☐

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

☒

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

☐

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

☐

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

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

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

U.S. GAAP ☐

International Financial Reporting Standards as issued by the International Accounting Standards Board ☒

Other ☐

		Page
CURRENCY PRESENTATION AND DEFINITIONS		7
PRESENTATION OF FINANCIAL INFORMATION		11
PRESENTATION OF INDUSTRY AND MARKET DATA		13
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	14
D.	Risk Factors	14
ITEM 4.	INFORMATION ON THE COMPANY	50
A.	History and Development of the Company	50
B.	Business Overview	50
C.	Organizational Structure	97
D.	Property, Plant and Equipment	99
ITEM 4A.	UNRESOLVED STAFF COMMENTS	99
ITEM 5.	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	100
A.	Operating Results	100
B.	Liquidity and Capital Resources	119
C.	Research and Development	127
D.	Trend Information	127
E.	Critical Accounting Estimates	127
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	136
A.	Directors and Senior Management	136
B.	Compensation	141
C.	Board Practices	157
D.	Employees	159
E.	Share Ownership	159
F.	Disclosure of a Registrant’s Action to Recover Erroneously Awarded Compensation	160
ITEM 7.	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	160
A.	Major Shareholders	160
B.	Related Party Transactions	161
C.	Interests of Experts and Counsel	164
ITEM 8.	FINANCIAL INFORMATION	164
A.	Consolidated Statements and Other Financial Information.	164
B.	Significant Changes	167
ITEM 9.	THE OFFER AND LISTING	167
A.	Offering and Listing Details.	167
B.	Plan of Distribution	167
C.	Markets	167
D.	Selling Shareholders	167
E.	Dilution	167
F.	Expenses of the Issue	167
ITEM 10.	ADDITIONAL INFORMATION	167
A.	Share Capital	167
B.	Memorandum and Articles of Association	168
C.	Material Contracts	168
D.	Exchange Controls	168
E.	Taxation	168
F.	Dividends and Paying Agents	174

G.	Statement by Experts	174
H.	Documents on Display	174
I.	Subsidiaries Information	174
ITEM 11.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	174
ITEM 12.	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	178
A.	Debt Securities	178
B.	Warrants and Rights	178
C.	Other Securities	178
D.	American Depositary Shares	178
ITEM 13.	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	179
ITEM 14.	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	179
ITEM 15.	CONTROLS AND PROCEDURES	179
ITEM 16.	RESERVED	180
ITEM 16A.	AUDIT COMMITTEE FINANCIAL EXPERT	180
ITEM 16B.	CODE OF ETHICS	180
ITEM 16C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	180
ITEM 16D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	182
ITEM 16E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	183
ITEM 16F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	183
ITEM 16G.	CORPORATE GOVERNANCE	183
ITEM 16H.	MINE SAFETY DISCLOSURE	183
ITEM 16I.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	183
ITEM 17.	FINANCIAL STATEMENTS	184
ITEM 18.	FINANCIAL STATEMENTS	184
ITEM 19.	EXHIBITS	184

•

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;

•	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;

•	potential regulatory changes in Spain in relation to the proposed remuneration parameters for the year 2023 to be applicable to our solar assets in Spain published on December 28, 2022 in draft form and which are subject to final publication;

•	changes in tax laws and regulations, including new taxes recently announced in Italy, Spain and the U.K.;

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

•	global recession risks, volatility in the financial markets, a persistent 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;

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

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

•	risks related to our reliance on third-party contractors or suppliers, including issues with our O&M suppliers and their employees, among others, resulting from disagreements with subcontractors;

•	risks related to disagreements and disputes with our employees, a union and employees represented by a union;

•	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;

•	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;

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

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

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

•	risks related to Russian military actions in Ukraine and across global geopolitical tensions; and

•	other factors discussed under “Risk Factors”.

•

references to “2020 Green Private Placement” refer to the €290 million (approximately $310 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, 2022 and 2021 and for the years ended December 31, 2022, 2021 and 2020, including the related notes thereto, prepared in accordance with IFRS as issued by the IASB (as such terms are defined herein), included in this annual report;

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

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

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

•

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

•	references to “ATN” refer to ATN S.A., the operational 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;

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

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

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

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

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

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

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

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

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

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

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

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

•	references to “Coso” refer to the 135 MW geothermal plant located in California;

•

references to the “Distribution Agreement” refer to the agreement entered into with 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”;

•

references to “Green Project Finance” refer to the green project financing agreement entered into between Logrosan, the sub-holding company of Solaben 1 & 6 and Solaben 2 & 3, as borrower, and ING Bank, B.V. and Banco Santander S.A., as lenders, as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements —Green Project Finance”;

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

•

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

•	references to “GWh” refer to gigawatt hour;

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

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

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

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

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

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

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

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

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

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

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

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

•	references to “MW” refer to megawatts;

•	references to “MWh” refer to megawatt hour;

•	references to “MWt” refer to thermal megawatts;

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

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

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

•

references to “Note Issuance Facility 2019” refer to the senior unsecured note facility dated April 30, 2019, as amended on May 14, 2019, October 23, 2020 and March 30, 2021 for a total amount of €268 million, (approximately $287 million), with Lucid Agency Services Limited, as facility agent and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder which was fully repaid on June 4, 2021;

•

references to “Note Issuance Facility 2020” refer to the senior unsecured note facility dated July 8, 2020, as amended on March 30, 2021 of €140 million (approximately $150 million), with Lucid Agency Services Limited, as facility agent and a group of funds managed by Westbourne Capital, as purchasers of the notes issued thereunder;

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

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

•	references to “Pemex” refer to Petróleos Mexicanos;

•	references to “PFIC” refer to passive foreign investment company within the meaning of Section 1297 of the 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 and May 5, 2022 providing for a senior secured revolving credit facility in an aggregate principal amount of $450 million;

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

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

•	references to “ROFO Agreements” refer to the Liberty GES ROFO Agreement and Algonquin ROFO Agreement;

•

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

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

•	references to “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.;

•	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.

•	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.

ITEM 1.

IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

ITEM 2.

OFFER STATISTICS AND EXPECTED TIMETABLE

ITEM 3

KEY INFORMATION

A.	[RESERVED]

B.	Capitalization and Indebtedness

C.	Reasons for the Offer and Use of Proceeds

D.	Risk Factors

•	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.

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

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

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

•	Certain of our facilities may not perform as expected.

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

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

•

The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, 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 insurance may be insufficient to cover relevant risks or the cost of our insurance may increase.

•	The COVID-19 pandemic or any other 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.

•	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.

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

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

•	By virtue of initiating a bankruptcy filing under the Spanish Insolvency Act, Abengoa may be subject to insolvency claw-back actions in which transactions may be set aside.

•

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 refinancing of the Company’s project level and corporate level indebtedness.

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

•	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 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.

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

•	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.

•	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.

•	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.

I.	Risks Related to Our Business and Our Assets

•

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.

-

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. Also, natural gas assets could trip offline due to operational issues caused by freezing conditions.

-

Rising temperatures and droughts could cause wildfires like the ones that have affected California starting in 2017. In California wildfires have been especially catastrophic, causing human fatalities and significant material losses. Although our assets in California are located in areas without trees and vegetation, wildfires affected PG&E, one of our clients in the recent past (see “Downstream” described below).

