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

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

OR

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

For the fiscal year ended December 31, 2023
OR

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

OR

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

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

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

Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 116,055,126 ordinary shares, nominal value $0.10 per share.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒Yes ☐ No
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐Yes ☒ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer, “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new orrevised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐
† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b) ☐
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

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

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

ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC
TABLE OF CONTENTS

|  | Page
CURRENCY PRESENTATION AND DEFINITIONS | 7
PRESENTATION OF FINANCIAL INFORMATION | 11
PRESENTATION OF INDUSTRY AND MARKET DATA | 12
ITEM 1. | IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS | 13
ITEM 2. | OFFER STATISTICS AND EXPECTED TIMETABLE | 13
ITEM 3. | KEY INFORMATION | 13
A | RESERVED | 13
B. | Capitalization and Indebtedness | 13
C. | Reasons for the Offer and Use of Proceeds | 13
D. | Risk Factors | 13
ITEM 4. | INFORMATION ON THE COMPANY | 48
A. | History and Development of the Company | 48
B. | Business Overview | 48
C. | Organizational Structure | 94
D. | Property, Plant and Equipment | 95
ITEM 4A. | UNRESOLVED STAFF COMMENTS | 95
ITEM 5. | OPERATING AND FINANCIAL REVIEW AND PROSPECTS | 95
A. | Operating Results | 95
B. | Liquidity and Capital Resources | 112
C. | Research and Development | 121
D. | Trend Information | 121
E. | Critical Accounting Estimates | 121
F. | Off-Balance Sheet Arrangements | 129
ITEM 6. | DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES | 129
A. | Directors and Senior Management | 129
B. | Compensation | 134
C. | Board Practices | 154
D. | Employees | 156
E. | Share Ownership | 157
F. | Disclosure of a Registrant’s Action to Recover Erroneously Awarded Compensation | 157
ITEM 7. | MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS | 158
A. | Major Shareholders | 158
B. | Related Party Transactions | 159
C. | Interests of Experts and Counsel | 162
ITEM 8. | FINANCIAL INFORMATION | 162
A. | Consolidated Statements and Other Financial Information. | 162
B. | Significant Changes | 165
ITEM 9. | THE OFFER AND LISTING | 165
A. | Offering and Listing Details. | 165
B. | Plan of Distribution | 165
C. | Markets | 165
D. | Selling Shareholders | 165
E. | Dilution | 165
F. | Expenses of the Issue | 165
ITEM 10. | ADDITIONAL INFORMATION | 165
A. | Share Capital | 165
B. | Memorandum and Articles of Association | 165
C. | Material Contracts | 165
D. | Exchange Controls | 166
E. | Taxation | 166

F. | Dividends and Paying Agents | 172
G. | Statement by Experts | 172
H. | Documents on Display | 172
I. | Subsidiaries Information | 172
J. | Annual Report to Security Holders | 172

3

ITEM 11. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 173
ITEM 12. | DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES | 177
A. | Debt Securities | 177
B. | Warrants and Rights | 177
C. | Other Securities | 177
D. | American Depositary Shares | 177
ITEM 13. | DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES | 178
ITEM 14. | MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS | 178
ITEM 15. | CONTROLS AND PROCEDURES | 178
ITEM 16. | RESERVED | 179
ITEM 16A. | AUDIT COMMITTEE FINANCIAL EXPERT | 179
ITEM 16B. | CODE OF ETHICS | 179
ITEM 16C. | PRINCIPAL ACCOUNTANT FEES AND SERVICES | 179
ITEM 16D. | EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES | 181
ITEM 16E. | PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS | 181
ITEM 16F. | CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT | 181
ITEM 16G. | CORPORATE GOVERNANCE | 181
ITEM 16H. | MINE SAFETY DISCLOSURE | 182
ITEM 16I. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS | 182
ITEM 16J. | INSIDER TRADING POLICIES | 182
ITEM 16K. | CYBERSECURITY | 182
ITEM 17. | FINANCIAL STATEMENTS | 183
ITEM 18. | FINANCIAL STATEMENTS | 183
ITEM 19. | EXHIBITS | 183

4

Table of Contents
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS
This annual 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, likely to, believe, will, could, should, would, estimated, may, plan, potential, future, projection, goals, target, outlook, predict, aim and intend or words of similar meaning) are not statements of historical facts and may be forward looking. Such statements occur throughout this annual report and include statements with respect to our strategy, including the development and construction of new assets, expected trends and outlook, electricity prices, 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, ability to capture growth opportunities, organic growth, 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 annual report, 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, and changes in, the debt and equity capital markets and other traditional liquidity sources 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;

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

• | the ability of our assets to serve our project debt and comply with financial or other covenants on their terms, including but not limited to our projects debts in Chile, and our ability to serve our corporate debt;

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

• | government regulation, including compliance with regulatory and permit requirements and changes in market rules, rates, tariffs, environmental laws and policies affecting renewable energy, including the IRA and recent changes in regulation defining the remuneration of our solar assets in Spain;

• | changes in tax laws and regulations, including the new legislation on restrictions to tax deductibility in Spain;

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

• | global recession risks, volatility in the financial markets, an inflationary environment, increases in interest rates and supply chain issues, and the related increases in prices of materials, labor, services and other costs and expenses required to operate our business;

• | risks related to our ability to capture growth opportunities, develop, build and complete projects in time and within budget, including construction risks and risks associated with the arrangements with our joint venture partners;

• | our ability to grow organically and inorganically, which depends on our ability to identify attractive development opportunities, attractive potential acquisitions, finance such opportunities and make new investments and acquisitions on favorable terms;

• | our ability to distribute a significant percentage of our cash for distribution as cash dividends, intention to increase such dividends over time;

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

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Table of Contents

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

• | risks related to our reliance on suppliers, including financial or technical uncertainties of original equipment manufacturer (OEM) suppliers, among others;

• | risks related to disagreements and disputes with our employees, unions and employees represented by unions;

• | 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, including as a result of interruptions or disruptions caused by supply chain issues and trade restrictions;

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

• | 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 PPAs;

• | 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;

• | risks related to our current or previous relationship with Abengoa, our former largest shareholder, including litigation risk;

• | performing the O&M services directly and the successful integration of the O&M employees where the services thereunder have been recently replaced and internalized;

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

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

• | the process to explore and evaluate potential strategic alternatives, including the risk that this process may not lead to the approval or completion of any transaction or other strategic change;

• | potential impact of potential pandemics 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;

• | our plans relating to the sale or disposition of assets, including the sale of our equity interest in Monterrey;

• | risks related to Russian military actions in Ukraine, to military actions in the Middle East, or to the potential escalation of any of the foregoing global geopolitical tensions; and

• | other factors discussed in “Part I, Item 3.D. – 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 $320 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 “Albisu” refer to the 10 MW solar PV plant located in Uruguay;

• | 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 and Liberty GES ROFO Agreement” refer to the agreements we entered into with Algonquin and with Liberty GES, respectively, on March 5, 2018, under which Algonquin and Liberty GES 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” 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, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021, 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 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 electric transmission asset in Peru, which is part of the Guaranteed Transmission System;

• | references to “ATS” refer to Atlantica 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;

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Table of Contents

• | 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), including proceeds from the sale of assets;

• | 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 PV 3” refer to the solar PV plant of 73 MW located in Chile;

• | references to “Chile TL 3” refer to the 50-mile transmission line located in Chile;

• | references to “Chile TL 4” 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 BofA Securities, Inc., MUFG Securities Americas Inc. and RBC Capital Markets LLC, as sales agents, dated February 28, 2022 as amended on May 9, 2022, under which we may offer and sell from time to time up to $150 million of our ordinary shares and pursuant to which such sales agents 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 U.S. 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;

• | 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”;

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• | 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 amended in June 2023 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 “IRA” refer to the U.S. Inflation Reduction Act;

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

• | references to “Italy PV” refer to the solar PV plants with combined capacity of 9.8 MW located in Italy;

• | 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 “La Tolua” 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 “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;

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

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

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

• | 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 $155 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, as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements — Note Issuance Facility 2020”;

• | references to “OECD” refer to the Organization for Economic Co-operation and Development;

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

• | references to “Omega Peru” refer to Omega Peru Operacion y Maintenimiento S.A.;

• | 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, August 28, 2020, March 1, 2021, May 5, 2022 and May 30, 2023 providing for a senior secured revolving credit facility in an aggregate principal amount of $450 million, as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements — Note Issuance Facility 2020”;

• | 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 “SEC” refer to the U.S. Securities and Exchange Commission;

• | 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 “SOFR” refer to Secured Overnight Financing Rate;

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

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• | references to “Solnova 1, 3 & 4” refer to three solar plants with capacity of 50 MW each 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;

• | references to “Tierra Linda” refer to the 10 MW solar PV plant located in Colombia;

• | 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, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021 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).
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. Adjusted EBITDA 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. Adjusted EBITDA 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 including Adjusted EBITDA 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;

• | 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 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 entities 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.
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All third-party information, as outlined above, has to our knowledge been accurately reproduced and, as far as we are aware and are able to ascertain, no facts have been omitted which would render the reproduced information inaccurate or misleading, but there can be no assurance as to the accuracy or completeness of the included information.
PART I

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

Not applicable.

ITEM 2. | OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3. | KEY INFORMATION

A. | [RESERVED]

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. Before making any investment decision, 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. 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 key risks we face. See below under this “Item 3.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

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

• | 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.

• | The PPAs and concession 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 suppliers.

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

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

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

• | 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.

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

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

• | A 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.

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

• | We depend on our key personnel and our ability to attract and retain skilled personnel. The operation and maintenance of most of our assets is labor intensive, and therefore work stoppages by employees could harm our business.

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

• | Our information technology and communications systems are subject to cybersecurity risk and other risks.

Risks Related to Our Relationship with Algonquin and Abengoa

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

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

• | Legal proceedings involving Abengoa, our former largest shareholder, and its current and previous insolvency processes and events and circumstances that led to them could affect us.

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, our ability to fund our operations, pay dividends or raise additional capital.

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

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

• | The process to explore and evaluate potential strategic alternatives may not be successful.

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

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

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

• | 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

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

Risks Related to Regulation

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

• | Revenues in our solar assets in Spain are subject to review periodically.

Risks Related to Ownership of Our Shares

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

• | Future dispositions of our shares by substantial shareholders or the perception thereof may cause the price of our shares to fall.

Risks Related to Taxation

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

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

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

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I. | Risks Related to Our Business and Our Assets

Our failure to maintain safe work environments may expose us to significant financial losses, as well as civil and criminal liabilities.
The ownership, construction and operation of our assets 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, batteries, 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 or the construction company, 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 or the construction company 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 the contractors in charge of the construction of our assets or other suppliers do not follow them, our employees and others may become injured. In addition, the construction and 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 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 131 years as of December 31, 2023.
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 B from S&P, B2 from Moody’s and B from Fitch. Eskom which is the off-taker of our Kaxu solar plant, is a state-owned, limited liability company, wholly owned by the Republic of South Africa. Eskom’s payment guarantees to our Kaxu solar plant are underwritten by the South African Department of Mineral Resources and 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 is currently BBB, B3 and B+ from S&P, Moody’s and Fitch, respectively. We have experienced delays in collections in the past, especially since the second half of 2019, which have been significant in certain quarters, including the fourth quarter of 2023.

1 Calculated as weighted average years remaining as of December 31, 2023 based on CAFD estimates for the 2024-2027 period, including assets that have reached COD before March 1, 2024.
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The cost of renewable energy has considerably decreased since most of our plants were built and renewable energy has become 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. Our competitors may be able to operate at lower costs, which may adversely affect our ability to compete for off-take agreement renewals. 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 power purchase agreements and concession 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.
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. 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 power purchase agreements or concession contracts may be adversely affected by problems including those related to our reliance on 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, solar fields, tanks, batteries, transformers or electrical generators fail because of design failures or faulty operation or for any other reason, we rely on internal teams and 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 and solar field systems. Repairs have been carried out in both assets. In Solana, availability in the storage system was lower than expected in 2021, 2022 and 2023 due to the repairs and replacements that we are carrying out after leaks were identified in the first quarter of 2020. These works have impacted production in 2021, 2022 and 2023, together with a lower solar field performance and may impact production in 2024 and upcoming years. We experienced delays in the repairs and replacements that we carried out. We cannot guarantee that the repairs will be effective, that Solana will reach expected production or that additional repairs will not be required. In addition, in 2023 an unscheduled outage occurred at Kaxu when a problem was found in the turbine, a few weeks after a scheduled turbine major overhaul was carried out by Siemens, the original equipment manufacturer. Part of the damage and the business interruption is covered by our insurance property policy, after a 60-day deductible. The plant restarted operations in mid-February 2024. Restarting operations after a long outage might result in lower production during a ramp-up period. Similar interruptions could happen again at our plants due to failure of key equipment.
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In addition, we currently have several projects under construction in different geographies. For example, Coso Batteries 1 and Coso Batteries 2 are currently under construction. Both projects were fully developed in-house. We will rely on batteries, software and other components manufactured by third parties which may contain undetected manufacturing-related defects or errors in a sector where our expertise is not as proven as in the rest of our businesses yet. 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 Siemens, Naes, GE, Nordex, Tesla, construction suppliers and equipment suppliers for assets under construction cannot or will not perform under their operation and maintenance and other agreements with us, or satisfy their related warranty obligations, 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.
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 Italy PV 4 and Chile PV 3 or assets which have recently ended construction such as Albisu, La Tolua, Tierra Linda and Honda 1, or assets under construction 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 to the construction and operation of such facilities, including, but not limited to, degradation of equipment in excess of our expectations, system failures and outages and higher maintenance capital expenditures than initially expected. The failure of these facilities to perform as we expect and/or higher than expected operational costs or maintenance capital expenditures may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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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 solar generation assets or our water facilities. Floods can also cause landslides which may affect our transmission lines.

| - | 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. In 2023, a winter storm affected a transmission line in our geothermal asset Coso in California and affected production for several days. Also, natural gas assets and battery systems could face operational issues caused by freezing or very cold conditions.

| - | Rising temperatures and droughts could cause wildfires like the ones that have affected California in recent years. 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 PG&E, one of our clients in 2018 and 2019.

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

Components of our equipment and systems, such as structures, mirrors, absorber tubes, blades, PV panels, batteries 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.
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• | Chronic physical.

| o | An increase in temperatures can reduce efficiency and increase operating costs at our plants. 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.

| - | Lower efficiency in battery systems.

| o | 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. 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 a negative impact on chemical costs in our water treatment plants at our generating 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.

• | 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.

Starting from 2024, we are required under UK regulations to include certain climate-related disclosures aligned with the Task Force on Climate-Related Financial Disclosures (TCFD) in our UK Annual Report.
Additionally, a group of our subsidiaries is currently subject to the EU Non-financial Reporting Directive as adopted by implementing regulations in Spain. In particular, on January 5, 2023, the European Union’s Corporate Sustainability Reporting Directive (“CSRD”) entered into force. Among other things, the CSRD expands the number of companies required to publicly report sustainability and ESG-related information on their management report to understand how sustainability matters affect their own development, performance and position, and defines the related information that companies are required to report in accordance with European Sustainability Reporting Standards (“ESRS”). The CSRD raises the bar on ESG matters and requires a “double materiality” analysis, meaning companies will have to detail both the impacts on the environment (e.g. the impact of corporate activity on sustainability matters from perspective of citizens, consumers, employees, etc.) and the climate-related risks they face (e.g. sustainability matters which from the investor perspective are material the company’s development, performance and position). Impacts, risks and opportunities are material if they satisfy one or both of these materiality tests. A sub consolidated group of our subsidiaries will fall within the scope of the new reporting requirements , effective January 1, 2025, and we will be required to provide such information for the fiscal year 2025 for this sub-consolidated group. In addition, the entire group will become subject to the CSRD from January 1, 2028. This will involve implementing processes to gather the relevant data, conduct materiality assessments and prepare a CSRD-compliant report, which will likely be a time-consuming and costly exercise and in the event that our disclosures prove incorrect we may incur liabilities.
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• | Emerging Regulation. Changes in regulation could have a negative impact on Atlantica’s growth or cause an increase in costs. Currently, renewable energy projects 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. The U.S. Inflation Reduction Act (IRA) signed into law on August 16, 2022 increased and / or extended some of these incentives and established new ones. For example, the IRA includes, among other incentives, a 30% solar investment tax credit (“ITC”) for solar projects to be built until 2032, a production tax credit (“PTC”) for wind projects to be built until 2032, a 30% ITC for standalone storage projects to be built until 2032 and a new tax credit that will award up to $3/kg for low carbon hydrogen. The IRA also includes transferability options for the ITCs and PTCs, which should allow an easier and faster monetization of these tax credits. A reduction in such incentives in the future 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”.

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.
Furthermore, several regions are increasing reporting requirements in relation to climate-related risks and opportunities and we will or may be subject to several of those requirements. We will be subject to new mandatory climate-related disclosures pursuant to SEC, proposed rules that are currently in draft form. The consolidated group or part of our subsidiaries will or may be subject to the Corporate Sustainability Reporting Directive in Europe, IFRS requirements for disclosure of sustainability-related financial information and may be subject to the California Climate Related Regulation.

• | Reputation. Decreased access to capital.

Climate change and ESG are important criteria for some shareholders and investors. 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 engines 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.

• | 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. 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.
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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.
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.
Unfavorable weather and atmospheric conditions could impair the effectiveness of our assets or reduce their output beneath their rated capacity or require shutdown of key equipment, hampering operation of our renewable assets and our ability to achieve forecasted revenues and cash flows.
We base our investment decisions with respect to each renewable generation facility on the findings of related wind, 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.
Our geothermal asset Coso depends on the geothermal resource available on the site of the plant, which is also ultimately beyond our control. If geothermal resource does not meet our expectations as it is, 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 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, electric storms, lightning (especially in our wind farms), 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.
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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.
A 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.
A pandemic could affect our operation and maintenance activities. 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.
We could also experience commercial disputes with our clients, suppliers and partners related to implications of a pandemic 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. All these situations 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.
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, Chile PV 2 and Chile PV 3 and we have invested through a debt instrument in Tenes. We also have partners in projects and assets under development or construction. Investments in assets or projects under development or construction over which we have no control, or 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. If we do not have control of a project or an asset, our partner may decide to sell such project or asset under terms and conditions that may not be the most beneficial to us. In Ten West Link we hold minority stakes, and our partner is an infrastructure fund that may decide to sell these assets in the future. In Monterrey, our partner initiated a process to sell its 70% stake in the asset and we do not have control of this process. 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.
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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.
We depend on our key personnel and our ability to attract and retain skilled personnel. The operation and maintenance of most of our assets is labor intensive, and therefore work stoppages by employees could harm our business.
In some of the geographies where we operate, competition for qualified personnel is high and our turnover has increased recently, in particular in the United States. Some of our assets are in remote locations, and it may be difficult for us to retain employees or to cover certain positions. We may experience difficulty in hiring and retaining employees with appropriate qualifications. We may face high turnover, requiring us to dedicate time and resources to find and train new employees. The challenging markets in which we compete for talent may also require us to invest significant amounts of cash and equity to attract and retain employees. If we fail to attract new personnel or fail to retain and motivate our current personnel, the performance of our assets, our business and future growth prospects and ability to compete could be adversely impacted.
In addition, 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. If our employees or 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.
We currently have three assets with merchant revenues (Chile PV 1 and Chile PV 3, where we have a 35% ownership, and Lone Star II, where we have a 49% ownership) and one asset with partially contracted revenues (Chile PV 2, where we have a 35% ownership). Although assets with merchant exposure represent less than a 2%2 of our portfolio in terms of Adjusted EBITDA, if electricity market prices were lower than expected, this may have a negative impact on our business, revenues, results of operations and cash flows.
For example, due to low electricity prices in Chile, which determine lower merchant revenues and consequently less cash and debt service payment capacity, the project debts of Chile PV 1 and 2 were under an event of default as of December 31, 2023 and impairments were recorded in 2023 and 2022. For further information, see “Item 4.B–Business overview–Our Operations.”
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. During the year 2022 and 2023, electricity market prices in Europe have also been affected by the war in Ukraine. In several of the jurisdictions in which we operate including Spain, Chile and Italy, 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 fully compensate for fluctuations in the market price component, and, consequently, total remuneration may be volatile. Recent high market prices that we have been experiencing in Spain since the third quarter of 2021 resulted in higher cash collections in 2021 and 2022 which, in accordance with the regulation in place, caused a reduction of the regulated remuneration component in 2022 and 2023. During 2023, electricity market prices have been lower than the price expected by the regulation. If market prices continue to be lower than the prices assumed by the regulation and the regulated parameters are not revised until 2026, we may have an adverse effect on revenues, results of operations and cash flows in 2024 and 2025, which we expect will be compensated starting in 2026 in accordance with the regulation in place (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 periodically.”).

2 Calculated as a percentage of our Adjusted EBITDA for the year 2023.
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In addition, operating costs in certain of our existing or future projects depend to some extent on market prices of electricity used for self-consumption and, to a lower extent, on market prices of natural gas. In Spain, for example, operating costs increased in 2022 as a result of the increase in the price of natural gas and electricity.
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 or not reaching minimum production. 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. We also depend on the assignment of the access to new interconnection points for the development and construction of new projects. 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 or in delays in the development and construction of new assets. 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. For example, in 2023 and 2022 some of our wind assets in the U.S. and some of our solar assets in Chile and in Spain have been subject to curtailment and may be subject to similar or higher curtailment in the future. In addition, our solar assets in Spain need to achieve an annual minimum production threshold in order to obtain the right to receive the Remuneration on Investment (Rinv). In the second quarter and beginning of third quarter of 2022, some of these assets were subject to significant technical curtailment by the grid operator, which had happened very seldomly in the past. Although curtailments in Spain were lower in 2023, if curtailments increased in the future, Atlantica’s assets may not reach the annual minimum production threshold necessary to obtain the Remuneration on Investment (Rinv). Curtailments in our different geographies may have a material adverse effect on our business, financial condition, results of operations and cash flows.
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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.
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. There have been cyber-attacks within the energy industry on electricity infrastructure such as substations and related assets in the past and there may be such attacks in the future. Our generation assets, transmission facilities, storage facilities, information technology systems and other infrastructure facilities and systems could be direct targets of, or otherwise be materially adversely affected by such activities.
Given the unpredictability of the timing, nature and scope of information technology disruptions, we could potentially be subject to production stops, unavailability in our transmission lines, 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. These events could cause reputational damage and could limit our ability to raise capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs. Such events or actions may materially adversely affect our business, financial condition, results of operations and prospects
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. Although we have a cybersecurity insurance policy, the costs related to cybersecurity threats or disruptions may not be fully insured. Material system breaches and failures could result in significant interruptions that could in turn affect our operating results and reputation and cash flows. For further information about our cybersecurity systems and management, see “Item 16K- Cybersecurity”.
Negative impacts on biodiversity, including harming of protected species or other environmental hazards can result in curtailment of power plant operations, monetary fines. Negative publicity and delays in development of projects.
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. Development of renewable and storage projects also requires us to comply with strict regulations aimed at preserving biodiversity in the development sites. Compliance with regulation and with our own biodiversity policy could cause delays in the development of these projects.
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, decrease on our ESG ratings and credentials 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.
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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. For further information about our legal proceedings, 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 Our Relationship with Algonquin and Abengoa

Algonquin is our largest shareholder and exercises substantial influence over us.
Currently, Algonquin beneficially owns 42.2% of our ordinary shares and is entitled to vote approximately 41.5% of our ordinary shares. As a result of this ownership, Algonquin has substantial influence on our affairs and has the power to vote 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, the sale of all or a high percentage of our assets and other strategic transactions.
In addition, Algonquin or other significant shareholders (present or future) could exercise substantial influence and could seek to direct or change our strategy or corporate governance or could obtain effective control of us. The Shareholders Agreement that we have entered into with Algonquin may be amended and Algonquin may increase its voting rights above 41.5% or may increase its equity interest and take a controlling position in Atlantica and change our strategy, including our dividend policy. Algonquin may also sell its stake in Atlantica and a third party may gain control over us and decide to change our strategy. There can be no assurance that the interests of Algonquin or other (present or future) significant shareholders will coincide with the interests of our other shareholders or that Algonquin or other significant shareholders (present or future) will act in a manner that is in our best interests. This concentration of ownership of our shares may also have the effect of discouraging others from making tender offers for our shares or propose other transactions that might otherwise provide you with an opportunity to dispose of or realize a premium on your investment in our shares.
Further, our reputation is closely related to that of Algonquin. Any damage to the public image or reputation of Algonquin including as a result of adverse publicity, poor financial or operating performance, liquidity, changes in financial condition, rating downgrades, decline in the price of its shares or otherwise could have a material adverse effect on our business, financial condition, results of operations, cash flows or the price of our shares.
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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.
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, one of our directors is an officer of Algonquin and another director was an officer of Algonquin until August 10, 2023.
Currently, Algonquin is a related party and may have interests that differ from our interests, including with respect to the growth appetite, types of investments made, the timing and amount of dividends paid by us, the re-investment of returns generated by our operations, the use of leverage or capital increases when making investments, the appointment of outside advisors and service providers and the potential sale of their equity interest in Atlantica, including its timing and process, among others. 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.
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 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.
In addition, in Mexico, Abengoa was the owner of a plant that shares certain infrastructure and has certain back-to-back obligations with ACT. ACT is required to deliver an equipment to Pemex which has been donated and delivered to ACT by such plant. If we are unable to comply with these obligations, it may result in a material adverse effect on ACT and on our business, financial conditions, results of operations and cash flows. According to public information, the plant mentioned above is currently controlled by a third party.

III. | 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, 2023, we had (i) $4,319 million of total indebtedness under various project-level debt arrangements and (ii) $1,085 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. Furthermore, we may incur in the future additional project-level debt and corporate debt.
Our substantial debt could have important negative consequences on our business, financial condition, results of operation and cash flows including:

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

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

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

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

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

• | exposing us to the risk of increased interest rates because a portion of some of our borrowings (approximately 7% as of December 31, 2023 after giving effect to hedging agreements) are at variable interest rates and exposing Atlantica to the risk of increased interest rates in the future when the Company needs to refinance its corporate debt;

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

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

The operating and financial restrictions and covenants in the Revolving Credit Facility, the 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.
Due to low electricity prices in Chile, the project debts of Chile PV 1 and 2 are under an event of default as of December 31, 2023 and as of the date of this annual report. Chile PV 1 was not able to maintain the minimum required cash in its debt service reserve account as of December 31, 2023 and did not make its debt service payment in January. In addition, in October 2023, Chile PV 2 did not make its debt service payment. This asset obtained additional financing from the banks and made the debt service payment in December 2023, although it was not able to sufficiently fund its debt service reserve account subsequently. As a result, although we do not expect an acceleration of the debt to be declared by the credit entities, as of December 31, 2023 Chile PV 1 and 2 did not have an unconditional right to defer the settlement of the debt for at least twelve months and the project debt was classified as current in our Annual Consolidated Financial Statements. We are in conversations with the banks, together with our partner, regarding a potential waiver. Impairments were recorded in these assets in 2023 and 2022. The value of the net assets contributed by Chile PV 1 and 2 to our Annual Consolidated Financial Statements, excluding non-controlling interest, was close to zero as of December 31, 2023. If we do not reach an agreement with the banks which have financed Chile PV 1 and 2, we may lose these assets.
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Letter of credit facilities or bank guarantees to support project-level contractual obligations generally need to be renewed, at which time we will need to satisfy applicable financial ratios and covenants. If we are unable to renew the letters of credit as expected or replace them with letters of credit under different facilities on favorable terms or at all, we may experience a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, such inability may constitute a default under certain project-level financing arrangements, restrict the ability of the project-level subsidiary to make distributions to us and/or reduce the amount of cash available at such subsidiary to make distributions to us.
We may not be able to arrange the required or desired financing for investments and acquisitions and for the successful financing or 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:

• | general economic and capital market conditions;

• | credit availability from banks, other financial institutions and tax equity investors;

• | investor confidence in us;

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

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

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

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

We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace project-level financing arrangements or other credit facilities on favorable terms or at all upon the expiration or termination thereof. We may be unable to repay our existing debt as it becomes due if we fail, or any of our projects fails, to obtain additional capital or enter into new or replacement financing arrangements, which would have a material adverse effect on our business, financial condition, results of operations and cash flows. We may be unable to find financing for projects under construction or long-term project financing and tax equity investor financing once the assets reach COD.
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 and 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 and refinancing relies on our ability to raise capital to finance our investments and acquisitions. Our high pay-out ratio may hamper our ability to manage liquidity in moments when accessing capital markets becomes more challenging. 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 material 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.
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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 or SOFR. During 2022, the U.S. Federal Reserve increased the reference interest rates in the United States from 0.125% to a targeted range between 4.25% and 4.50%, which was further increased to a range between 5.25% to 5.50% in 2023. Similarly, the European Central Bank increased the reference interest rates in the Euro zone from negative levels up to 2% in 2022 and up to 4.5% in 2023. Any increase in interest rates would increase our finance expenses relating to our un-hedged variable rate indebtedness and increase the costs of refinancing our existing indebtedness and issuing new debt at the corporate level or at the project level.
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 94% of our corporate debt was fixed or hedged as of December 31, 2023. The Revolving Credit Facility, with a limit of $450 million of which $378 million were available as of December 31, 2023 is subject to variable interest rates.
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, Italy, 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. However, if the euro depreciated against the U.S. dollar in the long term, we would have a negative impact on our cash flows after 24 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.”
In addition, 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.
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.
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 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, 2023, we had $4,319 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;

• | default under our other debt instruments;

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

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

If we fail to satisfy any of our debt service obligations or breach any related financial or operating covenants, the applicable lender could declare the full amount of the relevant project debt to be immediately due and payable and could foreclose on any assets pledged as collateral.
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.
Any of these events may have a material adverse effect 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. The project debt of some of our assets also requires a waiver in the event of a change of control. 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. In addition, the PPAs of some assets would require a waiver in the event of a change of control and some of our PPAs and project financing agreements would require a notification. 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 $9 million to $11 million, which could potentially decrease progressively over time as the asset depreciates. There could also be other tax impacts and other impacts that we have not yet identified. Furthermore, a change of control could trigger an ownership change under Section 382 of the IRC which could have a material adverse effect on our business, financial condition results of operations and cash flows (see “Risks Related to Taxation – Our ability to use U.S. NOLs to offset future income may be limited”).
The process to explore and evaluate potential strategic alternatives may not be successful.
On February 21, 2023, Atlantica’s board of directors commenced a process to explore and evaluate potential strategic alternatives that may be available to Atlantica to maximize shareholder value. There is no assurance about the outcome of this process, that any specific transaction will be identified or consummated or that any other strategic change will be implemented as a result of this strategic review, or that any such review may achieve any expected results.
Unanticipated developments could delay, prevent or otherwise adversely affect the planned strategic review, including but not limited to volatility in the financial markets, disruptions in general or financial market conditions or potential problems or delays in obtaining various regulatory and tax approvals or clearances.
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In addition, whether or not any such strategic alternative is identified, pursued and/or consummated, such review could cause disruptions in the businesses of the Company by directing the attention of the board of directors and management and other resources (including significant costs) toward such review or the preparation of the Company to pursue and consummate any strategic alternative. The process could potentially increase employee turnover. If no such strategic alternative is identified or completed, the Company may have incurred significant costs, including the diversion of directors and management resources, for which they will have received little or no benefit. The process could result in a transaction or a change in strategy that negatively affects our share price, either temporarily or permanently. As of the date of this annual report, the strategic review is ongoing and we have not determined a timeframe for its conclusion.

IV. | 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 investments in projects under development or construction and through the acquisition of additional revenue-generating assets. This strategy depends on our ability to successfully identify and evaluate investment opportunities, develop and build new assets and consummate acquisitions on favorable terms. The number of investment opportunities may be limited.
Our ability to develop, build or 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, PTCs, 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 develop and build new assets depends, among other things, on our ability to secure transmission interconnection access or agreements, to secure land rights, to secure PPAs or similar schemes and to obtain licenses and permits and we cannot guarantee that we will be successful obtaining them (see “Our ability to develop renewable projects is subject to construction risks and risks associated with the arrangements with our joint venture partners”). 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, 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 may pay more for acquisitions and may be able to identify, evaluate, bid for and purchase a greater number of assets or projects under development than our financial or human resources permit. If we are unable to identify and consummate future investments and 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.”
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.
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In addition, 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.
In addition, although we have a ROFO Agreement with Algonquin, our growth through the acquisitions from Algonquin or co-investments with them has been limited. 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.
Our ability to develop renewable projects is subject to development and construction risks and risks associated with the arrangements with our joint venture partners
We are developing projects and 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 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, including tax equity; our ability to estimate the future revenue and returns for storage projects after the end of the contracted period 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 over-runs, 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.
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In order to grow our business, we may invest in or acquire assets or businesses which have a higher risk profile or are less ESG-friendly than certain assets in our current portfolio.
In order to grow our business, we may develop and build or acquire assets and businesses which may have a higher risk profile than certain of the assets we currently own. Availability of assets with long-term contracts has decreased over the last few years, 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 over-runs 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 more 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 in new markets or 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. We may also invest in 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 85% of our Adjusted EBITDA generated by low carbon footprint assets, some investors with a focus on ESG may consider this target insufficient, which could cause us to become less attractive to investors.
As a result, the consummation of investments and acquisitions may have a material adverse effect on our ability to grow, our business, financial condition, results of operations and cash flows.
We cannot guarantee the success of our recent and future investments.
Acquisitions of and investments in companies and assets are subject to substantial risks, including unknown or contingent liabilities (including violations of environmental, antitrust, anti-corruption, 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.
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We may also make acquisitions or investments in assets that are located in different jurisdictions and are different from, and may be riskier than, those jurisdictions in which we currently operate (Canada, the United States, Mexico, Peru, Chile, 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. In addition, Algonquin may terminate the Shareholders Agreement if dividend payment is lower than 80% of the cash available for distribution. Our Board of Directors may change our dividend policy at any time. We may be precluded from pursuing otherwise attractive investments if the projected short-term cash flow from the acquisition or investment does not meet our minimum expectations.
Because of our dividend policy, our growth may not be as fast as that of businesses that re-invest 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.
In addition, our Board of Directors may decide at any time to change our strategy and may agree on measures to foster our ability to grow which could include, for example, to acquire a large development company to have a larger pipeline of projects under development or to reduce our dividend to re-invest in growth a larger part of the cash we generate.

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. Capital markets have been experiencing high volatility during 2022 and 2023 both in the United States and Europe. Concerns over the COVID-19 pandemic, high inflation, interest rate increases, war in Ukraine, energy crisis in Europe, volatile gas prices, high electricity prices particularly in Europe, tensions between the U.S., Russia and China, the availability and cost of credit, and the instability of the euro have contributed to increased volatility in capital markets and worsened expectations for the economy. During the year 2023 and beginning of 2024, the valuations of renewable ETFs and renewable companies in the United States and Europe have generally decreased.
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. Supply chain issues persisted in 2022 and 2023. 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. Prolonged inflation may also cause a material adverse effect on our business, financial condition, results of operations and cash flows
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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. In the past, including in 2023, the price of shares in certain sectors including companies paying a high dividend and companies with a strategy focused on growth has been inversely correlated with interest rates. If interest rates continued to raise, this may have a further negative impact on the price of our shares.
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. 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, from October 2023 military actions in the Middle East and military actions in the Red Sea may rise further and create heightened volatility in the electricity market as well as disruptions and delays in the supply chain 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 conflicts, could significantly affect worldwide electricity market prices and demand, negatively affect supply chains 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.
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 proposed in the past regulations which intend to benefit local business rather than foreign investors. In Peru, after an attempt by the former president to dissolve congress and replace it with an “exceptional emergency government”, the president was replaced. Political uncertainty may persist in the upcoming months. 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.
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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.

VI. | 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:

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

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

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

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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 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.
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. 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.”
Besides, the U.S. Inflation Reduction Act (IRA) signed into law on August 16, 2022 increased and / or extended some of these incentives and established new ones. For example, the IRA includes, among other incentives, a 30% solar ITC for solar projects to be built until 2032, a PTC for wind projects to be built until 2032, a 30% ITC for standalone storage projects to be built until 2032 and a new tax credit that will award up to $3/kg for low carbon hydrogen. The IRA also includes transferability options for the ITCs and PTCs, which should allow an easier and faster monetization of these tax credits. Presidential elections will take place in the US in November 2024 and the republican party has claimed its opposition to the IRA and its preference for traditional energy sources over renewables. A potential repeal of the IRA or a reduction of its tax benefits could have an adverse impact on our business, our ability to execute our growth strategy, our financial condition, results of operations and cash flows.
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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.
In addition, regulations approved in the United States in relation with the import of solar equipment from China and Southeast Asia, including the Antidumping and countervailing duties and the Uyghur Forced Labor Prevention Act has hindered the ability of developers to acquire equipment for the construction of new assets. If this situation persisted in the future and a domestic alternative industry was not able to develop, our growth in the U.S. through the development and construction of new assets may be negatively affected.
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.
Revenues in our solar assets in Spain are mainly defined by regulation and some of the parameters defining the remuneration are subject to review periodically.
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 from 2015 until 2020 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 government of Spain 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.
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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, taking into account that the reasonable rate of return will be revised only for part of our portfolio on January 1, 2026, assuming our assets in Spain continue to perform as expected and assuming no additional changes of circumstances, with the information currently available, a reduction of 100 basis points in the reasonable rate of return set by the government of Spain from 2026 could cause a reduction in its cash available for distribution of approximately €6 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. 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 and lower cash flows over the remaining regulatory life of our solar assets. On March 30, 2022, the Royal Decree Law 6/2022 introduced certain temporary changes to the detailed regulated components of revenue received by our solar assets in Spain, which is applicable from January 1, 2022. The proposed remuneration parameters for the year 2022 were published on May 12, 2022 and were declared final on December 14, 2022, with a decrease in regulated revenue. The remuneration parameters for the next semi-regulatory period, starting on January 1, 2023 were published on December 28, 2022 in draft form and on June 30, 2023, the final parameters were published, including a revised assumption for electricity prices for the years 2023, 2024 and 2025. The current regulatory parameters assume a market price which is higher than current market prices. If electricity market prices continue to be lower than the market price assumed in the regulation and regulatory parameters are not adjusted until 2026, this may have a negative impact on our cash flows in 2024 and 2025.
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, agents, intermediaries, subcontractors or similar business parties, 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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VII. | Risks Related to Ownership of Our Shares

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

• | operational performance of our assets;

• | maintenance capital expenditures in our assets and other potential capital expenditure requirements in our assets in the case there were technical problems, requirements by insurance companies, environmental or regulatory requirements, capital expenditures necessary to increase safety of our employees, or unanticipated increases in construction and design costs;

• | adverse weather;

• | our debt service requirements and other liabilities;

• | fluctuations in our working capital needs;

• | fluctuations in foreign exchange rates;

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

• | seasonal variations in revenues generated by the business;

• | losses experienced not covered by insurance;

• | shortage of qualified labor;

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

• | our ability to borrow funds, including corporate debt to finance growth and project debt and tax equity investments to finance new assets under construction or which have recently reached COD;

• | 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;

• | other business risks affecting our cash levels; and

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

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.
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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 respect to a quarter adversely affected by seasonality.
Dividends to holders of our shares will be paid at the discretion of our Board of Directors. Our Board of Directors may decrease the level of or entirely discontinue payment of dividends. Our Board of Directors may change our dividend policy at any point in time or modify the dividend for specific quarters following prevailing conditions. Our Board of Directors may also decide to change our dividend policy if, for example, they considered that increasing the portion of growth self-funded with cash generated by our operations is more efficient than raising most of the funds required to finance our growth strategy. 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 dispositions of our shares by substantial shareholders or the perception thereof may cause the price of our shares to fall.
Future dispositions 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 dispositions 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.
Further, Algonquin is the beneficial owner of approximately 42.2% of our ordinary shares some of which have been and may be encumbered in the future to secure debt or other obligations of Algonquin, its subsidiaries or affiliates. The market price of our shares could decline as a result of future dispositions of our shares by Algonquin, its secured creditors or other significant stockholders whether in public or private transactions (whether in a single transaction, a series of related organized transactions or otherwise), or the perception that these dispositions could occur.
Liberty GES has a secured credit facility in the amount of $306,500,000 maturing on September 30, 2024. Such loan is collateralized by a pledge over most of the Atlantica shares held indirectly by Algonquin through certain of its subsidiaries. A collateral shortfall under that facility would occur if the quotient of the net obligations of Liberty GES, divided by the aggregate collateral share value is equal to or greater than 50% in which case the creditors under that facility may sell Atlantica shares to eliminate the collateral shortfall. In addition, a default by Liberty GES under such facility may result in its creditors having the right to foreclose on the shares and sell the shares.
Many factors may influence Algonquin’s operations, plans, or strategy (including with respect to the holding or disposition of all or any portion of our shares), and we have limited knowledge and/or visibility with respect to Algonquin’s operations, plans, or strategy. In 2023, Algonquin conducted a strategic review which concluded in August 2023 with the announcement that they will pursue the sale of its renewable energy business and their intention focus on their regulated business. This announcement did not include Algonquin’s ownership in Atlantica. It is possible that in the future Algonquin may have interest in selling part or all of its equity interest in Atlantica. Uncertainty about Algonquin’s plans or strategy with respect to the holding or disposition of all or any portion of its equity interest in Atlantica and such uncertainty may negatively affect the market price for our shares and our ability to raise capital by offering equity or equity-related securities.
We cannot predict whether future sales of our shares, or the increase in the availability of our shares for sale, will occur and the impact thereof on the market price for our shares and our ability to raise capital by offering equity or equity-related securities.
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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.
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 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.
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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.

VII. | Risks Related to Taxation

Changes in our tax position can significantly affect our reported earnings and cash flows.
We have assets and operations 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 or operations. 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.
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 and operations 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 receive 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 that 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 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.
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The main rate of UK corporation tax rate increased to 25% for fiscal years beginning on April 1, 2023. We do not expect this increase to result in significant impacts in our tax position in the UK.
In 2022, the government of South Africa approved tax limitations on deductions for tax years ending on or after March 31, 2023. The net interest expense has been limited to 30% of the EBITDA and any NOLs carried forward may only be applied to offset 80% of a corporation’s taxable income. These new limitations may have a negative impact on our cash flows.
The government of Spain introduced new restrictions on the tax deductibility of financial expenses for tax periods beginning on January 1, 2024. Any exempt dividend received by our Spanish entities will not be considered to increase the limitation of 30% of the EBITDA (as defined in the relevant Spanish laws) which determines the annual tax allowance of financial expenses. We do not expect this limitation to result in significant impacts in our tax position.
Around 140 countries have 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 (when fully implemented) will 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 generally be payable by the parent entity of the multinational group to the tax authority in such parent’s country of residence.
The new legislation related to Pillar Two has been enacted or substantially enacted in certain jurisdictions in which Atlantica operates, including the U.K. The new legislation will be effective for Atlantica’s financial years beginning on or after December 31, 2023. We have performed a preliminary assessment of the potential exposure to Pillar Two top-up taxes. The assessment is based on the most recent country-by-country tax reporting and financial statements available for the constituent entities of the group. Based on the assessment performed, the Pillar Two effective tax rates in most of the jurisdictions in which Atlantica operates are above 15% and in all of them meet the requirements to apply the relevant transitional “safe harbors” as defined by OECD, with the exception of one jurisdiction, whose impact is not material. Therefore, we currently do not expect a material impact on our business, 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 that 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 HM 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. 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 may be applied to offset 80% of our 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. An ownership change may be triggered if Algonquin sold all or part of its equity interest in Atlantica or if there was a significant ownership change in the Algonquin shareholder base. 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 further limit our ability to use net operating loss carryforwards in the United States, which could have a potential adverse effect on cash flows from U.S. assets expected in the future. In addition, the IRS has issued proposed regulations concerning the calculation of built-in gains and losses under Section 382, which, if finalized, may significantly limit our annual use of pre-ownership change U.S. NOLs in the event that 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 taxable year ended December 31, 2023 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 taxable years. 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.”

IX. | Other Risks

Our suppliers may have lower ethical standards than we do and may not comply with all laws and regulations, which may adversely impact our business.
We have suppliers in different geographies. Although we have policies and procedures in place, including a Supplier Code of Conduct, we do not control our suppliers and their business practices. As a result, we cannot guarantee that they follow ethical business practices, such as fair wage practices and compliance with environmental, safety, and other local laws. In case our existing suppliers had a demonstrated lack of compliance, we may need to change suppliers, which may result in increased costs. Unethical practices and lack of compliance by our suppliers may also have a negative impact on our reputation, which may in turn have an adverse effect on our business, results of operations and cash flows.
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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.

ITEM 4. | INFORMATION ON 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 44.2% as of December 31, 2019. As of the date of this annual report, Algonquin owns 42.2% of our shares.
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 or public takeover offers made to and by the Company 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 URLs included in this annual report on Form 20-F are intended to be an inactive textual reference only. They are not intended to be an active hyperlink to the applicable website. 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 developing, building, investing and managing sustainable infrastructure assets, while creating long-term value for our investors and the rest of our stakeholders. In 2023, renewables represented 73% of our revenue, with solar energy representing 63%. 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.
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As of the date of this annual report, we own or have an interest in a portfolio of assets and new projects under development diversified in terms of business sector and geographic footprint. Our portfolio consists of 45 assets with 2,171 MW of aggregate renewable energy installed generation capacity (of which approximately 73% 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 and projects under development 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, 2023, our assets had a weighted average remaining contract life of approximately 13 years3.
We intend to grow our business through the development and construction of projects including expansion and repowering opportunities, as well as greenfield developments, third-party acquisitions, and the optimization of our existing portfolio. We currently have a pipeline of assets under development of approximately 2.2 GW of renewable energy and 6.0 GWh of storage. Approximately 47% of the projects are PV, 41% storage, 11% wind and 1% other projects, while 22% are expected to reach ready-to-build (“RTB”) in 2024-2025, 28% are in an advanced development stage and 50% are in early stage. Also, 20% are expansion or repowering opportunities of existing assets and 80% greenfield developments.
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.
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(17)
Solana | Renewable (Solar) | 100% | Arizona (USA) | USD | 280 MW | BBB+/A3/BBB+ | 2013 | 20
Mojave | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB/Ba1/BB+ | 2014 | 16
Coso | Renewable (Geothermal) | 100% | California (USA) | USD | 135 MW | Investment grade(11) | 1987/ 1989 | 18
Elkhorn Valley(16) | Renewable (Wind) | 49% | Oregon (USA) | USD | 101 MW | BBB/Baa1/-- | 2007 | 4
Prairie Star(16) | Renewable (Wind) | 49% | Minnesota (USA) | USD | 101 MW | --/A3/A- | 2007 | 4
Twin Groves II(16) | Renewable (Wind) | 49% | Illinois (USA) | USD | 198 MW | BBB+/Baa2/-- | 2008 | 2
Lone Star II(16) | Renewable (Wind) | 49% | Texas (USA) | USD | 196 MW | N/A | 2008 | N/A
Chile PV 1 | Renewable (Solar) | 35%(1) | Chile | USD | 55 MW | N/A | 2016 | N/A
Chile PV 2 | Renewable (Solar) | 35%(1) | Chile | USD | 40 MW | Not rated | 2017 | 7
Chile PV 3 | Renewable (Solar) | 35%(1) | Chile | USD | 73 MW | N/A | 2014 | N/A
La Sierpe | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2021 | 12
La Tolua | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2023 | 9
Tierra Linda | Renewable (Solar) | 100% | Colombia | COP | 10 MW | Not rated | 2023 | 9

3 Calculated as weighted average years remaining as of December 31, 2023 based on CAFD estimates for the 2024-2027 period, including assets that have reached COD before March 1, 2024.
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Honda 1 | Renewable (Solar) | 50% | Colombia | COP | 10 MW | BBB-/--/BBB | 2023 | 7
Albisu | Renewable (Solar) | 100% | Uruguay | UYU | 10 MW | Not rated | 2023 | 15
Palmatir | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2014 | 10
Cadonal | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2014 | 11
Melowind | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2015 | 12
Mini-Hydro | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB/Baa1/BBB | 2012 | 9
Solaben 2 & 3 | Renewable (Solar) | 70%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 14/14
Solacor 1 & 2 | Renewable (Solar) | 87%(3) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 13/13
PS 10 & PS 20 | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007/ 2009 | 8/10
Helioenergy 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 13/13
Helios 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 13/14
Solnova 1, 3 & 4 | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 11/11/12
Solaben 1 & 6 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 15/15
Seville PV | Renewable (Solar) | 80%(4) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 12
Italy PV 1 | Renewable (Solar) | 100% | Italy | Euro | 1.6 MW | BBB/Baa3/BBB | 2010 | 8
Italy PV 2 | Renewable (Solar) | 100% | Italy | Euro | 2.1 MW | BBB/Baa3/BBB | 2011 | 8
Italy PV 3 | Renewable (Solar) | 100% | Italy | Euro | 2.5 MW | BBB/Baa3/BBB | 2012 | 8
Italy PV 4 | Renewable (Solar) | 100% | Italy | Euro | 3.6 MW | BBB/Baa3/BBB | 2011 | 8
Kaxu | Renewable (Solar) | 51%(5) | South Africa | Rand | 100 MW | BB-/Ba2/BB-(13) | 2015 | 11
Calgary | Efficient natural gas & Heat | 100% | Canada | CAD | 55 MWt | ~60% AA- or higher (14) | 2010 | 12
ACT | Efficient natural gas & Heat | 100% | Mexico | USD | 300 MW | BBB/ B3/B+ | 2013 | 9
Monterrey(18) | Efficient natural gas & Heat | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 22
ATN (15) | Transmission line | 100% | Peru | USD | 379 miles | BBB/Baa1/BBB | 2011 | 17
ATS | Transmission line | 100% | Peru | USD | 569 miles | BBB/Baa1/BBB | 2014 | 20
ATN 2 | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 9
Quadra 1 & 2 | Transmission line | 100% | Chile | USD | 49 miles/ 32 miles | Not rated | 2013/2014 | 11/11
Palmucho | Transmission line | 100% | Chile | USD | 6 miles | BBB/-/BBB+ | 2007 | 14
Chile TL 3 | Transmission line | 100% | Chile | USD | 50 miles | A/A2/A- | 1993 | N/A
Chile TL 4 | Transmission line | 100% | Chile | USD | 63 miles | Not rated | 2016 | 48
Skikda | Water | 34.2%(6) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 10
Honaine | Water | 25.5%(7) | Algeria | USD | 7 M ft3/day | Not rated | 2012 | 14
Tenes | Water | 51%(8) | Algeria | USD | 7 M ft3/day | Not rated | 2015 | 16

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Notes:

(1) | 65% of the shares in Chile PV 1, Chile PV 2 and Chile PV 3 are indirectly held by financial partners through the renewable energy platform of the Company in Chile. Atlantica has control over these entities under IFRS 10, Consolidated Financial Statements.

(2) | Itochu Corporation holds 30% of the shares in each of Solaben 2 and Solaben 3.

(3) | JGC holds 13% of the shares in each of Solacor 1 and Solacor 2.

(4) | Instituto para la Diversificación y Ahorro de la Energía (“Idae”) holds 20% of the shares in Seville PV.

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

(6) | Algerian Energy Company, SPA owns 49% of Skikda and Sacyr Agua, S.L. owns the remaining 16.8%. Atlantica has control over it under IFRS 10, Consolidated Financial Statements.

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

(8) | Algerian Energy Company, SPA owns 49% of Tenes. The Company has an investment in Tenes through a secured loan to Befesa Agua Tenes (the holding company of Tenes) and the right to appoint a majority at the board of directors of the project company. Therefore, the Company controls Tenes since May 31, 2020, and fully consolidates the asset from that date.

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

(10) | Reflects the counterparty’s credit ratings issued by S&P, Moody’s, and Fitch. Not applicable (“N/A”) when the asset has no PPA.

(11) | 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. The third off-taker Southern California Public Power Authority is not rated.

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

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

(14) | Refers to the credit rating of a diversified mix of 22 high credit quality clients (~60% AA- rating or higher).

(15) | Including ATN Expansion 1 & 2.

(16) | Part of Vento II portfolio.

(17) | As of December 31, 2023.

(18) | Accounted for as held for sale as of December 31, 2023.

(*) | Commercial Operation Date.

Our Business Strategy
Our strategy focuses on climate change solutions in the power and water sectors. We intend to provide clean electricity, storage capacity, 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.
We intend to grow our business maintaining renewable energy as our main segment with a primary focus on North America and Europe. We expect to continue investing in the development and construction of new assets, with a focus on renewable energy and storage. We own a pipeline of projects under development of approximately 2.2 GW of renewable energy and approximately 6.0 GWh of storage. We also expect to acquire assets from third parties leveraging the local presence and network we have in geographies and sectors in which we operate.
Additionally, 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.
Our plan for executing this strategy includes the following key components:
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Grow our business by developing new projects and investing in new assets with a focus on renewable energy and storage.
We intend to develop new assets and, in some cases, to invest in assets under development or construction. 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 will assist us in achieving our growth plans.
Focus on stable assets in renewable energy, storage and transmission, generally contracted or regulated.
We intend to focus on owning and operating stable, sustainable infrastructure 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, Europe and South America, 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 limits risks, reinforces stability and provides us with better growth opportunities.
Grow our business through the optimization of the existing portfolio and through 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 complementary technologies including storage, particularly in our renewable energy assets and transmission lines.
Maintain a low-risk approach
We intend to maintain a portfolio of sustainable infrastructure assets, generally totally or partially contracted, with a low-risk profile for a significant part of our revenue. We generally seek to invest 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 or merchant revenue or in assets with revenue in currencies other than the U.S. dollar or euro. We have a set of policies and a risk management system in place which define thorough risk management processes.
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, 2023, approximately 93% 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.
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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. We estimate that the off-take agreements or regulation in place at our assets have a weighted average remaining term of approximately 134 years as of December 31, 2023, providing long-term cash flow visibility. In 2023, approximately 54% of our revenue was non-dependent on natural resource, not subject to the volatility that natural resource may have, especially solar and wind resources. This includes our transmission lines, our efficient natural gas plant, our water assets and approximately 76% of the revenue received from our solar assets in Spain with most of their revenues based on capacity in accordance with the regulation in place. In these assets, our revenue is not subject to (or has low dependence on) solar, wind or geothermal resources, which translates into a more stable cash-flow generation. Going forward, our new investments will probably be more 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.
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. 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 (BNEF), the next three decades will require between $46 trillion and $131 trillion of investment which translates into an annual range of $1.5-$4.4 trillion. BNEF projects an annual investment of $1.2-$3.9 trillion in low-carbon energy sources, including renewables, surpassing the $1 trillion invested in 20225. Furthermore, clean energy is on track to set new records. Global installation of wind, solar and storage is expected to exceed 680 GW in 2024, up 22% from 2023. Solar is anticipated to lead the way in 2024 with over 500 GW expected to be installed; which will likely make it the largest source of new capacity and new generation worldwide. Onshore wind follows as the second-highest, with close to 100 GW projected to be installed in 2024, followed by storage capacity, of which around 50 GW is expected to be installed6.
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 narrower geographic or technological focus. If certain geographies and business sectors become more competitive for investments 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 to capture growth opportunities
We have in-house development capabilities and partnerships with third parties to co-develop new projects. Our development asset identification is supported by rigorous analysis and deeply rooted industry knowledge and experience. In addition, we follow a disciplined approach to make capital allocation decisions and we have strict minimum required returns for development projects and acquisitions that we update frequently. In addition, our current portfolio of assets offers growth opportunities through the expansion and repowering of existing assets and through hybridization of existing assets with other complementary technologies. We can also grow by adding storage to our existing renewable assets or by developing standalone storage close to our existing assets.

4 Calculated as weighted average years remaining as of December 31, 2023 based on CAFD estimates for the 2024-2027 period, including assets that have reached COD before March 1, 2024.
5 BNEF Theme: Energy Investment and Climate Scenarios.
6 Where Energy Markets and Climate Policy Are Headed in 2024: BNEF.
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Proven capabilities in operation and maintenance
We perform operation and maintenance in-house in a majority of our assets. We believe this approach allows us to have full control of our assets and to optimize their performance. We can benefit from synergies in shared resources and centralized purchasing management, among other advantages. Our corporate operations departments have a plan to periodically review all our assets in detail to identify best practices and improvement actions which are then implemented across the portfolio.
Solid financing expertise
Our Finance team has extensive experience in project financing and project refinancing in our different geographies. In our corporate financing, we have access to different pools of capital. We have issued bonds in the public markets, including convertibles, private placements with different types of investors, bank financing and commercial paper. Since a portion of the assets have revenues denominated in euros, we can issue corporate financings in euros, to take advantage of lower costs.
Lean corporate structure focused on value added activities
We operate a lean and efficient organization where corporate functions support each operating asset. Our core corporate policies are supported by a solid commitment to risk management that guides all our decisions. We believe that our internal management system ensures a nimble decision making process while ensuring compliance with our policies and risk management system.
Well positioned in ESG
In 2023, 72% of our Adjusted EBITDA was derived from renewable energy and 62% of our Adjusted EBITDA corresponded to solar energy production. Adjusted EBITDA from low carbon footprint assets represented 89%, including renewable energy, transmission infrastructure, as well as water assets. We have set a target to maintain over 85% of our Adjusted EBITDA generated from low-carbon footprint assets.
We have set a target to reduce our scope 1 and scope 2 GHG emissions per unit of energy generated7 by 70% by 2035, with 2020 as base year. This target was validated in 2021 by the Science Based Targets initiative. We have also set a target to reduce our scope 3 emissions per unit of energy generated by 70% by 2035 from a 2020 base year. With this, we target to achieve net zero GHG emissions by 2040. Additionally, we have also set targets to reduce non-GHG emissions per unit of energy generated and to reduce our water consumption per unit of energy generated.
In 2023, our key health and safety indicators met annual targets and remained below the sector average in all our geographies. Health and Safety is our number one priority, and we want our employees, partners, and contractors to apply the highest standards to ensure safe and sustainable operations.
Regarding our local communities, we acknowledge that our day-to-day activities have impacts on nearby communities. We recognize that the communities where we operate are where some of our employees and
other stakeholders live and raise their families, and where part of our future workforce is educated and trained. We foster communities’ economic prosperity through local purchases and by hiring local employees. As such, it is key for us to be both proactive and a valued member of our communities. In 2023 we invested $1.5 million (in line with 2022 investment). Atlantica’s investments in local communities are focused on improving infrastructure and supporting education.
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. 22% of our directors are women. We believe that we have a solid compliance framework with a set of policies approved and reviewed annually by the Board of Directors, a Code of Conduct which is acknowledged by all employees annually and internal procedures aimed at ensuring that all geographies comply with our policies.

7 Including thermal generation.
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We have been rated by various ESG rating agencies, which we believe can provide relevant information for investors.
Our Operations
Renewable energy
Solana
Overview. Solana is a 250 MW net (280 MW gross) solar plant, wholly owned by us, 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 in October 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 (“ACC”) with annual increases of 1.84% per year. The PPA includes ongoing performance obligations. The PPA expires in October 2043.
O&M. We perform O&M for Solana with our own personnel.
Operations. Solana has not yet achieved its technical capacity on a continuous basis. During the last few years, repairs, replacements and improvements were conducted on the heat exchangers, the water plant, the storage system and the solar field. In 2021, 2022 and the beginning of 2023, availability in the storage system was lower than expected due to the repairs and replacements that we have been carrying out. These works have impacted production in 2021, 2022 and 2023 and may impact production in 2024 and upcoming years.
Project Level Financing. Solana received a loan from the Federal Financing Bank (“FFB”) in December 2010, with a guarantee from the DOE. The FFB loan is payable over a 29-year term and has an average fixed interest rate of 3.69%. As of December 31, 2023, the outstanding balance of the loan was $701.8 million. The FFB loan permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.20x.
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, 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. We perform O&M for Mojave with our own personnel.
Project Level Financing. Mojave received a loan from the FFB in September 2011, with a guarantee from the DOE. The FFB loan is payable over a 25-year term and has an average fixed interest rate of 2.75%. As of December 31, 2023, the outstanding balance of the loan was $570.5 million. The financing arrangement permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.20x.
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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.
PPAs. We have three PPAs with fixed prices:

| • | 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 Central Coast Community Energy (formerly Monterrey Bay Community Power), both with an “A” credit rating from S&P.

| • | 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.
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 is 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 in two tranches, the first tranche extends until 2027 with a strike rate of 0.86%, and the second tranche extends from 2027 to 2040 with a strike rate of 2.11%. As of December 31, 2023, the outstanding balance of the loan was $188.6 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 located in the states of Illinois, Texas, Oregon and Minnesota in the United States in which Atlantica has a 49% equity interest. The portfolio does not currently have any debt. O&M services are provided by EDP Renewables North America (“EDPR”) for the four assets.

| • | Elkhorn Valley

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 December 2027. Base price increases annually with a 3% escalation factor.

| • | Prairie Star

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 December 2027 with the option to extend it until 2036.

| • | Twin Groves II

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 March 2026.

| • | Lone Star II

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 had a PPA with EDPR North America, LLC at a fixed price that expired in January 2023 and the plant is currently selling electricity at market prices. Together with our partner EDPR, we have decided to sell electricity at market prices in the short-term and re-evaluate in the future the option to repower or recontract the asset.
Chile PV 1, Chile PV 2 and Chile PV 3
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 and storage in Chile and sign PPAs with credit-worthy off-takers.
Overview. Chile PV 1, Chile PV 2 and Chile PV 3 are three solar plants with 55 MW, 40 MW, and 73 MW, respectively. Chile PV 1 reached COD in May 2016, Chile PV 2 reached COD in August 2017 and Chile PV 3 reached COD in December 2014.
PPA. Chile PV 1 and Chile PV 3 sell their production to the Chilean power market. Chile PV 2 has PPAs signed for part of its production.
O&M. Chile PV 1, Chile PV 2 and Chile PV 3 have O&M agreements with third parties.
Project Level Financing. Two of the three assets have long-term project finance agreements in place in U.S. dollars, with a total outstanding balance of $70.9 million as of December 31, 2023. Payments are made semi-annually. The debt agreements bear interest based on six-month SOFR 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.
Due to low electricity prices in Chile, the project debts of Chile PV 1 and 2 are under an event of default as of December 31, 2023 and as of the date of this report. Chile PV 1 was not able to maintain the minimum required cash in its debt service reserve account as of December 31, 2023 and did not make its debt service payment in January. In addition, in October 2023, Chile PV 2 did not make its debt service payment. This asset obtained additional financing from the banks and made the debt service payment in December, although it was not able to fund its debt service reserve account subsequently. As a result, although we do not expect an acceleration of the debt to be declared by the credit entities, as of December 31, 2023 Chile PV 1 and 2 did not have an unconditional right to defer the settlement of the debt for at least twelve months and the project debt was classified as current in our Annual Consolidated Financial Statements. We are in conversations with the banks, together with our partner, regarding a potential waiver. Impairments were recorded in these assets in 2023 and 2022. The value of the net assets contributed by Chile PV 1&2 to the Annual Consolidated Financial Statements, excluding non-controlling interest, was close to zero as of December 31, 2023.
La Sierpe
Overview. La Sierpe is a 20 MW solar PV plant in Colombia, wholly owned by us, which reached COD in October 2021.
PPA. La Sierpe has a 15-year, fixed-price PPA in local currency with Coenersa, 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.
O&M. We perform O&M for La Sierpe with our own personnel.
Project Level Financing. The asset has no project finance debt.
La Tolua
Overview. La Tolua is a 20 MW solar PV asset in Colombia, wholly owned by us.
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PPA. The asset has a 10-year PPA (commencing on COD) in local currency with Coenersa, 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.
O&M. We perform O&M for La Tolua with our own personnel.
Project Level Financing. The asset has no project finance debt.
Tierra Linda
Overview. Tierra Linda is a 10 MW solar PV asset in Colombia, wholly owned by us.
PPA. The asset has a 10-year PPA (commencing on COD) in local currency with Coenersa, 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.
O&M. We perform O&M for Tierra Linda with our own personnel.
Project Level Financing. The asset has no project finance debt.
Honda 1
Overview. Honda 1 is a 10 MW solar PV asset in Colombia, 50% owned by us, which reached COD in December 2023.
PPA. The asset has a 7-year PPA commencing on COD in local currency with Enel Colombia. The PPA provides for the sale of electricity at a fixed base price indexed to local Consumer Price Index.
O&M. Honda 1 has an O&M agreement in place with a third party.
Project Level Financing. The asset has no project finance debt.
Albisu
Overview. Albisu is a 10 MW solar PV asset near the city of Salto, in Uruguay, wholly owned by us, which reached COD in January 2023.
PPA. The asset has a 15-year PPA, for approximately 60% of the plant’s capacity, starting in July 2023, with Montevideo Refrescos, S.R.L, a subsidiary of Coca-Cola FEMSA, S.A.B. de C.V. The PPA is denominated in local currency with a maximum and minimum price in U.S. dollars and is adjusted monthly based on a formula referring to U.S. Producer Price Index (PPI), Uruguay’s Consumer Price Index (CPI) and the applicable UYU/U.S. dollar exchange rate.
O&M. The O&M services are performed by a third party.
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 Tacuarembó, 170 miles north of the city of Montevideo, Uruguay. Palmatir has 25 wind turbines supplied by Siemens, and each turbine has a 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 is partially adjusted annually based on a formula referring to U.S. PPI, Uruguay’s PPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have wind turbines O&M agreement with Siemens that covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services.
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Project Level Financing. On April 11, 2013, Palmatir entered into a financing agreement for a U.S. dollar-denominated 19-year loan in two tranches in connection with this project. This financing agreement was subsequently amended to, among others, add an additional tranche. The first tranche is a $73 million loan with a fixed interest rate of 3.16%. The second tranche is a $33 million loan with a fixed interest rate of 6.35%. The third tranche is a $6.6 million loan with a floating interest rate of six-month U.S. adjusted term SOFR plus 4.13%. The combined outstanding balance of the three tranches as of December 31, 2023 was $66.3 million. The financing arrangements of the plant permits cash distributions to shareholders once per year subject to, among other things, a historical debt service coverage ratio for the previous twelve-month period of at least 1.25x and a projected debt service coverage ratio of at least 1.30x for the following twelve-month period.
Cadonal
Overview. Cadonal is an onshore, 50 MW wind farm facility wholly owned by us, located in Flores, 105 miles north of the city of Montevideo, Uruguay. Cadonal has 25 wind turbines of 2 MW each which were supplied by Siemens. 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. PPI, Uruguay’s PPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have wind turbines O&M agreement with Siemens that covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services.
Project Level Financing. In June 2020 we refinanced Cadonal’s debt for a total amount of $77.6 million and in March 2022 we prepaid $12.3 million, resulting in a loan principal comprised of:

| − | Tranche A: $29.7 million loan with maturity in 2034 and a floating interest rate of six-month adjusted term SOFR plus 2.9%, 81% hedged with a swap set at approximately 3.29% strike.

| − | Tranche B: $21.1 million loan with maturity in 2032 and a floating interest rate of six-month adjusted term SOFR plus 2.65%, 99% hedged with a swap set at approximately 3.16% strike.

