ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC

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		Page
CURRENCY PRESENTATION AND DEFINITIONS		7
PRESENTATION OF FINANCIAL INFORMATION		12
PRESENTATION OF INDUSTRY AND MARKET DATA		13
ITEM 1.	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS	14
ITEM 2.	OFFER STATISTICS AND EXPECTED TIMETABLE	14
ITEM 3.	KEY INFORMATION	14
A	RESERVED
B.	Capitalization and Indebtedness	14
C.	Reasons for the Offer and Use of Proceeds	14
D.	Risk Factors	14
ITEM 4.	INFORMATION ON THE COMPANY	48
A.	History and Development of the Company	48
B.	Business Overview	48
C.	Organizational Structure	87
D.	Property, Plant and Equipment	88
ITEM 4A.	UNRESOLVED STAFF COMMENTS	88
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	88
A.	Operating Results	88
B.	Liquidity and Capital Resources	105
C.	Research and Development	114
D.	Trend Information	114
E.	Critical Accounting Estimates	115
G.	Safe Harbor	120
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	121
A.	Directors and Senior Management	121
B.	Compensation	126
C.	Board Practices	141
D.	Employees	143
E.	Share Ownership	143
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	144
A.	Major Shareholders	144
B.	Related Party Transactions	145
C.	Interests of Experts and Counsel	148
ITEM 8.	FINANCIAL INFORMATION	148
A.	Consolidated Statements and Other Financial Information.	148
B.	Significant Changes	151
ITEM 9.	THE OFFER AND LISTING	151
A.	Offering and Listing Details.	151
B.	Plan of Distribution	151
C.	Markets	151
D.	Selling Shareholders	151
E.	Dilution	151
F.	Expenses of the Issue	151
ITEM 10.	ADDITIONAL INFORMATION	151
A.	Share Capital	151
B.	Memorandum and Articles of Association	151
C.	Material Contracts	151
D.	Exchange Controls	151
E.	Taxation	152
F.	Dividends and Paying Agents
G.	Statement by Experts	157
H.	Documents on Display	157
I.	Subsidiaries Information	158
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	158

ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	160
A.	Debt Securities	160
B.	Warrants and Rights	160
C.	Other Securities	160
D.	American Depositary Shares	160
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	161
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	161
ITEM 15.	CONTROLS AND PROCEDURES	161
ITEM 16.	RESERVED	162
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	162
ITEM 16B.	CODE OF ETHICS	162
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	162
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	164
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	164
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	164
ITEM 16G.	CORPORATE GOVERNANCE	165
ITEM 16H.	MINE SAFETY DISCLOSURE	165
ITEM 16I.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	165
ITEM 17.	FINANCIAL STATEMENTS	165
ITEM 18.	FINANCIAL STATEMENTS	165
ITEM 19.	EXHIBITS	166

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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 make 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, of “Item 3.D. 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, performance or achievements, to differ materially from the future results, performance or achievements expressed 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, refinance existing debt 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 and Eskom, 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 make new investments and acquisitions on favorable terms or to close outstanding acquisitions;

•	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 facilities not performing as expected, unplanned outages, higher than expected operating costs and/ or capital expenditures;

•	risks related to our exposure in the labor market;

•	potential issues arising with our employees and our O&M suppliers’ employees including disagreement with employees’ unions and subcontractors;

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•	risks related to extreme and chronic 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 our subsidiaries, our assets and our employees;

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

•	risks related to information technology systems and cyber-attacks could significantly impact our operations and business;

•	our electricity generation, our projections thereof and factors affecting production;

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

•	our ability to grow organically and investments in new assets;

•	risks related to our ability to develop renewable projects is subject to construction risks and risks associated with the arrangements with our joint venture partners;

•

risks related to our current or previous relationship with Abengoa, our former largest shareholder and currently one of our operation and maintenance suppliers, including bankruptcy, reputational risk and particularly the potential impact of Abengoa S.A.’s insolvency filing and Abenewco1, S.A.’s potential insolvency filing, as well as litigation risk;

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

•	potential impact of the continuance of the COVID-19 pandemic on our business and our off-takers’, financial condition, results of operations and cash flows;

•	reputational and financial damage caused by our off-takers PG&E, Pemex and Eskom;

•	risks related to the proposed electricity constitutional reform in Mexico and the potential impact on us;

•	our plans relating to our financings, including refinancing plans;

•	our plans relating to our “at-the-market program” and the use of proceeds from the offering thereunder;

•	risks related to recent Russian military actions across Ukraine and the potential actions and reactions of other parties that may be involved in such conflict; 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 these factors, nor can it assess the impact of each of these factors 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.

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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 “2020 Green Private Placement” refer to the €290 million (approximately $330 million) senior secured notes maturing on 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— Operating and Financial Review and Prospects— Liquidity and Capital Resources— Corporate debt agreements —2020 Green Private Placement”;

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

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

•	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, 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—ROFO Agreements”;

•	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, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019, 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;

•	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 “ATM Plan Letter Agreement” refer to the agreement by and among the Company and Algonquin dated August 3, 2021, pursuant to which the Company offers Algonquin shall have the right but not the obligation, on a quarterly basis, to purchase a number of ordinary shares to maintain its percentage interest in Atlantica at the average price of the shares sold under the Distribution Agreement in the previous quarter, as adjusted;

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

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•	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 “CAISO” refer to the California Independent System Operator;

•	references to “Calgary District Heating” or “Calgary” refer to the 55 MWt thermal capacity district heating asset in the city of Calgary which we acquired in May 2021;

•	references to “CENACE” refer to Centro Nacional de Control de Energía, the Mexican decentralized public agency, and an Independent System Operator;

•	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 “Chile TL3” refer to the 50-mile transmission line located in Chile;

•	references to “Chile TL4” refer to the 63-mile transmission line 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;

•

references to the “Distribution Agreement” refer to the agreement entered into with J.P. Morgan Securities LLC, as sales agent, dated August 3, 2021, under which the Company may offer and sell from time to time up to $150 million of our ordinary shares and pursuant to which J.P. Morgan Securities LLC may sell our ordinary shares by any method permitted by law deemed to be an “at the market offering” as defined by Rule 415(a)(4) promulgated under the Securities Act of 1933, as amended;

•	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 “ESG” refer to environmental, social and corporate governance;

•	references to “Eskom” refer to Eskom Holdings SOC Limited, together with its subsidiaries, unless the context otherwise requires;

•	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;

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•	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 “FERC” refer to the U.S. Federal Energy Regulatory Commission;

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

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

•

references to “Green Exchangeable Notes” refer to the $115 million green exchangeable senior notes due in 2025 issued by Atlantica Jersey on July 17, 2020, and fully and unconditionally guaranteed on a senior, unsecured basis, by Atlantica, as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements —Green Exchangeable Notes”;

•

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 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements —Green Project Finance”;

•	references to “Green Senior Notes” refer to the $400 million green senior notes due in 2028, as further described in “Item 5.B—Liquidity and Capital Resources— Corporate debt agreements —Green Senior Notes”;

•

references to “gross capacity” refer 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 “IAS” refer to International Accounting Standards issued by the IASB;

•	references to “IASB” refer to the International Accounting Standards Board;

•	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 IASB;

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

•	references to “Italy PV” refer to the six solar PV plants located in Italy with combined capacity of 6.2 MW;

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

•	references to “Kaxu” refer to the 100 MW solar plant located in South Africa;

•	references to “La Sierpe” refer to the 20 MW solar PV plant located in Colombia;

•	references to “Liberty GES” refer to Liberty Global Energy Solutions B.V., a subsidiary of Algonquin (formerly known as Abengoa-Algonquin Global Energy Solutions B.V. (AAGES)) which invests in the development and construction of contracted clean energy and water infrastructure assets;

•	references to “Liberty Interactive” refer to Liberty Interactive Corporation;

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•

references to “Liberty Interactive Ownership Interest in Solana” refer to Class A membership interests of ASO Holdings Company LLC (the holding company of Arizona Solar One LLC, owner of the 250 MW net (280 MW gross) solar electric generation facility located in Maricopa County, Arizona, known as the Solana plant), previously owned by Liberty Interactive and purchased by us on August 17, 2020;

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

•	references to “Liberty GES ROFO Agreement” refer to the agreement we entered into with Liberty GES on March 5, 2018, that provides us a right of first offer to purchase any of the assets offered for sale thereunder, as amended and restated from time to time;

•	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 “M ft3” refer to million standard cubic feet;

•	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 the Multinational Investment Guarantee Agency, a financial institution member of the World Bank Group which provides political insurance and credit enhancement guarantees;

•	references to “MW” refer to megawatts;

•	references to “MWh” refer to megawatt hour;

•	references to “MWt” refer to thermal megawatts;

•	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 $313 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, which was fully repaid in April 2020;

•

references to “Note Issuance Facility 2019” refer to the senior unsecured note facility dated April 30, 2019, as amended on May 14, 2019, October 23, 2020 and March 30, 2021 for a total amount of €268 million, (approximately $305 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 which was fully repaid on June 4, 2021;

•

references to “Note Issuance Facility 2020” refer to the senior unsecured note facility dated July 8, 2020, as amended on March 30, 2021 of €140 million (approximately $159 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;

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•	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 US Inland Revenue Code (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;

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

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

•	references to “PV” refer to photovoltaic power;

•

references to “Revolving Credit Facility” refer to the credit and guaranty agreement with a syndicate of banks entered into on May 10, 2018 as amended on January 24, 2019, August 2, 2019, December 17, 2019 and August 28, 2020 and March 1, 2021 providing for a senior secured revolving credit facility in an aggregate principal amount of $450 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 Liberty GES 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 the “Shareholders’ Agreement” refer to the agreement by and among Algonquin Power & Utilities Corp., Abengoa-Algonquin Global Energy Solutions and Atlantica, dated March 5, 2018, as amended;

•	references to “Skikda” refer to the seawater desalination plant in Algeria, which is 34% owned by Atlantica;

•	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, located in the municipality of Sanlucar la Mayor, Spain;

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

•	references to “Tenes” refer to Ténès Lilmiyah SpA, a water desalination plant in Algeria, which is 51% owned by Befesa Agua Tenes;

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

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

•	references to “Vento II” refer to the wind portfolio in the U.S. in which we acquired a 49% interest in June 2021; and

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

PRESENTATION OF FINANCIAL INFORMATION

The financial information as of December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019 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, 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, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership). Adjusted EBITDA previously excluded equity of profit/(loss) of associates carried under the equity method and did not include depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership). Prior periods have been presented accordingly.

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 and we aim to use it on a consistent basis moving forward 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.

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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.

Information presented as the pro-rata share of our unconsolidated affiliates reflects our proportionate ownership of each asset in our property portfolio that we do not consolidate and has been calculated by multiplying our unconsolidated affiliates’ financial statement line items by the Company’s percentage ownership thereto. Note 7 to the Annual Consolidated Financial Statements includes a description of our unconsolidated affiliates and our pro rata share thereof. We do not control the unconsolidated affiliates. Multiplying our unconsolidated affiliates’ financial statement line items by the Company’s percentage ownership may not accurately represent the legal and economic implications of holding a non-controlling interest in an unconsolidated affiliate. We include depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of our equity ownership) because we believe it assists investors in estimating the effect of such items in the profit/(loss) of associates carried under the equity method (which is included in the calculation of our Adjusted EBITDA) based on our economic interest in such unconsolidated affiliates. Each unconsolidated affiliate may report a specific line item in its financial statements in a different manner. In addition, other companies in our industry may calculate their proportionate interest in unconsolidated affiliates differently than we do, limiting the usefulness of such information as a comparative measure. Because of these limitations, the information presented as the pro-rata share of our unconsolidated affiliates should not be considered in isolation or as a substitute for our or such unconsolidated affiliates’ financial statements as reported under applicable accounting principles.

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.

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.

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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.

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. See below under this “Item 4.D—Risk Factors.” for a detailed discussion of the numerous risks and uncertainties to which the Company is subject.

Risks Related to Our Business and Our Assets

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

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Counterparties to our off-take agreements may not fulfill their obligations and, as our agreements expire, we may not be able to replace them on similar terms or at all in light of increasing competition.

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Certain agreements under which we conduct some of our operations are subject to revocation, termination or tariff reduction.

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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.

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

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Certain of our facilities may not perform as expected.

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Maintenance, expansion and refurbishment of facilities involve significant risks that could result in unplanned power outages or reduced output or availability.

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

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The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, or if the geothermal resource is lower than expected, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.

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Our insurance may be insufficient to cover relevant risks or the cost of our insurance may increase

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We may have joint venture partners or other co-investors with whom we have material disagreements

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The operation and maintenance of most of our assets is labor intensive, and therefore work stoppages by employees could harm our business.

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Revenue from some of our renewable energy facilities is or may be partially exposed to market electricity prices.

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Our information technology and communications systems are subject to cybersecurity risk and other risks. The failure of these systems could significantly impact our operations and business.

Risks Related to Our Relationship with Algonquin and Abengoa

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

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

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

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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, and may affect our reputation.

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Legal proceedings involving Abengoa S.A. and its current and previous insolvency processes and events and circumstances that led to them could affect us.

Risks Related to Our Indebtedness

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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 the ability of our project subsidiaries to make distributions Atlantica Sustainable Infrastructure plc, our ability to fund our operations, pay dividends or raise additional capital.

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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.

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Potential future defaults by our subsidiaries, off-takers, suppliers and Abengoa could adversely affect us.

Risks Related to Our Growth Strategy

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

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Our ability to develop renewable projects is subject to construction risks and risks associated with the arrangements with our joint venture partners.

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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.

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We cannot guarantee the success of our recent and future investments.

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

Risks Related to the Markets in Which We Operate

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

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Risks Related to Regulation

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We are subject to extensive governmental regulation in a number of different jurisdictions, including stringent environmental regulation.

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Government regulations could change at any time.

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Revenues in our solar assets in Spain are subject to review every six years.

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If approved, the proposed electricity constitutional reform in Mexico may have a negative impact on our current assets and might impact negatively on our ability to grow in that country.

Risks Related to Ownership of Our Shares

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

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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.

Risks Related to Taxation

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

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

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

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, electrical equipment, heat or liquids stored under pressure or at high temperatures 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. 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. 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. Although we maintain teams 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 complaints 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. Any of the foregoing could result in civil, criminal or other liabilities, reputational damage and/or financial losses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 or at all 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 15 years as of December 31, 2021.

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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 a contract default situation, or if they delayed payments, our 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.

The credit rating of Eskom 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 which is the off-taker of our Kaxu solar plant, is 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 annual report are BB-/Ba2/BB- by S&P, Moody’s and Fitch, respectively.

In addition, Pemex’s credit rating and financial condition have also weakened and is currently BBB, Ba3 and BB- from S&P, Moody’s and Fitch, respectively. We have been experiencing delays from Pemex in collections since the second half of 2019 which have been significant in certain quarters.

The cost of renewable energy has considerably decreased over the past several 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, including 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 increase in competition has contributed to a reduction in electricity prices paid by off-takers. Our competitors may be able to operate at lower costs, which may adversely affect our ability to compete for off-take agreement renewals. 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 current market prices. 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.

Our inability to enter into new or replacement off-take agreements or to compete successfully against current and future competitors 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 PPAs 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 PPAs 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 respective concession. Such commitments and standards may be amended in certain cases by the governmental bodies. Our failure to comply with the concession agreements and PPAs 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.

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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. Also, during the life of a PPA or 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. For example, in August 2021, the Arizona Corporation Commission (“ACC”) held a hearing related to different aspects of Arizona Public Service’s electricity supply during which the ACC Chairwoman raised the possibility to retroactively examine Solana’s PPA prudency. We are not aware of a precedent of a PPA prudency being reviewed by the ACC and the Solana PPA was approved by the ACC at the time of its execution. However, if the Solana PPA was effectively revised this would have a material adverse effect on our business, financial condition, results of operations and cash flows. In some cases, governments may also postpone annual tariff increases until a new tariff structure is approved without compensating energy providers for lost revenue. Furthermore, changes in laws and regulations may, in certain cases, have retroactive effect and expose us to additional compliance costs or undermine 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 PPAs and concessions. In circumstances where key components of our equipment, including but not limited to turbines, water pumps, heat exchangers, PV panels, tanks, 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.

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 2021 due to the improvements and replacements that we are carrying out after leaks were identified in the first quarter of 2020. These works have impacted production in 2021 and are expected to impact production in 2022 as we are experiencing delays due to COVID-19 restrictions and delays from subcontractors. We expect to fund these works with a cash repair reserve account funded at the asset level. We cannot guarantee that the repairs will be effective, that the funds in the cash repair reserve account will be sufficient or that additional repairs will not be required. Similar interruptions could happen again at our plants due to failure of 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 by our subcontractors of products or services which are not in compliance with the requirements of the subcontract, or delayed 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, NAEs, GE 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 replace these suppliers or acquire or repair these products. 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 have 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 business, financial condition, results of operations, and cash flows.

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The failure of any supplier 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 may be 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, Calgary District Heating, Coso, Vento II, I, Italy PV1, Italy PV2, La Sierpe, Italy PV3 and Chile TL 4 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 with our expectations. However, the ability of these facilities to meet our performance expectations is subject to the risks inherent in the operation 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 their revenues. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facilities may also reduce profitability.

If we make any major modifications to our renewable power generation facilities, efficient natural gas 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.

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

Climate change is causing an increasing number of severe, chronic and extreme weather events which are a risk to our facilities and may impact them. In addition, climate change may cause transition risks, related to existing and emerging regulation related to climate change. These risks include:

•

Acute physical. Severe and extreme weather events include severe winds and rains, hail, hurricanes, cyclones, droughts, as well as the risk of fire and flooding, among others and are becoming more frequent as a result of climate change. Any of these extreme weather events could cause damage to our assets and/or business interruption.

Our assets were designed and built by third parties complying with technical codes, local regulations and environmental impact studies. Technical codes should consider extreme weather events based on historical information and should include design safety margins. However, an increased severity of extreme weather events could have an impact on our assets.

Severe floods could damage our transmission lines, our solar generation assets or our water facilities.

Severe winds could cause damage the solar fields at our solar assets.

Storms with intense lightning activity could damage our plants, especially our wind farms.

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Severe droughts could result in water restrictions that may affect our operations and which may force us to stop generation at some of our facilities. For example, some regions in Spain are currently experiencing a severe drought, which may affect our facilities. A deterioration of the quality of the water would also have an impact on chemical costs in our water treatment plants at our generating facilities.

If our transmission assets caused a fire, we could be found liable if the fire damaged third parties.

Severe winter weather, like the storm in February 2021 in Texas, could cause supply from wind farms to decline due to wind turbine equipment freezing. Also, natural gas assets could trip offline due to operational issues caused by freezing conditions.

Rising temperatures and droughts could cause wildfires like the ones that have affected California starting in 2017. In California wildfires have been especially catastrophic, causing human fatalities and significant material losses. Although our assets in California are located in areas without trees and vegetation, wildfires affected one of our clients in the recent past. One of our off-takers is PG&E, a large utility in California which filed for bankruptcy protection under Chapter 11 due to large liabilities caused by its potential involvement in wildfires in California in 2017 and 2018. On July 1, 2020, PG&E emerged from Chapter 11. (see “Downstream” described below).

Components of our equipment and systems, such as structures, mirrors, absorber tubes, blades, PV panels or transformers are susceptible to being damaged by severe weather. 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, damage caused by our equipment to third parties due to weather events can result in liabilities for the Company.

•	Chronic physical. An increase in temperatures can reduce efficiency and increase operating costs at our plants.

The Emissions Gaps Report issued by the United Nations Environment Program (UNEP) in October 2021 states that even if all unconditional Nationally Determined Contributions combined with other mitigation measures put the world on track for a global temperature rise of 2.7°C (rise of 4.9ºF) by the end of the century. That is well above the goals of the Paris climate agreement and would lead to catastrophic changes in the Earth’s climate).

The main impacts of rising temperatures include:

Lower turbine efficiency in our efficient natural gas asset.

Reduced efficiency at our solar photovoltaic generation assets.

Lower air density at our wind facilities.

Higher consumption of chemicals used for operational purposes at our water treatment plants.

A reduction of mean precipitations may result in a reduction of availability of water from aquifers and could also modify the main water properties at our generation facilities.

If any of these acute physical or chronic physical risks were to materialize 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.

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Current Regulation. Atlantica is directly affected by environmental regulation at all our assets. This includes climate-related risks driven by laws, regulation, taxation, disclosure of emissions and other practices. As an example, we are subject to the requirements of the U.K. Climate Change Act 2008 on greenhouse gas (“GHG”) emissions reporting, and the Commission Regulation (EU) No 601/2012. Two U.S. solar plants are also subject to the permits under the Clean Air Act.

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Emerging Regulation. Changes in regulation could have a negative impact on Atlantica's growth or cause an increase in costs. Renewable energy projects currently benefit from various U.S. federal, state and local governmental incentives. These policies have had a significant impact on the development of renewable energy and they could change. 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. A reduction in such incentives could decrease the attractiveness of renewable energy to developers, utilities, retailers and customers. In addition, an increase in regulation could cause an increase in our compliance costs. See “—VII Risks Related to Regulation — Government regulations could change at any time and such changes may negatively impact our current business and growth strategy”.

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In addition, there may be additional taxes on GHG emissions. Some governments in certain geographies already have mechanisms in place for taxing GHG emissions and some other governments are considering establishing comparable mechanisms for the future. Additional taxes on emissions would increase the costs of operating the assets in our portfolio which have GHG emissions, particularly our natural gas assets.

•	Reputation. Decreased access to capital.

Climate change and ESG are becoming important criteria for shareholders and investors. In the last few years, we have seen an increased number of funds investing in renewable energy companies and a significant increase in the number of ETFs with a focus on clean energy and ESG investment. While a significant part of our business consists of renewable energy assets, we also own assets that can be considered less environmentally friendly, currently consisting of a 300 MW efficient natural gas plant and a non-controlling stake in a gas-fired engine facility which uses natural gas, both in Mexico. Owning these assets with higher GHG emissions than the rest of the portfolio may have a negative reputational impact on Atlantica as a renewable energy company. We rely on capital markets and bank financing to fund our growth initiatives. If our reputation worsened, our cost of capital could increase and our access to capital may become more difficult. In addition, some potential employees and /or suppliers could perceive Atlantica as a less appealing company due to an eventual deterioration in our reputation due to the foregoing.

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Downstream. Some of our clients are large utilities or industrial corporations. These are also exposed to significant climate change related risks, including current and emerging regulation, acute and chronic physical risks. A negative climate-related risk impact on our clients, including their credit quality could lead to their inability to comply with their obligations under our existing contracts. For example, one of our off-takers, PG&E, a large utility company in California, filed for bankruptcy protection under Chapter 11 due to liabilities related to its potential involvement in wildfires in California in 2017 and 2018. PG&E is the off-taker for our Mojave asset and emerged from Chapter 11 on July 1, 2020. During this process, California Legislature approved Assembly Bill 1054 which among other reforms created a Wildfire Fund, which would be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires. If our clients are affected by climate related risks, this could impact their credit quality and affect their ability to comply with the existing contract.

The efforts we may undertake in the future, to respond to the evolving and increased regulation, environmental initiatives of customers, investors, shareholders and other stakeholders, reputational risks related to climate change and climate related risks affecting our clients may cause increased costs, more difficult access to capital markets, a deterioration in the credit quality of our clients and other negative circumstances which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The electricity produced, and revenues generated by a renewable energy generation facility are highly dependent on suitable meteorological conditions, and associated weather conditions which are beyond our control. Our geothermal asset Coso depends on the geothermal resource available on the site of the plant, which is also ultimately beyond our control.

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.

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We base our investment decisions with respect to each renewable generation facility on the findings of related wind, solar and geothermal 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, wind and geothermal 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 the case of Coso, 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, earthquakes, drought or other natural disaster, terrorism, or other catastrophe, or if unexpected geological or other adverse physical conditions 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 and severe convective storms. 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 become 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% 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 we self-insured, 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, some of our project finance agreements 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 in some cases subject to approval by our lenders or counterparties. If we were unable to renew our insurance coverage, 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 or if additional key components were excluded from insurance coverage 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.

In addition, we might not be able to maintain insurance coverage comparable to those in effect in the past or currently at comparable cost, or at all. If insurance costs materially increased, 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 Vento II (our 596 MW wind portfolio in the United States composed by Elkhorn Valley, Prairie Star, Twin Groves II and Lone Star II), 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, Chile PV 1 and Chile PV 2 and we have invested through a debt instrument in Tenes. 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 in many cases our employees and our operators’ employees 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 for some of our assets. Abengoa is the operation and maintenance supplier in many of the assets for which we subcontract operation and maintenance services and Abengoa’s financial situation, including the insolvency filing by their holding company Abengoa S.A. on February 22, 2021, 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 in timely fashion. 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 some of our renewable energy 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 the price of GHG emission where applicable. In several of the jurisdictions in which we operate including Spain and Chile, we are exposed to remuneration schemes which contain both regulated incentives and market price components. In such jurisdictions, the regulated incentive or the contracted component may not compensate for fluctuations in the market price component, and, consequently, total remuneration may be volatile. Recent high market prices in that we have been experiencing in Spain since the third quarter of 2021 are resulting in higher cash collections which, in accordance with the regulation in place, will cause a reduction of the regulated remuneration component starting from 2023. In addition, the regulator may consider establishing a “cap” mechanism and limit the market price that we are able to charge (see “—VII Risks related to Regulation — 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.”)

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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.

Additionally, in some of our current or future PPAs, and contracts our subsidiaries have obligations to reach a minimum production, to deliver certain amounts of energy irrespective of actual production or to settle with the customer for the difference between the market price at our delivery point and a pre-agreed price in certain locations. This can result in our subsidiaries facing additional costs to purchase or sell power in the market or to settle for differences or defaulting on PPAs or contracts. This 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, or access to the grid might become uneconomical at certain times, 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.

Our information technology and communications systems are subject to cybersecurity risk and other risks. The failure of these systems 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, ransomware attacks, malicious or destructive code, phishing attacks, natural disasters, design defects, denial-of-service-attacks or information or fraud or other security breaches. 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. The COVID-19 pandemic and remote working has also increased the exposure to cybersecurity risks. 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 financial condition, results of operations or cash flows.

We maintain global information technology and communication networks and applications to support our business activities. Given the increasing sophistication and evolving nature of the above mentioned threats, we cannot rule out the possibility of them occurring in the future, and information technology security processes may not prevent future damages to systems, malicious actions, denial-of-service attacks, or fraud, resulting in corruption of our systems, theft of commercially sensitive data, unauthorized release, gathering, monitoring, misuse, loss or destruction of confidential, proprietary and other information, misappropriation of funds and businesses (also known as phishing), or other material disruptions to network access or business operations. To our knowledge, we have not experienced any of the system and data breaches described above. However, material system breaches and failures could result in significant interruptions that could in turn affect our operating results and reputation and cash flows.

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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. Violations of environmental and other laws, regulations and permit requirements may also result in criminal sanctions or injunctions.

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, assets, deals, or our subsidiaries not meeting their obligations. 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.”

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 non-investment 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 COVID-19 pandemic 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.

So far, we have not experienced any material impact from the COVID-19 pandemic on our business, results of operations or cash-flows. However, the COVID-19 pandemic could affect our operation and maintenance activities in the future. 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.

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In addition, in 2021, the rapid increase in demand after the slowdown in 2020 caused tensions in the supply chains, including delays to obtain some components and increased prices (see “—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 negative impact on our business”).

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. 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 previously mentioned 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 may continue to implement stimulus measures to reduce the negative impact of COVID-19 in the economy. In many cases, these measures may 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.

Given the dynamic nature of those events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist or their severity, or if they may have a material impact on our business, financial condition, results of operations or cash flows or the pace or extent of any subsequent recovery.

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 43.5% 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 its 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 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.

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Currently, Algonquin is a related party 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 or capital increases when making investments and the appointment of outside advisors and service providers. Any transaction between us and Algonquin or Liberty GES (including the acquisition of any assets under the ROFO Agreements or any co-investment with Algonquin or Liberty GES or any investment in an Algonquin or Liberty GES 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.

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. 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. A debt default 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. In September 2021, we obtained a waiver for such theoretical event of default which was conditional upon the replacement of the operation and maintenance supplier of the plant, which was an Abengoa subsidiary, before October 31, 2021. On November 4, 2021, we obtained an extension of the term for such replacement until January 31, 2022. On February 1, 2022, we completed the transfer of the employees performing the operation and maintenance from the above-mentioned supplier to an Atlantica subsidiary. The waiver has been extended until April 30, 2022 and is subject to the lenders receiving certain documentation from us, including formal evidence of the approval by our off-taker and the department of energy of South Africa of the operation and maintenance internalization and we are currently working on obtaining such documentation. If we were not able to deliver such documents by the deadline, we do not expect the Kaxu project debt lenders to declare the acceleration of the debt or take any other action. However, if not cured or waived, a cross-default or default scenario 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.

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, could have a negative impact on our current or future cash position.

The insolvency filing by the individual company Abengoa, S.A. in February 2021 or other circumstances 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, S.A. 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.