-

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

•	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.

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.

•

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.

•

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 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. 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”.

•

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.

III.	Risks Related to Our Indebtedness

•	increasing our vulnerability to general economic and industry conditions;

•

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

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

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

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

•	exposing us to the risk of increased interest rates because a portion of some of our borrowings (approximately 7% as of December 31, 2022 after giving effect to hedging agreements) are at variable interest rates;

•	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.

•	general economic and capital market conditions;

•	credit availability from banks and other financial institutions;

•	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.

•	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.

IV.	Risks Related to Our Growth Strategy

VI.	Risks Related to the Markets in Which We Operate

•	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.

•	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 intercompany loans;

•

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

•	other business risks affecting our cash levels;

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

VII.	Risks Related to Taxation

ITEM 4.

INFORMATION ON THE COMPANY

A.	History and Development of the Company

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	21
Mojave	Renewable (Solar)	100%	California (USA)	USD	280 MW	BB-/--/BB	2014	17
Coso	Renewable (Geothermal)	100%	California (USA)	USD	135 MW	Investment grade (11)	1987/ 1989	16
Elkhorn Valley(16)	Renewable (Wind)	49%	Oregon (USA)	USD	101 MW	BBB/Baa1/--	2007	5
Prairie Star(16)	Renewable (Wind)	49%	Minnesota (USA)	USD	101 MW	--/A3/A-	2007	5
Twin Groves II(16)	Renewable (Wind)	49%	Illinois (USA)	USD	198 MW	BBB/Baa2/--	2008	3
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	8
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	13
La Tolua	Renewable (Solar)	100%	Colombia	COP	20 MW	Not rated	2023	10
Tierra Linda	Renewable (Solar)	100%	Colombia	COP	10 MW	Not rated	2023	10
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	11
Cadonal	Renewable (Wind)	100%	Uruguay	USD	50 MW	BBB/Baa2/BBB-(12)	2014	12
Melowind	Renewable (Wind)	100%	Uruguay	USD	50 MW	BBB/Baa2/BBB-(12)	2015	13
Mini-Hydro	Renewable (Hydraulic)	100%	Peru	USD	4 MW	BBB/Baa1/BBB	2012	10
Solaben 2 & 3	Renewable (Solar)	70%(2)	Spain	Euro	2x50 MW	A/Baa1/A-	2012	15/15
Solacor 1 & 2	Renewable (Solar)	87%(3)	Spain	Euro	2x50 MW	A/Baa1/A-	2012	14/14

PS 10 & PS 20	Renewable (Solar)	100%	Spain	Euro	31 MW	A/Baa1/A-	2007& 2009	9/11
Helioenergy 1 & 2	Renewable (Solar)	100%	Spain	Euro	2x50 MW	A/Baa1/A-	2011	14/14
Helios 1 & 2	Renewable (Solar)	100%	Spain	Euro	2x50 MW	A/Baa1/A-	2012	14/15
Solnova 1, 3 & 4	Renewable (Solar)	100%	Spain	Euro	3x50 MW	A/Baa1/A-	2010	12/12/13
Solaben 1 & 6	Renewable (Solar)	100%	Spain	Euro	2x50 MW	A/Baa1/A-	2013	16/16
Seville PV	Renewable (Solar)	80%(4)	Spain	Euro	1 MW	A/Baa1/A-	2006	13
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	9
Italy PV 4	Renewable (Solar)	100%	Italy	Euro	3.6 MW	BBB/Baa3/BBB	2011	9
Kaxu	Renewable (Solar)	51%(5)	South Africa	Rand	100 MW	BB-/Ba2/BB-(13)	2015	12
Calgary	Efficient natural gas & Heat	100%	Canada	CAD	55 MWt	~41% A+ or higher(14)	2010	18
ACT	Efficient natural gas & Heat	100%	Mexico	USD	300 MW	BBB/ B1/BB-	2013	10
Monterrey	Efficient natural gas & Heat	30%	Mexico	USD	142 MW	Not rated	2018	23
ATN (13)	Transmission line	100%	Peru	USD	379 miles	BBB/Baa1/BBB	2011	18
ATS	Transmission line	100%	Peru	USD	569 miles	BBB/Baa1/BBB	2014	21
ATN 2	Transmission line	100%	Peru	USD	81 miles	Not rated	2015	10
Quadra 1 & 2	Transmission line	100%	Chile	USD	49 miles/ 32 miles	Not rated	2013-2014	12/12
Palmucho	Transmission line	100%	Chile	USD	6 miles	BBB/-/BBB+	2007	15
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	49
Skikda	Water	34.2%(6)	Algeria	USD	3.5 M ft3/day	Not rated	2009	11
Honaine	Water	25.5%(7)	Algeria	USD	7 M ft3/day	Not rated	2012	15
Tenes	Water	51%(8)	Algeria	USD	7 M ft3/day	Not rated	2015	17

---

---

•

Elkhorn Valley

•

Prairie Star

•

Twin Groves II

•

Lone Star II

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

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

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

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

−	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.

−

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%.

−	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.

−	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, 2022, the outstanding balance of this loan was $1.5 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, 2022, the outstanding balance of this loan was $0.5 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, 2022, the outstanding balance of this loan was $1.3 million.

−	Tranche 1: $205.4 million with 10-year maturity.

−	Tranche 2: $450.0 million with an 18-year maturity. The interest rate on each tranche is a floating rate based on the three-month LIBOR plus a margin of 3.5% from January 2019 to December 2024 and 3.75% from January 2025 to December 2031. The loan is 75% hedged at a weighted average rate of 3.94%.

−	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.

Asset	Type	Location	Capacity (gross)1	Expected COD	Expected Investment ($ million)	Off-taker
Coso Batteries 1	Battery Storage	California, US	100 MWh	2024	40-50	N.A.
Chile PMGD2	Solar PV	Chile	80 MW	2023 – 2024	303	Regulated
Honda 14	Solar PV	Colombia	10 MW	2023	11	Enel Colombia
Honda 24	Solar PV	Colombia	10 MW	2023	11	Enel Colombia
Apulo 14	Solar PV	Colombia	10 MW	2023	11	Enel Colombia
Solana C&I PV	Solar PV (behind the meter)	Arizona, US	2.5 MW	2023	3	Solana
Raurapata	Transmission Line	Peru	3.9KM 220Kv	2024	12	Conelsur4

(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.

(3)

Corresponds to the expected investment by Atlantica.

(4)

Atlantica owns 50% of the shares in Honda 1, Honda 2 and Apulo 1.

(5)

The contract is in the process of being transferred to Conelsur.

	Renewable Energy (GW)7	Storage  (GWh)7
North America	1.0	4.1
Europe	0.4	1.3
South America	0.6	0.2
Total	2.0	5.6

---

−

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 2022 at 1.0, compared to 1.2 in 2021.

−	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 2022 at 0.6, compared to 0.5 in 2021.

•	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.

•	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).

•

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

•

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.

•	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).

•

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 Spanish government can establish a specific remuneration through an auction process.

•	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.

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.

−

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. The proposed Rinv is detailed in the table below.