The combined outstanding balance of these two tranches as of December 31, 2023 was $44.3 million.
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.
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 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 every year based on a formula referring to U.S. PPI, Uruguay’s PPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have a wind turbines 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 adjusted term SOFR 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. Adjusted term SOFR exposure was 75% hedged with a swap at a rate of 3.26% with the financing bank. As of December 31, 2023, the outstanding balance of the loan was $66.0 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 Peruvian Ministry of Energy and Mines and the price is adjusted annually in accordance with the U.S. Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor.
O&M. We perform O&M for Mini-hydro Peru with our own personnel.
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 PS 10 & 20 (which is a 31 MW solar power complex). Except for PS 10 & PS 20 and Seville 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. Since March 2023, we perform the O&M services with our own personnel for all solar assets in Spain.
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 June and October 2012, respectively.
O&M. We perform O&M for Solaben 2 & 3 with our own personnel.
Project Level Financing. In March 2023 we refinanced Solaben 2&3. We entered into two green senior euro-denominated loan agreements for the two assets with a syndicate of banks for a total amount of €198.0 million. The new project debt replaced the previous project loans and maturity was extended from December 2030 to June 2037. The interest on the loans accrues at a rate per annum equal to the sum of six-month EURIBOR plus a margin of 1.50% between 2023 and June 2028, 1.60% between June 2028 and June 2033 and 1.70% from June 2033 onwards. The principal is 90% hedged for the life of the loan through a combination of the following instruments:

| − | a pre-existing cap with a 1.0% strike with notional of €115.1 million starting in March 2023 and decreasing over time until December 2025

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| − | a swap with a 3.16% strike with initial notional of €64.9 million starting in March 2023. The notional increases progressively until June 2026 and decreases progressively thereafter until maturity to ensure that the principal hedged stays at 90% over the life of the loan

The financing agreement also includes a mechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a reserve account should be established and funded on a six-month rolling basis for the additional revenue arising from the difference between actual prices and prices defined in the agreement. Under certain conditions, such amounts, if any, should be used for early prepayments upon regulatory parameters changes.
The total outstanding balance of these loans as of December 31, 2023 was $202.9 million for both Solaben 2 and Solaben 3. The financing arrangements permit cash distributions 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. The Green Project Finance is guaranteed by the shares of Logrosan and its lenders have no recourse to Atlantica corporate level.
In June 2023 we extended the maturity of the debt from April 2025 to December 2028. The facility had an initial notional of €140 million of which approximately 37% is amortized between the signing date and maturity. The outstanding balance of this facility as of December 31, 2023, was $118.2 million, of which €23.2 million is progressively amortized with a two-year grace period and the remaining €87.8 million is expected to be refinanced at maturity.
The interest on the loans accrues at a rate per annum equal to the sum of six-month EURIBOR plus a margin of 3.25%. The principal is 100% hedged for the life of the loan through a combination of the following instruments:

| − | a pre-existing cap with a 0% strike with notional of €115.9 million starting by June 2023 and decreasing over time until December 2025.

| − | a cap with a 3.5% strike with initial notional of €2.5 million starting in June 2023. The notional increases progressively until June 2025 up to €110.9 million and decreases progressively thereafter until maturity to ensure that the principal hedged stays at 100% over the life of the loan.

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.
The financing agreement also includes a mechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a reserve account should be established and funded on a six-month rolling basis for the additional revenue arising from the difference between actual prices and prices defined in the agreement. Under certain conditions, such amounts, if any, should be used for early prepayments upon regulatory parameters changes.
Solacor 1 & 2
Overview. Solacor 1 & 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 February and March 2012, respectively.
O&M. We perform O&M for Solacor 1 & 2 with our own personnel since March 2023.
Project Level Financing. In October 2022, we refinanced Solacor 1 & 2 project debt. The new financing is a green euro-denominated loan with a syndicate of banks for a total amount of €205.0 million with maturity in 2037. Interest accrue at a rate per annum equal to the sum of six-month EURIBOR plus a margin of 1.50% between 2022-2027, 1.60% between 2027-2032 and 1.70% between 2032-2037. We hedged our EURIBOR exposure:
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| − | 71% through a swap set at 2.36% for the life of the financing.

| − | 19% by maintaining the existing 1% strike caps with maturity in 2025.

The total outstanding balance of this loan as of December 31, 2023 was $209.4 million. This financing arrangement permits cash distribution to shareholders twice per year if the debt service coverage ratio is at least 1.15x.
The financing agreement also includes a mechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a reserve account should be established and funded on a six-month rolling basis for the additional revenue arising from the difference between actual prices and prices defined in the agreement. Under certain conditions, such amounts, if any, should be used for early prepayments every six months.
PS 10 & 20
Overview. PS 10 & 20 is a 31 MW solar complex wholly owned by us located in Andalusia, Spain. PS 10 reached COD in 2007 and PS 20 reached COD in 2009.
O&M. We perform O&M for PS 10 & 20 with our own personnel since March 2023.
Project Level Financing. The asset has no project finance debt. In November 2022, we repaid in full the project finance that was in place for PS 20.
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 March and June 2012, respectively.
O&M. We perform O&M for Helios 1 & 2 with our own personnel since March 2023.
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 ($359.4 million approximately). The notes were issued on July 23, 2020 and have a 17-year maturity. Interest accrues at a fixed rate per annum equal to 1.90%. Debt repayment is semi-annual over the 17-year tenor of the debt. The outstanding balance of the debt as of December 31, 2023 was $279.6 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 April and August 2011, respectively.
O&M. We perform O&M for Helioenergy 1 & 2 with our own personnel.
Project Level Financing. On June 26, 2018, Helioenergy 1 & 2 entered into:

− | a 15-year loan agreement of €218.5 million with a syndicate of banks. The interest rate for the loans is a floating rate based on six-month EURIBOR plus a margin of 2.25% until December 2025 and 2.50% until maturity. The banking tranche is 95.5% hedged through a swap set at approximately 3.8% strike and 3% hedged through a cap with a 1% strike.

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

The outstanding balance of these loans as of December 31, 2023 was $235.0 million. The financing arrangements permit cash distributions to shareholders semi-annually based on a debt service coverage ratio of at least 1.15x.
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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 February, June, and July 2010, respectively.
O&M. We perform O&M for Solnova 1, 3 & 4 with our own personnel since March 2023.
Project Level Financing. In December 2022 we refinanced Solnova 1, 3 & 4. We entered into a green senior euro-denominated loan agreement for the three assets with a syndicate of banks for a total amount of €338.5 million. The new project debt replaced the previous three project loans and maturity was extended from 2029 and 2030 to June 2035.
The interest rate for the loan accrues at a rate per annum equal to the sum of six-month EURIBOR plus a margin of 1.50% between 2023 and 2027, 1.65% between 2028 and 2032 and 1.80% from 2033 onwards. The principal is 90% hedged for the life of the loan through a combination of the following instruments:

− | a swap with a 3.23% strike with initial notional of €170.3 million starting in December 2022 and decreasing over time until maturity.

− | a cap with a 1.0% strike with initial notional of €134.2 million starting in December 2022 and decreasing over time until December 2025.

− | a cap with a 2.0% strike with initial notional of €64.9 million starting June 2026 and decreasing over time until December 2030.

The financing agreement also includes a mechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a reserve account should be established and funded on a six-month rolling basis for the additional revenue arising from the difference between actual prices and prices defined in the agreement. Under certain conditions, such amounts, if any, should be used for early prepayments upon regulatory parameters changes.
As of December 31, 2023, the outstanding balance of this loan was $338.1 million. The financing arrangement permits cash distributions to shareholders twice per year if the debt service coverage ratio is at least 1.10x from 2023 to 2032 and 1.15x from 2032 onwards.
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 September and October 2013, respectively.
O&M. We perform O&M for Solaben 1 & 6 with our own personnel.
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 with maturity in December 2034. The bonds have a coupon of 3.76% 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 balance as of December 31, 2023 was $179.7 million. The bonds permit cash distributions to shareholders twice per year if the debt service coverage ratio is at least 1.65x.
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. We perform O&M for Seville PV with our own personnel.
Project Level Financing. Seville PV does not have any project level financing.
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Italy PV 1, 2, 3 & 4
Overview. We own 7 PV assets in Italy which have a combined capacity of 9.8 MW. Italy PV 1 is a 1.6 MW solar PV plant which reached COD in December 2010. Italy PV 2 is a 2.1 MW solar PV plant which reached COD in April 2011. Italy PV 3 is a portfolio of 4 PV assets with a total capacity of 2.5 MW which reached COD between March and May 2012. Italy PV 4 is a 3.6 MW solar PV plant which reached COD in July 2011.
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 $2.7 million as of December 31, 2023.

− | In June 2011, Italy PV 1 entered into a 15-year loan agreement for €6.0 million with maturity in 2026. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin of 1.30%. As of December 31, 2023, the outstanding balance of this loan was $1.1 million.

− | In July 2016, Italy PV 3 entered into a 10-year loan agreement for €1.2 million with maturity in 2026. The interest rate for the loan is a fixed rate of 3.80%. As of December 31, 2023, the outstanding balance of this loan was $0.4 million.

− | In March 2022, Italy PV 4 entered into a 10-year loan agreement for €1.3 million with maturity also in 2031. The interest rate for the loan is a fixed rate of 1.00%. As of December 31, 2023, the outstanding balance of this loan was $1.2 million.

These financing arrangements permit dividend distributions any time throughout the year and regardless of any minimum debt service coverage ratios.
Kaxu
Overview. Kaxu is a 100 MW solar plant located in Pofadder, Northern Cape Province, South Africa. The project company is currently 51% owned by Atlantica South Africa (Pty) Ltd, which we fully own, while the remaining is owned by 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. In addition, Kaxu has a molten salt thermal energy storage system. The asset reached COD in January 2015.
PPA. Kaxu has a 20-year PPA with Eskom, under a take-or-pay contract for the purchase of electricity up to the contracted capacity of 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 Republic of South Africa. Eskom has recently announced a legal separation of the company into three entities. After this separation, Kaxu’s off-taker will be the National Transmission Company of South Africa. Eskom’s payment guarantees are underwritten by the South African Department of Mineral Resources and Energy, under the terms of an implementation agreement. Eskom’s credit ratings are currently B from S&P, B2 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 policy with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $47 million as of December 31, 2023, in the event of the South African Department of Mineral Resources and Energy not complying with its obligations as guarantor. This insurance policy does not cover credit risk.
O&M. We perform O&M for Kaxu with our own personnel.
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Operations. In the third quarter of 2023, a scheduled turbine major overhaul was carried out by Siemens, the original equipment manufacturer and took approximately 30 days longer than expected. After re-starting production, at the end of September, a problem was found in the turbine, likely related to the major overhaul. The plant restarted operations in mid-February 2024. Part of the damage and the business interruption is covered by our insurance property policy, after a 60-day deductible.
Additionally, in June 2023 we executed an EPC heat exchanger performance bond at Kaxu for approximately $11 million, as we believe that the conditions were met. The EPC supplier has informed us that they intend to start an arbitration process. The cash received in connection with such bond has been recorded as a deferred income and is expected to be used for repairs at the asset.
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 hedged interest rate exposure was 58% until 2023, decreasing to 43% from 2024 onwards. Current effective annual interest rate in rands is approximately 11.5% considering the hedge in place. As of December 31, 2023, the outstanding balance of these loans was ZAR 4,294 million, or $233.9 million and the financing was not in default.
The financing arrangement permits dividend distributions on a semi-annual basis after the first repayment of debt has occurred, provided that the historical and projected debt service coverage ratios are 1.20x or above.
Efficient Natural Gas and Heat
Calgary District Heating
Overview. Calgary is a 55MWt district heating facility, consisting of 55MWt natural gas boilers and 3.3 MWe Combined Heat and Power unit, located in the city of Calgary in Alberta, Canada which reached COD in 2010. Calgary District Heating is a wholly owned subsidiary of Atlantica.
Thermal Off-take Agreements. The asset has capacity-based thermal heat revenue with inflation indexation, investment grade off-takers and 12-year average contract life remaining. Contracted capacity and pass-through volume payments represent approximately 65% of the total revenue.
O&M. We perform O&M for Calgary District Heating with our own personnel.
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., (“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 20 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.
We have experienced delays in collections from Pemex, especially since the second half of 2019, which have been significant in certain quarters, including in the fourth quarter of 2023.
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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.
Project Level Financing. In December 2013 ACT Energy Mexico entered into a $660.0 million senior loan agreement with a syndicate of banks. In March 2014, after the loan’s first repayment, additional banks entered the syndicate, leading to a $655.4 million senior loan with two tranches. In 2023, Tranche 1 was fully repaid and the outstanding balance consisted of an original $450.0 million loan with an 18-year maturity. The interest rate is a floating rate based on SOFR plus a 3-month standard adjustment plus a margin of 3.75%. The loan is 75% hedged at a weighted average rate of 4.01%.
The outstanding balance of as of December 31, 2023 was $401.5 million. The senior loan agreement permits cash distributions to shareholders provided that the debt service coverage ratio is at least 1.20x.
Monterrey
Overview. Monterrey is a 142 MW gas-fired engine facility including 130 MW installed capacity and 12 MW battery capacity. We own 30% of Monterrey through Pemcorp S.A.P.I. de C.V., while Arroyo Energy owns the remaining 70%. The asset is located in Mexico and reached COD in the third quarter of 2018. The power plant is configured with seven Wärtsilä natural gas internal combustion engines.
In 2023, our partner in Monterrey initiated a process to sell its 70% stake in the asset. Such process is well advanced and, as part of it, we intend to sell our interest as well under the same terms. The net proceeds to Atlantica are expected to be in the range of $45 to $52 million, after tax. The transaction is subject to certain conditions precedent and final transaction closing. We cannot guarantee that the transaction will finally close.
PPA. It is a U.S. dollar-denominated PPA with two international large corporations engaged in the car manufacturing industry. The PPA had originally a 20-year term starting at COD. In May 2022, together with our partner, we entered into a 7.5-year PPA extension with the same off-takers, such that the PPA now ends in 2046. The extension involves an investment, which has been largely made as of December 31, 2023, to achieve certain improvements in the asset to provide, among other things, additional battery capacity and additional redundancy of electric power supply. The PPA includes price escalation factors. The asset also has a 20-year contract for the natural gas transportation. It has limited commodity risk since a majority of the gas cost is a pass-through to our clients.
O&M. Wärtsilä performs the O&M for Monterrey under a contract renewed in 2020 for five years. 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 $155.7 million outstanding balance as of December 31, 2023, which matures in September 2027. The interest rate of the loan is a floating rate based on the Adjusted Daily Simple SOFR plus a margin of 2.75% with a 0.25% increase after the third anniversary (September 2023) and another 0.25% increase after the sixth anniversary (September 2026). The variable interest rate exposure was 85% hedged with a swap rate of 2.11% 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 and Mines, 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 and Mines upon termination of the initial concession agreement.
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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 Foods 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, ATN Expansion 1 has a 15-year Transmission Service Agreement (“TSA”) and ATN Expansion 2 has two 20-year TSAs and one 30-year TSA denominated in U.S. dollars.
O&M. We perform O&M for ATN with our own personnel since July 2023.
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.

− | 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, 2023, the outstanding balance of this loan was $81.6 million. 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-mile 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 and Mines 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 Foods 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 an O&M agreement with Omega Peru that we can terminate every three years (or every two years under certain circumstances).
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, 2023, $384.6 million was outstanding. The project bond agreement permits cash distributions every six months subject to a debt service coverage ratio for both the 12 month period previous to and following the distribution of at least 1.20x.
ATN 2
Overview. ATN 2 is an 81 miles transmission line located in Peru wholly owned by us, which is part of the Complementary Transmission System. ATN 2 reached COD in June 2015.
ATN 2 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 Foods 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 ATN 2.
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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%).
O&M. ATN 2 has an O&M agreement with Omega Peru that we can terminate every three years (or every two years under certain circumstances).
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, 2023, the outstanding balance of the ATN 2 project loan was $40.7 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 line 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 December 2013 and January 2014, respectively.
Concession Agreement. Both projects have concession agreements with the Sierra Gorda SCM mining company, which is owned by KGHM Polska Mietz and South32 Limited. 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 contract expiring in 2027 and at Quadra 2 under a contract expiring in 2029 with an option to renew each O&M agreement for five additional years. Maintenance services at Quadra 1 and Quadra 2 are performed by a group of tier-1 suppliers.
Project Level Financing. In June 2019, we refinanced the project debt of our Chilean assets Palmucho, Chile TL 3, Quadra 1 and Quadra 2. This financing agreement consists of a single loan agreement for all these assets for an original 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 SOFR 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, 2023, the outstanding balance was $52.9 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
Overview. 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 Energysur.
Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.
Chile TL 3
Overview. Chile TL 3 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.
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O&M. We perform O&M for Chile TL 3 with our own personnel. Energysur performs maintenance services under a three-year contract expiring on January 1, 2025.
Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.
Chile TL 4
Overview. Chile TL 4 is a 63-mile transmission line in operation in Chile which reached COD in 2016. The asset has fully contracted revenues in U.S. 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 asset has O&M agreements with third parties.
Project Level Financing. Chile TL 4 does not have any project level financing.
Water
Honaine
Overview. Honaine is a water desalination plant of 7 M ft3 per day capacity located in Taffsout, Algeria. We indirectly own 25.5% through Myah Bahr Honaine Spa (“MBH”), Algerian Energy Company, or AEC, owns 49% and Sacyr owns the remaining 25.5% of Honaine.
Honaine reached COD in July 2012. AEC is the Algerian agency in charge of delivering Algeria’s large-scale desalination program. The technology used in the Honaine plant consists of desalination using membranes by reverse osmosis.
Concession Agreement. The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/Algerienne des Eaux, or ADE, from COD. The tariff structure is based upon plant capacity. 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 25-year contract from COD with a specialized O&M supplier.
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, 2023, the outstanding balance of the Honaine project loan was $35.6 million. The financing arrangement permits cash distributions 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, (“ADS”), AEC owns 49% and Sacyr owns the remaining 16.8%. We own a 67% of the holding company which in turns has a 51% equity stake in Skikda, as a result we fully consolidate the asset.
Skikda reached COD in 2009 and uses the same technology as Honaine.
Concession Agreement. The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/ADE from COD. The tariff structure is based upon plant capacity. 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 specialized O&M supplier.
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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, 2023, the outstanding balance of the Skikda project loan was $2.6 million. The financing arrangement permits cash distributions 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.
Since January 2019, we have an investment in Befesa Agua Tenes, the owner of 51.0% stake 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 a majority of directors at the board of directors of Befesa Agua Tenes. Therefore, through the loan and these decision rights, 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 COD. The tariff structure is based upon plant capacity. 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 a company owned by 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, 2023, the outstanding balance of the Tenes project loan was $73.7 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.
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Assets under construction
We currently have the following assets under construction or ready to start construction in the short-term:

Asset | Type | Location | Capacity (gross)(1) | Expected COD | Expected Investment(3) ($ million) | Off-taker
Coso Batteries 1 | Battery Storage | California, US | 100 MWh | 2025 | 40-50 | Investment grade utility
Coso Batteries 2 | Battery Storage | California, US | 80 MWh | 2025 | 35-45 | Investment grade utility
Chile PMGD(2) | Solar PV | Chile | 80 MW | 2024-2025 | 30 | Regulated
ATN Expansion 3 | Transmission Line | Peru | 2.4 miles 220kV | 2024 | 12 | Conelsur
ATS Expansion 1 | Transmission Line | Peru | n.a. (substation) | 2025 | 30 | Republic of Peru
Honda 2(4) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | Enel Colombia
Apulo 1(4) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | -

Notes:

(1) | Includes nominal capacity on a 100% basis, not considering Atlantica’s ownership.

(2) | Atlantica owns 49% of the shares, with joint control, in Chile PMGD. Atlantica’s economic rights are expected to be approximately 70%.

(3) | Corresponds to the expected investment by Atlantica.

(4) | Atlantica owns 50% of the shares in Honda 2 and Apulo 1.

• | In October 2023, we entered into two 15-year tolling agreements (PPAs) with an investment grade utility for Coso Batteries 1 and Coso Batteries 2. Under each of the tolling agreements, Coso Batteries 1 and 2 will receive fixed monthly payments adjusted by the financial settlement of CAISO’s Day-Ahead market. In addition, we expect to obtain revenue from ancillary services in each of the asset.

Coso Batteries 1 is a standalone battery storage project of 100 MWh (4 hours) capacity located inside Coso, our geothermal asset in California. Additionally, Coso Batteries 2 is a standalone battery storage project with 80 MWh (4 hours) capacity also located inside Coso. Our investment is expected to be in the range of $40 million to $50 million for Coso Batteries 1, and in the range of $35 to $45 million for Coso Batteries 2. Both projects were fully developed in-house and are now under construction. We have closed a contract with Tesla for the procurement of the batteries. COD is expected in 2025 for both projects.

• | In November 2022, we closed the acquisition of a 49% interest, with joint control, in an 80 MW portfolio of solar PV projects in Chile which is currently under construction (Chile PMGD). Our economic rights are expected to be approximately 70%. Total investment in equity and preferred equity is expected to be approximately $30 million and COD is expected to be progressive in 2024 and 2025. Revenue for these assets is regulated under the Small Distributed Generation Means Regulation Regime (“PMGD”) for projects with a capacity equal or lower than 9 MW which allows to sell electricity at a stabilized price.

• | In July 2022 we closed a 17-year transmission service agreement denominated in U.S. dollars that will allow us to build a substation and a 2.4-mile transmission line connected to our ATN transmission line serving a new mine in Peru (ATN Expansion 3). The substation is expected to enter in operation in 2024 and the investment is expected to be approximately $12 million.

• | In July 2023, as part of the New Transmission Plan Update in Peru, the Ministry of Energy and Mines published the Ministerial Resolution that enables to start construction of our ATS Expansion 1 project, consisting in the reinforcement of two existing substation with new equipment. The expansion will be part of our existing concession contract, a 30-year contract with a fixed-price tariff base denominated in U.S. dollars adjusted annually in accordance with the U.S. Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor. Given that the concession ends in 2044, we will be compensated with a one-time payment for the remaining 9 years of concession. The expansion is expected to enter in operation in 2025 and the investment is expected to be approximately $30 million.

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• | In May 2022, we agreed to develop and construct Honda 1 and 2, two PV assets in Colombia with a combined capacity of 20 MW where we have a 50% ownership. Each plant has a 7-year PPA with Enel Colombia. Our investment is expected to be $5.5 million for each plant. Honda 1 entered in operation in December 2023 and Honda 2 is expected to enter into operation in the second quarter of 2024.

Development Pipeline
We are developing new projects in most of our core geographies. In some cases, we do this with our local in-house teams and in other cases we have been working with local partners with whom we jointly invest in developing projects or with whom we have agreements based on milestones.
By focusing our development activities on locations where we already have assets in operation and by working in many cases with partners, we have been able to maintain our development cost at what we believe are low levels.
We currently have a pipeline of assets under development, including both repowering or expansion opportunities of existing assets and greenfield development, of approximately 2.2 GW7 of renewable energy and 6.0 GWh8 of storage. Approximately 47% of the projects are PV, 41% storage, 11% wind and 1% others, while 22% of the projects are expected to reach ready to build (“Rtb”) in 2024 or 2025, 28% are in an advanced development stage and 50% are in early stage. Also, 20% corresponds to expansion or repower opportunities of existing assets and 80% to greenfield developments.

| Renewable Energy (GW)8 | Storage (GWh)8
North America | 1.2 | 4.3
Europe | 0.4 | 1.6
South America | 0.6 | 0.1
Total | 2.2 | 6.0

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, Chile (Chile TL 3) and Italy. Chile PV 1, Chile PV 3 and Lone Star II, which represent less than 1% of our Adjusted EBITDA for the year 2023, sell 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.

8 Only includes projects estimated to be ready to build before or in 2030 of approximately 3.7 GW, 2.2 GW of renewable energy and 1.5 GW of storage (equivalent to 6.0 GWh). Capacity measured by multiplying the size of each project by Atlantica’s ownership. Potential expansions of transmission lines not included.
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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 and transmission lines are all capital-intensive with numerous industry participants. We compete based on the location of our assets in various countries and regions; however, because most of 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 develop or acquire new projects with developers, independent power producers and financial investors, including pension funds and infrastructure funds and other dividend growth-oriented companies, as well as utilities and oil and gas companies which are targeting to have a presence in renewables. 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.”
Environmental and Social Information
Environment
Environmental management is a key priority in our business and operations. Our facilities and operations are subject to significant government regulation, including stringent and comprehensive federal, provincial and local laws, statutes, regulations, guidelines, policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; storage, handling, use, disposal, transportation and distribution of dangerous materials and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the presence and remediation of hazardous materials in soil and groundwater, both on and offsite; the protection of natural resources; land use and zoning matters; and workers’ health and safety matters. We consider environmental protection as an area of performance and as such, environmental issues are included among the responsibilities of our key executives.
Employees
As of December 31, 2023, we had 1,366 employees. Following the internalization of the operations and maintenance services in our solar assets in the United States in 2019, in South Africa in 2022 and in our solar assets in Spain also in 2022 and 2023, part of the recently hired employees of the relevant O&M companies belong to previously existing labor unions. We believe that the relationship between the Company and its labor union is good. We have not experienced any strikes or work stoppages among our workforce. One of our plants has experienced strikes by employees working for one of our operation and maintenance suppliers in the past.
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Health & Safety
Among 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 ISO 45001 standard requirements. Our ISO 45001 certification is valid until 2024. The external audit is carried out by an independent third party. 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 2023:

− | 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 2023 at 0.9, compared to 1.0 in 2022.

− | 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 2023 at 0.4, compared to 0.6 in 2022.

TRIR and LTIR decreased in 2023 compared to the previous year mainly due to a decrease in the number of accidents with leave at our assets under construction, which were a top priority during the year. In 2024, we will maintain our focus on developing best practices in our assets under construction, working closely with our construction suppliers, while we maintain or improve our ratios in assets in operation.
Operation and Maintenance
We currently perform internally the O&M for a majority of our assets. In March 2023, we completed the process of transitioning O&M services for the assets in Spain where Abengoa was still the supplier to an Atlantica subsidiary. Additionally, since July 2023 we perform O&M for ATN with our own personnel. After these transfers, we perform the O&M services with our own personnel for assets representing approximately 74% of the consolidated revenue in 2023.
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.
Intellectual Property
We refer to “Item 5-Operating and Financial Review and Prospects-C. Research and Development” for a summary of the extent to which the Company is dependent on patents and licenses.
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.
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In addition, during 2021 and 2022, 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 II, 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.
Except as described above, Atlantica is not a party to any other significant legal proceedings other than legal proceedings (including administrative and regulatory proceedings) arising in the ordinary course of its business. Atlantica is party to various administrative and regulatory proceedings that have arisen in the ordinary course of business.
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 FERC and through other federal agencies, and certain environmental, health and safety matters. State and local governments regulate the siting, permitting, construction and operation of power generation facilities, the retail sale of electricity and certain other environmental, health, safety and permitting matters.
United States Federal Regulation of the Power Generation Facilities and Electric Transmission
The United States federal government regulates the wholesale sale of electric power and the transmission of electricity in interstate commerce through FERC, which draws its jurisdiction from the FPA, as amended, and from other federal legislation.
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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.
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 the 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.
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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.
Inflation Reduction Act
On August 16, 2022, U.S. President Biden signed into law the U.S. Inflation Reduction Act (IRA). The provisions of the IRA are intended to, among other things, incentivize clean energy investment, clean energy production and manufacturing of necessary components. The IRA includes, among other incentives, (i) the expansion and extension of ITCs to 30% (subject to satisfying the eligibility requirements under the IRA) for solar projects to be built until 2032, (ii) the expansion and extension of PTCs for wind projects to be built until 2032, (iii) a 30% ITC (subject to satisfying the eligibility requirements under the IRA) for standalone storage projects to be built until 2032, (iv) a new tax credit that will award up to $3/kg for low carbon hydrogen and a three-year extension and modification of PTCs for facilities that begin construction before December 31, 2024, and (v) the increase in total funds available for the U.S. Department of Energy’s Title 17 loan guarantee program by $3.6 billion, bringing the total to $40 billion. The IRA also includes transferability options for the ITCs and PTCs, which is intended to allow for an easier and faster monetization of these tax credits. Such credits will reduce the cost of renewable investments in the U.S. to developers.
We expect to claim ITCs or any other tax credits or benefits available under IRA for the projects currently under development and construction in the U.S. and for any other qualifying project that we develop and start construction in the U.S.
In determining ITC eligibility, we will rely upon applicable tax law and published IRS guidance. However, the application of law and guidance regarding ITC eligibility to the facts of particular solar energy and standalone storage projects is subject to a number of uncertainties, in particular with respect to the new IRA provisions for which Department of Treasury regulations (“Treasury Regulations”) are being developed and implemented, and there can be no assurance that the IRS will agree with our approach in the event of an audit. The Department of Treasury is expected to issue Treasury Regulations and additional guidance with respect to the application of the newly enacted IRA provisions, and the IRS and Department of Treasury may modify existing guidance, possibly with retroactive effect. Any of the foregoing could reduce the amount of ITCs or, if applicable, PTCs available to us. In this event, we could be required to seek alternative sources of funding for solar energy projects, which could have a material adverse effect on our business, financial condition, results of operations and prospects.
The ITC and PTC amount can be increased if certain domestic content requirements are satisfied or if a project is located in (i) an “energy community” or (ii) low-income community, each as defined in the IRA.
The full impact of the IRA cannot be known with certainty. However it is expected that, many of these provisions will reduce the cost of renewable investments in the U.S. due to the extensions and expansions of tax credits.
Trade Restrictions and Supply Chain
UFLPA
On December 23, 2021, U.S. President Biden signed into law the Uyghur Forced Labor Prevention Act (the “UFLPA”), which creates forced labor-related import restrictions that took effect on June 21, 2022 and seeks to block the import of products made with forced labor in certain areas of China. This may lead to certain suppliers being blocked from importing solar cells and panels to the U.S. While our assets and projects to start construction in the U.S. have not been impacted, further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements or to continue to supply cells or panels into the U.S. market on terms that we deem satisfactory.
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We cannot currently predict what, if any, impact the UFLPA will have on the overall supply of solar panels into the U.S. and the related timing and cost of solar projects, future disruption and their effect on U.S solar project development and construction activities are uncertain. As of the date of this annual report, there continues to be uncertainty in the market around achieving full compliance with UFLPA, whether related to sufficient traceability of materials or other factors.
AD/CVD
In August 2021, a group of anonymous domestic solar manufacturers filed a petition (“AD/CVD”) with the U.S. Department of Commerce (“DOC”) seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claimed that Chinese solar manufacturers were shifting products to these countries to avoid the tariffs required on products imported from China. In November 2021, the DOC rejected this petition. In denying the petition, the DOC cited the anonymous group’s refusal of the DOC’s request to provide more detail and identify its members due to concerns about retribution from the dominant Chinese solar industry.
In February 2022, a California based company filed an AD/CVD petition with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia. While the petition is similar to the one rejected by the DOC in November 2021, there are notable differences. The group added Cambodia to the petition and is requesting that the DOC conduct a country-wide inquiry into each of the four countries. In March 2022, the DOC decided to act on the February petition and investigate the claim. On August 18, 2023, the DOC issued its final affirmative determinations that solar cells and modules completed in Cambodia, Malaysia, Thailand, or Vietnam using certain specified components from China, and exported to the United States, are circumventing the antidumping duty and countervailing duty orders on solar cells, whether or not assembled into modules, from China. However, in June 2022, the U.S. Administration used its executive powers to issue a 24-month tariff moratorium on solar panels manufactured in Cambodia, Malaysia, Thailand, and Vietnam. The moratorium came as a direct response to concerns raised about the adverse impact from the ongoing DOC complaint on the U.S. solar industry. U.S. companies will be exempt from any retroactive tariffs that previously could have applied, but companies may still be subject to tariffs after the moratorium ends. The U.S. Administration also announced that it plans to invoke the Defense Production Act to accelerate the production of solar panels in the U.S. While this moratorium was introduced to stay in force until June 6, 2024, the existence of such petitions and possibility of further petitions and investigations create uncertainty related to the supply of solar modules, which can negatively impact the global solar market and the timing and viability of solar projects in our development pipeline.
If the investigation results in additional taxes, tariffs, duties, or other assessments on renewable energy or the equipment necessary to generate or deliver it, such as antidumping and countervailing duty rates, such developments could result in, among other items, lack of a satisfactory market for the development and/or financing of our U.S. renewable energy projects, abandonment of the development of certain U.S. renewable energy projects, a loss of our investments in projects in the U.S., and/or reduced project returns.
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 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.
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Arizona
The Arizona Corporation Commission 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.
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, (“CPUC”), governs, among other entities, California’s investor-owned utilities, including Pacific Gas & Electric Company. 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 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.
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Notwithstanding the foregoing, private entities were allowed to participate in the following activities not considered public utility services, as defined by the aforementioned law:

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

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

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

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

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

• | 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 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.
On December 3, 2021, the Mexican Energy regulatory Commission (Comisión Reguladora de la Energía), or CRE published Decree number A/037/2021, by 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 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.
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.
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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.
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.
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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.
Energy Regulators
By means of Agreement A/023/2023, published in the Official Federal Gazette on July 20, 2023, the CRE nullified Agreements (i) A/001/2021, which established the suspension of legal terms and deadlines as a measure to prevent and combat the spread of the COVID-19 and (ii) A/004/2023, which restored legal terms and deadlines in an orderly and staggered manner.
Therefore, the above is beneficial for the energy sector since the legal terms and deadlines before the CRE will be complied with in accordance with the applicable laws. However, Agreement A/023/2023 does not guarantee that the CRE will comply with its legal obligations, thus, if the CRE fails to comply, individuals may appeal to legal mechanisms to defend their interests.
Likewise, the Energy Ministry, by means of an agreement published on February 17, 2023 in the Official Federal Gazette, established the renewal of deadlines and legal terms with respect to all formalities, procedures and any activity that falls under the responsibility of the Energy Ministry, as of March 1, 2023.
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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 enacted regulatory framework:

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

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

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

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

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

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

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

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

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

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

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

• | Grid Code 2.0 (Código de Red 2.0).

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

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

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

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

• | General administrative provisions that establish the minimum requirement to be met by suppliers and qualified users participating in the Electricity Market to acquire energy demand in terms of article 12, section XXI, of the 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).

• | 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).

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

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

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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).

• | 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.

• | 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.
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.
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The Resolution 055-2020-OS/CD issued by OSINERGMIN approved the Annual Liquidation Procedure, applicable to all transmission concessionaires titleholders of SGT Contracts. This procedure, did not modify the base tariff established in the concession agreements. However, this procedure is relevant as it determines the monthly disbursements to be made in favor of the transmission agents of the electricity market in a tariff annual period and determines the transmission toll that must be paid by all customers pursuant to the Transmission Rules (Reglamento de Transmisión) in order to cover the base tariff.
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 and Mines 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 and Mines 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 Eléctricas, PCL), and its implementing rules; (ii) the Law 28832, Law to Ensure the Efficient Development of Electricity Generation (Ley para Asegurar el Desarrollo Eficiente de la Generación Eléctrica), (iii) the Transmission Rules (Reglamento de Transmisión), 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.
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.
The Economic Operations Committee of the National Interconnected System (Comité de Operación Económica del Sistema Interconectado Nacional – COES) is an entity created by the PCL and it is composed by different market participants (generation, transmission and distribution companies). COES is the operator of National Interconnected System - SEIN. COES supervises the interconnection of new facilities to the grid, organizes energy dispatch and supervises the real time operational of the system. The Resolution 083-2021-OS/CD approved the technical procedure No. 20 of the COES. By this procedure COES, regulates the main technical issues related to the entry, modification and withdrawal of electric facilities in the SEIN and established a regulation for the treatment of facilities connected to distribution concessions.
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.
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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.
The Resolution N° 002-2020-OS/CD issued by OSINERGMIN approved the procedure named “Conditions for the application of electricity generation and transmission tariffs”. This regulation is applicable to electricity agents (including transmission agents). By means of this procedure, 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.
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.
OSINERGMIN is the entity that verifies the compliance of the electricity regulation. Currently, OSINERGMIN applies its new Regulations for the Inspection and Sanctioning of Energy and Mining Activities approved by Resolution No. 208-2020-OS/CD, issued in December, 2020. Such new regulation is applicable to the transmission sector.
Moreover, during 2021, OSINERGMIN approved a modification to the Technical Procedure No. 31 of the COES regarding the calculation of the Variable Costs of the Generation Units, which had an impact on the energy business due to its impact on the marginal cost. Also, during 2022 such Procedure was (once again) modified through Resolution No. 171-2022-OS/CD.
In December 2022, through Supreme Decrees No. 154-2022-PCM and 157-2022-PCM, certain provisions related to the regime of the Contribution for Regulation in the electricity sub-sector in favor of OSINERGMIN and the Environmental Evaluation and Inspection Agency (OEFA) were approved. Specifically, in both cases, the rates of the Contribution for Regulation of the electric transmission concessionaires were updated for years 2023, 2024 and 2025.
By means of the Ministerial Resolution No. 227-2022-MINEM-DM, the Peruvian Ministry of Energy and Mines published for comments a draft of an amendment to the Law 28832. Among other topics, such resolution proposes: (i) a modification of some aspects related to the procedures to call for auctions for the execution of a SGT; (ii) the recognition of firm capacity for energy plants that produces with renewal energy resources, and (iii) the development of complementary services in the system (for example, based in the provision of frequency regulation services with battery energy storage systems).
Finally, regarding the existing limitations to vertical integration of the electric activities, Law No. 31112, “Law that establishes the prior control for corporate concentration operations” and its relevant implementing rules (Supreme Decree No. 039-2021-PCM) became effective on June 14, 2021.
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 Peruvian Ministry of Energy and Mines an instrument for environmental management (“IEM”), which after its approval is mandatory for implementation. In that sense, electricity companies are obliged to submit, on a yearly basis, an Annual Environmental Report with information on their level of compliance with environmental commitments (as established in the IEM) and other legal obligations that may result applicable. During 2022, guidelines for the filing of such Report were approved.
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On September 24, 2023, the Ministry of Energy and Mines issued Supreme Decree No. 016-2023-EM, approving the Citizen Participation Regulations for the execution of electrical activities. The purpose of these regulations is to establish provisions that govern the mechanisms of citizen involvement in various stages, including the preparation and evaluation of environmental management instruments, as well as the post-approval stage concerning electricity activities. Regarding the post-approval stage of the Environmental Study or IGAC, the regulations specify that citizen participation mechanisms must be incorporated into the Community Relations Plan of the Environmental Study or IGAC. This plan should outline the timing for compliance, the frequency, and the method of providing sources for verifying its implementation to the OEFA.
The Ministry of Energy and Mines has issued the Supreme Decree No. 014-2023-EM, which outlines complementary provisions for the Detailed Environmental Plan (PAD). The objective is to foster sustainable development within the realm of electricity generation, transmission, and distribution nationwide. The Detailed Environmental Plan serves as a supplementary environmental management tool, addressing both actual and potential adverse environmental impacts identified within the scope of ongoing electrical activities. Its purpose is to streamline the adaptation of these activities in a manner that aligns with environmental considerations.
The Supreme Decree No. 014-2023-EM introduces a revised timeline for notifying the Ministry of Energy and Mines regarding the intention to apply for a Detailed Environmental Plan (PAD), with a stipulated window of 3 months from the rule’s effective date, or until November 20, 2023. Additionally, the regulation outlines that, for the subsequent submission of the PAD, owners of electrical activities are granted a 3-year timeframe, whereas municipalities and regional governments are afforded 5 years, both calculated from the date of the Supreme Decree coming into effect.
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.
Regulation in Chile
Current Regulatory Framework
The general regulatory framework of the Chilean electricity sector, focused on photovoltaic solar plants, consists of:
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• | Decree with force of law no. 4, that fixes consolidated, coordinated, and systematized text of Decree with force of law no. 1, of Mining, of 1982, on General Law of Electric Services, in matters of electric energy, the “General Law of Electric Services”,

• | Law No. 19.300, March 9, 1994, on General Bases of the Environment, modified by Law No. 20.417, January 26, 2010, which creates the Ministry, the Environmental Evaluation Service and the Superintendence of the Environment;

• | Supreme Decree No. 327/1997 of the Ministry of Mining, published in the Official Gazette on September 10, 1998, modified by Supreme Decree No 68/2021, which contains “Regulation of General Law of Electric Services”;

• | Supreme Decree No. 125/2019 of the Ministry of Energy, published in the Official Gazette on December 20, 2019, which contains “Regulation of coordination and operation of the national electricity system”;

• | Supreme Decree No. 62/2006 of the Ministry of Economy, Development and Reconstruction, published in the Official Gazette on June 16, 2006, modified by Supreme Decree No 42/2020, which contains “Regulation of power transfers between companies regulated by General Law of Electric Services”;

• | Supreme Decree No. 88/2019 of the Ministry of Energy, published in the Official Gazette on October 8, 2020, modified by Supreme Decree No 27/2022, which contains “Regulation on Small Means on Distributed Generation” (PMGD).

• | Technical standard for the connection and operation of PMGD in medium voltage installations fixes by the National Energy Commission (“NTCO-PMGD” July 2019).

General Law of Electric Services
The purpose of the General Law of Electric Services is to establish a regulatory framework containing the rules applicable to the generation, transmission and distribution of electric power in Chile. This law is complemented by a series of technical regulations and standards.
In turn, for the electricity generation business, the applicable regulations establish a competitive market that seeks to supply the demand at minimum cost, so that the result is the economically efficient allocation of resources to and within the electric sector. To accomplish this, the National Electric Coordinator (“CEN”) determines the generation costs of each power plant and schedules the operation, according to the rules contained mainly in the “Regulation of coordination and operation of the national electricity system”.
The operation of electricity distribution companies require the granting of a concession by the authority and is usually a monopoly market. Pursuant to the General Law of Electric Services, the electric power distribution companies should provide public distribution services to all the customers located in their concession areas and are obliged to supply to all those who request it within such area. On the other hand, the regulations of the aforementioned law establish the duty of the distribution companies to ensure compliance with the obligation to provide supply. To comply with this, they must have a permanent supply of energy that, added to their own generation capacity, allows them to meet their total projected needs for a time horizon of at least three years.
Regulation applicable to transmission lines
The General Law of Electric Services establishes a medium and long term planning procedure for the most important transmission lines, to then publicly tender the construction of the works. In turn, the owners of the transmission lines are entitled to receive a remuneration called “tolls” as compensation for the investment and maintenance of the lines.
Regulation applicable to photovoltaic plants
The General Law of Electric Services establishes freedom to build, install or purchase photovoltaic plants, thus a previous state concession is not required to perform such activities. However, once a PV enters into operation, it must comply with the instructions given by the CEN for the entire National Electric System (“SEN”) regarding energy production. Such instructions will determine which plants must produce electricity in the next few days, depending on their production costs and the availability of the power plants, among other aspects. If the plant is “dispatched” by the CEN, it must operate and its energy will be injected into the National Electric System, from where the companies that have customers will obtain the electricity necessary to supply their consumption.
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According to the General Electric Services Law, all owners of generation facilities synchronized to the SEN shall have the right to sell the energy they produce at the instantaneous marginal cost, as well as their power surpluses at the node price of the power. As a result, in the generation market there are forced sales of electric power between the different plants, the price of which is determined by CEN and corresponds to the instantaneous marginal cost. The valuation of energy and power transfers between the different companies is carried out by CEN, according to the rules contained mainly in “Regulation of coordination and operation of the national electricity system” and “Regulation of power transfers between companies regulated by General Law of Electric Services”.
Regulation applicable to PMGDs
The General Electric Services Law provides that a regulation will establish the procedures for the determination of prices, when the generation facilities are directly connected to distribution system, as well as the price stabilization mechanisms applicable to the energy injected by power plants whose surplus of power that can be supplied to the electricity system does not exceed 9 MW. For that reason, Supreme Decree No. 244/05 (“DS 244”) was approved to incorporate a regulation for small-scale generation facilities (PMG and PMGD). Moreover, on October 8, 2020, Supreme Decree No. 88 (DS 88) was published in the Official Gazette, incorporating a new regulation for small-scale generation facilities (PMG and PMGD) which was amended in March 2022.
Any owner or operator of a small-scale generation facility must choose to sell the energy it injects into the system at the instantaneous marginal cost or under a stabilized price regime. This option must be communicated at least one month prior to the entry into operation. The minimum period of permanence in each regime will be four years and the option to change regime must be communicated to CEN at least six months in advance.
The price stabilization mechanism (or “Stabilized Price”) was incorporated in the General Law of Electric Services with Law No. 19,940/2004, with the intention of encouraging the construction of small non-conventional renewable energy generating plants, whose power surpluses do not exceed 9MW. The aim was to reduce the entry barriers faced by these plants, normally located close to consumption centers, stabilize their cash-flows, and diversify the energy matrix. Supreme Decree No. 244/05 (“DS 244”) regulated this matter and allowed the owners of such facilities if they sold the energy produced at the instantaneous marginal cost or at the Stabilized Prices set by Supreme Decree by the Ministry of Energy. The Stabilized Price would be determined by the National Energy Commission for a 4-year horizon, based on a projection of the marginal cost for that period. If the Stabilized Price was chosen, the plant had to remain for the same period of 4 years in the price stabilization mechanism. This Supreme Decree was replaced 15 years later by Supreme Decree No. 88/2019 (“DS 88”).
The new scheme set by DS 88 modifies the stabilized price regime for projects up to 9MW that are directly connected to low and medium voltage transmission lines and introduces adjustments aimed at streamlining the connection process. Regarding the new stabilized price regime, the calculation now considers six four-hour time intervals with independent prices during a given day, in contrast to the previous regime, which did not make distinctions based on the time of energy injection.
At the same time, in order to avoid a negative impact on the market of the PMGDs that had already used this mechanism, DS 88 created a grandfathering period for PMGDs that were (i) already in operation, (ii) declared under construction and/or (iii) with their sectorial environmental approvals granted. Under such grandfathering period, the facilities that met any of the abovementioned criteria can choose if they want to benefit from the Stabilized Price regime of DS 244 for a term of 165 months since the publication of DS 88, until July 2034. Given that Atlantica’s Chile PMGDs were already declared under construction when DS 88 became applicable, Atlantica chose to benefit from the grandfathering period and therefore receiving the stabilized price set by DS 244. Once the term of the grandfathering period elapses, all PMGDs will follow the new scheme set forth by DS 88.
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DS 88 establishes a regulated procedure for the authorization of PMGDs. Such procedure begins with the presentation of a request for connection to the grid belonging to a distribution company, accompanying a schedule of works, and a deposit of 20% of the costs corresponding to the connection studies. If declared admissible by the distribution company, it issues a Connection Criteria Report (ICC), which will be valid for 9, 12 or 18 months, with no possibility of extension, depending on the installed capacity of the project, as well as whether it has a significant impact on the grid. Moreover, in order to receive the authorizations required for construction, PMGDs must submit their “declaration under construction” to the CNE, at which time the CNE will analyze if their power surplus is less than or equal to 9MW, being a requirement to access to the special conditions defined exclusively for small-scale generation facilities, such as connection conditions, operation, price level and billing.
It is important to note that the electricity distribution companies must allow the connection to their distribution facilities to the PMGDs, complying with the specifications contained in the Technical Standards issued by the CNE, at present “NTCO-PMGD” July 2019 and shall guarantee access to their network for PMGD with the same quality of service applicable to Regulated customers.
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:

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

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

• | Entitlement to a specific payment scheme: under the system established by Royal Decree 413/2014, 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 government of Spain 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 (daily and intra-daily market managed by the market operator) or via a bilateral or forward contract (which makes them 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.

Remuneration System for Renewable Plants
According to Royal Decree 413/2014, producers receive (i) the electricity market price for the power they produce and (ii) a specific remuneration.
The specific remuneration system established by Royal Decree 413/2014 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.
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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 the following two concepts for remuneration:

a) | A remuneration per unit of installed power, which shall be called Remuneration on Investment (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 on Investment (Rinv) of the associated typical installation shall be multiplied by the power entitled to the specific remuneration system, without prejudice to the correction according to the number of equivalent hours of operation.

b) | A Remuneration on 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 on Operation (Ro) of an installation, the Remuneration on 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. Nevertheless, the granting of this specific remuneration system for existing facilities is regulated in the first transitory provision of Royal Decree 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 (which include the cyclical situation of the economy, the electricity demand and the appropriate profitability) 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%.
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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 filed arbitration processes back in the day.
In addition, in 2022 measures to adjust the regulated revenue component for renewable energy plants were introduced, following the increase since mid-2021 in the billings of these plants for the sale of electricity in the market. On March 30, 2022, the Royal Decree Law 6/2022 was published, adopting urgent measures in response to the economic and social consequences of the war in Ukraine. This Royal Decree Law contains a bundle of measures in diverse fields, including those targeted at containing the sharp rise in the prices of gas and electricity. It includes temporary changes to the detailed regulated components of revenue received by our solar assets in Spain, which are applicable from January 1, 2022. Specifically, prior to the entry into force of these new regulations, the level of remuneration under that specific remuneration system depended on the market price estimates used to calculate it, which are revised in each regulatory semi-period. Under article 5 of Royal Decree Law 6/2022, for the year 2022 the remuneration will be reviewed also taking into account 2020 and 2021 actual market prices and prices of the future prices of OMIP for year 2022. Further, through Royal Decree Law 6/2022 and Royal Decree Law 10/2022, the article 22 of Royal Decree Law was modified to the change the update of the remuneration. and therefore, the formula for the calculation of the adjustment value in each semi-period from 2023 was modified. Prior to these amendments, the reference index was exclusively the current daily market price. After these modifications, and as of 2023, the estimate of the market price for each year of the regulatory half-period is calculated as the arithmetic mean of the prices of the corresponding annual futures contracts traded on the electricity futures market organized by OMIP from 1 June to 30 November of the year prior to the start of the half-period for which the market price is estimated, and the adjustment value will be a weighting of the actual daily market price and OMIP futures prices at different time horizons. Nevertheless, Royal Decree Law 5/2023 has established an exemption to this modification for the estimation of the market price for 2023. Therefore, for the regulatory half-period beginning on 1 January 2023 and ending on 31 December 2025, the electricity market price for 2023 will be estimated on the basis of the daily market values between 1 January and 31 May 2023 and the futures values traded in that period for the energy delivered between 1 June and 31 December 2023. On the other hand, the estimate of the electricity market price for the year 2024 and subsequent years will be made on the basis of the futures markets. Due to these changes:

− | The statutory half-period of three years from 2020 to 2022 has been split into two statutory half-periods (1) from January 1, 2020 until December 31 2021 and (2) calendar year 2022. As a result, the fixed monthly payment based on installed capacity (Remuneration on Investment or Rinv) for calendar year 2022 was revised in the new Order TED/1232/2022.

− | Subsequently, following the mandate contained in Royal Decree Law 6/2022, Royal Decree Law 10/2022 and Royal Decree Law 5/2023, whose main measures have been exposed above, the remuneration parameters were updated for the years 2023-2025 by Order TED/741/2023, of June 30, 2023, that was published in final form on July 8, 2023. The proposed Rinv for 2023-2025 is detailed in the table below.

− | The electricity market price assumed by the regulation included in Royal Decree Law 5/2023 for calendar year 2023 is 109,31 €/MWh, the estimation of the market price for the year 2024 is 108,86 €/MWh and for the year 2025 is 89,37 €/MWh. For the years 2026 and beyond, the value for the year 2025 has been used. As a result, the variable payment based on net electricity produced (Remuneration on Operation or Ro), was also adjusted. The proposed Ro for the year 2024 is zero €/MWh for most of our assets reflecting the fact that market prices for the power sold in the market are significantly higher.

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Since January 1, 2023, the parameters foreseen in Order TED/741/2023 are as follows:

| Useful Life | Remuneration on Investment 2023 - 2025 (euros/MW) | Remuneration on Operation 2024 (euros/GWh) | Adjustment Rate | Maximum Hours | Minimum Hours 2024-2025 | Operating Threshold 2024-2025
Solaben 2 | 25 years | 378,506 | 0 | 0.9854 | 2,004 | 1,202 | 701
Solaben 3 | 25 years | 378,506 | 0 | 0.9854 | 2,004 | 1,202 | 701
Solacor 1 | 25 years | 378,506 | 0 | 0.9854 | 2,004 | 1,202 | 701
Solacor 2 | 25 years | 378,506 | 0 | 0.9854 | 2,004 | 1,202 | 701
PS 10 | 25 years | 533,115 | 19.798 | 0.9948 | 1,837 | 1,102 | 643
PS 20 | 25 years | 393,001 | 14.044 | 0.9942 | 1,837 | 1,102 | 643
Helioenergy 1 | 25 years | 372,549 | 0 | 0.9845 | 2,004 | 1,202 | 701
Helioenergy 2 | 25 years | 372,549 | 0 | 0.9845 | 2,004 | 1,202 | 701
Helios 1 | 25 years | 387,136 | 0 | 0.9857 | 2,004 | 1,202 | 701
Helios 2 | 25 years | 387,136 | 0 | 0.9857 | 2,004 | 1,202 | 701
Solnova 1 | 25 years | 392,031 | 0 | 0.9849 | 2,004 | 1,202 | 701
Solnova 3 | 25 years | 392,031 | 0 | 0.9849 | 2,004 | 1,202 | 701
Solnova 4 | 25 years | 392,031 | 0 | 0.9849 | 2,004 | 1,202 | 701
Solaben 1 | 25 years | 384,318 | 0 | 0.9860 | 2,004 | 1,202 | 701
Solaben 6 | 25 years | 384,318 | 0 | 0.9860 | 2,004 | 1,202 | 701
Seville PV | 30 years | 677,855 | 0 | 0.9809 | 2,030 | 1,218 | 711

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 extended those measures to the first calendar quarter of 2022. These measures were further extended to 2022 and 2023. Royal Decree-Law 8/2023 provides that the exemption will amount to 50% in the first calendar quarter of 2024 and to 25% in the second calendar quarter of 2024. No exemption will be applicable onwards.
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.
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:
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• | 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:
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 16.8% 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 ATN 2

(9) | 87.5% owned by Lotus Infrastructure

(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) | Solar and wind projects under development in Uruguay

(15) | 65% held by financial partners

(16) | Solar projects 100% owned by Chile Platform

(17) | Simplified structure

(18) | 51% held by EDPR Renewables

(19) | Simplified structure

(20) | Solar and battery project under development in the US

(21) | Solar projects under development in Colombia (Honda 1, Honda 2 and Apulo 1)

(22) | Coso Batteries 1, the standalone battery storage project of 100 MWh (4 hours) capacity

(23) | Solar and battery project under development in Arizona

(24) | 49% in solar projects in Chile. Simplified structure. 51% held by Akuo Energy Chile

(25) | ATN also owns a transmission line and substation under development in Peru

(26) | Battery projects in Mexico. 60% of voting rights through preferred equity shares that provide almost all economic rights to Atlantica

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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. 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 2023, renewables represented 73% of our revenue, with solar energy representing 63%. 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 also hold water assets, a relevant sector for sustainable development. We intend to grow our business through the development and construction of projects including expansion and repowering opportunities, as well as greenfield developments, third-party acquisitions and the optimization of our existing portfolio. We currently have a pipeline of assets under development of approximately 2.2 GW of renewable energy and 6.0 GWh of storage. 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 2023
Assets that Entered into Operation
During 2023, four assets that were under construction entered into operation:

• | Albisu, the 10 MW PV asset wholly owned by us reached COD in January 2023. Albisu is located in Uruguay and has a 15-year PPA with Montevideo Refrescos, S.R.L., a subsidiary of Coca-Cola Femsa, S.A.B. de C.V. The PPA is denominated in local currency with a maximum and minimum price in U.S. dollars and is adjusted monthly based on a formula referring to the U.S. Producer Price Index (PPI), Uruguay’s Consumer Price Index (CPI) and the applicable UYU/U.S. dollar exchange rate.

• | La Tolua and Tierra Linda are two wholly owned solar PV assets in Colombia with a combined capacity of 30 MW both of which reached COD in the first quarter of 2023. Each plant has a 10-year PPA in local currency with Coenersa, the largest independent electricity wholesaler in Colombia. Each PPA provides for the sale of electricity at fixed base price indexed to local CPI.

• | Honda 1, a 10 MW PV asset in Colombia reached COD in December 2023. Honda 1 is a 10 MW plant where we have a 50% ownership. The asset has a 7-year PPA with Enel Colombia, a major electricity company in the country. The PPA is denominated in local currency, with fixed base price, indexed to the local CPI.

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Assets Under Construction
We currently have the following assets under construction.

Asset | Type | Location | Capacity (gross)1 | Expected COD | Expected Investment3 ($ million) | Off-taker
Coso Batteries 1 | Battery Storage | California, US | 100 MWh | 2025 | 40-50 | Investment grade utility
Coso Batteries 2 | Battery Storage | California, US | 80 MWh | 2025 | 35-45 | Investment grade utility
Chile PMGD(2) | Solar PV | Chile | 80 MW | 2024- 2025 | 30 | Regulated
ATN Expansion 3 | Transmission Line | Peru | 2.4 miles 220kV | 2024 | 12 | Conelsur
ATS Expansion 1 | Transmission Line | Peru | n.a. (substation) | 2025 | 30 | Republic of Peru
Honda 2(4) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | Enel Colombia
Apulo 1(4) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | -

Notes:

(1) | Includes nominal capacity on a 100% basis, not considering Atlantica’s ownership

(2) | Atlantica owns 49% of the shares, with joint control, in Chile PMGD. Atlantica’s economic rights are expected to be approximately 70%

(3) | Corresponds to the expected investment by Atlantica

(4) | Atlantica owns 50% of the shares in Honda 2 and Apulo 1

We refer to “Item 4- Information on the Company – B. Business Overview – Assets under Construction” for a description of each of the assets under construction in the table above.
Advanced Projects

• | In February 2024, we entered into a 15-year busbar PPA with an investment grade utility for Overnight. Overnight is a 150 MW PV project located in California. Under the PPA, Overnight is set to receive a fixed price per MWh, with no basis risk. The project is currently in an advanced development stage. Total investment is anticipated to be within the range of $165 to $185 million. We expect to include storage in a second phase of the project.

• | In January 2024, we acquired from Liberty GES two PV projects in advanced development stage in Southern Spain with approximately 90 MW of combined generation capacity. The acquisition of land and interconnection are secured and the process for permits is well advanced. The projects were acquired in exchange for assuming the necessary guarantees, at no additional cost.