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A deterioration in the financial position of certain of Abengoa’s subsidiaries may result in a material adverse effect on certain of our operation and maintenance agreements. Abengoa and its subsidiaries provide O&M 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. On February 2, 2022 we internalized the O&M in Kaxu. For our assets in Spain, where Abengoa provides most of the operation and maintenance services, we reached an agreement in February 2022 subject to conditions precedent, including waivers from financial institutions, to terminate the O&M agreements in six plants in Spain and to introduce a clause to be able to terminate the rest of the agreements every three years. If and when the conditions precedent are met, we would perform the O&M for the six plants we would be terminating with third parties or internal resources. We may be required 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.

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’s subsidiaries 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 was the owner of a plant that shares certain infrastructure and has certain back-to-back obligations with ACT. We are required to deliver an equipment to Pemex which needs to be delivered to us by such plant first. If we are unable to comply with this obligation, it may result in a material adverse effect on ACT and on our business, financial condition, results of operations and cash flows. According to public information, this plant is currently controlled by a third party.

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.

Legal proceedings involving Abengoa and its current and previous insolvency processes and events and circumstances that led to them could affect us.

Prior to the completion of our initial public offering in 2014, we and many of our assets were part of Abengoa. Many of our senior executives have previously worked for Abengoa. Abengoa’s current and prior restructuring processes, and the events and circumstances that led to them, are currently the subject of various legal proceedings and investigations and may in the future become the subject of additional proceedings. To the extent that allegations are made in any such proceedings that involve us, our assets, our dealings with Abengoa or our employees, such proceedings may have a material adverse effect on our business, financial condition, results of operations and cash flows, as well as on our reputation and employees.

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, S.A. in the previous two years before it was declared insolvent and transactions we have entered into with Abengoa, S.A.’s subsidiaries in the previous two years before the subsidiary 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 S.A. or its subsidiaries 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.

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Any type of transaction and any amendment of an existing contract may be challenged by means of a claw back action. In practice, transactions that are more frequently subject to claw-back relate to: (a) unjustified payments or advances from the insolvent company, (b) transfers of assets or rights by the insolvent company at below market value, (c) payment-in-kind arrangements in which the property received in payment is higher in value than the debt owed to it, and (d) security provided by the insolvent company in relation to unsecured existing debt, or security provided for another group company’s obligations with no consideration. This determination will be a question of fact before a Spanish court due to the fact that Abengoa S.A. has initiated a bankruptcy filing in Spain or if the Abengoa S.A. subsidiary which was our counterparty in such transactions initiates a bankruptcy filing in Spain (this would be the case if the subsidiary has the center of main business 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 O&M services for us. The outcome of any bankruptcy proceedings initiated by Abengoa is 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.

Any other bankruptcy filing by Abengoa S.A. or its subsidiaries may permanently affect their operations. We cannot predict how any bankruptcy proceeding would be resolved or how our relationship with those entities will be affected following the initiation of any such proceedings or after the resolution of any such proceedings. Any bankruptcy proceedings or potential bankruptcy proceedings initiated by its subsidiaries 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 the ability of our project subsidiaries to make distributions to Atlantica Sustainable Infrastructure plc, our ability to fund our operations, pay dividends or raise additional capital.

As of December 31, 2021, we had (i) $5,036.2 million of total indebtedness under various project-level debt arrangements and (ii) $1,023.1 million of total indebtedness under our corporate arrangements, which include the Revolving Credit Facility, the Note Issuance Facility 2020, the 2020 Green Private Placement, the Green Exchangeable Notes and the Green Senior Notes. In addition, we may incur in the future additional project-level debt and corporate debt.

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Our substantial debt could have important negative consequences on our business, financial condition, results of operation and cash flows including:

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increasing our vulnerability to general economic and industry conditions;

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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;

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

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

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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;

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exposing us to the risk of increased interest rates because a portion of some of our borrowings (below 10% as of December 31, 2021 after giving effect to hedging agreements) are at variable interest rates;

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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

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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 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Senior Notes 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— Corporate debt agreements.”

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 service debt at the corporate level or to 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.

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.

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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.

Our ability to arrange the required or desired financing, either at corporate level or at a project-level, and the costs of such capital, are dependent on numerous factors, including:

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general economic and capital market conditions;

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credit availability from banks and other financial institutions;

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investor confidence in us;

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

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

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

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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.

In addition, the global capital and credit markets have experienced in the past and may continue to experience periods of extreme volatility and disruption. 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. In addition, given that our dividend policy is to distribute a high percentage of our cash available for distribution, our growth strategy relies on our ability to raise capital to finance our investments and acquisitions. In the event we are not able to raise capital, 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, LIBOR or over the alternative rates replacing these, including SOFR. The U.S. Federal Reserve has announced in the last months that it expects to increase the reference interest rates in the United States several times in 2022. 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, South Africa and Colombia are denominated in local currency. We have a hedging strategy for our solar assets in Europe. 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 assets in Europe. Our strategy is to hedge the exchange rate for the distributions received in euros 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. In addition, a depreciation of the South African rand, the Colombian peso or a long-term depreciation of the Euro could have a negative impact on our results of operations and cash flows. See “Item 5.A—Operating and Financial Review and Prospects —Results of Operations—Factors Affecting the Comparability of 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. We estimate that approximately 92% of our project debt and close to 100% of our corporate debt was fixed or hedged as of December 31, 2021.

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, 2021, we had $5,036.2 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:

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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;

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default under our other debt instruments;

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

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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. In 2021, we obtained a waiver which was subsequently extended and is subject to the lenders receiving certain documents from us. See “—III Risks Related to Our Relationship with Algonquin and Abengoa—If Abengoa defaults on certain of its debt obligations, including as a result of the insolvency filing by their holding company Abengoa S.A., we could potentially be in default of certain of our project financing agreements.”

Under the Revolving Credit Facility, the 2020 Green Private Placement, the Green Senior Notes 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.

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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.

On July 27, 2017, the Chief Executive of the U.K. Financial Conduct Authority (the “FCA”), which regulates LIBOR, announced that the sustainability of LIBOR cannot be guaranteed and that the FCA will no longer persuade or compel banks to submit rates for the calculation of LIBOR after 2021. On May 31, 2019, the Alternative Reference Rates Committee (“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. Moreover, on March 5, 2021, the ICE Benchmark Administration, which administers LIBOR, and the FCA announced that all LIBOR settings will either cease to be provided by any administrator, or no longer be representative immediately after December 31, 2021, for all non-USD LIBOR settings and one-week and two-month USD-LIBOR settings, and immediately after June 30, 2023 for the remaining USD-LIBOR settings, such as the overnight, one-month, three-month, six-month and 12-month USD-LIBOR settings (the “LIBOR Announcement”). Accordingly, the FCA has stated that is does not intend to persuade or compel banks to submit to LIBOR after such respective dates. Until such time, however, FCA panel banks have agreed to continue to support LIBOR.

As a result of the phase out of LIBOR, we may have to renegotiate certain of our LIBOR-based debt and derivative instruments to reflect the phase out of LIBOR and substitute for SOFR or another replacement benchmark.

We have not experienced any material impact of the LIBOR phase out and its transition to a replacement benchmark and as of today we do not expect any material impact. However, 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, discontinuance of LIBOR, modification or other reforms to any other reference rate, or the establishment of alternative reference rates may have, or other benchmarks. Furthermore, the shift to alternative reference rates, including SOFR, or other reforms is complex and could cause the payments calculated for the LIBOR-based debt and derivative instruments to be materially different than expected, which may affect our business, financial condition, results of operations, liquidity and cash flows. As of December 31, 2021, total principal amount of debt referenced to LIBOR was $1,068.5 million and total notional amount of derivatives hedging this debt, thus indexed to LIBOR as well was $62.6 million. Although we do not expect a material impact on our LIBOR-based debt and derivative instruments, we cannot guarantee that the shift to alternative reference rates will not have any impact on our business, financial condition, results of operations and cash flows.

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 $10 million to $12 million, which could potentially decrease progressively over time as the asset depreciates.

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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.

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 “—VII. Risks Related to Regulation—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 also depends on the availability of financing. See “—IV. Risks Related to Our Indebtedness—We may not be able to arrange the required or desired financing for investments or for the successful refinancing of the Company’s project level and corporate level indebtedness.”

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 program 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 their 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 Liberty GES’ and Algonquin’s ability to offer us investment opportunities. Liberty GES 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. Liberty GES 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 the Algonquin ROFO Agreement with us with a 180-day notice. Additionally, we may not reach an agreement on the price of assets offered by Liberty GES or Algonquin. For these reasons, we may not be able to consummate future investments from Liberty GES or Algonquin, which may restrict our ability to grow.

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Furthermore, Liberty GES 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. They could also decide to invest in other types of businesses which are not our core business. In addition, Liberty GES 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. Furthermore, Liberty GES and Algonquin may compete with us in some of the markets where we intend to grow.

Our ability to develop renewable projects is subject to construction risks and risks associated with the arrangements with our joint venture partners

We have reached agreements with a number of partners in order to develop assets in the geographies in which we operate, 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 projects and partners or that we will be able to acquire additional assets from those partners in the future. If we are unable to identify projects under such agreements or to reach new agreements on favorable terms with new partners, or if we are unable to consummate future acquisitions from any such agreement, 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 conducted with partners or on our own are subject to failure rate and different types of risks. Our ability to develop new assets is dependent on our ability to secure or renew our rights to an attractive site on reasonable terms; accurately measuring resource availability; the ability to secure new or renewed approvals, licenses and permits; the acceptance of local communities; the ability to secure transmission interconnection access or agreements; the ability to successfully integrate new projects into existing assets; the ability to acquire suitable labor, equipment and construction services on acceptable terms; the ability to attract project financing; and the ability to secure PPAs or other sales contracts on reasonable terms. Failure to achieve any one of these elements may prevent the development and construction of a project. If any of the foregoing were to occur, we may lose all of our investment in development expenditures and may be required to write-off project development assets.

In addition, the construction and development of new projects is subject to environmental, engineering and construction risks that could result in cost-overruns, delays and reduced performance. A number of factors that could cause such delays, cost over-runs or reduced performance include, changes in local laws or difficulties in obtaining permits, rights of way or approvals, changing engineering and design requirements, construction costs exceeding estimates for various reasons, including inaccurate engineering and planning, failures to properly estimate the cost of raw materials, components, equipment, labor or the inability to timely obtain them, unanticipated problems with project start-up, the performance of contractors, labor disruptions, inclement weather, defects in design, engineering or construction and project modifications. A delay in the projected completion of a project can result in a material increase in total project construction costs through higher capitalized interest charges, additional labor and other expenses, and a delay in the commencement of cash flow.

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.

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. We intend to increase our investments 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 investing in assets which are not contracted or not fully contracted, for which revenues will depend on the price of the electricity and which are therefore subject to merchant risk. We may also consider investing in businesses which are regulated or which are contracted with “as contracted” agreements or hedge agreements where we need to deliver the contracted power even if the facility is not in operation or which are subject to demand 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 long history track record as proven as our current assets, such as storage, district heating, geothermal, offshore wind or hydrogen. We may also consider investing in distributed generation in smaller commercial and industrial facilities. Furthermore, we may consider investing in assets with revenues not denominated in U.S. 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.

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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.

Acquisitions of and investments in companies and assets are subject to substantial risks, including unknown or contingent liabilities (including violations of environmental, antitrust, anticorruption, anti-bribery and anti-money laundering laws, and tax and labor disputes), the failure to identify material problems during due diligence (for which we may not be indemnified post-closing) or the risk of over-paying for assets (or not making acquisitions on an accretive basis). In some of our acquisitions the former owners agreed, or may agree, to indemnify us for certain of these matters. However, such indemnification obligations are often subject to materiality thresholds and guaranty limits, and such obligations are generally time limited. For certain acquisitions, we may not be able to successfully negotiate for such indemnification obligations. As a result, we may not recover any amounts with respect to losses due to unknown or contingent liabilities or breaches by the sellers of their representations and warranties. All this may adversely affect our business, financial condition, results of operations and prospects.

Furthermore, the integration and consolidation of acquisitions require 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. 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 investments, we may be unable to achieve projected cash flows or we may encounter regulatory complications arising from such transactions. Furthermore, the terms and conditions of financing for such 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 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, Colombia, Uruguay, Spain, Italy, South Africa and Algeria). See “—VI. Risks Related to 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.” 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 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, 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.

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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 negative impact on our business.

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 high volatility recently. Concerns over the COVID-19 pandemic (including the new highly contagious variants such as Omicron) and its effects on the global economy, higher inflation, volatile oil and gas prices, high electricity prices particularly in Europe, expected interest rate raise, geopolitical tensions, including the Russian military actions across Ukraine, and tensions between the U.S., Russia and China, 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.

After the sharp recession caused by the COVID-19 pandemic in 2020, the recovery in demand during the year 2021 caused disruptions in the supply chain with global shortages of some products and materials and high inflation rates. Further disruptions in the supply chain could limit the availability of certain parts required to operate our facilities and could adversely impact our ability (or our operation and maintenance suppliers’ ability) to operate our plants or to perform maintenance activities. 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. Supply chain tensions may also affect our projects in development and construction where we can experience delays or an increase in prices of equipment and materials required for the construction of new assets, which may cause a material adverse effect on our business, financial condition, results of operations and cash flows. If price increases translate into prolonged inflation, this may cause a material adverse effect on our business, financial condition, results of operations and cash flows

In addition, interest rates are now expected to increase faster than the market forecasted months ago. 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 and gas prices, increasing electricity prices, interest rates swings, changes in consumer spending, business investment, government spending, and rising inflation, among others, that could affect the economic and financial situation of our concession agreements’ counterparties and, ultimately, the profitability and growth of our business.

Generalized or localized downturns or inflationary 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, Spain, Mexico and Peru. Consequently, we are significantly affected by the general economic conditions in these countries. Spain, for instance, after the recession caused by the COVID-19 pandemic is facing high inflation including high electricity prices, and an economic recovery at a slower pace than the European average, with persistently high unemployment. 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.

Global geopolitical tensions, including from the February 2022 Russian military actions across Ukraine, may rise and create heightened volatility in the electricity market that could negatively affect both our ability to execute our business and growth strategy. Such military actions, and sanctions in response thereof as well as escalation of conflict, could significantly affect worldwide electricity market prices and demand and cause turmoil in the capital markets and generally in the global financial system. This could have a material adverse effect on our business, financial condition, results of operations and cash flows, making it difficult to execute our growth strategy.

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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, Colombia and Uruguay), and EMEA (Spain, Italy, 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.

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. Countries like Mexico, Peru and Chile currently have governments which are favorable to increase public spending and tax pressure. In addition, the current government in Mexico is proposing regulation which intends to benefit local business rather than foreign investors. 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 this may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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. 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. Likewise, our contracts in South Africa and Colombia are payable in local currency. Governments in Latin America and Africa frequently intervene in 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 (commonly referred to as “Brexit”) and entered into a transition period to, among other things, negotiate an agreement with the EU on the future terms of the U.K.’s relationship with the European Union. On December 24, 2020, both parties reached a trade agreement (the “Trade Agreement”), which contains rules for how the U.K. and EU are to live, work and trade together.

On December 31, 2020, the transition period ended, and 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 and Brexit could lead to additional political, legal and economic instability in the EU or labor shortages due to changes and restrictions regarding the free movement of people into the U.K. from the EU.

Since some of the proposed changes due to Brexit have only recently become effective (i.e., further tightening of border controls on January 1, 2022), we are still monitoring the impact that Brexit may have on its business, and we continue to evaluate our own risks and uncertainty related to Brexit to better navigate the changes in the U.K.-EU market. Notwithstanding, as of the date hereof, we have evaluated the impact of Brexit on us, our subsidiaries, our business, and our future operations, operating results, and cash flows and it has not materially changed our business to date and as of today we do not expect any material impact.

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Moreover, we cannot anticipate if the U.K. and EU will succeed in negotiating all material terms not otherwise addressed or covered by the Trade Agreement, or subsequent transition agreements or arrangements and/or if previously agreed upon items will be renegotiated in the future. Changes in these or other terms resulting from Brexit could, similarly, subject us or our subsidiaries, to certain risks and could adversely affect our business, financial condition, results of operations, liquidity 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 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., The power plants, transmission lines and other assets 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 affect our ability to satisfy applicable ESG standards. Compliance with regulatory requirements may result in substantial costs to our operations that may not be recovered. All the above could have a negative impact on us and a material adverse effect on our business, financial condition, results of operations and cash flows.

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. Our policy is to maintain environmental insurance policies. We can give no assurance that we will be able to maintain such policies in the future. Additionally, 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:

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

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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

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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. At any point in time, we are subject to review and in some cases challenges regarding our compliance that might result or not in future fines and penalties or other remediation measures. At this point in time, we believe that such reviews will not result in a material financial impact. In one of our plants in Spain we have a difference of interpretation with an agency which may result, if the agency, and eventually the court, decided against our position in an eventual modification of the plant several years from today with a cost that we do not expect to be material. 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, additional taxes and site closures. 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.

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

Our assets are subject to extensive regulation. 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. Also, such changes may in certain cases, have retroactive effects and may cause the result of operations to be lower than expected, or increase the size and number of claims and damages asserted against us or subject us to enforcement actions, fines and even criminal penalties. Our business may also be affected by additional taxes imposed on our activities or changes in regulations, reduction of regulated tariffs and other cuts or measures.

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.

Furthermore, in some of our assets such as the solar plants in Spain 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.

In addition, our strategy to grow our business through investments in 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. 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 or a reduction in the capacity of potential investors to benefit from such incentives could decrease the attractiveness of renewable energy projects to project developers, and the attractiveness of renewable assets to utilities, retailers and customers. Such a loss or reduction could reduce our investment 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 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.

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 benefitted 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.

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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.

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%.

The first review of this rate was at the end of 2018 applicable for the second regulatory period 2020-2025. On November 2, 2018, CNMC (the state-owned regulator for the electricity system in Spain) 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% reasonable rate of 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 rate of 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 assets in Spain 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.

In addition, the regulation includes a mechanism under which regulated revenues are reviewed every three years to reflect the difference between expected and actual market prices over the remaining regulatory life if the difference is higher than a pre-defined threshold. Electricity prices have increased significantly since mid-2021 and may remain high during the rest of 2022, which would cause higher short-term cash collections but also a negative adjustment in regulated revenue starting 2023, resulting in a negative impact on future cash flows from that year. In addition, from an accounting perspective, in 2021 we have recorded a negative provision with no cash impact on the current period that has lowered revenue and Adjusted EBITDA in this geography. If electricity prices remain high in 2022, we will record another similar non-cash provision also in 2022. Volatility in electricity market prices can cause volatility in our results of operations.

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If approved, the proposed electricity constitutional reform in Mexico may have a negative impact on our current assets and might impact negatively on our ability to grow in that country.

On March 9, 2021, Mexico’s President proposed a preferential reform to the Electricity Industry Law (Ley de la Industria Eléctrica). In broad terms, the reform aimed for CFE to expand its impact in the energy generation sector. Additionally, on September 30, 2021, Mexico’s President submitted an amendment proposal to the Constitution which will be discussed and resolved by the House of Representatives, the Mexican Senate and regional local congresses. If passed as presented, most of the energy reform of December 2013 would be modified and the sector would be significantly transformed. Although we do not expect a direct and immediate 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.

In addition, in December 2021, the Mexican Energy Regulatory Commission approved an amendment to the existing regulation on the isolated supply, which may affect our Monterrey asset. We have filed appeals for protection before specialized courts and we expect this situation to be solved without significant impact. However, we cannot guarantee that this change in regulation will not have any negative impact on our business, financial condition, results of operations and cash flows.

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 (the “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 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:

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operational performance of our assets;

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potential capital expenditure requirements in our assets in the case there were technical problems or environmental or regulatory requirements or unanticipated increases in construction and design costs;

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adverse weather;

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our debt service requirements and other liabilities;

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fluctuations in our working capital needs;

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fluctuations in foreign exchange rates;

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the level of our operating and general and administrative expenses,

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seasonal variations in revenues generated by the business;

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losses experienced not covered by insurance;

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shortage of qualified labor;

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

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our ability to borrow funds, including intercompany loans;

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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;

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

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other business risks affecting our cash levels;

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unfavorable regional, national or global economic and market conditions; and

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changes in accounting and financial reporting standards.

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 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. The ability of our operating subsidiaries to make distributions could also be limited by 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. Our ability to pay dividends on our shares is also limited by restrictions under the Revolving Credit Facility, the 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Senior Notes.

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. 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.

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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.”

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 43.5% of our ordinary shares. On November 28, 2018. Liberty GES obtained a secured credit facility in the amount of $306,500,000. Such loan is collateralized through a pledge of most of the Atlantica shares held by a company owned by Algonquin. A collateral shortfall would occur if the quotient of the net obligations, divided by the aggregate collateral share value, greater than or equal 50% of the share closing price of the Atlantica shares in which case the lenders, would have the right to sell Atlantica shares to eliminate the collateral shortfall. If Liberty GES 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 anticipation or perception by the market 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.

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 the laws of England and Wales. The rights of holders of our shares are governed by the laws of England and Wales, 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. A majority of our officers and directors reside outside the United States. In addition, a significant portion of our assets and a significant portion of the assets of our directors and officers are located outside the United States. As a result, it may be difficult or impossible to effect service of process within the United States upon us or such officers and directors, with respect to matters arising under U.S. federal securities law, or to force us or 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, predicated upon civil liability provisions under U.S. federal securities law, 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. In addition, punitive damages in actions brought in the United States or elsewhere may be unenforceable in England and Wales or in Spain.

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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.

In addition, under the Shareholders Agreement, Algonquin 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 Algonquin or the Liberty GES ROFO Agreement. If we issue ordinary shares for any other purpose, Algonquin may subscribe in cash for our ordinary shares in a pro rata amount of such Algonquin’s holding in us. The Shareholders Agreement may be terminated or modified in the future. In any case, Algonquin has the right but not the obligation to subscribe for our shares.

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 U.K. and whose securities are not admitted to trading on a regulated market in the U.K. 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 U.K. 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 U.K., 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 could adversely affect our assets. Limitations on the deductibility of interest expense could adversely affect our ability to deduct the interest we pay on our debt. These and other potential changes in tax laws and regulations could have a material adverse effect on our results and cash flows. In addition, 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.

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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 (“OECD”). 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.

In addition, the governments of some countries where we operate, including the United States, Spain, Chile, Peru and South Africa, could implement changes to their tax laws and regulations, the content of which are largely uncertain currently. These potential changes to applicable tax laws and regulations 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 tax laws and 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.

In addition, as of November 2021, 137 countries agreed to implement the “Two Pillars Solution”, an OECD/ G20 Inclusive Framework initiative, which aims to reform the international taxation policies and ensure that multinational companies pay taxes wherever they operate and generate profits. “Pillar Two” of this initiative generally provides for an effective global minimum corporate tax rate of 15% on profits generated by multinational companies with consolidated revenues of at least €750 million, calculated on a country-by country basis. This minimum tax would be applied on profits in any jurisdiction wherever the effective tax rate, determined on a jurisdictional basis, is below 15%. Any additional tax liability resulting from the application of this minimum tax will be payable by the parent entity of the multinational group to the tax authority in such parent’s country of residence. A framework for the coordinated implementation of the minimum tax is expected to be developed over 2022. Although this initiative is still subject to further developments in the countries where Atlantica operates, if implemented, it 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.

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Our NOL carryforwards and certain recognized built-in losses may be limited by Section 382 of the IRC if we experience an “ownership change.” In general, an “ownership change” occurs if 5% shareholders of our stock increase their collective ownership of the aggregate amount of the outstanding shares of our company by more than 50 percentage points, generally over a three-year testing period. In the event of an ownership change, NOLs that exceed the Section 382 limitation in any year will continue to be allowed as carryforwards for the remainder of the carryforward period and will be available to offset taxable income for years within the carryforward period subject to the Section 382 limitation in each year. Nevertheless, if the carryforward period for any NOL were to expire before that loss had been fully utilized, the unused portion of that loss would be lost. Our use of new NOLs arising after the date of an ownership change would not be affected by the Section 382 limitation (unless there were another ownership change after those new losses arose).

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 2019, the Internal Revenue Service issued proposed regulations concerning the calculation of built-in gains and losses under Section 382. If the proposed regulations are enacted and depending on its final outcome, these proposed regulations 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.

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 2021 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. The application of the PFIC rules is, however, subject to uncertainty in several respects, and we must make a separate determination after the close of each taxable year as to whether we were a PFIC for such year. 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—U.S. Federal Income Tax Considerations—Passive foreign investment company rules.”

X.	Other Risks

We may not satisfy the standards of our existing or future ESG certifications or those of investors or regulators for assets with sustainability characteristics.

There can be no assurance of the extent to which we will be successful in satisfying the requirements or standards of our existing or future ESG certifications or those of investors or regulators for assets with sustainability characteristics. In addition, there is no assurance that any future investments we make will meet investor expectations or any standards for investment in assets with sustainability characteristics, or standards regarding sustainability performance, in particular with regard to any direct or indirect environmental, sustainability or social impact. Failure to maintain any existing or future ESG certification or those of investors or regulators for assets with sustainability characteristics may adversely affect our business, financial condition, results of operations and prospects.

Further, adverse environmental, regulatory, political or social changes may occur during the design, construction and operation of any action we may take in furtherance of our sustainability goals, making it less likely, more expensive or impracticable for us to achieve such goals, or such actions may become controversial or criticized by activist groups or other stakeholders.

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ITEM 4.

INFORMATION OF THE COMPANY

A.	History and Development of the Company

Atlantica Sustainable Infrastructure plc was 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 Atlantica North America LLC, a Delaware limited liability company with its principal office located at 850 New Burton Road, Suite 201, Dover, Delaware 19904, 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 relevant 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 the current holding of 43.5%.

Investments

We refer to “Item 5.Operating and Financial Review and Prospects” for the description of our recent investments. Apart from these investments, there have been no material capital expenditures or divestitures in the last three years.

The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, which can be found at http://www.sec.gov. Our internet address is https://www.atlantica.com/web/en/. The information contained on our website is not incorporated by reference and does not form part of this annual report on Form 20-F.

B.	Business Overview

Overview

We are a sustainable infrastructure company with a majority of our business in renewable energy assets. 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. In 2021, our renewable sector represented 77% of our revenue with solar energy representing 69%. 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 also hold water assets, a relevant sector for sustainable development.

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 39 assets with 2,044 MW of aggregate renewable energy installed generation capacity (of which approximately 71% is solar), 343 MW of efficient natural gas-fired power generation capacity, 55 MWt of district heating capacity, 1,229 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, Colombia and Uruguay) and EMEA (Spain, Italy, Algeria and South Africa). Our assets generally have contracted or regulated revenue. As of December 31, 2021, our assets had a weighted average remaining contract life of approximately 15 years.

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, investments in new assets and acquisitions.

