This annual report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, strategies, future events or performance (often, but not always, through the use of words or phrases such as may result, are expected to, will continue, is anticipated, likely to, believe, will, could, should, would, estimated, may, plan, potential, future, projection, goals, target, outlook, predict, aim and intend or words of similar meaning) are not statements of historical facts and may be forward looking. Such statements occur throughout this annual report and include statements with respect to our strategy, including the development and construction of new assets, expected trends and outlook, electricity prices, potential market and currency fluctuations, occurrence and effects of certain trigger and conversion events, our capital requirements, changes in market price of our shares, future regulatory requirements, the ability to identify and/or make future investments and acquisitions on favorable terms, ability to capture growth opportunities, organic growth, reputational risks, divergence of interests between our company and that of our largest shareholder, tax and insurance implications, and more. Forward-looking statements involve estimates, assumptions and uncertainties. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, important factors included in Part I, of “Item 3.D. Risk Factors” (in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements) that could have a significant impact on our operations and financial results, and could cause our actual results, performance or achievements, to differ materially from the future results, performance or achievements expressed or implied in forward-looking statements made by us or on our behalf in this annual report, in presentations, on our website, in response to questions or otherwise. These forward-looking statements include, but are not limited to, statements relating to:
| • | the condition of, and changes in, the debt and equity capital markets and other traditional liquidity sources and our ability to borrow additional funds, refinance existing debt and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward; |
| • | our plans relating to our financings, including refinancing plans; |
| • | the ability of our assets to serve our project debt and comply with financial or other covenants on their terms, including but not limited to our projects debts in Chile, and our ability to serve our corporate debt; |
| • | the ability of our counterparties, including Pemex, to satisfy their financial commitments or business obligations and our ability to seek new counterparties in a competitive market; |
| • | government regulation, including compliance with regulatory and permit requirements and changes in market rules, rates, tariffs, environmental laws and policies affecting renewable energy, including the IRA and recent changes in regulation defining the remuneration of our solar assets in Spain; |
| • | changes in tax laws and regulations, including the new legislation on restrictions to tax deductibility in Spain; |
| • | risks relating to our activities in areas subject to economic, social and political uncertainties; |
| • | global recession risks, volatility in the financial markets, an inflationary environment, increases in interest rates and supply chain issues, and the related increases in prices of materials, labor, services and other costs and expenses required to operate our business; |
| • | risks related to our ability to capture growth opportunities, develop, build and complete projects in time and within budget, including construction risks and risks associated with the arrangements with our joint venture partners; |
| • | our ability to grow organically and inorganically, which depends on our ability to identify attractive development opportunities, attractive potential acquisitions, finance such opportunities and make new investments and acquisitions on favorable terms; |
| • | our ability to distribute a significant percentage of our cash for distribution as cash dividends, intention to increase such dividends over time; |
| • | risks relating to new assets and businesses which have a higher risk profile and our ability to transition these successfully; |
| • | potential environmental liabilities and the cost and conditions of compliance with applicable environmental laws and regulations; |
| • | risks related to our reliance on suppliers, including financial or technical uncertainties of original equipment manufacturer (OEM) suppliers, among others; |
| • | risks related to disagreements and disputes with our employees, unions and employees represented by unions; |
| • | risks related to our ability to maintain appropriate insurance over our assets; |
| • | risks related to our facilities not performing as expected, unplanned outages, higher than expected operating costs and/ or capital expenditures, including as a result of interruptions or disruptions caused by supply chain issues and trade restrictions; |
| • | risks related to our exposure in the labor market; |
| • | risks related to extreme and chronic weather events related to climate change could damage our assets or result in significant liabilities and cause an increase in our operation and maintenance costs; |
| • | the effects of litigation and other legal proceedings (including bankruptcy) against us our subsidiaries, our assets and our employees; |
| • | price fluctuations, revocation and termination provisions in our off-take agreements and PPAs; |
| • | risks related to information technology systems and cyber-attacks could significantly impact our operations and business; |
| • | our electricity generation, our projections thereof and factors affecting production; |
| • | risks related to our current or previous relationship with Abengoa, our former largest shareholder, including litigation risk; |
| • | performing the O&M services directly and the successful integration of the O&M employees where the services thereunder have been recently replaced and internalized; |
| • | our guidance targets or expectations with respect to Adjusted EBITDA derived from low-carbon footprint assets; |
| • | risks related to our relationship with our shareholders, including Algonquin, our major shareholder; |
| • | the process to explore and evaluate potential strategic alternatives, including the risk that this process may not lead to the approval or completion of any transaction or other strategic change; |
| • | potential impact of potential pandemics on our business and our off-takers’ financial condition, results of operations and cash flows; |
| • | reputational and financial damage caused by our off-takers PG&E, Pemex and Eskom; |
| • | our plans relating to the sale or disposition of assets, including the sale of our equity interest in Monterrey; |
| • | risks related to Russian military actions in Ukraine, to military actions in the Middle East, or to the potential escalation of any of the foregoing global geopolitical tensions; and |
| • | other factors discussed in “Part I, Item 3.D. – Risk Factors”. |
Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances, including, but not limited to, unanticipated events, after the date on which such statement is made, unless otherwise required by law. New factors emerge from time to time and it is not possible for management to predict all of these factors, nor can it assess the impact of each of these factors on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement.
CURRENCY PRESENTATION AND DEFINITIONS
In this annual report, all references to “U.S. dollar,” “$” and “USD” are to the lawful currency of the United States, all references to “euro,” “€” or “EUR” are to the single currency of the participating member states of the European and Monetary Union of the Treaty Establishing the European Community, as amended from time to time and all references to “South African rand,” “R” and “ZAR” are to the lawful currency of the Republic of South Africa.
Unless otherwise specified or the context requires otherwise in this annual report:
| • | references to “2020 Green Private Placement” refer to the €290 million (approximately $320 million) senior secured notes maturing on June 20, 2026 which were issued under a senior secured note purchase agreement entered with a group of institutional investors as purchasers of the notes issued thereunder as further described in “Item 5.B— Operating and Financial Review and Prospects— Liquidity and Capital Resources— Corporate debt agreements —2020 Green Private Placement”; |
| • | references to “Abengoa” refer to Abengoa, S.A., together with its subsidiaries, unless the context otherwise requires; |
| • | references to “ACT” refer to the gas-fired cogeneration facility located inside the Nuevo Pemex Gas Processing Facility near the city of Villahermosa in the State of Tabasco, Mexico; |
| • | references to “Adjusted EBITDA” have the meaning set forth in the Section entitled “Presentation of Financial Information—Non-GAAP Financial Measures” in the section below; |
| • | references to “Albisu” refer to the 10 MW solar PV plant located in Uruguay; |
| • | references to “Algonquin” refer to, as the context requires, either Algonquin Power & Utilities Corp., a North American diversified generation, transmission and distribution utility, or Algonquin Power & Utilities Corp. together with its subsidiaries; |
| • | references to “Algonquin ROFO Agreement and Liberty GES ROFO Agreement” refer to the agreements we entered into with Algonquin and with Liberty GES, respectively, on March 5, 2018, under which Algonquin and Liberty GES granted us a right of first offer to purchase any of the assets offered for sale located outside of the United States or Canada as amended from time to time. See “Item 7.B—Related Party Transactions—ROFO Agreements”; |
| • | references to “Amherst Island Partnership” refer to the holding company of Windlectric Inc; |
| • | references to “Annual Consolidated Financial Statements” refer to the audited annual consolidated financial statements as of December 31, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021, including the related notes thereto, prepared in accordance with IFRS as issued by the IASB (as such terms are defined herein), included in this annual report; |
| • | references to “ASI Operations” refer to ASI Operations LLC; |
| • | references to “Atlantica” refer to Atlantica Sustainable Infrastructure plc and, where the context requires, Atlantica Sustainable Infrastructure plc together with its consolidated subsidiaries; |
| • | references to “Atlantica Jersey” refer to Atlantica Sustainable Infrastructure Jersey Limited, a wholly-owned subsidiary of Atlantica; |
| • | references to “ATM Plan Letter Agreement” refer to the agreement by and among the Company and Algonquin dated August 3, 2021, pursuant to which the Company offers Algonquin the right but not the obligation, on a quarterly basis, to purchase a number of ordinary shares to maintain its percentage interest in Atlantica at the average price of the shares sold under the Distribution Agreement in the previous quarter, as adjusted; |
| • | references to “ATN” refer to ATN S.A., the operational electric transmission asset in Peru, which is part of the Guaranteed Transmission System; |
| • | references to “ATS” refer to Atlantica Transmision Sur S.A.; |
| • | references to “AYES Canada” refer to Atlantica Sustainable Infrastructure Energy Solutions Canada Inc., a vehicle formed by Atlantica and Algonquin to channel co-investment opportunities; |
| • | references to “Befesa Agua Tenes” refer to Befesa Agua Tenes, S.L.U.; |
| • | references to “cash available for distribution” or “CAFD” refer to the cash distributions received by the Company from its subsidiaries minus cash expenses of the Company (including third-party debt service and general and administrative expenses), including proceeds from the sale of assets; |
| • | references to “CAISO” refer to the California Independent System Operator; |
| • | references to “Calgary District Heating” or “Calgary” refer to the 55 MWt thermal capacity district heating asset in the city of Calgary which we acquired in May 2021; |
| • | references to “CENACE” refer to Centro Nacional de Control de Energía, the Mexican decentralized public agency, and an Independent System Operator; |
| • | references to “Chile PV 1” refer to the solar PV plant of 55 MW located in Chile; |
| • | references to “Chile PV 2” refer to the solar PV plant of 40 MW located in Chile; |
| • | references to “Chile PV 3” refer to the solar PV plant of 73 MW located in Chile; |
| • | references to “Chile TL 3” refer to the 50-mile transmission line located in Chile; |
| • | references to “Chile TL 4” refer to the 63-mile transmission line located in Chile; |
| • | references to “CNMC” refer to Comision Nacional de los Mercados y de la Competencia, the Spanish state-owned regulator; |
| • | references to “COD” refer to the commercial operation date of the applicable facility; |
| • | references to “Coso” refer to the 135 MW geothermal plant located in California; |
| • | references to the “Distribution Agreement” refer to the agreement entered into with BofA Securities, Inc., MUFG Securities Americas Inc. and RBC Capital Markets LLC, as sales agents, dated February 28, 2022 as amended on May 9, 2022, under which we may offer and sell from time to time up to $150 million of our ordinary shares and pursuant to which such sales agents may sell our ordinary shares by any method permitted by law deemed to be an “at the market offering” as defined by Rule 415(a)(4) promulgated under the U.S. Securities Act of 1933, as amended; |
| • | references to “DOE” refer to the U.S. Department of Energy; |
| • | references to “DTC” refer to The Depository Trust Company; |
| • | references to “EMEA” refer to Europe, Middle East and Africa; |
| • | references to “EPACT” refer to the Energy Policy Act of 2005; |
| • | references to “ESG” refer to environmental, social and corporate governance; |
| • | references to “Eskom” refer to Eskom Holdings SOC Limited, together with its subsidiaries, unless the context otherwise requires; |
| • | references to “EURIBOR” refer to Euro Interbank Offered Rate, a daily reference rate published by the European Money Markets Institute, based on the average interest rates at which Eurozone banks offer to lend unsecured funds to other banks in the euro wholesale money market; |
| • | references to “EU” refer to the European Union; |
| • | references to “Exchange Act” refer to the U.S. Securities Exchange Act of 1934, as amended, or any successor statute, and the rules and regulations promulgated by the SEC thereunder; |
| • | references to “Federal Financing Bank” refer to a U.S. government corporation by that name; |
| • | references to “FERC” refer to the U.S. Federal Energy Regulatory Commission; |
| • | references to “Fitch” refer to Fitch Ratings Inc.; |
| • | references to “FPA” refer to the U.S. Federal Power Act; |
| • | references to “Green Exchangeable Notes” refer to the $115 million green exchangeable senior notes due in 2025 issued by Atlantica Jersey on July 17, 2020, and fully and unconditionally guaranteed on a senior, unsecured basis, by Atlantica, as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements —Green Exchangeable Notes”; |
| • | references to “Green Project Finance” refer to the green project financing agreement entered into between Logrosan, the sub-holding company of Solaben 1 & 6 and Solaben 2 & 3, as borrower, and ING Bank, B.V. and Banco Santander S.A., as lenders, as amended in June 2023 as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements —Green Project Finance”; |
| • | references to “Green Senior Notes” refer to the $400 million green senior notes due in 2028, as further described in “Item 5.B—Liquidity and Capital Resources— Corporate debt agreements —Green Senior Notes”; |
| • | references to “gross capacity” refer to the maximum, or rated, power generation capacity, in MW, of a facility or group of facilities, without adjusting for the facility’s power parasitics’ consumption, or by our percentage of ownership interest in such facility as of the date of this annual report; |
| • | references to “GWh” refer to gigawatt hour; |
| • | references to “IAS” refer to International Accounting Standards issued by the IASB; |
| • | references to “IASB” refer to the International Accounting Standards Board; |
| • | references to “IFRIC 12” refer to International Financial Reporting Interpretations Committee’s Interpretation 12—Service Concessions Arrangements; |
| • | references to “IFRS as issued by the IASB” refer to International Financial Reporting Standards as issued by the IASB; |
| • | references to “IRA” refer to the U.S. Inflation Reduction Act; |
| • | references to “IPO” refer to our initial public offering of ordinary shares in June 2014; |
| • | references to “Italy PV” refer to the solar PV plants with combined capacity of 9.8 MW located in Italy; |
| • | references to “ITC” refer to investment tax credits; |
| • | references to “Kaxu” refer to the 100 MW solar plant located in South Africa; |
| • | references to “La Sierpe” refer to the 20 MW solar PV plant located in Colombia; |
| • | references to “La Tolua” refer to the 20 MW solar PV plant located in Colombia; |
| • | references to “Liberty GES” refer to Liberty Global Energy Solutions B.V., a subsidiary of Algonquin (formerly known as Abengoa-Algonquin Global Energy Solutions B.V. (AAGES)) which invests in the development and construction of contracted clean energy and water infrastructure assets; |
| • | references to “Logrosan” refer to Logrosan Solar Inversiones, S.A.; |
| • | references to “Lost time injury rate” refer to the total number of recordable accidents with leave (lost time injury) recorded in the last 12 months per two hundred thousand worked hours; |
| • | references to “LTIP” refer to the long-term incentive plans approved by the Board of Directors; |
| • | references to “MACRS” refer to the Modified Accelerated Cost Recovery System; |
| • | references to “M ft3” refer to million standard cubic feet; |
| • | references to “Monterrey” refer to the 142 MW gas-fired engine facility including 130 MW installed capacity and 12 MW battery capacity, located in Monterrey, Mexico; |
| • | references to “Multinational Investment Guarantee Agency” refer to the Multinational Investment Guarantee Agency, a financial institution member of the World Bank Group which provides political insurance and credit enhancement guarantees; |
| • | references to “MW” refer to megawatts; |
| • | references to “MWh” refer to megawatt hour; |
| • | references to “MWt” refer to thermal megawatts; |
| • | references to “Moody’s” refer to Moody’s Investor Service Inc.; |
| • | references to “NEPA” refer to the U.S. National Environment Policy Act; |
| • | references to “NOL” refer to net operating loss; |
| • | references to “Note Issuance Facility 2020” refer to the senior unsecured note facility dated July 8, 2020, as amended on March 30, 2021 of €140 million (approximately $155 million), with Lucid Agency Services Limited, as facility agent and a group of funds managed by Westbourne Capital, as purchasers of the notes issued thereunder, as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements — Note Issuance Facility 2020”; |
| • | references to “OECD” refer to the Organization for Economic Co-operation and Development; |
| • | references to “O&M” refer to operation and maintenance services provided at our various facilities; |
| • | references to “Omega Peru” refer to Omega Peru Operacion y Maintenimiento S.A.; |
| • | references to “operation” refer to the status of projects that have reached COD (as defined above); |
| • | references to “Pemex” refer to Petróleos Mexicanos; |
| • | references to “PFIC” refer to passive foreign investment company within the meaning of Section 1297 of the US Inland Revenue Code (the “IRC”); |
| • | references to “PG&E” refer to PG&E Corporation and its regulated utility subsidiary, Pacific Gas and Electric Company, collectively; |
| • | references to “PPA” refer to the power purchase agreements through which our power generating assets have contracted to sell energy to various off-takers; |
| • | references to “PTC” refer to production tax credits; |
| • | references to “PTS” refer to Pemex Transportation System; |
| • | references to “PV” refer to photovoltaic power; |
| • | references to “Revolving Credit Facility” refer to the credit and guaranty agreement with a syndicate of banks entered into on May 10, 2018 as amended on January 24, 2019, August 2, 2019, December 17, 2019, August 28, 2020, March 1, 2021, May 5, 2022 and May 30, 2023 providing for a senior secured revolving credit facility in an aggregate principal amount of $450 million, as further described in “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements — Note Issuance Facility 2020”; |
| • | references to “Rioglass” refer to Rioglass Solar Holding, S.A.; |
| • | references to “ROFO” refer to a right of first offer; |
| • | references to “ROFO Agreements” refer to the Liberty GES ROFO Agreement and Algonquin ROFO Agreement; |
| • | references to “RPS” refer to renewable portfolio standards adopted by 29 U.S. states and the District of Columbia that require a regulated retail electric utility to procure a specific percentage of its total electricity delivered to retail customers in the respective state from eligible renewable generation resources, such as solar or wind generation facilities, by a specific date; |
| • | references to “RRRE” refer to the Specific Remuneration System Register in Spain; |
| • | references to “SEC” refer to the U.S. Securities and Exchange Commission; |
| • | references to the “Shareholders’ Agreement” refer to the agreement by and among Algonquin Power & Utilities Corp., Abengoa-Algonquin Global Energy Solutions and Atlantica, dated March 5, 2018, as amended; |
| • | references to “Skikda” refer to the seawater desalination plant in Algeria, which is 34% owned by Atlantica; |
| • | references to “SOFR” refer to Secured Overnight Financing Rate; |
| • | references to “Solaben Luxembourg” refer to Solaben Luxembourg S.A.; |
| • | references to “Solnova 1, 3 & 4” refer to three solar plants with capacity of 50 MW each wholly owned by Atlantica, located in the municipality of Sanlucar la Mayor, Spain; |
| • | references to “S&P” refer to S&P Global Rating; |
| • | references to “Tenes” refer to Ténès Lilmiyah SpA, a water desalination plant in Algeria, which is 51% owned by Befesa Agua Tenes; |
| • | references to “Tierra Linda” refer to the 10 MW solar PV plant located in Colombia; |
| • | references to “U.K.” refer to the United Kingdom; |
| • | references to “U.S.” or “United States” refer to the United States of America; |
| • | references to “Vento II” refer to the wind portfolio in the U.S. in which we acquired a 49% interest in June 2021; and |
| • | references to “we,” “us,” “our,” “Atlantica” and the “Company” refer to Atlantica Sustainable Infrastructure plc and its consolidated subsidiaries, unless the context otherwise requires. |
PRESENTATION OF FINANCIAL INFORMATION
The financial information as of December 31, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021 is derived from, and qualified in its entirety by reference to, our Annual Consolidated Financial Statements, which are included elsewhere in this annual report and prepared in accordance with IFRS as issued by the IASB.
Certain numerical figures set out in this annual report, have been subject to rounding adjustments, and, as a result, the totals of the data in this annual report may vary slightly from the actual arithmetic totals of such information. Percentages and amounts reflecting changes over time periods relating to financial and other data set forth in “Item 5.A—Operating and Financial Review and Prospects—Operating Results” are calculated using the numerical data in our Annual Consolidated Financial Statements or the tabular presentation of other data (subject to rounding) contained in this annual report, as applicable, and not using the numerical data in the narrative description thereof.
Non-GAAP Financial Measures
This annual report contains non-GAAP financial measures including Adjusted EBITDA.
Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of our equity ownership).
Our management believes Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. Adjusted EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. Adjusted EBITDA is widely used by other companies in our industry.
Our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period and we aim to use it on a consistent basis moving forward and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.
We present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity. The non-GAAP financial measures including Adjusted EBITDA may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under IFRS as issued by the IASB. Non-GAAP financial measures and ratios are not measurements of our performance or liquidity under IFRS as issued by the IASB and should not be considered as alternatives to operating profit or profit for the year or any other performance measures derived in accordance with IFRS as issued by the IASB or any other generally accepted accounting principles or as alternatives to cash flow from operating, investing or financing activities.
Some of the limitations of these non-GAAP measures are:
| • | they do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments; |
| • | they do not reflect changes in, or cash requirements for, our working capital needs; |
| • | they may not reflect the significant interest expense, or the cash requirements necessary, to service interest or principal payments, on our debts; |
| • | although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often need to be replaced in the future and Adjusted EBITDA does not reflect any cash requirements that would be required for such replacements; |
| • | the fact that other companies in our industry may calculate Adjusted EBITDA differently than we do, which limits their usefulness as comparative measures. |
Information presented as the pro rata share of our unconsolidated affiliates reflects our proportionate ownership of each asset in our portfolio that we do not consolidate and has been calculated by multiplying our unconsolidated affiliates’ financial statement line items by the Company’s percentage ownership thereto. Note 7 to the Annual Consolidated Financial Statements includes a description of our unconsolidated affiliates and our pro rata share thereof. We do not control the unconsolidated affiliates. Multiplying our unconsolidated affiliates’ financial statement line items by the Company’s percentage ownership may not accurately represent the legal and economic implications of holding a non-controlling interest in an unconsolidated affiliate. We include depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of our equity ownership) because we believe it assists investors in estimating the effect of such items in the profit/(loss) of entities carried under the equity method (which is included in the calculation of our Adjusted EBITDA) based on our economic interest in such unconsolidated affiliates. Each unconsolidated affiliate may report a specific line item in its financial statements in a different manner. In addition, other companies in our industry may calculate their proportionate interest in unconsolidated affiliates differently than we do, limiting the usefulness of such information as a comparative measure. Because of these limitations, the information presented as the pro-rata share of our unconsolidated affiliates should not be considered in isolation or as a substitute for our or such unconsolidated affiliates’ financial statements as reported under applicable accounting principles.
PRESENTATION OF INDUSTRY AND MARKET DATA
In this annual report, we rely on, and refer to, information regarding our business and the markets in which we operate and compete. The market data and certain economic and industry data and forecasts used in this annual report were obtained from internal surveys, market research, governmental and other publicly available information, independent industry publications and reports prepared by industry consultants. We believe that these industry publications, surveys and forecasts are reliable, but we have not independently verified them, and there can be no assurance as to the accuracy or completeness of the included information.
Certain market information and other statements presented herein regarding our position relative to our competitors are not based on published statistical data or information obtained from independent third parties but reflect our best estimates. We have based these estimates upon information obtained from our customers, trade and business organizations and associations and other contacts in the industries in which we operate.
Elsewhere in this annual report, statements regarding our contracted assets and concessions activities, our position in the industries and geographies in which we operate are based solely on our experience, our internal studies and estimates and our own investigation of market conditions.
All of the information set forth in this annual report relating to the operations, financial results or market share of our competitors has been obtained from information made available to the public in such companies’ publicly available reports and independent research, as well as from our experience, internal studies, estimates and investigation of market conditions. We have not funded, nor are we affiliated with, any of the sources cited in this annual report. We have not independently verified the information and cannot guarantee its accuracy.
All third-party information, as outlined above, has to our knowledge been accurately reproduced and, as far as we are aware and are able to ascertain, no facts have been omitted which would render the reproduced information inaccurate or misleading, but there can be no assurance as to the accuracy or completeness of the included information.
PART I
| ITEM 1. | IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS |
Not applicable.
| ITEM 2. | OFFER STATISTICS AND EXPECTED TIMETABLE |
Not applicable.
| B. | Capitalization and Indebtedness |
Not applicable.
| C. | Reasons for the Offer and Use of Proceeds |
Not applicable.
Investing in our securities involves a high degree of risk. Before making any investment decision, you should carefully consider the risks and uncertainties described below, together with the other information contained in this annual report, including our Annual Consolidated Financial Statements and related notes, included elsewhere in this annual report. The risks described below may not be the only risks we face. We have described only those risks that we currently consider to be material and there may be additional risks that we do not currently consider to be material or of which we are not currently aware. Any of the following risks and uncertainties could have a material adverse effect on our business, prospects, results of operations and financial condition. The market price of our securities could decline due to any of these risks and uncertainties, and you could lose all or part of your investment.
Risk Factor Summary
Set forth below is only a summary of the key risks we face. See below under this “Item 3.D—Risk Factors.” for a detailed discussion of the numerous risks and uncertainties to which the Company is subject.
Risks Related to Our Business and Our Assets
| • | Our failure to maintain safe work environments may expose us to significant financial losses, as well as civil and criminal liabilities. |
| • | Counterparties to our off-take agreements may not fulfill their obligations and, as our contracts expire, we may not be able to replace them with agreements on similar terms or at all in light of increasing competition in the markets in which we operate. |
| • | The PPAs and concession agreements under which we conduct some of our operations are subject to revocation, termination or tariff reduction. |
| • | The performance of our assets under our PPAs or concession contracts may be adversely affected by problems including those related to our reliance on suppliers. |
| • | Supplier concentration may expose us to significant financial credit or performance risk. |
| • | Certain of our facilities may not perform as expected. |
| • | Maintenance, expansion and refurbishment of electric generation and other facilities involve significant risks that could result in unplanned power outages or reduced output or availability. |
| • | The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, or if the geothermal resource is lower than expected, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations. |
| • | Our business may be adversely affected by an increased number of extreme and chronic weather events including related to climate change. |
| • | Our insurance may be insufficient to cover relevant risks or the cost of our insurance may increase. |
| • | A pandemic could have a material adverse impact on our business, financial condition, liquidity, results of operations, cash flows, cash available for distribution and ability to make cash distributions to our shareholders. |
| • | We may have joint venture partners or other co-investors with whom we have material disagreements. |
| • | We depend on our key personnel and our ability to attract and retain skilled personnel. The operation and maintenance of most of our assets is labor intensive, and therefore work stoppages by employees could harm our business. |
| • | Revenue from some of our renewable energy facilities is or may be partially exposed to market electricity prices. |
| • | Our information technology and communications systems are subject to cybersecurity risk and other risks. |
Risks Related to Our Relationship with Algonquin and Abengoa
| • | Algonquin is our largest shareholder and exercises substantial influence over us. |
| • | Our ownership structure and certain agreements may create significant conflicts of interest that may be resolved in a manner that is not in our best interests. |
| • | Legal proceedings involving Abengoa, our former largest shareholder, and its current and previous insolvency processes and events and circumstances that led to them could affect us. |
Risks Related to Our Indebtedness
| • | Our indebtedness could limit our ability to react to changes in the economy or our industry, expose us to the risk of increased interest rates and limit our activities due to covenants in existing financing agreements. It could also adversely affect the ability of our project subsidiaries to make distributions to Atlantica, our ability to fund our operations, pay dividends or raise additional capital. |
| • | We may not be able to arrange the required or desired financing for investments and acquisitions and for the successful financing or refinancing of the Company’s project level and corporate level indebtedness. |
| • | Potential future defaults by our subsidiaries, our off-takers, our suppliers or other persons could adversely affect us. |
| • | The process to explore and evaluate potential strategic alternatives may not be successful. |
Risks Related to Our Growth Strategy
| • | We may not be able to identify or consummate future investments and acquisitions on favorable terms, or at all. |
| • | Our ability to develop renewable projects is subject to development and construction risks and risks associated with the arrangements with our joint venture partners. |
| • | In order to grow our business, we may invest in or acquire assets or businesses which have a higher risk profile or are less ESG-friendly than certain assets in our current portfolio. |
| • | We cannot guarantee the success of our recent and future investments. |
| • | Our cash dividend policy may limit our ability to grow and make investments through cash on hand. |
Risks Related to the Markets in Which We Operate
| • | We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties. |
Risks Related to Regulation
| • | We are subject to extensive governmental regulation in a number of different jurisdictions, including stringent environmental regulation. |
| • | Revenues in our solar assets in Spain are subject to review periodically. |
Risks Related to Ownership of Our Shares
| • | We may not be able to pay a specific or increasing level of cash dividends to holders of our shares in the future. |
| • | Future dispositions of our shares by substantial shareholders or the perception thereof may cause the price of our shares to fall. |
Risks Related to Taxation
| • | Changes in our tax position can significantly affect our reported earnings and cash flows. |
| • | Our future tax liability may be greater than expected if we do not use sufficient NOLs to offset our taxable income. |
| • | Our ability to use U.S. NOLs to offset future income may be limited. |
| I. | Risks Related to Our Business and Our Assets |
Our failure to maintain safe work environments may expose us to significant financial losses, as well as civil and criminal liabilities.
The ownership, construction and operation of our assets often put our employees and others, including those of our subcontractors, in close proximity with large pieces of mechanized equipment, moving vehicles, manufacturing or industrial processes, electrical equipment, batteries, heat or liquids stored under pressure or at high temperatures and highly regulated materials. On most projects and at most facilities, we, together in some cases with the operation and maintenance supplier or the construction company, are responsible for safety. Accordingly, we must implement safe practices and safety procedures, which are also applicable to on-site subcontractors. If we or the operation and maintenance supplier or the construction company fail to design and implement such practices and procedures, or if the practices and procedures are ineffective, or if our operation and maintenance service providers or the contractors in charge of the construction of our assets or other suppliers do not follow them, our employees and others may become injured. In addition, the construction and operation of our facilities can involve the handling of hazardous and other highly regulated materials, which, if improperly handled or disposed of, could subject us or our suppliers to civil and criminal liabilities. Unsafe work sites also have the potential to increase employee turnover, increase the cost of a project or the operation of a facility, and raise our operating costs. Although we maintain teams whose primary purpose is to ensure we implement effective health, safety and environmental work procedures throughout our organization, the failure to comply with such regulations could subject us to reputational damage and/or liability. In addition, we may incur liability based on complaints of illness or disease resulting from exposure of employees or other persons to hazardous materials or equipment that we handle or are present in our workplaces. Any of the foregoing could result in civil, criminal or other liabilities, reputational damage and/or financial losses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Counterparties to our off-take agreements may not fulfill their obligations and, as our contracts expire, we may not be able to replace them with agreements on similar terms or at all in light of increasing competition in the markets in which we operate.
A significant portion of the electric power we generate, the transmission capacity we have, and our desalination capacity is sold under long-term off-take agreements with public utilities, industrial or commercial end-users or governmental entities, with a weighted average remaining duration of approximately 131 years as of December 31, 2023.
If, for any reason, including, but not limited to, a deterioration in their financial situation or bankruptcy, any of our clients are unable or unwilling to fulfill their related contractual obligations or if they refuse to accept delivery of power delivered thereunder or if they otherwise terminate such agreements prior to the expiration thereof, or if prices were re-negotiated under a bankruptcy situation or a contract default situation, or if they delayed payments, our business, financial condition, results of operations and cash flow may be materially adversely affected. Furthermore, to the extent any of our power, transmission capacity or desalination capacity purchasers are, or are controlled by, governmental entities, our facilities may be subject to sovereign risk or legislative or other political action that may hamper their contractual performance.
The credit rating of Eskom is currently B from S&P, B2 from Moody’s and B from Fitch. Eskom which is the off-taker of our Kaxu solar plant, is a state-owned, limited liability company, wholly owned by the Republic of South Africa. Eskom’s payment guarantees to our Kaxu solar plant are underwritten by the South African Department of Mineral Resources and Energy, under the terms of an implementation agreement. The credit ratings of the Republic of South Africa have also weakened and as of the date of this annual report are BB-/Ba2/BB- by S&P, Moody’s and Fitch, respectively.
In addition, Pemex’s credit rating is currently BBB, B3 and B+ from S&P, Moody’s and Fitch, respectively. We have experienced delays in collections in the past, especially since the second half of 2019, which have been significant in certain quarters, including the fourth quarter of 2023.
1 Calculated as weighted average years remaining as of December 31, 2023 based on CAFD estimates for the 2024-2027 period, including assets that have reached COD before March 1, 2024.
The cost of renewable energy has considerably decreased since most of our plants were built and renewable energy has become a consistently competitive source of power generation compared to traditional fossil fuels in many regions, and it is expected to continue falling in the future. Our competitors may be able to operate at lower costs, which may adversely affect our ability to compete for off-take agreement renewals. Our off-takers may try to renegotiate or terminate our PPAs, most of which were signed several years ago and may be more expensive than recent PPAs or current market prices. We may not be able to replace an expiring or terminated agreement with an agreement on equivalent terms and conditions, including at prices that permit operation of the related facility on a profitable basis.
Our inability to enter into new or replacement off-take agreements or to compete successfully against current and future competitors may have a material adverse effect on our business, financial condition, results of operations and cash flows.
The power purchase agreements and concession agreements under which we conduct some of our operations are subject to revocation, termination or tariff reduction.
Certain of our operations are conducted pursuant to contracts and concessions granted by various governmental bodies and others are pursuant to PPAs signed with governmental entities and private clients. Generally, these contracts and concessions give us rights to provide services for a limited period, subject to various governmental regulations. The governmental bodies or private clients responsible for regulating and monitoring these services often have broad powers to monitor our compliance with the applicable concession and PPAs and can require us to supply them with technical, administrative and financial information. Among other obligations, we may be required to comply with operating targets and efficiency and safety standards established in the respective concession. Such commitments and standards may be amended in certain cases by the governmental bodies. Our failure to comply with the concession agreements and PPAs or other regulatory requirements may result in contracts and concessions being revoked, not being granted, upheld or renewed in our favor, or, if granted, upheld or renewed, may not be done on as favorable terms as currently applicable. In addition, in some cases our off-takers have an option to acquire the asset or to terminate the concession agreement in exchange for a compensation. All the above could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, in some cases, if we fail to comply with certain pre-established conditions, the government or customer (as applicable) may reduce the tariffs or rates payable to us. Also, during the life of a PPA or a concession, the relevant government authority may in some cases unilaterally impose additional restrictions on our tariff rates, subject to the regulatory frameworks applicable in each jurisdiction. Furthermore, changes in laws and regulations may, in certain cases, have retroactive effect and expose us to additional compliance costs or undermine our existing financial and business planning.
The performance of our assets under our power purchase agreements or concession contracts may be adversely affected by problems including those related to our reliance on suppliers.
Our projects rely on the supply of services, equipment, including technologically complex equipment and software which we subcontract in some cases to third-party suppliers in order to meet our contractual obligations under our PPAs and concessions. In circumstances where key components of our equipment, including, but not limited to, turbines, water pumps, heat exchangers, PV panels, solar fields, tanks, batteries, transformers or electrical generators fail because of design failures or faulty operation or for any other reason, we rely on internal teams and third parties to continue operating our assets. Equipment may not last as long as expected and we may need to replace it earlier than planned. Damages to our equipment may not be covered by insurance in place. In some cases, the replacement of damaged equipment can take a long period of time, which can cause our plants to curtail or cease operations during such time, which could have a negative impact on our business, financial condition, results of operations and cash flows.
For example, Solana and Kaxu have experienced technical issues in their storage and solar field systems. Repairs have been carried out in both assets. In Solana, availability in the storage system was lower than expected in 2021, 2022 and 2023 due to the repairs and replacements that we are carrying out after leaks were identified in the first quarter of 2020. These works have impacted production in 2021, 2022 and 2023, together with a lower solar field performance and may impact production in 2024 and upcoming years. We experienced delays in the repairs and replacements that we carried out. We cannot guarantee that the repairs will be effective, that Solana will reach expected production or that additional repairs will not be required. In addition, in 2023 an unscheduled outage occurred at Kaxu when a problem was found in the turbine, a few weeks after a scheduled turbine major overhaul was carried out by Siemens, the original equipment manufacturer. Part of the damage and the business interruption is covered by our insurance property policy, after a 60-day deductible. The plant restarted operations in mid-February 2024. Restarting operations after a long outage might result in lower production during a ramp-up period. Similar interruptions could happen again at our plants due to failure of key equipment.
In addition, we currently have several projects under construction in different geographies. For example, Coso Batteries 1 and Coso Batteries 2 are currently under construction. Both projects were fully developed in-house. We will rely on batteries, software and other components manufactured by third parties which may contain undetected manufacturing-related defects or errors in a sector where our expertise is not as proven as in the rest of our businesses yet. Design failures, technical inspections by suppliers or the need to replace key equipment can require unexpected capital expenditures and/or outages in our plants, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, the delivery by our subcontractors of products or services which are not in compliance with the requirements of the subcontract, or delayed supply of products and services, can cause us to be in default under our contracts with our concession counterparties. To the extent we are not able to transfer all of the risk or be fully indemnified by third-party contractors and suppliers, we may be subject to a claim by our customers as a result of a problem caused by a third party that could have a material adverse effect on our reputation, business, results of operations, financial condition and cash flows.
