changes in our revenues and/or cash generation in our assets due to delays in collections from our off-takers, legal disputes regarding contact terms, adjustments contemplated in existing regulation or changes in regulation or taxes in the countries in which we operate, or adverse weather conditions;
other business risks affecting our cash levels;
unfavorable regional, national or global economic and market conditions; and
changes in accounting and financial reporting standards.
As a result of all these factors, we cannot guarantee that we will have sufficient cash generated from operations to pay a specific or increasing level of cash dividends to holders of our shares. Furthermore, holders of our shares should be aware that the amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items.
We are a holding company whose sole material assets consist of our interests in our subsidiaries. We do not have any independent means of generating revenue. We intend to cause our operating subsidiaries to make distributions to us in an amount sufficient to cover our corporate debt service, corporate general and administrative expenses, all applicable taxes payable and dividends, if any, declared by us. To the extent that we need funds for a quarterly cash dividend to holders of our shares or otherwise, and one or more of our operating subsidiaries is restricted from making such distributions under the terms of its financing or other agreements or applicable law and regulations or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition and limit our ability to pay dividends to shareholders. Our project-level financing agreements generally prohibit distributions to us unless certain specific conditions are met, including the satisfaction of financial ratios. The ability of our operating subsidiaries to make distributions could also be limited by legal, regulatory or other restrictions or limitations applicable in the various jurisdictions in which we operate, such as exchange controls or similar matters or corporate law limitations. Our ability to pay dividends on our shares is also limited by restrictions under the Revolving Credit Facility, the 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Senior Notes.
Our cash available for distribution will likely fluctuate from quarter to quarter, in some cases significantly, due to seasonality. See “Item 4.B—Business Overview—Seasonality.” As result, we may reduce the amount of cash we distribute in a particular quarter to establish reserves to fund distributions to shareholders in future periods. If we fail to establish sufficient reserves, we may not be able to maintain our quarterly dividend with a respect to a quarter adversely affected by seasonality.
Dividends to holders of our shares will be paid at the discretion of our Board of Directors. Our Board of Directors may decrease the level of or entirely discontinue payment of dividends. Our Board of Directors may change our dividend policy at any point in time or modify the dividend for specific quarters following prevailing conditions. For a description of additional restrictions and factors that may affect our ability to pay cash dividends, please see “Item 8.A—Consolidated Statements and Other Financial Information—Dividend Policy.”
Future salesdispositions of our shares by Algonquinsubstantial shareholders or its lenders or by other substantial shareholdersthe perception thereof may cause the price of our shares to fall.
The market price of our shares could decline as a result of future sales by Algonquin of its shares in the market, or the perception that these sales could occur. Algonquin is the beneficial owner of approximately 43.5% of our ordinary shares. On November 28, 2018. Liberty GES obtained a secured credit facility in the amount of $306,500,000. Such loan is collateralized through a pledge of most of the Atlantica shares held by a company owned by Algonquin. A collateral shortfall would occur if the quotient of the net obligations, divided by the aggregate collateral share value, greater than or equal 50% of the share closing price of the Atlantica shares in which case the lenders, would have the right to sell Atlantica shares to eliminate the collateral shortfall. If Liberty GES defaulted on any of these financing arrangements, its lenders may foreclose on the shares and sell the shares in the market.
Future salesdispositions 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 salesdispositions 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 January 26, 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 January 2023 Algonquin announced a number of actions, including a plan to divest approximately $1 billion in assets. As one of the assets in Algonquin's portfolio, it is possible that Algonquin may have a potential 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 (i) up to 100.0% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under Algonquin or the Liberty GES ROFO Agreement. If we issue ordinary shares for any other purpose, Algonquin may subscribe in cash for our ordinary shares in a pro rata amount of such Algonquin’s holding in us. The Shareholders Agreement may be terminated or modified in the future. In any case, Algonquin has the right but not the obligation to subscribe for our shares.
Provisions in the UK City Code on Takeovers and Mergers may have anti-takeover effects that could discourage an acquisition of us by others, even if an acquisition would be beneficial to our shareholders.
The UK City Code on Takeovers and Mergers, or the Takeover Code, applies, among other things, to an offer for a public company whose registered office is in the U.K. and whose securities are not admitted to trading on a regulated market in the U.K. if the company is considered by the Panel on Takeovers and Mergers, or the Takeover Panel, to have its place of central management and control in the U.K. This is known as the “residency test.” The test for central management and control under the Takeover Code is different from that used by the UK tax authorities. Under the Takeover Code, the Takeover Panel will determine whether we have our place of central management and control in the United Kingdom by looking at various factors, including the structure of our Board of Directors, the functions of the directors and where they are resident.
If at the time of a takeover offer the Takeover Panel determines that we have our place of central management and control in the U.K., we would be subject to a number of rules and restrictions, including, but not limited to, the following: (1) our ability to enter into deal protection arrangements with a bidder would be extremely limited; (2) we may not, without the approval of our shareholders, be able to perform certain actions that could have the effect of frustrating an offer, such as issuing shares or carrying out acquisitions or disposals; and (3) we would be obliged to provide equality of information to all bona fide competing bidders.
IX.VII. | Risks Related to Taxation |
Changes in our tax position can significantly affect our reported earnings and cash flows.
We have assets in different jurisdictions, which are subject to different tax regimes. Changes in tax regimes such as the reduction or elimination of tax benefits could adversely affect our assets. Limitations on the deductibility of interest expense could adversely affect our ability to deduct the interest we pay on our debt. These and other potential changes in tax laws and regulations could have a material adverse effect on our results and cash flows. In addition, a reduction in corporate tax rates could make investments in renewable projects less attractive to potential tax equity investors, in which case we may not be able to obtain third-party financing on terms as beneficial as in the past, or at all, which could limit our ability to grow our business.
Changes in corporate tax rates and/or other relevant tax laws in the United Kingdom, the United States, Spain, Mexico or the other countries in which our assets are located may have a material impact on our future tax rate and/or our required tax payments. Such changes may include measures enacted in response to the ongoing initiatives in relation to fiscal legislation at an international level, such as the Action Plan on Base Erosion and Profit Shifting of the Organization for Economic Co-operation and Development (“OECD”). The final determination of our tax liability could be different from the forecasted amount, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. Changes to the U.K. controlled foreign company rules or adverse interpretations of them, could have an impact on our future tax rate and/or our required tax payments. With respect to some of our projects, we must meet defined requirements to apply favorable tax treatment, such as lower tax rates or exemptions. We intend to meet these requirements in order to benefit from the favorable tax treatment; however, there can be no assurance that we will be able to comply with all of the necessary requirements in the future, or the requirements could change or be interpreted in another manner, which could give rise to a greater tax liability and which may have a material adverse effect on our business, results of operations, financial condition and cash flows.
In addition, the governments of some countries where we operate including the United States, Spain, Chile, Peru and South Africa, could implement changes to their tax laws and regulations, the content of which are largely uncertain currently. These potential changes to applicable tax laws and regulations could have a negative impact on our financial condition, results of operations and cash flows. Furthermore, tax laws and regulations are subject to interpretation. Our tax returns in each country are subject to inspection and even if we believe that we are complying with all tax laws and regulations in each country, a tax inspector could have a different view, which may result in additional tax liabilities and may have a negative impact on our financial condition, results of operations and cash flows.
In December 2022, the UK government confirmed the increase of the corporation tax rate up 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 addition, asthe government of South Africa approved in 2022 new limitations for tax years ending on or after March 31, 2023. The net interest expense will be limited to 30% of the EBITDA and the NOLs carried forward may only be applied against 80% of taxable income of the corporate income tax. These new limitations may have a negative impact in our cash flows.
As of November 2021, 137 countries agreed to implement the “Two Pillars Solution”, an OECD/ G20 Inclusive Framework initiative, which aims to reform the international taxation policies and ensure that multinational companies pay taxes wherever they operate and generate profits. “Pillar Two” of this initiative generally provides for an effective global minimum corporate tax rate of 15% on profits generated by multinational companies with consolidated revenues of at least €750 million, calculated on a country-by country basis. This minimum tax would be applied on profits in any jurisdiction wherever the effective tax rate, determined on a jurisdictional basis, is below 15%. Any additional tax liability resulting from the application of this minimum tax will be payable by the parent entity of the multinational group to the tax authority in such parent’s country of residence. A framework forThe OECD and its members are still working on the coordinated implementation of the minimum tax is expected to be developed over 2022.tax. Although this initiative is still subject to further developments in the countries where Atlantica operates, if implemented,we operate, it is expected to be in force in the UK and the EU for fiscal years commencing on January 1, 2024. The global minimum tax may have a negative impact on our financial condition, results of operations and cash flows.
Our future tax liability may be greater than expected if we do not use sufficient NOLs to offset our taxable income.
We have NOLs that we can use to offset future taxable income. Based on our current portfolio of assets, which include renewable assets that benefit from an accelerated tax depreciation schedule, and subject to potential tax audits, which may result in income, sales, use or other tax obligations, we do not expect to pay significant taxes in the upcoming years.
Although we expect these NOLs will be available as a future benefit, in the event that they are not generated as expected, or are successfully challenged by the local tax authorities, such as the IRS or HerHis Majesty’s Revenue and Customs among others, by way of a tax audit or otherwise, or are subject to future limitations as discussed below, our ability to realize these benefits may be limited. A reduction in our expected NOLs, a limitation on our ability to use such NOLs or the occurrence of future tax audits may result in a material increase in our estimated future income tax liability and may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our ability to use U.S. NOLs to offset future income may be limited.
We have generated significant NOLs. For purposes of U.S. federal income taxation, NOLs generated on or before December 31, 2017, can generally be carried back two years and carried forward for up to twenty years and can be applied to offset 100% of taxable income in such years. As a result of the CARES Act, NOLs incurred between January 1, 2018, and December 31, 2020 may be carried forward indefinitely and carried back five years. Losses arising after December 31, 2020, cannot be carried back and are subject to limitations on their deductibility that may prevent us from using the NOLs to offset all taxable income in future years.
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 limit further our ability to use net operating loss carryforwards in the United States, which could have a potential adverse effect on cash flows from U.S. assets expected in the future. In 2019, the Internal Revenue Service (“IRS”) issued proposed regulations concerning the calculation of built-in gains and losses under Section 382. After receiving public comments, in May 2022 the IRS announced that they will issue new proposed regulations on calculating built in gains and losses following an ownership change. If the proposed regulations are enacted and depending on its final outcome, these proposed regulationsthey may significantly limit our annual use of pre-ownership change U.S. NOLs in the event a new ownership change occurs after the new rule is in place.
In addition, because we have recorded tax credits for the U.S. tax losses carryforwards in the past, a limit to our ability to use U.S. NOLs could result in writing off tax credits, which could cause a substantial non-cash income tax expense in our financial statements.
If we are a passive foreign investment company for U.S. federal income tax purposes for any taxable year, U.S. Holders of our shares could be subject to adverse U.S. federal income tax consequences.
If we were a PFIC for any taxable year during which a U.S. Holder held our shares, certain adverse U.S. federal income tax consequences may apply to the U.S. Holder. We do not believe that we were a PFIC for our 2021 taxable year and do not expect to be a PFIC for U.S. federal income tax purposes for the current taxable year or in the foreseeable future. The application of the PFIC rules is, however, subject to uncertainty in several respects, and we must make a separate determination after the close of each taxable year as to whether we were a PFIC for such year. PFIC status depends on the composition of a company’s income and assets and the fair market value of its assets (including certain equity investments) from time to time, as well as on the application of complex statutory and regulatory rules that are subject to potentially varying or changing interpretations. Accordingly, there can be no assurance that we will not be considered a PFIC for any taxable year.
If we were a PFIC, U.S. Holders of our shares may be subject to adverse U.S. federal income tax consequences, such as taxation at the highest marginal ordinary income tax rates on capital gains and on certain actual or deemed distributions, interest charges on certain taxes treated as deferred, and additional reporting requirements. See “Item 10.E—Taxation—U.S. Federal Income Tax Considerations—Passive foreign investment company rules.”
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 OFON 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, 17th17th 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 current holdingdate of 43.5%.this annual report, Algonquin owns 42.2% of our shares.
Investments
We refer to “Item 5.Operating5. —Operating and Financial Review and Prospects” for the description of our recent investments. Apart from these investments, there have been no material capital expenditures or divestitures in the last three years.
The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, which can be found at http://www.sec.gov. Our internet address is https://www.atlantica.com/web/en/. The 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.
Recent Developments
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.
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 “Item 3.D—Risk Factors” 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 assets, while creating long-term value for our investors and the rest of our stakeholders. In 2021,2022, our renewable sector represented 77%75% of our revenue with solar energy representing 69%64%. 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 assets in terms of business sector and geographic footprint. Our portfolio consists of 3944 assets with 2,0442,161 MW of aggregate renewable energy installed generation capacity (of which approximately 71%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, 2021,2022, we estimate that our assets had a weighted average remaining contract life of approximately 15 years.14 years3.
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(16) |
| | | | | | | | |
Solana | Renewable (Solar) | 100% | Arizona (USA) | USD | 280 MW | BBB+/A3/BBB+ | 2013 | 22 |
Mojave | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB-/--/BB | 2014 | 18 |
Coso | Renewable (Geothermal) | 100% | California (USA) | USD | 135 MW | Investment grade (14) | 1987/ 1989 | 17 |
Elkhorn Valley | Renewable (Wind) | 49% | Oregon (USA) | USD | 101 MW | BBB/A3/-- | 2007 | 6 |
Prairie Star | Renewable (Wind) | 49% | Minnesota (USA) | USD | 101 MW | --/A3/A- | 2007 | 6 |
Twin Groves II | Renewable (Wind) | 49% | Illinois (USA) | USD | 198 MW | BBB-/Baa2/-- | 2008 | 4 |
Lone Star II | Renewable (Wind) | 49% | Texas (USA) | USD | 196 MW | Not rated | 2008 | 1 |
Chile PV 1 | Renewable (Solar) | 35%(8) | Chile | USD | 55 MW | N/A | 2016 | N/A |
Chile PV 2 | Renewable (Solar) | 35%(8) | Chile | USD | 40 MW | Not rated | 2017 | 9 |
La Sierpe | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2021 | 14 |
Palmatir | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 12 |
Cadonal | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 13 |
Melowind | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2015 | 14 |
Mini-Hydro | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB+/Baa1/BBB | 2012 | 11 |
Solaben 2 & 3 | Renewable (Solar) | 70%(1) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 16/16 |
Solacor 1 & 2 | Renewable (Solar) | 87%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 15/15 |
PS10 & PS20 | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007& 2009 | 10/12 |
Helioenergy 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 15/15 |
Helios 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 15/16 |
Solnova 1, 3 & 4 | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 13/13/14 |
Solaben 1 & 6 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 17/17 |
Seville PV | Renewable (Solar) | 80%(6) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 14 |
Italy PV 1 | Renewable (Solar) | 100% | Italy | Euro | 1.6 MW | BBB/Baa3/BBB | 2010 | 9 |
Italy PV 2 | Renewable (Solar) | 100% | Italy | Euro | 2.1 MW | BBB/Baa3/BBB | 2011 | 9 |
Assets | Type | Ownership | Location | Currency(9) | Capacity (Gross) | Counterparty Credit Ratings(10) | COD* | Contract Years Remaining(17) |
| | | | | | | | |
Solana | Renewable (Solar) | 100% | Arizona (USA) | USD | 280 MW | BBB+/A3/BBB+ | 2013 | 21 |
Mojave | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB-/--/BB | 2014 | 17 |
Coso | Renewable (Geothermal) | 100% | California (USA) | USD | 135 MW | Investment grade (11) | 1987/ 1989 | 16 |
Elkhorn Valley(16) | Renewable (Wind) | 49% | Oregon (USA) | USD | 101 MW | BBB/Baa1/-- | 2007 | 5 |
Prairie Star(16) | Renewable (Wind) | 49% | Minnesota (USA) | USD | 101 MW | --/A3/A- | 2007 | 5 |
Twin Groves II(16) | Renewable (Wind) | 49% | Illinois (USA) | USD | 198 MW | BBB/Baa2/-- | 2008 | 3 |
Lone Star II(16) | Renewable (Wind) | 49% | Texas (USA) | USD | 196 MW | N/A | 2008 | N/A |
Chile PV 1 | Renewable (Solar) | 35%(1) | Chile | USD | 55 MW | N/A | 2016 | N/A |
Chile PV 2 | Renewable (Solar) | 35%(1) | Chile | USD | 40 MW | Not rated | 2017 | 8 |
Chile PV 3 | Renewable (Solar) | 35%(1) | Chile | USD | 73 MW | N/A | 2014 | N/A |
La Sierpe | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2021 | 13 |
La Tolua | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2023 | 10 |
Tierra Linda | Renewable (Solar) | 100% | Colombia | COP | 10 MW | Not rated | 2023 | 10 |
Albisu | Renewable (Solar) | 100% | Uruguay | UYU | 10 MW | Not rated | 2023 | 15 |
Palmatir | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 11 |
Cadonal | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 12 |
Melowind | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2015 | 13 |
Mini-Hydro | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB/Baa1/BBB | 2012 | 10 |
Solaben 2 & 3 | Renewable (Solar) | 70%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 15/15 |
Solacor 1 & 2 | Renewable (Solar) | 87%(3) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 14/14 |
49
3 Calculated as weighted average years remaining as of December 31, 2022 based on CAFD estimates for the 2023-2026 period, including assets that have reached COD before March 1, 2023.
Italy PV3 | Renewable (Solar) | 100% | Italy | Euro | 2.5 MW | BBB/Baa3/BBB | 2012 | 10 | |
PS 10 & PS 20 | | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007& 2009 | 9/11 |
Helioenergy 1 & 2 | | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 14/14 |
Helios 1 & 2 | | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 14/15 |
Solnova 1, 3 & 4 | | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 12/12/13 |
Solaben 1 & 6 | | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 16/16 |
Seville PV | | Renewable (Solar) | 80%(4) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 13 |
Italy PV 1 | | Renewable (Solar) | 100% | Italy | Euro | 1.6 MW | BBB/Baa3/BBB | 2010 | 8 |
Italy PV 2 | | Renewable (Solar) | 100% | Italy | Euro | 2.1 MW | BBB/Baa3/BBB | 2011 | 8 |
Italy PV 3 | | Renewable (Solar) | 100% | Italy | Euro | 2.5 MW | BBB/Baa3/BBB | 2012 | 9 |
Italy PV 4 | | Renewable (Solar) | 100% | Italy | Euro | 3.6 MW | BBB/Baa3/BBB | 2011 | 9 |
Kaxu | Renewable (Solar) | 51%(3) | South Africa | Rand | 100 MW | BB-/Ba2/BB-(11) | 2015 | 13 | Renewable (Solar) | 51%(5) | South Africa | Rand | 100 MW | BB-/Ba2/BB-(13) | 2015 | 12 |
Calgary | Efficient natural gas & Heat | 100% | Canada | CAD | 55 MWt | ~41% A+ or higher(15) | 2010 | 19 | Efficient natural gas & Heat | 100% | Canada | CAD | 55 MWt | ~41% A+ or higher(14) | 2010 | 18 |
ACT | Efficient natural gas & Heat | 100% | Mexico | USD | 300 MW | BBB/ Ba3/BB- | 2013 | 11 | Efficient natural gas & Heat | 100% | Mexico | USD | 300 MW | BBB/ B1/BB- | 2013 | 10 |
Monterrey | Efficient natural gas & Heat | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 17 | Efficient natural gas & Heat | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 23 |
ATN (13) | Transmission line | 100% | Peru | USD | 379 miles | BBB+/Baa1/BBB | 2011 | 19 | Transmission line | 100% | Peru | USD | 379 miles | BBB/Baa1/BBB | 2011 | 18 |
ATS | Transmission line | 100% | Peru | USD | 569 miles | BBB+/Baa1/BBB | 2014 | 22 | Transmission line | 100% | Peru | USD | 569 miles | BBB/Baa1/BBB | 2014 | 21 |
ATN 2 | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 11 | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 10 |
Quadra 1 & 2 | Transmission line | 100% | Chile | USD | 49 miles/ 32 miles | Not rated | 2014 | 13/13 | Transmission line | 100% | Chile | USD | 49 miles/ 32 miles | Not rated | 2013-2014 | 12/12 |
Palmucho | Transmission line | 100% | Chile | USD | 6 miles | BBB/-/A- | 2007 | 16 | Transmission line | 100% | Chile | USD | 6 miles | BBB/-/BBB+ | 2007 | 15 |
Chile TL3 | Transmission line | 100% | Chile | USD | 50 miles | A/A1/A- | 1993 | Regulated | |
Chile TL4 | Transmission line | 100% | Chile | USD | 63 miles | Not rated | 2016 | 50 | |
Chile TL 3 | | Transmission line | 100% | Chile | USD | 50 miles | A/A2/A- | 1993 | N/A |
Chile TL 4 | | Transmission line | 100% | Chile | USD | 63 miles | Not rated | 2016 | 49 |
Skikda | Water | 34.2%(4) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 12 | Water | 34.2%(6) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 11 |
Honaine | Water | 25.5%(5) | Algeria | USD | 7 M ft3/day | Not rated | 2012 | 16 | Water | 25.5%(7) | Algeria | USD | 7 M ft3/day | Not rated | 2012 | 15 |
Tenes | Water | 51%(7) | Algeria | USD | 7 M ft3/day | Not rated | 2015 | 18 | Water | 51%(8) | Algeria | USD | 7 M ft3/day | Not rated | 2015 | 17 |
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 botheach of Solaben 2 and Solaben 3. |
(2)(3) | JGC holds 13% of the shares in each of Solacor 1 and Solacor 2. |
(3)(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 (29%(“IDC”, 29%) and Kaxu Community Trust (20%). |
(4)(6) | Algerian Energy Company, SPA owns 49% of Skikda and Sacyr Agua, S.L. .(“Sacyr”) owns the remaining 16.8%. Atlantica has control over it under IFRS 10, Consolidated Financial Statements. |
(5)(7) | Algerian Energy Company, SPA owns 49% of Honaine and Sacyr Agua, S.L. owns the remaining 25.5%. |
(6)(8) | Instituto para la Diversificación y Ahorro de la Energía, holds 20% of the shares in Seville PV.
|
(7) | Algerian Energy Company, SPA owns 49% of Tenes. 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. |
(8) | 65% of the shares in Chile PV 1 and Chile PV 2 are held by financial partners at our renewable energy platform in Chile.
|
(9) | Certain contracts denominated in U.S. dollars are payable in local currency. |
(10) | Reflects the counterparty’s credit ratings issued by Standard & Poor’s Ratings Services, or S&P, Moody’s Investors Service Inc., or Moody’s, and Fitch Ratings Ltd, or Fitch. Not applicable (“N/A”) when the asset has no PPA. |
(11) | Refers to the credit rating of the Republic of South Africa. The offtaker is Eskom, which is a state-owned utility company in South Africa.
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(12) | Refers to the credit rating of Uruguay, as UTE (Administración Nacional de Usinas y Transmisoras Eléctricas) is unrated.
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(13) | Including the acquisition of ATN Expansion 1 & 2.
|
(14) | Refers to the credit rating of two Community Choice Aggregators: Silicon Valley Clean Energy and Monterrey Bar Community Power, both with A Rating from S&P and Southern California Public Power Authority. The third off-taker is not rated. |
(15)(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 (~41%A+ rating or higher, the rest is unrated). |
(15) | Including ATN Expansion 1 & 2. |
(16) | Part of Vento II portfolio.
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(17) | As of December 31, 2021.2022. |
(*) | Commercial Operation Date. |
Our Business Strategy
Our strategy focuses on climate change solutions in the power and water sectors. We intend to provide clean electricity, transmission capacity and desalinated water in a safe, reliable and environmentally responsible way. We believe our value creation capability is significantly enhanced by investing in sustainable sectors and managing our assets in a sustainable manner to the benefit of our shareholders and other stakeholders.
We intend to take advantage of, and leverage our growth strategy on, favorable trends in clean power generation, energy scarcity and the global focus on the reduction of carbon emissions. We believe that we are well positioned to benefit from the expected transition towards a more sustainable power generation mix in our markets. In addition, we believe that water is going to be the next frontier in a transition towards a more sustainable world.
We seek to grow our cash available for distribution and our dividends to shareholders through organic growth and by investing in new assets, while ensuring the ongoing stability and sustainability of our business. We intend to grow our business maintaining renewable energy as our main segment with a primary focus on North America and Europe.
We believe we can achieve organic growth through the optimization of the existing portfolio, escalation factors at many of our assets,as well as the repowering and hybridization with other technologies of some of the renewable energy facilities and the expansion of our existing transmission lines.
Additionally, we expect to acquire assets from third parties leveraging the local presence and network we have in geographies and sectors in which we operate. We will also continue to investinvesting in the development and construction of new assets, in some cases on our own and in other cases with partners. We have entered into and intend to continue to enter into agreements or partnerships with developersdevelopers.
We also expect to acquire assets from third parties leveraging the local presence and asset owners.network we have in geographies and sectors in which we operate.
Our plan for executing this strategy includes the following key components:
Focus on stable assets in the power and water sectors, including renewable energy, storage, efficient natural gas and heat, transmission assets as well as water assets, generally contracted or regulated.
We intend to focus on owning and operating stable, sustainable infrastructuresinfrastructure 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, and Europe, helps to ensure exposure to markets in which we believe renewable energy, storage and transmission will continue to grow significantly. We believe that our diversification by business sector and geography provides us with access to different sources of growth.
Grow our business through the optimization of the existing portfolio and through the investments in the expansion of our current assets.
We intend to grow our business through organic growth that we expect to deliver through the optimization of the existing portfolio, price escalation factors in many of our assets as well as through investments in the expansion and repowering of our current assets and hybridization of existing assets with other complimentarycomplementary technologies including storage, particularly in our transmission lines and renewable energy assets.assets and transmission lines.
Grow our business by developing new projects and investing in new assets in the business sectors where we are present.
We will seek to grow our business by investing in new assets, generally totally or partially contracted or regulated. We intend to develop new assets and in some cases to invest in assets under development or construction either directly or with partners. We currently own a pipeline of assets under development and construction in North America, Europe and South America with approximately 2.0 GW of renewable energy projects and approximately 5.6 GWh of storage projects under development4. We also expect to acquire assets from third parties leveraging the local presence and network we have in the geographies and sectors in which we operate. We have also entered into and intend to enter into agreements or partnerships with developers or asset owners to develop or acquire assets. We also invest in assets under development or construction either directly or with partners via investment vehicles. We believe that our know-how and operating expertise in our key markets together with a critical mass of assets in several geographic areas as well as our access to capital provided by being a listed company will assist us in achieving our growth plans.
Foster a low-risk approach
We intend to maintain a portfolio of sustainable infrastructure assets, generally totally or partially contracted, assets with a low-risk profile for a significant part of our revenue. A large majority of our revenue is contracted or regulated. We generally seek to invest generally in assets with proven technologies in which we generally have significant experience, located in countries where we believe conditions to be stable and safe. We may complement our portfolio with investments or co-investments in assets with shorter contracts or with partially contracted or merchant revenue or in assets with revenue in currencies other than the U.S. dollar or euro. We also invest in assets under development or construction either directly or with partners via investment vehicles.
Additionally, our policies and management systems include thorough risk analysis and risk management processes applied on an ongoing basis from the date of asset acquisition.basis. Our policy is to insure all of our assets whenever economically feasible, retaining in some cases part of the risk in house.
4 Only includes projects estimated to be ready to build before or in 2030 of approximately 3.3 GW, 2.0 GW (gross) of renewable energy and 1.3 GW (gross) of storage (equivalent to 5.6 GWh). Gross capacity measured by multiplying the size of each project by Atlantica’s ownership. Potential expansions of transmission lines not included.
Maintain a prudent financial policy and financial flexibility
Non-recourse project debt is an important principle for us. We intend to continue financing our assets with project debt progressively amortized using the cash flows from each asset and where lenders do not have recourse to the holding company assets. The majority of our consolidated debt is project debt.
In addition, we hedge a significant portion of our interest rate risk exposure. We estimate that as of December 31, 2021,2022, approximately 92%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. TheWe estimate that the off-take agreements or regulation in place at our assets have a weighted average remaining term of approximately 15145 years as of December 31, 2021,2022, providing long-term cash flow visibility. In 2021,2022, approximately 58%51% of our revenue was non-dependent on natural resource, not subject to the volatility that natural resource may have, especially solar and wind resource.resources. This includes our transmission lines, our efficient natural gas plant, our water assets and approximately 77%76% of the revenue received from our solar assets in Spain.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 ininto a more stable cash-flow generation. Going forward, our new investments will probably be dependent on the natural resource. Additionally, our facilities have minimal or no fuel risk.
Our diversification by geography and business sector also strengthens the stability of our cash flow generation. We expect our well-diversified asset portfolio, in terms of business sector and geography to maintain cash flow stability.
Furthermore, due to the fact that we are a U.K. registered company, we should benefit from a more favorable treatment than if we were a corporation based in the U.S. when receiving dividends from our subsidiaries that hold our international assets because they should generally be exempt from U.K. taxation due to the U.K.’s distribution exemption. Based on our current portfolio of assets, which includes renewable assets that benefit from an accelerated tax depreciation schedule, and tax regulations benefits permitted in the jurisdictions in which we operate, under current regulations we do not expect to pay significant income tax in the upcoming years in most of our geographies due to existing net operating losses, or NOLs. See “Item 3.D—Risk Factors—Risks Related to Taxation—Our future tax liability may be greater than expected if we do not use sufficient NOLs sufficient to offset our taxable income,” “Item 3.D—Risk Factors—Risks Related to Taxation—Our ability to use U.S. NOLs to offset future income may be limited” and “Item 3.D—Risk Factors—Risks Related to Taxation—Changes in our tax position can significantly affect our reported earnings and cash flows.” Furthermore, based on our existing portfolio of assets, we believe that there is limited repatriation risk in the jurisdictions in which we operate. See “Item 3.D—Risk Factors—Risks Related to Our Business and the Markets in Which We Operate—We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.”
5 Calculated as weighted average years remaining as of December 31, 2022 based on CAFD estimates for the 2023-2026 period, including assets that have reached COD before March 1, 2023.
Positioned in business sectors with high growth prospects
The renewable energy industry has grown significantly in recent years and it is expected to continue to grow in the coming decades. According to Bloomberg New Energy Finance 2021,2022, renewable energy is expected to account for the majority of new investments in the power sector in most markets. In Bloomberg’s greeneconomic transition scenario, approximately 1,400 GW22.9 TW of renewables will be added every year for the next three decades.new capacity additions are expected by 2050. Solar PV, seeswind and battery storage see the largest deployment with 16.519.5 TW, installed by 2050. Requiredcollectively capturing 85% of this new power capacity. Total required investment in energy supply and infrastructure amounts to between $92 trillion and $173 trillion over the next three decades.decades tops $119 trillion. To achieve this, annual investment will need to more than double from around $1.7$2.0 trillion, to somewhere between $3.1 trillion and $5.8 trillion per year.$4.1 trillion.
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 narrownarrower geographic or technological focus. If certain geographies and business sectors become more competitive for asset acquisitionsinvestments 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
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. In addition, we have in-house development capabilities and partnerships with third parties to co-develop new projects.
Well positioned in ESG
In 2021, 73%2022, 74% of our Adjusted EBITDA was derived from renewable energy and 64%62% of our Adjusted EBITDA corresponded to solar energy production. Adjusted EBITDA from low carbon footprint assets represented 87.9%89.4%, including renewable energy, transmission infrastructure, as well as water assets. We have set a target to maintain over 80% of our Adjusted EBITDA generated from low-carbon footprint assets.
In addition, we have set a target to reduce our scope 1 and scope 2 GHG emissions per unit of energy generated16by 70% by 2035, with 2020 as base year. This target has beenwas validated in 2021 by the Science Based Targets initiative in 2021.initiative.
In terms of governance, we maintain a simple structure with one class of shares. The majority of our Directors are independent, and all the board committees are formed exclusively by independent directors. In 2021, the Board updated and /or issued, as applicable, several key ESG related documents following our long-term strategy. 25%22% of our directors are women.
We have been rated by various ESG rating agencies, which we believe can provide relevant information for investors.
1
6 Including thermal generation.
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 onin October 9, 2013.
PPA.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 on-going performance obligations. The PPA expires in October 2043.
O&M. ASI Operations, one ofWe perform O&M for Solana with our subsidiaries, provides O&M services for Solana.own personnel.
Operations.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 steam generator,heat exchangers, the water plant, and the storage system.system and more recently the solar field. In 2021 and 2022, availability in the storage system was lower than expected due to the improvementsrepairs and replacements that we arehave been carrying out after certain leaks were identified in the first quarter of 2020.out. These works have impacted production in 2021 and are expected to2022 and may impact production in 2022 as we are experiencing delays due to COVID-19 restrictions and delays from subcontractors. We expect to fund these works with a cash repair reserve account funded at the asset level.2023.
Project Level Financing.Financing. Solana received a loan from the FFBFederal Financing Bank (“FFB”) in December 2010, with a guarantee from the DOE. The long-term trancheFFB loan is payable over a 29-year term and has an average fixed interest rate of 3.69%. The principal balance was $742 million asAs of December 31, 2021.2022, the outstanding balance of the loan was $722.8 million. The FFB loan permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.2x.
Partnerships. On August 17, 2020, we closed the acquisition of the Liberty Interactive Ownership Interest in Solana. Liberty Interactive was a tax equity investor in the asset. Since then, we are the sole owner of the asset.
Mojave
Overview. Mojave is a 250 MW net (280 MW gross) solar plant wholly-owned by us located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Mojave relies on a conventional parabolic trough solar power system to generate electricity. Mojave reached COD in December 2014.
PPA.PPA. Mojave has a 25-year, fixed-price PPA with Pacific Gas & Electric Company, or PG&E, for 100% of the output of Mojave which began on COD. The PPA provides for the sale of electricity at a fixed base price with seasonal adjustments and adjustments for time of delivery. Mojave can deliver and receive payment for at least 110% of contracted capacity under the PPA. The PPA expires in 2039.
O&M. We perform O&M services for Mojave.Mojave with our own personnel.
Project Level Financing. Mojave received a loan from the Federal Financing Bank (the “FFB”)FFB in September 2011, with a guarantee from the DOE, whichDOE. The FFB loan is payable over a 25-year term. The FFB loanterm and has an average fixed interest rate of 2.75%. The principal balance of this tranche was $639 million asAs of December 31, 2021.2022, the outstanding balance of the loan was $605.4 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 signed 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 Monterrey Bay Community Power, both with an “A” credit rating from S&P Global Rating (“S&P”).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.
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A PPA for approximately 15% of the revenues until 2026, 40% from 2027 until 2036 and 50% from 2037 until 2041 with Southern California Public Power Authority (“SCPPA”), which is not rated.