Potential Asset Sale
Our partner in Monterrey initiated a process to sell its 70% stake in the asset. Such process is well advanced and, as part of it, we intend to sell our interest as well under the same terms. The net proceeds to Atlantica are expected to be in the range of $45 to $52 million, after tax. The closing of the transaction is subject to certain conditions precedent. We cannot guarantee that the transaction will finally close.
Project Debt Refinancing
In March 2023, we refinanced the Solaben 2 and Solaben 3 project debt by entering into two green senior euro-denominated loan agreements for the two assets with a syndicate of banks for a total amount of €198.0 million. The new project debt replaced the previous project loans for a similar amount and maturity was extended from December 2030 to June 2037.
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In addition, in June 2023 we extended the maturity of the debt for Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 2 & 3 and Solaben 1 & 6 from April 2025 to December 2028 (see “Item 4— Information on the Company— Our Operations —Renewable Energy”).
Operation and Maintenance
In March 2023, we completed the process of transitioning in-house the O&M services for our assets in Spain through the acquisition of the business of an Abengoa subsidiary which was still providing those services to some of our assets.
In addition, in July 2023 we internalized the O&M services for ATN, which were previously performed by Omega Peru. Additionally, the O&M contract for ATS with Omega Peru, which could be terminated every five years was modified and can now be terminated every three years (or two years under certain circumstances) and the contract for ATN2, which was a long-term contract expiring in 2027, was also amended to reflect the same termination provision.
Currently, we perform O&M services with our own personnel for assets representing approximately 74% of our consolidated revenue for the year ended December 31, 2023.
Regulation in Spain.
In June 2023, the final parameters for the year 2023 were published, including a revised assumption for electricity prices for the years 2023, 2024 and 2025. For a detailed discussion please see “Item 4—Information on the Company—Business Overview—Regulation in Spain”.
Strategic Review
On February 21, 2023, Atlantica’s board of directors commenced a process to explore and evaluate potential strategic alternatives that may be available to Atlantica to maximize shareholder value. The Company believes it has attractive growth and other opportunities in front of it and is committed to ensuring it is best positioned to take advantage of those opportunities. The decision has the support of the Company’s largest shareholder, Algonquin. Atlantica expects to continue executing on its existing plans while the review of strategic alternatives is ongoing, including its current growth plan. As of the date of this annual report, the strategic review is ongoing. There is no assurance that any specific transaction will be consummated, or other strategic change will be implemented as a result of this strategic review. See “Cautionary Statements Regarding Forward-Looking Statements” and “Part I, Item 3.D.—Risk Factors” in our Annual Report.
Factors Affecting the Comparability of Our Results of Operations
Investments
The results of operations of Chile TL4, Italy PV 4 and Chile PV 3 have been fully consolidated since January 2022, April 2022 and September 2022, respectively and the results of Albisu, Tierra Linda and La Tolua have been fully consolidated since these assets entered into operation in the first quarter of 2023. For the full year 2023, these investments represented revenues and Adjusted EBITDA of $14.1 million and $10.5 million respectively, which represents an increase of $7.9 million in revenue and $7.6 million in Adjusted EBITDA for the year ended December 31, 2023 with respect to 2022.
Impairment
In 2023, considering that expected electricity prices in Chile over the remaining useful life of Chile PV1 have decreased, we have identified an impairment triggering event, in accordance with IAS 36 (Impairment of Assets). As a result, an impairment test has been performed and resulted in an impairment loss of $16.1 million in 2023 in the line “Depreciation, amortization, and impairment charges”. In 2022, we also recorded an impairment loss of $20.4 million in Chile PV1 and Chile PV2. Our equity interest in Chile PV 1 and Chile PV 2 is 35%. As a result, the impact of the impairment charges in “Profit / (loss) for the year attributable to the parent company” after non-controlling interest was $5.6 million in 2023 and $7.1 million in 2022.
During 2022 we recorded an impairment loss of $41.2 million in Solana with no corresponding triggering event and impairment in 2023.
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In addition, IFRS 9 requires impairment provisions to be based on expected credit losses on financial assets rather than on actual credit losses, which affects the concessional assets accounted for as financial assets. For the year 2023 we recorded a decrease in the expected credit loss impairment provision of $13.2 million reflected in the line item “Depreciation, amortization, and impairment charges” and was primarily related to ACT ($10.9 million). In 2022, we recorded an increase in the expected credit loss impairment provision of $6.7 million, also primarily related to ACT ($4.0 million).
Electricity market prices
Total revenues in Spain were stable in 2023 compared to the previous year. In addition to regulated revenue, our solar assets in Spain receive revenue from the sale of electricity at market prices. The average electricity market price captured by our assets was approximately €69.9 per MWh during 2023 compared to approximately €145.3 per MWh during 2022. Revenue from the sale of electricity at current market prices represented $84.3 million during 2023, compared to $142.9 million in 2022. Regulated revenues are revised periodically to reflect, among other things, the difference between expected and actual market prices if the difference is higher than a pre-defined threshold and as a result, we record a provision. We decreased our provision by $3.5 million in 2023, with no cash impact, compared to an increase of $25.3 million in the previous year.
In 2023, we have calculated the provision assuming that the average market price must be corrected using the solar time of day adjustment factor (“coeficiente de apuntamiento”), as it was stated in the regulations published since 2020. This factor, which is 90% for 2023, aims to capture the difference between the daily (24 hours) average market price and the price captured by solar assets. Although the factor is not mentioned in the regulation for 2023, we believe the last order includes a clerical error that we expect is going to be corrected.
On May 12, 2022, remuneration parameters in Spain for the year 2022 were published and became final on December 14, 2022, with a decrease in regulated revenue. In addition, on June 30, 2023, the new parameters were published, including a revised assumption on electricity prices for the years 2023, 2024 and 2025. Revenue from the sale of electricity at market prices net of the incremental market price provision was $84.0 million for the full year 2023, compared to $117.6 million for the full year 2022. This decrease was offset by higher production in 2023.
Additionally, in 2022 we collected revenue from our assets in line with the parameters corresponding to the regulation in place at the beginning of the year 2022, however revenue for the year ended December 31, 2022 was recorded in accordance with the new parameters that became final on December 14, 2022, which were lower. Collections were regularized in the first quarter of 2023.
Exchange rates
We refer to “Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Significant Trends Affecting Results of Operations—Exchange rates” below.
Significant Trends Affecting Results of Operations
Investments and acquisitions
If the recently built assets and the recently closed acquisitions perform as anticipated, we expect these assets to positively impact our results of operations in 2024 and upcoming years.
S olar, 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.
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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 presentation currency and the functional currency of most of our subsidiaries is the U.S. dollar, as most of their 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, La Sierpe, La Tolua and Tierra Linda, Honda 1, our solar plants in Colombia, have their revenue and expenses denominated in Colombian pesos and Albisu, our solar plant in Uruguay, has its revenue denominated in Uruguayan pesos, with a maximum and a minimum price in U.S. dollars.
Project financing is typically denominated in the same currency as that of the contracted revenue agreement, which limits our exposure to foreign exchange risk. In addition, we maintain part of our corporate general and administrative expenses and part of our corporate debt in euros which creates a natural hedge for the distributions we receive from our assets in Europe. To further mitigate this exposure, our strategy is to hedge cash distributions from our assets in Europe. We hedge the exchange rate for the net distributions in euros (after deducting interest payments and general and administrative expenses in euros). 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 the South African rand and Colombian peso with respect to the U.S. dollar may also affect our operating results.
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.
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.”
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, 2023, approximately 92% of our project debt and close to 94% of our corporate debt either has fixed interest rates or has been hedged with swaps or caps. Nevertheless, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates, which typically bear a spread over EURIBOR or SOFR.
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Trends on electricity market prices
As previously discussed, our solar assets in Spain receive revenue from the sale of electricity at market prices in addition to regulated revenue. Regulated revenues are revised periodically to reflect the difference between expected and actual market prices if the difference is higher than a pre-defined threshold. Additionally, our assets in Italy have contracted revenues through a regulated feed-in premium in addition to merchant revenues for the energy sold to the wholesale market.
Furthermore, we currently have three assets with merchant revenues (Chile PV 1 and Chile PV 3, where we have a 35% ownership, and Lone Star II, where we have a 49% ownership) and one asset with partially contracted revenues (Chile PV 2, where we have a 35% ownership). Our exposure to merchant electricity prices represents less than 1% of our portfolio9 in terms of Adjusted EBITDA. At Lone Star II we are analyzing, together with our partner, the option to repower or recontract the asset in the context of the IRA, at a point in time to be determined.
Due to low electricity prices in Chile, the project debts of Chile PV 1 and 2 are under an event of default as of December 31, 2023 and as of the date of this report. Chile PV 1 was not able to maintain the minimum required cash in its debt service reserve account as of December 31, 2023 and did not make its debt service payment in January. In addition, in October 2023, Chile PV 2 did not make its debt service payment. This asset obtained additional financing from the banks and made the debt service payment in December, although it was not able to fund its debt service reserve account subsequently. As a result, although we do not expect an acceleration of the debt to be declared by the credit entities, as of December 31, 2023 Chile PV 1 and 2 did not have an unconditional right to defer the settlement of the debt for at least twelve months and the project debt was classified as current in our Annual Consolidated Financial Statements. We are in conversations with the banks, together with our partner, regarding a potential waiver. Impairments were recorded in these assets in 2023 and 2022. The value of the net assets contributed by Chile PV 1 and 2 to the Annual Consolidated Financial Statements, excluding non-controlling interest, was close to zero as of December 31, 2023.
Key Financial Measures
Our revenue and Adjusted EBITDA by geography and business sector for the years ended December 31, 2023, 2022 and 2021 are set forth in the following tables:
Revenue by geography

| Year ended December 31, |
| 2023 |  | 2022 |  | 2021 |
| $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
North America |  | $ | 424.9 |  |  |  | 38.6 | % |  | $ | 405.1 |  |  |  | 36.8 | % |  | $ | 395.8 |  |  |  | 32.7 | %
South America |  |  | 188.1 |  |  |  | 17.1 | % |  |  | 166.4 |  |  |  | 15.1 | % |  |  | 155.0 |  |  |  | 12.8 | %
EMEA |  |  | 486.9 |  |  |  | 44.3 | % |  |  | 530.5 |  |  |  | 48.1 | % |  |  | 660.9 |  |  |  | 54.5 | %
Total revenue |  | $ | 1,099.9 |  |  |  | 100.0 | % |  | $ | 1,102.0 |  |  |  | 100.0 | % |  | $ | 1,211.7 |  |  |  | 100.0 | %

Revenue by business sector

| Year ended December 31, |
| 2023 |  | 2022 |  | 2021 |
| $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |  | $ in millions |  | % of revenue |
Renewable energy |  | $ | 802.8 |  |  |  | 73.0 | % |  | $ | 821.4 |  |  |  | 74.5 | % |  | $ | 928.5 |  |  |  | 76.6 | %
Efficient natural gas & heat |  |  | 118.4 |  |  |  | 10.8 | % |  |  | 113.6 |  |  |  | 10.3 | % |  |  | 123.7 |  |  |  | 10.2 | %
Transmission lines |  |  | 123.5 |  |  |  | 11.2 | % |  |  | 113.2 |  |  |  | 10.3 | % |  |  | 105.6 |  |  |  | 8.7 | %
Water |  |  | 55.2 |  |  |  | 5.0 | % |  |  | 53.8 |  |  |  | 4.9 | % |  |  | 53.9 |  |  |  | 4.5 | %
Total revenue |  | $ | 1,099.9 |  |  |  | 100.0 | % |  | $ | 1,102.0 |  |  |  | 100.0 | % |  | $ | 1,211.7 |  |  |  | 100.0 | %

9 Calculated as a percentage of our Adjusted EBITDA in 2023.
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Adjusted EBITDA by geography

| Year ended December 31, |
| 2023 |  | 2022 |  | 2021 |
| $ in Millions |  | % of Adjusted EBITDA |  | $ in millions |  | % of Adjusted EBITDA |  | $ in millions |  | % of Adjusted EBITDA |
North America |  | $ | 319.3 |  |  |  | 40.1 | % |  | $ | 310.0 |  |  |  | 38.9 | % |  | $ | 311.8 |  |  |  | 37.8 | %
South America |  |  | 146.7 |  |  |  | 18.5 | % |  |  | 126.5 |  |  |  | 15.9 | % |  |  | 119.6 |  |  |  | 14.5 | %
EMEA |  |  | 328.9 |  |  |  | 41.4 | % |  |  | 360.6 |  |  |  | 45.2 | % |  |  | 393.0 |  |  |  | 47.7 | %
Total Adjusted EBITDA |  | $ | 794.9 |  |  |  | 100.0 | % |  | $ | 797.1 |  |  |  | 100.0 | % |  | $ | 824.4 |  |  |  | 100.0 | %

Adjusted EBITDA by business sector

| Year ended December 31, |
| 2023 |  | 2022 |  | 2021 |
| $ in millions |  | % of Adjusted EBITDA |  | $ in millions |  | % of Adjusted EBITDA |  | $ in millions |  | % of Adjusted EBITDA |
Renewable energy |  | $ | 575.7 |  |  |  | 72.4 | % |  | $ | 588.0 |  |  |  | 73.8 | % |  | $ | 602.6 |  |  |  | 73.1 | %
Efficient natural gas & heat |  |  | 87.4 |  |  |  | 11.0 | % |  |  | 84.6 |  |  |  | 10.6 | % |  |  | 100.0 |  |  |  | 12.1 | %
Transmission lines |  |  | 96.0 |  |  |  | 12.1 | % |  |  | 88.0 |  |  |  | 11.0 | % |  |  | 83.6 |  |  |  | 10.2 | %
Water |  |  | 35.8 |  |  |  | 4.5 | % |  |  | 36.5 |  |  |  | 4.6 | % |  |  | 38.2 |  |  |  | 4.6 | %
Total Adjusted EBITDA |  | $ | 794.9 |  |  |  | 100.0 | % |  | $ | 797.1 |  |  |  | 100.0 | % |  | $ | 824.4 |  |  |  | 100.0 | %

Note:
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 profit/loss for the year attributable to the Company:

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
|  | ($ in millions) |
Profit/(Loss) for the year attributable to the Company |  | $ | 43.4 |  |  | $ | (5.4 | ) |  | $ | (30.1 | )
Profit/(Loss) attributable to non-controlling interest |  |  | (6.9 | ) |  |  | 3.3 |  |  |  | 19.2 |
Income tax expense/(benefit) |  |  | 0.8 |  |  |  | (9.7 | ) |  |  | 36.2 |
Financial expense, net |  |  | 318.0 |  |  |  | 310.9 |  |  |  | 340.9 |
Depreciation, amortization and impairment charges |  |  | 418.3 |  |  |  | 473.6 |  |  |  | 439.4 |
Depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership) |  |  | 21.3 |  |  |  | 24.4 |  |  |  | 18.7 |
Adjusted EBITDA |  | $ | 794.9 |  |  | $ | 797.1 |  |  | $ | 824.4 |

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

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
|  | ($ in millions) |
Net cash flow provided by operating activities |  | $ | 388.1 |  |  | $ | 586.3 |  |  | $ | 505.6 |
Net interest /taxes paid |  |  | 272.7 |  |  |  | 277.3 |  |  |  | 342.3 |
Variations in working capital |  |  | 95.8 |  |  |  | (78.8 | ) |  |  | 3.1 |
Non-monetary items and other |  |  | 3.7 |  |  |  | (33.5 | ) |  |  | (57.7 | )
Share of profit/(loss) of entities carried under the equity method, depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership) |  |  | 34.6 |  |  |  | 45.8 |  |  |  | 31.1 |
Adjusted EBITDA |  | $ | 794.9 |  |  | $ | 797.1 |  |  | $ | 824.4 |

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, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
Renewable Energy |  |  |  |  |  |  |  |  |
MW in operation(1) |  |  | 2,171 |  |  |  | 2,121 |  |  |  | 2,044 |
GWh produced(2) |  |  | 5,458 |  |  |  | 5,319 |  |  |  | 4,655 |
Efficient natural gas & heat |  |  |  |  |  |  |  |  |  |  |  |
MW in operation(3) |  |  | 398 |  |  |  | 398 |  |  |  | 398 |
GWh produced(4) |  |  | 2,549 |  |  |  | 2,501 |  |  |  | 2,292 |
Availability (%) |  |  | 99.6 | % |  |  | 98.9 | % |  |  | 100.6 | %
Transmission lines |  |  |  |  |  |  |  |  |  |  |  |
Miles in operation |  |  | 1,229 |  |  |  | 1,229 |  |  |  | 1,166 |
Availability (%) |  |  | 100.0 | % |  |  | 100 | % |  |  | 100.0 | %
Water |  |  |  |  |  |  |  |  |  |  |  |
Mft3 in operation(1) |  |  | 17.5 |  |  |  | 17.5 |  |  |  | 17.5 |
Availability (%) |  |  | 99.7 | % |  |  | 102.3 | % |  |  | 97.9 | %

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 2.6% in 2023, compared to 2022. The increase was largely due to an increase in production in our solar assets in Spain and to the contribution from the assets recently consolidated or which have entered into operation recently, including Chile PV 3, La Tolua, Tierra Linda, Albisu and Italy PV 4, bringing approximately 147.9 MWh of additional electricity generation during the year 2023.

| • | In our solar assets in the U.S., production increased by 7.4% in 2023 compared to 2022, in spite of lower solar radiation in average during the year. The increase was mainly due to greater availability of the storage system in Solana. On the other hand, production decreased by 9.8% in our wind assets in the U.S., due to lower wind resource in 2023 compared to 2022. Production also decreased at Coso mostly due to scheduled maintenance stops and to lower availability of the transmission line due to the snow storm in California in the first quarter of 2023.

| • | In Chile, production at our Chile PV 1 and Chile PV 2 assets decreased by 11.5% in 2023 compared to 2022 mainly because of higher curtailments. At our wind assets in South America, production increased by 6.6% due to better wind resource.

| • | In Spain, production at our solar assets increased by 17.5% in 2023 mostly due to better solar radiation compared to 2022, with good performance of the assets.

| • | At Kaxu, production decreased by 48.6% in 2023 compared to 2022 mostly due to an outage of the plant. In the third quarter, a scheduled turbine major overhaul was carried out by Siemens, the original equipment manufacturer and took approximately 30 days longer than expected. After restarting production, at the end of September, a problem was found in the turbine, likely related to the major overhaul. The plant restarted operations in mid-February 2024. Part of the damage and the business interruption is covered by our insurance property policy, after a 60-day deductible.

Our efficient natural gas and heat assets, our water assets and our transmission lines, for which revenue is based on availability, continued at very high levels during 2023.
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Results of Operations
The table below illustrates our results of operations for the years ended December 31, 2023, 2022 and 2021.

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
|  | ($ in millions) |
Revenue |  | $ | 1,099.9 |  |  | $ | 1,102.0 |  |  | $ | 1,211.7 |
Other operating income |  |  | 101.1 |  |  |  | 80.8 |  |  |  | 74.6 |
Employee benefit expenses |  |  | (104.1 | ) |  |  | (80.2 | ) |  |  | (78.7 | )
Depreciation, amortization, and impairment charges |  |  | (418.3 | ) |  |  | (473.6 | ) |  |  | (439.4 | )
Other operating expenses |  |  | (336.6 | ) |  |  | (351.3 | ) |  |  | (414.3 | )
Operating profit |  | $ | 342.0 |  |  | $ | 277.7 |  |  | $ | 353.9 |
Financial income |  |  | 25.0 |  |  |  | 10.1 |  |  |  | 6.0 |
Financial expense |  |  | (323.7 | ) |  |  | (330.4 | ) |  |  | (360.9 | )
Net exchange differences |  |  | (2.5 | ) |  |  | 10.3 |  |  |  | 1.9 |
Other financial income/(expense), net |  |  | (16.6 | ) |  |  | (0.9 | ) |  |  | 12.1 |
Financial expense, net(1) |  | $ | (318.0 | ) |  | $ | (310.9 | ) |  | $ | (340.9 | )
Share of profit of entities carried under the equity method |  |  | 13.2 |  |  |  | 21.4 |  |  |  | 12.3 |
Profit/(loss) before income tax |  | $ | 37.2 |  |  | $ | (11.8 | ) |  | $ | 25.3 |
Income tax (expense)/income |  |  | (0.8 | ) |  |  | 9.7 |  |  |  | (36.2 | )
Profit/(loss) for the year |  | $ | 36.5 |  |  | $ | (2.1 | ) |  | $ | (10.9 | )
Profit/(loss) attributable to non-controlling interests |  |  | 6.9 |  |  |  | (3.3 | ) |  |  | (19.2 | )
Profit / (loss) for the year attributable to the parent company |  | $ | 43.4 |  |  | $ | (5.4 | ) |  | $ | (30.1 | )
Weighted average number of ordinary shares outstanding (thousands) – basic |  |  | 116,152 |  |  |  | 114,695 |  |  |  | 111,008 |
Weighted average number of ordinary shares outstanding (thousands) – diluted |  |  | 119,720 |  |  |  | 118,865 |  |  |  | 115,408 |
Basic earnings per share attributable to the parent company (U.S. dollar per share) |  |  | 0.37 |  |  |  | (0.05 | ) |  |  | (0.27 | )
Diluted earnings per share attributable to the parent company (U.S. dollar per share) |  |  | 0.37 |  |  |  | (0.09 | ) |  |  | (0.27 | )
Dividend paid per share(2) |  |  | 1.78 |  |  |  | 1.77 |  |  |  | 1.72 |

Note:

(1) | Classification within “Financial income” and “Financial expense” has been revised to show a more meaningful classification of financial income and expense following the increase in interest rates. Prior period classification has been revised accordingly.

(2) | On February 28, 2023, May 4, 2023, July 31, 2023 and November 7, 2023 our board of directors approved a dividend of $0.445per share each quarter, corresponding to the fourth quarter of 2022, the first quarter of 2023, the second quarter of 2023 and the third quarter of 2023 which were paid on March 25, 2023, June 15, 2023, September 15, 2023, and December 15, 2023 respectively. On February 25, 2022, May 5, 2022, August 2, 2022 and November 8, 2022 our board of directors approved a dividend of $0.44, $0.44, $0.445 and $0.445 per share, respectively, corresponding to the fourth quarter of 2021, the first quarter of 2022, the second quarter of 2022 and the third quarter of 2022 which were paid on March 25, 2022, June 15, 2022, September 15, 2022, and December 15, 2022 respectively.

Comparison of the Years Ended December 31, 2023 and 2022
The significant variances or variances of the significant components of the results of operations are discussed in the following section.
Revenue
Revenue decreased to $1,099.9 million for the year 2023 compared to $1,102.0 million for 2022. Revenue decreased primarily due to the decrease in production at Kaxu resulting from the unscheduled outage and the maintenance stop previously explained. Revenue at Kaxu decreased by $45.8 million. Part of the damage and the business interruption is covered by our insurance property policy, after deductibles, and as such we have recorded a $15.3 million insurance income in Other operating income.
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These effects were partially offset by higher revenues at our solar assets in the U.S. due to higher electricity production especially in Solana, as previously explained. Revenue also increased at our transmission lines in 2023 compared to 2022 mostly as a result of inflation adjustments to tariffs, including a positive tariff adjustment in Chile TL 3 corresponding to previous years, which was published in the second quarter of 2023. In addition, the Company generated additional revenue from assets recently consolidated and assets that entered into operation recently, which together represented a total of $14.1 million of revenue in 2023 compared to $6.2 million in 2022. Revenue remained stable at our solar assets in Spain, since higher production during the period was offset by lower electricity prices, net of its corresponding accounting provision (see “Factors Affecting the Comparability of Our Results of Operations—Electricity market prices”)
Other operating income
The following table sets forth our Other operating income for the years ended December 31, 2023 and 2022:

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |
Other operating income |  | ($ in millions) |
Grants |  | $ | 58.7 |  |  | $ | 59.1 |
Insurance proceeds and other |  |  | 35.8 |  |  |  | 21.7 |
Income from construction services for our assets and concessions |  |  | 6.6 |  |  |  | - |
Total |  | $ | 101.1 |  |  | $ | 80.8 |

“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 during 2023, compared to 2022.
“Insurance proceeds and other” increased by $14.1 million in 2023 compared to 2022. In 2023, “Insurance proceeds and other” included $15.3 million of insurance proceeds related to the Kaxu unscheduled outage, as previously explained. In addition, it included $4.6 million income from the sale of part of our equity interest in our development company in Colombia to a partner who now holds a 50% equity interest, with joint control. Finally, it includes $4.8 million related to improvements in our Calgary district heating asset which are re-invoiced to the municipality, with the corresponding cost recorded in “Other operating expenses”. In 2022, “Insurance proceeds and other” included an insurance income of $9.5 million.
“Income from construction services for our assets and concessions” is related to the construction of ATS Expansion 1 and ATN Expansion 3. Since these assets are accounted for under IFRIC 12, we are required to account for income from construction services as “Other operating income”, with the corresponding construction cost recorded within “Other operating expenses, Construction costs”.
Employee benefit expenses
Employee benefit expenses increased by 29.7% to $104.1 million for 2023, compared to $80.2 million in 2022 mainly due to the internalization of the O&M services at Kaxu in 2022 and at our solar assets in Spain in 2022 and 2023.
Depreciation, amortization, and impairment charges
Depreciation, amortization, and impairment charges decreased by 11.7% to $418.3 million for the year ended December 31, 2023, compared to $473.6 million for the year ended December 31, 2022. The decrease was mainly due to the $41 million impairment loss recorded at Solana in 2022, with no corresponding amount in 2023. The decrease was also due to a decrease 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 decrease in the credit loss impairment provision of $10.9 million in 2023, while in 2022, it recorded an increase in the credit loss impairment provision of $4.0 million. In Chile, we recorded an impairment of $16.1 million related to Chile PV1. In 2022 we also recorded an impairment of $20.4 million at Chile PV 1 and Chile PV 2. On the other hand, these effects on depreciation, amortization and impairment were partially offset by increased charges due to the consolidation of assets recently acquired or which entered in operation recently.
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Other operating expenses
The following table sets forth our Other operating expenses for the years ended December 31, 2023 and 2022:

|  | Year ended December 31, |  |
|  | 2023 |  |  | 2022 |  |
Other operating expenses |  | $ in millions |  |  | % of revenue |  |  | $ in millions |  |  | % of revenue |  |
Raw Materials |  | $ | 35.4 |  |  |  | 3.2 | % |  | $ | 19.7 |  |  |  | 1.8 |  | %
Leases and fees |  |  | 14.4 |  |  |  | 1.3 | % |  |  | 11.5 |  |  |  | 1.0 |  | %
Operation and maintenance |  |  | 130.4 |  |  |  | 11.9 | % |  |  | 140.4 |  |  |  | 12.7 |  | %
Independent professional services |  |  | 30.7 |  |  |  | 2.8 | % |  |  | 38.9 |  |  |  | 3.6 |  | %
Supplies |  |  | 37.8 |  |  |  | 3.4 | % |  |  | 59.3 |  |  |  | 5.4 |  | %
Insurance |  |  | 41.1 |  |  |  | 3.7 | % |  |  | 45.8 |  |  |  | 4.2 |  | %
Levies and duties |  |  | 15.0 |  |  |  | 1.4 | % |  |  | 19.8 |  |  |  | 1.8 |  | %
Other expenses |  |  | 25.2 |  |  |  | 2.3 | % |  |  | 16.0 |  |  |  | 1.3 |  | %
Construction costs |  |  | 6.6 |  |  |  | 0.6 | % |  |  | - |  |  |  |  |  | -
Total |  | $ | 336.6 |  |  |  | 30.6 | % |  | $ | 351.3 |  |  |  | 31.8 |  | %

Other operating expenses decreased by 4.2% to $336.6 million for the year ended December 31, 2023, compared to $351.3 million for the year ended December 31, 2022 mainly due to lower cost of “Supplies” and lower “Operation and maintenance” costs.
Cost of supplies decreased mostly due to lower price of electricity in our assets in Spain. In addition, our operation and maintenance costs decreased during 2023, compared to 2022 mainly due to lower O&M costs in Spain, where these services have been internalized and are now provided by employees of Atlantica, with the cost classified in “Employee benefit” expenses.
On the other hand, the cost of “Raw Materials” increased in the subsidiaries which are now performing the operation and maintenance which was previously subcontracted, as these costs are now assumed directly by subsidiaries of Atlantica. “Other expenses” include costs related to improvements in our Calgary district heating asset which are re-invoiced to the municipality, as previously discussed.
“Construction costs” refers to the cost of construction of ATS Expansion 1 and ATN Expansion 3.
Operating profit
As a result of the previously above-mentioned factors, operating profit increased by 23.2% to $342.0 million for the year ended December 31, 2023, compared with $277.7 million for the year ended December 31, 2022.
Financial income and financial expense 10

|  | Year ended December 31, |
Financial income and financial expense |  | 2023 |  |  | 2022 |
|  | ($ in millions) |
Financial income |  | $ | 25.0 |  |  | $ | 10.1 |
Financial expense |  |  | (323.8 | ) |  |  | (330.4 | )
Net exchange differences |  |  | (2.5 | ) |  |  | 10.3 |
Other financial income/(loss), net |  |  | (16.7 | ) |  |  | (0.9 | )
Financial expense, net |  | $ | (318.0 | ) |  | $ | (310.9 | )

10 Classification within Financial income and financial expense has been revised to show a more meaningful classification of financial income and expense following the increase in interest rates. Prior period classification has been revised accordingly.
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Financial income
The following table sets forth our Financial income for the years ended 2023, and 2022:

|  | Year ended December 31 |
Financial income |  | 2023 |  |  | 2022 |
|  | ($ in thousands) |
Interest income on deposits and current accounts |  | $ | 21.7 |  |  |  | 7.7 |
Interest income from loans and credits |  |  | 2.9 |  |  |  | 1.3 |
Interest rate gains on derivatives: cash flow hedges |  |  | 0.4 |  |  |  | 1.1 |
Total |  | $ | 25.0 |  |  |  | 10.1 |

Financial income increased from $10.1 million in 2022 to $25.0 million 2023 mostly due to higher remuneration of deposits resulting from higher interest rates.
Financial expense
The following table sets forth our financial expense for the years ended December 31, 2023 and 2022:

|  | Year ended December 31, |
Financial expense |  | 2023 |  |  | 2022 |
|  | ($ in millions) |
Interest on loans and notes |  | $ | (350.4 | ) |  | $ | (292.0 | )
Interest rates gains / losses derivatives: cash flow hedges |  |  | 26.6 |  |  |  | (38.4 | )
Total |  | $ | (323.8 | ) |  | $ | (330.4 | )

Financial expense decreased to $323.8 million in 2023 compared to $330.4 million in 2022. Interest rates have been higher in 2023 than in 2022, causing an increase in interest on loans and notes, which has been more than offset by the impact in our income statement of the derivatives hedging our loans. The decrease is due to a $26.6 million gain in “Interest rate gains/losses on derivatives: cash flow hedges”, where we record transfers from equity to the income statement when the hedged item impacts profit and loss compared to a $38.4 million loss in 2022, due to the increase in the reference rates in 2023, compared to 2022. Considering interest gains on hedge instruments of such loans and notes, total interest decreased in 2023 as in 2022, which is primarily due to the repayment of project and corporate debt in accordance with our financing arrangements.
Net exchange differences
Net exchange differences decreased to a $2.5 million loss in 2023 compared to a $10.3 million income in 2022. The decrease was mainly due to the change in fair value of caps hedging our net cash flows in Euros, which was largely stable in 2023 while it increased in 2022.
Other financial income/(expense), net
The following table sets forth our other financial income/(expense), net for the years ended December 31, 2023 and 2022:

|  | Year ended December 31, |
Other financial income/(expense), net |  | 2023 |  |  | 2022 |
|  | ($ in millions) |
Other financial income |  | $ | 8.8 |  |  | $ | 20.5 |
Other financial expense |  |  | (25.5 | ) |  |  | (21.4 | )
Total |  | $ | (16.7 | ) |  | $ | (0.9 | )

Other financial income/(expense), net increased to a net expense of $16.7 million in 2023, compared to a net expense of $0.9 million in 2022.
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Other financial income in 2023, primarily includes an income of $3.9 million corresponding to the change in the fair value of the conversion option of the Green Exchangeable Notes in the period, (compared to $12.0 million in 2022). Other financial income also includes a non-monetary change to the fair value of derivatives of Kaxu for which hedge accounting is not applied for $0.1 million (compared to $6.2 million in the 2022) and a one-time income related to the extension in the maturity of the Green Project Finance, which qualifies as a refinancing from an accounting perspective.
Other financial expense increased in 2023, mainly due to the financial impact related to the electricity market prices provision recorded at our solar assets in Spain. This is a long-term provision recorded at present value in accordance with the effective interest method, which progressively accrues a financial expense. Other financial expense also 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 decreased to $13.2 million in the year ended December 31, 2023, compared to $21.4 million in the year ended December 31, 2022 primarily due to a lower profit at Vento II, resulting from lower production and a lower price at Lone Star II after its PPA expired in January 2023.
Profit/(loss) before income tax
As a result of the previously mentioned factors, we reported a profit before income tax of $37.2 million for the year ended December 31, 2023, compared to a loss before income tax of $11.8 million for the year ended December 31, 2022.
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, 2023 and 2022, is as follows:

|  | For the year ended December 31, |
|  | 2023 |  |  | 2022 |
|  | ($ in millions) |
Consolidated profit / (loss) before taxes |  |  | 37.2 |  |  |  | (11.8 | )
Average statutory tax rate(1) |  |  | 25 | % |  |  | 25 | %
Corporate income tax at average statutory tax rate |  |  | (9.3 | ) |  |  | 2.9 |
Income tax of associates, net |  |  | 3.3 |  |  |  | 5.4 |
Differences in statutory tax rates |  |  | (4.3 | ) |  |  | (4.3 | )
Unrecognized NOLs and deferred tax assets |  |  | (11.1 | ) |  |  | (10.9 | )
Other Permanent Differences |  |  | 17.5 |  |  |  | 4.0 |
Other non-taxable income/(expense) |  |  | 3.1 |  |  |  | 12.7 |
Corporate income tax |  |  | (0.8 | ) |  |  | 9.7 |

Note:

(1) | The average statutory tax rate was calculated as an average of the statutory tax rates applicable to each of our subsidiaries weighted by the income before tax.

For the year ended December 31, 2023 the overall effective tax rate was different than the statutory rate of 25% primarily due to permanent differences, most of which relate to exchange rate differences in Mexico, where taxes are calculated in local currency, which was partially offset by unrecognized tax credits in several jurisdictions.
Loss /(profit) attributable to non-controlling interests
Loss attributable to non-controlling interests was $6.9 million for the year ended December 31, 2023 compared to $3.4 million profit for the year ended December 31, 2022. Loss /(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, Chile PV 3 and Tenes). The loss in profit attributable to non-controlling interest in 2023 was mainly due to the loss reported in Kaxu resulting from lower production as previously explained.
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Profit/(loss) attributable to the parent company
As a result of the previously mentioned factors, profit attributable to the parent company was $43.4 million for the year ended December 31, 2023, compared to a loss of $5.4 million for the year ended December 31, 2022.
Comparison of the Years Ended December 31, 2022 and 2021
The significant variances or variances of the significant components of the results of operations between the years ended December 31, 2022 and December 31, 2021, are discussed in the annual report on Form 20-F filed with the SEC on February 28, 2022.
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 lines and Water. We report our results in accordance with both criteria.
Comparison of the Years Ended December 31, 2023 and 2022
Revenue and Adjusted EBITDA by geography
The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 2023 and 2022, by geographic region:
Revenue by geography

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |
Revenue by geography |  | $ in millions |  |  | % of revenue |  |  | $ in millions |  |  | % of revenue |
North America |  | $ | 424.9 |  |  |  | 38.6 | % |  | $ | 405.1 |  |  |  | 36.8 | %
South America |  |  | 188.1 |  |  |  | 17.1 | % |  |  | 166.4 |  |  |  | 15.1 | %
EMEA |  |  | 486.9 |  |  |  | 44.3 | % |  |  | 530.5 |  |  |  | 48.1 | %
Total revenue |  | $ | 1,099.9 |  |  |  | 100.0 | % |  | $ | 1,102.0 |  |  |  | 100 | %

Adjusted EBITDA by geography

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |
Adjusted EBITDA by geography |  | $ in millions |  |  | % of Adjusted EBITDA |  |  | $ in millions |  |  | % of Adjusted EBITDA |
North America |  | $ | 319.3 |  |  |  | 40.1 | % |  | $ | 310.0 |  |  |  | 38.9 | %
South America |  |  | 146.7 |  |  |  | 18.5 | % |  |  | 126.5 |  |  |  | 15.9 | %
EMEA |  |  | 328.9 |  |  |  | 41.4 | % |  |  | 360.6 |  |  |  | 45.2 | %
Adjusted EBITDA(1) |  | $ | 794.9 |  |  |  | 100.0 | % |  | $ | 797.1 |  |  |  | 100.0 | %

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.”

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Volume by geography

|  | Volume produced/availability |
|  | Year ended December 31, |
Volume / availability by geography |  | 2023 |  |  | 2022 |
North America (GWh)(1) |  |  | 5,749 |  |  |  | 5,743 |
North America availability(2) |  |  | 99.6 | % |  |  | 98.9 | %
South America (GWh)(3) |  |  | 957 |  |  |  | 799 |
South America availability(2) |  |  | 99.9 | % |  |  | 99.9 | %
EMEA (GWh) |  |  | 1,301 |  |  |  | 1,278 |
EMEA availability |  |  | 99.7 | % |  |  | 102.3 | %

Notes:

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

(2) | Availability includes only those assets that have revenue based on availability.

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

North America
Revenue increased by 4.9% to $424.9 million for the year ended December 31, 2023, compared to $405.1 million for the year ended December 31, 2022, while Adjusted EBITDA increased by 3.0% to $319.3 million for the year ended December 31, 2023, compared to $310.0 million for 2022. The increase in revenue was mainly due to higher electricity production in our solar assets in the U.S. as previously discussed, together with higher revenue at ACT (see “Efficient natural gas & heat” below), which was partially offset by lower revenue at Coso due to lower production. Adjusted EBITDA increased mainly due to the increase in revenue and lower costs in our solar assets in the US, mostly caused by lower insurance costs and lower O&M costs at Mojave. These effects were partially offset by lower EBITDA at Vento II, caused by lower production and lower prices at Lone Star II after the end of its PPA.
South America
Revenue increased by 13.0% to $188.1 million for the year ended December 31, 2023, compared to $166.4 million for the year ended December 31, 2022. The increase was mainly due to indexation to inflation in our revenue in transmission lines, including a positive tariff adjustment in Chile TL 3 corresponding to previous years which was published in the second quarter of 2023, and in wind assets in South America. Revenue also increased due to assets recently consolidated and assets which entered in operation recently. This increase was partially offset by lower revenue at our PV assets in Chile, where production decreased mostly due to lower electricity prices and, to a lower extent, curtailments. Adjusted EBITDA increased by 15.9% to $146.7 million for the year ended December 31, 2023, compared to $126.5 million for the year ended December 31, 2022, mostly due to the increase in revenue and to a $4.6 million gain from the sale of part of our equity interest in our development company in Colombia to a partner in the first quarter of 2023.
EMEA
Revenue decreased to $486.9 million for the year ended December 31, 2023, which represents a decrease of 8.2% compared to $530.5 million for the year ended December 31, 2022. The decrease was mainly due to lower revenue at Kaxu by $45.8 million, mostly due to an unscheduled outage coupled with a prolonged maintenance stop, as previously explained. Revenue at our solar assets in Spain remained stable.
Adjusted EBITDA decreased to $328.9 million for the year ended December 31, 2023, which represents a decrease of 8.8% compared to $360.6 million for the year ended December 31, 2022. Adjusted EBITDA decreased mainly due to the outage at Kaxu causing a $26.6 million decrease in EBITDA. The impact in Adjusted EBITDA was lower as a result of insurance 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, 2023 and 2022, by business sector:

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |
Revenue by business sector |  | $ in millions |  |  | % of revenue |  |  | $ in millions |  |  | % of revenue |
Renewable energy |  | $ | 802.8 |  |  |  | 73.0 | % |  | $ | 821.4 |  |  |  | 74.5 | %
Efficient natural gas & heat |  |  | 118.4 |  |  |  | 10.8 | % |  |  | 113.6 |  |  |  | 10.3 | %
Transmission lines |  |  | 123.5 |  |  |  | 11.2 | % |  |  | 113.2 |  |  |  | 10.3 | %
Water |  |  | 55.2 |  |  |  | 5.0 | % |  |  | 53.8 |  |  |  | 4.9 | %
Revenue |  | $ | 1,099.9 |  |  |  | 100.0 | % |  | $ | 1,102.0 |  |  |  | 100 | %

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |
Adjusted EBITDA by business sector |  | $ in millions |  |  | % of Adjusted EBITDA |  |  | $ in millions |  |  | % of Adjusted EBITDA |
Renewable energy |  | $ | 575.7 |  |  |  | 72.4 | % |  | $ | 588.0 |  |  |  | 73.8 | %
Efficient natural gas & heat |  |  | 87.4 |  |  |  | 11.0 | % |  |  | 84.6 |  |  |  | 10.6 | %
Transmission lines |  |  | 96.0 |  |  |  | 12.1 | % |  |  | 88.0 |  |  |  | 11.0 | %
Water |  |  | 35.8 |  |  |  | 4.5 | % |  |  | 36.5 |  |  |  | 4.6 | %
Adjusted EBITDA(1) |  | $ | 794.9 |  |  |  | 100.0 | % |  | $ | 797.1 |  |  |  | 100 | %

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.”

Volume by business sector

|  | Volume produced/availability |
|  | Year ended December 31, |
Volume / availability by business sector |  | 2023 |  |  | 2022 |
Renewable energy (GWh) (1) |  |  | 5,458 |  |  |  | 5,319 |
Efficient natural gas & Heat (GWh) (2) |  |  | 2,549 |  |  |  | 2,501 |
Efficient natural gas & Heat availability |  |  | 99.6 | % |  |  | 98.9 | %
Transmission availability |  |  | 100.0 | % |  |  | 100.0 | %
Water availability |  |  | 99.7 | % |  |  | 102.3 | %

Notes:

(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.

Renewable energy
Revenue decreased to $802.8 million for the year ended December 31, 2023, which represents a decrease of 2.3% compared to $821.4 million for the year ended December 31, 2022. The decrease in revenue was primarily due to lower revenue at Kaxu as previously discussed. On the other hand, revenue increased at our solar assets in the U.S. due to higher electricity production as previously explained and at our wind assets in South America due to higher production and price indexation to inflation, together with the contribution of assets recently consolidated. As previously explained, revenue at our solar assets in Spain remained stable.
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Adjusted EBITDA decreased to $575.7 million for the year ended December 31, 2023, which represents a decrease of 2.1% compared to $588.0 million for the year ended December 31, 2022. The decrease in Adjusted EBITDA was mainly due to the decrease in revenue and to lower EBITDA at Vento II, as previously explained.
Efficient natural gas & heat
Revenue increased by 4.2% to $118.4 million for the year ended December 31, 2023, compared to $113.6 million for the year ended December 31, 2022, while Adjusted EBITDA increased by 3.3% to $87.4 million for the year ended December 31, 2023, compared to $84.6 million for the year ended December 31, 2022. Revenue and Adjusted EBITDA increased at ACT with Adjusted EBITDA increasing by less mainly due to higher O&M costs, since there is a portion of revenue related to O&M services plus a margin.
Transmission lines
Revenue increased by 9.0% to $123.5 million for the year ended December 31, 2023, compared to $113.2 million for year ended December 31, 2022, while Adjusted EBITDA increased by 9.1% to $96.0 million for the year ended December 31, 2023 compared to $88.0 million for the year ended December 31, 2022. The increase in revenue and Adjusted EBITDA was mainly due to tariff indexation to inflation including a positive tariff adjustment in Chile TL 3 corresponding to previous years.
Water
Revenue increased to $55.2 million for the year ended December 31, 2023, which represents a 2.6% increase compared to $53.8 million for the year ended December 31, 2022. Adjusted EBITDA decreased to $35.7 million for the year ended December 31, 2023, which represents a 1.9% decrease compared to $36.5 million for year ended December 31, 2022. Adjusted EBITDA decreased while Revenue increased because of higher O&M costs, which are indexed to inflation.
Comparison of the Years Ended December 31, 2022 and 2021
The significant variances in the revenue and volume, by geographic region and business sector, between the years ended December 31, 2022 and December 31, 2021, are discussed in the Form 20-F filed with the SEC on February 28, 2023.

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 the development and construction of new assets and operations (see “Item 4.B—Business Overview—Our Business Strategy”).

As 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.
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Liquidity position

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |
|  | ($ in millions) |
Corporate Liquidity |  |  |  |  |  |
Cash and cash equivalents at Atlantica Sustainable Infrastructure, plc, excluding subsidiaries |  | $ | 33.0 |  |  | $ | 60.8 |
Revolving Credit Facility availability |  |  | 378.1 |  |  |  | 385.1 |
Total Corporate Liquidity(1) |  | $ | 411.1 |  |  | $ | 445.9 |
Liquidity at project companies |  |  |  |  |  |  |  |
Restricted Cash |  |  | 177.0 |  |  |  | 207.6 |
Non-restricted cash |  |  | 238.3 |  |  |  | 332.6 |
Total cash at project companies |  | $ | 415.3 |  |  | $ | 540.2 |

Note:

(1) | Corporate Liquidity means cash and cash equivalents held at Atlantica Sustainable Infrastructure plc as of December 31, 2023, and available revolver capacity as of December 31, 2023.

Cash at the project level includes $177.0 million and $207.6 million restricted cash balances as of December 31, 2023 and 2022, 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.
As of December 31, 2023, $16.9 million of letters of credit were outstanding under the Revolving Credit Facility and we had $55 million of borrowings. As a result, as of December 31, 2023, $378.1 million was available under the Revolving Credit Facility. As of December 31, 2022, we had $30 million of borrowings and $34.9 million of letters of credit outstanding and $385.1 million was available under our Revolving Credit Facility.
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 and distributions in the future.
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 working capital requirements, 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.
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.
The following table summarizes our credit ratings as of December 31, 2023. 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, the “at-the-market program”, other credit lines and our commercial paper program.
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|  |  |  |  | As of December 31, 2023 |  |  | As of December 31, 2022 |
|  | Maturity |  |  | ($ in millions) |
Revolving Credit Facility |  | 2025 |  |  | $ | 54.4 |  |  |  | 29.4 |
Other Facilities(1) |  | 2024-2028 |  |  |  | 53.3 |  |  |  | 30.1 |
Green Exchangeable Notes |  | 2025 |  |  |  | 110.0 |  |  |  | 107.0 |
2020 Green Private Placement |  | 2026 |  |  |  | 318.7 |  |  |  | 308.4 |
Note Issuance Facility 2020 |  | 2027 |  |  |  | 152.4 |  |  |  | 147.2 |
Green Senior Notes |  | 2028 |  |  |  | 396.0 |  |  |  | 395.1 |
Total Corporate Debt(2) |  |  |  |  | $ | 1,084.8 |  |  |  | 1,017.2 |
Total Project Debt |  |  |  |  | $ | 4,319.3 |  |  |  | 4,553.1 |

Notes:

(1) | Other facilities include the commercial paper program, accrued interest payable and other debts.

(2) | Accounting amounts may differ from notional amounts.

A) Corporate debt agreements
Green Senior Notes
On May 18, 2021, we issued the 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.
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, the Green Exchangeable Notes and the credit line with Export Development Canada.
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.
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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, the Green Senior Notes, and the credit line with Export Development Canada.
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 €140 million ($155 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 three-month EURIBOR plus a margin of 5.25% with a floor of 0% for the EURIBOR. We had a cap at 0% for the EURIBOR with 3.5 years maturity and in December 2023, we entered into a cap at 4% to hedge the variable interest rate risk with maturity on December 31, 2024.
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, the Green Senior Notes, and the credit line with Export Development Canada. 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 ($320 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.
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, the Green Senior Notes and the credit line with Export Development Canada. 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.
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). On May 30, 2023, the maturity of the Revolving Credit Facility was extended to December 31, 2025. 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, Term SOFR, plus a Term SOFR Adjustment equal to 0.10% per annum, 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 ½ of 1.00%, (ii) the prime rate of the administrative agent under the Revolving Credit Facility and (iii) Term SOFR plus 1.00%, in any case, plus a percentage determined by reference to our leverage ratio, ranging between 0.60% and 1.00%.
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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, the Green Senior Notes and the credit line with Export Development Canada. 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.
Credit Line with Export Development Canada
In June 2023 we entered into a senior unsecured $50 million line of credit with Export Development Canada with a 3 year maturity. The purpose of the credit line is to finance the construction of sustainable projects. The interest is at a rate per annum equal to Term SOFR plus a percentage determined by reference to our leverage ratio, ranging between 2.46% and 3.11%, with a floor of 0% for the Term SOFR. The facility matures on May 25, 2026 and was fully available as of December 31, 2023.
Our obligations under this credit line are equal in right of payment with our outstanding obligations under the 2020 Green Private Placement, the Note Issuance Facility 2020, the Green Exchangeable Notes, the Green Senior Notes, the Revolving Credit Facility. Our payment obligations under this line 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, and are 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 ($11.0 million) which was available in Euros or U.S. Dollars. Amounts drawn accrue interest at a rate per annum equal to the sum of the three-month EURIBOR or SOFR, plus a margin of 2%, with a floor of 0% for the EURIBOR or SOFR. On August 7, 2023 the limit was increased to €15 million ($16.6 million) and the maturity was extended until July 2025. As of December 31, 2023, €9.0 million ($9.9 million) where drawn from this credit line.
In December 2020 and January 2022, we also entered into two different loans with banks for €5 million ($5.5 million) each. The maturity dates are December 4, 2025 and January 31, 2026, respectively, and such loans accrue interest at a rate per annum equal to 2.50% and 1.90%, respectively. Furthermore, in February 2023, we entered into a loan with a bank for €7 million ($7.7 million) with maturity in February 2028 accrues interest at a rate per annum equal to 4.2%.
Commercial Paper Program
On November 21, 2023, we filed a euro commercial paper program with the Alternative Fixed Income Market (MARF) in Spain. The program has a maturity of twelve months. The program allows Atlantica to issue short term notes for up to €100 million, with such notes having a tenor of up to two years. As of December 31, 2023, we had €23.3 million ($25.7 million) issued and outstanding under the Commercial Paper Program at an average cost of 5.23% maturing on or before June 2024.
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).
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Furthermore, our corporate debt agreements contain customary change of control provisions (as such term is defined in each of those agreements) or similar provisions. Under the Revolving Credit Facility, a change of control without required lenders’ consent would trigger an event of default. In the other corporate debt agreements or securities, a change of control or similar provision without the consent of the relevant required holders would trigger the obligation to make an offer to purchase the respective notes at (i) 100% of the principal amount in the case of the 2020 Green Private Placement and Green Exchangeable Notes and at (ii) 101% of the principal amount in the case of the Note Issuance Facility 2020 and the Green Senior Notes. In the case of the Green Senior Notes, such prepayment obligation would be triggered only if there is a credit rating downgrade by any of the agencies.
B) At-The-Market Program
On February 28, 2022, we established an “at-the-market program” and entered into the Distribution Agreement with BofA Securities, Inc., MUFG Securities Americas Inc. and RBC Capital Markets LLC, as our sales agents, 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 shelf registration statement on Form F-3 filed with the SEC on August 3, 2021, and a prospectus supplement that we filed on February 28, 2022. During the year 2023, we did not issue and sell any ordinary shares under the program.
C) Project debt refinancing
In March 2023, we refinanced the Solaben 2 and Solaben 3 project debt. In June 2023 we extended the maturity of the debt for Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 2 & 3 and Solaben 1 & 6. (see “Item 4— Information on the Company— Our Operations —Renewable Energy”)
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Uses of liquidity and capital
A) Debt Service
Principal payments on debt as of December 31, 2023, are due in the following periods according to their contracted maturities:
Principal debt repayment schedule

|  | Total |  |  | 2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | 2028 |  |  | Subsequent years |
|  | $ in millions |  |  |  |
Solana |  |  | 568.1 |  |  |  | 25.4 |  |  |  | 26.8 |  |  |  | 29.5 |  |  |  | 32.4 |  |  |  | 35.4 |  |  |  | 418.6 |
Mojave |  |  | 471.2 |  |  |  | 37.6 |  |  |  | 38.1 |  |  |  | 39.4 |  |  |  | 40.7 |  |  |  | 36.2 |  |  |  | 279.2 |
Coso(1) |  |  | 188.6 |  |  |  | 14.6 |  |  |  | 14.2 |  |  |  | 14.7 |  |  |  | 145.1 |  |  |  | - |  |  |  | - |
ACT |  |  | 401.5 |  |  |  | 39.2 |  |  |  | 42.3 |  |  |  | 54.6 |  |  |  | 59.0 |  |  |  | 68.0 |  |  |  | 138.4 |
North America |  |  | 1,629.4 |  |  |  | 116.8 |  |  |  | 121.4 |  |  |  | 138.2 |  |  |  | 277.2 |  |  |  | 139.6 |  |  |  | 836.2 |
Chile PV 1 |  |  | 50.2 |  |  |  | 2.6 |  |  |  | 1.0 |  |  |  | 1.1 |  |  |  | 1.6 |  |  |  | 2.2 |  |  |  | 41.7 |
Chile PV 2 |  |  | 20.8 |  |  |  | 1.3 |  |  |  | 1.4 |  |  |  | 2.4 |  |  |  | 2.0 |  |  |  | 2.2 |  |  |  | 11.5 |
Palmatir |  |  | 66.3 |  |  |  | 7.0 |  |  |  | 6.6 |  |  |  | 7.0 |  |  |  | 7.5 |  |  |  | 8.0 |  |  |  | 30.2 |
Cadonal |  |  | 44.3 |  |  |  | 3.5 |  |  |  | 3.1 |  |  |  | 3.4 |  |  |  | 3.6 |  |  |  | 3.9 |  |  |  | 26.8 |
Melowind |  |  | 66.2 |  |  |  | 4.8 |  |  |  | 5.0 |  |  |  | 5.1 |  |  |  | 4.8 |  |  |  | 5.7 |  |  |  | 40.8 |
ATN |  |  | 81.6 |  |  |  | 6.1 |  |  |  | 6.4 |  |  |  | 6.9 |  |  |  | 7.3 |  |  |  | 6.7 |  |  |  | 48.2 |
ATS |  |  | 384.6 |  |  |  | 12.0 |  |  |  | 8.3 |  |  |  | 9.5 |  |  |  | 10.7 |  |  |  | 12.1 |  |  |  | 332.0 |
ATN 2 |  |  | 40.7 |  |  |  | 5.0 |  |  |  | 5.1 |  |  |  | 5.4 |  |  |  | 5.4 |  |  |  | 5.6 |  |  |  | 14.2 |
Quadra 1&2 and Palmucho |  |  | 54.2 |  |  |  | 5.5 |  |  |  | 6.1 |  |  |  | 6.6 |  |  |  | 7.3 |  |  |  | 8.0 |  |  |  | 20.7 |
South America |  |  | 808.9 |  |  |  | 47.8 |  |  |  | 43.0 |  |  |  | 47.4 |  |  |  | 50.2 |  |  |  | 54.4 |  |  |  | 566.1 |
Solaben 2&3(2) |  |  | 321.2 |  |  |  | 13.2 |  |  |  | 19.4 |  |  |  | 21.5 |  |  |  | 23.1 |  |  |  | 115.9 |  |  |  | 128.1 |
Solacor 1&2 |  |  | 209.6 |  |  |  | 14.7 |  |  |  | 15.1 |  |  |  | 15.5 |  |  |  | 15.9 |  |  |  | 16.1 |  |  |  | 132.3 |
Helios 1&2 |  |  | 279.7 |  |  |  | 22.2 |  |  |  | 22.4 |  |  |  | 21,8 |  |  |  | 22.2 |  |  |  | 22.5 |  |  |  | 168.6 |
Helioenergy 1&2 |  |  | 235.2 |  |  |  | 19.3 |  |  |  | 20.5 |  |  |  | 19.4 |  |  |  | 20.7 |  |  |  | 23.0 |  |  |  | 132.3 |
Solnova 1,3&4 |  |  | 338.1 |  |  |  | 31.5 |  |  |  | 31.5 |  |  |  | 33.1 |  |  |  | 32.9 |  |  |  | 31.7 |  |  |  | 177.4 |
Solaben 1&6 |  |  | 179.7 |  |  |  | 14.3 |  |  |  | 15.2 |  |  |  | 15.9 |  |  |  | 16.3 |  |  |  | 17.0 |  |  |  | 101.0 |
Rioglass |  |  | 5.6 |  |  |  | 2.4 |  |  |  | 1.6 |  |  |  | 1.2 |  |  |  | 0.3 |  |  |  | 0.1 |  |  |  | - |
Italy PV 1,3&4 |  |  | 1.5 |  |  |  | 0.6 |  |  |  | 0.6 |  |  |  | 0.3 |  |  |  | 0.0 |  |  |  | - |  |  |  | - |
Kaxu |  |  | 234.0 |  |  |  | 26.3 |  |  |  | 26.0 |  |  |  | 29.3 |  |  |  | 31.9 |  |  |  | 34.7 |  |  |  | 85.8 |
Skikda |  |  | 2.6 |  |  |  | 2.6 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Tenes |  |  | 73.7 |  |  |  | 8.6 |  |  |  | 8.6 |  |  |  | 8.9 |  |  |  | 9.3 |  |  |  | 9.6 |  |  |  | 28.7 |
EMEA |  |  | 1,880.9 |  |  |  | 155.7 |  |  |  | 160.9 |  |  |  | 166.9 |  |  |  | 172.6 |  |  |  | 270.6 |  |  |  | 954.2 |
Total project debt |  | $ | 4,319.3 |  |  |  | 320.3 |  |  |  | 325.3 |  |  |  | 352.5 |  |  |  | 500.0 |  |  |  | 464.6 |  |  |  | 2,356.5 |
Corporate debt |  | $ | 1,084.8 |  |  |  | 34.0 |  |  |  | 179.1 |  |  |  | 321.0 |  |  |  | 154.0 |  |  |  | 396.8 |  |  |  | - |
Total |  | $ | 5,404.0 |  |  |  | 354.3 |  |  |  | 504.4 |  |  |  | 673.5 |  |  |  | 654.0 |  |  |  | 861.4 |  |  |  | 2,356.5 |

Note:

| (1) | Includes the outstanding amount of the Project Finance from Coso. Of which, on July 15, 2021 the notional amount was $233 million. From that amount, $93 million is progressively repaid until 2027. The remaining $140 million are expected to be refinanced on or before 2027.

| (2) | 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 |  |  | 713.5 |  |  |  | 81.9 |  |  |  | 100.0 |  |  |  | 97.0 |  |  |  | 434.6 |
Accrued interest estimate during the useful life of loans |  |  | 1,717.8 |  |  |  | 264.2 |  |  |  | 481.4 |  |  |  | 359.4 |  |  |  | 612.8 |

Purchase obligations include agreements for the purchase of goods or services that are enforceable and legally binding and that specify all significant terms.
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.

C) | Cash dividends to investors

We intend to distribute a significant portion of our cash available for distribution to shareholders on an annual basis less reserves for the prudent conduct of our business, 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 (See “Item 8 — Financial Information—Consolidated Statements and Other Financial Information—Dividend Policy.”).

D) | Investments and Acquisitions

The investments and the assets under construction detailed in “Significant events in 2023” have been part of the use of our liquidity in 2023. In addition, we have made investments in assets which are currently under development or construction.
We intend to grow our business through the development and construction of our project pipeline including expansion and repowering opportunities, as well as greenfield developments, third-party acquisitions and the optimization of our existing portfolio. We currently have a pipeline of assets under development of approximately 2.2 GW of renewable energy and 6.0 GWh of storage. Approximately 47% of the projects are PV, 43% storage 11% wind and 1% other projects, while 22% are expected to reach RTB in 2024-2025, 28% are in an advanced development stage and 50% are in early stage. Also, 20% are expansion or repowering opportunities of existing assets and 80% greenfield developments.

E) | Capital Expenditures

In 2023, we invested $27.9 million in maintenance capital expenditures in our assets. In 2022, we invested $39.1 million in maintenance capital expenditures in our assets, mainly corresponding to capital expenditures and equipment replacements at Solana. 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, 2023, 2022 and 2021:

|  | Year ended December 31, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
|  | ($ in millions) |
Gross cash flows from operating activities |  |  |  |  |  |  |  |  |
Profit/(loss) for the year |  | $ | 36.4 |  |  | $ | (2.1 | ) |  | $ | (10.9 | )
Adjustments to reconcile after-tax profit to net cash generated by operating activities |  |  | 720.2 |  |  |  | 786.9 |  |  |  | 861.9 |
Profit/(loss) for the year adjusted by non-monetary items |  | $ | 756.6 |  |  | $ | 784.8 |  |  | $ | 851.0 |
Net interest/taxes paid |  |  | (272.7 | ) |  |  | (277.3 | ) |  |  | (342.3 | )
Changes in working capital |  |  | (95.8 | ) |  |  | 78.8 |  |  |  | (3.1 | )
Net cash provided by operating activities |  | $ | 388.1 |  |  | $ | 586.3 |  |  | $ | 505.6 |
Net cash used in investing activities |  |  |  |  |  |  |  |  |  |  |  |
Business Combinations and investments in entities under equity method |  |  | (29.2 | ) |  |  | (50.5 | ) |  |  | (362.4 | )
Investments in operating concessional assets(1) |  |  | (27.9 | ) |  |  | (39.1 | ) |  |  | (19.2 | )
Investments in assets under development or construction |  |  | (56.3 | ) |  |  | (36.8 | ) |  |  | (7.0 | )
Distributions from entities under the equity method |  |  | 34.3 |  |  |  | 67.7 |  |  |  | 34.8 |
Net divestment in other non-current financial assets |  |  | 27.5 |  |  |  | 1.3 |  |  |  | 2.7 |
Net cash used in investing activities |  | $ | (51.6 | ) |  | $ | (57.4 | ) |  | $ | (351.2 | )
Net cash used in financing activities |  | $ | (491.4 | ) |  | $ | (535.0 | ) |  | $ | (380.1 | )
Net (decrease) in cash and cash equivalents |  |  | (154.9 | ) |  |  | (6.1 | ) |  |  | (225.7 | )
Cash and cash equivalents at beginning of the year |  |  | 601.0 |  |  |  | 622.7 |  |  |  | 868.5 |
Translation differences cash and cash equivalents |  |  | 2.2 |  |  |  | (15.6 | ) |  |  | (20.1 | )
Cash and cash equivalents at the end of the year |  | $ | 448.3 |  |  | $ | 601.0 |  |  | $ | 622.7 |

Net cash flows provided by operating activities
Net cash provided by operating activities in 2023 was $388.1 million, a 33.8% decrease compared to $586.3 million for the previous year. The decrease was mainly due to the negative impact of changes in working capital for $95.8 million in the twelve-month period ended December 31, 2023 compared to a positive change in working capital for $78.8 million in the same period of the previous year:

| - | During the year 2022, in our assets in Spain we collected cash in line with the old parameters corresponding to the regulation in place at the beginning of the year 2022 and we were booking revenue in accordance with the new parameters published in draft form, which were lower. This caused a positive change in working capital of approximately $68.7 million in the twelve-month period ended December 31, 2022. In the first quarter of 2023, collections at these assets in Spain were regularized, following the approval on December 14, 2022 of the new parameters for 2022, causing a negative change in working capital of approximately $57.8 million for the twelve-month period ended December 31, 2023.

| - | Additionally, working capital in the twelve-month period ended December 31, 2023, also includes a negative change due to lower collections in ACT of approximately $56.4 million compared to a positive change in working capital of approximately $40.4 million of the same period from 2022

| - | In 2022, we had a positive variation in working capital of $78.8 million mostly due to better collections from Pemex in ACT and better collections in Spain. In Spain, in 2022 we collected revenue in line with the parameters corresponding to the regulation in place at the beginning of the year 2022, as the new parameters became final on December 14, 2022, while revenue for the year ended December 31, 2022 was recorded in accordance with the new parameters.

The significant variances in the net cash flows provided by or used in operating activities for the year ended December 31, 2022 compared to the year ended December 31, 2021 are discussed in the Form 20-F filed with the SEC on March 1, 2023.
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Net cash used in investing activities
For the year ended December 31, 2023, net cash used in investing activities amounted to $51.6 million and corresponded mainly to $84.2 million investments in new assets as well as development and construction of and investments in existing assets, including investments and replacements in Solana. These cash outflows were partially offset by $34.3 million of dividends received from associates under the equity method, of which $11.4 million corresponded to Amherst by AYES Canada, most of which were paid to our partner in this project, and $16.1 million corresponding to Vento II.
For the year ended December 31, 2022, net cash used in investing activities amounted to $57.4 million and included mainly to $50.5 million paid for acquisitions consisting mainly of Chile TL4, Chile PV 3, Chile PMGD and Italy PV4, investments in assets under construction for $36.8 million and other investments in existing assets for $39.1 million, including the investments and replacements in Solana. These cash outflows were partially offset by $67.7 million of dividends received from entities under the equity method, of which $26.9 million corresponded to Amherst Island Partnership by AYES Canada, most of which were paid to our partner in this project.
Net cash used in financing activities
For the year ended December 31, 2023, net cash used in financing activities amounted to $491.4 million and includes the net repayment of principal of our project financing for $318.6 million, dividends paid to shareholders for $206.8 million and non-controlling interests for $31.4 million. These cash outflows were partially offset by the net proceeds of corporate debt mainly related to the issuance of commercial paper for a net amount of $14.6 million and the Revolving Credit Facility, which was drawn for an additional $25.0 million in the twelve-month period ended December 31, 2023. In 2023, we also had a cash inflow of $19.8 million corresponding to the capital contribution of our partner to the project Chile PV3, in which we are building a 121 MWh battery system.
For the year ended December 31, 2022, net cash used in financing activities amounted to $535.0 million and includes the net repayment of principal of our project financing for $426.4 million and dividends paid to shareholders for $203.1 million and non-controlling interests for $39.2 million. These cash outflows were partially offset by the proceeds from the equity raised under the “at-the-market program” for a net amount of $113.1 million and by net proceeds from corporate debt of $20.6 million, corresponding mainly to the increase of the amount drawn under our Revolving Credit Facility.

C. | Research and Development

As of December 31, 2023, we own 22 patents and technology licenses related to key components of our assets, to processes and to solutions to monitor, operate and maintain our assets in a sustainable and cost-effective manner, as well as 3 patents currently in process. We also have an Operations Department that dedicates time and effort to identifying potential measures to improve asset performance, reducing operating costs and developing tools to manage our assets more efficiently. In addition, we have an in-house advanced analytics team to improve the performance of our existing technologies. The advanced analytics team focuses on data analytics and machine learning technologies to provide accurate energy production forecasts, predict equipment breakdowns or malfunctions, and reduce the risk of major outages as well as health and safety and environmental risks, among others.

D. | Trend Information

Other than as disclosed elsewhere in this annual report on, we are not aware of any trends, uncertainties, demands, commitments or events for the year ended December 31, 2023 that are reasonably likely to have a material adverse effect on our revenues, income, profitability, liquidity or capital resources, or that caused the disclosed financial information to be not necessarily indicative of future operating results or financial conditions.

E. | 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.
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For an understanding of the accounting policies for these items it 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:
Estimates:

- | Impairment of contracted concessional, Property, Plant and Equipment (PP&E) and other intangible assets

Impairment exists when the carrying value of an asset or cash generating unit exceeds its recoverable amount, which is the higher of its fair value less costs of disposal and its value in use. The value in use calculation is based on a discounted cash flow model, which is sensitive to the discount rate used as well as the expected future cash-inflows. The significant assumptions which required substantial estimates used in management’s impairment calculation are discount rates and projections considering real data based on contract terms and projected changes in selling prices, energy generation and costs.

- | Recoverability of deferred tax assets

Deferred tax assets are recognized for unused tax losses to the extent that it is probable that taxable profit will be available against which the losses can be utilized. Significant management estimates are required to determine the amount of deferred tax assets that can be recognized, based upon the likely timing and the level of future taxable profits together with future tax planning strategies.

- | Fair value of derivative financial instruments

When the fair values of financial assets and financial liabilities recorded in the statement of financial position cannot be measured based on quoted prices in active markets, their fair value is measured using valuation techniques including the discounted cash flow model. The inputs to these models are taken from observable markets where possible, but where this is not feasible, a degree of estimate is required in establishing fair values. Estimates include considerations of inputs such as liquidity risk, credit risk and volatility. Changes in assumptions relating to these factors could affect the reported fair value of financial instruments.

- | Fair value of identifiable assets and liabilities arising from a business combination

The assets acquired and liabilities assumed on a business combination are recognized at the fair values of the underlying items. The estimates that have a significant risk of causing a material adjustment to the carrying amounts of the assets and liabilities are the ones considered when performing impairment review of operating assets (see above).
Judgements:

- | Assessment of contracted concessional agreements

By evaluating the terms and conditions of each contracted concessional agreement, we determine the accounting category to which the asset belongs (e.g. IAS 16, IFRIC 12 or IFRS 16).

- | Assessment of control

Judgement is required in determining the nature of Atlantica´s interest in another entity and in determining if it has control, joint control or significant influence over it.
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.
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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, 2023, 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.
Contracted concessional, Property, Plant and Equipment (PP&E) and other intangible assets
The assets accounted for by Atlantica as contracted concessional assets under IFRIC 12 (either intangible model or financial model) as PP&E under IAS 16 or as other intangible assets under IAS 38 or under IFRS 16 (as “Lessee” or “Lessor”), include renewable energy assets, transmission lines, efficient natural gas assets and water plants.

a) | Contracted concessional assets under IFRIC 12

The infrastructure used in a concession accounted for under IFRIC 12 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.
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. If the operator performs more than one service (i.e. construction or upgrade services and operation services) under a single contract or arrangement, consideration received or receivable shall be allocated by reference to the relative fair values of the services delivered, when the amounts are separately identifiable.
Consequently, even though construction is subcontracted and it is not performed by Atlantica, in accordance with the provisions of IFRIC 12, we recognize and measure revenue and costs for providing construction services during the period of construction of the infrastructure in accordance with IFRS 15. Construction revenue is recorded within “Other operating income” and Construction cost, which is fully contracted, is recorded within “Other operating expenses”. This applies in the same way to the two models.
The useful life of these assets is approximately the same as the length of the concession arrangement.
Intangible asset
We recognize an intangible asset to the extent that it receives a right to charge final customers for the use of the infrastructure. This intangible asset is subject to the provisions of IAS 38 and is amortized linearly, taking into account the estimated period of commercial operation of the infrastructure which coincides with the concession period.
Once the infrastructure is in operation, the treatment of income and expenses is as follows:

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

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- | 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.