Supplier concentration may expose us to significant financial credit or performance risk.
We often rely on a single contracted supplier or a small number of suppliers for the provision of certain personnel, spare parts, equipment, technology, fuel, transportation of fuel, and/or other services required for the operation of certain of our facilities. If any of these suppliers, including Siemens, Naes, GE, Nordex, Tesla, construction suppliers and equipment suppliers for assets under construction cannot or will not perform under their operation and maintenance and other agreements with us, or satisfy their related warranty obligations, we will need to access the marketplace to replace these suppliers or acquire or repair these products. There can be no assurance that the marketplace can provide these products and services as, when and where required. We may not be able to enter into replacement agreements on favorable terms or at all. If we are unable to enter into replacement agreements to provide for equipment, technology or fuel and other required services, we may have to seek to purchase the related goods or services at higher prices. We may also be required to make significant capital contributions to remove, replace or redesign equipment that cannot be supported or maintained by replacement suppliers, which may have a material adverse effect on our business, financial condition, results of operations, and cash flows.
The failure of any supplier to fulfill its contractual obligations to us may have a material adverse effect on our business, financial condition, results of operations and cash flows. Consequently, the financial performance of our facilities may be dependent on the credit quality of, and continued performance by, our suppliers and vendors.
Certain of our facilities may not perform as expected.
Our expectations regarding the operating performance of certain assets in our portfolio, particularly Solana and Kaxu, assets recently acquired such as Italy PV 4 and Chile PV 3 or assets which have recently ended construction such as Albisu, La Tolua, Tierra Linda and Honda 1, or assets under construction are based on assumptions, estimates and past experience, and without the benefit of a substantial operating history under our control. Our projections regarding our ability to generate cash available for distribution assumes facilities perform in accordance with our expectations. However, the ability of these facilities to meet our performance expectations is subject to the risks inherent to the construction and operation of such facilities, including, but not limited to, degradation of equipment in excess of our expectations, system failures and outages and higher maintenance capital expenditures than initially expected. The failure of these facilities to perform as we expect and/or higher than expected operational costs or maintenance capital expenditures may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Maintenance, expansion and refurbishment of electric generation and other facilities involve significant risks that could result in unplanned power outages or reduced output or availability.
The facilities in our portfolio may require periodic upgrading and improvement in the future. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce the performance and availability of our facilities below expected levels, reducing our revenues. Degradation of the performance of our solar facilities above levels provided for in the related off-take agreements may also reduce their revenues. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facilities may also reduce profitability.
If we make any major modifications to our renewable power generation facilities, efficient natural gas or electric transmission lines, we may be required to comply with more stringent environmental regulations, which would likely result in substantial additional capital expenditures. We may also choose to repower, refurbish or upgrade our facilities based on our assessment that such activity will provide adequate financial returns. Such facilities require time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. This may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our business may be adversely affected by an increased number of extreme and chronic weather events including related to climate change.
Climate change is causing an increasing number of severe, chronic and extreme weather events which are a risk to our facilities and may impact them. In addition, climate change may cause transition risks, related to existing and emerging regulation related to climate change. These risks include:
| • | Acute physical. Severe and extreme weather events include severe winds and rains, hail, hurricanes, cyclones, droughts, as well as the risk of fire and flooding, among others and are becoming more frequent as a result of climate change. Any of these extreme weather events could cause damage to our assets and/or business interruption. |
Our assets were designed and built by third parties complying with technical codes, local regulations and environmental impact studies. Technical codes should consider extreme weather events based on historical information and should include design safety margins. However, an increased severity of extreme weather events could have an impact on our assets.
| | - | Severe floods could damage our solar generation assets or our water facilities. Floods can also cause landslides which may affect our transmission lines. |
| - | If our transmission assets caused a fire, we could be found liable if the fire damaged third parties. |
| - | Severe winter weather, like the storm in February 2021 in Texas, could cause supply from wind farms to decline due to wind turbine equipment freezing. In 2023, a winter storm affected a transmission line in our geothermal asset Coso in California and affected production for several days. Also, natural gas assets and battery systems could face operational issues caused by freezing or very cold conditions. |
| - | Rising temperatures and droughts could cause wildfires like the ones that have affected California in recent years. In California wildfires have been especially catastrophic, causing human fatalities and significant material losses. Although our assets in California are located in areas without trees and vegetation, wildfires affected PG&E, one of our clients in 2018 and 2019. |
| - | Severe winds could cause damage to the solar fields at our solar assets. |
Components of our equipment and systems, such as structures, mirrors, absorber tubes, blades, PV panels, batteries or transformers are susceptible to being damaged by severe weather. In addition, replacement and spare parts for key components may be difficult or costly to acquire or may be unavailable and may have long lead times. In addition, damage caused by our equipment to third parties due to weather events can result in liabilities for the Company.
| o | An increase in temperatures can reduce efficiency and increase operating costs at our plants. The main impacts of rising temperatures include: |
| - | Lower turbine efficiency in our efficient natural gas asset. |
| | - | Reduced efficiency at our solar photovoltaic generation assets. |
| - | Lower air density at our wind facilities. |
| - | Lower efficiency in battery systems. |
| o | A reduction of mean precipitations may result in a reduction of availability of water from aquifers and could also modify the main water properties at our generation facilities. Droughts could result in water restrictions that may affect our operations, and which may force us to stop generation at some of our facilities. For example, some regions in Spain are currently experiencing a severe drought, which may affect our facilities. A deterioration of the quality of the water would also have a negative impact on chemical costs in our water treatment plants at our generating facilities. |
If any of these acute physical or chronic physical risks were to materialize at any of our plants, facilities or electric transmission lines, we may not be able to carry out our business activities at that location or such operations could be significantly reduced. Any of these circumstances could result in lost revenue at these sites during the period of disruption and costly remediation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
| • | Current Regulation. Atlantica is directly affected by environmental regulation at all our assets. This includes climate-related risks driven by laws, regulation, taxation, disclosure of emissions and other practices. As an example, we are subject to the requirements of the U.K. Climate Change Act 2008 on greenhouse gas (“GHG”) emissions reporting, and the Commission Regulation (EU) No 601/2012. Two U.S. solar plants are also subject to the permits under the Clean Air Act. |
Starting from 2024, we are required under UK regulations to include certain climate-related disclosures aligned with the Task Force on Climate-Related Financial Disclosures (TCFD) in our UK Annual Report.
Additionally, a group of our subsidiaries is currently subject to the EU Non-financial Reporting Directive as adopted by implementing regulations in Spain. In particular, on January 5, 2023, the European Union’s Corporate Sustainability Reporting Directive (“CSRD”) entered into force. Among other things, the CSRD expands the number of companies required to publicly report sustainability and ESG-related information on their management report to understand how sustainability matters affect their own development, performance and position, and defines the related information that companies are required to report in accordance with European Sustainability Reporting Standards (“ESRS”). The CSRD raises the bar on ESG matters and requires a “double materiality” analysis, meaning companies will have to detail both the impacts on the environment (e.g. the impact of corporate activity on sustainability matters from perspective of citizens, consumers, employees, etc.) and the climate-related risks they face (e.g. sustainability matters which from the investor perspective are material the company’s development, performance and position). Impacts, risks and opportunities are material if they satisfy one or both of these materiality tests. A sub consolidated group of our subsidiaries will fall within the scope of the new reporting requirements , effective January 1, 2025, and we will be required to provide such information for the fiscal year 2025 for this sub-consolidated group. In addition, the entire group will become subject to the CSRD from January 1, 2028. This will involve implementing processes to gather the relevant data, conduct materiality assessments and prepare a CSRD-compliant report, which will likely be a time-consuming and costly exercise and in the event that our disclosures prove incorrect we may incur liabilities.
| • | Emerging Regulation. Changes in regulation could have a negative impact on Atlantica’s growth or cause an increase in costs. Currently, renewable energy projects benefit from various U.S. federal, state and local governmental incentives. These policies have had a significant impact on the development of renewable energy and they could change. These incentives make the development of renewable energy projects more competitive by providing tax credits, accelerated depreciation and expensing for a portion of the development costs. The U.S. Inflation Reduction Act (IRA) signed into law on August 16, 2022 increased and / or extended some of these incentives and established new ones. For example, the IRA includes, among other incentives, a 30% solar investment tax credit (“ITC”) for solar projects to be built until 2032, a production tax credit (“PTC”) for wind projects to be built until 2032, a 30% ITC for standalone storage projects to be built until 2032 and a new tax credit that will award up to $3/kg for low carbon hydrogen. The IRA also includes transferability options for the ITCs and PTCs, which should allow an easier and faster monetization of these tax credits. A reduction in such incentives in the future could decrease the attractiveness of renewable energy to developers, utilities, retailers and customers. In addition, an increase in regulation could cause an increase in our compliance costs. See “—VII Risks Related to Regulation — Government regulations could change at any time and such changes may negatively impact our current business and growth strategy”. |
In addition, there may be additional taxes on GHG emissions. Some governments in certain geographies already have mechanisms in place for taxing GHG emissions and some other governments are considering establishing comparable mechanisms for the future. Additional taxes on emissions would increase the costs of operating the assets in our portfolio which have GHG emissions, particularly our natural gas assets.
Furthermore, several regions are increasing reporting requirements in relation to climate-related risks and opportunities and we will or may be subject to several of those requirements. We will be subject to new mandatory climate-related disclosures pursuant to SEC, proposed rules that are currently in draft form. The consolidated group or part of our subsidiaries will or may be subject to the Corporate Sustainability Reporting Directive in Europe, IFRS requirements for disclosure of sustainability-related financial information and may be subject to the California Climate Related Regulation.
| • | Reputation. Decreased access to capital. |
Climate change and ESG are important criteria for some shareholders and investors. While a significant part of our business consists of renewable energy assets, we also own assets that can be considered less environmentally friendly, currently consisting of a 300 MW efficient natural gas plant and a non-controlling stake in a gas-fired engines facility which uses natural gas, both in Mexico. Owning these assets with higher GHG emissions than the rest of the portfolio may have a negative reputational impact on Atlantica as a renewable energy company. We rely on capital markets and bank financing to fund our growth initiatives. If our reputation worsened, our cost of capital could increase and our access to capital may become more difficult. In addition, some potential employees and /or suppliers could perceive Atlantica as a less appealing company due to an eventual deterioration in our reputation due to the foregoing.
| • | Downstream. Some of our clients are large utilities or industrial corporations. These are also exposed to significant climate change related risks, including current and emerging regulation, acute and chronic physical risks. If our clients are affected by climate related risks, this could impact their credit quality and affect their ability to comply with the existing contract. |
The efforts we may undertake in the future, to respond to the evolving and increased regulation, environmental initiatives of customers, investors, shareholders and other stakeholders, reputational risks related to climate change and climate related risks affecting our clients may cause increased costs, more difficult access to capital markets, a deterioration in the credit quality of our clients and other negative circumstances which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, or if the geothermal resource is lower than expected, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.
The electricity produced, and revenues generated by a renewable energy generation facility are highly dependent on suitable meteorological conditions, and associated weather conditions which are beyond our control.
Unfavorable weather and atmospheric conditions could impair the effectiveness of our assets or reduce their output beneath their rated capacity or require shutdown of key equipment, hampering operation of our renewable assets and our ability to achieve forecasted revenues and cash flows.
We base our investment decisions with respect to each renewable generation facility on the findings of related wind, solar and geothermal studies conducted on-site by third parties prior to construction or based on historical conditions at existing facilities. However, actual climatic conditions at a facility site, particularly wind conditions, which are sometimes severe, may not conform to the findings of these studies and therefore, our solar, wind and geothermal energy facilities may not meet anticipated production levels or the rated capacity of its generation assets, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our geothermal asset Coso depends on the geothermal resource available on the site of the plant, which is also ultimately beyond our control. If geothermal resource does not meet our expectations as it is, this may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our business may be adversely affected by catastrophes, natural disasters, unexpected geological or other physical conditions, or criminal or terrorist acts at one or more of our plants, facilities and electric transmission lines.
If one or more of our plants, facilities or electric transmission lines were to be subject in the future to fire, flood, earthquakes, electric storms, lightning (especially in our wind farms), drought or other natural disaster, terrorism, or other catastrophe, or if unexpected geological or other adverse physical conditions were to occur at any of our plants, facilities or electric transmission lines, we may not be able to carry out our business activities at that location or such operations could be significantly reduced. We own two assets in Southern California, which is an area classified as high seismic risk. Any of these circumstances could result in lost revenue at these sites during the period of disruption and costly remediation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, it is possible that our sites and assets could be affected by criminal or terrorist acts. There are also certain risks for which we may not be able to acquire adequate insurance coverage, including earthquakes and severe convective storms. Any such events could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our insurance may be insufficient to cover relevant risks or the cost of our insurance may increase.
We cannot guarantee that our insurance coverage is, or will be, sufficient to cover all the possible losses we may face in the future. Our property damage and business interruption policy have significant deductibles and exclusions with respect to some key equipment which, if damaged, could result in financial losses and business interruptions. Moreover, insurance market terms and conditions have become more onerous over the last few years and insurance companies are requiring some companies in our sector to retain a portion of the overall risks instead of transferring 100% to the insurers. As a result, we have self-retained a portion of our own risks and may need to increase this percentage in the future. If equipment failed in one of our assets and this equipment was part of the insurance exclusions or if the event was part of the risks we self-insured, we would need to assume the repairs and business interruption costs, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Furthermore, some of our project finance agreements and PPAs include specific conditions regarding insurance coverage that we may need to modify. If we did not obtain a waiver from our project finance lenders accepting these modifications, an event of default could be triggered by our lenders due to non-compliance with the terms of the project finance agreement. If we were to incur a serious uninsured loss or a loss that significantly exceeded the coverage limits established in our insurance policies or we were not able to modify coverage conditions, this could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, our insurance policies are subject to periodic renewals and the terms of the renewal are in some cases subject to approval by our lenders or counterparties. If we were unable to renew our insurance coverage, we would not be in compliance with the requirements of our project finance agreements and our PPAs, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. If insurance premiums were to increase in the future and/or or if additional key components were excluded from insurance coverage and/or if certain types of insurance coverage were to become unavailable or there was a further increase in deductibles for damages and/or loss of production, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, we might not be able to maintain insurance coverage comparable to those in effect in the past or currently at comparable cost, or at all. If insurance costs materially increased, such additional costs could have a material adverse effect on our business, financial condition, results of operations and cash flows.
A pandemic could have a material adverse impact on our business, financial condition, liquidity, results of operations, cash flows, cash available for distribution and ability to make cash distributions to our shareholders.
A pandemic could affect our operation and maintenance activities. We may experience delays in certain operation and maintenance activities, or certain activities may take longer than usual, or, in a worst-case scenario, a potential outbreak at one of our assets may prevent our employees or our operation and maintenance suppliers’ employees from operating the plant. All these can hamper or prevent the operation and maintenance of our assets, which may result in a material adverse effect on our business, financial condition, results of operations and cash flows.
We could also experience commercial disputes with our clients, suppliers and partners related to implications of a pandemic in contractual relations. All the risks referred to can cause delays in distributions from our assets to the holding company. In addition, we may experience delays in distributions due to logistic and bureaucratic difficulties to approve those distributions, which can negatively affect our cash available for distributions, our business, financial condition and cash flows. If we were to experience delays in distributions due to the risks previously mentioned and this situation persisted over time, we may fail to comply with financial covenants in our credit facilities and other financing agreements. All these situations may have a material impact on our business, financial condition, results of operations or cash flows or the pace or extent of any subsequent recovery.
We may have joint venture partners or other co-investors with whom we have material disagreements.
We have made and may continue to make equity investments in certain strategic assets managed by or together with third parties, including governmental entities and private entities. In certain cases, we may only have partial or joint control over a particular asset. We hold a minority stake in Vento II (our 596 MW wind portfolio in the United States composed by Elkhorn Valley, Prairie Star, Twin Groves II and Lone Star II), Honaine (Algeria), Monterrey (Mexico), Amherst (Canada) and Ten West Link (United States) and do not have control over the operation of these assets. In addition, we have partners in Seville PV, Solacor 1 & 2, Solaben 2 & 3, Skikda, Kaxu, Chile PV 1, Chile PV 2 and Chile PV 3 and we have invested through a debt instrument in Tenes. We also have partners in projects and assets under development or construction. Investments in assets or projects under development or construction over which we have no control, or partial or joint control are subject to the risk that the other shareholders of the assets, who may have different business or investment strategies than us or with whom we may have a disagreement or dispute, may have the ability to independently make or block business, financial or management decisions, such as appoint members of management, which may be crucial to the success of the project or our investment in the project, or otherwise implement initiatives which may be contrary to our interests. If we do not have control of a project or an asset, our partner may decide to sell such project or asset under terms and conditions that may not be the most beneficial to us. In Ten West Link we hold minority stakes, and our partner is an infrastructure fund that may decide to sell these assets in the future. In Monterrey, our partner initiated a process to sell its 70% stake in the asset and we do not have control of this process. Additionally, the approval of other shareholders or partners may be required to sell, pledge, transfer, assign or otherwise convey our interest in such assets. Alternatively, other shareholders may have rights of first refusal or rights of first offer in the event of a proposed sale or transfer of our interests in such assets or in the event we acquire an interest in new assets pursuant to ROFO agreements with third parties. These restrictions may limit the price or interest level for our interests in such assets, in the event we want to sell such interests.
Finally, our partners in existing or future projects may be unable, or unwilling, to fulfill their obligations under the relevant shareholder agreements, may experience financial or other difficulties or might sell their position to third parties that we did not choose, which may adversely affect our investment in a particular joint venture or adversely affect us. In certain of our joint ventures, we may also rely on the expertise of our partners and, as a result, any failure to perform its obligations in a diligent manner could also adversely affect the joint venture. If any of the foregoing were to occur, our business, financial condition, results of operations and cash flows may be materially adversely affected.
We depend on our key personnel and our ability to attract and retain skilled personnel. The operation and maintenance of most of our assets is labor intensive, and therefore work stoppages by employees could harm our business.
In some of the geographies where we operate, competition for qualified personnel is high and our turnover has increased recently, in particular in the United States. Some of our assets are in remote locations, and it may be difficult for us to retain employees or to cover certain positions. We may experience difficulty in hiring and retaining employees with appropriate qualifications. We may face high turnover, requiring us to dedicate time and resources to find and train new employees. The challenging markets in which we compete for talent may also require us to invest significant amounts of cash and equity to attract and retain employees. If we fail to attract new personnel or fail to retain and motivate our current personnel, the performance of our assets, our business and future growth prospects and ability to compete could be adversely impacted.
In addition, the operation and maintenance of most of our assets is labor intensive and in many cases our employees and our operators’ employees are covered by collective bargaining agreements. A dispute with a union or employees represented by a union could result in production interruptions caused by work stoppages. In addition, we subcontract the operation and maintenance services for some of our assets. If our employees or our operators’ employees were to initiate a work stoppage, they may not be able to reach an agreement with them in timely fashion. If a strike or work stoppage or disruption were to occur, our business, financial conditions, results of operations and cash flows may be materially adversely affected.
Revenue from some of our renewable energy facilities is or may be partially exposed to market electricity prices.
We currently have three assets with merchant revenues (Chile PV 1 and Chile PV 3, where we have a 35% ownership, and Lone Star II, where we have a 49% ownership) and one asset with partially contracted revenues (Chile PV 2, where we have a 35% ownership). Although assets with merchant exposure represent less than a 2%2 of our portfolio in terms of Adjusted EBITDA, if electricity market prices were lower than expected, this may have a negative impact on our business, revenues, results of operations and cash flows.
For example, due to low electricity prices in Chile, which determine lower merchant revenues and consequently less cash and debt service payment capacity, the project debts of Chile PV 1 and 2 were under an event of default as of December 31, 2023 and impairments were recorded in 2023 and 2022. For further information, see “Item 4.B–Business overview–Our Operations.”
Market prices may be volatile and are affected by various factors, including the cost of raw materials, user demand, and the price of GHG emission where applicable. During the year 2022 and 2023, electricity market prices in Europe have also been affected by the war in Ukraine. In several of the jurisdictions in which we operate including Spain, Chile and Italy, we are exposed to remuneration schemes which contain both regulated incentives and market price components. In such jurisdictions, the regulated incentive or the contracted component may not fully compensate for fluctuations in the market price component, and, consequently, total remuneration may be volatile. Recent high market prices that we have been experiencing in Spain since the third quarter of 2021 resulted in higher cash collections in 2021 and 2022 which, in accordance with the regulation in place, caused a reduction of the regulated remuneration component in 2022 and 2023. During 2023, electricity market prices have been lower than the price expected by the regulation. If market prices continue to be lower than the prices assumed by the regulation and the regulated parameters are not revised until 2026, we may have an adverse effect on revenues, results of operations and cash flows in 2024 and 2025, which we expect will be compensated starting in 2026 in accordance with the regulation in place (see “—VII Risks related to Regulation — Revenues in our solar assets in Spain are mainly defined by regulation and some of the parameters defining the remuneration are subject to review every periodically.”).
2 Calculated as a percentage of our Adjusted EBITDA for the year 2023.
In addition, operating costs in certain of our existing or future projects depend to some extent on market prices of electricity used for self-consumption and, to a lower extent, on market prices of natural gas. In Spain, for example, operating costs increased in 2022 as a result of the increase in the price of natural gas and electricity.
There can be no assurance that market prices will remain at levels which enable us to maintain profit margins and desired rates of return on investment. A decline in market prices below anticipated levels could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Additionally, in some of our current or future PPAs, and contracts our subsidiaries have obligations to reach a minimum production, to deliver certain amounts of energy irrespective of actual production or to settle with the customer for the difference between the market price at our delivery point and a pre-agreed price in certain locations. This can result in our subsidiaries facing additional costs to purchase or sell power in the market or to settle for differences or defaulting on PPAs or contracts or not reaching minimum production. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Lack of electric transmission capacity availability, potential upgrade costs to the electric transmission grid, and other systems constraints could significantly impact our ability to generate electricity power sales and develop new projects.
We depend on electric interconnection and transmission facilities owned and operated by others to deliver the wholesale power we sell from our electric generation assets to our customers. We also depend on the assignment of the access to new interconnection points for the development and construction of new projects. A failure or delay in the operation or development of these interconnection or transmission facilities or a significant increase in the cost of the development of such facilities could result in the loss of revenues or in delays in the development and construction of new assets. Such failures or delays could limit the amount of power our operating facilities deliver or delay the completion of our construction projects, as the case may be. Additionally, such failures, delays or increased costs may have a material adverse effect on our business, financial condition, results of operations and cash flows. If a region’s electric transmission infrastructure is inadequate, our ability to generate electricity may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have a sufficient incentive to invest in expansion of transmission infrastructure. We cannot predict whether interconnection and transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. Certain of our operating facilities’ generation of electricity may be curtailed without compensation, or access to the grid might become uneconomical at certain times, due to transmission limitations or limitations on the electricity grid’s ability to accommodate intermittent electricity generating sources, reducing our revenues and impairing our ability to fully capitalize on a particular facility’s generating potential. For example, in 2023 and 2022 some of our wind assets in the U.S. and some of our solar assets in Chile and in Spain have been subject to curtailment and may be subject to similar or higher curtailment in the future. In addition, our solar assets in Spain need to achieve an annual minimum production threshold in order to obtain the right to receive the Remuneration on Investment (Rinv). In the second quarter and beginning of third quarter of 2022, some of these assets were subject to significant technical curtailment by the grid operator, which had happened very seldomly in the past. Although curtailments in Spain were lower in 2023, if curtailments increased in the future, Atlantica’s assets may not reach the annual minimum production threshold necessary to obtain the Remuneration on Investment (Rinv). Curtailments in our different geographies may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our information technology and communications systems are subject to cybersecurity risk and other risks. The failure of these systems could significantly impact our operations and business.
We are dependent upon information technology systems to run our operations. Our information technology systems are subject to disruption, damage or failure from a variety of sources, including, without limitation, computer viruses, security breaches, cyber-attacks, ransomware attacks, malicious or destructive code, phishing attacks, natural disasters, design defects, denial-of-service-attacks or information or fraud or other security breaches. Recently, energy facilities worldwide have been experiencing an increased number of cyber-attacks. Cybersecurity incidents, in particular, are constantly evolving and include malicious software, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in systems, unauthorized release of confidential or otherwise protected information and to the corruption of data. There have been cyber-attacks within the energy industry on electricity infrastructure such as substations and related assets in the past and there may be such attacks in the future. Our generation assets, transmission facilities, storage facilities, information technology systems and other infrastructure facilities and systems could be direct targets of, or otherwise be materially adversely affected by such activities.
Given the unpredictability of the timing, nature and scope of information technology disruptions, we could potentially be subject to production stops, unavailability in our transmission lines, operational delays, the compromising of confidential or otherwise protected information, destruction or corruption of data, security breaches, other manipulation or improper use of our systems and networks or financial losses from remedial actions. These events could cause reputational damage and could limit our ability to raise capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs. Such events or actions may materially adversely affect our business, financial condition, results of operations and prospects
We maintain global information technology and communication networks and applications to support our business activities. Given the increasing sophistication and evolving nature of the above mentioned threats, we cannot rule out the possibility of them occurring in the future, and information technology security processes may not prevent future damages to systems, malicious actions, denial-of-service attacks, or fraud, resulting in corruption of our systems, theft of commercially sensitive data, unauthorized release, gathering, monitoring, misuse, loss or destruction of confidential, proprietary and other information, misappropriation of funds and businesses (also known as phishing), or other material disruptions to network access or business operations. Although we have a cybersecurity insurance policy, the costs related to cybersecurity threats or disruptions may not be fully insured. Material system breaches and failures could result in significant interruptions that could in turn affect our operating results and reputation and cash flows. For further information about our cybersecurity systems and management, see “Item 16K- Cybersecurity”.
Negative impacts on biodiversity, including harming of protected species or other environmental hazards can result in curtailment of power plant operations, monetary fines. Negative publicity and delays in development of projects.
Managing and operating large infrastructure assets may have a negative impact on biodiversity in the regions where we operate. In particular, the operation of wind and solar power plants can adversely affect endangered, threatened or otherwise protected animal species. Wind power plants involve a risk that protected species will be harmed, as the turbine blades travel at a high rate of speed and may strike flying animals (such as birds or bats) that happen to travel into the path of spinning blades. Solar power plants can also present a risk to animals. Development of renewable and storage projects also requires us to comply with strict regulations aimed at preserving biodiversity in the development sites. Compliance with regulation and with our own biodiversity policy could cause delays in the development of these projects.
Excessive killing of protected species or other environmental accidents or hazards could result in requirements to implement mitigation strategies, including curtailment of operations, and/or substantial monetary fines and negative publicity. We cannot guarantee that any curtailment of operations, monetary fines that are levied, decrease on our ESG ratings and credentials or negative publicity as a result of incidental killing of protected species and other environmental hazards will not have a material adverse effect on our business, financial condition, results of operations and cash flows. Violations of environmental and other laws, regulations and permit requirements may also result in criminal sanctions or injunctions.
We may be subject to litigation, other legal proceedings and tax inspections.
We are subject to the risk of legal claims and proceedings (including bankruptcy proceeding), requests for arbitration, tax inspections as well as regulatory enforcement actions in the ordinary course of our business and otherwise, including claims against our subsidiaries, assets, deals, or our subsidiaries not meeting their obligations. The results of legal and regulatory proceedings or tax inspections cannot be predicted with certainty. We cannot guarantee that the results of current or future legal or regulatory proceedings, tax inspections or actions will not materially harm our operations, business, financial condition or results of operations, nor can we guarantee that we will not incur losses in connection with current or future legal or regulatory proceedings, tax inspections or actions that exceed any provisions we may have set aside in respect of such proceedings or actions or that exceed any available insurance coverage, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. For further information about our legal proceedings, see “Item 4.B—Business Overview—Legal Proceedings.”
If we are deemed to be an investment company, we may be required to institute burdensome compliance requirements and our activities may be restricted, which may make it difficult for us to complete strategic acquisitions or effect combinations.
If we were deemed to be an investment company under the Investment Company Act of 1940 (the “Investment Company Act”), our business would be subject to applicable restrictions under the Investment Company Act, which could make it impractical for us to continue our business as contemplated. We believe our Company is not an investment company under Section 3(b)(1) of the Investment Company Act because we are primarily engaged in a non-investment company business, and we intend to conduct our operations so that we will not be deemed an investment company. However, if we were to be deemed an investment company, restrictions imposed by the Investment Company Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated.
| II. | Risks Related to Our Relationship with Algonquin and Abengoa |
Algonquin is our largest shareholder and exercises substantial influence over us.
Currently, Algonquin beneficially owns 42.2% of our ordinary shares and is entitled to vote approximately 41.5% of our ordinary shares. As a result of this ownership, Algonquin has substantial influence on our affairs and has the power to vote a significant percentage of the shares eligible to vote on any matter requiring the approval of our shareholders. Such matters include the election of directors, the adoption of amendments to our articles of association and approval of mergers, the sale of all or a high percentage of our assets and other strategic transactions.
In addition, Algonquin or other significant shareholders (present or future) could exercise substantial influence and could seek to direct or change our strategy or corporate governance or could obtain effective control of us. The Shareholders Agreement that we have entered into with Algonquin may be amended and Algonquin may increase its voting rights above 41.5% or may increase its equity interest and take a controlling position in Atlantica and change our strategy, including our dividend policy. Algonquin may also sell its stake in Atlantica and a third party may gain control over us and decide to change our strategy. There can be no assurance that the interests of Algonquin or other (present or future) significant shareholders will coincide with the interests of our other shareholders or that Algonquin or other significant shareholders (present or future) will act in a manner that is in our best interests. This concentration of ownership of our shares may also have the effect of discouraging others from making tender offers for our shares or propose other transactions that might otherwise provide you with an opportunity to dispose of or realize a premium on your investment in our shares.
Further, our reputation is closely related to that of Algonquin. Any damage to the public image or reputation of Algonquin including as a result of adverse publicity, poor financial or operating performance, liquidity, changes in financial condition, rating downgrades, decline in the price of its shares or otherwise could have a material adverse effect on our business, financial condition, results of operations, cash flows or the price of our shares.
Our ownership structure and certain agreements may create significant conflicts of interest that may be resolved in a manner that is not in our best interests.
Our ownership structure involves several relationships that may give rise to certain conflicts of interest between us, Algonquin, and the rest of our shareholders. Currently, one of our directors is an officer of Algonquin and another director was an officer of Algonquin until August 10, 2023.
Currently, Algonquin is a related party and may have interests that differ from our interests, including with respect to the growth appetite, types of investments made, the timing and amount of dividends paid by us, the re-investment of returns generated by our operations, the use of leverage or capital increases when making investments, the appointment of outside advisors and service providers and the potential sale of their equity interest in Atlantica, including its timing and process, among others. Any transaction between us and Algonquin or Liberty GES (including the acquisition of any assets under the ROFO Agreements or any co-investment with Algonquin or Liberty GES or any investment in an Algonquin or Liberty GES asset) is subject to our related party transactions policy, which requires prior approval of such transaction by the related party transactions committee, which is composed of independent directors. The existence of our related party transactions approval policy may not insulate us from derivative claims related to related party transactions and the conflicts of interest described in this risk factor. Regardless of the merits of such claims, we may be required to spend significant management time and financial resources in the defense thereof. Additionally, to the extent we fail to appropriately deal with any such conflicts, it could negatively impact our reputation and ability to raise additional funds and the willingness of counterparties to do business with us, all of which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Legal proceedings involving Abengoa and its current and previous insolvency processes and events and circumstances that led to them could affect us.
Prior to the completion of our initial public offering in 2014, we and many of our assets were part of Abengoa. Many of our senior executives have previously worked for Abengoa. Abengoa’s restructuring processes, and the events and circumstances that led to them, are currently the subject of various legal proceedings and investigations, and may in the future become the subject of additional proceedings. To the extent that allegations are made in any such proceedings that involve us, our assets, our dealings with Abengoa or our employees, such proceedings may have a material adverse effect on our business, financial condition, results of operations and cash flows, as well as on our reputation and employees.
In addition, in Mexico, Abengoa was the owner of a plant that shares certain infrastructure and has certain back-to-back obligations with ACT. ACT is required to deliver an equipment to Pemex which has been donated and delivered to ACT by such plant. If we are unable to comply with these obligations, it may result in a material adverse effect on ACT and on our business, financial conditions, results of operations and cash flows. According to public information, the plant mentioned above is currently controlled by a third party.
| III. | Risks Related to Our Indebtedness |
Our indebtedness could limit our ability to react to changes in the economy or our industry, expose us to the risk of increased interest rates and limit our activities due to covenants in existing financing agreements. It could also adversely affect the ability of our project subsidiaries to make distributions to Atlantica Sustainable Infrastructure plc, our ability to fund our operations, pay dividends or raise additional capital.
As of December 31, 2023, we had (i) $4,319 million of total indebtedness under various project-level debt arrangements and (ii) $1,085 million of total indebtedness under our corporate arrangements, which include the Revolving Credit Facility, the Note Issuance Facility 2020, the 2020 Green Private Placement, the Green Exchangeable Notes and the Green Senior Notes. Furthermore, we may incur in the future additional project-level debt and corporate debt.
Our substantial debt could have important negative consequences on our business, financial condition, results of operation and cash flows including:
| • | increasing our vulnerability to general economic and industry conditions; |
| • | requiring a substantial portion of our cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to pay dividends to holders of our shares or to use our cash flow to fund our operations, capital expenditures, and future business opportunities; |
| • | limiting our ability to enter into long-term power sales, fuel purchases and swaps which require credit support; |
| • | limiting our ability to fund operations or future investments and acquisitions; |
| • | restricting our ability to make certain distributions with respect to our shares and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants in our credit facilities and other financing agreements; |
| • | exposing us to the risk of increased interest rates because a portion of some of our borrowings (approximately 7% as of December 31, 2023 after giving effect to hedging agreements) are at variable interest rates and exposing Atlantica to the risk of increased interest rates in the future when the Company needs to refinance its corporate debt; |
| • | limiting our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, investments and acquisitions and general corporate or other purposes, and limiting our ability to post collateral to obtain such financing; and |
| • | limiting our ability to adjust to changing market conditions and placing us at a disadvantage compared to our competitors who have less debt. |
The operating and financial restrictions and covenants in the Revolving Credit Facility, the 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Senior Notes may adversely affect our ability to finance our future operations or capital needs, to engage in other business activities that may be in our interest and to execute our business strategy as we intend to do so. Each contains covenants that limit certain of our, the guarantors’ and other subsidiaries’ activities. If we breach any of these covenants (including as a result of our inability to satisfy certain financial covenants), a default may result which may entitle the related noteholders or lenders, as applicable to demand repayment and accelerate all such debt or to enforce their security interests, which would have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Item 5.B—Operating and Financial Review and Prospects—Liquidity and Capital Resources— Corporate debt agreements.”
In addition, our inability to satisfy certain financial covenants may prevent cash distributions by the particular project(s) and other subsidiaries to us. If our project-level and other subsidiaries are unable to make distributions, it would likely have a material adverse effect on our ability to service debt at the corporate level or to pay dividends to holders of our shares. Our failure to comply with those and other covenants could result in an event of default which, if not cured or waived, may entitle the related noteholders or lenders, as applicable to demand repayment or to enforce their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, failure to comply with such covenants, may entitle the related noteholders or lenders, as applicable, to demand repayment and accelerate all such indebtedness.
Due to low electricity prices in Chile, the project debts of Chile PV 1 and 2 are under an event of default as of December 31, 2023 and as of the date of this annual report. Chile PV 1 was not able to maintain the minimum required cash in its debt service reserve account as of December 31, 2023 and did not make its debt service payment in January. In addition, in October 2023, Chile PV 2 did not make its debt service payment. This asset obtained additional financing from the banks and made the debt service payment in December 2023, although it was not able to sufficiently fund its debt service reserve account subsequently. As a result, although we do not expect an acceleration of the debt to be declared by the credit entities, as of December 31, 2023 Chile PV 1 and 2 did not have an unconditional right to defer the settlement of the debt for at least twelve months and the project debt was classified as current in our Annual Consolidated Financial Statements. We are in conversations with the banks, together with our partner, regarding a potential waiver. Impairments were recorded in these assets in 2023 and 2022. The value of the net assets contributed by Chile PV 1 and 2 to our Annual Consolidated Financial Statements, excluding non-controlling interest, was close to zero as of December 31, 2023. If we do not reach an agreement with the banks which have financed Chile PV 1 and 2, we may lose these assets.
Letter of credit facilities or bank guarantees to support project-level contractual obligations generally need to be renewed, at which time we will need to satisfy applicable financial ratios and covenants. If we are unable to renew the letters of credit as expected or replace them with letters of credit under different facilities on favorable terms or at all, we may experience a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, such inability may constitute a default under certain project-level financing arrangements, restrict the ability of the project-level subsidiary to make distributions to us and/or reduce the amount of cash available at such subsidiary to make distributions to us.