O&M. Operation and maintenance is performed in-house, with the same team providing these services before the acquisition by Atlantica.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 areis progressively repaid following a theoretical 2036 maturity, with a legal maturity in 2027. The remaining $140 million are expected to be refinanced on or before 2027. Interest has been hedged until 2027 such that the total annual interest rate is 2.985%2.99% until 2027. As of December 31, 2021,2022, the outstanding amountbalance of the loan was $214$200.9 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, although we may raise some non-recourse debt at an intermediate holding subsidiary.debt. Operation and maintenance services are provided by EDP RenováveisRenewables North America (“EDPR”) for the four assets.
Elkhorn Valley
Overview. Elkhorn Valley is a 101 MW wind asset in Union County, Oregon, which entered into operation in November 2007.
PPA. Elkhorn Valley has a PPA with Idaho Power Company at a fixed price, expiring in December 2027. Base price increases annually with a 3% escalation factor.
Prairie Star
Overview. Prairie Star is a 101 MW wind asset in Filmore County, Minnesota, which entered into operation in December 2007.
PPA. Prairie Star has a PPA with Great River Energy. The PPA expires in December 2027 with the option to extend it until 2036.
Twin Groves II
Overview. Twin Groves II is a 198 MW wind asset in McLean County, Illinois, which entered into operation in March 2008.
PPA. Twin Groves II has a PPA with Exelon Generation Co LLC at a fixed price, expiring in March 2026.
Lone Star II
Overview. Lone Star II is a 196 MW wind asset in Albany, Texas, which entered into operation in May 2008.
PPA. Lone Star II hashad a PPA with EDPR North America, LLC at a fixed price expiringthat expired in January 2023. Our expectation is that the asset could enter into shorter PPAs or hedge agreements once the current PPA is over and we will evaluate togetherTogether 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 the asset in the future.asset.
Chile PV 1, Chile PV 2 and Chile PV 23
In April 2020 we made an investment in the creation of a renewable energy platform in Chile, together with financial partners, where we now own approximately a 35% stake and have a strategic investor role. The platform intends to make further investments in renewable energy in Chile and sign PPAs with credit-worthy off-takers.
Overview:Overview. Chile PV 1, Chile PV 2 and Chile PV 23 are twothree solar plants with 55 MW, 40 MW, and 4073 MW, respectively. Chile PV 1 reached COD in May 2016, and Chile PV 2 reached COD in 2017.August 2017 and Chile PV 3 reached COD in December 2014.
PPA: PPA. Chile PV 1 sells itsand Chile PV 3 sell their production to the Chilean power market. Chile PV 2 has PPAs signed for part of its production.
O&M:&M. Chile PV 1, Chile PV 2 and Chile PV 23 have O&M agreements with third parties.
Project Level Financing: The renewable energy platform hasFinancing. Two of the three assets have long-term project finance agreements in place in US$,U.S. dollars, with ana total outstanding amountbalance of $77$72.0 million as of December 31, 2021.2022. Payments are made semi-annually. The debt bearsagreements bear interest based on six-month LIBOR and more than 75% has been hedged. The financing arrangements permit dividend distributions at least once per year subject to meeting the debt service coverage ratios required by contract.
La Sierpe
Overview: Overview. La Sierpe is a 20 MW solar PV plant in Colombia, wholly owned by us, which reached COD in lateOctober 2021.
PPA: PPA. La Sierpe has a 15-year, fixed-price PPA in local currency with Synermin,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 (the “CPI”).Index.
O&M:&M. We perform O&M agreementfor La Sierpe with a third party under a 10-year fixed price agreement indexed to local CPI We are currently negotiating a potential termination of this agreement in order to internalize the O&M.our own personnel.
Project Level Financing: theFinancing. 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. La Tolua has an O&M agreement in place with a third party.
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. Tierra Linda 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 Tacuarembo, 170 miles north of the city of Montevideo, Uruguay. Palmatir has 25 wind turbines supplied by Siemens, and each turbine has a nominal capacity of 2 MW. The plant reached COD in May 2014.
PPA.PPA. Palmatir signed a PPA with UTE in September 2011 for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and will beis partially adjusted annually based on a formula referring to U.S. CPI,PPI, Uruguay’s CPIPPI and the applicable UYU/U.S. dollar exchange rate.
O&M.&M. We perform O&M with our own personnel, and we have a turbinewind 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.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 the project, denominated in USD.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 $40$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. LIBOR plus 4.125%, which was 80% hedged with a swap at a rate of 2.22%4.13%. The combined principaloutstanding balance of boththe three tranches as of December 31, 20212022 was $77$72.0 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.PPA. Cadonal signed a PPA with UTE on December 28, 2012, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted annually based on a formula referring to U.S. CPI,PPI, Uruguay’s CPIPPI and the applicable UYU/U.S. dollar exchange rate.
O&M.&M. We perform O&M with our own personnel, and we have a turbinewind 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:million and in March 2022 we prepaid $12.3 million, resulting in a loan principal comprised of:
| − | Tranche A is a $36.0A: $29.7 million loan with maturity in 2034 and a floating interest rate of six-month LIBOR plus 2.9%, 81% hedged with a swap set at approximately 3.29% strike. |
| − | Tranche B is a $33.5B: $21.1 million loan with maturity in 2032 and a floating interest rate of six-month LIBOR plus 2.65%, 81%99% hedged with a swap set at approximately 3.16% strike. |
| − | Subordinated tranche for $8.1 million with maturity in 2034 and a floating interest rate of six-month LIBOR plus 5.5%.
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The combined principaloutstanding balance of these loans was $60 milliontwo tranches as of December 31, 2021. 2022 was $46.6 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 and a total debt service coverage ratio for the previous twelve-month period being at least 1.10x.
Melowind
Overview. Melowind is an onshore, 50 MW wind farm facility wholly owned by us, located in Cerro Largo, 200 miles north of the city of Montevideo, Uruguay. Melowind has 20 wind turbines supplied by Nordex, each with a capacity of 2.5 MW. The asset reached COD in November 2015.
PPA.PPA. Melowind signed a PPA with UTE in August 2021,2012, 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. CPI,PPI, Uruguay’s CPIPPI and the applicable UYU/U.S. dollar exchange rate.
O&M.&M. We perform O&M with our own personnel, and we have a turbinewind turbines O&M agreement with Nordex that covers scheduled and unscheduled turbine maintenance.
Project Level Financing.Financing. On December 13, 2018, Melowind entered into a financing agreement payable over a period of 16 years. The financing consists of a $76 million loan with a floating interest rate based on six-month LIBOR plus a margin of 2.25% until December 2021, 2.5% from January 2022 to December 2024, 2.75% from January 2025 to December 2027 and 3.0% from January 2028 to December 2034. LIBOR exposure was 75% hedged with a swap at a rate of 3.26% with the financing bank. As of December 31, 2021,2022, the outstanding amountbalance of the loan was $71$68.6 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.Agreement. It has a 20-year fixed-price concession agreement denominated in U.S. dollars with the Peruvian Ministry of Energy of Peruand Mines and the price is adjusted annually in accordance with the U.S. Consumer Price Index.Finished Goods Less Foods and Energy Index as published by the U.S. Department of Labor.
O&M. We perform O&M. The operation and maintenance services are performed internally. for Mini-hydro Peru with our own personnel.
Project Level Financing.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 PS10PS 10 & 20 (which is a 31 MW solar power complex). Except for PS10PS 10 & PS20PS 20 and SevillaSeville 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. We perform O&M for Solaben 2 & 3, Solaben 1 & 6, Helioenergy 1 & 2 and Seville PV with our own personnel, and Abengoa performs O&M for Solacor 1 & 2, PS 10 & 20, Helios 1 & 2 and Solnova 1, 3 & 4. As of the date of this annual report, we are in the process of transitioning the operation and maintenance services for those assets in Spain where Abengoa performs the O&M services, are provided byfrom an Abengoa through all-in contracts, except for Seville PV, where O&M services are provided bysubsidiary to a different third party. In February 2022, we reached an agreement with Abengoa, subject to conditions precedent, including waivers from financial institutions, to terminate the O&M agreements in six plants in Spain and to introduce a clause to be able to terminate the rest of the agreements every three years. If and when the conditions precedent are met, we would perform the O&M for the six plants we would be terminating with third parties or internal resources.Company’s subsidiary.
These assets benefit from the tax accelerated depreciation regime established by the Spanish Corporate Income Tax Act.
Solaben 2 & 3
Overview. Solaben 2 and Solaben 3 are two 50 MW solar plants located in Extremadura, Spain. Atlantica owns 70% of each asset and Itochu, a Japanese trading company, owns the remaining 30%. The assets reached COD in 2012.June and October 2012, respectively.
O&M. Abengoa provides currently&M. We perform O&M services under an all-in contract that we could terminate every three years.for Solaben 2 & 3 with our own personnel since June 2022.
Project Level Financing.Financing. In December 2010, Solaben 2 and Solaben 3 each entered into a euro denominated 20-year loan agreement with a syndicate of banks. The loan for Solaben 2 was for €169.3 million and the loan for Solaben 3 was for €171.5 million. The interest rate for each loan is a floating rate based on six-month EURIBOR plus a margin of 1.5%. We hedged our EURIBOR exposure:
| − | 40% through a swap set at approximately 3.7% for the duration of the loans. |
| − | 60% through a cap set at approximately 1% until 2025. From January 2026, 40% through a cap with approximately 3.75% strike price for the duration of the loans. |
The outstanding amountbalance of these loans as of December 31, 20212022 was $118$100.2 million for Solaben 2 and $120$102.4 million for Solaben 3. The financing arrangements permit cash distributiondistributions to shareholders twice per year if the debt service coverage ratio is at least 1.10x.
In addition, on April 8, 2020, Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 2 & 3 and Solaben 1 & 6 entered into the Green Project Finance with ING Bank, B.V. and Banco Santander S.A. The facility is a green project financing euro-denominated agreement that has a notional of €140 million of which 25% is progressively amortized over its 5-yearfive-year term and the remaining 75% is expected to be refinanced at maturity. The Green Project Finance is guaranteed by the shares of Logrosan and its lenders have no recourse to Atlantica corporate level. Interest accrue at a rate per annum equal to the sum of 6-month EURIBOR plus a margin of 3.25% and we hedged the EURIBOR with a 0% cap for the total amount and the entire life of the loan. The outstanding amountbalance of this facility as of December 31, 2021,2022, was $145$127.5 million. The Green Project Finance permits cash distribution to shareholders twice per year if Logrosan sub-holding company debt service coverage ratio is at least 1.20x and the debt service coverage ratio of the sub-consolidated group of Logrosan and the Solaben 1 & 6 and Solaben 2 & 3 assets is at least 1.075x.
Solacor 1 & 2
Overview. Solacor 1 and Solacor& 2 are two 50 MW solar plants located in Andalusia, Spain. Atlantica owns 87% and JGC Corporation, a Japanese engineering company, holds the remaining 13%. The assets reached COD in 2012.February and March 2012, respectively.
O&M.&M. Abengoa currently provides currently O&M services under an all-in contract thatcontract. As of the date of this annual report, we could terminate every three years.
Project Level Financing. In August 2010,are in the process of transitioning the O&M services of Solacor 1 & 2 entered into 20-yearfrom an Abengoa subsidiary to a Company’s subsidiary.
Project Level Financing. In October 2022, we refinanced Solacor 1 & 2 project debt. The new financing is a green euro-denominated loan agreements with a syndicate of banks for a total amount of €353 million. The interest€205.0 million with maturity in 2037. Interest accrue at a rate forper annum equal to the loans is a floating rate based onsum of six-month EURIBOR plus a margin of 1.5%.1.50% between 2022-2027, 1.60% between 2027-2032 and 1.70% between 2032-2037. We hedgehedged our EURIBOR exposure:
| − | 53%71% through a swap set at approximately 3.20%2.36% for the life of the financing.
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| − | 28% through a cap with a 3.25%19% by maintaining the existing 1% strike for the life of the financing.
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| − | In addition, we contracted caps with a 1% strike covering 19.3% of the principal of Solacor 1 and 18.2% of the principal of Solacor 2. Both caps hedge the interest rate throughmaturity in 2025.
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The total outstanding amountbalance of these loansthis loan as of December 31, 20212022 was $234$212.8 million. TheseThis financing arrangements permitarrangement permits cash distribution to shareholders twice per year if the debt service coverage ratio is at least 1.10x.1.15x.
PS10The 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. PS10 PS 10 & 20 is a 31 MW solar complex wholly owned by us located in Andalusia, Spain. PS10PS 10 reached COD in 2007 and PS20PS 20 reached COD in 2009.
O&M.&M. Abengoa provides currently O&M services throughunder an all-in contract. As of the date of this annual report, we are in the process of transitioning the O&M services of PS 10 & 20 from an Abengoa subsidiary to a 21-year all-in contract.Company’s subsidiary.
Project Level Financing.Financing. The asset has no project finance debt. In 2006, PS20 entered into a 24.5-year loan agreement respectively, whichNovember 2022, we repaid in full the project finance that was subsequently increased in 2007 to €94.6 million. The interest rate placefor PS20 loan is a floating rate based on six-month EURIBOR plus a margin of 1.0% to 1.10% (depending on the level of the debt service coverage ratio). We hedged 100% of our EURIBOR exposure for the life of the financing:
| − | 30% through a swap set at approximately 4.07%
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| − | 70% through a cap set at approximately 1% and 4,5% until 2025
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| − | From January 2026 70% through a cap with a 4.5% strike
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The outstanding amount of the PS20 loan as of December 31, 2021 was $56 million. This financing arrangement permit cash distribution to shareholders once per year if the debt service coverage ratio is at least 1.10x.
Helios 1 & 2
Overview. Helios 1 and Helios 2 are two 50 MW solar plants wholly owned by us located in Castilla laCastilla-La Mancha, Spain. The assets reached COD in 2012.March and June 2012, respectively.
O&M.&M. Abengoa provides currently O&M services throughunder an all-in contract. As of the date of this annual report, we are in the process of transitioning the O&M services of Helios 1 & 2 from an Abengoa subsidiary to a 25-year all-in contract.Company’s subsidiary.
Project Level Financing.Financing. On July 14, 2020, we refinanced Helios 1 & 2. We entered into a senior secured note facility with a group of institutional investors as purchasers of the notes issued thereunder for a total amount of €325.6 million ($370.2 million approximately). The notes were issued on July 23, 2020 and have a 17-year maturity. Interest accrueaccrues at a fixed rate per annum equal to 1.90%. Debt repayment is semiannual over the 17-year tenor of the debt. The outstanding amountbalance of the debt as of December 31, 20212022 was $327$290.8 million. The note facility permits cash distributions to shareholders twice per year if the debt service coverage ratio is at least 1.15x.
Helioenergy 1 & 2
Overview. Helioenergy 1 and Helioenergy 2 are two 50 MW solar plants wholly owned by us located in Andalusia, Spain. They reached COD in 2011.April and August 2011, respectively.
O&M. Abengoa provides currently&M. We perform O&M services through a 20-year all-in contract.for Helioenergy 1 & 2 with our own personnel since June 2022.
Project Level Financing.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 amountbalance of these loans as of December 31, 20212022 was $273$243.5 million. The financing arrangements permit cash distributions to shareholders semi-annually based on a debt service coverage ratio of at least 1.15x.
Solnova 1, 3 & 4
Overview. Solnova 1, Solnova 3 and Solnova 4 are three 50 MW solar plants wholly owned by us located in Andalusia, Spain, in the same complex as PS-10 and PS-20. Solnova 1, 3 & 4 projects reached COD in 2010.February, June, and July 2010, respectively.
O&M.&M. Abengoa provides currently O&M services throughunder an all-in contract. As of the date of this annual report, we are in the process of transitioning the O&M services of Solnova 1, 3 & 4 from an Abengoa subsidiary to a 25-year all-in contract.Company’s subsidiary.
Project Level Financing.Financing. In December 2007,2022 we refinanced Solnova 1, 3 & 4. We entered into a 22-yeargreen senior euro-denominated loan agreement for €233.4 millionthe three assets with a syndicate of banks. 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 isaccrues at a floating rate based onper annum equal to the sum of six-month EURIBOR plus a margin in the range of 1.15% up to 1.25%, depending on the debt service coverage ratio.1.50% between 2023-2027, 1.65% between 2028-2032 and 1.80% from 2033 onwards. The principal is hedged: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. |
− | 78% through a swap set at approximately 4.76% strike until 2027.
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| − | 22% through a cap with a 1%1.0% strike covering the principal throughwith initial notional of €134.2 million starting in December 2022 and decreasing over time until December 2025.
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In January 2008, Solnova 3 entered into a 22-year loan agreement for €227.5 million with a syndicate of banks. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin in the range from 1.15% up to 1.25%, depending on the debt service coverage ratio. The principal is hedged:
| − | 23% through a swap set at approximately 4.34% strike for the life of the debt.
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| − | 77% through a cap with a 1%2.0% strike covering the principal through 2025. with initial notional of €64.9 million starting June 2026 and decreasing over time until December 2030. |
In August 2008, Solnova 4 entered intoThe financing agreement also includes a 22-year loan agreement for €217.1 million withmechanism under which, in the case that electricity market prices are above certain levels defined in the contract, a syndicate of banks. The interest ratereserve account should be established and funded on a six-month rolling basis for the loan is a floating rate based on six-month EURIBOR plus a marginadditional revenue arising from the difference between actual prices and prices defined in the range from 1.50% up to 1.60%, depending on the debt service coverage ratio. The principal is hedged:agreement. Under certain conditions, such amounts, if any, should be used for early prepayments upon regulatory parameters changes.
| − | 83% through a swap set at approximately 4.87% strike for the life of the debt.
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| − | 17% through a cap with a 1% strike covering the principal through 2025.
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As of December 31, 2021,2022, the outstanding amountbalance of these loansthis loan was $435$354.9 million. The financing arrangements of the three plants permitarrangement permits cash distributions to shareholders oncetwice per year if the debt service coverage ratio is at least 1.15x.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 the third quarter of 2013.September and October 2013, respectively.
O&M. Abengoa provides currently&M. We perform O&M services through a 25-year all-in contract.for Solaben 1 & 6 with our own personnel since June 2022.
Project Level Financing.Financing. On September 30, 2015, Solaben Luxembourg S.A., a holding company of the two project companies, issued a project bond for €285 million (approximately $324 million) with maturity in December 2034. The bonds have a coupon of 3.758%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 amountbalance as of December 31, 20212022 was $214$188.0 million. The bonds permit cash distributions to shareholders twice per year if the debt service coverage ratio is at least 1.650x.
Seville PV
Overview. Seville PV is a 1 MW photovoltaic farm located alongside PS 10 & 20 and Solnova 1, 3 & 4, in Andalusia, Spain. Seville PV reached COD in 2006.
O&M. We perform O&M. for Seville PV has an O&M agreement in place with a third party.our own personnel since May 2022.
Project Level Financing.Financing. Seville PV does not have any project level financing.
Italy PV 1, 2, and 3 & 4
Overview. We own 67 PV assets in Italy which have a combined capacity of 6.29.8 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 2012.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.&M. O&M agreements with third parties.
Project Level Financing.Financing. The assets have non-recourse project financing in place for a total amount outstanding of $2.8$3.3 million as of December 31, 2021 The loans have an average cost of 1.6% and average2022.
− | In June 2011, Italy PV 1 entered into a 15-year loan agreement for €6.0 million with maturity in 2026. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin of 1.30%. As of December 31, 2022, the outstanding balance of this loan was $1.5 million. |
− | In July 2016, Italy PV 3 entered into a 10-year loan agreement for €1.2 million with maturity in 2026. The interest rate for the loan is a fixed rate of 3.80%. As of December 31, 2022, the outstanding balance of this loan was $0.5 million. |
− | In March 2022, Italy PV 4 entered into a 10-year loan agreement for €1.3 million with maturity also in 2031. The interest rate for the loan is a fixed rate of 1.00%. As of December 31, 2022, the outstanding balance of this loan was $1.3 million. |
These financing arrangements permit dividend distributions at least once perany time throughout the year subject to meeting theand regardless of any minimum debt service coverage ratios required by contract.ratios.
Kaxu
Overview. Kaxu is a 100 MW net solar plant located in Pofadder, Northern Cape Province, South Africa. The project company is currently 51% owned by us through ABY SolarAtlantica South Africa (Pty) Ltd, (51%),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. It alsoIn addition, Kaxu has a molten salt thermal energy storage system. The asset reached COD in January 2015.
PPA.PPA. Kaxu has a 20-year PPA with Eskom, under a take–or-paytake-or-pay contract for the purchase of electricity up to the contracted capacity fromof the facility, which expires in February 2035. Eskom purchases all the output of the Kaxu plant under a fixed-price formula in South African Rand subject to indexation to local inflation.
Eskom is a state-owned, limited liability company, wholly owned by the government of the Republic of South Africa. Eskom’s payment guarantees are underwritten by the South African Department of Mineral Resources and Energy, under the terms of an implementation agreement. Eskom’s credit ratings are currently CCC+ from S&P, Caa1 from Moody’s and BBB- from Fitch. The Republic of South Africa’s credit ratings are currently BB- from S&P, Ba2 from Moody’s and BB- from Fitch.
In addition, in 2019, we entered into a political risk insurance agreement with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $78$58 million in the event of the South African Department of Mineral Resources and Energy does not complycomplying with its obligations as guarantor. This insurance policy does not cover credit risk.
O&M.&M. Since February 1, 2022, and following an agreement with Abengoa, the employeespersonnel performing the operation and maintenance of the plant have been transferred to an Atlantica subsidiary, so the O&M services are performed internally since such date.
Project Level Financing.Financing. Kaxu entered into a long-term financing agreement with a lenders’ group for a total initial amount of approximately $367.4 million. The loan consists of senior and subordinated long-term loans payable in South African rand over an 18-year term with the cash generated by the project. The interest rate exposure was initially 100% hedged through a swap with the same banks providing the financing, and the coverage progressively reduces over the life of the loan. Current effective annual interest rate is approximately 9.6%11.1% considering the hedge in place. As of December 31, 2021,2022, the outstanding amountbalance of these loans was ZAR 5,0154,728 million, or $314$277.5 million.
The financing arrangement permits dividend distributions on a semi-annual basis after the first repayment of debt has occurred, as long asprovided that the historical and projected debt service coverage ratios are at least 1.2x.1.2x or above.
The project financing arrangement for Kaxu contains cross-default provisions related to Abengoa such that a debt default by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. The insolvency filing by the individual company Abengoa S.A. in February 2021 represented a theoretical event of default under the Kaxu project finance agreement and the total amount of the debt was classified as current in our consolidated financial statements as of December 31, 2021. In September 2021, we obtained a waiver for such theoretical event of default which was conditional upon the replacement of the operation and maintenance supplier of the plant, as extended in November, 2021. On February 1, 2022, we transferred the employees performing the operation and maintenance services to an Atlantica subsidiary. The waiver has been extended until April 30, 2022 and is subject to the lenders receiving certain documentation from us, including formal evidence of the approval by our off-taker and the department of energy of South Africa of the operation and maintenance internalization and we are currently working on obtaining such documentation.
Efficient Natural Gas and Heat
Calgary District Heating
Overview. Calgary is a 55MWt District Heatingdistrict heating facility located in the city of Calgary in Alberta, Canada which reached COD in 2010. Calgary District Heating is a wholly owned subsidiary of Atlantica.
Concession Agreement.Thermal Off-take Agreements. The asset has availability-basedcapacity-based thermal heat revenue with inflation indexation, investment grade off-takers and 20 years of weightedan 18-year average contract life with investment grade off-takers.remaining. Contracted capacity and pass-through volume payments represent approximately 80% of the total revenue. Calgary District Heating is well-positioned to provide a pathway to reduced GHG heat.
O&M. We perform O&M. The operation and maintenance services are performed by NAES. for Calgary District Heating with our own personnel.
Project Level Financing.Financing. The asset does not have any project level financing.
ACT
Overview. ACT is a gas-fired cogeneration facility 99.99% owned by us through ACT Energy Mexico, S. de R.L. de C.V., or ACT Energy Mexico. The asset is located inside the Nuevo Pemex Gas Processing Facility near the city of Villahermosa in the State of Tabasco, Mexico. It has a rated capacity of approximately 300 MW and between 550 and 800 metric tons per hour of steam. ACT reached COD in 2013.
Conversion Services Agreement.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 1920 years from the in-service date and will expire on March 31, 2033. The Pemex CSA requires Pemex to supply the facility, free of charge, with the fuel and water necessary to operate ACT, and the latter has to produce electrical energy and steam requested by Pemex based on the expected levels of efficiency. The Pemex CSA is denominated in U.S. dollars. The price is fixed and is adjusted annually, according to a mechanism agreed in the contract that establishes that the average adjustments over the life of the contract should reflect the expected inflation. Pemex has the possibility to terminate the Pemex CSA under certain circumstances paying an indemnity.
In recent years, Pemex’s credit rating has weakened and is currently BBB from S&P, Ba3 from Moody’s and BB- from Fitch. 67
We have been experiencingexperienced delays in collections from Pemex in collectionsthe past, especially since the second half of 2019, which have been significant in certain quarters. As of December 31, 2022 these delays were shorter than in previous quarters.
O&M. GE provides services for the maintenance, service and repair of the gas turbines and NAES is responsible for the O&M. The O&M agreement with NAES expires upon the expiration of the Pemex CSA, although we may cancel it with no penalty at any time.
We own all of the shares of ACT except for two ordinary shares, which represent less than 0.01% of the total capital of ACT and which are owned by wholly owned subsidiaries of Abengoa.
Project Level Financing.Financing. In March 2014,December 2013 ACT Energy Mexico entered into a $655$660.0 million senior loan agreement with a syndicate of banks. The financing consists ofIn March 2014, after the loan’s first repayment, additional banks entered the syndicate, leading to a $205$655.4 million tranche one with 10-year maturity and a $450.0 million tranche two with an 18-year maturity. The interest rate on each tranche is a floating rate based on the three-month USD LIBOR plus a margin of 3.5% from January 2019 to December 2024 and 3.75% from January 2025 to December 2031. Thesenior loan is 75% hedged at a weighted average rate of 3.94%.comprised of:
− | Tranche 1: $205.4 million with 10-year maturity. |
− | Tranche 2: $450.0 million with an 18-year maturity. The interest rate on each tranche is a floating rate based on the three-month LIBOR plus a margin of 3.5% from January 2019 to December 2024 and 3.75% from January 2025 to December 2031. The loan is 75% hedged at a weighted average rate of 3.94%. |
The combined outstanding amountbalance of these loanstwo tranches as of December 31, 20212022 was $479$441.0 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. We entered into a ROFO agreement with Arroyo Energy for the remaining 70% stake in Monterrey, currently owned by them.
PPA. It is a U.S. dollar-denominated 20-year PPA with two international large corporations engaged in the car manufacturing industry. The PPA alsohad 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 will involve an investment to achieve 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 from Texas with a U.S. energy company.transportation. It has nolimited commodity risk. We are currently working with our partner and the clients inrisk since a potential 7-year extensionmajority of the PPA which would involve an investmentgas cost is a pass-through to achieve improvements in the asset to provide, among other things, electric power redundancy to theour clients.
O&M.&M. Wärtsilä performs the O&M for Monterrey. The term of theMonterrey under a contract is three years from COD and we expect to renew the contract with the same supplier.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.Financing. Monterrey has a loan of $147$159.4 million outstanding amountbalance as of December 31, 2021,2022, which matures in September 2027 and a credit line of $14 million available until September 2022, subject to certain conditions.2027. The interest rate of the loan is a floating rate based on the three-month USD LIBOR plus a margin of 2.75% with a 0.25% increase after three years. The LIBOR exposure was 85% hedged with a swap rate of 2.26% with the financing bank. The loan agreement permits cash distributions after the asset reached COD provided that the debt service coverage ratio is at least 1.20x.
Transmission Lines
ATN
Overview. ATN is a 365 miles transmission line located in Peru wholly owned by us, which is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATN reached COD in 2011. On December 28, 2018, ATN S.A. completed the acquisition of a power substation and two small transmission lines to connect our line to the Shahuindo (ATN expansion 1) mine located nearby. In October 2019, we also closed the acquisition of ATN Expansion 2.
Concession Agreement.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 FoodFoods and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations. In addition, both ATN Expansion 1 has a 15-year Transmission Service Agreement (“TSA”) and ATN Expansion 2 havehas two 20-year PPAsTSAs and one 30-year TSA denominated in US $.U.S. dollars.
O&M. ATN has a 27-year terman O&M agreement with a subsidiaryOmega Peru Operación y Mantenimiento S.A., one of Abengoa.the main O&M providers in Peru.
Project Level Financing. ATN has a project bond in place which was issued in September 2013 and which currently has three tranches outstanding:
| -− | 1st1st 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.
|
| -− | 2nd2nd 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.
|
| -− | 3rd3rd tranche had a principal amount of $10 million with a 15-year term and bears interest at a rate of 6.88% per year.
|
As of December 31, 2021, $92 million in aggregate principal amount2022, the outstanding balance of this loan was outstanding.$87.2 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 miles transmission line located in Peru wholly owned by us. ATS is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATS reached COD in 2014.
Concession Agreement.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 FoodFoods and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to the ATS Project.
O&M. ATS has a five-year terman O&M agreement with a subsidiary of Abengoa.Omega Peru Operación y Mantenimiento S.A. that we can terminate every five years.
Project Level Financing. On April 8, 2014, ATS issued a project bond denominated in U.S. dollars with a 29-year term with semi-annual amortization and which bears a fixed interest rate of 6.875%. As of December 31, 2021, $3972022, $391.5 million was outstanding. The project bond agreement permits cash distributions every six months subject to a trailing historical debt service coverage ratio for the previous two quarters of at least 1.20x.
ATN2ATN 2
Overview. ATN2,ATN 2, is an 81 miles transmission line located in Peru wholly owned by us, which is part of the Complementary Transmission System. ATN2ATN 2 reached COD in June 2015.
ATN2ATN 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 FoodFoods and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to ATN2.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%).
Maintenance & MonitoringO&M.. ATN 2 has an O&M agreement with a subsidiary of AbengoaOmega Peru Operación y Mantenimiento S.A. until 2027.
Project Level Financing. In 2011 and 2014, a 15-year loan agreement was executed for a commitment of $50.0 million and $31.0 million, respectively. All debt has a fixed interest rate amounting to 4.85% on a weighted average basis and matures in 2031. As of December 31, 2021,2022, the outstanding amountbalance of the ATN2ATN 2 project loan was $50$45.3 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 2014.
65December 2013 and January 2014, respectively.
Concession Agreement.Agreement. Both projects have concession agreements with the Sierra Gorda SCM mining company, which is owned by Sumitomo Corporation, Sumitomo Metal Mining and KGHM Polska Mietz. The concession agreement is denominated in U.S. dollars and has a 21-year term that began on the COD. The contract price is indexed mainly to the U.S. CPI.
The concession agreement grants in favor of Sierra Gorda a call option over the transmission lines, exercisable at any time during the life of the contract. According to the call option, Sierra Gorda is entitled to purchase the transmission line at an agreed price and with a six-month prior written notice.
O&M. Enor performs operations services at Quadra 1 under a 10-year contract expiring in 2027. Gas Atacama provides operations services2027 and at Quadra 2 under a 12-year contract expiring in 2029. Cobra performs maintenance2029 with an option to renew each O&M agreement for five additional years. Maintenance services at Quadra 1 and Quadra 2 under 6-year contracts expiring in 2023.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 TL3,TL 3, Quadra 1 and Quadra 2. This financing agreement consists of a single loan agreement for all these assets for a totalan 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 USD LIBOR plus 3.60%. We contracted an interest rate swap at an approximate fixed rate of 2.25% to hedge 75% of the amount nominal during the entire debt term. As of December 31, 2021,2022, the outstanding amountbalance was $63$57.4 million. The financing agreement is cross collateralized jointly between the Chilean assets and permits cash distributions twice per year if the combined debt service coverage ratio for the three assets is at least 1.20x.
Palmucho
Palmucho is a transmission line in Chile of approximately 6 miles. Palmucho has a 14-year concession contract with Enel Generacion Chile, whereby both parties are obliged to enter into a four-year valid toll contract at the end of the term of the concession contract and the valid toll contract will be renewed for three periods of four years each until one of the parties decides not to renew. O&M services are provided by Cobra.Energysur.
Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.
Chile TL3TL 3
Overview. Chile TL3TL 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. &MOperation services are performed internally.. We perform O&M for Chile TL 3 with our own personnel. Energysur performs maintenance services under a 3-yearthree-year contract expiring on January 1, 2025.
Project Level Financing. See Project Level Financing section for Quadra 1 and Quadra 2 above.
Chile TL4TL 4
Overview. Chile TL4TL 4 is a 63-mile transmission line in operation in Chile which reached COD in 2016. The asset has fully contracted revenues in USU.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 assets haveasset has O&M agreements with third parties.
Project Level Financing. Chile TL4TL 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. We are currently in conversations with Sacyr to reorganize our equity interests in the desalination assets in Algeria to manage our business more efficiently.
Honaine reached COD in July 2012. AEC is the Algerian agency in charge of delivering Algeria’s large-scale desalination program. The technology used in the Honaine plant is currently the most commonly used in this kind of asset. It consists of desalination using membranes by reverse osmosis.
Honaine had a corporate income tax exemption until 2021. After that period, the exemption was not extended, and the tariff was adjusted accordingly.
Concession Agreement.Agreement. The water purchase agreement is a 30-year25-year take-or-pay contract with Sonatrach/Algerienne des Eaux, or ADE, from the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost).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 30-year25-year contract from COD with a joint venture between Abengoa (50%) and Sacyr (50%) from the date of the execution (or 25-year term from COD). Sacyr has reached an agreement with Abengoa to acquire its equity interest in this joint venture. Such agreement is subject to customary approvals for this type of transactions.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, 2021,2022, the outstanding amountbalance of the Honaine project loan was $52$43.6 million. The financing arrangement permits cash distributiondistributions to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.
Skikda
Overview. The Skikda project is a 3.5 M ft3 per day capacity water desalination plant located in Skikda, Algeria. Skikda is located 510 km east of Algiers. We indirectly own 34.2% of Skikda through Aguas de Skikda, or ADS, AEC owns 49% and Sacyr owns the remaining 16.8%. We are currentlyown a 67% of the holding company which in negotiations with Sacyr to reorganize ourturns has a 51% equity interestsstake in Skikda, as a result we fully consolidate the desalination assets in Algeria to manage our business more efficiently.asset.
Skikda reached COD in 2009 and uses the same technology as Honaine.
Skikda had a corporate income tax exemption until 2019. After that period, the exemption was not extended, and the tariff was adjusted accordingly.
Concession Agreement. The water purchase agreement is a 30-year25-year take-or-pay contract with Sonatrach/ADE from the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost).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 joint venture between Abengoa (67%) and Sacyr (33%). Sacyr has reached an agreement with Abengoa to acquire its equity interest in this joint venture which is subject to customary approvals for this type of transactions.
67specialized 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, 2021,2022, the outstanding amountbalance of the Skikda project loan was $12$7.4 million. The financing arrangement permits cash distributiondistributions to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.