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

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

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

b) | Property, plant and equipment (PP&E) under IAS 16

Property, plant and equipment is measured at historical cost, including all expenses directly attributable to the acquisition, less depreciation and impairment losses, with the exception of land, which is presented net of any impairment losses. Such cost includes the cost of replacing part of the plant and equipment and borrowing costs for long-term installation projects if the recognition criteria is met. Repair and maintenance costs are recognized in profit or loss as incurred.
Depreciation is calculated on a straight-line basis over the estimated useful lives of the assets.
We review the estimated residual values and expected useful lives of assets at least annually. In particular, we consider the impact of health, safety and environmental legislation in its assessment of expected useful lives and estimated residual values.
An item of property, plant and equipment and any significant part initially recognized is derecognized upon disposal (i.e., at the date the recipient obtains control) or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss when the asset is derecognized.

c) | Right of uses under IFRS 16

We assess at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.
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Atlantica as a lessee:
We apply a single recognition and measurement approach for all leases, except for short-term leases and leases of low-value assets. We recognize lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets.
Main right of use agreements corresponds to land rights. We recognize 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.

d) | Other intangible assets

Other intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and accumulated impairment losses. Intangible assets are amortized over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired.
An intangible asset is derecognized upon disposal (i.e., at the date the recipient obtains control) or when no future economic benefits are expected from its use or disposal. Any gain or loss arising upon derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss.
Research and development costs:
Research costs are expensed as incurred. Development expenditures on an individual project are recognized as an intangible asset when we can demonstrate:

- | the technical feasibility of completing the intangible asset so that the asset will be available for use or sale

- | its intention to complete and its ability and intention to use or sell the asset

- | how the asset will generate future economic benefits

- | the availability of resources to complete the asset

- | the ability to measure reliably the expenditure during development

Following initial recognition of the development expenditure as an asset, the asset is carried at cost less any accumulated amortization and accumulated impairment losses. Amortization of the asset begins when development is complete, and the asset is available for use. It is amortized over the period of expected future benefit. During the period of development, the asset is tested for impairment annually.
Revenue Recognition
According to IFRS 15, Revenue from Contracts with Customers, we assess the goods and services promised in the contracts with the customers and identifies as a performance obligation 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 Appendix III-2.
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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 rate of return 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 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 concessional assets to identify any indicators of impairment at least annually. When impairment indicators exist, we calculate the recoverable amount of the asset.
The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, we calculate the recoverable amount of the cash generating unit, or CGU to which the asset belongs.
When the carrying amount of the CGU to which these assets belong is higher than its recoverable amount, the assets are impaired.
Assumptions used to calculate value in use include a discount rate and projections considering real data based on the contract terms and projected changes in both selling prices and costs. The discount rate is estimated by management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.
For contracted or concession revenue assets with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no terminal value is assumed. Contracted revenue assets have a contractual structure that permits to estimate quite accurately the costs of the project and revenue during the life of the project.
Projections take into account real data based on the contract terms and fundamental assumptions based on part in specific reports prepared internally and supported by third-party reports, assumptions on demand and assumptions on production. Additionally, assumptions on macroeconomic conditions are also considered, such as inflation rates, future interest rates and sensitivity analysis are performed over all major assumptions, which can have a significant impact on the value of the asset.
Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.
Taking into account that in most CGUs the specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash-flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is performed.
In any case, sensitivity analyses are performed, especially in relation with the discount rate used and fair value changes in the main business variables, in order to ensure that possible changes in the estimates of these items do not impact the recovery of recognized assets.
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”.
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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, we estimate the CGU’s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the income statement.
Assessment of control
Control over an investee is achieved when we have power over the investee, we are exposed, or have rights, to variable returns from our involvement with the investee and have the ability to use its power to affect its returns. We reassess whether or not we control an investee when facts and circumstances indicate that there are changes to one or more of these three elements of control.
We use the acquisition method to account for business combinations of companies controlled by a third party. According to this method, identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Any contingent consideration is recognized at fair value at the acquisition date and subsequent changes in its fair value are recognized in accordance with IFRS 9 either in profit or loss or as a change to other comprehensive income. Acquisition-related costs are expensed as incurred. We recognize any non-controlling interest in the acquired entity either at fair value or at the non-controlling interest’s proportionate share of the acquirer’s net assets on an acquisition-by-acquisition basis.
All assets and liabilities between entities within the group, equity, income, expenses and cash flows relating to transactions between entities of the group are eliminated in full.
Derivative financial instruments and hedging activities
Derivatives are recognized at fair value in the statement of financial position. We maintain 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.
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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, among others. The valuation of derivatives requires the use of considerable professional judgment. These determinations were based on available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Income taxes and recoverable amount of deferred tax assets
The current income tax provision is calculated on the basis of relevant tax laws in force at the date of the statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.
Determining income tax provision requires judgment in assessing the timing and the amount of deductible and taxable items, as well as the interpretation and application of tax laws in different jurisdictions. Due to this fact, contingencies or additional tax expenses could arise as a result of tax inspections or different interpretations of certain tax laws by the corresponding tax authorities.
We recognize deferred tax assets for all deductible temporary differences and all unused tax losses and tax credits to the extent that it is probable that future taxable profit will be available against which they can be utilized. We consider it probable that we will have sufficient taxable profit available in the future to enable a deferred tax asset to be recovered when:

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

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

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

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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, 2023, 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 $83.2 million compared to $88.0 million in 2022. In addition, Atlantica had issued guarantees amounting to $239.8 million as of December 31, 2023 ($216.9 million as of December 31, 2022). 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.

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 nine members:

Name |  | Position |  | Year of birth
William Aziz |  | Director, Independent |  | 1956
Arun Banskota |  | Director |  | 1961
Debora Del Favero |  | Director, Independent |  | 1964
Brenda Eprile |  | Director, Independent |  | 1954
Ryan Farquhar |  | Director |  | 1971
Michael Forsayeth |  | Director, Independent |  | 1954
Edward C. Hall |  | Director, Independent |  | 1959
Santiago Seage |  | Chief Executive Officer and Director |  | 1969
Michael Woollcombe |  | Director and Chair of the Board, Independent |  | 1968

The business address of the members of the Board of Directors of Atlantica is Great West House, GW1, 17th floor, Great West Road, Brentford, TW8 9DF, United Kingdom.
There are no family relationships among any of our executive officers or directors. There are no potential conflicts of interest between the private interests or other duties of the members of the Board of Directors listed above and their duties to Atlantica, except in the case of Mr. Arun Banskota who served on Algonquin’s board as President and Chief Executive Officer until August 2023 and Mr. Ryan Farquhar who is the current Senior Vice President, Corporate and Business Development at Algonquin.
The following is the biographical information of members of our Board of Directors.
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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 has more than 30 years of experience in senior roles from a combination of industries such as renewable energy development, construction, financing, and operations. He served as Chief Executive Officer of Algonquin since February 2020 until August 2023. He has also served as manager of multiple large business units and three start-ups in the clean-tech space. Mr. Banskota holds a Masters of Arts (University of Denver) and a Master of Business Administration (University of Chicago).
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 advisory. 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.
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. She is also a board member and chair of the HR 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.
Ryan Farquhar, Director
Mr. Farquhar is Senior Vice President, Corporate and Business Development at Algonquin. Mr. Farquhar joined Algonquin in 2018 and has been responsible for oversight of international growth, including utility mergers and acquisitions. He also leads solar and storage projects and asset recycling initiatives. Mr. Farquhar has broad investing experience, ranging from infrastructure and energy projects to venture capital and private equity. Mr. Farquhar holds a Bachelor of Laws Degree from the University of Western Ontario. Additionally, he holds a Bachelor of Commerce (Hons.) from Queen’s University.
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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 (Honors) from Queen’s University.
Edward C. Hall, Director
Mr. Hall is an active independent director and advisor with 35 years of experience in all facets of the electricity industry. Mr. Hall brings a deep understanding of electricity markets, power generation technologies, utility operations and commercial structuring. Mr. Hall serves as Chairman of Cypress Creek Renewables, Vice Chairman of Japan Wind Development Company and as a Director of Wellesley Municipal Light. Mr. Hall spent 25 years of his career with AES Corporation, where he was a member of the AES Executive Leadership Team and served as Chief Operating Officer of AES’s global generation. Mr. Hall has previously served on the boards of General Cable, Globeleq, TerraForm Power and Green Conversion Systems. Mr. Hall earned a B.S. in Mechanical Engineering from Tufts University and M.S. in Finance and Technology Innovation from the MIT Sloan School of Management.
Santiago Seage, Chief Executive Officer and Director
Mr. Seage has served as a director since our formation in 2013 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 that, he was a partner with McKinsey & Company. Mr. Seage also serves as independent director of NYSE listed UGI Corporation. Mr. Seage holds a degree in Business Management from ICADE University in Madrid.
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 (Honors) from Queen’s University and an LLB from the University of Western Ontario.
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Board Diversity Matrix
On August 6, 2021 the 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 are required to 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 as of December 31, 2023 and December 31, 2022:
Board Diversity Matrix as of December 31, 2023 and 2022

| 2023 | 2022
Total Number of Directors | 9 | 9

| Female |  | Male |  | Non-Binary |  | Did not disclose Gender
| 2023 | 2022 |  | 2023 | 2022 |  | 2023 | 2022 |  | 2023 | 2022
Part I: Gender Identity |  |  |  |  |  |  |  |  |  |  |
Directors | 2 | 2 |  | 7 | 7 |  | - | - |  | - | -
Part II: Demographic Background |  |  |  |  |  |  |  |  |  |  |
African American or Black | - | - |  | - | - |  | - | - |  | - | -
Alaskan native or Native American | - | - |  | - | - |  | - | - |  | - | -
Asian(1) | - | - |  | 1 | 1 |  | - | - |  | - | -
Hispanic or Latinx(2) | - | - |  | 1 | 1 |  | - | - |  | - | -
Native Hawaiian or Pacific Islander | - | - |  | - | - |  | - | - |  | - | -
White(3) | 2 | 2 |  | 5 | 5 |  | - | - |  | - | -
Two or More Races or Ethnicities | - | - |  | - | - |  | - | - |  | - | -
LGBTQ+ | - | - |  | - | - |  | - | - |  | - | -
Did Not Disclose Demographic Background | - | - |  | - | - |  | - | - |  | - | -

Note: 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.

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Senior Management of Atlantica
We have a senior management team with extensive experience in developing, financing, managing and operating contracted assets.
Our senior management comprises the following members:

Name |  | Position |  | Year of birth
Javier Albarracin |  | Head of Development and Investment and CIO |  | 1971
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
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.
Javier Albarracin, Head of Development and Investment and CIO
Mr. Albarracin was appointed to serve as our Head of Finance and as Chief Investment Officer in June 2023. He has more than 20 years of experience in the development and financing of infrastructure projects in North and South America, Europe, and Africa. He previously served as Head of Finance for Atlantica since 2016. He holds a Business Administration Degree and a Master in Finance and Financial Markets.
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 Development department for two years. Before that, 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. 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 and Chief Compliance Officer
Ms. Hernandez has served as our General Counsel since June 2014 and also serves as Chief Compliance Officer and Head of People and Culture. 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)).
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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.
Lead Independent Director
Our corporate governance guidelines provide that one of our independent directors shall serve as a lead independent director at any time when an independent director is not serving as the chair of our Board of Directors.

B) | Compensation

Compensation of the Board of Directors and Chief Executive Officer
In 2023, each independent non-executive Director was entitled to receive an annual fee of $150.0 thousand. The Chair of the Board and Chairs of the committees of the Board were entitled to receive additional compensation as detailed in the table below.
Non-independent non-executive directors were entitled to be compensated on the same terms as independent non-executive directors. From April 2020 until August 2023, Mr. Banskota declined compensation. Since August 2023 (when he resigned as CEO of Algonquin) Mr. Banskota has received compensation from the Company for his role as non-executive director. In 2023, Mr. Farquhar declined compensation. From April 2022 (when he retired from a senior executive role at Algonquin Power Utilities Corp) until August 30, 2023 (when he resigned from his position of Director of the Company) Mr. Trisic received compensation as a non-independent non-executive director.
The following table sets out the fee schedule for 2023 and 2022:

In thousands of U.S. Dollars |  | 2023 |  |  | 2022 |
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 |

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The table below summarizes the total annual compensation of the executive and non-executive directors who received remuneration during 2023 and 2022:

In thousands of U.S. Dollars | Salary and Fees in Cash | Salary and Fees in DRSUs(2) | Annual Bonuses | Long-Term Incentive Awards(3) (Vested) | Deferred Restricted Share Units Dividend Equivalents(4) | Total Fixed Remuneration | Total Variable Remuneration | Total
Name(1) | 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | 2022 | 2023 | 2022
William Aziz | 160.0 | 160.0 | - | - | - | - | - | - | - | - | 160.0 | 160.0 | - |  | 160.0 | 160.0
Arun Banskota(8) | 58.8 | - | - | - | - | - | - | - | - | - | 58.8 | - | - | - | 58.8 | -
Debora Del Favero | 112.0 | 112.0 | 48.0 | 48.0 | - | - | - | - | 5.7 | 2.5 | 165.7 | 162.5 | - |  | 165.7 | 162.5
Brenda Eprile | 165.0 | 165.0 | - | - | - | - | - | - | - | - | 165.0 | 165.0 | - |  | 165.0 | 165.0
Michael Forsayeth | 75.0 | 75.0 | 75.0 | 75.0 | - | - | - | - | 9.0 | 4.0 | 159.0 | 154.0 | - |  | 159.0 | 154.0
Edward C Hall(5) | 150.0 | 62.5 | - | - | - | - | - | - | - | - | 150.0 | 62.5 | - |  | 150.0 | 62.5
Santiago Seage(6) | 798.6 | 727.2 | - | - | 975.6 | 931.3 | 1,023.2 | 2,992.4 | - | - | 798.6 | 727.2 | 1,998.8 | 3,923.7 | 2,797.4 | 4,651.0
George Trisic(7) | - | - | 100.0 | 110.0 | - | - | - | - | 10.6 | 1.6 | 110.6 | 111.6 | - | - | 110.6 | 111.6
Michael Woollcombe | - | - | 225.0 | 225.0 | - | - | - | - | 26.9 | 11.9 | 251.9 | 236.9 | - | - | 251.9 | 236.9
Total | 1,519.4 | 1,301.7 | 448.0 | 458.0 | 975.6 | 931.3 | 1,023.2 | 2,992.4 | 52.2 | 20.0 | 2,019.5 | 1,779.7 | 1,998.8 | 3,923.7 | 4,018.3 | 5,703.5

Notes:

(1) | None of the Directors received any pension entitlement and/or taxable benefits in 2023 or 2022.

(2) | Non-executive directors receive salary and fees via a mix of cash and Deferred Restricted Share Units (DRSUs). 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 the annual fees payable to them by the Company from May 31, 2021 would be irrevocably substituted for the grant of DRSUs. The Company also determined and Mr. Trisic agreed that 100% of the annual fees payable to him by the Company would be irrevocably substituted for the grant of DRSUs for the period when he received remuneration.

(3) | In 2022 Long-term Incentive Awards vested under both the (LTIP) and the One-Off Plan calculating amounts using the share price at vesting date. In 2022, from the $2,992.4 thousand worth of awards that vested, $1,490.1 corresponded to share price appreciation. In 2023 Long-term Incentive Awards vested under the LTIP calculating amounts using the share price at vesting date. There was no share price appreciation between the grant date and the vesting date for the LTIP awards that vested in 2023.

(4) | Dividend equivalent rights accumulated on the DRSUs corresponding to the dividends paid for one share in the period between the DRSU grant date and December 31, 2023 and 2022, respectively, multiplied by the number of DRSUs held on that date. Such rights were payable on vesting of the DRSUs.

(5) | Mr. Hall was appointed to the Board on August 2, 2022 as an independent non-executive Director. Mr. Hall’s 2022 fee was prorated for the year based on the annual directors’ retainer.

(6) | The CEO’s compensation is approved in Euros. Salary and Fees have been converted to U.S. dollars for reporting purposes, at the average exchange rate of each year, which was 1.08€/$ in 2023 and 1.05 €/$ in 2022. Annual bonus amounts have been converted to U.S. dollars for reporting purposes, at the exchange rate of December 31, 2023, which was 1.10 €/$ and at the exchange rate of December 31, 2022 which was 1.07 €/$ in 2022.

| - | In 2023, the CEO’s total pay amounted to €2,594.4 thousand ($2,797.4 thousand). Fixed salary amounted to €738.3 thousand ($798.6 thousand), annual bonus to €883.8 thousand ($975.6 thousand) and long-term incentive awards to €972.3 thousand ($1,023.2 thousand).

| - | In 2022, the CEO’s total pay amounted to €4,401.7 thousand ($4,651.0 thousand). Fixed salary amounted to €690.0 thousand ($727.2 thousand), annual bonus to €870.0 thousand ($931.3 thousand) and long-term incentive awards to €2,841.7 thousand ($2,992.4 thousand).

(7) | Mr. Trisic, non-independent non-executive director, has received compensation since April 6, 2022 until August 30, 2023 when he resigned from his position of Director of the Company. Mr. Trisic’s 2022 and 2023 fees were prorated for each year based on the annual directors’ retainer. The Company determined and Mr. Trisic agreed that 100% of his fees were irrevocably substituted for the grant of DRSUs.

(8) | Mr. Banskota, non-independent, non-executive director, has received compensation since August 2023, when he resigned as CEO of Algonquin.

The Directors’ Remuneration 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 2023 or 2022. 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.
During 2023, no third party provided material advice or services to the Compensation Committee. In 2024 the Board of Directors engaged Hugessen Consulting, a consultancy company to review the remuneration of directors, including the CEO. The consultants were appointed by the Compensation Committee, their advice was independent, and the fees paid for these services were approximately $28.0 thousand Canadian dollar ($21 thousand U.S. dollar).
The decrease in the remuneration of the CEO in 2023 was mainly due to a decrease in the amount of share options exercised in 2023 compared to 2022. Share options awarded in 2020 and 2021 under the LTIP that vested in 2023 were underwater and were not exercised. In addition, the number of share units that vested in 2023 under the 2020 LTIP was lower than the number share units that vested in 2022 and the price and the stock price on the vesting date of 2023 was also lower than in 2022. Finally, the One-off plan had fully vested in 2022, as explained below.
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Chief Executive Officer Long-Term Incentives awards vested

| 1) | Restricted Stock Units vested under the LTIP

In January 2023 and June 2022 RSUs awarded in 2020 and 2019 respectively under the LTIP vested and shares were transferred to the CEO in accordance with the terms of the plan. The value of the vested RSUs have been included in the Single Total Figure of Remuneration table above in their vesting period.

RSU Grant Date | RSU Vesting Date | Number of Restricted Stock Units Vesting | Share Price on Vesting Date (USD) | RSUs Value at Vesting Date (000’s USD)(1, 2)
2020 | 2023 | 33,641 | 25.27 | 1,023.2
2019 | 2022 | 46,987 | 31.10 | 1,708.7

Notes:

(1) | 33,641 RSUs (granted in under the 2020 LTIP) vested in 2023 plus dividend equivalent rights corresponding to the dividends paid on one share between the 2020 LTIP grant date and the date on which the RSU vested ($5.15 per share). 46,987 RSUs (granted under the 2019 LTIP) vested in 2022 plus dividend equivalent rights corresponding to dividends paid on one share between the 2019 LTIP grant date and the date on which the RSU vested ($5.07 per share).

(2) | The RSUs that vested in 2023 were subject to (i) the CEO remaining employed with the Group and (ii) a minimum average 5% average annual TSR (both of which were achieved).

| 2) | Options vested under the LTIP

One-third of each of the CEO’s share options awarded in 2020 and 2021 under the LTIP vested during 2023. These were underwater on the vesting date and were not exercised.
The share options value have been included in the Single Total Figure of Remuneration table above in their vesting period.

LTIP Share Option Grant Date(1) | Share Option Vesting Date | Number of Share Options Vesting(3) | Share Price on Vesting Date (USD) | Exercise Price per Share Option (USD) | Share Options Value at Vesting Date (000’s USD)(2)
2021 | 2023 | 24,948 | 28.17 | 37.98 | -
2022 | 24,948 | 32.53 | 37.98 | -
2020 | 2023 | 34,494 | 25.27 | 26.39 | -
2022 | 34,494 | 34.48 | 26.39 | 279.1
2019 | 2022 | 40,693 | 31.30 | 19.60 | 476.1

Notes:

(1) | Additional information on the LTIP is disclosed in the Remuneration Policy section.

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

(3) | There were no performance measures related to these options.

| 3) | One-off plan

An award in the form of restricted stock units (RSUs) was granted under the One-off plan to the CEO in 2019. In June 2022 the third and final tranche vested, and shares were transferred to the CEO in accordance with the terms of the plan. The One-off plan RSUs were fully vested in 2022, and therefore no One-Off Plan RSUs vested in 2023.
The value of the shares transferred have been included in the Single Total Figure of Remuneration table above in their vesting period.
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One-Off Plan | One-Off Plan Vesting | Number of Restricted Stock Units | Share Price on Vesting Date (USD) | RSUs Value at Vesting Date (000’s USD)(1)
2019 | June 2023 | - | - | -
June 2022(2) | 14,535 | 31.30 | 528.6

Notes:

(1) | On each vesting date, one third of the RSUs vested (14,535 RSUs) plus dividend equivalent rights corresponding to the dividends paid on one share in the period between the One-off plan grant date and the date on which the RSU vest ($5.07 per share for 2022), multiplied by the number of RSUs vesting on that date.

(2) | In June 2022, the final tranche of RSUs vested. As a result, since then there have been no other awards outstanding under this plan.

In 2023, most of the objectives defined for the Chief Executive Officer’s variable bonus were met or exceeded and the Compensation Committee decided to approve a bonus corresponding to 104.0% of the target variable compensation, which will be payable in 2024.

| Percentage Weight | Achievement
CAFD(1) – Equal or higher than the CAFD budgeted in the 2023 budget | 35% | 97.5%
Adjusted EBITDA – Equal or higher than the Adjusted EBITDA budgeted in the 2023 budget | 15% | 99%
Capital allocation management on a value accretive basis | 20% | 110%
Achievement of ESG metrics including health and safety targets – (Frequency with Leave / Lost Time Index below 3.7 and General Frequency Index below 9.5) | 10% | 120%
Management of relationships with key shareholders and partners | 10% | 120%
Continued executive talent development | 10% | 90%

Note:

(1) | Cash Available for Distribution (CAFD) 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 2023, Mr. Seage was awarded $975.6 thousand as a bonus payment in accordance with his service agreement, payable in 2024. In 2022, Mr. Seage was awarded $931.3 as thousand as a bonus payment in accordance with his service agreement, which was paid in 2023. 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 Chief Executive Officer’s maximum potential bonus is 120% of such bonus, which is approximately $1,126 thousand (approximately €1,020 thousand).
No element of the Chief Executive Officer’s annual bonus is deferred.
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Deferred Restricted Shares Units (“DRSU”) Plan
The following table sets out the total compensation received by non-executive directors via a mix of cash and DRSUs in 2023:

Name |  | Total Remuneration (000’s USD) |  |  | Total Remuneration in Cash and/or Deferred Restricted Stock Units (DRSU) |
|  |  | Remuneration in Cash (000’s USD) |  |  | Remuneration in DRSUs |
|  |  | DRSUs (000’s USD) |  |  | Number of DRSUs(4) |
|  | 2023 |  |  | 2022 |  |  |  | 2023 |  |  |  | 2022 |  |  |  | 2023 |  |  |  | 2022 |  |  |  | 2023 |  |  |  | 2022 |
William Aziz |  |  | 160.0 |  |  |  | 160.0 |  |  |  | 160.0 |  |  |  | 160.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Arun Banskota(5) |  |  | 58.8 |  |  |  | - |  |  |  | 58.8 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Debora Del Favero(1) |  |  | 160.0 |  |  |  | 160.0 |  |  |  | 112.0 |  |  |  | 112.0 |  |  |  | 48.0 |  |  |  | 48.0 |  |  |  | 2,102 |  |  |  | 1,619 |
Brenda Eprile |  |  | 165.0 |  |  |  | 165.0 |  |  |  | 165.0 |  |  |  | 165.0 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Michael Forsayeth(1) |  |  | 150.0 |  |  |  | 150.0 |  |  |  | 75.0 |  |  |  | 75.0 |  |  |  | 75.0 |  |  |  | 75.0 |  |  |  | 3,284 |  |  |  | 2,530 |
Edward C. Hall(2) |  |  | 150.0 |  |  |  | 62.5 |  |  |  | 150.0 |  |  |  | 62.5 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
George Trisic(3) |  |  | 100.0 |  |  |  | 110.0 |  |  |  | - |  |  |  | - |  |  |  | 100.0 |  |  |  | 110.0 |  |  |  | 4,003 |  |  |  | 3,901 |
Michael Woollcombe(1) |  |  | 225.0 |  |  |  | 225.0 |  |  |  | - |  |  |  | - |  |  |  | 225.0 |  |  |  | 225.0 |  |  |  | 9,852 |  |  |  | 7,589 |
Total |  |  | 1,168.8 |  |  |  | 1,032.5 |  |  |  | 720.8 |  |  |  | 574.5 |  |  |  | 448.0 |  |  |  | 458.0 |  |  |  | 19,240 |  |  |  | 15,638 |

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 the annual fees payable to them by the Company from May 31, 2021 would be irrevocably substituted for the grant of DRSUs.

(2) | Mr. Hall was appointed to the Board on August 2, 2022 as an independent non-executive Director. Mr. Hall’s 2022 fee was prorated based on the annual director’s retainer.

(3) | Mr. Trisic, non-independent non-executive director, received compensation from April 6, 2022 until August 30, 2023. Mr. Trisic’s 2022 and 2023 fees were prorated based on the annual directors’ retainer. The Company determined and Mr. Trisic agreed that 100% of his fee would be irrevocably substituted for the grant of DRSUs.

(4) | The number of DRSUs granted is determined by dividing the amount of the annual compensation to be substituted for DRSUs by the market value of an ordinary share at the time of grant.

(5) | Mr. Banskota resigned as Chief Executive Officer of Algonquin on August 11, 2023. Since then, he has received compensation from the Company. His fees for 2023 were prorated.

Remuneration of the Chief Executive Officer
The information provided in this part of the report is subject to audit.
Details for Mr. Seage, who serves in the role of the Chief Executive Officer, are set out in the “Single Total Figure of Remuneration for Each Director” section above.
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Scheme Interests Awarded During 2023:

LTIP | Number of Restricted Stock Units | Price per RSU at the grant date (USD) | Restricted Stock Units Face Value1 (000’s USD) | Performance Criteria
2023 | 44,9502 | 25.77 | 1,158.5 | - 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.

Notes:

(1) | Face Value means the maximum number of shares that would vest if performance measures are met using the share price at the grant date (January 6th, 2023). The face value for the restricted stock units (RSUs) is calculated using the share price at the grant date.

(2) | RSUs will vest on the third anniversary of the grant date, subject to the satisfaction of the performance criteria.

For 67% of the award, 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 value of the RSUs granted to the CEO was equal to 70% of the previous year target annual compensation (fixed + target annual bonus) at the grant date. Further information including a description of each type of interest awarded and the basis on which the award is made is provided in the Remuneration Policy section below.
The following information provided in this part of the report is not subject to audit (unless otherwise indicated).
Total Shareholder Return and Chief Executive Officer Pay
The chart below shows the Company’s TSR since June 2014, the date of our Initial Public Offering (“IPO”), until the end of 2023 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.
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The table below shows the total remuneration of the Chief Executive Officer, his bonus and his long-term incentive awards expressed as a percentage of the maximum he is likely to be awarded.

|  |  |  |  | Bonus |  |  | Long-Term Incentive Awards(3) |
Year |  | Total Pay(1) (000’s USD) |  |  | Percentage of Target |  |  | Amount of Bonus(2) (000’s USD) |  |  | Percentage of Maximum |  |  | Value (000’s USD) |
2023 |  |  | 2,797.4 |  |  |  | 104.0 | % |  |  | 975.6 |  |  |  | 100.0 | % |  |  | 1,023.2 |
2022 |  |  | 4,651.0 |  |  |  | 102.4 | % |  |  | 931.3 |  |  |  | 100.0 | % |  |  | 2,992.4 |
2021 |  |  | 3,752.7 |  |  |  | 105.0 | % |  |  | 1,056.3 |  |  |  | 100.0 | % |  |  | 1,879.8 |
2020 |  |  | 2,524.1 |  |  |  | 102.7 | % |  |  | 996.4 |  |  |  | 100.0 | % |  |  | 770.9 |
2019 |  |  | 1,685.4 |  |  |  | 100.7 | % |  |  | 957.7 |  |  |  | - |  |  |  | - |
2018 |  |  | 2,511.1 |  |  |  | 101.8 | % |  |  | 992.2 |  |  |  | 22.0 | % |  |  | 751.1 |
2017 |  |  | 1,602.0 |  |  |  | 96.3 | % |  |  | 924.2 |  |  |  | - |  |  |  | - |
2016 |  |  | 1,499.4 |  |  |  | 100.0 | % |  |  | 940.5 |  |  |  | - |  |  |  | - |
2015 |  |  | 1,597.6 | (4) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
2014 |  |  | 174.1 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |

Notes:

(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 each year. The total pay received by the CEO in thousands of Euros was €2,594.4 in 2023, €4,401.7 in 2022, €3,148.6 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 earned by the CEO at year-end and paid the next year. For example: In 2021, the CEO earned a bonus of $1,056.3 thousand, which was paid to the Chief Executive Officer in 2022.

(3) | Long-Term Incentive Awards includes awards granted under both the LTIP and One-Off Plan which vested in the year.

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

The Chief Executive Officer did not receive any variable remuneration for services provided to the Company for the years ended December 31, 2015 and 2014. Mr. Seage occupied that office between January and May 2015, and again from late November 2015. Mr. Garoz held that position between May and November 2015, when Santiago Seage left the Company.
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Directors’, Chief Executive Officer’s and Employee’s Pay
The table below sets out the percentage change between 2023 and 2022 in salary and, bonus for executive and non-executive directors who received remuneration and the average per capita change for employees of the Company’s group as a whole, excluding the Chief Executive Officer.

|  | 2023 (% Change from 2022 to 2023) |  |  | 2022 (% Change from 2021 to 2022) |  |  | 2021 (% Change from 2020 to 2021) |
|  | Salary and Fees (Cash and DRSU) |  |  | Bonus |  |  | Salary and Fees (Cash and DRSU)(1) |  |  | Bonus |  |  | Salary and Fees (Cash and DRSU) |  |  | Bonus |
Non-executive directors |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
William Aziz |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Arun Banskota(4) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Debora Del Favero |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Brenda Eprile |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Michael Forsayeth |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Edward C. Hall(2) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
George Trisic3 |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Michael Woollcombe |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Executive director |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Santiago Seage (CEO) |  |  | 7 | %(6) |  |  | 2 | %(6) |  |  | 0 | %(6) |  |  | -3 | %(6) |  |  | 4 | %(6) |  |  | 2 | %(6)
Employees (excluding CEO)(5) |  |  | 6 | % |  |  | 6 | % |  |  | 4 | % |  |  | 9 | % |  |  | 4 | % |  |  | 8 | %

Notes:
None of the non-executive directors received any bonus, and/or taxable benefits in 2023, 2022 or 2021.

(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 the annual feeS payable to them by the Company from May 31, 2021 would be irrevocably substituted for the grant of DRSUs.

(2) | Mr. Hall was appointed to the Board on August 2, 2022 as an independent non-executive Director.

(3) | Mr. Trisic, non-independent non-executive director, has received compensation from April 6, 2022 until August 30, 2023, when he resigned from his position as Director of the Company. The Company determined and Mr. Trisic agreed that 100% of his fee would be irrevocably substituted for the grant of DRSUs.

(4) | Mr. Banskota, non-independent non-executive director, has received compensation since August 12, 2023, when he resigned as CEO of Algonquin.

(5) | 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 2023, 2022 and 2021. This is the most appropriate methodology to reflect how much the salary and potential bonus changed on a year-to-year basis as it excludes the effect of employee hires and turnover.

(6) | For 2023, the Compensation Committee approved (i) fixed remuneration of €738.3 thousand for the Chief Executive Officer (in 2022, the CEO’s fixed remuneration was €690 thousand), and (ii) variable remuneration of €883.8 thousand compared to €870.0 thousand for 2022, representing a 2% increase in Euros on a year-to-year basis.

(7) | For 2022, the Compensation Committee approved (i) fixed remuneration of €690 thousand for the Chief Executive Officer (in 2021, the CEO’s fixed remuneration was also €690 thousand), and (ii) variable remuneration of €870.0 thousand compared to €893 thousand for 2021, representing a 3% decrease in Euros on a year-to-year basis.

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Pay Ratio Information
The average number of employees in the U.K. is below 250 employees. Following the U.K. pay ratio disclosure requirements, Atlantica is exempt from disclosing U.K. pay ratio-related information.
Relative Importance of Spend on Pay
The following table sets out the change in overall employee costs, directors’ compensation and dividends.

$ in Millions |  | 2023 |  |  | 2022 |  |  | Difference |
Spend on Pay for All Employees |  |  | 104.1 |  |  |  | 80.2 |  |  |  | 23.9 |
Total Remuneration of Directors |  |  | 4.0 |  |  |  | 5.6 |  |  |  | -1.6 |
Total Remuneration of employees and directors |  |  | 108.1 |  |  |  | 85.9 |  |  |  | 22.3 |
Dividends Paid |  |  | 206.8 |  |  |  | 203.1 |  |  |  | 3.7 |

The Company has not made any share repurchases during 2023 or 2022.
The average number of employees in 2023 in Atlantica was 1,304 employees, compared to 874 employees in 2022. The $23.9 million increase in spend on pay and the increase in the average number of employees is mostly due to the internalization of the operation and maintenance activities. We refer to section “People and Culture” under “Social Sustainability.”
The decrease in the remuneration of the CEO in 2023 was mainly due to a decrease in the amount of share options exercised in 2023 compared to 2022. Share options awarded in 2020 and 2021 under the LTIP that vested in 2023 were underwater and were not exercised. In addition, the number of share units that vested in 2023 under the 2020 LTIP was lower than the number share units that vested in 2022 and the price and the stock price on the vesting date of 2023 was also lower than in 2022. Finally, the One-off plan had fully vested in 2022, as explained below.
Payments for Loss of Office (Audited)
Mr. Trisic resigned as non-executive Director of the Company on August 30, 2023.
DRSUs granted to Mr. Trisic, (in lieu of fees), together with the dividend equivalents accumulated with respect to these DRSUs from April 6, 2022 until vesting were fully settled on August 30, 2023. The settlement of the dividend equivalents was made on the basis of a price per share of $22.87 corresponding to the average price of the 5 days prior to August 30, 2023, the date of resignment. In total (for his DRSUs and dividend equivalent rights), Mr. Trisic received 8,435 shares from the Company before taxes ($192,903.7).
Apart from this, no other termination payments were made to the Chief Executive Officer or any other director in 2023 nor 2022. 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 2024
The current Remuneration Policy was approved at our 2021 Annual General Meeting, and amendments were approved at the 2023 Annual General Meeting held in April 2023. A new Remuneration Policy is being put to shareholder vote at the 2024 Annual General Meeting- the only key changes (compared to the current Remuneration Policy) relate to (i) the clawback policy, (ii) amending the maximum value of LTIP awards granted to executive directors, (iii) the conditions for the LTIP and (iv) establishing additional fees for all non-executive directors who are chair of a board commitee, eliminating the exception for chair of the related party committee.
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Non-independent non-executive directors are entitled to be compensated on the same terms as independent non-executive directors.
The main terms of the LTIP included in the Remuneration Policy proposed for approval in 2024 that would apply to awards granted to the CEO and Executives are as follows:

| Main terms of the LTIP for awards granted to all Executives as – Restricted Stock Units
Value at grant date | The value of the RSUs granted to the CEO is up to 105% of the previous year target annual remuneration (fixed + target annual bonus) at the grant date. The value of the RSUs granted to an executive other than the CEO is equal to between 50% and 70% (with the exact percentage to be determined by the Compensation Committee at grant) of the previous year target annual remuneration (fixed + target annual bonus) at the grant date.
Exercisability and Vesting Period | 33% of the RSUs will vest on the third anniversary of the grant date (provided the participant remains employed with the Group) and 67% of the RSUs will vest on the third anniversary of the grant date only if the conditions described below are met over such 3-year period. Each of the below conditions must be considered individually and each of the conditions weigh individually in considering the two thirds of the RSU. It is not necessary that all of them together are met for the vesting of the two-thirds of the total number of RSUs. The Company will decide at vesting if vested RSUs will be settled in cash or shares.
Ownership and Dividends | The participant will be entitled to receive, for each RSU held, a payment equivalent in value to any dividend or distribution paid on each share between the grant date and the date on which the RSU vests.

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(1) | Includes storage.

(2) | Includes floors and caps when measuring compliance (i.e. floor of 70% and cap of 130% when measuring performance versus financial objectives)

(3) | Percentage weights are calculated as a fraction of the percentage weight assigned to each section or subsection, based on a 100% basis. The values are rounded to the nearest tenth.

For 2024, the bonus measures for the remuneration of the Chief Executive Officer, will focus on four areas: financial targets, capital allocation management, ESG including health and safety, and continued executive talent development.
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.
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For 2024 the bonus objectives are:

| Percentage Weight
CAFD – Equal or higher than the CAFD budgeted in the 2024 budget | 35%
Adjusted EBITDA – Equal or higher than the Adjusted EBITDA budgeted in the 2024 budget | 15%
Capital allocation management | 30%
Achievement of ESG metrics including health and safety targets – (Frequency with Leave / Lost Time Index below 3.0 and General Frequency Index below 6.8) | 10%
Continued executive talent development | 10%

Remuneration Policy
The current Remuneration Policy was approved at our 2021 Annual General Meeting, and amendments were approved at our 2023 Annual General Meeting. Shareholders will be asked to approve a new Remuneration Policy at our 2024 Annual General Meeting to be held in April 2024. The new Remuneration Policy is intended to take effect immediately following the 2024 Annual General Meeting (subject to shareholder approval).
The only changes that will apply to the new proposed Remuneration Policy (compared to the current policy) consist of (1) amending the Clawback Policy to comply with the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and the relevant Nasdaq Stock Market rules, (2) amending the maximum value of LTIP awards granted to executive directors, (3) introducing new conditions for LTIP awards, as we describe in more detail below, and (4) establishing additional fees for all non-executive directors who are chair of the board committee, eliminating the exception for chair of the related party committee.
Executive Directors:
The policy for executive directors, only applicable to the Chief Executive Officer as the only executive director, is as follows:

Name of component |  | Description of component |  | How does this component support the company’s (or Group’s) short and long-term objectives? |  | What is the maximum that may be paid in respect of the component? |  | Framework used to assess performance
Salary/fees |  | Fixed remuneration payable monthly. |  | Helps to recruit and retain executive directors and forms the basis of a competitive remuneration package. |  | Maximum amount €800 thousand (approximately $850 thousand), may be increased by 5% per year. Salary levels for peers are considered. |  | Not applicable. No retention or clawback.
Benefits |  | Opportunity to join existing plans for employees but without any increase in remuneration.
Annual Bonus |  | Annual bonus is paid following the end of the financial year for performance over the year. There are no retention or forfeiture provisions. |  | Helps to offer a competitive remuneration package and align it with the Company’s objectives. |  | 200% of base salary. |  | 25%-50% of CAFD. 10-15% of Adjusted EBITDA. 40%-50% of other operational or qualitative objectives. No retention. Clawback policy.

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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
Strategic Review Bonus |  | One-time bonus related to the strategic review process and payable upon closing of a potential strategic transaction. |  | Helps retain executive directors who are relevant for the success of the strategic review process. |  | 110% of 2023 target annual remuneration (including fixed salary + target annual bonus). |  | Closing of a strategic transaction as such term is defined by the Board of Directors.
Long Term Incentive Awards |  | RSUs subject to certain vesting periods and conditions. |  | Align executive directors and shareholders interests. |  | Up to 105% of target annual remuneration of the previous year (including fixed salary + target annual bonus). |  | RSUs will be subject to - Continuing employment for 33% of the award and - Continuing employment and achievement of three year objectives for 67% of the award. Out of this 67%, the objectives consist of: - One third based on the Company reaching a minimum 5% average annual TSR target. - One third based on the Company reaching appropriate financial targets (for example Adjusted EBITDA and CAFD) - One third based on strategic objectives: for example ESG targets, (for example growth in renewables and storage). and other strategic objectives in line with the Company’s long term strategy. Granted in the form of RSUs. Subject to the Company’s Clawback policy.

TSR, CAFD, Adjusted EBITDA are considered standard indicators of financial performance in our sector. In addition, the LTIP is subject to strategic objectives that the Board believes are aligned with the Company’s strategy and long-term targets.
Restricted Stock Units granted prior to the approval of the new 2024 Remuneration Policy and after the approval to the amendments to the Remuneration Policy in 2023 are subject to:

| - | Continuing employment for 33% of the award and

| - | Continuing employment and achievement of a minimum 5% average annual TSR for 67% of the award.

If the TSR performance condition has not been met during the vesting period, the participanting Restricted Stock Units subject to minimum annual TSR condition will lapse on the vesting date, save that the 2024 grants of Restricted Stock Units may be subject to the vesting conditions set out in the table above, if the Board so decides, provided that the new Remuneration Policy is approved by shareholders at the 2024 Annual General Meeting.
Restricted Stock Units granted prior to the approval of the amendments to the Remuneration Policy in 2023 are subject to continuing employment and achievement of a minimum 5% average annual TSR for 100% of the award.
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Clawback Policy
The Company has operated an incentive compensation recoupment or clawback policy since 2021 and in 2023 has adopted provisions to comply with the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and the relevant Nasdaq Stock Market rules.
The policy is aimed at allowing the Company to recover performance-based compensation during the lookback period, which is generally three years after short-term variable compensation and/or long-term compensation awards are granted. In the case of a restatement, the lookback period is three completed fiscal years immediately preceding the date on which the Company is required to prepare a restatement for a given reporting period.
The policy is applicable to all executives who participate in long term incentive arrangements including current and former executive officers (as defined in Nasdaq Rule 5608(d)).
The policy is applicable in the event of the occurrence of either of the following triggering events: (1) a restatement, whether or not as a result of misconduct, as described in subsection 1 below or (2) fraud, embezzlement or other serious misconduct that is materially detrimental to the Company, as described in subsection 2 below.

1. | In the event that the Company is required to prepare a restatement (as defined in Nasdaq Rule 5608(b)(1)), executives covered by the policy shall be required to repay to the Company the amount of any covered compensation (as defined below) granted, vested or paid to such executive during the lookback period that exceeds the amount of the covered compensation that otherwise would have been granted, vested or paid to such executive had such amount been determined based on the restatement, computed on a pre-tax basis.

For the purposes of this subsection 1, “covered compensation” means any incentive-based compensation (as defined in Nasdaq Rule 5608(d)) granted, vested or paid to a person who served as an executive officer at any time during the performance period for the incentive-based compensation and that was received (within the meaning of Nasdaq Rule 5608(d)): (i) on or after October 2, 2023, (ii) after the person became an executive officer and (iii) at a time that the Company had a class of securities listed on a national securities exchange or a national securities association.
For covered compensation based on the Company’s stock price or total shareholder return, where the amount of the erroneously-awarded covered compensation is not subject to mathematical recalculation directly from the information in the restatement, the Compensation Committee shall determine the amount to be repaid, if any, based on a reasonable estimate of the effect of the restatement on the stock price or total shareholder return.
The Compensation Committee must reasonably promptly pursue (and shall not have the discretion to waive) the repayment of any erroneously-awarded covered compensation, except where a determination has been made in accordance with Nasdaq Rule 5608(b)(1)(iv) that recovery would be impracticable. The Company is prohibited from indemnifying any current or former executive officer against the repayment of any erroneously-awarded covered compensation under the policy.
This subsection 1 is intended to satisfy the requirements of Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act and any related rules or regulations promulgated by the U.S. Securities and Exchange Commission or the Nasdaq, including the Nasdaq rules and any additional or new requirements that become effective after the adoption of the policy, which upon effectiveness shall be deemed to automatically amend this subsection 1 to the extent necessary to comply with such requirements.

2. | If the Company is required to prepare a material restatement 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 if 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, then, in addition to any remedies set forth in subsection 1 above, the Company may require the executive (or the executive’s beneficiary) to reimburse the Company for, or forfeit, all or any portion of any short or long term variable compensation awards.

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The Compensation Committee shall retain discretion regarding application of this subsection 2. The clawback policy is incremental to other remedies that are available to the Company
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 long-term incentive plan permits the granting of Restricted Stock Units (“RSUs”) to the executive team of the Company (the “Executives”). The LTIP applies to approximately 13 Executives and the Chief Executive Officer.
The aggregate number of shares which may be reserved for issuance under the LTIP must not exceed 2% of the number of the shares outstanding at the time of the Awards are granted but is expected to be significantly less. In addition, total equity-based awards will be limited to 10% of the Company’s issued share capital over a 10-year rolling period, in order to assure shareholders that dilution will remain within a reasonable range. In any case, the Compensation Committee may decide that, instead of issuing or transferring shares, the Executives may be paid in cash.
The value of the RSUs will be equal to between 50% and 70% of the Executives’ (other than the CEO) target annual remuneration (including fixed salary + target annual bonus) for the year closed before the date upon which an RSU is granted and, in the case of the Chief Executive Officer, it will be up to 105% of the previous year target annual remuneration (including fixed salary + target annual bonus)at the grant date. The award will be granted in Restricted Stock Units.
Main terms of the LTIP included in the Remuneration Policy proposed for approval in 2024:

| Main terms of the LTIP for awards granted to all Executives – Restricted Stock Units
Nature | Restricted Stock Units will be subject to: - Continuing employment for 33% of the award) and - Continuing employment and achievement of three year objectives for 67% of the award. Out of this 67%, the objectives consist of: • One third based on the Company meeting a minimum 5% average annual TSR. • One third based on the Company meeting appropriate financial targets (for example Adjusted EBITDA and CAFD) • One third based on strategic objectives: for example ESG, including growth in renewables and storage and other strategic objectives in line with the Company’s long term strategy Appropriate targets for each measure will be considered and set by the Compensation Committee at the start of each financial year and disclosed in the annual report of the relevant financial year accordingly, in accordance with the Regulations.
Exercisability and Vesting Period | 33% of the shares will vest on the third anniversary of the grant date (subject to continued employment) and 67% of the shares will vest on the third anniversary of the grant date only if the conditions described above are met over such 3-year period. Each of the above conditions must be considered individually and each of the conditions weigh individually in considering the two thirds of the RSU. It is not necessary that all of them together are met for the vesting of the two-thirds of the total number of RSUs. The Company will decide at vesting if vested RSUs will be settled in cash or shares.
Ownership and Dividends | The participant will be entitled to receive, for each Restricted Stock Unit held, a payment equivalent in value to any dividend or distribution paid on each share between the grant date and the date on which the Restricted Stock Unit vests.

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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 granted under the LTIP after the approval of the amendments to the Remuneration Policy in 2023 and all past awards granted under the LTIP to executives participating in the strategic review bonus shall vest based on the satisfaction of performance conditions as at the time of the change in control. All Awards granted to other employees prior to this 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 granted under the LTIP after the approval of the amendments to the Remuneration Policy in 2023 and all past awards granted under the LTIP to executives participating in the strategic review bonus shall vest based on the satisfaction of performance conditions as at the time of delisting and will be settled in cash. All Awards granted to other employees prior to this 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.
Strategic review bonus
On February 21, 2023, Atlantica announced the initiation of a process to explore and evaluate potential strategic alternatives that may be available to Atlantica to maximize shareholder value. In connection with this process, the purpose of the strategic review bonus is to retain talent for certain positions in the organization which are relevant for the success of this process. The strategic review bonus applies to ten executives and the CEO. The value of the bonus is defined as 75% of the target annual remuneration for 2023 (including fixed salary + target annual bonus for 2023) (110% in the case of the CEO) and will become payable upon closing of a potential strategic transaction, as such term is defined by the Board of Directors. In the case of the CEO, the strategic review bonus was approved at the Shareholders Annual General Meeting held in April 2023.
Pension
The CEO (being the only executive director) does not receive any pension contributions.
None of the non-executive directors receive bonuses, long-term incentive awards, pension contributions 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.
Chief Executive Officer Remuneration Policy
The Compensation Committee approved a fixed remuneration of €738.3 thousand ($815.0 thousand converted to U.S. dollars at the December 31, 2023 exchange rate, which is 1.10 $/€) and variable target remuneration of €850.0 thousand for the Chief Executive Officer for 2024 ($935.0 thousand converted to U.S. dollars at the December 31, 2023 exchange rate, which is 1.10 $/€). In 2023, the CEO's fixed remuneration also was €738.8 thousand.
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Total remuneration of the only executive director for a minimum, target and maximum performance in 2024 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 vesting in 2023 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 vesting in 2024 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 2024 including vesting long-term awards would be approximately $3,880 thousand. If we assume a 50% appreciation of the share price with respect to the December 31, 2023 share price, maximum remuneration for 2024 including vesting long-term awards would be approximately $2,215 thousand. In this scenario, the minimum annual TSR of at least a 5% yearly average over the 3-year period would not be met and share options awarded in 2021 under the LTIP would be underwater, therefore share options vesting in 2024 would not be exercised. Only 33% of the RSU’s would vest under the LTIP.
For 2024, the bonus measures for the remuneration of the Chief Executive Officer, will focus on four areas: financial targets, capital allocation management, ESG including health and safety, and continued executive talent development.
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 2024 bonus objectives are disclosed under the section Annual Report on Remuneration.
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.
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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 Chief Executive Officer, 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 Chief Executive Officer.
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 Key Managers, including the CEO, the Company would make payments for loss of office or employment in addition to the severance payment under the prevailing labor 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.
Consideration of Employee Conditions Elsewhere
Our policy is to use external consultants to estimate market conditions for specific roles of a similar level 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 last Annual General Meeting was held in April 2023.
Summary of Policy for Non-Executive Directors
The Company’s policy is to compensate non-executive directors via cash or Deferred Restricted Share Units (“DRSUs”) for the time dedicated to promoting greater alignment of interests between directors and shareholders 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.
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The DRSU 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 determines, and the directors shall agreed, that a percentage of their fees, starting on May 31, 2021, that would be irrevocably substituted for the grant of Deferred 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.
None of the non-executive directors receive bonuses, long-term incentive awards, pension contributions or other benefits in respect of their services to the Company.

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 high-performing non-executive directors. Align interests of non-executive 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. | Annual total compensation for 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, 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 2023

$ thousand |  | 2023 |  |  | 20222 |
Short-term employee benefits |  |  | 5,454.4 |  |  |  | 4,949.7 |
LTIP awards |  |  | 1,868.3 |  |  |  | 4,639.8 |
One-off awards |  |  | - |  |  |  | 1,212.3 |
Post-employment benefits |  |  | - |  |  |  | - |
Other long-term benefits |  |  | - |  |  |  | - |
Termination benefits1 |  |  | - |  |  |  | - |
Share-based payment |  |  | - |  |  |  | - |
Total |  |  | 7,322.7 |  |  |  | 10,801.8 |

Notes:

(1) | Mr. Trisic resigned from his position as non-independent non-executive Director of Atlantica on August 30, 2023. DRSUs granted to Mr. Trisic, (in lieu of fees), together with the dividend equivalents accumulated with respect to these DRSUs from April 6, 2022 until vesting were fully settled on August 30, 2023. The settlement of the dividend equivalents was made on at the basis of a price per share of $22.87 corresponding to the average price of the 5 days prior to August 30, 2023, the date of resignment. In total (for his DRSUs and dividend equivalent rights) Mr. Trisic received 8,435 shares ($193 thousand).

(2) | 2022 short-term employee benefits have been revised to include the Directors benefits.

The table above includes compensation for the Directors of the Company, the CEO, the CFO and 5 key executives. Short-term employee benefits to management are paid in euros and have been converted to U.S. dollars using the average foreign exchange rate for each period.
The 2023 “LTIP Awards” figure includes share units vested in the year. The 2022 “LTIP Awards” and “One-off Awards” figures include share options and share units vested in the year. 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 by each of our current directors and executive officers, as well as their connected persons as of the date of this annual report, in relation to any compensation paid and/or benefits granted by the Company.
Directors who do not receive remuneration from the Company are not required to comply with the minimum share ownership requirements as they do not receive remuneration from the Company.
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Name(1) |  | Number of Shares |  | Number of Deferred Restricted Share Units(2) |  | Number of Share Units(3) subject to performance measures |  | Investment Value ($000’s)(4) |  | Minimum Share Ownership Requirement |  | Compliance With Policy(5) |  | Number of Share Options Vested Unexercised(6) |  | Share Options Not Vested(7)
William Aziz |  | 2,500 |  | - |  | - |  | 54 |  | 3 times annual compensation |  | On track |  | - |  | -
Arun Banskota |  | - |  | - |  | - |  | - |  | 3 times annual compensation |  | On track |  | - |  | -
Debora Del Favero |  | - |  | 4,973 |  | - |  | 107 |  | 3 times annual compensation |  | On track |  | - |  | -
Brenda Eprile |  | 13,000 |  | - |  | - |  | 280 |  | 3 times annual compensation |  | On track |  | - |  | -
Michael Forsayeth |  | 2,500 |  | 7,770 |  | - |  | 221 |  | 3 times annual compensation |  | On track |  | - |  | -
Edward C. Hall |  | 1,500 |  | - |  | - |  | 32 |  | 3 times annual compensation |  | On track |  | - |  | -
Santiago Seage |  | 117,491 |  | - |  | 105,868 |  | 4,802 |  | 6 times fixed compensation |  | ✔ |  | 84,389 |  | 24,948
Michael Woollcombe |  | 5,000 |  | 23,311 |  | - |  | 609 |  | 3 times annual compensation |  | ✔ |  | - |  | -

Notes:

(1) | Mr. Farquhar, non-independent, non-executive Director, does not receive remuneration from the Company. Thus, he is not required to comply with minimum share ownership requirements.

(2) | The number of DRSUs includes accumulated cash dividend equivalent rights, corresponding to the dividends paid for one share in the period between the DRSU grant date and December 31, 2023, multiplied by the number of DRSUs outstanding on that date and divided by the share price of $21.50 as of December 31, 2023. The director shall not have any rights of a shareholder unless and until the DRSUs vest and are settled by the issuance of shares and dividend equivalent rights will not be payable until the DRSUs vest.

(3) | Unvested share units as of December 31, 2023. LTIP share units subject to 5% minimum Total Shareholder Return.

(4) | Assuming a share price of $21.50 as of December 31, 2023.

(5) | Mr. Aziz, Ms. Del Favero, Ms. Eprile, Mr. Forsayeth, Mr. Seage and Mr. Woollcombe have a 5-year window starting in May 2021 to comply with this policy. Mr. Hall has a 5-year window starting in August 2022 and Mr. Banskota has a 5-year window starting in August 2023.

(6) | Share options granted in 2021 (49,895) and share options granted in 2020 (34,494) were underwater as of December 31, 2023 were underwater as of December 31, 2022.

(7) | Share options awarded in 2020 and 2021 under the LTIP (84,389). These share options have not vested as of December 31, 2023.

C. | Board Practices

Our Board of Directors consists of nine directors, six 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 requiring directors to be appointed until the next Annual General Meeting. After this period, our board members are eligible for reelection by the Annual General Meeting, which will be held on April 15, 2024.
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 ROFO Agreements. See “Item 7.B—Related Party Transactions—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest.”
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Our Board of Directors is responsible for, among other things, overseeing the conduct of our business; reviewing and, where appropriate, approving, our long-term strategic, financial and organizational goals and plans; and reviewing the performance of our Chief Executive Officer and other members of senior management.
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
William Aziz |  | Member
Brenda Eprile |  | Chair
Michael Forsayeth |  | Member

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

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

The duties and functions of our Nominating and Corporate Governance Committee include, among others, regularly reviewing the structure, size and composition (including the skills, knowledge, experience and diversity) of the Board of Directors and make recommendations to the Board of Directors with regard to any changes, and keep under review corporate governance rules, developments and best practices (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.
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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
Edward C. Hall |  | 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 Compensation Committee meets at least twice a year at appropriate intervals in the financial reporting and audit cycle and otherwise as required. The Compensation Committee informs and makes proposals to the Board of Directors. Mr. Hall was appointed as a member of the Compensation Committee on February 3, 2023.
Related Party Transactions Committee
Our Related Party Transactions Committee comprises the following three members, each of whom is an independent director:

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

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.

D. | Employees

The following table shows the number of employees as of December 31, 2023, 2022 and 2021, on a consolidated basis:

|  | Year ended December 31, |
Geography |  | 2023 |  |  | 2022 |  |  | 2021 |
North America |  |  | 331 |  |  |  | 312 |  |  |  | 308 |
South America |  |  | 97 |  |  |  | 93 |  |  |  | 68 |
EMEA |  |  | 796 |  |  |  | 443 |  |  |  | 166 |
Corporate |  |  | 142 |  |  |  | 130 |  |  |  | 115 |
Total |  |  | 1,366 |  |  |  | 978 |  |  |  | 658 |

The increase in the number of employees in the last two years was mainly due to the internalization of the O&M services at Kaxu and at our solar assets in Spain in 2022 and 2023.
We refer to “Item 4.B-Business Overview-Environmental and Social Information-Employees” for information regarding the relationship between management and labor unions.
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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;

- | Chief Executive Officer: 6 times his fixed compensation;

- | Chief Financial Officer: 3 times his fixed compensation; and

- | 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 the 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.

F. | Disclosure of a Registrant’s Action to Recover Erroneously Awarded Compensation

The Company, during or after the last completed fiscal year, was not required to prepare an accounting restatement that required erroneously awarded compensation.
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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 116,159,054 ordinary shares outstanding as of the date of this annual report.

Name |  | Ordinary Shares Beneficially Owned |  |  | Deferred Restricted Share Units (2) |  |  | Share Units (3) |  |  | Percentage |
Directors and Officers |  |  |  |  |  |  |  |  |  |  |  |
William Aziz |  |  | 2,500 |  |  |  | - |  |  |  | - |  |  |  | - |
Arun Banskota |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Debora Del Favero |  |  | - |  |  |  | 4,973 |  |  |  | - |  |  |  | - |
Brenda Eprile |  |  | 13,000 |  |  |  | - |  |  |  | - |  |  |  | - |
Michael Forsayeth |  |  | 2,500 |  |  |  | 7,770 |  |  |  | - |  |  |  | - |
Edward C. Hall |  |  | 1,500 |  |  |  | - |  |  |  | - |  |  |  | - |
Santiago Seage |  |  | 117,491 |  |  |  | - |  |  |  | 105,868 |  |  |  | - |
Michael Woollcombe |  |  | 5,000 |  |  |  | 23,310 |  |  |  | - |  |  |  | - |
5% Beneficial Owner |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Algonquin (AY Holdco) B.V. (1) |  |  | 48,962,925 |  |  |  | - |  |  |  | - |  |  |  | 42.2 | %

Notes:

(1) | This information is based on the Schedule 13D filed on May 10, 2022 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 and our outstanding shares as of December 31, 2023.

(2) | The number of DRSUs includes accumulated cash dividend equivalent rights, corresponding to the dividends paid for one share in the period between the DRSU grant date and December 31, 2023, multiplied by the number of DRSUs on that date and divided by the share price of $21.50 as of December 31, 2023. The director shall not have any rights of a shareholder unless and until the DRSUs vest and are settled by the issuance of shares, and the dividend equivalent rights will not be payable until the DRSUs vest.

(3) | Non-vested Share Units as of December 31, 2023. LTIP share units subject to 5% minimum Total Shareholder Return.

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, 116,159,054 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 108,753,745 ordinary shares representing approximately 93.6% 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.
We are not aware of any arrangement that may, at a subsequent date, result in a change of control of our company.
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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 or Algonquin, 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’ or Algonquin’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 annual report Algonquin is the beneficial owner of 48,962,925 ordinary shares, representing 42.2% 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 contracted assets or proposed contracted assets described thereunder, with certain exceptions and 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.
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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.
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.
In July 2021 we acquired from Algonquin two solar projects which were under development at that time, La Tolua and Tierra Linda, both of which started operations in the first quarter of 2023.
In January 2024, we acquired from Liberty GES two PV projects in advanced development stage in Southern Spain with approximately 90 MW of combined generation capacity. The acquisition of land and interconnection are secured and the process for permits is well advanced. The projects were acquired in exchange for assuming the necessary guarantees, at no additional cost.
Given the fact that in the last five years we have only closed these acquisitions under the ROFO Agreements and given that to the best of our knowledge Algonquin’s pipeline outside Canada and the U.S. is limited, we do not currently expect these ROFO Agreements to be a material source of growth for us going forward.
ATM Plan Letter Agreement
In relation to our current ATM program established pursuant to the Distribution Agreement, we have 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.
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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 was subsequently amended to allow Algonquin to increase its shareholding in Atlantica up to a 48.5% without any change in corporate governance. Algonquin’s voting rights and rights to appoint directors are still limited to a 41.5% and the additional shares (the difference between the actual shares beneficially owned by Algonquin and shares representing a 41.5% voting rights) will vote replicating non-Algonquin’s shareholder’s vote.
One of the directors appointed by 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).
Dividend Distributions
We agreed that each of 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, 2023, our dividend payout objective was 80%. This objective can be modified by our Board of Directors in the future.
Pre-emption right
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 ROFO Agreements; 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.
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Termination
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.
As described under “—Dividend Distributions” above, each of 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.
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 which was initially $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 which was initially $92.3 million and was recorded 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.
Code of Conduct
We have 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 and sign 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 2021:

Declared | Record | Payable | Amount ($) per share
February 29, 2024 | March 12, 2024 | March 22, 2024 | 0.445
November 7, 2023 | November 30, 2023 | December 15, 2023 | 0.445
July 31, 2023 | August 31, 2023 | September 15, 2023 | 0.445
May 4, 2023 | May 31, 2023 | June 15, 2023 | 0.445
February 28, 2023 | March 14, 2023 | March 25, 2023 | 0.445
November 8, 2022 | November 30, 2022 | December 15, 2022 | 0.445
August 2, 2022 | August 31, 2022 | September 15, 2022 | 0.445
May 5, 2022 | May 31, 2022 | June 15, 2022 | 0.44
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

We declared our first quarterly dividend in November 2014 and paid it on December 15, 2014. Recently, on February 29, 2024, our Board of Directors approved a dividend of $0.445 per share corresponding to the fourth quarter of 2023, which is expected to be paid on March 22, 2024.
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, on an annual basis. We intend to distribute a quarterly dividend to shareholders. We intend to grow our business via organic growth through the optimization of the existing portfolio and through investments, development and construction of new assets and acquisitions. 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 Board of Directors may, by resolution, amend the cash dividend policy at any time.
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, the Note Issuance Facility 2020, the 2020 Green Private Placement and the Revolving Credit Facility contain, among other covenants, certain financial incurrence and maintenance covenants, as applicable. See “Item 5.B— 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, electricity market prices, 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, low electricity prices in our assets with exposure to merchant revenues, 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, maintenance capital expenditures, principal and interest payments on our and our subsidiaries’ outstanding debt, income tax expenses, inability to upstream cash from subsidiaries or to do it in an efficient manner, 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 through the development and construction of projects including expansion and repowering opportunities, as well as greenfield development, third-party acquisitions and the optimization of the existing portfolio. 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. Our Board of Directors may also decide to finance our investments with cash generated from operations to increase the capital dedicated to finance development, construction and acquisition of new assets and foster our growth.
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To the extent we issue additional shares to fund our business, our growth or for any other reason, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. Additionally, the incurrence of additional commercial bank borrowings or other debt to finance our growth would result in increased interest expense, which in turn may impact our cash available for distribution and, in turn, our ability to pay dividends to our shareholders.

B. | Significant Changes

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

ITEM 9. | THE OFFER AND LISTING

A. | Offering and Listing Details

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

B. | Plan of Distribution

Not applicable.

C. | Markets

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

D. | Selling Shareholders

Not applicable.

E. | Dilution

Not applicable.

F. | Expenses of the Issue

Not applicable.

ITEM 10. | ADDITIONAL INFORMATION

A. | Share Capital

Not applicable

B. | Memorandum and Articles of Association

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

C. | Material Contracts

See “Item 4.B—Business Overview,” “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources—Corporate debt agreements”.
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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.”