We may not be able to arrange the required or desired financing for investments and acquisitions and for the successful financing or refinancing of the Company’s project level and corporate level indebtedness.
Our ability to arrange the required or desired financing, either at corporate level or at a project-level, and the costs of such capital, are dependent on numerous factors, including:
| • | general economic and capital market conditions; |
| • | credit availability from banks, other financial institutions and tax equity investors; |
| • | investor confidence in us; |
| • | our financial performance, cash flow generation and the financial performance of our subsidiaries; |
| • | our level of indebtedness and compliance with covenants in debt agreements; |
| • | maintenance of acceptable project and corporate credit ratings or credit quality; and |
| • | tax and securities laws that may impact raising capital. |
We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace project-level financing arrangements or other credit facilities on favorable terms or at all upon the expiration or termination thereof. We may be unable to repay our existing debt as it becomes due if we fail, or any of our projects fails, to obtain additional capital or enter into new or replacement financing arrangements, which would have a material adverse effect on our business, financial condition, results of operations and cash flows. We may be unable to find financing for projects under construction or long-term project financing and tax equity investor financing once the assets reach COD.
In addition, the global capital and credit markets have experienced in the past and may continue to experience periods of extreme volatility and disruption. At times, our access to financing was curtailed by market conditions and other factors. Continued disruptions, uncertainty or volatility in the global capital and credit markets may limit our access to additional capital required to refinance our debt on satisfactory terms or at all, may limit our ability to replace, in a timely manner, maturing liabilities, and may limit our access to new debt and equity capital to make further investments and acquisitions. Volatility in debt markets may also limit our ability to fund or refinance many of our projects and corporate level debt, even in cases where such capital has already been committed. In addition, given that our dividend policy is to distribute a high percentage of our cash available for distribution, our growth strategy and refinancing relies on our ability to raise capital to finance our investments and acquisitions. Our high pay-out ratio may hamper our ability to manage liquidity in moments when accessing capital markets becomes more challenging. In the event we are not able to raise capital, we may have to postpone or cancel planned acquisitions, investments or capital expenditures. The inability to raise capital, higher costs of capital or postponement or cancellation of planned acquisitions, investments or capital expenditures may have a material adverse effect on our business, financial condition, results of operations and cash flows. If financing is available, utilization of our credit facilities, debt securities or project level financing for all or a portion of the purchase price of an acquisition, as applicable, could significantly increase our interest expense and debt repayment, impose additional or more restrictive covenants, and reduce cash available for distribution.
We may be subject to increased finance expenses if we do not effectively manage our exposure to interest rate and foreign currency exchange rate risks.
We are exposed to various types of market risk in the normal course of business, including the impact of interest rate changes and foreign currency exchange rate fluctuations. Some of our indebtedness (including project-level indebtedness) bears interest at variable rates, generally linked to market benchmarks such as EURIBOR or SOFR. During 2022, the U.S. Federal Reserve increased the reference interest rates in the United States from 0.125% to a targeted range between 4.25% and 4.50%, which was further increased to a range between 5.25% to 5.50% in 2023. Similarly, the European Central Bank increased the reference interest rates in the Euro zone from negative levels up to 2% in 2022 and up to 4.5% in 2023. Any increase in interest rates would increase our finance expenses relating to our un-hedged variable rate indebtedness and increase the costs of refinancing our existing indebtedness and issuing new debt at the corporate level or at the project level.
In addition, we seek to actively work with lending financial institutions to mitigate our interest rate risk exposure and to secure lower interest rates by entering into interest rate options and swaps. We estimate that approximately 92% of our project debt and 94% of our corporate debt was fixed or hedged as of December 31, 2023. The Revolving Credit Facility, with a limit of $450 million of which $378 million were available as of December 31, 2023 is subject to variable interest rates.
In addition, although most of our long-term contracts are denominated in, indexed or hedged to U.S. dollars, we conduct our business and incur certain costs in the local currency of the countries in which we operate. In addition, the revenues, costs and debt of our solar assets in Spain, Italy, South Africa and Colombia are denominated in local currency. We have a hedging strategy for our solar assets in Europe. Since the beginning of 2017, we have maintained euro-denominated debt at the corporate level. Interest payments in euros and our euro denominated general and administrative expenses create a natural hedge for a portion of the distributions from assets in Europe. Our strategy is to hedge the exchange rate for the distributions received in euros after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, we hedge on a rolling basis 100% of the net euro net exposure for the next 12 months and 75% of the net euro net exposure for the following 12 months. However, if the euro depreciated against the U.S. dollar in the long term, we would have a negative impact on our cash flows after 24 months. In addition, a depreciation of the South African rand, the Colombian peso or a long-term depreciation of the Euro could have a negative impact on our results of operations and cash flows. See “Item 5.A—Operating and Financial Review and Prospects —Results of Operations—Factors Affecting the Comparability of Our Results of Operations.”
In addition, although we hedge cash-flows in euros, fluctuations in the value of the euro in relation to the U.S. dollar may affect our operating results. For example, revenue in euro-denominated companies could decrease when translated to U.S. dollars at the average foreign exchange rate solely due to a decrease in the average foreign exchange rate, in spite of revenue in the original currency being stable. Fluctuations in the value of South African rand and Colombian peso with respect to the U.S. dollar may also affect our operating results.
As we continue expanding our business, an increasing percentage of our revenue and cost of sales may be denominated in currencies other than our reporting currency, the U.S. dollar. Under that scenario, we would become subject to increasing currency exchange risk, whereby changes in exchange rates between the U.S. dollar and the other currencies in which we do business could result in foreign exchange losses.
If our risk-management strategies are not successful in limiting our exposure to changes in interest rates and foreign currency exchange rates our business, financial condition, results of operations and cash flows maybe materially adversely affected.
Potential future defaults by our subsidiaries, our off-takers, our suppliers or other persons could adversely affect us.
The financing agreements of our project subsidiaries are primarily loan agreements which provide that the repayment of the loans (and interest thereon) is secured solely by the shares, physical assets, contracts and cash flow of that project company. This type of financing is usually referred to herein as “project debt.” As of December 31, 2023, we had $4,319 million of outstanding indebtedness under various project-level debt arrangements.
While the lenders under our project debt do not have direct recourse to us or our subsidiaries (other than the letter of credit and bank guarantee facilities), defaults by the project borrowers under such financings can still have important consequences for us and our subsidiaries, including, without limitation:
| • | reducing our receipt of dividends, fees, interest payments, loans and other sources of cash, since the project company will typically be prohibited from distributing cash to us and our subsidiaries until the event of default is cured or waived; |
| • | default under our other debt instruments; |
| • | causing us to record a loss in the event the lender forecloses on the assets of the project company; and |
| • | the loss or impairment of investors and project finance lenders’ confidence in us. |
If we fail to satisfy any of our debt service obligations or breach any related financial or operating covenants, the applicable lender could declare the full amount of the relevant project debt to be immediately due and payable and could foreclose on any assets pledged as collateral.
Under the Revolving Credit Facility, the 2020 Green Private Placement, the Green Senior Notes and the Note Issuance Facility 2020, a payment default with respect to indebtedness having an aggregate principal amount above certain thresholds by us, any guarantor thereof or one or more of our non-recourse subsidiaries representing more than 25% of the cash available for distribution distributed in the previous four fiscal quarters could trigger a default.
Any of these events may have a material adverse effect on our business, financial condition, results of operations and cash flows.
A change of control or a delisting of our shares may have negative implications for us.
If any investor acquires over 50.0% of our shares or if our ordinary shares cease to be listed on the NASDAQ or a similar stock exchange, we may be required to refinance all or part of our corporate debt or obtain waivers from the related noteholders or lenders, as applicable, due to the fact that all of our corporate financing agreements contain customary change of control provisions and delisting restrictions. The project debt of some of our assets also requires a waiver in the event of a change of control. If we fail to obtain such waivers and the related noteholders or lenders, as applicable, elect to accelerate the relevant corporate debt, we may not be able to repay or refinance such debt (on favorable terms or at all), which may have a material adverse effect on our business, financial condition results of operations and cash flows. In addition, the PPAs of some assets would require a waiver in the event of a change of control and some of our PPAs and project financing agreements would require a notification. Additionally, in the event of a change of control we could see an increase in the yearly state property tax payment in Mojave, which would be reassessed by the tax authority at the time the change of control potentially occurred. Our best estimate with current information available and subject to further analysis is that we could have an incremental annual payment of property tax of approximately $9 million to $11 million, which could potentially decrease progressively over time as the asset depreciates. There could also be other tax impacts and other impacts that we have not yet identified. Furthermore, a change of control could trigger an ownership change under Section 382 of the IRC which could have a material adverse effect on our business, financial condition results of operations and cash flows (see “Risks Related to Taxation – Our ability to use U.S. NOLs to offset future income may be limited”).
The process to explore and evaluate potential strategic alternatives may not be successful.
On February 21, 2023, Atlantica’s board of directors commenced a process to explore and evaluate potential strategic alternatives that may be available to Atlantica to maximize shareholder value. There is no assurance about the outcome of this process, that any specific transaction will be identified or consummated or that any other strategic change will be implemented as a result of this strategic review, or that any such review may achieve any expected results.
Unanticipated developments could delay, prevent or otherwise adversely affect the planned strategic review, including but not limited to volatility in the financial markets, disruptions in general or financial market conditions or potential problems or delays in obtaining various regulatory and tax approvals or clearances.
In addition, whether or not any such strategic alternative is identified, pursued and/or consummated, such review could cause disruptions in the businesses of the Company by directing the attention of the board of directors and management and other resources (including significant costs) toward such review or the preparation of the Company to pursue and consummate any strategic alternative. The process could potentially increase employee turnover. If no such strategic alternative is identified or completed, the Company may have incurred significant costs, including the diversion of directors and management resources, for which they will have received little or no benefit. The process could result in a transaction or a change in strategy that negatively affects our share price, either temporarily or permanently. As of the date of this annual report, the strategic review is ongoing and we have not determined a timeframe for its conclusion.
| IV. | Risks Related to Our Growth Strategy |
We may not be able to identify or consummate future investments and acquisitions on favorable terms, or at all.
Our business strategy includes growth through investments in projects under development or construction and through the acquisition of additional revenue-generating assets. This strategy depends on our ability to successfully identify and evaluate investment opportunities, develop and build new assets and consummate acquisitions on favorable terms. The number of investment opportunities may be limited.
Our ability to develop, build or acquire future renewable energy projects or businesses depends on the viability of renewable energy projects generally. These projects are in some cases contingent on public policy mechanisms including, among others, ITCs, PTCs, cash grants, loan guarantees, accelerated depreciation, expensing for certain capital expenditures, carbon trading plans, environmental tax credits and research and development incentives. See “—VII. Risks Related to Regulation—Government regulations could change at any time and such changes may negatively impact our current business and our growth strategy.” Our ability to develop and build new assets depends, among other things, on our ability to secure transmission interconnection access or agreements, to secure land rights, to secure PPAs or similar schemes and to obtain licenses and permits and we cannot guarantee that we will be successful obtaining them (see “Our ability to develop renewable projects is subject to construction risks and risks associated with the arrangements with our joint venture partners”). Our ability to consummate future investments and acquisitions may also depend on our ability to obtain any required government or regulatory approvals for such investments, including, but not limited to, FERC, approval under Section 203 of the FPA in respect of investments in the United States; or any other approvals in the countries in which we may purchase assets in the future. We may also be required to seek authorizations, waivers or notifications from debt and/or equity financing providers at the project or holding company level; local or regional agencies or bodies; and/or development agencies or institutions that may have a contractual right to authorize a proposed acquisition.
Furthermore, we will compete with other local and international companies for acquisition opportunities from third parties, which may increase our cost of making investments or cause us to refrain from making acquisitions from third parties. Some of our competitors for investments and acquisitions may pay more for acquisitions and may be able to identify, evaluate, bid for and purchase a greater number of assets or projects under development than our financial or human resources permit. If we are unable to identify and consummate future investments and acquisitions, it will impede our ability to execute our growth strategy and limit our ability to increase the amount of dividends paid to holders of our shares.
Our ability to consummate future investments also depends on the availability of financing. See “—IV. Risks Related to Our Indebtedness—We may not be able to arrange the required or desired financing for investments or for the successful refinancing of the Company’s project level and corporate level indebtedness.”
Demand for renewable energy may be affected by the cost of other energy sources. To the extent renewable energy becomes less cost-competitive, demand for renewable energy could decrease. Slow growth or a long-term reduction in the energy demand could cause a reduction in the development of renewable energy program projects. Decreases in the prices of electricity could affect our ability to acquire assets, as renewable energy developers may not be able to compete with providers of other energy sources at such lower prices. Our inability to acquire assets could have a material adverse effect on our ability to execute our growth strategy.
In addition, our ability to grow organically is limited to some assets which have inflation indexation mechanisms in their revenues, to our transmission lines and to some renewable assets. We may not be able to deliver organic growth.
In addition, although we have a ROFO Agreement with Algonquin, our growth through the acquisitions from Algonquin or co-investments with them has been limited. Liberty GES and Algonquin may not offer us assets at all or may not offer us assets that fit within our portfolio or contribute to our growth strategy. Only certain assets outside the United States and Canada are included in the Algonquin ROFO Agreement. Liberty GES and Algonquin may decide to keep assets subject to our ROFO Agreements in their portfolios and not offer them to us for acquisition. Algonquin can terminate the Algonquin ROFO Agreement with us with a 180-day notice. Additionally, we may not reach an agreement on the price of assets offered by Liberty GES or Algonquin. For these reasons, we may not be able to consummate future investments from Liberty GES or Algonquin, which may restrict our ability to grow.
Our ability to develop renewable projects is subject to development and construction risks and risks associated with the arrangements with our joint venture partners
We are developing projects and we have reached agreements with a number of partners in order to develop assets in the geographies in which we operate, however we cannot guarantee that our investments will be successful and that our growth expectations will materialize. Additionally, we cannot guarantee that we will be successful in identifying new potential projects and partners or that we will be able to acquire additional assets from those partners in the future. If we are unable to identify projects under such agreements or to reach new agreements on favorable terms with new partners, or if we are unable to consummate future acquisitions from any such agreement, it may limit our ability to execute our growth strategy and may have a materially adverse effect on our business, financial condition, results of operation and cash flows.
Furthermore, development and construction activities are subject to failure rate and different types of risks. Our ability to develop new assets is dependent on our ability to secure or renew our rights to an attractive site on reasonable terms; accurately measuring resource availability; the ability to secure new or renewed approvals, licenses and permits; the acceptance of local communities; the ability to secure transmission interconnection access or agreements; the ability to successfully integrate new projects into existing assets; the ability to acquire suitable labor, equipment and construction services on acceptable terms; the ability to attract project financing, including tax equity; our ability to estimate the future revenue and returns for storage projects after the end of the contracted period and the ability to secure PPAs or other sales contracts on reasonable terms. Failure to achieve any one of these elements may prevent the development and construction of a project. If any of the foregoing were to occur, we may lose all of our investment in development expenditures and may be required to write-off project development assets.
In addition, the construction and development of new projects is subject to environmental, engineering and construction risks that could result in cost over-runs, delays and reduced performance. A number of factors that could cause such delays, cost over-runs or reduced performance include, changes in local laws or difficulties in obtaining permits, rights of way or approvals, changing engineering and design requirements, construction costs exceeding estimates for various reasons, including inaccurate engineering and planning, failures to properly estimate the cost of raw materials, components, equipment, labor or the inability to timely obtain them, unanticipated problems with project start-up, the performance of contractors, labor disruptions, inclement weather, defects in design, engineering or construction and project modifications. A delay in the projected completion of a project can result in a material increase in total project construction costs through higher capitalized interest charges, additional labor and other expenses, and a delay in the commencement of cash flow.
If we co-invest with partners, or on our own, in assets under development or construction, we cannot guarantee that the development and construction of the asset will be successful and that we end up owning an operational asset.
In order to grow our business, we may invest in or acquire assets or businesses which have a higher risk profile or are less ESG-friendly than certain assets in our current portfolio.
In order to grow our business, we may develop and build or acquire assets and businesses which may have a higher risk profile than certain of the assets we currently own. Availability of assets with long-term contracts has decreased over the last few years, competition to acquire contracted assets in operation has been high in recent years and is expected to continue being so. We intend to increase our investments in assets which are not currently in operation, and which are subject to development and construction risk. Construction of renewable assets, among others, is subject to risk of cost over-runs and delays. There can be no assurances that assets under development and construction will perform as expected or that the returns will be as expected. In addition, we may consider investing more in assets which are not contracted or not fully contracted, for which revenues will depend on the price of the electricity and which are therefore subject to merchant risk. We may also consider investing in businesses which are regulated or which are contracted with “as contracted” agreements or hedge agreements where we need to deliver the contracted power even if the facility is not in operation or which are subject to demand risk. We have recently invested and may consider investing in business sectors where we do not have previous experience and may not be able to achieve the expected returns. We may also consider investing with partners or on our own in new technologies which do not have for the moment a long history track record as proven as our current assets, such as storage, district heating, geothermal, offshore wind or hydrogen. We may also consider investing in distributed generation in smaller commercial and industrial facilities. Furthermore, we may consider investing in assets in new markets or with revenues not denominated in U.S. dollars or euros, which would increase our exposure to local currency, and which could generate higher volatility in the cash flows we generate. In all these types of assets and businesses, the risk of not meeting the expected cash flow generation and expected returns is higher than in contracted assets. In addition, these type of assets and businesses could present a higher variability in the cash flows they generate. We may also invest in assets which may be considered as less ESG-friendly than certain assets in our current portfolio by current and potential investors. For example, considering the competitive landscape for renewable assets in recent years, we may acquire additional natural gas assets. Although we have set a target to maintain at least 85% of our Adjusted EBITDA generated by low carbon footprint assets, some investors with a focus on ESG may consider this target insufficient, which could cause us to become less attractive to investors.
As a result, the consummation of investments and acquisitions may have a material adverse effect on our ability to grow, our business, financial condition, results of operations and cash flows.
We cannot guarantee the success of our recent and future investments.
Acquisitions of and investments in companies and assets are subject to substantial risks, including unknown or contingent liabilities (including violations of environmental, antitrust, anti-corruption, anti-bribery and anti-money laundering laws, and tax and labor disputes), the failure to identify material problems during due diligence (for which we may not be indemnified post-closing) or the risk of over-paying for assets (or not making acquisitions on an accretive basis). In some of our acquisitions the former owners agreed, or may agree, to indemnify us for certain of these matters. However, such indemnification obligations are often subject to materiality thresholds and guaranty limits, and such obligations are generally time limited. For certain acquisitions, we may not be able to successfully negotiate for such indemnification obligations. As a result, we may not recover any amounts with respect to losses due to unknown or contingent liabilities or breaches by the sellers of their representations and warranties. All this may adversely affect our business, financial condition, results of operations and prospects.
Furthermore, the integration and consolidation of acquisitions require substantial human, financial and other resources and, ultimately, our acquisitions may divert management’s attention from our existing business concerns, disrupt our ongoing business or not be successfully integrated at all. As a result, the consummation of acquisitions may have a material adverse effect on our ability to grow, our business, financial condition, results of operations and cash flows.
We may be unable to complete all, or any, such transactions that we may analyze. Even where we consummate investments, we may be unable to achieve projected cash flows or we may encounter regulatory complications arising from such transactions. Furthermore, the terms and conditions of financing for such investments could restrict the manner in which we conduct our business. These risks could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may also make acquisitions or investments in assets that are located in different jurisdictions and are different from, and may be riskier than, those jurisdictions in which we currently operate (Canada, the United States, Mexico, Peru, Chile, Colombia, Uruguay, Spain, Italy, South Africa and Algeria). See “—VI. Risks Related to the Markets in Which We Operate—We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.” These changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our cash dividend policy may limit our ability to grow and make investments through cash on hand.
Our dividend policy is to distribute a high percentage of our cash available for distribution, after corporate general and administrative expenses and cash interest payments and less reserves for the prudent conduct of our business, and to rely primarily upon external financing sources, including the issuance of debt and equity securities as well as borrowings under credit facilities to fund our acquisitions, investments and potential growth capital expenditures. In addition, Algonquin may terminate the Shareholders Agreement if dividend payment is lower than 80% of the cash available for distribution. Our Board of Directors may change our dividend policy at any time. We may be precluded from pursuing otherwise attractive investments if the projected short-term cash flow from the acquisition or investment does not meet our minimum expectations.
Because of our dividend policy, our growth may not be as fast as that of businesses that re-invest their available cash to expand ongoing operations. To the extent we issue additional equity securities in connection with any acquisitions or growth capital expenditures, the payment of dividends on these additional equity securities may increase the risk that we will be unable to maintain or increase our per share dividend. There are no limitations in our articles of association on our ability to issue equity securities, including convertible bonds, preferred shares or other securities ranking senior to our shares.
In addition, our Board of Directors may decide at any time to change our strategy and may agree on measures to foster our ability to grow which could include, for example, to acquire a large development company to have a larger pipeline of projects under development or to reduce our dividend to re-invest in growth a larger part of the cash we generate.
| VI. | Risks Related to the Markets in Which We Operate |
Difficult conditions in the global economy and in the global capital markets have caused, and may continue to cause, a negative impact on our business.
Our results of operations have been, and continue to be, materially affected by conditions in the global economy. Capital markets have been experiencing high volatility during 2022 and 2023 both in the United States and Europe. Concerns over the COVID-19 pandemic, high inflation, interest rate increases, war in Ukraine, energy crisis in Europe, volatile gas prices, high electricity prices particularly in Europe, tensions between the U.S., Russia and China, the availability and cost of credit, and the instability of the euro have contributed to increased volatility in capital markets and worsened expectations for the economy. During the year 2023 and beginning of 2024, the valuations of renewable ETFs and renewable companies in the United States and Europe have generally decreased.
After the sharp recession caused by the COVID-19 pandemic in 2020, the recovery in demand during the year 2021 caused disruptions in the supply chain with global shortages of some products and materials and high inflation rates. Supply chain issues persisted in 2022 and 2023. Further disruptions in the supply chain could limit the availability of certain parts required to operate our facilities and could adversely impact our ability (or our operation and maintenance suppliers’ ability) to operate our plants or to perform maintenance activities. If we were to experience a shortage of or inability to acquire critical spare parts, we could incur significant delays in returning facilities to full operation, which could negatively impact our business, financial condition, results of operations and cash flows. Supply chain tensions may also affect our projects in development and construction where we can experience delays or an increase in prices of equipment and materials required for the construction of new assets, which may cause a material adverse effect on our business, financial condition, results of operations and cash flows. Prolonged inflation may also cause a material adverse effect on our business, financial condition, results of operations and cash flows
Adverse events and continuing disruptions in the global economy and capital markets may have a material adverse effect on our business, financial condition, results of operations and cash flows. Moreover, even in the absence of a market downturn, we are exposed to risk of loss due to market volatility and other factors, including volatile oil and gas prices, increasing electricity prices, interest rates swings, changes in consumer spending, business investment, government spending, and rising inflation, among others, that could affect the economic and financial situation of our concession agreements’ counterparties and, ultimately, the profitability and growth of our business. In the past, including in 2023, the price of shares in certain sectors including companies paying a high dividend and companies with a strategy focused on growth has been inversely correlated with interest rates. If interest rates continued to raise, this may have a further negative impact on the price of our shares.
Generalized or localized downturns or inflationary pressures in our key geographical areas could also have a material adverse effect on our business, financial condition, results of operations and cash flows. A significant portion of our business activity is concentrated in the United States, Spain, Mexico and Peru. Consequently, we are significantly affected by the general economic conditions in these countries. To the extent uncertainty regarding the European economic recovery continues to negatively affect government or regional budgets, our business, financial condition, results of operations and cash flows could be materially adversely affected.
Global geopolitical tensions, including from the February 2022 Russian military actions across Ukraine, from October 2023 military actions in the Middle East and military actions in the Red Sea may rise further and create heightened volatility in the electricity market as well as disruptions and delays in the supply chain that could negatively affect both our ability to execute our business and growth strategy. Such military actions, and sanctions in response thereof as well as escalation of conflicts, could significantly affect worldwide electricity market prices and demand, negatively affect supply chains and cause turmoil in the capital markets and generally in the global financial system. This could have a material adverse effect on our business, financial condition, results of operations and cash flows, making it difficult to execute our growth strategy.
We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.
We operate our activities in a range of international locations, including North America (Canada, the United States and Mexico), South America (Peru, Chile, Colombia and Uruguay), and EMEA (Spain, Italy, Algeria and South Africa), and we may expand our operations to certain core countries within these regions. Accordingly, we face several risks associated with operating and investing in different countries that may have a material adverse effect on our business, financial condition, results of operations and cash flows. These risks include, but are not limited to, adapting to the regulatory requirements of such countries, compliance with changes in laws and regulations applicable to foreign corporations, the uncertainty of judicial processes, and the absence, loss or non-renewal of favorable treaties, or similar agreements, with local authorities, or political, social and economic instability, all of which can place disproportionate demands on our management, as well as significant demands on our operational and financial personnel and business. As a result, we can provide no assurance that our future international operations and investments will remain profitable.
A significant portion of our current and potential future operations and investments are conducted in various emerging countries worldwide. Our activities and investments in these countries involve a number of risks that are more prevalent than in developed markets, such as economic and governmental instability, the possibility of significant amendments to, or changes in, the application of governmental regulations, the nationalization and expropriation of private property, payment collection difficulties, social unrest or protests, substantial fluctuations in interest and exchange rates, changes in the tax framework or the unpredictability of enforcement of contractual provisions, currency control measures, limits on the repatriation of funds and other unfavorable interventions or restrictions imposed by public authorities. Countries like Mexico, Peru and Chile currently have governments which are favorable to increase public spending and tax pressure. In addition, the current government in Mexico proposed in the past regulations which intend to benefit local business rather than foreign investors. In Peru, after an attempt by the former president to dissolve congress and replace it with an “exceptional emergency government”, the president was replaced. Political uncertainty may persist in the upcoming months. In countries such as Algeria or South Africa, a change in government can cause instability in the country and a new government may decide to change laws and regulations affecting our assets or may decide to expropriate such assets. All this may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our U.S. dollar-denominated contracts in several assets are payable in local currency at the exchange rate of the payment date and in some cases include portions in local currency. In the event of a rapid devaluation or implementation of exchange or currency controls, we may not be able to exchange the local currency for the agreed dollar amount, which could affect our cash available for distribution. Likewise, our contracts in South Africa and Colombia are payable in local currency. Governments in Latin America and Africa frequently intervene in their economies and occasionally make significant changes in policy and regulations. Governmental actions aimed to control inflation and other similar policies and regulations have often involved, among other measures, price controls, currency devaluations, capital or exchange controls and limits on imports. Such devaluation, implementation of exchange or currency controls or governmental involvement may have a material adverse effect on our business, financial condition, results of operations and cash flows.
| VI. | Risks Related to Regulation |
We are subject to extensive governmental regulation in a number of different jurisdictions, and our inability to comply with existing regulations or requirements in applicable regulations or requirements may have a negative impact on our business, financial condition, results of operations and cash flows.
We are subject to extensive regulation of our business in the countries in which we operate. Such laws and regulations require licenses, permits and other approvals to be obtained in connection with the operations of our activities. This regulatory framework imposes significant actual, day-to-day compliance burdens, costs and risks on us. The power plants, transmission lines and other assets that we own are subject to strict international, national, state and local regulations relating to their operation and expansion (including, among other things, leasing and use of land, and corresponding building permits, landscape conservation, noise regulation, environmental protection and environmental permits and electric transmission and distribution network congestion regulations). Non-compliance with such regulations could result in reputational damage, the revocation of permits, sanctions, fines, criminal penalties or affect our ability to satisfy applicable ESG standards. Compliance with regulatory requirements may result in substantial costs to our operations that may not be recovered. All the above could have a negative impact on us and a material adverse effect on our business, financial condition, results of operations and cash flows.
Our business is subject to stringent environmental regulation.
We are subject to significant environmental regulation, which, among other things, requires us to obtain and maintain regulatory licenses, permits and other approvals and comply with the requirements of such licenses, permits and other approvals and perform environmental impact studies on changes to projects. In addition, our assets need to comply with strict environmental regulation on air emissions, water usage and contaminating spills, among others. Our policy is to maintain environmental insurance policies. We can give no assurance that we will be able to maintain such policies in the future. Additionally, as a company with a focus on ESG and most of the business in renewable energy, environmental incidents can also significantly harm our reputation. There can be no assurance that:
| • | public opposition will not result in delays, modifications to or cancellation of any project or license; |
| • | laws or regulations will not change or be interpreted in a manner that increases our costs of compliance or require new investments and may have a material adverse effect on our business, financial condition, results of operations and cash flows, including preventing us from operating an asset if we are not in compliance; or |
| • | governmental authorities will approve our environmental impact studies where required to implement proposed changes to operational projects. |
We believe that we are currently in material compliance with all applicable regulations, including those governing the environment. In the past, we have experienced some environmental accidents and we have been found not to be in compliance with certain environmental regulations and have incurred fines and penalties associated with such violations which, to date, have not been material in amount. At any point in time, we are subject to review and in some cases challenges regarding our compliance that might result in future fines and penalties or other remediation measures. At this point in time, we believe that such reviews will not result in a material financial impact. In one of our plants in Spain we have a difference of interpretation with an agency which may result, if the agency, and eventually the court, decided against our position in an eventual modification of the plant several years from today with a cost that we do not expect to be material. We can give no assurance, however, that we will continue to be in compliance or avoid material fines, penalties, sanctions and expenses associated with compliance issues in the future. Violation of such regulations may give rise to significant liability, including fines, damages, fees and expenses, additional taxes and site closures. The costs of compliance as well as non-compliance may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Government regulations could change at any time and such changes may negatively impact our current business and our growth strategy.
Our assets are subject to extensive regulation. Changes in existing energy, environmental and administrative laws and regulations may have a material adverse effect on our business, financial condition, results of operations and cash flows, including on our growth plan and investment strategy. Also, such changes may in certain cases, have retroactive effects and may cause the result of operations to be lower than expected, or increase the size and number of claims and damages asserted against us or subject us to enforcement actions, fines and even criminal penalties. Our business may also be affected by additional taxes imposed on our activities or changes in regulations, reduction of regulated tariffs and other cuts or measures.
Changes in laws and regulations could increase the size and number of claims and damages asserted against us or subject us to enforcement actions, fines and even criminal penalties. In addition, changes in laws and regulations may, in certain cases, have retroactive effect and may cause the result of operations to be lower than expected. In particular, our activities in the energy sector are subject to regulations applicable to the economic regime of generation of electricity from renewable sources and to subsidies or public support in the benefit of our production of energy from renewable energy sources, which vary by jurisdiction, and are subject to modifications that may be more restrictive or unfavorable to us.
Furthermore, in some of our assets such as the solar plants in Spain and one of our transmission lines in Chile, revenues are based on existing regulation. We may also acquire in the future additional assets or businesses with regulated revenues. For these types of assets and businesses, if regulation changes, it may have a material adverse effect on our business, financial condition, results of operations and cash flows.
In addition, our strategy to grow our business through investments in renewable energy projects partly depends on current government policies that promote and support renewable energy and enhance the economic viability of owning solar and wind energy projects. Renewable energy projects currently benefit from various U.S. federal, state and local governmental incentives, such as ITCs, PTCs, loan guarantees, RPS programs, or MACRS along with other incentives. These incentives make the development of renewable energy projects more competitive. These policies have had a significant impact on the development of renewable energy, and they could change at any time. A loss or reduction in such incentives or the value of such incentives, a change in policy away from limitations on coal and gas electric generation or a reduction in the capacity of potential investors to benefit from such incentives could decrease the attractiveness of renewable energy projects to project developers, and the attractiveness of renewable assets to utilities, retailers and customers. Such a loss or reduction could reduce our investment opportunities and our willingness to pursue renewable energy projects due to higher operating costs or lower revenues from off-take agreements. See also “—Risks Related to Taxation.”
Besides, the U.S. Inflation Reduction Act (IRA) signed into law on August 16, 2022 increased and / or extended some of these incentives and established new ones. For example, the IRA includes, among other incentives, a 30% solar ITC for solar projects to be built until 2032, a PTC for wind projects to be built until 2032, a 30% ITC for standalone storage projects to be built until 2032 and a new tax credit that will award up to $3/kg for low carbon hydrogen. The IRA also includes transferability options for the ITCs and PTCs, which should allow an easier and faster monetization of these tax credits. Presidential elections will take place in the US in November 2024 and the republican party has claimed its opposition to the IRA and its preference for traditional energy sources over renewables. A potential repeal of the IRA or a reduction of its tax benefits could have an adverse impact on our business, our ability to execute our growth strategy, our financial condition, results of operations and cash flows.
Additionally, some U.S. states with RPS targets have met, or in the near future will meet, their renewable energy targets. For example, California, which has among the most aggressive RPS laws in the United States will be required to meet the higher renewable energy mandate of 60.0% by 2030 and 100% by 2045 that was adopted in 2018. If, as a result of achieving these targets, these and other U.S. states do not increase their targets in the near future, demand for additional renewable energy could decrease. In addition, the substantial increase of grid connected intermittent solar and wind generation assets resulting from the adoption of RPS targets has created significant technical challenges for grid operators. As a result, RPS targets may need to be scaled back or delayed in order to develop technologies or infrastructure to accommodate this increase in intermittent generation assets.
In addition, regulations approved in the United States in relation with the import of solar equipment from China and Southeast Asia, including the Antidumping and countervailing duties and the Uyghur Forced Labor Prevention Act has hindered the ability of developers to acquire equipment for the construction of new assets. If this situation persisted in the future and a domestic alternative industry was not able to develop, our growth in the U.S. through the development and construction of new assets may be negatively affected.
Subsidy regimes for renewable energy generation have been challenged in the past on constitutional and other grounds (including that such regimes constitute impermissible European Union state aid) in certain jurisdictions. In addition, certain loan-guarantee programs in the United States, including those which have enabled the DOE to provide loan guarantees to support our Solana and Mojave projects in the United States, have been challenged on grounds of failure by the appropriate authorities to comply with applicable U.S. federal administrative and energy law. If all or part of the subsidy and incentive regimes for renewable energy generation in any jurisdiction in which we operate were found to be unlawful and, therefore, reduced or discontinued, we may be unable to compete effectively with conventional and other renewable forms of energy. We currently have two financing arrangements with the Federal Financing Bank for the Solana and Mojave assets, repayment of which to the Federal Financing Bank by those projects is with a guarantee by the DOE. Additionally, these projects benefitted from the ITCs. Unilateral changes to these agreements or the ITC regime may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Revenues in our solar assets in Spain are mainly defined by regulation and some of the parameters defining the remuneration are subject to review periodically.
According to Royal Decree 413/2014, solar electricity producers in Spain receive: (i) the pool price for the power they produce, (ii) a payment based on the standard investment cost for each type of plant (without any relation whatsoever to the amount of power they generate) and (iii) an “operating payment” (in €/MWh produced).
The principle driving this economic regime is that the payments received by a renewable energy producer should be equivalent to the costs that they are unable to recover on the electricity pool market where they compete with non-renewable technologies. This economic regime seeks to allow a “well-run and efficient enterprise” to recover the costs of building and running a plant, plus a reasonable return on investment (project investment rate of return). The rate applicable during the first regulatory period from 2015 until 2020 was 7.398%
The first review of this rate was at the end of 2018 applicable for the second regulatory period 2020-2025. On November 2, 2018, CNMC (the state-owned regulator for the electricity system in Spain) issued its final report with a proposed reasonable rate of return of 7.09%. In December 2018, the government issued a draft project law proposing a reasonable rate of return of 7.09%, with the possibility of maintaining the 7.398% reasonable rate of return under certain circumstances. On November 24, 2019, the government of Spain approved Royal Decree-law 17/2019 setting out a 7.09% reasonable rate of return applicable from January 1, 2020 until December 31, 2025, as a general rule and the possibility, under certain circumstances including not having any ongoing legal proceeding against the Kingdom of Spain ongoing, of maintaining the 7.398% reasonable rate of return for two consecutive regulatory periods. The reasonable rate of return was calculated by reference to the weighted average cost of capital (WACC), the calculation method that most of the European regulators apply to determine the return rates applicable to regulated activities within the energy sector. As a result, some of the assets in our Spanish portfolio are receiving a remuneration based on a 7.09% reasonable rate of return until December 31, 2025, while others are receiving a remuneration based on a 7.398% reasonable rate of return until December 31, 2031.