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Current Operations

Our assets are organized into the following four business sectors: Renewable Energy, Efficient Natural Gas and Heat, Transmission Lines 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 Remaining⁽¹⁶⁾

Solana	Renewable (Solar)	100%	Arizona (USA)	USD	280 MW	BBB+/A3/BBB+	2013	22
Mojave	Renewable (Solar)	100%	California (USA)	USD	280 MW	BB-/--/BB	2014	18
Coso	Renewable (Geothermal)	100%	California (USA)	USD	135 MW	Investment grade ⁽¹⁴⁾	1987/ 1989	17
Elkhorn Valley	Renewable (Wind)	49%	Oregon (USA)	USD	101 MW	BBB/A3/--	2007	6
Prairie Star	Renewable (Wind)	49%	Minnesota (USA)	USD	101 MW	--/A3/A-	2007	6
Twin Groves II	Renewable (Wind)	49%	Illinois (USA)	USD	198 MW	BBB-/Baa2/--	2008	4
Lone Star II	Renewable (Wind)	49%	Texas (USA)	USD	196 MW	Not rated	2008	1
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	Not rated	2017	9
La Sierpe	Renewable (Solar)	100%	Colombia	COP	20 MW	Not rated	2021	14
Palmatir	Renewable (Wind)	100%	Uruguay	USD	50 MW	BBB/Baa2/BBB-⁽¹²⁾	2014	12
Cadonal	Renewable (Wind)	100%	Uruguay	USD	50 MW	BBB/Baa2/BBB-⁽¹²⁾	2014	13
Melowind	Renewable (Wind)	100%	Uruguay	USD	50 MW	BBB/Baa2/BBB-⁽¹²⁾	2015	14
Mini-Hydro	Renewable (Hydraulic)	100%	Peru	USD	4 MW	BBB+/Baa1/BBB	2012	11
Solaben 2 & 3	Renewable (Solar)	70%⁽¹⁾	Spain	Euro	2x50 MW	A/Baa1/A-	2012	16/16
Solacor 1 & 2	Renewable (Solar)	87%⁽²⁾	Spain	Euro	2x50 MW	A/Baa1/A-	2012	15/15
PS10 & PS20	Renewable (Solar)	100%	Spain	Euro	31 MW	A/Baa1/A-	2007& 2009	10/12
Helioenergy 1 & 2	Renewable (Solar)	100%	Spain	Euro	2x50 MW	A/Baa1/A-	2011	15/15
Helios 1 & 2	Renewable (Solar)	100%	Spain	Euro	2x50 MW	A/Baa1/A-	2012	15/16
Solnova 1, 3 & 4	Renewable (Solar)	100%	Spain	Euro	3x50 MW	A/Baa1/A-	2010	13/13/14
Solaben 1 & 6	Renewable (Solar)	100%	Spain	Euro	2x50 MW	A/Baa1/A-	2013	17/17
Seville PV	Renewable (Solar)	80%⁽⁶⁾	Spain	Euro	1 MW	A/Baa1/A-	2006	14
Italy PV 1	Renewable (Solar)	100%	Italy	Euro	1.6 MW	BBB/Baa3/BBB	2010	9
Italy PV 2	Renewable (Solar)	100%	Italy	Euro	2.1 MW	BBB/Baa3/BBB	2011	9

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Italy PV3	Renewable (Solar)	100%	Italy	Euro	2.5 MW	BBB/Baa3/BBB	2012	10
Kaxu	Renewable (Solar)	51%⁽³⁾	South Africa	Rand	100 MW	BB-/Ba2/BB-⁽¹¹⁾	2015	13
Calgary	Efficient natural gas & Heat	100%	Canada	CAD	55 MWt	~41% A+ or higher⁽¹⁵⁾	2010	19
ACT	Efficient natural gas & Heat	100%	Mexico	USD	300 MW	BBB/ Ba3/BB-	2013	11
Monterrey	Efficient natural gas & Heat	30%	Mexico	USD	142 MW	Not rated	2018	17
ATN ⁽¹³⁾	Transmission line	100%	Peru	USD	379 miles	BBB+/Baa1/BBB	2011	19
ATS	Transmission line	100%	Peru	USD	569 miles	BBB+/Baa1/BBB	2014	22
ATN 2	Transmission line	100%	Peru	USD	81 miles	Not rated	2015	11
Quadra 1 & 2	Transmission line	100%	Chile	USD	49 miles/ 32 miles	Not rated	2014	13/13
Palmucho	Transmission line	100%	Chile	USD	6 miles	BBB/-/A-	2007	16
Chile TL3	Transmission line	100%	Chile	USD	50 miles	A/A1/A-	1993	Regulated
Chile TL4	Transmission line	100%	Chile	USD	63 miles	Not rated	2016	50
Skikda	Water	34.2%⁽⁴⁾	Algeria	USD	3.5 M ft3/day	Not rated	2009	12
Honaine	Water	25.5%⁽⁵⁾	Algeria	USD	7 M ft3/day	Not rated	2012	16
Tenes	Water	51%⁽⁷⁾	Algeria	USD	7 M ft3/day	Not rated	2015	18

Notes:

(1)	Itochu Corporation, holds 30% of the shares in both Solaben 2 and Solaben 3.

(2)	JGC, 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. .(“Sacyr”) owns the remaining 16.8%.

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

(6)	Instituto para la Diversificación y Ahorro de la Energía, 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)	Refers to the credit rating of two Community Choice Aggregators: Silicon Valley Clean Energy and Monterrey Bar Community Power, both with A Rating from S&P and Southern California Public Power Authority. The third off-taker is not rated.

(15)	Refers to the credit rating of a diversified mix of 22 high credit quality clients (~41%A+ rating or higher, the rest is unrated).

(16)	As of December 31, 2021.

(*)	Commercial Operation Date.

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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 our value creation capability is significantly enhanced by investing in sustainable sectors and managing our assets in a sustainable manner to the benefit of our shareholders and other stakeholders.

We intend to take advantage of, and leverage our growth strategy on, favorable trends in clean power generation, energy scarcity and the global focus on the reduction of carbon emissions. We believe that we are well positioned to benefit from the expected transition towards a more sustainable power generation mix in our markets. In addition, we believe that water is going to be the next frontier in a transition towards a more sustainable world.

We seek to grow our cash available for distribution and our dividends to shareholders through organic growth and by investing in new assets, while ensuring the ongoing stability and sustainability of our business. We intend to grow our business maintaining renewable energy as our main segment with a primary focus on North America and Europe.

We believe we can achieve organic growth through the optimization of the existing portfolio, escalation factors at many of our assets, as well as the repowering and hybridization with other technologies of some of the renewable energy facilities and the expansion of our existing transmission lines.

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 will also continue to invest in the development and construction of new assets, in some cases on our own and in other cases with partners. We have entered into and intend to continue to enter into agreements or partnerships with developers and asset owners.

Our plan for executing this strategy includes the following key components:

Focus on stable assets in the power and water sectors, including renewable energy, storage, efficient natural gas and heat, transmission assets as well as water assets, generally contracted or regulated.

We intend to focus on owning and operating stable, sustainable infrastructures assets, 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 intend to maintain a diversified portfolio with a large majority of our Adjusted EBITDA generated from low-carbon footprint assets, as we believe these sectors will see significant growth in our targeted geographies.

Maintain diversification across our business sectors and geographies.

Our focus on three core geographies, North America, South America and Europe, helps to ensure exposure to markets in which we believe renewable energy, storage and transmission will continue to grow significantly. We believe that our diversification by business sector and geography provides us with access to different sources of growth.

Grow our business through the optimization of the existing portfolio and through the investments in the expansion of our current assets.

We intend to grow our business 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 and repowering of our current assets and hybridization of existing assets with other complimentary technologies including storage, particularly in our transmission lines and renewable energy assets.

Grow our business by investing in new assets in the business sectors where we are present.

We will seek to grow our business 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 develop or acquire assets. We also invest in assets under development or construction either directly or with partners via investment vehicles. 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.

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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 seek to invest generally in assets with proven technologies in which we generally have significant experience, located in countries where we believe conditions to be stable and safe. We may complement our portfolio with investments or co-investments in assets with shorter contracts or with partially contracted revenue or in assets with revenue in currencies other than U.S. dollar or euro. We also invest in assets under development or construction either directly or with partners via investment vehicles.

Additionally, our policies and management systems include thorough risk analysis and risk management processes applied on an ongoing basis from the date of asset acquisition. 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

Non-recourse project debt is an important principle for us. We intend to continue financing 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, 2021, approximately 92% of our total interest risk exposure was fixed or hedged, generally for the long-term. We also 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.

We also 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 15 years as of December 31, 2021, providing long-term cash flow visibility. In 2021, approximately 58% of our revenue was non-dependent on natural resource, not subject to the volatility that natural resource may have, especially solar and wind resource. This includes our transmission lines, our efficient natural gas plant, our water assets and approximately 77% of the revenue received from our solar assets in Spain. In these assets, our revenue is not subject to (or has low dependence on) solar, wind or geothermal resources, which translates in a more stable cash-flow generation. Going forward, our new investments will probably be dependent on the natural resource. 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.

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Furthermore, due to the fact that we are a U.K. registered company, we should benefit from a more favorable treatment than if we were a corporation based in the U.S. 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, under current regulations 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 2021, renewable energy is expected to account for the majority of new investments in the power sector in most markets. In Bloomberg’s green scenario, approximately 1,400 GW of renewables will be added every year for the next three decades. Solar PV sees the largest deployment with 16.5 TW installed by 2050. Required investment in energy supply and infrastructure amounts to between $92 trillion and $173 trillion over the next three decades. To achieve this, annual investment will need to more than double from around $1.7 trillion, to somewhere between $3.1 trillion and $5.8 trillion per year.

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 additional wind and solar energy generation. We believe that we are well positioned in sectors with solid growth expectations.

We also believe that our diversified 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 in the future, we believe we can continue to execute on our growth strategy by having the flexibility to invest in other regions or in other business sectors.

Well positioned in ESG

In 2021, 73% of our Adjusted EBITDA was derived from renewable energy and 64% of our Adjusted EBITDA corresponded to solar energy production. Adjusted EBITDA from low carbon footprint assets represented 87.9%, including renewable energy, transmission infrastructure, as well as water assets. We have set a target to maintain over 80% of our Adjusted EBITDA generated from low-carbon footprint assets.

In addition, we have set a target to reduce our scope 1 and scope 2 GHG emissions per unit of energy generated¹ by 70% by 2035, with 2020 as base year. This target has been validated by the Science Based Targets initiative in 2021.

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 2021, the Board updated and /or issued, as applicable, several key ESG related documents following our long-term strategy. 25% of our directors are women.

We have been rated by various ESG rating agencies, which we believe can provide relevant information for investors.

¹ Including thermal generation.

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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 2021, availability in the storage system was lower than expected due to the improvements and replacements that we are carrying out after certain leaks were identified in the first quarter of 2020. These works have impacted production in 2021 and are expected to impact production in 2022 as we are experiencing delays due to COVID-19 restrictions and delays from subcontractors. We expect to fund these works with a cash repair reserve account funded at the asset level.

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 3.69%. The principal balance was $742 million as of December 31, 2021. 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. On August 17, 2020, we closed the acquisition of the Liberty Interactive Ownership Interest in Solana. Liberty Interactive was a tax equity investor in the asset. 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.

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.

O&M. ASI Operations, one of our subsidiaries, provides O&M services for Mojave.

Project Level Financing. Mojave received a loan from the Federal Financing Bank (the “FFB”) in September 2011, with a guarantee from the DOE, which 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 $639 million as of December 31, 2021. The financing arrangement permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.20x.

Coso

Overview. Coso is a platform of nine geothermal units with a total net capacity of approximately 135 MW located in Inyo County, California. This asset provides baseload renewable generation to CAISO.

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PPAs. We have signed three PPAs with fixed prices:

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Two PPAs representing approximately 85% of the revenues until 2026 and 60% from 2027 until 2036 with two Community Choice Aggregators (“CCAs”), Silicon Valley Clean Energy and Monterrey Bay Community Power, both with an “A” credit rating from S&P Global Rating (“S&P”).

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A PPA for approximately 15% of the revenues until 2026, 40% from 2027 until 2036 and 50% from 2037 until 2041 with Southern California Public Power Authority (“SCPPA”), which is not rated.

O&M. Operation and maintenance is performed in-house, with the same team providing these services before the acquisition by Atlantica.

Project Level Financing. In December 2020, before the acquisition of Coso was closed, the asset entered into a $273 million financing agreement. On July 15, 2021, we prepaid $40 million, and the notional amount was reduced to $233 million. From the total amount, $93 million are progressively repaid following a theoretical 2036 maturity, with a legal maturity in 2027. The remaining $140 million are expected to be refinanced on or before 2027. Interest has been hedged until 2027 such that the total annual interest rate is 2.985% until 2027. As of December 31, 2021, the outstanding amount of the loan was $214 million.

The financing agreement permits cash distributions to shareholders subject to a debt service coverage ratio of at least 1.20x.

Vento II

Vento II is a portfolio of four wind assets in the United States in which Atlantica has a 49% equity interest. The portfolio does not currently have any debt, although we may raise some non-recourse debt at an intermediate holding subsidiary. Operation and maintenance services are provided by EDP Renováveis (“EDPR”) for the four assets.

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Elkhorn Valley

Overview. Elkhorn Valley is a 101 MW wind asset in Union County, Oregon, which entered into operation in November 2007.

PPA. Elkhorn Valley has a PPA with Idaho Power Company at a fixed price, expiring in 2027. Base price increases annually with a 3% escalation factor.

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Prairie Star

Overview. Prairie Star is a 101 MW wind asset in Filmore County, Minnesota, which entered into operation in December 2007.

PPA. Prairie Star has a PPA with Great River Energy. The PPA expires in 2027 with the option to extend it until 2036.

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Twin Groves II

Overview. Twin Groves II is a 198 MW wind asset in McLean County, Illinois, which entered into operation in March 2008.

PPA. Twin Groves II has a PPA with Exelon Generation Co LLC at a fixed price, expiring in 2026.

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Lone Star II

Overview. Lone Star II is a 196 MW wind asset in Albany, Texas, which entered into operation in May 2008.

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PPA. Lone Star II has a PPA with EDPR North America, LLC at a fixed price, expiring in 2023. Our expectation is that the asset could enter into shorter PPAs or hedge agreements once the current PPA is over and we will evaluate together with our partner the option to repower the asset in the future.

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. Chile PV 1 reached COD in 2016 and Chile PV 2 reached COD in 2017.

PPA: Chile PV 1 sells its production to the Chilean power market. Chile PV 2 has PPAs 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$, with an outstanding amount of $77 million as of December 31, 2021. 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.

La Sierpe

Overview: La Sierpe is a 20 MW solar PV plant in Colombia, wholly owned by us, which reached COD in late 2021.

PPA: La Sierpe has a 15-year, fixed-price PPA in local currency with Synermin, the largest independent electricity wholesaler in Colombia. The PPA provides for the sale of electricity at a fixed base price indexed to local Consumer Price Index (the “CPI”).

O&M: O&M agreement with a third party under a 10-year fixed price agreement indexed to local CPI We are currently negotiating a potential termination of this agreement in order to internalize the O&M.

Project Level Financing: the asset has no project finance debt.

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, 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 19-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, 2021 was $77 million.

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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. The plant 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.

Project Level Financing. In June 2020 we refinanced Cadonal’s debt for a total amount of $77.6 million:

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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.

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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.

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

The combined principal balance of these loans was $60 million as of December 31, 2021. 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 August, 2021, 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, 2021, the outstanding amount of the loan was $71 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.

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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 services are performed internally.

Project Level Financing. The asset does not have any project level financing.

Solar Assets in Spain

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 consists 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 and Sevilla PV, 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 U.S.

O&M services are provided by Abengoa through all-in contracts, except for Seville PV, where O&M services are provided by a different third party. In February 2022, we reached an agreement with Abengoa, subject to conditions precedent, including waivers from financial institutions, to terminate the O&M agreements in six plants in Spain and to introduce a clause to be able to terminate the rest of the agreements every three years. If and when the conditions precedent are met, we would perform the O&M for the six plants we would be terminating with third parties or internal resources.

These assets benefit from the tax accelerated depreciation regime established by the Spanish Corporate Income Tax Act.

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 currently O&M services under an all-in contract that we could terminate every three years.

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:

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

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60% through a cap set at approximately 1% until 2025. From January 2026 40% through a cap with approximately 3.75% strike price for the duration of the loans.

The outstanding amount of these loans as of December 31, 2021 was $118 million for Solaben 2 and $120 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, 2021, was $145 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 1.20x 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 1.075x.

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 currently O&M services under an all-in contract that we could terminate every three years.

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:

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

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

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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, 2021 was $234 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 currently O&M services through a 21-year all-in contract.

Project Level Financing. In 2006, PS20 entered into a 24.5-year loan agreement respectively, which was subsequently increased in 2007 to €94.6 million. The interest rate for PS20 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:

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30% through a swap set at approximately 4.07%

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70% through a cap set at approximately 1% and 4,5% until 2025

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From January 2026 70% through a cap with a 4.5% strike

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The outstanding amount of the PS20 loan as of December 31, 2021 was $56 million. This financing arrangement 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 currently 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 ($370.2 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, 2021 was $327 million. The note facility permits cash distributions to shareholders twice per year 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 currently O&M services through a 20-year all-in contract.

Project Level Financing. On June 26, 2018, Helioenergy 1 & 2 entered into:

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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 95.5% hedged through a swap set at approximately 3.8% strike and 3% hedged through a cap with a 1% strike.

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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, 2021 was $273 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 currently 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:

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78% through a swap set at approximately 4.76% strike until 2027.

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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:

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

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

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:

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

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

As of December 31, 2021, the outstanding amount of these loans was $435 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 currently 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 (approximately $324 million) with maturity in December 2034. The bonds have a coupon of 3.758% with interest payable in semi-annual instalments on June 30 and December 31 of each year. The principal is amortized over the life of the financing. The outstanding amount as of December 31, 2021 was $214 million. The bonds permit cash distributions to shareholders twice 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 a third party.

Project Level Financing. Seville PV does not have any project level financing.

Italy PV 1, 2 and 3

Overview. We own 6 PV assets in Italy which have a combined capacity of 6.2 MW. Italy PV 1 is a 1.6 MW solar PV plant which reached COD in 2010. Italy PV 2 is a 2.1 MW solar PV plant which reached COD in 2011. Italy PV 3 is a portfolio of 4 PV assets with a total capacity of 2.5 MW which reached COD in 2012.

PPA. The assets have contracted revenues through a regulated feed in premium in addition to merchant revenues for the energy sold to the wholesale market.

O&M. O&M agreements with third parties.

Project Level Financing. The assets have non-recourse project financing in place for a total amount outstanding of $2.8 million as of December 31, 2021 The loans have an average cost of 1.6% and average maturity in 2026. The financing arrangements permit dividend distributions at least once per year subject to meeting the debt service coverage ratios required by contract.

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.

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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, which 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 $78 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. Since February 1, 2022, and following an agreement with Abengoa, the employees performing the operation and maintenance of the plant have been transferred to an Atlantica subsidiary, so the O&M services are performed internally since such date.

Project Level Financing. Kaxu entered into a long-term financing agreement with a lenders’ group for a total initial amount of approximately $367.4 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 9.6% considering the hedge in place. As of December 31, 2021, the outstanding amount of these loans was ZAR 5,015 million, or $314 million.

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 a debt default 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 represented a theoretical event of default under the Kaxu project finance agreement and the total amount of the debt was classified as current in our consolidated financial statements as of December 31, 2021. In September 2021, we obtained a waiver for such theoretical event of default which was conditional upon the replacement of the operation and maintenance supplier of the plant, as extended in November, 2021. On February 1, 2022, we transferred the employees performing the operation and maintenance services to an Atlantica subsidiary. The waiver has been extended until April 30, 2022 and is subject to the lenders receiving certain documentation from us, including formal evidence of the approval by our off-taker and the department of energy of South Africa of the operation and maintenance internalization and we are currently working on obtaining such documentation.

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Efficient Natural Gas and Heat

Calgary District Heating

Overview. Calgary is a 55MWt District Heating located in the city of Calgary in Alberta, Canada which reached COD in 2010.

Concession Agreement. The asset has availability-based revenue with inflation indexation and 20 years of weighted average contract life, with investment grade off-takers. Contracted capacity and volume payments represent approximately 80% of the total revenue.

O&M. The operation and maintenance services are performed by NAES.

Project Level Financing. The asset does not have any project level financing.

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. The asset 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.

Conversion Services Agreement. On September 18, 2009, ACT entered into the Pemex Conversion Services Agreement, with Pemex (“Pemex CSA”), 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 is adjusted annually, 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. Pemex has the possibility to terminate the Pemex CSA under certain circumstances paying an indemnity.

In recent years, Pemex’s credit rating has weakened and is currently BBB from S&P, Ba3 from Moody’s and BB- from Fitch. We have been experiencing delays from Pemex in collections since the second half of 2019 which have been significant in certain quarters.

O&M. GE provides services for the maintenance, service and repair of the gas turbines and 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 March 2014, ACT Energy Mexico entered into a $655 million senior loan agreement with a syndicate of banks. The financing consists of a $205 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 USD 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, 2021 was $479 million. The senior loan agreement permits cash distributions to shareholders provided that the debt service coverage ratio is at least 1.20x.

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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. We are currently working with our partner and the clients in a potential 7-year extension of the PPA which would involve an investment to achieve improvements in the asset to provide, among other things, electric power redundancy to the clients.

O&M. Wärtsilä performs the O&M for Monterrey. The term of the contract is three years from COD and we expect to renew the contract with the same supplier. 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 $147 million outstanding amount as of December 31, 2021, 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 USD LIBOR plus a margin of 2.75% with a 0.25% increase after three years. The LIBOR exposure was 85% hedged with a swap rate of 2.26% 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.

Transmission Lines

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 lines 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 the transmission line and substations. 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.

Project Level Financing. ATN has a project bond in place which was issued in September 2013 and which currently has three tranches outstanding:

1st tranche had 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.

2nd tranche had a principal amount of $45 million with a 26-year term and bears interest at a rate of 7.53% per year. The second tranche has a 15-year grace period for principal repayments.

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3rd tranche had 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, 2021, $92 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, 2021, $397 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 an O&M agreement with a subsidiary of Abengoa until 2027.

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 4.85% on a weighted average basis and matures in 2031. As of December 31, 2021, the outstanding amount of the ATN2 project loan was $50 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 USD 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, 2021, the outstanding amount was $63 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 determined by the regulator 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. Energysur performs maintenance services under a 3-year contract expiring on January 1, 2025.

Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.

Chile TL4

Overview. Chile TL4 is a 63-mile transmission line in operation in Chile which reached COD in 2016. The asset has fully contracted revenues in US dollars, with inflation escalation and 50-year contract life. The off-takers are several mini-hydro plants that receive contracted or regulated payments from third parties.

O&M. The assets have O&M agreements with third parties.

Project Level Financing. Chile TL4 does not have any project level financing.

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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. We are currently in conversations with Sacyr to reorganize our equity interests in the desalination assets in Algeria to manage our business more efficiently.

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 had a corporate income tax exemption until 2021. After that period, the exemption was not extended, and the tariff was adjusted accordingly.

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.

O&M. 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). Sacyr has reached an agreement with Abengoa to acquire its equity interest in this joint venture. Such agreement is subject to customary approvals for this type of transactions.

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. As of December 31, 2021, the outstanding amount of the Honaine project loan was $52 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.

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%. We are currently in negotiations with Sacyr to reorganize our equity interests in the desalination assets in Algeria to manage our business more efficiently.

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 tariff was adjusted accordingly.

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%). Sacyr has reached an agreement with Abengoa to acquire its equity interest in this joint venture which is subject to customary approvals for this type of transactions.

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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, 2021, the outstanding amount of the Skikda project loan was $12 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, including the right to appoint majority of Directors at the Board of Directors of Befesa Agua Tenes. Therefore, we control Tenes since May 31, 2020 and as a result we have fully consolidated the asset from that date.

Tenes has 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, 2021, the outstanding amount of the Tenes project loan was $86 million. The financing arrangements permit cash distribution to shareholders subject to a debt service coverage ratio of at least 1.10x.

Geographies and business sectors

We refer to “Item 5. Operating and Financial Review and Prospects” and to Note 4 to our Consolidated Financial Statements for a breakdown of our revenue by geography and by business sector.

Assets under construction

Albisu

Overview. Albisu is a 10 MW PV asset wholly owned by us, currently under construction near the city of Salto (Uruguay).

PPA. The asset has a 15-year PPA with Montevideo Refrescos, S.R.L, a subsidiary of Coca-Cola Femsa. The PPA is denominated in local currency with a maximum and minimum price in US$ and is adjusted monthly based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollar exchange rate.

La Tolua and Tierra Linda

Overview. La Tolua and Tierra Linda are two solar PV assets wholly owned by us, currently under construction in Córdoba (Colombia) with a combined capacity of 30 MW.

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PPA. Each plant has a 15-year PPA in local currency indexed to local inflation with Synermin, the largest independent electricity wholesaler in Colombia.

Customers

We derive our revenue from selling electricity, electric transmission capacity, water desalination capacity and heat. 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). Chile PV1, representing a very small percentage of our revenue sells electricity at market prices. Additionally, we have other assets that sell a percentage of their production 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 heat transmission lines 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, or if the geothermal resource is lower than expected 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.

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Employees and Human Resources

As December 31, 2021, we had 658 employees. 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 (“O&M”) activities of our subcontractors as reflected in our corporate health and safety policy.

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 five years. Additionally, we perform periodic health and safety audits of our asset contractors to monitor their 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 key safety metrics targets in all our assets which include both Atlantica and subcontractor employees, which were achieved in 2021:

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 hours worked. We ended 2021 at 1.2, compared to 1.0 in 2020.

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 hours worked. We ended 2021 at 0.5, compared to 0.3 in 2020.

The key metrics provided above do not include Rioglass, since the asset was acquired during 2021 and the integration process is still ongoing. The increase in both KPIs was mainly caused by higher rates in some of the assets recently acquired. During the year 2022, we expect to continue working on the integration of recent acquisitions, to ensure that our strict practices are consistently established in all the assets.

Operation and Maintenance

In terms of operational efficiency, we focus on ensuring long-term availability, reliability and asset integrity with maintenance and monitoring. The suppliers of our solar panels, turbines, transmission towers and equipment are selected 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 our 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. In Kaxu, we internalized the operation and maintenance services on February 1, 2022, after the transfer of the employees performing those services to an Atlantica subsidiary. In addition, in February 2022, we reached an agreement with Abengoa, subject to conditions precedent, including waivers from financial institutions, to terminate the O&M agreements in six plants in Spain and to introduce a clause to be able to terminate the rest of the agreements every three years. If and when the conditions precedent are met, we would perform the O&M for the six plants we would be terminating with third parties or internal resources. See “Item 3.D—Risk Factors— III. Risks Related to Our Relationship with Algonquin and Abengoa—If Abengoa defaults on certain of its debt obligations, including as a result of the insolvency filling by their holding company Abengoa S.A. we could potentially be in default of certain of our project financing agreements”

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Legal Proceedings

In 2018, 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 called on this $2.5 million from the escrow account and Abengoa reimbursed us for this amount. The insurance company could claim additional amounts if they faced new losses after following a process agreed between the parties and, in any case, Atlantica would only make payments if and when the actual loss has been confirmed and after arbitration if the Company initiates it. In the past we had 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.

In addition, during 2021, several lawsuits were filed related to the February 2021 winter storm in Texas against among others Electric Reliability Council of Texas (“ERCOT”), two utilities in Texas and more than 230 individual power generators, including Post Oak Wind, LLC, the project company owner of Lone Star I, one of the wind assets in Vento II where we currently have a 49% equity interest. The basis for the lawsuit is that the defendants failed to properly prepare for cold weather, including failure to implement measures and equipment to protect against cold weather, and failed to properly conduct their operations before and during the storm.

Atlantica is not a party to any other significant legal proceedings Atlantica is party to various administrative and regulatory proceedings that have arisen in the ordinary course of business.

While Atlantica does not expect the above noted proceedings, either individually or in combination, 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 operating 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 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.

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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 the Public Utility Holding Company Act of 1935 (“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 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.

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.

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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 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. 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 ( the “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 ( the “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 was 10% of retail electric sales in 2020 and increases annually until it reaches 15% in 2025.

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.

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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 with 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 the 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 California Energy Commission (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:

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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;

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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;

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

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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;

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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 commencement of the energy reform process, secondary legislation and regulation was enacted and changes were implemented through a substantial modification of the legal framework that had governed the development of the energy industry in the country.

However, on March 9, 2021, Mexico´s President proposed a preferential reform to the Electric Industry Law. In broad terms, the reform aimed for CFE to re-instate its significance 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 enforce the termination of grandfathered self-supply 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 to decide which generation permits are granted by the FERC.

Several legal defense mechanisms were activated and filed before Mexican courts, arguing that the aforementioned reform was against constitutional principles, which have resulted in Mexican District Courts suspending the application of the reform until constitutional proceedings are definitely resolved, thus leaving the Electric Industry Law of 2014 effective.

On September 30, 2021, the Mexican President submitted before the House of Representatives a new bill pursuant to which articles 25, 27 and 28 of the Mexican Constitution are proposed to be amended. As a constitutional amendment, such bill is to be discussed and passed by the House of Representatives, the Mexican Senate and local congresses. If passed as presented, most of the energy reform of December 2013 would be reversed and the sector would be significantly transformed.

On December 3, 2021,the Mexican Energy regulatory Commission (Comisión Reguladora de la Energía), or CRE published in DOF Decree number A/037/2021, by means of which the interpretation criteria of the concept self-needs was amended, with an impact on general aspects of isolated supply and local generation activities.

Additionally, on December 31, 2021, CRE published in DOF the new rules for the grid code (Código de Red) on aspects of efficiency, quality, reliability, safety and sustainability of the National Electric System (Sistema Eléctrico Nacional).

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 harmful emissions.

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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 Mexican Wholesale Electricity Market (Mercado Eléctrico Mayorista), or 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.

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.

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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) suppliers, (iii) non-supplier 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), or the Guidelines 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.

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.

All the aforementioned matters regarding the Electric Industry Law will remain in force until the final decisions of the constitutional proceedings mentioned above are issued. In the event that the reform of the Electric Industry Law proposed in 2021 enters into force, the aforementioned will have to be modified in accordance with the new provisions and framework applicable to the electricity market.

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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:

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

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Electric Industry Law (Ley de la Industria Eléctrica).

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

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

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Energy Transition Law (Ley de Transición Energética).

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

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

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

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Geothermal Energy Law (Ley de Energía Geotérmica).

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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.

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Guidelines of the Market (Bases del Mercado Eléctrico).

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Grid Code 2.0 (Código de Red 2.0).

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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).

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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).

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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).

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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).

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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 Electric 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).

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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).

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

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Decree to guarantee the Efficiency, Quality, Reliability, Continuity and Safety of the National Electric 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)).

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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).

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Decree number A/037/2021 of the Energy Regulatory Commission by means of which decree number A/049/2017 is amended, regarding the interpretation criteria of the concept self-needs and the general aspects applicable to the isolated supply activity.