Tenes
Overview. Tenes is a 7 M ft3 per day capacity water desalination plant located 208 km west of Algiers, in Algeria. Tenes uses the same technology as Honaine and Skikda and has been in operation since 2015. Befesa Agua Tenes has a 51.0% stake in Ténès Lilmiyah SpA and we have a majority at the Board of Directors of Befesa Agua Tenes, the remaining 49% is owned by AEC.
Since January 2019, we have an investment in 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 Directorsdirectors at the Boardboard of Directorsdirectors 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 the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost).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.&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, 2021,2022, the outstanding amountbalance of the Tenes project loan was $86$79.3 million. The financing arrangements permit cash distribution to shareholders subject to a debt service coverage ratio of at least 1.10x.
Geographies and business sectors
We refer to “Item 5. Operating and Financial Review and Prospects” and to Note 4 to our Consolidated Financial Statements for a breakdown of our revenue by geography and by business sector.
Assets under construction
Albisu
Overview. Albisu is a 10 MW PV asset wholly owned by us,We currently have the following assets under construction nearor ready to start construction in the cityshort-term:
Asset | Type | Location | Capacity (gross)1 | Expected COD | Expected Investment ($ million) | Off-taker |
Coso Batteries 1 | Battery Storage | California, US | 100 MWh | 2024 | 40-50 | N.A. |
Chile PMGD2 | Solar PV | Chile | 80 MW | 2023 – 2024 | 303 | Regulated |
Honda 14 | Solar PV | Colombia | 10 MW | 2023 | 11 | Enel Colombia |
Honda 24 | Solar PV | Colombia | 10 MW | 2023 | 11 | Enel Colombia |
Apulo 14 | Solar PV | Colombia | 10 MW | 2023 | 11 | Enel Colombia |
Solana C&I PV | Solar PV (behind the meter) | Arizona, US | 2.5 MW | 2023 | 3 | Solana |
Raurapata | Transmission Line | Peru | 3.9KM 220Kv | 2024 | 12 | Conelsur4 |
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. |
| (3) | Corresponds to the expected investment by Atlantica. |
| (4) | Atlantica owns 50% of the shares in Honda 1, Honda 2 and Apulo 1. |
| (5) | The contract is in the process of being transferred to Conelsur. |
Development Pipeline
We are developing new projects in most of Salto (Uruguay).
PPA. The asset has a 15-year PPAour core geographies. In some cases, we do this with Montevideo Refrescos, S.R.L, a subsidiary of Coca-Cola Femsa. The PPA is denominatedour local in-house teams and in other cases we have been working with local currencypartners with a maximum and minimum pricewhom we jointly invest in US$ and is adjusted monthlydeveloping projects or with whom we have agreements based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollar exchange rate.milestones.
La Tolua and Tierra Linda
Overview. La Tolua and Tierra Linda are two solar PV assets wholly owned by us, currently under construction in Córdoba (Colombia) with a combined capacity of 30 MW.
PPA. Each plant hasBy 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 15-year PPApipeline of assets under development, including both repowering or expansion opportunities of existing assets and greenfield development, of approximately 2.0 GW7 of renewable energy and 5.6 GWh7 of storage. Approximately 40% of the projects are PV, 40% storage and 19% wind, while 18% of the projects are expected to reach ready to build (“Rtb”) in local currency indexed2023 or 2024, 17% are in an advanced development stage and 65% are in early stage. 27% correspond to local inflation with Synermin, the largest independent electricity wholesaler in Colombia.expansion or repower opportunities of existing assets and 73% to greenfield developments.
| Renewable Energy (GW)7 | Storage (GWh)7 |
North America | 1.0 | 4.1 |
Europe | 0.4 | 1.3 |
South America | 0.6 | 0.2 |
Total | 2.0 | 5.6 |
Customers
We derive our revenue from selling electricity, electric transmission capacity, water desalination capacity and heat. Our customers are mainly comprised of electrical utilities and corporations, with which we typically have entered into PPAs. We also employ concession contracts, typically ranging from 20 to 30 years. We also have regulated assets in Spain, and Chile (Chile TL3).TL 3) and Italy. Chile PV1, representing a very small percentagePV 1, Chile PV 3 and Lone Star II, which represent less than 2% of our revenue sellsAdjusted EBITDA for the year 2022, 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.
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.”
7 Only includes projects estimated to be ready to build before or in 2030 of approximately 3.3 GW, 2.0 GW of renewable energy and 1.3 GW of storage (equivalent to 5.6 GWh). Capacity measured by multiplying the size of each project by Atlantica’s ownership. Potential expansions of transmission lines not included.
Competition
Renewable energy, storage, efficient natural gas and heat transmission lines are all capital-intensive and commodity-driven businesses with numerous industry participants. We compete based on the location of our assets in various countries and regions; however, because 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.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 and Sustainability
Environmental management is a key priority in our business and operations. Our facilities and operations are subject to significant government regulation, including stringent and comprehensive federal, provincial and local laws, statutes, regulations, guidelines, policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; storage, handling, use, disposal, transportation and distribution of dangerous materials and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the presence and remediation of hazardous materials in soil and groundwater, both on and offsite; the protection of natural resources; land use and zoning matters; and workers’ health and safety matters. We consider environmental protection as an area of performance and as such, environmental issues are included among the responsibilities of our key executives.
Employees and Human Resources
As December 31, 2021,2022, we had 658978 employees. Following our acquisitionthe internalization of ASI Operations, the subsidiary which provides operationoperations and maintenance services in our solar assets in the U.S., certainUnited States in 2019, in South Africa in 2022 and in part of our solar assets in Spain also in 2022, part of the recently hired employees nowof the relevant O&M companies belong to apreviously existing labor union.unions. We believe that the relationship between the Company and its labor union is good. We have not experienced any strikes or work stoppages amongstamong our workforce. One of our plants has experienced strikes by employees working for one of our operation and maintenance suppliers in the past.
Health & Safety
Within our values, the first one is “Integrity, Compliance and Safety”. We are committed to prioritizing and actively promoting health and safety as a tool to protect the integrity and health of our employees, subcontractors and partners involved in our business activity. We promote a safe operating culture across Atlantica and encourage a preventive culture in the (“O&M”)&M activities of our subcontractors as reflected in our corporate health and safety policy.
Annually, we conduct internal and external audits to evaluate our health and safety management system in accordance with the OHSAS:18001ISO 45001 standard requirements. Our ISO 45001 certification is valid until 2024. The external audit is carried out by an independent third party. These efforts have resulted in the continuation of the certification of the Occupational Health and Safety Management System in OHSAS: 18001 obtained in 2015. This certification has been successfully renewed during the last five years. Additionally, we perform periodic health and safety audits of our asset contractors to monitor their compliance with legal regulations, contractual requirements and our safety best practices. We also develop an annual training program to train managers and employees on safety awareness. This annual plan is designed in accordance with local regulations and risk assessment at every work position and work center.
On an annual basis, we establish key safety metrics targets in all our assets which include both Atlantica and subcontractor employees, which were achieved in 2021:2022:
− | - | 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 20212022 at 1.2,1.0, compared to 1.01.2 in 2020. 2021. |
− | - | Our Lost Time Injury Rate (LTIR) represents the total number of recordable accidents with leave (lost time injury) recorded in the last 12 months on 200 thousand of hours worked. We ended 20212022 at 0.5,0.6, compared to 0.30.5 in 2020. 2021. |
The key metrics provided above do not include Rioglass, sinceLTIR increased in 2022 compared to the asset was acquired during 2021previous year because we had more assets under construction in 2022, as the accident rates are typically higher in construction activities than in operation and maintenance activities. If we consider only our assets in operation, LTIR decreased to 0.3 in 2022 from 0.5 in 2021. Similarly, TRIR decreased in 2022, but the integration processdecrease is still ongoing. The increasehigher if we look only at our assets in both KPIs was mainly caused by higher ratesoperation, where TRIR decreased to 0.8 in some of the2022 compared to 1.2 in 2021. In 2023, we will focus on developing best practices in our assets recently acquired. During the year 2022,under construction, working closely with our EPC contractors, while we expect to continue working on the integration of recent acquisitions, to ensure thatmaintain or improve our strict practices are consistently establishedratios in all the assets.assets in operation.
Operation and Maintenance
In terms of operational efficiency, we focus on ensuring long-term availability, reliability and asset integrity with maintenance and monitoring. The suppliers of our solar panels, turbines, transmission towers and equipment are selected through a detailed evaluation process, focusing on their commercial track record and regular availability of components and replacement parts for the proper functioning and maintenance of our assets and facilities. Our corporate operations team identifies best practices and controls which are implemented in all our assets. Additionally, we require all our suppliers to comply with our Suppliers’ Code of Conduct.
Operation and maintenanceWe currently perform internally the O&M for a majority of our assets. In 2022, Abengoa performed O&M services for certainassets that represented approximately 20% of our assets are provided by subsidiaries of Abengoa, S.A. On February 22, 2021, Abengoa, S.A. filedconsolidated revenue for insolvency proceedings in Spain. Based on the public information filed in connection with these proceedings, such insolvency proceedings do not include other Abengoa companies, including Abenewco1, S.A., the controlling companythat year. As of the subsidiaries performingdate of this annual report, we are in the process of transitioning the operation and maintenance services for us. In Kaxu, we internalized the operation and maintenance services on February 1, 2022, after the transfer of the employees performing those services to an Atlantica subsidiary. In addition, in February 2022, we reached an agreement with Abengoa, subject to conditions precedent, including waivers from financial institutions, to terminate the O&M agreements in six plantsthese assets in Spain andfrom an Abengoa subsidiary to introduce a clauseCompany’s subsidiary. Once this transfer is completed, we expect Abengoa to be able to terminate the rest of the agreements every three years. If and when the conditions precedent are met, we would perform theprovide O&M services for the six plants we would be terminating with third parties or internal resources.assets representing less than 5% of our consolidated revenue in 2022. See “Item 3.D—Risk Factors— III. Risks Related to Our Relationship with Algonquin and Abengoa—If Abengoa defaults on certain of its debt obligations, including as a result of the insolvency filling by their holding company Abengoa S.A. we could potentially be in default of certain of our project financing agreements”
Abengoa”.
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 I, one of the wind assets in Vento II where we currently have a 49% equity interest. The basis for the lawsuit is that the defendants failed to properly prepare for cold weather, including failure to implement measures and equipment to protect against cold weather, and failed to properly conduct their operations before and during the storm.
Atlantica is not a party to any other significant legal proceedings Atlantica is party to various administrative and regulatory proceedings that have arisen in the ordinary course of business.
While Atlantica does not expect the above noted proceedings, either individually or in combination, to have a material adverse effect on its financial position or results of operations, because of the nature of these proceedings Atlantica is not able to predict their ultimate outcomes, some of which may be unfavorable to Atlantica.
Regulation
Overview
We operate in a significant number of highly regulated markets. The degree of regulation to which our activities are subject varies by country. In a number of the countries in which we operate, regulation is carried out mainly by national regulatory authorities. In others, such as the United States and, to a certain degree, Spain, there are various additional layers of regulation at the state, regional and/or local level. In countries with these additional layers of regulatory agencies, the scope, nature and extent of regulation may differ among the various states, regions and/or localities.
While we believe the requisite authorizations, permits and approvals for our assets have been obtained and that our activities are operating in substantial compliance with applicable laws and regulations, we remain subject to a varied and complex body of laws and regulations that both public officials and private parties may seek to enforce. The following is a description of the primary industry-related regulations applicable to our assets that are currently in force in the principal markets in which we operate.
Regulation in the United States
In the United States, our electricity generation project companies are subject to extensive federal, state and local laws and regulations that govern the development, ownership, business organization and operation of power generation facilities. The federal government regulates wholesale sales, operation and interstate transmission of electric power through the FERC and through other federal agencies, and certain environmental, health and safety matters. State and local governments regulate the siting, permitting, construction and operation of power generation facilities, the retail sale of electricity and certain other environmental, health, safety and permitting matters.
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 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 should allow an easier and faster monetization of these tax credits. Such credits will reduce the cost of renewable investments in the U.S.
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 forthcoming, 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.
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. A DOC decision is expected by May 2023. If the DOC determines that the petition has merit, it would be able to apply any final tariffs retroactively to November 4, 2021. If imposed, the new tariffs are expected to further disrupt the supply of solar modules to the United States and could impact the cost and timing of our solar projects.
In June 2022, the Biden Administration used its executive powers to issue a 24-month tariff moratorium on solar panels manufactured in Cambodia, Malaysia, Thailand, and Vietnam. The moratorium comes as a direct response to concerns raised about the adverse impact from the ongoing DOC complaint on the U.S. solar industry. As the DOC will continue its investigation discussed above, companies may still be subject to tariffs after the moratorium ends; however, U.S. companies will reportedly be exempt from any retroactive tariffs that previously could have applied. The Biden Administration also announced that it plans to invoke the Defense Production Act to accelerate the production of solar panels in the U.S.
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 renewable portfolio standards, or RPS, which generally require electric utilities to generate or purchase a certain percentage of their electricity supplied to consumers from renewable resources. In certain states, it is not only mandatory to meet these percentages, which in general are on the increase from renewable resources, but also electric utilities may be required to generate or purchase a percentage of their electricity supplied to consumers from specific renewable energy technologies, including solar technology.
Arizona
The Arizona Corporation Commission ( the “ACC”) has complete and exclusive jurisdiction over the rates and terms under which regulated utilities may provide electricity service to retail customers in Arizona. Under Arizona’s Renewable Energy Standard & Tariff ( the(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, or the CPUC, governs, among other entities, California’s investor-owned utilities, including Pacific Gas & Electric Company, or PG&E.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 Federal Electricity Commission, or CFE, an entity wholly owned and controlled by the Mexican government, and legally independent from the Mexican Ministry of Energy, or Secretaría de Energía or SENER. CFE was the only entity authorized to provide electricity directly to the public and to supply services to the Mexican wholesale market. CFE was also responsible for the construction and maintenance of infrastructure necessary for the delivery of electricity, such as the national electric grid, the Sistema Eléctrico Nacional, or SEN.
Notwithstanding the foregoing, private entities were allowed to participate in the following activities not considered public utility services, as defined by the aforementioned law:
| • | Cogeneration. The electricity produced is used to supply power to the establishments associated with the cogeneration process and/or the shareholders of the cogeneration company; |
| • | Self-Supply Generation. The electricity produced is used for the self-supply purposes of the holder of the relevant self-supply power generation permit and/or its shareholders; |
| • | Independent Power Production. All the electricity produced is delivered to CFE; |
| • | Small-Scale Production. The electricity produced does not exceed 30 MW and is used for export purposes or the supply of all power output is sold to CFE; |
| • | Exports. The electricity produced is exported in its entiretyentirety; 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(Ley de la Industria Eléctrica)ctrica), the power generation sector has been more open to private participation and investment, creating a competitive spot market in power generation, although electric transmission and distribution remain public services to be provided exclusively by CFE. The national electric grid is a responsibility of the Centro Nacional de Control de Energía, or the CENACE, which became a decentralized public agency, an Independent System Operator, or ISO.
Since commencement of the energy reform process, secondary legislation and regulation was enacted and changes were implemented through a substantial modification of the legal framework that had governed the development of the energy industry in the country.
However, on March 9, 2021, Mexico´s President proposed a preferential reform to the Electric Industry Law. In broad terms, the reform aimed for CFE to re-instate its significance in the energy generation sector with the constitutional reform of 2013 by, among others, (i) changing the dispatch criteria from economic merit to CFE´s assets; (ii) giving CFE the ability to enforce the termination of grandfathered self-supply contracts; (iii) allowing any renewable generator to get clean energy certificates (which will create a surplus and therefore will undermine their purpose); (iv) eliminating CFE´s obligation to buy energy through auctions; and (v) granting the Energy Ministry the possibility to decide which generation permits are granted by the FERC.
Several legal defense mechanisms were activated and filed before Mexican courts, arguing that the aforementioned reform was against constitutional principles, which have resulted in Mexican District Courts suspending the application of the reform until constitutional proceedings are definitely resolved, thus leaving the Electric Industry Law of 2014 effective.
On September 30, 2021, the Mexican President submitted before the House of Representatives a new bill pursuant to which articles 25, 27 and 28 of the Mexican Constitution are proposed to be amended. As a constitutional amendment, such bill is to be discussed and passedOn April 17, 2022, the Electricity Reform did not reach the qualified majority required for its approval by the House of Representatives in Mexico, and was therefore dismissed. Although the Mexican Senate and local congresses. If passedPresident has stated that he does not intend to re-submit a modified amendment proposal for approval again, at this point we cannot guarantee that he will not pursue other changes to the electricity sector in Mexico, since this has been an important component of his political agenda. However, as presented, most ofseveral experts in the energy reform of December 2013 would be reversed and the sector would be significantly transformed.
On December 3, 2021,field have explained, the Mexican Energy regulatory Commission (Comisión Reguladora de la Energía), or CRE, publishedstill has failed to provide a response to permit applications, modifications and other requests, which has created uncertainty in DOF Decree number A/037/2021, by meansthe market and further delayed the development of which the interpretation criteria of the concept self-needs was amended, with an impact on general aspects of isolated supply and local generation activities.projects.
Additionally, on December 31, 2021, CRE published in DOF the new rules for the grid code (Có(Código de Red)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(Bases del Mercado Eléctrico)ctrico), 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(Reglas del Mercado), such as the methodology that is used to forecast the level of demand in the spot market, information on market participants, and the methodology to determine the price of the electricity sold and purchased within the spot market.
The Guidelines are part of the Rules of the Market, which are administrative provisions of general application that specifically detail different aspects of the operation of the MEM, and determine the rules that all market participants, such as generators, traders, suppliers, non-supplier traders or qualified users, as well as the competent authorities must comply with.
All the aforementioned matters regarding the Electric Industry Law will remain in force until the final decisions of the constitutional proceedings mentioned above are issued. In the event that the reform of the Electric Industry Law proposed in 2021 enters into force, the aforementioned will have to be modified in accordance with the new provisions and framework applicable to the electricity market.
Current Regulatory Framework
The following laws and regulations are among the main provisions that include constitutional, legal and regulatory provisions applying to the development of cogeneration projects in Mexico, according to the recently enacted regulatory framework:
Political Constitution of the United Mexican States (Constitución Política de los Estados Unidos Mexicanos).
Electric Industry Law (Ley de la Industria Eléctrica).
Regulation of the Electric Industry Law (Reglamento de la Ley de la Industria Eléctrica)
Energy Regulatory Bodies Law (Ley de los Órganos Reguladores Coordinados en Materia Energética).
Energy Transition Law (Ley de Transición Energética).
Federal Electricity Commission Law (Ley de la Comisión Federal de Electricidad).
Regulations of the Federal Electricity Commission Law (Reglamento de la Ley de la Comisión Federal de Electricidad).
Terms for the strict legal segregation of the Federal Electricity Commission (Términos para la estricta separación legal de la Comisión Federal de Electricidad).
Geothermal Energy Law (Ley de Energía Geotérmica).
Guidelines that regulate the criteria for granting clean energy certificates (Lineamientos que establecen los criterios para el otorgamiento de certificados de energía limpia) which have been recently amended and which relevant implications will be further mentioned below.
Guidelines of the Market (Bases del Mercado Eléctrico).
Grid Code 2.0 (Código de Red 2.0).
General Administrative Provisions that establish the terms for the operation of the Register of Qualified Users (Disposiciones administrativas de carácter general que establecen los términos para la operación y funcionamiento del registro de Usuarios Calificados).
| • | Resolution by means of which the Energy Regulatory Commission issues the general administrative provisions that establish the general conditions for the provision of the energy supply (Resolución por la que la Comisión Reguladora de Energía expide las Disposiciones administrativas de carácter general que establecen las condiciones generales para la prestación del suministro eléctrico). |
| • | Mechanism to request the modification of the permits granted under the Electricity Public Service Law for generation permits, as well as the criteria under which the permit holders of such regime may execute an interconnection contract while the Wholesale Electricity Market becomes effective (Mecanismo para solicitar la modificación de los permisos otorgados bajo la Ley del Servicio Público de Energía Eléctrica por permisos con carácter único de generación, así como los criterios bajo los cuales los permisionarios de dicho régimen podrán celebrar un contrato de interconexión en tanto entra en operación el mercado eléctrico mayorista). |
| • | General administrative provisions for the operation of the certificate procurement system and the compliance with the clean energy obligations (Disposiciones administrativas de carácter general para el funcionamiento del sistema de gestión de certificados y cumplimiento de obligaciones de energías limpias). |
| • | General administrative provisions that establish the minimum requirement to be met by suppliers and qualified users participating in the Electricity Market to acquire energy demand in terms of article 12, section XXI, of the Electric Industry Law (Disposiciones administrativas de carácter general que establecen el Requisito mínimo que deberán cumplir los suministradores y los usuarios calificados participantes del mercado para adquirir potencia en términos del artículo 12, fracción XXI, de la Ley de la Industria Eléctrica). |
| • | General administrative provisions regarding open access and provision of services in the National Transmission Network and the General Distribution Networks (Disposiciones administrativas de carácter general en materia de acceso abierto y prestación de los servicios en la Red Nacional de Transmisión y las Redes Generales de Distribución de Energía Eléctrica). |
| • | General administrative provisions that establish the requirements and minimum amounts of electricity coverage contracts that suppliers must hold regarding electric power, energy demand and clean energy certificates that they will supply to the represented load centers and their verification (Disposiciones administrativas de carácter general que establecen los requisitos y montos mínimos de contratos de cobertura eléctrica que los suministradores deberán celebrar relativos a la energía eléctrica, potencia y certificados de energía limpia que suministrarán a los centros de carga que representen y su verificación). |
| • | Policy on Reliability, Safety, Continuity and Quality on the National Electric System (Política de Confiabilidad, Seguridad, Continuidad y Calidad en el Sistema Eléctrico Nacional). |
| • | Decree to guarantee the Efficiency, Quality, Reliability, Continuity and Safety of the National Electric System, due to the recognition of the epidemic of the SARS-CoV2 virus disease (COVID-19) (Decreto para garantizar la Eficiencia, Calidad, Confiabilidad, Continuidad ySeguridad del Sistema Eléctrico Nacional, con motivo del reconocimiento de la epidemia de la enfermedad por el virus SARS-CoV2 (COVID-19)). |
| • | Resolution by means of which CFE announced the new wheeling tariffs to owners of Legacy Interconnection Agreements with renewable energy sources (Resolución por medio de la cual CFE dio a conocer las nuevas tarifas de transmisión a los titulares de Contratos de Interconexión Legados con fuentes de energía renovable). |
Decree number A/037/2021 of the Energy Regulatory Commission by means of which decree number A/049/2017 is amended, regarding the interpretation criteria of the concept self-needs and the general aspects applicable to the isolated supply activity.
Resolution number RES/550/2021 of the Energy Regulatory Commission by means of which the General Administrative Provisions regarding the efficiency, quality, reliability, continuity, safety and sustainability standards of the National Electric System are published: Grid Code.
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(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(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(Reglamento de Transmision)Transmision).
The SCT is remunerated on the basis of the annual average cost of the corresponding facilities approved by OSINERGMIN. The applicable tariffs and their respective actualization formulas are approved by OSINERGMIN every four years.
Penalties
The concessionaires must maintain certain quality, safety and maintenance standards of the facilities. The failure to meet the quality standards established by applicable industry regulations, such as the technical rules of quality for power services, and the National Electricity Code, may result in the imposition of penalties, fines and restrictions. In addition to these penalties, fines and restrictions, if our concession is terminated due to the breach of obligations under the Concession Agreements, the Peruvian Ministry of Energy 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 Electricas, 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 Generacion Electrica), (iii) the Transmission Rules (Reglamento de Transmision), or the Transmission Rules; (iv) the General Environmental Law; (v) the Regulations for the Environmental Protection in Power Activities; (vi) the Laws creating OSINERGMIN; (vii) the OSINERGMIN Rules ; (viii) the Regulatory Agencies of Private Investment in Public Services Framework Law; and (ix) the Legislative Decree that promotes investment in the generation of power through renewable resources and its regulations.
These rules regulate how to enter the electricity sector (applicable permits and licenses); the main obligations of the different participants of the electricity market (generators, transmission companies and distribution companies); remuneration systems for the different market participants; rights of electricity consumers and the attributions of the competent authorities.
Some of the main aspects of Peru’s regulatory framework concerning its power sector are: (i) the separation between the power generation, transmission and distribution activities; (ii) unregulated prices for the generation of power supplied to unregulated customers; (iii) regulated prices for the generation of power supplied to regulated customers; (iv) regulated prices applicable to transmission and distribution of power for both regulated and unregulated customers; and (v) the private administration of the SEIN, according to the principles of efficiency, cost reduction, guaranty of quality and reliability in the provision of services.
All entities that generate, transmit or distribute power to third parties in Peru, including self-generators and co-generators that sell their excess capacity and energy in the SEIN are regulated by the Energy Legal Framework.
The Peruvian government retains ultimate oversight and regulatory control. In addition, the Peruvian government owns and controls various generation and distribution companies in Peru.
During 2020, OSINERGMIN approved a new Annual Liquidation Procedure for the SGT Electricity Transmission Service, which applies to all concessionaires that have transmission facilities subject to the SGT Contracts regime. The regulation specifies that the Liquidation Procedure to be carried out in 2021 will comprise a Liquidation Period of ten months, from March 1, 2020 to December 31, 2020. By means of this procedure, the base tariff for the transmission service cannot be modified; however, this is relevant as it determines the monthly disbursements to be made in favor of the agents of the electricity market.
Additionally, OSINERGMIN has approved certain procedure applicable to electricity agents (including transmission agents) including the Procedure "Conditionsnamed “Conditions for the application of electricity generation and transmission tariffs"tariffs”, by means of which, the conditions for the application of the generation and transmission prices were established for certain electric energy supplies as further detailed in the Electrical Concessions Law. Moreover, OSINERGMIN, has updated the database of the “Investment Standard Modules for Transmission Systems”, with costs as of 2019.
In addition, the same way it was approved the Procedure for the Auditing of Contracts and Authorizations of the Electricity Subsector and Concession Contracts in Natural Gas Activities was approved(Resolutionapproved (Resolution No. 166-2020-OS/CD), having as the purpose of this regulation is to audit the obligations contained in concession contracts, authorizations and investment commitment contracts in the electricity sub-sector, including the transmission service, which are under the competence of OSINERGMIN. For the electric transmission systems, the following aspects are subject to audit: (i) the Electric Power Transmission Systems Concession Contract (SGT and SCT); (ii) Electric Power Transmission System Expansions; (iii) Concession Contract to Develop the Electric Power Transmission Activity.
In March of 2020, the Presidency of the Council of Ministers ordered the reorganization of OSINERGMIN passed through a Supreme Decree No. 023-2020-PCM in order to evaluate the administrative, organizational and management situation of the entity, as well as to propose the necessary reform measures. In such context, in December 2020, OSINERGMIN approved a new Regulations for the Inspection and Sanctioning of Energy and Mining Activities under the responsibility of OSINERGMIN, by means of Resolution No. 208-2020-OS/CD, issued on December, 2020. Such new regulations are applicable to the transmission sector and will come into effect with the publication of other pending norms in charge of the entity. Regarding the sanctioning power of OSINERGMIN in the electric sector, a new Fine Application Limit has been adopted.
During 2021, the OSINERGMIN issued Resolution No. 069-2021-OS-CD that approved the calculation of the annual settlement corresponding to the transmission concessionaires for the income obtained from the transmission tolls of the Secondary Transmission Systems and the Complementary Transmission Systems. Said resolution was subsequently amended by Resolution No. 242-2021-OS/CD, in order to change the procedure for the determination, collection, settlement of the Annual Average Cost and the unit value of the Transmission Toll of the projects included in the Transmission Investment Plans for the periods 2013-2017, 2017-2021 and 2021-2025 that have been reallocated through the mechanism of expression of interest of the transmission concessionaires. Likewise, it regulates the form of payment of such amounts and the corresponding information reporting. In addition, Resolution 083-2021-OS/CD approved the new technical procedure No. 20 of the COES related to the entry, modification and withdrawal of electric facilities in the SEIN and established a new regulation for the treatment of facilities connected to distribution facilities.
Finally, other relevant regulations have been modified, such as Board Resolution No. 092-2021-OS/CD, whichMoreover, during 2021, OSINERGMIN approved the modificationsa modification to the Technical Procedure regarding No. 31 onof the COES regarding the calculation of the Variable Costs of the Generation Units. This isUnits, which had an impact on the most relevant regulatory change in the tariff regime of the electricity system since it will affect the electricityenergy business due to theits impact on the marginal cost. Also, during 2022 such Procedure was (once again) modified through Resolution No. 171-2022-OS/CD.
The Power Sector Antitrust Law (LawIn December 2022, through Supreme Decrees No. 26876)154-2022-PCM and its regulations (Supreme Decree No. 017-98-ITINCI)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 superseded byapproved. 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 newdraft 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 applicableservices with battery energy storage systems).
Finally, regarding the existing limitations to all typesvertical integration of mergers and acquisitions. The the electric activities, Law No. 31112, "Law“Law that establishes the prior control for corporate concentration operations" was published on January of 2021,operations” and its relevant implementing rules (Supreme Decree No. 039-2021-PCM) were published in Marchbecame effective on June 14, 2021. This law modifies the regulatory regime applicable to business concentrations in the electricity sector (and expands it to other sectors under different economic thresholds).
Regulation for Environmental Protection in Electrical Activities
In accordance with the current environmental legal framework, as a general rule, prior to the construction and beginning of any electrical activities (i.e. generation, transmission or distribution) the holder must obtain from the 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.
The Guaranteedguaranteed 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 (“PV”)
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 electricity 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 recently 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 PMGD, 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 Spanish government can establish a specific remuneration through an auction process.
The significant obligations of the renewable energy electricity producers under the Electricity Act include, inter alia, a requirement to:
Offer to sell the energy they produce through the market operator even when they have not entered into(daily and intra-daily market managed by the market operator) or via a bilateral or forward contract and are(which makes them consequently excluded from the bidding system managed by the market operator.
operator).Maintain the plant’s planned production capacity. Power lines, which include connections with the transmission or distribution network and transformers are considered part of the production facility.
Additionally, the Royal Decree 413/2004 establishes the following relevant obligations for renewable energy electricity facilities:
Having, prior to the beginning of discharge into the grid, the equipment for measuring electrical energy.
The facilities must be registered in the Administrative Register of Electrical Energy Production Facilities under the Ministry of Industry.
Voltage dips: all facilities or groupings of photovoltaic facilities with an installed power greater than 2 MW, in accordance with the definition of grouping, shall be obliged to comply with the requirements for responding to voltage dips established by means of the corresponding operating procedure.
Control centers: all facilities with installed power greater than 5 MW, and those with installed power less than or equal to 5 MW but which form part of a grouping of the same subgroup of article 2 whose total sum of installed powers is greater than 5 MW, must be attached to a generation control center.
Telemetric measurements: all facilities producing from renewable energy sources, cogeneration and waste with installed capacity greater than 1 MW, or less than or equal to 1 MW but which form part of a grouping of the same subgroup whose total installed capacity is greater than 1 MW, must send telemetric measurements to the system operator in real time.
Compliance with these last three obligations will be a necessary condition for the receipt of the specific retribution regime and must be accredited to the body in charge of carrying out the settlements. Otherwise, only market revenues will be received, without prejudice to the applicable sanctioning regime.
Permits and authorizations
The Electricity Act and the Royal Decree 1955/2000 generally require facilities producing renewable energy to obtain the following administrative authorizations:
• | Prior Administrative authorization (Autorización Administrativa Previa), which refers to the preliminary project of the installation as a technical document that will be processed, where appropriate, together with the environmental impact study.
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• | Approval of the execution project (Autorización Administrativa de Construcción), which refers to the specific project of the facility and allows its owner to construct or establish it.
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• | Operating permit (Autorización Administrativa de Explotación), which, once the project has been executed, allows the facilities to be energized and to proceed with their commercial exploitation.
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Registration on Public Registers
The Electricity Act and Royal Decree 413/2014 require electricity generation facilities to be entered on the official register of electricity production plants maintained by the Ministry for Ecological Transition and the Demographic Challenge.
The autonomous regions may keep their own registers of electricity generation plants they have authorized if such plants have a capacity of 50 MW or less. The registration details of these plants must be provided to the Ministry for Ecological Transition and the Demographic Challenge.
To receive their facility-specific reimbursement, renewable energy facilities are required under the Electricity Act and Royal Decree 413/2014 to be recorded on a new register , known as the registry of the specific remuneration regime (“Registro de régimen retributivo específico” or “RRRE”). Unregistered plants will only receive the pool price.
The first transitional provision of Royal Decree 413/2014 states that power plants based on renewable sources recognized under the previous economic regime, as in the case of Solaben 2 & 3, Solacor 1 & 2, PS10 & 20 were automatically included in the RRRE.
Remuneration System for Renewable Plants
According to Royal Decree 413/2014, producers receive (i) the poolelectricity market price for the power they produce and (ii) a specific remuneration.
AThe 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:
a) A remuneration per unit of installed power, which shall be called investment remuneration (Rinv) and shall be expressed in €/MW. To determine this parameter, the standard value of the initial investment resulting from the competitive tendering procedure established to grant the specific remuneration system to each installation will be considered. For the calculation of the annual income from the remuneration for the investment of an installation, the remuneration for the investment (Rinv) of the associated typical installation shall be multiplied by the power entitled to the specific remuneration system, without prejudice to the correction according to the number of equivalent hours of operation.
b) A remuneration for the operation (Ro) which shall be calculated in accordance with the provisions of Article 17 of the Royal Decree 413/2014, expressed in €/MWh. In order to calculate the income from the remuneration for the operation of an installation, the remuneration for the operation (Ro) of the associated typical installation shall be multiplied, for each settlement period, by the energy sold on the production market in any of its forms of contracting in said period, attributable to the fraction of power entitled to aThis specific remuneration system without prejudice toshall consist of the correction based on the number of equivalent hours of operation.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 as described above.established. Nevertheless, the granting of this specific remuneration system for existing facilities is regulated in the first transitory provision of RDRoyal 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 have arbitration process outstanding.
The final parameters were finally approved by the Order TED/171/2020, of February 24 that was published on February 28, 2020. The Order takes as a starting point the new reasonable rate of return approved by Royal Decree-Law 17/2019. These remuneration parameters shall be applicable with retroactive effect from the start of the regulatory period (i.e. from January 1, 2020), for the period 2020-2025. The estimated market price for each year of said half-period was set at 54.42 €/MWh, 52.12 €/MWh and 48.82 €/MWh, for the years 2020, 2021 and 2022, respectively.
