100.0 |  | 30 Years | Republic of Peru | (I) |  |  | 356,876 |  |  |  | (93,061 | ) |  |  | 5,680 |  | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index |  | 30-year Concession Agreement with the Peruvian Government
Quadra I | Chile | (O) |  |  | 100.0 |  | 21 Years | Sierra Gorda | (F) |  |  | 41,237 |  |  |  | - |  |  |  | 5,716 |  | Fixed price in USD with annual adjustments indexed mainly to US CPI |  | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others

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Quadra II | Chile | (O) |  |  | 100.0 |  | 21 Years | Sierra Gorda | (F) |  |  | 55,157 |  |  |  | - |  |  |  | 6,638 |  | Fixed price in USD with annual adjustments indexed mainly to US CPI |  | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others
ATN 2 | Peru | (O) |  |  | 100.0 |  | 18 Years | Las Bambas Mining | (F) |  |  | 80,407 |  |  |  | - |  |  |  | 14,432 |  | Fixed-price tariff base denominated in U.S. dollars with Las Bambas |  | 18 years purchase agreement
Water: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Skikda | Argelia | (O) |  |  | 34.2 |  | 25 Years | Sonatrach & ADE | (F) |  |  | 87,285 |  |  |  | - |  |  |  | 15,583 |  | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE |  | 25 years purchase agreement
Honaine | Argelia | (O) |  |  | 25.5 |  | 25 Years | Sonatrach & ADE | (F) |  |  | N/A | (9) |  |  | N/A | (9) |  |  | N/A | (9) | U.S. dollar indexed take- or-pay contract with Sonatrach / ADE |  | 25 years purchase agreement

(1) | In operation (O), Construction (C) as of December 31, 2019.

(2) | Liberty Interactive Corporation agreed to invest $300 million in Class A membership interests in exchange for a share of the dividends and the taxable loss generated by Solana on October 2, 2013. Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3. JGC Corporation holds 13% of the economic rights to each Solacor 1 and Solacor 2. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua, S.L., a subsidiary of Sacyr, S.A., owns the remaining 25.5% of the Honaine project. AEC owns 49% and Sacyr Agua S.L. owns the remaining 16.83% of the Skikda project. Industrial Development Corporation of South Africa (29%) & Kaxu Community Trust (20%) for the Kaxu Project

(3) | Classified as concessional financial asset (F) or as intangible assets (I).

(4) | The infrastructure is used for its entire useful life. There are no obligations to deliver assets at the end of the concession periods, except for ATN and ATS.

(5) | Generally, there are no termination provisions other than customary clauses for situations such as bankruptcy or fraud from the operator, for example.

(6) | Sales to wholesale markets and additional fixed payments established by the Spanish government.

(7) | In each case the off-taker is the grantor.

(8) | Figures reflect the contribution to the consolidated financial statements of Atlantica Sustainable Infrastructure plc. as of December 31, 2019.

(9) | Recorded under the equity method.

The Appendices are an integral part of the Notes to the consolidated financial statements.
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Appendices | Appendix IV

Additional information of subsidiaries including material non-controlling interest as of December 31, 2020

Subsidiary name | Non- controlling interests name |  | % of non- controlling interests held |  |  | Dividends paid to non- controlling interests |  |  | Profit/(Loss) of non- controlling interests in Atlantica consolidated net result 2020 |  |  | Non- controlling interests in Atlantica consolidated equity as of December 31, 2020 |  |  | Non- current assets* |  |  | Current Assets* |  |  | Non- current liabilities* |  |  | Current liabilities* |  |  | Net Profit /(Loss)* |  |  | Total Comprehensive income* |
Aguas de Skikda S.P.A. | Algerian Energy Company S.P.A. |  |  | 49 | %** |  |  | 3,584 |  |  |  | 1,563 |  |  |  | 44,486 |  |  |  | 75,893 |  |  |  | 28,343 |  |  |  | 22,336 |  |  |  | 7,801 |  |  |  | 2,374 |  |  |  | - |
Atlantica Yield Energy Solutions Canada Inc. | Algonquin Power Co. |  |  | 90 | % |  |  | 15,709 |  |  |  | (6 | ) |  |  | 54,924 |  |  |  | 56,308 |  |  |  | 4,312 |  |  |  | - |  |  |  | 4,292 |  |  |  | (6 | ) |  |  | - |

* Stand-alone figures as of December 31, 2020.
** Atlantica Sustainable Infrastructure plc. owns 67% of the shares in Geida Skikda, S.L., which in its turn owns 51% of Aguas de Skikda S.P.A., so that indirectly Atlantica Sustainable Infrastructure plc. owns 34.17% of Aguas de Skikda S.P.A. The table only shows information related to the non-controlling interests of the SPV, Aguas de Skikda S.P.A.
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Appendices | Appendix IV

Additional Information of subsidiaries including material non-controlling interest as of December 31, 2019

Subsidiary name | Non- controlling interests name |  | % of non- controlling interests held |  |  | Dividends paid to non- controlling interests |  |  | Profit/(Loss) of non- controlling interests in Atlantica consolidated net result 2019 |  |  | Non- controlling interests in Atlantica consolidated equity as of December 31, 2019 |  |  | Non- current assets* |  |  | Current Assets* |  |  | Non- current liabilities* |  |  | Current liabilities* |  |  | Net Profit /(Loss)* |  |  | Total Comprehensive income* |
Aguas de Skikda S.P.A. | Algerian Energy Company S.P.A. |  |  | 49 | %** |  |  | 4,116 |  |  |  | 8,473 |  |  |  | 53,215 |  |  |  | 85,668 |  |  |  | 29,363 |  |  |  | 19,945 |  |  |  | 7,726 |  |  |  | 12,477 |  |  |  | - |
Atlantica Yield Energy Solutions Canada Inc. | Algonquin Power Co. |  |  | 90 | % |  |  | 20,332 |  |  |  | - |  |  |  | 69,050 |  |  |  | 72,156 |  |  |  | 5,789 |  |  |  | - |  |  |  | 5,790 |  |  |  | - |  |  |  | - |

* Stand-alone figures as of December 31, 2019.
** Atlantica Sustainable Infrastructure plc. owns 67% of the shares in Geida Skikda, S.L., which in its turn owns 51% of Aguas de Skikda S.P.A., so that indirectly Atlantica Sustainable Infrastructure plc. owns 34.17% of Aguas de Skikda S.P.A. The table only shows information related to the non-controlling interests of the SPV, Aguas de Skikda S.P.A.
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