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Resolution number RES/550/2021 of the Energy Regulatory Commission by means of which the General Administrative Provisions regarding the efficiency, quality, reliability, continuity, safety and sustainability standards of the National Electric System are published: Grid Code.

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 (Sistema Garantizado de Transmisión or 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(Sistema Complementario de Transmisión or 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.

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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 and award a SGT concession agreement ( see further information regarding SGT Concession Agreements below).

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 the Transmission Rules (Reglamento de Transmision).

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, and the National Electricity 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. In addition, the OSINERGMIN could impose penalties, including, among others, (a) admonishment, (b) successive fines, depending on the nature and effect of the interruption and its frequency, (c) temporary suspension of activities, and (d) definitive suspension of activities and the provisional administration of operations by an intervenor, if a termination event occurs and the Peruvian Ministry of Energy notifies of its desire to terminate the SGT Concession Agreement.

Electricity Legal Framework

The principal laws and regulations governing the Peruvian energy sector, or the Electricity Legal Framework, are: (i) the Electricity Concessions Law (Ley de Concesiones Electricas, PCL), and its implementing rules; (ii) the Law to Ensure the Efficient Development of Electricity Generation (Ley para Asegurar el Desarrollo Eficiente de la Generacion Electrica), (iii) the Transmission Rules (Reglamento de Transmision), or the Transmission Rules; (iv) the General Environmental Law; (v) the Regulations for the Environmental Protection in Power Activities; (vi) the Laws creating OSINERGMIN; (vii) the OSINERGMIN Rules ; (viii) the Regulatory Agencies of Private Investment in Public Services Framework Law; and (ix) the Legislative Decree that promotes investment in the generation of power through renewable resources and its regulations.

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These rules 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.

All entities that generate, transmit or distribute power to third parties in Peru, including self-generators and co-generators that sell their excess capacity and energy in the SEIN are regulated by the Energy Legal Framework.

The Peruvian government retains ultimate oversight and regulatory control. In addition, the Peruvian government owns and controls various generation and distribution companies in Peru.

During 2020, OSINERGMIN approved a new Annual Liquidation Procedure for the SGT Electricity Transmission Service, which applies to all concessionaires that have transmission facilities subject to the SGT Contracts regime. The regulation specifies that the Liquidation Procedure to be carried out in 2021 will comprise a Liquidation Period of ten months, from March 1, 2020 to December 31, 2020. By means of this procedure, the base tariff for the transmission service cannot be modified; however, this is relevant as it determines the monthly disbursements to be made in favor of the agents of the electricity market.

Additionally, OSINERGMIN has approved certain procedure applicable to electricity agents (including transmission agents) including the Procedure "Conditions for the application of electricity generation and transmission tariffs", by means of which, the conditions for the application of the generation and transmission prices were established for certain electric energy supplies as further detailed in the Electrical Concessions Law. Moreover, OSINERGMIN, has updated the database of the “Investment Standard Modules for Transmission Systems”, with costs as of 2019.

In addition, the same way it was approved the Procedure for the Auditing of Contracts and Authorizations of the Electricity Subsector and Concession Contracts in Natural Gas Activities was approved(Resolution No. 166-2020-OS/CD), having as the purpose of this regulation is to audit the obligations contained in concession contracts, authorizations and investment commitment contracts in the electricity sub-sector, including the transmission service, which are under the competence of OSINERGMIN. For the electric transmission systems, the following aspects are subject to audit: (i) the Electric Power Transmission Systems Concession Contract (SGT and SCT); (ii) Electric Power Transmission System Expansions; (iii) Concession Contract to Develop the Electric Power Transmission Activity.

In March of 2020, the Presidency of the Council of Ministers ordered the reorganization of OSINERGMIN passed through a Supreme Decree No. 023-2020-PCM in order to evaluate the administrative, organizational and management situation of the entity, as well as to propose the necessary reform measures. In such context, in December 2020, OSINERGMIN approved a new Regulations for the Inspection and Sanctioning of Energy and Mining Activities under the responsibility of OSINERGMIN, by means of Resolution No. 208-2020-OS/CD, issued on December, 2020. Such new regulations are applicable to the transmission sector and will come into effect with the publication of other pending norms in charge of the entity. Regarding the sanctioning power of OSINERGMIN in the electric sector, a new Fine Application Limit has been adopted.

During 2021, the OSINERGMIN issued Resolution No. 069-2021-OS-CD that approved the calculation of the annual settlement corresponding to the transmission concessionaires for the income obtained from the transmission tolls of the Secondary Transmission Systems and the Complementary Transmission Systems. Said resolution was subsequently amended by Resolution No. 242-2021-OS/CD, in order to change the procedure for the determination, collection, settlement of the Annual Average Cost and the unit value of the Transmission Toll of the projects included in the Transmission Investment Plans for the periods 2013-2017, 2017-2021 and 2021-2025 that have been reallocated through the mechanism of expression of interest of the transmission concessionaires. Likewise, it regulates the form of payment of such amounts and the corresponding information reporting. In addition, Resolution 083-2021-OS/CD approved the new technical procedure No. 20 of the COES related to the entry, modification and withdrawal of electric facilities in the SEIN and established a new regulation for the treatment of facilities connected to distribution facilities.

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Finally, other relevant regulations have been modified, such as Board Resolution No. 092-2021-OS/CD, which approved the modifications to the Technical Procedure regarding No. 31 on the calculation of the Variable Costs of the Generation Units. This is the most relevant regulatory change in the tariff regime of the electricity system since it will affect the electricity business due to the impact on the marginal cost.

The Power Sector Antitrust Law (Law No. 26876) and its regulations (Supreme Decree No. 017-98-ITINCI) were superseded by means of a new regulation applicable to all types of mergers and acquisitions. The Law No. 31112, "Law that establishes the prior control for corporate concentration operations" was published on January of 2021, and relevant implementing rules (Supreme Decree No. 039-2021-PCM) were published in March 2021. This law modifies the regulatory regime applicable to business concentrations in the electricity sector (and expands it to other sectors under different economic thresholds).

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 any electrical activities (i.e. generation, transmission or distribution) the holder must obtain from the Ministry of Energy and Mines an instrument for environmental management (“IEM”), which after its approval is mandatory for implementation.

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.

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. Related to this, the compensation for facilities that are part of the SGT is allocated to customers by OSINERGMIN according to the amounts of investment, operational and maintenance costs set forth in the SGT Concession Agreement. 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.

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Regulation in Spain

Primary Rights and Obligations under the Spanish Electricity Act

The Electricity Act recognizes the following rights for producers with facilities that use renewable energy sources:

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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.

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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.

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Entitlement to a specific payment scheme: the sale of electricity at market price is complemented with a specific regulated remuneration that allows these technologies to compete on an equal basis 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 Spanish government can establish a specific remuneration through an auction process.

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 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.

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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.

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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.

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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 energy 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.

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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 the granting of the specific remuneration system, the conditions, technologies or group of specific facilities that may participate in the competitive competition mechanism are established as described above. Nevertheless, 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.

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 (“reasonable rate of return”).

The Royal Decree 413/2014 establishes statutory periods of six years, with the second regulatory period beginning in January 2020. Each statutory period is divided into two statutory half-periods of three years. 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.

The second regulatory period began on January 1, 2020. Following the recommendations of the CNMC, the reasonable return was calculated 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. For the second regulatory period, the Royal Decree-Law 17/2019 updated the reasonable rate of return that applies to standard renewable energy facilities in the period 2020-2025. The reasonable return applicable over the remaining regulatory life of standard facilities applicable during the second regulatory period, is 7.09%.

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 February 24 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, for the years 2020, 2021 and 2022, respectively.

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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 2022 are as follows:

	Useful Life	Return on Investment 2020-2022(euros/MW)	Operating Remuneration 2022 (euros/GWh)	Maximum Hours	Minimum Hours	Operating Threshold
Solaben 2	25 years	398,174	45,85	2,008	1,210	706
Solaben 3	25 years	398,174	45,85	2,008	1,210	706
Solacor 1	25 years	398,174	45,85	2,008	1,210	706
Solacor 2	25 years	398,174	45,85	2,008	1,210	706
PS 10	25 years	550,263	68,32	1,840	1,109	647
PS 20	25 years	407,269	62,46	1,840	1,109	647
Helioenergy 1	25 years	393,071	45,66	2,008	1,210	706
Helioenergy 2	25 years	393,071	45,66	2,008	1,210	706
Helios 1	25 years	407,037	46,19	2,008	1,210	706
Helios 2	25 years	407,037	46,19	2,008	1,210	706
Solnova 1	25 years	413,423	46,55	2,008	1,210	706
Solnova 3	25 years	413,423	46,55	2,008	1,210	706
Solnova 4	25 years	413,423	46,55	2,008	1,210	706
Solaben 1	25 years	403,599	46,06	2,008	1,210	706
Solaben 6	25 years	403,599	46,06	2,008	1,210	706
Seville PV	30 years	709,200	33,23	2,041	1,237	721

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 resolve the issue with 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, at 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 Court of Justice of the EU declared the conformity of this tax to the EU legislation in March 2021.

However, the Royal Decree-Law 12/2021 and the Royal Decree-Law 17/2021 included an exemption from this tax, for the electricity produced and incorporated into the electricity system during the third and last calendar quarter of 2021. This entails modifying the calculation of the tax base and of the fractioned payments regulated in the tax regulations.

The Royal Decree-Law 29/2021 has extended those measures to the first calendar quarter of 2022.

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.

C.	Organizational Structure

The following summary chart sets forth our ownership structure as of the date of this annual report:

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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. Sacyr. holds 25.5% of Honaine and 16.9% of Skikda

(6)	20% of Seville PV owned by 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)	49% owned by Industrial Development Corporation, a South African Government company

(11)	70% owned by Arroyo Energy

(12)	100% indirectly owned by Arroyo Energy Netherlands II

(13)	70% held by Algonquin

(14)	65% held by financial partners

(15)	Solar projects 100% owned by Chile Platform

(16)	51% held by EDP Renewables

(17)	Simplified structure

D.	Property, Plant and Equipment

See “Item 4.B—Business Overview.”

ITEM 4A.

UNRESOLVED STAFF COMMENTS

Not applicable.

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. In 2021, our renewable sector represented 77% of our revenue, with solar energy representing 69%. We complement our portfolio of renewable assets with storage, efficient natural gas and heat 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. For a detailed discussion, please see “Item 4—Information on the Company—Business Overview—Overview” and “Item 4—Information on the Company—Business Overview—Our Business Strategy”.

Significant Events in 2021

Investments

•

In April 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. In January 2021, we closed our second investment through this platform with the acquisition of Chile PV 2, a 40 MW PV plant. Total equity investment in this new asset was $5.0 million. The platform intends to make further investments in renewable energy in Chile and sign PPAs with creditworthy off-takers.

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•

In January 2021, we closed the acquisition of a 42.5% equity interest in Rioglass, a supplier of spare parts and services in the solar industry, increasing our equity interest to 57.5%. In addition, on July 22, 2021, we exercised the option to acquire the remaining 42.5% equity interest in Rioglass. The total investment made in 2021 to acquire the additional 85% equity interest, resulting in a 100% ownership, was $17.1 million.

•

In April 2021, we closed the acquisition of 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 Independent System Operator (California ISO). It has PPAs signed with an 18-year average contract life. The total equity investment was $130 million, which was paid in April 2021. In addition, on July 15, 2021, we repaid $40 million of project debt.

•

In May 2021, we closed the acquisition of Calgary District Heating, a district heating asset in Canada, for a total equity investment of $22.7 million. The asset has availability-based revenue with inflation indexation and 20 years of weighted average contract life at the time of the acquisition. Contracted capacity and volume payments represent approximately 80% of the total revenue.

•

In June 2021, we closed the acquisition of a 49% interest in Vento II, a 596 MW wind portfolio in the U.S. for a total equity investment of $198.3 million. EDP Renewables owns the remaining 51%. The assets have PPAs with investment grade off-takers with five-year average remaining contract life at the time of the investment.

•

In August 2021, we closed the acquisition of Italy PV 1 and Italy PV 2, two solar PV plants in Italy with a combined capacity of 3.7 MW for a total equity investment of $9 million. These assets have regulated revenues under a feed in tariff until 2030 and 2031, respectively.

•

In November 2021, we closed the acquisition of La Sierpe, a 20 MW solar PV plant in Colombia for a total equity investment of $23.5 million. The asset was acquired under our Liberty GES ROFO Agreement. We also acquired two additional solar projects in Colombia with a combined capacity of 30 MW which are currently in construction, la Tolua and Tierra Linda.

•

In December 2021, we closed the acquisition of Italy PV 3, a 2.5 MW solar portfolio in Italy for a total equity investment of $4.0 million. The four assets in the portfolio have regulated revenues under a feed in tariff until 2032.

•

In October 2018, we reached an agreement to acquire PTS, a natural gas transportation platform located in Mexico. We initially acquired a 5% stake in the project and reached an agreement to increase our equity interest. Given that the project financing did not close, in June 2021, we reached an agreement with our partner to sell our 5% ownership in the project at cost. There are no other costs or liabilities related to this investment.

•

In January 2022, we closed the acquisition of Chile TL4, a 63-mile transmission line and 2 substations in Chile for a total equity investment of $39 million. We expect to make an expansion of the line in 2022, which would represent an additional investment of approximately $8 million. The asset has fully contracted revenues in US dollars, with inflation escalation and a 50-year contract life. The off-takers are several mini-hydro plants that receive contracted or regulated payments.

Corporate Financing Activities during the year

On January 7, 2021, Algonquin purchased 4,020,860 ordinary shares in a private placement in order to maintain its equity interest in the Company, as a consequence of the prior underwritten public offering of 5,069,200 ordinary shares in December 2020. Gross proceeds of the private placement were $300 million, which were used to finance growth opportunities and for general corporate purposes after deducting underwriting discounts and commissions and offering expenses.

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On May 18, 2021, we issued the Green Senior Notes amounting to an aggregate principal amount of $400 million due in 2028. The Green Senior Notes bear interest at a rate of 4.125% per year, payable on June 15 and December 15 of each year, commencing December 15, 2021, and will mature on June 15, 2028. The proceeds were used to fully prepay the Note Issuance Facility 2019 and to finance investments and acquisitions.

On August 3, 2021, we established an “at-the-market program” and entered into the Distribution Agreement with J.P. Morgan Securities LLC, as sales agent, under which we may offer and sell from time to time up to $150 million of our ordinary shares, including in “at-the-market” offerings under our universal shelf registration statement on Form F-3 and a prospectus supplement that we filed on August 3, 2021. During the third and fourth quarters, we have issued 1.6 million shares under the program at an average market price of $38.43 per share pursuant to the Distribution Agreement, representing net proceeds of $61.4 million.

Factors Affecting the Comparability of Our Results of Operations

Acquisitions and Non-recurrent Projects

The results of operations of Chile PV 1 and Tenes have been fully consolidated since April and May 2020, respectively. Tenes was recorded under the equity-method from January 2019 to May 2020, at which point we then gained control over the asset and started to fully consolidate it. The results of operations of Chile PV 2, Coso, Calgary District Heating, Italy PV 1 and Italy PV 2, La Sierpe and Italy PV 3 have been fully consolidated since January, April, May and August, November and December 2021, respectively. Vento II has been recorded under the equity method since June, 2021.

In addition, the results of operations of Rioglass have been fully consolidated since January 2021. In 2021, most of Rioglass operating results relate to a specific solar project which ended in October 2021, and which represented $85.3 million in revenue and $1.0 million in Adjusted EBITDA, included in our EMEA and Renewable energy segments for 2021 and which are non-recurrent.

Impairment

Considering the delays in the improvements and replacements that we are carrying out in the storage system in Solana and their impact on production in 2021, as well as an increase in the discount rate, we identified an impairment triggering event in accordance with IAS 36 (Impairment of Assets). As a result, an impairment test has been performed which resulted in the recording of an impairment loss of $43.1 million for the year ended December 31, 2021 in the line “Depreciation, amortization, and impairment charges”.

In addition, 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, 2021 we recorded a reversal of the expected credit loss impairment provision at ACT for $24.9 million following an improvement of its client’s credit risk metrics which is reflected in the line item “Depreciation, amortization, and impairment charges”. In 2020 we had recorded a $26.6 million impairment provision in ACT.

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. This change in the estimated useful life was accounted for as a change in accounting estimates in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors. This caused a $46.0 million increase if we compare the results of the two years since the change was applied for twelve months in 2021 and only four months in 2020.

Electricity market prices

In addition to regulated revenue, our solar assets in Spain receive revenue from the sale of electricity at market prices. Electricity prices have increased significantly since mid-2021 and revenues from the sale of electricity at power prices represented $132.9 million in 2021 compared to 42.9 million in 2020, causing higher short-term cash collections. Regulated revenues are revised every three years to reflect, among other things, the difference between expected and actual market prices if the difference is higher than a pre-defined threshold. Current higher market prices in Spain will therefore cause lower regulated revenue to be received progressively over the remaining regulatory life of our solar assets. As a result, we recorded a negative provision for $77.1 million with no cash impact on the current period that has lowered revenue and Adjusted EBITDA in this geography, compared to a positive provision reversal for $22.3 million in 2020.

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Significant Trends Affecting Results of Operations

Acquisitions

If the acquisitions recently closed perform as expected, we expect these assets to positively impact our results of operations in 2022 and upcoming years.

Solar, wind and geothermal resources

The availability of solar, wind and 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. Based on the extent to which the solar, wind and geothermal resources are not available at expected levels, this could have a 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 these acquisitions. Fluctuations in capital markets may affect our ability to access this capital through debt or equity financings.

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, with the exception of Calgary, with revenue in Canadian dollars, 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 Europe have their revenue and expenses denominated in euros, Kaxu, our solar plant in South Africa, has its revenue and expenses denominated in South African rand and La Sierpe our solar plant in Colombia has its revenue and expenses denominated in Colombian pesos. Project financing 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 streams 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 assets in Europe. We hedge the exchange rate for the distributions in euros 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. For example, revenue in euro-denominated companies could decrease when translated to U.S. dollars at the average foreign exchange rate solely due to a decrease in the average foreign exchange rate, in spite of revenue in the original currency being stable. Fluctuations in the value of South African rand and Colombian peso with respect to the U.S. dollar may also affect our operating results. Apart from the impact of these translation differences, the exposure of our income statement to fluctuations of foreign currencies is limited, as the financing of projects is typically denominated in the same currency as that of the contracted revenue agreements.

In our discussion of operating results, we have included foreign exchange impacts in our revenue by providing constant currency revenue growth. The constant currency presentation is not a measure recognized under IFRS and excludes the impact of fluctuations in foreign currency exchange rates. We believe providing constant currency information provides valuable supplemental information regarding our results of operations. We calculate constant currency amounts by converting our current period local currency revenue using the prior period foreign currency average exchange rates and comparing these adjusted amounts to our prior period reported results. This calculation may differ from similarly titled measures used by others and, accordingly, the constant currency presentation is not meant to substitute recorded amounts presented in conformity with IFRS as issued by the IASB, nor should such amounts be considered in isolation.

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Impacts associated with fluctuations in foreign currency are discussed in more detail under “Item 11—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, 2021, approximately 92% of our project debt and close to 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, LIBOR or over the alternative rates replacing these.

Electricity market prices

In addition to regulated revenue, our solar assets in Spain receive revenue from the sale of electricity at market prices. Regulated revenues are revised every three years to reflect the difference between expected and actual market prices if the difference is higher than a pre-defined threshold. Given that since mid-2021 electricity prices in Spain have been, and may continue to be, significantly higher than expected, it will cause lower regulated revenue starting in 2023 over the remaining regulatory life of our solar assets. Also, the regulator or the administration may change or may create new mechanisms to adjust the price of electricity, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Key Financial Measures

Our revenue and Adjusted EBITDA by geography and business sector for the years ended December 31, 2021, 2020 and 2019 are set forth in the following tables:

Revenue by geography

	Year ended December 31,
	2021					2020					2019
	$ in millions		% of revenue			$ in millions		% of revenue			$ in millions		% of revenue
North America	$	395.8		32.7	%	$	330.9		32.6	%	$	333.0		32.9	%
South America		155.0		12.8	%		151.5		15.0	%		142.2		14.1	%
EMEA		660.9		54.5	%		530.9		52.4	%		536.3		53.0	%
Total revenue	$	1,211.7		100.0	%	$	1,013.3		100.0	%	$	1,011.5		100.0	%

Revenue by business sector

	Year ended December 31,
	2021					2020					2019
	$ in millions		% of revenue			$ in millions		% of revenue			$ in millions		% of revenue
Renewable Energy	$	928.5		76.6	%	$	753.1		74.3	%	$	761.1		75.2	%
Efficient natural gas & Heat		123.7		10.2	%		111.0		11.0	%		122.3		12.1	%
Transmission Lines		105.6		8.7	%		106.1		10.5	%		103.5		10.2	%
Water		53.9		4.5	%		43.1		4.2	%		24.6		2.4	%
Total revenue	$	1,211.7		100.0	%	$	1,013.3		100.0	%	$	1,011.5		100.0	%

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Adjusted EBITDA by geography

	Year ended December 31,
	2021					2020					2019
	$ in millions		% of revenue			$ in millions		% of revenue			$ in millions		% of revenue
North America	$	311.8		78.8	%	$	279.4		84.4	%	$	307.2		92.3	%
South America		119.6		77.2	%		120.0		79.2	%		115.4		81.2	%
EMEA		393.0		59.5	%		396.7		74.7	%		399.0		74.4	%
Adjusted EBITDA⁽¹⁾	$	824.4		68.0	%	$	796.1		78.6	%	$	821.6		81.2	%

Adjusted EBITDA by business sector

	Year ended December 31,
	2021					2020					2019
	$ in millions		% of revenue			$ in millions		% of revenue			$ in millions		% of revenue
Renewable Energy	$	602.6		64.9	%	$	576.3		76.5	%	$	604.1		79.4	%
Efficient natural gas & Heat		100.0		80.8	%		101.0		91.0	%		109.2		89.3	%
Transmission Lines		83.6		79.2	%		87.3		82.3	%		85.7		82.8	%
Water		38.2		70.9	%		31.5		73.1	%		22.6		91.9	%
Adjusted EBITDA⁽¹⁾	$	824.4		68.0	%	$	796.1		78.6	%	$	821.6		81.2	%

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, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership). 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

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

	Year ended December 31,
	2021			2020		2019
	($ in millions)
Profit/(loss) for the year attributable to the parent company	$	(30.1	)	$	11.9	$	62.1
Profit/(loss) attributable to non-controlling interest from continued operations		19.2			4.9		12.5
Income tax expense		36.2			24.9		30.9
Depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of our equity ownership)		18.7			13.9		3.0
Financial expense, net		340.9			331.8		402.3
Depreciation, amortization and impairment charges		439.4			408.6		310.8
Adjusted EBITDA	$	824.4		$	796.1	$	821.6

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Reconciliation of net cash generated by operating activities to Adjusted EBITDA

	Year ended December 31,
	2021			2020		2019
	($ in millions)
Net cash flow provided by operating activities	$	505.6		$	438.2	$	363.5
Net interest /taxes paid		342.3			287.2		299.5
Variations in working capital		3.1			10.9		125.0
Other non-monetary items		(55.8	)		43.9		25.8
Share of profit/(loss) of associates carried under the equity method, depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership) and other		29.2			15.9		7.8
Adjusted EBITDA	$	824.4		$	796.1	$	821.6

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 and heat assets, miles in operation in the case of Transmission lines and Mft³ per day 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 and heat assets provides information about the performance of these assets.

•

Availability in the case of our Efficient natural gas and heat assets, Transmission lines 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.

Key Performance Indicators

	As of and for the year ended December 31,
	2021			2020			2019
Renewable Energy
MW in operation⁽¹⁾		2,044			1,551			1,496
GWh produced⁽²⁾		4,655			3,244			3,236
Efficient natural gas & Heat
MW in operation⁽³⁾		398			343			343
GWh produced⁽⁴⁾		2,292			2,574			2,090
Availability (%)⁽⁴⁾		100.6	%		102.1	%		95.0	%
Transmission lines
Miles in operation		1,166			1,166			1,166
Availability (%)		100.0	%		100.0	%		100.0	%
Water
Mft³ in operation⁽¹⁾		17.5			17.5			10.5
Availability (%)		97.9	%		100.1	%		101.2	%

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 except for Vento II for which we have included our 49% interest.

(2)	Includes 49% of Vento II wind portfolio production since its acquisition. Includes curtailment in wind assets for which we receive compensation

(3)	Includes 43 MW corresponding to our 30% share in Monterrey and 55MWt corresponding to Calgary District Heating.

(4)	GWh produced includes 30% of the production from Monterrey.

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Production in the renewable business sector increased by 43.5% in 2021, compared to 2020. The increase was mainly driven by the contribution from the recently acquired renewable assets Coso, Chile PV1, Chile PV 2, Vento II, Italy PV 1, Italy PV 2, Italy PV 3 and La Sierpe bringing approximately 1,339 GWh of additional electricity generation. The increase was also due to higher production at Kaxu compared to the prior year when an unscheduled outage that affected part of the first half of 2020, largely covered by insurance. Production also increased in our assets in Spain where solar radiation was better than in the previous year.

In our solar assets in the U.S. production decreased by 3.5% year over year mainly due to lower solar resource in Arizona, especially in the third quarter, and lower availability in the storage system, as we are carrying out the improvements and replacements that were scheduled. These works have impacted production in 2021 and are expected to impact production in 2022 as we have been experiencing delays due to COVID-19 restrictions and delays from subcontractors.

In our wind assets in Uruguay production decreased by 10.4% in 2021, mainly due to lower wind resource in the period. Wind resource was also lower than expected in our wind assets in the United States.

Efficient natural gas and heat production was lower in 2021 compared to 2020 due to lower production at ACT, mainly due to lower demand from our off-taker. This did not affect our revenue as the contract is based on availability and continues to achieve high availability levels.

In Water, the decrease in availability was mainly due to lower availability in Tenes in the fourth quarter of 2021, resulting principally from the high number of suspended particles in the water caused by heavy rains in the region in the fourth quarter. Availability in this plant in the first quarter of 2021 was also lower largely due to the installation of some new safety-related equipment. Our transmission lines, where revenue is also based on availability, continue to achieve high availability levels.

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Results of Operations

The table below illustrates our results of operations for the years ended December 31, 2021, 2020 and 2019.

	Year ended December 31,
	2021			2020			2019
	$ in millions
Revenue	$	1,211.7		$	1,013.3		$	1,011.5
Other operating income		74.6			99.5			93.8
Employee benefit expenses		(78.7	)		(54.4	)		(32.2	)
Depreciation, amortization and impairment charges		(439.4	)		(408.6	)		(310.8	)
Other operating expenses		(414.3	)		(276.7	)		(261.8	)
Operating profit/(loss)	$	353.9		$	373.1		$	500.4
Financial income		2.7			7.1			4.1
Financial expense		(361.2	)		(378.4	)		(408.0	)
Net exchange differences		1.9			(1.4	)		2.7
Other financial income/(expense), net		15.7			40.9			(1.1	)
Financial expense, net	$	(340.9	)	$	(331.8	)	$	(402.3	)
Share of profit/(loss) of associates carried under the equity method		12.3			0.5			7.4
Profit/(loss) before income tax	$	25.3		$	41.8		$	105.6
Income tax expense		(36.2	)		(24.9	)		(30.9	)
Profit/(loss) for the year	$	(10.9	)	$	16.9		$	74.6
Profit/(loss) attributable to non-controlling interests		(19.2	)		(4.9	)		(12.5	)
Profit / (loss) for the year attributable to the parent company	$	(30.1	)	$	12.0		$	62.1
Weighted average number of ordinary shares outstanding (thousands) - basic		111,008			101,879			101,063
Weighted average number of ordinary shares outstanding (thousands) - diluted		114,523			103,392			101,063
Basic earnings per share attributable to the parent company (U.S. dollar per share)		(0.27	)		0.12			0.61
Diluted earnings per share attributable to the parent company (U.S. dollar per share)		(0.26	)		0.12			0.61
Dividend paid per share⁽¹⁾		1.72			1.66			1.57

Note:

(1)

On February 26, 2021, May 4, 2021, July 30, 2021 and November 9, 2021 our board of directors approved a dividend of $0.42, $0.43, $0.43 and $0.435 per share, respectively, corresponding to the fourth quarter of 2020, the first quarter of 2021, the second quarter of 2021, and the fourth quarter of 2021, which were paid on March 22, 2021, June 15, 2021, September 15, 2021, and December 15, 2021, respectively. On February 26, 2020, May 6, 2020, July 31, 2020 and November 4, 2020, our board of directors approved a dividend of $0.41, $0.41, $0.42 and $0.42 per share corresponding to the fourth quarter of 2019, the first quarter of 2020, the second quarter of 2020 and the third quarter of 2021, respectively, which were paid on March 23, 2020, June 15, 2020, September 15, 2020 and December 15, 2020, respectively.

Comparison of the Years Ended December 31, 2021 and 2020

The significant variances or variances of the significant components of the results of operations are discussed in the following section.