If the payments for renewable energy plants are revised to lower amounts in the next regulatory period starting on January 1, 2026 until December 31, 2031, or starting on January 1, 2032, depending on each asset, this could have a material adverse effect on our business, financial condition, results of operations and cash flows. As a reference, taking into account that the reasonable rate of return will be revised only for part of our portfolio on January 1, 2026, assuming our assets in Spain continue to perform as expected and assuming no additional changes of circumstances, with the information currently available, a reduction of 100 basis points in the reasonable rate of return set by the government of Spain from 2026 could cause a reduction in its cash available for distribution of approximately €6 million per year. This estimate is subject to certain assumptions, which may change in the future.
In addition, the regulation includes a mechanism under which regulated revenues are reviewed every three years to reflect the difference between expected and actual market prices over the remaining regulatory life if the difference is higher than a pre-defined threshold. Given that since mid-2021 electricity prices in Spain have been, and may continue to be, significantly higher than expected, it will cause lower regulated revenue and lower cash flows over the remaining regulatory life of our solar assets. On March 30, 2022, the Royal Decree Law 6/2022 introduced certain temporary changes to the detailed regulated components of revenue received by our solar assets in Spain, which is applicable from January 1, 2022. The proposed remuneration parameters for the year 2022 were published on May 12, 2022 and were declared final on December 14, 2022, with a decrease in regulated revenue. The remuneration parameters for the next semi-regulatory period, starting on January 1, 2023 were published on December 28, 2022 in draft form and on June 30, 2023, the final parameters were published, including a revised assumption for electricity prices for the years 2023, 2024 and 2025. The current regulatory parameters assume a market price which is higher than current market prices. If electricity market prices continue to be lower than the market price assumed in the regulation and regulatory parameters are not adjusted until 2026, this may have a negative impact on our cash flows in 2024 and 2025.
Our international operations require us to comply with anti-corruption and other laws and regulations of the United States government and various non-U.S. jurisdictions.
Doing business in multiple countries requires us and our subsidiaries to comply with the laws and regulations of the United States government and various non-U.S. jurisdictions. Our failure to comply with these rules and regulations may expose us to liabilities. These laws and regulations may apply to us, our subsidiaries, individual directors, officers, employees and agents, and may restrict our operations, trade practices, investment decisions and partnering activities.
In particular, our non-U.S. operations are subject to United States and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, as amended (the “FCPA”), and similar laws and regulations. The FCPA prohibits United States companies and their officers, directors, employees and agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. The FCPA also requires companies keep books, records and accounts that accurately and fairly reflect transactions and dispositions of assets and to maintain a system of adequate internal accounting controls. As part of our business, we deal with state-owned business enterprises, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. As a result, business dealings between our employees, agents, intermediaries, subcontractors or similar business parties, and any such foreign official could expose us to the risk of violating anti-corruption laws even if such business practices may be customary or are not otherwise prohibited between the us and a private third party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civil penalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures.
We have established policies and procedures designed to assist us and our personnel in complying with applicable United States and non-U.S. laws and regulations; however, we cannot assure you that these policies and procedures will completely eliminate the risk of a violation of these legal requirements, and any such violation (inadvertent or otherwise) could have a material adverse effect on our business, financial condition, results of operations and cash flows.
| VII. | Risks Related to Ownership of Our Shares |
We may not be able to pay a specific or increasing level of cash dividends to holders of our shares in the future.
The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:
| • | operational performance of our assets; |
| • | maintenance capital expenditures in our assets and other potential capital expenditure requirements in our assets in the case there were technical problems, requirements by insurance companies, environmental or regulatory requirements, capital expenditures necessary to increase safety of our employees, or unanticipated increases in construction and design costs; |
| • | our debt service requirements and other liabilities; |
| • | fluctuations in our working capital needs; |
| • | fluctuations in foreign exchange rates; |
| • | the level of our operating and general and administrative expenses; |
| • | seasonal variations in revenues generated by the business; |
| • | losses experienced not covered by insurance; |
| • | shortage of qualified labor; |
| • | restrictions contained in our debt agreements (including our project-level financing); |
| • | our ability to borrow funds, including corporate debt to finance growth and project debt and tax equity investments to finance new assets under construction or which have recently reached COD; |
| • | changes in our revenues and/or cash generation in our assets due to delays in collections from our off-takers, legal disputes regarding contact terms, adjustments contemplated in existing regulation or changes in regulation or taxes in the countries in which we operate, or adverse weather conditions; |
| • | other business risks affecting our cash levels; and |
| • | unfavorable regional, national or global economic and market conditions; |
As a result of all these factors, we cannot guarantee that we will have sufficient cash generated from operations to pay a specific or increasing level of cash dividends to holders of our shares. Furthermore, holders of our shares should be aware that the amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items.
We are a holding company whose sole material assets consist of our interests in our subsidiaries. We do not have any independent means of generating revenue. We intend to cause our operating subsidiaries to make distributions to us in an amount sufficient to cover our corporate debt service, corporate general and administrative expenses, all applicable taxes payable and dividends, if any, declared by us. To the extent that we need funds for a quarterly cash dividend to holders of our shares or otherwise, and one or more of our operating subsidiaries is restricted from making such distributions under the terms of its financing or other agreements or applicable law and regulations or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition and limit our ability to pay dividends to shareholders. Our project-level financing agreements generally prohibit distributions to us unless certain specific conditions are met, including the satisfaction of financial ratios. The ability of our operating subsidiaries to make distributions could also be limited by legal, regulatory or other restrictions or limitations applicable in the various jurisdictions in which we operate, such as exchange controls or similar matters or corporate law limitations. Our ability to pay dividends on our shares is also limited by restrictions under the Revolving Credit Facility, the 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Senior Notes.
Our cash available for distribution will likely fluctuate from quarter to quarter, in some cases significantly, due to seasonality. See “Item 4.B—Business Overview—Seasonality.” As result, we may reduce the amount of cash we distribute in a particular quarter to establish reserves to fund distributions to shareholders in future periods. If we fail to establish sufficient reserves, we may not be able to maintain our quarterly dividend with respect to a quarter adversely affected by seasonality.
Dividends to holders of our shares will be paid at the discretion of our Board of Directors. Our Board of Directors may decrease the level of or entirely discontinue payment of dividends. Our Board of Directors may change our dividend policy at any point in time or modify the dividend for specific quarters following prevailing conditions. Our Board of Directors may also decide to change our dividend policy if, for example, they considered that increasing the portion of growth self-funded with cash generated by our operations is more efficient than raising most of the funds required to finance our growth strategy. For a description of additional restrictions and factors that may affect our ability to pay cash dividends, please see “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy.”
Future dispositions of our shares by substantial shareholders or the perception thereof may cause the price of our shares to fall.
Future dispositions of substantial amounts of the shares and/or equity-related securities in the public market, or the anticipation or perception by the market that such dispositions could occur, could adversely affect prevailing trading prices of the shares and could impair our ability to raise capital through future offerings of equity or equity-related securities.
Further, Algonquin is the beneficial owner of approximately 42.2% of our ordinary shares some of which have been and may be encumbered in the future to secure debt or other obligations of Algonquin, its subsidiaries or affiliates. The market price of our shares could decline as a result of future dispositions of our shares by Algonquin, its secured creditors or other significant stockholders whether in public or private transactions (whether in a single transaction, a series of related organized transactions or otherwise), or the perception that these dispositions could occur.
Liberty GES has a secured credit facility in the amount of $306,500,000 maturing on September 30, 2024. Such loan is collateralized by a pledge over most of the Atlantica shares held indirectly by Algonquin through certain of its subsidiaries. A collateral shortfall under that facility would occur if the quotient of the net obligations of Liberty GES, divided by the aggregate collateral share value is equal to or greater than 50% in which case the creditors under that facility may sell Atlantica shares to eliminate the collateral shortfall. In addition, a default by Liberty GES under such facility may result in its creditors having the right to foreclose on the shares and sell the shares.
Many factors may influence Algonquin’s operations, plans, or strategy (including with respect to the holding or disposition of all or any portion of our shares), and we have limited knowledge and/or visibility with respect to Algonquin’s operations, plans, or strategy. In 2023, Algonquin conducted a strategic review which concluded in August 2023 with the announcement that they will pursue the sale of its renewable energy business and their intention focus on their regulated business. This announcement did not include Algonquin’s ownership in Atlantica. It is possible that in the future Algonquin may have interest in selling part or all of its equity interest in Atlantica. Uncertainty about Algonquin’s plans or strategy with respect to the holding or disposition of all or any portion of its equity interest in Atlantica and such uncertainty may negatively affect the market price for our shares and our ability to raise capital by offering equity or equity-related securities.
We cannot predict whether future sales of our shares, or the increase in the availability of our shares for sale, will occur and the impact thereof on the market price for our shares and our ability to raise capital by offering equity or equity-related securities.
As a “foreign private issuer” in the United States, we are exempt from certain rules under the U.S. securities laws and are permitted to file less information with the SEC than U.S. companies.
As a “foreign private issuer,” we are exempt from certain rules under the Exchange Act that impose certain disclosure obligations and procedural requirements for proxy solicitations under Section 14 of the Exchange Act. In addition, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules under the Exchange Act with respect to their purchases and sales of our shares. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act. In addition, we are not required to comply with Regulation FD, which restricts the selective disclosure of material information.
If we were to lose our “foreign private issuer” status, we would no longer be exempt from certain provisions of the U.S. securities laws we would be required to commence reporting on forms required of U.S. companies, and we could incur increased compliance and other costs, among other consequences.
The rights of our shareholders may differ from the rights typically offered to shareholders of a U.S. corporation organized in Delaware.
We are incorporated under the laws of England and Wales. The rights of holders of our shares are governed by the laws of England and Wales, including the provisions of the UK Companies Act 2006, and by our articles of association. These rights differ in certain respects from the rights of shareholders in typical U.S. corporations organized in Delaware. The principal differences are set forth in “Item 10.B—Memorandum and Articles of Association.”
There are limitations on enforceability of civil liabilities against us.
We are incorporated under the laws of England and Wales. A majority of our officers and directors reside outside the United States. In addition, a significant portion of our assets and a significant portion of the assets of our directors and officers are located outside the United States. As a result, it may be difficult or impossible to effect service of process within the United States upon us or such officers and directors, with respect to matters arising under U.S. federal securities law, or to force us or them to appear in a U.S. court. It may also be difficult or impossible to enforce a judgment of a U.S. court against persons outside the United States, predicated upon civil liability provisions under U.S. federal securities law, or to enforce a judgment of a foreign court against such persons in the United States. We believe that there may be doubt as to the enforceability against persons in England and Wales and in Spain, whether in original actions or in actions for the enforcement of judgments of U.S. courts, of civil liabilities predicated solely upon the laws of the United States, including its federal securities laws. In addition, punitive damages in actions brought in the United States or elsewhere may be unenforceable in England and Wales or in Spain.
Shareholders in certain jurisdictions may not be able to exercise their pre-emptive rights if we increase our share capital.
Under our articles of association, holders of our shares generally have the right to subscribe and pay for a sufficient number of our shares to maintain their relative ownership percentages prior to the issuance of any new shares in exchange for cash consideration. Holders of shares in certain jurisdictions may not be able to exercise their pre-emptive rights unless securities laws have been complied with in such jurisdictions with respect to such rights and the related shares, or an exemption from the requirements of the securities laws of these jurisdictions is available. To the extent that such shareholders are not able to exercise their pre-emptive rights, the pre-emptive rights would lapse, and the proportional interests of such holders would be reduced.
In addition, under the Shareholders Agreement, Algonquin may subscribe to capital increases in cash for up to 100.0% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under Algonquin or the Liberty GES ROFO Agreement. If we issue ordinary shares for any other purpose, Algonquin may subscribe in cash for our ordinary shares in a pro rata amount of such Algonquin’s holding in us. The Shareholders Agreement may be terminated or modified in the future. In any case, Algonquin has the right but not the obligation to subscribe for our shares.
Provisions in the UK City Code on Takeovers and Mergers may have anti-takeover effects that could discourage an acquisition of us by others, even if an acquisition would be beneficial to our shareholders.
The UK City Code on Takeovers and Mergers, or the Takeover Code, applies, among other things, to an offer for a public company whose registered office is in the U.K. and whose securities are not admitted to trading on a regulated market in the U.K. if the company is considered by the Panel on Takeovers and Mergers, or the Takeover Panel, to have its place of central management and control in the U.K. This is known as the “residency test.” The test for central management and control under the Takeover Code is different from that used by the UK tax authorities. Under the Takeover Code, the Takeover Panel will determine whether we have our place of central management and control in the United Kingdom by looking at various factors, including the structure of our Board of Directors, the functions of the directors and where they are resident.
If at the time of a takeover offer the Takeover Panel determines that we have our place of central management and control in the U.K., we would be subject to a number of rules and restrictions, including, but not limited to, the following: (1) our ability to enter into deal protection arrangements with a bidder would be extremely limited; (2) we may not, without the approval of our shareholders, be able to perform certain actions that could have the effect of frustrating an offer, such as issuing shares or carrying out acquisitions or disposals; and (3) we would be obliged to provide equality of information to all bona fide competing bidders.
| VII. | Risks Related to Taxation |
Changes in our tax position can significantly affect our reported earnings and cash flows.
We have assets and operations in different jurisdictions, which are subject to different tax regimes. Changes in tax regimes such as the reduction or elimination of tax benefits could adversely affect our assets or operations. Limitations on the deductibility of interest expense could adversely affect our ability to deduct the interest we pay on our debt. These and other potential changes in tax laws and regulations could have a material adverse effect on our results and cash flows. In addition, a reduction in corporate tax rates could make investments in renewable projects less attractive to potential tax equity investors, in which case we may not be able to obtain third-party financing on terms as beneficial as in the past, or at all, which could limit our ability to grow our business.
Changes in corporate tax rates and/or other relevant tax laws in the United Kingdom, the United States, Spain, Mexico or the other countries in which our assets and operations are located may have a material impact on our future tax rate and/or our required tax payments. Such changes may include measures enacted in response to the ongoing initiatives in relation to fiscal legislation at an international level, such as the Action Plan on Base Erosion and Profit Shifting of the Organization for Economic Co-operation and Development (“OECD”). The final determination of our tax liability could be different from the forecasted amount, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. Changes to the U.K. controlled foreign company rules or adverse interpretations of them, could have an impact on our future tax rate and/or our required tax payments. With respect to some of our projects, we must meet defined requirements to receive favorable tax treatment, such as lower tax rates or exemptions. We intend to meet these requirements in order to benefit from the favorable tax treatment; however, there can be no assurance that we will be able to comply with all of the necessary requirements in the future, or that the requirements could change or be interpreted in another manner, which could give rise to a greater tax liability and which may have a material adverse effect on our business, results of operations, financial condition and cash flows.
In addition, the governments of some countries where we operate could implement changes to their tax laws and regulations, the content of which are largely uncertain currently. These potential changes to applicable tax laws and regulations could have a negative impact on our financial condition, results of operations and cash flows. Furthermore, tax laws and regulations are subject to interpretation. Our tax returns in each country are subject to inspection and even if we believe that we are complying with all tax laws and regulations in each country, a tax inspector could have a different view, which may result in additional tax liabilities and may have a negative impact on our financial condition, results of operations and cash flows.
The main rate of UK corporation tax rate increased to 25% for fiscal years beginning on April 1, 2023. We do not expect this increase to result in significant impacts in our tax position in the UK.
In 2022, the government of South Africa approved tax limitations on deductions for tax years ending on or after March 31, 2023. The net interest expense has been limited to 30% of the EBITDA and any NOLs carried forward may only be applied to offset 80% of a corporation’s taxable income. These new limitations may have a negative impact on our cash flows.
The government of Spain introduced new restrictions on the tax deductibility of financial expenses for tax periods beginning on January 1, 2024. Any exempt dividend received by our Spanish entities will not be considered to increase the limitation of 30% of the EBITDA (as defined in the relevant Spanish laws) which determines the annual tax allowance of financial expenses. We do not expect this limitation to result in significant impacts in our tax position.
Around 140 countries have agreed to implement the “Two Pillars Solution”, an OECD/ G20 Inclusive Framework initiative, which aims to reform the international taxation policies and ensure that multinational companies pay taxes wherever they operate and generate profits. “Pillar Two” of this initiative generally provides for an effective global minimum corporate tax rate of 15% on profits generated by multinational companies with consolidated revenues of at least €750 million, calculated on a country-by country basis. This minimum tax (when fully implemented) will be applied on profits in any jurisdiction wherever the effective tax rate, determined on a jurisdictional basis, is below 15%. Any additional tax liability resulting from the application of this minimum tax will generally be payable by the parent entity of the multinational group to the tax authority in such parent’s country of residence.
The new legislation related to Pillar Two has been enacted or substantially enacted in certain jurisdictions in which Atlantica operates, including the U.K. The new legislation will be effective for Atlantica’s financial years beginning on or after December 31, 2023. We have performed a preliminary assessment of the potential exposure to Pillar Two top-up taxes. The assessment is based on the most recent country-by-country tax reporting and financial statements available for the constituent entities of the group. Based on the assessment performed, the Pillar Two effective tax rates in most of the jurisdictions in which Atlantica operates are above 15% and in all of them meet the requirements to apply the relevant transitional “safe harbors” as defined by OECD, with the exception of one jurisdiction, whose impact is not material. Therefore, we currently do not expect a material impact on our business, financial condition, results of operations and cash flows.
Our future tax liability may be greater than expected if we do not use sufficient NOLs to offset our taxable income.
We have NOLs that we can use to offset future taxable income. Based on our current portfolio of assets, which include renewable assets that benefit from an accelerated tax depreciation schedule, and subject to potential tax audits, which may result in income, sales, use or other tax obligations, we do not expect to pay significant taxes in the upcoming years.
Although we expect that these NOLs will be available as a future benefit, in the event that they are not generated as expected, or are successfully challenged by the local tax authorities, such as the IRS or HM Revenue and Customs among others, by way of a tax audit or otherwise, or are subject to future limitations as discussed below, our ability to realize these benefits may be limited. A reduction in our expected NOLs, a limitation on our ability to use such NOLs or the occurrence of future tax audits may result in a material increase in our estimated future income tax liability and may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our ability to use U.S. NOLs to offset future income may be limited.
We have generated significant NOLs. For purposes of U.S. federal income taxation, NOLs generated on or before December 31, 2017, can generally be carried back two years and carried forward for up to twenty years and can be applied to offset 100% of taxable income in such years. NOLs incurred between January 1, 2018, and December 31, 2020 may be carried forward indefinitely and carried back five years. Losses arising after December 31, 2020, cannot be carried back and may be applied to offset 80% of our taxable income in future years.
Our NOL carryforwards and certain recognized built-in losses may be limited by Section 382 of the IRC if we experience an “ownership change.” In general, an “ownership change” occurs if 5% shareholders of our stock increase their collective ownership of the aggregate amount of the outstanding shares of our company by more than 50 percentage points, generally over a three-year testing period. An ownership change may be triggered if Algonquin sold all or part of its equity interest in Atlantica or if there was a significant ownership change in the Algonquin shareholder base. In the event of an ownership change, NOLs that exceed the Section 382 limitation in any year will continue to be allowed as carryforwards for the remainder of the carryforward period and will be available to offset taxable income for years within the carryforward period subject to the Section 382 limitation in each year. Nevertheless, if the carryforward period for any NOL were to expire before that loss had been fully utilized, the unused portion of that loss would be lost. Our use of new NOLs arising after the date of an ownership change would not be affected by the Section 382 limitation (unless there were another ownership change after those new losses arose).
We have experienced ownership changes in the past. Future sales by our largest shareholder, future equity issuances and in general the activity of our direct or indirect shareholders may further limit our ability to use net operating loss carryforwards in the United States, which could have a potential adverse effect on cash flows from U.S. assets expected in the future. In addition, the IRS has issued proposed regulations concerning the calculation of built-in gains and losses under Section 382, which, if finalized, may significantly limit our annual use of pre-ownership change U.S. NOLs in the event that a new ownership change occurs after the new rule is in place.
In addition, because we have recorded tax credits for the U.S. tax losses carryforwards in the past, a limit to our ability to use U.S. NOLs could result in writing off tax credits, which could cause a substantial non-cash income tax expense in our financial statements.
If we are a passive foreign investment company for U.S. federal income tax purposes for any taxable year, U.S. Holders of our shares could be subject to adverse U.S. federal income tax consequences.
If we were a PFIC for any taxable year during which a U.S. Holder held our shares, certain adverse U.S. federal income tax consequences may apply to the U.S. Holder. We do not believe that we were a PFIC for our taxable year ended December 31, 2023 and do not expect to be a PFIC for U.S. federal income tax purposes for the current taxable year or in the foreseeable future taxable years. The application of the PFIC rules is, however, subject to uncertainty in several respects, and we must make a separate determination after the close of each taxable year as to whether we were a PFIC for such year. PFIC status depends on the composition of a company’s income and assets and the fair market value of its assets (including certain equity investments) from time to time, as well as on the application of complex statutory and regulatory rules that are subject to potentially varying or changing interpretations. Accordingly, there can be no assurance that we will not be considered a PFIC for any taxable year.
If we were a PFIC, U.S. Holders of our shares may be subject to adverse U.S. federal income tax consequences, such as taxation at the highest marginal ordinary income tax rates on capital gains and on certain actual or deemed distributions, interest charges on certain taxes treated as deferred, and additional reporting requirements. See “Item 10.E—Taxation—U.S. Federal Income Tax Considerations—Passive foreign investment company rules.”
Our suppliers may have lower ethical standards than we do and may not comply with all laws and regulations, which may adversely impact our business.
We have suppliers in different geographies. Although we have policies and procedures in place, including a Supplier Code of Conduct, we do not control our suppliers and their business practices. As a result, we cannot guarantee that they follow ethical business practices, such as fair wage practices and compliance with environmental, safety, and other local laws. In case our existing suppliers had a demonstrated lack of compliance, we may need to change suppliers, which may result in increased costs. Unethical practices and lack of compliance by our suppliers may also have a negative impact on our reputation, which may in turn have an adverse effect on our business, results of operations and cash flows.
We may not satisfy the standards of our existing or future ESG certifications or those of investors or regulators for assets with sustainability characteristics.
There can be no assurance of the extent to which we will be successful in satisfying the requirements or standards of our existing or future ESG certifications or those of investors or regulators for assets with sustainability characteristics. In addition, there is no assurance that any future investments we make will meet investor expectations or any standards for investment in assets with sustainability characteristics, or standards regarding sustainability performance, in particular with regard to any direct or indirect environmental, sustainability or social impact. Failure to maintain any existing or future ESG certification or those of investors or regulators for assets with sustainability characteristics may adversely affect our business, financial condition, results of operations and prospects.
Further, adverse environmental, regulatory, political or social changes may occur during the design, construction and operation of any action we may take in furtherance of our sustainability goals, making it less likely, more expensive or impracticable for us to achieve such goals, or such actions may become controversial or criticized by activist groups or other stakeholders.
| ITEM 4. | INFORMATION ON THE COMPANY |
| A. | History and Development of the Company |
Atlantica Sustainable Infrastructure plc was incorporated in England and Wales as a private limited company on December 17, 2013. On June 18, 2014, we completed our IPO and our shares are listed on the NASDAQ Global Select Market under the symbol “AY.” The address of our principal executive offices is Great West House, GW1, 17th floor, Great West Road, Brentford, TW8 9DF, United Kingdom, and our phone number is +44 203 499 0465. Our current agent in the U.S. is Atlantica North America LLC, a Delaware limited liability company with its principal office located at 850 New Burton Road, Suite 201, Dover, Delaware 19904, United States.
Prior to the consummation of our IPO, Abengoa transferred ten assets to us and since then our portfolio has grown through acquisitions and investments. On November 1, 2017, Algonquin agreed to acquire 25.0% of our shares from Abengoa and upon completion of the relevant share sale, became our largest shareholder. On November 27, 2018, Algonquin acquired from Abengoa the remaining 16.5% of our shares previously held by Abengoa and in 2019, Algonquin progressively increased its stake in our shares up to 44.2% as of December 31, 2019. As of the date of this annual report, Algonquin owns 42.2% of our shares.
Investments
We refer to “Item 5. —Operating and Financial Review and Prospects” for the description of our recent investments. Apart from these investments, there have been no material capital expenditures or divestitures or public takeover offers made to and by the Company in the last three years.
The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, which can be found at http://www.sec.gov. Our internet address is https://www.atlantica.com/web/en/. The URLs included in this annual report on Form 20-F are intended to be an inactive textual reference only. They are not intended to be an active hyperlink to the applicable website. The information contained on our website is not incorporated by reference and does not form part of this annual report on Form 20-F.
Overview
We are a sustainable infrastructure company with a majority of our business in renewable energy assets. Our purpose is to support the transition towards a more sustainable world by developing, building, investing and managing sustainable infrastructure assets, while creating long-term value for our investors and the rest of our stakeholders. In 2023, renewables represented 73% of our revenue, with solar energy representing 63%. We complement our renewable assets portfolio with storage, efficient natural gas and transmission infrastructure assets, as enablers of the transition towards a clean energy mix. We also hold water assets, a relevant sector for sustainable development.
As of the date of this annual report, we own or have an interest in a portfolio of assets and new projects under development diversified in terms of business sector and geographic footprint. Our portfolio consists of 45 assets with 2,171 MW of aggregate renewable energy installed generation capacity (of which approximately 73% is solar), 343 MW of efficient natural gas-fired power generation capacity, 55 MWt of district heating capacity, 1,229 miles of electric transmission lines and 17.5 M ft3 per day of water desalination.
We currently own and manage operating facilities and projects under development in North America (United States, Canada and Mexico), South America (Peru, Chile, Colombia and Uruguay) and EMEA (Spain, Italy, Algeria and South Africa). Our assets generally have contracted or regulated revenue. As of December 31, 2023, our assets had a weighted average remaining contract life of approximately 13 years3.
We intend to grow our business through the development and construction of projects including expansion and repowering opportunities, as well as greenfield developments, third-party acquisitions, and the optimization of our existing portfolio. We currently have a pipeline of assets under development of approximately 2.2 GW of renewable energy and 6.0 GWh of storage. Approximately 47% of the projects are PV, 41% storage, 11% wind and 1% other projects, while 22% are expected to reach ready-to-build (“RTB”) in 2024-2025, 28% are in an advanced development stage and 50% are in early stage. Also, 20% are expansion or repowering opportunities of existing assets and 80% greenfield developments.
Our objective is to pay a consistent and growing cash dividend to shareholders that is sustainable on a long-term basis. We expect to distribute a significant percentage of our cash available for distribution as cash dividends and we will seek to increase such cash dividends over time through organic growth, investments in new assets and acquisitions.
Current Operations
Our assets are organized into the following four business sectors: Renewable Energy, Efficient Natural Gas and Heat, Transmission Lines and Water. The following table provides an overview of our current assets:
| Assets | Type | Ownership | Location | Currency(9) | Capacity (Gross) | Counterparty Credit Ratings(10) | COD* | Contract Years Remaining(17) |
| | | | | | | | | |
| Solana | Renewable (Solar) | 100% | Arizona (USA) | USD | 280 MW | BBB+/A3/BBB+ | 2013 | 20 |
| Mojave | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB/Ba1/BB+ | 2014 | 16 |
| Coso | Renewable (Geothermal) | 100% | California (USA) | USD | 135 MW | Investment grade(11) | 1987/ 1989 | 18 |
Elkhorn Valley(16) | Renewable (Wind) | 49% | Oregon (USA) | USD | 101 MW | BBB/Baa1/-- | 2007 | 4 |
Prairie Star(16) | Renewable (Wind) | 49% | Minnesota (USA) | USD | 101 MW | --/A3/A- | 2007 | 4 |
Twin Groves II(16) | Renewable (Wind) | 49% | Illinois (USA) | USD | 198 MW | BBB+/Baa2/-- | 2008 | 2 |
Lone Star II(16) | Renewable (Wind) | 49% | Texas (USA) | USD | 196 MW | N/A | 2008 | N/A |
| Chile PV 1 | Renewable (Solar) | 35%(1) | Chile | USD | 55 MW | N/A | 2016 | N/A |
| Chile PV 2 | Renewable (Solar) | 35%(1) | Chile | USD | 40 MW | Not rated | 2017 | 7 |
| Chile PV 3 | Renewable (Solar) | 35%(1) | Chile | USD | 73 MW | N/A | 2014 | N/A |
| La Sierpe | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2021 | 12 |
| La Tolua | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2023 | 9 |
| Tierra Linda | Renewable (Solar) | 100% | Colombia | COP | 10 MW | Not rated | 2023 | 9 |
3 Calculated as weighted average years remaining as of December 31, 2023 based on CAFD estimates for the 2024-2027 period, including assets that have reached COD before March 1, 2024.
| Honda 1 | Renewable (Solar) | 50% | Colombia | COP | 10 MW | BBB-/--/BBB | 2023 | 7 |
| Albisu | Renewable (Solar) | 100% | Uruguay | UYU | 10 MW | Not rated | 2023 | 15 |
| Palmatir | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2014 | 10 |
| Cadonal | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2014 | 11 |
| Melowind | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB+/Baa2/BBB(12) | 2015 | 12 |
| Mini-Hydro | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB/Baa1/BBB | 2012 | 9 |
| Solaben 2 & 3 | Renewable (Solar) | 70%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 14/14 |
| Solacor 1 & 2 | Renewable (Solar) | 87%(3) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 13/13 |
| PS 10 & PS 20 | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007/ 2009 | 8/10 |
| Helioenergy 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 13/13 |
| Helios 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 13/14 |
| Solnova 1, 3 & 4 | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 11/11/12 |
| Solaben 1 & 6 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 15/15 |
| Seville PV | Renewable (Solar) | 80%(4) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 12 |
| Italy PV 1 | Renewable (Solar) | 100% | Italy | Euro | 1.6 MW | BBB/Baa3/BBB | 2010 | 8 |
| Italy PV 2 | Renewable (Solar) | 100% | Italy | Euro | 2.1 MW | BBB/Baa3/BBB | 2011 | 8 |
| Italy PV 3 | Renewable (Solar) | 100% | Italy | Euro | 2.5 MW | BBB/Baa3/BBB | 2012 | 8 |
| Italy PV 4 | Renewable (Solar) | 100% | Italy | Euro | 3.6 MW | BBB/Baa3/BBB | 2011 | 8 |
| Kaxu | Renewable (Solar) | 51%(5) | South Africa | Rand | 100 MW | BB-/Ba2/BB-(13) | 2015 | 11 |
| Calgary | Efficient natural gas & Heat | 100% | Canada | CAD | 55 MWt | ~60% AA- or higher (14) | 2010 | 12 |
| ACT | Efficient natural gas & Heat | 100% | Mexico | USD | 300 MW | BBB/ B3/B+ | 2013 | 9 |
Monterrey(18) | Efficient natural gas & Heat | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 22 |
ATN (15) | Transmission line | 100% | Peru | USD | 379 miles | BBB/Baa1/BBB | 2011 | 17 |
| ATS | Transmission line | 100% | Peru | USD | 569 miles | BBB/Baa1/BBB | 2014 | 20 |
| ATN 2 | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 9 |
| Quadra 1 & 2 | Transmission line | 100% | Chile | USD | 49 miles/ 32 miles | Not rated | 2013/2014 | 11/11 |
| Palmucho | Transmission line | 100% | Chile | USD | 6 miles | BBB/-/BBB+ | 2007 | 14 |
| Chile TL 3 | Transmission line | 100% | Chile | USD | 50 miles | A/A2/A- | 1993 | N/A |
| Chile TL 4 | Transmission line | 100% | Chile | USD | 63 miles | Not rated | 2016 | 48 |
| Skikda | Water | 34.2%(6) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 10 |
| Honaine | Water | 25.5%(7) | Algeria | USD | 7 M ft3/day | Not rated | 2012 | 14 |
| Tenes | Water | 51%(8) | Algeria | USD | 7 M ft3/day | Not rated | 2015 | 16 |
Notes:
| (1) | 65% of the shares in Chile PV 1, Chile PV 2 and Chile PV 3 are indirectly held by financial partners through the renewable energy platform of the Company in Chile. Atlantica has control over these entities under IFRS 10, Consolidated Financial Statements. |
| (2) | Itochu Corporation holds 30% of the shares in each of Solaben 2 and Solaben 3. |
| (3) | JGC holds 13% of the shares in each of Solacor 1 and Solacor 2. |
| (4) | Instituto para la Diversificación y Ahorro de la Energía (“Idae”) holds 20% of the shares in Seville PV. |
| (5) | Kaxu is owned by the Company (51%), Industrial Development Corporation of South Africa (“IDC”, 29%) and Kaxu Community Trust (20%). |
| (6) | Algerian Energy Company, SPA owns 49% of Skikda and Sacyr Agua, S.L. owns the remaining 16.8%. Atlantica has control over it under IFRS 10, Consolidated Financial Statements. |
| (7) | Algerian Energy Company, SPA owns 49% of Honaine and Sacyr Agua, S.L. owns the remaining 25.5%. |
| (8) | Algerian Energy Company, SPA owns 49% of Tenes. The Company has an investment in Tenes through a secured loan to Befesa Agua Tenes (the holding company of Tenes) and the right to appoint a majority at the board of directors of the project company. Therefore, the Company controls Tenes since May 31, 2020, and fully consolidates the asset from that date. |
| (9) | Certain contracts denominated in U.S. dollars are payable in local currency. |
| (10) | Reflects the counterparty’s credit ratings issued by S&P, Moody’s, and Fitch. Not applicable (“N/A”) when the asset has no PPA. |
| (11) | Refers to the credit rating of two Community Choice Aggregators: Silicon Valley Clean Energy and Monterrey Bar Community Power, both with A Rating from S&P. The third off-taker Southern California Public Power Authority is not rated. |
| (12) | Refers to the credit rating of Uruguay, as UTE (Administración Nacional de Usinas y Transmisoras Eléctricas) is unrated. |
| (13) | Refers to the credit rating of the Republic of South Africa. The off-taker is Eskom, which is a state-owned utility company in South Africa. |
| (14) | Refers to the credit rating of a diversified mix of 22 high credit quality clients (~60% AA- rating or higher). |
| (15) | Including ATN Expansion 1 & 2. |
| (16) | Part of Vento II portfolio. |
| (17) | As of December 31, 2023. |
| (18) | Accounted for as held for sale as of December 31, 2023. |
| (*) | Commercial Operation Date. |
Our Business Strategy
Our strategy focuses on climate change solutions in the power and water sectors. We intend to provide clean electricity, storage capacity, transmission capacity and desalinated water in a safe, reliable and environmentally responsible way. We believe our value creation capability is significantly enhanced by investing in sustainable sectors and managing our assets in a sustainable manner to the benefit of our shareholders and other stakeholders.
We intend to take advantage of, and leverage our growth strategy on, favorable trends in clean power generation, energy scarcity and the global focus on the reduction of carbon emissions. We believe that we are well positioned to benefit from the expected transition towards a more sustainable power generation mix in our markets.
We intend to grow our business maintaining renewable energy as our main segment with a primary focus on North America and Europe. We expect to continue investing in the development and construction of new assets, with a focus on renewable energy and storage. We own a pipeline of projects under development of approximately 2.2 GW of renewable energy and approximately 6.0 GWh of storage. We also expect to acquire assets from third parties leveraging the local presence and network we have in geographies and sectors in which we operate.
Additionally, we believe we can achieve organic growth through the optimization of the existing portfolio, escalation factors at many of our assets, as well as the repowering and hybridization with other technologies of some of the renewable energy facilities and the expansion of our existing transmission lines.
Our plan for executing this strategy includes the following key components:
Grow our business by developing new projects and investing in new assets with a focus on renewable energy and storage.
We intend to develop new assets and, in some cases, to invest in assets under development or construction. We believe that our know-how and operating expertise in our key markets together with a critical mass of assets in several geographic areas as well as our access to capital will assist us in achieving our growth plans.
Focus on stable assets in renewable energy, storage and transmission, generally contracted or regulated.
We intend to focus on owning and operating stable, sustainable infrastructure assets, with long useful lives, generally contracted, for which we believe we have extensive experience and proven systems and management processes, as well as the critical mass to benefit from operating efficiencies and scale. We intend to maintain a diversified portfolio with a large majority of our Adjusted EBITDA generated from low-carbon footprint assets, as we believe these sectors will see significant growth in our targeted geographies.
Maintain diversification across our business sectors and geographies.
Our focus on three core geographies, North America, Europe and South America, helps to ensure exposure to markets in which we believe renewable energy, storage and transmission will continue to grow significantly. We believe that our diversification by business sector and geography limits risks, reinforces stability and provides us with better growth opportunities.
Grow our business through the optimization of the existing portfolio and through investments in the expansion of our current assets.
We intend to grow our business through organic growth that we expect to deliver through the optimization of the existing portfolio, price escalation factors in many of our assets as well as through investments in the expansion and repowering of our current assets and hybridization of existing assets with other complementary technologies including storage, particularly in our renewable energy assets and transmission lines.