E. | Taxation

Material UK Tax Considerations
The following is a general summary of material UK tax considerations relating to the ownership and disposal of our shares. The comments set out below are based on current UK tax law as applied in England and Wales and HM Revenue & Customs (“HMRC”) published 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 and is written on the basis that we do not (and will not) directly or indirectly derive 75% or more of our qualifying asset value from U.K. land. 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.
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A corporate holder of shares that is a U.S. Holder will generally not be liable for UK corporation tax on chargeable gains realized on the disposal of its Atlantica Sustainable Infrastructure shares unless it carries on a trade in the United Kingdom through a permanent establishment to which the shares are attributable.
An individual holder of shares who is temporarily a non-UK resident for UK tax purposes will, in certain circumstances, become liable to UK tax on capital gains in respect of gains realized while he or she was not resident in the United Kingdom.
Stamp Duty and Stamp Duty Reserve Tax
The stamp duty and stamp duty reserve tax, or SDRT, treatment of the issue and transfer of, and the agreement to transfer, Atlantica Sustainable Infrastructure shares outside a depositary receipt system or a clearance service are discussed in the paragraphs under ‘—General’ below. The stamp duty and SDRT treatment of such transactions in relation to such systems are discussed in the paragraphs under “Depositary Receipt Systems and Clearance Services” below. 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.
Instruments transferring 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
No stamp duty, or SDRT, will arise on the issue of shares to a clearance service or depositary receipt system by Atlantica Sustainable Infrastructure.
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 be payable unless an exemption applies. If stamp duty or SDRT is payable, it is generally charged 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. Relevant exemptions include those relating to capital-raising arrangements or qualifying listing arrangements. The application of such exemptions is fact-specific and so holders of our shares should accordingly seek their own advice before paying or accepting such a charge.
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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, stamp duty or 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 the relevant shares) 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 1986.
Except in relation to clearance services that have made and maintained an election under Section 97A(1) of the Finance Act 1986 (to which the special rules outlined above 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.
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 the 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 holder 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.
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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 should 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.
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 our current or accumulated earnings and profits (as determined for U.S. federal income tax purposes), and will be includible in the gross income of a U.S. Holder 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. We intend to calculate our earnings and profits in accordance with U.S. federal income tax principles. If distributions exceed our current and accumulated earnings and profits, such excess distributions will generally constitute a return of capital to the extent of a 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) we are 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 we were not and will not be considered a PFIC for any taxable year, we do not believe that we were a PFIC, for U.S. federal income tax purposes, for the taxable year ended December 31, 2023, and do not anticipate becoming a PFIC for the current taxable year or in any future taxable year. 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 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.
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Taxation upon sale or other disposition of shares
A U.S. Holder will generally recognize a 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.
Any gain or loss recognized by a U.S. Holder on the sale or other disposition of the shares will generally be treated as U.S.-source gain or loss for U.S. foreign tax credit purposes, which may limit the ability to claim the foreign tax credit in respect of non-U.S. taxes imposed on the sale or other disposition of the shares. 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.
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 generally 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 a 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.
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, 2023, and do not anticipate becoming a PFIC for the current taxable year or foreseeable future taxable years. 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 were not a PFIC for the taxable year ended December 31, 2023, or will not be a PFIC for the current taxable year or in 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 (each, 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.
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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 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.
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 general tax treatment for PFICs described above 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 the 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.
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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.

I. | Subsidiaries Information

Not applicable.

J. | Annual Report to Security Holders

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

Our activities are undertaken through our segments and are exposed to market risks that include foreign exchange risk, interest rate risk, credit risk, liquidity risk, electricity price risk and country risk. Our objective is to protect Atlantica against material economic exposures and variability of results from those risks. 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 foreign exchange rate risk, interest rate risk, credit risk and liquidity risk, among others. Our internal management policies also define the use of hedging instruments and derivatives and the investment of excess cash. We use swaps and options on interest rates and foreign exchange rates to manage certain of our risks. None of the derivative contracts signed has an unlimited loss exposure.
The following table outlines Atlantica´s market risks and how they are managed:

Market Risk | Description of Risk |  | Management of Risk
Foreign exchange risk | We are exposed to foreign currency risk – including euro, Canadian dollar, South African rand, Colombian peso and Uruguayan peso – related to operations and certain foreign currency debt. Our presentation currency and the functional currency of most of our subsidiaries 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, whose revenue is 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, our solar plants in Colombia, have their revenue and expenses denominated in Colombian pesos and Albisu, our solar plant in Uruguay, has its revenue denominated in Uruguayan pesos, with a maximum and a minimum price in US dollars. |  | The main cash flows in our subsidiaries are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Project financing is typically denominated in the same currency as that of the contracted revenue agreement, which limits our exposure to foreign exchange risk. In addition, we maintain part of our corporate general and administrative expenses and part of our corporate debt in euros which creates a natural hedge for the distributions we receive from our assets in Europe. To further mitigate this exposure, our strategy is to hedge cash distributions from our assets in Europe. We hedge the exchange rate for the net distributions in euros (after deducting interest payments and general and administrative expenses in euros). 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. If the difference between the euro/U.S. dollar hedged rate for the year 2024 and the current rate was reduced by 5%, it would create a negative impact on cash available for distribution of approximately $4 million. This amount has been calculated as the average net euro exposure expected for the years 2024 to 2027 multiplied by the difference between the average hedged euro /U.S. dollar rate for 2024 and the euro/U.S. dollar rate as of the date of this annual report reduced by 5%. 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, the Colombian peso and the Uruguayan 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 | We are exposed to interest rate risk on our variable-rate debt. Interest rate risk arises mainly from our financial liabilities at variable interest rates (less than 10% of our consolidated debt currently). Interest rate risk may also arise in the future when we refinance our corporate debt, since interest rates at the moment of refinancing may be higher than current interest rates in our existing facilities. The most significant impact on our Annual Consolidated Condensed Interim Financial Statements related to interest rates corresponding to the potential impact of changes in EURIBOR or SOFR on the debt with interest rates based on these reference rates and on derivative positions. In relation to our interest rate swaps positions, an increase in EURIBOR or SOFR 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 SOFR that does not exceed the contracted fixed interest rate would not be offset by our derivative position and would result in a stable net expense recognized in our consolidated income statement. In relation to our interest rate options positions, an increase in EURIBOR, or SOFR 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. However, an increase in these rates of reference below the strike price would result in higher interest expenses. |  | Our assets largely consist of long duration physical assets, and financial liabilities consist primarily of long-term fixed-rate debt or floating-rate debt that has been swapped to fixed rates with interest rate financial instruments to minimize the exposure to interest rate fluctuations. We use interest rate swaps and interest rate options (caps) to mitigate interest rate risk. As of December 31, 2023, approximately 93% of our consolidated debt has fixed rates or is hedged. As of that same date, 92% of our project debt and approximately 94% of our corporate debt either has fixed interest rates or has been hedged with swaps or caps. Our revolving credit facility has variable interest rates and is not hedged as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements—Revolving Credit Facility”; In the event that EURIBOR or SOFR had risen by 25 basis points as of December 31, 2023, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $0.7 million (a loss of $1.3 million in 2022) and a gain in hedging reserves of $17.6 million ($18.4 million in 2022). The increase in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.

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Credit risk | We are exposed to credit risk mainly from operating activities, the maximum exposure of which is represented by the carrying amounts reported in the statements of financial position. We are exposed to credit risk if counterparties to our contracts, trade receivables, interest rate swaps, or foreign exchange hedge contracts are unable to meet their obligations. The credit rating of Eskom is currently B from S&P, B2 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 Republic of South Africa. In addition, Pemex’s credit rating is currently BBB from S&P, B3 from Moody’s and B+ from Fitch. We have experienced delays in collections from Pemex, especially since the second half of 2019, which have been significant in certain quarters, including in the fourth quarter of 2023. |  | The diversification by geography and business sector helps to diversify credit risk exposure by diluting our exposure to a single client. In the case of Kaxu, Eskom’s payment guarantees to our Kaxu solar plant are underwritten by the South African Department of Mineral Resources and Energy, under the terms of an implementation agreement. The credit ratings of the Republic of South Africa as of the date of this annual report are BB-/Ba2/BB- by S&P, Moody’s and Fitch, respectively. In the case of Pemex, we continue to maintain a proactive approach including fluent dialogue with our client.
Liquidity risk | We are exposed to liquidity risk for financial liabilities. Our liquidity at the corporate level depends on distribution from the project level entities, most of which have project debt in place. Distributions are generally subject to the compliance with covenants and other conditions under our project finance agreements. |  | 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 or by groups of projects. 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. In addition, we maintain a periodic communication with our lenders and regular monitoring of debt covenants and minimum ratios. As of December 31, 2023, we had $411.1 million liquidity at the corporate level, comprised of $33.0 million of cash on hand at the corporate level and $378.1 million available under our Revolving Credit Facility. We believe that the Company’s liquidity position, cash flows from operations and availability under our 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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Electricity price risk | We currently have three assets with merchant revenues (Chile PV 1 and Chile PV 3, where we have a 35% ownership, and Lone Star II, where we have a 49% ownership) and one asset with partially contracted revenues (Chile PV 2, where we have a 35% ownership). Due to low electricity prices in Chile, the project debts of Chile PV 1 and 2 are under an event of default as of December 31, 2023 and as of the date of this annual report. Chile PV 1 was not able to maintain the minimum required cash in its debt service reserve account as of December 31, 2023 and did not make its debt service payment in January. In addition, in October 2023, Chile PV 2 did not make its debt service payment. This asset obtained additional financing from the banks and made the debt service payment in December, although it was not able to fund its debt service reserve account subsequently. As a result, although we do not expect an acceleration of the debt to be declared by the credit entities, as of December 31, 2023 Chile PV 1 and 2 did not have an unconditional right to defer the settlement of the debt for at least twelve months and the project debt was classified as current in our Annual Consolidated Financial Statements. We are in conversations with the banks, together with our partner, regarding a potential waiver. The value of the net assets contributed by Chile PV 1&2 to the Annual Consolidated Financial Statements, excluding non-controlling interest, was close to zero as of December 31, 2023 (see “Item 4—Information on the Company—Our Operations”). In addition, in several of the jurisdictions in which we operate including Spain, Chile and Italy 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 fully compensate for fluctuations in the market price component, and, consequently, total remuneration may be volatile. |  | We manage our exposure to electricity price risk by ensuring that most of our revenues are not exposed to fluctuations in electricity prices. As of December 31, 2023, assets with merchant exposure represent less than a 2% of our portfolio in terms of Adjusted EBITDA. Regarding regulated assets with exposure to electricity market prices, these assets have the right to receive a “reasonable rate of return” (see “Item 4—Information on the Company— Regulation”). As a result, fluctuations in market prices may cause volatility in results of operations and cash flows, but it should not affect the net value of these assets.

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| In addition, operating costs in certain of our existing or future projects depend to some extent on market prices of electricity used for self-consumption. |  |
Country risk | We consider that Algeria and South Africa, which represent a small portion of the portfolio in terms of cash available for distribution, are the geographies with a higher political risk profile. |  | Most of the countries in which we have operations are OECD countries. In 2019, we entered into a political risk insurance policy with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $47.0 million in the event that the South African Department of Mineral Resources and Energy does not comply with its obligations as guarantor. We also have a political risk insurance policy in place for two of our assets in Algeria for up to $35.8 million, including two years of dividend coverage. These insurance policies do not cover credit 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, 2023. 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 SEC, 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.
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, 2023, based on the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (2013). Based on this assessment, management concluded that, as of December 31, 2023, its internal control over financial reporting was effective based on those criteria.
Our internal control over financial reporting as of December 31, 2023, has been audited by Ernst & Young S.L., an independent registered public accounting firm, as stated in their report which follows below.
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(c) | Attestation Report of the Independent Registered Public Accounting Firm

The report of Ernst & Young, S.L., our Independent Registered Public Accounting Firm (“EY”), 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, Mr. William Aziz, Ms. Brenda Eprile and Mr. Michael Forsayeth qualify as “audit committee financial experts” under applicable SEC rules.

ITEM 16B. | CODE OF ETHICS

Our Board of Directors 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. classified by type of service rendered in 2023:

|  | EY |  |  | Other Auditors |  |  | Total |
|  | ($ in thousands) |
Audit Fees |  |  | 1,954 |  |  |  | 105 |  |  |  | 2,059 |
Audit-Related Fees |  |  | 70 |  |  |  | - |  |  |  | 70 |
Tax Fees |  |  | 344 |  |  |  | - |  |  |  | 344 |
Total |  |  | 2,368 |  |  |  | 105 |  |  |  | 2,473 |

The following table provides information on the aggregate fees billed by our principal accountants, EY classified by type of service rendered in 2022:

|  | EY |  |  | Other Auditors |  |  | Total |
|  | ($ in thousands) |
Audit Fees |  |  | 1,643 |  |  |  | 295 |  |  |  | 1,938 |
Audit-Related Fees |  |  | 422 |  |  |  | - |  |  |  | 422 |
Tax Fees |  |  | 502 |  |  |  | - |  |  |  | 502 |
Total |  |  | 2,567 |  |  |  | 295 |  |  |  | 2,862 |

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“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.
“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 2023 and 2022 related to comfort letters and consents required for capital market transactions of our largest shareholder are also included in this category ($25 thousand and $204 thousand in 2023 and 2022 respectively). These fees were re-invoiced and paid by our largest shareholder.
“Tax Fees” include mainly fees charged for transfer pricing services and tax compliance services in our US subsidiaries.
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 policy deals with the relationships between the external auditor and Atlantica and it also relates to Audit Committee pre-approval of services provided by the external auditor.
Subject to the approval of the independent auditor by our shareholders, the Audit Committee has the sole authority to appoint, retain or replace the independent auditor. The Audit Committee is also directly responsible for the compensation and oversight of the work of the independent auditor. These policies generally provide that we will not engage our independent auditors to render audit or non-audit services unless the service is specifically approved in advance by the Audit Committee. The Audit Committee’s pre-approval policy, which covers audit and non-audit services provided to us or to any of our subsidiaries, is as follows:

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

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

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

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

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

| o | Tax services;

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

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• | 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.

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.
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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.

ITEM 16J. | INSIDER TRADING POLICIES

Not applicable.

ITEM 16K. | CYBERSECURITY

1. | Risk Management Strategy

Atlantica regularly assesses risks from cybersecurity threats, monitors its information systems for potential vulnerabilities and tests those systems pursuant to the Company’s cybersecurity policies, processes and practices, which are integrated into the Company’s overall risk management system. This integration ensures that cybersecurity considerations are evaluated alongside other business risks, such as financial, operational, or legal. This integration ensures that cybersecurity is not treated in isolation but is seen as a critical aspect of the company’s risk management.
The continuous monitoring and identification of significant cybersecurity risks and threats leads to the design of what we believe are efficient action plans to prevent and mitigate cybersecurity risks and threats. This approach is aligned with Atlantica’s general risk management strategy, which ensures a proactive approach towards risk mitigation.
The design and implementation of Atlantica’s company-wide cybersecurity strategic, policy, standards, architecture, and processes are the responsibility of our IT team, which includes our Head of IT, with approximately 25 years of experience in information security, and a dedicated IT Security Manager with more than 10 years of experience in information security.
We engage external IT suppliers to manage some aspects of IT security under the supervision of our IT Security Manager and certify our information security management system through a recognized audit firm in accordance with ISO 27001 “Information security – Security techniques – Information Security Management System”, ensuring comprehensive evaluation and compliance. Additionally, we perform an annual “red team” exercise conducted by experienced cybersecurity specialists from a third party.
To protect Atlantica’s information systems from cybersecurity threats, the Company uses various security tools that help the Company identify, escalate, investigate, resolve and recover from security incidents in a timely manner. We have preventive, detective, and reactive controls in-place to avoid and/or mitigate damage or failure to our plants that could lead to business disruption.
Our cybersecurity risk management program is aligned with internal and external audit recommendations, international standards, industry standards and best practices such as international standard ISO 31000 “Risk Management”, ISO 27005 “Guidance on managing information security risks” and National Institute of Standards and Technology (NIST) Special Publication 800-30 “Guide for Conducting Risk Assessments” that provide guidelines and principles for information technology security risk management.
These standards follow a risk-based approach to cybersecurity threats which involves conducting regular risk assessments to identify potential cybersecurity threats and vulnerabilities, followed by the implementation of controls to mitigate these risks. Our cyber security risk management system is dynamic, it is continually reviewed and updated to respond to new security challenges and advancements in technology.
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2. | Cybersecurity Governance

Board’s Role
The Board is responsible for the effective oversight of the Company’s strategy and performance, financial reporting, corporate governance process, and internal control and risk management framework, including cybersecurity. The Audit Committee oversees the Company’s risk management program, which focuses on the most significant risks the Company faces in the short-, intermediate-, and long-term timeframe. Audit Committee meetings include discussions of specific risk areas throughout the year, including, among others, those relating to cybersecurity, and reports from the Head of Risks on the Company’s enterprise risk profile on an annual basis. The Board of Directors is informed at least twice a year on the company’s cybersecurity strategy, risk assessment, and measures and systems to securely protect and safeguard Atlantica’s information.
Management Role
Atlantica relies on certified employees for its security risk assessment, such as Certified Information System Auditor (CISA by ISACA), Certified Information Security Manager (CISM by ISACA), ISO 27001 Lead Auditor and ISO 27001 Lead Implementer.
At the management level, our Head of IT, with approximately 25 years of experience in information security, is responsible for defining Atlantica’s cybersecurity strategy. The Head of IT reports to the Chief Financial Officer (CFO) and is a member of both the Management Committee and the Compliance Management Committee. The Chief Executive Officer, the Chief Financial Officer, and the Head of IT review Atlantica’s cybersecurity at least on a monthly basis.
Our IT Security Committee is chaired by the Head of IT and also includes our IT Security Manager, and other IT managers relevant for this purpose. This committee meets weekly to review and update potential threats, the most recent trends in cyber-attacks, the progress in implementing action plans, and the evaluation of possible opportunities for further improvement.
Atlantica recognizes the critical importance of training employees as part of its cybersecurity risk management strategy. We conduct an annual cybersecurity awareness training program, tailored sessions on specific topics are organized for selected roles and internal phishing exercises to assess the awareness level of our employees.
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.

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 Sustainable Infrastructure plc (incorporated by reference from Exhibit 3.1 to Atlantica Sustainable Infrastructure plc’s (formerly known as Atlantica Yield plc) 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.

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4.1 | Credit and Guaranty Agreement dated May 10, 2018 (incorporated by reference from Exhibit 99.1 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on September 5, 2018– SEC File No. 001-36487).
4.2 | First Amendment and Joinder to Credit and Guaranty Agreement, dated January 24, 2019 (incorporated by reference from Exhibit 4.14 from Atlantica Sustainable Infrastructure plc’s Form 20-F filed with the SEC on February 28, 2019 – SEC File No. 001-36487).
4.3 | Second Amendment to Credit and Guaranty Agreement, dated August 2, 2019 (incorporated by reference from Exhibit 4.18 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on November 7, 2019 – SEC File No. 001-36487).
4.4 | Third Amendment to Credit and Guaranty Agreement, dated December 17, 2019 (incorporated by reference from Exhibit 4.19 from Atlantica Sustainable Infrastructure plc’s Form 20-F filed with the SEC on February 28, 2020 – SEC File No. 001-36487).
4.5 | 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).
4.6 | Fifth Amendment to Credit and Guaranty Agreement, dated December 3, 2020 (incorporated by reference from Exhibit 4.20 from Atlantica Sustainable Infrastructure plc’s Form 20-F, as amended, filed with the SEC on February 28, 2022 – SEC File No. 001-36487).
4.7 | 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).
4.8 | Seventh Amendment to Credit and Guaranty Agreement, dated May 5, 2022 (incorporated by reference from Exhibit 4.26 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on May 9, 2022 – SEC File No. 001-36487).
4.9 | Eighth Amendment to Credit and Guaranty Agreement, dated May 30, 2023 (incorporated by reference from Exhibit 4.24 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on May 31, 2023 – SEC File No. 001-36487).
4.10 | Shareholder’s Agreement dated March 5, 2018 among Atlantica Sustainable Infrastructure plc (formerly known as Atlantica Yield plc), Liberty GES and Algonquin Power & Utilities Corp. (incorporated by reference from Exhibit 4.13 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on March 12, 2018– SEC File No. 001-36487).
4.11 | Right of First Offering Agreement dated March 5, 2018 between Atlantica Sustainable Infrastructure plc (formerly known as Atlantica Yield plc) and Algonquin Power and Utilities Corp. (incorporated by reference from Exhibit 4.15 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on March 12, 2018– SEC File No. 001-36487).
4.12 | Enhanced Cooperation Agreement, dated May 9, 2019, by and among Algonquin Power & Utilities, Corp., Atlantica Sustainable Infrastructure plc (formerly known as Atlantica Yield plc) and Abengoa-Algonquin Global Energy Solutions B.V. (incorporated by reference from Exhibit 99.1 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 7, 2019 – SEC File No. 001-36487).

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4.13 | Subscription Agreement, dated May 9, 2019, by and between Algonquin Power & Utilities, Corp. and Atlantica Sustainable Infrastructure plc (formerly known as Atlantica Yield plc) (incorporated by reference from Exhibit 99.2 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 7, 2019 – SEC File No. 001-36487).
4.14 | AYES Shareholder Agreement, dated May 24, 2019, by and among Algonquin Power & Utilities, Corp., Atlantica Sustainable Infrastructure plc (formerly known as Atlantica Yield plc) and Atlantica Yield Energy Solutions Canada Inc. (incorporated by reference from Exhibit 99.3 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 7, 2019 – SEC File No. 001-36487).
4.15 | Note Purchase Agreement, dated March 20, 2020, between Atlantica Sustainable Infrastructure plc (formerly known as 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 Sustainable Infrastructure plc’s Form 6-K filed with the SEC on May 7, 2020 – SEC File No. 001-36487).
4.16 | 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).
4.17 | 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).
4.18 | 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).
4.19 | 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).
4.20 | Amendment No. 1 to Note Issuance Facility Agreement, dated March 30, 2021. (incorporated by reference from Exhibit 4.22 from Atlantica Sustainable Infrastructure plc’s Form 20-F, as amended, filed with the SEC on February 28, 2022 – SEC File No. 001-36487).

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4.21 | 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).
4.22 | Distribution Agreement, dated February 28, 2022, between the Company and BofA Securities Inc., MUFG Securities Americas Inc., and RBC Capital Markets LLC (incorporated by reference from Exhibit 1.1 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on February 28, 2022 – SEC File No. 001-36487).
4.23 | Amendment Agreement to the Distribution Agreement, dated May 9, 2022 (incorporated by reference from Exhibit 1.1 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on May 9, 2022 – SEC File No. 001-36487).
4.24 | 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.
97.1 | Compensation (Clawback) Recovery Policy.

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SIGNATURE
The registrant hereby certifies that it meets all of the requirements for filing this Amendment No. 1 on Form 20-F/A and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
Date: March 1, 2024

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

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

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ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC
INDEX TO FINANCIAL STATEMENTS
Annual Consolidated Financial Statements as of December 31, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021

Report of Ernst and Young, S.L. (PCAOB ID 1461) | F-1
Consolidated statements of financial position as of December 31, 2023 and 2022 | F-4
Consolidated income statements for the years ended December 31, 2023, 2022 and 2021 | F-6
Consolidated financial statements of comprehensive income for the years ended December 31, 2023, 2022 and 2021 | F-7
Consolidated statements of changes in equity for the years ended December 31, 2023, 2022 and 2021 | F-8
Consolidated cash flow statements for the years ended December 31, 2023, 2022 and 2021 | F-11
Notes to the annual consolidated financial statements | F-13
Appendix I: Entities included in the Group as subsidiaries as of December 31, 2023 and 2022 | F-57
Appendix II: Investments recorded under the equity method as of December 31, 2023 and 2022 | F-59
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, 2023 and 2022 | F-61
Appendix IV: Additional Information of Subsidiaries including material Non-controlling interest as of December 31, 2023 and 2022 | F-66

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atlantica Sustainable Infrastructure, PLC
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of Atlantica Sustainable Infrastructure, PLC (the “Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, changes in equity and cash flows, for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with International Financial Reporting Standards as issued by International Accounting Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 29, 2024, expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
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Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Recoverability assessment of contracted concessional, PP&E and other intangible assets

Description of the Matter | As described in Note 6 to the consolidated financial statements, the Company includes “contracted concessional, PP&E and other intangible assets” amounting to $7,204 million at December 31, 2023. Revenue derived from the Company’s contracted concessional, PP&E and other intangible assets are primarily governed by power purchase agreements (“PPAs”) with the Company’s customers or by the applicable energy market regulations of each country, mainly in Spain and Chile. As described in Note 2 to the consolidated financial statements, the Company reviews its contracted concessional assets, PP&E and other intangible assets for impairment indicators whenever events or changes in circumstances indicate that the carrying amounts of the assets or group of assets may not be recoverable, or previous impairment losses are no longer adequate. As discussed in Note 6, management identified triggering events at two Chilean assets (Chile PV1 and Chile PV2) and as a result, a $16 million impairment charge was recorded in 2023 for Chile PV1 and no impairment for Chile PV2. Auditing the Company’s recoverability assessment of contracted concessional, PP&E and other intangible assets involves significant judgment in determining whether impairment indicators existed and, if an indicator exists, in the assumptions used by management in the determination of whether an impairment should be recorded or reversed. The main inputs considered when evaluating for impairment indicators include the performance of the assets versus budget, changes in applicable regulations and estimates of future electricity prices. The significant assumptions which required substantial judgement or estimation used in management’s impairment calculation are discount rates and projections considering real data based on contract terms and projected changes in both selling prices and costs.
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company’s contracted concessional, PP&E and other intangible assets recoverability assessment process. Among others, we tested controls over management’s identification of potential impairment indicators, as well as controls over the determination of significant assumptions used in the impairment calculation, including, the discount rates and underlying projections used in the Company’s impairment assessment. To test the Company’s impairment indicators assessment for contracted concessional, PP&E and other intangible assets, our audit procedures included, among others, comparing actual energy production versus budget for each asset, assessing the estimated future electricity prices versus prior year future estimates and determining whether identified changes in applicable regulation would negatively impact the Company’s assets’ future cash flows. As part of our impairment test audit procedures, we assessed the appropriateness of the main inputs used in the cash ﬂow projections, by, for example, comparing future price estimates versus prior year future estimates. For the discount rate, we involved our valuation specialists to assist us in developing independent estimates for a range of discount rates, which we compared to those used by the Company. We assessed the adequacy of the related disclosures in the Company’s consolidated financial statements, including the sensitivity analysis on electricity prices and discount rate assumptions.

/s/ ERNST & YOUNG, S.L.
We have served as the Company’s auditor since 2019
Madrid, Spain
February 29, 2024

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atlantica Sustainable Infrastructure PLC:
Opinion on Internal Control Over Financial Reporting
We have audited Atlantica Sustainable Infrastructure PLC’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Atlantica Sustainable Infrastructure PLC (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2023 consolidated financial statements of the Company and our report dated February 29, 2024, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ ERNST & YOUNG, S.L.
We have served as the Company’s auditor since 2019.
Madrid, Spain
February 29, 2024
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Consolidated statements of financial position as of December 31, 2023 and 2022
Amounts in thousands of U.S. dollars

|  |  |  |  | As of December 31, |
|  | Note (1) |  |  | 2023 |  |  | 2022 |
Assets |  |  |  |  |  |  |  |  |
Non-current assets |  |  |  |  |  |  |  |  |
Contracted concessional, PP&E and other intangible assets |  |  | 6 |  |  |  | 7,204,267 |  |  |  | 7,483,259 |
Investments carried under the equity method |  |  | 7 |  |  |  | 230,307 |  |  |  | 260,031 |
Other accounts receivable |  |  | 9 |  |  |  | 79,875 |  |  |  | 86,431 |
Derivative assets |  |  | 10 |  |  |  | 56,707 |  |  |  | 89,806 |
Other financial assets |  |  | 9 |  |  |  | 136,582 |  |  |  | 176,237 |
Deferred tax assets |  |  | 19 |  |  |  | 160,995 |  |  |  | 149,656 |
Total non-current assets |  |  |  |  |  |  | 7,732,151 |  |  |  | 8,069,183 |
Current assets |  |  |  |  |  |  |  |  |  |  |  |
Inventories |  |  |  |  |  |  | 29,870 |  |  |  | 34,511 |
Trade receivables |  |  | 12 |  |  |  | 213,345 |  |  |  | 125,437 |
Credits and other receivables |  |  | 12 |  |  |  | 73,138 |  |  |  | 74,897 |
Trade and other receivables |  |  | 12 |  |  |  | 286,483 |  |  |  | 200,334 |
Other financial assets |  |  | 9 |  |  |  | 188,886 |  |  |  | 195,893 |
Cash and cash equivalents |  |  | 13 |  |  |  | 448,301 |  |  |  | 600,990 |
|  |  |  |  |  |  | 953,540 |  |  |  | 1,031,728 |
Assets held for sale |  |  | 8 |  |  |  | 28,642 |  |  |  | - |
Total current assets |  |  |  |  |  |  | 982,182 |  |  |  | 1,031,728 |
Total assets |  |  |  |  |  |  | 8,714,333 |  |  |  | 9,100,911 |

(1) | Notes 1 to 25 are an integral part of the Consolidated Financial Statements

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Consolidated statements of financial position as of December 31, 2023 and 2022
Amounts in thousands of U.S. dollars

|  |  |  |  | As of December 31, |
|  | Note (1) |  |  | 2023 |  |  | 2022 |
Equity and liabilities |  |  |  |  |  |  |  |  |
Equity attributable to the Company |  |  |  |  |  |  |  |  |
Share capital |  |  | 14 |  |  |  | 11,616 |  |  |  | 11,606 |
Share premium |  |  | 14 |  |  |  | 736,594 |  |  |  | 986,594 |
Capital reserves |  |  | 14 |  |  |  | 858,220 |  |  |  | 814,951 |
Other reserves |  |  | 10 |  |  |  | 308,002 |  |  |  | 345,567 |
Accumulated currency translation differences |  |  | 14 |  |  |  | (139,434 | ) |  |  | (161,307 | )
Accumulated deficit |  |  | 14 |  |  |  | (351,521 | ) |  |  | (397,540 | )
Non-controlling interest |  |  | 14 |  |  |  | 165,332 |  |  |  | 189,176 |
Total equity |  |  |  |  |  |  | 1,588,809 |  |  |  | 1,789,047 |
Non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Long-term corporate debt |  |  | 15 |  |  |  | 1,050,816 |  |  |  | 1,000,503 |
Borrowings |  |  |  |  |  |  | 3,061,033 |  |  |  | 3,322,115 |
Notes and bonds |  |  |  |  |  |  | 870,840 |  |  |  | 904,403 |
Long-term project debt |  |  | 16 |  |  |  | 3,931,873 |  |  |  | 4,226,518 |
Grants and other liabilities |  |  | 17 |  |  |  | 1,233,808 |  |  |  | 1,252,513 |
Derivative liabilities |  |  | 10 |  |  |  | 29,957 |  |  |  | 16,847 |
Deferred tax liabilities |  |  | 19 |  |  |  | 271,288 |  |  |  | 296,481 |
Total non-current liabilities |  |  |  |  |  |  | 6,517,742 |  |  |  | 6,792,862 |
Current liabilities |  |  |  |  |  |  |  |  |  |  |  |
Short-term corporate debt |  |  | 15 |  |  |  | 34,022 |  |  |  | 16,697 |
Borrowings |  |  |  |  |  |  | 332,734 |  |  |  | 273,556 |
Notes and bonds |  |  |  |  |  |  | 54,653 |  |  |  | 52,978 |
Short-term project debt |  |  | 16 |  |  |  | 387,387 |  |  |  | 326,534 |
Trade payables and other current liabilities |  |  | 18 |  |  |  | 141,713 |  |  |  | 140,230 |
Income and other tax payables |  |  |  |  |  |  | 44,660 |  |  |  | 35,541 |
Total current liabilities |  |  |  |  |  |  | 607,782 |  |  |  | 519,002 |
Total equity and liabilities |  |  |  |  |  |  | 8,714,333 |  |  |  | 9,100,911 |

(1) | Notes 1 to 25 are an integral part of the Consolidated Financial Statements

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Consolidated statements of profit or loss for the years ended December 31, 2023, 2022 and 2021
Amounts in thousands of U.S. dollars

|  | Note (1) |  |  | For the year ended December 31, |
|  |  |  |  | 2023 |  |  | 2022 |  |  | 2021 |
Revenue |  |  | 4 |  |  |  | 1,099,894 |  |  |  | 1,102,029 |  |  |  | 1,211,749 |
Other operating income |  |  | 22 |  |  |  | 101,087 |  |  |  | 80,782 |  |  |  | 74,670 |
Employee benefit expenses |  |  | 21 |  |  |  | (104,083 | ) |  |  | (80,232 | ) |  |  | (78,758 | )
Depreciation, amortization, and impairment charges |  |  | 6 |  |  |  | (418,271 | ) |  |  | (473,638 | ) |  |  | (439,441 | )
Other operating expenses |  |  | 22 |  |  |  | (336,622 | ) |  |  | (351,248 | ) |  |  | (414,330 | )
Operating profit |  |  |  |  |  |  | 342,005 |  |  |  | 277,693 |  |  |  | 353,890 |
Financial income |  |  | 23 |  |  |  | 25,007 |  |  |  | 10,149 |  |  |  | 5,962 |
Financial expense |  |  | 23 |  |  |  | (323,749 | ) |  |  | (330,445 | ) |  |  | (360,898 | )
Net exchange differences |  |  | 23 |  |  |  | (2,549 | ) |  |  | 10,257 |  |  |  | 1,873 |
Other financial income/(loss), net |  |  | 23 |  |  |  | (16,683 | ) |  |  | (895 | ) |  |  | 12,171 |
Financial expense, net |  |  |  |  |  |  | (317,974 | ) |  |  | (310,934 | ) |  |  | (340,892 | )
Share of profit of entities carried under the equity method |  |  | 7 |  |  |  | 13,207 |  |  |  | 21,465 |  |  |  | 12,304 |
Profit /(loss) before income tax |  |  |  |  |  |  | 37,238 |  |  |  | (11,776 | ) |  |  | 25,302 |
Income tax (expense)/income |  |  | 19 |  |  |  | (790 | ) |  |  | 9,689 |  |  |  | (36,220 | )
Profit/(loss) for the year |  |  |  |  |  |  | 36,448 |  |  |  | (2,087 | ) |  |  | (10,918 | )
Profit/(loss) attributable to non-controlling interest |  |  |  |  |  |  | 6,932 |  |  |  | (3,356 | ) |  |  | (19,162 | )
Profit/(loss) for the year attributable to the Company |  |  |  |  |  |  | 43,380 |  |  |  | (5,443 | ) |  |  | (30,080 | )
Weighted average number of ordinary shares outstanding (thousands) – basic |  |  | 24 |  |  |  | 116,152 |  |  |  | 114,695 |  |  |  | 111,008 |
Weighted average number of ordinary shares outstanding (thousands) – diluted |  |  | 24 |  |  |  | 119,720 |  |  |  | 118,865 |  |  |  | 115,408 |
Basic earnings per share (U.S. dollar per share) |  |  | 24 |  |  |  | 0.37 |  |  |  | (0.05 | ) |  |  | (0.27 | )
Diluted earnings per share (U.S. dollar per share) (*) |  |  | 24 |  |  |  | 0.37 |  |  |  | (0.09 | ) |  |  | (0.28 | )

(*) | Antidilutive effect applied, where applicable (see Note 24)

(1) | Notes 1 to 25 are an integral part of the Consolidated Financial Statements

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Table of Contents
Consolidated statements of comprehensive income for the years ended December 31, 2023, 2022 and 2021
Amounts in thousands of U.S. dollars

|  |  |  |  | For the year ended December 31, |
|  | Note (1) |  |  | 2023 |  |  | 2022 |  |  | 2021 |
Profit/(loss) for the year |  |  |  |  |  | 36,448 |  |  |  | (2,087 | ) |  |  | (10,918 | )
Items that may be subject to transfer to profit and loss statement |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Change in fair value of cash flow hedges |  |  |  |  |  | (22,437 | ) |  |  | 218,737 |  |  |  | 33,846 |
Currency translation differences |  |  |  |  |  | 24,584 |  |  |  | (33,704 | ) |  |  | (41,956 | )
Tax effect |  |  |  |  |  | 1,258 |  |  |  | (54,405 | ) |  |  | (9,139 | )
Net income/(expense) recognized directly in equity |  |  |  |  |  | 3,405 |  |  |  | 130,628 |  |  |  | (17,249 | )
Cash flow hedges |  |  | 10 |  |  |  | (27,115 | ) |  |  | 38,187 |  |  |  | 58,292 |
Tax effect |  |  |  |  |  |  | 6,779 |  |  |  | (9,547 | ) |  |  | (14,573 | )
Transfers to profit and loss statement |  |  |  |  |  |  | (20,336 | ) |  |  | 28,640 |  |  |  | 43,719 |
Other comprehensive income/(loss) |  |  |  |  |  |  | (16,931 | ) |  |  | 159,268 |  |  |  | 26,470 |
Total comprehensive income for the year |  |  |  |  |  |  | 19,517 |  |  |  | 157,181 |  |  |  | 15,552 |
Total comprehensive (income)/loss attributable to non-controlling interest |  |  |  |  |  |  | 8,171 |  |  |  | (14,613 | ) |  |  | (14,586 | )
Total comprehensive income attributable to the Company |  |  |  |  |  |  | 27,688 |  |  |  | 142,568 |  |  |  | 966 |

(1) | Notes 1 to 25 are an integral part of the Consolidated Financial Statements

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Table of Contents
Consolidated statements of changes in equity for the years ended December 31, 2023, 2022 and 2021
Amounts in thousands of U.S. dollars

|  | 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, 2021 |  |  | 10,667 |  |  |  | 1,011,743 |  |  |  | 881,745 |  |  |  | 96,641 |  |  |  | (99,925 | ) |  |  | (373,489 | ) |  |  | 1,527,382 |  |  |  | 213,499 |  |  |  | 1,740,881 |
Profit/(loss) for the year after taxes |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (30,080 | ) |  |  | (30,080 | ) |  |  | 19,162 |  |  |  | (10,918 | )
Change in fair value of cash flow hedges net of transfer to profit and loss statement |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 97,421 |  |  |  | - |  |  |  | (10,060 | ) |  |  | 87,361 |  |  |  | 4,777 |  |  |  | 92,138 |
Currency translation differences |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (33,525 | ) |  |  | - |  |  |  | (33,525 | ) |  |  | (8,431 | ) |  |  | (41,956 | )
Tax effect |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (22,790 | ) |  |  | - |  |  |  | - |  |  |  | (22,790 | ) |  |  | (922 | ) |  |  | (23,712 | )
Other comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 74,631 |  |  |  | (33,525 | ) |  |  | (10,060 | ) |  |  | 31,046 |  |  |  | (4,576 | ) |  |  | 26,470 |
Total comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 74,631 |  |  |  | (33,525 | ) |  |  | (40,140 | ) |  |  | 966 |  |  |  | 14,586 |  |  |  | 15,552 |
Capital contribution |  |  | 573 |  |  |  | 60,268 |  |  |  | 128,920 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 189,761 |  |  |  | - |  |  |  | 189,761 |
Reduction of Share Premium |  |  | - |  |  |  | (200,000 | ) |  |  | 200,000 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Business combinations |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 8,287 |  |  |  | 8,287 |
Share-based compensation |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 14,928 |  |  |  | 14,928 |  |  |  | - |  |  |  | 14,928 |
Distributions |  |  | - |  |  |  | - |  |  |  | (190,638 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (190,638 | ) |  |  | (30,166 | ) |  |  | (220,804 | )
Balance as of December 31, 2021 |  |  | 11,240 |  |  |  | 872,011 |  |  |  | 1,020,027 |  |  |  | 171,272 |  |  |  | (133,450 | ) |  |  | (398,701 | ) |  |  | 1,542,399 |  |  |  | 206,206 |  |  |  | 1,748,605 |

Notes 1 to 25 are an integral part of the Consolidated Financial Statements
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Table of Contents

|  | 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, 2022 |  |  | 11,240 |  |  |  | 872,011 |  |  |  | 1,020,027 |  |  |  | 171,272 |  |  |  | (133,450 | ) |  |  | (398,701 | ) |  |  | 1,542,399 |  |  |  | 206,206 |  |  |  | 1,748,605 |
Profit/(Loss) for the year after taxes |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (5,443 | ) |  |  | (5,443 | ) |  |  | 3,356 |  |  |  | (2,087 | )
Change in fair value of cash flow hedges net of transfer to profit and loss statement |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 235,732 |  |  |  | - |  |  |  | 1,573 |  |  |  | 237,305 |  |  |  | 19,619 |  |  |  | 256,924 |
Currency translation differences |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (27,857 | ) |  |  | - |  |  |  | (27,857 | ) |  |  | (5,847 | ) |  |  | (33,704 | )
Tax effect |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (61,437 | ) |  |  | - |  |  |  | - |  |  |  | (61,437 | ) |  |  | (2,515 | ) |  |  | (63,952 | )
Other comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 174,295 |  |  |  | (27,857 | ) |  |  | 1,573 |  |  |  | 148,011 |  |  |  | 11,257 |  |  |  | 159,268 |
Total comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 174,295 |  |  |  | (27,857 | ) |  |  | (3,870 | ) |  |  | 142,568 |  |  |  | 14,613 |  |  |  | 157,181 |
Capital contribution (Note 14) |  |  | 366 |  |  |  | 114,583 |  |  |  | (1,970 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 112,979 |  |  |  | - |  |  |  | 112,979 |
Business combinations (Note 5) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 14,300 |  |  |  | 14,300 |
Share-based compensation (Note 14) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 5,031 |  |  |  | 5,031 |  |  |  | - |  |  |  | 5,031 |
Distributions (Note 14) |  |  | - |  |  |  | - |  |  |  | (203,106 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (203,106 | ) |  |  | (45,943 | ) |  |  | (249,049 | )
Balance as of December 31, 2022 |  |  | 11,606 |  |  |  | 986,594 |  |  |  | 814,951 |  |  |  | 345,567 |  |  |  | (161,307 | ) |  |  | (397,540 | ) |  |  | 1,599,871 |  |  |  | 189,176 |  |  |  | 1,789,047 |

Notes 1 to 25 are an integral part of the Consolidated Financial Statements
F-9

Table of Contents

|  | 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, 2023 |  |  | 11,606 |  |  |  | 986,594 |  |  |  | 814,951 |  |  |  | 345,567 |  |  |  | (161,307 | ) |  |  | (397,540 | ) |  |  | 1,599,871 |  |  |  | 189,176 |  |  |  | 1,789,047 |
Profit/(Loss) for the year after taxes |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 43,380 |  |  |  | 43,380 |  |  |  | (6,932 | ) |  |  | 36,448 |
Change in fair value of cash flow hedges net of transfer to profit and loss statement |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (44,335 | ) |  |  | - |  |  |  | - |  |  |  | (44,335 | ) |  |  | (5,217 | ) |  |  | (49,552 | )
Currency translation differences |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 21,873 |  |  |  | - |  |  |  | 21,873 |  |  |  | 2,711 |  |  |  | 24,584 |
Tax effect |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 6,770 |  |  |  | - |  |  |  | - |  |  |  | 6,770 |  |  |  | 1,267 |  |  |  | 8,037 |
Other comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (37,565 | ) |  |  | 21,873 |  |  |  | - |  |  |  | (15,692 | ) |  |  | (1,239 | ) |  |  | (16,931 | )
Total comprehensive income |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (37,565 | ) |  |  | 21,873 |  |  |  | 43,380 |  |  |  | 27,688 |  |  |  | (8,171 | ) |  |  | 19,517 |
Divestments (Note 7) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  |  |  |  |  | (2,817 | ) |  |  | (2,817 | )
Reduction of share premium (Note 14) |  |  | - |  |  |  | (250,000 | ) |  |  | 250,000 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Share-based compensation (Note 14) |  |  |  |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 2,639 |  |  |  | 2,639 |  |  |  | - |  |  |  | 2,639 |
Capital contribution (Note 14) |  |  | 10 |  |  |  | - |  |  |  | 25 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 35 |  |  |  | 19,467 |  |  |  | 19,502 |
Distributions (Note 14) |  |  | - |  |  |  | - |  |  |  | (206,756 | ) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (206,756 | ) |  |  | (32,323 | ) |  |  | (239,079 | )
Balance as of December 31, 2023 |  |  | 11,616 |  |  |  | 736,594 |  |  |  | 858,220 |  |  |  | 308,002 |  |  |  | (139,434 | ) |  |  | (351,521 | ) |  |  | 1,423,477 |  |  |  | 165,332 |  |  |  | 1,588,809 |

Notes 1 to 25 are an integral part of the Consolidated Financial Statements
F-10

Table of Contents
Consolidated cash flow statements for the years ended December 31, 2023, 2022 and 2021
Amounts in thousands of U.S. dollars

|  |  |  |  | For the year |
|  | Note (1) |  |  | 2023 |  |  | 2022 |  |  | 2021 |
I. Profit/(loss) for the year |  |  |  |  |  | 36,448 |  |  |  | (2,087 | ) |  |  | (10,918 | )
Non-monetary adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Depreciation, amortization and impairment charges |  |  | 6 |  |  |  | 418,271 |  |  |  | 473,638 |  |  |  | 439,441 |
Financial expense |  |  | 23 |  |  |  | 319,286 |  |  |  | 335,546 |  |  |  | 359,550 |
Fair value gains on derivative financial instruments |  |  | 23 |  |  |  | (1,869 | ) |  |  | (19,138 | ) |  |  | (16,785 | )
Shares of profits from entities carried under the equity method |  |  | 7 |  |  |  | (13,207 | ) |  |  | (21,465 | ) |  |  | (12,304 | )
Income tax |  |  | 19 |  |  |  | 790 |  |  |  | (9,689 | ) |  |  | 36,220 |
Other non-monetary items |  |  |  |  |  |  | (3,119 | ) |  |  | 27,996 |  |  |  | 55,809 |
II. Profit/(loss) for the year adjusted by non-monetary items |  |  |  |  |  |  | 756,600 |  |  |  | 784,801 |  |  |  | 851,013 |
Changes in working capital |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Inventories |  |  |  |  |  |  | (6,285 | ) |  |  | (6,955 | ) |  |  | 5,215 |
Trade and other receivables |  |  | 12 |  |  |  | (107,201 | ) |  |  | 99,249 |  |  |  | 48,521 |
Trade payables and other current liabilities |  |  | 18 |  |  |  | (415 | ) |  |  | (6,158 | ) |  |  | (25,782 | )
Other current assets/liabilities |  |  |  |  |  |  | 18,057 |  |  |  | (7,331 | ) |  |  | (31,081 | )
III. Changes in working capital |  |  |  |  |  |  | (95,844 | ) |  |  | 78,805 |  |  |  | (3,127 | )
Income tax paid |  |  |  |  |  |  | (26,020 | ) |  |  | (14,730 | ) |  |  | (51,684 | )
Interest received |  |  |  |  |  |  | 21,668 |  |  |  | 9,178 |  |  |  | 2,519 |
Interest paid |  |  |  |  |  |  | (268,356 | ) |  |  | (271,732 | ) |  |  | (293,098 | )
A. Net cash provided by operating activities |  |  |  |  |  |  | 388,048 |  |  |  | 586,322 |  |  |  | 505,623 |
Business combinations and investments in entities under the equity method |  |  | 5&7 |  |  |  | (29,259 | ) |  |  | (50,507 | ) |  |  | (362,449 | )
Investments in operating concessional assets |  |  | 6 |  |  |  | (27,929 | ) |  |  | (39,107 | ) |  |  | (19,216 | )
Investments in assets under development or construction |  |  | 6 |  |  |  | (56,280 | ) |  |  | (36,784 | ) |  |  | (7,028 | )
Distributions from entities under the equity method |  |  | 7 |  |  |  | 34,329 |  |  |  | 67,695 |  |  |  | 34,883 |
Net divestment in other non-current financial assets |  |  |  |  |  |  | 27,505 |  |  |  | 1,265 |  |  |  | 2,655 |
B. Net cash used in investing activities |  |  |  |  |  |  | (51,634 | ) |  |  | (57,438 | ) |  |  | (351,155 | )
Proceeds from project debt |  |  | 16 |  |  |  | 213,232 |  |  |  | - |  |  |  | 14,560 |
Proceeds from corporate debt |  |  | 15 |  |  |  | 161,498 |  |  |  | 101,140 |  |  |  | 429,014 |
Repayment of project debt |  |  | 16 |  |  |  | (531,837 | ) |  |  | (426,396 | ) |  |  | (418,265 | )
Repayment of corporate debt |  |  | 15 |  |  |  | (115,891 | ) |  |  | (80,519 | ) |  |  | (376,154 | )
Dividends paid to Company´s shareholders |  |  | 14 |  |  |  | (206,755 | ) |  |  | (203,106 | ) |  |  | (190,638 | )
Dividends paid to non-controlling interest |  |  | 14 |  |  |  | (31,433 | ) |  |  | (39,209 | ) |  |  | (28,134 | )
Non-controlling interest capital contribution |  |  | 14 |  |  |  | 19,823 |  |  |  | - |  |  |  | - |
Capital contribution |  |  | 14 |  |  |  | - |  |  |  | 113,072 |  |  |  | 189,454 |
C. Net cash used in financing activities |  |  |  |  |  |  | (491,363 | ) |  |  | (535,018 | ) |  |  | (380,163 | )
Net decrease in cash and cash equivalents |  |  |  |  |  |  | (154,949 | ) |  |  | (6,134 | ) |  |  | (225,695 | )
Cash and cash equivalents at beginning of the year |  |  | 13 |  |  |  | 600,990 |  |  |  | 622,689 |  |  |  | 868,501 |
Translation differences in cash and cash equivalents |  |  |  |  |  |  | 2,260 |  |  |  | (15,565 | ) |  |  | (20,117 | )
Cash and cash equivalents at the end of the year |  |  | 13 |  |  |  | 448,301 |  |  |  | 600,990 |  |  |  | 622,689 |

(1) | Notes 1 to 25 are an integral part of the Consolidated Financial Statements. Reference to such notes is indicated here to provide with additional information on the nature of some of the lines of the Consolidated cash flow statement.

F-11

Table of Contents
Contents

Note 1.- Nature of the business | F-13
Note 2.- Significant accounting policies | F-16
Note 3.- Financial risk management | F-27
Note 4.- Financial information by segment | F-28
Note 5.- Business combinations | F-33
Note 6.- Contracted concessional, PP&E and other intangible assets | F-34
Note 7.- Investments carried under the equity method | F-36
Note 8.- Assets held for sale | F-38
Note 9.- Financial instruments by category | F-38
Note 10.- Derivative financial instruments | F-39
Note 11.- Related parties | F-41
Note 12.- Trade and other receivables | F-42
Note 13.- Cash and cash equivalents | F-42
Note 14.- Equity | F-43
Note 15.- Corporate debt | F-44
Note 16.- Project debt | F-46
Note 17.- Grants and other liabilities | F-49
Note 18.-Trade payables and other current liabilities | F-50
Note 19.- Income tax | F-50
Note 20.- Commitments, third-party guarantees, contingent assets and liabilities | F-53
Note 21.- Employee benefit expenses | F-54
Note 22.- Other operating income and expenses | F-54
Note 23.- Financial expense, net | F-54
Note 24.- Earnings per share | F-55
Note 25.- Other information | F-56
Appendices(1) | F-57

(1) The Appendices are an integral part of the notes to the Consolidated Financial Statements
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Note 1.- Nature of the business
Atlantica Sustainable Infrastructure plc (“Atlantica” or the “Company”) is a sustainable infrastructure company with a majority of its business in renewable energy assets. Atlantica currently owns, manages and invests in renewable energy, storage, efficient natural gas and heat, electric transmission lines and water assets focused on North America (the United States, Canada and Mexico), South America (Peru, Chile, Colombia and Uruguay) and EMEA (Spain, Italy, Algeria and South Africa). Its registered address is Great West House, GW1 Great West Road Brentford TW8 9DF, London (United Kingdom).
Atlantica’s shares trade on the NASDAQ Global Select Market under the symbol “AY”.
In March 2023, the Company completed the process of transitioning O&M services for the assets in Spain where Abengoa was still the supplier to an Atlantica’ subsidiary (Note 5). Currently, Atlantica performs the O&M services with its own personnel for assets representing approximately 74% of the consolidated revenue for the year ended December 31, 2023.
The following four assets that the Company had under construction during 2022, finished construction and reached Commercial Operation Date (“COD”) in 2023:

- | Albisu, a 10 MW solar PV asset wholly owned by the Company. Albisu is located in the city of Salto (Uruguay). The asset has a 15-year PPA with Montevideo Refrescos, S.R.L, a subsidiary of Coca-Cola Femsa., S.A.B. de C.V. The PPA is denominated in local currency with a maximum and minimum price in U.S. dollars and is adjusted monthly based on a formula referring to U.S. Producer Price Index (PPI), Uruguay’s Consumer Price Index (CPI) and the applicable UYU/U.S. dollar exchange rate.

- | La Tolua and Tierra Linda, two wholly owned solar PV assets in Colombia with a combined capacity of 30 MW, both of which reached COD in the first quarter of 2023. Each plant has a 10-year PPA in local currency indexed to local inflation with Coenersa, the largest independent electricity wholesaler in Colombia. Each PPA provides for the sale of electricity at fixed base price indexed to local CPI.

- | Honda 1, a 10 MW solar PV asset in Colombia where the Company has a 50% ownership, and which reached COD in December 2023. The asset has a 7-year PPA with Enel Colombia, a major electricity company in the country. The PPA is denominated in local currency, with fixed base price, indexed to the local CPI.

During the year 2022, the Company completed the following investments:

- | On January 17, 2022, the Company closed the acquisition of Chile TL4, a 63-mile transmission line and 2 substations in Chile for a total equity investment of $38.4 million (Note 5). The Company expects to expand the transmission line in 2024, which would represent an additional investment of approximately $8 million. The asset has fully contracted revenues in U.S dollars, with inflation escalation and a 50-year remaining contract life. The off-takers are several mini-hydro plants that receive contracted or regulated payments.

- | On April 4, 2022, the Company closed the acquisition of Italy PV 4, a 3.6 MW solar portfolio in Italy for a total equity investment of $3.7 million (Note 5). The asset has regulated revenues under a feed in tariff until 2031.

- | On September 2, 2022, the Company completed its third investment through its Chilean renewable energy platform in a 73 MW solar PV plant, Chile PV 3, located in Chile, for $7.7 million corresponding to a 35% of equity interest (Note 5). The Company expects to install batteries with a capacity of approximately 100 MWh in 2024. Total investment including batteries is expected to be in the range of $15 million to $25 million depending on the capital structure. Part of the asset’s revenue is currently based on capacity payments. Adding storage would increase the portion of capacity payments.

- | On November 16, 2022, the Company closed the acquisition of a 49% interest, with joint control, in an 80 MW portfolio of solar PV projects in Chile, Chile PMGD, which is currently under construction. Atlantica´s economic rights are expected to be approximately 70%. Total investment in equity and preferred equity is expected to be approximately $30 million and COD is expected to be progressive in 2024. Revenue for these assets is regulated under the Small Distributed Generation Means Regulation Regime (“PMGD”) for projects with a capacity equal or lower than 9MW, which allows to sell electricity through a stabilized price.

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The following table provides an overview of the main operating assets the Company owned or had an interest in as of December 31, 2023:

Assets | Type | Ownership | Location | Currency(9) | Capacity (Gross) | Counterparty Credit Ratings(10) | COD* | Contract Years Remaining(17)
Solana | Renewable (Solar) | 100% | Arizona (USA) | USD | 280 MW | BBB+/A3/BBB+ | 2013 | 20
Mojave | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB/ Ba1/BB+ | 2014 | 16
Coso | Renewable (Geothermal) | 100% | California (USA) | USD | 135 MW | Investment Grade(11) | 1987-1989 | 18
Elkhorn Valley(16) | Renewable (Wind) | 49% | Oregon (USA) | USD | 101 MW | BBB/Baa1/-- | 2007 | 4
Prairie Star(16) | Renewable (Wind) | 49% | Minnesota (USA) | USD | 101 MW | --/A3/A- | 2007 | 4
Twin Groves II(16) | Renewable (Wind) | 49% | Illinois (USA) | USD | 198 MW | BB+/Baa2/-- | 2008 | 2
Lone Star II(16) | Renewable (Wind) | 49% | Texas (USA) | USD | 196 MW | N/A | 2008 | N/A
Chile PV 1 | Renewable (Solar) | 35%(1) | Chile | USD | 55 MW | N/A | 2016 | N/A
Chile PV 2 | Renewable (Solar) | 35%(1) | Chile | USD | 40 MW | Not rated | 2017 | 7
Chile PV 3 | Renewable (Solar) | 35%(1) | Chile | USD | 73 MW | N/A | 2014 | N/A
La Sierpe | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2021 | 12
La Tolua | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2023 | 9
Tierra Linda | Renewable (Solar) | 100% | Colombia | COP | 10 MW | Not rated | 2023 | 9
Honda 1 | Renewable (Solar) | 50% | Colombia | COP | 10 MW | BBB-/-/BBB | 2023 | 7
Albisu | Renewable (Solar) | 100% | Uruguay | UYU | 10 MW | Not rated | 2023 | 15
Palmatir | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2014 | 10
Cadonal | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2014 | 11
Melowind | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2015 | 12
Mini-Hydro | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB/Baa1/BBB | 2012 | 9
Solaben 2 & 3 | Renewable (Solar) | 70%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 14/14
Solacor 1 & 2 | Renewable (Solar) | 87%(3) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 13/13
PS10 & PS20 | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007&2009 | 8/10
Helioenergy 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 13/13
Helios 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 13/14
Solnova 1, 3 & 4 | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 11/11/12
Solaben 1 & 6 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 15/15
Seville PV | Renewable (Solar) | 80%(4) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 12
Italy PV 1 | Renewable (Solar) | 100% | Italy | Euro | 1.6 MW | BBB/Baa3/BBB | 2010 | 8
Italy PV 2 | Renewable (Solar) | 100% | Italy | Euro | 2.1 MW | BBB/Baa3/BBB | 2011 | 8
Italy PV 3 | Renewable (Solar) | 100% | Italy | Euro | 2.5 MW | BBB/Baa3/BBB | 2012 | 8
Italy PV 4 | Renewable (Solar) | 100% | Italy | Euro | 3.6 MW | BBB/Baa3/BBB | 2011 | 8
Kaxu | Renewable (Solar) | 51%(5) | South Africa | Rand | 100 MW | BB-/Ba2/BB-(13) | 2015 | 11
Calgary | Efficient natural gas &heat | 100% | Canada | CAD | 55 MWt | ~60% AA- or higher(14) | 2010 | 12
ACT | Efficient natural gas & heat | 100% | Mexico | USD | 300 MW | BBB/B3/B+ | 2013 | 9
Monterrey (18) | Efficient natural gas &heat | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 22
ATN (15) | Transmission line | 100% | Peru | USD | 379 miles | BBB/Baa1/BBB | 2011 | 17
ATS | Transmission line | 100% | Peru | USD | 569 miles | BBB/Baa1/BBB | 2014 | 20
ATN 2 | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 9
Quadra 1 & 2 | Transmission line | 100% | Chile | USD | 49 miles/32 miles | Not rated | 2014 | 11/11
Palmucho | Transmission line | 100% | Chile | USD | 6 miles | BBB/ -- /BBB+ | 2007 | 14
Chile TL3 | Transmission line | 100% | Chile | USD | 50 miles | A/A2/A- | 1993 | N/A
Chile TL4 | Transmission line | 100% | Chile | USD | 63 miles | Not rated | 2016 | 48
Skikda | Water | 34.20%(6) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 10
Honaine | Water | 25.50%(7) | Algeria | USD | 7 M ft3/day | Not rated | 2012 | 14
Tenes | Water | 51%(8) | Algeria | USD | 7 M ft3/day | Not rated | 2015 | 16

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(1) | 65% of the shares in Chile PV 1, Chile PV 2 and Chile PV 3 are indirectly held by financial partners through the renewable energy platform of the Company in Chile.

(2) | Itochu Corporation holds 30% of the shares in each of Solaben 2 and Solaben 3.

(3) | JGC holds 13% of the shares in each of Solacor 1 and Solacor 2.

(4) | Instituto para la Diversificación y Ahorro de la Energía (“Idae”) holds 20% of the shares in Seville PV.

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

(6) | Algerian Energy Company, SPA owns 49% of Skikda and Sacyr Agua, S.L. owns the remaining 16.8%.

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

(8) | Algerian Energy Company, SPA owns 49% of Tenes. The Company has an investment in Tenes through a secured loan to Befesa Agua Tenes (the holding company of Tenes) and the right to appoint a majority at the board of directors of the project company. Therefore, the Company controls Tenes since May 31, 2020, and fully consolidates the asset from that date.

(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. Not applicable (“N/A”) when the asset has no PPA.

(11) | 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.

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

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

(14) | Refers to the credit rating of a diversified mix of 22 high credit quality clients (~60% AA- rating or higher, the rest is unrated).

(15) | Including ATN Expansion 1 & 2.

(16) | Part of Vento II Portfolio.

(17) | As of December 31, 2023.

(18) | Accounted for as held for sale as of December 31, 2023.

(*) | Commercial Operation Date.

Additionally, Atlantica currently has the following assets under construction or ready to start construction in the short term:

Asset | Type | Location | Capacity (gross)1 | Expected COD | Expected Investment 2 ($ million) | Off-taker
Coso Batteries 1 | Battery Storage | California, US | 100 MWh | 2025 | 40-50 | Investment grade utility
Coso Batteries 2 | Battery Storage | California, US | 80 MWh | 2025 | 35-45 | Investment grade utility
Chile PMGD | Solar PV | Chile | 80 MW | 2024-2025 | 30 | Regulated
ATN Expansion 3 | Transmission Line | Peru | 2.4miles 220kV | 2024 | 12 | Conelsur
ATS Expansion 1 | Transmission Line | Peru | n.a. (substation) | 2025 | 30 | Republic of Peru
Honda 2(3) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | Enel Colombia
Apulo 1(3) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | -

(1) | Includes nominal capacity on a 100% basis, not considering Atlantica’s ownership

(2) | Corresponds to the expected investment by Atlantica

(3) | Atlantica owns 50% of the shares in Honda 2 and Apulo 1.

In October 2023, the Company entered into two 15-year tolling agreements (PPAs) with an investment grade utility for Coso Batteries 1 and Coso Batteries 2. Under each of the tolling agreements, Coso Batteries 1 and 2 will receive fixed monthly payments adjusted by the financial settlement of CAISO’s ( California Independent System Operator) Day-Ahead market. In addition, the Company expects to obtain revenue from ancillary services in each of the assets.
Coso Batteries 1 is a standalone battery storage project of 100 MWh (4 hours) capacity, located inside Coso, its geothermal asset in California. Additionally, Coso Batteries 2 is a standalone battery storage project with 80 MWh (4 hours) capacity also located inside Coso. The investment is expected to be in the range of $40 million to $50 million for Coso Batteries 1, and in the range of $35 to $45 million for Coso Batteries 2. Both projects were fully developed in-house and are now under construction. Atlantica has closed a contract with Tesla for the procurement of the batteries. COD is expected in 2025 for both projects.
In July 2022 the Company closed a 17-year transmission service agreement denominated in U.S. dollars that allows to build a substation and a 2.4-miles transmission line connected to ATN transmission line serving a new mine in Peru (ATN Expansion 3). The substation is expected to enter in operation in 2024 and the investment is expected to be approximately $12 million.
In July 2023, as part of the New Transmission Plan Update in Peru, the Ministry of Energy and Mines published the Ministerial Resolution that enables to start construction of ATS Expansion 1 project, consisting in the reinforcement of two existing substations with new equipment. The expansion will be part of the existing concession contract, a 30-year contract with a fixed-price tariff base denominated in U.S. dollars adjusted annually in accordance with the U.S. Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor. Given that the concession ends in 2044, Atlantica will be compensated with a one-time payment for the remaining 9 years of concession. The expansion is expected to enter in operation in 2025 and the investment is expected to be approximately $30 million.
In May 2022, the Company agreed to develop and construct Honda 1 and 2, two PV assets in Colombia with a combined capacity of 20 MW, where it has a 50% ownership. Each plant has a 7-year PPA with Enel Colombia. Honda 1, as it is stated above, reached COD in December 2023. Honda 2 is expected to enter into operation in the second quarter of 2024. The investment is expected to be $5.5 million for each plant.
Chile PV 1 and PV 2 events of default
Due to low electricity prices in Chile, the project debts of Chile PV 1 and PV2, where the Company owns a 35% equity interest, are under an event of default as of December 31, 2023. Chile PV 1 was not able to maintain the minimum required cash in its debt service reserve account as of December 31, 2023 and did not make its debt service payment in January 2024. In addition, in October 2023, Chile PV 2 did not make its debt service payment. This asset obtained additional financing from the banks and made the debt service payment in December 2023, although it was not able to fund its debts service reserve account. As a result, although the Company does not expect an acceleration of the debts to be declared by the credit entities, Chile PV 1 and Chile PV2, did not have an unconditional right to defer the settlement of the debts for at least twelve months and the project debts, which amount to $71 million as of December 31, 2023 (Note 16), were classified as current in these Consolidated Financial Statements in accordance with International Accounting Standards 1 (“IAS 1”), “Presentation of Financial Statements”. The Company is, together with the partner, in conversations with the banks regarding a potential waiver.
The Consolidated Financial Statements were approved by the Board of Directors of the Company on February 29, 2024.
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Note 2.- Significant accounting policies
2.1 Basis of preparation
These Consolidated Financial Statements are presented in accordance with the International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
The Consolidated Financial Statements are presented in U.S. dollars, which is the Company’s functional and presentation currency. Amounts included in these Consolidated Financial Statements are all expressed in thousands of U.S. dollars, unless otherwise indicated.
The Company presents assets and liabilities in the statement of financial position based on current/non-current classification. An asset or liability is current when it is expected or due to be realized within twelve months after the reporting period.
The Company recognizes that there may be potential financial implications in the future from changes in legislation and regulation implemented to address climate change risk. Over time these changes may have an impact across a number of areas of accounting. However, as at the reporting sheet date, the Company believes there is no material impact on the balance sheet carrying values of assets or liabilities.
Application of new accounting standards

a) | Standards, interpretations and amendments effective from January 1, 2023 under IFRS-IASB, applied by the Company in the preparation of these Consolidated Financial Statements:

The applications of these amendments have not had any material impact on these Consolidated Financial Statements.
In addition, the IASB published in May 2023 an amendment to IAS 12, “Income taxes”, to clarify the application of this standard arising from tax legislation enacted or substantively enacted in each country to implement the Pillar Two model rules in which it provides:

- | a temporary exception to the accounting for deferred taxes in connection with the implementation of Pillar Two.