Revenue

Revenue increased by 19.6% to $1,211.7 million for the year 2021, compared to $1,013.3 million for the year 2020. On a constant currency basis, revenue in 2021 was $1,187.7 million, representing an increase of 17.2% compared to the year 2020. On a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project, revenue for the year 2021 was $1,102.3 million, representing an increase of 8.8% compared to the previous year.

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This increase (on a constant currency basis and excluding the Rioglass non-recurrent solar project) was mainly due to the contribution of the recently acquired and consolidated assets which represent a total of $92.3 million of additional revenue in 2021. Revenue was also higher at Kaxu. Damage and business interruption were covered by our insurance; however, insurance proceeds were recorded in “Other operating income”. In addition, revenue increased at ACT mainly due to higher revenue in the portion of the tariff related to operation and maintenance services, driven by higher operation and maintenance costs for the year 2021 compared to the previous year. At ACT, operation and maintenance costs are higher in the quarters preceding any major maintenance, which is scheduled for the beginning of 2022.

These effects were partially offset by a 4.8% decrease in revenue from our solar assets in Spain on a constant currency basis, in spite of higher production in the period. The decrease results mainly from a negative provision that reduces revenue but has no cash impact on the current period, as further explained in the discussion of the EMEA region. Revenue also decreased in our solar assets in North America, mainly due to lower solar radiation in the year ended December 31, 2021 compared to the previous year and lower availability of the storage system in Solana, as previously described.

Other operating income

The following table sets forth our other operating income for the years ended December 31, 2021 and 2020:

	Year ended December 31,
	2021		2020
Other operating income	$ in millions
Grants	$	60.7	$	59.0
Insurance proceeds and other		13.9		40.5
Total	$	74.6	$	99.5

Other operating income decreased by 25.0% to $74.6 million for the year ended December 31, 2021, compared to $99.5 million for the year ended December 31, 2020.

“Insurance proceeds and other” for the year 2020 included $18.4 million in insurance income in Kaxu in compensation for the unscheduled outage, as well as $5.7 million in insurance income received at Solana and Mojave in compensation for events from prior years, which are the main reasons for the decrease.

“Grants” represent the financial support provided by the U.S. Department of the Treasury 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 2021 compared to the previous year.

Employee benefit expenses

Employee benefit expenses increased by 44.4% to $78.7 million for the year ended December 31, 2021, compared to $54.5 million for the year ended December 31, 2020. The increase was mainly due to the consolidation of Coso and Rioglass.

Depreciation, amortization and impairment charges

Depreciation, amortization and impairment charges increased by 7.5% to $439.4 million for the year ended December 31, 2021, compared to $408.6 million for the year ended December 31, 2020. The increase was mainly due to an increase in depreciation and amortization at our solar assets in Spain. In September 2020, we reduced the useful life of our solar assets in Spain from 35 to 25 years after COD, which increased our depreciation and amortization charges for the year ended December 31, 2021 by $46.0 million compared to the previous year. In addition, the increase is also due to the $43.1 million impairment loss recorded in Solana in September 2021, after a triggering event was identified mainly due to delays in the improvements and replacements in the storage system and their impact on production in 2021, as well as to the increase in the discount rate. Depreciation, amortization and impairment charges also increased due to the consolidation of recent acquisitions and because in 2020 this caption included a reversal of an impairment charge in our wind assets in Uruguay for $18.7 million in Cadonal and Palmatir, with no corresponding amount in 2021.

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These effects were partially offset by a reversal of the expected credit loss impairment provision at ACT. IFRS 9 requires impairment provisions to be based on the expected credit loss of the financial assets in addition to actual credit losses. ACT recorded a reversal of the expected credit loss impairment provision of $24.9 million for the year ended December 31, 2021, while in the year ended December 31, 2020, there was an increase of $26.6 million in the expected credit loss impairment provision. In addition, for the year ended December 31, 2020, depreciation, amortization and impairment charges included an equipment write-off of $48 million related to the Solana storage system with no corresponding amount in the current period.

Other operating expenses

The following table sets forth our other operating expenses for the years ended December 31, 2021 and 2020:

	Year ended December 31,
	2021					2020
Other operating expenses	$ in millions		% of revenue			$ in millions		% of revenue
Raw Materials	$	70.7		5.8	%	$	7.8		0.8	%
Leases and fees		9.3		0.8	%		2.6		0.3	%
Operation and maintenance		154.0		12.7	%		110.9		10.9	%
Independent professional services		39.2		3.2	%		40.2		4.0	%
Supplies		40.8		3.4	%		27.9		2.8	%
Insurance		45.4		3.8	%		37.6		3.7	%
Levies and duties		29.9		2.5	%		39.8		3.9	%
Other expenses		25.0		2.1	%		9.9		1.0	%
Total	$	414.3		34.2	%	$	276.7		27.3	%

Other operating expenses increased by 49.7% to $414.3 million for the year ended December 31, 2021, compared to $276.7 million for the year ended December 31, 2020, mainly due to higher raw material costs corresponding to the aforementioned Rioglass non-recurrent solar project.

Other operating expenses also increased due to higher operation and maintenance costs mainly caused by the contribution of the recently consolidated assets for $17.9 million and higher costs at ACT, since operation and maintenance costs are higher in this asset in the quarters preceding a major overhaul, which is scheduled to be performed at the beginning of 2022.

In addition, the cost of supplies increased mainly because part of our supply costs are related to the electricity market prices, which have increased in 2021 compared to the previous year.

Operating profit

As a result of the above-mentioned factors, operating profit decreased by 5.1% to $353.9 million for the year ended December 31, 2021, compared with $373.1 million for the year ended December 31, 2020.

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Financial income and financial expense

	Year ended December 31,
Financial income and financial expense	2021			2020
	$ in millions
Financial income	$	2.7		$	7.1
Financial expense		(361.2	)		(378.4	)
Net exchange differences		1.9			(1.4	)
Other financial income/(expense), net		15.7			40.9
Financial expense, net	$	(340.9	)	$	(331.8	)

Financial income

Financial income decreased to $2.7 million for the year ended December 31, 2021, compared to $7.1 million for the year ended December 31, 2020, primarily due to a $3.8 million of non-monetary financial income resulting from the refinancing of the Cadonal project debt in 2020.

Financial expense

The following table sets forth our financial expense for the years ended December 31, 2021 and 2020:

	Year ended December 31,
Financial expense	2021			2020
	$ in millions
Interest on loans and notes	$	(302.5	)	$	(316.2	)
Interest rates losses derivatives: cash flow hedges		(58.7	)		(62.2	)
Total	$	(361.3	)	$	(378.4	)

Financial expense decreased by 4.5% to $361.3 million for the year ended December 31, 2021, compared to $378.4 million for the year ended December 31, 2020.

The decrease of “Interest on loans and notes” was mainly due to a decrease in interest on loans indexed to LIBOR and EURIBOR, since the reference rates were lower in the year ended December 31, 2021 compared to the previous year. The decrease was also due to the acquisition of Liberty Interactive’s equity interest in Solana in August 2020, which caused a decrease of $15.0 million. In addition, the year ended December 31, 2020 included costs and expenses related to the prepayment of the Note Issuance Facility 2017. This decrease was partially offset by the contribution of recently consolidated assets and by interest accruing on the Green Senior Notes and the Green Exchangeable Notes, which have contributed a full year in 2021, for a total amount of $18.0 million.

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 decrease was mainly due to lower losses from the Helios 1&2 swap, which was canceled after the Helios 1&2 project debt was refinanced in 2020 with a new fixed rate financing. This decrease was partially offset by higher losses in swaps hedging loans indexed to LIBOR, as a result of lower reference rates than in the previous year.

Other financial income/(expense), net

	Year ended December 31,
Other financial income/(expense), net	2021			2020
	$ in millions
Other financial income	$	32.3		$	162.3
Other financial expense		(16.6	)		(121.4	)
Total	$	15.7		$	40.9

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Other financial income/(expense), net decreased to a net income of $15.7 million for the year ended December 31, 2021 compared to a net income of $40.9 million for the year ended December 31, 2020.

In the year 2020, Other financial income includes a non-cash gain of $145 million from the acquisition of Liberty Interactive´s equity interest in Solana, which is the primary reason for the decrease. Liberty Interactive was the tax equity investor in Solana and although the investment of Liberty Interactive was in shares, under IFRS it was recorded as liability. In August 2020, we acquired Liberty Interactive´s equity interest in Solana and recorded a gain corresponding to the difference between book value of Liberty Interactive´s equity interest in Solana and the total price expected to be paid to Liberty Interactive. For the year ended December 31, 2021, Other financial income includes $9.2 million income corresponding to the change in the fair value of the conversion option of the Green Exchangeable Notes since December 2020 and $7.6 million of income corresponding to the change in fair value of Kaxu derivatives, for which hedge accounting is not applied. Residual items are primarily interest on deposits and loans, including non-monetary changes to the amortized costs of such loans.

The decrease in other financial expenses is primarily due to a one-time non-cash loss of $73.0 million caused by the refinancing of Helios 1&2 in 2020. Other financial expense includes 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 increased to $12.3 million in the year ended December 31, 2021, compared to $0.5 million in the year ended December 31, 2020. The increase was primarily due to the contribution of the recently acquired Vento II and a higher profit in Honaine.

Profit/(loss) before income tax

As a result of the previously mentioned factors, we reported a profit before income tax of $25.3 million for the year ended December 31, 2021, compared to a profit before income tax of $41.8 million for the year ended December 31, 2020.

Income tax

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, 2021 and 2020, is as follows:

	For the year ended December 31,
	2021			2020
	$ in millions
Consolidated income before taxes		25.3			41.8
Average statutory tax rate		25	%		25	%
Corporate income tax at average statutory tax rate		(6.3	)		(10.4	)
Income tax of associates, net		3.1			0.1
Differences in statutory tax rates		(3.4	)		(0.1	)
Unrecognized NOLs and deferred tax assets		(11.2	)		(37.1	)
Purchase of Liberty Interactive´s equity interest in Solana		-			36.4
Other Permanent Differences		(4.1	)		(8.9	)
Other non-taxable income/(expense)		(14.3	)		(4.7	)
Corporate income tax		(36.2	)		(24.9	)

For the year ended December 31, 2021, the overall effective tax rate was different than the statutory average rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in the U.K. entities and to provisions recorded for potential tax contingencies.

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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 U.K. entities, partially offset by the non-taxable gain recorded in the consolidated financial statements on the purchase of Liberty Interactive’s equity interest in Solana.

Profit attributable to non-controlling interests

Profit attributable to non-controlling interests was $19.2 million for the year ended December 31, 2021 compared to $4.9 million for the year ended December 31, 2020. Profit attributable to non-controlling interests 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, Chile PV 2 and Tenes). The increase is due to higher profits at Kaxu and Skikda, as well as to the consolidation of Tenes since the second quarter of 2020.

Profit/(loss) attributable to the parent company

As a result of the previously mentioned factors, loss attributable to the parent company was $30.1 million for the year ended December 31, 2021, compared to a profit of $12.0 million for the year ended December 31, 2020.

Comparison of the Years Ended December 31, 2020 and 2019

The significant variances or variances of the significant components of the results of operations between the years ended December 31, 2020 and December 31, 2019, are discussed in the Form 20-F filed with the SEC on March 1, 2021.

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 and heat, Transmission and Water. We report our results in accordance with both criteria. Our Efficient natural gas and heat segment was renamed to include Calgary District Heating which has been consolidated since its acquisition in May 2021.

Comparison of the Years Ended December 31, 2021 and 2020

Revenue and Adjusted EBITDA by geography

The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 2021 and 2020, by geographic region:

Revenue by geography

	Year ended December 31,
	2021					2020
Revenue by geography	$ in millions		% of revenue			$ in millions		% of revenue
North America	$	395.8		32.7	%	$	330.9		32.6	%
South America		155.0		12.8	%		151.5		15.0	%
EMEA		660.9		54.5	%		530.9		52.4	%
Total revenue	$	1,211.7		100.0	%	$	1,013.3		100.0	%

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Adjusted EBITDA by geography

	Year ended December 31,
	2021					2020
Adjusted EBITDA by geography	$ in millions		% of revenue			$ in millions		% of revenue
North America	$	311.8		78.8	%	$	279.4		84.4	%
South America		119.6		77.2	%		120.0		79.2	%
EMEA		393.0		59.5	%		396.7		74.7	%
Adjusted EBITDA⁽¹⁾	$	824.4		68.0	%	$	796.1		78.6	%

Note:

Volume by geography

	Volume produced/availability
	Year ended December 31,
Volume by geography	2021			2020

North America (GWh)⁽¹⁾		4,818			3,908
North America availability⁽¹⁾		100.6	%		102.1	%
South America (GWh)⁽²⁾		722			667
South America availability		100.0	%		100.0	%
EMEA (GWh)		1,407			1,243
EMEA availability		97.9	%		100.1	%

Note:

(1)	GWh produced includes 30% of the production from Monterrey and our 49% of Vento II wind portfolio production since its acquisition.

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

North America

Revenue increased by 19.6% to $395.8 million for the year ended December 31, 2021, compared to $330.9 million for the year ended December 31, 2020. The increase was mainly due to the contribution from the recently acquired assets, Coso and Calgary. The increase was also caused by higher revenue at ACT mainly due to the higher revenue in the portion of the tariff related to operation and maintenance services, driven by higher operation and maintenance costs for year ended December 31, 2021. This increase was partially offset by a 2.4% decrease in revenue at our solar assets in North America, mainly due to lower radiation in Arizona and lower availability of the Solana storage system, as previously described.

Adjusted EBITDA increased by 11.6% to $311.8 million for the year ended December 31, 2021, compared to $279.4 million for the year ended December 31, 2020. Adjusted EBITDA increased due to the recently acquired assets Coso, Vento II and Calgary. This effect was partially offset by lower Adjusted EBITDA at our solar assets in North America mainly due to lower revenue and to the insurance income received in the year 2020 amounting to $5.7 million. Adjusted EBITDA was also lower at ACT due to higher operation and maintenance expenses in 2021. Adjusted EBITDA margin decreased to 78.8% for the year ended December 31, 2021, compared to 84.4% for year ended December 31, 2020, mainly due to the events described above and to the lower margins of the recently acquired assets.

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South America

Revenue increased by 2.3% to $155.0 million for the year ended December 31, 2021, compared to $151.5 million for the year ended December 31, 2020. Adjusted EBITDA remained stable at $119.6 million for the year ended December 31, 2021, compared to $120.0 million for the year ended December 31, 2020. The increase in revenue was primarily due to the contribution of Chile PV 1 and Chile PV 2. This increase was offset by lower revenue and Adjusted EBITDA from our wind assets in Uruguay, resulting mainly from lower wind resource. Adjusted EBITDA margin decreased slightly to 77.2% for the year ended December 31, 2021, compared to 79.2% for the year ended December 31, 2020 mainly due to lower Adjusted EBITDA margins in the assets recently acquired.

EMEA

Revenue increased by 24.5% to $660.9 million for the year ended December 31, 2021, compared to $530.9 million for the year ended December 31, 2020. On a constant currency basis, revenue for the year ended December 31, 2021, was $636.9 million, which represents an increase of 20.0% compared to 2020. On a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project, revenue for the year ended December 31, 2021, was $551.5 million, which represents an increase of 3.9% compared to 2020. The increase was primarily due to higher revenue at Kaxu, where an unscheduled outage affected production in part of the first quarter of 2020. Property Damage and business interruption were covered by our insurance; however, insurance proceeds were recorded in “Other operating income”. Revenue also increased due to the contribution from Tenes, fully consolidated since the second quarter of 2020. At our solar assets in Spain, revenue decreased by 4.8% on a constant currency basis in spite of higher production in the period mainly due to a non-cash negative provision related to higher than historical electricity prices. Electricity market prices have been higher than expected and the regulation establishes a compensation mechanism under which regulated revenue is revised every three years to reflect the difference between expected and actual market prices if the difference is higher than a pre-defined threshold. Current higher market prices in Spain will therefore cause lower regulated revenue to be received progressively over the remaining regulatory life of our solar assets. As a result, we recorded a negative provision with no cash impact in the current period for $77 million that reduced our revenue in 2021. Due to methodology used in the calculation, revenue from sales of electricity at market prices, net of the provision, decreased by approximately $10 million, which is the main reason for the decrease in revenue in our solar assets in Spain.

Adjusted EBITDA decreased by 0.9% to $393.0 million for the year ended December 31, 2021, compared to $396.7 million for the year ended December 31, 2020. On a constant currency basis, Adjusted EBITDA for the year ended December 31, 2021, was $375.9 million which represents a decrease of 5.2% compared to 2020. On a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project, Adjusted EBITDA for the year ended December 31, 2021, was $374.9 million which represents a decrease of 5.5% compared to 2020. This decrease was mainly caused by lower revenue in our solar assets in Spain as previously explained and to higher supply costs, since the prices are partially linked to electricity prices, and was partially offset by the contribution of Tenes and the recently acquired assets in Italy as well as higher Adjusted EBITDA at Kaxu. Adjusted EBITDA margin decreased to 59.5% for the year ended December 31, 2021, compared to 74.7% for the year ended December 31, 2020, mainly due to lower margin at the Rioglass non-recurrent solar project and to the higher than usual Adjusted EBITDA margin in Kaxu in the year 2020 due to insurance proceeds recorded in “Other Operating Income”.

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Revenue and Adjusted EBITDA by business sector

The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 2021 and 2020, by business sector:

	Year ended December 31,
	2021					2020
Revenue by business sector	$ in millions		% of revenue			$ in millions		% of revenue
Renewable energy	$	928.5		76.6	%	$	753.1		74.3	%
Efficient natural gas & Heat		123.7		10.2	%		111.0		11.0	%
Transmission lines		105.6		8.7	%		106.1		10.5	%
Water		53.9		4.5	%		43.1		4.2	%
Total revenue	$	1,211.7		100.0	%	$	1,013.3		100.0	%

	Year ended December 31,
	2021					2020
Adjusted EBITDA by business sector	$ in millions		% of revenue			$ in millions		% of revenue
Renewable energy	$	602.6		64.9	%	$	576.3		76.5	%
Efficient natural gas & Heat		100.0		80.8	%		101.0		91.0	%
Transmission lines		83.6		79.2	%		87.3		82.3	%
Water		38.2		70.9	%		31.5		73.1	%
Adjusted EBITDA⁽¹⁾	$	824.4		68.0	%	$	796.1		78.6	%

Note:

Volume by business sector

	Volume produced/availability
	Year ended December 31,
Volume by business sector	2021			2020
Renewable energy (GWh)⁽¹⁾		4,655			3,244
Efficient natural gas & Heat (GWh)⁽²⁾		2,292			2,574
Efficient natural gas & Heat availability		100.6	%		102.1	%
Transmission availability		100.0	%		100.0	%
Water availability		97.9	%		100.1	%

Note:

(1)	Includes curtailment production in wind assets for which we receive compensation. Includes our 49% of Vento II wind portfolio production since its acquisition.

(2)	GWh produced includes 30% of the production from Monterrey.

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Renewable energy

Revenue increased by 23.3% to $928.5 million for the year ended December 31, 2021, compared to $753.1 million for the year ended December 31, 2020. On a constant currency basis, revenue for the year ended December 31, 2021, was $904.4 million, which represents an increase of 20.1% compared to 2020. On a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project, revenue for the year ended December 31, 2021, was $819.1 million, which represents an increase of 8.8% compared to 2020. Adjusted EBITDA increased by 4.6% to $602.6 million for the year ended December 31, 2021, compared to $576.3 million for 2020. On a constant currency basis, Adjusted EBITDA for the year ended December 31, 2021, was $585.5 million, which represents an increase of 1.6% compared to 2020. On a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project, Adjusted EBITDA for the year ended December 31, 2021, was $584.5 million, a 1.4% increase compared to the previous year. The increase in revenue and Adjusted EBITDA was primarily due to the contribution from the recently acquired assets Coso, Vento II, Chile PV1, Chile PV2, Italy PV 1, Italy PV 2 and Italy PV 3. Revenue and Adjusted EBITDA also increased due to higher revenue at Kaxu as previously explained. The increase in revenue was partially offset by the decrease in revenue in Spain with no cash impact in the current period, as previously explained. The increase in Adjusted EBITDA was partially offset by higher supply costs in Spain since the prices are partially linked to electricity prices. Adjusted EBITDA margin decreased to 64.9% for the year ended December 31, 2021, from 76.5% for the year ended December 31, 2020, mainly due to lower margin at the non-recurrent one-off project previously described, higher than usual Adjusted EBITDA margin at Kaxu in 2020 due to insurance proceeds recorded in “Other Operating Income” and lower Adjusted EBITDA margins at some of the recently acquired assets.

Efficient natural gas & heat

Revenue increased by 11.4% to $123.7 million for the year ended December 31, 2021, compared to $111.0 million for the year ended December 31, 2020, while Adjusted EBITDA decreased by 1.0% to $100.0 million for the year ended December 31, 2021, compared to $101.0 million for the year ended December 31, 2020. At ACT, operation and maintenance costs are higher in the quarters preceding any major maintenance works, the next of which is scheduled at the beginning of 2022. Revenue increased due to higher operation and maintenance costs, since there is a portion of revenue related to operation and maintenance services plus a margin. Revenue also increased due to the contribution from the recently acquired Calgary district heating asset. Adjusted EBITDA margin decreased due to these higher operation and maintenance costs.

Transmission lines

Revenue remained stable at $105.6 million for the year ended December 31, 2021, compared to $106.1 million for the year ended December 31, 2020. Adjusted EBITDA also remained stable at $83.6 million for the year ended December 31, 2021 compared to $87.3 million for the year ended December 31, 2020.

Water

Revenue increased by 25.0% to $53.9 million for the year ended December 31, 2021, compared to $43.1 million for the year ended December 31, 2020. Adjusted EBITDA increased by 21.2% to $38.2 million for the year ended December 31, 2021, compared to $31.5 million for the year ended December 31, 2020. The increases were mainly due to the contribution from Tenes, which we started to consolidate on May 31, 2020. Adjusted EBITDA margin was stable compared to the previous year.

Comparison of the Years Ended December 31, 2020 and 2019

The significant variances in the revenue and volume, by geographic region and business sector, between the years ended December 31, 2020 and December 31, 2019, are discussed in the Form 20-F filed with the SEC on March 1, 2021.

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

•

investments in new assets and companies and operations (see “Item 4.B—Business Overview—Our Business Strategy”).

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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,
	2021		2020
	$ in millions
Corporate Liquidity
Cash and cash equivalents at Atlantica Sustainable Infrastructure, plc, excluding subsidiaries	$	88.3	$	335.2
Revolving Credit Facility availability		440.0		415.0
Total Corporate Liquidity	$	528.3	$	750.2
Liquidity at project companies
Restricted Cash		254.3		279.8
Non-restricted cash		280.1		253.5
Total cash at project companies	$	534.4	$	533.3

Cash at the project level includes $254.3 million and $279.8 million restricted cash balances as of December 31, 2021 and 2020, respectively. Restricted cash consists primarily of funds required to meet the requirements of certain project debt arrangements. In the case of Solana, part of the restricted cash is being used and is expected to be used for equipment replacement. Restricted cash also includes Kaxu’s cash balance, given that the project financing of this asset was under a theoretical event of default. (see “Item 4—Information on the Company—Our Operations—Renewable energy—Kaxu.”).

Non-restricted cash at project companies includes among others, the cash that is required for day-to-day management of the companies, as well as amounts that are earmarked to be used for debt service in the future.

As of December 31, 2021, $10 million of letters of credit were outstanding under the Revolving Credit Facility and we had no borrowings. In March 2021, we increased the notional amount of this facility from $425 million to $450 million and extended its maturity to December 2023. As a result, as of December 30, 2021 $440 million was available under our Revolving Credit Facility. As of December 31, 2020, we had no borrowings, $10 million of letters of credit were outstanding and $415 million was available under our 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 activities within the guidelines of prudent balance sheet management.

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Credit Ratings

Credit rating agencies rate us and part of our debt securities. These ratings are used by the debt markets to evaluate our 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.

In March and April 2021 both Fitch and S&P upgraded Atlantica’s corporate rating to BB+. The following table summarizes our credit ratings as of December 31, 2021. The ratings outlook is stable for S&P and 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 financing 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 Green Senior Notes, the Revolving Credit Facility and our commercial paper program.

			As of December 31, 2021		As of December 31, 2020
	Maturity		($ in millions)
Revolving Credit Facility		2023		-		-
Other Facilities⁽¹⁾		2021-2025		41.7		29.7
Note Issuance Facility 2019⁽²⁾		-		-		344.0
Green Exchangeable Notes		2025		104.3		102.1
2020 Green Private Placement		2026		327.1		351.0
Note Issuance Facility 2020		2027		155.8		166.9
Green Senior Notes		2028		394.2		-
Total Corporate Debt			$	1,023.1	$	993.7
Total Project Debt			$	5,036.2	$	5,237.6

Note:

(1)	Other facilities include the commercial paper program issued in October 2020, accrued interest payable and other debts.

(2)	The Note Issuance Facility 2019 was fully prepaid on June 4, 2021 with the proceeds of the Green Senior Notes.

A)	Corporate debt agreements

Green Senior Notes

On May 18, 2021, we issued Green Senior Notes with an aggregate principal amount of $400 million due in 2028. The Green Senior Notes bear interest at a rate of 4.125% per year, payable on June 15 and December 15 of each year, commencing December 15, 2021, and will mature on June 15, 2028.

The Green Senior Notes were issued pursuant to an Indenture, dated May 18, 2021, by and among Atlantica as issuer, Atlantica Peru S.A., ACT Holding, S.A. de C.V., Atlantica Infraestructura Sostenible, S.L.U., Atlantica Investments Limited, Atlantica Newco Limited, Atlantica North America LLC, as guarantors, BNY Mellon Corporate Trustee Services Limited, as trustee, The Bank of New York Mellon, London Branch, as paying agent, and The Bank of New York Mellon SA/NV, Dublin Branch, as registrar and transfer agent.

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Our obligations under the Green Senior Notes rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Exchangeable Notes.

Green Exchangeable Notes

On July 17, 2020, we issued 4.00% Green Exchangeable Notes amounting to an aggregate principal amount of $100 million due in 2025. On July 29, 2020, we issued an additional $15 million aggregate principal amount in 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 they are repurchased or redeemed earlier by Atlantica or exchanged, and bear interest at a rate of 4.00% per annum.

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, at the option of the noteholder. Upon exchange, the notes may be settled, at our election, into Atlantica ordinary shares, cash or a combination of both. The initial exchange rate of the notes is 29.1070 ordinary shares per $1,000 of the 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 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Senior Notes.

Note Issuance Facility 2020

On July 8, 2020, we entered into the Note Issuance Facility 2020, a senior unsecured euro-denominated financing with a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of approximately $159 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 accrues at a rate per annum equal to the sum of the 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 the 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 2020 Green Private Placement, the Green Exchangeable Notes and the Green Senior Notes. The notes issued under the Note Issuance Facility 2020 are guaranteed on a senior unsecured basis by our subsidiaries Atlantica Infraestructura Sostenible, S.L.U., Atlantica Peru, S.A., ACT Holding, S.A. de C.V., Atlantica Investments Limited, Atlantica Newco Limited and Atlantica North America LLC.

2020 Green Private Placement

On March 20, 2020, we entered into a senior secured 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 $330 million), maturing on June 20, 2026. Interest accrues at a rate per annum equal to 1.96%. If at any time the rating of these senior secured notes is below investment grade, the interest rate thereon would increase by 100 basis points until such notes are again rated investment grade.

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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 2020 and the Green Senior Notes. Our payment obligations under the 2020 Green Private Placement are guaranteed on a senior secured basis by our subsidiaries Atlantica Infraestructura Sostenible, S.L.U., Atlantica Peru, S.A., ACT Holding, S.A. de C.V., Atlantica Investments Limited, Atlantica Newco Limited and Atlantica North America LLC. The 2020 Green Private Placement is also secured with a pledge over the shares of the subsidiary guarantors, the collateral of which is shared with the lenders under the Revolving Credit Facility.

Note Issuance Facility 2019

On April 30, 2019, we entered into the Note Issuance Facility 2019, a senior unsecured financing with a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of €268 million, approximately $305 million. In June 2021 we prepaid the Note Issuance Facility 2019 in full before maturity in accordance with the terms thereof, with the proceeds of the Green Senior Notes.

Revolving Credit Facility

On May 10, 2018, we entered into a $215 million Revolving Credit Facility with a syndicate of banks. The Revolving Credit Facility was increased by $85 million to $300 million on January 25, 2019 and was further increased by $125 million (to a total limit of $425 million) on August 2, 2019. On March 1, 2021, this facility was further increased by $25 million (to a total limit of $450 million) and the maturity date was extended to December 31, 2023. In addition, the lenders under the Revolving Credit Facility have the option to extend the maturity date of all or any portion of their commitments and/or loans for additional consecutive 365-day periods, upon request from us subject to certain conditions. Under the Revolving Credit Facility, we are also able to request the issuance of letters of credit, which are subject to a sublimit of $100 million that are included in the aggregate commitments available under the Revolving Credit Facility.