Maintain a low-risk approach
We intend to maintain a portfolio of sustainable infrastructure assets, generally totally or partially contracted, with a low-risk profile for a significant part of our revenue. We generally seek to invest in assets with proven technologies in which we generally have significant experience, located in countries where we believe conditions to be stable and safe. We may complement our portfolio with investments or co-investments in assets with shorter contracts or with partially contracted or merchant revenue or in assets with revenue in currencies other than the U.S. dollar or euro. We have a set of policies and a risk management system in place which define thorough risk management processes.
Maintain a prudent financial policy and financial flexibility
Non-recourse project debt is an important principle for us. We intend to continue financing our assets with project debt progressively amortized using the cash flows from each asset and where lenders do not have recourse to the holding company assets. The majority of our consolidated debt is project debt.
In addition, we hedge a significant portion of our interest rate risk exposure. We estimate that as of December 31, 2023, approximately 93% of our total interest risk exposure was fixed or hedged, generally for the long-term. We also limit our foreign exchange exposure. We intend to ensure that at least 80% of our cash available for distribution is always in U.S. dollars and euros. Furthermore, we hedge net distributions in euros for the upcoming 24 months on a rolling basis.
We also intend to maintain a solid financial position through a combination of cash on hand and undrawn credit facilities. In order to maintain financial flexibility, we use diversified sources of financing in our project and corporate debt including banks, capital markets and private investor financing. In recent years we have been active in green financing initiatives, improving our access to new debt investors.
Our Competitive Strengths
We believe that we are well-positioned to execute our business strategies thanks to the following competitive strengths:
Stable and predictable long-term cash flows
We believe that our portfolio of sustainable infrastructure has a stable cash flow profile. We estimate that the off-take agreements or regulation in place at our assets have a weighted average remaining term of approximately 134 years as of December 31, 2023, providing long-term cash flow visibility. In 2023, approximately 54% of our revenue was non-dependent on natural resource, not subject to the volatility that natural resource may have, especially solar and wind resources. This includes our transmission lines, our efficient natural gas plant, our water assets and approximately 76% of the revenue received from our solar assets in Spain with most of their revenues based on capacity in accordance with the regulation in place. In these assets, our revenue is not subject to (or has low dependence on) solar, wind or geothermal resources, which translates into a more stable cash-flow generation. Going forward, our new investments will probably be more dependent on the natural resource. Additionally, our facilities have minimal or no fuel risk.
Our diversification by geography and business sector also strengthens the stability of our cash flow generation. We expect our well-diversified asset portfolio, in terms of business sector and geography to maintain cash flow stability.
Positioned in business sectors with high growth prospects
The renewable energy industry has grown significantly in recent years and it is expected to continue to grow in the coming decades. The renewable energy industry has grown significantly in recent years and it is expected to continue to grow in the coming decades. According to Bloomberg New Energy Finance (BNEF), the next three decades will require between $46 trillion and $131 trillion of investment which translates into an annual range of $1.5-$4.4 trillion. BNEF projects an annual investment of $1.2-$3.9 trillion in low-carbon energy sources, including renewables, surpassing the $1 trillion invested in 20225. Furthermore, clean energy is on track to set new records. Global installation of wind, solar and storage is expected to exceed 680 GW in 2024, up 22% from 2023. Solar is anticipated to lead the way in 2024 with over 500 GW expected to be installed; which will likely make it the largest source of new capacity and new generation worldwide. Onshore wind follows as the second-highest, with close to 100 GW projected to be installed in 2024, followed by storage capacity, of which around 50 GW is expected to be installed6.
The significant increase expected in the renewable energy space over the coming decades also requires significant new investments in electric transmission and distribution lines for power supply, as well as storage and natural gas generation for dispatchability, with each becoming key elements to support additional wind and solar energy generation. We believe that we are well positioned in sectors with solid growth expectations.
We also believe that our diversified exposure to international markets will allow us to pursue improved growth opportunities and achieve higher returns than we would have if we had a narrower geographic or technological focus. If certain geographies and business sectors become more competitive for investments in the future, we believe we can continue to execute on our growth strategy by having the flexibility to invest in other regions or in other business sectors.
Well positioned to capture growth opportunities
We have in-house development capabilities and partnerships with third parties to co-develop new projects. Our development asset identification is supported by rigorous analysis and deeply rooted industry knowledge and experience. In addition, we follow a disciplined approach to make capital allocation decisions and we have strict minimum required returns for development projects and acquisitions that we update frequently. In addition, our current portfolio of assets offers growth opportunities through the expansion and repowering of existing assets and through hybridization of existing assets with other complementary technologies. We can also grow by adding storage to our existing renewable assets or by developing standalone storage close to our existing assets.
4 Calculated as weighted average years remaining as of December 31, 2023 based on CAFD estimates for the 2024-2027 period, including assets that have reached COD before March 1, 2024.
5 BNEF Theme: Energy Investment and Climate Scenarios.
6 Where Energy Markets and Climate Policy Are Headed in 2024: BNEF.
Proven capabilities in operation and maintenance
We perform operation and maintenance in-house in a majority of our assets. We believe this approach allows us to have full control of our assets and to optimize their performance. We can benefit from synergies in shared resources and centralized purchasing management, among other advantages. Our corporate operations departments have a plan to periodically review all our assets in detail to identify best practices and improvement actions which are then implemented across the portfolio.
Solid financing expertise
Our Finance team has extensive experience in project financing and project refinancing in our different geographies. In our corporate financing, we have access to different pools of capital. We have issued bonds in the public markets, including convertibles, private placements with different types of investors, bank financing and commercial paper. Since a portion of the assets have revenues denominated in euros, we can issue corporate financings in euros, to take advantage of lower costs.
Lean corporate structure focused on value added activities
We operate a lean and efficient organization where corporate functions support each operating asset. Our core corporate policies are supported by a solid commitment to risk management that guides all our decisions. We believe that our internal management system ensures a nimble decision making process while ensuring compliance with our policies and risk management system.
Well positioned in ESG
In 2023, 72% of our Adjusted EBITDA was derived from renewable energy and 62% of our Adjusted EBITDA corresponded to solar energy production. Adjusted EBITDA from low carbon footprint assets represented 89%, including renewable energy, transmission infrastructure, as well as water assets. We have set a target to maintain over 85% of our Adjusted EBITDA generated from low-carbon footprint assets.
We have set a target to reduce our scope 1 and scope 2 GHG emissions per unit of energy generated7 by 70% by 2035, with 2020 as base year. This target was validated in 2021 by the Science Based Targets initiative. We have also set a target to reduce our scope 3 emissions per unit of energy generated by 70% by 2035 from a 2020 base year. With this, we target to achieve net zero GHG emissions by 2040. Additionally, we have also set targets to reduce non-GHG emissions per unit of energy generated and to reduce our water consumption per unit of energy generated.
In 2023, our key health and safety indicators met annual targets and remained below the sector average in all our geographies. Health and Safety is our number one priority, and we want our employees, partners, and contractors to apply the highest standards to ensure safe and sustainable operations.
Regarding our local communities, we acknowledge that our day-to-day activities have impacts on nearby communities. We recognize that the communities where we operate are where some of our employees and
other stakeholders live and raise their families, and where part of our future workforce is educated and trained. We foster communities’ economic prosperity through local purchases and by hiring local employees. As such, it is key for us to be both proactive and a valued member of our communities. In 2023 we invested $1.5 million (in line with 2022 investment). Atlantica’s investments in local communities are focused on improving infrastructure and supporting education.
In terms of governance, we maintain a simple structure with one class of shares. The majority of our Directors are independent, and all the board committees are formed exclusively by independent directors. 22% of our directors are women. We believe that we have a solid compliance framework with a set of policies approved and reviewed annually by the Board of Directors, a Code of Conduct which is acknowledged by all employees annually and internal procedures aimed at ensuring that all geographies comply with our policies.
7 Including thermal generation.
We have been rated by various ESG rating agencies, which we believe can provide relevant information for investors.
Our Operations
Renewable energy
Solana
Overview. Solana is a 250 MW net (280 MW gross) solar plant, wholly owned by us, located in Maricopa County, Arizona, approximately 70 miles southwest of Phoenix. Solana uses a conventional parabolic trough solar power system to generate electricity, including a 22-mile 230kV transmission line and a molten salt thermal energy storage system. Solana reached COD in October 2013.
PPA. Solana has a 30-year, fixed-price PPA with Arizona Public Service Company, or APS, for at least 110% of the output of the project. The PPA provides for the sale of electricity at a fixed base price approved by the Arizona Corporation Commission (“ACC”) with annual increases of 1.84% per year. The PPA includes ongoing performance obligations. The PPA expires in October 2043.
O&M. We perform O&M for Solana with our own personnel.
Operations. Solana has not yet achieved its technical capacity on a continuous basis. During the last few years, repairs, replacements and improvements were conducted on the heat exchangers, the water plant, the storage system and the solar field. In 2021, 2022 and the beginning of 2023, availability in the storage system was lower than expected due to the repairs and replacements that we have been carrying out. These works have impacted production in 2021, 2022 and 2023 and may impact production in 2024 and upcoming years.
Project Level Financing. Solana received a loan from the Federal Financing Bank (“FFB”) in December 2010, with a guarantee from the DOE. The FFB loan is payable over a 29-year term and has an average fixed interest rate of 3.69%. As of December 31, 2023, the outstanding balance of the loan was $701.8 million. The FFB loan permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.20x.
Mojave
Overview. Mojave is a 250 MW net (280 MW gross) solar plant wholly-owned by us located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Mojave relies on a conventional parabolic trough solar power system to generate electricity. Mojave reached COD in December 2014.
PPA. Mojave has a 25-year, fixed-price PPA with Pacific Gas & Electric Company, for 100% of the output of Mojave which began on COD. The PPA provides for the sale of electricity at a fixed base price with seasonal adjustments and adjustments for time of delivery. Mojave can deliver and receive payment for at least 110% of contracted capacity under the PPA. The PPA expires in 2039.
O&M. We perform O&M for Mojave with our own personnel.
Project Level Financing. Mojave received a loan from the FFB in September 2011, with a guarantee from the DOE. The FFB loan is payable over a 25-year term and has an average fixed interest rate of 2.75%. As of December 31, 2023, the outstanding balance of the loan was $570.5 million. The financing arrangement permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.20x.
Coso
Overview. Coso is a platform of nine geothermal units with a total net capacity of approximately 135 MW located in Inyo County, California. This asset provides baseload renewable generation to CAISO.
PPAs. We have three PPAs with fixed prices:
| • | Two PPAs representing approximately 85% of the revenues until 2026 and 60% from 2027 until 2036 with two Community Choice Aggregators (“CCAs”), Silicon Valley Clean Energy and Central Coast Community Energy (formerly Monterrey Bay Community Power), both with an “A” credit rating from S&P. |
| • | A PPA for approximately 15% of the revenues until 2026, 40% from 2027 until 2036 and 50% from 2037 until 2041 with Southern California Public Power Authority (“SCPPA”), which is not rated. |
O&M. Operation and maintenance is performed in-house.
Project Level Financing. In December 2020, before the acquisition of Coso was closed, the asset entered into a $273 million financing agreement. On July 15, 2021, we prepaid $40 million, and the notional amount was reduced to $233 million. From the total amount, $93 million is progressively repaid following a theoretical 2036 maturity, with a legal maturity in 2027. The remaining $140 million are expected to be refinanced on or before 2027. Interest has been hedged in two tranches, the first tranche extends until 2027 with a strike rate of 0.86%, and the second tranche extends from 2027 to 2040 with a strike rate of 2.11%. As of December 31, 2023, the outstanding balance of the loan was $188.6 million. The financing agreement permits cash distributions to shareholders subject to a debt service coverage ratio of at least 1.20x.
Vento II
Vento II is a portfolio of four wind assets located in the states of Illinois, Texas, Oregon and Minnesota in the United States in which Atlantica has a 49% equity interest. The portfolio does not currently have any debt. O&M services are provided by EDP Renewables North America (“EDPR”) for the four assets.
Elkhorn Valley is a 101 MW wind asset in Union County, Oregon, which entered into operation in November 2007.
PPA. Elkhorn Valley has a PPA with Idaho Power Company at a fixed price, expiring in December 2027. Base price increases annually with a 3% escalation factor.
Prairie Star is a 101 MW wind asset in Filmore County, Minnesota, which entered into operation in December 2007.
PPA. Prairie Star has a PPA with Great River Energy. The PPA expires in December 2027 with the option to extend it until 2036.
Twin Groves II is a 198 MW wind asset in McLean County, Illinois, which entered into operation in March 2008.
PPA. Twin Groves II has a PPA with Exelon Generation Co LLC at a fixed price, expiring in March 2026.
Lone Star II is a 196 MW wind asset in Albany, Texas, which entered into operation in May 2008.
PPA. Lone Star II had a PPA with EDPR North America, LLC at a fixed price that expired in January 2023 and the plant is currently selling electricity at market prices. Together with our partner EDPR, we have decided to sell electricity at market prices in the short-term and re-evaluate in the future the option to repower or recontract the asset.
Chile PV 1, Chile PV 2 and Chile PV 3
In April 2020 we made an investment in the creation of a renewable energy platform in Chile, together with financial partners, where we now own approximately a 35% stake and have a strategic investor role. The platform intends to make further investments in renewable energy and storage in Chile and sign PPAs with credit-worthy off-takers.
Overview. Chile PV 1, Chile PV 2 and Chile PV 3 are three solar plants with 55 MW, 40 MW, and 73 MW, respectively. Chile PV 1 reached COD in May 2016, Chile PV 2 reached COD in August 2017 and Chile PV 3 reached COD in December 2014.
PPA. Chile PV 1 and Chile PV 3 sell their production to the Chilean power market. Chile PV 2 has PPAs signed for part of its production.
O&M. Chile PV 1, Chile PV 2 and Chile PV 3 have O&M agreements with third parties.
Project Level Financing. Two of the three assets have long-term project finance agreements in place in U.S. dollars, with a total outstanding balance of $70.9 million as of December 31, 2023. Payments are made semi-annually. The debt agreements bear interest based on six-month SOFR and more than 75% has been hedged. The financing arrangements permit dividend distributions at least once per year subject to meeting the debt service coverage ratios required by contract.
Due to low electricity prices in Chile, the project debts of Chile PV 1 and 2 are under an event of default as of December 31, 2023 and as of the date of this report. Chile PV 1 was not able to maintain the minimum required cash in its debt service reserve account as of December 31, 2023 and did not make its debt service payment in January. In addition, in October 2023, Chile PV 2 did not make its debt service payment. This asset obtained additional financing from the banks and made the debt service payment in December, although it was not able to fund its debt service reserve account subsequently. As a result, although we do not expect an acceleration of the debt to be declared by the credit entities, as of December 31, 2023 Chile PV 1 and 2 did not have an unconditional right to defer the settlement of the debt for at least twelve months and the project debt was classified as current in our Annual Consolidated Financial Statements. We are in conversations with the banks, together with our partner, regarding a potential waiver. Impairments were recorded in these assets in 2023 and 2022. The value of the net assets contributed by Chile PV 1&2 to the Annual Consolidated Financial Statements, excluding non-controlling interest, was close to zero as of December 31, 2023.
La Sierpe
Overview. La Sierpe is a 20 MW solar PV plant in Colombia, wholly owned by us, which reached COD in October 2021.
PPA. La Sierpe has a 15-year, fixed-price PPA in local currency with Coenersa, the largest independent electricity wholesaler in Colombia. The PPA provides for the sale of electricity at a fixed base price indexed to local Consumer Price Index.
O&M. We perform O&M for La Sierpe with our own personnel.
Project Level Financing. The asset has no project finance debt.
La Tolua
Overview. La Tolua is a 20 MW solar PV asset in Colombia, wholly owned by us.
PPA. The asset has a 10-year PPA (commencing on COD) in local currency with Coenersa, the largest independent electricity wholesaler in Colombia. The PPA provides for the sale of electricity at a fixed base price indexed to local Consumer Price Index.
O&M. We perform O&M for La Tolua with our own personnel.
Project Level Financing. The asset has no project finance debt.
Tierra Linda
Overview. Tierra Linda is a 10 MW solar PV asset in Colombia, wholly owned by us.
PPA. The asset has a 10-year PPA (commencing on COD) in local currency with Coenersa, the largest independent electricity wholesaler in Colombia. The PPA provides for the sale of electricity at a fixed base price indexed to local Consumer Price Index.
O&M. We perform O&M for Tierra Linda with our own personnel.
Project Level Financing. The asset has no project finance debt.
Honda 1
Overview. Honda 1 is a 10 MW solar PV asset in Colombia, 50% owned by us, which reached COD in December 2023.
PPA. The asset has a 7-year PPA commencing on COD in local currency with Enel Colombia. The PPA provides for the sale of electricity at a fixed base price indexed to local Consumer Price Index.
O&M. Honda 1 has an O&M agreement in place with a third party.
Project Level Financing. The asset has no project finance debt.
Albisu
Overview. Albisu is a 10 MW solar PV asset near the city of Salto, in Uruguay, wholly owned by us, which reached COD in January 2023.
PPA. The asset has a 15-year PPA, for approximately 60% of the plant’s capacity, starting in July 2023, with Montevideo Refrescos, S.R.L, a subsidiary of Coca-Cola FEMSA, S.A.B. de C.V. The PPA is denominated in local currency with a maximum and minimum price in U.S. dollars and is adjusted monthly based on a formula referring to U.S. Producer Price Index (PPI), Uruguay’s Consumer Price Index (CPI) and the applicable UYU/U.S. dollar exchange rate.
O&M. The O&M services are performed by a third party.
Project Level Financing. The asset has no project finance debt.
Palmatir
Overview. Palmatir is an onshore, 50 MW wind farm facility wholly owned by us, located in Tacuarembó, 170 miles north of the city of Montevideo, Uruguay. Palmatir has 25 wind turbines supplied by Siemens, and each turbine has a capacity of 2 MW. The plant reached COD in May 2014.
PPA. Palmatir signed a PPA with UTE in September 2011 for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted annually based on a formula referring to U.S. PPI, Uruguay’s PPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have wind turbines O&M agreement with Siemens that covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services.
Project Level Financing. On April 11, 2013, Palmatir entered into a financing agreement for a U.S. dollar-denominated 19-year loan in two tranches in connection with this project. This financing agreement was subsequently amended to, among others, add an additional tranche. The first tranche is a $73 million loan with a fixed interest rate of 3.16%. The second tranche is a $33 million loan with a fixed interest rate of 6.35%. The third tranche is a $6.6 million loan with a floating interest rate of six-month U.S. adjusted term SOFR plus 4.13%. The combined outstanding balance of the three tranches as of December 31, 2023 was $66.3 million. The financing arrangements of the plant permits cash distributions to shareholders once per year subject to, among other things, a historical debt service coverage ratio for the previous twelve-month period of at least 1.25x and a projected debt service coverage ratio of at least 1.30x for the following twelve-month period.
Cadonal
Overview. Cadonal is an onshore, 50 MW wind farm facility wholly owned by us, located in Flores, 105 miles north of the city of Montevideo, Uruguay. Cadonal has 25 wind turbines of 2 MW each which were supplied by Siemens. The plant reached COD in December 2014.
PPA. Cadonal signed a PPA with UTE on December 28, 2012, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted annually based on a formula referring to U.S. PPI, Uruguay’s PPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have wind turbines O&M agreement with Siemens that covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services.
Project Level Financing. In June 2020 we refinanced Cadonal’s debt for a total amount of $77.6 million and in March 2022 we prepaid $12.3 million, resulting in a loan principal comprised of:
| − | Tranche A: $29.7 million loan with maturity in 2034 and a floating interest rate of six-month adjusted term SOFR plus 2.9%, 81% hedged with a swap set at approximately 3.29% strike. |
| − | Tranche B: $21.1 million loan with maturity in 2032 and a floating interest rate of six-month adjusted term SOFR plus 2.65%, 99% hedged with a swap set at approximately 3.16% strike. |
The combined outstanding balance of these two tranches as of December 31, 2023 was $44.3 million.
The financing arrangements of the plant permits cash distributions to shareholders twice a year subject to, among other things, a senior debt service coverage ratio for the previous twelve-month period of at least 1.20x.
Melowind
Overview. Melowind is an onshore, 50 MW wind farm facility wholly owned by us, located in Cerro Largo, 200 miles north of the city of Montevideo, Uruguay. Melowind has 20 wind turbines supplied by Nordex, each with a capacity of 2.5 MW. The asset reached COD in November 2015.
PPA. Melowind signed a PPA with UTE in August 2012, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted every year based on a formula referring to U.S. PPI, Uruguay’s PPI and the applicable UYU/U.S. dollar exchange rate.
O&M. We perform O&M with our own personnel, and we have a wind turbines O&M agreement with Nordex that covers scheduled and unscheduled turbine maintenance.
Project Level Financing. On December 13, 2018, Melowind entered into a financing agreement payable over a period of 16 years. The financing consists of a $76 million loan with a floating interest rate based on six-month adjusted term SOFR plus a margin of 2.25% until December 2021, 2.5% from January 2022 to December 2024, 2.75% from January 2025 to December 2027 and 3.0% from January 2028 to December 2034. Adjusted term SOFR exposure was 75% hedged with a swap at a rate of 3.26% with the financing bank. As of December 31, 2023, the outstanding balance of the loan was $66.0 million. The financing arrangement permits cash distributions to shareholders semi-annually subject, among other things, to a historical debt service coverage ratio for the previous twelve-month period of at least 1.15x.
Mini-hydro Peru
Overview. Mini-hydro Peru is a 4 MW mini-hydroelectric power plant located approximately 99 miles from Lima. The plant reached COD in April 2012.
Concession Agreement. It has a 20-year fixed-price concession agreement denominated in U.S. dollars with the Peruvian Ministry of Energy and Mines and the price is adjusted annually in accordance with the U.S. Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor.
O&M. We perform O&M for Mini-hydro Peru with our own personnel.
Project Level Financing. The asset does not have any project level financing.
Solar Assets in Spain
We own a portfolio of solar assets in Spain which are all subject to the same regulation. Renewable assets in Spain sell the power they produce into the wholesale electricity market and receive additional payments from the CNMC, the Spanish state-owned regulator. Solar power plants receive, in addition to the revenue from the sale of electricity in the market, two monthly payments. These payments consist of: (i) a fixed monthly payment based on installed capacity, and (ii) a variable payment based on net electricity produced.
There is a maximum number of production hours per year beyond which no variable payment is received. The regulation also includes a minimum number of yearly hours of generation, under which the plant would receive no regulated payments for that year and another higher threshold below which regulated payments would be reduced for a certain year. Those numbers are 35.0% and 60.0% of the maximum yearly hours, respectively. None of our plants has failed to meet these thresholds since our IPO in 2014. See “—Regulation—Regulation in Spain.”
The portfolio of solar assets in Spain consists of solar platforms generally of two 50 MW solar plants, with the exception of Solnova 1, 3 & 4, (which has three 50 MW solar plants) and PS 10 & 20 (which is a 31 MW solar power complex). Except for PS 10 & PS 20 and Seville PV, all the assets rely on a conventional parabolic trough solar power system to generate electricity, which is similar to the technology used in other solar power plants that we own in the U.S.
O&M. Since March 2023, we perform the O&M services with our own personnel for all solar assets in Spain.
These assets benefit from the tax accelerated depreciation regime established by the Spanish Corporate Income Tax Act.
Solaben 2 & 3
Overview. Solaben 2 and Solaben 3 are two 50 MW solar plants located in Extremadura, Spain. Atlantica owns 70% of each asset and Itochu, a Japanese trading company, owns the remaining 30%. The assets reached COD in June and October 2012, respectively.
O&M. We perform O&M for Solaben 2 & 3 with our own personnel.
Project Level Financing. In March 2023 we refinanced Solaben 2&3. We entered into two green senior euro-denominated loan agreements for the two assets with a syndicate of banks for a total amount of €198.0 million. The new project debt replaced the previous project loans and maturity was extended from December 2030 to June 2037. The interest on the loans accrues at a rate per annum equal to the sum of six-month EURIBOR plus a margin of 1.50% between 2023 and June 2028, 1.60% between June 2028 and June 2033 and 1.70% from June 2033 onwards. The principal is 90% hedged for the life of the loan through a combination of the following instruments:
| − | a pre-existing cap with a 1.0% strike with notional of €115.1 million starting in March 2023 and decreasing over time until December 2025 |
| − | a swap with a 3.16% strike with initial notional of €64.9 million starting in March 2023. The notional increases progressively until June 2026 and decreases progressively thereafter until maturity to ensure that the principal hedged stays at 90% over the life of the loan |
The financing agreement also includes a mechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a reserve account should be established and funded on a six-month rolling basis for the additional revenue arising from the difference between actual prices and prices defined in the agreement. Under certain conditions, such amounts, if any, should be used for early prepayments upon regulatory parameters changes.
The total outstanding balance of these loans as of December 31, 2023 was $202.9 million for both Solaben 2 and Solaben 3. The financing arrangements permit cash distributions to shareholders twice per year if the debt service coverage ratio is at least 1.10x.
In addition, on April 8, 2020, Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 2 & 3 and Solaben 1 & 6 entered into the Green Project Finance with ING Bank, B.V. and Banco Santander S.A. The facility is a green project financing euro-denominated agreement. The Green Project Finance is guaranteed by the shares of Logrosan and its lenders have no recourse to Atlantica corporate level.
In June 2023 we extended the maturity of the debt from April 2025 to December 2028. The facility had an initial notional of €140 million of which approximately 37% is amortized between the signing date and maturity. The outstanding balance of this facility as of December 31, 2023, was $118.2 million, of which €23.2 million is progressively amortized with a two-year grace period and the remaining €87.8 million is expected to be refinanced at maturity.
The interest on the loans accrues at a rate per annum equal to the sum of six-month EURIBOR plus a margin of 3.25%. The principal is 100% hedged for the life of the loan through a combination of the following instruments:
| − | a pre-existing cap with a 0% strike with notional of €115.9 million starting by June 2023 and decreasing over time until December 2025. |
| − | a cap with a 3.5% strike with initial notional of €2.5 million starting in June 2023. The notional increases progressively until June 2025 up to €110.9 million and decreases progressively thereafter until maturity to ensure that the principal hedged stays at 100% over the life of the loan. |
The Green Project Finance permits cash distribution to shareholders twice per year if Logrosan sub-holding company debt service coverage ratio is at least 1.20x and the debt service coverage ratio of the sub-consolidated group of Logrosan and the Solaben 1 & 6 and Solaben 2 & 3 assets is at least 1.075x.
The financing agreement also includes a mechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a reserve account should be established and funded on a six-month rolling basis for the additional revenue arising from the difference between actual prices and prices defined in the agreement. Under certain conditions, such amounts, if any, should be used for early prepayments upon regulatory parameters changes.
Solacor 1 & 2
Overview. Solacor 1 & 2 are two 50 MW solar plants located in Andalusia, Spain. Atlantica owns 87% and JGC Corporation, a Japanese engineering company, holds the remaining 13%. The assets reached COD in February and March 2012, respectively.
O&M. We perform O&M for Solacor 1 & 2 with our own personnel since March 2023.
Project Level Financing. In October 2022, we refinanced Solacor 1 & 2 project debt. The new financing is a green euro-denominated loan with a syndicate of banks for a total amount of €205.0 million with maturity in 2037. Interest accrue at a rate per annum equal to the sum of six-month EURIBOR plus a margin of 1.50% between 2022-2027, 1.60% between 2027-2032 and 1.70% between 2032-2037. We hedged our EURIBOR exposure:
| − | 71% through a swap set at 2.36% for the life of the financing. |
| − | 19% by maintaining the existing 1% strike caps with maturity in 2025. |
The total outstanding balance of this loan as of December 31, 2023 was $209.4 million. This financing arrangement permits cash distribution to shareholders twice per year if the debt service coverage ratio is at least 1.15x.
The financing agreement also includes a mechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a reserve account should be established and funded on a six-month rolling basis for the additional revenue arising from the difference between actual prices and prices defined in the agreement. Under certain conditions, such amounts, if any, should be used for early prepayments every six months.
PS 10 & 20
Overview. PS 10 & 20 is a 31 MW solar complex wholly owned by us located in Andalusia, Spain. PS 10 reached COD in 2007 and PS 20 reached COD in 2009.
O&M. We perform O&M for PS 10 & 20 with our own personnel since March 2023.
Project Level Financing. The asset has no project finance debt. In November 2022, we repaid in full the project finance that was in place for PS 20.
Helios 1 & 2
Overview. Helios 1 and Helios 2 are two 50 MW solar plants wholly owned by us located in Castilla-La Mancha, Spain. The assets reached COD in March and June 2012, respectively.
O&M. We perform O&M for Helios 1 & 2 with our own personnel since March 2023.
Project Level Financing. On July 14, 2020, we refinanced Helios 1 & 2. We entered into a senior secured note facility with a group of institutional investors as purchasers of the notes issued thereunder for a total amount of €325.6 million ($359.4 million approximately). The notes were issued on July 23, 2020 and have a 17-year maturity. Interest accrues at a fixed rate per annum equal to 1.90%. Debt repayment is semi-annual over the 17-year tenor of the debt. The outstanding balance of the debt as of December 31, 2023 was $279.6 million. The note facility permits cash distributions to shareholders twice per year if the debt service coverage ratio is at least 1.15x.
Helioenergy 1 & 2
Overview. Helioenergy 1 and Helioenergy 2 are two 50 MW solar plants wholly owned by us located in Andalusia, Spain. They reached COD in April and August 2011, respectively.
O&M. We perform O&M for Helioenergy 1 & 2 with our own personnel.
Project Level Financing. On June 26, 2018, Helioenergy 1 & 2 entered into:
| − | a 15-year loan agreement of €218.5 million with a syndicate of banks. The interest rate for the loans is a floating rate based on six-month EURIBOR plus a margin of 2.25% until December 2025 and 2.50% until maturity. The banking tranche is 95.5% hedged through a swap set at approximately 3.8% strike and 3% hedged through a cap with a 1% strike. |
| − | a 17-year, fully amortizing loan agreement with an institutional investor for a €45 million with a fixed interest rate of 4.37%. In July 2020, we added a new $43 million notional amount long dated tranche of debt from the same institutional investor with 15-year maturity and with a fixed interest rate of 3.00%. |
The outstanding balance of these loans as of December 31, 2023 was $235.0 million. The financing arrangements permit cash distributions to shareholders semi-annually based on a debt service coverage ratio of at least 1.15x.
Solnova 1, 3 & 4
Overview. Solnova 1, Solnova 3 and Solnova 4 are three 50 MW solar plants wholly owned by us located in Andalusia, Spain, in the same complex as PS-10 and PS-20. Solnova 1, 3 & 4 projects reached COD in February, June, and July 2010, respectively.
O&M. We perform O&M for Solnova 1, 3 & 4 with our own personnel since March 2023.
Project Level Financing. In December 2022 we refinanced Solnova 1, 3 & 4. We entered into a green senior euro-denominated loan agreement for the three assets with a syndicate of banks for a total amount of €338.5 million. The new project debt replaced the previous three project loans and maturity was extended from 2029 and 2030 to June 2035.
The interest rate for the loan accrues at a rate per annum equal to the sum of six-month EURIBOR plus a margin of 1.50% between 2023 and 2027, 1.65% between 2028 and 2032 and 1.80% from 2033 onwards. The principal is 90% hedged for the life of the loan through a combination of the following instruments:
| − | a swap with a 3.23% strike with initial notional of €170.3 million starting in December 2022 and decreasing over time until maturity. |
| − | a cap with a 1.0% strike with initial notional of €134.2 million starting in December 2022 and decreasing over time until December 2025. |
| − | a cap with a 2.0% strike with initial notional of €64.9 million starting June 2026 and decreasing over time until December 2030. |
The financing agreement also includes a mechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a reserve account should be established and funded on a six-month rolling basis for the additional revenue arising from the difference between actual prices and prices defined in the agreement. Under certain conditions, such amounts, if any, should be used for early prepayments upon regulatory parameters changes.
As of December 31, 2023, the outstanding balance of this loan was $338.1 million. The financing arrangement permits cash distributions to shareholders twice per year if the debt service coverage ratio is at least 1.10x from 2023 to 2032 and 1.15x from 2032 onwards.
Solaben 1 & 6
Overview. Solaben 1 and Solaben 6 are two 50 MW solar plants wholly owned by us located in Extremadura, Spain, in the same complex as Solaben 2 & 3. Solaben 1 & 6 reached COD in September and October 2013, respectively.
O&M. We perform O&M for Solaben 1 & 6 with our own personnel.
Project Level Financing. On September 30, 2015, Solaben Luxembourg S.A., a holding company of the two project companies, issued a project bond for €285 million with maturity in December 2034. The bonds have a coupon of 3.76% with interest payable in semi-annual instalments on June 30 and December 31 of each year. The principal is amortized over the life of the financing. The outstanding balance as of December 31, 2023 was $179.7 million. The bonds permit cash distributions to shareholders twice per year if the debt service coverage ratio is at least 1.65x.
Seville PV
Overview. Seville PV is a 1 MW photovoltaic farm located alongside PS 10 & 20 and Solnova 1, 3 & 4, in Andalusia, Spain. Seville PV reached COD in 2006.
O&M. We perform O&M for Seville PV with our own personnel.
Project Level Financing. Seville PV does not have any project level financing.
Italy PV 1, 2, 3 & 4
Overview. We own 7 PV assets in Italy which have a combined capacity of 9.8 MW. Italy PV 1 is a 1.6 MW solar PV plant which reached COD in December 2010. Italy PV 2 is a 2.1 MW solar PV plant which reached COD in April 2011. Italy PV 3 is a portfolio of 4 PV assets with a total capacity of 2.5 MW which reached COD between March and May 2012. Italy PV 4 is a 3.6 MW solar PV plant which reached COD in July 2011.
PPA. The assets have contracted revenues through a regulated feed in premium in addition to merchant revenues for the energy sold to the wholesale market.
O&M. O&M agreements with third parties.
Project Level Financing. The assets have non-recourse project financing in place for a total amount outstanding of $2.7 million as of December 31, 2023.
| − | In June 2011, Italy PV 1 entered into a 15-year loan agreement for €6.0 million with maturity in 2026. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin of 1.30%. As of December 31, 2023, the outstanding balance of this loan was $1.1 million. |
| − | In July 2016, Italy PV 3 entered into a 10-year loan agreement for €1.2 million with maturity in 2026. The interest rate for the loan is a fixed rate of 3.80%. As of December 31, 2023, the outstanding balance of this loan was $0.4 million. |
| − | In March 2022, Italy PV 4 entered into a 10-year loan agreement for €1.3 million with maturity also in 2031. The interest rate for the loan is a fixed rate of 1.00%. As of December 31, 2023, the outstanding balance of this loan was $1.2 million. |
These financing arrangements permit dividend distributions any time throughout the year and regardless of any minimum debt service coverage ratios.
Kaxu
Overview. Kaxu is a 100 MW solar plant located in Pofadder, Northern Cape Province, South Africa. The project company is currently 51% owned by Atlantica South Africa (Pty) Ltd, which we fully own, while the remaining is owned by Industrial Development Corporation of South Africa (29%) and Kaxu Community Trust (20%). Kaxu relies on a conventional parabolic trough solar power system to generate electricity. This technology is similar to the technology used in solar power plants that we own in the U.S. and Spain. In addition, Kaxu has a molten salt thermal energy storage system. The asset reached COD in January 2015.
PPA. Kaxu has a 20-year PPA with Eskom, under a take-or-pay contract for the purchase of electricity up to the contracted capacity of the facility, which expires in February 2035. Eskom purchases all the output of the Kaxu plant under a fixed-price formula in South African Rand subject to indexation to local inflation.
Eskom is a state-owned, limited liability company, wholly owned by the Republic of South Africa. Eskom has recently announced a legal separation of the company into three entities. After this separation, Kaxu’s off-taker will be the National Transmission Company of South Africa. Eskom’s payment guarantees are underwritten by the South African Department of Mineral Resources and Energy, under the terms of an implementation agreement. Eskom’s credit ratings are currently B from S&P, B2 from Moody’s and B from Fitch. The Republic of South Africa’s credit ratings are currently BB- from S&P, Ba2 from Moody’s and BB- from Fitch.
In addition, in 2019, we entered into a political risk insurance policy with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $47 million as of December 31, 2023, in the event of the South African Department of Mineral Resources and Energy not complying with its obligations as guarantor. This insurance policy does not cover credit risk.
O&M. We perform O&M for Kaxu with our own personnel.
Operations. In the third quarter of 2023, a scheduled turbine major overhaul was carried out by Siemens, the original equipment manufacturer and took approximately 30 days longer than expected. After re-starting production, at the end of September, a problem was found in the turbine, likely related to the major overhaul. The plant restarted operations in mid-February 2024. Part of the damage and the business interruption is covered by our insurance property policy, after a 60-day deductible.