The Annex IIIn addition, in 2022 measures to adjust the regulated revenue component for renewable energy plants, 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 referred Order TED/1717/2020 establisheswar 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 regulation, 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. Now, under article 5 of Royal Decree Law 6/2022, an extraordinary measure has been taken to subdivide the current regulatory semi-period, so as to create a new semi-period between January 1, 2022 and December 31, 2022 and the remuneration will be reviewed also taking into account future prices of OMIP. Further on May 14, 2022, the Royal Decree Law 10/2022 was published, including the so-called “Iberian mechanism”, which is the temporary production cost adjustment mechanism for reducing the price of electricity in the wholesale market. The main changes included by these regulations are:
| − | The statutory half-period of three years from 2020 to 2022 has been split into two statutory half-periods (1) from January 1, 2020 until December 31 2021 and (2) calendar year 2022. As a result, the fixed monthly payment based on installed capacity (Remuneration on Investment or Rinv) for calendar year 2022 was revised in the new Order TED/1232/2022. The proposed Rinv is detailed in the table below. |
| − | The electricity market price assumed by the regulation for calendar year 2022 was changed from €48.82 per MWh to an expected price of €121.9 per MWh, i.e., the remuneration parameters of 2022 have been updated with real prices of 2020 (33.94 €/MWh) and 2021 (111.90 €/MWh) and the future prices of OMIP for 2022 (value of second semester 2021: 121.9 €/MWh). As a result, the variable payment based on net electricity produced (Remuneration on Operation or Ro), was also adjusted. The proposed Ro for the year 2022 is zero €/MWh for most of our assets reflecting the fact that market prices for the power sold in the market are significantly higher. |
Following the mandate contained in Royal Decree Law 6/2022 and Royal Decree Law 10/2022, which main measures have been exposed above, the remuneration parameters have been updated for standard installations applicablethe year 2022 by the recent Order TED/1232/2022, of December 2, 2022, that was published in final form on December 14, 2022.
According to such regulation, the years 2020, 2021 and 2022: return on investment, number of equivalent operating hours minimum, operating threshold and other remuneration parameters. The parameters applicable to our plants for 2022 are as follows:follows, as approved by Order TED/1232/2022:
| Useful Life | | Return on Investment 2020-2022(euros/MW) | | | Operating Remuneration 2022 (euros/GWh) | | | Maximum Hours | | | Minimum Hours | | | Operating Threshold | | Useful Life
| | Remuneration on Investment 2022 (euros/MW) | | Remuneration on Operation 2022 (euros/GWh) | | Maximum Hours | | Minimum Hours | | Operating Threshold | |
Solaben 2 | 25 years | | 398,174 | | | 45,85 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 390,453 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Solaben 3 | 25 years | | 398,174 | | | 45,85 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 390,453 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Solacor 1 | 25 years | | 398,174 | | | 45,85 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 390,453 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Solacor 2 | 25 years | | 398,174 | | | 45,85 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 390,453 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
PS 10 | 25 years | | 550,263 | | | 68,32 | | | 1,840 | | | 1,109 | | | 647 | | 25 years | | | 543,185 | | | | 7,580 | | | | 1,840 | | | | 1,104 | | | | 644 | |
PS 20 | 25 years | | 407,269 | | | 62,46 | | | 1,840 | | | 1,109 | | | 647 | | 25 years | | | 401,296 | | | | 1,777 | | | | 1,840 | | | | 1,104 | | | | 644 | |
Helioenergy 1 | 25 years | | 393,071 | | | 45,66 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 385,014 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Helioenergy 2 | 25 years | | 393,071 | | | 45,66 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 385,014 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Helios 1 | 25 years | | 407,037 | | | 46,19 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 398,498 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Helios 2 | 25 years | | 407,037 | | | 46,19 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 398,498 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Solnova 1 | 25 years | | 413,423 | | | 46,55 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 404,292 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Solnova 3 | 25 years | | 413,423 | | | 46,55 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 404,292 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Solnova 4 | 25 years | | 413,423 | | | 46,55 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 404,292 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Solaben 1 | 25 years | | 403,599 | | | 46,06 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 395,304 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Solaben 6 | 25 years | | 403,599 | | | 46,06 | | | 2,008 | | | 1,210 | | | 706 | | 25 years | | | 395,304 | | | | 0 | | | | 2,008 | | | | 1,205 | | | | 703 | |
Seville PV | 30 years | | 709,200 | | | 33,23 | | | 2,041 | | | 1,237 | | | 721 | | 30 years | | | 696,418 | | | | 0 | | | | 2,041 | | | | 1,225 | | | | 714 | |
For the three-year half period starting on January 1, 2023 and ending on December 31, 2025, the adjustment for electricity price deviations in the preceding statutory half period will be progressively modified to take into account a mix of actual market prices and future market prices.
In addition, on December 28, 2022 the proposed parameters for the year 2023 were published in draft form. They are subject to review (the public information phase ended on January 20, 2023) and are as follows:
| Useful Life
| | Remuneration on Investment 2023(euros/MW) | | | Remuneration On Operation 2023 (euros/GWh) | | | Maximum Hours | | | Minimum Hours | | | Operating Threshold | |
Solaben 2 | 25 years | | | 358,562 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Solaben 3 | 25 years | | | 358,562 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Solacor 1 | 25 years | | | 358,562 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Solacor 2 | 25 years | | | 358,562 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
PS 10 | 25 years | | | 509,713 | | | | 0 | | | | 1,837 | | | | 1,102 | | | | 643 | |
PS 20 | 25 years | | | 373,114 | | | | 0 | | | | 1,837 | | | | 1,102 | | | | 643 | |
Helioenergy 1 | 25 years | | | 351,751 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Helioenergy 2 | 25 years | | | 351,751 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Helios 1 | 25 years | | | 365,595 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Helios 2 | 25 years | | | 365,595 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Solnova 1 | 25 years | | | 368,603 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Solnova 3 | 25 years | | | 368,603 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Solnova 4 | 25 years | | | 368,603 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Solaben 1 | 25 years | | | 363,530 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Solaben 6 | 25 years | | | 363,530 | | | | 0 | | | | 2,004 | | | | 1,202 | | | | 701 | |
Seville PV | 30 years | | | 654,194 | | | | 0 | | | | 2,030 | | | | 1,218 | | | | 711 | |
Electricity Sales Tax
On December 27, 2012, the Spanish Parliament approved Law 15/2012, which became effective on January 1, 2013. The aim of Law 15/2012 was to try to resolve the issue with so-called tariff deficit. Law 15/2012, as amended, provides for an electricity sales tax which is levied on activities related to electricity production. The tax is triggered by the sale of electricity and affects ordinary energy producers and those generating power from renewable sources. The tax, at a flat rate of 7%, is levied on the total income received from the power produced at each of the facilities, which means that every calendar year, solar power plants will be required to pay 7% of the total amount which they are entitled to receive for production and incorporation into the electricity system of electric power, measured as the net output generated.
In January 2021, the Spanish Courts referred a preliminary ruling to the Court of Justice of the EU related to the validity of the electricity sales tax. The Court of Justice of the EU declared the conformity of this tax to the EU legislation in March 2021.
However, the Royal Decree-Law 12/2021 and the Royal Decree-Law 17/2021 included an exemption from this tax, for the electricity produced and incorporated into the electricity system during the third and last calendar quarter of 2021. This entails modifying the calculation of the tax base and of the fractioned payments regulated in the tax regulations.
The Royal Decree-Law 29/2021 has extended those measures to the first calendar quarter of 2022. These measures were further extended to 2022 and 2023.
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:
Assets under development and construction Assets in operation 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.Sacyr holds 25.5% of Honaine and 16.9%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 ATN2 ATN 2 |
(9) | 87.5% owned by Starwood |
(10) | 49% owned by Industrial Development Corporation, a South African Government company |
(11) | 70% owned by Arroyo Energy |
(12) | 100% indirectly owned by Arroyo Energy Netherlands II |
(13) | 70% held by Algonquin |
(14) | Solar and wind projects under development in Uruguay |
(15) | 65% held by financial partners |
(15)(16) | Solar projects 100% owned by Chile Platform |
(16)(18) | 51% held by EDP Renewables EDPR |
(17)(19) | Simplified structure |
(20) | Solar and battery project under development in the US |
(21) | Solar projects under development in Colombia including (Honda 1, Honda 2 and Apulo 1) |
(22) | Coso Batteries 1, the standalone battery storage project of 100 MWh (4 hours) capacity |
(23) | 49% in solar projects in Chile. Simplified structure. 51% held by Akuo Energy Chile |
(25) | ATN also owns a transmission line and substation under development in Peru |
D. | Property, Plant and Equipment |
See “Item 4.B—Business Overview.”
ITEM 4A. | UNRESOLVED STAFF COMMENTS |
Not applicable.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.In 2021, our renewable sector represented 77% of our revenue, with solar energy representing 69%. We complement our portfolio of renewable assets with storage, efficient natural gas and heat and transmission infrastructure assets, as enablers of the transition towards a clean energy mix. We are also present in water infrastructure assets, a sector at the core of sustainable development. Our purpose is to support the transition towards a more sustainable world by investing in and managing sustainable infrastructure, while creating long-term value for our investors and the rest of our stakeholders. In 2022, our renewable sector represented 75% of our revenue, with solar energy representing 64%. 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. 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 20212022
Investments
In April 2020, we made an investment in the creation of a renewable energy platform in Chile, together with financial partners, in which we now own approximately a 35% stake and have a strategic investor role. In January 2021, we closed our second investment through this platform with the acquisition of Chile PV 2, a 40 MW PV plant. Total equity investment in this new asset was $5.0 million. The platform intends to make further investments in renewable energy in Chile and sign PPAs with creditworthy off-takers.
In January 2021, we closed the acquisition of a 42.5% equity interest in Rioglass, a supplier of spare parts and services in the solar industry, increasing our equity interest to 57.5%. In addition, on July 22, 2021, we exercised the option to acquire the remaining 42.5% equity interest in Rioglass. The total investment made in 2021 to acquire the additional 85% equity interest, resulting in a 100% ownership, was $17.1 million.
In April 2021, we closed the acquisition of Coso, a 135 MW renewable asset in California. Coso is the third largest geothermal plant in the United States and provides base load renewable energy to the California Independent System Operator (California ISO). It has PPAs signed with an 18-year average contract life. The total equity investment was $130 million, which was paid in April 2021. In addition, on July 15, 2021, we repaid $40 million of project debt.
In May 2021, we closed the acquisition of Calgary District Heating, a district heating asset in Canada, for a total equity investment of $22.7 million. The asset has availability-based revenue with inflation indexation and 20 years of weighted average contract life at the time of the acquisition. Contracted capacity and volume payments represent approximately 80% of the total revenue.
In June 2021, we closed the acquisition of a 49% interest in Vento II, a 596 MW wind portfolio in the U.S. for a total equity investment of $198.3 million. EDP Renewables owns the remaining 51%. The assets have PPAs with investment grade off-takers with five-year average remaining contract life at the time of the investment.
In August 2021, we closed the acquisition of Italy PV 1 and Italy PV 2, two solar PV plants in Italy with a combined capacity of 3.7 MW for a total equity investment of $9 million. These assets have regulated revenues under a feed in tariff until 2030 and 2031, respectively.
In November 2021, we closed the acquisition of La Sierpe, a 20 MW solar PV plant in Colombia for a total equity investment of $23.5 million. The asset was acquired under our Liberty GES ROFO Agreement. We also acquired two additional solar projects in Colombia with a combined capacity of 30 MW which are currently in construction, la Tolua and Tierra Linda.
In December 2021, we closed the acquisition of Italy PV 3, a 2.5 MW solar portfolio in Italy for a total equity investment of $4.0 million. The four assets in the portfolio have regulated revenues under a feed in tariff until 2032.
In October 2018, we reached an agreement to acquire PTS, a natural gas transportation platform located in Mexico. We initially acquired a 5% stake in the project and reached an agreement to increase our equity interest. Given that the project financing did not close, in June 2021, we reached an agreement with our partner to sell our 5% ownership in the project at cost. There are no other costs or liabilities related to this investment.
In January 2022, we closed the acquisition of Chile TL4, a 63-mile transmission line and 2 substations in Chile for a total equity investment of $39$38.4 million. We expect to make an expansion ofexpand the transmission line in 2022,2023-2024, which would represent an additional investment of approximately $8 million. The asset has fully contracted revenues in USU.S. dollars, with annual inflation escalationadjustments and a 50-year remaining contract life. The off-takers are several mini-hydro plants that receive contracted or regulated payments.
In April 2022, we closed the acquisition of Italy PV 4, a 3.6 MW solar portfolio in Italy for a total equity investment of $3.7 million. The asset has regulated revenues under a feed-in tariff until 2031.
Corporate Financing Activities during
In May 2022, together with our partner, we closed a 7.5-year PPA extension for Monterrey with our current off-takers. The extension will involve an investment that is expected to be financed with cash available at the yearasset level. The main objective of the investment is to achieve improvements in the asset to provide, among other things, additional battery capacity and additional redundancy of electric power supply. The PPA, which is denominated in U.S. dollars, now ends in 2046.
On January 7, 2021, Algonquin purchased 4,020,860 ordinary sharesIn July 2022 we closed a 12-year transmission service agreement denominated in U.S. dollars that will allow us to build a private placementsubstation and a 2.4-mile transmission line connected to our ATN transmission line serving a new mine in orderPeru. The substation is expected to maintain itsenter in operation in 2024 and the investment is expected to be approximately $12 million.
In September 2022, we closed the acquisition of Chile PV 3, a 73 MW solar PV plant through our renewable energy platform in Chile. The equity investment corresponding to our 35% equity interest was $8 million, and we expect to install batteries with a capacity of approximately 100 MWh in 2023-2024. Total investment including batteries is expected to be in the Company, as a consequencerange of $15 million to $25 million depending on the capital structure. Part of the prior underwritten public offeringasset’s revenue is currently based on capacity payments. Adding storage would increase the portion of 5,069,200 ordinary shares in December 2020. Gross proceeds of the private placement were $300 million, which were used to finance growth opportunities and for general corporate purposes after deducting underwriting discounts and commissions and offering expenses.capacity payments.
On May 18, 2021,In September 2022, we issuedagreed our first investment in a standalone battery storage project of 100 MWh (4 hours) capacity located inside Coso, our geothermal asset in California. Our investment is expected to be in the Green Senior Notes amountingrange of $40 million to $50 million. This project is at an aggregate principal amountadvanced stage and we are preparing to start construction, with COD expected in 2024.
In November 2022, we closed the acquisition of $400a 49% interest, with joint control, in an 80 MW portfolio of solar PV projects in Chile which is currently starting construction (Chile PMGD). Our economic rights are expected to be approximately 70%. Total investment in equity and preferred equity is expected to be approximately $30 million dueand COD is expected to be progressive in 2028. The Green Senior Notes bear interest at2023 and 2024. Revenue for these assets is regulated under the Small Distributed Generation Means Regulation Regime (“PMGD”) for projects with a ratecapacity equal or lower than 9 MW which allows to sell electricity through a stabilized price.
In addition, we have finished construction of 4.125% per year, payable on June 15the three assets that we had under construction during 2022 and December 15 of each year, commencing December 15, 2021, and will mature on June 15, 2028. The proceeds were usedhave reached or are about to fully prepay the Note Issuance Facility 2019 and to finance investments and acquisitions.reach COD:
| - | Albisu, the 10 MW PV asset wholly owned by us reached COD in January 2023. Albisu is located in Uruguay and has a 15-year PPA with Montevideo Refrescos, S.R.L, a subsidiary of Coca-Cola Femsa., S.A.B. de C.V. The PPA is denominated in local currency with a maximum and minimum price in U.S. dollars and is adjusted monthly based on a formula referring to the U.S. Producer Price Index (PPI), Uruguay’s Consumer Price Index (CPI) and the applicable UYU/U.S. dollar exchange rate. |
| - | La Tolua and Tierra Linda are two solar PV assets in Colombia with a combined capacity of 30 MW. Each plant has a 10-year PPA (commencing on COD) in local currency with Coenersa, the largest independent electricity wholesaler in Colombia. |
Corporate Financing Activities
On August 3, 2021,February 28, 2022, we established an “at-the-market program” and entered into the Distribution Agreement with J.P. MorganBofA Securities, Inc., MUFG Securities Americas Inc. and RBC Capital Markets LLC, as our sales agent,agents, under which we may offer and sell from time to time up to $150 million of our ordinary shares, including in “at-the-market” offerings under our universal shelf registration statement on Form F-3 filed with the SEC on August 3, 2021, and a prospectus supplement that we filed on August 3, 2021. DuringFebruary 28, 2022. For the thirdyear ended December 31, 2022, we issued and fourth quarters, we have issued 1.6 millionsold 3,423,593 ordinary shares under thesuch program at an average market price of $38.43$33.57 per share pursuant to theour Distribution Agreement, representing gross proceeds of $114.9 million and net proceeds of $61.4$113.8 million. This program replaced our previous “at-the market program” with J.P. Morgan Securities, LLC.
Project Debt Refinancing
In October 2022, we refinanced the project debt of Solacor 1 & 2 and in December 2022, we refinanced the project debt of Solnova 1, 3 & 4 (see “Item 4— Information on the Company—Our Operations —Renewable Energy”)
Regulation in Spain
As expected, in 2022 the Administration in Spain approved measures to adjust the regulated revenue component for renewable energy plants, following the increase since mid-2021 in the billings of these plants for the sale of electricity in the market. On March 30, 2022, 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 gas and electricity prices. 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. The proposed remuneration parameters for the year 2022 were published on May 12, 2022 in draft form and became final on December 14, 2022 (see “Item 4 — Information on the Company—Regulation in Spain”).
Inflation Reduction Act
On August 16, 2022, the U.S. Inflation Reduction Act (“IRA”) was signed into law. The provisions of the IRA are intended to, among other things, incentivize clean energy investment. The IRA includes, among other incentives, a 30% solar ITC for solar projects to be built until 2032, that can be increased for projects that meet certain criteria, 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 (see “Item 4 — Information on the Company—Regulation —Regulation in the United States”).
Recent Developments
On February 21, 2023, Atlantica’s board of directors commenced a strategic review process (see “Item 4 — Information on the Company—Recent Developments).
Factors Affecting the Comparability of Our Results of Operations
Investments, Acquisitions, New Assets and Non-recurrent Projects
The results of operations of Chile PV 1 and Tenes have been fully consolidated since April and May 2020, respectively. Tenes was recorded under the equity-method from January 2019 to May 2020, at which point we then gained control over the asset and started to fully consolidate it. The results of operations of Chile PV 2, Coso, Calgary District Heating, Italy PV 1, and Italy PV 2, La Sierpe, Italy PV 3, Chile TL4, Italy PV 4 and ItalyChile PV 3 have been fully consolidated since January, April 2021, May 2021, August 2021 for Italy PV 1 and August,Italy PV 2, November and2021, December 2021, January 2022, April 2022 and September 2022, respectively. Vento II has been recorded under the equity method since June 2021. These investments and acquisitions represent additional revenue for $30.4 million and additional Adjusted EBITDA of $26.2 million for the year ended December 31, 2022, when compared to the year ended December 31, 2021.
In addition, the results of operations of Rioglass have been fully consolidated since January 2021. InFor the year ended December 31, 2021, most of Rioglass operating results relate to a specific solar project which ended in October 2021, and which represented $85.3 million in revenue and $1.0 million in Adjusted EBITDA, included in our EMEA and Renewable energy segments for the year ended December 31, 2021, and which are non-recurrent.
Impairment
Considering the delays in the improvementsrepairs and replacements that we are carrying out in the storage system inat Solana and their impact on production in 2021,2022, as well as an increase in the discount rate, we identified an impairment triggering event in accordance with IAS 36 (Impairment of Assets). As a result, an impairment test has been performed which resulted in the recording of an impairment loss of $43.1$41.2 million for the year ended December 31, 2021in 2022 in the line “Depreciation, amortization, and impairment charges”. In 2021, we recorded an impairment loss of $43.1 million at Solana.
In addition, in 2022, considering that expected electricity prices in Chile over the remaining useful life of Chile PV1 and Chile PV2 have decreased and are currently lower than the prices assumed at the time of the acquisition, 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 $20.4 million in 2022 in the line “Depreciation, amortization, and impairment charges”.
Furthermore, IFRS 9 requires impairment provisions to be based on expected credit losses on financial assets rather than on actual credit losses. For the year ended December 31, 2022 we recorded an expected credit loss impairment provision of $4.0 million which is reflected in the line item “Depreciation, amortization, and impairment charges”. In 2021, we recorded a reversal of the expected credit loss impairment provision at ACT for $24.9 million following an improvement of its client’s credit risk metrics which is reflected in the line item “Depreciation, amortization, and impairment charges”. In 2020 we had recorded a $26.6 million impairment provision in ACT.metrics.
Change in the useful life of the solar plants in Spain
In September 2020, following a thorough analysis of recent developments in the Energy and Climate Policy Framework adopted by Spain in 2020, we decided to reduce the useful life of the solar plants in Spain from 35 years to 25 years after COD, effective from September 1, 2020. This change in the estimated useful life was accounted for as a change in accounting estimates in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors. This caused a $46.0 million increase if we compare the results of the two years since the change was applied for twelve months in 2021 and only four months in 2020.
Electricity market prices
In addition to regulated revenue, our solar assets in Spain receive revenue from the sale of electricity at market prices. Electricity prices have increased significantly since mid-2021 and revenuesrevenue from the sale of electricity at powercurrent market prices represented $132.9$142.9 million in 2021for the year ended December 31, 2022, compared to 42.9$129.1 million for the year ended December 31, 2021, resulting in 2020, causing higher short-term cash collections. Regulated revenues are revised every three yearsperiodically to reflect, among other things, the difference between expected and actual market prices if the difference is higher than a pre-defined threshold. Current higher market prices in Spain will therefore cause lower regulated revenue to be received progressively over the remaining regulatory life of our solar assets. As a result, we recorded a negativeincreased our provision by $25.3 million for $77.1 millionthe year ended December 31, 2022, with no cash impact on the current period, that has lowered revenue and Adjusted EBITDA in this geography, compared to a positivean increase of $77.1 million for the year ended December 31, 2021.
On May 12, 2022 remuneration parameters in Spain for the year 2022 were published and became final on December 14, 2022. Revenue from the sale of electricity at market prices plus Ro (Remuneration on operation) less incremental market price provision reversalwas $117.6 million for $22.3the year ended December 31, 2022, compared to $107.7 million for the year ended December 31, 2021. In 2022 we collected revenue from our assets in 2020.
line with the parameters corresponding to the regulation in place at the beginning of the year902022, as the new parameters became final on December 14, 2022, while revenue for the year ended December 31, 2022, was recorded in accordance with the new parameters. Collections have started to be regularized in 2023, see “Item 4 — Information on the Company—Regulation in Spain”.
Exchange rates
We refer to “Item 5—Operating and Financial Review and Prospects —Significant Trends Affecting Results of Contents
Operations—Exchange Rates” below.
Significant Trends Affecting Results of Operations
Acquisitions
and New AssetsIf the acquisitions recently closed and new assets recently built perform as expected, we expect these assets to positively impact our results of operations in 20222023 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 ourtheir 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,euros; Kaxu, our solar plant in South Africa, has its revenue and expenses denominated in South African rand, and La Sierpe, La Tolua and Tierra Linda, our solar plantplants in Colombia, has itshave their revenue and expenses denominated in Colombian pesos. pesos and Albisu, our solar plant in Uruguay, has its revenue denominated in Uruguayan pesos, with a maximum and a minimum price in US dollars.
Project financing is typically denominated in the same currency as that of the contracted revenue agreement. This policy seeksagreement, which limits our exposure to ensure that the main revenue and expenses streams in foreign companies are denominated in the same currency, limiting our risk of foreign exchange differencesrisk. 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 financial results.
Ourassets 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(after deducting euro-denominated interest payments and euro-denominated general and administrative expenses.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 South African rand and Colombian peso with respect to the U.S. dollar may also affect our operating results. Apart from the impact of these translation differences, the exposure of our income statement to fluctuations of foreign currencies is limited, as the financing of projects is typically denominated in the same currency as that of the contracted revenue agreements.
In our discussion of operating results, we have included foreign exchange impacts in our revenue by providing constant currency revenue growth. The constant currency presentation is not a measure recognized under IFRS and excludes the impact of fluctuations in foreign currency exchange rates. We believe providing constant currency information provides valuable supplemental information regarding our results of operations. We calculate constant currency amounts by converting our current period local currency revenue using the prior period foreign currency average exchange rates and comparing these adjusted amounts to our prior period reported results. This calculation may differ from similarly titled measures used by others and, accordingly, the constant currency presentation is not meant to substitute recorded amounts presented in conformity with IFRS as issued by the IASB, nor should such amounts be considered in isolation.
Impacts associated with fluctuations in foreign currency are discussed in more detail under “Item 11—Quantitative and Qualitative Disclosure about Market Risk—Foreign exchange risk”. Fluctuations in the value of the South African rand in relation to the U.S. dollar may also affect our operating results.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, 2021,2022, approximately 92% of our project debt and close to 100%96% of our corporate debt either has fixed interest rates or has been hedged with swaps or caps. Nevertheless, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates, which typically bear a spread over EURIBOR, LIBOR, SOFR or over the alternative rates replacing these.
Electricity market prices
In addition to regulated revenue,As previously discussed, our solar assets in Spain receive revenue from the sale of electricity at market prices.prices in addition to regulated revenue. Regulated revenues are revised every three yearsperiodically to reflect the difference between expected and actual market prices if the difference is higher than a pre-defined threshold. Given that since mid-2021 electricity prices in Spain have been, and may continue to be, significantly higher than expected, it will cause lower regulated revenue starting in 2023 over the remaining regulatory life of our solar assets. Also,On December 28, 2022, the regulator orparameters applicable for the administration may change or may create new mechanismsyear 2023 were published in draft form and are subject to adjustfinal publication (see “Item 4—Information on the priceCompany — Regulation— Spain”). Additionally, our assets in Italy have contracted revenues through a regulated feed in premium in addition to merchant revenues for the energy sold to the wholesale market.
Furthermore, we currently have three assets with merchant revenues (Chile PV 1 and Chile PV 3, where we have a material adverse effect on35% ownership, and Lone Star II, where we have a 49% ownership) and one asset with partially contracted revenues (Chile PV 2, where we have a 35% ownership). Our exposure to merchant electricity prices represents less than 2% of our business, financial condition, resultsportfolio8 in terms of operations and cash flows.
Adjusted EBITDA. In Lone Star II we are analyzing, together with our partner, the option to repower the asset in the context of the IRA, at a point in time to be determined.
Key Financial Measures
Our revenue and Adjusted EBITDA by geography and business sector for the years ended December 31, 2022, 2021 2020 and 20192020 are set forth in the following tables:
Revenue by geography
| | Year ended December 31, | |
| | 2021 | | | 2020 | | | 2019 | |
| | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | |
North America | | $ | 395.8 | | | | 32.7 | % | | $ | 330.9 | | | | 32.6 | % | | $ | 333.0 | | | | 32.9 | % |
South America | | | 155.0 | | | | 12.8 | % | | | 151.5 | | | | 15.0 | % | | | 142.2 | | | | 14.1 | % |
EMEA | | | 660.9 | | | | 54.5 | % | | | 530.9 | | | | 52.4 | % | | | 536.3 | | | | 53.0 | % |
Total revenue | | $ | 1,211.7 | | | | 100.0 | % | | $ | 1,013.3 | | | | 100.0 | % | | $ | 1,011.5 | | | | 100.0 | % |
| | Year ended December 31, | |
| | 2022 | | | 2021 | | | 2020 | |
| | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | |
North America | | $ | 405.1 | | | | 36.8 | % | | $ | 395.8 | | | | 32.7 | % | | $ | 330.9 | | | | 32.6 | % |
South America | | | 166.4 | | | | 15.1 | % | | | 155.0 | | | | 12.8 | % | | | 151.5 | | | | 15.0 | % |
EMEA | | | 530.5 | | | | 48.1 | % | | | 660.9 | | | | 54.5 | % | | | 530.9 | | | | 52.4 | % |
Total revenue | | $ | 1,102.0 | | | | 100.0 | % | | $ | 1,211.7 | | | | 100.0 | % | | $ | 1,013.3 | | | | 100.0 | % |
Revenue by business sector
| | Year ended December 31, | |
| | 2021 | | | 2020 | | | 2019 | |
| | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | |
Renewable Energy | | $ | 928.5 | | | | 76.6 | % | | $ | 753.1 | | | | 74.3 | % | | $ | 761.1 | | | | 75.2 | % |
Efficient natural gas & Heat | | | 123.7 | | | | 10.2 | % | | | 111.0 | | | | 11.0 | % | | | 122.3 | | | | 12.1 | % |
Transmission Lines | | | 105.6 | | | | 8.7 | % | | | 106.1 | | | | 10.5 | % | | | 103.5 | | | | 10.2 | % |
Water | | | 53.9 | | | | 4.5 | % | | | 43.1 | | | | 4.2 | % | | | 24.6 | | | | 2.4 | % |
Total revenue | | $ | 1,211.7 | | | | 100.0 | % | | $ | 1,013.3 | | | | 100.0 | % | | $ | 1,011.5 | | | | 100.0 | % |
| | Year ended December 31, | |
| | 2022 | | | 2021 | | | 2020 | |
| | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | |
Renewable Energy | | $ | 821.4 | | | | 74.5 | % | | $ | 928.5 | | | | 76.6 | % | | $ | 753.1 | | | | 74.3 | % |
Efficient natural gas & Heat | | | 113.6 | | | | 10.3 | % | | | 123.7 | | | | 10.2 | % | | | 111.0 | | | | 11.0 | % |
Transmission Lines | | | 113.2 | | | | 10.3 | % | | | 105.6 | | | | 8.7 | % | | | 106.1 | | | | 10.5 | % |
Water | | | 53.8 | | | | 4.9 | % | | | 53.9 | | | | 4.5 | % | | | 43.1 | | | | 4.2 | % |
Total revenue | | $ | 1,102.0 | | | | 100.0 | % | | $ | 1,211.7 | | | | 100.0 | % | | $ | 1,013.3 | | | | 100.0 | % |
Adjusted EBITDA by geography
| | Year ended December 31, | |
| | 2022 | | | 2021 | | | 2020 | |
| | $ in millions | | | % of Adjusted EBITDA | | | $ in millions | | | % of Adjusted EBITDA | | | $ in millions | | | % of Adjusted EBITDA | |
North America | | $ | 310.0 | | | | 38.9 | % | | $ | 311.8 | | | | 37.8 | % | | $ | 279.4 | | | | 35.1 | % |
South America | | | 126.5 | | | | 15.9 | % | | | 119.6 | | | | 14.5 | % | | | 120.0 | | | | 15.1 | % |
EMEA | | | 360.6 | | | | 45.2 | % | | | 393.0 | | | | 47.7 | % | | | 396.7 | | | | 49.8 | % |
Total Adjusted EBITDA | | $ | 797.1 | | | | 100.0 | % | | $ | 824.4 | | | | 100.0 | % | | $ | 796.1 | | | | 100.0 | % |
8 Calculated as a percentage of our Adjusted EBITDA in 2022.
Adjusted EBITDA by geography
| | Year ended December 31, | |
| | 2021 | | | 2020 | | | 2019 | |
| | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | |
North America | | $ | 311.8 | | | | 78.8 | % | | $ | 279.4 | | | | 84.4 | % | | $ | 307.2 | | | | 92.3 | % |
South America | | | 119.6 | | | | 77.2 | % | | | 120.0 | | | | 79.2 | % | | | 115.4 | | | | 81.2 | % |
EMEA | | | 393.0 | | | | 59.5 | % | | | 396.7 | | | | 74.7 | % | | | 399.0 | | | | 74.4 | % |
Adjusted EBITDA(1) | | $ | 824.4 | | | | 68.0 | % | | $ | 796.1 | | | | 78.6 | % | | $ | 821.6 | | | | 81.2 | % |
Adjusted EBITDA by business sector
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | 2020 | | 2019 | | | 2022 | | 2021 | | 2020 | |
| | $ in millions | | % of revenue | | $ in millions | | % of revenue | | $ in millions | | % of revenue | | | $ in millions | | % of Adjusted EBITDA | | $ in millions | | % of Adjusted EBITDA | | $ in millions | | % of Adjusted EBITDA | |
Renewable Energy | | $ | 602.6 | | | | 64.9 | % | | $ | 576.3 | | | | 76.5 | % | | $ | 604.1 | | | | 79.4 | % | | $ | 588.0 | | | | 73.8 | % | | $ | 602.6 | | | | 73.1 | % | | $ | 576.3 | | | | 72.4 | % |
Efficient natural gas & Heat | | | 100.0 | | | | 80.8 | % | | | 101.0 | | | | 91.0 | % | | | 109.2 | | | | 89.3 | % | | | 84.6 | | | | 10.6 | % | | | 100.0 | | | | 12.1 | % | | | 101.0 | | | | 12.7 | % |
Transmission Lines | | | 83.6 | | | | 79.2 | % | | | 87.3 | | | | 82.3 | % | | | 85.7 | | | | 82.8 | % | | | 88.0 | | | | 11.0 | % | | | 83.6 | | | | 10.2 | % | | | 87.3 | | | | 11.0 | % |
Water | | | 38.2 | | | | 70.9 | % | | | 31.5 | | | | 73.1 | % | | | 22.6 | | | | 91.9 | % | | | 36.5 | | | | 4.6 | % | | | 38.2 | | | | 4.6 | % | | | 31.5 | | | | 3.9 | % |
Adjusted EBITDA(1) | | $ | 824.4 | | | | 68.0 | % | | $ | 796.1 | | | | 78.6 | % | | $ | 821.6 | | | | 81.2 | % | |
Total Adjusted EBITDA | | | $ | 797.1 | | | | 100.0 | % | | $ | 824.4 | | | | 100.0 | % | | $ | 796.1 | | | | 100.0 | % |
Note:—
(1)
Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership). Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”
Reconciliation of profit/(loss) for the year to Adjusted EBITDA
The following table sets forth a reconciliation of Adjusted EBITDA to our net cash generated by or used in operating activities:
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | | 2020 | | | 2019 | | | 2022 | | | 2021 | | | 2020 | |
| | ($ in millions) | | | ($ in millions) | |
Profit/(loss) for the year attributable to the parent company | | $ | (30.1 | ) | | $ | 11.9 | | | $ | 62.1 | | | $ | (5.4 | ) | | $ | (30.1 | ) | | $ | 11.9 | |
Profit/(loss) attributable to non-controlling interest from continued operations | | | 19.2 | | | | 4.9 | | | | 12.5 | | |
Profit/(loss) attributable to non-controlling interest | | | | 3.3 | | | | 19.2 | | | | 4.9 | |
Income tax expense | | | 36.2 | | | | 24.9 | | | | 30.9 | | | | (9.7 | ) | | | 36.2 | | | | 24.9 | |
Depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of our equity ownership)
| | | 18.7 |
| | | 13.9 |
| | | 3.0 |
| |
Financial expense, net | | | 340.9 | | | | 331.8 | | | | 402.3 | | | | 310.9 | | | | 340.9 | | | | 331.8 | |
Depreciation, amortization and impairment charges | | | 439.4 | | | | 408.6 | | | | 310.8 | | | | 473.6 | | | | 439.4 | | | | 408.6 | |
Depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership) | | | | 24.4 | | | | 18.7 | | | | 13.9 | |
Adjusted EBITDA | | $ | 824.4 | | | $ | 796.1 | | | $ | 821.6 | | | $ | 797.1 | | | $ | 824.4 | | | $ | 796.1 | |
Reconciliation of net cash generated by operating activities to Adjusted EBITDA
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | | 2020 | | | 2019 | | | 2022 | | | 2021 | | | 2020 | |
| | ($ in millions) | | | ($ in millions) | |
Net cash flow provided by operating activities
| | $ | 505.6 | | | $ | 438.2 | | | $ | 363.5 | | | $ | 586.3 | | | $ | 505.6 | | | $ | 438.2 | |
Net interest /taxes paid
| | | 342.3 | | | | 287.2 | | | | 299.5 | | | | 277.3 | | | | 342.3 | | | | 287.2 | |
Variations in working capital
| | | 3.1 | | | | 10.9 | | | | 125.0 | | | | (78.8 | ) | | | 3.1 | | | | 10.9 | |
Other non-monetary items
| | | (55.8 | ) | | | 43.9 | | | | 25.8 | | |
Share of profit/(loss) of associates carried under the equity method, depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership) and other | | | 29.2 | | | | 15.9 | | | | 7.8 | | |
Non-monetary items and other | | | | (33.5 | ) | | | (57.7 | ) | | | 45.3 | |
Share of profit/(loss) of entities carried under the equity method, depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership) | | | | 45.8 | | | | 31.1 | | | | 14.5 | |
| | $ | 824.4 | | | $ | 796.1 | | | $ | 821.6 | | | $ | 797.1 | | | $ | 824.4 | | | $ | 796.1 | |
Operational Metrics
In addition to the factors described above, we closely monitor the following key drivers of our business sectors’ performance to plan for our needs, and to adjust our expectations, financial budgets and forecasts appropriately.