- | qualitative and quantitative disclosures to enable users to understand the entities’ exposure to taxes that may arise from the Pillar Two model rules and/or the entity’s progress in its implementation.

Global minimum taxation (Pillar Two OECD/G20 BEPS 2.0 top-up taxes as agreed by the Inclusive Framework) legislation has been enacted or substantially enacted in certain jurisdictions in which the Atlantica operates. The new legislation will be effective for the Company´s financial years beginning January 1, 2024. Atlantica is in scope of the enacted or substantially enacted legislation and has performed an assessment of the Company´s potential exposure to Pillar Two top-up taxes.
The assessment is based on the country-by-country reporting and financial statements for the constituent entities of Atlantica. Based on the assessment performed, the Pillar Two effective tax rates in most of the jurisdictions in which Atlantica operates are above 15% and in all of them meet the requirements to apply the relevant transitional safe harbors, with the exception of one jurisdiction, whose impact is not material. Therefore, Atlantica does not expect a material exposure to Pillar Two income taxes for accounting periods commencing on or after December 31, 2023.
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b) | Standards, interpretations and amendments published by the IASB that will be effective for periods beginning on or after January 1, 2024:

The Company does not anticipate any significant impact on the Consolidated Financial Statements derived from the application of the new standards and amendments that will be effective for annual periods beginning on or after January 1, 2024, although it is currently still in the process of evaluating such application.
The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.
2.2. Principles to include and record companies in the consolidated financial statements
Companies included in these Consolidated Financial Statements are accounted for as subsidiaries as long as Atlantica has control over them and are accounted for as investments under the equity method as long as Atlantica has significant influence over them, in the periods presented.

a) | Controlled entities

Control is achieved when the Company:

| ● | Has power over the investee;

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

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

The Company reassesses whether or not it controls an investee when facts and circumstances indicate that there are changes to one or more of the three elements of control listed above.
The Company uses the acquisition method to account for business combinations of companies previously 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. The Company recognizes any non-controlling interest in the acquiree either at fair value or at the non-controlling interest’s proportionate share of the acquirer’s net assets on an acquisition by acquisition basis.
All assets and liabilities between entities of the group, equity, income, expenses, and cash flows relating to transactions between entities of the group are eliminated in full.

b) | Investments accounted for under the equity method

An associate is an entity over which the Company has significant influence. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.
A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint venture. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
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The results and assets and liabilities of associates and joint ventures are incorporated in these financial statements using the equity method of accounting. Under the equity method, an investment in an associate or joint venture is initially recognized in the statement of financial position at fair value and adjusted thereafter to recognize changes in Atlantica´s share of net assets of the associate or joint venture since the acquisition date. Any goodwill relating to the associate or joint venture is included in the carrying amount of the investment and is not tested for impairment separately.
Controlled entities, associates and joint ventures included in these financial statements as of December 31, 2023 and 2022 are set out in appendices.
2.3. Contracted concessional, Property, Plant and Equipment (PP&E) and other intangible assets
The assets accounted for by the Company as contracted concessional assets under IFRIC 12 (either intangible model or financial model), as PP&E under IAS 16 or as other intangible assets under IAS 38 or under IFRS 16 (as “Lessee” or “Lessor”), include renewable energy assets, storage assets, transmission lines, efficient natural gas and heat assets and water plants.

| a) | Contracted concessional assets under IFRIC 12

The infrastructure used in a concession accounted for under IFRIC 12 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.
Under the terms of contractual arrangements within the scope of this interpretation, the operator shall recognize and measure revenue in accordance IFRS 15 for the services it performs. If the operator performs more than one service (i.e. construction or upgrade services and operation services) under a single contract or arrangement, consideration received or receivable shall be allocated by reference to the relative fair values of the services delivered, when the amounts are separately identifiable.
Consequently, even though construction is subcontracted and it is not performed by Atlantica, in accordance with the provisions of IFRIC 12, the Company recognizes and measures revenue and costs for providing construction services during the period of construction of the infrastructure in accordance with IFRS 15. Construction revenue is recorded within “Other operating income” and Construction cost, which is fully contracted, is recorded within “Other operating expenses”. This applies in the same way to the two models.
The useful life of these assets is approximately the same as the length of the concession arrangement.
Intangible assets
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 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.

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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 return rate 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 (financial assets)
According to IFRS 9, Atlantica recognizes an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Company expects to receive.
There are two main approaches to applying the ECL model according to IFRS 9: the general approach which involves a three stage approach, and the simplified approach, which can be applied to trade receivables, contract assets and lease receivables. Atlantica applies the simplified approach. Under this approach, there is no need to monitor for significant increases in credit risk and entities will be required to measure lifetime expected credit losses at the end of each reporting period.
The key elements of the ECL calculations, based on external sources of information, are the following:

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

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

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

| b) | Property, plant and equipment under IAS 16

Property, plant and equipment is measured at historical cost, including all expenses directly attributable to the acquisition, less depreciation and impairment losses, with the exception of land, which is presented net of any impairment losses. Such cost includes the cost of replacing part of the plant and equipment and borrowing costs for long-term installation projects if the recognition criteria are met. Repair and maintenance costs are recognized in profit or loss as incurred.
Depreciation is calculated on a straight-line basis over the estimated useful lives of the assets.
The Company reviews the estimated residual values and expected useful lives of assets at least annually. In particular, the Company considers the impact of health, safety and environmental legislation in its assessment of expected useful lives and estimated residual values.
An item of property, plant and equipment and any significant part initially recognized is derecognized upon disposal (i.e., at the date the recipient obtains control) or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss when the asset is derecognized.

| c) | Rights of use under IFRS 16

The Company assesses at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.
Company as a lessee:
The Company applies a single recognition and measurement approach for all leases, except for short-term leases and leases of low-value assets. The Company recognizes lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets.
Main right of use agreements correspond 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 (Note 2.12). The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets.

| d) | Other intangible assets

Other intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and accumulated impairment losses. Intangible assets are amortized using the straight-line method over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired.
An intangible asset is derecognised upon disposal (i.e., at the date the recipient obtains control) or when no future economic benefits are expected from its use or disposal. Any gain or loss arising upon derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss.
Research and development costs:
Research costs are expensed as incurred. Development expenditures on an individual project are recognised as an intangible asset when the Company can demonstrate:

- | the technical feasibility of completing the intangible asset so that the asset will be available for use or sale

- | its intention to complete and its ability and intention to use or sell the asset

- | how the asset will generate future economic benefits

- | the availability of resources to complete the asset

- | the ability to measure reliably the expenditure during development.

Following initial recognition of the development expenditure as an asset, the asset is carried at cost less any accumulated amortization and accumulated impairment losses. Amortization of the asset begins when development is complete, and the asset is available for use. It is amortized using the straight-line method over the period of expected future benefit. During the period of development, the asset is tested for impairment annually.
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| e) | Asset impairment

Atlantica reviews its contracted concessional, PP&E and other intangible assets to identify any indicators of impairment at least annually, except for ECL assessment for financial assets which is discussed above. When impairment indicators exist, the Company calculates the recoverable amount of the asset.
The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, the Company calculates the recoverable amount of the Cash Generating Unit (‘CGU’) to which the asset belongs.
When the carrying amount of the CGU to which these assets belong is higher than its recoverable amount, the assets are impaired.
Assumptions used to calculate value in use include a discount rate and projections considering real data based in the contracts terms and projected changes in both selling prices and costs. The discount rate is estimated by Management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.
For contracted concessional assets, with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no relevant terminal value is assumed.
Contracted concessional assets have a contractual structure that permits the Company to estimate quite accurately the costs of the project and revenue during the life of the project.
Projections take into account real data based on the contract terms and fundamental assumptions based on specific reports prepared internally and third-party reports, assumptions on demand and assumptions on production. Additionally, assumptions on macro-economic conditions are taken into account, such as inflation rates, future interest rates, etc. and sensitivity analyses are performed over all major assumptions which can have a significant impact in the value of the asset.
Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.
Taking into account that in most CGUs the specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash-flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is located.
In any case, sensitivity analyses are performed, especially in relation to 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 profit and loss 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 profit and loss statement.
2.4. Revenue recognition
According to IFRS 15, Revenue from Contracts with Customers, the Company assesses the goods and services promised in the contracts with the customers and identifies as a performance obligation 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 Appendix III-2.
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 rate of return 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 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 return on investment (project investment rate of return). Some of the Company´s assets in Spain 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.
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2.5. Loans and accounts receivable
Loans and accounts receivable are non-derivative financial assets with fixed or determinable payments, not listed on an active market.
In accordance with IFRIC 12, certain assets under concessions qualify as financial assets and are recorded as is described in Note 2.3. Pursuant to IFRS 9, Atlantica recognizes an allowance for ECL for loans and accounts receivable which 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.
Loans and accounts receivable are initially recognized at fair value plus transaction costs and are subsequently measured at amortized cost in accordance with the effective interest rate method. Interest calculated using the effective interest rate method is recognized as financial income within the consolidated statement of profit or loss.
2.6. Derivative financial instruments and hedging activities
Derivatives are recognized at fair value in the statement of financial position. The Company maintains both derivatives designated as hedging instruments in hedging relationships, and derivatives to which hedge accounting is not applied.
When hedge accounting is applied, hedging strategy and risk management objectives are documented at inception, as well as the relationship between hedging instruments and hedged items. Effectiveness of the hedging relationship needs to be assessed on an ongoing basis. Effectiveness tests are performed prospectively at inception and at each reporting date. The Company analyses on each date if all these requirements are met:

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

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

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

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

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

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

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

In the event that prices cannot be observed, management shall make its best estimate of the price that the market would otherwise establish based on proprietary internal models which, in the majority of cases, use data based on observable market parameters as significant inputs (Level 2) but occasionally use market data that is not observed as significant inputs (Level 3). Different techniques can be used to make this estimate, including extrapolation of observable market data. The best indication of the initial fair value of a financial instrument is the price of the transaction, except when the value of the instrument can be obtained from other transactions carried out in the market with the same or similar instruments, or valued using a valuation technique in which the variables used only include observable market data, mainly interest rates. Differences between the transaction price and the fair value based on valuation techniques that use data that is not observed in the market, are not initially recognized in the profit and loss statement.
Atlantica derivatives correspond primarily to the interest rate swaps designated as cash flow hedges, which are classified as Level 2.
Description of the valuation method
Interest rate swap valuations consist in valuing separately the swap part of the contract and the credit risk. The methodology used by the market and applied by Atlantica to value interest rate swaps is to discount the expected future cash flows according to the parameters of the contract. Variable interest rates, which are needed to estimate future cash flows, are calculated using the curve for the corresponding currency and extracting the implicit rates for each of the reference dates in the contract. These estimated flows are discounted with the swap zero curve for the reference period of the contract.
The effect of the credit risk on the valuation of the interest rate swaps depends on the future settlement. If the settlement is favorable for the Company, the counterparty credit spread will be incorporated to quantify the probability of default at maturity. If the expected settlement is negative for the Company, its own credit risk will be applied to the final settlement.
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Classic models for valuing interest rate swaps use deterministic valuation of the future of variable rates, based on future outlooks. When quantifying credit risk, this model is limited by considering only the risk for the current paying party, ignoring the fact that the derivative could change sign at maturity. A payer and receiver swaption model is proposed for these cases. This enables the associated risk in each swap position to be reflected. Thus, the model shows each agent’s exposure, on each payment date, as the value of entering into the ‘tail’ of the swap, i.e. the live part of the swap.
Variables (Inputs)
Interest rate derivative valuation models use the corresponding interest rate curves for the relevant currency and underlying reference in order to estimate the future cash flows and to discount them. Market prices for deposits, futures contracts and interest rate swaps are used to construct these curves. Interest rate options (caps and floors) also use the volatility of the reference interest rate curve.
To estimate the credit risk of the counterparty, the credit default swap (CDS) spreads curve is obtained in the market for important individual issuers. For less liquid issuers, the spreads curve is estimated using comparable CDSs or based on the country curve. To estimate proprietary credit risk, prices of debt issues in the market and CDSs for the sector and geographic location are used.
The fair value of the financial instruments that results from the aforementioned internal models takes into account, among other factors, the terms and conditions of the contracts and observable market data, such as interest rates, credit risk and volatility. The valuation models do not include significant levels of subjectivity, since these methodologies can be adjusted and calibrated, as appropriate, using the internal calculation of fair value and subsequently compared to the corresponding actively traded price. However, valuation adjustments may be necessary when the listed market prices are not available for comparison purposes.
2.8. Trade and other receivables
Trade and other receivables are amounts due from customers for sales in the normal course of business. They are recognized initially at fair value and subsequently measured at amortized cost using the effective interest rate method, less allowance for doubtful accounts. Trade receivables due in less than one year are carried at their face value at both initial recognition and subsequent measurement, provided that the effect of not discounting cash flows is not significant.
An allowance for doubtful accounts is recorded in accordance with IFRS 9, when the Company estimates it will not be able to recover all amounts due as per the original terms of the receivables.
2.9. Cash and cash equivalents
Cash and cash equivalents include cash in hand, cash in bank and other highly-liquid current investments with an original maturity of three months or less which are held for the purpose of meeting short-term cash commitments.
2.10. Assets held for sale
The Company classifies non-current assets and disposal groups as held for sale if their carrying amounts will be recovered principally through a sale transaction rather than through continuing use. Non-current assets and disposal groups classified as held for sale are measured at the lower of their carrying amount and fair value less costs to sell. Costs to sell are the incremental costs directly attributable to the disposal of an asset (disposal group), excluding finance costs and income tax expense.
The criteria for held for sale classification is regarded as met only when the sale is highly probable, and the asset or disposal group is available for immediate sale in its present condition. Actions required to complete the sale should indicate that it is unlikely that significant changes to the sale will be made or that the decision to sell will be withdrawn. Management must be committed to the plan to sell the asset and the sale expected to be completed within one year from the date of the classification.
Property, plant and equipment and intangible assets are not depreciated or amortised once classified as held for sale.
Assets and liabilities classified as held for sale are presented separately as current items in the statement of financial position.
2.11. Grants
Grants are recognized at fair value when it is considered that there is a reasonable assurance that the grant will be received and that the necessary qualifying conditions, as agreed with the entity assigning the grant, will be adequately complied with.
Grants are recorded as liabilities in the consolidated statement of financial position and are recognized in “Other operating income” in the consolidated profit and loss statement based on the period necessary to match them with the costs they intend to compensate.
In addition, as described in Note 2.12 below, grants correspond also to loans with interest rates below market rates, for the initial difference between the fair value of the loan and the proceeds received.
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2.12. Loans and borrowings
Loans and borrowings are initially recognized at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortized cost and any difference between the proceeds initially received (net of transaction costs incurred in obtaining such proceeds) and the repayment value is recognized in the consolidated profit and loss statement over the duration of the borrowing using the effective interest rate method.
In the case of modification of terms of loans and borrowings, the Company determines whether the modification constitutes an exchange or an extinguishment of the debt instrument. In determining whether there is an exchange, the Company evaluates whether the redemption of the old debt and the issuance of new debt were negotiated in contemplation of one another (qualitative assessment) and performs the 10 per cent test to determine if the terms of the modified debt are substantially different (the net present value of the modified cash flows, including any fees paid to net of any fees received from the lenders, is higher than 10% different from the net present value of the remaining cash flows of the liability prior to the modification, both discounted at the original effective interest rate). When the terms of the modified liability are substantially different, the modification is accounted for as an extinguishment of the original liability and recognition of a new liability.
Loans with interest rates below market rates are initially recognized at fair value in liabilities and the difference between proceeds received from the loan and its fair value is initially recorded within “Grants and Other liabilities” in the consolidated statement of financial position, and subsequently recorded in “Other operating income” in the consolidated profit and loss statement when the costs financed with the loan are expensed.
Lease liabilities are recognized by the Company at the commencement date of the lease at the present value of lease payments to be made over the lease term. The lease payments include the exercise price of a purchase option reasonably certain to be exercised by the Company and payments of penalties for terminating the lease, if the lease term reflects the Company exercising the option to terminate. In calculating the present value of lease payments, the Company uses its incremental borrowing rate at the lease commencement date considering that the interest rate implicit in the lease is not readily determinable.
2.13. Bonds and notes
The Company initially recognizes ordinary notes at fair value, net of issuance costs incurred. Subsequently, notes are measured at amortized cost until settlement upon maturity. Any other difference between the proceeds obtained (net of transaction costs) and the redemption value is recognized in the consolidated profit and loss statement over the term of the debt using the effective interest rate method.
Convertible bonds or notes or debt issued with conversion features must be separated into liability and equity components if the feature meets the equity classification conditions in IAS 32. The issuer separates the instrument into its components by determining the fair value of the liability component and then deducting that amount from the fair value of the instrument as a whole; the residual amount is allocated to the equity component. If the equity conversion feature does not satisfy the equity classification conditions in IAS 32, it is bifurcated as an embedded derivative unless the issuer elects to apply the fair value option to the convertible debt. The embedded derivative is initially recognized at fair value and classified as derivatives in the statement of financial position. Changes in the fair value of the embedded derivatives are subsequently accounted for directly through the profit and loss statement. The debt element of the bond or note (the host contract), will be initially valued as the difference between the consideration received from the holders for the instrument and the value of the embedded derivative, and thereafter at amortized cost using the effective interest method.
2.14. Income taxes
Current income tax expense is calculated on the basis of the tax laws in force as of the date of the consolidated statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.
Deferred income tax is calculated in accordance with the liability method, based upon the temporary differences arising between the carrying amount of assets and liabilities and their tax base. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date.
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Deferred tax assets are recognized to the extent that it is probable that taxable profit will be available against which the deductible temporary differences, and the carry forward of unused tax credits and unused tax losses can be utilized.
2.15. Trade payables and other liabilities
Trade payables are obligations arising from purchases of goods and services in the ordinary course of business and are recognized initially at fair value and are subsequently measured at their amortized cost using the effective interest method. Other liabilities are obligations not arising in the normal course of business and which are not treated as financing transactions. Advances received from customers are recognized as “Trade payables and other current liabilities”.
2.16. Foreign currency transactions
The Consolidated Financial Statements are presented in U.S. dollars, which is Atlantica’s functional and presentation currency. Financial statements of each subsidiary within the Company are measured in the currency of the principal economic environment in which the subsidiary operates, which is the subsidiary’s functional currency.
Transactions denominated in a currency different from the entity’s functional currency are translated into the entity’s functional currency applying the exchange rates in force at the time of the transactions. Foreign currency gains and losses that result from the settlement of these transactions and the translation of monetary assets and liabilities denominated in foreign currency at the year-end rates are recognized in the consolidated profit and loss statement, unless they are deferred in equity, as occurs with cash flow hedges and net investment in foreign operations hedges.
Assets and liabilities of subsidiaries with a functional currency different from the Company’s reporting currency are translated to U.S. dollars at the exchange rate in force at the closing date of the financial statements. Income and expenses are translated into U.S. dollars using the average annual exchange rate, which does not differ significantly from using the exchange rates of the dates of each transaction. The difference between equity translated at the historical exchange rate and the net financial position that results from translating the assets and liabilities at the closing rate is recorded in equity under the heading “Accumulated currency translation differences”.
Results of companies carried under the equity method are translated at the average annual exchange rate.
2.17. Equity
The Company has recyclable balances in its equity, corresponding mainly to hedge reserves and translation differences arising from currency conversion in the preparation of these Consolidated Financial Statements. These balances have been presented separately in equity.
Ordinary shares are classified as equity. Any excess above the par value of shares received upon issuance of those shares is classified as share premium. Capital reserves is mainly the result of reductions of the share premium account which have increased distributable reserves.
Non-controlling interest represents interest of other partners in subsidiaries included in these Consolidated Financial Statements which are not fully owned by Atlantica as of the dates presented.
The costs of issuing equity instruments are accounted for as a deduction from equity.
2.18. Provisions and contingencies
Provisions are recognized when:

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

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

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

- | Impairment of contracted concessional, PP&E and other intangible assets.

Impairment exists when the carrying value of an asset or cash generating unit exceeds its recoverable amount, which is the higher of its fair value less costs of disposal and its value in use. The value in use calculation is based on a discounted cash flow model, which is sensitive to the discount rate used as well as projected cash-flows (Note 6).
The significant assumptions which required substantial estimates used in management’s impairment calculation are discount rates and projections considering real data based on contract terms and projected changes in selling prices, energy generation and costs.

- | Recoverability of deferred tax assets.

Deferred tax assets are recognised for unused tax losses to the extent that it is probable that taxable profit will be available against which the losses can be utilised. Significant management estimates are required to determine the amount of deferred tax assets that can be recognised, based upon the likely timing and the level of future taxable profits together with future tax planning strategies (Note 19).

- | Fair value of derivative financial instruments

When the fair values of financial assets and financial liabilities recorded in the statement of financial position cannot be measured based on quoted prices in active markets, their fair value is measured using valuation techniques including the discounted cash flow model. The inputs to these models are taken from observable markets where possible, but where this is not feasible, a degree of estimate is required in establishing fair values. Estimates include considerations of inputs such as liquidity risk, credit risk and volatility. Changes in assumptions relating to these factors could affect the reported fair value of financial instruments (Note 10).

- | Fair value of identifiable assets and liabilities arising from a business combination

The assets acquired and liabilities assumed on a business combination are recognised at the fair values of the underlying items. The estimates that have a significant risk of causing a material adjustment to the carrying amounts of the assets and liabilities are the ones considered when performing impairment review of operating assets (see above).
Judgements:

- | Assessment of assets agreements.

By evaluating the terms and conditions of each assets agreement, the Company determines the accounting category to which the asset belongs, e.g. IAS 16, IFRIC 12 or IFRS 16 (Note 2.3.).

- | Assessment of control.

Judgement is required in determining the nature of Atlantica´s interest in another entity and in determining if it has control, joint control or significant influence over it (Note 2.2.).
As of the date of preparation of these Consolidated Financial Statements, no relevant changes in the estimates made are anticipated and, therefore, no significant changes in the value of the assets and liabilities recognized at December 31, 2023, are expected.
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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 profit and loss statement of the year in which the change occurs.
Note 3.- Financial risk management
Atlantica’s activities are exposed to various financial risks: market risk (including currency risk and interest rate risk), credit risk and liquidity risk. Risk is managed by the Company’s Risk Management and Finance Departments, which are responsible for identifying and evaluating financial risks quantifying them by project, region and company, 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. The internal management policies of the Company also define the use of hedging instruments and derivatives and the investment of excess cash.

a) | Market risk

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

- | Interest rate risk

Interest rate risk arises when the Company’s activities are exposed to changes in interest rates, which arises from financial liabilities at variable interest rates. The main interest rate exposure for the Company relates to the variable interest rate with reference to the EURIBOR and SOFR. To minimize the interest rate risk, the Company primarily uses interest rate swaps and interest rate options (caps), which, in exchange for a fee, offer protection against an increase in interest rates. The Company does not use derivatives for speculative purposes.
As of December 31, 2023, approximately 92% of the Project debt of the Company and approximately 94% of the Corporate debt either has fixed interest rates or has been hedged with swaps or caps. The Revolving Credit Facility of the Company has variable interest rates and is not hedged (Note 15).
In connection with the interest rate derivative positions of the Company, the most significant impacts on these Consolidated Financial Statements are derived from the changes in EURIBOR and SOFR, which represent the reference interest rate for most of the debt of the Company. In the event that EURIBOR and SOFR had risen by 25 basis points as of December 31, 2023, with the rest of the variables remaining constant, the effect in the consolidated profit and loss statement would have been a loss of $0.7 million (a loss of $1.3 million in 2022 and a loss of $2.5 million in 2021) and a gain in hedging reserves of $17.6 million ($18.4 million in 2022 and $22.4 million in 2021). The gain in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.
A breakdown of the interest rates derivatives as of December 31, 2023 and 2022, is provided in Note 10.

- | Currency risk

The main cash flows in the entities included in these Consolidated Financial Statements are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Given that financing of the projects is typically closed in the same currency in which the contract with client is signed, a natural hedge exists for the main operations of the Company.
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In addition, to further mitigate this exposure, the Company policy is to contract currency options with leading financial institutions, which guarantee a minimum Euro-U.S. dollar exchange rate on the net distributions expected from solar assets in Europe. The net Euro exposure is 100% hedged for the coming 12 months and 75% for the following 12 months on a rolling basis.
Although the Company hedges cash-flows in euros, fluctuations in the value of the euro in relation to the U.S. dollar may affect its 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, the Colombian peso and the Uruguayan peso with respect to the U.S. dollar may also affect the operating results of the Company. Apart from the impact of these translation differences, the exposure of the profit and loss statement of the Company 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.

b) | Credit risk

The Company considers that it has a limited credit risk with clients as revenues primarily derive from power purchase agreements with electric utilities and state-owned entities. In addition, the diversification by geography and business sector helps to diversify credit risk exposure by diluting the exposure of the Company to a single client.

c) | Liquidity risk

Atlantica’s liquidity and financing policy is intended to ensure that the Company maintains sufficient funds to meet its financial obligations as they fall due.
Project finance borrowing permits the Company to finance the project through project debt and thereby insulate the rest of its assets from such credit exposure. The Company incurs in project-finance debt on a project-by-project basis.
The repayment profile of each project is established on the basis of the projected cash flow generation of the business. This ensures that sufficient financing is available to meet deadlines and maturities, which mitigates the liquidity risk significantly. In addition, the Company maintains a periodic communication with its lenders and regular monitoring of debt covenants and minimum ratios.
Corporate and Project debt repayment schedules are disclosed in Note 15 and 16, respectively.
Note 4.- Financial information by segment
Atlantica’s segment structure reflects how management currently makes financial decisions and allocates resources. Its operating and reportable segments are based on the following geographies where the contracted concessional assets are located: North America, South America and EMEA. In addition, based on the type of business, as of December 31, 2023, the Company had the following business sectors: Renewable energy, Efficient natural gas and heat, Transmission lines and Water.
Atlantica’s Chief Operating Decision Maker (CODM), which is the CEO, assesses the performance and assignment of resources according to the identified operating segments. The CODM considers the revenue as a measure of the business activity and the Adjusted EBITDA as a measure of the performance of each segment. Adjusted EBITDA is calculated as profit/(loss) for the 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 these Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of Atlantica’s equity ownership).
In order to assess performance of the business, the CODM receives reports of each reportable segment using revenue and Adjusted EBITDA. Net interest expense evolution is assessed on a consolidated basis. Financial expense and amortization are not taken into consideration by the CODM for the allocation of resources.
In the year ended December 31, 2023, Atlantica had four customers with revenues representing more than 10% of total revenue, three in the renewable energy and one in the efficient natural gas and heat business sectors. In the year ended December 31, 2022, Atlantica had three customers with revenues representing more than 10% of the total revenue, two in the renewable energy and one in the efficient natural gas and heat business sectors.
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a) | The following tables show Revenues and Adjusted EBITDA by operating segments and business sectors for the years 2023, 2022 and 2021:

|  | Revenue |  |  | Adjusted EBITDA |
|  | For the year ended December 31, |  |  | For the year ended December 31, |
Geography |  | 2023 |  |  | 2022 |  |  | 2021 |  |  | 2023 |  |  | 2022 |  |  | 2021 |
North America |  |  | 424,888 |  |  |  | 405,047 |  |  |  | 395,775 |  |  |  | 319,264 |  |  |  | 309,988 |  |  |  | 311,803 |
South America |  |  | 188,127 |  |  |  | 166,441 |  |  |  | 154,985 |  |  |  | 146,722 |  |  |  | 126,551 |  |  |  | 119,547 |
EMEA |  |  | 486,879 |  |  |  | 530,541 |  |  |  | 660,989 |  |  |  | 328,936 |  |  |  | 360,561 |  |  |  | 393,038 |
Total |  |  | 1,099,894 |  |  |  | 1,102,029 |  |  |  | 1,211,749 |  |  |  | 794,922 |  |  |  | 797,100 |  |  |  | 824,388 |

|  | Revenue |  |  | Adjusted EBITDA |
|  | For the year ended December 31, |  |  | For the year ended December 31, |
Business sectors |  | 2023 |  |  | 2022 |  |  | 2021 |  |  | 2023 |  |  | 2022 |  |  | 2021 |
Renewable energy |  |  | 802,756 |  |  |  | 821,377 |  |  |  | 928,525 |  |  |  | 575,704 |  |  |  | 588,016 |  |  |  | 602,583 |
Efficient natural gas & heat |  |  | 118,417 |  |  |  | 113,591 |  |  |  | 123,692 |  |  |  | 87,393 |  |  |  | 84,560 |  |  |  | 99,935 |
Transmission lines |  |  | 123,476 |  |  |  | 113,273 |  |  |  | 105,680 |  |  |  | 96,043 |  |  |  | 88,010 |  |  |  | 83,635 |
Water |  |  | 55,245 |  |  |  | 53,788 |  |  |  | 53,852 |  |  |  | 35,782 |  |  |  | 36,514 |  |  |  | 38,235 |
Total |  |  | 1,099,894 |  |  |  | 1,102,029 |  |  |  | 1,211,749 |  |  |  | 794,922 |  |  |  | 797,100 |  |  |  | 824,388 |

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

|  | For the year ended December 31, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
Profit/(loss) attributable to the Company |  |  | 43,380 |  |  |  | (5,443 | ) |  |  | (30,080 | )
Profit/(loss) attributable to non-controlling interest |  |  | (6,932 | ) |  |  | 3,356 |  |  |  | 19,162 |
Income tax expense/(income) |  |  | 790 |  |  |  | (9,689 | ) |  |  | 36,220 |
Financial expense, net |  |  | 317,974 |  |  |  | 310,934 |  |  |  | 340,892 |
Depreciation, amortization, and impairment charges |  |  | 418,271 |  |  |  | 473,638 |  |  |  | 439,441 |
Depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of Atlantica’s equity ownership) |  |  | 21,439 |  |  |  | 24,304 |  |  |  | 18,753 |
Total segment Adjusted EBITDA |  |  | 794,922 |  |  |  | 797,100 |  |  |  | 824,388 |

b) | The assets and liabilities by geography and business sector at the end of 2023 and 2022 are as follows:

Assets and liabilities by geography as of December 31, 2023:

|  | North America |  |  | South America |  |  | EMEA |  |  | Balance as of December 31, 2023 |
Assets allocated |  |  |  |  |  |  |  |  |  |  |  |
Contracted concessional, PP&E and other intangible assets |  |  | 3,063,019 |  |  |  | 1,184,599 |  |  |  | 2,956,649 |  |  |  | 7,204,267 |
Investments carried under the equity method |  |  | 177,260 |  |  |  | 9,178 |  |  |  | 43,869 |  |  |  | 230,307 |
Other current financial assets |  |  | 110,016 |  |  |  | 30,803 |  |  |  | 48,067 |  |  |  | 188,886 |
Cash and cash equivalents (project companies) |  |  | 137,480 |  |  |  | 121,945 |  |  |  | 155,551 |  |  |  | 414,976 |
Assets held for sale |  |  | 28,642 |  |  |  | - |  |  |  | - |  |  |  | 28,642 |
Subtotal allocated |  |  | 3,516,417 |  |  |  | 1,346,525 |  |  |  | 3,204,136 |  |  |  | 8,067,078 |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 297,577 |
Other current assets (including cash and cash equivalents at holding company level) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 349,678 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 647,255 |
Total assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 8,714,333 |

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|  | North America |  |  | South America |  |  | EMEA |  |  | Balance as of December 31, 2023 |
Liabilities allocated |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term project debt |  |  | 1,629,278 |  |  |  | 808,481 |  |  |  | 1,881,501 |  |  |  | 4,319,260 |
Grants and other liabilities |  |  | 945,888 |  |  |  | 36,307 |  |  |  | 251,613 |  |  |  | 1,233,808 |
Subtotal allocated |  |  | 2,575,166 |  |  |  | 844,788 |  |  |  | 2,133,114 |  |  |  | 5,553,068 |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term corporate debt |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,084,838 |
Other non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 301,245 |
Other current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 186,373 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,572,456 |
Total liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,125,524 |
Equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,588,809 |
Total liabilities and equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,161,265 |
Total liabilities and equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 8,714,333 |

Assets and liabilities by geography as of December 31, 2022:

|  | North America |  |  | South America |  |  | EMEA |  |  | Balance as of December 31, 2022 |
Assets allocated |  |  |  |  |  |  |  |  |  |  |  |
Contracted concessional, PP&E and other intangible assets |  |  | 3,167,490 |  |  |  | 1,241,879 |  |  |  | 3,073,889 |  |  |  | 7,483,259 |
Investments carried under the equity method |  |  | 210,704 |  |  |  | 4,450 |  |  |  | 44,878 |  |  |  | 260,031 |
Other current financial assets |  |  | 118,385 |  |  |  | 31,136 |  |  |  | 46,373 |  |  |  | 195,893 |
Cash and cash equivalents (project companies) |  |  | 187,568 |  |  |  | 85,697 |  |  |  | 266,557 |  |  |  | 539,822 |
Subtotal allocated |  |  | 3,684,147 |  |  |  | 1,363,162 |  |  |  | 3,431,697 |  |  |  | 8,479,005 |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 325,893 |
Other current assets (including cash and cash equivalents at holding company level) |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 296,013 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 621,906 |
Total assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,100,911 |

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|  | North America |  |  | South America |  |  | EMEA |  |  | Balance as of December 31, 2022 |
Liabilities allocated |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term project debt |  |  | 1,713,125 |  |  |  | 841,906 |  |  |  | 1,998,021 |  |  |  | 4,553,052 |
Grants and other liabilities |  |  | 994,874 |  |  |  | 25,031 |  |  |  | 232,608 |  |  |  | 1,252,513 |
Subtotal allocated |  |  | 2,707,999 |  |  |  | 866,937 |  |  |  | 2,230,629 |  |  |  | 5,805,565 |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term corporate debt |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,017,200 |
Other non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 313,328 |
Other current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 175,771 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,506,299 |
Total liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,311,864 |
Equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,789,047 |
Total liabilities and equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,295,346 |
Total liabilities and equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,100,911 |

Assets and liabilities by business sectors as of December 31, 2023:

|  | Renewable energy |  |  | Efficient natural gas & heat |  |  | Transmission lines |  |  | Water |  |  | Balance as of December 31, 2023 |
Assets allocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contracted concessional, PP&E and other intangible assets |  |  | 5,798,818 |  |  |  | 460,766 |  |  |  | 777,360 |  |  |  | 167,323 |  |  |  | 7,204,267 |
Investments carried under the equity method |  |  | 189,672 |  |  |  | - |  |  |  | - |  |  |  | 40,635 |  |  |  | 230,307 |
Other current financial assets |  |  | 10,866 |  |  |  | 103,907 |  |  |  | 30,746 |  |  |  | 43,367 |  |  |  | 188,886 |
Cash and cash equivalents (project companies) |  |  | 299,987 |  |  |  | 35,098 |  |  |  | 58,004 |  |  |  | 21,887 |  |  |  | 414,976 |
Assets held for sale |  |  | - |  |  |  | 28,642 |  |  |  | - |  |  |  | - |  |  |  | 28,642 |
Subtotal allocated |  |  | 6,299,343 |  |  |  | 628,413 |  |  |  | 866,110 |  |  |  | 273,212 |  |  |  | 8,067,078 |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 297,577 |
Other current assets (including cash and cash equivalents at holding company level) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 349,678 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 647,255 |
Total assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 8,714,333 |

|  | Renewable energy |  |  | Efficient natural gas & heat |  |  | Transmission lines |  |  | Water |  |  | Balance as of December 31, 2023 |
Liabilities allocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term project debt |  |  | 3,280,618 |  |  |  | 401,460 |  |  |  | 560,906 |  |  |  | 76,276 |  |  |  | 4,319,260 |
Grants and other liabilities |  |  | 1,185,487 |  |  |  | 32,916 |  |  |  | 12,884 |  |  |  | 2,521 |  |  |  | 1,233,808 |
Subtotal allocated |  |  | 4,466,105 |  |  |  | 434,376 |  |  |  | 573,790 |  |  |  | 78,797 |  |  |  | 5,553,068 |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term corporate debt |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,084,838 |
Other non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 301,245 |
Other current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 186,373 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,572,456 |
Total liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,125,524 |
Equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,588,809 |
Total liabilities and equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,161,265 |
Total liabilities and equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 8,714,333 |

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Assets and liabilities by business sectors as of December 31, 2022:

|  | Renewable energy |  |  | Efficient natural gas & heat |  |  | Transmission lines |  |  | Water |  |  | Balance as of December 31, 2022 |
Assets allocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contracted concessional, PP&E and other intangible assets |  |  | 6,035,091 |  |  |  | 485,431 |  |  |  | 800,067 |  |  |  | 162,670 |  |  |  | 7,483,259 |
Investments carried under the equity method |  |  | 207,870 |  |  |  | 10,034 |  |  |  | - |  |  |  | 42,128 |  |  |  | 260,031 |
Other current financial assets |  |  | 6,706 |  |  |  | 116,366 |  |  |  | 30,582 |  |  |  | 42,240 |  |  |  | 195,893 |
Cash and cash equivalents (project companies) |  |  | 392,577 |  |  |  | 73,673 |  |  |  | 48,073 |  |  |  | 25,498 |  |  |  | 539,822 |
Subtotal allocated |  |  | 6,642,244 |  |  |  | 685,504 |  |  |  | 878,722 |  |  |  | 272,536 |  |  |  | 8,479,005 |
Unallocated assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other non-current assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 325,893 |
Other current assets (including cash and cash equivalents at holding company level) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 296,013 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 621,906 |
Total assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,100,911 |

|  | Renewable energy |  |  | Efficient natural gas & heat |  |  | Transmission lines |  |  | Water |  |  | Balance as of December 31, 2022 |
Liabilities allocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term project debt |  |  | 3,442,625 |  |  |  | 440,999 |  |  |  | 582,689 |  |  |  | 86,739 |  |  |  | 4,553,052 |
Grants and other liabilities |  |  | 1,211,878 |  |  |  | 32,138 |  |  |  | 6,040 |  |  |  | 2,457 |  |  |  | 1,252,513 |
Subtotal allocated |  |  | 4,654,503 |  |  |  | 473,137 |  |  |  | 588,729 |  |  |  | 89,196 |  |  |  | 5,805,565 |
Unallocated liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Long-term and short-term corporate debt |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,017,200 |
Other non-current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 313,328 |
Other current liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 175,771 |
Subtotal unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,506,299 |
Total liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,311,864 |
Equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,789,047 |
Total liabilities and equity unallocated |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 3,295,346 |
Total liabilities and equity |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 9,100,911 |

c) | The amount of depreciation, amortization and impairment charges recognized for the years ended December 31, 2023, 2022 and 2021 are as follows:

|  | For the year ended December 31, |
Depreciation, amortization and impairment by geography |  | 2023 |  |  | 2022 |  |  | 2021 |
North America |  |  | (125,725 | ) |  |  | (182,159 | ) |  |  | (152,946 | )
South America |  |  | (77,855 | ) |  |  | (80,039 | ) |  |  | (57,214 | )
EMEA |  |  | (214,691 | ) |  |  | (211,440 | ) |  |  | (229,281 | )
Total |  |  | (418,271 | ) |  |  | (473,638 | ) |  |  | (439,441 | )

|  | For the year ended December 31, |
Depreciation, amortization and impairment by business sectors |  | 2023 |  |  | 2022 |  |  | 2021 |
Renewable energy |  |  | (398,394 | ) |  |  | (434,042 | ) |  |  | (432,138 | )
Efficient natural gas & heat |  |  | 9,365 |  |  |  | (5,430 | ) |  |  | 23,910 |
Transmission lines |  |  | (29,331 | ) |  |  | (32,466 | ) |  |  | (31,286 | )
Water |  |  | 89 |  |  |  | (1,700 | ) |  |  | 73 |
Total |  |  | (418,271 | ) |  |  | (473,638 | ) |  |  | (439,441 | )

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Note 5.- Business combinations
For the year ended December 31, 2023
On March 1, 2023, the Company completed the process of transitioning the O&M services for the assets in Spain where Abengoa was still the supplier to an Atlantica’ subsidiary. This acquisition has been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. The O&M services are included within the Renewable energy sector and the EMEA geography.
The fair value of assets and liabilities consolidated at the effective acquisition date is shown in the following table:

|  | Business combinations for the year ended December 31, 2023 |
Property, plant and equipment under IAS 16 (Note 6) |  |  | 1,565 |
Intangible assets under IAS 38 (Note 6) |  |  | 4,486 |
Inventories |  |  | 1,646 |
Other current and non-current liabilities |  |  | (5,494 | )
Total net assets acquired at fair value |  |  | 2,203 |
Asset acquisition – purchase price |  |  | (2,203 | )
Net result of business combinations |  |  | - |

The purchase price equals the fair value of the net assets acquired.
The allocation of the purchase price is provisional as of December 31, 2023, and amounts indicated above may be adjusted during the measurement period to reflect new information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the amounts recognized as of December 31, 2023. The measurement period will not exceed one year from the acquisition date.
The amount of revenue contributed by the acquisitions during 2023 to the Consolidated Financial Statements of the Company is nil, and the amount of loss after tax is $0.8 million. Had the acquisitions been consolidated from January 1, 2023, the consolidated statement of comprehensive income would not have included any additional revenue and additional loss after tax of $0.2 million.
For the year ended December 31, 2022
On January 17, 2022, the Company closed the acquisition of Chile TL4, a 63-mile transmission line and 2 substations in Chile for a total equity investment of $38.4 million. Atlantica has control over Chile TL4 under IFRS 10, Consolidated Financial Statements. The acquisition of Chile TL4 had been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. Chile TL4 is included within the Transmission Lines sector and the South America geography.
On April 4, 2022, the Company closed the acquisition of Italy PV 4, a 3.6 MW solar portfolio in Italy for a total equity investment of $3.7 million. Atlantica has control over Italy PV 4 under IFRS 10, Consolidated Financial Statements. The acquisition of Italy PV 4 had been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. Italy PV4 is included within the Renewable energy sector and the EMEA geography.
On September 2, 2022 the Company closed the acquisition of Chile PV 3, a 73 MW solar PV plant through its renewable energy platform in Chile for a total equity investment of $7.7 million. Atlantica has control over Chile PV 3 under IFRS 10, Consolidated Financial Statements. The acquisition of Chile PV 3 had been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations, showing 65% of non-controlling interests. Chile PV 3 is included within the Renewable energy sector and the South America geography.
The fair value of assets and liabilities consolidated at the effective acquisition date is shown in aggregate on the basis that they are individually not significant in the following table:

|  | Business combinations for the year ended December 31, 2022 |
Property, plant and equipment under IAS 16 (Note 6) |  |  | 58,002 |
Rights of use under IFRS 16 (Lessee) or intangible assets under IAS 38 (Note 6) |  |  | 16,993 |
Cash & cash equivalents |  |  | 1,057 |
Other current assets |  |  | 8,283 |
Non-current Project debt (Note 16) |  |  | (1,301 | )
Current Project debt (Note 16) |  |  | (148 | )
Other current and non-current liabilities |  |  | (18,919 | )
Non-controlling interest |  |  | (14,300 | )
Total net assets acquired at fair value |  |  | 49,667 |
Asset acquisition – purchase price paid |  |  | (49,667 | )
Net result of business combinations |  |  | - |

The purchase price equals the fair value of the net assets acquired.
The amount of revenue contributed by the acquisitions performed during 2022 to the Consolidated Financial Statements of the Company for the year 2022 was $6.2 million, and the amount of profit after tax was $1.7 million. Had the acquisitions been consolidated from January 1, 2022, the consolidated statement of comprehensive income would have included additional revenue of $4.8 million and additional profit after tax of $1.7 million.
In January, April and September 2023, the provisional period for the purchase price allocation of Chile TL 4, Italy PV 4 and Chile PV 3, respectively, closed, and did not result in significant adjustments to the initial amounts recognized.
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Note 6.- Contracted concessional, PP&E and other intangible assets
The Company has assets recorded as intangible or financial assets in accordance with IFRIC 12, property plant and equipment in accordance with IAS 16 and right of use assets under IFRS 16 or intangible assets under IAS 38. For further details on the application of IFRIC 12 to assets of the Company, see Appendix III.
The following table shows the movements of assets included in the heading “Contracted Concessional, PP&E and other intangible assets” for 2023:

|  | Financial assets under IFRIC 12 |  |  | Financial assets under IFRS 16 (Lessor) |  |  | Intangible assets under IFRIC 12 |  |  | Right of use assets under IFRS 16 (Lessee) and intangible assets under IAS 38 |  |  | Property, plant and equipment under IAS 16 |  |  |  |
Cost |  |  |  | Land |  |  | Technical installations |  |  | Total assets |
Total as of January 1, 2023 |  |  | 818,170 |  |  |  | 2,787 |  |  |  | 8,845,151 |  |  |  | 120,308 |  |  |  | 137,767 |  |  |  | 938,799 |  |  |  | 10,862,982 |
Additions |  |  | - |  |  |  | - |  |  |  | 27,531 |  |  |  | 4,409 |  |  |  | 62 |  |  |  | 50,805 |  |  |  | 82,807 |
Subtractions |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (644 | ) |  |  | - |  |  |  | (5,487 | ) |  |  | (6,131 | )
Business combinations (Note 5) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 4,486 |  |  |  | - |  |  |  | 1,565 |  |  |  | 6,051 |
Currency translation differences |  |  | 5,025 |  |  |  | (132 | ) |  |  | 84,060 |  |  |  | 4,756 |  |  |  | 1,515 |  |  |  | 19,847 |  |  |  | 115,071 |
Reclassification and other movements |  |  | (38,016 | ) |  |  | - |  |  |  | 348 |  |  |  | 17,632 |  |  |  | - |  |  |  | (11,537 | ) |  |  | (31,573 | )
Total cost, as of December 31, 2023 |  |  | 785,179 |  |  |  | 2,655 |  |  |  | 8,957,090 |  |  |  | 150,947 |  |  |  | 139,344 |  |  |  | 993,992 |  |  |  | 11,029,207 |

Depreciation, amortization and impairment |  | Financial assets under IFRIC 12 |  |  | Financial assets under IFRS 16 (Lessor) |  |  | Intangible assets under IFRIC 12 |  |  | Right of use assets under IFRS 16 (Lessee) and intangible assets under IAS 38 |  |  | Property, plant and equipment under IAS 16 |  |  |  |
|  |  |  |  |  |  |  |  | Land |  |  | Technical installations |  |  | Total assets |
Total as of January 1, 2023 |  |  | (69,557 | ) |  |  | - |  |  |  | (3,088,778 | ) |  |  | (26,783 | ) |  |  | - |  |  |  | (194,605 | ) |  |  | (3,379,723 | )
Additions |  |  | - |  |  |  | - |  |  |  | (358,602 | ) |  |  | (11,869 | ) |  |  | - |  |  |  | (41,924 | ) |  |  | (412,395 | )
Impairment charges |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | (16,079 | ) |  |  | (16,079 | )
Reversal of impairment |  |  | 13,378 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 13,378 |
Currency translation differences |  |  | (199 | ) |  |  | - |  |  |  | (32,084 | ) |  |  | (533 | ) |  |  | - |  |  |  | (4,511 | ) |  |  | (37,327 | )
Reclassification and other movements |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 372 |  |  |  | - |  |  |  | 6,834 |  |  |  | 7,206 |
Total depreciation, amortization and impairment, as of December 31, 2023 |  |  | (56,378 | ) |  |  | - |  |  |  | (3,479,464 | ) |  |  | (38,813 | ) |  |  | - |  |  |  | (250,285 | ) |  |  | (3,824,940 | )
Total net book value, as of December 31, 2023 |  |  | 728,801 |  |  |  | 2,655 |  |  |  | 5,477,626 |  |  |  | 112,134 |  |  |  | 139,344 |  |  |  | 743,707 |  |  |  | 7,204,267 |

The increase in the contracted concessional assets cost is primarily due to the higher value of the Euro denominated assets since the exchange rate of the Euro increased against the U.S. dollar since December 31, 2022 and to the investments for the year in operating concessional assets and assets under development or construction. The increase in accumulated depreciation, amortization and impairment is primarily due to the amortization charge for the year and the impairment registered in Chile PV1 (see further explanation below).
The decrease included in “Reclassification and other movement” is mainly due to the reclassification from the long to the short term of the current portion of the contracted concessional financial assets.
The following table shows the movements of assets included in the heading “Contracted Concessional, PP&E and other intangible assets” for 2022:

|  | Financial assets under IFRIC 12 |  |  | Financial assets under IFRS 16 (Lessor) |  |  | Intangible assets under IFRIC 12 |  |  | Right of use assets under IFRS 16 (Lessee) and intangible assets under IAS 38 |  |  | Property, plant and equipment under IAS 16 |  |  |  |
Cost |  |  |  |  |  |  |  |  |  | Land |  |  | Technical installations |  |  | Total assets |
Total as of January 1, 2022 |  |  | 874,525 |  |  |  | 2,843 |  |  |  | 9,068,646 |  |  |  | 100,109 |  |  |  | 137,037 |  |  |  | 835,975 |  |  |  | 11,019,135 |
Additions |  |  | - |  |  |  | - |  |  |  | 32,941 |  |  |  | 5,637 |  |  |  | 3,532 |  |  |  | 75,182 |  |  |  | 117,292 |
Subtractions |  |  | - |  |  |  | (57 | ) |  |  | (499 | ) |  |  | (1,510 | ) |  |  | - |  |  |  | (8,495 | ) |  |  | (10,561 | )
Business combinations (Note 5) |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 16,993 |  |  |  | - |  |  |  | 58,002 |  |  |  | 74,995 |
Currency translation differences |  |  | 1,760 |  |  |  | 1 |  |  |  | (258,735 | ) |  |  | (4,446 | ) |  |  | (2,802 | ) |  |  | (21,090 | ) |  |  | (285,312 | )
Reclassification and other movements |  |  | (58,115 | ) |  |  | - |  |  |  | 2,798 |  |  |  | 3,525 |  |  |  | - |  |  |  | (775 | ) |  |  | (52,567 | )
Total cost, as of December 31, 2022 |  |  | 818,170 |  |  |  | 2,787 |  |  |  | 8,845,151 |  |  |  | 120,308 |  |  |  | 137,767 |  |  |  | 938,799 |  |  |  | 10,862,982 |

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|  | Financial assets under IFRIC 12 |  |  | Financial assets under IFRS 16 (Lessor) |  |  | Intangible assets under IFRIC 12 |  |  | Right of use assets under IFRS 16 (Lessee) and intangible assets under IAS 38 |  |  | Property, plant and equipment under IAS 16 |  |  |  |
Depreciation, amortization and impairment |  |  |  |  |  |  |  |  |  | Land |  |  | Technical installations |  |  | Total assets |
Total as of January 1, 2022 |  |  | (62,889 | ) |  |  | - |  |  |  | (2,769,345 | ) |  |  | (21,578 | ) |  |  | - |  |  |  | (143,755 | ) |  |  | (2,997,567 | )
Additions |  |  | (6,560 | ) |  |  | - |  |  |  | (357,401 | ) |  |  | (6,865 | ) |  |  | - |  |  |  | (43,414 | ) |  |  | (414,240 | )
Impairment charges |  |  |  |  |  |  |  |  |  |  | (41,238 | ) |  |  | - |  |  |  | - |  |  |  | (20,446 | ) |  |  | (61,684 | )
Reversal of impairment |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 859 |  |  |  | - |  |  |  | 7,643 |  |  |  | 8,502 |
Currency translation differences |  |  | (108 | ) |  |  | - |  |  |  | 79,206 |  |  |  | 801 |  |  |  | - |  |  |  | 5,367 |  |  |  | 85,266 |
Total depreciation, amortization and impairment, as of December 31, 2022 |  |  | (69,557 | ) |  |  | - |  |  |  | (3,088,778 | ) |  |  | (26,783 | ) |  |  | - |  |  |  | (194,605 | ) |  |  | (3,379,723 | )
Total net book value, as of December 31, 2022 |  |  | 748,613 |  |  |  | 2,787 |  |  |  | 5,756,373 |  |  |  | 93,525 |  |  |  | 137,767 |  |  |  | 744,194 |  |  |  | 7,483,259 |

The decrease in the contracted concessional assets cost was primarily due to the lower value of the Euro denominated assets since the exchange rate of the Euro decreased against the U.S. dollar since December 31, 2021, that more than offset the increase resulting from business combinations and the additions for the year that primarily corresponded to investments in operating concessional assets and assets under development or construction. The increase in accumulated depreciation, amortization and impairment was primarily due to the amortization charge for the year and the impairment registered in Solana, Chile PV1 and Chile PV2 (see further explanation below).
The decrease included in “Reclassification and other movement” was mainly due to the reclassification from the long to the short term of the current portion of the contracted concessional financial assets.
Solana triggering event of impairment
Considering the continued delays in the works and replacements that the Company was carrying out in the storage system at Solana and their impact on production in 2022, as well as an increase in the discount rate, the Company identified an impairment triggering event as of December 31, 2022, in accordance with IAS 36, Impairment of assets. As a result, an impairment test was performed using historical level of output (generation), which resulted in the recording of an impairment loss of $41 million in 2022.
The impairment was recorded within the line “Depreciation, amortization and impairment charges” of the consolidated profit and loss statement, decreasing the amount of intangible assets under IFRIC 12 pertaining to the Renewable energy sector and the North America geography. The recoverable amount considered was the value in use and amounted to $881 million for Solana, as of December 31, 2022.
No triggering event of impairment was identified in Solana as of December 31, 2023.
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Chile PV1 and Chile PV2 triggering event of impairment
Considering that expected electricity prices in Chile over the remaining useful life of Chile PV1 and Chile PV2 further decreased in 2023, the Company identified an impairment triggering event as of December 31, 2023, 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 $16 million for Chile PV1 ($8 million in 2022) and no impairment for Chile PV2 ($12 million in 2022).
The impairment has been recorded within the line “Depreciation, amortization and impairment charges” of the consolidated profit and loss statement, decreasing the amount of Property, plant and equipment under IAS 16 pertaining to the Renewable energy sector and the South America geography. The recoverable amount considered is the value in use and amounts to $40 million for Chile PV1 and $22 million for Chile PV2 as of December 31, 2023 ($58 million and $22 million respectively as of December 31,2022). A specific discount rate has been used in each year considering changes in the debt/equity leverage ratio over the useful life of the projects, resulting in the use of a range of pre-tax discount rate between 7.7% and 8.7% for Chile PV1 and 7.7% and 9.8% for Chile PV2 (between 7.5% and 8.4% for Chile PV1 and between 7.5% and 8.3% for Chile PV2 in 2022).
The value of the net assets contributed by Chile PV 1 and PV2 to these Consolidated Financial Statements, excluding non-controlling interest, is close to nil as of December 31, 2023.
An adverse change in the key assumptions which are individually used for the valuation could lead to future impairment recognition; specifically, a 5% decrease in electricity prices over the entire remaining useful life of these projects would generate an additional total impairment of approximately $3 million. An increase of 50 basis points in the discount rate would lead to an additional total impairment of approximately $2 million.
The Company did not identify any other triggering event of impairment of its contracted concessional, PP&E and other intangible assets as of December 31, 2023 and 2022.
Expected credit losses
The impairment provision based on the expected credit losses on contracted concessional financial assets, calculated in accordance with IFRS 9, Financial instruments, decreased by $13 million in the year ended December 31, 2023, primarily in ACT following an improvement of its client’s credit risk metrics (increased by $7 million in the year ended December 31, 2022, primarily in ACT).
Note 7.- Investments carried under the equity method
The table below shows the breakdown and the movement of the investments held in associates and joint ventures for 2023 and 2022:

Investments in associates and joint ventures |  | 2023 |  |  | 2022 |
Initial balance |  |  | 260,031 |  |  |  | 294,581 |
Share of profit |  |  | 13,207 |  |  |  | 21,465 |
Distributions |  |  | (38,780 | ) |  |  | (57,537 | )
New entities carried under the equity method |  |  | 4,439 |  |  |  | 4,901 |
Investment in associates classified as held for sale during the year (Note 8) |  |  | (10,194 | ) |  |  | - |
Others (incl. currency translation differences) |  |  | 1,604 |  |  |  | (3,379 | )
Final balance |  |  | 230,307 |  |  |  | 260,031 |

On October 30, 2023, the conditions to classify the investment in Pemcorp as held for sale were met. As a consequence, the book value of the equity investment held by Atlantica in Pemcorp of US$ 10.2 million is classified as held for sale in these Consolidated Financial Statements from that date (Note 8).
Other variations in investments carried under the equity method in 2023 are primarily due to:

| - | Distributions:

In 2023, the Company received distributions from Amherst Island Partnership for $17.3 million ($20.9 million in 2022), distributions from Vento II for $16.1 million ($32.6 million in 2022) and distributions from Honaine for $5.4 million ($4.0 million in 2022). A significant portion of the distributions received from Amherst Island Partnership are distributed by the Company to Algonquin Power Co. (Note 14).

| - | New entities carried under the equity method

On March 1, 2023, Atlantica sold part of its equity interest in the Colombian portfolio of renewable energy entities to a partner, which now holds a 50% equity interest. The Colombian portfolio of renewable energy entities includes the following entities: Atlantica – HIC Renovables S.A.S., SJ Renovables Sun 1 S.A.S., AC Renovables Sol 1 S.A.S., SJ Renovables Wind 1 S.A.S., PA Renovables Sol 1 S.A.S. and Atlantica Hidro Colombia S.A.S. Atlantica and the partner hold 50% of the shares each and have joint control over these entities in accordance with IFRS 11, Joint arrangements. As a result, the subsidiaries, which were previously fully consolidated showing 30% of non-controlling interest, are now recorded as an investment in joint ventures under the equity method in these Consolidated Financial Statements in accordance with IAS 28, Investments in Associates and Joint Ventures. The carrying amount of the non-controlling interests in these entities was derecognized at the date control was lost by Atlantica. Further to the sale of part of its equity interest, Atlantica recorded a gain of $4.6 million as Other operating income in the year 2023 (Note 22).

| - | Share of profit

The profit decreases in 2023 compared to 2022 primarily due to a lower profit at Vento II resulting from lower production and a lower price at Lone Star II after its PPA expired in January 2023.
In November 2022, Atlantica closed the acquisition of a 49% interest, with joint control, in Chile PMGD, an 80 MW portfolio of solar PV assets in Chile, which is currently under construction (Note 1). Chile PMGD is accounted for in these Consolidated Financial Statements using the equity method as per IAS 28 – Investments in Associates and Joint ventures.
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The tables below show a breakdown of stand-alone amounts of assets, revenues and profit and loss as well as other information of interest for the years 2023 and 2022 for the entities carried under the equity method:

Company |  | % Shares of the Company |  |  | 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 (1) |  |  | 49.00 |  |  |  | 411,099 |  |  |  | 25,777 |  |  |  | - |  |  |  | 56,508 |  |  |  | 11,285 |  |  |  | 82,849 |  |  |  | 21,024 |  |  |  | 19,752 |  |  |  | 175,351 |
Windlectric Inc (2) |  |  | 30.00 |  |  |  | 284,618 |  |  |  | 30,884 |  |  |  | - |  |  |  | 159,406 |  |  |  | 77,389 |  |  |  | 21,514 |  |  |  | 8,515 |  |  |  | (2,157 | ) |  |  | 1,910 |
Myah Bahr Honaine, S.P.A.(3) |  |  | 25.50 |  |  |  | 155,338 |  |  |  | 63,451 |  |  |  | 35,569 |  |  |  | 20,240 |  |  |  | 4,653 |  |  |  | 56,172 |  |  |  | 34,576 |  |  |  | 27,084 |  |  |  | 40,635 |
Akuo Atlantica PMGD Holding S.P.A. (4) |  |  | 49.00 |  |  |  | 56,214 |  |  |  | 7,210 |  |  |  | 24,214 |  |  |  | 18,090 |  |  |  | 13,739 |  |  |  | 192 |  |  |  | (75 | ) |  |  | (83 | ) |  |  | 4,409 |
Colombian portfolio of renewable energy entities |  |  | 50.00 |  |  |  | 9,092 |  |  |  | 4,970 |  |  |  | - |  |  |  | 9,872 |  |  |  | 956 |  |  |  | - |  |  |  | (587 | ) |  |  | 1,920 |  |  |  | 4,754 |
Pectonex, R.F. Proprietary Limited |  |  | 50.00 |  |  |  | 1,749 |  |  |  | - |  |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | - |  |  |  | (149 | ) |  |  | (149 | ) |  |  | 1,337 |
Evacuación Valdecaballeros, S.L. |  |  | 57.16 |  |  |  | 15,839 |  |  |  | 1,005 |  |  |  | - |  |  |  | 13,538 |  |  |  | 159 |  |  |  | 878 |  |  |  | (59 | ) |  |  | (91 | ) |  |  | 807 |
Atlantica SailH2, S.L. |  |  | 50.00 |  |  |  | 499 |  |  |  | 333 |  |  |  | - |  |  |  | - |  |  |  | 165 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 653 |
Evacuación Villanueva del Rey, S.L. |  |  | 40.02 |  |  |  | 2,218 |  |  |  | 83 |  |  |  | - |  |  |  | 1,308 |  |  |  | 181 |  |  |  | - |  |  |  | 63 |  |  |  | - |  |  |  | - |
Liberty Infraestructuras S.L. |  |  | 20.00 |  |  |  | 81 |  |  |  | 357 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 4 |  |  |  | (46 | ) |  |  | (68 | ) |  |  | - |
Fontanil Solar, S.L.U. |  |  | 25.00 |  |  |  | 328 |  |  |  | 13 |  |  |  | - |  |  |  | 354 |  |  |  | 7 |  |  |  | - |  |  |  | (1 | ) |  |  | (18 | ) |  |  | 229 |
Murum Solar, S.L.U. |  |  | 25.00 |  |  |  | 266 |  |  |  | 35 |  |  |  | - |  |  |  | 314 |  |  |  | - |  |  |  | - |  |  |  | (1 | ) |  |  | (15 | ) |  |  | 222 |
As of December 31, 2023 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 230,307 |

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Company |  | % Shares of the Company |  |  | 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 (1) |  |  | 49.00 |  |  |  | 435,029 |  |  |  | 14,198 |  |  |  | - |  |  |  | 57,596 |  |  |  | 11,515 |  |  |  | 103,362 |  |  |  | 42,662 |  |  |  | 40,992 |  |  |  | 181,735 |
Windlectric Inc (2) |  |  | 30.00 |  |  |  | 278,504 |  |  |  | 3,338 |  |  |  | - |  |  |  | 167,519 |  |  |  | 43,227 |  |  |  | 24,996 |  |  |  | 10,560 |  |  |  | (15 | ) |  |  | 18,935 |
Myah Bahr Honaine, S.P.A.(3) |  |  | 25.50 |  |  |  | 150,623 |  |  |  | 66,246 |  |  |  | 43,579 |  |  |  | 18,902 |  |  |  | 4,257 |  |  |  | 55,267 |  |  |  | 33,374 |  |  |  | 26,768 |  |  |  | 42,128 |
Akuo Atlantica PMGD Holding S.P.A. (4) |  |  | 49.00 |  |  |  | 14,814 |  |  |  | 2,828 |  |  |  | - |  |  |  | 8,755 |  |  |  | 326 |  |  |  | - |  |  |  | - |  |  |  | (348 | ) |  |  | 4,450 |
Pemcorp SAPI de CV (5) |  |  | 30.00 |  |  |  | 138,931 |  |  |  | 112,352 |  |  |  | 159,382 |  |  |  | 90,474 |  |  |  | 4,328 |  |  |  | 45,625 |  |  |  | 1,680 |  |  |  | (17,747 | ) |  |  | 10,034 |
Pectonex, R.F. Proprietary Limited |  |  | 50.00 |  |  |  | 2,045 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 1 |  |  |  | - |  |  |  | (168 | ) |  |  | (168 | ) |  |  | 1,411 |
Evacuación Valdecaballeros, S.L. |  |  | 57.16 |  |  |  | 15,551 |  |  |  | 1,020 |  |  |  | - |  |  |  | 13,635 |  |  |  | 232 |  |  |  | 860 |  |  |  | (60 | ) |  |  | (89 | ) |  |  | 858 |
Evacuación Villanueva del Rey, S.L. |  |  | 40.02 |  |  |  | 2,317 |  |  |  | 12 |  |  |  | - |  |  |  | 1,386 |  |  |  | 111 |  |  |  | - |  |  |  | 57 |  |  |  | - |  |  |  | - |
Liberty Infraestructuras S.L. |  |  | 20.00 |  |  |  | 93 |  |  |  | 283 |  |  |  | - |  |  |  | - |  |  |  | 37 |  |  |  | - |  |  |  | - |  |  |  | (22 | ) |  |  | 29 |
Fontanil Solar, S.L.U. |  |  | 25.00 |  |  |  | 117 |  |  |  | 7 |  |  |  | - |  |  |  | 99 |  |  |  | 24 |  |  |  | - |  |  |  | (1 | ) |  |  | (2 | ) |  |  | 229 |
Murum Solar, S.L.U. |  |  | 25.00 |  |  |  | 228 |  |  |  | 8 |  |  |  | - |  |  |  | 180 |  |  |  | 59 |  |  |  | - |  |  |  | (1 | ) |  |  | (5 | ) |  |  | 222 |
As of December 31, 2022 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 260,031 |