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 2020 Green Private Placement, the Note Issuance Facility 2020, the Green Exchangeable Notes and the Green Senior Notes. Our payment obligations under the Revolving Credit Facility are guaranteed on a senior secured basis by Atlantica Infraestructura Sostenible, S.L.U., Atlantica Peru, S.A., ACT Holding, S.A. de C.V., Atlantica Investments Limited, Atlantica Newco Limited and Atlantica North America LLC. The Revolving Credit Facility is also secured with a pledge over the shares of the subsidiary guarantors, the collateral of which is shared with the holders of the notes issued under 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 $11.4 million) which was available in euros or U.S. dollars. On June 30, 2021, the maturity was extended to July 1, 2023. Amounts drawn accrue interest at a rate per annum equal to the sum of the 3-month EURIBOR or LIBOR, plus a margin of 2%, with a floor of 0% for the EURIBOR or LIBOR. As of December 31, 2021, $8.2 million were drawn down.

In December 2020, we also entered into a loan with a bank for €5 million ($5.7 million). The maturity date is December 4, 2025. The loan accrues interest at a rate per annum equal to 2.50%.

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 has been extended twice, for annual periods. 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, 2021, we had €21.5 million ($24.4 million) issued and outstanding under the Commercial Paper Program at an average cost of 0.36%.

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Covenants, restrictions and events of default

The Note Issuance Facility 2020, the 2020 Green Private Placement, the Green Senior Notes and the Revolving Credit Facility contain covenants that limit certain of our and the guarantors’ activities. The Note Issuance Facility 2020, the 2020 Green Private Placement and the Green Exchangeable Notes 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 our cash available for distribution distributed in the previous four fiscal quarters, which in excess of certain thresholds could trigger a default. Additionally, under the 2020 Green Private Placement, the Revolving Credit Facility and the Note Issuance Facility 2020 we are required to comply with a leverage ratio of our corporate indebtedness excluding non-recourse project debt 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).

At-The-Market Program

On August 3, 2021, we established an “at-the-market program” and entered into the Distribution Agreement with J.P. Morgan Securities LLC, as sales agent, under which we may offer and sell from time to time up to $150 million of our ordinary shares, including in “at-the-market” offerings under our universal shelf registration statement on Form F-3 and a prospectus supplement that we filed on August 3, 2021. During the third and fourth quarters of 2021, we have issued 1.6 million shares under the program at an average market price of $38.43 per share pursuant to our Distribution Agreement, representing gross proceeds of $62 million and net proceeds of $61.4 million.

Uses of liquidity and capital requirements

A)	Debt Service

Principal payments on debt as of December 31, 2021, are due in the following periods according to their contracted maturities:

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Principal debt repayment schedule

	Total		2022		2023		2024		2025		2026		Subsequent years
	$ in millions
Solana		585.0		20.7		21.8		24.2		26.8		29.5		461.8
Mojave		514.7		35.3		35.7		36.9		38.1		39.4		329.4
Coso		214.4		15.4		14.1		14.6		14.2		14.7		141.3
ACT		478.7		38.3		40.0		37.6		42.3		54.6		266.1
North America		1,792.7		109.7		111.6		113.3		121.4		138.2		1,198.6
Chile PV 1		51.0		1.6		0.9		1.1		1.1		1.2		45.1
Chile PV 2		25.6		0.8		0.9		1.0		1.7		2.9		18.5
Palmatir		77.3		6.5		6.1		6.2		6.6		7.0		44.9
Cadonal		60.4		3.8		3.5		3.7		3.9		4.3		41.2
Melowind		70.9		2.5		2.8		4.8		5.0		5.1		50.7
ATN		92.4		5.4		5.7		6.0		6.4		6.8		62.0
ATS		397.2		11.4		7.9		7.4		8.3		9.5		352.8
ATN 2		49.8		4.7		4.8		5.0		5.1		5.3		24.9
Quadra 1&2 and Palmucho		62.8		4.5		4.9		5.4		5.9		6.5		35.5
South America		887.5		41.3		37.4		40.6		44.0		48.6		675.6
Solaben 2&3⁽¹⁾		382.8		33.5		32.8		34.4		146.1		30.4		105.5
Solacor 1&2		233.9		23.9		24.4		27.3		29.3		31.0		98.0
PS 20		56.1		5.8		6.0		6.3		6.7		7.1		24.2
Helios 1&2		327.3		19.7		21.7		22.6		23.0		22.5		217.9
Helioenergy 1&2		272.9		17.4		18.5		19.9		21.1		20.0		176.1
Solnova 1,3&4		435.2		45.6		45.1		48.0		50.7		53.6		192.2
Solaben 1&6		213.7		14.3		14.8		14.8		15.7		16.3		137.8
Rioglass		19.0		9.9		3.6		1.9		2.0		1.2		0.3
Italy PV 1&3		2.8		0.5		0.6		0.6		0.6		0.3		0.3
Kaxu		314.5		1.4		27.0		29.4		29.9		33.7		193.1
Skikda		12.0		4.7		4.8		2.5		0.0		0.0		0.0
Tenes		85.9		7.7		7.7		8.0		8.3		8.6		45.6
EMEA		2,356.0		184.4		207.0		215.6		333.3		224.8		1,190.9
Total project debt	$	5,036.2		335.4		356.0		369.5		498.7		411.5		3,065.1
Corporate debt	$	1,023.1		27.9		10.1		1.9		106.2		327.1		550.0
Total	$	6,059.3		363.3		366.1		371.4		604.9		738.6		3,615.1

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.

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.

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	Total		Up to one year		Between one and three years		Between three and five years		Subsequent years
	$ in millions
Purchase commitments		1,570.8		79.2		191.2		159.3		1,141.1
Accrued interest estimate during the useful life of loans		2,029.4		267.6		497.6		427.2		837.0

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. In the first quarter of 2022, we have reached an agreement to internalize some of our long-term operation and maintenance contracts and to reduce the duration of other contracts.

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.

B)	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, 2021	March 12, 2021	March 22, 2021	0.42
May 4, 2021	May 31, 2021	June 15, 2021	0.43
July 30, 2021	August 31, 2021	September 15, 2021	0.43
November 9, 2021	November 30, 2021	December 15, 2021	0.435
February 25, 2022	March 14, 2022	March 25, 2022	0.44

D)	Investments and Acquisitions

The acquisitions and investments detailed in “Significant events in 2021” have been part of the use of our liquidity in 2021. In addition, we have made investments in assets which are currently under development or construction. We expect to continue making investments in assets in operation or under construction or development to grow our portfolio.

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.

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Cash flow

The following table sets forth cash flow data for the years ended December 31, 2021, 2020 and 2019:

	Year ended December 31,
	2021			2020			2019
	$ in millions
Gross cash flows from operating activities
Profit/(loss) for the year	$	(10.9	)	$	16.9		$	74.6
Adjustments to reconcile after-tax profit to net cash generated by operating activities		861.9			719.5			713.5
Profit for the year adjusted by non-monetary items	$	851.0		$	736.4		$	788.1
Net interest/taxes paid		(342.3	)		(287.3	)		(299.5	)
Variations in working capital		(3.1	)		(10.9	)		(125.0	)
Total net cash flow provided by/ (used in) operating activities	$	505.6		$	438.2		$	363.6
Net cash flows from investing activities
Acquisitions of subsidiaries and entities under equity method		(362.4	)		2.5			(173.4	)
Investments in contracted concessional assets⁽¹⁾		(24.7	)		(1.4	)		22.0
Distributions from entities under the equity method		34.8			22.2			30.5
Other non-current assets/liabilities		1.1			(29.2	)		2.7
Total net cash flows (used in)/ provided by investing activities	$	(351.2	)	$	(5.9	)	$	(118.2	)
Net cash flows used in financing activities	$	(380.1	)	$	(137.3	)	$	(310.2	)
Net increase / (decrease) in cash and cash equivalents		(225.7	)		295.0			(64.8	)
Cash, cash equivalents and bank overdraft at beginning of the year		868.5			562.8			631.5
Translation differences cash or cash equivalents		(20.1	)		10.7			(3.9	)
Cash and cash equivalents at the end of the period	$	622.7		$	868.5		$	562.8

Note:

(1) Includes proceeds for $20.5 million and $7.4 million in 2021 and 2020 respectively, See Note 6 of the Annual Consolidated Financial Statements.

Net cash flows provided by/ (used in) operating activities

Net cash provided by operating activities in 2021 was $505.6 million, a 15.4% increase compared to $438.2 million for the previous year. The increase was mainly due to the increase in Adjusted EBITDA previously explained and to higher electricity market prices in Spain in 2021 when compared to 2020. This effect was partially offset by higher interest and income tax paid in 2021 compared to the previous year.

The significant variances in the net cash flows provided by or used in operating activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 are discussed in the Form 20-F filed with the SEC on March 1, 2021.

Net cash provided by/ (used in) investing activities

For the year 2021, net cash used in investing activities amounted to $351.2 million and corresponded mainly to $362.0 million paid for the acquisitions of Vento II, Coso, Calgary, Chile PV2, Rioglass, Italy PV 1, Italy PV 2, Italy PV 3 and La Sierpe, net of the initial cash contribution from these entities. Net cash used in investing activities also includes investments in concessional assets for $24.7 million, mainly corresponding to capital expenditures and equipment replacements at Solana for $24.5 million and in Spain for $8.5 million, partially offset by $20.5 million proceeds from the sale of a building owned by Rioglass. These cash outflows were partially offset by $34.8 million of dividends received from associates under the equity method, of which $15.8 million corresponded to Amherst Island Partnership by AYES Canada, most of which were paid to our partner in this project.

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For the year, 2020, net cash provided by investing activities was $5.9 million 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.

The significant variances in the net cash flows provided by or used in investing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 are discussed in the Form 20-F filed with the SEC on March 1, 2021.

Net cash provided by/ (used in) financing activities

For the year 2021, net cash used in financing activities amounted to $380.1 million and includes the repayment of principal of our project financing agreements for an approximate amount of $418.3 and $218.7 million of dividends paid to shareholders and non-controlling interests. These cash outflows were partially offset by the proceeds from the equity private placement closed in January 2021 for a net amount of $130.6 million and equity raised under the ATM for a net amount of $58.8 million, net of transaction costs. In addition, in the second quarter of 2021 we prepaid the Note Issuance Facility 2019 for $354.2 million with the proceeds of the Green Senior Notes issued, amounting to $394.0 million, which created a net cash inflow of $39.8 million.

For the year 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 $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 $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 Interactive Ownership Interest in Solana.

C.	Research and Development

Not applicable.

D.	Trend Information

Other than as disclosed elsewhere in this annual report on Form 20F, we are not aware of any trends, uncertainties, demands, commitments or events for the year ended December 31, 2021 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.

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E.	Critical Accounting 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:

-	Assessment of Contracted concessional agreements;

-	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, 2021, 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 on Form 20F.

Contracted concessional assets

Contracted concessional assets correspond to the assets of the Company recorded as intangible or financial assets in accordance with IFRIC 12, property plant and equipment in accordance with IAS 16 and financial asset in accordance with IFRS 16. The assets accounted for by the Company as concessions include renewable energy assets, transmission lines, efficient natural gas assets and heat 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 to, among other factors, (i) the identification of certain infrastructures and contractual agreements in the scope of IFRIC 12, (ii) an 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 revenue from construction and concessionary activity.

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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 expense is as follows:

- Revenues from the updated annual revenue for the contracted concession, as well as revenues from providing 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, using a theoretical internal rate of return specific to the asset. Revenue from operations and maintenance services is recognized in each period according to IFRS 15 “Revenue from contracts with Customers”.

Allowance for expected credit losses

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 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. We have 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. We calculate PD based on Credit Default Swaps spreads;

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

the Loss Given Default 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

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 the same as intangible assets.

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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.

e)	Revenue Recognition

According to IFRS 15, Revenue from Contracts with Customers, the Company asses the goods and services promised in the contracts with the customers and identifies as a performance obligations each promise to transfer to the customer a good or service (or a bundle of goods or services).

In the case of contracts related to intangible or financial assets under IFRIC 12, the performance obligation of the Company is the operation of the asset. The contracts between the parties set the price of the service in an orderly transaction and therefore corresponds to the fair value of the service provided. The service is satisfied over time. The same conclusion applies to concessional assets that are classified as tangible assets under IAS 16 or leases under IFRS 16. All of the transaction prices of assets under IFRIC 12 are fixed and included as part of the long-term PPAs of the Company as disclosed in Note 1 to our Annual Consolidated Financial Statements, presented elsewhere in this annual report.

In the case of financial asset under IFRIC 12 the financial asset accounts for the payments to be received from the client over the residual life of the contract, discounted at a theoretical internal return rate for the project. In each period, the financial asset is reduced by the amounts received from the client and increased by any capital expenditure that the project may incur and by the effect of unwinding the discount of the financial asset at the theoretical internal rate of return. The increase of the financial asset deriving from the unwinding of the discount of the financial asset is recorded as revenue in each period. Revenue will therefore differ from the actual billings made by the asset to the client in each period.

In the case of Spain, according to Royal Decree 413/2014, solar electricity producers receive: (i) the market 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 rate of return on investment (project investment rate of return). Some of the Company´s Spanish assets 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.

Impairment of intangible assets and property, plant and equipment

We review our contracted revenue assets to identify any indicators of impairment at least annually. Except for ECL assessment for financial assets which is discussed in Note 2.3. to our Annual Consolidated Financial Statements. 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.

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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.

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 in profit or loss. 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.

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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.

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.

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Income taxes and recoverable amount of deferred tax assets

Current income tax expense is calculated on the basis of relevant tax laws in force at the date of the consolidated 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 recoverability 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.

F.	Off-Balance Sheet Arrangements

As of December 31, 2021, 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 $92.7 million. In addition, Atlantica issued guarantees amounting to $174.2 million as of December 31, 2021 ($159.8 million as of December 31, 2020). Guarantees issued by us correspond mainly to guarantees provided to off-takers in PPAs, guarantees for debt service reserve accounts and guarantees for interconnection requests or agreements for renewable energy projects.

G.	Safe Harbor

This annual report on Form 20F 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, 17^th 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 President and 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 President and 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).

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Brenda Eprile, Director

Brenda Eprile is a corporate director and sits on a variety of public and private company boards. She currently chairs the board of Global Container Terminals Inc. which operates 2 marine terminals in Vancouver and 2 marine terminals in the Port of New York/New Jersey. She is also a board member 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. From 2016 to 2018, Ms. Eprile 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 LLP 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 earned an MBA from the Schulich School of Business at York University.

Debora Del Favero, Director

Debora Del Favero is a senior executive with extensive 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.

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 PWC) 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 of Algonquin. In his role, Mr. Trisic is responsible for leading the sustainability and government affairs. 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).

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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.

Board Diversity Matrix

On August 6, 2021 the U.S. Securities and Exchange Commission (“SEC”) approved Nasdaq’s Board Diversity Rule, requiring Nasdaq-listed companies to, subject to certain transition periods and exceptions (1) publicly disclose board-level diversity statistics in its annual report or on its website and in an aggregated form, using a standardized template and (2) have or explain why they do not have at least two diverse directors.

Atlantica, as a listed foreign private issuer, is required to have, or explain why it does not have, at least two diverse directors, including one who self-identifies as female, and one who self-identifies as either female, LGBTQ+ or an underrepresented individual. Foreign private issuers shall, starting by the later of (i) August 8, 2022, or (ii) the date when the annual report for the year ended 2022 is filed with the SEC, publish board level diversity statistics annually using either the U.S. domestic issuers prescribed matrix or the foreign private issuers prescribed matrix, and have, or explain why they do not have, one diverse director in 2023, and two diverse directors in 2025.

Considering that Atlantica voluntarily follows many U.S. domestic issuers reporting requirements, we report board diversity information following the U.S. domestic issuers prescribed matrix. The Company believes that it is presently in compliance with the diversity requirements pursuant to Nasdaq’s listing rules.

The information provided below is based on the voluntary self-identification of each member of the Company’s board of directors:

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Board Diversity Matrix as of December 31, 2021
Total Number of Directors	8
	Female	Male	Non-Binary	Did Not Disclose Gender
Part I: Gender Identity
Directors	2	6	-	-
Part II: Demographic Background
African American or Black	-	-	-	-
Alaskan Native or Native American	-	-	-	-
Asian¹	-	1	-	-
Hispanic or Latinx²	-	1	-	-
Native Hawaiian or Pacific Islander	-	-	-	-
White³	2	4	-	-
Two or More Races or Ethnicities	-	-	-	-
LGBTQ+	-
Did Not Disclose Demographic Background	-

Note 1: This is the first year the Company discloses the Board Diversity Matrix. Over subsequent years we expect to include in our disclosures the current year and immediately prior year diversity statistics.

Note 2: Nasdaq demographic background definitions include:

(1)	Asian – A person having origins in any of the original peoples of the Far East, Southeast Asia, or the Indian subcontinent, including, for example, Cambodia, China, India, Japan, Korea, Malaysia, Pakistan, the Philippine Islands, Thailand, and Vietnam.

(2)

Hispanic or Latinx – A person of Cuban, Mexican, Puerto Rican, South or Central American, or other Spanish culture or origin, regardless of race. The term Latinx applies broadly to all gendered and gender-neutral forms that may be used by individuals of Latin American heritage, including individuals who self-identify as Latino/a/e.

(3)	White (not of Hispanic or Latinx origin) – A person having origins in any of the original peoples of Europe, the Middle East, or North Africa.

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.

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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 energy 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.

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.

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B.	Compensation

Compensation of the Board of Directors and Chief Executive Officer

Each independent non-executive director is entitled to receive annual compensation of $150.0 thousand. The Chair of the Board and Chairs of the committees of the Board are entitled to receive additional compensation as detailed in the table below. Non-independent non-executive directors are entitled to be compensated on the same terms as independent non-executive directors. In 2021 and 2020, non-independent non-executive directors declined compensation.

The following table sets out the fee schedule for 2021 and 2020:

In thousands of U.S. Dollars	2021		2020
Annual Director Retainer
Non-Executive Director		150.0		150.0
Annual Committee Chair Retainer
Chair of the Board		75.0		75.0
Chair of the Audit Committee		15.0		15.0
Chair of the Nominating and Corporate Governance Committee		10.0		10.0
Chair of the Compensation Committee		10.0		10.0

The table below summarizes the directors who received remuneration during 2021, as well as the prior year for comparison. The Chief Executive Officer’s total annual compensation is also detailed in this table.

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	Salary and Fees				Annual Bonuses				LTIP²				Total Fixed Remuneration				Total Variable remuneration				Total
	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
Name¹	(in thousands of U.S. dollars)
William Aziz³		160.0		106.7		-		-		-		-		160.0		106.7		-		-		160.0		106.7
Debora Del Favero³		160.0		106.7		-		-		-		-		160.0		106.7		-		-		160.0		106.7
Brenda Eprile³		165.0		110.0		-		-		-		-		165.0		110.0		-		-		165.0		110.0
Michael Forsayeth³		150.0		100.0		-		-		-		-		150.0		100.0		-		-		150.0		100.0
Santiago Seage ⁴		816.6		756.8		1,056.3		996.4		1,879.8		770.9		816.6		756.8		2,936.1		1,767.3		3,752.7		2,524.1
Michael Woollcombe³		225.0		150.0		-		-		-		-		225.0		150.0		-		-		225.0		150.0
Andrea Brentan⁵		-		56.3		-		-		-		-		-		56.3		-		-		-		56.3
Robert Dove⁵		-		60.0		-		-		-		-		-		60.0		-		-		-		60.0
Francisco J. Martinez⁵		-		61.9		-		-								61.9								61.9
Jackson Robinson⁵		-		60.0		-		-								60.0								60.0
Daniel Villalba⁵		-		84.4.		-		-								84.4								84.4
Total		1,676.6		1,652.8		1,056.3		996.4		1,879.8		770.9		1,676.6		1,652.8		2,936.1		1,767.3		4,612.7		3,420.1

Notes:

(1)	All directors served only part of 2020 (see Directors’ Report), except for Santiago Seage.

(2)

Long-term Incentive Awards includes Long-term Incentive Plan (LTIP) and One-Off Plan vested in the year and calculating amounts with the share price at vesting date. In 2021, from the $1,879.8 thousand vested, $1,549.1 corresponded to share appreciation. In 2020, from the $770.9 vested, $464.7 thousand corresponded to share appreciation.

(3)

Mr. Aziz, Mrs. Del Favero, Mrs. Eprile, Mr. Forsayeth and Mr. 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.

(4)	The Chief Executive Officer’s compensation is approved in euros. It has been converted to U.S. dollars for reporting purposes, at the average exchange rate of each year, which is 1.18 $/€ in 2021 and 1.14 $/€ in 2020.

In 2021, the Chief Executive Officer’s total pay amounted to €3,148.6 thousand ($3,752.7 thousand). Fixed salary amounted to €690.0 thousand ($816.6 thousand), annual bonus to €892.5 thousand ($1,056.3 thousand) and long-term incentive awards to €1,566.1 thousand ($1,879.8 thousand).

In 2020, the Chief Executive Officer’s total pay amounted to €2,222.2 thousand ($2,524.1 thousand). Fixed 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).

(5)

This compensation report is presented in U.S. dollars since remuneration of all directors except the CEO is defined in U.S. dollars and the functional currency of the Company is also the U.S. dollar. None of the directors received any pension entitlement and/or taxable benefits in 2021 or 2020. 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.

Chief Executive Officer Long-Term Incentives awards vested

In June 2021, one-third of the Chief Executive Officer’s (the “CEO”) one-off plan stock units vested, and shares were transferred to the CEO in accordance with the terms of the plan using the share price at the date of vesting (June 20, 2021).

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In June 2020, one-third of the CEO’s one-off plan stock 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 value of the shares transferred and cash payments have been included in the table above in their vesting period.

One-Off Plan	One-Off Plan Vesting	One-Third of Restricted Stock Units (RSUs)		Price on Vesting Date (US$)		Remuneration in Cash ($ thousand)*		RSUs Value at Vesting Date ($ thousand)*
2019	June 2021		14,535		36.50		-		578.8
2019	June 2020		14,535		27.97		430.3		-

* One-off plan vesting includes one third of RSUs (14,535 RSUs) plus dividend equivalent rights corresponding to the amount of dividends paid on one share RSU between the One-off plan effective date and the date on which the RSU vests.

In addition, one-third of the CEO’s share options awarded in 2019 and 2020 under the LTIP vested in June and January 2021, respectively. These share options were exercised, and shares were transferred to the CEO in accordance with the terms of the plan.

In 2020, one-third of the CEO’s share options awarded in 2019 under the LTIP vested. They were exercised in 2021 and the shares were transferred to the CEO in accordance with the terms of the plan.

The share options have been included in the table above in their vesting period.

LTIP	LTIP Vesting	One-Third of Share Options		Share Price on Vesting Date (US$)		LTIP Vesting Price per Option (US$)		Share Options Value at Vesting Date (thousand US$)*
2020	2021		34,494		44.17		26.39		613.3
2019	2021		40,693		36.50		19.60		687.7
2019	2020		40,693		27.97		19.60		340.6

* The value of the share options on vesting date is calculated using the number of share options multiplied by (the share price on vesting date minus the LTIP vesting price per option).

In 2021, the majority of the objectives set for the CEO’s variable bonus were met or exceeded and the Compensation Committee decided to approve a bonus corresponding to 105.0% of the target variable compensation, which will be payable in 2022.

	Percentage weight	Achievement
CAFD (cash available for distribution) – Equal or higher than the CAFD budgeted in the 2021 budget	40%	99%
EBITDA– Equal or Higher than the EBITDA budgeted in the 2021 budget	15%	99%
Close accretive acquisitions for the Company	20%	120%
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%	116%
Implement the succession plan	15%	100%

(*) Cash Available for Distribution refers to the cash distributions received by the Company from its subsidiaries, minus cash expenses of the Company, including debt service and general and administrative expenses.

In 2020, most of the objectives defined for the CEO’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 was paid in 2021.

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The CEO’s maximum potential bonus could be 120% of such bonus, approximately $1,150 thousand (approximately €1,020 thousand). No element of the CEO’s annual bonus is deferred.

Deferred Restricted Shares Units (“DRSU”) Plan

In 2021 the Board of Directors established a DRSU Plan for non-executive directors to promote a greater alignment of interests between directors and shareholders, which was approved at the Annual General Meeting held in May 2021. The plan provides 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 DRSU Plan, the Company shall determine, and the directors shall agree, the percentage of their fees, starting on May 31, 2021, that shall be irrevocably substituted for the grant of Restricted Stock Units.

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 an ordinary share at the time of the grant. 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.

The following table sets out the total compensation received by independent, non-executive directors via a mix of cash and DRSUs in 2021:

			Total Remuneration in Cash and/or Deferred Restricted Stock Units (DRSU)
Name	Total Remuneration ($ thousand)		Remuneration in cash ($ thousand)		DRSUs ($ thousand)		Number of DRSUs (#)²
William Aziz		160.0		160.0		-		-
Debora Del Favero¹		160.0		128.5		31.5		878
Brenda Eprile		165.0		165.0		-		-
Michael Forsayeth¹		150.0		100.8		49.2		1,372
Michael Woollcombe¹		225.0		77.5		147.5		4,117
Total		860.0		631.9		228.1		6,367

Notes:

(1)

Following the Annual General Meeting held in May 2021, the Company determined, and Ms. Del Favero, Mr. Forsayeth, and Mr. Woollcombe agreed that, 30%, 50% and 100% respectively of their annual fee payable to the director by the Company for the period starting on May 31, 2021 shall be irrevocably substituted for the grant of Restricted Stock Units.

(2)	The number of DRSUs is determined by dividing the amount of the annual compensation to be received in DRSUs by the market value of an ordinary shares at the time of grant.

Remuneration of the Chief Executive Officer

Details for Mr. Seage, who serves in the role of the CEO, are set out in the Compensation of the Board of Directors and CEO section above.

In 2021, he accrued $1,056.3 thousand as a bonus payment in accordance with his service agreement, payable in 2022. In 2020, Mr. Seage accrued $996.4 thousand in accordance with his service agreement, which was paid in 2021. The CEO’s bonus is approved in euros and converted to U.S. dollars for reporting purposes at the average exchange rate of each year. The increase is due in part to the fluctuation of the euro-Dollar exchange rate.

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LTIP		Number of Restricted Stock Units				Number of Share Options				FaceValue ($ thousand)			Performance Criteria
2021			25,716				74,843			$	1,302		RSU: 5% minimum Total Shareholder Return Performance Stock Unit Share Options: Time-Based Vesting

In 2021, under the LTIP, 25,716 Restricted Stock Units were awarded to the CEO, which will vest on the third anniversary of the grant date. In addition, 74,843 stock options were awarded, which vest one third per year, starting on the first anniversary of the grant date.

If the total shareholder return (“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 each type of interest awarded and the basis on which the award is made is provided under the section “—Remuneration Policy section below” of this annual report.

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 2021 compared with the TSR 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.

TSR is calculated in U.S. dollars.

The table below shows the total remuneration of the CEO, his bonus and his long-term incentive awards expressed as a percentage of the maximum he is likely to be awarded.

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Year				Bonus					LTIP awards⁽³⁾
	(In thousands of U.S. Dollars)
	Total Pay⁽¹⁾			Percentage of target			Amount of Bonus⁽²⁾		Percentage of maximum			Value
2021		3,752.7			105.0	%		1,056.3		100	%		1,879.8
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	⁽⁴⁾		-			-		-			-
2014		174.1			-			-		-			-

(1)

The CEO’s compensation is approved in euros. It has been converted to U.S. dollars for reporting purposes at the average exchange rate of each year. The total pay received by the CEO in thousands of euros was €3,147.6 in 2021, €2,222.2 in 2020, €1,505.5 in 2019, €2,170.3 in 2018, €1,418.1 in 2017, €1,329.1 in 2016, €1,440.9 in 2015, and €130.9 in 2014.

(2)	Amount of bonus accrued by the Company at year-end and paid the next year. For example: In 2020, the Company accrued $996.4 thousand of the bonus paid to the CEO in 2021.

(3)	Long-Term Incentive Awards includes LTIP and One-Off Plan vested in the year

(4)	Includes a €1,189.5 thousand (approximately $1,319.6 thousand) termination payment received by Mr. Garoz after leaving the Company on November 25, 2015.

The CEO 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 from late November 2015. Meanwhile, Mr. Garoz held that position between May and November 2015, when Santiago Seage left the Company.

Director’s, Chief Executive Officer’s and Employee’s Pay

The table below sets out the percentage change between 2020 and 2021 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 Company’s group as a whole, excluding the Chief Executive Officer.