• | MW in operation in the case of Renewable energy and Efficient natural gas and heat assets, miles in operation in the case of Transmission lines and Mft3 per day in operation in the case of Water assets, are indicators which provide information about the installed capacity or size of our portfolio of assets. |
Production measured in GWh in our Renewable energy and Efficient natural gas and heat assets provides information about the performance of these assets.
Availability in the case of our Efficient natural gas and heat assets, Transmission lines and Water assets also provides information on the performance of the assets. In these business segments revenues are based on availability, which is the time during which the asset was available to our client totally or partially divided by contracted availability or budgeted availability, as applicable.
Key Performance Indicators
| | As of and for the year ended December 31, | |
| | 2021 | | | 2020 | | | 2019 | |
Renewable Energy | | | | | | | | | |
MW in operation(1) | | | 2,044 | | | | 1,551 | | | | 1,496 | |
GWh produced(2) | | | 4,655 | | | | 3,244 | | | | 3,236 | |
Efficient natural gas & Heat | | | | | | | | | | | | |
MW in operation(3) | | | 398 | | | | 343 | | | | 343 | |
GWh produced(4) | | | 2,292 | | | | 2,574 | | | | 2,090 | |
Availability (%)(4) | | | 100.6 | % | | | 102.1 | % | | | 95.0 | % |
Transmission lines | | | | | | | | | | | | |
Miles in operation | | | 1,166 | | | | 1,166 | | | | 1,166 | |
Availability (%) | | | 100.0 | % | | | 100.0 | % | | | 100.0 | % |
Water | | | | | | | | | | | | |
Mft3 in operation(1) | | | 17.5 | | | | 17.5 | | | | 10.5 | |
Availability (%) | | | 97.9 | % | | | 100.1 | % | | | 101.2 | % |
| | As of and for the year ended December 31, | |
| | 2022 | | | 2021 | | | 2020 | |
Renewable Energy | | | | | | | | | |
MW in operation(1) | | | 2,121 | | | | 2,044 | | | | 1,551 | |
GWh produced(2) | | | 5,319 | | | | 4,655 | | | | 3,244 | |
Efficient natural gas & Heat | | | | | | | | | | | | |
MW in operation(3) | | | 398 | | | | 398 | | | | 343 | |
GWh produced(4) | | | 2,501 | | | | 2,292 | | | | 2,574 | |
Availability (%) | | | 98.9 | % | | | 100.6 | % | | | 102.1 | % |
Transmission lines | | | | | | | | | | | | |
Miles in operation | | | 1,229 | | | | 1,166 | | | | 1,166 | |
Availability (%) | | | 100 | % | | | 100.0 | % | | | 100.0 | % |
Water | | | | | | | | | | | | |
Mft3 in operation(1) | | | 17.5 | | | | 17.5 | | | | 17.5 | |
Availability (%) | | | 102.3 | % | | | 97.9 | % | | | 100.1 | % |
Note:
(1) | Represents total installed capacity in assets owned or consolidated at the end of the year, regardless of our percentage of ownership in each of the assets except for Vento II for which we have included our 49% interest. |
(2) | Includes 49% of Vento II wind portfolio production since its acquisition. Includes curtailment in wind assets for which we receive compensation |
(3) | Includes 43 MW corresponding to our 30% share in Monterrey and 55MWt corresponding to Calgary District Heating. |
(4) | GWh produced includes 30% of the production from Monterrey. |
Production in the renewable business sector increased by 43.5%14.3% in 2021,2022, compared to 2020.2021. The increase was mainly driven bylargely due to the contribution from the recently acquired renewable assets Coso, Chile PV1, Chile PV 2, Vento II, Italy PV 1, Italy PV 2, Italy PV 3, Italy PV 4, Chile PV 3 and La Sierpe bringing approximately 1,339812 GWh of additionalincremental electricity generation. The increase was also due to higher production at Kaxu compared to the prior year when an unscheduled outage that affected part of the first half of 2020, largely covered by insurance. Production also increased in our assets in Spain where solar radiation was better than in the previous year.
In our solar assets in the U.S. production decreased by 3.5% year over year mainly due to lower solar resourceradiation was higher in Arizona, especially in the third quarter, and lower availability in the storage system, as we are carrying out the improvements and replacements that were scheduled. These works have impacted production2022 than in 2021, and are expectedproduction increased by 0.7% compared to impactthe same period in the previous year. In our wind assets in the U.S., wind resource was mostly in line with expectations in the year ended December 31, 2022.
In Chile, production at our PV assets in 2022 as we have been experiencing delays due to COVID-19 restrictions and delayswas in line with the previous year, with an increase in Chile PV 1 mainly caused by better solar radiation largely offset by a decrease in Chile PV 2 resulting from subcontractors.
larger curtailments. In our wind assets in Uruguay, production decreased by 10.4% in 2021,3.8% mainly due to lower wind resource in the period. Wind resource was alsosecond and third quarters of 2022 compared to the same periods of the previous year.
In Spain, production decreased by 13.1% in 2022, partly due to lower than expectedsolar radiation compared to 2021. In addition, some of our assets experienced significant technical curtailments by the grid operator during the second quarter and the beginning of third quarter of 2022. At Kaxu, production increased in our wind assetsspite of lower solar radiation during the year mainly due to the scheduled maintenance stop performed in the United States.
third quarter of 2021.Efficient natural gas and heat availability and production was lowerlevels during 2022 were higher than in 2021 compared to 2020the same period of the previous year due to lower production at ACT, mainly due to lower demand from our off-taker. This did not affect our revenue as the contract is based on availability and continues to achieve high availability levels.
In Water, the decrease in availability was mainly due to lower availability in Tenes in the fourth quarter of 2021, resulting principally from the high number of suspended particles in the water caused by heavy rains in the region in the fourth quarter. Availability in this plantscheduled maintenance stops performed in the first quarter of 2021 and to higher demand from our off-taker in 2022 compared to 2021.
In Water, availability in 2022 was also lower largely due tohigher than in 2021, with very good performance in all the installation of some new safety-related equipment.assets. Our transmission lines, where revenue is also based on availability, continue to achieve high availability levels.
Results of Operations
The table below illustrates our results of operations for the years ended December 31, 2022, 2021 2020 and 2019.2020.
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | 2020 | | 2019 | | | 2022 | | 2021 | | 2020 | |
| | $ in millions | | | ($ in millions) | |
Revenue | | $ | 1,211.7 | | | $ | 1,013.3 | | | $ | 1,011.5 | | | $ | 1,102.0 | | | $ | 1,211.7 | | | $ | 1,013.3 | |
Other operating income | | | 74.6 | | | | 99.5 | | | | 93.8 | | | 80.8 | | | 74.6 | | | 99.5 | |
Employee benefit expenses | | | (78.7 | ) | | | (54.4 | ) | | | (32.2 | ) | | (80.2 | ) | | (78.7 | ) | | (54.4 | ) |
Depreciation, amortization and impairment charges | | | (439.4 | ) | | | (408.6 | ) | | | (310.8 | ) | | (473.6 | ) | | (439.4 | ) | | (408.6 | ) |
Other operating expenses | | | (414.3 | ) | | | (276.7 | ) | | | (261.8 | ) | | | (351.3 | ) | | | (414.3 | ) | | | (276.7 | ) |
Operating profit/(loss) | | $ | 353.9 | | | $ | 373.1 | | | $ | 500.4 | | | $ | 277.7 | | | $ | 353.9 | | | $ | 373.1 | |
Financial income | | | 2.7 | | | | 7.1 | | | | 4.1 | | | 5.6 | | | 2.7 | | | 7.1 | |
Financial expense | | | (361.2 | ) | | | (378.4 | ) | | | (408.0 | ) | | (333.3 | ) | | (361.2 | ) | | (378.4 | ) |
Net exchange differences | | | 1.9 | | | | (1.4 | ) | | | 2.7 | | | 10.3 | | | 1.9 | | | (1.4 | ) |
Other financial income/(expense), net | | | 15.7 | | | | 40.9 | | | | (1.1 | ) | | | 6.5 | | | | 15.7 | | | | 40.9 | |
Financial expense, net | | $ | (340.9 | ) | | $ | (331.8 | ) | | $ | (402.3 | ) | | $ | (310.9 | ) | | $ | (340.9 | ) | | $ | (331.8 | ) |
Share of profit/(loss) of associates carried under the equity method | | | 12.3 | | | | 0.5 | | | | 7.4 | | |
Share of profit/(loss) of entities carried under the equity method | | | | 21.4 | | | | 12.3 | | | | 0.5 | |
Profit/(loss) before income tax | | $ | 25.3 | | | $ | 41.8 | | | $ | 105.6 | | | $ | (11.8 | ) | | $ | 25.3 | | | $ | 41.8 | |
Income tax expense | | | (36.2 | ) | | | (24.9 | ) | | | (30.9 | ) | | | 9.7 | | | | (36.2 | ) | | | (24.9 | ) |
Profit/(loss) for the year | | $ | (10.9 | ) | | $ | 16.9 | | | $ | 74.6 | | | $ | (2.1 | ) | | $ | (10.9 | )
| | $ | 16.9 | |
Profit/(loss) attributable to non-controlling interests | | | (19.2 | ) | | | (4.9 | ) | | | (12.5 | ) | |
Profit attributable to non-controlling interests | | | | (3.3 | ) | | | (19.2 | ) | | | (4.9 | ) |
Profit / (loss) for the year attributable to the parent company | | $ | (30.1 | ) | | $ | 12.0 | | | $ | 62.1 | | | $ | (5.4 | ) | | $ | (30.1 | ) | | $ | 12.0 | |
Weighted average number of ordinary shares outstanding (thousands) - basic | | | 111,008 | | | | 101,879 | | | | 101,063 | | |
Weighted average number of ordinary shares outstanding (thousands) - diluted | | | 114,523 | | | | 103,392 | | | | 101,063 | | |
Weighted average number of ordinary shares outstanding (thousands) – basic | | | 114,695 | | | 111,008 | | | 101,879 | |
Weighted average number of ordinary shares outstanding (thousands) – diluted | | | 118,501 | | | 114,523 | | | 103,392 | |
Basic earnings per share attributable to the parent company (U.S. dollar per share) | | | (0.27 | ) | | | 0.12 | | | | 0.61 | | | (0.05 | ) | | (0.27 | ) | | 0.12 | |
Diluted earnings per share attributable to the parent company (U.S. dollar per share) | | | (0.26 | ) | | | 0.12 | | | | 0.61 | | | (0.05 | ) | | (0.27 | ) | | 0.12 | |
Dividend paid per share(1) | | | 1.72 | | | | 1.66 | | | | 1.57 | | | 1.77 | | | 1.72 | | | 1.66 | |
Note:
(1) | On February 25, 2022, May 5, 2022, August 2, 2022 and November 8, 2022 our board of directors approved a dividend of $0.44, $0.44, $0.445 and $0.445 per share, respectively, corresponding to the fourth quarter of 2021, the first quarter of 2022, the second quarter of 2022 and the third quarter of 2022 which were paid on March 25, 2022, June 15, 2022, September 15, 2022, and December 15, 2022 respectively. On February 26, 2021, May 4, 2021, July 30, 2021 and November 9, 2021 our board of directors approved a dividend of $0.42, $0.43, $0.43 and $0.435 per share, respectively, corresponding to the fourth quarter of 2020, the first quarter of 2021, the second quarter of 2021 and the fourththird quarter of 2021, which were paid on March 22, 2021, June 15, 2021, September 15, 2021, and December 15, 2021 respectively. On February 26, 2020, May 6, 2020, July 31, 2020 and November 4, 2020, our board of directors approved a dividend of $0.41, $0.41, $0.42 and $0.42 per share corresponding to the fourth quarter of 2019, the first quarter of 2020, the second quarter of 2020 and the third quarter of 2021, respectively, which were paid on March 23, 2020, June 15, 2020, September 15, 2020 and December 15, 2020, respectively. |
Comparison of the Years Ended December 31, 20212022 and 20202021
The significant variances or variances of the significant components of the results of operations are discussed in the following section.
Revenue
Revenue increased by 19.6%decreased to $1,102.0 million for the year 2022, which represents a decrease of 9.1% compared to $1,211.7 million for the year 2021, compared to $1,013.3 million for the year 2020.2021. On a constant currency basis, revenue in 20212022, was $1,187.7$1,159.2 million, representing an increasewhich represents a decrease of 17.2%4.3% compared to the year 2020. On2021. Additionally, on a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project accounted for in 2021, revenue for the year 2021 was $1,102.3 million, representing an increase of 8.8% compared to the previous year.increased by 2.9% in 2022.
This increase (on a constant currency basis and excluding the Rioglass non-recurrent solar project) was mainly due to the contribution of the recently acquired and consolidated assets which represent a total of $92.3$30.4 million of additional revenue in 2022 compared to 2021. Revenue was alsoincreased in the U.S. and at Kaxu due to higher at Kaxu. Damage and business interruption were covered by our insurance; however, insurance proceeds were recorded in “Other operating income”.production during 2022 compared to 2021, as previously explained. In addition, revenue increasedremained stable at ACT mainlyour solar assets in Spain (0.4% increase on a constant currency basis and excluding the non-recurrent solar project), in spite of lower production during the year primarily due to higher electricity prices net of its corresponding accounting provision (see “Item 5—Operating and Financial Review and Prospects —Factors Affecting our Results of Operations—Electricity market prices”). In our wind assets in Uruguay, revenue increased in the portionspite of lower production as a result of the tariff related to operation and maintenance services, driven by higher operation and maintenance costs for the year 2021 compared to the previous year. At ACT, operation and maintenance costs are higher in the quarters preceding any major maintenance, which is scheduled for the beginning of 2022.
inflation adjustment. These effects were partially offset by a 4.8% decrease in revenue from our solar assetsat ACT in Spain on a constant currency basis, in spite of higher production in the period. The decrease results mainly from a negative provision that reduces revenue but has no cash impact on the current period, as further explained in the discussion of the EMEA region.Revenue also decreased in our solar assets in North America, mainly due to lower solar radiation in the year ended December 31, 20212022 compared to the previous year (due to the factors described under “—Revenue and lower availability of the storage system in Solana, as previously described.Adjusted EBITDA by business sector — Efficient natural gas & heat” below).
Other operating income
The following table sets forth our other operating income for the years ended December 31, 20212022 and 2020:2021:
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
Other operating income | | $ in millions | | | ($ in millions) | |
Grants | | $ | 60.7 | | | $ | 59.0 | | | $ | 59.1 | | | $ | 60.7 | |
Insurance proceeds and other | | | 13.9 | | | | 40.5 | | | | 21.7 | | | | 13.9 | |
Total | | $ | 74.6 | | | $ | 99.5 | | | $ | 80.8 | | | $ | 74.6 | |
Other operating income decreasedincreased by 25.0%8.3% to $80.8 million for the year ended December 31, 2022, compared to $74.6 million for the year ended December 31, 2021, compared to $99.5 million for the year ended December 31, 2020.2021.
“Insurance proceeds and other” for the year 2020 included $18.4 million in insurance income in Kaxu in compensation for the unscheduled outage, as well as $5.7 million in insurance income received at Solana and Mojave in compensation for events from prior years, which are the main reasons for the decrease.
“Grants” represent the financial support provided by the U.S. Department of the Treasury to Solana and Mojave and consist of an ITC Cash Grant and an implicit grant related to the below market interest rates of the project loans with the Federal Financing Bank. Grants were stable for the year 20212022 compared to the previous year.
“Insurance proceeds and other” for the year ended December 31, 2022 included an insurance income of $9.5 million which corresponded to previous years. In December 2022, a Spanish court dictated in favor of our solar assets in a legal proceeding against our former insurance company. This is the main reason for the increase when compared to the year ended December 31, 2021.
Employee benefit expenses
Employee benefit expenses increased by 44.4%1.9% to $80.2 million for the year ended December 31, 2022, compared to $78.7 million for the year ended December 31, 2021, compared to $54.5 million for the year ended December 31, 2020.2021. The increase was mainly due to the consolidation of Coso and Rioglass.the internalization of the operation and maintenance services at Kaxu and in part of our solar assets in Spain. During 2022, we transferred the employees performing the operation and maintenance services at Kaxu and in part of our solar assets in Spain from an Abengoa subsidiary to an Atlantica subsidiary. As a result, the O&M cost is now recorded under “Employee Benefit Expenses” from the dates of such transfer. The increase was partially offset by a decrease in the number of employees who were working for the Rioglass non-recurrent solar project previously mentioned once it was completed.
Depreciation, amortization and impairment charges
Depreciation, amortization and impairment charges increased by 7.5%7.8% to $473.6 million for the year ended December 31, 2022, compared to $439.4 million for the year ended December 31, 2021, compared to $408.6 million for the year ended December 31, 2020.2021. The increase was mainly due to an increase in depreciation and amortization at our solar assets in Spain. In September 2020, we reduced the useful life of our solar assets in Spain from 35 to 25 years after COD, which increased our depreciation and amortization charges for the year ended December 31, 2021 by $46.0 million compared to the previous year. In addition, the increase is also due to the $43.1 million impairment loss recorded in Solana in September 2021, after a triggering event was identified mainly due to delays in the improvements and replacements in the storage system and their impact on production in 2021, as well as to the increase in the discount rate. Depreciation, amortization and impairment charges also increased due to the consolidation of recent acquisitions and because in 2020 this caption included a reversal of an impairment charge in our wind assets in Uruguay for $18.7 million in Cadonal and Palmatir, with no corresponding amount in 2021.
These effects were partially offset by a reversal of the expected credit loss impairment provision recorded at ACT. IFRS 9 requires impairment provisions to be based on the expected credit loss of the financial assets in addition to actual credit losses. ACT recorded an expected credit loss impairment provision of $4.0 million in 2022, while in 2021, there was a reversal of the expected credit loss impairment provision of $24.9 million for the year ended December 31, 2021, whilemillion. In addition, in the year ended December 31, 2020, there was2022, we recorded an increaseimpairment loss of $26.6$41.2 million in Solana, as previously described, compared to a $43.1 million impairment in 2021. In 2022 we also recorded an impairment of $20.4 million at Chile PV 1 and Chile PV 2. Depreciation, amortization and impairment charges also increased due to the expected credit loss impairment provision. In addition, forconsolidation of recent acquisitions. On the year ended December 31, 2020,other hand, depreciation, amortization and impairment charges included an equipment write-off of $48 million relateddecreased in our solar assets in Spain mainly due to the Solana storage system with no corresponding amount indepreciation of the current period.euro against the U.S. dollar.
Other operating expenses
The following table sets forth our other operating expenses for the years ended December 31, 20212022 and 2020:2021:
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
Other operating expenses | | $ in millions | | % of revenue | | $ in millions | | % of revenue | | | $ in millions | | % of revenue | | $ in millions | | % of revenue | |
Raw Materials | | $ | 70.7 | | | | 5.8 | % | | $ | 7.8 | | | | 0.8 | % | | $ | 19.7 | | | | 1.8 | % | | $ | 70.7 | | | | 5.8 | % |
Leases and fees | | | 9.3 | | | | 0.8 | % | | | 2.6 | | | | 0.3 | % | | | 11.5 | | | | 1.0 | % | | | 9.3 | | | | 0.8 | % |
Operation and maintenance | | | 154.0 | | | | 12.7 | % | | | 110.9 | | | | 10.9 | % | | | 140.4 | | | | 12.7 | % | | | 154.0 | | | | 12.7 | % |
Independent professional services | | | 39.2 | | | | 3.2 | % | | | 40.2 | | | | 4.0 | % | | | 38.9 | | | | 3.6 | % | | | 39.2 | | | | 3.2 | % |
Supplies | | | 40.8 | | | | 3.4 | % | | | 27.9 | | | | 2.8 | % | | | 59.3 | | | | 5.4 | % | | | 40.8 | | | | 3.4 | % |
Insurance | | | 45.4 | | | | 3.8 | % | | | 37.6 | | | | 3.7 | % | | | 45.8 | | | | 4.2 | % | | | 45.4 | | | | 3.8 | % |
Levies and duties | | | 29.9 | | | | 2.5 | % | | | 39.8 | | | | 3.9 | % | | | 19.8 | | | | 1.8 | % | | | 29.9 | | | | 2.5 | % |
Other expenses | | | 25.0 | | | | 2.1 | % | | | 9.9 | | | | 1.0 | % | | | 16.0 | | | | 1.3 | % | | | 25.0 | | | | 2.1 | % |
Total | | $ | 414.3 | | | | 34.2 | % | | $ | 276.7 | | | | 27.3 | % | | $ | 351.3 | | | | 31.8 | % | | $ | 414.3 | | | | 34.2 | % |
Other operating expenses increaseddecreased by 49.7%15.2% to $351.3 million for the year ended December 31, 2022, compared to $414.3 million for the year ended December 31, 2021. Additionally, on a constant currency basis and excluding the Rioglass non-recurrent solar project accounted for in the year ended December 31, 2021, comparedother operating expenses in 2022 increased by 8.4%. The increase was mainly due to $276.7higher cost of supplies primarily in Spain, due to the increase of the electricity market prices since mid-2021. This increase was partially offset by a decrease of levies and duties since the Spanish government granted an exemption from the 7% electricity sales tax in our Spanish assets. On the other hand, our operation and maintenance costs decreased mainly due the internalization of operation and maintenance at Kaxu and in part of our solar assets in Spain. These services are now provided by a subsidiary of Atlantica, with the cost classified in “Employee benefit expenses”.
Operating profit
As a result of the previously above-mentioned factors, operating profit decreased by 21.5% to $277.7 million for the year ended December 31, 2020, mainly due to higher raw material costs corresponding to the aforementioned Rioglass non-recurrent solar project.
Other operating expenses also increased due to higher operation and maintenance costs mainly caused by the contribution of the recently consolidated assets for $17.9 million and higher costs at ACT, since operation and maintenance costs are higher in this asset in the quarters preceding a major overhaul, which is scheduled to be performed at the beginning of 2022.
In addition, the cost of supplies increased mainly because part of our supply costs are related to the electricity market prices, which have increased in 20212022, compared to the previous year.
Operating profit
As a result of the above-mentioned factors, operating profit decreased by 5.1% towith $353.9 million for the year ended December 31, 2021, compared with $373.1 million for the year ended December 31, 2020.2021.
Financial income and financial expense
| | Year ended December 31, | |
Financial income and financial expense | | 2022 | | | 2021 | |
| | ($ in millions) | |
Financial income | | $ | 5.6 | | | $ | 2.7 | |
Financial expense | | | (333.3 | ) | | | (361.2 | ) |
Net exchange differences | | | 10.3 | | | | 1.9 | |
Other financial income/(expense), net | | | 6.5 | | | | 15.7 | |
Financial expense, net | | $ | (310.9 | ) | | $ | (340.9 | ) |
Financial income and financial expense
| | Year ended December 31, | |
Financial income and financial expense | | 2021 | | | 2020 | |
| | $ in millions | |
Financial income | | $ | 2.7 | | | $ | 7.1 | |
Financial expense | | | (361.2 | ) | | | (378.4 | ) |
Net exchange differences | | | 1.9 | | | | (1.4 | ) |
Other financial income/(expense), net | | | 15.7 | | | | 40.9 | |
Financial expense, net | | $ | (340.9 | ) | | $ | (331.8 | ) |
Financial income
Financial income decreased to $2.7 million for the year ended December 31, 2021, compared to $7.1 million for the year ended December 31, 2020, primarily due to a $3.8 million of non-monetary financial income resulting from the refinancing of the Cadonal project debt in 2020.
Financial expense
The following table sets forth our financial expense for the years ended December 31, 20212022 and 2020:2021:
| | Year ended December 31, | | | Year ended December 31, | |
Financial expense | | 2021 | | 2020 | | | 2022 | | 2021 | |
| | $ in millions | | | ($ in millions) | |
Interest on loans and notes | | $ | (302.5 | ) | | $ | (316.2 | ) | | $ | (292.1 | ) | | $ | (302.6 | ) |
Interest rates losses derivatives: cash flow hedges | | | (58.7 | ) | | | (62.2 | ) | | | (41.2 | ) | | | (58.7 | ) |
Total | | $ | (361.3 | ) | | $ | (378.4 | ) | | $ | (333.3 | ) | | $ | (361.3 | ) |
Financial expense decreased by 4.5%7.7% to $333.3 million for the year ended December 31, 2022, compared to $361.3 million for the year ended December 31, 2021, compared to $378.4 million for the year ended December 31, 2020.2021.
The decrease of “Interest“Interest on loans and notes” was mainly due to a decrease in interest on loans indexed to LIBOR and EURIBOR, since the reference rates were lower in the year ended December 31, 2021 compared to the previous year. The decrease was alsoexpense decreasedprimarily due to the acquisitionrepayment of Liberty Interactive’s equity interestproject and corporate debt in Solana in August 2020, which caused a decrease of $15.0 million. In addition,accordance with the year ended December 31, 2020 included costsfinancing arrangements and expenses related to the prepaymentdepreciation of the Note Issuance Facility 2017. This decrease was partially offset byeuro against the contribution of recently consolidated assets and by interest accruing on the Green Senior Notes and the Green Exchangeable Notes, which have contributed a full year in 2021, for a total amount of $18.0 million.U.S. dollar.
InterestUnder “Interest rate losses on derivatives designated as cash flow hedges correspond primarily tohedges” we record transfers from equity to financial expense when the hedged item impacts profit and loss.loss for hedging instruments classified as cash-flow hedges from an accounting perspective. The decrease was mainly due to lower losses from the Helios 1&2 swap, which was canceled after the Helios 1&2 project debt was refinanced in 2020 with a new fixed rate financing. This decrease was partially offset by higher losses in swaps hedging loans indexed to EURIBOR, SOFR and LIBOR as a result of lowerprimarily due to the increase in the reference rates than in 2022, compared to 2021, and to lower notional amounts, as we progressively repay our project debt.
Net exchange differences
Net exchange differences increased to $10.3 million in 2022 compared to $1.9 million income in 2021. The increase was mainly due the previous year.impact of foreign exchange caps hedging our net cash flow in Euros, resulting from the appreciation of the U.S. dollar against the Euro.
Other financial income/(expense), net
| | Year ended December 31, | | | Year ended December 31, | |
Other financial income/(expense), net | | 2021 | | 2020 | | | 2022 | | 2021 | |
| | $ in millions | | | ($ in millions) | |
Other financial income | | $ | 32.3 | | | $ | 162.3 | | | $ | 27.9 | | | $ | 32.3 | |
Other financial expense | | | (16.6 | ) | | | (121.4 | ) | | | (21.4 | ) | | | (16.6 | ) |
Total | | $ | 15.7 | | | $ | 40.9 | | | $ | 6.5 | | | $ | 15.7 | |
Other financial income/(expense), net decreased to a net income of $6.5 million for the year ended December 31, 2022 compared to a net income of $15.7 million for the year ended December 31, 2021 compared to a net income of $40.9 million for the year ended December 31, 2020.2021.
In the year 2020, Other financial income includes a non-cash gain of $145in 2022 include $6.2 million from the acquisition of Liberty Interactive´s equity interest in Solana, which is the primary reason for the decrease. Liberty Interactive was the tax equity investor in Solana and although the investment of Liberty Interactive was in shares, under IFRS it was recorded as liability. In August 2020, we acquired Liberty Interactive´s equity interest in Solana and recorded a gain corresponding to the difference between book value of Liberty Interactive´s equity interest in Solana and the total price expected to be paid to Liberty Interactive. For the year ended December 31, 2021, Other financial income includes $9.2 million income corresponding to the change in the fair value of the conversion option of the Green Exchangeable Notes since December 2020 and $7.6 million of income corresponding to the change in fair value of interest rate derivatives at Kaxu, derivatives, for which hedge accounting is not applied.applied, and $12.0 million income corresponding the mark-to-market of the derivative liability embedded in the Green Exchangeable Notes. Residual items are primarily relate to interest on deposits and loans, including non-monetary changes to the amortized costscost of such loans.
The decrease inof other financial expenses is primarilyincome for the year ended December 31, 2022, was mainly due to a one-time non-cash lossincome of $73.0$10.4 million caused byrecorded in 2021 and corresponding to the refinancingreversal of Helios 1&2 in 2020. a potential earn-out which was finally not payable.
Other financial expense includes expenses for guarantees and letters of credit, wire transfers, other bank fees and other minor financial expenses.expenses and the non-monetary financial component of the long-term provision related to electricity market prices in Spain and other long-term liabilities. The increase is mainly due to the financial impact related to the electricity market prices provision recorded at our solar assets in Spain. This is a long-term provision recorded at present value in accordance with the effective interest method, which progressively accrues a financial expense.
Share of profitprofit/(loss) of associatesentities carried under the equity method
Share of profit of associatesentities carried under the equity method increased to $21.4 million in the year ended December 31, 2022, compared to $12.3 million in the year ended December 31, 2021 compared to $0.5 million in the year ended December 31, 2020. The increase was primarily due to the contribution of the recently acquired Vento II and a higher profit in Honaine.II.
Profit/(loss) before income tax
As a result of the previously mentioned factors, we reported a loss before income tax of $11.8 million for the year ended December 31, 2022, compared to a profit before income tax of $25.3 million for the year ended December 31, 2021, compared to a profit before income tax of $41.8 million for the year ended December 31, 2020.2021.
Income tax
The reconciliation between the theoretical income tax resulting from applying an average statutory tax rate to profit before income tax and the actual income tax expense recognized in the consolidated income statements for the years ended December 31, 20212022 and 2020,2021, is as follows:
| | For the year ended December 31, | | | For the year ended December 31, | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
| | $ in millions | | | ($ in millions) | |
Consolidated income before taxes | | | 25.3 | | | | 41.8 | | |
Average statutory tax rate | | | 25 | % | | | 25 | % | |
Consolidated profit / (loss) before taxes | | | (11.8 | ) | | 25.3 | |
Average statutory tax rate1 | | | 25 | % | | 25 | % |
Corporate income tax at average statutory tax rate | | | (6.3 | ) | | | (10.4 | ) | | 2.9 | | | (6.3 | ) |
Income tax of associates, net | | | 3.1 | | | | 0.1 | | | 5.4 | | | 3.1 | |
Differences in statutory tax rates | | | (3.4 | ) | | | (0.1 | ) | | (4.3 | ) | | (3.4 | ) |
Unrecognized NOLs and deferred tax assets | | | (11.2 | ) | | | (37.1 | ) | | (10.9 | ) | | (11.2 | ) |
Purchase of Liberty Interactive´s equity interest in Solana | | | - | | | | 36.4 | | |
Other Permanent Differences | | | (4.1 | ) | | | (8.9 | ) | | 4.0 | | | (4.1 | ) |
Other non-taxable income/(expense) | | | (14.3 | ) | | | (4.7 | ) | | | 12.7 | | | | (14.3 | ) |
Corporate income tax | | | (36.2 | ) | | | (24.9 | ) | | | 9.7 | | | | (36.2 | ) |
Note:
(1) | The average statutory tax rate was calculated as an average of the statutory tax rates applicable to each of our subsidiaries weighted by the income before tax. |
For the year ended December 31, 2021, the overall effective tax rate was different than the statutory average rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in the U.K. entities and to provisions recorded for potential tax contingencies.
For the year ended December 31, 2020,2022 the overall effective tax rate was different than the statutory rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in the U.K.Chilean entities. For the year ended December 31, 2021, the overall effective tax rate was different than the statutory rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in UK entities partially offset by the non-taxable gainand to provisions recorded for potential tax contingencies in the consolidated financial statements on the purchasesome jurisdictions.
113
Profit attributable to non-controlling interests
Profit attributable to non-controlling interests was $3.4 million for the year ended December 31, 2022 compared to $19.2 million for the year ended December 31, 2021 compared to $4.9 million for the year ended December 31, 2020.2021. Profit attributable to non-controlling interests corresponds to the portion attributable to our partners in the assets that we consolidate (Kaxu, Skikda, Solaben 2 & 3, Solacor 1 & 2, Seville PV, Chile PV 1, Chile PV 2, Chile PV 3 and Tenes). The increasedecrease is due to higher profits at Kaxu and Skikda, as well as to the consolidation of Tenes sincelosses in our PV assets in Chile which were primarily caused by the second quarter of 2020.impairment previously discussed.
Profit/(loss) attributable to the parent company
As a result of the previously mentioned factors, loss attributable to the parent company was $5.4 million for the year ended December 31, 2022, compared to a loss of $30.1 million for the year ended December 31, 2021, compared to a profit of $12.0 million for the year ended December 31, 2020.2021.
Comparison of the Years Ended December 31, 20202021 and 20192020
The significant variances or variances of the significant components of the results of operations between the years ended December 31, 20202021 and December 31, 2019,2020, are discussed in the annual report on Form 20-F filed with the SEC on March 1, 2021.February 28, 2022.
Segment Reporting
We organize our business into the following three geographies where the contracted assets and concessions are located: North America, South America and EMEA. In addition, we have identified four business sectors based on the type of activity: Renewable energy, Efficient natural gas and heat, Transmission lines and Water. We report our results in accordance with both criteria. Our Efficient natural gas and heat segment was renamed to include Calgary District Heating which has been consolidated since its acquisition in May 2021.