The Company has no control over Evacuación Valdecaballeros, S.L. as all relevant decisions of this company require the approval of a minimum of shareholders accounting for more than 75% of the shares.
None of the associated companies referred to above is a listed company.
(1) 2007 Vento II, LLC, is the holding company of a 596 MW portfolio of wind assets in the U.S., 49% owned by Atlantica since June 16, 2021, and accounted for under the equity method in these Consolidated Financial Statements. Share of profit of 2007 Vento II, LLC. included in these Consolidated Financial Statements amounts to $9.7 million in 2023 and $20.1 million in 2022.
(2) Windlectric Inc., the project entity, is 100% owned by Amherst Island Partnership which is accounted for under the equity method in these Consolidated Financial Statements.
(3) Myah Bahr Honaine, S.P.A., the project entity, is 51% owned by Geida Tlemcen, S.L. which is accounted for using the equity method in these Consolidated Financial Statements. Geida Tlemcen, S.L. is 50% owned by Atlantica. Share of profit of Myah Bahr Honaine S.P.A. included in these Consolidated Financial Statements amounts to $6.9 million in 2023 and $6.8 million in 2022.
(4) Akuo Atlantica PMGD Holding S.P.A. is the holding company of a 80 MW portfolio of solar PV assets in Chile, which is currently under construction, 49% owned by Atlantica, with joint control since November 2022 and accounted for under the equity method in these Consolidated Financial Statement s.
(5) Pemcorp SAPI de CV, Monterrey´s project entity, is 100% owned by Arroyo Netherlands II B.V., which was accounted for under the equity method in the Consolidated Financial Statements as of December 31, 2022. Arroyo Netherlands II B.V. is 30% owned by Atlantica. The investment held by Atlantica in Pemcorp has been classified as held for sale in these Consolidated Financial (Note 8). Share of profit of Pemcorp SAPI de CV included in these Consolidated Financial Statements amounts to a $0.2 million profit in 2023 and a $5.3 million loss in 2022.
Note 8.- Assets held for sale
In 2023, the Atlantica´s partner in Monterrey initiated a process to sell its 70% stake in the asset. Such process is well advanced and, as part of it, Atlantica intends to sell its interest as well under the same terms. The net proceeds to Atlantica are expected to be in the range of $45 to $52 million, after tax. The transaction is subject to certain conditions precedent and final transaction closing and is expected to be completed in 2024. On October 30, 2023, the conditions to classify the loan granted by Atlantica to Arroyo II and the investment in Pemcorp as held for sale were met. As a consequence, the book value of the equity investment held by Atlantica in Pemcorp of $10.2 million (Note 7) and the loan granted by Atlantica to Arroyo II of $18.5 million (Note 11) as of December 31, 2023, were classified as held for sale in these Consolidated Financial Statements since that date.
Share of profit in Pemcorp is not reflected since October 30, 2023, in these Consolidated Financial Statements according to IFRS 5 Non-current Assets Held for Sale and Discontinued Operations. The loan granted by Atlantica to Arroyo II, shall continue to be measured in accordance with IFRS 9, at amortized cost, and the interests accrued classified as financial income in the profit and loss statement until closing of the sale occurs.
Note 9.- Financial instruments by category
Financial instruments, in addition to financial assets included within Contracted concessional, PP&E and other intangible assets disclosed in Note 6, are primarily deposits, derivatives, trade and other receivables and loans. Financial instruments by category (current and non-current), reconciled with the statement of financial position as of December 31, 2023 and 2022 are as follows:
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|  | Notes |  |  | Amortized cost |  |  | Fair value through other comprehensive income |  |  | Fair value through profit or loss |  |  | Balance as of December 31, 2023 |
Derivative assets |  |  | 10 |  |  |  | - |  |  |  | - |  |  |  | 61,697 |  |  |  | 61,697 |
Investment in Ten West Link |  |  |  |  |  |  | - |  |  |  | 11,719 |  |  |  | - |  |  |  | 11,719 |
Financial assets under IFRIC 12 (short-term portion) (*) |  |  |  |  |  |  | 177,407 |  |  |  | - |  |  |  | - |  |  |  | 177,407 |
Trade and other receivables |  |  | 12 |  |  |  | 286,483 |  |  |  | - |  |  |  | - |  |  |  | 286,483 |
Cash and cash equivalents |  |  | 13 |  |  |  | 448,301 |  |  |  | - |  |  |  | - |  |  |  | 448,301 |
Other financial assets |  |  |  |  |  |  | 74,645 |  |  |  | - |  |  |  | - |  |  |  | 74,645 |
Total financial assets |  |  |  |  |  |  | 986,836 |  |  |  | 11,719 |  |  |  | 61,697 |  |  |  | 1,060,252 |
Corporate debt (**) |  |  | 15 |  |  |  | 1,084,838 |  |  |  | - |  |  |  | - |  |  |  | 1,084,838 |
Project debt (**) |  |  | 16 |  |  |  | 4,319,260 |  |  |  | - |  |  |  | - |  |  |  | 4,319,260 |
Lease liabilities (non-current portion) |  |  | 17 |  |  |  | 82,366 |  |  |  | - |  |  |  | - |  |  |  | 82,366 |
Trade and other current liabilities |  |  | 18 |  |  |  | 141,713 |  |  |  | - |  |  |  | - |  |  |  | 141,713 |
Derivative liabilities |  |  | 10 |  |  |  | - |  |  |  | - |  |  |  | 29,957 |  |  |  | 29,957 |
Total financial liabilities |  |  |  |  |  |  | 5,628,177 |  |  |  | - |  |  |  | 29,957 |  |  |  | 5,658,134 |

|  | Notes |  |  | Amortized cost |  |  | Fair value through other comprehensive income |  |  | Fair value through profit or loss |  |  | Balance as of December 31, 2022 |
Derivative assets |  |  | 10 |  |  |  | - |  |  |  | - |  |  |  | 97,381 |  |  |  | 97,381 |
Investment in Ten West Link |  |  |  |  |  |  | - |  |  |  | 15,959 |  |  |  | - |  |  |  | 15,959 |
Financial assets under IFRIC 12 (short-term portion) (*) |  |  |  |  |  |  | 186,841 |  |  |  | - |  |  |  | - |  |  |  | 186,841 |
Trade and other receivables |  |  | 12 |  |  |  | 200,334 |  |  |  | - |  |  |  | - |  |  |  | 200,334 |
Cash and cash equivalents |  |  | 13 |  |  |  | 600,990 |  |  |  | - |  |  |  | - |  |  |  | 600,990 |
Other financial assets |  |  |  |  |  |  | 71,949 |  |  |  | - |  |  |  | - |  |  |  | 71,949 |
Total financial assets |  |  |  |  |  |  | 1,060,114 |  |  |  | 15,959 |  |  |  | 97,381 |  |  |  | 1,173,454 |
Corporate debt (**) |  |  | 15 |  |  |  | 1,017,200 |  |  |  | - |  |  |  | - |  |  |  | 1,017,200 |
Project debt (**) |  |  | 16 |  |  |  | 4,553,052 |  |  |  | - |  |  |  | - |  |  |  | 4,553,052 |
Lease liabilities (non-current portion) |  |  | 17 |  |  |  | 63,076 |  |  |  | - |  |  |  | - |  |  |  | 63,076 |
Trade and other current liabilities |  |  | 18 |  |  |  | 140,230 |  |  |  | - |  |  |  | - |  |  |  | 140,230 |
Derivative liabilities |  |  | 10 |  |  |  | - |  |  |  | - |  |  |  | 16,847 |  |  |  | 16,847 |
Total financial liabilities |  |  |  |  |  |  | 5,773,558 |  |  |  | - |  |  |  | 16,847 |  |  |  | 5,790,405 |

(*) The long-term portion of Financial assets under IFRIC 12 is included within the line Contracted concessional, PP&E and other intangible assets (Note 6).
(**) The percentage of Corporate and Project debt at fixed interest or hedged is 94% and 92% respectively as of December 31, 2023 (96% and 92% respectively as of December 31, 2022).
Other financial assets as of December 31, 2023 and December 31, 2022 include, among others, loans to entities accounted for under the equity method in these Consolidated Financial Statements (Note 11) and restricted cash for repairs or scheduled major maintenance work.
Investment in Ten West Link is a 12.5% interest in a 114-mile transmission line in the U.S., currently under construction.
Note 10.- Derivative financial instruments
The breakdowns of the fair value amount of the derivative financial instruments as of December 31, 2023 and 2022 are as follows:

|  | Balance as of December 31, 2023 |  |  | Balance as of December 31, 2022 |
|  | Assets |  |  | Liabilities |  |  | Assets |  |  | Liabilities |
Interest rate cash flow hedge |  |  | 60,102 |  |  |  | 29,163 |  |  |  | 94,192 |  |  |  | 12,159 |
Foreign exchange derivatives instruments |  |  | 1,595 |  |  |  | - |  |  |  | 3,189 |  |  |  | - |
Notes conversion option (Note 15) |  |  | - |  |  |  | 794 |  |  |  | - |  |  |  | 4,688 |
Total |  |  | 61,697 |  |  |  | 29,957 |  |  |  | 97,381 |  |  |  | 16,847 |

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

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

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

The notional amounts hedged, strikes contracted and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, can be diverse. As of December 31, 2023, approximately 92% of the Project debt and 94% of the Corporate debt of the Company either has fixed interest rates or has been hedged with swaps or caps (92% and 96%, respectively, as of December 31, 2022).
The table below shows a breakdown of the maturities of notional amounts of interest rate cash flow hedge derivatives as of December 31, 2023 and 2022.

Notionals |  | Balance as of December 31, 2023 |  |  | Balance as of December 31, 2022 |
|  | Assets |  |  | Liabilities |  |  | Assets |  |  | Liabilities |
Up to 1 year |  |  | 248,898 |  |  |  | 43,013 |  |  |  | 245,147 |  |  |  | 47,029 |
Between 1 and 2 years |  |  | 279,215 |  |  |  | 95,701 |  |  |  | 310,393 |  |  |  | 102,476 |
Between 2 and 3 years |  |  | 314,644 |  |  |  | 104,848 |  |  |  | 217,498 |  |  |  | 112,855 |
Subsequent years |  |  | 523,564 |  |  |  | 264,563 |  |  |  | 659,186 |  |  |  | 280,016 |
Total |  |  | 1,366,321 |  |  |  | 508,125 |  |  |  | 1,432,224 |  |  |  | 542,376 |

The table below shows a breakdown of the maturity of the fair values of interest rate cash flow hedge derivatives as of December 31, 2023 and 2022:

Fair value |  | Balance as of December 31, 2023 |  |  | Balance as of December 31, 2022 |
|  | Assets |  |  | Liabilities |  |  | Assets |  |  | Liabilities |
Up to 1 year |  |  | 3,957 |  |  |  | (1,740 | ) |  |  | 10,868 |  |  |  | (991 | )
Between 1 and 2 years |  |  | 10,124 |  |  |  | (5,347 | ) |  |  | 17,860 |  |  |  | (2,189 | )
Between 2 and 3 years |  |  | 12,070 |  |  |  | (5,848 | ) |  |  | 12,257 |  |  |  | (2,851 | )
Subsequent years |  |  | 33,951 |  |  |  | (16,228 | ) |  |  | 53,207 |  |  |  | (6,128 | )
Total |  |  | 60,102 |  |  |  | (29,163 | ) |  |  | 94,192 |  |  |  | (12,159 | )

The net amount of the fair value of interest rate derivatives designated as cash flow hedges transferred to the consolidated profit and loss statement in 2023 is a profit of $27.1 million (loss of $38.2 million in 2022 and a loss of $58.3 million in 2021).
The after-tax result accumulated in equity in connection with derivatives designated as cash flow hedges at the years ended December 31, 2023 and 2022, amounts to a $308.0 million gain and a $345.6 million gain, respectively.
Additionally, the Company has currency options with leading international financial institutions, which guarantee minimum Euro-U.S. dollar exchange rates. The strategy of the Company is to hedge the exchange rate for the net distributions from its European assets after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, the strategy of the Company is to hedge 100% of its euro-denominated net exposure for the next 12 months and 75% of its euro denominated net exposure for the following 12 months, on a rolling basis. Change in fair value of these foreign exchange derivatives instruments are directly recorded in the consolidated profit and loss statement.
Finally, the conversion option of the Green Exchangeable Notes issued in July 2020 (Note 15) is recorded as a derivative with a fair value (liability) of $0.8 million as of December 31, 2023 ($4.7 million as of December 31, 2022).
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Note 11.- Related parties
The related parties of the Company are primarily Algonquin and its subsidiaries, non-controlling interests (Note 14), entities accounted for under the equity method (Note 7) and Directors and the Senior Management of the Company.
Details of balances with related parties as of December 31, 2023 and 2022 are as follows:

| As of December 31, |  |  | Receivables (current) |  |  |  | Receivables (non- current) |  |  |  | Payables (current) |  |  |  | Payables (non- current) |
Entities accounted for under the equity method: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Arroyo Netherland II B.V (Note 8) | 2023 |  |  | 18,448 |  |  |  | - |  |  |  | - |  |  |  | - |
2022 |  |  | 1,097 |  |  |  | 17,006 |  |  |  | - |  |  |  | - |
Amherst Island Partnership | 2023 |  |  | 5,817 |  |  |  | - |  |  |  | - |  |  |  | - |
2022 |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Akuo Atlantica PMGD Holding | 2023 |  |  | - |  |  |  | 16,677 |  |  |  | - |  |  |  | - |
2022 |  |  | - |  |  |  | 504 |  |  |  | - |  |  |  | - |
Colombian assets portfolio | 2023 |  |  | - |  |  |  | 13,578 |  |  |  | 34 |  |  |  | - |
2022 |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Other | 2023 |  |  | 21 |  |  |  | 148 |  |  |  | - |  |  |  | - |
2022 |  |  | 127 |  |  |  | - |  |  |  | - |  |  |  | - |
Non controlling interest: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Algonquin | 2023 |  |  | - |  |  |  | - |  |  |  | 5,683 |  |  |  | - |
2022 |  |  | - |  |  |  | - |  |  |  | 4,762 |  |  |  | - |
JGC Corporation | 2023 |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 4,612 |
2022 |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 6,088 |
Other | 2023 |  |  | - |  |  |  | - |  |  |  | 2,314 |  |  |  | 27 |
2022 |  |  | - |  |  |  | - |  |  |  | 1,311 |  |  |  | - |
Other related parties: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Atlantica´s partner in Colombia (Note 7) | 2023 |  |  | 918 |  |  |  | - |  |  |  | - |  |  |  | - |
2022 |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |
Total | 2023 |  |  | 25,204 |  |  |  | 30,403 |  |  |  | 8,031 |  |  |  | 4,639 |
2022 |  |  | 1,224 |  |  |  | 17,510 |  |  |  | 6,073 |  |  |  | 6,088 |

Receivables with Arroyo Netherland II B.V, the holding company of Pemcorp SAPI de CV, Monterrey´s project entity, correspond to the loan that was granted at acquisition date of the project and accrues an interest of SOFR plus 6.31% with maturity date on November 25, 2027. As of December 31, 2023, the loan is classified as current receivable as it is accounted for as assets held for sale in these Consolidated Financial Statements (Note 8).
Current receivables with Amherst Island Partnership as of December 31, 2023 include a dividend to be collected by AYES Canada for $5.8 million.
Non-current receivables include a loan that accrues a fixed interest of 8.75% with Akuo Atlantica PMGD Holding S.P.A and a loan with the Colombian portfolio of renewable energy entities in which the Company has a 50% equity interest, which accrues a fixed interest of 8%.
Current payables primarily include the dividend to be paid by AYES Canada to Algonquin.
Non-current payables with JGC Corporation include a subordinated debt with Solacor 1 and Solacor 2 that accrues an interest of Euribor plus 2.5% and with maturity date in 2037.
Current receivables with the partner of the Company in Colombia include Atlantica´s pending purchase price payment to be received for the partial sale of its investment in the Colombian portfolio of renewable energy entities (Note 7).
The transactions carried out by entities included in these Consolidated Financial Statements with related parties for the years ended December 31, 2023, 2022 and 2021 have been as follows:

|  |  | Financial income |  |  | Financial expense |  |  | Operating income |
Entities accounted for under the equity method: |  |  |  |  |  |  |  |  |  |
Arroyo Netherland II B.V | 2023 |  |  | 1,845 |  |  |  | - |  |  |  | - |
2022 |  |  | 1,275 |  |  |  | - |  |  |  | - |
2021 |  |  | 2,061 |  |  |  | - |  |  |  | - |
Akuo Atlantica PMGD Holding | 2023 |  |  | 607 |  |  |  | - |  |  |  | 316 |
2022 |  |  | - |  |  |  | - |  |  |  | - |
2021 |  |  | - |  |  |  | - |  |  |  | - |
Colombian assets portfolio | 2023 |  |  | 588 |  |  |  | - |  |  |  | - |
2022 |  |  | - |  |  |  | - |  |  |  | - |
2021 |  |  | - |  |  |  | - |  |  |  | - |
Other | 2023 |  |  | - |  |  |  | - |  |  |  | 9 |
2022 |  |  | - |  |  |  | - |  |  |  | - |
2021 |  |  | - |  |  |  | - |  |  |  | - |
Non controlling interest: |  |  |  |  |  |  |  |  |  |  |  |  |
Other | 2023 |  |  | - |  |  |  | (471 | ) |  |  | - |
2022 |  |  | 23 |  |  |  | (153 | ) |  |  | - |
2021 |  |  | 8 |  |  |  | (97 | ) |  |  | - |
Total | 2023 |  |  | 3,040 |  |  |  | (471 | ) |  |  | 325 |
| 2022 |  |  | 1,298 |  |  |  | (153 | ) |  |  | - |
| 2021 |  |  | 2,069 |  |  |  | (97 | ) |  |  | - |

The total amount of the remuneration received by the Board of Directors of the Company, including the CEO, amounts to $4.0 million in 2023 ($5.7 million in 2022), including $0.9 million of annual bonus ($0.9 million in 2022) and $1.0 million of long-term award vested in 2023 ($3.0 million in 2022). The decrease of the total remuneration in 2023 is mainly due to a decrease in the amount of share options exercised in 2023 compared to 2022, and to the decrease of Atlantica’s share price from the date of such awards being granted. Share options awarded in 2020 and 2021 under the incentive plans that vested in 2023 were underwater and thus not exercised. None of the directors received any pension remuneration in 2023 nor 2022.
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Note 12.- Trade and other receivables
Trade and other receivable as of December 31, 2023 and 2022, consist of the following:

|  | Balance as of December 31, |
|  | 2023 |  |  | 2022 |
Trade receivables |  |  | 213,345 |  |  |  | 125,437 |
Tax receivables |  |  | 37,134 |  |  |  | 45,680 |
Prepayments |  |  | 12,717 |  |  |  | 11,827 |
Other accounts receivable |  |  | 23,287 |  |  |  | 17,390 |
Total |  |  | 286,483 |  |  |  | 200,334 |

The increase in trade receivables is primarily due to collections pending from the Spanish state-owner regulator, Comision Nacional de los Mercados y de la Competencia or “CNMC” in the solar assets of the Company in Spain and from Pemex in ACT. The Company experienced delays in collections from Pemex, especially since the second half of 2019, which have been significant in certain quarters, including in the fourth quarter of 2023.
During the year 2022, in the assets in Spain, the Company collected revenue in line with the parameters corresponding to the regulation in place at the beginning of the year 2022, as the new parameters, reflecting lower revenue, became final on December 14, 2022. As a result, as of December 31, 2022, trade receivables in the assets in Spain were lower than usual. During the year 2023, collections at these assets in Spain were regularized.
As of December 31, 2023, and December 31, 2022, the fair value of trade and other receivables accounts does not differ significantly from its carrying amount.
Trade receivables in foreign currency as of December 31, 2023 and 2022, are as follows:

|  | Balance as of December 31, |
|  | 2023 |  |  | 2022 |
Euro |  |  | 53,012 |  |  |  | 4,088 |
South African Rand |  |  | - |  |  |  | 23,416 |
Chilean peso |  |  | 4,431 |  |  |  | 5,037 |
Mexican peso |  |  | 4,557 |  |  |  | 1,298 |
Other |  |  | 4,376 |  |  |  | 2,676 |
Total |  |  | 66,376 |  |  |  | 36,515 |

The increase in trade receivables in Euro is primarily due to collections pending from the CNMC. Trade receivables in South African Rand decreased due to the unscheduled outage in Kaxu since the end of September 2023 (Note 22).
Note 13.- Cash and cash equivalents
The following table shows the detail of Cash and cash equivalents as of December 31, 2023 and 2022:

|  | Balance as of December 31, |
|  | 2023 |  |  | 2022 |
Cash at bank and on hand - non restricted |  |  | 271,329 |  |  |  | 393,430 |
Cash at bank and on hand - restricted |  |  | 176,972 |  |  |  | 207,560 |
Total |  |  | 448,301 |  |  |  | 600,990 |

Cash includes funds held to satisfy the customary requirements of certain non-recourse debt agreements within the Company´s projects (Note 16) amounting to $177 million as of December 31, 2023 ($208 million as of December 31, 2022).
The following breakdown shows the main currencies in which cash and cash equivalent balances are denominated:

|  | Balance as of December 31, |
Currency |  | 2023 |  |  | 2022 |
U.S. dollar |  |  | 266,200 |  |  |  | 309,756 |
Euro |  |  | 102,820 |  |  |  | 217,675 |
South African Rand |  |  | 30,908 |  |  |  | 36,137 |
Mexican Peso |  |  | 13,455 |  |  |  | 4,010 |
Algerian Dinar |  |  | 21,168 |  |  |  | 24,727 |
Other |  |  | 13,750 |  |  |  | 8,685 |
Total |  |  | 448,301 |  |  |  | 600,990 |

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Note 14.- Equity
As of December 31, 2023, the share capital of the Company amounts to $11,615,905 ($11,605,513 as of December 31, 2022) represented by 116,159,054 ordinary shares (116,055,126 shares as of December 31, 2022) fully subscribed and disbursed with a nominal value of $0.10 each, all in the same class and series. Each share grants one voting right.
Algonquin owns 42.2% of the shares of the Company and is its largest shareholder as of December 31, 2023. Algonquin’s voting rights and rights to appoint directors are limited to 41.5% and the difference between Algonquin´s ownership and 41.5% will vote replicating non-Algonquin’s shareholders’ vote.
The Company accounts for its existing long-term incentive plans granted to employees as equity-settled in accordance with IFRS 2, Share-based Payment when incentives are being settled in shares. During the year 2023, the Company issued 103,928 new shares (228,560 new shares during the year 2022) to its employees to settle a portion of these plans.
On February 28, 2022, the Company established a new “at-the-market program” which replaced its previous program, and entered into a distribution agreement with BofA Securities, MUFG and RBC Capital Markets, as its sales agents, under which the Company may offer and sell from time to time up to $150 million of its ordinary shares. During the year 2023, the Company did not sell any shares under this program. During the year 2022, the Company sold 3,423,593 shares at an average market price of $33.57 pursuant to its distribution agreement, representing net proceeds of $114 million.
Atlantica´s reserves as of December 31, 2023 are made up of share premium account and capital reserves. The share premium account reduction by $250 million during the year 2023, increasing capital reserves by the same amount, was made effective upon the confirmation received on June 26, 2023 from the High Court in the UK, pursuant to the Companies Act 2006.
Other reserves primarily include the change in fair value of cash flow hedges and its tax effect.
Accumulated currency translation differences primarily include the result of translating the financial statements of subsidiaries prepared in a foreign currency into the presentation currency of the Company, the U.S. dollar.
Accumulated deficit primarily includes results attributable to Atlantica.
Non-controlling interest fully relate to interest held by JGC in Solacor 1 and Solacor 2, by Idae in Seville PV, by Itochu Corporation in Solaben 2 and Solaben 3, by Algerian Energy Company, SPA and Sacyr Agua S.L. in Skikda, by Algerian Energy Company, SPA in Tenes, by Industrial Development Corporation of South Africa (IDC) and Kaxu Community Trust in Kaxu, by Algonquin Power Co. in AYES Canada, and by partners of the Company in the Chilean renewable energy platform in Chile PV 1, Chile PV 2 and Chile PV 3.
Additional information of subsidiaries including material non-controlling interest as of December 31, 2023, and 2022, is disclosed in Appendix IV.
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Dividends declared during the year 2023 and the first quarter of 2024 by the Board of Directors of the Company were as follows:

Declared | Payable |  | Amount ($) per share |
February 29, 2024 | March 22, 2024 |  | 0.445 |
November 7, 2023 | December 15, 2023 |  |  | 0.445 |
July 31, 2023 | September 15, 2023 |  |  | 0.445 |
May 4, 2023 | June 15, 2023 |  |  | 0.445 |
February 28, 2023 | March 25, 2023 |  |  | 0.445 |

Dividends declared during the year 2022 by the Board of Directors of the Company were as follows:

Declared | Payable |  | Amount ($) per share |
November 8, 2022 | December 15, 2022 |  |  | 0.445 |
August 2, 2022 | September 15, 2022 |  |  | 0.445 |
May 5, 2022 | June 15, 2022 |  |  | 0.44 |
February 25, 2022 | March 25, 2022 |  |  | 0.44 |

In addition, the Company declared dividends and distributions in 2023 to non-controlling interest primarily to Algonquin (interest in Amherst through AYES Canada, see Note 7) for $16.6 million ($20.4 million in 2022), Itochu Corporation for $6.9 million ($3.5 million in 2022), Algerian Energy Company for $6.7 million ($5.4 million in 2022) and IDC and Kaxu Community Trust for $1.2 million ($5.8 million in 2022).
In 2023, Chile PV 3 received a capital contribution of $19.5 million from the financial partners (Non-controlling interest) through the renewable energy platform of the Company in Chile to install batteries in the asset (Note 1).
As of December 31, 2023 and December 31, 2022, there was no treasury stock and there have been no transactions with treasury stock during the years then ended.
Note 15.- Corporate debt
The breakdown of the corporate debt as of December 31, 2023 and 2022 is as follows:

|  | Balance as of December 31, |
|  | 2023 |  |  | 2022 |
Non-current |  |  | 1,050,816 |  |  |  | 1,000,503 |
Current |  |  | 34,022 |  |  |  | 16,697 |
Total Corporate debt |  |  | 1,084,838 |  |  |  | 1,017,200 |

On July 20, 2017, the Company signed a credit facility (the “2017 Credit Facility”) for up to €10.0 million ($11.0 million), which is available in euros or U.S. dollars. Amounts drawn down accrue interest at a rate per year equal to EURIBOR plus 2% or SOFR plus 2%, depending on the currency, with a floor of 0% on the EURIBOR and SOFR. As of December 31, 2023, $9.9 million has been drawn down ($6.4 million as of December 31, 2022). As of December 31, 2022, the credit facility maturity was July 1, 2024. On August 7, 2023, the available amount under the 2017 Credit Facility has been increased to €15.0 million ($16.6 million) and the maturity extended to July 1, 2025.
On May 10, 2018, the Company entered into the Revolving Credit Facility for $215 million with a syndicate of banks. Amounts drawn down accrue interest at a rate per year equal to (A) for Eurodollar rate loans, Term SOFR, plus a Term SOFR Adjustment equal to 0.10% per annum, plus a percentage determined by reference to the leverage ratio of the Company, ranging between 1.60% and 2.25% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. Federal funds brokers on such day plus ½ of 1.00%, (ii) the U.S. prime rate and (iii) Term SOFR plus 1.00%, in any case, plus a percentage determined by reference to the leverage ratio of the Company, ranging between 0.60% and 1.00%. Letters of credit may be issued using up to $100 million of the Revolving Credit Facility. Since then, the amount of the Revolving Credit Facility increased to $450 million. On May 30, 2023, the maturity was extended to December 31, 2025. On December 31, 2023, $55 million were drawn down ($30 million as of December 31, 2022). On December 31, 2023, the Company issued letters of credit for $17 million ($35 million as of December 31, 2022). As of December 31, 2023, therefore, $378 million of the Revolving Credit Facility were available ($385 million as of December 31, 2022).
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On October 8, 2019, the Company filed a euro commercial paper program (the “Commercial Paper”) with the Alternative Fixed Income Market (MARF) in Spain. The program had an original maturity of twelve months and was extended for annual periods until October 2023. The program allowed Atlantica to issue short term notes over the next twelve months for up to €50 million ($55 million), with such notes having a tenor of up to two years. On November 21, 2023, the Company filed a new program that allows Atlantica to issue short term notes for up to €100 million, with such notes having a tenor of up to two years and the program maturity has been extended twelve months. As of December 31, 2023, the Company had €23.3 million ($25.7 million) issued and outstanding under the program at an average cost of 5.23% (€9.3 million, or $10.1 million, as of December 31, 2022).
On April 1, 2020, the Company closed the secured 2020 Green Private Placement for €290 million ($320 million). The private placement accrues interest at an annual 1.96% interest rate, payable quarterly and has a June 2026 maturity.
On July 8, 2020, the Company entered into the Note Issuance Facility 2020, 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 $155 million which is denominated in euros (€140 million). The Note Issuance Facility 2020 was issued on August 12, 2020, 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, payable quarterly and has a maturity of seven years from the closing date. The Company initially entered into a cap at 0% for the EURIBOR with 3.5 years maturity and in December 2023, into a cap at 4% to hedge the variable interest rate risk with maturity on December 31, 2024.
On July 17, 2020, ASI Jersey Ltd, a subsidiary of the Company issued the Green Exchangeable Notes for $100 million in aggregate principal amount of 4.00% convertible bonds due in 2025. On July 29, 2020, the Company closed an additional $15 million aggregate principal amount of the Green Exchangeable Notes. The notes mature on July 15, 2025, and bear interest at a rate of 4.00% per annum. The initial exchange rate of the notes is 29.1070 ordinary shares per $1,000 principal amount of notes, which is equivalent to an initial exchange price of $34.36 per ordinary share. Noteholders may exchange their notes at their option at any time prior to the close of business on the scheduled trading day immediately preceding April 15, 2025, only during certain periods and upon satisfaction of certain conditions. On or after April 15, 2025, noteholders may exchange their notes at any time. Upon exchange, the notes may be settled, at the election of the Company, into Atlantica ordinary shares, cash or a combination thereof. The exchange rate is subject to adjustment upon the occurrence of certain events.
As per IAS 32, “Financial Instruments: Presentation”, the conversion option of the Green Exchangeable Notes is an embedded derivative classified within the line “Derivative liabilities” of these Consolidated Financial Statements (Note 10). It was initially valued at the transaction date for $10 million, and prospective changes to its fair value are accounted for directly through the profit and loss statement. This instrument is classified as Level 2 in the fair value hierarchy (Note 2.7) based on the observable inputs used for the calculation of its fair value. The valuation technique used is a Monte Carlo which uses regressions to estimate, given a stock price level, the continuation value of the instrument. The principal element of the Green Exchangeable Notes, classified within the line “Corporate debt” of these Consolidated Financial Statements, is initially valued as the difference between the consideration received from the holders of the instrument and the value of the embedded derivative, and thereafter, at amortized cost using the effective interest method as per IFRS 9, Financial Instruments.
On May 18, 2021, the Company issued the Green Senior Notes due in 2028 in an aggregate principal amount of $400 million. The notes mature on May 15, 2028 and bear interest at a rate of 4.125% per annum payable on June 15 and December 15 of each year, commencing December 15, 2021.
On May 10, 2023, the Company entered into a senior unsecured $50 million line of credit with Export Development Canada with a 3-year maturity. Loan under the credit line accrues interest at a rate per annum equal to Term SOFR plus a percentage determined by reference to the leverage ratio of the Company, ranging between 2.46% and 3.11%, with a floor of 0.00% for the Term SOFR. The facility matures on May 25, 2026, and was fully available as of December 31, 2023.
Since 2020, the Company entered into loans with different banks as follows:

| - | a €5 million ($5.5 million) loan on December 4, 2020, which accrues interest at a rate per year equal to 2.50%. The maturity date is December 4, 2025.

| - | a €5 million ($5.5 million) loan on January 31, 2022, which accrues interest at a rate per year equal to 1.90%. The maturity date is January 31, 2026.

| - | a €7 million ($7.7 million) loan on February 24, 2023, which accrues interest at a rate per year equal to 4.21%. The maturity date is February 24, 2028.

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The repayment schedule for the corporate debt as of December 31, 2023 is as follows:

|  | 2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | 2028 |  |  | Total |
2017 Credit Facility |  |  | 13 |  |  |  | 9,876 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 9,889 |
Revolving Credit Facility |  |  | 261 |  |  |  | 54,427 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 54,688 |
Commercial Paper |  |  | 25,691 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 25,691 |
2020 Green Private Placement |  |  | 174 |  |  |  | - |  |  |  | 318,668 |  |  |  | - |  |  |  | - |  |  |  | 318,842 |
2020 Note Issuance Facility |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 152,356 |  |  |  | - |  |  |  | 152,356 |
Green Exchangeable Notes |  |  | 2,108 |  |  |  | 110,020 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 112,128 |
Green Senior Note |  |  | 963 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 395,964 |  |  |  | 396,927 |
Other bank Loans |  |  | 4,812 |  |  |  | 4,736 |  |  |  | 2,288 |  |  |  | 1,642 |  |  |  | 839 |  |  |  | 14,317 |
Total |  |  | 34,022 |  |  |  | 179,059 |  |  |  | 320,956 |  |  |  | 153,998 |  |  |  | 396,803 |  |  |  | 1,084,838 |

The repayment schedule for the corporate debt as of December 31, 2022 was as follows:

|  | 2023 |  |  | 2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | Subsequent years |  |  | Total |
2017 Credit Facility |  |  | 8 |  |  |  | 6,423 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 6,431 |
Revolving Credit Facility |  |  | 112 |  |  |  | 29,387 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 29,499 |
Commercial Paper |  |  | 9,937 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 9,937 |
2020 Green Private Placement |  |  | 423 |  |  |  | - |  |  |  | - |  |  |  | 308,389 |  |  |  | - |  |  |  | - |  |  |  | 308,812 |
2020 Note Issuance Facility |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 147,257 |  |  |  | - |  |  |  | 147,257 |
Green Exchangeable Notes |  |  | 2,107 |  |  |  | - |  |  |  | 107,055 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 109,162 |
Green Senior Note |  |  | 964 |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | - |  |  |  | 395,060 |  |  |  | 396,024 |
Other bank Loans |  |  | 3,146 |  |  |  | 3,122 |  |  |  | 3,124 |  |  |  | 686 |  |  |  | - |  |  |  | - |  |  |  | 10,078 |
Total |  |  | 16,697 |  |  |  | 38,932 |  |  |  | 110,179 |  |  |  | 309,075 |  |  |  | 147,257 |  |  |  | 395,060 |  |  |  | 1,017,200 |

The following table details the movement in corporate debt for the year 2023:

|  | Corporate debt - long term |  |  | Corporate debt - short term |  |  | Total |
Balance as of December 31, 2022 |  |  | 1,000,503 |  |  |  | 16,697 |  |  |  | 1,017,200 |
Nominal increase |  |  | 35,648 |  |  |  | 126,537 |  |  |  | 162,185 |
Nominal repayment |  |  | - |  |  |  | (115,891 | ) |  |  | (115,891 | )
Interest payment |  |  | - |  |  |  | (40,573 | ) |  |  | (40,573 | )
Total cash changes |  |  | 35,648 |  |  |  | (29,927 | ) |  |  | 5,721 |
Interest accrued |  |  | - |  |  |  | 40,570 |  |  |  | 40,570 |
Currency translation differences |  |  | 15,037 |  |  |  | 1,255 |  |  |  | 16,292 |
Other non-cash changes |  |  | 5,055 |  |  |  | - |  |  |  | 5,055 |
Reclassifications |  |  | (5,427 | ) |  |  | 5,427 |  |  |  | - |
Total non-cash changes |  |  | 14,665 |  |  |  | 47,252 |  |  |  | 61,917 |
Balance as of December 31, 2023 |  |  | 1,050,816 |  |  |  | 34,022 |  |  |  | 1,084,838 |

The following table details the movement in corporate debt for the year 2022:

|  | Corporate debt - long term |  |  | Corporate debt - short term |  |  | Total |
Balance as of December 31, 2021 |  |  | 995,190 |  |  |  | 27,881 |  |  |  | 1,023,071 |
Nominal increase |  |  | 35,574 |  |  |  | 65,566 |  |  |  | 101,140 |
Nominal repayment |  |  | (1,323 | ) |  |  | (79,196 | ) |  |  | (80,519 | )
Interest payment |  |  | - |  |  |  | (38,117 | ) |  |  | (38,117 | )
Total cash changes |  |  | 34,251 |  |  |  | (51,747 | ) |  |  | (17,496 | )
Interest accrued |  |  | - |  |  |  | 38,321 |  |  |  | 38,321 |
Currency translation differences |  |  | (29,419 | ) |  |  | (1,423 | ) |  |  | (30,842 | )
Other non-cash changes |  |  | 4,146 |  |  |  | - |  |  |  | 4,146 |
Reclassifications |  |  | (3,665 | ) |  |  | 3,665 |  |  |  | - |
Total non-cash changes |  |  | (28,938 | ) |  |  | 40,563 |  |  |  | 11,625 |
Balance as of December 31, 2022 |  |  | 1,000,503 |  |  |  | 16,697 |  |  |  | 1,017,200 |

Note 16.- Project debt
This note shows the project debt linked to the assets included in Note 6 of these Consolidated Financial Statements.
Project debt is generally used to finance contracted assets, exclusively using as a guarantee the assets and cash flows of the company or group of companies carrying out the activities financed. In most of the cases, the assets and/or contracts are set up as a guarantee to ensure the repayment of the related financing. In addition, the cash of the Company´s projects includes funds held to satisfy the customary requirements of certain non-recourse debt agreements and other restricted cash (Note 13) for an amount of $177 million as of December 31, 2023 ($208 million as of December 31, 2022).
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The variations in 2023 of project debt have been the following:

|  | Project debt - long term |  |  | Project debt - short term |  |  | Total |
Balance as of December 31, 2022 |  |  | 4,226,518 |  |  |  | 326,534 |  |  |  | 4,553,052 |
Nominal increase |  |  | 213,232 |  |  |  | - |  |  |  | 213,232 |
Nominal repayment |  |  | (4,768 | ) |  |  | (513,576 | ) |  |  | (518,344 | )
Interest payment |  |  | - |  |  |  | (227,145 | ) |  |  | (227,145 | )
Total cash changes |  |  | 208,464 |  |  |  | (740,721 | ) |  |  | (532,257 | )
Interest accrued |  |  | - |  |  |  | 227,418 |  |  |  | 227,418 |
Currency translation differences |  |  | 28,808 |  |  |  | 7,150 |  |  |  | 35,958 |
Other non-cash changes |  |  | 35,024 |  |  |  | 65 |  |  |  | 35,089 |
Reclassifications |  |  | (566,941 | ) |  |  | 566,941 |  |  |  | - |
Total non-cash changes |  |  | (503,109 | ) |  |  | 801,574 |  |  |  | 298,465 |
Balance as of December 31, 2023 |  |  | 3,931,873 |  |  |  | 387,387 |  |  |  | 4,319,260 |

The decrease in total project debt as of December 31, 2023, is primarily due to the repayment of project debt for the period in accordance with the financing arrangements.
The Company refinanced the Solaben 2&3 assets in March 2023, entering into two green senior euro-denominated loan agreements for the two assets with a syndicate of banks for a total amount of €198.0 million. The new project debt replaced the previous project loans for a similar amount and maturity was extended from December 2030 to June 2037.
Chile PV 1 and Chile PV 2, where the Company owns a 35% equity interest, were not able to maintain the minimum required cash in its debt service reserve account during the year 2023 due to low electricity prices, which represents an event of default as of December 31, 2023. As a result, although the Companies do not expect an acceleration of the debts to be declared by the credit entities, Chile PV 1 and Chile PV 2 did not have an unconditional right to defer the settlement of the debt for at least twelve months and the project debts, which amount to $50 million and $21 million as of December 31, 2023, respectively, were classified as current in these Consolidated Financial Statements in accordance with International Accounting Standards 1 (“IAS 1”), “Presentation of Financial Statements”.
The variations in 2022 of project debt were the following:

|  | Project debt - long term |  |  | Project debt - short term |  |  | Total |
Balance as of December 31, 2021 |  |  | 4,387,674 |  |  |  | 648,519 |  |  |  | 5,036,193 |
Nominal repayment |  |  | (73,478 | ) |  |  | (310,629 | ) |  |  | (384,107 | )
Interest payment |  |  | - |  |  |  | (232,855 | ) |  |  | (232,855 | )
Total cash changes |  |  | (73,478 | ) |  |  | (543,484 | ) |  |  | (616,962 | )
Interest accrued |  |  | - |  |  |  | 230,237 |  |  |  | 230,237 |
Business combination (Note 5) |  |  | 1,301 |  |  |  | 148 |  |  |  | 1,449 |
Currency translation differences |  |  | (119,068 | ) |  |  | (18,040 | ) |  |  | (137,108 | )
Other non-cash changes |  |  | 39,161 |  |  |  | 82 |  |  |  | 39,243 |
Reclassifications |  |  | (9,072 | ) |  |  | 9,072 |  |  |  | - |
Total non-cash changes |  |  | (87,678 | ) |  |  | 221,499 |  |  |  | 133,821 |
Balance as of December 31, 2022 |  |  | 4,226,518 |  |  |  | 326,534 |  |  |  | 4,553,052 |

The decrease in total project debt as of December 31, 2022 was primarily due to:

| - | the repayment of project debt for the period in accordance with the financing arrangements; and

| - | the lower value of debt denominated in Euros given the depreciation of the Euro against the U.S. dollar since December 31, 2021.

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As of December 31, 2021, Kaxu total debt was presented as current in the Consolidated Financial Statements of the Company, for an amount of $314 million, in accordance with International Accounting Standards 1 (“IAS 1”), “Presentation of Financial Statements”, as a result of the existence of a theoretical event of default under the Kaxu project finance agreement. Since March 31, 2022, the Company has again an unconditional right to defer the settlement of the debt for at least more than twelve months, and therefore the debt previously presented as current in these Consolidated Financial Statements was reclassified as non-current in accordance with the financing agreements.
The repayment schedule for project debt in accordance with the financing arrangements as of December 31, 2023, and assuming there would be no acceleration at the Chile PV 1 and Chile PV 2 debts as of December 31, 2023, is as follows and is consistent with the projected cash flows of the related projects:

2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | 2028 |  |  | Subsequent years |  |  | Total |
Interest payment |  |  | Nominal repayment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| 15,215 |  |  |  | 305,087 |  |  |  | 325,303 |  |  |  | 352,495 |  |  |  | 499,968 |  |  |  | 464,648 |  |  |  | 2,356,544 |  |  |  | 4,319,260 |

The repayment schedule for project debt in accordance with the financing arrangements was as follows and was consistent with the projected cash flows of the related projects:

2023 |  |  | 2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | Subsequent years |  |  | Total |
Interest payment |  |  | Nominal repayment |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| 15,053 |  |  |  | 311,481 |  |  |  | 323,731 |  |  |  | 442,920 |  |  |  | 358,444 |  |  |  | 504,954 |  |  |  | 2,596,469 |  |  |  | 4,553,052 |

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The equivalent in U.S. dollars of the foreign currency-denominated project debts held by the Company is as follows:

|  | Balance as of December 31, |
Currency |  | 2023 |  |  | 2022 |
Euro |  |  | 1,571,369 |  |  |  | 1,633,790 |
South African Rand |  |  | 233,854 |  |  |  | 277,492 |
Algerian Dinar |  |  | 76,277 |  |  |  | 86,739 |
Total |  |  | 1,881,500 |  |  |  | 1,998,021 |

All of the Company’s financing agreements have a carrying amount close to its fair value.
Note 17.- Grants and other liabilities
Grants and other liabilities as of December 31, 2023 and December 31, 2022 are as follows:

|  | Balance as of December 31, |
|  | 2023 |  |  | 2022 |
Grants |  |  | 852,854 |  |  |  | 911,593 |
Other liabilities and provisions |  |  | 380,954 |  |  |  | 340,920 |
Dismantling provision |  |  | 155,279 |  |  |  | 140,595 |
Lease liabilities |  |  | 82,366 |  |  |  | 63,076 |
Accruals on Spanish market prices differences |  |  | 98,820 |  |  |  | 91,884 |
Other |  |  | 44,489 |  |  |  | 45,365 |
Grant and other non-current liabilities |  |  | 1,233,808 |  |  |  | 1,252,513 |

As of December 31, 2023, the amount recorded in Grants corresponds primarily to the ITC Grant awarded by the U.S. Department of the Treasury to Solana and Mojave for a total amount of $578 million ($610 million as of December 31, 2022), which was primarily used to fully repay the Solana and Mojave short-term tranche of the loan with the Federal Financing Bank. The amount recorded in Grants as a liability is progressively recorded as other operating income over the useful life of the asset.
The remaining balance of the “Grants” account corresponds to loans with interest rates below market rates for Solana and Mojave for a total amount of $273 million ($299 million as of December 31, 2022). Loans with the Federal Financing Bank guaranteed by the Department of Energy for these projects bear interest at a rate below market rates for these types of projects and terms. The difference between proceeds received from these loans and its fair value, is initially recorded as “Grants” in the consolidated statement of financial position, and subsequently recorded in “Other operating income” starting at the entry into operation of the plants.
Total amount of income for these two types of grants for Solana and Mojave is $58.5 million and $58.6 million for the years ended December 31, 2023 and 2022, respectively (Note 22).
The increase in other liabilities and provisions in 2023 is primarily due to the accretion expense recognized in the year when updating the present value of these liabilities.
The “Accruals on Spanish market prices differences” corresponds to the differences that occur in each financial year between revenue from the sale of energy at the estimated price determined by the Administration in Spain in accordance with the reasonable profitability scheme determined by law, and the revenue from the sale of energy at the actual average market price in the year. These market price differences are regularized through the compensation and adjustment of the parameters which serve as a basis for calculating the regulated revenue compensation to be received from the Administration in Spain over the remaining regulatory life of the solar assets of the Company to obtain the guaranteed profitability for each solar asset. Current portion amounts to $12.5 million as of December 31, 2023 and $11.9 million as of December 31, 2022 (Note 18).
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The maturity of Other liabilities and provisions as of December 31, 2023 and 2022 is as follows:

As of December 31, 2023 |  | Total |  |  | 2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | 2028 |  |  | Subsequent |
Other liabilities and provisions |  |  | 380,954 |  |  |  | - |  |  |  | 26,503 |  |  |  | 21,714 |  |  |  | 22,975 |  |  |  | 22,367 |  |  |  | 287,395 |
Total |  |  | 380,954 |  |  |  | - |  |  |  | 26,503 |  |  |  | 21,714 |  |  |  | 22,975 |  |  |  | 22,367 |  |  |  | 287,395 |

As of December 31, 2022 |  | Total |  |  | 2023 |  |  | 2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | Subsequent |
Other liabilities and provisions |  |  | 340,920 |  |  |  | - |  |  |  | 26,393 |  |  |  | 20,096 |  |  |  | 20,561 |  |  |  | 20,867 |  |  |  | 253,003 |
Total |  |  | 340,920 |  |  |  | - |  |  |  | 26,393 |  |  |  | 20,096 |  |  |  | 20,561 |  |  |  | 20,867 |  |  |  | 253,003 |

Note 18.- Trade payables and other current liabilities
Trade payables and other current liabilities as of December 31, 2023 and 2022 are as follows:

|  | Balance as of December 31, |
Item |  | 2023 |  |  | 2022 |
Trade accounts payables |  |  | 77,266 |  |  |  | 84,465 |
Accruals on Spanish market prices differences (Note 17) |  |  | 12,475 |  |  |  | 11,936 |
Down payments from clients and other deferred income |  |  | 16,905 |  |  |  | 11,169 |
Other accounts payables |  |  | 35,067 |  |  |  | 32,660 |
Total |  |  | 141,713 |  |  |  | 140,230 |

Trade accounts payables mainly relate to the operation and maintenance of the plants owned by the Company.
Nominal values of trade payables and other current liabilities are considered to approximately equal fair values and the effect of discounting them is not significant.
Note 19.- Income Tax
All the companies of Atlantica file income taxes according to the tax regulations in force in each country on an individual basis or under consolidation tax regulations.
The consolidated income tax has been calculated as an aggregation of income tax expenses/income of each individual company. In order to calculate the taxable income of the consolidated entities individually, the accounting result is adjusted for temporary and permanent differences, recording the corresponding deferred tax assets and liabilities. At each consolidated profit and loss statement date, a current tax asset or liability is recorded, representing income taxes currently refundable or payable. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial statement and income tax purposes, as determined under enacted tax laws and rates.
Income tax payable is the result of applying the applicable tax rate in force to each tax-paying entity, in accordance with the tax laws in force in the country in which the entity is registered. Additionally, tax deductions and credits are available to certain entities, primarily relating to inter-company trades and tax treaties between various countries to prevent double taxation.
The Company offsets deferred tax assets and deferred tax liabilities in each entity where the latter has a legally enforceable right to set off current tax assets against current tax liabilities, and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.
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As of December 31, 2023, and 2022, the analysis of deferred tax assets and deferred tax liabilities is as follows:

Deferred tax assets |  | Balance as of December 31, |
From |  | 2023 |  |  | 2022 |
Net operating loss carryforwards (“NOL´s”) |  |  | 478,179 |  |  |  | 442,415 |
Temporary tax non-deductible expenses |  |  | 158,201 |  |  |  | 134,328 |
Derivatives financial instruments |  |  | 6,855 |  |  |  | 3,461 |
Other |  |  | 20,800 |  |  |  | 5,895 |
Total deferred tax assets |  |  | 664,035 |  |  |  | 586,099 |

Deferred tax liabilities |  | Balance as of December 31, |
From |  | 2023 |  |  | 2022 |
Accelerated tax amortization |  |  | 589,111 |  |  |  | 524,363 |
Other difference between tax and book value of assets |  |  | 154,875 |  |  |  | 186,536 |
Derivatives financial instruments |  |  | 12,989 |  |  |  | 19,034 |
Other |  |  | 17,353 |  |  |  | 2,991 |
Total deferred tax liabilities |  |  | 774,328 |  |  |  | 732,924 |

After offsetting deferred tax assets and deferred tax liabilities, where applicable, the resulting net amounts presented on the consolidated balance sheet are as follows:

Consolidated balance sheets classifications |  | Balance as of December 31, |
|  | 2023 |  |  | 2022 |
Deferred tax assets |  |  | 160,995 |  |  |  | 149,656 |
Deferred tax liabilities |  |  | 271,288 |  |  |  | 296,481 |
Net deferred tax liabilities |  |  | 110,293 |  |  |  | 146,825 |

Most of the NOL´s recognized as deferred tax assets correspond to the entities in the U.S. for $310 million, South Africa for $46 million, Peru for $46 million, Chile for $38 million and Spain for $33 million as of December 31, 2023 ($278 million, $53 million, $46 million, $35 million and $28 million as of December 31, 2022, respectively).
As of December 31, 2023, deferred tax assets for non-deductible expenses are primarily due to the temporary limitation of financial expenses deductibles for tax purposes in the solar plants in Spain for $93 million and in the U.S. assets for $49 million ($94 million and $25 million as of December 31, 2022, respectively).
As of December 31, 2023, deferred tax liabilities for accelerated tax amortization are primarily in the U.S. assets for $339 million, the solar plants in Spain for $173 million and Kaxu for $55 million ($274 million, $173 million and $63 million as of December 31, 2022, respectively).
Deferred tax liabilities for other temporary differences between the tax and book value of contracted concessional assets relate primarily to the U.S. entities for $43 million, the Peruvian entities for $39 million, ACT for $34 million and the Chilean entities for $27 million as of December 31, 2023 ($51 million, $37 million, $56 million, and $27 million as of December 31, 2022, respectively).
In relation to tax losses carryforwards and deductions pending to be used recorded as deferred tax assets, the entities evaluate their recoverability projecting forecasted taxable result for the upcoming years and taking into account their tax planning strategy. Deferred tax liabilities reversals are also considered in these projections, as well as any limitation established by tax regulations in force in each tax jurisdiction. Therefore, the carrying amount of deferred tax assets is reviewed at each annual closing date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilized. Unrecognized deferred tax assets are re-assessed at each annual closing date and are recognized to the extent that it has become probable that future taxable profits will allow the deferred tax asset to be recovered. In assessing the recoverability of deferred tax assets, Atlantica relies on projections of results over the useful life of the contracted concessional assets.
In addition, the Company has $448 million of unrecognized net operating loss carryforwards as of December 31, 2023 ($477 million as of December 31, 2022), as it considers it is not probable that future taxable profits will be available against which these unused tax losses can be utilized.
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The movements in deferred tax assets and liabilities during the years ended December 31, 2023 and 2022 were as follows:

Deferred tax assets |  | Amount |
As of December 31, 2021 |  |  | 172,268 |
Increase/(decrease) through the consolidated profit and loss statement |  |  | 29,197 |
Increase/(decrease) through other consolidated comprehensive income (equity) |  |  | (46,344 | )
Currency translation differences and other |  |  | (5,465 | )
As of December 31, 2022 |  |  | 149,656 |
Increase/(decrease) through the consolidated profit and loss statement |  |  | 7,327 |
Increase/(decrease) through other consolidated comprehensive income (equity) |  |  | 2,207 |
Currency translation differences and other |  |  | 1,805 |
As of December 31, 2023 |  |  | 160,995 |

Deferred tax liabilities |  | Amount |
As of December 31, 2021 |  |  | 308,859 |
Increase/(decrease) through the consolidated profit and loss statement |  |  | (19,864 | )
Increase/(decrease) through other consolidated comprehensive income (equity) |  |  | 17,608 |
Currency translation differences and other |  |  | (10,122 | )
As of December 31, 2022 |  |  | 296,481 |
Increase/(decrease) through the consolidated profit and loss statement |  |  | (27,055 | )
Increase/(decrease) through other consolidated comprehensive income (equity) |  |  | (5,830 | )
Currency translation differences and other |  |  | 7,692 |
As of December 31, 2023 |  |  | 271,288 |

Details of income tax for the years ended December 31, 2023, 2022 and 2021 are as follows:

|  | For the year ended December 31, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
Current tax |  |  | (35,172 | ) |  |  | (39,372 | ) |  |  | (51,016 | )
Deferred tax |  |  | 34,382 |  |  |  | 49,061 |  |  |  | 14,796 |
- relating to the origination and reversal of temporary differences |  |  | 34,382 |  |  |  | 49,061 |  |  |  | 14,796 |
Total income tax (expense)/income |  |  | (790 | ) |  |  | 9,689 |  |  |  | (36,220 | )

The reconciliation between the theoretical income tax resulting from applying an average statutory tax rate to profit/(loss) before income tax and the actual income tax (expense)/income recognized in the consolidated profit and loss statements for the years ended December 31, 2023, 2022, and 2021, is as follows:

|  | For the year ended December 31, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
Consolidated profit/(loss) before taxes |  |  | 37,238 |  |  |  | (11,776 | ) |  |  | 25,302 |
Average statutory tax rate |  |  | 25 | % |  |  | 25 | % |  |  | 25 | %
Corporate income tax at average statutory tax rate |  |  | (9,310 | ) |  |  | 2,944 |  |  |  | (6,326 | )
Income tax of associates, net |  |  | 3,302 |  |  |  | 5,366 |  |  |  | 3,076 |
Differences in statutory tax rates |  |  | (4,270 | ) |  |  | (4,296 | ) |  |  | (3,359 | )
Unrecognized NOLs and deferred tax assets |  |  | (11,070 | ) |  |  | (10,944 | ) |  |  | (11,232 | )
Permanent differences |  |  | 17,493 |  |  |  | 3,957 |  |  |  | (4,052 | )
Other adjustments to taxable income and expense |  |  | 3,065 |  |  |  | 12,662 |  |  |  | (14,327 | )
Corporate income tax |  |  | (790 | ) |  |  | 9,689 |  |  |  | (36,220 | )

For the year ended December 31, 2021, the overall effective tax rate was significantly different than the average statutory rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in the UK entities and to provisions recorded for potential tax contingencies in some jurisdictions. The overall effective tax rate is closer to the average statutory rate of 25% for the years ended December 31, 2023 and 2022.
Uncertain tax positions as of December 31, 2023, 2022 and 2021 have been analyzed by the Company in accordance with IFRIC 23 (uncertainty over income tax treatments). As a result of this analysis, the Company concluded that the risk of the uncertainties is remote and accordingly, the expectation is that these uncertainties would have an insignificant effect on the Consolidated Financial Statements.
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Note 20.- Commitments, third-party guarantees, contingent assets and liabilities
Contractual obligations
The following tables show the breakdown of the third-party commitments and contractual obligations as of December 31, 2023 and 2022:

2023 |  | Total |  |  | 2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | 2028 |  |  | Subsequent |
Corporate debt (Note 15) |  |  | 1,084,838 |  |  |  | 34,022 |  |  |  | 179,059 |  |  |  | 320,956 |  |  |  | 153,998 |  |  |  | 396,803 |  |  |  | - |
Loans with credit institutions (Project debt) (Note 16) |  |  | 3,393,767 |  |  |  | 265,649 |  |  |  | 273,015 |  |  |  | 298,527 |  |  |  | 443,503 |  |  |  | 406,282 |  |  |  | 1,706,791 |
Notes and bonds (Project debt) (Note 16) |  |  | 925,493 |  |  |  | 54,653 |  |  |  | 52,288 |  |  |  | 53,968 |  |  |  | 56,465 |  |  |  | 58,366 |  |  |  | 649,753 |
Purchase commitments* |  |  | 713,509 |  |  |  | 81,868 |  |  |  | 52,814 |  |  |  | 47,164 |  |  |  | 51,768 |  |  |  | 45,243 |  |  |  | 434,652 |
Accrued interest estimate during the useful life of loans |  |  | 1,717,831 |  |  |  | 264,223 |  |  |  | 257,379 |  |  |  | 224,032 |  |  |  | 198,073 |  |  |  | 161,346 |  |  |  | 612,778 |

2022 |  | Total |  |  | 2023 |  |  | 2024 |  |  | 2025 |  |  | 2026 |  |  | 2027 |  |  | Subsequent |
Corporate debt (Note 15) |  |  | 1,017,200 |  |  |  | 16,697 |  |  |  | 38,932 |  |  |  | 110,179 |  |  |  | 309,075 |  |  |  | 147,257 |  |  |  | 395,060 |
Loans with credit institutions (Project debt) (Note 16) |  |  | 3,595,671 |  |  |  | 273,556 |  |  |  | 275,105 |  |  |  | 391,770 |  |  |  | 305,616 |  |  |  | 449,653 |  |  |  | 1,899,971 |
Notes and bonds (Project debt) (Note 16) |  |  | 957,381 |  |  |  | 52,978 |  |  |  | 48,626 |  |  |  | 51,150 |  |  |  | 52,828 |  |  |  | 55,301 |  |  |  | 696,498 |
Purchase commitments* |  |  | 823,856 |  |  |  | 96,847 |  |  |  | 99,597 |  |  |  | 54,747 |  |  |  | 51,058 |  |  |  | 56,852 |  |  |  | 464,755 |
Accrued interest estimate during the useful life of loans |  |  | 1,821,915 |  |  |  | 264,626 |  |  |  | 248,794 |  |  |  | 229,142 |  |  |  | 203,961 |  |  |  | 179,386 |  |  |  | 696,006 |

* Purchase commitments include lease commitments for lease arrangements accounted for under IFRS 16 for $135.1 million as of December 31, 2023 ($112.0 million as of December 31, 2022), of which $9.4 million is due within one year and $125.7 million thereafter as of December 31, 2023 ($7.9 million due within one year and $104.1 million thereafter as of December 31, 2022).
Third-party guarantees
As of December 31, 2023, the sum of bank guarantees and surety bonds deposited by the subsidiaries of the Company as a guarantee to third parties (clients, financial entities and other third parties) amounted to $83.2 million ($88.0 million as of December 31, 2022). In addition, Atlantica Sustainable Infrastructure plc or other holding entities on its behalf had outstanding guarantees amounting to $239.8 million as of December 31, 2023 ($216.9 million as of December 31, 2022), which correspond mainly to guarantees provided to off-takers in PPAs, guarantees for debt service reserve accounts and guarantees for points of access for renewable energy projects.
Corporate debt guarantees
The payment obligations under the Green Senior Notes, the Revolving Credit Facility, the Note Issuance Facility 2020 and the 2020 Green Private Placement are guaranteed on a senior unsecured basis by following subsidiaries of the Company: 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 and the 2020 Green Private Placement are also secured with a pledge over the shares of the subsidiary guarantors.
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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 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. The Company used to have indemnities from Abengoa for certain potential losses, but such indemnities are no longer valid following the insolvency filing by Abengoa S.A. in February 2021.
In addition, during 2021 and 2022, 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 2, one of the wind assets in Vento II where the Company currently has 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 other than legal proceedings arising in the ordinary course of its business. Atlantica is party to various administrative and regulatory proceedings that have arisen in the ordinary course of business.
While Atlantica does not expect these 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.
Note 21.- Employee benefit expenses
The table below shows the employee benefit expenses and the average number of employees for the years ended December 31, 2023, 2022 and 2021:

|  | For the year ended December 31, |
|  | 2023 |  |  | 2022 |  |  | 2021 |
Employee benefit expenses |  |  | 104,083 |  |  |  | 80,232 |  |  |  | 78,758 |
Average number of employees |  |  | 1,304 |  |  |  | 874 |  |  |  | 655 |

The increase in employee benefit expenses in 2023 and 2022 is primarily due to the internalization of operation and maintenance services in the solar assets in Spain during 2022 and 2023, and of Kaxu since February 2022.
Note 22.- Other operating income and expenses
The table below shows the detail of Other operating income and expenses for the years ended December 31, 2023, 2022 and 2021:

|  | For the year ended December 31, |
Other operating income |  | 2023 |  |  | 2022 |  |  | 2021 |
Grants |  |  | 58,742 |  |  |  | 59,056 |  |  |  | 60,746 |
Insurance proceeds and other |  |  | 35,731 |  |  |  | 21,726 |  |  |  | 13,925 |
Income from construction services for contracted concessional assets of the Company accounted for under IFRIC 12 |  |  | 6,614 |  |  |  | - |  |  |  | - |
Total |  |  | 101,087 |  |  |  | 80,782 |  |  |  | 74,670 |

|  | For the year ended December 31, |
Other operating expenses |  | 2023 |  |  | 2022 |  |  | 2021 |
Raw materials and consumables used |  |  | (35,380 | ) |  |  | (19,639 | ) |  |  | (70,690 | )
Leases and fees |  |  | (14,403 | ) |  |  | (11,512 | ) |  |  | (9,332 | )
Operation and maintenance |  |  | (130,442 | ) |  |  | (140,382 | ) |  |  | (154,007 | )
Independent professional services |  |  | (30,656 | ) |  |  | (38,894 | ) |  |  | (39,177 | )
Supplies |  |  | (37,822 | ) |  |  | (59,336 | ) |  |  | (40,790 | )
Insurance |  |  | (41,087 | ) |  |  | (45,756 | ) |  |  | (45,429 | )
Levies and duties |  |  | (15,031 | ) |  |  | (19,764 | ) |  |  | (29,949 | )
Other expenses |  |  | (25,187 | ) |  |  | (15,965 | ) |  |  | (24,957 | )
Construction costs from construction services for contracted concessional assets of the Company accounted for under IFRIC 12 |  |  | (6,614 | ) |  |  | - |  |  |  | - |
Total |  |  | (336,622 | ) |  |  | (351,248 | ) |  |  | (414,330 | )

Grants income mainly relate to ITC cash grants and implicit grants recorded for accounting purposes in relation to the FFB loans with interest rates below market rates in Solana and Mojave projects (Note 17).
Insurance proceeds and other includes $15.3 million of insurance income in 2023 related to an unscheduled outage in Kaxu further to a problem found in the turbine. The Company expects to receive compensation from the insurance company to cover part of the damage and business interruption of the plant. In addition, it includes a gain of $4.6 million related to the sale of part of Atlantica´s equity interest in the Colombian portfolio of renewable energy entities (Note 7).
Income and costs from construction services correspond to the projects ATN Expansion 3 and ATS Expansion 1, which are currently under construction. Given that these projects are included within the scope of IFRIC 12 (intangible assets), the Company has recorded the income and the cost of construction in the consolidated statement of profit or loss (Note 2.3.).
The decrease in other operating expenses in 2023 is primarily due to:

| - | the internalization of the O&M services in the solar assets in Spain during 2022 and 2023. These services are now provided by employees of Atlantica, whose cost is classified within the line “Employee benefit expenses” of the profit and loss statement; and

| - | the lower cost of supplies due to lower prices of electricity in the solar assets in Spain in 2023.