−

The electricity market price assumed by the regulation for calendar year 2022 was changed from €48.82 per MWh to an expected price of €121.9 per MWh, i.e., the remuneration parameters of 2022 have been updated with real prices of 2020 (33.94 €/MWh) and 2021 (111.90 €/MWh) and the future prices of OMIP for 2022 (value of second semester 2021: 121.9 €/MWh). 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 2022 is zero €/MWh for most of our assets reflecting the fact that market prices for the power sold in the market are significantly higher.

	Useful Life		Remuneration on Investment 2022 (euros/MW)				Remuneration on Operation 2022 (euros/GWh)				Maximum Hours				Minimum Hours				Operating Threshold
Solaben 2	25 years			390,453				0				2,008				1,205				703
Solaben 3	25 years			390,453				0				2,008				1,205				703
Solacor 1	25 years			390,453				0				2,008				1,205				703
Solacor 2	25 years			390,453				0				2,008				1,205				703
PS 10	25 years			543,185				7,580				1,840				1,104				644
PS 20	25 years			401,296				1,777				1,840				1,104				644
Helioenergy 1	25 years			385,014				0				2,008				1,205				703
Helioenergy 2	25 years			385,014				0				2,008				1,205				703
Helios 1	25 years			398,498				0				2,008				1,205				703
Helios 2	25 years			398,498				0				2,008				1,205				703
Solnova 1	25 years			404,292				0				2,008				1,205				703
Solnova 3	25 years			404,292				0				2,008				1,205				703
Solnova 4	25 years			404,292				0				2,008				1,205				703
Solaben 1	25 years			395,304				0				2,008				1,205				703
Solaben 6	25 years			395,304				0				2,008				1,205				703
Seville PV	30 years			696,418				0				2,041				1,225				714

	Useful Life		Remuneration on Investment 2023(euros/MW)				Remuneration On Operation 2023 (euros/GWh)				Maximum Hours				Minimum Hours				Operating Threshold
Solaben 2	25 years			358,562				0				2,004				1,202				701
Solaben 3	25 years			358,562				0				2,004				1,202				701
Solacor 1	25 years			358,562				0				2,004				1,202				701
Solacor 2	25 years			358,562				0				2,004				1,202				701
PS 10	25 years			509,713				0				1,837				1,102				643
PS 20	25 years			373,114				0				1,837				1,102				643
Helioenergy 1	25 years			351,751				0				2,004				1,202				701
Helioenergy 2	25 years			351,751				0				2,004				1,202				701
Helios 1	25 years			365,595				0				2,004				1,202				701
Helios 2	25 years			365,595				0				2,004				1,202				701
Solnova 1	25 years			368,603				0				2,004				1,202				701
Solnova 3	25 years			368,603				0				2,004				1,202				701
Solnova 4	25 years			368,603				0				2,004				1,202				701
Solaben 1	25 years			363,530				0				2,004				1,202				701
Solaben 6	25 years			363,530				0				2,004				1,202				701
Seville PV	30 years			654,194				0				2,030				1,218				711

•

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).

(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 Starwood

(10)	49% owned by Industrial Development Corporation, a South African Government company

(11)	70% owned by Arroyo Energy

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

(13)	70% held by Algonquin

(14)	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

(19)	Simplified structure

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

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

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

(23)	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

D.	Property, Plant and Equipment

ITEM 4A.

UNRESOLVED STAFF COMMENTS

ITEM 5.

OPERATING AND FINANCIAL REVIEW AND PROSPECTS

A.	Operating Results

•

In January 2022, we closed the acquisition of Chile TL4, a 63-mile transmission line and 2 substations in Chile for a total equity investment of $38.4 million. We expect to expand the transmission line in 2023-2024, which would represent an additional investment of approximately $8 million. The asset has fully contracted revenues in U.S. dollars, with annual inflation adjustments and a 50-year remaining contract life. The off-takers are several mini-hydro plants that receive contracted or regulated payments.

•	In April 2022, we closed the acquisition of Italy PV 4, a 3.6 MW solar portfolio in Italy for a total equity investment of $3.7 million. The asset has regulated revenues under a feed-in tariff until 2031.

•

In May 2022, together with our partner, we closed a 7.5-year PPA extension for Monterrey with our current off-takers. The extension will involve an investment that is expected to be financed with cash available at the asset level. The main objective of the investment is to achieve improvements in the asset to provide, among other things, additional battery capacity and additional redundancy of electric power supply. The PPA, which is denominated in U.S. dollars, now ends in 2046.

•

In July 2022 we closed a 12-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. The substation is expected to enter in operation in 2024 and the investment is expected to be approximately $12 million.

•

In September 2022, we closed the acquisition of Chile PV 3, a 73 MW solar PV plant through our renewable energy platform in Chile. The equity investment corresponding to our 35% equity interest was $8 million, and we expect to install batteries with a capacity of approximately 100 MWh in 2023-2024. 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.

•

In September 2022, we agreed our first investment in a standalone battery storage project of 100 MWh (4 hours) capacity located inside Coso, our geothermal asset in California. Our investment is expected to be in the range of $40 million to $50 million. This project is at an advanced stage and we are preparing to start construction, with COD expected in 2024.

•

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 starting 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 2023 and 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 9 MW which allows to sell electricity through a stabilized price.

•	In addition, we have finished construction of the three assets that we had under construction during 2022 and have reached or are about to reach COD:

-

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 solar PV assets in Colombia with a combined capacity of 30 MW. Each plant has a 10-year PPA (commencing on COD) in local currency with Coenersa, the largest independent electricity wholesaler in Colombia.

		Year ended December 31,
		2022								2021								2020
		$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue
North America		$	405.1				36.8	%		$	395.8				32.7	%		$	330.9				32.6	%
South America			166.4				15.1	%			155.0				12.8	%			151.5				15.0	%
EMEA			530.5				48.1	%			660.9				54.5	%			530.9				52.4	%
Total revenue		$	1,102.0				100.0	%		$	1,211.7				100.0	%		$	1,013.3				100.0	%

		Year ended December 31,
		2022								2021								2020
		$ in millions				% of revenue				$ in millions				% of revenue				$ in millions				% of revenue
Renewable Energy		$	821.4				74.5	%		$	928.5				76.6	%		$	753.1				74.3	%
Efficient natural gas & Heat			113.6				10.3	%			123.7				10.2	%			111.0				11.0	%
Transmission Lines			113.2				10.3	%			105.6				8.7	%			106.1				10.5	%
Water			53.8				4.9	%			53.9				4.5	%			43.1				4.2	%
Total revenue		$	1,102.0				100.0	%		$	1,211.7				100.0	%		$	1,013.3				100.0	%

		Year ended December 31,
		2022								2021								2020
		$ in millions				% of Adjusted EBITDA				$ in millions				% of Adjusted EBITDA				$ in millions				% of Adjusted EBITDA
North America		$	310.0				38.9	%		$	311.8				37.8	%		$	279.4				35.1	%
South America			126.5				15.9	%			119.6				14.5	%			120.0				15.1	%
EMEA			360.6				45.2	%			393.0				47.7	%			396.7				49.8	%
Total Adjusted EBITDA		$	797.1				100.0	%		$	824.4				100.0	%		$	796.1				100.0	%