Additionally, in June 2023 we executed an EPC heat exchanger performance bond at Kaxu for approximately $11 million, as we believe that the conditions were met. The EPC supplier has informed us that they intend to start an arbitration process. The cash received in connection with such bond has been recorded as a deferred income and is expected to be used for repairs at the asset.
Project Level Financing. Kaxu entered into a long-term financing agreement with a lenders’ group for a total initial amount of approximately $367.4 million. The loan consists of senior and subordinated long-term loans payable in South African rand over an 18-year term with the cash generated by the project. The interest rate exposure was initially 100% hedged through a swap with the same banks providing the financing, and the coverage progressively reduces over the life of the loan. Current hedged interest rate exposure was 58% until 2023, decreasing to 43% from 2024 onwards. Current effective annual interest rate in rands is approximately 11.5% considering the hedge in place. As of December 31, 2023, the outstanding balance of these loans was ZAR 4,294 million, or $233.9 million and the financing was not in default.
The financing arrangement permits dividend distributions on a semi-annual basis after the first repayment of debt has occurred, provided that the historical and projected debt service coverage ratios are 1.20x or above.
Efficient Natural Gas and Heat
Calgary District Heating
Overview. Calgary is a 55MWt district heating facility, consisting of 55MWt natural gas boilers and 3.3 MWe Combined Heat and Power unit, located in the city of Calgary in Alberta, Canada which reached COD in 2010. Calgary District Heating is a wholly owned subsidiary of Atlantica.
Thermal Off-take Agreements. The asset has capacity-based thermal heat revenue with inflation indexation, investment grade off-takers and 12-year average contract life remaining. Contracted capacity and pass-through volume payments represent approximately 65% of the total revenue.
O&M. We perform O&M for Calgary District Heating with our own personnel.
Project Level Financing. The asset does not have any project level financing.
ACT
Overview. ACT is a gas-fired cogeneration facility 99.99% owned by us through ACT Energy Mexico, S. de R.L. de C.V., (“ACT Energy Mexico”). The asset is located inside the Nuevo Pemex Gas Processing Facility near the city of Villahermosa in the State of Tabasco, Mexico. It has a rated capacity of approximately 300 MW and between 550 and 800 metric tons per hour of steam. ACT reached COD in 2013.
Conversion Services Agreement. On September 18, 2009, ACT entered into the Pemex Conversion Services Agreement, with Pemex (“Pemex CSA”), under which ACT is required to sell all of the plant’s thermal and electrical output to Pemex. The Pemex CSA has an initial term of 20 years from the in-service date and will expire on March 31, 2033. The Pemex CSA requires Pemex to supply the facility, free of charge, with the fuel and water necessary to operate ACT, and the latter has to produce electrical energy and steam requested by Pemex based on the expected levels of efficiency. The Pemex CSA is denominated in U.S. dollars. The price is fixed and is adjusted annually, according to a mechanism agreed in the contract that establishes that the average adjustments over the life of the contract should reflect the expected inflation. Pemex has the possibility to terminate the Pemex CSA under certain circumstances paying an indemnity.
We have experienced delays in collections from Pemex, especially since the second half of 2019, which have been significant in certain quarters, including in the fourth quarter of 2023.
O&M. GE provides services for the maintenance, service and repair of the gas turbines and NAES is responsible for the O&M. The O&M agreement with NAES expires upon the expiration of the Pemex CSA, although we may cancel it with no penalty at any time.
Project Level Financing. In December 2013 ACT Energy Mexico entered into a $660.0 million senior loan agreement with a syndicate of banks. In March 2014, after the loan’s first repayment, additional banks entered the syndicate, leading to a $655.4 million senior loan with two tranches. In 2023, Tranche 1 was fully repaid and the outstanding balance consisted of an original $450.0 million loan with an 18-year maturity. The interest rate is a floating rate based on SOFR plus a 3-month standard adjustment plus a margin of 3.75%. The loan is 75% hedged at a weighted average rate of 4.01%.
The outstanding balance of as of December 31, 2023 was $401.5 million. The senior loan agreement permits cash distributions to shareholders provided that the debt service coverage ratio is at least 1.20x.
Monterrey
Overview. Monterrey is a 142 MW gas-fired engine facility including 130 MW installed capacity and 12 MW battery capacity. We own 30% of Monterrey through Pemcorp S.A.P.I. de C.V., while Arroyo Energy owns the remaining 70%. The asset is located in Mexico and reached COD in the third quarter of 2018. The power plant is configured with seven Wärtsilä natural gas internal combustion engines.
In 2023, our partner in Monterrey initiated a process to sell its 70% stake in the asset. Such process is well advanced and, as part of it, we intend to sell our interest as well under the same terms. The net proceeds to Atlantica are expected to be in the range of $45 to $52 million, after tax. The transaction is subject to certain conditions precedent and final transaction closing. We cannot guarantee that the transaction will finally close.
PPA. It is a U.S. dollar-denominated PPA with two international large corporations engaged in the car manufacturing industry. The PPA had originally a 20-year term starting at COD. In May 2022, together with our partner, we entered into a 7.5-year PPA extension with the same off-takers, such that the PPA now ends in 2046. The extension involves an investment, which has been largely made as of December 31, 2023, to achieve certain improvements in the asset to provide, among other things, additional battery capacity and additional redundancy of electric power supply. The PPA includes price escalation factors. The asset also has a 20-year contract for the natural gas transportation. It has limited commodity risk since a majority of the gas cost is a pass-through to our clients.
O&M. Wärtsilä performs the O&M for Monterrey under a contract renewed in 2020 for five years. In addition, the asset has in place a Generator Maintenance Agreement with Wärtsilä for the seven generators for a period of 15 years from COD.
Project Level Financing. Monterrey has a loan of $155.7 million outstanding balance as of December 31, 2023, which matures in September 2027. The interest rate of the loan is a floating rate based on the Adjusted Daily Simple SOFR plus a margin of 2.75% with a 0.25% increase after the third anniversary (September 2023) and another 0.25% increase after the sixth anniversary (September 2026). The variable interest rate exposure was 85% hedged with a swap rate of 2.11% with the financing bank. The loan agreement permits cash distributions after the asset reached COD provided that the debt service coverage ratio is at least 1.20x.
Transmission Lines
ATN
Overview. ATN is a 365 miles transmission line located in Peru wholly owned by us, which is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATN reached COD in 2011. On December 28, 2018, ATN S.A. completed the acquisition of a power substation and two small transmission lines to connect our line to the Shahuindo (ATN expansion 1) mine located nearby. In October 2019, we also closed the acquisition of ATN Expansion 2.
Concession Agreement. Pursuant to the initial concession agreement, the Peruvian Ministry of Energy and Mines, on behalf of the Peruvian Government, granted ATN a concession to construct, develop, own, operate and maintain the transmission line and substations. ATN owns all assets that it has acquired to construct and operate ATN for the duration of the concession. The ownership of these assets will revert to the Peruvian Ministry of Energy and Mines upon termination of the initial concession agreement.
ATN has a 30-year fixed-price tariff base denominated in U.S. dollars that is adjusted annually in accordance with the U.S. Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations. In addition, ATN Expansion 1 has a 15-year Transmission Service Agreement (“TSA”) and ATN Expansion 2 has two 20-year TSAs and one 30-year TSA denominated in U.S. dollars.
O&M. We perform O&M for ATN with our own personnel since July 2023.
Project Level Financing. ATN has a project bond in place which was issued in September 2013 and which currently has three tranches outstanding:
| − | 1st tranche had a principal amount of $50 million with a 15-year term with quarterly amortization and bears interest at a rate of 6.15% per year. |
| − | 2nd tranche had a principal amount of $45 million with a 26-year term and bears interest at a rate of 7.53% per year. The second tranche has a 15-year grace period for principal repayments. |
| − | 3rd tranche had a principal amount of $10 million with a 15-year term and bears interest at a rate of 6.88% per year. |
As of December 31, 2023, the outstanding balance of this loan was $81.6 million. The project bond agreement permits cash distributions subject to a debt service coverage ratio for the last six months of at least 1.10x.
ATS
Overview. ATS is a 569-mile transmission line located in Peru wholly owned by us. ATS is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATS reached COD in 2014.
Concession Agreement. The initial concession agreement became effective on July 22, 2010 and will expire 30 years after achieving COD. Pursuant to the initial concession agreement, ATS will own all assets it has acquired to construct and operate the ATS Project for the duration of the concession. These assets will revert to the Peruvian Ministry of Energy and Mines upon termination of the initial concession agreement.
The concession agreement has a fixed-price tariff base denominated in U.S. dollars and is adjusted annually in accordance with the U.S. Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to the ATS Project.
O&M. ATS has an O&M agreement with Omega Peru that we can terminate every three years (or every two years under certain circumstances).
Project Level Financing. On April 8, 2014, ATS issued a project bond denominated in U.S. dollars with a 29-year term with semi-annual amortization and which bears a fixed interest rate of 6.875%. As of December 31, 2023, $384.6 million was outstanding. The project bond agreement permits cash distributions every six months subject to a debt service coverage ratio for both the 12 month period previous to and following the distribution of at least 1.20x.
ATN 2
Overview. ATN 2 is an 81 miles transmission line located in Peru wholly owned by us, which is part of the Complementary Transmission System. ATN 2 reached COD in June 2015.
ATN 2 has an 18-year, fixed-price tariff base contract denominated in U.S. dollars with Minera Las Bambas. The tariff is partially adjusted annually in accordance with the U.S. Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to ATN 2.
Minera Las Bambas is owned by a partnership consisting of a China Minmetals Corporation subsidiary (62.5%), a wholly owned subsidiary of Guoxin International Investment Co. Ltd (22.5%) and CITIC Metal Co. Ltd (15.0%).
O&M. ATN 2 has an O&M agreement with Omega Peru that we can terminate every three years (or every two years under certain circumstances).
Project Level Financing. In 2011 and 2014, a 15-year loan agreement was executed for a commitment of $50.0 million and $31.0 million, respectively. All debt has a fixed interest rate amounting to 4.85% on a weighted average basis and matures in 2031. As of December 31, 2023, the outstanding balance of the ATN 2 project loan was $40.7 million. The loan agreement permits cash distributions subject to a debt service coverage ratio of at least 1.15x.
Quadra 1 & Quadra 2
Overview. Quadra 1 is a 49-mile transmission line in Chile. Quadra 1 connects to the Sierra Gorda substation owned by Sierra Gorda SCM, a mining company and is located in the commune of Sierra Gorda. Quadra 2 is a 32-mile transmission asset that provides electricity to the seawater pump stations owned by the Sierra Gorda SCM in Chile. Quadra 1 and Quadra 2 reached COD in December 2013 and January 2014, respectively.
Concession Agreement. Both projects have concession agreements with the Sierra Gorda SCM mining company, which is owned by KGHM Polska Mietz and South32 Limited. The concession agreement is denominated in U.S. dollars and has a 21-year term that began on the COD. The contract price is indexed mainly to the U.S. CPI.
The concession agreement grants in favor of Sierra Gorda a call option over the transmission lines, exercisable at any time during the life of the contract. According to the call option, Sierra Gorda is entitled to purchase the transmission line at an agreed price and with a six-month prior written notice.
O&M. Enor performs operations services at Quadra 1 under a contract expiring in 2027 and at Quadra 2 under a contract expiring in 2029 with an option to renew each O&M agreement for five additional years. Maintenance services at Quadra 1 and Quadra 2 are performed by a group of tier-1 suppliers.
Project Level Financing. In June 2019, we refinanced the project debt of our Chilean assets Palmucho, Chile TL 3, Quadra 1 and Quadra 2. This financing agreement consists of a single loan agreement for all these assets for an original amount of $75 million with a syndicate of local banks. The loan is denominated in U.S. dollars and matures on September 30, 2031. It has a semi-annual amortization schedule and accrues interest at a variable rate based on the six-month SOFR plus 3.60%. We contracted an interest rate swap at an approximate fixed rate of 2.25% to hedge 75% of the amount nominal during the entire debt term. As of December 31, 2023, the outstanding balance was $52.9 million. The financing agreement is cross collateralized jointly between the Chilean assets and permits cash distributions twice per year if the combined debt service coverage ratio for the three assets is at least 1.20x.
Palmucho
Overview. Palmucho is a transmission line in Chile of approximately 6 miles. Palmucho has a 14-year concession contract with Enel Generacion Chile, whereby both parties are obliged to enter into a four-year valid toll contract at the end of the term of the concession contract and the valid toll contract will be renewed for three periods of four years each until one of the parties decides not to renew. O&M services are provided by Energysur.
Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.
Chile TL 3
Overview. Chile TL 3 is a 50-mile transmission line in operation in Chile which reached COD in 1993. It generates revenue under the current regulation in Chile. The asset has a fixed-price tariff determined by the regulator and is partially adjusted annually in accordance with the U.S. and Chilean Consumer Price Indexes and currency exchange rates.
O&M. We perform O&M for Chile TL 3 with our own personnel. Energysur performs maintenance services under a three-year contract expiring on January 1, 2025.
Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.
Chile TL 4
Overview. Chile TL 4 is a 63-mile transmission line in operation in Chile which reached COD in 2016. The asset has fully contracted revenues in U.S. dollars, with inflation escalation and 50-year contract life. The off-takers are several mini-hydro plants that receive contracted or regulated payments from third parties.
O&M. The asset has O&M agreements with third parties.
Project Level Financing. Chile TL 4 does not have any project level financing.
Water
Honaine
Overview. Honaine is a water desalination plant of 7 M ft3 per day capacity located in Taffsout, Algeria. We indirectly own 25.5% through Myah Bahr Honaine Spa (“MBH”), Algerian Energy Company, or AEC, owns 49% and Sacyr owns the remaining 25.5% of Honaine.
Honaine reached COD in July 2012. AEC is the Algerian agency in charge of delivering Algeria’s large-scale desalination program. The technology used in the Honaine plant consists of desalination using membranes by reverse osmosis.
Concession Agreement. The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/Algerienne des Eaux, or ADE, from COD. The tariff structure is based upon plant capacity. Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
O&M. Honaine has a 25-year contract from COD with a specialized O&M supplier.
Project Level Financing. In May 2007, MBH signed a financing agreement for $233 million which accrues interest at a fixed-rate of 3.75%. The repayment of the Honaine facility agreement consists of quarterly payments, ending in April 2027. As of December 31, 2023, the outstanding balance of the Honaine project loan was $35.6 million. The financing arrangement permits cash distributions to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.
Skikda
Overview. The Skikda project is a 3.5 M ft3 per day capacity water desalination plant located in Skikda, Algeria. Skikda is located 510 km east of Algiers. We indirectly own 34.2% of Skikda through Aguas de Skikda, (“ADS”), AEC owns 49% and Sacyr owns the remaining 16.8%. We own a 67% of the holding company which in turns has a 51% equity stake in Skikda, as a result we fully consolidate the asset.
Skikda reached COD in 2009 and uses the same technology as Honaine.
Concession Agreement. The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/ADE from COD. The tariff structure is based upon plant capacity. Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
O&M. Skikda has a 25-year contract from COD with a specialized O&M supplier.
Project Level Financing. In July 2005, ADS signed a financing agreement for $108.9 million which accrues interest at a fixed-rate of 3.75%. The repayment of the Skikda facility agreement consists of sixty quarterly payments, ending in May 2024. As of December 31, 2023, the outstanding balance of the Skikda project loan was $2.6 million. The financing arrangement permits cash distributions to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.
Tenes
Overview. Tenes is a 7 M ft3 per day capacity water desalination plant located 208 km west of Algiers, in Algeria. Tenes uses the same technology as Honaine and Skikda and has been in operation since 2015.
Since January 2019, we have an investment in Befesa Agua Tenes, the owner of 51.0% stake in Tenes, through a secured loan to be reimbursed by Befesa Agua Tenes, together with 12% per annum interest, through a full cash-sweep of all the dividends to be received from the asset. On May 31, 2020, we entered into a new agreement which provides us with certain additional decision rights, including the right to appoint a majority of directors at the board of directors of Befesa Agua Tenes. Therefore, through the loan and these decision rights, we control Tenes since May 31, 2020 and as a result we have fully consolidated the asset from that date.
Tenes has a corporate income tax exemption until 2025. After that period, in case the exemption is not extended, a claim may be made under the water purchase agreement for compensation in the tariff.
Concession Agreement. The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/ADE from COD. The tariff structure is based upon plant capacity. Tariffs are adjusted monthly based on the exchange rate between the U.S. dollar and local currency and yearly based on indexation mechanisms that include local inflation and U.S. inflation.
O&M. Tenes has a 25-year contract from COD with a company owned by Abengoa.
Project Level Financing. Tenes signed a financing agreement for $211 million. The loan accrues a fixed interest rate of 3.75%. The repayment of the facility agreement consists of sixty quarterly payments, ending in August 2031. As of December 31, 2023, the outstanding balance of the Tenes project loan was $73.7 million. The financing arrangements permit cash distribution to shareholders subject to a debt service coverage ratio of at least 1.10x.
Geographies and business sectors
We refer to “Item 5. Operating and Financial Review and Prospects” and to Note 4 to our Consolidated Financial Statements for a breakdown of our revenue by geography and by business sector.
Assets under construction
We currently have the following assets under construction or ready to start construction in the short-term:
Asset | Type | Location | Capacity (gross)(1) | Expected COD | Expected Investment(3) ($ million) | Off-taker |
| Coso Batteries 1 | Battery Storage | California, US | 100 MWh | 2025 | 40-50 | Investment grade utility |
| Coso Batteries 2 | Battery Storage | California, US | 80 MWh | 2025 | 35-45 | Investment grade utility |
Chile PMGD(2) | Solar PV | Chile | 80 MW | 2024-2025 | 30 | Regulated |
| ATN Expansion 3 | Transmission Line | Peru | 2.4 miles 220kV | 2024 | 12 | Conelsur |
| ATS Expansion 1 | Transmission Line | Peru | n.a. (substation) | 2025 | 30 | Republic of Peru |
Honda 2(4) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | Enel Colombia |
Apulo 1(4) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | - |
Notes:
| (1) | Includes nominal capacity on a 100% basis, not considering Atlantica’s ownership. |
| (2) | Atlantica owns 49% of the shares, with joint control, in Chile PMGD. Atlantica’s economic rights are expected to be approximately 70%. |
| (3) | Corresponds to the expected investment by Atlantica. |
| (4) | Atlantica owns 50% of the shares in Honda 2 and Apulo 1. |
| • | In October 2023, we entered into two 15-year tolling agreements (PPAs) with an investment grade utility for Coso Batteries 1 and Coso Batteries 2. Under each of the tolling agreements, Coso Batteries 1 and 2 will receive fixed monthly payments adjusted by the financial settlement of CAISO’s Day-Ahead market. In addition, we expect to obtain revenue from ancillary services in each of the asset. |
Coso Batteries 1 is a standalone battery storage project of 100 MWh (4 hours) capacity located inside Coso, our geothermal asset in California. Additionally, Coso Batteries 2 is a standalone battery storage project with 80 MWh (4 hours) capacity also located inside Coso. Our investment is expected to be in the range of $40 million to $50 million for Coso Batteries 1, and in the range of $35 to $45 million for Coso Batteries 2. Both projects were fully developed in-house and are now under construction. We have closed a contract with Tesla for the procurement of the batteries. COD is expected in 2025 for both projects.
| • | In November 2022, we closed the acquisition of a 49% interest, with joint control, in an 80 MW portfolio of solar PV projects in Chile which is currently under construction (Chile PMGD). Our economic rights are expected to be approximately 70%. Total investment in equity and preferred equity is expected to be approximately $30 million and COD is expected to be progressive in 2024 and 2025. Revenue for these assets is regulated under the Small Distributed Generation Means Regulation Regime (“PMGD”) for projects with a capacity equal or lower than 9 MW which allows to sell electricity at a stabilized price. |
| • | In July 2022 we closed a 17-year transmission service agreement denominated in U.S. dollars that will allow us to build a substation and a 2.4-mile transmission line connected to our ATN transmission line serving a new mine in Peru (ATN Expansion 3). The substation is expected to enter in operation in 2024 and the investment is expected to be approximately $12 million. |
| • | In July 2023, as part of the New Transmission Plan Update in Peru, the Ministry of Energy and Mines published the Ministerial Resolution that enables to start construction of our ATS Expansion 1 project, consisting in the reinforcement of two existing substation with new equipment. The expansion will be part of our existing concession contract, a 30-year contract with a fixed-price tariff base denominated in U.S. dollars adjusted annually in accordance with the U.S. Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor. Given that the concession ends in 2044, we will be compensated with a one-time payment for the remaining 9 years of concession. The expansion is expected to enter in operation in 2025 and the investment is expected to be approximately $30 million. |
| • | In May 2022, we agreed to develop and construct Honda 1 and 2, two PV assets in Colombia with a combined capacity of 20 MW where we have a 50% ownership. Each plant has a 7-year PPA with Enel Colombia. Our investment is expected to be $5.5 million for each plant. Honda 1 entered in operation in December 2023 and Honda 2 is expected to enter into operation in the second quarter of 2024. |
Development Pipeline
We are developing new projects in most of our core geographies. In some cases, we do this with our local in-house teams and in other cases we have been working with local partners with whom we jointly invest in developing projects or with whom we have agreements based on milestones.
By focusing our development activities on locations where we already have assets in operation and by working in many cases with partners, we have been able to maintain our development cost at what we believe are low levels.
We currently have a pipeline of assets under development, including both repowering or expansion opportunities of existing assets and greenfield development, of approximately 2.2 GW7 of renewable energy and 6.0 GWh8 of storage. Approximately 47% of the projects are PV, 41% storage, 11% wind and 1% others, while 22% of the projects are expected to reach ready to build (“Rtb”) in 2024 or 2025, 28% are in an advanced development stage and 50% are in early stage. Also, 20% corresponds to expansion or repower opportunities of existing assets and 80% to greenfield developments.
| | Renewable Energy (GW)8 | Storage (GWh)8 |
| North America | 1.2 | 4.3 |
| Europe | 0.4 | 1.6 |
| South America | 0.6 | 0.1 |
| Total | 2.2 | 6.0 |
Customers
We derive our revenue from selling electricity, electric transmission capacity, water desalination capacity and heat. Our customers are mainly comprised of electrical utilities and corporations, with which we typically have entered into PPAs. We also employ concession contracts, typically ranging from 20 to 30 years. We also have regulated assets in Spain, Chile (Chile TL 3) and Italy. Chile PV 1, Chile PV 3 and Lone Star II, which represent less than 1% of our Adjusted EBITDA for the year 2023, sell electricity at market prices. Additionally, we have other assets that sell a percentage of their production at market prices. See the description of each asset under “—Our Operations” for more detail on each concession contract.
8 Only includes projects estimated to be ready to build before or in 2030 of approximately 3.7 GW, 2.2 GW of renewable energy and 1.5 GW of storage (equivalent to 6.0 GWh). Capacity measured by multiplying the size of each project by Atlantica’s ownership. Potential expansions of transmission lines not included.
Our main contracts in our business also include the project finance contracts with banks or financial institutions and the operation and maintenance contracts of each of our assets. See description of financing and operation and maintenance contracts under “—Our Operations.”
Competition
Renewable energy, storage, efficient natural gas and heat and transmission lines are all capital-intensive with numerous industry participants. We compete based on the location of our assets in various countries and regions; however, because most of our assets typically have long-term contracts, competition with other asset operations is limited with respect to existing assets until the expiration of the PPAs. Power generation and transmission are highly regulated businesses in each country in which we operate and are currently highly fragmented and have a diverse industry structure. Our competitors have a wide variety of capabilities and resources. Our competitors include, among others, regulated utilities and transmission companies, other independent power producers and power marketers or trading companies and state-owned monopolies.
We also compete to develop or acquire new projects with developers, independent power producers and financial investors, including pension funds and infrastructure funds and other dividend growth-oriented companies, as well as utilities and oil and gas companies which are targeting to have a presence in renewables. Competitive conditions may vary over time depending on capital market conditions and regulation, which may affect the costs of constructing and operating projects.
Seasonality
Our operating results and cash flows can be significantly affected by weather in some of our most relevant projects, such as the solar power plants. We expect to derive a majority of our annual revenue in the months of May through September, when solar generation is the highest in the majority of our markets and when some of our off-take arrangements provide for higher payments to us. See “Item 3.D — Risk Factors—Risks Related to Our Business and Our Assets—The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, or if the geothermal resource is lower than expected our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.”
Environmental and Social Information
Environment
Environmental management is a key priority in our business and operations. Our facilities and operations are subject to significant government regulation, including stringent and comprehensive federal, provincial and local laws, statutes, regulations, guidelines, policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; storage, handling, use, disposal, transportation and distribution of dangerous materials and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the presence and remediation of hazardous materials in soil and groundwater, both on and offsite; the protection of natural resources; land use and zoning matters; and workers’ health and safety matters. We consider environmental protection as an area of performance and as such, environmental issues are included among the responsibilities of our key executives.
Employees
As of December 31, 2023, we had 1,366 employees. Following the internalization of the operations and maintenance services in our solar assets in the United States in 2019, in South Africa in 2022 and in our solar assets in Spain also in 2022 and 2023, part of the recently hired employees of the relevant O&M companies belong to previously existing labor unions. We believe that the relationship between the Company and its labor union is good. We have not experienced any strikes or work stoppages among our workforce. One of our plants has experienced strikes by employees working for one of our operation and maintenance suppliers in the past.
Health & Safety
Among our values, the first one is “Integrity, Compliance and Safety”. We are committed to prioritizing and actively promoting health and safety as a tool to protect the integrity and health of our employees, subcontractors and partners involved in our business activity. We promote a safe operating culture across Atlantica and encourage a preventive culture in the O&M activities of our subcontractors as reflected in our corporate health and safety policy.
Annually, we conduct internal and external audits to evaluate our health and safety management system in accordance with the ISO 45001 standard requirements. Our ISO 45001 certification is valid until 2024. The external audit is carried out by an independent third party. Additionally, we perform periodic health and safety audits of our asset contractors to monitor their compliance with legal regulations, contractual requirements and our safety best practices. We also develop an annual training program to train managers and employees on safety awareness. This annual plan is designed in accordance with local regulations and risk assessment at every work position and work center.
On an annual basis, we establish key safety metrics targets in all our assets which include both Atlantica and subcontractor employees, which were achieved in 2023:
| − | Our Total Recordable Incident Rate (TRIR) has been calculated following Sustainable Accounting Standards IF-EU-320a.1. It represents the total number of recordable accidents with and without leave (lost time injury) recorded in the last 12 months on 200 thousand hours worked. We ended 2023 at 0.9, compared to 1.0 in 2022. |
| − | Our Lost Time Injury Rate (LTIR) represents the total number of recordable accidents with leave (lost time injury) recorded in the last 12 months on 200 thousand of hours worked. We ended 2023 at 0.4, compared to 0.6 in 2022. |
TRIR and LTIR decreased in 2023 compared to the previous year mainly due to a decrease in the number of accidents with leave at our assets under construction, which were a top priority during the year. In 2024, we will maintain our focus on developing best practices in our assets under construction, working closely with our construction suppliers, while we maintain or improve our ratios in assets in operation.
Operation and Maintenance
We currently perform internally the O&M for a majority of our assets. In March 2023, we completed the process of transitioning O&M services for the assets in Spain where Abengoa was still the supplier to an Atlantica subsidiary. Additionally, since July 2023 we perform O&M for ATN with our own personnel. After these transfers, we perform the O&M services with our own personnel for assets representing approximately 74% of the consolidated revenue in 2023.
In terms of operational efficiency, we focus on ensuring long-term availability, reliability and asset integrity with maintenance and monitoring. The suppliers of our solar panels, turbines, transmission towers and equipment are selected through a detailed evaluation process, focusing on their commercial track record and regular availability of components and replacement parts for the proper functioning and maintenance of our assets and facilities. Our corporate operations team identifies best practices and controls which are implemented in all our assets. Additionally, we require all our suppliers to comply with our Suppliers’ Code of Conduct.
Intellectual Property
We refer to “Item 5-Operating and Financial Review and Prospects-C. Research and Development” for a summary of the extent to which the Company is dependent on patents and licenses.
Legal Proceedings
In 2018, an insurance company covering certain Abengoa obligations in Mexico claimed certain amounts related to a potential loss. Atlantica reached an agreement under which Atlantica’s maximum theoretical exposure would in any case be limited to approximately $35 million, including $2.5 million to be held in an escrow account. In January 2019, the insurance company called on this $2.5 million from the escrow account and Abengoa reimbursed us for this amount. The insurance company could claim additional amounts if they faced new losses after following a process agreed between the parties and, in any case, Atlantica would only make payments if and when the actual loss has been confirmed and after arbitration if the Company initiates it. In the past we had indemnities from Abengoa for certain potential losses, but such indemnities are no longer valid following the insolvency filing by Abengoa S.A. in February 2021.
In addition, during 2021 and 2022, several lawsuits were filed related to the February 2021 winter storm in Texas against among others Electric Reliability Council of Texas (“ERCOT”), two utilities in Texas and more than 230 individual power generators, including Post Oak Wind, LLC, the project company owner of Lone Star II, one of the wind assets in Vento II where we currently have a 49% equity interest. The basis for the lawsuit is that the defendants failed to properly prepare for cold weather, including failure to implement measures and equipment to protect against cold weather, and failed to properly conduct their operations before and during the storm.
Except as described above, Atlantica is not a party to any other significant legal proceedings other than legal proceedings (including administrative and regulatory proceedings) arising in the ordinary course of its business. Atlantica is party to various administrative and regulatory proceedings that have arisen in the ordinary course of business.
While Atlantica does not expect the above noted proceedings, either individually or in combination, to have a material adverse effect on its financial position or results of operations, because of the nature of these proceedings Atlantica is not able to predict their ultimate outcomes, some of which may be unfavorable to Atlantica.
Regulation
Overview
We operate in a significant number of highly regulated markets. The degree of regulation to which our activities are subject varies by country. In a number of the countries in which we operate, regulation is carried out mainly by national regulatory authorities. In others, such as the United States and, to a certain degree, Spain, there are various additional layers of regulation at the state, regional and/or local level. In countries with these additional layers of regulatory agencies, the scope, nature and extent of regulation may differ among the various states, regions and/or localities.
While we believe the requisite authorizations, permits and approvals for our assets have been obtained and that our activities are operating in substantial compliance with applicable laws and regulations, we remain subject to a varied and complex body of laws and regulations that both public officials and private parties may seek to enforce. The following is a description of the primary industry-related regulations applicable to our assets that are currently in force in the principal markets in which we operate.
Regulation in the United States
In the United States, our electricity generation project companies are subject to extensive federal, state and local laws and regulations that govern the development, ownership, business organization and operation of power generation facilities. The federal government regulates wholesale sales, operation and interstate transmission of electric power through FERC and through other federal agencies, and certain environmental, health and safety matters. State and local governments regulate the siting, permitting, construction and operation of power generation facilities, the retail sale of electricity and certain other environmental, health, safety and permitting matters.
United States Federal Regulation of the Power Generation Facilities and Electric Transmission
The United States federal government regulates the wholesale sale of electric power and the transmission of electricity in interstate commerce through FERC, which draws its jurisdiction from the FPA, as amended, and from other federal legislation.
Federal Regulation of Electricity Generators
The FPA provides FERC with exclusive ratemaking jurisdiction over all public utilities that engage in wholesale sales of electricity and/or the transmission of electricity in interstate commerce. The owners of renewable energy facilities selling at wholesale are therefore generally subject to FERC’s ratemaking jurisdiction. FERC may authorize a public utility to make wholesale sales of electric energy and related products at negotiated or market-based rates if the public utility can demonstrate that it does not have, or that it has adequately mitigated, horizontal and vertical market power and that it cannot otherwise erect barriers to market entry. Entities granted market-based rate approval face ongoing filing and compliance requirements. Failure to comply with such requirements may result in a revocation of market-based rate authority, disgorgement of profits, civil penalties or other remedies that FERC finds appropriate based on the specific underlying facts and circumstances.
FERC also implements the requirements of the Public Utility Holding Company Act of 1935 (“PUHCA”) applicable to “holding companies” having direct or indirect voting interests of 10% or more in companies that (among other activities) own or operate facilities used for the generation of electricity for sale, which includes renewable energy facilities. PUHCA imposes certain record-keeping, reporting and accounting obligations on such holding companies and certain of their affiliates, subject to certain exceptions.
Federal Reliability Standards
EPACT amended the FPA to grant FERC jurisdiction over all users, owners and operators of the bulk power system for the purpose of enforcing compliance with certain standards for the reliable operation of the bulk power system. Pursuant to its authority under the FPA, FERC certified the North American Electric Reliability Corporation (“NERC”) as the entity responsible for developing reliability standards, submitting them to FERC for approval, and overseeing and enforcing compliance with them, subject in each case to FERC review. NERC, in turn, has delegated certain monitoring and enforcement powers to regional reliability organizations. Users, owners, and operators of the bulk power system meeting certain materiality thresholds are required to register with the NERC compliance registry and comply with FERC-approved reliability standards.
Federal Environmental Regulation, Permitting and Compliance
Construction and operation of power generation facilities, including solar power plants, and the generation and electric transmission of renewable energy from such facilities are subject to environmental regulation at the federal, state and local level. At the federal level, environmental laws and regulations typically require a lengthy and complex process for obtaining licenses, permits and approvals prior to construction, operation or modification of a generation project or electric transmission facilities. Prior to development, permitting authorities may require that project developers consider and address, among other things, the impact on water resources and water quality, endangered species and other biological resources, compatibility with existing land uses and zoning, agricultural resources, archaeological, paleontological, recreational and cultural considerations, environmental justice and cumulative and visual impacts. In an effort to identify and minimize the potential impacts to these resources, power generation facilities may be required to comply with a myriad of federal regulatory programs and applicable federal permits under various federal laws.
In addition, various federal environmental, health and safety regulations applicable during the construction phase are also applicable to the operational phase of power generation facilities. During the operational phase, obtaining certain federal permits or federal approval of certain operating documents (e.g., O&M plans, the spill prevention, control and countermeasure plan, and an emergency and preparedness response plan), as well as maintaining strict compliance with such permits or operating documents, is mandatory. Failure to maintain compliance may result in the revocation of any applicable permit or authorization, civil and criminal charges and fines or potentially the closure of the plant.
U.S. Federal Considerations for Renewable Energy Generation Facilities
The United States provides various federal, state and local tax incentives to stimulate investment in renewable energy generation capacity, including solar power. These tax incentives are subject to change and, possibly, elimination in the future. Certain U.S. federal income tax incentives are described below.
Section 1603 U.S. Treasury Grant Program
In lieu of claiming certain U.S. federal income tax credits, in particular, the ITC, owners of eligible solar energy property were eligible for a period of time to receive a cash grant from the U.S. Treasury equal to 30% of the tax basis of the eligible property. Solana received its 1603 Cash Grant final award from the U.S. Treasury in October 2014, and Mojave received its 1603 Cash Grant final award from the U.S. Treasury in September 2015.
Federal Loan Guarantee Program
The DOE was authorized to grant guarantees with respect to certain loans to renewable energy projects and related manufacturing facilities and electric power transmission projects under Section 1703 of EPACT. The senior debt for Solana and Mojave is guaranteed by the DOE pursuant to the Section 1705 loan guarantee program.
Inflation Reduction Act
On August 16, 2022, U.S. President Biden signed into law the U.S. Inflation Reduction Act (IRA). The provisions of the IRA are intended to, among other things, incentivize clean energy investment, clean energy production and manufacturing of necessary components. The IRA includes, among other incentives, (i) the expansion and extension of ITCs to 30% (subject to satisfying the eligibility requirements under the IRA) for solar projects to be built until 2032, (ii) the expansion and extension of PTCs for wind projects to be built until 2032, (iii) a 30% ITC (subject to satisfying the eligibility requirements under the IRA) for standalone storage projects to be built until 2032, (iv) a new tax credit that will award up to $3/kg for low carbon hydrogen and a three-year extension and modification of PTCs for facilities that begin construction before December 31, 2024, and (v) the increase in total funds available for the U.S. Department of Energy’s Title 17 loan guarantee program by $3.6 billion, bringing the total to $40 billion. The IRA also includes transferability options for the ITCs and PTCs, which is intended to allow for an easier and faster monetization of these tax credits. Such credits will reduce the cost of renewable investments in the U.S. to developers.
We expect to claim ITCs or any other tax credits or benefits available under IRA for the projects currently under development and construction in the U.S. and for any other qualifying project that we develop and start construction in the U.S.