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2021 (% Change from 2020 to 2021)

2020 (% Change from 2019 to 2020)

Name

Salary

Bonus

Long-Term

Incentive Awards⁽¹⁾

Salary

Bonus

Long-Term

Incentive Awards⁽¹⁾

Independent, non-executive directors

William Aziz⁽²⁾

n/a

Debora Del Favero⁽²⁾

n/a

Brenda Eprile⁽²⁾

n/a

Michael Forsayeth⁽²⁾

n/a

Michael Woollcombe⁽²⁾

n/a

Andrea Brentan⁽³⁾

n/a

Robert Dove⁽³⁾

n/a

Francisco J. Martinez⁽³⁾

n/a

Jackson Robinson⁽³⁾

n/a

Daniel Villalba⁽³⁾

n/a

Executive director

Santiago Seage (CEO)

%⁵

144

%⁷

%⁽⁵⁾

n/a

⁽⁶⁾

Employees (excluding CEO)⁽⁴⁾

163

%⁷

n/a

⁽⁶⁾

Notes:

All directors served only part of 2020, except for Santiago Seage.

Only directors who received remuneration are included in the table above.

None of the non-executive directors received any bonus, long-term incentive awards, pension entitlement and/or taxable benefits in 2021 or 2020.

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

(2)	Mr. Aziz, Mrs. Del Favero, Mrs. Eprile, Mr. Forsayeth and Mr. Woollcombe joined the Board of Directors on May 5, 2020 as independent non-executive Directors.

(3)

Mr. Villalba, Mr. Dove, Mr. Martinez and Mr. 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 was calculated on a full-time equivalent basis for 2020, hence based on their total remuneration received in 2019 compared to their 2020 entitled compensation as shown in the Compensation of the Board of Directors and CEO section above. Mr. Andrea Brentan was a director until May 5, 2020.

(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 2021 and 2020. 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.

(5)

The Compensation Committee approved a (i) fixed remuneration of €690 thousand ($817 thousand) for the CEO for 2021 compared to €663 thousand ($757 thousand) for 2020, representing a 4% increase in euros on a year-to-year basis, and (ii) variable remuneration of €793 thousand ($1,056 thousand) for 2021 compared to €873 thousand ($996 thousand) for 2020, representing a 2% increase in euros on a year-to-year basis.

(6)

The Compensation Committee approved a (i) fixed remuneration of €663 thousand ($757 thousand) for the CEO 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.

(7)

In 2021, the long-term incentive awards increase for the CEO and the rest of the employees is driven by the (i) vesting of one-third of his share options awarded in 2020 under the LTIP, and (ii) increase of Atlantica’s share price that resulted in higher LTIP and One-off plan amounts at vesting date.

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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 2021	Amount in 2020	Difference
Spend on pay for all employees^(*)	78.8	54.5	24.3
Total remuneration of directors	4.6	3.4	1.2
Total Remuneration of employees and directors	83.4	57.9	25.5
Dividends paid	190.4	168.8	21.6

The Company has not made any share repurchases during 2021 or 2020.

The average number of employees in 2021 in Atlantica was 655 employees, compared to 441 employees in 2020. The $24.3 million increase in spend on pay and the increase in the average number of employees is mostly due to the investments closed during 2021. The increase in total remuneration of directors is mainly due to the vesting of one-third of the CEO’s share options awarded in 2020 and the increase of Atlantica’s share price that resulted in higher LTIP and One-off plan amounts at vesting date.

Termination Payments (Audited)

No termination payments were made to the CEO or any other director in 2021 nor 2020. The policy for termination payments is detailed under the section “—Policy on payments for loss of office” of this report”.

Statement of Implementation of Policy in 2021

The targets for bonuses are detailed under the section “—Remuneration Policy” of this annual report. The current policy was approved at our 2021 Annual General Meeting, held in May 2021. The approved Remuneration Policy is set out below. There have been no changes to this approved version.

For 2022, the bonus measures for the remuneration of the CEO, will focus on six areas: financial targets, value creating growth/investments, health and safety, management of relationships with key shareholders and partners, executive talent development and disclosure best standards.

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 2022 the bonus objectives are:

	Percentage weight
CAFD (cash available for distribution) – Equal or higher than the CAFD budgeted in the 2022 budget	35%
EBITDA– Equal or Higher than the EBITDA budgeted in the 2022 budget	15%
Close sustainable value accretive investments	15%
Achieve health and safety targets – (Frequency with Leave / Lost Time Index below 3.9 and General frequency index below 10.1) based on reliable targets and consistent measure metrics	10%
Manage relationships with key shareholders and partners	10%
Continued executive talent development	10%
Disclosure best standards	5%

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Remuneration Policy

The current policy was approved at our 2021 Annual General Meeting, held on May 2021. The approved Remuneration Policy is set out below. There have been no changes to this approved version.

Non-Executive Directors:

For non-executive directors, independent and non-independent directors, the Company’s policy is to compensate via cash or DRSUs 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.

In 2021, the Board of Directors established a DRSU Plan for non-executive directors which was approved by the shareholders’ meeting. See “—Compensation of the Board of Directors and CEO— Deferred Restricted Shares Units (“DRSU”) Plan” of this report for a description of the plan.

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:

The policy for executive directors, only applicable to the CEO 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 $910 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.			Not applicable. No retention or clawback.
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.	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.
Long Term Incentive Awards		Align executive directors and shareholders interests.	Special one-off plan in 2019 for 50% of 2019 salary + bonus.	Share units. Clawback policy.

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CAFD, EBITDA and TSR have been selected as key parameters to measure the company’s performance due to their importance for our shareholders. These measures are considered standard indicators of financial performance in our sector.

Clawback Policy

In 2021, the Company implemented 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 concludes 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.

Long-Term Incentive Awards

The purpose of the 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 LTIP 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 CEO.

In addition, the management has discretion to grant additional LTIPs to a certain group of employees and decide the value up to the 50% of the participant´s total annual compensation for the year closed before the date upon which an Award is granted.

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 CEO, would be 70% of the same previous year total annual compensation at the grant date. The award will be granted in Restricted Stock Units.

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Main Terms of the LTIP:

	Restricted Stock Units
	Executives who are not Directors	Executives who are Directors
Nature	Conditions shall be based on: - Continuing employment (or other service relationship) for 33% of the award and - Continuing employment and achievement of a minimum 5% average annual TSR for 67% of the award.	Conditions shall be based on continuing employment (or other service relationship) and achievement of a minimum 5% average annual TSR.
Exercisability and Vesting Period	33% of the shares will vest on the third anniversary of the grant date and 67% of 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 for the 67% portion will lapse on the vesting date. The Company will decide at vesting if cash or shares are given as payment.	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.	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.

Effect on Termination of Employment

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.

Change of Control

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.

Delisting

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.

One-Off Plan

There is a one-off plan in-place that grants Restricted Stock Units to certain members of the management and certain members of middle management , consisting of approximately 25 managers including the CEO. 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.

Pension

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 company implemented the clawback provision in 2021.

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Chief Executive Officer Remuneration Policy

The Compensation Committee approved a fixed remuneration of €690 thousand ($785 thousand converted to U.S. dollars at the December 31, 2021 exchange rate, which is 1.137 $/€). In 2021, the CEO’s fixed remuneration was also €690 thousand.

Total remuneration of the only executive director for a minimum, target and maximum performance in 2022 is presented in the chart below.

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 RSU and assuming no value for the options vesting in the year.
Target:	Fixed remuneration, plus half of target annual bonus and the LTIP and one-off plans vesting in 2022 at face value, using share price at grant date for units and option value at grant date for options, not including dividends, and assuming that the minimum annual TSR of at least a 5% yearly average over the 3-year period is met for the units.
Maximum:	Fixed remuneration, plus maximum annual bonus and LTIP and one-off plans vesting in 2022 at face value, using share price at grant date for units and option value at grant date for options not including dividends, and assuming that the minimum annual TSR of at least a 5% yearly average over the 3-year period is met for the units.

In addition, if we assume a 50% appreciation of the share price with respect to the grant date, maximum remuneration for 2022 including vesting long-term awards would be approximately $5,058 thousand.

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.

The CEO’s 2022 bonus objectives are disclosed under the section “—Remuneration Policy” of this annual report.”

Approach to Recruitment

The remuneration policy reflects the composition of the remuneration package for the appointment of new executive and non-executive directors. We expect to offer a competitive fixed remuneration, an annual bonus (for executive directors) not exceeding 200% of the fixed remuneration and participation in the LTIP. Whenever needed, the Company can contract an external advisor to hire key personnel.

Nominee directors do not receive any compensation from the Company.

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Policy on Payments for Loss of Office

The Company has an agreement in-place with certain executives with strategic and key responsibilities in the Company (“Key Managers”), including the CEO, to protect the Company's know-how and to ensure continuity in terms of attainment of business objectives, the policy approved by our shareholders at the 2019 Annual General Meeting, introduced certain termination payments to key executives, including the CEO.

No payments would be made to Key Managers for dismissal for breach of contract, breach of fiduciary duties or gross misconduct, determined (in the event of a dispute) by a court of competent jurisdiction to reach a final determination.

The Company agreed with certain executives with strategic and key responsibilities in the Company (“Key Managers”), including the Chief Executive Officer, the Company would make payments for loss of office or employment in addition to the severance payment under the prevailing labour and legal conditions in their contracts or countries where they are employed if they should leave (by loss of office or employment) the Company within 2 years of a change in control. The payment would represent six months of remuneration and will be adjusted to ensure that total payment including severance payment required under prevailing laws represent at least 12 months of remuneration (including salary, benefits, long term incentive plans and variable pay), but never more than 24 months of remuneration, unless required by local law.

A change of control means that a third party or coordinated parties (i) acquire directly or indirectly by any means a number of shares in the Company which (together with the shares that such party may already hold in the Company) amount to more than 50% of the share capital of the Company; or (ii) appoint or have the right to appoint at least half of the members of the Board of Directors of the Company.

The “Effect on Termination of Employment” section includes additional disclosure related to termination payments.

Consideration of Employee Conditions Elsewhere

For the management team and key personnel, our policy is to use two external consultants to estimate market conditions for roles of a similar level of managerial responsibilities and complexity in terms of fixed and variable remuneration and, as a general rule, based on a performance appraisal, set target remuneration within that market practice.

The annual variable remuneration payment is calculated with reference to the achievement of a number of specific measurable targets defined in the previous year. Each specific target is measured on a performance scale of 0%-120%.

For the rest of its employees, the Company establishes predefined remuneration ranges for different positions and reviews each individual remuneration depending on performance appraisal within two ranges without employee consultation.

The remuneration of all employees, including the members of the management team, may be adjusted periodically in the framework of the annual salary review process which is carried out for all employees.

Overall, we expect that, following the implementation of our policies, remunerations of the Company’s employees will increase in line with the market with the exception of individuals that have recently been promoted or whose remuneration is above market conditions.

Statement of Consideration of Shareholder Views

There are no comments in respect of directors’ remuneration expressed to the Company by shareholders. The next Annual General Meeting is expected to be held in May 2022.

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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 chair of the Board and the chair of each committee receive additional fees. DRSUs: the Company and the Directors shall agree the percentage of their fees that shall be paid in DRSUs. The number of DRSUs credited is determined using the market value of an ordinary share at the time of the grant. Upon a participant ceasing to be a member of the Board 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, or such number of ordinary shares equal to the vested DRSUs, from the grant date until the vesting date. Minimum share ownership: 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.	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.

Non-independent, non-executive directors are entitled to the same compensation as independent non-executive directors.

In 2021, the Board of Directors adopted minimum share ownership guidelines for directors receiving remuneration from the Company (see the Directors’ Shareholdings section). Within a period of five years, non-executive directors receiving remuneration from the Company should have a minimum share ownership in the Company of 3 times their annual compensation.

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In addition, starting in 2021, the directors may elect to receive compensation via a mix of cash and DRSUs. The DRSUs shall vest upon the date on which the director ceases to be a member of the Board due to a voluntary or involuntary separation from service. The director shall not have any rights of a shareholder unless and until the DRSUs vest and are settled by the issuance of shares (see further detail in the “— Current remuneration policy” section above).

Directors and Key Management Compensation for 2021

$ thousand	2021		2020
Short-term employee benefits		5,098.4		4,792.5
LTIP Awards		2,140.2		496.5
One-off Awards		1,231.5		852.6
Post-employment benefits		-		-
Other long-term benefits		-		-
Termination benefits		-		-
Share-based payment		-		-
Total		8,470.1		6,141.6

The table above includes compensation for the Directors, CEO, 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” and “One-off Awards” include share options and share units, respectively, vested in 2021. The vested options and share units 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, 2021 and by each of our current directors and executive officers, as well as their connected persons, in relation to any compensation paid and/or benefits granted by the Company.

Non-independent, non-executive directors are not required to comply with minimum share ownership requirements as they do not receive remuneration from the Company.

Name⁽¹⁾	Shares		Deferred Restricted Share Units		Share Units⁽²⁾		Investment Value $ in thousands⁽³⁾		Minimum Share Ownership Requirements	Compliance with Policy⁽⁴⁾
William Aziz		2,500		-		-		89	3 times annual compensation	On track
Debora Del Favero		-		878		-		31	3 times annual compensation	On track
Brenda Eprile		5,500		-		-		197	3 times annual compensation	On track
Michael Forsayeth		2,500		1,372		-		138	3 times annual compensation	On track
Santiago Seage		55,666		-		120,880		6,313	6 times fixed compensation	✓
George Trisic		1,000		-		-		-	Non-applicable	Non-applicable
Michael Woollcombe		5,000		4,117		-		326	3 times annual compensation	On track

Notes:

(1)	Mr. Banskota, non-independent, non-executive director, has no shares and is not required to comply with minimum share ownership requirements.

(2)	Non-vested Share Units as of December 31, 2021. LTIP share units subject to 5% minimum Total Shareholder Return Performance Stock Unit. As of December 31, 2021, the CEO has no share units vested and not exercised.

(3)	Assuming a share price of $35.76 as of December 31, 2021.

(4)	5-year window from May 2021 to comply with this policy.

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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 less, as decided by the Board. In December 2020, the Board decided to establish a 1-year 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 Liberty GES 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 CEO and other members of senior management.

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.

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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.

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.

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Employees

The following table shows the number of employees as of December 31, 2021, 2020 and 2019, on a consolidated basis:

	Year ended December 31,
Geography	2021		2020		2019
North America		308		243		229
South America		68		51		43
EMEA		166		55		50
Corporate		115		107		103
Total		658		456		425

The increase in the number of employees is mainly due to investments closed during 2021.

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:

-	Non-executive directors receiving remuneration from the Company: 3 times their annual compensation;

-	1: 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.

The Directors not receiving remuneration from the Company are not required to comply with minimum share ownership requirements.

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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 112,451,438 ordinary shares outstanding as of the date of this annual report.

Name	Ordinary Shares Beneficially Owned		Deferred Restricted Share Units		Shares Units		Percentage
Directors and Officers
Santiago Seage		55,666				120,880		-
William Aziz		2,500						-
Brenda Eprile		5,500						-
Michael Forsayeth		2,500		1,372				-
Michael Woollcombe		5,000		4,117				-
Debora Del Favero		-		878				-

5% Beneficial Owners
Algonquin (AY Holdco) B.V. ⁽¹⁾		48,962,925						43.5	%
Morgan Stanley ⁽²⁾		5,677,200						5.1	%

(1)

This information is based solely on the Schedule 13D filed on August 4, 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 Liberty (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, 2022 by Morgan Stanley, corporation incorporated under the laws of Delaware. The registered address of Morgan Stanley is 1585 Broadway New York, NY 10036

As of December 31, 2021, the CEO holds 120,880 units convertible into shares in the future and 184,524 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, 112,451,438 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 105,046,131 ordinary shares representing approximately 93.4% 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

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 Liberty GES 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 Liberty GES, 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 Liberty GES’, Algonquin’s or Abengoa’s interest in the transaction. Our Related Party Transactions Policy is available on our website at www.atlantica.com.

Arrangements for Change in Control of the Company

On May 9, 2019, Algonquin, Liberty GES and the Company entered into the Enhanced Cooperation Agreement, and on May 17, 2019, 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, which were fully subscribed and paid by Algonquin. 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. Additionally, Algonquin 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. On August 3, 2021, we established an “at-the-market program” (the “ATM”) and on the same date we entered into the ATM Plan Letter Agreement with Algonquin, pursuant to which we will offer Algonquin the right but not the obligation, on a quarterly basis, to purchase a number of ordinary shares to maintain its percentage interest in Atlantica (see —ATM Plan Letter Agreement below). As of the date of this report Algonquin is the beneficial owner of 48,962,925 ordinary shares, representing 43.5% of the issued and outstanding ordinary shares.

Agreements with Current Shareholders

We entered into the ROFO Agreements with Liberty GES and Algonquin, respectively. In addition, Algonquin, Liberty GES and the Company entered into the Enhanced Cooperation Agreement, and Algonquin and the Company entered into a subscription agreement.

ROFO agreements

Pursuant to the ROFO Agreements, Algonquin and Liberty GES granted us a right of first offer on any proposed sale, transfer or other disposition of the assets described thereunder, subject to the conditions and procedures set out in such agreement. Specifically, the Algonquin ROFO Agreements is applicable with respect to any assets located outside of the United States or Canada.

If either Algonquin or Liberty GES transfers interests in any asset under the ROFO Agreements, then either Algonquin or Liberty GES must require such transferee to acquire any asset under the ROFO Agreements subject to our right of first offer except under certain circumstances. The ROFO Agreements have each an initial term of ten years.

Under the ROFO Agreement, Algonquin and Liberty GES are 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 ROFO Agreements, Algonquin and Liberty GES may have equity partners with rights regulating divestitures by either of them of their stake such as drag-along and tag-along clauses, and rights of first refusal, among others. We will consider and take into account all the clauses thereunder when deciding whether to present an offer.

Any material transaction between Algonquin or Liberty GES and us (including the proposed acquisition of any asset under the ROFO Agreements) 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—V. Risks Related to Our Growth Strategy— Our ability to grow organically is limited to some assets which have inflation indexation mechanisms in their revenues, to our transmission lines and to some renewable assets. We may not be able to deliver organic growth.”

Furthermore, with respect to the Liberty GES ROFO Agreement, Liberty GES 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 Liberty GES current or future portfolio. Pursuant to the terms of such agreement, Liberty GES may sell equity in these assets to third parties without being subject to the Liberty GES 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 PV plant in Colombia for a total equity investment of approximately $23.5 million. The acquisition closed in November 2021.

Additionally, in December 2020, we agreed to potentially co-invest with Algonquin in two additional solar projects in Colombia with a combined capacity of approximately 30 MW. In July 2021 we acquired from Algonquin the two solar projects which are currently under construction.

ATM Plan Letter Agreement

On August 3, 2021, we established an ATM program and entered into the Distribution Agreement with J.P. Morgan Securities LLC, as sales agent. On that same date, we entered into an agreement with Algonquin, pursuant to which we will offer Algonquin the right but not the obligation, on a quarterly basis, to purchase a number of ordinary shares to maintain its percentage interest in Atlantica at the average price of the shares sold under the Distribution Agreement in the previous quarter, adjusted for any dividends, distributions, reorganizations or business combinations or similar transactions as if the portion of such shares equivalent to the portion of the shares issued under the ATM prior to the record date had also been issued to Algonquin prior to the record date with respect to such event. In the event that Algonquin exercises such right, subject to certain conditions further described in the ATM Plan Letter Agreement, including that a material adverse effect in relation to the Company shall not have occurred, we and Algonquin will enter into a subscription agreement with a settlement date no earlier than three business days and no later than one hundred and eighty days from Algonquin’s notice that it is subscribing for the ordinary shares.

Algonquin Shareholders Agreement

We entered into a Shareholders Agreement with Algonquin and Liberty GES. The Shareholders Agreement, among other things, sets forth certain corporate governance matters and 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, Liberty GES or Algonquin will have the right to appoint to our board the maximum number of directors that corresponds to Liberty GES’ 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.

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One of the directors appointed by Liberty GES 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 Liberty GES and Algonquin have the right to appoint a director and no such director is then serving on our Board of Directors, Liberty GES 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 Liberty GES 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, 2021, our dividend payout objective was 80%. This objective can be modified by our Board of Directors in the future.

Pre-emption rights

Liberty GES 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 Liberty GES 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 Liberty GES ROFO Agreement. If we issue ordinary shares for any other purpose, Liberty GES and Algonquin may subscribe in cash for ordinary shares in the amount pro rata to such Liberty GES’ and Algonquin’s aggregate holding of voting rights.

In addition, if Liberty GES 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 Liberty GES’ 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 Liberty GES and Algonquin holding in the aggregate more than 48.5% of the total voting rights or otherwise acquire control over us.

Also, Liberty GES and Algonquin will not be in breach of the standstill restriction if the shareholding of Liberty GES and Algonquin has increased in connection with our action to reduce the number of our outstanding shares.

Termination

Among others, the Shareholders Agreement will terminate if, among others, Liberty GES 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.

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.

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Code of Conduct

We have adopted a code of conduct applicable to 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 2019:

Declared	Record	Payable	Amount ($) per share
-February 25, 2022	March 14, 2022	March 25, 2022	0.44
November 9, 2021	November 30, 2021	December 15, 2021	0.435
July 30, 2021	August 31, 2021	September 15, 2021	0.43
May 4, 2021	May 31, 2021	June 15, 2021	0.43
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

We declared our first quarterly dividend in November 2014 and paid it on December 15, 2014. Recently, on February 25, 2022, our Board of Directors approved a dividend of $0.44 per share corresponding to the fourth quarter of 2021, which is expected to be paid on March 25, 2022.

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 “Item 4.B—Business Overview—Our Operations—Project Level Financing” under the individual project descriptions. 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.

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•

Additionally, indebtedness we have incurred under the Green Senior Notes, 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— Operating and Financial Review and Prospects—Liquidity and Capital Resources—Corporate debt agreements.”

•

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, repowering, hybridization with other technologies, and expansion of our current assets and through investments in development 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.

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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.”

B.	Plan of Distribution

Not applicable.

Markets

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

D.	Selling Shareholders

Not applicable.

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— Operating and Financial Review and Prospects—Liquidity and Capital Resources—Corporate debt agreements”

D.	Exchange Controls

See “Item 5.A—Operating and Financial Review and Prospects—Operating Results—Factors Affecting the Comparability of Our Results of Operations—Regulation.”

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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, save where expressly stated otherwise 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 United Kingdom 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.

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 U.K. tax in respect of any dividends. There are certain exceptions from U.K. tax in respect of dividends on shares held in connection with a trade carried on in the United Kingdom for trades conducted in the United Kingdom through independent agents, such as some brokers and investment managers.

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.

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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. The discussion under the headings below applies to transactions undertaken by any holder of our shares.

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 (or, in certain circumstances and if it is higher, the market value of our shares to be transferred in accordance with the relevant agreement). 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 (or, in certain circumstances and if it is higher, the market value of our shares to be transferred by the relevant instrument) 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 published guidance stating 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 HMRC’s position following the transition period which expired on December 31, 2020 after the withdrawal of the United Kingdom from the EU.

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. In certain circumstances, there may be no charge to stamp duty or SDRT, and holders of our shares should accordingly seek their own advice before paying or accepting such charge.

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.

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Any liability for stamp duty or SDRT in respect of any 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 generally applicable to the ownership and disposition of shares by U.S. Holders (as defined below). Unless otherwise noted, this summary addresses only U.S. Holders that hold shares as capital assets (generally, property held for investment) for U.S. federal income tax purposes. This summary is based upon the U.S. Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations promulgated thereunder (“Regulations”), judicial decisions, administrative pronouncements, and other relevant applicable authorities, all as of the date hereof and all of which are subject to change or differing interpretations, possibly with retroactive effect.

As used herein, the term “U.S. Holder” means a beneficial owner of shares that is, for U.S. federal income tax purposes:

•

an individual who is a citizen or resident of the United States;

•

a corporation (or other entity subject to tax as a corporation for U.S. federal income tax purposes) created in or organized under the laws of the United States or any political subdivision thereof;

•

an estate the income of which is subject to U.S. federal income taxation regardless of its source; or

•

a trust (i) 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 (ii) the trust has validly elected to be treated as a domestic trust for U.S. federal income tax purposes;

This summary does not address all aspects of U.S. federal income taxation that may be relevant to a particular investor in light of that holder’s particular circumstances or that may be relevant to certain types of holders subject to special treatment under U.S. federal income tax law, such as: insurance companies; tax-exempt organizations; banks and other financial institutions; pension plans; cooperatives; real estate investment trusts; dealers in securities or currencies; traders that elect to use a mark-to-market method of accounting; certain former U.S. citizens or long-term residents; persons holding shares as part of a straddle, hedge, conversion, constructive sale or other integrated transaction for U.S. federal income tax purposes; persons who acquire shares pursuant to any employee share option or otherwise as compensation; persons holding shares through an individual retirement account or other tax-deferred account; persons who actually or constructively own 10% or more of our stock (by vote or value); persons whose functional currency is not the U.S. dollar; partnerships or other entities or arrangements subject to tax as partnerships for U.S. federal income tax purposes or persons holding shares through such entities; 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 a partnership (or other entity or arrangement subject to tax as a partnership for U.S. federal income tax purposes) is a beneficial owner of shares, the U.S. federal income tax treatment of a partner in such partnership will generally depend upon the status of the partner and the activities of the partnership. A partnership for U.S. federal income tax purposes that holds shares and its partners are urged to consult their tax advisors regarding an investment in the shares.

In addition, this summary does not address any U.S. state or local or non-U.S. tax considerations or any U.S. federal estate, gift, or alternative minimum tax considerations, or the Medicare tax on certain net investment income.

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Taxation of distributions on the shares

The gross amount of any distributions received by a U.S. Holder on shares will generally be subject to tax as 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), and will be includible in the gross income of U.S. Holders on the day actually or constructively received. Such dividends will not be eligible for the dividends received deduction generally allowed to U.S. corporations under the Code. The following discussion assumes that any dividends will be paid in U.S. dollars. 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 generally 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 its shares, such excess will generally be subject to tax as capital gain.

Individuals and other non-corporate U.S. Holders of shares may be eligible for reduced rates of taxation if the dividends are “qualified dividend income.” Distributions received by a U.S. Holder on shares will generally be qualified dividend income if: (i) the shares on which the distribution are paid are readily tradable on an established securities market in the United States (such as NASDAQ Global Select Market, where our shares are listed), (ii) certain holding period requirements are satisfied, and (iii) Atlantica Sustainable Infrastructure is not classified as a PFIC for the taxable year in which the dividend is paid or the preceding taxable year. 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. There can be no assurance, moreover, that the shares will be considered readily tradable on an established securities market in the current year or in future years. Individuals and other non-corporate U.S. Holders should consult their tax advisors to determine whether they are subject to any special rules that limit their ability to be taxed at these favorable rates.

Dividends on the shares will generally be treated as income from sources outside the United States and will generally constitute passive category income for U.S. foreign tax credit purposes. Depending on the individual facts and circumstances, a U.S. Holder may be eligible, subject to a number of complex limitations, to claim a foreign tax credit not in excess of any applicable treaty rate in respect of any foreign withholding taxes imposed on dividends received on our common shares. A U.S. Holder who does not elect to claim a foreign tax credit for foreign taxes withheld may instead claim a deduction, for U.S. federal income tax purposes, in respect of such withholding, but only for a year in which such U.S. Holder elects to do so for all creditable foreign income taxes. The rules governing the U.S. foreign tax credit are complex and the application thereof depends in large part on the U.S. Holder’s individual facts and circumstances. Accordingly, U.S. Holders should consult their tax advisors regarding the availability of the U.S. foreign tax credit in their particular circumstances.

Taxation upon sale or other disposition of shares

A U.S. Holder will generally recognize U.S. source capital gain or loss on the sale or other disposition of the shares, which will generally be long-term capital gain or loss if the U.S. Holder’s holding period for the shares is more than one year at the time of disposition. The amount of the U.S. Holder’s gain or loss will generally be equal to the difference between the amount realized on the disposition and the U.S. Holder’s adjusted tax basis in the shares. Individuals and certain other non-corporate U.S. Holders will generally be subject to U.S. federal income tax on net long-term capital gains at a lower rate than the rate applicable to ordinary income. The deductibility of a capital loss may be subject to limitations.

Passive foreign investment company rules

A non-U.S. corporation, such as our company, will be classified as a PFIC for U.S. federal income tax purposes for any taxable year, if either (i) 75% or more of its gross income for such year consists of certain types of “passive” income or (ii) 50% or more of the value of its assets (determined on the basis of a quarterly average) during such year produce or are held for the production of passive income. Passive income generally includes dividends, interest, royalties, rents, annuities, net gains from the sale or exchange of property producing such income and net foreign currency gains. For this purpose, cash is categorized as a passive asset and the company’s unbooked intangibles associated with active business activity are taken into account as a non-passive asset. We will be treated as owning our proportionate share of the assets and earning our proportionate share of the income of any other corporation in which we own, directly, indirectly or constructively, 25% or more (by value) of the stock.

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Based on our income and assets, and the value of our shares, we do not believe that we were a PFIC, for U.S. federal income tax purposes, for the taxable year ended December 31, 2021, and do not anticipate becoming a PFIC for the current taxable year or for the foreseeable future. Nevertheless, because PFIC status is a factual determination made annually after the close of each taxable year on the basis of the composition of our income and assets, there can be no assurance that we will not be a PFIC for the current taxable year or any future taxable year. Under circumstances where revenues from activities that produce passive income significantly increase relative to our revenues from activities that produce non-passive income, or where we determine not to deploy significant amounts of cash, our risk of becoming classified as a PFIC may substantially increase. In addition, because we have valued our goodwill based on the market value of our shares, a decrease in the market value of our shares may also result in our becoming a PFIC.