		Year ended December 31,
		2022								2021								2020
		$ in millions				% of Adjusted EBITDA				$ in millions				% of Adjusted EBITDA				$ in millions				% of Adjusted EBITDA
Renewable Energy		$	588.0				73.8	%		$	602.6				73.1	%		$	576.3				72.4	%
Efficient natural gas & Heat			84.6				10.6	%			100.0				12.1	%			101.0				12.7	%
Transmission Lines			88.0				11.0	%			83.6				10.2	%			87.3				11.0	%
Water			36.5				4.6	%			38.2				4.6	%			31.5				3.9	%
Total Adjusted EBITDA		$	797.1				100.0	%		$	824.4				100.0	%		$	796.1				100.0	%

		Year ended December 31,
		2022				2021				2020
		($ in millions)
Profit/(loss) for the year attributable to the parent company		$	(5.4	)		$	(30.1	)		$	11.9
Profit/(loss) attributable to non-controlling interest			3.3				19.2				4.9
Income tax expense			(9.7	)			36.2				24.9
Financial expense, net			310.9				340.9				331.8
Depreciation, amortization and impairment charges			473.6				439.4				408.6
Depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership)			24.4				18.7				13.9
Adjusted EBITDA		$	797.1			$	824.4			$	796.1

		Year ended December 31,
		2022				2021				2020
		($ in millions)
Net cash flow provided by operating activities		$	586.3			$	505.6			$	438.2
Net interest /taxes paid			277.3				342.3				287.2
Variations in working capital			(78.8	)			3.1				10.9
Non-monetary items and other			(33.5	)			(57.7	)			45.3
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)			45.8				31.1				14.5
Adjusted EBITDA		$	797.1			$	824.4			$	796.1

•

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.

		As of and for the year ended December 31,
		2022				2021				2020
Renewable Energy
MW in operation(1)			2,121				2,044				1,551
GWh produced(2)			5,319				4,655				3,244
Efficient natural gas & Heat
MW in operation(3)			398				398				343
GWh produced(4)			2,501				2,292				2,574
Availability (%)			98.9	%			100.6	%			102.1	%
Transmission lines
Miles in operation			1,229				1,166				1,166
Availability (%)			100	%			100.0	%			100.0	%
Water
Mft3 in operation(1)			17.5				17.5				17.5
Availability (%)			102.3	%			97.9	%			100.1	%

(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.

		Year ended December 31,
		2022				2021				2020
		($ in millions)
Revenue		$	1,102.0			$	1,211.7			$	1,013.3
Other operating income			80.8				74.6				99.5
Employee benefit expenses			(80.2	)			(78.7	)			(54.4	)
Depreciation, amortization and impairment charges			(473.6	)			(439.4	)			(408.6	)
Other operating expenses			(351.3	)			(414.3	)			(276.7	)
Operating profit/(loss)		$	277.7			$	353.9			$	373.1
Financial income			5.6				2.7				7.1
Financial expense			(333.3	)			(361.2	)			(378.4	)
Net exchange differences			10.3				1.9				(1.4	)
Other financial income/(expense), net			6.5				15.7				40.9
Financial expense, net		$	(310.9	)		$	(340.9	)		$	(331.8	)
Share of profit/(loss) of entities carried under the equity method			21.4				12.3				0.5
Profit/(loss) before income tax		$	(11.8	)		$	25.3			$	41.8
Income tax expense			9.7				(36.2	)			(24.9	)
Profit/(loss) for the year		$	(2.1	)		$	(10.9	)		$	16.9
Profit attributable to non-controlling interests			(3.3	)			(19.2	)			(4.9	)
Profit / (loss) for the year attributable to the parent company		$	(5.4	)		$	(30.1	)		$	12.0
Weighted average number of ordinary shares outstanding (thousands) – basic			114,695				111,008				101,879
Weighted average number of ordinary shares outstanding (thousands) – diluted			118,501				114,523				103,392
Basic earnings per share attributable to the parent company (U.S. dollar per share)			(0.05	)			(0.27	)			0.12
Diluted earnings per share attributable to the parent company (U.S. dollar per share)			(0.05	)			(0.27	)			0.12
Dividend paid per share(1)			1.77				1.72				1.66

(1)

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

		Year ended December 31,
		2022				2021
Other operating income		($ in millions)
Grants		$	59.1			$	60.7
Insurance proceeds and other			21.7				13.9
Total		$	80.8			$	74.6

		Year ended December 31,
		2022								2021
Other operating expenses		$ in millions				% of revenue				$ in millions				% of revenue
Raw Materials		$	19.7				1.8	%		$	70.7				5.8	%
Leases and fees			11.5				1.0	%			9.3				0.8	%
Operation and maintenance			140.4				12.7	%			154.0				12.7	%
Independent professional services			38.9				3.6	%			39.2				3.2	%
Supplies			59.3				5.4	%			40.8				3.4	%
Insurance			45.8				4.2	%			45.4				3.8	%
Levies and duties			19.8				1.8	%			29.9				2.5	%
Other expenses			16.0				1.3	%			25.0				2.1	%
Total		$	351.3				31.8	%		$	414.3				34.2	%

		Year ended December 31,
Financial income and financial expense		2022				2021
		($ in millions)
Financial income		$	5.6			$	2.7
Financial expense			(333.3	)			(361.2	)
Net exchange differences			10.3				1.9
Other financial income/(expense), net			6.5				15.7
Financial expense, net		$	(310.9	)		$	(340.9	)

		Year ended December 31,
Financial expense		2022				2021
		($ in millions)
Interest on loans and notes		$	(292.1	)		$	(302.6	)
Interest rates losses derivatives: cash flow hedges			(41.2	)			(58.7	)
Total		$	(333.3	)		$	(361.3	)

		Year ended December 31,
Other financial income/(expense), net		2022				2021
		($ in millions)
Other financial income		$	27.9			$	32.3
Other financial expense			(21.4	)			(16.6	)
Total		$	6.5			$	15.7

		For the year ended December 31,
		2022				2021
		($ in millions)
Consolidated profit / (loss) before taxes			(11.8	)			25.3
Average statutory tax rate1			25	%			25	%
Corporate income tax at average statutory tax rate			2.9				(6.3	)
Income tax of associates, net			5.4				3.1
Differences in statutory tax rates			(4.3	)			(3.4	)
Unrecognized NOLs and deferred tax assets			(10.9	)			(11.2	)
Other Permanent Differences			4.0				(4.1	)
Other non-taxable income/(expense)			12.7				(14.3	)
Corporate income tax			9.7				(36.2	)

(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.