In determining ITC eligibility, we will rely upon applicable tax law and published IRS guidance. However, the application of law and guidance regarding ITC eligibility to the facts of particular solar energy and standalone storage projects is subject to a number of uncertainties, in particular with respect to the new IRA provisions for which Department of Treasury regulations (“Treasury Regulations”) are being developed and implemented, and there can be no assurance that the IRS will agree with our approach in the event of an audit. The Department of Treasury is expected to issue Treasury Regulations and additional guidance with respect to the application of the newly enacted IRA provisions, and the IRS and Department of Treasury may modify existing guidance, possibly with retroactive effect. Any of the foregoing could reduce the amount of ITCs or, if applicable, PTCs available to us. In this event, we could be required to seek alternative sources of funding for solar energy projects, which could have a material adverse effect on our business, financial condition, results of operations and prospects.
The ITC and PTC amount can be increased if certain domestic content requirements are satisfied or if a project is located in (i) an “energy community” or (ii) low-income community, each as defined in the IRA.
The full impact of the IRA cannot be known with certainty. However it is expected that, many of these provisions will reduce the cost of renewable investments in the U.S. due to the extensions and expansions of tax credits.
Trade Restrictions and Supply Chain
UFLPA
On December 23, 2021, U.S. President Biden signed into law the Uyghur Forced Labor Prevention Act (the “UFLPA”), which creates forced labor-related import restrictions that took effect on June 21, 2022 and seeks to block the import of products made with forced labor in certain areas of China. This may lead to certain suppliers being blocked from importing solar cells and panels to the U.S. While our assets and projects to start construction in the U.S. have not been impacted, further disruptions may impact our suppliers’ ability or willingness to meet their contractual agreements or to continue to supply cells or panels into the U.S. market on terms that we deem satisfactory.
We cannot currently predict what, if any, impact the UFLPA will have on the overall supply of solar panels into the U.S. and the related timing and cost of solar projects, future disruption and their effect on U.S solar project development and construction activities are uncertain. As of the date of this annual report, there continues to be uncertainty in the market around achieving full compliance with UFLPA, whether related to sufficient traceability of materials or other factors.
AD/CVD
In August 2021, a group of anonymous domestic solar manufacturers filed a petition (“AD/CVD”) with the U.S. Department of Commerce (“DOC”) seeking to impose new tariffs on solar panels and cells imported from several countries, including Malaysia, Vietnam, and Thailand. The petitioners claimed that Chinese solar manufacturers were shifting products to these countries to avoid the tariffs required on products imported from China. In November 2021, the DOC rejected this petition. In denying the petition, the DOC cited the anonymous group’s refusal of the DOC’s request to provide more detail and identify its members due to concerns about retribution from the dominant Chinese solar industry.
In February 2022, a California based company filed an AD/CVD petition with the DOC seeking to impose new tariffs on solar panels and cells imported from multiple countries, including Malaysia, Vietnam, Thailand, and Cambodia. While the petition is similar to the one rejected by the DOC in November 2021, there are notable differences. The group added Cambodia to the petition and is requesting that the DOC conduct a country-wide inquiry into each of the four countries. In March 2022, the DOC decided to act on the February petition and investigate the claim. On August 18, 2023, the DOC issued its final affirmative determinations that solar cells and modules completed in Cambodia, Malaysia, Thailand, or Vietnam using certain specified components from China, and exported to the United States, are circumventing the antidumping duty and countervailing duty orders on solar cells, whether or not assembled into modules, from China. However, in June 2022, the U.S. Administration used its executive powers to issue a 24-month tariff moratorium on solar panels manufactured in Cambodia, Malaysia, Thailand, and Vietnam. The moratorium came as a direct response to concerns raised about the adverse impact from the ongoing DOC complaint on the U.S. solar industry. U.S. companies will be exempt from any retroactive tariffs that previously could have applied, but companies may still be subject to tariffs after the moratorium ends. The U.S. Administration also announced that it plans to invoke the Defense Production Act to accelerate the production of solar panels in the U.S. While this moratorium was introduced to stay in force until June 6, 2024, the existence of such petitions and possibility of further petitions and investigations create uncertainty related to the supply of solar modules, which can negatively impact the global solar market and the timing and viability of solar projects in our development pipeline.
If the investigation results in additional taxes, tariffs, duties, or other assessments on renewable energy or the equipment necessary to generate or deliver it, such as antidumping and countervailing duty rates, such developments could result in, among other items, lack of a satisfactory market for the development and/or financing of our U.S. renewable energy projects, abandonment of the development of certain U.S. renewable energy projects, a loss of our investments in projects in the U.S., and/or reduced project returns.
State and Local Regulation of the Electricity Industry in the United States
State regulatory agencies in the United States have jurisdiction over the rates and terms of electricity service to retail customers. Regulated investor-owned utilities often must obtain state approval for the contracts through which they purchase electricity, including renewable energy, if they seek to pass along the costs of these contracts to their retail ratepayers. Different states apply different standards for determining acceptable prices for utility procurement contracts, including PPAs. Our electricity generation project companies operate in Arizona and California. Information about the regulatory frameworks in Arizona and California is provided below.
United States State-Level Incentives
In addition to federal legislation, many states have enacted legislation, principally in the form of RPS, which generally require electric utilities to generate or purchase a certain percentage of their electricity supplied to consumers from renewable resources. In certain states, it is not only mandatory to meet these percentages, which in general are on the increase from renewable resources, but also electric utilities may be required to generate or purchase a percentage of their electricity supplied to consumers from specific renewable energy technologies, including solar technology.
Arizona
The Arizona Corporation Commission has complete and exclusive jurisdiction over the rates and terms under which regulated utilities may provide electricity service to retail customers in Arizona. Under Arizona’s Renewable Energy Standard & Tariff (the “REST”) regulated electric utilities must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies. The renewable energy requirement was 10% of retail electric sales in 2020 and increases annually until it reaches 15% in 2025.
Unlike many other state regulatory commissions, the ACC does not approve PPAs executed by regulated utilities, nor does it issue rulings of “prudency” regarding PPAs. In the case of Solana, however, the power purchaser, Arizona Public Service Company, or APS, voluntarily sought a hearing before the ACC to request its informal opinion of the prudency of the Solana PPA and the ACC affirmed that the PPA should be deemed “a reasonable means” by which APS could meet its requirements under the REST, thereby providing greater assurance of APS’s successful rate recovery request.
Various state and county regulations, mostly related to the environment and public health and safety are applicable during the operational phase of a solar power plant located in Maricopa County, Arizona. Obtaining a permit or requesting the approval of certain operating plans, as well as strict compliance with such permits and plans, is mandatory. Failure to comply may result in the revocation of the permit or authorization, civil and criminal charges and fines, or potentially the closure of Solana.
In addition, in accordance with the NEPA designation of a Finding of No Significant Impact (FONSI) issued by the DOE, Solana must comply with certain water requirements due to the reduction in tail water runoff being contributed to a wash located near the site. Failure to comply with the regulation in place could cause temporary closure of the plant until the non-compliance condition is cured.
Many of the permits obtained for Solana carry specific conditions that must be complied with and which are continuously monitored, measured, and documented by the Solana plant operators, including those related to reliability, emergency response, potential hazards of waste disposal, and human health and safety. These requirements originate with federal laws, and in many cases are enforced via delegated authority from the appropriate federal agency to a state or county agency.
California
The California Public Utilities Commission, (“CPUC”), governs, among other entities, California’s investor-owned utilities, including Pacific Gas & Electric Company. The CPUC reviewed Mojave’s PPA and approved the contract by issuing a formal decision in November 2011.
Mojave must maintain compliance with the California Energy Commission (CEC) decision conditions of certification. These conditions of certification address, among others, biological resources, health and safety, cultural resources, fire safety, and water. The conditions require Mojave to provide plans, notifications, and other reports on an ongoing basis. Such compliance is monitored by CEC staff. Per the CEC decision, “failure to comply with any of the Conditions of Certification or the compliance conditions may result in reopening of the case and revocation of Energy Commission certification; an administrative fine; or other action as appropriate.” Additional regulations are administered by the California Independent System Operator and under the terms of the federally administered Large Generator Interconnection Agreement.
Regulation in Mexico
Overview
Until December 2013, under the Electricity Public Service Law (Ley del Servicio Público de Energía Eléctrica) enacted in 1975 and amended in 1992, the electricity industry in Mexico was entirely controlled by the federal government, acting through the CFE, an entity wholly owned and controlled by the Mexican government, and legally independent from the Mexican Ministry of Energy, or Secretaría de Energía or SENER. CFE was the only entity authorized to provide electricity directly to the public and to supply services to the Mexican wholesale market. CFE was also responsible for the construction and maintenance of infrastructure necessary for the delivery of electricity, such as the national electric grid, the Sistema Eléctrico Nacional, or SEN.
Notwithstanding the foregoing, private entities were allowed to participate in the following activities not considered public utility services, as defined by the aforementioned law:
| • | Cogeneration. The electricity produced is used to supply power to the establishments associated with the cogeneration process and/or the shareholders of the cogeneration company; |
| • | Self-Supply Generation. The electricity produced is used for the self-supply purposes of the holder of the relevant self-supply power generation permit and/or its shareholders; |
| • | Independent Power Production. All the electricity produced is delivered to CFE; |
| • | Small-Scale Production. The electricity produced does not exceed 30 MW and is used for export purposes or the supply of all power output is sold to CFE; |
| • | Exports. The electricity produced is exported in its entirety; and |
| • | Imports for Independent Consumption. The import of power is used for self-supply purposes. |
Since the energy reform of December 2013 and the enactment of the Electric Industry Law (Ley de la Industria Eléctrica), the power generation sector has been more open to private participation and investment, creating a competitive spot market in power generation, although electric transmission and distribution remain public services to be provided exclusively by CFE. The national electric grid is a responsibility the CENACE, which became a decentralized public agency, an Independent System Operator, or ISO.
Since commencement of the energy reform process, secondary legislation and regulation was enacted and changes were implemented through a substantial modification of the legal framework that had governed the development of the energy industry in the country.
On December 3, 2021, the Mexican Energy regulatory Commission (Comisión Reguladora de la Energía), or CRE published Decree number A/037/2021, by which the interpretation criteria of the concept self-needs was amended, with an impact on general aspects of isolated supply and local generation activities.
Additionally, on December 31, 2021, CRE published the new rules for the grid code (Código de Red) on aspects of efficiency, quality, reliability, safety and sustainability of the National Electric System (Sistema Eléctrico Nacional).
Conventional Electricity Generation in Mexico
Electric Industry Law
The Electric Industry Law regulates planning activities, the control of the national electric grid, the public services of transmission and distribution of electricity, and all other activities related to the Mexican energy industry, in order to promote the sustainable development of the industry and to ensure its continuous, efficient, and secure operation for the benefit of all users, as well as the fulfillment of the obligations to provide a general and public service of electricity, to develop clean energies, and to reduce harmful emissions.
Pursuant to the Electric Industry Law, the government holds the operational control of the national electric grid, through the CENACE, and CENACE, as an ISO, indicates the elements for the national transmission grid and the related operations which may correspond to the wholesale market.
Regulations of the Electric Industry Law
The Regulations of the Electric Industry Law provide details for the application of the Electric Industry Law. These regulations expand on certain administrative procedures in the electric industry, such as the development of public bidding procedures by CFE, for private sector contracts for activities related to the national electric grid; the specific requirements for the application for power generation and power supply permits with CRE; the process for infrastructure contributions by the private sector to the State; and the registration of participants in the wholesale spot market with CENACE.
Permits and Authorizations
Pursuant to the Electric Industry Law, all power plants with a capacity greater than or equal to 0.5 MW require a generation permit granted by CRE. The Electric Industry Law also provides for several requirements which generators who represent power plants interconnected to the national electric grid have to comply with, including, among others, the execution of the corresponding interconnection agreements, issued by CRE.
CRE may also issue a supply permit for private parties, which will allow companies to participate in the Mexican Wholesale Electricity Market (Mercado Eléctrico Mayorista), or by carrying out transactions with final users, which are called “qualified users.” In this sense, private parties may supply power directly to consumers through bilateral long-term agreements, which will be partially regulated by the CRE.
Consequently, the Mexican power industry is divided into two main areas: (i) the public service of electricity under CFE’s control, and (ii) the activities where private parties may be involved (such as where CFE actively promoted private investment in the construction and operation of power plants for supplying CFE and private parties under self-supply and cogeneration schemes).
While power generated in Mexico is still predominantly generated by CFE, there is a large amount of electricity generated by private energy producers, which generally fall under the categories of independent power production and self-supply generation, although cogeneration has come to be a relevant source of power as a result of certain amendments enacted in 2006 which allowed Pemex to develop new cogeneration projects independently and in collaboration with CFE. These amendments allowed Pemex to enter into the Pemex conversion services agreement and to receive the power generated by ACT.
As a consequence of the corresponding reforms the issuance of a new class of permit available to those interested in generating electricity is provided for pursuant to the Electric Industry Law. This permit expanded the ways in which entities are allowed to participate as energy producers under the Electric Industry Law and is within the scope of the CRE’s regulatory control.
The permits provided for in the Electric Industry Law are, as aforementioned, granted and issued by CRE, upon prior submission of the corresponding application, payment of the corresponding duties, all relevant legal and technical information, and project description. Such permits will be terminated or revoked pursuant to the different scenarios indicated in the Electric Industry Law and its regulations, and as determined by CRE.
Transmission and Distribution of Electricity in Mexico
Pursuant to the Electric Industry Law, regarding conventional energy generation, dispatchers and distributors are responsible for the national transmission grid and the general distribution grids and will operate their grids pursuant to the instruction provided by CENACE.
CFE is required by law to provide its wheeling (the transfer of electrical power through transmission and distribution lines to another utility), dispatch and backup services to all permit holders whenever the requested service is technically feasible on a first-come, first-served basis. CFE’s wheeling services are provided pursuant to an interconnection agreement and a transmission services agreement entered into between CFE and the relevant permit holder (in ACT’s case, these were executed by Pemex). Those agreements follow model contracts approved by the CRE, which also approves the methodology used to calculate the applicable tariffs. The permit holders must build their own transmission lines for self-use in order to connect to the power grid. In addition, permit holders are required to enter into a back-up services agreement with CFE, which also follow a model agreement approved by the CRE.
The Electric Industry Law incorporates requirements to carry out the sale and purchase of electricity. Aside from being classified as a generator or qualified user, along with the need to comply with the rules issued by CRE for the execution of the corresponding agreements, there are requirements for the interconnection to the transmission grid owned by CFE.
Open Access
Both the Electric Industry Law and in the regulations thereunder establish that CFE is obligated to grant non-discriminatory open access to all users of the national electric grid. Open access is a crucial component of the electric industry since CFE, as owner of the grid, competes directly with other private sector participants in several activities of the industry, which could lead to a monopoly by CFE. In order to avoid such situation, the CENACE, as an independent system operator, will ensure competitive conditions for all users who want to use CFE’s infrastructure.
Pursuant to the regulations, CRE issued the general guidelines regarding open access conditions, the procedure for users to request such open access and the procedure to which the CENACE will be subject to grant this open access, among others.
Wholesale Spot Market, Mercado Eléctrico Mayorista
MEM participants can be (i) generators, (ii) suppliers, (iii) non-supplier traders, or (iv) qualified users, prior to execution of the corresponding agreement with CENACE. Transactions carried out within the MEM must be formalized through “electric coverage agreements” executed by and between such MEM participants. Generators, as MEM participants may, sell their generated energy and both traders and qualified users may purchase such energy through CENACE, which is the independent operator of the electric system.
CENACE is responsible for managing the supply and demand of MEM participants, conducting transactions and continuously generating prices. The price to be paid in MEM transactions has to be a “competition price” in terms of the Electric Industry Law and has to reflect elements such as electricity generation costs and other operating costs, as well as the amount of electricity demanded by and supplied within the MEM. Such competition price serves as a reference for long-term supply agreements between providers and qualified users, partially replacing the CFE-published tariffs.
Even though the Electric Industry Law provides the general guidelines to which the operation of the MEM is subject, on September 8, 2015, the Mexican Ministry of Energy published the Guidelines of the Market (Bases del Mercado Eléctrico), or the Guidelines as the general administrative provisions which establish the principles for the design and operation of the MEM. The regulations list certain topics which are described in depth in the Rules of the Market (Reglas del Mercado), such as the methodology that is used to forecast the level of demand in the spot market, information on market participants, and the methodology to determine the price of the electricity sold and purchased within the spot market.
The Guidelines are part of the Rules of the Market, which are administrative provisions of general application that specifically detail different aspects of the operation of the MEM, and determine the rules that all market participants, such as generators, traders, suppliers, non-supplier traders or qualified users, as well as the competent authorities must comply with.
Energy Regulators
By means of Agreement A/023/2023, published in the Official Federal Gazette on July 20, 2023, the CRE nullified Agreements (i) A/001/2021, which established the suspension of legal terms and deadlines as a measure to prevent and combat the spread of the COVID-19 and (ii) A/004/2023, which restored legal terms and deadlines in an orderly and staggered manner.
Therefore, the above is beneficial for the energy sector since the legal terms and deadlines before the CRE will be complied with in accordance with the applicable laws. However, Agreement A/023/2023 does not guarantee that the CRE will comply with its legal obligations, thus, if the CRE fails to comply, individuals may appeal to legal mechanisms to defend their interests.
Likewise, the Energy Ministry, by means of an agreement published on February 17, 2023 in the Official Federal Gazette, established the renewal of deadlines and legal terms with respect to all formalities, procedures and any activity that falls under the responsibility of the Energy Ministry, as of March 1, 2023.
Current Regulatory Framework
The following laws and regulations are among the main provisions that include constitutional, legal and regulatory provisions applying to the development of cogeneration projects in Mexico, according to the enacted regulatory framework:
| • | Political Constitution of the United Mexican States (Constitución Política de los Estados Unidos Mexicanos). |
| • | Electric Industry Law (Ley de la Industria Eléctrica). |
| • | Regulation of the Electric Industry Law (Reglamento de la Ley de la Industria Eléctrica) |
| • | Energy Regulatory Bodies Law (Ley de los Órganos Reguladores Coordinados en Materia Energética). |
| • | Energy Transition Law (Ley de Transición Energética). |
| • | Federal Electricity Commission Law (Ley de la Comisión Federal de Electricidad). |
| • | Regulations of the Federal Electricity Commission Law (Reglamento de la Ley de la Comisión Federal de Electricidad). |
| • | Terms for the strict legal segregation of the Federal Electricity Commission (Términos para la estricta separación legal de la Comisión Federal de Electricidad). |
| • | Geothermal Energy Law (Ley de Energía Geotérmica). |
| • | Guidelines that regulate the criteria for granting clean energy certificates (Lineamientos que establecen los criterios para el otorgamiento de certificados de energía limpia) which have been recently amended and which relevant implications will be further mentioned below. |
| • | Guidelines of the Market (Bases del Mercado Eléctrico). |
| • | Grid Code 2.0 (Código de Red 2.0). |
| • | General Administrative Provisions that establish the terms for the operation of the Register of Qualified Users (Disposiciones administrativas de carácter general que establecen los términos para la operación y funcionamiento del registro de Usuarios Calificados). |
| • | Resolution by means of which the Energy Regulatory Commission issues the general administrative provisions that establish the general conditions for the provision of the energy supply (Resolución por la que la Comisión Reguladora de Energía expide las Disposiciones administrativas de carácter general que establecen las condiciones generales para la prestación del suministro eléctrico). |
| • | Mechanism to request the modification of the permits granted under the Electricity Public Service Law for generation permits, as well as the criteria under which the permit holders of such regime may execute an interconnection contract while the Wholesale Electricity Market becomes effective (Mecanismo para solicitar la modificación de los permisos otorgados bajo la Ley del Servicio Público de Energía Eléctrica por permisos con carácter único de generación, así como los criterios bajo los cuales los permisionarios de dicho régimen podrán celebrar un contrato de interconexión en tanto entra en operación el mercado eléctrico mayorista). |
| • | General administrative provisions for the operation of the certificate procurement system and the compliance with the clean energy obligations (Disposiciones administrativas de carácter general para el funcionamiento del sistema de gestión de certificados y cumplimiento de obligaciones de energías limpias). |
| • | General administrative provisions that establish the minimum requirement to be met by suppliers and qualified users participating in the Electricity Market to acquire energy demand in terms of article 12, section XXI, of the Electric Industry Law (Disposiciones administrativas de carácter general que establecen el Requisito mínimo que deberán cumplir los suministradores y los usuarios calificados participantes del mercado para adquirir potencia en términos del artículo 12, fracción XXI, de la Ley de la Industria Eléctrica). |
| • | General administrative provisions regarding open access and provision of services in the National Transmission Network and the General Distribution Networks (Disposiciones administrativas de carácter general en materia de acceso abierto y prestación de los servicios en la Red Nacional de Transmisión y las Redes Generales de Distribución de Energía Eléctrica). |
| • | General administrative provisions that establish the requirements and minimum amounts of electricity coverage contracts that suppliers must hold regarding electric power, energy demand and clean energy certificates that they will supply to the represented load centers and their verification (Disposiciones administrativas de carácter general que establecen los requisitos y montos mínimos de contratos de cobertura eléctrica que los suministradores deberán celebrar relativos a la energía eléctrica, potencia y certificados de energía limpia que suministrarán a los centros de carga que representen y su verificación). |
| • | Policy on Reliability, Safety, Continuity and Quality on the National Electric System (Política de Confiabilidad, Seguridad, Continuidad y Calidad en el Sistema Eléctrico Nacional). |
| • | Resolution by means of which CFE announced the new wheeling tariffs to owners of Legacy Interconnection Agreements with renewable energy sources (Resolución por medio de la cual CFE dio a conocer las nuevas tarifas de transmisión a los titulares de Contratos de Interconexión Legados con fuentes de energía renovable). |
| • | Decree number A/037/2021 of the Energy Regulatory Commission by means of which decree number A/049/2017 is amended, regarding the interpretation criteria of the concept self-needs and the general aspects applicable to the isolated supply activity. |
| • | Resolution number RES/550/2021 of the Energy Regulatory Commission by means of which the General Administrative Provisions regarding the efficiency, quality, reliability, continuity, safety and sustainability standards of the National Electric System are published: Grid Code. |
Regulation in Peru
The Electric Transmission Sector
The Peruvian electric system serves energy to a large area of the country through its national grid, the SEIN (the Sistema Eléctrico Interconectado Nacional).
Pursuant to Law 28832, which is applicable to any transmission project commissioned after July 2006, the transmission facilities integrating the transmission grid are classified as those belonging to: either (i) the Guaranteed Transmission System (Sistema Garantizado de Transmisión or SGT), for transmission facilities that are included in the transmission plan and developed pursuant to a concession agreement granted by the Peruvian government to the winner of a public tender, or (ii) the Complementary Transmission System(Sistema Complementario de Transmisión or SCT), for transmission facilities that are either (a) included in the transmission plan and developed by the private entity that was awarded a concession as a result of the successful review of a private initiative proposal, or (b) not included in the transmission plan. ATN and ATS are part of the Guaranteed Transmission System. ATN2 is part of the Complementary Transmission System.
Under Law 28832, the projected expansions of the transmission system identified in the Peruvian transmission plan are part of the SGT. The government organizes tender procedures to call private investors interested in building the projected lines of the SGT and award a SGT concession agreement (see further information regarding SGT Concession Agreements below).
Transmission lines of interest to generation plants, distribution networks or large consumers are part of the SCT. The lines of the SCT included in the Peruvian transmission plan and certain projects that exclusively serve the demand, as defined by the government, may be subject to tenders for the granting of SCT Concession Agreements up to 30 years. The rest of the SCT projects are subject to the general regime in which the owners of the SCT lines (for example, the generation companies building them to connect their plants to the system) are the holders of the respective Definitive Transmission Concession and own the transmission assets through the term of the concession.
Tariff Regime
The SGT is compensated through the tariff base, which is the authorized annual remuneration for facilities belonging to the SGT. The tariff base is established in annual amounts and includes the following: (i) remuneration of investments (including adjustments), which is calculated based on a 30-year recovery period applying a 12% rate of return, (ii) efficient operating and maintenance costs, and (iii) the liquidation of imbalances between the authorized tariff base for the previous year and the proceeds obtained during that year.
The tariff base will be paid through the (i) tariff income and (ii) the transmission toll. The tariff income is paid monthly by the electricity generation companies in proportion to their respective capacity income. The transmission toll is paid by the electricity generation companies based on their collection of the transmission toll paid by their respective customers pursuant to the Transmission Rules (Reglamento de Transmision).
The SCT is remunerated on the basis of the annual average cost of the corresponding facilities approved by OSINERGMIN. The applicable tariffs and their respective actualization formulas are approved by OSINERGMIN every four years.
The Resolution 055-2020-OS/CD issued by OSINERGMIN approved the Annual Liquidation Procedure, applicable to all transmission concessionaires titleholders of SGT Contracts. This procedure, did not modify the base tariff established in the concession agreements. However, this procedure is relevant as it determines the monthly disbursements to be made in favor of the transmission agents of the electricity market in a tariff annual period and determines the transmission toll that must be paid by all customers pursuant to the Transmission Rules (Reglamento de Transmisión) in order to cover the base tariff.
Penalties
The concessionaires must maintain certain quality, safety and maintenance standards of the facilities. The failure to meet the quality standards established by applicable industry regulations, such as the technical rules of quality for power services, and the National Electricity Code, may result in the imposition of penalties, fines and restrictions. In addition to these penalties, fines and restrictions, if our concession is terminated due to the breach of obligations under the Concession Agreements, the Peruvian Ministry of Energy and Mines may appoint an intervenor to supervise the operations related to the concession to ensure the continuity in the provision of the service, and the compliance with applicable laws and regulations.
If a concessionaire suspends or interrupts the service for reasons other than regular maintenance and repairs, force majeure events, or failures caused by third parties, such concessionaire may be required to indemnify those who were affected for the damages caused by any such service interruption, in accordance with applicable regulations. In addition, the OSINERGMIN could impose penalties, including, among others, (a) admonishment, (b) successive fines, depending on the nature and effect of the interruption and its frequency, (c) temporary suspension of activities, and (d) definitive suspension of activities and the provisional administration of operations by an intervenor, if a termination event occurs and the Peruvian Ministry of Energy and Mines notifies of its desire to terminate the SGT Concession Agreement.
Electricity Legal Framework
The principal laws and regulations governing the Peruvian energy sector, or the Electricity Legal Framework, are: (i) the Electricity Concessions Law (Ley de Concesiones Eléctricas, PCL), and its implementing rules; (ii) the Law 28832, Law to Ensure the Efficient Development of Electricity Generation (Ley para Asegurar el Desarrollo Eficiente de la Generación Eléctrica), (iii) the Transmission Rules (Reglamento de Transmisión), or the Transmission Rules; (iv) the General Environmental Law; (v) the Regulations for the Environmental Protection in Power Activities; (vi) the Laws creating OSINERGMIN; (vii) the OSINERGMIN Rules ; (viii) the Regulatory Agencies of Private Investment in Public Services Framework Law; and (ix) the Legislative Decree that promotes investment in the generation of power through renewable resources and its regulations.
These rules regulate how to enter the electricity sector (applicable permits and licenses); the main obligations of the different participants of the electricity market (generators, transmission companies and distribution companies); remuneration systems for the different market participants; rights of electricity consumers and the attributions of the competent authorities.
The Economic Operations Committee of the National Interconnected System (Comité de Operación Económica del Sistema Interconectado Nacional – COES) is an entity created by the PCL and it is composed by different market participants (generation, transmission and distribution companies). COES is the operator of National Interconnected System - SEIN. COES supervises the interconnection of new facilities to the grid, organizes energy dispatch and supervises the real time operational of the system. The Resolution 083-2021-OS/CD approved the technical procedure No. 20 of the COES. By this procedure COES, regulates the main technical issues related to the entry, modification and withdrawal of electric facilities in the SEIN and established a regulation for the treatment of facilities connected to distribution concessions.
Some of the main aspects of Peru’s regulatory framework concerning its power sector are: (i) the separation between the power generation, transmission and distribution activities; (ii) unregulated prices for the generation of power supplied to unregulated customers; (iii) regulated prices for the generation of power supplied to regulated customers; (iv) regulated prices applicable to transmission and distribution of power for both regulated and unregulated customers; and (v) the private administration of the SEIN, according to the principles of efficiency, cost reduction, guaranty of quality and reliability in the provision of services.
All entities that generate, transmit or distribute power to third parties in Peru, including self-generators and co-generators that sell their excess capacity and energy in the SEIN are regulated by the Energy Legal Framework.
The Peruvian government retains ultimate oversight and regulatory control. In addition, the Peruvian government owns and controls various generation and distribution companies in Peru.
The Resolution N° 002-2020-OS/CD issued by OSINERGMIN approved the procedure named “Conditions for the application of electricity generation and transmission tariffs”. This regulation is applicable to electricity agents (including transmission agents). By means of this procedure, the conditions for the application of the generation and transmission prices were established for certain electric energy supplies as further detailed in the Electrical Concessions Law.
In addition, the same way it was approved the procedure for the Auditing of Contracts and Authorizations of the Electricity Subsector and Concession Contracts in Natural Gas Activities was approved (Resolution No. 166-2020-OS/CD), having as the purpose of this regulation is to audit the obligations contained in concession contracts, authorizations and investment commitment contracts in the electricity sub-sector, including the transmission service, which are under the competence of OSINERGMIN. For the electric transmission systems, the following aspects are subject to audit: (i) the Electric Power Transmission Systems Concession Contract (SGT and SCT); (ii) Electric Power Transmission System Expansions; (iii) Concession Contract to Develop the Electric Power Transmission Activity.
OSINERGMIN is the entity that verifies the compliance of the electricity regulation. Currently, OSINERGMIN applies its new Regulations for the Inspection and Sanctioning of Energy and Mining Activities approved by Resolution No. 208-2020-OS/CD, issued in December, 2020. Such new regulation is applicable to the transmission sector.
Moreover, during 2021, OSINERGMIN approved a modification to the Technical Procedure No. 31 of the COES regarding the calculation of the Variable Costs of the Generation Units, which had an impact on the energy business due to its impact on the marginal cost. Also, during 2022 such Procedure was (once again) modified through Resolution No. 171-2022-OS/CD.
In December 2022, through Supreme Decrees No. 154-2022-PCM and 157-2022-PCM, certain provisions related to the regime of the Contribution for Regulation in the electricity sub-sector in favor of OSINERGMIN and the Environmental Evaluation and Inspection Agency (OEFA) were approved. Specifically, in both cases, the rates of the Contribution for Regulation of the electric transmission concessionaires were updated for years 2023, 2024 and 2025.
By means of the Ministerial Resolution No. 227-2022-MINEM-DM, the Peruvian Ministry of Energy and Mines published for comments a draft of an amendment to the Law 28832. Among other topics, such resolution proposes: (i) a modification of some aspects related to the procedures to call for auctions for the execution of a SGT; (ii) the recognition of firm capacity for energy plants that produces with renewal energy resources, and (iii) the development of complementary services in the system (for example, based in the provision of frequency regulation services with battery energy storage systems).
Finally, regarding the existing limitations to vertical integration of the electric activities, Law No. 31112, “Law that establishes the prior control for corporate concentration operations” and its relevant implementing rules (Supreme Decree No. 039-2021-PCM) became effective on June 14, 2021.
Regulation for Environmental Protection in Electrical Activities
In accordance with the current environmental legal framework, as a general rule, prior to the construction and beginning of any electrical activities (i.e. generation, transmission or distribution) the holder must obtain from the Peruvian Ministry of Energy and Mines an instrument for environmental management (“IEM”), which after its approval is mandatory for implementation. In that sense, electricity companies are obliged to submit, on a yearly basis, an Annual Environmental Report with information on their level of compliance with environmental commitments (as established in the IEM) and other legal obligations that may result applicable. During 2022, guidelines for the filing of such Report were approved.
On September 24, 2023, the Ministry of Energy and Mines issued Supreme Decree No. 016-2023-EM, approving the Citizen Participation Regulations for the execution of electrical activities. The purpose of these regulations is to establish provisions that govern the mechanisms of citizen involvement in various stages, including the preparation and evaluation of environmental management instruments, as well as the post-approval stage concerning electricity activities. Regarding the post-approval stage of the Environmental Study or IGAC, the regulations specify that citizen participation mechanisms must be incorporated into the Community Relations Plan of the Environmental Study or IGAC. This plan should outline the timing for compliance, the frequency, and the method of providing sources for verifying its implementation to the OEFA.
The Ministry of Energy and Mines has issued the Supreme Decree No. 014-2023-EM, which outlines complementary provisions for the Detailed Environmental Plan (PAD). The objective is to foster sustainable development within the realm of electricity generation, transmission, and distribution nationwide. The Detailed Environmental Plan serves as a supplementary environmental management tool, addressing both actual and potential adverse environmental impacts identified within the scope of ongoing electrical activities. Its purpose is to streamline the adaptation of these activities in a manner that aligns with environmental considerations.
The Supreme Decree No. 014-2023-EM introduces a revised timeline for notifying the Ministry of Energy and Mines regarding the intention to apply for a Detailed Environmental Plan (PAD), with a stipulated window of 3 months from the rule’s effective date, or until November 20, 2023. Additionally, the regulation outlines that, for the subsequent submission of the PAD, owners of electrical activities are granted a 3-year timeframe, whereas municipalities and regional governments are afforded 5 years, both calculated from the date of the Supreme Decree coming into effect.
The guaranteed Transmission System—SGT Concession Agreement
ATN and ATS, as concessionaires, have SGT Concession Agreements granted by the Peruvian government as a result of a public tender. Under the SGT Concession Agreement, the Peruvian Ministry of Energy grants the concession necessary to construct, develop, own, operate, and maintain the transmission lines and substations comprising a project to provide electricity transmission services that has been included in the Peruvian transmission plan.
The SGT Concession Agreement must specify the works schedule of the project and the corresponding guaranties of compliance. It also specifies the causes of termination of the agreement. The SGT concessionaires are not obliged to pay the grantor any consideration for the SGT Concession Agreement.
Under the SGT Concession Agreement, the concessionaire shall build the lines and be responsible for their operation and maintenance. The recovery of the investment during the term of the contract (30 years) is guaranteed thereunder. The concessionaire owns the transmission assets during the term of the contract. Upon expiry of the contract the assets return to the state, which shall call a new tender if the lines are required at such time for the operation of the system.
The revenues of the project are established under the terms of the SGT Concession Agreement. In addition, the revenues of the project are funded by the users of electricity system. Related to this, the compensation for facilities that are part of the SGT is allocated to customers by OSINERGMIN according to the amounts of investment, operational and maintenance costs set forth in the SGT Concession Agreement. The SGT will receive monthly compensation from the generation companies that collect the tariff base from their customers. Their compensation will be paid on a monthly basis and these monthly payments are liquidated by the COES, following the tariffs established annually by OSINERGMIN.
Regulation in Chile
Current Regulatory Framework
The general regulatory framework of the Chilean electricity sector, focused on photovoltaic solar plants, consists of:
| • | Decree with force of law no. 4, that fixes consolidated, coordinated, and systematized text of Decree with force of law no. 1, of Mining, of 1982, on General Law of Electric Services, in matters of electric energy, the “General Law of Electric Services”, |
| • | Law No. 19.300, March 9, 1994, on General Bases of the Environment, modified by Law No. 20.417, January 26, 2010, which creates the Ministry, the Environmental Evaluation Service and the Superintendence of the Environment; |
| • | Supreme Decree No. 327/1997 of the Ministry of Mining, published in the Official Gazette on September 10, 1998, modified by Supreme Decree No 68/2021, which contains “Regulation of General Law of Electric Services”; |
| • | Supreme Decree No. 125/2019 of the Ministry of Energy, published in the Official Gazette on December 20, 2019, which contains “Regulation of coordination and operation of the national electricity system”; |
| • | Supreme Decree No. 62/2006 of the Ministry of Economy, Development and Reconstruction, published in the Official Gazette on June 16, 2006, modified by Supreme Decree No 42/2020, which contains “Regulation of power transfers between companies regulated by General Law of Electric Services”; |
| • | Supreme Decree No. 88/2019 of the Ministry of Energy, published in the Official Gazette on October 8, 2020, modified by Supreme Decree No 27/2022, which contains “Regulation on Small Means on Distributed Generation” (PMGD). |
| • | Technical standard for the connection and operation of PMGD in medium voltage installations fixes by the National Energy Commission (“NTCO-PMGD” July 2019). |
General Law of Electric Services
The purpose of the General Law of Electric Services is to establish a regulatory framework containing the rules applicable to the generation, transmission and distribution of electric power in Chile. This law is complemented by a series of technical regulations and standards.
In turn, for the electricity generation business, the applicable regulations establish a competitive market that seeks to supply the demand at minimum cost, so that the result is the economically efficient allocation of resources to and within the electric sector. To accomplish this, the National Electric Coordinator (“CEN”) determines the generation costs of each power plant and schedules the operation, according to the rules contained mainly in the “Regulation of coordination and operation of the national electricity system”.