If we are a PFIC for any taxable year during which a U.S. Holder holds our shares, such holder will be subject to special tax rules with respect to any “excess distribution” that such holder receives on the shares and any gain such holder realizes from a sale or other disposition (including a pledge) of the shares, unless such holder makes a “mark-to-market” election as discussed below. Distributions received by a U.S. Holder in a taxable year that are greater than 125% of the average annual distributions such holder received during the shorter of the three preceding taxable years or such holder’s holding period for the shares will be treated as an excess distribution. Under these special tax rules:

•

the excess distribution or gain will be allocated ratably over the U.S. Holder’s holding period for the shares;

•

amounts allocated to the current taxable year and any taxable years in the U.S. Holder’s holding period prior to the first taxable year in which we are classified as a PFIC (a “pre-PFIC year”) will be subject to tax as ordinary income; and

•

amounts allocated to each prior taxable year, other than the current taxable year or a pre-PFIC year, will be subject to tax at the highest tax rate in effect applicable to the U.S. Holder for that year, and such amounts will be increased by an additional tax equal to interest on the resulting tax deemed deferred with respect to such years.

If we are a PFIC for any taxable year during which a U.S. Holder holds shares and any of our non-U.S. affiliated entities are also PFICs, such holder will be treated as owning a proportionate amount (by value) of the shares of each such non-U.S. affiliate classified as a PFIC for purposes of the application of these rules.

Alternatively, a U.S. Holder of “marketable stock” (as defined below) in a PFIC may make a mark-to-market election for such stock of a PFIC to elect out of the tax treatment discussed in the second preceding paragraph. If a U.S. Holder makes a valid mark-to-market election for the shares, the U.S. Holder will include in income each year an amount equal to the excess, if any, of the fair market value of the shares as of the close of such holder’s taxable year over such holder’s adjusted basis in such shares. The U.S. Holder is allowed a deduction for the excess, if any, of such holder’s adjusted basis in the shares over their fair market value as of the close of the taxable year. Deductions are allowable, however, only to the extent of any net mark-to-market gains on the shares included in the U.S. Holder’s income for prior taxable years. Amounts included in the U.S. Holder’s income under a mark-to-market election, as well as gain on the actual sale or other disposition of the shares, are treated as ordinary income. Ordinary loss treatment also applies to the deductible portion of any mark-to-market loss on the shares, as well as to any loss realized on the actual sale or disposition of the shares, to the extent that the amount of such loss does not exceed the net mark-to-market gains previously included in income with respect to such shares. The U.S. Holder’s basis in the shares will be adjusted to reflect any such income or loss amounts. If a U.S. Holder makes such a mark-to-market election, tax rules that apply to distributions by corporations which are not PFICs would apply to distributions by us (except that the lower applicable capital gains rate for qualified dividend income would not apply). If a U.S. Holder makes a valid mark-to-market election, and we subsequently cease to be classified as a PFIC, such U.S. Holder will not be required to take into account the mark-to-market income or loss described above during any period that we are not classified as a PFIC.

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The mark-to-market election is available only for “marketable stock” which is stock that is traded in other than de minimis quantities on at least 15 days during each calendar quarter (“regularly traded”) on a qualified exchange or other market, as defined in applicable Regulations. We expect that the shares will continue to be listed on the NASDAQ Global Select Market, which is a qualified exchange for these purposes, and, consequently, assuming that the shares are regularly traded, if a U.S. Holder holds the shares, it is expected that the mark-to-market election would be available to such holder were we to become a PFIC.

In addition, because, as a technical matter, a mark-to-market election cannot be made for any lower-tier PFICs that we may own, a U.S. Holder may continue to be subject to the PFIC rules with respect to such holder’s indirect interest in any investments held by us that are treated as an equity interest in a PFIC for U.S. federal income tax purposes.

We do not intend to provide information necessary for U.S. Holders to make qualified electing fund elections, which, if available, would result in tax treatment different from the general tax treatment for PFICs described above.

If a U.S. Holder owns the shares during any taxable year that we are a PFIC, such holder must generally file an annual report with the IRS regarding their ownership of shares. U.S. Holders should consult their tax advisors concerning the U.S. federal income tax considerations of holding and disposing of the shares if we are or become a PFIC, including the availability and possibility of making a mark-to-market election.

Foreign financial asset reporting

A U.S. Holder may be required to report information relating to an interest in the shares, generally by filing IRS Form 8938 (Statement of Specified Foreign Financial Assets) with the U.S. Holder’s federal income tax return. A U.S. Holder may also be subject to significant penalties if the U.S. Holder is required to report such information and fails to do so. U.S. Holders should consult their tax advisors regarding information reporting obligations, if any, with respect to ownership and disposition of the shares.

THE PRECEDING DISCUSSION OF U.S. FEDERAL INCOME TAX CONSIDERATIONS IS INTENDED FOR GENERAL INFORMATION ONLY AND DOES NOT CONSTITUTE TAX ADVICE. U.S. HOLDERS SHOULD CONSULT THEIR TAX ADVISORS AS TO THE U.S. FEDERAL, STATE, LOCAL AND NON-U.S. TAX CONSIDERATIONS TO THEM OF THE OWNERSHIP AND DISPOSITION OF THE SHARES IN THEIR PARTICULAR CIRCUMSTANCES.

F.	Dividends and Paying Agent

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.

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I.	Subsidiaries Information

Not applicable.

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 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, with the exception of Calgary, with revenue in Canadian dollars. Our solar power plants in Europe have their revenue and expenses denominated in euros, Kaxu, our solar plant in South Africa, has its revenue and expenses denominated in South African rand and La Sierpe, our solar plant in Colombia, has its revenue and expenses denominated in Colombian pesos. Project financing 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 streams in foreign companies are denominated in the same currency, limiting our risk of foreign exchange differences in our financial results.

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. For example, revenue in euro-denominated companies could decrease when translated to U.S. dollars at the average foreign exchange rate solely due to a decrease in the average foreign exchange rate, in spite of revenue in the original currency being stable. Fluctuations in the value of the South African rand and the Colombian peso with respect to the U.S. dollar may also affect our operating results. Apart from the impact of these translation differences, the exposure of our income statement to fluctuations of foreign currencies is limited, as the financing of projects is typically denominated in the same currency as that of the contracted revenue agreement.

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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, 2021, 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: between 75% and 100% of the notional amount, with hedged maturing until 2038 at an average guaranteed strike interest rates of between 0.00% and 4.87%.

•	Project debt in U.S. dollars: between 75% and 100% of the notional amount, with hedges maturing until 2038 and average strike interest rates of between 0.86% and 5.89%.

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 our hedges, increasing our financial expense up to our contracted fixed interest rate, thus likely resulting in a neutral effect.

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, 2021, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $2.5 million (a loss of $2.9 million in 2020 and a loss of $2.7 million in 2019) and an increase in hedging reserves of $22.4 million ($22.1 million in 2020 and $27.6 million in 2019). 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

The credit rating of Eskom 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 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 is currently BBB from S&P, Ba3 from Moody’s and BB- from Fitch. We have been experiencing delays from Pemex in collections since the second half of 2019 which have been significant in certain quarters.

In 2019, we also 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 $78.0 million in the event the South African Department of Energy does not comply with its obligations as guarantor. We also have a political risk insurance in place for our assets in Algeria up to $38.2 million, including two years dividend coverage. These insurance policies do not cover credit risk.

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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.

D.	American Depositary Shares

Not applicable.

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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, 2021. 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.

(b)	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.

In accordance with guidance issued by the U.S. Securities and Exchange Commission, companies are permitted to exclude acquisitions from their annual assessment of internal control over financial reporting for the first fiscal year in which the acquisition occurred.

Our management’s evaluation of internal control over financial reporting excluded the internal control activities of the businesses acquired in 2021 (Coso, Rioglass, Calgary District Heating, Chile PV2, Italy PV1, PV2 and PV3 and La Sierpe, as described in Note 5 Business Combinations to our, Consolidated Financial Statements) in accordance with the general guidance issued by the Staff of the U.S. Securities and Exchange Commission. These businesses represented 6.0% of consolidated net assets and 13.5% of the Company’s consolidated revenues (6.9% excluding the revenues from Rioglass non-recurrent project) as of and for the year ended December 31, 2021.

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, 2021, 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, 2021, its internal control over financial reporting was effective based on those criteria.

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Our internal control over financial reporting as of December 31, 2021, has been audited by Ernst & Young S.L., an independent registered public accounting firm, as stated in their report which follows below.

(c)	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.

(d)	Changes in Internal Controls over Financial Reporting

There has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

(e)	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. . We will provide any person, free of charge, a copy of our code of ethics upon written request to our registered office.

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 2021:

	EY		Other Auditors		Total
	($ in thousands)
Audit Fees		1,571		289		1,860
Audit-Related Fees		651		-		651
Tax Fees		633		-		633
All Other Fees		-		-		-
Total		2,855		289		3,144

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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

“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 2021 and 2020 related to comfort letters and consents required for capital market transactions of our major shareholder are also included in this category ($272 thousand and $212 thousand in 2021 and 2020 respectively). These fees were re-invoiced and paid by our major shareholder.

“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 some amendments to the 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;

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•

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:

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

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

Tax services;

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 50% 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.

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

Not applicable.

ITEM 16F.

CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

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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.

In addition, as a foreign private issuer and as a UK company, we are not required to and we do not follow the NASDAQ Stock Market Rule 5635(c) as it relates to the approval by the shareholders of the Company prior to the issuance of securities when a stock option or purchase plan is to be established or materially amended or other equity compensation arrangement made or materially amended. As permitted by the UK Companies Act 2006, any material amendment to any of our stock option or other equity compensation arrangement with respect to our Executives may be approved either by the Board of Directors or by the shareholders of the Company.

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.

ITEM 16I.

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

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).
4.2	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).
4.3	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).
4.4	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).
4.5	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).
4.6	Shareholder’s Agreement dated March 5, 2018 among Atlantica Yield, Liberty GES 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).
4.7	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).
4.8	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).
4.9	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).
4.10	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).
4.11	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).
4.12	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).
4.13	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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4.14	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).
4.15	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).
4.16	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).
4.17	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).
4.18	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).
4.19	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).
4.20	Fifth Amendment to Credit and Guaranty Agreement, dated December 3, 2020.
4.21	Sixth Amendment to Credit and Guaranty Agreement, dated March 1, 2021 (incorporated by reference from Exhibit 99.1 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on March 30, 2021 – SEC File No. 001-36487)
4.22	Amendment No. 1 to Note Issuance Facility Agreement, dated March 30, 2021.
4.23	Indenture (including Form of Global Notes) relating to Atlantica Sustainable Infrastructure plc's 4.125% Green Senior Notes due 2028 dated May 18, 2021, by and among Atlantica Sustainable Infrastructure plc, as Issuer, Atlantica Peru S.A., ACT Holding, S.A. de C.V., Atlantica Infraestructura Sostenible, S.L.U., Atlantica Investments Limited, Atlantica Newco Limited, Atlantica North America LLC, as Guarantors, BNY Mellon Corporate Trustee Services Limited, as Trustee, The Bank of New York Mellon, London Branch, as paying agent, and The Bank of New York Mellon SA/NV, Dublin Branch, as registrar and transfer agent (incorporated by reference from Exhibit 4.28 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on May 24, 2021 – SEC File No. 001-36487).
4.24	Distribution Agreement, dated August 3, 2021, between the Company and J.P. Morgan Securities LLC (incorporated by reference from Exhibit 1.1 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2021 – SEC File No. 001-36487).
4.25	ATM Plan Letter Agreement, dated August 3, 2021, between Atlantica Sustainable Infrastructure plc and Algonquin Power & Utilities Corp (incorporated by reference from Exhibit 4.29 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2021 – 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
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document

167

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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

168

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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: February 28, 2022

	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

169

Table of Contents

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

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

Report of Ernst and Young, S.L. (PCAOB ID 1461)	F-1
Consolidated statements of financial position as of December 31, 2021 and 2020	F-3
Consolidated income statements for the years ended December 31, 2021, 2020 and 2019	F-5
Consolidated financial statements of comprehensive income for the years ended December 31, 2021, 2020 and 2019	F-6
Consolidated statements of changes in equity for the years ended December 31, 2021, 2020 and 2019	F-7
Consolidated cash flow statements for the years ended December 31, 2021, 2020 and 2019	F-10
Notes to the annual consolidated financial statements	F-11
Appendix I: Entities included in the Group as subsidiaries as of December 31, 2021 and 2020	F-62
Appendix II: Investments recorded under the equity method as of December 31, 2021 and 2020	F-66
Appendix III-1 and Appendix III-2: Assets subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2021 and 2020	F-68
Appendix IV: Additional Information of Subsidiaries including material Non-controlling interest as of December 31, 2021 and 2020	F-83

			As of December 31,
	Note (1)		2021		2020
Assets
Non-current assets
Contracted concessional assets		6		8,021,568		8,155,418
Investments carried under the equity method		7		294,581		116,614
Other accounts receivable		8		85,801		88,655
Derivative assets		9		10,807		1,099
Financial investments		8		96,608		89,754
Deferred tax assets		18		172,268		152,290

Total non-current assets				8,585,025		8,514,076

Current assets
Inventories				29,694		23,958
Trade receivables		11		227,343		258,087
Credits and other receivables		11		79,800		73,648
Trade and other receivables		11		307,143		331,735
Financial investments		8		207,379		200,084
Cash and cash equivalents		12		622,689		868,501

Total current assets				1,166,905		1,424,278

Total assets				9,751,930		9,938,354

	Share capital		Share premium			Capital reserves			Other reserves			Accumulated currency translation differences			Accumulated deficit			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			(68,315	)		(449,274	)		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	)		(22,509	)		1,682			(42,041	)		(44	)		(42,085	)

Total comprehensive income		-		-			-			(21,214	)		(22,509	)		63,817			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			(90,824	)		(385,457	)		1,508,476			206,380			1,714,856

			For the year ended
	Note ⁽¹⁾		2021			2020			2019
I. Profit/(loss) for the year				(10,918	)		16,874			74,608
Non-monetary adjustments
Depreciation, amortization and impairment charges		6		439,441			408,604			310,755
Financial (income)/expenses		21		359,550			315,151			405,634
Fair value (gains)/losses on derivative financial instruments		21		(16,785	)		15,308			(613	)
Shares of (profits)/losses from associates		7		(12,304	)		(510	)		(7,457	)
Income tax		18		36,220			24,877			30,950
Other non-monetary items				55,809			(43,943	)		(25,800	)

II. Profit/(loss) for the year adjusted by non-monetary items				851,013			736,361			788,077

Changes in working capital
Inventories				5,215			(4,590	)		(1,343	)
Trade and other receivables		11		48,521			(790	)		(71,505	)
Trade payables and other current liabilities		17		(25,782	)		(9,771	)		(36,533	)
Financial investments and other current assets/liabilities				(31,081	)		4,249			(15,602	)

III. Changes in working capital				(3,127	)		(10,902	)		(124,983	)

Income tax received/(paid)				(51,684	)		(16,425	)		(23	)
Interest received				2,519			5,148			10,135
Interest paid				(293,098	)		(275,961	)		(309,625	)

A. Net cash provided by operating activities				505,623			438,221			363,581

Acquisitions of subsidiaries and entities under the equity method		5&7		(362,449	)		2,453			(173,366	)
Investments in contracted concessional assets*		6		(24,682	)		(1,361	)		22,009
Distributions from entities under the equity method		7		34,883			22,246			30,443
Other non-current assets/liabilities				1,093			(29,198	)		2,703

B. Net cash used in investing activities				(351,155	)		(5,860	)		(118,211	)

Proceeds from project debt		15		14,560			603,949			5,860
Proceeds from corporate debt		14		429,014			678,651			352,966
Repayment of project debt		15		(418,265	)		(621,691	)		(282,255	)
Repayment of corporate debt		14		(376,154	)		(502,042	)		(320,815	)
Dividends paid to Company´s shareholders		13		(190,638	)		(168,659	)		(159,002	)
Dividends paid to non-controlling interest		13		(28,134	)		(22,944	)		(29,239	)
Purchase of Liberty´s Interactive's equity interests in Solana		1		-			(266,850	)		-
Non-controlling interest capital contribution				-			-			92,303
Capital increase		13		189,454			162,246			30,000

C. Net cash used in financing activities				(380,163	)		(137,340	)		(310,182	)

Net increase/(decrease) in cash and cash equivalents				(225,695	)		295,021			(64,812	)

Cash and cash equivalents at beginning of the year		12		868,501			562,795			631,542
Translation differences in cash and cash equivalents				(20,117	)		10,685			(3,935	)
Cash and cash equivalents at the end of the year		12		622,689			868,501			562,795

Note 1.- Nature of the business	F-12

Note 2.- Significant accounting policies	F-16

Note 3.- Financial risk management	F-28

Note 4.- Financial information by segment	F-29

Note 5.- Business combinations	F-34

Note 6.- Contracted concessional assets	F-36

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-45

Note 11.- Trade and other receivables	F-46

Note 12.- Cash and cash equivalents	F-46

Note 13.- Equity	F-47

Note 14.- Corporate debt	F-48

Note 15.- Project debt	F-50

Note 16.- Grants and other liabilities	F-53

Note 17.-Trade payables and other current liabilities	F-54

Note 18.- Income tax	F-54

Note 19.- Commitments, third-party guarantees, contingent assets and liabilities	F-57

Note 20.- Employee benefit expenses and other operating income and expenses	F-58

Note 21.- Financial expense, net	F-59

Note 22.- Earnings per share	F-60

Note 23.- Other information	F-61

Appendices⁽¹⁾	F-62

Monterrey	Efficient natural gas &heat	30%	Mexico	USD	142 MW	Not rated	2018	17

ATN ⁽¹⁵⁾	Transmission line	100%	Peru	USD	379 miles	BBB+/Baa1/BBB	2011	19

ATS	Transmission line	100%	Peru	USD	569 miles	BBB+/Baa1/BBB	2014	22

ATN 2	Transmission line	100%	Peru	USD	81 miles	Not rated	2015	11

Quadra 1 & 2	Transmission line	100%	Chile	USD	49 miles/32 miles	Not rated	2014	13/13

Palmucho	Transmission line	100%	Chile	USD	6 miles	BBB/ -- /A-	2007	16

Chile TL3	Transmission line	100%	Chile	USD	50 miles	A/A1/A-	1993	Regulated

Skikda	Water	34.2%⁽⁶⁾	Algeria	USD	3.5 M ft3/day	Not rated	2009	12

Honaine	Water	25.5%⁽⁷⁾	Algeria	USD	7 M ft3/day	Not rated	2012	16

Tenes	Water	51%⁽⁸⁾	Algeria	USD	7 M ft3/day	Not rated	2015	18

	Carrying amount as of December 31, 2021
	Assets		Liabilities
Non-derivative assets and liabilities referenced to LIBOR
Measured at amortized cost
Project debt		-		1,068,501
Total non-derivatives items		-		1,068,501
Derivatives		-		62,571
Total assets and liabilities referenced to LIBOR		-		1,131,072

	Carrying amount as of December 31, 2021
	Notional		Assets		Liabilities		Balance sheet line item(s)	2021 changes in fair value used for calculating hedge ineffectiveness
Cash flow hedge
Interest rate swaps		939,670		-		62,571	Derivative liabilities		30,013
Total cash flow hedges		939,670		-		62,571			30,013

	North America		South America		EMEA		Balance as of December 31, 2021
Assets allocated
Contracted concessional assets		3,355,669		1,231,276		3,434,623		8,021,568
Investments carried under the equity method		253,221		-		41,360		294,581
Current financial investments		135,224		28,155		44,000		207,379
Cash and cash equivalents (project companies)		171,744		74,149		287,655		533,548
Subtotal allocated		3,915,858		1,333,580		3,807,638		9,057,076
Unallocated assets
Other non-current assets								268,876
Other current assets (including cash and cash equivalents at holding company level)								425,978
Subtotal unallocated								694,854
Total assets								9,751,930

	Renewable energy		Efficient natural gas & Heat		Transmission lines		Water		Balance as of December 31, 2021
Assets allocated
Contracted concessional assets		6,533,408		517,247		805,987		164,926		8,021,568
Investments carried under the equity method		240,302		15,358		-		38,921		294,581
Current financial investments		10,761		128,461		27,813		40,344		207,379
Cash and cash equivalents (project companies)		442,213		25,392		44,574		21,369		533,548
Subtotal allocated		7,226,684		686,458		878,374		265,560		9,057,076
Unallocated assets
Other non-current assets										268,876
Other current assets (including cash and cash equivalents at holding company level)										425,978
Subtotal unallocated										694,854
Total assets										9,751,930

	Renewable energy		Efficient natural gas & Heat		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

	Business combinations for the year ended December 31, 2021
	Coso			Other			Total
Contracted concessional assets (Note 6)		383,153			158,927			542,080
Deferred tax asset (Note 18)		-			4,410			4,410
Other non-current assets		11,024			1,943			12,967
Cash & cash equivalents		6,363			14,649			21,012
Other current assets		14,378			46,679			61,057
Non-current Project debt (Note 15)		(248,544	)		(39,808	)		(288,352	)
Current Project debt (Note 15)		(13,415	)		(25,366	)		(38,781	)
Deferred tax liabilities (Note 18)		-			(4,910	)		(4,910	)
Other current and non-current liabilities		(22,959	)		(64,825	)		(87,784	)
Non-controlling interests		-			(8,287	)		(8,287	)
Total net assets acquired at fair value		130,000			83,412			213,412
Asset acquisition – purchase price paid		(130,000	)		(80,364	)		(210,364	)
Fair value of previously held 15% stake in Rioglass		-			(3,048	)		(3,048	)
Net result of business combinations		-			-			-

Business combinations for the year ended December 31, 2020
Contracted concessional assets (Note 6)	172,321
Other non-current assets	356
Cash & cash equivalents	17,646
Other current assets	31,421
Non-current Project debt (Note 15)	(149,585	)
Current Project debt (Note 15)	(8,680	)
Other current and non-current liabilities	(15,561	)
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	-

Cost	Financial assets under IFRIC 12			Financial assets under IFRS 16 (Lessor)			Intangible assets under IFRIC 12			Intangible assets under IFRS 16 (Lessee)			Property, plant and equipment under IAS 16 and other intangible assets under IAS 38			Total assets
Total as of January 1, 2021		936,837			2,941			9,467,309			66,230			350,720			10,824,037
Additions		922			442			40,383			2,459			14,204			58,410
Subtractions		-			-			(348	)		-			(21,282	)		(21,630	)
Business combinations (Note 5)		-			-			-			19,148			522,932			542,080
Currency translation differences		(9,519	)		(540	)		(334,497	)		(5,019	)		(20,703	)		(370,278	)
Reclassification and other movements		(53,715	)		-			29,692			-			10,539			(13,484	)
Total cost		874,525			2,843			9,202,539			82,818			856,410			11,019,135

Investments in associates	2021			2020
Initial balance		116,614			139,925
Share of profit		12,304			510
Distributions		(36,877	)		(23,703	)
Acquisitions		202,345			-
Others (incl. currency translation differences)		195			(118	)
Final balance		294,581			116,614

Company	% Shares		Non- current assets		Current assets		Project debt		Other non- current liabilities		Other current liabilities		Revenue		Operating profit/ (loss)			Net profit/ (loss)			Investment under the equity method
2007 Vento II, LLC (*)		49.00		459,037		13,511		-		62,387		10,259		104,461		34,216			32,806			195,952
Windlectric Inc (**)		30.00		310,751		11,036		-		207,404		38,126		24,008		10,442			152			41,911
Myah Bahr Honaine, S.P.A.(***)		25.50		151,830		59,020		51,721		18,142		3,293		53,450		33,935			24,899			38,922
Pemcorp SAPI de CV (****)		30.00		127,892		117,083		146,931		101,439		2,925		40,166		6,561			(6,522	)		15,358
Pectonex, R.F. Proprietary Limited		50.00		2,356		-		-		-		1		-		(186	)		(186	)		1,495
Evacuación Valdecaballeros, S.L.		57.16		17,185		976		-		15,022		156		938		(63	)		(93	)		923
Evacuación Villanueva del Rey, S.L		40.02		2,637		63		-		1,601		172		-		59			-			-
ABY Infraestructuras S.L.U.		20.00		238		46		-		-		5		-		(54	)		(54	)		21
As of December 31, 2021																						294,581

	Notes		Amortized cost		Fair value through other comprehensive income		Fair value through profit or loss		Balance as of December 31, 2021
Derivative assets		9		-		-		12,960		12,960
Investment in Ten West Link				-		14,459		-		14,459
Financial assets under IFRIC 12 (short-term portion)				188,912		-		-		188,912
Trade and other receivables		11		307,143		-		-		307,143
Cash and cash equivalents		12		622,689		-		-		622,689
Other financial investments				87,657		-		-		87,657
Total financial assets				1,206,401		14,459		12,960		1,233,820

Corporate debt	14	1,023,071	-	-	1,023,071
Project debt	15	5,036,193	-	-	5,036,193
Trade and other current liabilities	17	113,907	-	-	113,907
Derivative liabilities	9	-	-	223,453	223,453
Total financial liabilities		6,173,171	-	223,453	6,396,624

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

	Balance as of December 31, 2021				Balance as of December 31, 2020
	Assets		Liabilities		Assets		Liabilities
Interest rate cash flow hedge		9,550		206,763		898		302,302
Foreign exchange derivatives instruments		3,410		-		661		-
Notes conversion option (Note 14)		-		16,690		-		25,882
Total		12,960		223,453		1,559		328,184

Notionals	Balance as of December 31, 2021				Balance as of December 31, 2020
	Assets		Liabilities		Assets		Liabilities
Up to 1 year		71,386		106,191		61,364		120,874
Between 1 and 2 years		304,930		240,197		296,828		249,785
Between 2 and 3 years		262,973		271,350		257,548		276,111
Subsequent years		217,989		860,777		292,011		852,696
Total		857,278		1,478,515		907,752		1,499,466

Fair value	Balance as of December 31, 2021					Balance as of December 31, 2020
	Assets		Liabilities			Assets		Liabilities
Up to 1 year		678		(15,039	)		59		(21,042	)
Between 1 and 2 years		1,810		(33,670	)		255		(48,276	)
Between 2 and 3 years		2,268		(39,834	)		305		(55,220	)
Subsequent years		4,794		(118,220	)		280		(177,764	)
Total		9,550		(206,763	)		898		(302,302	)

	Balance as of December 31,
	2021		2020

Credit receivables (current)		19,387		23,067
Credit receivables (non-current)		15,768		10,082
Total receivables from related parties		35,155		33,149

Credit payables (current)		9,494		18,477
Credit payables (non-current)		5		6,810
Total payables to related parties		9,499		25,287

	Balance as of December 31,
Currency	2021		2020
U.S. dollar		318,071		575,567
Euro		230,136		196,431
South African Rand		38,268		40,561
Mexican Peso		4,926		23,570
Algerian Dinar		21,156		21,114
Others		10,132		11,258
Total		622,689		868,501

	Project debt - long term			Project debt - short term			Total
Balance as of December 31, 2020		4,925,268			312,346			5,237,614
Increases		54,908			256,581			311,489
Decreases		(85,259	)		(564,603	)		(649,862	)
Business combinations (Note 5)		288,352			38,781			327,133
Currency translation differences		(140,502	)		(49,679	)		(190,181	)
Reclassifications		(655,093	)		655,093			-
Balance as of December 31, 2021		4,387,674			648,519			5,036,193

	Balance as of December 31,
Item	2021		2020
Trade accounts payables		79,052		51,421
Down payments from clients		542		416
Other accounts payables		34,313		40,720
Total		113,907		92,557

Deferred tax assets	Balance as of December 31,
from	2021		2020
Net operating loss carryforwards (“NOL´s”)		323,115		497,184
Temporary tax non-deductible expenses		128,186		115,063
Derivatives financial instruments		55,217		83,847
Other		4,225		3,021
Total deferred tax assets		510,743		699,115

Deferred tax liabilities	Balance as of December 31,
from	2021		2020
Accelerated tax amortization		465,219		652,600
Other difference between tax and book value of assets		180,218		154,969
Other		1,897		179
Total deferred tax liabilities		647,334		807,748

Consolidated balance sheets classifications	Balance as of December 31,
	2021		2020
Deferred tax assets		172,268		152,290
Deferred tax liabilities		308,859		260,923
Net deferred tax liabilities		136,591		108,633

Deferred tax assets	Amount
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)
Currency translation differences and other		7,019
As of December 31, 2020		152,290

Increase/(decrease) through the consolidated income statement		46,855
Increase/(decrease) through other consolidated comprehensive income (equity)		(23,712	)
Business combinations (Note 5)		4,410
Currency translation differences and other		(7,575)
As of December 31, 2021		172,268