The decrease in other operating expenses in 2022, and specifically Raw materials and consumables used, was primarily due to a specific non-recurrent solar project of Rioglass which ended in October 2021.
Note 23.- Financial expense, net
The following table sets forth financial income and expense for the years ended December 31, 2023, 2022 and 2021:

|  | For the year ended December 31, |
Financial income |  | 2023 |  |  | 2022 |  |  | 2021 |
Interest income on deposits and current accounts |  |  | 21,715 |  |  |  | 7,740 |  |  |  | 3,580 |
Interest income from loans and credits |  |  | 2,942 |  |  |  | 1,299 |  |  |  | 2,066 |
Interest rates gains on derivatives: cash flow hedges |  |  | 350 |  |  |  | 1,110 |  |  |  | 316 |
Total |  |  | 25,007 |  |  |  | 10,149 |  |  |  | 5,962 |

|  | For the year ended December 31, |
Financial expense |  | 2023 |  |  | 2022 |  |  | 2021 |
Interest on loans and notes |  |  | (350,347 | ) |  |  | (292,043 | ) |  |  | (302,558 | )
Interest rates gains/(losses) on derivatives: cash flow hedges |  |  | 26,598 |  |  |  | (38,402 | ) |  |  | (58,340 | )
Total |  |  | (323,749 | ) |  |  | (330,445 | ) |  |  | (360,898 | )

Interest income on deposits and current accounts increased in 2023 mostly due to higher remuneration of deposits resulting from higher interest rates.
Interest expense on loans and notes primarily include interest on corporate and project debt which increase in 2023 is primarily due to the increase in variable spot interest rates. Considering interest gains on hedge instruments of such loans and notes, total interest decreased in 2023 as in 2022, which is primarily due to the repayment of project and corporate debt in accordance with the financing arrangements.
Gains and losses from interest rate derivatives designated as cash flow hedges primarily correspond to transfers from equity to financial income or expense when the hedged item impacts the consolidated profit and loss statement. The decrease on losses and increase of gains in 2023 compared to 2022 and 2021 is due to an increase in the spot interest rates in 2023 and 2022 compared to the previous year, which implies lower interest payments or higher payments received from the derivatives instruments contracted.
Net exchange differences
Net exchange differences primarily correspond to realized and unrealized exchange gains and losses on transactions in foreign currencies as part of the normal course of the business of the Company, and to the change in fair value of caps hedging the net cash flows in Euros of the Company, which was largely stable in 2023 while it accounted for an income in 2022.
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Other financial income/(expense), net
The following table sets out Other financial income/(expense), net for the years 2023, 2022 and 2021:

|  | For the year ended December 31, |
Other financial income/(expense), net |  | 2023 |  |  | 2022 |  |  | 2021 |
Other financial income |  |  | 8,863 |  |  |  | 20,539 |  |  |  | 28,742 |
Other financial losses |  |  | (25,546 | ) |  |  | (21,434 | ) |  |  | (16,571 | )
Total |  |  | (16,683 | ) |  |  | (895 | ) |  |  | 12,171 |

Other financial income in 2023 primarily include $3.9 million of income further to the change in the fair value of the conversion option of the Green Exchangeable Notes (Note 15) since December 2022, and $0.1 million of income for non-monetary change to the fair value of derivatives of Kaxu for which hedge accounting is not applied ($12.0 million and $6.2 million of income in 2022, respectively, and $9.2 million and $7.6 million of income in 2021, respectively).
Other financial losses primarily include guarantees and letters of credit, other bank fees and non-monetary interest expenses for updating the present value of provisions and other long-term liabilities reflecting the passage of time.
Note 24.- Earnings per share
Basic earnings per share have been calculated by dividing the profit/(loss) attributable to equity holders of the Company by the average number of outstanding shares.
Average number of outstanding diluted shares for the year 2023 have been calculated considering the potential issuance of 3,347,305 shares (3,347,305 shares as of December 31, 2022, and December 31, 2021) on the settlement of the Green Exchangeable Notes (Note 15) and the potential issuance of 217,418 shares (226,032 as of December 31, 2022 and 327,749 shares as of December 31, 2021) under the long-term incentive plans granted to employees. It also included the potential issuance of 596,681 shares to Algonquin for the year 2022 (725,041 shares as of December 31, 2021) under the agreement signed on August 3, 2021, according to which Algonquin has the option, on a quarterly basis, to subscribe such number of shares to maintain its percentage in Atlantica in relation to the use of the ATM program (Note 14).

|  | For the year ended December 31, |
Item |  | 2023 |  |  | 2022 |  |  | 2021 |
Profit/(loss) attributable to Atlantica |  |  | 43,380 |  |  |  | (5,443 | ) |  |  | (30,080 | )
Average number of ordinary shares outstanding (thousands) - basic |  |  | 116,152 |  |  |  | 114,695 |  |  |  | 111,008 |
Average number of ordinary shares outstanding (thousands) - diluted |  |  | 119,720 |  |  |  | 118,865 |  |  |  | 115,408 |
Earnings per share for the year (US dollar per share) - basic |  |  | 0.37 |  |  |  | (0.05 | ) |  |  | (0.27 | )
Earnings per share for the year (US dollar per share) - diluted (*) |  |  | 0.37 |  |  |  | (0.09 | ) |  |  | (0.28 | )

(*) The potential ordinary shares related to the Green Exchangeable Notes and the long-term incentive plans granted to employees have not been considered in the calculation of diluted earnings per share for the year ended December 31, 2023, as they have an antidilutive effect. For the years ended December 31, 2022, and December 31, 2021, the potential ordinary shares related to the long-term incentive plans granted to employees and the ATM program have not been considered in the calculation of diluted earnings per share as they have an antidilutive effect.
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Note 25.- Other information
25.1 Restricted Net assets
Certain of the consolidated entities are restricted from remitting certain funds to Atlantica Sustainable Infrastructure plc. as a result of a number of regulatory, contractual or statutory requirements. These restrictions are mainly related to standard requirements to maintain debt service coverage ratios and other requirements from the financing arrangements. At December 31, 2023, the accumulated amount of the temporary restrictions for the entire restricted term of these affiliates was $267 million.
The Company performed a test on the restricted net assets of consolidated subsidiaries in accordance with Securities and Exchange Commission Regulation S-X Rule 12-04 and concluded the restricted net assets did not exceed 25% of the consolidated net assets of the Company as of December 31, 2023. Therefore, separate financial statements of Atlantica Sustainable Infrastructure, plc. do not have to be presented.
25.2 Subsequent events
On February 29, 2024, the Board of Directors of the Company approved a dividend of 0.445 per share, which is expected to be paid on March 22, 2024.
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Appendices | Appendix I

Entities included in the Group as subsidiaries as of December 31, 2023

Company name | Project name | Registered address | % of interest | Business
ACT Energy México, S. de R.L. de C.V. | ACT | Santa Barbara (Mexico) | 100.00 | (2)
Agrisun, Srl. | Italy PV 1 | Rome (Italy) | 100.00 | (3)
Alcala Sviluppo Solare S.r.l |  | Rovereto (Italy) | 100.00 | (3)
Atlantica Canada Inc. |  | Calgary (Canada) | 100.00 | (5)
Atlantica North America, LLC |  | Delaware (United States) | 100.00 | (5)
Atlantica Hystone S.L.U. |  | Seville (Spain) | 100.00 | (3)
Atlantica Infraestructura Sostenible, S.L.U |  | Seville (Spain) | 100.00 | (5)
Atlantica Perú, S.A. |  | Lima (Peru) | 100.00 | (5)
Atlantica Renewable Power Mexico de R.L. de C.V |  | Mexico D.F. (Mexico) | 100.00 | (5)
Atlantica Sustainable Infrastructure Jersey, Ltd |  | Jersey (United Kingdom) | 100.00 | (5)
Atlantica Newco Limited |  | Brentford (United Kingdom) | 100.00 | (5)
Atlantica DCR, LLC |  | Delaware (United States) | 100.00 | (5)
ASHUSA Inc. |  | Delaware (United States) | 100.00 | (5)
Atlantica South Africa (Pty) Ltd |  | Pretoria (South Africa) | 100.00 | (5)
Atlantica South Africa Operations Proprietary Limited Ltd |  | Upington (South Africa) | 92.00 | (3)
ASUSHI, Inc. |  | Delaware (United States) | 100.00 | (5)
Atlantica Holdings USA LLC |  | Tempe (United States) | 100.00 | (5)
Atlantica Energia Sostenibile Italia, Srl. |  | Rome (Italy) | 100.00 | (5)
Atlantica Colombia S.A.S. | La Sierpe | Bogota D.C. (Colombia) | 100.00 | (3)
Atlantica Chile SpA |  | Santiago de Chile (Chile) | 100.00 | (5)
Atlantica y Quartux Almacenamiento de Energía S.A.P.I. de C.V. |  | Mexico D.F. (Mexico) | 88.00 | (3)
Atlantica Solutions LLC |  | Tempe (United States) | 100.00 | (3)
ATN, S.A. | ATN | Lima (Peru) | 100.00 | (1)
ATN 4, S.A |  | Lima (Peru) | 100.00 | (1)
Atlantica Transmisión Sur, S.A. | ATS | Lima (Peru) | 100.00 | (1)
ACT Holdings, S.A. de C.V. |  | Mexico D.F. (Mexico) | 100.00 | (5)
Aguas de Skikda S.P.A. | Skikda | Dely Ibrahim (Algeria) | 51.00 | (4)
Arizona Solar One, LLC. | Solana | Delaware (United States) | 100.00 | (3)
ASI Operations LLC |  | Delaware (United States) | 100.00 | (3)
ASO Holdings Company, LLC. |  | Delaware (United States) | 100.00 | (5)
Atlantica Investment Ltd. |  | Brentford (United Kingdom) | 100.00 | (5)
AYES International UK Ltd |  | Brentford (United Kingdom) | 100.00 | (5)
Atlantica Energia Sostenible España, S.L. |  | Seville (Spain) | 100.00 | (5)
ATN 2, S.A. | ATN 2 | Lima (Peru) | 100.00 | (1)
AY Holding Uruguay, S.A. |  | Montevideo (Uruguay) | 100.00 | (5)
Atlantica Yield Energy Solutions Canada Inc. |  | Vancouver (Canada) | 10.00* | (5)
A&F PV Solar SAPI de C.V. |  | Mexico D.F. (Mexico) | 70.00 | (3)
Banitod, S.A. |  | Montevideo (Uruguay) | 100.00 | (5)
Befesa Agua Tenes, S.P.A. |  | Seville (Spain) | 100.00 | (5)
BPC US Wind Corporation, Inc. |  | Tempe (United States) | 100.00 | (5)
Cadonal, S.A. | Cadonal | Montevideo (Uruguay) | 100.00 | (3)
Calgary District Heating, Inc | Calgary | Vancouver (Canada) | 100.00 | (2)
Carpio Solar Inversiones, S.A. |  | Seville (Spain) | 100.00 | (5)
CGP Holding Finance, LLC | Coso | Delaware (United States) | 100.00 | (3)
Chile PV I | Chile PV I | Santiago de Chile (Chile) | 35.00* | (3)
Chile PV II | Chile PV II | Santiago de Chile (Chile) | 35.00* | (3)
Chile PV III | Chile PV III | Santiago de Chile (Chile) | 35.00* | (3)
Coropuna Transmisión, S.A. |  | Lima (Peru) | 100.00 | (1)
Day Ahead Solar LLC |  | Tempe (United States) | 100.00 | (3)
Diamond FV S.R.L. |  | Rome (Italy) | 100.00 | (3)
Ecija Solar Inversiones, S.A. |  | Seville (Spain) | 100.00 | (5)
Energía Renovable Dalia 1 SA de CV |  | San Luis Potosi (Mexico) | 51.00 | (3)
Energía Renovable Dalia 2 SA de CV |  | San Luis Potosi (Mexico) | 55.00 | (3)
Energía Renovable Dalia 3 SA de CV |  | San Luis Potosi (Mexico) | 53.50 | (3)
Estrellada, S.A. | Melowind | Montevideo (Uruguay) | 100.00 | (3)
Extremadura Equity Investments Sárl. |  | Luxembourg (Luxembourg) | 100.00 | (5)
Fabroen Seconda S.r.l. |  | Rome (Italy) | 85.00 | (3)
Fotovoltaica Solar Sevilla, S.A. | Seville PV | Seville (Spain) | 80.00 | (3)
Geida Skikda, S.L. |  | Madrid (Spain) | 67.00 | (5)
Global Solar Participations Sarl |  | Luxembourg (Luxembourg) | 100.00 | (5)
Gold FV S.R.L. |  | Rome (Italy) | 100.00 | (3)
Helioenergy Electricidad Uno, S.A. | Helioenergy 1 | Seville (Spain) | 100.00 | (3)
Helioenergy Electricidad Dos, S.A. | Helioenergy 2 | Seville (Spain) | 100.00 | (3)
Helios I Hyperion Energy Investments, S.A. | Helios 1 | Seville (Spain) | 100.00 | (3)
Helios II Hyperion Energy Investments, S.A. | Helios 2 | Seville (Spain) | 100.00 | (3)
Helios 2, S.R.L | Italy PV 4 | Rome (Italy) | 100.00 | (3)
Hidrocañete S.A. | Mini-Hydro | Lima (Peru) | 100.00 | (3)
Hornero ST, S.L.U. |  | Seville (Spain) | 100.00 | (3)
Hornero ST Dos, S.L.U |  | Seville (Spain) | 100.00 | (3)
Hypesol Energy Holding, S.L. |  | Seville (Spain) | 100.00 | (5)
Hypesol Solar Inversiones, S.A |  | Seville (Spain) | 100.00 | (5)
Kaxu Solar One (Pty) Ltd. | Kaxu | Gauteng (South Africa) | 51.00 | (3)
Logrosán Equity Investments Sárl. |  | Luxembourg (Luxembourg) | 100.00 | (5)
Logrosán Solar Inversiones, S.A. |  | Seville (Spain) | 100.00 | (5)
Logrosán Solar Inversiones Dos, S.L. |  | Seville (Spain) | 100.00 | (5)
Menhir Solar S.L.U. |  | Seville (Spain) | 100.00 | (3)
Mojave Solar Holdings, LLC. |  | Delaware (United States) | 100.00 | (5)
Mojave Solar LLC. | Mojave | Delaware (United States) | 100.00 | (3)
Montesejo Carda, S.R.L. | Italy PV 3 | Rome (Italy) | 100.00 | (3)
Montesejo Pianno, S.R.L. | Italy PV 3 | Rome (Italy) | 100.00 | (3)
Montesejo Poggio, S.R.L. | Italy PV 3 | Rome (Italy) | 100.00 | (3)
Mordor ES1 LLC | Coso Batteries 1 | Tempe (United States) | 100.00 | (3)
Mordor ES2 LLC | Coso Batteries 2 | Tempe (United States) | 100.00 | (3)
Nesyla, S.A | Albisu | Montevideo (Uruguay) | 100.00 | (3)
Overnight Solar LLC |  | Arizona (United States) | 100.00 | (3)
Palmatir S.A. | Palmatir | Montevideo (Uruguay) | 100.00 | (3)
Palmucho, S.A. | Palmucho | Santiago de Chile (Chile) | 100.00 | (1)
Parque Fotovoltaico La Tolua S.A.S | La Tolua | Bogota D.C. (Colombia) | 100.00 | (3)
Parque Solar Tierra Linda, S.A.S | Tierra Linda | Bogota D.C. (Colombia) | 100.00 | (3)
Raitan ST1, S.L.U |  | Seville (Spain) | 100.00 | (3)
Re Sole, Srl. | Italy PV 2 | Rome (Italy) | 100.00 | (3)
Rilados S.A |  | Montevideo (Uruguay) | 100.00 | (3)
Rio-Huan (Inner Mongolia) Solar Co., Ltd |  | Inner Mongolia (China) | 55.00 | (3)
Rioglass Services North America LLC |  | Delaware (Unites States) | 100.00 | (3)
Rioglass Servicios S.L.U. |  | Seville (Spain) | 100.00 | (3)
Rioglass Solar Holding, S.A. |  | Asturias (Spain) | 100.00 | (5)
Rioglass Solar SAU |  | Asturias (Spain) | 100.00 | (3)
Rioglass Solar Chile SpA |  | Antofagasta (Chile) | 100.00 | (3)
Rioglass Solar Internacional, S.A. |  | Brussels (Belgium) | 100.00 | (3)
Rioglass Solar Systems |  | Tel Aviv (Israel) | 100.00 | (3)
Rioglass Solar SCH, S.L |  | Seville (Spain) | 100.00 | (3)
Rioglass South Africa Pty Ltd |  | Upington (South Africa) | 100.00 | (3)
Rising Sun Inc. |  | Calgary (Canada) | 100.00 | (3)
RRHH Servicios Corporativos, S. de R.L. de C.V. |  | Santa Barbara (Mexico) | 100.00 | (5)
Sanlucar Solar, S.A. | PS-10 | Seville (Spain) | 100.00 | (3)
Solaben Electricidad Uno S.A. | Solaben 1 | Caceres (Spain) | 100.00 | (3)
Solaben Electricidad Dos S.A. | Solaben 2 | Caceres (Spain) | 70.00 | (3)
Solaben Electricidad Tres S.A. | Solaben 3 | Caceres (Spain) | 70.00 | (3)
Solaben Electricidad Seis S.A. | Solaben 6 | Caceres (Spain) | 100.00 | (3)
Solaben Luxembourg S.A. |  | Luxembourg (Luxembourg) | 100.00 | (5)
Solacor Electricidad Uno, S.A. | Solacor 1 | Seville (Spain) | 87.00 | (3)
Solacor Electricidad Dos, S.A. | Solacor 2 | Seville (Spain) | 87.00 | (3)
Atlantica Corporate Resources, S.L |  | Seville (Spain) | 100.00 | (5)
Solar Processes, S.A. | PS-20 | Seville (Spain) | 100.00 | (3)
Solnova Solar Inversiones, S.A. |  | Seville (Spain) | 100.00 | (5)
Solnova Electricidad, S.A. | Solnova 1 | Seville (Spain) | 100.00 | (3)
Solnova Electricidad Tres, S.A. | Solnova 3 | Seville (Spain) | 100.00 | (3)
Solnova Electricidad Cuatro, S.A. | Solnova 4 | Seville (Spain) | 100.00 | (3)
Tenes Lilmiyah, S.P.A | Tenes | Dely Ibrahim (Algeria) | 51.00 | (4)
Transmisora Mejillones, S.A. | Quadra 1 | Santiago de Chile (Chile) | 100.00 | (1)
Transmisora Melipeuco S.A. | Melipeuco | Santiago de Chile (Chile) | 100.00 | (1)
Transmisora Baquedano, S.A. | Quadra 2 | Santiago de Chile (Chile) | 100.00 | (1)
Vernay S.A. |  | Montevideo (Uruguay) | 70.00 | (3)
White Rock Insurance (Europe) PCC Limited |  | Birkirkara (Malta) | 100.00 | (5)

(1) | Business sector: Transmission lines

(2) | Business sector: Efficient natural gas and heat

(3) | Business sector: Renewable energy

(4) | Business sector: Water

(5) | Holding Company

* | Atlantica has control over these entities under IFRS 10, Consolidated Financial Statements.

The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
F-57

Table of Contents
Entities included in the Group as subsidiaries as of December 31, 2022

Company name | Project name | Registered address | % of interest | Business
ACT Energy México, S. de R.L. de C.V. | ACT | Santa Barbara (Mexico) | 100.00 | (2)
AC Renovables Sol 1 S.A.S. |  | Bogota D.C. (Colombia) | 70.00 | (3)
Agrisun, Srl. | Italy PV 1 | Rome (Italy) | 100.00 | (3)
Alcala Sviluppo Solare S.r.l |  | Rovereto (Italy) | 99.00 | (3)
Atlantica North America, LLC |  | Delaware (United States) | 100.00 | (5)
Atlantica Infraestructura Sostenible, S.L.U |  | Seville (Spain) | 100.00 | (5)
Atlantica Perú, S.A. |  | Lima (Peru) | 100.00 | (5)
Atlantica Renewable Power Mexico de R.L. de C.V |  | Mexico D.F. (Mexico) | 100.00 | (5)
Atlantica Sustainable Infrastructure Jersey, Ltd |  | Jersey (United Kingdom) | 100.00 | (5)
Atlantica Newco Limited |  | Brentford (United Kingdom) | 100.00 | (5)
Atlantica DCR, LLC |  | Delaware (United States) | 100.00 | (5)
Atlantica-HIC Renovables S.A.S. |  | Bogota D.C. (Colombia) | 70.00 | (3)
ASHUSA Inc. |  | Delaware (United States) | 100.00 | (5)
Atlantica South Africa (Pty) Ltd |  | Pretoria (South Africa) | 100.00 | (5)
Atlantica South Africa Operations Proprietary Limited Ltd |  | Upington (South Africa) | 92.00 | (3)
ASUSHI, Inc. |  | Delaware (United States) | 100.00 | (5)
Atlantica Hidro Colombia SPA |  | Bogota D.C. (Colombia) | 15.00* | (3)
Atlantica Holdings USA LLC |  | Tempe (United States) | 100.00 | (5)
Atlantica Energia Sostenibile Italia, Srl. |  | Rome (Italy) | 100.00 | (5)
Atlantica Colombia S.A.S. |  | Bogota D.C. (Colombia) | 100.00 | (5)
Atlantica Chile SpA |  | Santiago de Chile (Chile) | 100.00 | (5)
Atlantica y Quartux Almacenamiento de Energía S.A.P.I. de C.V. |  | Mexico D.F. (Mexico) | 60.00 | (3)
Atlantica Solutions LLC |  | Tempe (United States) | 100.00 | (3)
ATN, S.A. | ATN | Lima (Peru) | 100.00 | (1)
ATN 4, S.A |  | Lima (Peru) | 100.00 | (1)
Atlantica Transmisión Sur, S.A. | ATS | Lima (Peru) | 100.00 | (1)
ACT Holdings, S.A. de C.V. |  | Mexico D.F. (Mexico) | 100.00 | (5)
Aguas de Skikda S.P.A. | Skikda | Dely Ibrahim (Algeria) | 51.00 | (4)
Arizona Solar One, LLC. | Solana | Delaware (United States) | 100.00 | (3)
ASI Operations LLC |  | Delaware (United States) | 100.00 | (3)
ASI Vento LLC |  | Tempe (United States) | 100.00 | (5)
ASO Holdings Company, LLC. |  | Delaware (United States) | 100.00 | (5)
Atlantica Investment Ltd. |  | Brentford (United Kingdom) | 100.00 | (5)
AYES International UK Ltd |  | Brentford (United Kingdom) | 100.00 | (5)
Atlantica Energia Sostenible España, S.L. |  | Seville (Spain) | 100.00 | (5)
ATN 2, S.A. | ATN 2 | Lima (Peru) | 100.00 | (1)
AY Holding Uruguay, S.A. |  | Montevideo (Uruguay) | 100.00 | (5)
Atlantica Yield Energy Solutions Canada Inc. |  | Vancouver (Canada) | 10.00* | (5)
A&F PV Solar SAPI de C.V. |  | Mexico D.F. (Mexico) | 100.00 | (3)
Banitod, S.A. |  | Montevideo (Uruguay) | 100.00 | (5)
Befesa Agua Tenes |  | Seville (Spain) | 100.00 | (5)
BPC US Wind Corporation, Inc. |  | Tempe (United States) | 100.00 | (5)
Cadonal, S.A. | Cadonal | Montevideo (Uruguay) | 100.00 | (3)
Calgary District Heating, Inc | Calgary | Vancouver (Canada) | 100.00 | (2)
Carpio Solar Inversiones, S.A. |  | Seville (Spain) | 100.00 | (5)
CGP Holding Finance, LLC | Coso | Delaware (United States) | 100.00 | (3)
Chile PV I | Chile PV I | Santiago de Chile (Chile) | 35.00* | (3)
Chile PV II | Chile PV II | Santiago de Chile (Chile) | 35.00* | (3)
Chile PV III | Chile PV III | Santiago de Chile (Chile) | 35.00* | (3)
Coropuna Transmisión, S.A. |  | Lima (Peru) | 100.00 | (1)
Day Ahead Solar LLC |  | Tempe (United States) | 100.00 | (3)
Ecija Solar Inversiones, S.A. |  | Seville (Spain) | 100.00 | (5)
Energía Renovable Dalia 1 SA de CV |  | San Luis Potosi (Mexico) | 51.00 | (3)
Energía Renovable Dalia 2 SA de CV |  | San Luis Potosi (Mexico) | 51.00 | (3)
Energía Renovable Dalia 3 SA de CV |  | San Luis Potosi (Mexico) | 51.00 | (3)
Estrellada, S.A. | Melowind | Montevideo (Uruguay) | 100.00 | (3)
Extremadura Equity Investments Sárl. |  | Luxembourg (Luxembourg) | 100.00 | (5)
Fotovoltaica Solar Sevilla, S.A. | Seville PV | Seville (Spain) | 80.00 | (3)
Geida Skikda, S.L. |  | Madrid (Spain) | 67.00 | (5)
Global Solar Participations Sarl |  | Luxembourg (Luxembourg) | 100.00 | (5)
Helioenergy Electricidad Uno, S.A. | Helioenergy 1 | Seville (Spain) | 100.00 | (3)
Helioenergy Electricidad Dos, S.A. | Helioenergy 2 | Seville (Spain) | 100.00 | (3)
Helios I Hyperion Energy Investments, S.A. | Helios 1 | Seville (Spain) | 100.00 | (3)
Helios II Hyperion Energy Investments, S.A. | Helios 2 | Seville (Spain) | 100.00 | (3)
Helios 2, S.R.L | Italy PV 4 | Rome (Italy) | 100.00 | (3)
Hidrocañete S.A. | Mini-Hydro | Lima (Peru) | 100.00 | (3)
Hypesol Energy Holding, S.L. |  | Seville (Spain) | 100.00 | (5)
Hypesol Solar Inversiones, S.A |  | Seville (Spain) | 100.00 | (5)
Kaxu Solar One (Pty) Ltd. | Kaxu | Gauteng (South Africa) | 51.00 | (3)
Logrosán Equity Investments Sárl. |  | Luxembourg (Luxembourg) | 100.00 | (5)
Logrosán Solar Inversiones, S.A. |  | Seville (Spain) | 100.00 | (5)
Logrosán Solar Inversiones Dos, S.L. |  | Seville (Spain) | 100.00 | (5)
Mojave Solar Holdings, LLC. |  | Delaware (United States) | 100.00 | (5)
Mojave Solar LLC. | Mojave | Delaware (United States) | 100.00 | (3)
Montesejo Pianno, S.R.L. | Italy PV 3 | Rome (Italy) | 100.00 | (3)
Mordor ES1 LLC |  | Tempe (United States) | 100.00 | (3)
Mordor ES2 LLC |  | Tempe (United States) | 100.00 | (3)
Nesyla, S.A | Albisu | Montevideo (Uruguay) | 100.00 | (3)
Overnight Solar LLC |  | Arizona (United States) | 100.00 | (3)
Palmatir S.A. | Palmatir | Montevideo (Uruguay) | 100.00 | (3)
Palmucho, S.A. | Palmucho | Santiago de Chile (Chile) | 100.00 | (1)
PA Renovables Sol 1 S.A.S. |  | Bogota D.C. (Colombia) | 70.00 | (3)
Parque Fotovoltaico La Tolua S.A.S | La Tolua | Bogota D.C. (Colombia) | 100.00 | (3)
Parque Solar Tierra Linda, S.A.S | Tierra Linda | Bogota D.C. (Colombia) | 100.00 | (3)
Parque Fotovoltaico La Sierpe S.A.S | La Sierpe | Bogota D.C. (Colombia) | 100.00 | (3)
Re Sole, Srl. | Italy PV 2 | Rome (Italy) | 100.00 | (3)
Rilados S.A |  | Montevideo (Uruguay) | 100.00 | (3)
Rioglass Solar Holding, S.A. |  | Asturias (Spain) | 100.00 | (3)
RRHH Servicios Corporativos, S. de R.L. de C.V. |  | Santa Barbara (Mexico) | 100.00 | (5)
Sanlucar Solar, S.A. | PS-10 | Seville (Spain) | 100.00 | (3)
SJ Renovables Sun 1 S.A.S. |  | Bogota D.C. (Colombia) | 70.00 | (3)
SJ Renovables Wind 1 S.A.S. |  | Bogota D.C. (Colombia) | 70.00 | (3)
Solaben Electricidad Uno S.A. | Solaben 1 | Caceres (Spain) | 100.00 | (3)
Solaben Electricidad Dos S.A. | Solaben 2 | Caceres (Spain) | 70.00 | (3)
Solaben Electricidad Tres S.A. | Solaben 3 | Caceres (Spain) | 70.00 | (3)
Solaben Electricidad Seis S.A. | Solaben 6 | Caceres (Spain) | 100.00 | (3)
Solaben Luxembourg S.A. |  | Luxembourg (Luxembourg) | 100.00 | (5)
Solacor Electricidad Uno, S.A. | Solacor 1 | Seville (Spain) | 87.00 | (3)
Solacor Electricidad Dos, S.A. | Solacor 2 | Seville (Spain) | 87.00 | (3)
Atlantica Corporate Resources, S.L |  | Seville (Spain) | 100.00 | (5)
Solar Processes, S.A. | PS-20 | Seville (Spain) | 100.00 | (3)
Solnova Solar Inversiones, S.A. |  | Seville (Spain) | 100.00 | (5)
Solnova Electricidad, S.A. | Solnova 1 | Seville (Spain) | 100.00 | (3)
Solnova Electricidad Tres, S.A. | Solnova 3 | Seville (Spain) | 100.00 | (3)
Solnova Electricidad Cuatro, S.A. | Solnova 4 | Seville (Spain) | 100.00 | (3)
Tenes Lilmiyah, S.P.A | Tenes | Dely Ibrahim (Algeria) | 51.00 | (4)
Transmisora Mejillones, S.A. | Quadra 1 | Santiago de Chile (Chile) | 100.00 | (1)
Transmisora Melipeuco S.A. | Melipeuco | Santiago de Chile (Chile) | 100.00 | (1)
Transmisora Baquedano, S.A. | Quadra 2 | Santiago de Chile (Chile) | 100.00 | (1)
White Rock Insurance (Europe) PCC Limited |  | Birkirkara (Malta) | 100.00 | (5)

(1) | Business sector: Transmission lines

(2) | Business sector: Efficient natural gas and heat

(3) | Business sector: Renewable energy

(4) | Business sector: Water

(5) | Holding Company

* | Atlantica has control over these entities under IFRS 10, Consolidated Financial Statements.

The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
F-58

Table of Contents

Appendices | Appendix II

Investments recorded under the equity method as of December 31, 2023

Company name |  | Project name |  | Registered address |  | % of interest |  | Business |
AC Renovables Sol 1 S.A.S |  |  |  | Bogota D.C. (Colombia) |  | 50.0 |  | (3 | )
Akuo Atlantica PMGD Holding |  | Chile PMGD |  | Santiago de Chile (Chile) |  | 49.0 |  | (3 | )
Amherst Island Partnership |  | Windlectric |  | Ontario (Canada) |  | 30.0 |  | (3 | )
Atlantica - HIC Renovables S.A.S. |  |  |  | Bogota D.C. (Colombia) |  | 50.0 |  | (3 | )
Atlantica Hidro Colombia, S.A.S. |  |  |  | Bogota D.C. (Colombia) |  | 50.0 |  | (3 | )
Atlantica SailH2, S.L. |  |  |  | Seville (Spain) |  | 50.0 |  | (3 | )
Ecorer S.A.C. |  |  |  | Lima (Peru) |  | 50.0 |  | (3 | )
Evacuacion Valdecaballeros, S.L. |  |  |  | Caceres (Spain) |  | 57.2 |  | (3 | )
Evacuación Villanueva del Rey, S.L. |  |  |  | Seville (Spain) |  | 40.0 |  | (3 | )
Fontanil Solar S.L. |  |  |  | Albacete (Spain) |  | 25.0 |  | (3 | )
Geida Tlemcen S.L. |  | Honaine |  | Madrid (Spain) |  | 50.0 |  | (4 | )
Liberty Infraestructuras, S.L. |  |  |  | Seville (Spain) |  | 20.0 |  | (3 | )
Murum Solar, S.L. |  |  |  | Murcia (Spain) |  | 25.0 |  | (3 | )
PA Renovables Sol 1 S.A.S. |  |  |  | Bogota D.C. (Colombia) |  | 50.0 |  | (3 | )
Pectonex R.F. |  |  |  | Pretoria (South Africa) |  | 50.0 |  | (3 | )
SJ Renovables Sun 1 S.A.S. |  |  |  | Bogota D.C. (Colombia) |  | 50.0 |  | (3 | )
SJ Renovables Wind 1 S.A.S. |  |  |  | Bogota D.C. (Colombia) |  | 50.0 |  | (3 | )
2007 Vento II, LLC. |  | Vento II |  | Delaware (United States) |  | 49.0 |  | (3 | )

(1) | Business sector: Transmission lines

(2) | Business sector: Efficient natural gas and heat

(3) | Business sector: Renewable energy

(4) | Business sector: Water

(5) | Holding Company

The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
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Investments recorded under the equity method as of December 31, 2022

Company name |  | Project name |  | Registered address |  | % of interest |  | Business |
Akuo Atlantica PMGD Holding |  | Chile PMGD |  | Santiago de Chile (Chile) |  | 49.0 |  | (3 | )
Amherst Island Partnership |  | Windlectric |  | Ontario (Canada) |  | 30.0 |  | (3 | )
Arroyo Energy Netherlands II B.V. |  | Monterrey |  | Amsterdam (Netherlands) |  | 30.0 |  | (2 | )
Evacuacion Valdecaballeros, S.L. |  |  |  | Caceres (Spain) |  | 57.2 |  | (3 | )
Evacuación Villanueva del Rey, S.L. |  |  |  | Seville (Spain) |  | 40.0 |  | (3 | )
Fontanil Solar S.L. |  |  |  | Albacete (Spain) |  | 25.0 |  | (3 | )
Geida Tlemcen S.L. |  | Honaine |  | Madrid (Spain) |  | 50.0 |  | (4 | )
Liberty Infraestructuras, S.L. |  |  |  | Seville (Spain) |  | 20.0 |  | (3 | )
Murum Solar, S.L. |  |  |  | Murcia (Spain) |  | 25.0 |  | (3 | )
Pectonex R.F. |  |  |  | Pretoria (South Africa) |  | 50.0 |  | (3 | )
2007 Vento II, LLC. |  | Vento II |  | Delaware (United States) |  | 49.0 |  | (3 | )

(1) | Business sector: Transmission lines

(2) | Business sector: Efficient natural gas and heat

(3) | Business sector: Renewable energy

(4) | Business sector: Water

(5) | Holding Company

The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
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Appendices | Appendix III-1

Assets subject to the application of IFRIC 12 interpretation based on the concession of
services as of December 31, 2023 and 2022
Description of the Arrangements
Solana
Solana is a 250 MW net (280 MW gross) solar electric generation facility located in Maricopa County, Arizona, approximately 70 miles southwest of Phoenix. Arizona Solar One LLC, or Arizona Solar, owns the Solana project. Solana includes a 22-mile 230kV transmission line and a molten salt thermal energy storage system. Solana reached COD on October 9, 2013.
Solana has a 30-year, PPA with Arizona Public Service, or APS, approved by the Arizona Corporation Commission (ACC). The PPA provides for the sale of electricity at a fixed price per MWh with annual increases of 1.84% per year. The PPA includes limitations on the amount and condition of the energy that is received by APS with minimum and maximum thresholds for delivery capacity that must not be breached.
Mojave
Mojave is a 250 MW net (280 MW gross) solar electric generation facility located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Mojave reached COD on December 1, 2014.
Mojave has a 25-year, PPA with Pacific Gas & Electric Company, or PG&E, approved by the California Public Utilities Commission (CPUC). The PPA provides for the sale of electricity at a fixed base price per MWh without any indexation mechanism, including limitations on the amount and condition of the energy that is received by PG&E with minimum and maximum thresholds for delivery capacity that must not be breached.
Palmatir
Palmatir is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Palmatir has 25 wind turbines and each turbine has a nominal capacity of 2 MW. UTE, Uruguay’s state-owned electricity company, has agreed to purchase all energy produced by Palmatir pursuant to a 20-year PPA. UTE pays a fixed-price tariff per MWh under the PPA, which is denominated in U.S. dollars and is partially adjusted in January of each year according to a formula based on inflation.
Palmatir reached COD in May 2014.
Cadonal
Cadonal is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Cadonal has 25 wind turbines and each turbine has a nominal capacity of 2 MW each. UTE, Uruguay´s state-owned electricity company, has agreed to purchase all energy produced by Cadonal pursuant to a 20-year PPA.
Cadonal reached COD in December 2014.
Melowind
Melowind is an on-shore wind farm facility wholly owned by the Company, located in Uruguay with a capacity of 50 MW. Melowind has 20 wind turbines of 2.5 MW each. The asset reached COD in November 2015.
Melowind signed a 20-year PPA with UTE in 2015, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted every year based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollars exchange rate.
Solaben 2 & Solaben 3
The Solaben 2 and Solaben 3 are two 50 MW Solar Power facilities and reached COD in 2012. Itochu Corporation holds 30% of Solaben 2 & Solaben 3.
Renewable energy plants in Spain, like Solaben 2 and Solaben 3, are regulated through a series of laws and rulings which guarantee the owners of the plants a reasonable return for their investments. Solaben 2 and Solaben 3 sell the power they produce into the wholesale electricity market, where offer and demand are matched and the pool price is determined, and also receive additional payments from the CNMC, the Spanish state-owned regulator.
Solacor 1 & Solacor 2
The Solacor 1 and Solacor 2 are two 50 MW Solar Power facilities and reached COD in 2012. JGC Corporation holds 13% of Solacor 1 & Solacor 2.
Solnova 1, 3 & 4
The Solnova 1, 3 and 4 solar plants are located in the municipality of Sanlucar la Mayor, Spain. The plants have 50 MW each and reached COD in 2010.
Helios 1 & 2
The Helios 1 and 2 solar plants are located in Ciudad Real, Spain, and reached COD in 2012. The plants have 50 MW each.
Helioenergy 1 & 2
The Helioenergy 1 and 2 solar plants are located in Ecija, Spain, and reached COD in 2011. The plants have 50 MW each.
Solaben 1 & 6
The Solaben 1&6 are two 50 MW solar plants located in the municipality of Logrosán, Spain and reached COD in 2013.
Kaxu
Kaxu Solar One, or Kaxu, is a 100 MW solar Conventional Parabolic Trough Project located in Paulputs in the Northern Cape Province of South Africa. Atlantica owns 51% of the Kaxu Project, while Industrial Development Corporation of South Africa owns 29% and Kaxu Community Trust owns 20%.
The project reached COD in February 2015.
Kaxu has a 20-year PPA with Eskom SOC Ltd., or Eskom, under a take or pay contract for the purchase of electricity up to the contracted capacity from the facility. Eskom purchases all the output of the Kaxu plant under a fixed price formula in local currency subject to indexation to local inflation. The PPA expires in February 2035.
ACT
The ACT plant is a gas-fired cogeneration facility with a rated capacity of approximately 300 MW and between 550 and 800 metric tons per hour of steam. The plant includes a substation and an approximately 52 mile and 115-kilowatt transmission line.
On September 18, 2009, ACT entered into the Pemex Conversion Services Agreement, or the Pemex CSA, with Pemex. Pemex is a state-owned oil and gas company supervised by the (CRE), the Mexican state agency that regulates the energy industry. The Pemex CSA has a term of 20 years from the in-service date and will expire on March 31, 2033.
According to the Pemex CSA, ACT must provide, in exchange for a fixed price with escalation adjustments, services including the supply and transformation of natural gas and water into thermal energy and electricity. Part of the electricity is to be supplied directly to a Pemex facility nearby, allowing the (CFE) to supply less electricity to that facility. Approximately 90% of the electricity must be injected into the Mexican electricity network to be used by retail and industrial end customers of CFE in the region. Pemex is then entitled to receive an equivalent amount of energy in more than 1,000 of their facilities in other parts of the country from CFE, following an adjustment mechanism under the supervision of CFE.
The Pemex CSA is denominated in U.S. dollars. The price is a fixed tariff and is adjusted annually, part of it according to inflation and part according to a mechanism agreed in the contract that on average over the life of the contract reflects expected inflation. The components of the price structure and yearly adjustment mechanisms were prepared by Pemex and provided to bidders as part of the request for proposal documents.
ATS
ATS is a 569 miles transmission line located in Peru wholly owned by the Company. ATS is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATS reached COD in 2014. In July 2023, the Company started construction of ATS Expansion 1 project, consisting in the reinforcement of two existing substation with new equipment. The expansion will be part of the existing concession contract and is expected to enter in operation in 2025.
Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATS a concession to construct, develop, own, operate and maintain the ATS Project. The initial concession agreement became effective on July 22, 2010 and will expire 30 years after COD, which took place in January 2014. ATS is obliged to provide the service of transmission of electric energy through the operation and maintenance of the electric transmission line, according to the terms of the contract and the applicable law.
The laws and regulations of Peru establish the key parameters of the concession contract, the price indexation mechanism, the rights and obligations of the operator and the procedure that have to be followed in order to fix the applicable tariff, which occurs through a regulated bidding process. Once the bidding process is complete and the operator is granted the concession, the pricing of the power transmission service is established in the concession agreement. ATS has a 30-year concession agreement with fixed-price tariff base denominated in U.S. dollars that is adjusted annually after COD of each line, in accordance with the U.S. Finished Goods Less Food and Energy Index published by the U.S. Department of Labor.
ATN
ATN is a 365 miles transmission line located in Peru wholly owned by the Company, 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 its line to the Shahuindo (ATN expansion 1) mine located nearby. In October 2019, the Company also closed the acquisition of ATN Expansion 2. In July 2022 the Company closed a transmission service agreement that allows to build a substation and a 2.4-miles transmission line connected to ATN transmission line serving a new mine in Peru (ATN Expansion 3), which is expected to enter in operation in 2024.
Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATN a concession to construct, develop, own, operate and maintain the ATN Project. The initial concession agreement became effective on May 22, 2008 and will expire 30 years after COD of the first tranche of the line, which took place in January 2011. ATN is obliged to provide the service of transmission of electric energy through the operation and maintenance of the electric transmission line, according to the terms of the contract and the applicable law.
The laws and regulations of Peru establish the key parameters of the concession contract, the price indexation mechanism, the rights and obligations of the operator and the procedures that have to be followed in order to fix the applicable tariff, which occurs through a regulated bidding process. Once the bidding process is complete and the operator is granted the concession, the pricing of the power transmission service is established in the concession agreement. ATN has a 30-year concession agreement with a fixed-price tariff base denominated in U.S. dollars that is adjusted annually after COD of each line, in accordance with the U.S. Finished Goods Less Food and Energy Index published by the U.S. Department of Labor. In addition, both ATN Expansion 1 and ATN Expansion 2 have 20-year PPAs denominated in U.S. dollars. ATN Expansion 3 has a 17-year transmission service agreement denominated in U.S. dollars.
ATN 2
ATN 2, is an 81 miles transmission line located in Peru wholly owned by the Company, which is part of the Complementary Transmission System. ATN 2 reached COD in June 2015.
The Client is Las Bambas Mining Company.
The ATN 2 Project has a 18-year contract period, after that, ATN 2 assets will remain as property of the SPV allowing ATN 2 to potentially sign a new contract. The ATN 2 Project has a fixed-price tariff base denominated in U.S. dollars, partially adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. The receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to the ATN 2 Project. The tariff base is intended to provide the ATN 2 Project with consistent and predictable monthly revenues sufficient to cover the ATN 2 Project’s operating costs and debt service and to earn an equity return. Peruvian law requires the existence of a definitive concession agreement to perform electricity transmission activities where the transmission facilities cross public land or land owned by third parties. On May 31, 2014, the Ministry of Energy granted the project a definitive concession agreement to the transmission lines of the ATN 2 Project.
Quadra 1 & Quadra 2
Quadra 1 is a 49-miles transmission line project and Quadra 2 is a 32-miles transmission line project, each connected to the Sierra Gorda substations.
Both projects have concession agreements with Sierra Gorda SCM. The agreements are denominated in U.S. dollars and are indexed mainly to CPI. The concession agreements each have a 21-year term that began on COD, which took place in April 2014 and March 2014 for Quadra 1 and Quadra 2, respectively.
Quadra 1 and Quadra 2 belong to the Northern Interconnected System (SING), one of the two interconnected systems into which the Chilean electricity market is divided and structured for both technical and regulatory purposes.
As part of the SING, Quadra 1 and Quadra 2 and the service they provide are regulated by several regulatory bodies, in particular: the Superintendent’s office of Electricity and Fuels (SEC), the Economic Local Dispatch Center (CDEC), the National Board of Energy (CNE) and the National Environmental Board (CONAMA) and other environmental regulatory bodies.
In all these concession arrangements, the operator has all the rights necessary to manage, operate and maintain the assets and the obligation to provide the services defined above, which are clearly defined in each concession contract and in the applicable regulations in each country.
Skikda
The Skikda project is a water desalination plant located in Skikda, Algeria. AEC owns 49% and Sacyr Agua S.L. owns indirectly the remaining 16.83% of the Skikda project.
Skikda has a capacity of 3.5 M ft3 per day of desalinated water and is in operation since February 2009. The project serves a population of 0.5 million.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach / Algerienne des Eaux (“ADE”). The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
Honaine
The Honaine project is a water desalination plant located in Taffsout, Algeria. Myah Bahr Honaine Spa, or MBH, is the vehicle incorporated in Algeria for the purposes of owning the Honaine project. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua S.L., a subsidiary of Sacyr, S.A., owns indirectly the remaining 25.5% of the Honaine project.
Honaine has a capacity of 7 M ft3 per day of desalinated water and it is under operation since July 2012.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach / ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
Tenes
Tenes is a water desalination plant located in Algeria. Befesa Agua Tenes has a 51% stake in Ténès Lilmiyah SpA. The remaining 49% is owned by AEC.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the exchange rate between the U.S. dollar and local currency and yearly based on indexation mechanisms that include local inflation and U.S. inflation.
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Appendices | Appendix III-2

Assets subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2023

Project name | Country | Status(1) |  | % of Nominal Share(2) |  | Period of Concession (4)(5) | off-taker(7) | Financial/ Intangible(3) |  | Assets/ Investment |  |  | Accumulated Amortization |  |  | Operating Profit/ (Loss)(8) |  | Arrangement Terms (price) | Description of the Arrangement
Renewable energy: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Solana | USA | (O) |  |  | 100.0 |  | 30 Years | APS | (I) |  |  | 1,904,464 |  |  |  | (718,410 | ) |  |  | 32,723 |  | Fixed price per MWh with annual increases of 1.84% per year | 30-year PPA with APS regulated by ACC
Mojave | USA | (O) |  |  | 100.0 |  | 25 Years | PG&E | (I) |  |  | 1,581,518 |  |  |  | (559,300 | ) |  |  | 50,164 |  | Fixed price per MWh without any indexation mechanism | 25-year PPA with PG&E regulated by CPUC and CAEC
Palmatir | Uruguay | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 147,934 |  |  |  | (71,074 | ) |  |  | 5,454 |  | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility
Cadonal | Uruguay | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 122,013 |  |  |  | (55,724 | ) |  |  | 3,272 |  | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility
Melowind | Uruguay | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 136,089 |  |  |  | (51,197 | ) |  |  | 5,141 |  | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility
Solaben 2 | Spain | (O) |  |  | 70.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 307,766 |  |  |  | (114,598 | ) |  |  | 5,534 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solaben 3 | Spain | (O) |  |  | 70.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 306,228 |  |  |  | (115,252 | ) |  |  | 5,555 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solacor 1 | Spain | (O) |  |  | 87.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 310,841 |  |  |  | (122,549 | ) |  |  | 3,970 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solacor 2 | Spain | (O) |  |  | 87.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 324,096 |  |  |  | (126,518 | ) |  |  | 3,028 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solnova 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 310,660 |  |  |  | (142,585 | ) |  |  | 6,267 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solnova 3 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 290,380 |  |  |  | (129,102 | ) |  |  | 7,914 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solnova 4 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 271,494 |  |  |  | (120,218 | ) |  |  | 8,141 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Helios 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 315,215 |  |  |  | (118,604 | ) |  |  | 3,645 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Helios 2 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 307,195 |  |  |  | (113,976 | ) |  |  | 3,417 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Helioenergy 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 300,569 |  |  |  | (117,465 | ) |  |  | 7,826 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Helioenergy 2 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 301,317 |  |  |  | (115,295 | ) |  |  | 7,556 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solaben 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 305,396 |  |  |  | (104,265 | ) |  |  | 6,581 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solaben 6 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 302,681 |  |  |  | (103,057 | ) |  |  | 6,984 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Kaxu | South Africa | (O) |  |  | 51.0 |  | 20 Years | Eskom | (I) |  |  | 464,692 |  |  |  | (188,089 | ) |  |  | 23,414 |  | Take or pay contract for the purchase of electricity up to the contracted capacity from the facility. | 20-year PPA with Eskom SOC Ltd. With a fixed price formula in local currency subject to indexation to local inflation
Efficient natural gas &heat: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ACT | Mexico | (O) |  |  | 100.0 |  | 20 Years | Pemex | (F) |  |  | 477,650 |  |  |  | - |  |  |  | 98,468 |  | Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract | 20-year Services Agreement with Pemex, Mexican oil & gas state-owned company
Transmission lines: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ATS | Peru | (O) |  |  | 100.0 |  | 30 Years | Republic of Peru | (I) |  |  | 534,332 |  |  |  | (175,380 | ) |  |  | 34,602 |  | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | 30-year Concession Agreement with the Peruvian Government
ATN | Peru | (O) |  |  | 100.0 |  | 30 Years | Republic of Peru | (I) |  |  | 366,654 |  |  |  | (142,906 | ) |  |  | 13,186 |  | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | 30-year Concession Agreement with the Peruvian Government
ATN 2 | Peru | (O) |  |  | 100.0 |  | 18 Years | Las Bambas Mining | (F) |  |  | 74,423 |  |  |  | - |  |  |  | 11,957 |  | Fixed-price tariff base denominated in U.S. dollars with Las Bambas | 18 years purchase agreement
Quadra I | Chile | (O) |  |  | 100.0 |  | 21 Years | Sierra Gorda | (F) |  |  | 35,852 |  |  |  | - |  |  |  | 7,255 |  | Fixed price in USD with annual adjustments indexed mainly to US CPI | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superintendencia de Electricidad, among others
Quadra II | Chile | (O) |  |  | 100.0 |  | 21 Years | Sierra Gorda | (F) |  |  | 49,483 |  |  |  | - |  |  |  | 6,258 |  | Fixed price in USD with annual adjustments indexed mainly to US CPI | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superintendencia de Electricidad, among others
Water: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Skikda | Algeria | (O) |  |  | 34.2 |  | 25 Years | Sonatrach & ADE | (F) |  |  | 73,581 |  |  |  | - |  |  |  | 11,533 |  | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | 25 years purchase agreement
Honaine | Algeria | (O) |  |  | 25.5 |  | 25 Years | Sonatrach & ADE | (F) |  |  | N/A | (9) |  |  | N/A | (9) |  |  | N/A | (9) | U.S. dollar indexed take- or-pay contract with Sonatrach / ADE | 25 years purchase agreement
Tenes | Algeria | (O) |  |  | 51.0 |  | 25 Years | Sonatrach & ADE | (F) |  |  | 101,144 |  |  |  | - |  |  |  | 17,462 |  | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | 25 years purchase agreement

(1) | In operation (O), Construction (C) as of December 31, 2023.

(2) | Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3. JGC Corporation holds 13% of the economic rights to each Solacor 1 and Solacor 2. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua, S.L., a subsidiary of Sacyr, S.A., owns the remaining 25.5% of the Honaine project. AEC owns 49% and Sacyr Agua S.L. owns the remaining 16.83% of the Skikda project. Industrial Development Corporation of South Africa (29%) & Kaxu Community Trust (20%) for the Kaxu Project. AEC owns 49% of the Tenes project.

(3) | Classified as concessional financial asset (F) or as intangible assets (I).

(4) | The infrastructure is used for its entire useful life. There are no obligations to deliver assets at the end of the concession periods, except for ATN and ATS.

(5) | Generally, there are no termination provisions other than customary clauses for situations such as bankruptcy or fraud from the operator, for example.

(6) | Sales to wholesale markets and additional fixed payments established by the Spanish government.

(7) | In each case the off-taker is the grantor.

(8) | Figures reflect the contribution to the Consolidated Financial Statements of Atlantica Sustainable Infrastructure plc. as of December 31, 2023.

(9) | Recorded under the equity method.

The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
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Assets subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 2022

Project name | Country | Status(1) |  | % of Nominal Share(2) |  | Period of Concession (4)(5) | off-taker(7) | Financial/ Intangible(3) |  | Assets/ Investment |  |  | Accumulated Amortization |  |  | Operating Profit/ (Loss)(8) |  | Arrangement Terms (price) | Description of the Arrangement
Renewable energy: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Solana | USA | (O) |  |  | 100.0 |  | 30 Years | APS | (I) |  |  | 1,887,669 |  |  |  | (664,681 | ) |  |  | (25,082 | ) | Fixed price per MWh with annual increases of 1.84% per year | 30-year PPA with APS regulated by ACC
Mojave | USA | (O) |  |  | 100.0 |  | 25 Years | PG&E | (I) |  |  | 1,573,621 |  |  |  | (497,072 | ) |  |  | 45,193 |  | Fixed price per MWh without any indexation mechanism | 25-year PPA with PG&E regulated by CPUC and CAEC
Palmatir | Uruguay | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 147,937 |  |  |  | (63,692 | ) |  |  | 4,021 |  | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility
Cadonal | Uruguay | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 122,012 |  |  |  | (49,616 | ) |  |  | 3,680 |  | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility
Melowind | Uruguay | (O) |  |  | 100.0 |  | 20 Years | UTE, Uruguay Administration | (I) |  |  | 136,053 |  |  |  | (43,988 | ) |  |  | 3,567 |  | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility
Solaben 2 | Spain | (O) |  |  | 70.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 298,791 |  |  |  | (97,618 | ) |  |  | 6,163 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solaben 3 | Spain | (O) |  |  | 70.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 297,865 |  |  |  | (98,526 | ) |  |  | 6,319 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solacor 1 | Spain | (O) |  |  | 87.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 299,306 |  |  |  | (105,031 | ) |  |  | 5,275 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solacor 2 | Spain | (O) |  |  | 87.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 311,671 |  |  |  | (108,306 | ) |  |  | 5,698 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solnova 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 301,041 |  |  |  | (123,894 | ) |  |  | 7,509 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solnova 3 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 281,557 |  |  |  | (112,213 | ) |  |  | 7,027 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solnova 4 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 263,079 |  |  |  | (104,282 | ) |  |  | 7,694 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Helios 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 304,015 |  |  |  | (101,255 | ) |  |  | 5,201 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Helios 2 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 296,267 |  |  |  | (97,167 | ) |  |  | 4,508 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Helioenergy 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 291,454 |  |  |  | (101,428 | ) |  |  | 8,032 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Helioenergy 2 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 292,225 |  |  |  | (99,126 | ) |  |  | 8,149 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solaben 1 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 293,721 |  |  |  | (99,126 | ) |  |  | 6,453 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Solaben 6 | Spain | (O) |  |  | 100.0 |  | 25 Years | Kingdom of Spain | (I) |  |  | 290,745 |  |  |  | (86,822 | ) |  |  | 7,110 |  | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain
Kaxu | South Africa | (O) |  |  | 51.0 |  | 20 Years | Eskom | (I) |  |  | 455,517 |  |  |  | (179,417 | ) |  |  | 44,487 |  | Take or pay contract for the purchase of electricity up to the contracted capacity from the facility. | 20-year PPA with Eskom SOC Ltd. With a fixed price formula in local currency subject to indexation to local inflation

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Efficient natural gas &heat: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ACT | Mexico | (O) |  |  | 100.0 |  | 20 Years | Pemex | (F) |  |  | 512,796 |  |  |  | - |  |  |  | 80,731 |  | Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract | 20-year Services Agreement with Pemex, Mexican oil & gas state-owned company
Transmission lines: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
ATS | Peru | (O) |  |  | 100.0 |  | 30 Years | Republic of Peru | (I) |  |  | 532,859 |  |  |  | (157,573 | ) |  |  | 31,351 |  | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | 30-year Concession Agreement with the Peruvian Government
ATN | Peru | (O) |  |  | 100.0 |  | 30 Years | Republic of Peru | (I) |  |  | 360,412 |  |  |  | (130,364 | ) |  |  | 10,988 |  | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | 30-year Concession Agreement with the Peruvian Government
ATN 2 | Peru | (O) |  |  | 100.0 |  | 18 Years | Las Bambas Mining | (F) |  |  | 71,966 |  |  |  | - |  |  |  | 10,673 |  | Fixed-price tariff base denominated in U.S. dollars with Las Bambas | 18 years purchase agreement
Quadra I | Chile | (O) |  |  | 100.0 |  | 21 Years | Sierra Gorda | (F) |  |  | 37,423 |  |  |  | - |  |  |  | 5,847 |  | Fixed price in USD with annual adjustments indexed mainly to US CPI | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superintendencia de Electricidad, among others
Quadra II | Chile | (O) |  |  | 100.0 |  | 21 Years | Sierra Gorda | (F) |  |  | 51,552 |  |  |  | - |  |  |  | 4,845 |  | Fixed price in USD with annual adjustments indexed mainly to US CPI | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superintendencia de Electricidad, among others

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Water: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Skikda | Algeria | (O) |  |  | 34.2 |  | 25 Years | Sonatrach & ADE | (F) |  |  | 71,007 |  |  |  | - |  |  |  | 13,121 |  | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | 25 years purchase agreement
Honaine | Algeria | (O) |  |  | 25.5 |  | 25 Years | Sonatrach & ADE | (F) |  |  | N/A | (9) |  |  | N/A | (9) |  |  | N/A | (9) | U.S. dollar indexed take- or-pay contract with Sonatrach / ADE | 25 years purchase agreement
Tenes | Algeria | (O) |  |  | 51.0 |  | 25 Years | Sonatrach & ADE | (F) |  |  | 98,962 |  |  |  | - |  |  |  | 14,637 |  | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | 25 years purchase agreement

(1) | In operation (O), Construction (C) as of December 31, 2022.

(2) | Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3. JGC Corporation holds 13% of the economic rights to each Solacor 1 and Solacor 2. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua, S.L., a subsidiary of Sacyr, S.A., owns the remaining 25.5% of the Honaine project. AEC owns 49% and Sacyr Agua S.L. owns the remaining 16.83% of the Skikda project. Industrial Development Corporation of South Africa (29%) & Kaxu Community Trust (20%) for the Kaxu Project. AEC owns 49% of the Tenes project.

(3) | Classified as concessional financial asset (F) or as intangible assets (I).

(4) | The infrastructure is used for its entire useful life. There are no obligations to deliver assets at the end of the concession periods, except for ATN and ATS.

(5) | Generally, there are no termination provisions other than customary clauses for situations such as bankruptcy or fraud from the operator, for example.

(6) | Sales to wholesale markets and additional fixed payments established by the Spanish government.

(7) | In each case the off-taker is the grantor.

(8) | Figures reflect the contribution to the Consolidated Financial Statements of Atlantica Sustainable Infrastructure plc. as of December 31, 2022.

(9) | Recorded under the equity method.

The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
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Appendices | Appendix IV

Additional information of subsidiaries including material non-controlling interest as of December 31, 2023

Subsidiary name | Non- controlling interest name |  | % of non- controlling interest held |  |  | Distributions paid to non- controlling interest |  |  | Profit/(Loss) of non- controlling interest in Atlantica consolidated net result 2023 |  |  | Non- controlling interest in Atlantica consolidated equity as of December 31, 2023 |  |  | Non- current assets* |  |  | Current Assets* |  |  | Non- current liabilities* |  |  | Current liabilities* |  |  | Net Profit /(Loss)* |  |  | Total Comprehensive income* |
Aguas de Skikda S.P.A. | Algerian Energy Company S.P.A. |  |  | 49 | %** |  |  | 3,072 |  |  |  | 6,164 |  |  |  | 51,145 |  |  |  | 71,400 |  |  |  | 27,290 |  |  |  | 10,151 |  |  |  | 4,325 |  |  |  | 9,363 |  |  |  | - |
Chile PV 3 | Financial partners |  |  | 65 | % |  |  | - |  |  |  | (2,189 | ) |  |  | 30,526 |  |  |  | 31,371 |  |  |  | 30,374 |  |  |  | 11,791 |  |  |  | 1,273 |  |  |  | (3,368 | ) |  |  | - |
Solaben Electricidad Dos S.A. | Itochu Europe Plc |  |  | 30 | % |  |  | 3,684 |  |  |  | (202 | ) |  |  | 20,580 |  |  |  | 192,089 |  |  |  | 9,989 |  |  |  | 125,455 |  |  |  | 8,957 |  |  |  | (992 | ) |  |  | (6,412 | )
Solaben Electricidad Tres S.A. | Itochu Europe Plc |  |  | 30 | % |  |  | 3,259 |  |  |  | (245 | ) |  |  | 20,261 |  |  |  | 191,585 |  |  |  | 10,059 |  |  |  | 125,165 |  |  |  | 9,679 |  |  |  | (1,133 | ) |  |  | (6,378 | )
Ténès Lilmiyah SPA | Algerian Energy Company S.P.A. |  |  | 49 | % |  |  | 3,581 |  |  |  | 7,123 |  |  |  | 29,963 |  |  |  | 97,105 |  |  |  | 41,208 |  |  |  | 66,175 |  |  |  | 10,989 |  |  |  | 14,701 |  |  |  | - |

* Stand-alone figures as of December 31, 2023.
** Atlantica Sustainable Infrastructure plc. owns 67% of the shares in Geida Skikda, S.L., which in its turn owns 51% of Aguas de Skikda S.P.A., so that indirectly Atlantica Sustainable Infrastructure plc. owns 34.17% of Aguas de Skikda S.P.A. The table only shows information related to the non-controlling interest of the SPV, Aguas de Skikda S.P.A.
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Appendices | Appendix IV

Additional information of subsidiaries including material non-controlling interest as of December 31, 2022

Subsidiary name | Non- controlling interest name |  | % of non- controlling interest held |  | Distributions paid to non- controlling interest |  |  | Profit/(Loss) of non- controlling interest in Atlantica consolidated net result 2022 |  |  | Non- controlling interest in Atlantica consolidated equity as of December 31, 2022 |  |  | Non- current assets* |  |  | Current Assets* |  |  | Non- current liabilities* |  |  | Current liabilities* |  |  | Net Profit /(Loss)* |  |  | Total Comprehensive income* |
Aguas de Skikda S.P.A. | Algerian Energy Company S.P.A. |  |  | 49 | %** |  | 2,849 |  |  |  | 7,060 |  |  |  | 47,509 |  |  |  | 68,655 |  |  |  | 29,293 |  |  |  | 12,470 |  |  |  | 6,788 |  |  |  | 10,725 |  |  |  | - |
Solaben Electricidad Dos S.A. | Itochu Europe Plc |  |  | 30 | % |  | 1,913 |  |  |  | 402 |  |  |  | 25,271 |  |  |  | 201,060 |  |  |  | 12,730 |  |  |  | 115,109 |  |  |  | 14,857 |  |  |  | 1,158 |  |  |  | (1,428 | )
Solaben Electricidad Tres S.A. | Itochu Europe Plc |  |  | 30 | % |  | 1,397 |  |  |  | 370 |  |  |  | 24,522 |  |  |  | 201,088 |  |  |  | 13,814 |  |  |  | 117,948 |  |  |  | 15,495 |  |  |  | 1,051 |  |  |  | (1,642 | )
Ténès Lilmiyah SPA | Algerian Energy Company S.P.A. |  |  | 49 | % |  | 2,260 |  |  |  | 5,675 |  |  |  | 25,592 |  |  |  | 94,989 |  |  |  | 40,884 |  |  |  | 72,279 |  |  |  | 11,365 |  |  |  | 11,581 |  |  |  | - |

* Stand-alone figures as of December 31, 2022.
** Atlantica Sustainable Infrastructure plc. owns 67% of the shares in Geida Skikda, S.L., which in its turn owns 51% of Aguas de Skikda S.P.A., so that indirectly Atlantica Sustainable Infrastructure plc. owns 34.17% of Aguas de Skikda S.P.A. The table only shows information related to the non-controlling interest of the SPV, Aguas de Skikda S.P.A.
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