Comparison of the Years Ended December 31, 20212022 and 20202021
Revenue and Adjusted EBITDA by geography
The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 20212022 and 2020,2021, by geographic region:
Revenue by geography
| | Year ended December 31, | |
| | 2021 | | | 2020 | |
Revenue by geography | | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | |
North America | | $ | 395.8 | | | | 32.7 | % | | $ | 330.9 | | | | 32.6 | % |
South America | | | 155.0 | | | | 12.8 | % | | | 151.5 | | | | 15.0 | % |
EMEA | | | 660.9 | | | | 54.5 | % | | | 530.9 | | | | 52.4 | % |
Total revenue | | $ | 1,211.7 | | | | 100.0 | % | | $ | 1,013.3 | | | | 100.0 | % |
Revenue by geography
| | Year ended December 31, | |
| | 2022 | | | 2021 | |
Revenue by geography | | $ in millions | | | % of revenue | | | $ in millions | | | % of revenue | |
North America | | $ | 405.1 | | | | 36.8 | % | | $ | 395.8 | | | | 32.7 | % |
South America | | | 166.4 | | | | 15.1 | % | | | 155.0 | | | | 12.8 | % |
EMEA | | | 530.5 | | | | 48.1 | % | | | 660.9 | | | | 54.5 | % |
Total revenue | | $ | 1,102.0 | | | | 100 | % | | $ | 1,211.7 | | | | 100.0 | % |
Adjusted EBITDA by geography
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
Adjusted EBITDA by geography | | $ in millions | | % of revenue | | $ in millions | | % of revenue | | | $ in millions | | % of Adjusted EBITDA | | $ in millions | | % of Adjusted EBITDA | |
North America | | $ | 311.8 | | | | 78.8 | % | | $ | 279.4 | | | | 84.4 | % | | $ | 310.0 | | | | 38.9 | % | | $ | 311.8 | | | | 37.8 | % |
South America | | | 119.6 | | | | 77.2 | % | | | 120.0 | | | | 79.2 | % | | | 126.5 | | | | 15.9 | % | | | 119.6 | | | | 14.5 | % |
EMEA | | | 393.0 | | | | 59.5 | % | | | 396.7 | | | | 74.7 | % | | | 360.6 | | | | 45.2 | % | | | 393.0 | | | | 47.7 | % |
Adjusted EBITDA(1) | | $ | 824.4 | | | | 68.0 | % | | $ | 796.1 | | | | 78.6 | % | | $ | 797.1 | | | | 100 | % | | $ | 824.4 | | | | 100 | % |
Note:
(1) | Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership). Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.” |
(1) Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership). Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”
Volume by geography
| | Volume produced/availability | |
| | Year ended December 31, | |
Volume by geography | | 2021 | | | 2020 | |
| | | |
North America (GWh) (1) | | | 4,818 | | | | 3,908 | |
North America availability(1) | | | 100.6 | % | | | 102.1 | % |
South America (GWh) (2) | | | 722 | | | | 667 | |
South America availability | | | 100.0 | % | | | 100.0 | % |
EMEA (GWh) | | | 1,407 | | | | 1,243 | |
EMEA availability | | | 97.9 | % | | | 100.1 | % |
| | Volume produced/availability | |
| | Year ended December 31, | |
Volume / availability by geography | | 2022 | | | 2021 | |
| | | |
North America (GWh)(1) | | | 5,743 | | | | 4,818 | |
North America availability | | | 98.9 | % | | | 100.6 | % |
South America (GWh)(2) | | | 799 | | | | 722 | |
South America availability | | | 99.9 | % | | | 100.0 | % |
EMEA (GWh) | | | 1,278 | | | | 1,407 | |
EMEA availability | | | 102.3 | % | | | 97.9 | % |
Note:
(1) | GWh produced includes 30% of the production from Monterreyand our 49% of Vento II wind portfolio production since its acquisition. |
(2) | Includes curtailment production in wind assets for which we receive compensation. |
North America
Revenue increased by 19.6%2.3% to $405.1 million for the year ended December 31, 2022, compared to $395.8 million for the year ended December 31, 2021, compared to $330.9 millionwhile Adjusted EBITDA remained stable, with a 0.6% decrease for the year ended December 31, 2020.2022, compared to 2021. The increase in Revenue was mainly due to the contribution from the recently acquired assets, Coso and Calgary. The increase wasRevenue also caused by higher revenue at ACT mainly due to the higher revenue in the portion of the tariff related to operation and maintenance services, driven by higher operation and maintenance costs for year ended December 31, 2021. This increase was partially offset by a 2.4% decrease in revenueincreased at our solar assets in North America mainly due to lower radiation in Arizona and lower availability of the Solana storage system, as previously described.
Adjusted EBITDA increased by 11.6% to $311.8 million for the year ended December 31, 2021, compared to $279.4 million for the year ended December 31, 2020. Adjusted EBITDA increased due to the recently acquired assets Coso, Vento II and Calgary. This effecthigher production. The increase was partially offset by lower revenue at ACT where revenue is recorded under IFRIC 12 – financial asset model (see “—Revenue and Adjusted EBITDA by business sector—Efficient natural gas & heat” below). Adjusted EBITDA decreased mainly due to lower Adjusted EBITDA in ACT, resulting mostly from lower revenue, higher operating and maintenance expenses at our solar assets in North America mainly due to lower revenue and to the insurance income received in the year 2020 amounting to $5.7 million. Adjusted EBITDA was also lower at ACTmostly due to higher operation and maintenance expenses in 2021. Adjusted EBITDA margin decreased to 78.8% for the year ended December 31, 2021, compared to 84.4% for year ended December 31, 2020, mainly duecosts related to the events described abovescheduled major maintenance at Solana and tohigher supply costs, mainly driven by higher electricity prices. This decrease was partially offset by the lower margins ofcontribution from the recently acquired assets.assets Coso, Calgary and Vento II.
South America
Revenue increased by 2.3%7.4% to $166.4 million for the year ended December 31, 2022, compared to $155.0 million for the year ended December 31, 2021, compared2021. The increase was mainly due to $151.5the contribution from the recently acquired assets, La Sierpe, Chile TL4 and Chile PV 3. Revenue at our wind assets in Uruguay also increased slightly in spite of lower wind resource as a result of the inflation adjustment to revenue. Adjusted EBITDA increased by 5.8% to $126.5 million for the year ended December 31, 2020. Adjusted EBITDA remained stable at2022, compared to $119.6 million for the year ended December 31, 2021, comparedmostly due to $120.0the same reasons.
EMEA
Revenue decreased to $530.5 million for the year ended December 31, 2020. The increase in revenue was primarily due to the contribution2022, which represents a decrease of Chile PV 1 and Chile PV 2. This increase was offset by lower revenue and Adjusted EBITDA from our wind assets in Uruguay, resulting mainly from lower wind resource. Adjusted EBITDA margin decreased slightly to 77.2% for the year ended December 31, 2021,19.7% compared to 79.2% for the year ended December 31, 2020 mainly due to lower Adjusted EBITDA margins in the assets recently acquired.
EMEA
Revenue increased by 24.5% to $660.9 million for the year ended December 31, 2021, compared to $530.9 million for the year ended December 31, 2020.2021. On a constant currency basis, revenue for the year ended December 31, 2021,2022, was $636.9$587.4 million, which represents an increasea decrease of 20.0%11.1% compared to 2020. Onthe year ended December 31, 2021. Additionally, on a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project accounted for in the year ended December 31, 2021, revenue in 2022, increased by 2.0%.
The increase was mainly due to higher revenue at Kaxu caused by higher production during the year ended December 31, 2022, compared to the same period of previous year and to the indexation of our PPA to local inflation. The increase was also due to the contribution of the recently acquired assets in Italy. Revenue remained stable at our solar assets in Spain (0.4% increase on a constant currency basis and excluding the non-recurrent solar project), since the negative impact of lower production was offset by higher electricity prices net of its corresponding accounting provision (see “Item 2—Operating and Financial Review and Prospects —Factors Affecting our Results of Operations—Electricity market prices”).
Adjusted EBITDA decreased to $360.6 million for the year ended December 31, 2021, was $551.5 million,2022, which represents an increasea decrease of 3.9%8.2% compared to 2020. The increase was primarily due to higher revenue at Kaxu, where an unscheduled outage affected production in part of the first quarter of 2020. Property Damage and business interruption were covered by our insurance; however, insurance proceeds were recorded in “Other operating income”. Revenue also increased due to the contribution from Tenes, fully consolidated since the second quarter of 2020. At our solar assets in Spain, revenue decreased by 4.8% on a constant currency basis in spite of higher production in the period mainly due to a non-cash negative provision related to higher than historical electricity prices. Electricity market prices have been higher than expected and the regulation establishes a compensation mechanism under which regulated revenue is revised every three years to reflect the difference between expected and actual market prices if the difference is higher than a pre-defined threshold. Current higher market prices in Spain will therefore cause lower regulated revenue to be received progressively over the remaining regulatory life of our solar assets. As a result, we recorded a negative provision with no cash impact in the current periodfor $77 million that reduced our revenue in 2021. Due to methodology used in the calculation, revenue from sales of electricity at market prices, net of the provision, decreased by approximately $10 million, which is the main reason for the decrease in revenue in our solar assets in Spain.
Adjusted EBITDA decreased by 0.9% to $393.0 million for the year ended December 31, 2021, compared to $396.7 million for the year ended December 31, 2020.2021. On a constant currency basis, Adjusted EBITDA for the year ended December 31, 2021,in 2022, was $375.9$399.1 million which represents a decreasean increase of 5.2%1.5% compared to 2020. On2021. Additionally, on a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project Adjusted EBITDAaccounted for in the year ended December 31, 2021, was $374.9 million which represents a decrease of 5.5% compared to 2020.Adjusted EBITDA in 2022 increased by 1.8%. This decreaseincrease was mainly caused by lower revenue in our solar assets in Spain as previously explaineddue to higher EBITDA at Kaxu and to higher supply costs, since the prices are partially linked to electricity prices, and was partially offset by the contribution of Tenes and the recently acquired assets in Italy as well as higherpreviously explained. In our solar assets in Spain, Adjusted EBITDA at Kaxu. Adjusted EBITDA margin decreased to 59.5% for the year ended December 31, 2021, compared to 74.7% for the year ended December 31, 2020, mainly due to lower margin at the Rioglass non-recurrent solar project and to the higher than usual Adjusted EBITDA margin in Kaxu in the year 2020 due to insurance proceeds recorded in “Other Operating Income”.costs of supplies largely caused by higher electricity prices.
Revenue and Adjusted EBITDA by business sector
The following table sets forth our revenue, Adjusted EBITDA and volumes for the years ended December 31, 20212022 and 2020,2021, by business sector:
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
Revenue by business sector | | $ in millions | | % of revenue | | $ in millions | | % of revenue | | | $ in millions | | % of revenue | | $ in millions | | % of revenue | |
Renewable energy | | $ | 928.5 | | | | 76.6 | % | | $ | 753.1 | | | | 74.3 | % | | $ | 821.4 | | | | 74.5 | % | | $ | 928.5 | | | | 76.6 | % |
Efficient natural gas & Heat | | | 123.7 | | | | 10.2 | % | | | 111.0 | | | | 11.0 | % | | | 113.6 | | | | 10.3 | % | | | 123.7 | | | | 10.2 | % |
Transmission lines | | | 105.6 | | | | 8.7 | % | | | 106.1 | | | | 10.5 | % | | | 113.2 | | | | 10.3 | % | | | 105.6 | | | | 8.7 | % |
Water | | | 53.9 | | | | 4.5 | % | | | 43.1 | | | | 4.2 | % | | | 53.8 | | | | 4.9 | % | | | 53.9 | | | | 4.5 | % |
Total revenue | | $ | 1,211.7 | | | | 100.0 | % | | $ | 1,013.3 | | | | 100.0 | % | |
Revenue | | | $ | 1,102.0 | | | | 100 | % | | $ | 1,211.7 | | | | 100.0 | % |
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | 2020 | | | 2022 | | 2021 | |
Adjusted EBITDA by business sector | | $ in millions | | % of revenue | | $ in millions | | % of revenue | | | $ in millions | | % of Adjusted EBITDA | | $ in millions | | % of Adjusted EBITDA | |
Renewable energy | | $ | 602.6 | | | | 64.9 | % | | $ | 576.3 | | | | 76.5 | % | | $ | 588.0 | | | | 73.8 | % | | $ | 602.6 | | | | 73.1 | % |
Efficient natural gas & Heat | | | 100.0 | | | | 80.8 | % | | | 101.0 | | | | 91.0 | % | | | 84.6 | | | | 10.6 | % | | | 100.0 | | | | 12.1 | % |
Transmission lines | | | 83.6 | | | | 79.2 | % | | | 87.3 | | | | 82.3 | % | | | 88.0 | | | | 11.0 | % | | | 83.6 | | | | 10.2 | % |
Water | | | 38.2 | | | | 70.9 | % | | | 31.5 | | | | 73.1 | % | | | 36.5 | | | | 4.6 | % | | | 38.2 | | | | 4.6 | % |
Adjusted EBITDA(1) | | $ | 824.4 | | | | 68.0 | % | | $ | 796.1 | | | | 78.6 | % | | $ | 797.1 | | | | 100 | % | | $ | 824.4 | | | | 100.0 | % |
Note:
(1) | Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership). Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.” |
(1) Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of our equity ownership). Adjusted EBITDA is not a measure of performance under IFRS as issued by the IASB and you should not consider Adjusted EBITDA as an alternative to operating income or profits or as a measure of our operating performance, cash flows from operating, investing and financing activities or as a measure of our ability to meet our cash needs or any other measures of performance under generally accepted accounting principles. We believe that Adjusted EBITDA is a useful indicator of our ability to incur and service our indebtedness and can assist securities analysts, investors and other parties to evaluate us. Adjusted EBITDA and similar measures are used by different companies for different purposes and are often calculated in ways that reflect the circumstances of those companies. Adjusted EBITDA may not be indicative of our historical operating results, nor is it meant to be predictive of potential future results. See “Presentation of Financial Information—Non-GAAP Financial Measures.”
Volume by business sector
| | Volume produced/availability | |
| | Year ended December 31, | |
Volume by business sector | | 2021 | | | 2020 | |
Renewable energy (GWh) (1) | | | 4,655 | | | | 3,244 | |
Efficient natural gas & Heat (GWh) (2) | | | 2,292 | | | | 2,574 | |
Efficient natural gas & Heat availability | | | 100.6 | % | | | 102.1 | % |
Transmission availability | | | 100.0 | % | | | 100.0 | % |
Water availability | | | 97.9 | % | | | 100.1 | % |
| | Volume produced/availability | |
| | Year ended December 31, | |
Volume / availability by business sector | | 2022 | | | 2021 | |
Renewable energy (GWh) (1) | | | 5,319 | | | | 4,655 | |
Efficient natural gas & Heat (GWh) (2) | | | 2,501 | | | | 2,292 | |
Efficient natural gas & Heat availability | | | 98.9 | % | | | 100.6 | % |
Transmission availability | | | 100.0 | % | | | 100.0 | % |
Water availability | | | 102.3 | % | | | 97.9 | % |
Note:
(1) | Includes curtailment production in wind assets for which we receive compensation. Includes our 49% of Vento II wind portfolio production since its acquisition. |
(2) | GWh produced includes 30% of the production from Monterrey. |
Renewable energy
Revenue increased by 23.3%decreased to $821.4 million for the year ended December 31, 2022, which represents a decrease of 11.5% compared to $928.5 million for the year ended December 31, 2021, compared to $753.1 million for the year ended December 31, 2020.2021. On a constant currency basis, revenue for the year ended December 31, 2021,in 2022 was $904.4$878.5 million, which represents an increasea decrease of 20.1%5.4% compared to 2020. On2021. Additionally, on a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project accounted for in 2021, revenue for the year ended December 31, 2021, was $819.1 million, which represents an increase of 8.8% compared to 2020. Adjusted EBITDAin 2022 increased by 4.6% to $602.6 million for the year ended December 31, 2021, compared to $576.3 million for 2020. On a constant currency basis, Adjusted EBITDA for the year ended December 31, 2021, was $585.5 million, which represents an increase of 1.6% compared to 2020. On a constant currency basis and excluding the aforementioned Rioglass non-recurrent solar project, Adjusted EBITDA for the year ended December 31, 2021, was $584.5 million, a 1.4% increase compared to the previous year.4.2%. The increase in revenue and Adjusted EBITDA was primarily due to the contribution from the recently acquired assets Coso, Vento II,La Sierpe, our PV assets in Italy and Chile PV1, Chile PV2, Italy PV 1, Italy PV 2 and Italy PV 3. Revenue and Adjusted EBITDA also increased due to higher revenue at Kaxu, as previously explained. The increasewell as at our solar assets in revenue was partially offset by the decreaseNorth America. Revenue also increased at our wind assets in revenueUruguay in Spain with no cash impact in the current period,spite of lower wind resources as previously explained. The increase in described.
Adjusted EBITDA was partially offset by higher supply costs in Spain since the prices are partially linked to electricity prices. Adjusted EBITDA margin decreased to 64.9%$588.0 million for the year ended December 31, 2021, from 76.5%2022, which represents a decrease of 2.4% compared to $602.6 million for the year ended December 31, 2020,2021. On a constant currency basis, Adjusted EBITDA in 2022 was $626.7 million which represents an increase of 4.0% compared to 2021. Additionally, on a constant currency basis and excluding the non-recurrent solar project accounted for in 2021, Adjusted EBITDA increased by 4.2%. Adjusted EBITDA increased mainly due to lower margin at the non-recurrent one-off project previously described, higher than usual Adjusted EBITDA margin at Kaxuincrease in 2020 due to insurance proceeds recorded in “Other Operating Income”Revenue and the contribution of Vento II. This increase was partially offset by lower Adjusted EBITDA margins at some of the recently acquired assets.our solar assets in North America and Spain, as previously discussed.
Efficient natural gas & heat
Revenue increaseddecreased by 11.4%8.2% to $113.6 million for the year ended December 31, 2022, compared to $123.7 million for the year ended December 31, 2021, compared to $111.0 million for the year ended December 31, 2020, while Adjusted EBITDA decreased by 1.0%15.4% to $84.6 million for the year ended December 31, 2022, compared to $100.0 million for the year ended December 31, 2021,2021. Revenue at ACT is recorded under IFRIC 12 – financial asset model. Although billings to clients increased in 2022 compared to $101.0 million for the year ended December 31, 2020. At2021 as a result of inflation indexation, accounting revenue decreases progressively over time. Revenue at ACT operation and maintenance costs are higher in the quarters preceding any major maintenance works, the next of which is scheduled at the beginning of 2022. Revenue increasedalso decreased due to higherlower operation and maintenance costs, since there is a portion of revenue related to operation and maintenance services plus a margin. Revenue also increased due toOperation and maintenance costs were higher in 2021 as it happens in the contribution from the recently acquired Calgary district heating asset.quarters preceding any major maintenance works. Adjusted EBITDA margin decreased due to these higher operation and maintenance costs.largely for the same reasons.
Transmission lines
Revenue remained stable at $105.6increased by 7.2% to $113.2 million for the year ended December 31, 2021,2022, compared to $106.1$105.6 million for year ended December 31, 2021, while Adjusted EBITDA increased by 5.2% to $88.0 million for the year ended December 31, 2020. Adjusted EBITDA also remained stable at2022 compared to $83.6 million for the year ended December 31, 2021 compared2021. The increase in revenue and Adjusted EBITDA was mainly due to $87.3the contribution of the recently acquired asset Chile TL 4 and to lower operation and maintenance costs at some of our transmission lines in 2022 after a renegotiation with the supplier of these services.
Water
Revenue remained stable at $53.8 million for the year ended December 31, 2020.
Water
Revenue increased by 25.0%2022, compared to $53.9 million for the year ended December 31, 2021, compared2021. Adjusted EBITDA decreased by 4.5% to $43.1$36.5 million for the year ended December 31, 2020. Adjusted EBITDA increased by 21.2%2022, compared to $38.2 million for the year ended December 31, 2021, compared to $31.5 million for the year ended December 31, 2020. The increases2021. Operating expenses were mainlyhigher in 2022 mostly due to the contribution fromhigher availability in Tenes, which we started to consolidate on May 31, 2020.caused the decrease in Adjusted EBITDA margin was stable compared toEBITDA. Revenue follows the previous year.IFRIC 12- financial model and did not increase accordingly.
Comparison of the Years Ended December 31, 20202021 and 20192020
The significant variances in the revenue and volume, by geographic region and business sector, between the years ended December 31, 20202021 and December 31, 2019,2020, are discussed in the Form 20-F filed with the SEC on March 1, 2021.February 28, 2022.
B. | Liquidity and Capital Resources |
Our principal liquidity and capital requirements consist of the following:
debt service requirements on our existing and future debt;
cash dividends to investors; and
investments in new assets and companies and operations (see “Item 4.B—Business Overview—Our Business Strategy”).
As a normal part of our business, depending on market conditions, we will from time to time consider opportunities to repay, redeem, repurchase or refinance our indebtedness. Changes in our operating plans, lower than anticipated sales, increased expenses, acquisitions or other events may cause us to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all. Debt financing, if available, could impose additional cash payment obligations and additional covenants and operating restrictions. In addition, any of the items discussed in detail under “Item 3.D—Risk Factors” and other factors may also significantly impact our liquidity.
Liquidity position
| | Year ended December 31, | |
| | 2022 | | | 2021 | |
| | ($ in millions) | |
Corporate Liquidity | | | | | | |
Cash and cash equivalents at Atlantica Sustainable Infrastructure, plc, excluding subsidiaries | | $ | 60.8 | | | $ | 88.3 | |
Revolving Credit Facility availability | | | 385.1 | | | | 440.0 | |
Total Corporate Liquidity(1) | | $ | 445.9 | | | $ | 528.3 | |
Liquidity at project companies | | | | | | | | |
Restricted Cash | | | 207.6 | | | | 254.3 | |
Non-restricted cash | | | 332.6 | | | | 280.1 | |
Total cash at project companies | | $ | 540.2 | | | $ | 534.4 | |
| | Year ended December 31, | |
| | 2021 | | | 2020 | |
| | $ in millions | |
Corporate Liquidity | | | | | | |
Cash and cash equivalents at Atlantica Sustainable Infrastructure, plc, excluding subsidiaries | | $ | 88.3 | | | $ | 335.2 | |
Revolving Credit Facility availability | | | 440.0 | | | | 415.0 | |
Total Corporate Liquidity | | $ | 528.3 | | | $ | 750.2 | |
Liquidity at project companies | | | | | | | | |
Restricted Cash | | | 254.3 | | | | 279.8 | |
Non-restricted cash | | | 280.1 | | | | 253.5 | |
Total cash at project companies | | $ | 534.4 | | | $ | 533.3 | |
Note:
(1) | Corporate Liquidity means cash and cash equivalents held at Atlantica Sustainable Infrastructure plc as of December 31, 2022, and available revolver capacity as of December 31, 2022. |
Cash at the project level includes $254.3$207.6 million and $279.8$254.3 million restricted cash balances as of December 31, 20212022 and 2020,2021, respectively. Restricted cash consists primarily of funds required to meet the requirements of certain project debt arrangements. In the case of Solana, part of the restricted cash is being used and is expected to be used for equipment replacement. RestrictedAs of December 31, 2021, restricted cash also includesincluded Kaxu’s cash balance, given that the project financing of this asset was under a theoretical event of default.default which was resolved as of March 31, 2022 (see “Item 4—Information on the Company—Our Operations—Renewable energy—Kaxu.”).
Non-restricted cash at project companies includes among others, the cash that is required for day-to-day management of the companies, as well as amounts that are earmarked to be used for debt service and distributions in the future.
As of December 31, 2021, $102022, $34.9 million of letters of credit were outstanding under the Revolving Credit Facility and we had no$30 million of borrowings. In March 2021, we increased the notional amount of this facility from $425 million to $450 million and extended its maturity to December 2023. As a result, as of December 30,31, 2022 $385.1 million was available under the Revolving Credit Facility. As of December 31, 2021, $440we had $10.0 million of letters of credits outstanding, and we had no borrowing. As a result, $440.0 million was available under our Revolving Credit Facility. AsFacility as of December 31, 2020, we had no borrowings, $10 million of letters of credit were outstanding and $415 million was available under our Revolving Credit Facility.2021.
Management believes that the Company'sCompany’s liquidity position, cash flows from operations and availability under its revolving credit facilityRevolving Credit Facility will be adequate to meet the Company'sCompany’s working capital requirements, financial commitments and debt obligations; growth, operating and maintenance capital expenditures; and dividend distributions to shareholders. Management continues to regularly monitor the Company'sCompany’s ability to finance the needs of its operating, financing and investing activities within the guidelines of prudent balance sheet management.
Credit Ratings
Credit rating agencies rate us and part of our debt securities. These ratings are used by the debt markets to evaluate our credit risk. Ratings influence the price paid to issue new debt securities as they indicate to the market our ability to pay principal, interest and dividends.
In March and April 2021 both Fitch and S&P upgraded Atlantica’s corporate rating to BB+. The following table summarizes our credit ratings as of December 31, 2021.2022. The ratings outlook is stable for S&P and Fitch.
| S&P | Fitch |
Atlantica Sustainable Infrastructure Corporate Rating | BB+ | BB+ |
Senior Secured Debt | BBB- | BBB- |
Senior Unsecured Debt | BB | BB+ |
Sources of liquidity
We expect our ongoing sources of liquidity to include cash on hand, cash generated from our operations, project debt arrangements, corporate debt and the issuance of additional equity securities, as appropriate, and given market conditions. Our financing agreements consist mainly of the project-level financing for our various assets and our corporate debt financings, including our Green Exchangeable Notes, the Note Issuance Facility 2020, the 2020 Green Private Placement, the Green Senior Notes, the Revolving Credit Facility, the “at-the-market program”, other credit lines and our commercial paper program.
| | | | | As of December 31, 2021 | | | As of December 31, 2020 | | | | | | As of December 31, 2022 | | | As of December 31, 2021 | |
| | Maturity | | | ($ in millions) | | | Maturity | | | ($ in millions) | |
Revolving Credit Facility | |
| 2023 | | | | - | | | | - | | | 2024 | | | | 29.4 | | | | - | |
Other Facilities(1) | | | 2021-2025 | | | | 41.7 | | | | 29.7 | | | 2023-2026 | | | | 30.1 | | | | 41.7 | |
Note Issuance Facility 2019(2) | | | - | | | | - | | | | 344.0 | | |
Green Exchangeable Notes | | | 2025 | | | | 104.3 | | | | 102.1 | | | 2025 | | | | 107.0 | | | | 104.3 | |
2020 Green Private Placement | | | 2026 | | | | 327.1 | | | | 351.0 | | | 2026 | | | | 308.4 | | | | 327.1 | |
Note Issuance Facility 2020 | | | 2027 | | | | 155.8 | | | | 166.9 | | | 2027 | | | | 147.2 | | | | 155.8 | |
Green Senior Notes | | | 2028 | | | | 394.2 | | | | - | | | 2028 | | | | 395.1 | | | | 394.2 | |
Total Corporate Debt | | | | | | $ | 1,023.1 | | | $ | 993.7 | | | | | | | $ | 1,017.2 | | | $ | 1,023.1 | |
Total Project Debt | | | | | | $ | 5,036.2 | | | $ | 5,237.6 | | | | | | | $ | 4,553.1 | | | $ | 5,036.2 | |
Note:
(1) | Other facilities include the commercial paper program issued in October 2020, accrued interest payable and other debts. |
(2) | The Note Issuance Facility 2019 was fully prepaid on June 4, 2021 with the proceeds of the Green Senior Notes. |
A) | Corporate debt agreements |
Green Senior Notes
On May 18, 2021, we issued the Green Senior Notes with an aggregate principal amount of $400 million due in 2028. The Green Senior Notes bear interest at a rate of 4.125% per year, payable on June 15 and December 15 of each year, commencing December 15, 2021, and will mature on June 15, 2028.
The Green Senior Notes were issued pursuant to an Indenture, dated May 18, 2021, by and among Atlantica as issuer, Atlantica Peru S.A., ACT Holding, S.A. de C.V., Atlantica Infraestructura Sostenible, S.L.U., Atlantica Investments Limited, Atlantica Newco Limited, Atlantica North America LLC, as guarantors, BNY Mellon Corporate Trustee Services Limited, as trustee, The Bank of New York Mellon, London Branch, as paying agent, and The Bank of New York Mellon SA/NV, Dublin Branch, as registrar and transfer agent.
Our obligations under the Green Senior Notes rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Exchangeable Notes.
Green Exchangeable Notes
On July 17, 2020, we issued 4.00% Green Exchangeable Notes amounting to an aggregate principal amount of $100 million due in 2025. On July 29, 2020, we issued an additional $15 million aggregate principal amount in Green Exchangeable Notes. The Green Exchangeable Notes are the senior unsecured obligations of Atlantica Jersey, a wholly owned subsidiary of Atlantica, and fully and unconditionally guaranteed by Atlantica on a senior, unsecured basis. The notesGreen Exchangeable Notes mature on July 15, 2025, unless they are repurchased or redeemed earlier by Atlantica or exchanged, and bear interest at a rate of 4.00% per annum.
Noteholders may exchange all or any portion of their notes at their option at any time prior to the close of business on the scheduled trading day immediately preceding April 15, 2025, only during certain periods and upon satisfaction of certain conditions. Noteholders may exchange all or any portion of their notes during any calendar quarter if the last reported sale price of Atlantica’s ordinary shares for at least 20 trading days during a period of 30 consecutive trading days, ending on the last trading day of the immediately preceding calendar quarter is greater than 120% of the exchange price on each applicable trading day. On or after April 15, 2025, until the close of business on the second scheduled trading day immediately preceding the maturity date thereof, noteholders may exchange any of their notes at any time, at the option of the noteholder. Upon exchange, the notes may be settled, at our election, into Atlantica ordinary shares, cash or a combination of both. The initial exchange rate of the notes is 29.1070 ordinary shares per $1,000 of the principal amount of notes (which is equivalent to an initial exchange price of $34.36 per ordinary share). The exchange rate is subject to adjustment upon the occurrence of certain events.
Our obligations under the Green Exchangeable Notes rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the 2020 Green Private Placement, the Note Issuance Facility 2020 and the Green Senior Notes.
Note Issuance Facility 2020
On July 8, 2020, we entered into the Note Issuance Facility 2020, a senior unsecured euro-denominated financing with a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of approximately $159€140 million (€140($150 million). The notes under the Note Issuance Facility 2020 were issued on August 12, 2020 and are due on August 12, 2027. Interest accrues at a rate per annum equal to the sum of the 3-month EURIBOR plus a margin of 5.25% with a floor of 0% for the EURIBOR. We have entered into a cap at 0% for the EURIBOR with 3.5 years maturity to hedge the variable interest rate risk.
Our obligations under the Note Issuance Facility 2020 rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the 2020 Green Private Placement, the Green Exchangeable Notes and the Green Senior Notes. The notes issued under the Note Issuance Facility 2020 are guaranteed on a senior unsecured basis by our subsidiaries Atlantica Infraestructura Sostenible, S.L.U., Atlantica Peru, S.A., ACT Holding, S.A. de C.V., Atlantica Investments Limited, Atlantica Newco Limited and Atlantica North America LLC.
2020 Green Private Placement
On March 20, 2020, we entered into a senior secured note purchase agreement with a group of institutional investors as purchasers providing for the 2020 Green Private Placement. The transaction closed on April 1, 2020, and we issued notes for a total principal amount of €290 million (approximately $330($310 million), maturing on June 20, 2026. Interest accrues at a rate per annum equal to 1.96%. If at any time the rating of these senior secured notes is below investment grade, the interest rate thereon would increase by 100 basis points until such notes are again rated investment grade.
Our obligations under the 2020 Green Private Placement rank equal in right of payment with our outstanding obligations under the Revolving Credit Facility, the Note Issuance Facility 2020 and the Green Senior Notes. Our payment obligations under the 2020 Green Private Placement are guaranteed on a senior secured basis by our subsidiaries Atlantica Infraestructura Sostenible, S.L.U., Atlantica Peru, S.A., ACT Holding, S.A. de C.V., Atlantica Investments Limited, Atlantica Newco Limited and Atlantica North America LLC. The 2020 Green Private Placement is also secured with a pledge over the shares of the subsidiary guarantors, the collateral of which is shared with the lenders under the Revolving Credit Facility.
Note Issuance Facility 2019
On April 30, 2019, we entered into the Note Issuance Facility 2019, a senior unsecured financing with a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of €268 million, approximately $305 million. In June 2021 we prepaid the Note Issuance Facility 2019 in full before maturity in accordance with the terms thereof, with the proceeds of the Green Senior Notes.
Revolving Credit Facility
On May 10, 2018, we entered into a $215 million Revolving Credit Facility with a syndicate of banks. The Revolving Credit Facility was increased by $85 million to $300 million on January 25, 2019, and was further increased by $125 million (to a total limit of $425 million) on August 2, 2019. On March 1, 2021, this facility was further increased by $25 million (to a total limit of $450 million) and. On May 5, 2022, the maturity dateof the Revolving Credit Facility was extended to December 31, 2023. In addition, the lenders under the Revolving Credit Facility have the option to extend the maturity date of all or any portion of their commitments and/or loans for additional consecutive 365-day periods, upon request from us subject to certain conditions.2024. Under the Revolving Credit Facility, we are also able to request the issuance of letters of credit, which are subject to a sublimit of $100 million that are included in the aggregate commitments available under the Revolving Credit Facility.
Loans under the Revolving Credit Facility accrue interest at a rate per annum equal to: (A) for eurodollareuro dollar rate loans, LIBORTerm SOFR, plus a Term SOFR Adjustment equal to 0.10% per annum, plus a percentage determined by reference to our leverage ratio, ranging between 1.60% and 2.25% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. federal funds brokers on such day plus 1 /2½ of 1.00%, (ii) the prime rate of the administrative agent under the Revolving Credit Facility and (iii) LIBORTerm SOFR plus 1.00%, in any case, plus a percentage determined by reference to our leverage ratio, ranging between 0.60% and 1.00%.
Our obligations under the Revolving Credit Facility rank equal in right of payment with our outstanding obligations under the 2020 Green Private Placement, the Note Issuance Facility 2020, the Green Exchangeable Notes and the Green Senior Notes. Our payment obligations under the Revolving Credit Facility are guaranteed on a senior secured basis by Atlantica Infraestructura Sostenible, S.L.U., Atlantica Peru, S.A., ACT Holding, S.A. de C.V., Atlantica Investments Limited, Atlantica Newco Limited and Atlantica North America LLC. The Revolving Credit Facility is also secured with a pledge over the shares of the subsidiary guarantors, the collateral of which is shared with the holders of the notes issued under the 2020 Green Private Placement.
Other Credit Lines
In July 2017, we signed a line of credit with a bank for up to €10.0 million (approximately $11.4($10.7 million) which was available in euros or U.S. dollars. On June 30, 2021, the maturity was extended to July 1, 2023. Amounts drawn accrue interest at a rate per annum equal to the sum of the 3-month EURIBOR or LIBOR, plus a margin of 2%, with a floor of 0% for the EURIBOR or LIBOR. On July 1, 2022, the maturity was extended to July 1, 2024. As of December 31, 2021, $8.22022, we had $6.4 million were drawn down.under this line of credit.