		Year ended December 31,
		2022								2021
Revenue by geography		$ in millions				% of revenue				$ in millions				% of revenue
North America		$	405.1				36.8	%		$	395.8				32.7	%
South America			166.4				15.1	%			155.0				12.8	%
EMEA			530.5				48.1	%			660.9				54.5	%
Total revenue		$	1,102.0				100	%		$	1,211.7				100.0	%

		Year ended December 31,
		2022								2021
Adjusted EBITDA by geography		$ in millions				% of Adjusted EBITDA				$ in millions				% of Adjusted EBITDA
North America		$	310.0				38.9	%		$	311.8				37.8	%
South America			126.5				15.9	%			119.6				14.5	%
EMEA			360.6				45.2	%			393.0				47.7	%
Adjusted EBITDA(1)		$	797.1				100	%		$	824.4				100	%

(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 produced/availability
		Year ended December 31,
Volume / availability by geography		2022				2021
North America (GWh)(1)			5,743				4,818
North America availability			98.9	%			100.6	%
South America (GWh)(2)			799				722
South America availability			99.9	%			100.0	%
EMEA (GWh)			1,278				1,407
EMEA availability			102.3	%			97.9	%

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

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

		Year ended December 31,
		2022								2021
Revenue by business sector		$ in millions				% of revenue				$ in millions				% of revenue
Renewable energy		$	821.4				74.5	%		$	928.5				76.6	%
Efficient natural gas & Heat			113.6				10.3	%			123.7				10.2	%
Transmission lines			113.2				10.3	%			105.6				8.7	%
Water			53.8				4.9	%			53.9				4.5	%
Revenue		$	1,102.0				100	%		$	1,211.7				100.0	%

		Year ended December 31,
		2022								2021
Adjusted EBITDA by business sector		$ in millions				% of Adjusted EBITDA				$ in millions				% of Adjusted EBITDA
Renewable energy		$	588.0				73.8	%		$	602.6				73.1	%
Efficient natural gas & Heat			84.6				10.6	%			100.0				12.1	%
Transmission lines			88.0				11.0	%			83.6				10.2	%
Water			36.5				4.6	%			38.2				4.6	%
Adjusted EBITDA(1)		$	797.1				100	%		$	824.4				100.0	%

(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 produced/availability
		Year ended December 31,
Volume / availability by business sector		2022				2021
Renewable energy (GWh) (1)			5,319				4,655
Efficient natural gas & Heat (GWh) (2)			2,501				2,292
Efficient natural gas & Heat availability			98.9	%			100.6	%
Transmission availability			100.0	%			100.0	%
Water availability			102.3	%			97.9	%

(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.

•	debt service requirements on our existing and future debt;

•	cash dividends to investors; and

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

		Year ended December 31,
		2022				2021
		($ in millions)
Corporate Liquidity
Cash and cash equivalents at Atlantica Sustainable Infrastructure, plc, excluding subsidiaries		$	60.8			$	88.3
Revolving Credit Facility availability			385.1				440.0
Total Corporate Liquidity(1)		$	445.9			$	528.3
Liquidity at project companies
Restricted Cash			207.6				254.3
Non-restricted cash			332.6				280.1
Total cash at project companies		$	540.2			$	534.4

(1)	Corporate Liquidity means cash and cash equivalents held at Atlantica Sustainable Infrastructure plc as of December 31, 2022, and available revolver capacity as of December 31, 2022.

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

						As of December 31, 2022				As of December 31, 2021
		Maturity				($ in millions)
Revolving Credit Facility		2024					29.4				-
Other Facilities(1)		2023-2026					30.1				41.7
Green Exchangeable Notes		2025					107.0				104.3
2020 Green Private Placement		2026					308.4				327.1
Note Issuance Facility 2020		2027					147.2				155.8
Green Senior Notes		2028					395.1				394.2
Total Corporate Debt						$	1,017.2			$	1,023.1
Total Project Debt						$	4,553.1			$	5,036.2

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

A)	Corporate debt agreements

		Total				2023				2024				2025				2026				2027				Subsequent years
		$ in millions
Solana			577.4				23.0				24.2				26.8				29.5				32.4				441.5
Mojave			493.8				36.4				36.9				38.1				39.4				40.7				302.3
Coso			200.8				14.1				14.6				14.2				14.7				143.2				-
ACT			441.1				41.5				37.6				42.3				54.6				59.0				206.1
North America			1,713.1				115.0				113.3				121.4				138.2				275.3				949.9
Chile PV 1			50.5				2.0				1.1				1.0				1.1				1.5				43.8
Chile PV 2			21.4				1.2				0.8				1.4				2.4				2.1				13.5
Palmatir			72.0				6.9				6.2				6.6				7.0				7.5				37.8
Cadonal			46.6				3.3				3.0				3.1				3.4				3.6				30.2
Melowind			68.6				2.8				4.8				5.0				5.1				4.8				46.1
ATN			87.0				5.7				6.0				6.4				6.8				7.3				54.8
ATS			391.5				12.6				7.4				8.3				9.5				10.7				343.0
ATN 2			45.3				4.8				5.0				5.1				5.3				5.4				19.7
Quadra 1&2 and Palmucho			58.7				5.0				5.3				5.9				6.5				7.2				28.8
South America			841.6				44.3				39.6				42.8				47.1				50.1				617.7
Solaben 2&3(1)			330.4				31.4				32.4				138.1				28.7				31.2				68.6
Solacor 1&2			212.8				10.3				14.0				14.6				15.0				15.4				143.5
Helios 1&2			290.8				20.7				21.3				21.7				21.1				21.5				184.5
Helioenergy 1&2			243.5				17.4				18.7				19.9				18.8				20.1				148.6
Solnova 1,3&4			354.9				28.1				30.0				30.6				32.1				31.9				202.2
Solaben 1&6			188.0				13.9				13.9				14.8				15.4				15.8				114.2
Rioglass			10.3				5.2				1.7				1.9				1.3				0.1				0.1
Italy PV 1&3			3.4				0.7				0.7				0.7				0.5				0.2				0.6
Kaxu			277.6				26.7				27.5				28.0				31.6				34.4				129.4
Skikda			7.4				4.9				2.5				-				-				-				-
Tenes			79.3				8.0				8.1				8.4				8.7				9.0				37.1
EMEA			1,998.4				167.3				170.8				278.7				173.2				179.6				1,028.8
Total project debt		$	4,553.1				326.6				323.7				442.9				358.5				505.0				2,596.4
Corporate debt		$	1,017.2				16.7				38.9				110.2				309.1				147.3				395.0
Total		$	5,570.3				345.3				362.6				553.1				667.6				652.3				2,989.4

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

		Total				Up to one year				Between one and three years				Between three and five years				Subsequent years
		$ in millions
Purchase commitments			823.9				96.8				154.3				107.9				464.8
Accrued interest estimate during the useful life of loans			1,821.9				264.6				477.9				383.3				696.0

C)	Cash dividends to investors

D)	Investments and Acquisitions

E)	Capital Expenditures

		Year ended December 31,
		2022				2021				2020
		($ in millions)
Gross cash flows from operating activities
Profit/(loss) for the year		$	(2.1	)		$	(10.9	)		$	16.9
Adjustments to reconcile after-tax profit to net cash generated by operating activities			786.9				861.9				719.5
Profit for the year adjusted by non-monetary items		$	784.8			$	851.0			$	736.4
Net interest/taxes paid			(277.3	)			(342.3	)			(287.3	)
Variations in working capital			78.8				(3.1	)			(10.9	)
Total net cash flow provided by/ (used in) operating activities		$	586.3			$	505.6			$	438.2
Net cash flows from investing activities
Acquisitions of subsidiaries and entities under equity method			(50.5	)			(362.4	)			2.5
Investments in operating concessional assets(1)			(39.1	)			(19.2	)			(1.4	)
Investments in assets under development or construction			(36.8	)			(7.0	)			-
Distributions from entities under the equity method			67.7				34.8				22.2
Other non-current assets/liabilities			1.3				2.7				(29.2	)
Total net cash flows (used in)/ provided by investing activities		$	(57.4	)		$	(351.2	)		$	(5.9	)
Net cash flows used in financing activities		$	(535.0	)		$	(380.1	)		$	(137.3	)
Net increase / (decrease) in cash and cash equivalents			(6.1	)			(225.7	)			295.0	)
Cash, cash equivalents and bank overdraft at beginning of the year			622.7				868.5				562.8
Translation differences cash or cash equivalents			(15.6	)			(20.1	)			10.7	)
Cash and cash equivalents at the end of the period		$	601.0			$	622.7			$	868.5

(1)	Includes proceeds for $20.5 million and $17.4 million in 2021 and 2020 respectively. See Note 6 of the Annual Consolidated Financial Statements.