The operation of electricity distribution companies require the granting of a concession by the authority and is usually a monopoly market. Pursuant to the General Law of Electric Services, the electric power distribution companies should provide public distribution services to all the customers located in their concession areas and are obliged to supply to all those who request it within such area. On the other hand, the regulations of the aforementioned law establish the duty of the distribution companies to ensure compliance with the obligation to provide supply. To comply with this, they must have a permanent supply of energy that, added to their own generation capacity, allows them to meet their total projected needs for a time horizon of at least three years.
Regulation applicable to transmission lines
The General Law of Electric Services establishes a medium and long term planning procedure for the most important transmission lines, to then publicly tender the construction of the works. In turn, the owners of the transmission lines are entitled to receive a remuneration called “tolls” as compensation for the investment and maintenance of the lines.
Regulation applicable to photovoltaic plants
The General Law of Electric Services establishes freedom to build, install or purchase photovoltaic plants, thus a previous state concession is not required to perform such activities. However, once a PV enters into operation, it must comply with the instructions given by the CEN for the entire National Electric System (“SEN”) regarding energy production. Such instructions will determine which plants must produce electricity in the next few days, depending on their production costs and the availability of the power plants, among other aspects. If the plant is “dispatched” by the CEN, it must operate and its energy will be injected into the National Electric System, from where the companies that have customers will obtain the electricity necessary to supply their consumption.
According to the General Electric Services Law, all owners of generation facilities synchronized to the SEN shall have the right to sell the energy they produce at the instantaneous marginal cost, as well as their power surpluses at the node price of the power. As a result, in the generation market there are forced sales of electric power between the different plants, the price of which is determined by CEN and corresponds to the instantaneous marginal cost. The valuation of energy and power transfers between the different companies is carried out by CEN, according to the rules contained mainly in “Regulation of coordination and operation of the national electricity system” and “Regulation of power transfers between companies regulated by General Law of Electric Services”.
Regulation applicable to PMGDs
The General Electric Services Law provides that a regulation will establish the procedures for the determination of prices, when the generation facilities are directly connected to distribution system, as well as the price stabilization mechanisms applicable to the energy injected by power plants whose surplus of power that can be supplied to the electricity system does not exceed 9 MW. For that reason, Supreme Decree No. 244/05 (“DS 244”) was approved to incorporate a regulation for small-scale generation facilities (PMG and PMGD). Moreover, on October 8, 2020, Supreme Decree No. 88 (DS 88) was published in the Official Gazette, incorporating a new regulation for small-scale generation facilities (PMG and PMGD) which was amended in March 2022.
Any owner or operator of a small-scale generation facility must choose to sell the energy it injects into the system at the instantaneous marginal cost or under a stabilized price regime. This option must be communicated at least one month prior to the entry into operation. The minimum period of permanence in each regime will be four years and the option to change regime must be communicated to CEN at least six months in advance.
The price stabilization mechanism (or “Stabilized Price”) was incorporated in the General Law of Electric Services with Law No. 19,940/2004, with the intention of encouraging the construction of small non-conventional renewable energy generating plants, whose power surpluses do not exceed 9MW. The aim was to reduce the entry barriers faced by these plants, normally located close to consumption centers, stabilize their cash-flows, and diversify the energy matrix. Supreme Decree No. 244/05 (“DS 244”) regulated this matter and allowed the owners of such facilities if they sold the energy produced at the instantaneous marginal cost or at the Stabilized Prices set by Supreme Decree by the Ministry of Energy. The Stabilized Price would be determined by the National Energy Commission for a 4-year horizon, based on a projection of the marginal cost for that period. If the Stabilized Price was chosen, the plant had to remain for the same period of 4 years in the price stabilization mechanism. This Supreme Decree was replaced 15 years later by Supreme Decree No. 88/2019 (“DS 88”).
The new scheme set by DS 88 modifies the stabilized price regime for projects up to 9MW that are directly connected to low and medium voltage transmission lines and introduces adjustments aimed at streamlining the connection process. Regarding the new stabilized price regime, the calculation now considers six four-hour time intervals with independent prices during a given day, in contrast to the previous regime, which did not make distinctions based on the time of energy injection.
At the same time, in order to avoid a negative impact on the market of the PMGDs that had already used this mechanism, DS 88 created a grandfathering period for PMGDs that were (i) already in operation, (ii) declared under construction and/or (iii) with their sectorial environmental approvals granted. Under such grandfathering period, the facilities that met any of the abovementioned criteria can choose if they want to benefit from the Stabilized Price regime of DS 244 for a term of 165 months since the publication of DS 88, until July 2034. Given that Atlantica’s Chile PMGDs were already declared under construction when DS 88 became applicable, Atlantica chose to benefit from the grandfathering period and therefore receiving the stabilized price set by DS 244. Once the term of the grandfathering period elapses, all PMGDs will follow the new scheme set forth by DS 88.
DS 88 establishes a regulated procedure for the authorization of PMGDs. Such procedure begins with the presentation of a request for connection to the grid belonging to a distribution company, accompanying a schedule of works, and a deposit of 20% of the costs corresponding to the connection studies. If declared admissible by the distribution company, it issues a Connection Criteria Report (ICC), which will be valid for 9, 12 or 18 months, with no possibility of extension, depending on the installed capacity of the project, as well as whether it has a significant impact on the grid. Moreover, in order to receive the authorizations required for construction, PMGDs must submit their “declaration under construction” to the CNE, at which time the CNE will analyze if their power surplus is less than or equal to 9MW, being a requirement to access to the special conditions defined exclusively for small-scale generation facilities, such as connection conditions, operation, price level and billing.
It is important to note that the electricity distribution companies must allow the connection to their distribution facilities to the PMGDs, complying with the specifications contained in the Technical Standards issued by the CNE, at present “NTCO-PMGD” July 2019 and shall guarantee access to their network for PMGD with the same quality of service applicable to Regulated customers.
Regulation in Spain
Primary Rights and Obligations under the Spanish Electricity Act
The Electricity Act recognizes the following rights for producers with facilities that use renewable energy sources:
| • | Priority off-take. Producers of electricity from renewable sources have priority over conventional generators in transmitting to off-takers the energy they produce under equal market conditions, without prejudice to the requirements relating to the maintenance of the reliability and safety of the national electricity system and based on transparent and non-discriminatory criteria, in terms to be determined by the Government in a regulatory manner. |
| • | Priority of access and connection to transmission and distribution networks. Without prejudice to the security of supply and the efficient development of the system, producers of electricity from renewable energy sources have priority in obtaining access and connecting to the grid, subject to the terms set forth in the regulations, on the basis of objective, transparent and non-discriminatory criteria. |
| • | Entitlement to a specific payment scheme: under the system established by Royal Decree 413/2014, the sale of electricity at market price is complemented with a specific regulated remuneration that allows these technologies to compete on an equal basis with the rest of the technologies on the market. This specific complementary remuneration will be sufficient to reach the minimum level necessary to cover the costs and enables them to compete on a level playing field with the other, non-renewable technologies on the market while achieving a reasonable return on investment. In case of new facilities, the government of Spain can establish a specific remuneration through an auction process. |
The significant obligations of the renewable energy electricity producers under the Electricity Act include, inter alia, a requirement to:
| • | Offer to sell the energy they produce through the market (daily and intra-daily market managed by the market operator) or via a bilateral or forward contract (which makes them consequently excluded from the bidding system managed by the market operator). |
| • | Maintain the plant’s planned production capacity. Power lines, which include connections with the transmission or distribution network and transformers are considered part of the production facility. |
Remuneration System for Renewable Plants
According to Royal Decree 413/2014, producers receive (i) the electricity market price for the power they produce and (ii) a specific remuneration.
The specific remuneration system established by Royal Decree 413/2014 applies to production facilities using renewable energy sources, high-efficiency cogeneration and waste that do not reach the minimum level necessary to cover the costs. It allows them to compete on an equal footing with the rest of the technologies on the market, obtaining a reasonable return.
In order to determine the specific remuneration system applicable in each case, each installation, depending on its characteristics, will be assigned a standard installation which will be established according to technology, installed power, age, electrical system, etc. The specific remuneration of each installation will be obtained from the remuneration parameters of the corresponding standard installation and from the characteristics of the installation itself. For the calculation of the remuneration parameters of the standard installation, the values resulting from the competitive competition procedure shall be applied.
This specific remuneration system shall consist of the following two concepts for remuneration:
| a) | A remuneration per unit of installed power, which shall be called Remuneration on Investment (Rinv) and shall be expressed in €/MW. To determine this parameter, the standard value of the initial investment resulting from the competitive tendering procedure established to grant the specific remuneration system to each installation will be considered. For the calculation of the annual income from the remuneration for the investment of an installation, the Remuneration on Investment (Rinv) of the associated typical installation shall be multiplied by the power entitled to the specific remuneration system, without prejudice to the correction according to the number of equivalent hours of operation. |
| b) | A Remuneration on Operation (Ro), which shall be calculated in accordance with the provisions of Article 17 of the Royal Decree 413/2014, expressed in €/MWh. In order to calculate the income from the Remuneration on Operation (Ro) of an installation, the Remuneration on Operation (Ro) of the associated typical installation shall be multiplied, for each settlement period, by the energy sold on the production market in any of its forms of contracting in said period, attributable to the fraction of power entitled to a specific remuneration system, without prejudice to the correction based on the number of equivalent hours of operation. |
For the granting of the specific remuneration system, the conditions, technologies or group of specific facilities that may participate in the competitive competition mechanism are established. Nevertheless, the granting of this specific remuneration system for existing facilities is regulated in the first transitory provision of Royal Decree 413/2014, that establishes that they will be automatically registered on a date to be determined by order of the Minister for Ecological Transition and Demographic Challenge. In any case, it contemplates the possibility of requesting the modification of the inaccuracies that could contain the data of the registry after the referred automatic inscription.
According to article 14 of the Electricity Act, the remuneration shall not exceed the minimum level necessary to cover the costs that allow production facilities from renewable energy sources, high-efficiency cogeneration and waste to compete on an equal level with the other technologies on the market and that allows reasonable return to be obtained in relation to the standard installation in each applicable case (“reasonable rate of return”).
The Royal Decree 413/2014 establishes statutory periods of six years, with the second regulatory period beginning in January 2020. Each statutory period is divided into two statutory half-periods of three years. This “statutory period” mechanism aims to set forth how and when the Ministry for Ecological Transition and Demographic Challenge is entitled to revise the different payment factors (which include the cyclical situation of the economy, the electricity demand and the appropriate profitability) used to determine the specific remuneration to be received by the standard facilities. At the end of each statutory half-period (three years) the Ministry for Ecological Transition and Demographic Challenge may revise (i) the electricity market price estimates and (ii) the adjustment value for electricity market price deviations in the preceding statutory half-period.
The second regulatory period began on January 1, 2020. Following the recommendations of the CNMC, the reasonable return was calculated by reference to the weighted average cost of capital (WACC). The WACC is the calculation method that most of the European regulators apply in most of the cases to determine the return rates applicable to regulated activities within the energy sector. For the second regulatory period, the Royal Decree-Law 17/2019 updated the reasonable rate of return that applies to standard renewable energy facilities in the period 2020-2025. The reasonable return applicable over the remaining regulatory life of standard facilities applicable during the second regulatory period, is 7.09%.
In addition, the Royal Decree-Law introduced a third final provision in Law 24/2013, of 26 December, on the Electricity Sector, which exceptionally, gave the option to the owners of renewable facilities that were recognized as having primary remuneration before the entry into force of Royal Decree-Law 9/2013, to maintain the value of the reasonable return fixed for the first regulatory period for two consecutive regulatory periods starting on January 1, 2020. In other words, these owners are able to maintain a reasonable return for their facilities of 7.398% until 2031. However, this new measure shall not be applicable when an arbitration or judicial proceeding based on the modification of the special remuneration system after Royal Decree 661/2007 is initiated or has previously been initiated by any current or previous shareholders unless it is proven that the arbitration or legal proceedings have been early terminated and the resumption or continuation of the proceedings and the receipt of compensation or indemnification has been duly waived. According to public information, current minority shareholders and previous shareholders of six of our solar plants filed arbitration processes back in the day.
In addition, in 2022 measures to adjust the regulated revenue component for renewable energy plants were introduced, following the increase since mid-2021 in the billings of these plants for the sale of electricity in the market. On March 30, 2022, the Royal Decree Law 6/2022 was published, adopting urgent measures in response to the economic and social consequences of the war in Ukraine. This Royal Decree Law contains a bundle of measures in diverse fields, including those targeted at containing the sharp rise in the prices of gas and electricity. It includes temporary changes to the detailed regulated components of revenue received by our solar assets in Spain, which are applicable from January 1, 2022. Specifically, prior to the entry into force of these new regulations, the level of remuneration under that specific remuneration system depended on the market price estimates used to calculate it, which are revised in each regulatory semi-period. Under article 5 of Royal Decree Law 6/2022, for the year 2022 the remuneration will be reviewed also taking into account 2020 and 2021 actual market prices and prices of the future prices of OMIP for year 2022. Further, through Royal Decree Law 6/2022 and Royal Decree Law 10/2022, the article 22 of Royal Decree Law was modified to the change the update of the remuneration. and therefore, the formula for the calculation of the adjustment value in each semi-period from 2023 was modified. Prior to these amendments, the reference index was exclusively the current daily market price. After these modifications, and as of 2023, the estimate of the market price for each year of the regulatory half-period is calculated as the arithmetic mean of the prices of the corresponding annual futures contracts traded on the electricity futures market organized by OMIP from 1 June to 30 November of the year prior to the start of the half-period for which the market price is estimated, and the adjustment value will be a weighting of the actual daily market price and OMIP futures prices at different time horizons. Nevertheless, Royal Decree Law 5/2023 has established an exemption to this modification for the estimation of the market price for 2023. Therefore, for the regulatory half-period beginning on 1 January 2023 and ending on 31 December 2025, the electricity market price for 2023 will be estimated on the basis of the daily market values between 1 January and 31 May 2023 and the futures values traded in that period for the energy delivered between 1 June and 31 December 2023. On the other hand, the estimate of the electricity market price for the year 2024 and subsequent years will be made on the basis of the futures markets. Due to these changes:
| − | The statutory half-period of three years from 2020 to 2022 has been split into two statutory half-periods (1) from January 1, 2020 until December 31 2021 and (2) calendar year 2022. As a result, the fixed monthly payment based on installed capacity (Remuneration on Investment or Rinv) for calendar year 2022 was revised in the new Order TED/1232/2022. |
| − | Subsequently, following the mandate contained in Royal Decree Law 6/2022, Royal Decree Law 10/2022 and Royal Decree Law 5/2023, whose main measures have been exposed above, the remuneration parameters were updated for the years 2023-2025 by Order TED/741/2023, of June 30, 2023, that was published in final form on July 8, 2023. The proposed Rinv for 2023-2025 is detailed in the table below. |
| − | The electricity market price assumed by the regulation included in Royal Decree Law 5/2023 for calendar year 2023 is 109,31 €/MWh, the estimation of the market price for the year 2024 is 108,86 €/MWh and for the year 2025 is 89,37 €/MWh. For the years 2026 and beyond, the value for the year 2025 has been used. As a result, the variable payment based on net electricity produced (Remuneration on Operation or Ro), was also adjusted. The proposed Ro for the year 2024 is zero €/MWh for most of our assets reflecting the fact that market prices for the power sold in the market are significantly higher. |
Since January 1, 2023, the parameters foreseen in Order TED/741/2023 are as follows:
| | Useful Life | Remuneration on Investment 2023 - 2025 (euros/MW) | Remuneration on Operation 2024 (euros/GWh) | Adjustment Rate | Maximum Hours | Minimum Hours 2024-2025 | Operating Threshold 2024-2025 |
| Solaben 2 | 25 years | 378,506 | 0 | 0.9854 | 2,004 | 1,202 | 701 |
| Solaben 3 | 25 years | 378,506 | 0 | 0.9854 | 2,004 | 1,202 | 701 |
| Solacor 1 | 25 years | 378,506 | 0 | 0.9854 | 2,004 | 1,202 | 701 |
| Solacor 2 | 25 years | 378,506 | 0 | 0.9854 | 2,004 | 1,202 | 701 |
| PS 10 | 25 years | 533,115 | 19.798 | 0.9948 | 1,837 | 1,102 | 643 |
| PS 20 | 25 years | 393,001 | 14.044 | 0.9942 | 1,837 | 1,102 | 643 |
| Helioenergy 1 | 25 years | 372,549 | 0 | 0.9845 | 2,004 | 1,202 | 701 |
| Helioenergy 2 | 25 years | 372,549 | 0 | 0.9845 | 2,004 | 1,202 | 701 |
| Helios 1 | 25 years | 387,136 | 0 | 0.9857 | 2,004 | 1,202 | 701 |
| Helios 2 | 25 years | 387,136 | 0 | 0.9857 | 2,004 | 1,202 | 701 |
| Solnova 1 | 25 years | 392,031 | 0 | 0.9849 | 2,004 | 1,202 | 701 |
| Solnova 3 | 25 years | 392,031 | 0 | 0.9849 | 2,004 | 1,202 | 701 |
| Solnova 4 | 25 years | 392,031 | 0 | 0.9849 | 2,004 | 1,202 | 701 |
| Solaben 1 | 25 years | 384,318 | 0 | 0.9860 | 2,004 | 1,202 | 701 |
| Solaben 6 | 25 years | 384,318 | 0 | 0.9860 | 2,004 | 1,202 | 701 |
| Seville PV | 30 years | 677,855 | 0 | 0.9809 | 2,030 | 1,218 | 711 |
Electricity Sales Tax
On December 27, 2012, the Spanish Parliament approved Law 15/2012, which became effective on January 1, 2013. The aim of Law 15/2012 was to try to resolve the issue with so-called tariff deficit. Law 15/2012, as amended, provides for an electricity sales tax which is levied on activities related to electricity production. The tax is triggered by the sale of electricity and affects ordinary energy producers and those generating power from renewable sources. The tax, at a flat rate of 7%, is levied on the total income received from the power produced at each of the facilities, which means that every calendar year, solar power plants will be required to pay 7% of the total amount which they are entitled to receive for production and incorporation into the electricity system of electric power, measured as the net output generated.
In January 2021, the Spanish Courts referred a preliminary ruling to the Court of Justice of the EU related to the validity of the electricity sales tax. The Court of Justice of the EU declared the conformity of this tax to the EU legislation in March 2021.
However, the Royal Decree-Law 12/2021 and the Royal Decree-Law 17/2021 included an exemption from this tax, for the electricity produced and incorporated into the electricity system during the third and last calendar quarter of 2021. This entails modifying the calculation of the tax base and of the fractioned payments regulated in the tax regulations. The Royal Decree-Law 29/2021 extended those measures to the first calendar quarter of 2022. These measures were further extended to 2022 and 2023. Royal Decree-Law 8/2023 provides that the exemption will amount to 50% in the first calendar quarter of 2024 and to 25% in the second calendar quarter of 2024. No exemption will be applicable onwards.
In any case, in this situation we expect that the remuneration received by our assets in Spain would be adjusted for the same amount, as a result we do not expect any impact.
Tax Incentive of Accelerated Depreciation of New Assets
Under provisions of the Spanish Corporate Income Tax Act, tax-free depreciation is permitted on investments in new material assets and investment properties used for economic activities acquired between January 1, 2009 and March 31, 2012. Taxpayers who made investments during such period and have amounts pending to be deducted for this concept may apply such amounts with certain limitations.
Taxpayers who made investments from March 31, 2012 through March 31, 2015 in new material assets and investment properties used for economic activities are permitted to take accelerated depreciation for those assets subject to certain limitations. The accelerated depreciation is permitted if:
| • | 40% of the tax base before the amortization or depreciation and before the offset of tax loss carryforwards for taxpayers (subject to requirements to keep up employment levels); or |
| • | 20% of the tax base before the amortization or depreciation and before the offset of tax loss carryforwards for taxpayers (without employment requirements). |
Most of the investment in our Spanish assets was undertaken within the regime that applied between January 1, 2009 and March 31, 2012.
These limitations do not apply in respect of companies that meet the requirements set forth in article 108.1 of the Spanish Corporate Income Tax Act related to the special rules for enterprises of a reduced size.
| C. | Organizational Structure |
The following summary chart sets forth our ownership structure as of the date of this annual report:
Notes:
| (1) | Atlantica Sustainable Infrastructure plc directly holds one share in Palmucho and 10 shares in each of Quadra 1 and Quadra 2 |
| (2) | ATIS directly holds one share in each of Atlantica Peru S.A. (AP), ATN S.A. and ATS S.A. |
| (3) | 30% owned by Itochu, a Japanese company |
| (4) | 13% owned by JGC, a Japanese company |
| (5) | AEC holds 49% of Honaine and Skikda. Sacyr holds 25.5% of Honaine and 16.8% of Skikda |
| (6) | 20% of Seville PV owned by IDEA, a Spanish state-owned company |
| (7) | ATN holds a 75% stake in ATS |
| (8) | ATN holds a 25% stake in ATN 2 |
| (9) | 87.5% owned by Lotus Infrastructure |
| (10) | 49% owned by Industrial Development Corporation, a South African Government company |
| (11) | 70% owned by Arroyo Energy |
| (12) | 100% indirectly owned by Arroyo Energy Netherlands II |
| (13) | 70% held by Algonquin |
| (14) | Solar and wind projects under development in Uruguay |
| (15) | 65% held by financial partners |
| (16) | Solar projects 100% owned by Chile Platform |
| (18) | 51% held by EDPR Renewables |
| (20) | Solar and battery project under development in the US |
| (21) | Solar projects under development in Colombia (Honda 1, Honda 2 and Apulo 1) |
| (22) | Coso Batteries 1, the standalone battery storage project of 100 MWh (4 hours) capacity |
| (23) | Solar and battery project under development in Arizona |
| (24) | 49% in solar projects in Chile. Simplified structure. 51% held by Akuo Energy Chile |
| (25) | ATN also owns a transmission line and substation under development in Peru |
| (26) | Battery projects in Mexico. 60% of voting rights through preferred equity shares that provide almost all economic rights to Atlantica |
| D. | Property, Plant and Equipment |
See “Item 4.B—Business Overview.”
| ITEM 4A. | UNRESOLVED STAFF COMMENTS |
Not Applicable.
| ITEM 5. | OPERATING AND FINANCIAL REVIEW AND PROSPECTS |
The following discussion should be read together with, and is qualified in its entirety by reference to, our Annual Consolidated Financial Statements. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs, which are based on assumptions we believe to be reasonable. Our actual results could differ materially from those discussed in these forward-looking statements as a result of various factors, including those set forth under “Item 3.D—Risk Factors” and elsewhere in this annual report.
Overview
We are a sustainable infrastructure company with a majority of our business in renewable energy assets. Our purpose is to support the transition towards a more sustainable world by investing in and managing sustainable infrastructure, while creating long-term value for our investors and the rest of our stakeholders. In 2023, renewables represented 73% of our revenue, with solar energy representing 63%. We complement our portfolio of renewable assets with storage, efficient natural gas and heat and transmission infrastructure assets, as enablers of the transition towards a clean energy mix. We also hold water assets, a relevant sector for sustainable development. We intend to grow our business through the development and construction of projects including expansion and repowering opportunities, as well as greenfield developments, third-party acquisitions and the optimization of our existing portfolio. We currently have a pipeline of assets under development of approximately 2.2 GW of renewable energy and 6.0 GWh of storage. For a detailed discussion, please see “Item 4—Information on the Company—Business Overview—Overview” and “Item 4—Information on the Company—Business Overview—Our Business Strategy”.
Significant Events in 2023
Assets that Entered into Operation
During 2023, four assets that were under construction entered into operation:
| • | Albisu, the 10 MW PV asset wholly owned by us reached COD in January 2023. Albisu is located in Uruguay and has a 15-year PPA with Montevideo Refrescos, S.R.L., a subsidiary of Coca-Cola Femsa, S.A.B. de C.V. The PPA is denominated in local currency with a maximum and minimum price in U.S. dollars and is adjusted monthly based on a formula referring to the U.S. Producer Price Index (PPI), Uruguay’s Consumer Price Index (CPI) and the applicable UYU/U.S. dollar exchange rate. |
| • | La Tolua and Tierra Linda are two wholly owned solar PV assets in Colombia with a combined capacity of 30 MW both of which reached COD in the first quarter of 2023. Each plant has a 10-year PPA in local currency with Coenersa, the largest independent electricity wholesaler in Colombia. Each PPA provides for the sale of electricity at fixed base price indexed to local CPI. |
| • | Honda 1, a 10 MW PV asset in Colombia reached COD in December 2023. Honda 1 is a 10 MW plant where we have a 50% ownership. The asset has a 7-year PPA with Enel Colombia, a major electricity company in the country. The PPA is denominated in local currency, with fixed base price, indexed to the local CPI. |
Assets Under Construction
We currently have the following assets under construction.
Asset | Type | Location | Capacity (gross)1 | Expected COD | Expected Investment3 ($ million) | Off-taker |
| Coso Batteries 1 | Battery Storage | California, US | 100 MWh | 2025 | 40-50 | Investment grade utility |
| Coso Batteries 2 | Battery Storage | California, US | 80 MWh | 2025 | 35-45 | Investment grade utility |
Chile PMGD(2) | Solar PV | Chile | 80 MW | 2024- 2025 | 30 | Regulated |
| ATN Expansion 3 | Transmission Line | Peru | 2.4 miles 220kV | 2024 | 12 | Conelsur |
| ATS Expansion 1 | Transmission Line | Peru | n.a. (substation) | 2025 | 30 | Republic of Peru |
Honda 2(4) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | Enel Colombia |
Apulo 1(4) | Solar PV | Colombia | 10 MW | 2024 | 5.5 | - |
Notes:
| (1) | Includes nominal capacity on a 100% basis, not considering Atlantica’s ownership |
| (2) | Atlantica owns 49% of the shares, with joint control, in Chile PMGD. Atlantica’s economic rights are expected to be approximately 70% |
| (3) | Corresponds to the expected investment by Atlantica |
| (4) | Atlantica owns 50% of the shares in Honda 2 and Apulo 1 |
We refer to “Item 4- Information on the Company – B. Business Overview – Assets under Construction” for a description of each of the assets under construction in the table above.
Advanced Projects
| • | In February 2024, we entered into a 15-year busbar PPA with an investment grade utility for Overnight. Overnight is a 150 MW PV project located in California. Under the PPA, Overnight is set to receive a fixed price per MWh, with no basis risk. The project is currently in an advanced development stage. Total investment is anticipated to be within the range of $165 to $185 million. We expect to include storage in a second phase of the project. |
| • | In January 2024, we acquired from Liberty GES two PV projects in advanced development stage in Southern Spain with approximately 90 MW of combined generation capacity. The acquisition of land and interconnection are secured and the process for permits is well advanced. The projects were acquired in exchange for assuming the necessary guarantees, at no additional cost. |
Potential Asset Sale
Our partner in Monterrey initiated a process to sell its 70% stake in the asset. Such process is well advanced and, as part of it, we intend to sell our interest as well under the same terms. The net proceeds to Atlantica are expected to be in the range of $45 to $52 million, after tax. The closing of the transaction is subject to certain conditions precedent. We cannot guarantee that the transaction will finally close.
Project Debt Refinancing
In March 2023, we refinanced the Solaben 2 and Solaben 3 project debt by entering into two green senior euro-denominated loan agreements for the two assets with a syndicate of banks for a total amount of €198.0 million. The new project debt replaced the previous project loans for a similar amount and maturity was extended from December 2030 to June 2037.
In addition, in June 2023 we extended the maturity of the debt for Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 2 & 3 and Solaben 1 & 6 from April 2025 to December 2028 (see “Item 4— Information on the Company— Our Operations —Renewable Energy”).
Operation and Maintenance
In March 2023, we completed the process of transitioning in-house the O&M services for our assets in Spain through the acquisition of the business of an Abengoa subsidiary which was still providing those services to some of our assets.
In addition, in July 2023 we internalized the O&M services for ATN, which were previously performed by Omega Peru. Additionally, the O&M contract for ATS with Omega Peru, which could be terminated every five years was modified and can now be terminated every three years (or two years under certain circumstances) and the contract for ATN2, which was a long-term contract expiring in 2027, was also amended to reflect the same termination provision.
Currently, we perform O&M services with our own personnel for assets representing approximately 74% of our consolidated revenue for the year ended December 31, 2023.
Regulation in Spain.
In June 2023, the final parameters for the year 2023 were published, including a revised assumption for electricity prices for the years 2023, 2024 and 2025. For a detailed discussion please see “Item 4—Information on the Company—Business Overview—Regulation in Spain”.
Strategic Review
On February 21, 2023, Atlantica’s board of directors commenced a process to explore and evaluate potential strategic alternatives that may be available to Atlantica to maximize shareholder value. The Company believes it has attractive growth and other opportunities in front of it and is committed to ensuring it is best positioned to take advantage of those opportunities. The decision has the support of the Company’s largest shareholder, Algonquin. Atlantica expects to continue executing on its existing plans while the review of strategic alternatives is ongoing, including its current growth plan. As of the date of this annual report, the strategic review is ongoing. There is no assurance that any specific transaction will be consummated, or other strategic change will be implemented as a result of this strategic review. See “Cautionary Statements Regarding Forward-Looking Statements” and “Part I, Item 3.D.—Risk Factors” in our Annual Report.
Factors Affecting the Comparability of Our Results of Operations
Investments
The results of operations of Chile TL4, Italy PV 4 and Chile PV 3 have been fully consolidated since January 2022, April 2022 and September 2022, respectively and the results of Albisu, Tierra Linda and La Tolua have been fully consolidated since these assets entered into operation in the first quarter of 2023. For the full year 2023, these investments represented revenues and Adjusted EBITDA of $14.1 million and $10.5 million respectively, which represents an increase of $7.9 million in revenue and $7.6 million in Adjusted EBITDA for the year ended December 31, 2023 with respect to 2022.
Impairment
In 2023, considering that expected electricity prices in Chile over the remaining useful life of Chile PV1 have decreased, we have identified an impairment triggering event, in accordance with IAS 36 (Impairment of Assets). As a result, an impairment test has been performed and resulted in an impairment loss of $16.1 million in 2023 in the line “Depreciation, amortization, and impairment charges”. In 2022, we also recorded an impairment loss of $20.4 million in Chile PV1 and Chile PV2. Our equity interest in Chile PV 1 and Chile PV 2 is 35%. As a result, the impact of the impairment charges in “Profit / (loss) for the year attributable to the parent company” after non-controlling interest was $5.6 million in 2023 and $7.1 million in 2022.
During 2022 we recorded an impairment loss of $41.2 million in Solana with no corresponding triggering event and impairment in 2023.
In addition, IFRS 9 requires impairment provisions to be based on expected credit losses on financial assets rather than on actual credit losses, which affects the concessional assets accounted for as financial assets. For the year 2023 we recorded a decrease in the expected credit loss impairment provision of $13.2 million reflected in the line item “Depreciation, amortization, and impairment charges” and was primarily related to ACT ($10.9 million). In 2022, we recorded an increase in the expected credit loss impairment provision of $6.7 million, also primarily related to ACT ($4.0 million).
Electricity market prices
Total revenues in Spain were stable in 2023 compared to the previous year. In addition to regulated revenue, our solar assets in Spain receive revenue from the sale of electricity at market prices. The average electricity market price captured by our assets was approximately €69.9 per MWh during 2023 compared to approximately €145.3 per MWh during 2022. Revenue from the sale of electricity at current market prices represented $84.3 million during 2023, compared to $142.9 million in 2022. Regulated revenues are revised periodically to reflect, among other things, the difference between expected and actual market prices if the difference is higher than a pre-defined threshold and as a result, we record a provision. We decreased our provision by $3.5 million in 2023, with no cash impact, compared to an increase of $25.3 million in the previous year.
In 2023, we have calculated the provision assuming that the average market price must be corrected using the solar time of day adjustment factor (“coeficiente de apuntamiento”), as it was stated in the regulations published since 2020. This factor, which is 90% for 2023, aims to capture the difference between the daily (24 hours) average market price and the price captured by solar assets. Although the factor is not mentioned in the regulation for 2023, we believe the last order includes a clerical error that we expect is going to be corrected.
On May 12, 2022, remuneration parameters in Spain for the year 2022 were published and became final on December 14, 2022, with a decrease in regulated revenue. In addition, on June 30, 2023, the new parameters were published, including a revised assumption on electricity prices for the years 2023, 2024 and 2025. Revenue from the sale of electricity at market prices net of the incremental market price provision was $84.0 million for the full year 2023, compared to $117.6 million for the full year 2022. This decrease was offset by higher production in 2023.
Additionally, in 2022 we collected revenue from our assets in line with the parameters corresponding to the regulation in place at the beginning of the year 2022, however revenue for the year ended December 31, 2022 was recorded in accordance with the new parameters that became final on December 14, 2022, which were lower. Collections were regularized in the first quarter of 2023.
Exchange rates
We refer to “Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Significant Trends Affecting Results of Operations—Exchange rates” below.
Significant Trends Affecting Results of Operations
Investments and acquisitions
If the recently built assets and the recently closed acquisitions perform as anticipated, we expect these assets to positively impact our results of operations in 2024 and upcoming years.
Solar, wind and geothermal resources
The availability of solar, wind and geothermal resources affects the financial performance of our renewable assets, which may impact our overall financial performance. Due to the variable nature of solar, wind and geothermal resources, we cannot predict future availabilities or potential variances from expected performance levels from quarter to quarter. Based on the extent to which the solar, wind and geothermal resources are not available at expected levels, this could have a negative impact on our results of operations.
Capital markets conditions
The capital markets in general are subject to volatility that is unrelated to the operating performance of companies. Our growth strategy depends on our ability to close acquisitions, which often requires access to debt and equity financing to complete these acquisitions. Fluctuations in capital markets may affect our ability to access this capital through debt or equity financings.
Exchange rates
Our presentation currency and the functional currency of most of our subsidiaries is the U.S. dollar, as most of their revenue and expenses are denominated or linked to U.S. dollars. All our companies located in North America, with the exception of Calgary, with revenue in Canadian dollars, and most of our companies in South America have their revenue and financing contracts signed in or indexed totally or partially to U.S. dollars. Our solar power plants in Europe have their revenue and expenses denominated in euros; Kaxu, our solar plant in South Africa, has its revenue and expenses denominated in South African rand, La Sierpe, La Tolua and Tierra Linda, Honda 1, our solar plants in Colombia, have their revenue and expenses denominated in Colombian pesos and Albisu, our solar plant in Uruguay, has its revenue denominated in Uruguayan pesos, with a maximum and a minimum price in U.S. dollars.
Project financing is typically denominated in the same currency as that of the contracted revenue agreement, which limits our exposure to foreign exchange risk. In addition, we maintain part of our corporate general and administrative expenses and part of our corporate debt in euros which creates a natural hedge for the distributions we receive from our assets in Europe. To further mitigate this exposure, our strategy is to hedge cash distributions from our assets in Europe. We hedge the exchange rate for the net distributions in euros (after deducting interest payments and general and administrative expenses in euros). Through currency options, we have hedged 100% of our euro-denominated net exposure for the next 12 months and 75% of our euro-denominated net exposure for the following 12 months. We expect to continue with this hedging strategy on a rolling basis.
Although we hedge cash-flows in euros, fluctuations in the value of the euro in relation to the U.S. dollar may affect our operating results. For example, revenue in euro-denominated companies could decrease when translated to U.S. dollars at the average foreign exchange rate solely due to a decrease in the average foreign exchange rate, in spite of revenue in the original currency being stable. Fluctuations in the value of the South African rand and Colombian peso with respect to the U.S. dollar may also affect our operating results.
In our discussion of operating results, we have included foreign exchange impacts in our revenue by providing constant currency revenue growth. The constant currency presentation is not a measure recognized under IFRS and excludes the impact of fluctuations in foreign currency exchange rates. We believe providing constant currency information provides valuable supplemental information regarding our results of operations. We calculate constant currency amounts by converting our current period local currency revenue using the prior period foreign currency average exchange rates and comparing these adjusted amounts to our prior period reported results. This calculation may differ from similarly titled measures used by others and, accordingly, the constant currency presentation is not meant to substitute recorded amounts presented in conformity with IFRS as issued by the IASB, nor should such amounts be considered in isolation.
Impacts associated with fluctuations in foreign currency are discussed in more detail under “Item 11—Quantitative and Qualitative Disclosure about Market Risk—Foreign exchange risk.”
Interest rates
We incur significant indebtedness at the corporate and asset level. The interest rate risk arises mainly from indebtedness at variable interest rates. To mitigate interest rate risk, we primarily use long-term interest rate swaps and interest rate options which, in exchange for a fee, offer protection against a rise in interest rates. As of December 31, 2023, approximately 92% of our project debt and close to 94% of our corporate debt either has fixed interest rates or has been hedged with swaps or caps. Nevertheless, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates, which typically bear a spread over EURIBOR or SOFR.