In December 2020 and January 2022, we also entered into a loantwo different loans with a bankbanks for €5 million ($5.75.4 million). each. The maturity date isdates are December 4, 2025. The loan accrues2025 and January 31, 2026, respectively, and such loans accrue interest at a rate per annum equal to 2.50%.
and 1.90%, respectively.Commercial Paper Program
On October 8, 2019, we filed a euro commercial paper program with the Alternative Fixed Income Market (MARF) in Spain. The program had an original maturity of twelve months and has been extended twice, for annual periods. The program allows Atlantica to issue short term notes for up to €50 million, with such notes having a tenor of up to two years. As of December 31, 2021,2022, we had €21.5€9.3 million ($24.410.0 million) issued and outstanding under the Commercial Paper Program at an average cost of 0.36%.
2.21% maturing on or before March 7, 2023.
Covenants, restrictions and events of default
The Note Issuance Facility 2020, the 2020 Green Private Placement, the Green Senior Notes and the Revolving Credit Facility contain covenants that limit certain of our and the guarantors’ activities. The Note Issuance Facility 2020, the 2020 Green Private Placement and the Green Exchangeable Notes also contain customary events of default, including a cross-default with respect to our indebtedness, indebtedness of the guarantors thereunder and indebtedness of our material non-recourse subsidiaries (project-subsidiaries) representing more than 25% of our cash available for distribution distributed in the previous four fiscal quarters, which in excess of certain thresholds could trigger a default. Additionally, under the 2020 Green Private Placement, the Revolving Credit Facility and the Note Issuance Facility 2020 we are required to comply with a leverage ratio of our corporate indebtedness excluding non-recourse project debt to our cash available for distribution of 5.00:1.00 (which may be increased under certain conditions to 5.50:1.00 for a limited period in the event we consummate certain acquisitions).
Furthermore, our corporate debt agreements contain customary change of control provisions (as such term is defined in each of those agreements) or similar provisions. Under the Revolving Credit Facility, a change of control without required lenders’ consent would trigger an event of default. In the other corporate debt agreements or securities, a change of control or similar provision without the consent of the relevant required holders would trigger the obligation to make an offer to purchase the respective notes at (i) 100% of the principal amount in the case of the 2020 Green Private Placement and Green Exchangeable Notes and at (ii) 101% of the principal amount in the case of the Note Issuance Facility 2020 and the Green Senior Notes. In the case of the Green Senior Notes, such prepayment obligation would be triggered only if there is a credit rating downgrade by any of the agencies.
At-The-Market Program
On August 3, 2021,February 28, 2022, we established an “at-the-market program” and entered into the Distribution Agreement with J.P. MorganBofA Securities, Inc., MUFG Securities Americas Inc. and RBC Capital Markets LLC, as our sales agent,agents, under which we may offer and sell from time to time up to $150 million of our ordinary shares, including in “at-the-market” offerings under our universal shelf registration statement on Form F-3 filed with the SEC on August 3, 2021, and a prospectus supplement that we filed on August 3, 2021. DuringFebruary 28, 2022. For the thirdyear ended December 31, 2022, we issued and fourth quarters of 2021, we have issued 1.6 millionsold 3,423,593 ordinary shares under thesuch program at an average market price of $38.43$33.57 per share pursuant to our Distribution Agreement, representing gross proceeds of $62$114.9 million and net proceeds of $61.4 million$113.8 million.
Project debt refinancing
In October 2022, we refinanced the project debt of Solacor 1 & 2 and in December 2022, we refinanced the project debt of Solnova 1, 3 & 4 (see “Item 4— Information on the Company— Our Operations —Renewable Energy”)
123
Uses of liquidity and capital requirements
Principal payments on debt as of December 31, 2021,2022, are due in the following periods according to their contracted maturities:
Principal debt repayment schedule
| | Total | | 2022 | | 2023 | | 2024 | | 2025 | | 2026 | | | Subsequent years | | | Total | | 2023 | | 2024 | | 2025 | | 2026 | | 2027 | | | Subsequent years | |
| | $ in millions | | | | | | $ in millions | | | | |
Solana | | | 585.0 | | | | 20.7 | | | | 21.8 | | | | 24.2 | | | | 26.8 | | | | 29.5 | | | | 461.8 | | | 577.4 | | | 23.0 | | | 24.2 | | | 26.8 | | | 29.5 | | 32.4 | | | 441.5 | |
Mojave | | | 514.7 | | | | 35.3 | | | | 35.7 | | | | 36.9 | | | | 38.1 | | | | 39.4 | | | | 329.4 | | | 493.8 | | | 36.4 | | | 36.9 | | | 38.1 | | | 39.4 | | 40.7 | | | 302.3 | |
Coso | | | 214.4 | | | | 15.4 | | | | 14.1 | | | | 14.6 | | | | 14.2 | | | | 14.7 | | | | 141.3 | | | 200.8 | | | 14.1 | | | 14.6 | | | 14.2 | | | 14.7 | | 143.2 | | | - | |
ACT | | | 478.7 | | | | 38.3 | | | | 40.0 | | | | 37.6 | | | | 42.3 | | | | 54.6 | | | | 266.1 | | | 441.1 | | | 41.5 | | | 37.6 | | | 42.3 | | | 54.6 | | 59.0 | | | 206.1 | |
North America | | | 1,792.7 | | | | 109.7 | | | | 111.6 | | | | 113.3 | | | | 121.4 | | | | 138.2 | | | | 1,198.6 | | | 1,713.1 | | | 115.0 | | | 113.3 | | | 121.4 | | | 138.2 | | 275.3 | | | 949.9 | |
Chile PV 1 | | | 51.0 | | | | 1.6 | | | | 0.9 | | | | 1.1 | | | | 1.1 | | | | 1.2 | | | | 45.1 | | | 50.5 | | | 2.0 | | | 1.1 | | | 1.0 | | | 1.1 | | 1.5 | | | 43.8 | |
Chile PV 2 | | | 25.6 | | | | 0.8 | | | | 0.9 | | | | 1.0 | | | | 1.7 | | | | 2.9 | | | | 18.5 | | | 21.4 | | | 1.2 | | | 0.8 | | | 1.4 | | | 2.4 | | 2.1 | | | 13.5 | |
Palmatir | | | 77.3 | | | | 6.5 | | | | 6.1 | | | | 6.2 | | | | 6.6 | | | | 7.0 | | | | 44.9 | | | 72.0 | | | 6.9 | | | 6.2 | | | 6.6 | | | 7.0 | | 7.5 | | | 37.8 | |
Cadonal | | | 60.4 | | | | 3.8 | | | | 3.5 | | | | 3.7 | | | | 3.9 | | | | 4.3 | | | | 41.2 | | | 46.6 | | | 3.3 | | | 3.0 | | | 3.1 | | | 3.4 | | 3.6 | | | 30.2 | |
Melowind | | | 70.9 | | | | 2.5 | | | | 2.8 | | | | 4.8 | | | | 5.0 | | | | 5.1 | | | | 50.7 | | | 68.6 | | | 2.8 | | | 4.8 | | | 5.0 | | | 5.1 | | 4.8 | | | 46.1 | |
ATN | | | 92.4 | | | | 5.4 | | | | 5.7 | | | | 6.0 | | | | 6.4 | | | | 6.8 | | | | 62.0 | | | 87.0 | | | 5.7 | | | 6.0 | | | 6.4 | | | 6.8 | | 7.3 | | | 54.8 | |
ATS | | | 397.2 | | | | 11.4 | | | | 7.9 | | | | 7.4 | | | | 8.3 | | | | 9.5 | | | | 352.8 | | | 391.5 | | | 12.6 | | | 7.4 | | | 8.3 | | | 9.5 | | 10.7 | | | 343.0 | |
ATN 2 | | | 49.8 | | | | 4.7 | | | | 4.8 | | | | 5.0 | | | | 5.1 | | | | 5.3 | | | | 24.9 | | | 45.3 | | | 4.8 | | | 5.0 | | | 5.1 | | | 5.3 | | 5.4 | | | 19.7 | |
Quadra 1&2 and Palmucho | | | 62.8 | | | | 4.5 | | | | 4.9 | | | | 5.4 | | | | 5.9 | | | | 6.5 | | | | 35.5 | | | 58.7 | | | 5.0 | | | 5.3 | | | 5.9 | | | 6.5 | | 7.2 | | | 28.8 | |
South America | | | 887.5 | | | | 41.3 | | | | 37.4 | | | | 40.6 | | | | 44.0 | | | | 48.6 | | | | 675.6 | | | 841.6 | | | 44.3 | | | 39.6 | | | 42.8 | | | 47.1 | | 50.1 | | | 617.7 | |
Solaben 2&3(1) | | | 382.8 | | | | 33.5 | | | | 32.8 | | | | 34.4 | | | | 146.1 | | | | 30.4 | | | | 105.5 | | | 330.4 | | | 31.4 | | | 32.4 | | | 138.1 | | | 28.7 | | 31.2 | | | 68.6 | |
Solacor 1&2 | | | 233.9 | | | | 23.9 | | | | 24.4 | | | | 27.3 | | | | 29.3 | | | | 31.0 | | | | 98.0 | | | 212.8 | | | 10.3 | | | 14.0 | | | 14.6 | | | 15.0 | | 15.4 | | | 143.5 | |
PS 20 | | | 56.1 | | | | 5.8 | | | | 6.0 | | | | 6.3 | | | | 6.7 | | | | 7.1 | | | | 24.2 | | |
Helios 1&2 | | | 327.3 | | | | 19.7 | | | | 21.7 | | | | 22.6 | | | | 23.0 | | | | 22.5 | | | | 217.9 | | | 290.8 | | | 20.7 | | | 21.3 | | | 21.7 | | | 21.1 | | 21.5 | | | 184.5 | |
Helioenergy 1&2 | | | 272.9 | | | | 17.4 | | | | 18.5 | | | | 19.9 | | | | 21.1 | | | | 20.0 | | | | 176.1 | | | 243.5 | | | 17.4 | | | 18.7 | | | 19.9 | | | 18.8 | | 20.1 | | | 148.6 | |
Solnova 1,3&4 | | | 435.2 | | | | 45.6 | | | | 45.1 | | | | 48.0 | | | | 50.7 | | | | 53.6 | | | | 192.2 | | | 354.9 | | | 28.1 | | | 30.0 | | | 30.6 | | | 32.1 | | 31.9 | | | 202.2 | |
Solaben 1&6 | | | 213.7 | | | | 14.3 | | | | 14.8 | | | | 14.8 | | | | 15.7 | | | | 16.3 | | | | 137.8 | | | 188.0 | | | 13.9 | | | 13.9 | | | 14.8 | | | 15.4 | | 15.8 | | | 114.2 | |
Rioglass | | | 19.0 | | | | 9.9 | | | | 3.6 | | | | 1.9 | | | | 2.0 | | | | 1.2 | | | | 0.3 | | | 10.3 | | | 5.2 | | | 1.7 | | | 1.9 | | | 1.3 | | 0.1 | | | 0.1 | |
Italy PV 1&3 | | | 2.8 | | | | 0.5 | | | | 0.6 | | | | 0.6 | | | | 0.6 | | | | 0.3 | | | | 0.3 | | | 3.4 | | | 0.7 | | | 0.7 | | | 0.7 | | | 0.5 | | 0.2 | | | 0.6 | |
Kaxu | | | 314.5 | | | | 1.4 | | | | 27.0 | | | | 29.4 | | | | 29.9 | | | | 33.7 | | | | 193.1 | | | 277.6 | | | 26.7 | | | 27.5 | | | 28.0 | | | 31.6 | | 34.4 | | | 129.4 | |
Skikda | | | 12.0 | | | | 4.7 | | | | 4.8 | | | | 2.5 | | | | 0.0 | | | | 0.0 | | | | 0.0 | | | 7.4 | | | 4.9 | | | 2.5 | | | - | | | - | | - | | | - | |
Tenes | | | 85.9 | | | | 7.7 | | | | 7.7 | | | | 8.0 | | | | 8.3 | | | | 8.6 | | | | 45.6 | | | 79.3 | | | 8.0 | | | 8.1 | | | 8.4 | | | 8.7 | | 9.0 | | | 37.1 | |
EMEA | | | 2,356.0 | | | | 184.4 | | | | 207.0 | | | | 215.6 | | | | 333.3 | | | | 224.8 | | | | 1,190.9 | | | 1,998.4 | | | 167.3 | | | 170.8 | | | 278.7 | | | 173.2 | | 179.6 | | | 1,028.8 | |
Total project debt | | $ | 5,036.2 | | | | 335.4 | | | | 356.0 | | | | 369.5 | | | | 498.7 | | | | 411.5 | | | | 3,065.1 | | | $ | 4,553.1 | | | 326.6 | | | 323.7 | | | 442.9 | | | 358.5 | | 505.0 | | | 2,596.4 | |
Corporate debt | | $ | 1,023.1 | | | | 27.9 | | | | 10.1 | | | | 1.9 | | | | 106.2 | | | | 327.1 | | | | 550.0 | | | $ | 1,017.2 | | | 16.7 | | | 38.9 | | | 110.2 | | | 309.1 | | 147.3 | | | 395.0 | |
Total | | $ | 6,059.3 | | | | 363.3 | | | | 366.1 | | | | 371.4 | | | | 604.9 | | | | 738.6 | | | | 3,615.1 | | | $ | 5,570.3 | | | 345.3 | | | 362.6 | | | 553.1 | | | 667.6 | | 652.3 | | | 2,989.4 | |
Note:
(1) | Includes the outstanding amount of the Green Project Finance from the sub-holding company of Solaben 1 & 6 and Solaben 2 & 3. This facility is 25% progressively amortized over its 5-year term and the remaining 75% is expected to be refinanced before maturity. |
The project debt maturities will be repaid with cash flows generated from the projects in respect of which that financing was incurred.
B) | Contractual obligations |
In addition to the principal repayment debt obligations detailed above, we have other contractual obligations to make future payments. The material obligations consist of interest related to our project debt and corporate debt and agreements in which we enter in the normal course of business.
| | Total | | | Up to one year | | | Between one and three years | | | Between three and five years | | | Subsequent years | |
| | $ in millions | |
Purchase commitments | | | 823.9 | | | | 96.8 | | | | 154.3 | | | | 107.9 | | | | 464.8 | |
Accrued interest estimate during the useful life of loans | | | 1,821.9 | | | | 264.6 | | | | 477.9 | | | | 383.3 | | | | 696.0 | |
| | Total | | | Up to one year | | | Between one and three years | | | Between three and five years | | | Subsequent years | |
| | $ in millions | |
Purchase commitments | | | 1,570.8 | | | | 79.2 | | | | 191.2 | | | | 159.3 | | | | 1,141.1 | |
Accrued interest estimate during the useful life of loans | | | 2,029.4 | | | | 267.6 | | | | 497.6 | | | | 427.2 | | | | 837.0 | |
Purchase obligations include agreements for the purchase of goods or services that are enforceable and legally binding on the combined group and that specify all significant terms, including fixed or minimum quantities to be purchased, fixed, minimum or variable price provisions and the appropriate timing of the transactions.terms. In the first quarter of 2022, we have reached an agreement to internalize some of our long-term operation and maintenance contracts at Kaxu and at part of our solar assets in Spain and to reduce the duration of other contracts. As a result, purchase commitments have decreased with respect to December 31, 2022. In addition, as of the date of this report we are in the process of transitioning the operation and maintenance services for the rest of our assets in Spain from an Abengoa subsidiary to an Company’s subsidiary. The information in the table above is as of December 31, 2022 and includes purchase commitments with Abengoa, which are no longer binding after such transfer.
Accrued interest estimate during the useful life of loans represents the estimation for the total amount of interest to be paid or accumulated over the useful life of the loans, notes and bonds, taking into consideration the hedging contracts.
B)C) | Cash dividends to investors |
We intend to distribute a significant portion of our cash available for distribution to shareholders on an annual basis less all cash expenses including corporate debt service and corporate general and administrative expenses and less reserves for the prudent conduct of our business, (including, among other things, dividend shortfall as a result of fluctuations in our cash flows), on an annual basis. We intend to distribute a quarterly dividend to shareholders. Our board of directors may, by resolution, amend the cash dividend policy at any time. The determination of the amount of the cash dividends to be paid to shareholders will be made by our board of directorstime (See “Item 8 — Financial Information—Consolidated Statements and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our board of directors deem relevant.Other Financial Information—Dividend Policy.”).
Our cash available for distribution is likely to fluctuate from quarter to quarter and, in some cases, significantly as a result of the seasonality of our assets, the terms of our financing arrangements, maintenance and outage schedules, among other factors. Accordingly, during quarters in which our projects generate cash available for distribution in excess of the amount necessary for us to pay our stated quarterly dividend, we may reserve a portion of the excess to fund cash distributions in future quarters. During quarters in which we do not generate sufficient cash available for distribution to fund our stated quarterly cash dividend, if our board of directors so determines, we may use retained cash flow from other quarters, and other sources of cash.
Declared | | Record Date | | Payment Date | | $ per share | |
February 26, 2021 | | March 12, 2021 | | March 22, 2021 | | 0.42 | |
May 4, 2021 | | May 31, 2021 | | June 15, 2021 | | 0.43 | |
July 30, 2021 | | August 31, 2021 | | September 15, 2021 | | 0.43 | |
November 9, 2021 | | November 30, 2021 | | December 15, 2021 | | 0.435 | |
February 25, 2022 | | March 14, 2022 | | March 25, 2022 | | 0.44 | |
D) | Investments and Acquisitions |
The acquisitions and investments detailed in “Significant events in 2021”2022” have been part of the use of our liquidity in 2021. In addition, we have made investments in assets which are currently under development or construction.2022. We expect to continue making investments in assets in operation or under construction or development to grow our portfolio.
In 2022, we invested $39.1 million in maintenance capital expenditures in our assets. From this amount, $20.5 million corresponded to investments in the storage system in Solana. In 2021, we invested $19.2 million in maintenance capital expenditures in our assets, mainly corresponding to capital expenditures and equipment replacements at Solana. In some cases, maintenance capex is included in the operation and maintenance agreement, therefore it is included in operating expenses within our Income Statement.income statement.
Cash flow
The following table sets forth cash flow data for the years ended December 31, 2022, 2021 2020 and 2019:2020:
| | Year ended December 31, | | | Year ended December 31, | |
| | 2021 | | 2020 | | 2019 | | | 2022 | | 2021 | | 2020 | |
| | $ in millions | | | ($ in millions) | |
Gross cash flows from operating activities | | | | | | | | | | | | | | |
Profit/(loss) for the year | | $ | (10.9 | ) | | $ | 16.9 | | | $ | 74.6 | | | $ | (2.1 | ) | | $ | (10.9 | ) | | $ | 16.9 | |
Adjustments to reconcile after-tax profit to net cash generated by operating activities | | | 861.9 | | | | 719.5 | | | | 713.5 | | | | 786.9 | | | | 861.9 | | | | 719.5 | |
Profit for the year adjusted by non-monetary items | | $ | 851.0 | | | $ | 736.4 | | | $ | 788.1 | | | $ | 784.8 | | | $ | 851.0 | | | $ | 736.4 | |
Net interest/taxes paid | | | (342.3 | ) | | | (287.3 | ) | | | (299.5 | ) | | | (277.3 | ) | | | (342.3 | ) | | | (287.3 | ) |
Variations in working capital | | | (3.1 | ) | | | (10.9 | ) | | | (125.0 | ) | | | 78.8 | | | | (3.1 | ) | | | (10.9 | ) |
Total net cash flow provided by/ (used in) operating activities | | $ | 505.6 | | | $ | 438.2 | | | $ | 363.6 | | | $ | 586.3 | | | $ | 505.6 | | | $ | 438.2 | |
Net cash flows from investing activities | | | | | | | | | | | | | | | | | | | | | | | | |
Acquisitions of subsidiaries and entities under equity method | | | (362.4 | ) | | | 2.5 | | | | (173.4 | ) | | | (50.5 | ) | | | (362.4 | ) | | | 2.5 | |
Investments in contracted concessional assets(1) | | | (24.7 | ) | | | (1.4 | ) | | | 22.0 | | |
Investments in operating concessional assets(1) | | | | (39.1 | ) | | | (19.2 | ) | | | (1.4 | ) |
Investments in assets under development or construction | | | | (36.8 | ) | | | (7.0 | ) | | | - | |
Distributions from entities under the equity method | | | 34.8 | | | | 22.2 | | | | 30.5 | | | | 67.7 | | | | 34.8 | | | | 22.2 | |
Other non-current assets/liabilities | | | 1.1 | | | | (29.2 | ) | | | 2.7 | | | | 1.3 | | | | 2.7 | | | | (29.2 | ) |
Total net cash flows (used in)/ provided by investing activities | | $ | (351.2 | ) | | $ | (5.9 | ) | | $ | (118.2 | ) | | $ | (57.4 | ) | | $ | (351.2 | ) | | $ | (5.9 | ) |
Net cash flows used in financing activities | | $ | (380.1 | ) | | $ | (137.3 | ) | | $ | (310.2 | ) | | $ | (535.0 | ) | | $ | (380.1 | ) | | $ | (137.3 | ) |
Net increase / (decrease) in cash and cash equivalents | | | (225.7 | ) | | | 295.0 | | | | (64.8 | ) | | | (6.1 | ) | | | (225.7 | ) | | | 295.0 | ) |
Cash, cash equivalents and bank overdraft at beginning of the year | | | 868.5 | | | | 562.8 | | | | 631.5 | | | | 622.7 | | | | 868.5 | | | | 562.8 | |
Translation differences cash or cash equivalents | | | (20.1 | ) | | | 10.7 | | | | (3.9 | ) | | | (15.6 | ) | | | (20.1 | ) | | | 10.7 | ) |
Cash and cash equivalents at the end of the period | | $ | 622.7 | | | $ | 868.5 | | | $ | 562.8 | | | $ | 601.0 | | | $ | 622.7 | | | $ | 868.5 | |
Note:
(1) | Includes proceeds for $20.5 million and $17.4 million in 2021 and 2020 respectively. See Note 6 of the Annual Consolidated Financial Statements. |
(1) Includes proceeds for $20.5 million and $7.4 million in 2021 and 2020 respectively, See Note 6 of the Annual Consolidated Financial Statements.
Net cash flows provided by/ (used in) operating activities
Net cash provided by operating activities in 20212022 was $505.6$586.3 million, a 15.4%16.0% increase compared to $438.2$505.6 million for the previous year. The increase was mainly due to an improvement of changes in working capital and lower interest and income tax paid. Changes in working capital improved in the increaseyear ended December 31, 2022, mostly due to better collections from Pemex in Adjusted EBITDA previously explainedACT and to higher electricity market pricesbetter collections in Spain. In Spain, in 2021 when compared2022 we collected revenue in line with the parameters corresponding to 2020. This effectthe regulation in place at the beginning of the year 2022, as the new parameters became final on December 14, 2022, while revenue for the year ended December 31, 2022 was partially offset by higherrecorded in accordance with the new parameters. Collections have started to be regularized in 2023 (see “Item 4—Information on the Company—Regulation— Regulation in Spain”). Net interest and income tax paid were lower in 2021the year ended December 31, 2022 compared to the same period of the previous year.year due to the impact of foreign exchange rate and because interest paid typically decrease in each asset as we progressively repay our project debt.
The significant variances in the net cash flows provided by or used in operating activities for the year ended December 31, 20202021 compared to the year ended December 31, 20192020 are discussed in the Form 20-F filed with the SEC on March 1, 2021.February, 2022.
Net cash provided by/ (used in) investing activities
For the year ended December 31, 2022, net cash used in investing activities amounted to $57.4 million and included mainly to $50.5 million paid for acquisitions consisting mainly of Chile TL4, Chile PV 3, Chile PMGD and Italy PV4, investments in assets under construction for $36.8 million and other investments in existing assets for $39.1 million, including the investments and replacements in Solana. These cash outflows were partially offset by $67.7 million of dividends received from entities under the equity method, of which $26.9 million corresponded to Amherst Island Partnership by AYES Canada, most of which were paid to our partner in this project.
For the year 2021, net cash used in investing activities amounted to $351.2 million and corresponded mainly to $362.0 million paid for the acquisitions of Vento II, Coso, Calgary, Chile PV2, Rioglass, Italy PV 1, Italy PV 2, Italy PV 3 and La Sierpe, net of the initial cash contribution from these entities. Net cash used in investing activities also includes investments in concessional assets for $24.7$19.2 million, mainly corresponding to capital expenditures and equipment replacements at Solana for $24.5 million and in Spain for $8.5 million, partially offset by $20.5 million of proceeds from the sale of a buildingreal state assets owned by Rioglass. These cash outflows were partially offset by $34.8 million of dividends received from associates under the equity method, of which $15.8 million corresponded to Amherst Island Partnership by AYES Canada, most of which were paid to our partner in this project.
For the year, 2020, net cash provided by investing activities was $5.9 million and included $22.2 million of dividends received from associates under equity method, of which $16.4 million corresponds to dividends received from Amherst Island Partnership and should be considered together with the $15.7 million paid to non-controlling interest and classified as net cash provided by financing activities. Net cash provided by investing activities also included $11.1 million positive amount from the acquisition of Tenes, since the cash consolidated at the acquisition date is higher than the payment made under the agreement signed in May 2020. These effects were partially offset by $8.7 million paid in investments, $21.6 million transferred to financial investments for potential equipment replacements in Solana and other minor maintenance capex.
The significant variances in the net cash flows provided by or used in investing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 are discussed in the Form 20-F filed with the SEC on March 1, 2021.
Net cash provided by/ (used in) financing activities
For the year ended December 31, 2022, net cash used in financing activities amounted to $535.0 million and includes the repayment of principal of our project financing for $426.4 million and dividends paid to shareholders for $203.1 million and non-controlling interests for $39.2 million. These cash outflows were partially offset by the proceeds from the equity raised under the “at-the-market program” for a net amount of $113.2 million and by net proceeds from corporate debt of $20.6 million, corresponding mainly to the increase of the amount drawn under our Revolving Credit Facility.
For the year 2021, net cash used in financing activities amounted to $380.1 million and includes the repayment of principal of our project financing agreements for an approximate amount of $418.3 million and $218.7 million of dividends paid to shareholders and non-controlling interests. These cash outflows were partially offset by the proceeds from the equity private placement closed in January 2021 for a net amount of $130.6 million and equity raised under the ATMprevious “at-the-market program” for a net amount of $58.8 million, net of transaction costs. In addition, in the second quarter of 2021 we prepaid the Note Issuance Facility 2019 for $354.2 million with the proceeds of the Green Senior Notes issued, amounting to $394.0 million, which created a net cash inflow of $39.8 million.
For the year 2020, net cash used in financing activities was $137.3 million and corresponded mainly to the proceeds from the 2020 Green Private Placement, the Note Issuance Facility 2020, the Green Project Finance, the Green Exchangeable Notes and the project debt refinancings of Helios and Helioenergy, for a total amount of $827.1 million and to the withdrawal of $90.0 million under the Revolving Credit Facility in the first quarter of 2020. Net cash used in financing activities also includes $162.2 million from the underwritten public offering closed in December 2020. These cash inflows were partially offset by the repayment of $308.8 million of the Note Issuance Facility 2017, the repayment of $174.0 million of our Revolving Credit Facility in the third quarter, the scheduled repayment of principal of our project financing agreements for $298.7 million and $191.6 million of dividends paid to shareholders and non-controlling interest. Net cash used in financing activities also includes $266.8 million paid for the acquisition of the Liberty Interactive Ownership Interest in Solana.
The significant variances in the net cash flows provided by or used in investing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 are discussed in the Form 20-F filed with the SEC on March 1, 2021.
C. | Research and Development |
Not applicable.As of December 31, 2022, we own 31 patents and technology licenses related to key components of our assets, to processes and to solutions to monitor, operate and maintain our assets in a sustainable and cost-effective manner, as well as 6 patents currently in process. We also have an Operations Department that dedicates time and effort to identifying potential measures to improve asset performance, reducing operating costs and developing tools to manage our assets more efficiently. In addition, we have an in-house advanced analytics team to improve the performance of our existing technologies. The advanced analytics team focuses on data analytics and machine learning technologies to provide accurate energy production forecasts, predict equipment breakdowns or malfunctions, and reduce the risk of major outages as well as health and safety and environmental risks, among others.
Other than as disclosed elsewhere in this annual report on, Form 20F, we are not aware of any trends, uncertainties, demands, commitments or events for the year ended December 31, 20212022 that are reasonably likely to have a material adverse effect on our revenues, income, profitability, liquidity or capital resources, or that caused the disclosed financial information to be not necessarily indicative of future operating results or financial conditions.
E. | Critical Accounting Estimates |
The preparation of our Annual Consolidated Financial Statements in conformity with IFRS requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions we believe to be reasonable under the specific circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.
For an understanding of the accounting policies for these items it is important to understand the Annual Consolidated Financial Statements. The following discussion provides more information regarding the estimates and assumptions used for these items in accordance with IFRS and should be considered in conjunction with the Annual Consolidated Financial Statements.
The most critical accounting policies, which reflect significant management estimates and judgment to determine amounts in our Annual Consolidated Financial Statements, are as follows:
Estimates:
- | Impairment of contracted concessional, Property, Plant and Equipment (PP&E) and other intangible assets |
Impairment exists when the carrying value of an asset or cash generating unit exceeds its recoverable amount, which is the higher of its fair value less costs of disposal and its value in use. The value in use calculation is based on a discounted cash flow model, which is sensitive to the discount rate used as well as the expected future cash-inflows. The significant assumptions which required substantial estimates used in management’s impairment calculation are discount rates and projections considering real data based on contract terms and projected changes in selling prices, energy generation and costs.
- | Recoverability of deferred tax assets |
Deferred tax assets are recognized for unused tax losses to the extent that it is probable that taxable profit will be available against which the losses can be utilized. Significant management estimates are required to determine the amount of deferred tax assets that can be recognized, based upon the likely timing and the level of future taxable profits together with future tax planning strategies.
- | Fair value of derivative financial instruments |
When the fair values of financial assets and financial liabilities recorded in the statement of financial position cannot be measured based on quoted prices in active markets, their fair value is measured using valuation techniques including the discounted cash flow model. The inputs to these models are taken from observable markets where possible, but where this is not feasible, a degree of estimate is required in establishing fair values. Estimates include considerations of inputs such as liquidity risk, credit risk and volatility. Changes in assumptions relating to these factors could affect the reported fair value of financial instruments
- | Fair value of identifiable assets and liabilities arising from a business combination |
The assets aquired and liabilites assumed on a business combination are recognised at the fair values of the underlying items. The estimates that have a significant risk of causing a material adjustment to the carrying amounts of the assets and liabilities are the ones considered when performing impairment review of operating assets (see above).
Judgements:
- | Assessment of Contractedcontracted concessional agreements;agreements. |
- | Impairment of intangible assets and property, plants and equipment; |
By evaluating the terms and conditions of each contracted concessional agreement, we determine the accounting category to which the asset belongs (e.g. IAS 16, IFRIC 12 or IFRS 16).
- | Derivative financial instruments and fair value estimates; and |
- | Income taxes and recoverable amount of deferred tax assets.control. |
Judgement is required in determining the nature of Atlantica´s interest in another entity and in determining if it has control, joint control or significant influence over it.
Some of the accounting policies applied require the application of significant judgment by management to select the appropriate assumptions to determine these estimates. These assumptions and estimates are based on our historical experience, advice from experienced consultants, forecasts and other circumstances and expectations as of the close of the financial period. The assessment is considered in relation to the global economic situation of the industries and regions where we operate, considering future development of our businesses. By their nature, these judgments are subject to an inherent degree of uncertainty; therefore, actual results could materially differ from the estimates and assumptions used. In such cases, the carrying values of assets and liabilities are adjusted.
As of the date of preparation of our Annual Consolidated Financial Statements, no relevant changes in the estimates made are anticipated and, therefore, no significant changes in the value of the assets and liabilities recognized at December 31, 2021,2022, are expected.
Although these estimates and assumptions are being made using all available facts and circumstances, it is possible that future events may require management to amend such estimates and assumptions in future periods. Changes in accounting estimates are recognized prospectively, in accordance with IAS 8, in the consolidated income statement of the year in which the change occurs. Our significant accounting policies are more fully described in noteNote 2 to our Annual Consolidated Financial Statements, presented elsewhere in this annual report on Form 20F.report.
Contracted concessional, Property, Plant and Equipment (PP&E) and other intangible assets
Contracted concessional assets correspond to the assets of the Company recorded as intangible or financial assets in accordance with IFRIC 12, property plant and equipment in accordance with IAS 16 and financial asset in accordance with IFRS 16. The assets accounted for by the CompanyAtlantica as concessionscontracted concessional assets under IFRIC 12 (either intangible model or financial model) as PP&E under IAS 16 or as other intangible assets under IAS 38 or under IFRS 16 (as “Lessee” or “Lessor”), include renewable energy assets, transmission lines, efficient natural gas assets and heat and water plants. The useful life of these assets is approximately the same as the length of the concession arrangement.
a) | Contracted concessional assets under IFRIC 12 |
The infrastructure used in a concession accounted for under IFRIC 12 can be classified as an intangible asset or a financial asset, depending on the nature of the payment entitlements established in the agreement.
The application of IFRIC 12 requires extensive judgement in relation to, among other factors, (i) the identification of certain infrastructures and contractual agreements in the scope of IFRIC 12, (ii) an understanding of the nature of the payments in order to determine the classification of the infrastructure as a financial asset or as an intangible asset and (iii) the timing and recognition of revenue from construction and concessionary activity.
Under the terms of contractual arrangements within the scope of this interpretation, the operator shall recognize and measure revenue in accordance with IFRS 15 for the services it performs.
The useful life of these assets is approximately the same as the length of the concession arrangement.
The Company recognizesWe recognize an intangible asset to the extent that it receives a right to charge final customers for the use of the infrastructure. This intangible asset is subject to the provisions of IAS 38 and is amortized linearly, taking into account the estimated period of commercial operation of the infrastructure which coincides with the concession period.
Once the infrastructure is in operation, the treatment of income and expenseexpenses is as follows:
- Revenues from the updated annual revenue for the contracted concession, as well as revenues from providing operations and maintenance services are recognized in each period according to IFRS 15 “Revenue from contracts with Customers”.
- Operating and maintenance costs and general overheads and administrative costs are recorded in accordance with the nature of the cost incurred (amount due) in each period.
b)- | Revenues from the updated annual revenue for the contracted concession, as well as operations and maintenance services are recognized in each period according to IFRS 15. |
- | Operating and maintenance costs and general overheads and administrative costs are recorded in accordance with the nature of the cost incurred (amount due) in each period. |
The Company recognizesWe recognize a financial asset when demand risk is assumed by the grantor, to the extent that the concession holder has an unconditional right to receive payments for the asset. This asset is recognized at the fair value of the construction services provided, considering upgrade services in accordance with IFRS 15, if any.
The financial asset is subsequently recorded at amortized cost calculated according to the effective interest method, using a theoretical internal rate of return specific to the asset.method. Revenue from operations and maintenance services is recognized in each period according to IFRS 15 “Revenue from contracts with Customers”.15.
Allowance for expected credit losses (financial assets)
According to IFRS 9, we recognize an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Company expectswe expect to receive.