C.	Research and Development

D.	Trend Information

E.	Critical Accounting Estimates

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

-	Recoverability of deferred tax assets

-	Assessment of contracted concessional agreements.

-	Assessment of control.

a)	Contracted concessional assets under IFRIC 12

-	Intangible asset

-	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.

-	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

-	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

c)	Right of uses under IFRS 16

d)	Other intangible assets

-

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

-

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.

F.	Off-Balance Sheet Arrangements

A.	Directors and Senior Management

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
Michael Forsayeth		Director, Independent		1954
Edward C. Hall		Director, Independent		1959
Santiago Seage		Chief Executive Officer and Director		1969
George Trisic		Director		1960
Michael Woollcombe		Director and Chair of the Board, Independent		1968

	2022	2021
Total Number of Directors	9	8

		Female								Male								Non-Binary								Did not disclosed Gender
		2022				2021				2022				2021				2022				2021				2022				2021
Part I: Gender Identity
Directors			2				2				7				6				-				-				-				-
Part II: Demographic Background
African American or Black			-				-				-				-				-				-				-				-
Alaskan Native or Native American			-				-				-				-				-				-				-				-
Asian1			-				-				1				1				-				-				-				-
Hispanic or Latinx2			-				-				1				1				-				-				-				-
Native Hawaiian or Pacific Islander			-				-				-				-				-				-				-				-
White3			2				2				5				4				-				-				-				-
Two or More Races or Ethnicities			-				-				-				-				-				-				-				-
LGBTQ+			-				-				-				-				-				-				-				-
Did Not Disclose Demographic Background			-				-				-				-				-				-				-				-

(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.

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

B)	Compensation

In thousands of U.S. Dollars		2022				2021
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

In thousands of U.S. Dollars		Salary and Fees in Cash								Salary and Fees in DRSUs2								Annual Bonuses								Long-Term Incentive Awards3 (Vested)								Deferred Restricted Share Units Dividend Equivalents 3								Total Fixed Remuneration								Total Variable Remuneration								Total
Name1		2022				2021				2022				2021				2022				2021				2022				2021				2022				2021				2022				2021				2022				2021				2022				2021
William Aziz			160.0				160.0				-				-				-				-				-				-				-				-				160.0				160.0				-				-				160.0				160.0
Debora Del Favero			112.0				128.5				48.0				31.5				-				-				-				-				2.5				0.3				162.5				160.3				-				-				162.5				160.3
Brenda Eprile			165.0				165.0				-				-				-				-				-				-				-				-				165.0				165.0				-				-				165.0				165.0
Michael Forsayeth			75.0				100.8				75.0				49.2				-				-				-				-				4.0				0.5				154.0				150.5				-				-				154.0				150.5
Edward C Hall5			62.5				-				-				-				-				-				-				-				-				-				62.5				-				-				-				62.5				-
Santiago Seage6			727.2				816.6				-				-				931.3				1,056.3				2,992.4				1,879.8				-				-				727.2				816.6				3,923.7				2,936.1				4,651.0				3,752.7
George Trisic7			-				-				110.0				-				-				-				-				-				1.6				-				111.6				-				-				-				111.6				-
Michael Woollcombe			-				77.5				225.0				147.5				-				-				-				-				11.9				1.5				236.9				226.5				-				-				236.9				226.5
Total			1,301.7				1,448.5				458.0				228.1				931.3				1,056.3				2,992.4				1,879.8				20.0				2.3				1,779.7				1,679.0				3,923.7				2,936.1				5,703.5				4,615.1

-

Chief Executive Officer Long-Term Incentives awards vested

One-Off Plan1	One-Off Plan Vesting		Number of Restricted Stock Units (RSUs)				Share Price on Vesting Date (US$)				RSUs Value at Vesting Date ($ thousand)2
2019	June 20223			14,535				31.30				528.6
	June 2021			14,535				36.50				578.8

LTIP Share Option Grant Date1	Share Option Vesting Date		Number of Share Options Vesting (#)				Share Price on Vesting Date (USD)				Exercise Price per Share Option (USD)				Share Options Value at Vesting Date (000’s USD)2
2021	2022			24,948				32.53				37.98				-
2020	2022			34,494				34.48				26.39				279.1
	2021			34,494				44.17				26.39				613.3
2019	2022			40,693				31.30				19.60				476.1
	2021			40,693				36.50				19.60				687.7

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
2019	2022			46,987				31.10				1,708.7

		Percentage weight			Achievement
CAFD (cash available for distribution) – Equal or higher than the CAFD budgeted in the 2022 budget			35	%	99%
Adjusted EBITDA– Equal or Higher than the Adjusted EBITDA budgeted in the 2022 budget			15	%	98%
Close sustainable value accretive investments			15	%	85%
Achieve health and safety targets – (Frequency with Leave / Lost Time Index below 3.9 and General frequency index below 10.1) based on reliable targets and consistent measure metrics			10	%	120%
Management of relationships with key shareholders and partners			10	%	120%
Continued executive talent development			10	%	120%
Disclosure best standards			5	%	85%

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
		2022				2021				2022				2021				2022				2021				2022				2021
William Aziz			160.0				160.0				160.0				160.0				-				-				-				-
Debora Del Favero1			160.0				160.0				112.0				128.5				48.0				31.5				1,619				878
Brenda Eprile			165.0				165.0				165.0				165.0				-				-				-				-
Michael Forsayeth1			150.0				150.0				75.0				100.8				75.0				49.2				2,530				1,372
Edward C. Hall2			62.5				-				62.5				-				-				-				-				-
George Trisic3			110.0				-				-				-				110.0				-				3,901				-
Michael Woollcombe1			225.0				225.0				-				77.5				225.0				147.5				7,589				4,117
Total			1,032.5				860.0				574.5				631.9				458.0				228.1				15,638				6,367

LTIP		Number of Restricted Stock Units		Restricted Stock Units Face Value1 (000’s USD)		Performance Criteria
2022		35,2022		1,197.2		RSU: 5% minimum Total Shareholder Return performance stock unit over a three year period

		Bonus													LTIP awards(3)
		(In thousands of U.S. Dollars)
Year		Total Pay(1)					Percentage of target				Amount of Bonus(2)				Percentage of maximum				Value
2022			4,651.0					102.4	%			931.3				100	%			2,992.4
2021			3,752.7					105.0	%			1,056.3				100	%			1,879.8
2020			2,524.1					102.7	%			996.4				100	%			770.9
2019			1,685.4					100.7	%			957.7				-				-
2018			2,511.1					101.8	%			992.2				22.0	%			751.1
2017			1,602.0					96.3	%			924.2				-				-
2016			1,499.4					100	%			940.5				-				-
2015			1,597.6	(4)				-				-				-				-
2014			174.1					-				-				-				-

		2022 (% Change from 2021 to 2022)								2021 (% Change from 2020 to 2021)								2020 (% Change from 2019 to 2020)
Name		Salary and fees (Cash and DRSU)				Bonus				Salary and fees (Cash and DRSU)(1)				Bonus				Salary				Bonus
Non-executive directors
William Aziz2			-				-				-				-				-				-
Debora Del Favero2			-				-				-				-				-				-
Brenda Eprile2			-				-				-				-				-				-
Michael Forsayeth2			-				-				-				-				-				-
Edward C. Hall3			-				-				-				-				-				-
George Trisic4			-				-				-				-				-				-
Michael Woollcombe2			-				-				-				-				-				-
Andrea Brentan5			-				-				-				-				3	%			-
Robert Dove5			-				-				-				-				3	%			-
Francisco J. Martinez5			-				-				-				-				3	%			-
Jackson Robinson5			-				-				-				-				3	%			-
Daniel Villalba5			-				-				-				-				3	%			-
Executive director
Santiago Seage (CEO)			0	%7			-3	%7			4	%7			2	%7			2	%			2	%
Employees (excluding CEO)6			4	%			9	%			4	%			8	%			5	%			8	%

$ in Millions		2022				2021				Difference
Spend on Pay for All Employees			80.2				78.8				1.4
Total Remuneration of Directors			5.6				4.6				1.0
Total Remuneration of employees and directors			85.9				83.4				2.5
Dividends Paid			203.1				190.4				12.7

	Percentage weight
CAFD (cash available for distribution) – Equal or higher than the CAFD budgeted in the 2023 budget	35%
Adjusted EBITDA– Equal or Higher than the Adjusted EBITDA budgeted in the 2023 budget	15%
Capital allocation management on a value accretive basis	20%
Achievement of ESG metrics including health and safety targets (Frequency with leave/ lost time index below 3.7 and General Frequnecy index below 9.5)	10%
Management of relationships with key shareholders and partners	10%
Continued executive talent development	10%

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.
Strategic Review Bonus	One-time bonus related to the strategic review process and payable upon closing of a potential strategic transaction as such term is defined by the Board of Directors.	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	Restricted Stock Units subject to certain vesting periods and in part to minimum TSR.	Align executive directors and shareholders interests.	70% of target annual remuneration (including fixed salary + target annual bonus).	Restricted Stock Units granted after the approval of the proposed amendments to the Policy in 2023 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 participant’s Restricted Stock Units subject to minimum annual TSR condition will lapse on the vesting date. Restricted Stock Units granted prior to the approval of the proposed amendments to the Policy in 2023 subject to - Continuing employment and achievement of a minimum 5% average annual TSR for 100% of the award. If the TSR performance condition has not been met during the vesting period, the participant’s Restricted Stock Units will lapse in full on the vesting date. Share units. Clawback policy.

	Main terms of the LTIP for awards granted to all Executives after the approval of the proposed amendments to the Policy in 2023
Nature	Conditions shall be based on: -          Continuing employment (or other service relationship) for 33% of the award and -          Continuing employment and achievement of a minimum 5% average annual TSR for 67% of the award.
Exercisability and Vesting Period	33% of the shares will vest on the third anniversary of the grant date and 67% of the shares will vest on the third anniversary of the grant date but only if the annual TSR has been at least a 5% yearly average over such 3-year period. If the TSR has not met such threshold during the period, the participant’s relevant Restricted Stock Units for the 67% portion will lapse on the vesting date. The Company will decide at vesting if cash or shares are given as payment.
Ownership and Dividends	The participant will be entitled to receive, for each Restricted Stock Unit held, a payment equivalent to the amount of any dividend or distribution paid on one share between the grant date and the date on which the Restricted Stock Unit vests.

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 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.

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 (except the Related Parties 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.

$ thousand		2022				2021
Short-term employee benefits			3,917.2				5,098.4
LTIP Awards			4,639.8				2,140.2
One-off Awards			1,212.3				1,231.5
Post-employment benefits			-				-
Other long-term benefits			-				-
Termination benefits			-				-
Share-based payment			-				-
Total			9,769.3				8,470.1

Name1		Number of Shares				Number of Deferred Restricted Share Units2				Number of Share Units3 subject to performance measures				Investment Value ($000’s)4			Minimum Share Ownership Requirement	Compliance With Policy5		Number of Share Options Vested Unexercised6				Share Options Not Vested7
William Aziz			2,500				-				-				65		3 times annual compensation	On track			-				-
Debora Del Favero			-				2,608				-				68		3 times annual compensation	On track			-				-
Brenda Eprile			13,000				-				-				337		3 times annual compensation	On track			-				-
Michael Forsayeth			2,500				4,075				-				170		3 times annual compensation	On track			-				-
Edward Hall			1,500				-				-				39		3 times annual compensation	On track			-				-
Santiago Seage			117,491				-				105,868				5,785		6 times fixed compensation	✔			24,948				84,389
George Trisic			1,000				3,962				-				129		3 times annual compensation	On track			-				-
Michael Woollcombe			5,000				12,225				-				446		3 times annual compensation	On track			-				-

1	Mr. Banskota, 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 amount of dividends paid for one share in the period between the DRSU effective date and December 31, 2022 and 2021, respectively, multiplied by the number of DRSU on that date and divided by the share price of $25.90 as of December 31, 2022. 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	Non-vested Share Units as of December 31, 2022. LTIP share units subject to 5% minimum Total Shareholder Return.

4	Assuming a share price of $25.90 as of December 31, 2022.

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 and Mr. Trisic have a 5-year window starting in August and April 2022, respectively.

6	2021 share options (24,948) 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, 2022.

Name		Position
William Aziz		Member
Brenda Eprile		Chair
Michael Forsayeth		Member

Name		Position
Debora Del Favero		Chair
Michael Forsayeth		Member

Name		Position
William Aziz		Chair
Debora Del Favero		Member
Edward C. Hall		Member

Name		Position
William Aziz		Member
Brenda Eprile		Member
Michael Forsayeth		Chair

		Year ended December 31,
Geography		2022				2021				2020
North America			312				308				243
South America			93				68				51
EMEA			443				166				55
Corporate			130				115				107
Total			978				658				456

-	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.

ITEM 7.

MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

•	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.

Name		Ordinary Shares Beneficially Owned				Deferred Restricted Share Units (2)				Shares Units (3)				Percentage
Directors and Officers
William Aziz			2,500				-				-				-
Debora Del Favero			-				2,608				-				-
Brenda Eprile			13,000				-				-				-
Michael Forsayeth			2,500				4,075				-				-
Edward C. Hall			1,500				-				-				-
Santiago Seage			117,491				-				105,868				-
George Trisic			1,000				3,962				-				-
Michael Woollcombe			5,000				12,225				-				-
5% Beneficial Owner
Algonquin (AY Holdco) B.V. (1)			48,962,925				-				-				42.2	%

(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, 2022.

ITEM 8.

FINANCIAL INFORMATION

Declared	Record	Payable	Amount ($) per share
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
November 4, 2020	November 30, 2020	December 15, 2020	0.42
July 31, 2020	August 31, 2020	September 15, 2020	0.42
May 6, 2020	June 1, 2020	June 15, 2020	0.41
February 26, 2020	March 12, 2020	March 23, 2020	0.41

•

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.

•

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.

ITEM 9.

THE OFFER AND LISTING

ITEM 10.

ADDITIONAL INFORMATION

•	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.

•	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;

•	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.

ITEM 11.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 Uraguayan 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, La Sierpe, La Tolua and Tierra Linda, 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 in the case of Uruguayan peso.	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. The difference between the euro/U.S. dollar hedged rate for the year 2023 and the current rate reduced by 5% would create a negative impact on cash available for distribution of approximately $5.5 million. This amount has been calculated as the average net euro exposure expected for the years 2023 to 2026 multiplied by the difference between the average hedged euro /U.S. dollar rate for 2023 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.
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 rate (less than 10% of our consolidated debt). The most significant impact on our Annual Consolidated Financial Statements related to interest rates corresponds to the potential impact of changes in EURIBOR, SOFR or LIBOR 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, SOFR or LIBOR above the contracted fixed interest rate would create an increase in our financial expense which would be positively mitigated by our hedges, reducing our financial expense to our contracted fixed interest rate. However, an increase in EURIBOR, SOFR or LIBOR 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, SOFR or LIBOR above the strike price would result in higher interest expenses, which would be positively mitigated by our hedges, reducing our financial expense to our capped interest rate. 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, 2022, approximately 92% of our project debt and approximately 96% 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, SOFR and LIBOR had risen by 25 basis points as of December 31, 2022, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $1.3 million (a loss of $2.5 million in 2021 and a loss of $2.9 million in 2020) and an increase in hedging reserves of $18.4 million ($22.4 million increase in 2021 and $22.1 million increase in 2020). The increase in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.

Credit Risk

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, foreign exchange hedge contracts are unable to meet their obligations. The credit rating of Eskom is currently CCC+ from S&P , Caa1 from Moody’s and B from Fitch. Eskom is the off-taker of our Kaxu solar plant, a state-owned, limited liability company, wholly owned by the Republic of South Africa. In addition, Pemex’s credit rating is currently BBB from S&P, B1 from Moody’s and BB- from Fitch. We have experienced delays in collections in the past, especially since the second half of 2019, which have been significant in certain quarters. As of December 31, 2022 these delays were shorter than in previous quarters.

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, during 2022 we have maintained a pro-active 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, 2022, we had $445.9 million liquidity at the corporate level, comprised of $60.8 million of cash on hand at the corporate level and $385.1 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.
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). 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. 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 have increased during 2021 and 2022 as a result of the increase in the price of electricity and natural gas.	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, 2022, assets with merchant exposure represent less than a 2%9 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.

---

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 agreement with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $58.0 million in the event the South African Department of Mineral Resources and Energy does not comply with its obligations as guarantor. We also have a political risk insurance in place for two of our assets in Algeria for up to $37.2 million, including two years dividend coverage. These insurance policies do not cover credit risk.

ITEM 12.

DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

ITEM 13.

DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

ITEM 14.

MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

ITEM 15.

CONTROLS AND PROCEDURES.

ITEM 16.

RESERVED

ITEM 16A.

AUDIT COMMITTEE FINANCIAL EXPERT

ITEM 16B.

CODE OF ETHICS

ITEM 16C.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

		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

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

•

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

•

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

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

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

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

o	Tax services;

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

•	Courses or seminars.

•	For non-audit services, the accumulated fees must remain below the threshold of 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.

ITEM 16D.

EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

ITEM 16E.

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

ITEM 16F.

CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

ITEM 16G.

CORPORATE GOVERNANCE

ITEM 16H.

MINE SAFETY DISCLOSURE

ITEM 16I.

DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

ITEM 17.

FINANCIAL STATEMENTS

ITEM 18.

FINANCIAL STATEMENTS

ITEM 19.

EXHIBITS

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 (incorporated by reference from Exhibit 2.1 to Atlantica Sustainable Infrastructure plc’s Form 20-F, as amended, filed with the SEC on February 28, 2022 – SEC File No. 001-36487).
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	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).
4.10	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).
4.11	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).
4.12	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).
4.13	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).
4.14	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).
4.15	Memorandum and Articles of Association of Atlantica Sustainable Infrastructure Jersey Limited (incorporated by reference from Exhibit 4.21 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2020 – SEC File No. 001-36487).
4.16	Indenture (including Form of Global Note) relating to Atlantica Sustainable Infrastructure Jersey Limited’s 4.00% Green Exchangeable Senior Notes due 2025, dated July 17, 2020, by and among Atlantica Sustainable Infrastructure Jersey Limited, as Issuer, Atlantica Sustainable Infrastructure plc, as Guarantor, BNY Mellon Corporate Trustee Services Limited, as Trustee, The Bank of New York Mellon, London Branch, as Paying and Exchange Agent, and The Bank of New York Mellon SA/NV, Luxembourg Branch, as Note Registrar and Transfer Agent (incorporated by reference from Exhibit 4.22 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2020 – SEC File No. 001-36487). (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).
4.17	Deed Poll granted by Atlantica Sustainable Infrastructure plc, as Guarantor, in favor of Atlantica Sustainable Infrastructure Jersey Limited, as Issuer, dated July 17, 2020, in connection with the 4.00% Green Exchangeable Senior Notes due 2025 (incorporated by reference from Exhibit 4.23 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2020 – SEC File No. 001-36487).

4.18	The Note Issuance Facility for an amount of €140 million, dated July 8, 2020, among Atlantica Sustainable Infrastructure plc, the guarantors named therein, Lucid Agency Services Limited, as facility agent, and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder (incorporated by reference from Exhibit 4.24 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2020 – SEC File No. 001-36487).
4.19	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).
4.20	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).
4.21	Distribution Agreement, dated August 3, 2021, between the Company and J.P. Morgan Securities LLC (incorporated by reference from Exhibit 1.1 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2021 – SEC File No. 001-36487).
4.22	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).
4.23	ATM Plan Letter Agreement, dated August 3, 2021, between Atlantica Sustainable Infrastructure plc and Algonquin Power & Utilities Corp (incorporated by reference from Exhibit 4.29 from Atlantica Sustainable Infrastructure plc’s Form 6-K filed with the SEC on August 3, 2021 – SEC File No. 001-36487).
8.1	Subsidiaries of Atlantica Sustainable Infrastructure plc.
12.1	Certification of Santiago Seage, Chief Executive Officer of Atlantica Sustainable Infrastructure plc, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
12.2	Certification of Francisco Martinez-Davis, Chief Financial Officer of Atlantica Sustainable Infrastructure plc, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
13.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
15.1	Consent of EY
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document