There are two main approaches to applying the ECL model according to IFRS 9: the general approach which involves a three-stage approach, and the simplified approach, which can be applied to trade receivables, contract assets and lease receivables. We have elected to apply the simplified approach. Under this approach, there is no need to monitor for significant increases in credit risk and entities will be required to measure lifetime expected credit losses at the end of each reporting period.
The key elements of the ECL calculations, based on external sources of information, are the following:
| - | the Probability of Default (“PD”) is an estimate of the likelihood of default over a given time horizon. We calculate PD based on Credit Default Swaps spreads;spreads (“CDS”); |
| - | the Exposure at Default (“EAD”) is an estimate of the exposure at a future default date; and |
| - | the Loss Given Default (“LGD”) is an estimate of the loss arising in the case where a default occurs at a given time. It is based on the difference between the contractual cash flows due and those that the Companywe would expect to receive. It is expressed as a percentage of the EAD. |
c)b) | Property, plant and equipment (PP&E) under IAS 16 |
Assets recorded as property,Property, plant and equipment areis measured at historical cost, including all expenses directly attributable to the acquisition, less depreciation and impairment losses, with the exception of land, which is presented net of any impairment losses. OnceSuch cost includes the infrastructurecost of replacing part of the plant and equipment and borrowing costs for long-term installation projects if the recognition criteria is met. Repair and maintenance costs are recognized in operation,profit or loss as incurred.
Depreciation is calculated on a straight-line basis over the treatmentestimated useful lives of income and expenses is the same as intangible assets.
We review the estimated residual values and expected useful lives of assets at least annually. In particular, we consider the impact of health, safety and environmental legislation in its assessment of expected useful lives and estimated residual values.
An item of property, plant and equipment and any significant part initially recognized is derecognized upon disposal (i.e., at the date the recipient obtains control) or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss when the asset is derecognized.
c) | Right of uses under IFRS 16
|
We assess at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.
Atlantica as a lessee:
We apply a single recognition and measurement approach for all leases, except for short-term leases and leases of low-value assets. We recognize lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets.
Main right of use agreements corresponds to land rights. The Company recognizesWe recognize right-of-use assets at the commencement date of the lease (i.e., the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities (see Note 2.3 to our Annual Consolidated Financial Statements). The cost of right-of-use assets includes the amount of lease liabilities recognized, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets.
e)d) | Revenue RecognitionOther intangible assets |
Other intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and accumulated impairment losses. Intangible assets are amortized over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired.
An intangible asset is derecognized upon disposal (i.e., at the date the recipient obtains control) or when no future economic benefits are expected from its use or disposal. Any gain or loss arising upon derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss.
Research and development costs:
Research costs are expensed as incurred. Development expenditures on an individual project are recognised as an intangible asset when we can demonstrate:
| - | the technical feasibility of completing the intangible asset so that the asset will be available for use or sale |
| - | its intention to complete and its ability and intention to use or sell the asset |
| - | how the asset will generate future economic benefits |
| - | the availability of resources to complete the asset |
| - | the ability to measure reliably the expenditure during development |
Following initial recognition of the development expenditure as an asset, the asset is carried at cost less any accumulated amortization and accumulated impairment losses. Amortization of the asset begins when development is complete, and the asset is available for use. It is amortized over the period of expected future benefit. During the period of development, the asset is tested for impairment annually.
According to IFRS 15, Revenue from Contracts with Customers, the Company asseswe assess the goods and services promised in the contracts with the customers and identifies as a performance obligationsobligation each promise to transfer to the customer a good or service (or a bundle of goods or services).
In the case of contracts related to intangible or financial assets under IFRIC 12, the performance obligation of the Company is the operation of the asset. The contracts between the parties set the price of the service in an orderly transaction and therefore corresponds to the fair value of the service provided. The service is satisfied over time. The same conclusion applies to concessional assets that are classified as tangible assets under IAS 16 or leases under IFRS 16. All of the transaction prices of assets under IFRIC 12 are fixed and included as part of the long-term PPAs of the Company as disclosed in Note 1 to our Annual Consolidated Financial Statements, presented elsewhere in this annual report.Appendix III-2.
In the case of financial asset under IFRIC 12, the financial asset accounts for the payments to be received from the client over the residual life of the contract, discounted at a theoretical internal rate of return rate for the project. In each period, the financial asset is reduced by the amounts received from the client and increased by any capital expenditure that the project may incur and by the effect of unwinding the discount of the financial asset at the theoretical internal rate of return. The increase of the financial asset deriving from the unwinding of the discount of the financial asset is recorded as revenue in each period. Revenue will therefore differ from the actual billings made by the asset to the client in each period.
In the case of Spain, according to Royal Decree 413/2014, solar electricity producers receive: (i) the market price for the power they produce, (ii) a payment based on the standard investment cost for each type of plant (without any relation whatsoever to the amount of power they generate) and (iii) an “operating payment” (in €/MWh produced). The principle driving this economic regime is that the payments received by a renewable energy producer should be equivalent to the costs that they are unable to recover on the electricity pool market where they compete with non-renewable technologies. This economic regime seeks to allow a “well-run and efficient enterprise” to recover the costs of building and running a plant, plus a reasonable rate of return on investment (project investment rate of return). Some of the Company´s Spanish assets are receiving a remuneration based on a 7.09% reasonable rate of return until December 31, 2025 while others are receiving a remuneration based on a 7.398% reasonable rate of return until December 31, 2031.
Impairment of intangible assets and property, plant and equipment
We review our contracted revenueconcessional assets to identify any indicators of impairment at least annually. Except for ECL assessment for financial assets which is discussed in Note 2.3. to our Annual Consolidated Financial Statements. When impairment indicators exist, the Company calculateswe calculate the recoverable amount of the asset.
The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, we calculate the recoverable amount of the cash generating unit, or CGU to which the asset belongs.
When the carrying amount of the CGU to which these assets belong is higher than its recoverable amount, the assets are impaired.
Assumptions used to calculate value in use include a discount rate and projections considering real data based on the contract terms and projected changes in both selling prices and costs. The discount rate is estimated by management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.
For contracted or concession revenue assets with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no terminal value is assumed. Contracted revenue assets have a contractual structure that permits to estimate quite accurately the costs of the project and revenue during the life of the project.
Projections take into account real data based on the contract terms and fundamental assumptions based on part in specific reports prepared internally and supported by third-party reports, assumptions on demand and assumptions on production. Additionally, assumptions on macroeconomic conditions are also considered, such as inflation rates, future interest rates and sensitivity analysis are performed over all major assumptions, which can have a significant impact on the value of the asset.
Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.
Taking into account that in most CGUs the specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash-flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is performed.
In any case, sensitivity analyses are performed, especially in relation with the discount rate used and fair value changes in the main business variables, in order to ensure that possible changes in the estimates of these items do not impact the recovery of recognized assets.
In the event that the recoverable amount of an asset is lower than its carrying amount, an impairment charge for the difference would be recorded in the income statement under the item “Depreciation, amortization and impairment charges”.
An assessment is made at each reporting date to determine whether there is an indication that previously recognized impairment losses no longer exist or have decreased. If such indication exists, the Company estimateswe estimate the CGU’s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the income statement.
Assessment of control
Control over an investee is achieved when we have power over the investee, we are exposed, or have rights, to variable returns from our involvement with the investee and have the ability to use its power to affect its returns. We reassess whether or not we control an investee when facts and circumstances indicate that there are changes to one or more of these three elements of control.
We use the acquisition method to account for business combinations of companies controlled by a third party. According to this method, identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Any contingent consideration is recognized at fair value at the acquisition date and subsequent changes in its fair value are recognized in accordance with IFRS 9 either in profit or loss.loss or as a change to other comprehensive income. Acquisition-related costs are expensed as incurred. We recognize any non-controlling interest in the acquired entity either at fair value or at the non-controlling interest’s proportionate share of the acquirer’s net assets on an acquisition-by-acquisition basis.
All assets and liabilities between entities within the group, equity, income, expenses and cash flows relating to transactions between entities of the group are eliminated in full.
Derivative financial instruments and fair value estimates
Derivatives are recognized at fair value in the statement of financial position. The Company maintainsWe maintain both derivatives designated as hedging instruments in hedging relationships, and derivatives to which hedge accounting is not applied.
When hedge accounting is applied, hedging strategy and risk management objectives are documented at inception, as well as the relationship between hedging instruments and hedged items. Effectiveness of the hedging relationship needs to be assessed on an ongoing basis. Effectiveness tests are performed prospectively at inception and at each reporting date. We analyze on each date if all these requirements are met:
- | there is an economic relationship between the hedged item and the hedging instrument; |
- | the effect of credit risk does not dominate the value changes that result from that economic relationship; and |
- | the hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that we actually hedge and the quantity of the hedging instrument that we use to hedge that quantity of hedged item. |
Ineffectiveness is measured following accumulated dollar offset method.
In all cases, current Company’s hedging relationships are considered cash flow hedges. Under this model, the effective portion of changes in fair value of derivatives designated as cash flow hedges are recorded temporarily in equity and are subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffective portion of the hedged transaction is recorded in the consolidated income statement as it occurs.
When interest rate options are designated as hedging instruments, the time value is excluded from the hedging instrument as permitted by IFRS 9. Changes in the effective portion of the intrinsic are recorded in equity and subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffectiveness is recorded as financial income or expense as it occurs. Changes in options time value is recorded as cost of hedging. More precisely, considering that the hedged items are, in all cases, time period hedged item, changes in time value is recognized in other comprehensive income to the extent that it relates to the hedged item. The time value at the date of designation of the option as a hedging instrument, to the extent that it relates to the hedged item, is amortized on a systematic and rational basis over the period during which the hedge adjustment for the option’s intrinsic value could affect profit or loss.
When the hedging instrument matures or is sold, or when it no longer meets the requirements to apply hedge accounting, accumulated gains and losses recorded in equity remain as such until the forecast transaction is ultimately recognized in the income statement. However, if it becomes unlikely that the forecast transaction will actually take place, the accumulated gains and losses in equity are recognized immediately in the income statement.
Any change in fair value of derivatives instruments to which hedge accounting is not applied is directly recorded in the income statement.
The inputs used to calculate fair value of our derivatives are based on inputs other than quoted prices that are observable for the asset or liability, either directly (i.e., as prices) or indirectly (i.e., derived from prices), through the application of valuation models (Level 2). The valuation techniques used to calculate fair value of our derivatives include discounting estimated future cash flows, using assumptions based on market conditions at the date of valuation or using market prices of similar comparable instruments, amongstamong others. The valuation of derivatives requires the use of considerable professional judgment. These determinations were based on available market information and appropriate valuation methodologies. The use of different market assumptions and/or estimation methodologies may have a material effect on the estimated fair value amounts.
Income taxes and recoverable amount of deferred tax assets
CurrentThe current income tax expenseprovision is calculated on the basis of relevant tax laws in force at the date of the consolidated statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.
Determining income tax provision requires judgment in assessing the timing and the amount of deductible and taxable items, as well as the interpretation and application of tax laws in different jurisdictions. Due to this fact, contingencies or additional tax expenses could arise as a result of tax inspections or different interpretations of certain tax laws by the corresponding tax authorities.
We recognize deferred tax assets for all deductible temporary differences and all unused tax losses and tax credits to the extent that it is probable that future taxable profit will be available against which they can be utilized. We consider it probable that we will have sufficient taxable profit available in the future to enable a deferred tax asset to be recovered when:
- | There are sufficient taxable temporary differences relating to the same tax authority, and the same taxable entity is expected to reverse either in the same period as the expected reversal of the deductible temporary difference or in periods into which a tax loss arising from the deferred tax asset can be carried back or forward. |
- | It is probable that the taxable entity will have sufficient taxable profit, relating to the same tax authority and the same taxable entity, in the same period as the reversal of the deductible temporary difference (or in the periods into which a tax loss arising from the deferred tax asset can be carried back or forward). |
- | Tax planning opportunities are available to the entity that will create taxable profit in appropriate periods. |
Our management assesses the recoverability of deferred tax assets on the basis of estimates of future taxable profit. These estimates are derived from the projections of each of our assets. Based on our current estimates, we expect to generate sufficient future taxable income to achieve the realization of our current tax credits and tax loss carryforwards, supported by our historical trend of business performance.
In assessing the recoverability of our deferred tax assets, our management also considers the foreseen reversal of deferred tax liabilities and tax planning strategies. To the extent management relies on deferred tax liabilities for the recoverability of our deferred tax assets, such deferred tax liabilities are expected to reverse in the same period and jurisdiction and are of the same character as the temporary differences giving rise to the deferred tax assets. We consider that the recovery of our current deferred tax assets is probable without counting on potential tax planning strategies that we could use in the future.
F. | Off-Balance Sheet Arrangements |
As of December 31, 2021,2022, the overall sum of the Bank and Surety Insurances Bonds directly deposited by subsidiaries of Atlantica as a guarantee to third parties (clients, financial entities and other third parties) was $92.7$88.0 million. In addition, Atlantica issued guarantees amounting to $174.2$216.9 million as of December 31, 20212022 ($159.8174.2 million as of December 31, 2020)2021). Guarantees issued by us correspond mainly to guarantees provided to off-takers in PPAs, guarantees for debt service reserve accounts and guarantees for interconnection requests or agreements for renewable energy projects.
This annual report on Form 20F contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act and as defined in the Private Securities Litigation Reform Act of 1995. See “Cautionary Statements Regarding Forward-Looking Statements.”
ITEM 6.
| DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES |
A. | Directors and Senior Management |
Board of Directors of Atlantica
The Board of Directors of Atlantica comprises the following eight members:
Name | | Position | | Year of birth |
William Aziz | | Director, Independent | | 1956 |
Arun Banskota | | Director | | 1961 |
Brenda Eprile | | Director, Independent | | 1954 |
Debora Del Favero | | Director, Independent | | 1964 |
Brenda Eprile | | Director, Independent | | 1954 |
Michael Forsayeth | | Director, Independent | | 1954 |
Edward C. Hall | | Director, Independent | | 1959 |
Santiago Seage | | Chief Executive Officer and Director | | 1969 |
George Trisic | | Director | | 1960 |
Michael Woollcombe | | Director and Chair of the Board, Independent | | 1968 |
The business address of the members of the Board of Directors of Atlantica is Great West House, GW1, 17th floor, Great West Road, Brentford, TW8 9DF, United Kingdom.
There are no family relationships among any of our executive officers or directors. There are no potential conflicts of interest between the private interests or other duties of the members of the Board of Directors listed above and their duties to Atlantica, except in the case of Mr. Arun Banskota and Mr. George Trisic who serveserves on Algonquin’s board as President and Chief Executive Officer and Mr. George Trisic, who served until April 2022 as Chief Governance Officer and Corporate Secretary of Algonquin, respectively.Algonquin. Mr. Edward C. Hall has been an independent director since he was appointed on August 2, 2022.
The following is the biographical information of members of our Board of Directors.
William Aziz, Director
William Aziz is the President and Chief Executive Officer of BlueTree Advisors Inc., a private management advisory firm focused on improving the performance of global client companies by providing expertise to manage operational, financial and organizational challenges. Mr. Aziz is a director and Chair of the Audit Committee of TSX-listed Maple Leaf Foods Inc. and a member of the Advisory Board for Fengate Real Assets. From 2009 to 2019, Mr. Aziz was a Director of the Cdn. $100 billion Ontario Municipal Employees’ Retirement System, where he was Chair of its Investment Committee and a member of its Human Resources Committee. Mr. Aziz has served as a director of a number of publicly-traded companies. Mr. Aziz is a graduate of the Ivey School of Business at Western University in Honors Business Administration and is a Chartered Professional Accountant. Mr. Aziz has also completed the Institute of Corporate Directors Governance College at the Rotman School of Business, University of Toronto and holds the ICD.D designation and is a member of the Insolvency Institute of Canada.
Arun Banskota, Director
Mr. Banskota is the President of Algonquin and its President and Chief Executive Officer. Mr. Banskota joined Algonquin in February 2020 and has 30 years of experience in senior roles from a combination of industries such as renewable energy development, construction, financing, and operations. He has also served as manager of multiple large business units and three start-ups in the clean-tech space. Mr. Banskota holds a Master of Arts (University of Denver) and a Master of Business Administration (University of Chicago).
Debora Del Favero, Director
Debora Del Favero is a senior executive with extensive international mergers and acquisition and corporate finance experience including in the renewables sector. She is a Co-Founder of CMC Capital Limited, a U.K.-based corporate finance advisory boutique established in 2011 that specializes in M&A and corporate advisory. Previously, for over 17 years, Ms. Del Favero held progressively senior roles in both the London and New York offices of the investment banking division of Credit Suisse. This included approximately seven years as a Managing Director and member of the Energy Group and M&A Group of Credit Suisse in London. Ms. Del Favero also served on the European investment banking committee of Credit Suisse. Prior to joining Credit Suisse, Ms. Del Favero was a Senior Analyst at Analitica based in Milan, Italy, a start-up specializing in equity research on Italian publicly-listed companies. Ms. Del Favero holds a Masters of Arts in Economics and Business Administration from Bocconi University in Milan, Italy, with a focus on corporate finance and commercial law.
Brenda Eprile, Director
Brenda Eprile is a corporate director and sits on a variety of public and private company boards. She currently chairs the board of Global Container Terminals Inc. which operates 2 marine terminals in Vancouver and 2 marine terminals in the Port of New York/New Jersey. She is also a board member and chair of the Audit Committee of Westport Fuel Systems Inc., a TSX and NASDAQ-listed company that invents, engineers, builds and supplies clean alternative fuel systems and components. Ms. Eprile has been a director of Westport since 2013, and previously served as Chair of the Board from February 2017 to April 2020. From 2016 to 2018, Ms. Eprile served as a director TSX-listed alternative mortgage lender Home Capital Group Ltd., where she became Chair of the Board in 2017 and was part of leading Home Capital’s efforts in responding to a severe liquidity and regulatory crisis and in obtaining the support of Berkshire Hathaway Inc. as a major strategic investor. From 2000 to 2012, Ms. Eprile was a Senior Partner at PricewaterhouseCoopers LLP and led its Canadian Risk Advisory Services practice. From 1998 to 2000, Ms. Eprile led the Canadian Regulatory Risk practice at Deloitte LLP. From 1985 to 1997, Ms. Eprile had a distinguished career as a securities regulator in Canada, holding the positions of both Executive Director and Chief Accountant at the Ontario Securities Commission. Ms. Eprile is a Fellow Chartered Professional Accountant and holds the ICD.D designation. Ms. Eprile earned an MBA from the Schulich School of Business at York University.
Debora Del Favero, Director
Debora Del Favero is a senior executive with extensive international mergers and acquisition and corporate finance experience including in the renewables sector. She is a Co-Founder of CMC Capital Limited, a U.K.-based corporate finance advisory boutique established in 2011 that specializes in M&A and corporate advice. Previously, for over 17 years, Ms. Del Favero held progressively senior roles in both the London and New York offices of the Investment Banking Division of Credit Suisse. This included approximately seven years as a Managing Director and member of the Energy Group and M&A Group of Credit Suisse in London. Ms. Del Favero also served on the European Investment Banking Committee of Credit Suisse. Prior to joining Credit Suisse, Ms. Del Favero was a Senior Analyst at Analitica based in Milan, Italy, a start-up specializing in equity research on Italian publicly-listed companies. Ms. Del Favero holds a Masters of Arts in Economics and Business Administration from Bocconi University in Milan, Italy, with a focus on corporate finance and commercial law.
Michael Forsayeth, Director
Michael Forsayeth is an experienced business leader having held Chief Executive Officer, Chief Financial Officer and other senior executive positions in several large public and private real estate, hospitality, foodservice and other businesses over his career. Most recently, Mr. Forsayeth was Chief Executive Officer and a director of TSX and NYSE-listed Granite Real Estate Investment Trust, a large Canadian-based REIT with industrial, warehouse and logistics properties in North America and Europe. Prior to being appointed as Granite’s CEO, Mr. Forsayeth served as Granite’s Chief Financial Officer from 2011 to 2015. From 2007 to 2011, Mr. Forsayeth was Chief Financial Officer of Intrawest ULC, a significant developer and manager of resort properties in North America and Europe, following its $3 billion privatization by a private equity group. From 1999 to 2007, Mr. Forsayeth was the Chief Financial Officer of Cara Operations Limited (now Recipe Unlimited), a leading Canadian foodservice business, where Mr. Forsayeth played a key leadership role in Cara Operation’s successful going-private transaction. Previously, Mr. Forsayeth held senior executive positions with TSX and NYSE-listed Laidlaw Inc., and TSX-listed Derlan Industries Limited. Mr. Forsayeth is a CPA and CA and spent nine years with Coopers & Lybrand (now PWC)Pwc) in various areas including the audit practice and a secondment in its London, England office. Mr. Forsayeth holds a Bachelor of Commerce (Honours)(Honors) from Queen’s University.
Edward C. Hall, Director
Mr. Hall is an active independent director and advisor with 35 years of experience in all facets of the electricity industry. Mr. Hall brings a deep understanding of electricity markets, power generation technologies, utility operations and commercial structuring. Mr. Hall serves as Chairman of Cypress Creek Renewables, Vice Chairman of Japan Wind Development Company and as a Director of Wellesley Municipal Light. Mr. Hall spent 25 years of his career with AES Corporation, where he was a member of the AES Executive Leadership Team and served as Chief Operating Officer of AES’s global generation. Mr. Hall has previously served on the boards of General Cable, Globeleq, TerraForm Power and Green Conversion Systems. Mr. Hall earned a B.S. in Mechanical Engineering from Tufts University and M.S. in Finance and Technology Innovation from the MIT Sloan School of Management.
Santiago Seage, Chief Executive Officer and Director
Mr. Seage has served as a director since our formation in 20142013 until March 2018 and from December 2018. Mr. Seage has served as our Chief Executive Officer since our formation, except for the six-month period between May and November 2015, while he was Chair of our Board and Chief Executive Officer of Abengoa. Prior to the foregoing, he served as Abengoa Solar’s CEO beginning in 2006. Before joining Abengoa,that, he was a partner with McKinsey & Company. Mr. Seage holds a degree in Business Management from ICADE University in Madrid.
George Trisic, Director
Mr. Trisic iswas the Chief Governance Officer of Algonquin.Algonquin until April 2022. In his role, Mr. Trisic iswas responsible for leading the sustainability and government affairs. He has broad experience managing high growth, start up and expanding businesses across multiple sites and regions. His skill set includes leading multi-functional groups in finance, human resources, legal and information technology in a senior executive role. Mr. Trisic holds a Bachelor of Laws Degree from the University of Western Ontario. Additionally, he holds a Chartered Director certification from the Directors College (McMaster University).
Michael Woollcombe, Director and Chair of the Board
Michael Woollcombe has been a Partner of Voorheis & Co. LLP and Executive Vice-President of VC & Co. Incorporated for more than 20 years. Since 2011, Mr. Woollcombe has also been President of VWK Capital Management Inc., the investment manager for VWK Partners Fund LP, a long-short investment fund. Mr. Woollcombe is one of the leading special situations advisors in Canada and has been centrally involved in directing numerous high-profile shareholder disputes, proxy contests, M&A transactions, special committee mandates, internal and independent corporate investigations and complex restructurings. Mr. Woollcombe regularly serves as a trusted strategic advisor to institutional and other significant shareholders, boards of directors and chief executive officers to address their most important opportunities and crisis situations. Mr. Woollcombe has acted as a director and as member of special board committees of a number of publicly-traded companies. Previously, Mr. Woollcombe practiced corporate and securities law at a major law firm in Toronto, Canada. Mr. Woollcombe holds a Bachelor of Commerce (Honours)(Honors) from Queen’s University and an LLB from the University of Western Ontario.
Board Diversity Matrix
On August 6, 2021 the U.S. Securities and Exchange Commission (“SEC”)SEC approved Nasdaq’sNASDAQ’s Board Diversity Rule, requiring Nasdaq-listed companies to, subject to certain transition periods and exceptions (1) publicly disclose board-level diversity statistics in its annual report or on its website and in an aggregated form, using a standardized template and (2) have or explain why they do not have at least two diverse directors.
Atlantica, as a listed foreign private issuer, is required to have, or explain why it does not have, at least two diverse directors, including one who self-identifies as female, and one who self-identifies as either female, LGBTQ+ or an underrepresented individual. Foreign private issuers shall, starting by the later of (i) August 8, 2022, or (ii) the date when the annual report for the year ended 2022 is filed with the SEC, publish board level diversity statistics annually using either the U.S. domestic issuers prescribed matrix or the foreign private issuers prescribed matrix, and have, or explain why they do not have, one diverse director in 2023, and two diverse directors in 2025.
Considering that Atlantica voluntarily follows many U.S. domestic issuers reporting requirements, we report board diversity information following the U.S. domestic issuers prescribed matrix. The Company believes that it is presently in compliance with the diversity requirements pursuant to Nasdaq’sNASDAQ’s listing rules.
The information provided below is based on the voluntary self-identification of each member of the Company’s boardBoard of directors:Directors as of December 31, 2021 and December 31, 2022:
Board Diversity Matrix as of December 31, 2021 |
Total Number of Directors | | 8 |
| | Female | | Male | | Non-Binary | | Did Not Disclose Gender |
Part I: Gender Identity | | | | | | | | |
Directors | | 2 | | 6 | | - | | - |
Part II: Demographic Background | | | | | | | | |
African American or Black | | - | | - | | - | | - |
Alaskan Native or Native American | | - | | - | | - | | - |
Asian1 | | - | | 1 | | - | | - |
Hispanic or Latinx2 | | - | | 1 | | - | | - |
Native Hawaiian or Pacific Islander | | - | | - | | - | | - |
White3 | | 2 | | 4 | | - | | - |
Two or More Races or Ethnicities | | - | | - | | - | | - |
LGBTQ+ | | - |
Did Not Disclose Demographic Background | | - |
Note 1: This is the first year the Company discloses the Board Diversity Matrix. Over subsequent years we expect to include in our disclosures the current yearMatrix as of December 31, 2022 and immediately prior year diversity statistics.2021
Note 2: Nasdaq
| 2022 | 2021 |
Total Number of Directors | 9 | 8 |
| | Female | | | Male | | | Non-Binary | | | Did not disclosed Gender | |
| | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | |
Part I: Gender Identity | | | | | | | | | | | | | | | | | | | | | | | | |
Directors | | | 2 | | | | 2 | | | | 7 | | | | 6 | | | | - | | | | - | | | | - | | | | - | |
Part II: Demographic Background | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
African American or Black | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Alaskan Native or Native American | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Asian1 | | | - | | | | - | | | | 1 | | | | 1 | | | | - | | | | - | | | | - | | | | - | |
Hispanic or Latinx2 | | | - | | | | - | | | | 1 | | | | 1 | | | | - | | | | - | | | | - | | | | - | |
Native Hawaiian or Pacific Islander | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
White3 | | | 2 | | | | 2 | | | | 5 | | | | 4 | | | | - | | | | - | | | | - | | | | - | |
Two or More Races or Ethnicities | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
LGBTQ+ | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Did Not Disclose Demographic Background | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Note: NASDAQ demographic background definitions include:
(1) | Asian – A person having origins in any of the original peoples of the Far East, Southeast Asia, or the Indian subcontinent, including, for example, Cambodia, China, India, Japan, Korea, Malaysia, Pakistan, the Philippine Islands, Thailand, and Vietnam. |
(2) | Hispanic or Latinx – A person of Cuban, Mexican, Puerto Rican, South or Central American, or other Spanish culture or origin, regardless of race. The term Latinx applies broadly to all gendered and gender-neutral forms that may be used by individuals of Latin American heritage, including individuals who self-identify as Latino/a/e. |
(3) | White (not of Hispanic or Latinx origin) – A person having origins in any of the original peoples of Europe, the Middle East, or North Africa. |
Senior Management of Atlantica
We have a senior management team with extensive experience in developing, financing, managing and operating contracted assets.
Our senior management is made up ofcomprises the following members:
Name | | Position | | Year of birth |
David Esteban | | Vice President EMEA | | 1979 |
Emiliano Garcia | | Vice President North America | | 1968 |
Irene M. Hernandez | | General Counsel and Chief of Compliance | | 1980 |
Francisco Martinez-Davis | | Chief Financial Officer | | 1963 |
Antonio Merino | | Vice President South America | | 1967 |
Stevens C. Moore | | Vice President Strategy and Corporate Development | | 1973 |
Santiago Seage | | Chief Executive Officer and Director | | 1969 |
The business address of the members of the senior management of Atlantica is Great West House, GW1, 17 floor, Great West Road, Brentford, TW8 9DF, United Kingdom.
There are no potential conflicts of interest between the private interests or other duties of the members of the senior management listed above and their duties to Atlantica. There are no family relationships among any of our executive officers or directors.
Below are the biographies of those members of the senior management of Atlantica Sustainable Infrastructure who do not also serve on our Board of Directors.
David Esteban, Vice President EMEA
Mr. Esteban has served as Vice President of our operations in EMEA since July 2014. He had previously served at Abengoa’s Corporate Concession department for two years. Before joining Abengoa, David worked for the management consulting firm Arthur D. Little for seven years in the industries of Telecoms & Energy and then moved to a private equity firm specialized in renewable energy investments in Europe for three years.
Emiliano Garcia, Vice President North America
Mr. Garcia serves as Vice President of our North American business. Based in Phoenix, Arizona, he is responsible for managing two of our key assets, Solana and Mojave. Mr. Garcia was previously the General Manager of Abengoa Solar in the United States and of the Solana Power Plant. Before that, he held a number of managerial positions in various Abengoa companies over two decades. Mr. Garcia holds a Bachelor’s degree in Engineering from Madrid Technical University.
Irene M. Hernandez, General Counsel and Chief Compliance Officer
Ms. Hernandez has served as our General Counsel since June 2014.2014 and also serves as Chief Compliance Officer and Head of People and Culture. Prior to that, she served as head of our legal department since the date of our formation. Before that, Ms. Hernandez served as Deputy Secretary General at Abengoa Solar since 2012. Before joining Abengoa, she worked for several law firms. Ms. Hernandez holds a law degree from Complutense Madrid University and a Master’s degree in law from the Madrid Bar Association (Colegio de Abogados de Madrid (ICAM)).
Francisco Martinez-Davis, Chief Financial Officer
Mr. Martinez-Davis was appointed as our Chief Financial Officer on January 11, 2016. Mr. Martinez-Davis has more than 30 years of experience in senior finance positions both in the United States and Spain. He has served as Chief Financial Officer of several large industrial companies. Most recently, he was Chief Financial Officer for the company responsible for the management and operation of metropolitan rail service of the city of Madrid where he was also member of the Executive Committee. He has also worked as CFO for a retailer and as Deputy General Manager in Finance and Treasury for Telefonica Moviles. Prior to that, he worked for different investment banks in New York City and London for more than 10 years, including J.P. Morgan Chase & Co. and BNP Paribas. Mr. Martinez-Davis holds a Bachelor of Science, cum laude, in Business Administration from Villanova University in Philadelphia and an MBA from The Wharton School at the University of Pennsylvania.
Antonio Merino, Vice President South America
Mr. Merino serves as Vice President of our South American business. Previously, he was the Vice President of Abengoa’s Brazilian business, as well as the head of Abengoa’s commercial activities and partnerships in South America. Mr. Merino holds an MBA from San Telmo International Institute.
Stevens C. Moore, Vice President Strategy & Corporate Development
Mr. Moore has more than 25 years of experience in finance positions in Spain, the United Kingdom and the United States. He has worked in various positions in structured and leveraged finance at Citibank and Banco Santander, and vice president of M&A at GBS Finanzas. Most recently, he was director of corporate development and investor relations at Codere, the Madrid stock exchange listed international gaming company. He holds a B.A. degree in history from Tulane University of New Orleans, Louisiana.
Lead Independent Director
Our corporate governance guidelines provide that one of our independent directors shall serve as a lead independent director at any time when an independent director is not serving as the chair of our Board of Directors.
Compensation of the Board of Directors and Chief Executive Officer
Each independent non-executive director is entitled to receive annual compensation of $150.0 thousand. The Chair of the Board and Chairs of the committees of the Board are entitled to receive additional compensation as detailed in the table below.
Non-independent non-executive directors are entitled to be compensated on the same terms as independent non-executive directors. In 2021, and 2020, non-independent non-executive directors declined compensation. In 2022, Mr. Banskota also declined compensation. Since April 2022, Mr. Trisic has received compensation after retiring from a senior executive role at Algonquin Power Utilities Corp.
The following table sets out the fee schedule for 20212022 and 2020:2021:
In thousands of U.S. Dollars | | 2021 | | | 2020 | | | 2022 | | | 2021 | |
Annual Director Retainer | | | | | | | | | | | | |
Non-Executive Director | | 150.0 | | | 150.0 | | | 150.0 | | | 150.0 | |
Annual Committee Chair Retainer | | | | | | | | | | | | |
Chair of the Board | | 75.0 | | | 75.0 | | | 75.0 | | | 75.0 | |
Chair of the Audit Committee | | 15.0 | | | 15.0 | | | 15.0 | | | 15.0 | |
Chair of the Nominating and Corporate Governance Committee | | 10.0 | | | 10.0 | | | 10.0 | | | 10.0 | |
Chair of the Compensation Committee | | 10.0 | | | 10.0 | | | 10.0 | | | 10.0 | |
The table below summarizes the total annual compensation of the executive and non-executive directors who received remuneration during 2021, as well as the prior year for comparison. The Chief Executive Officer’s total annual compensation is also detailed in this table.2022 and 2021.
| | Salary and Fees | | | Annual Bonuses | | | LTIP2 | | | Total Fixed Remuneration | | | Total Variable remuneration | | | Total | |
| | 2021 | | | 2020 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | | | 2021 | | | 2020 | |
Name1 | | (in thousands of U.S. dollars) | |
William Aziz 3 | | | 160.0 | | | | 106.7 | | | | - | | | | - | | | | - | | | | - | | | | 160.0 | | | | 106.7 | | | | - | | | | - | | | | 160.0 | | | | 106.7 | |
Debora Del Favero3 | | | 160.0 | | | | 106.7 | | | | - | | | | - | | | | - | | | | - | | | | 160.0 | | | | 106.7 | | | | - | | | | - | | | | 160.0 | | | | 106.7 | |
Brenda Eprile3 | | | 165.0 | | | | 110.0 | | | | - | | | | - | | | | - | | | | - | | | | 165.0 | | | | 110.0 | | | | - | | | | - | | | | 165.0 | | | | 110.0 | |
Michael Forsayeth3 | | | 150.0 | | | | 100.0 | | | | - | | | | - | | | | - | | | | - | | | | 150.0 | | | | 100.0 | | | | - | | | | - | | | | 150.0 | | | | 100.0 | |
Santiago Seage 4 | | | 816.6 | | | | 756.8 | | | | 1,056.3 | | | | 996.4 | | | | 1,879.8 | | | | 770.9 | | | | 816.6 | | | | 756.8 | | | | 2,936.1 | | | | 1,767.3 | | | | 3,752.7 | | | | 2,524.1 | |
Michael Woollcombe3 | | | 225.0 | | | | 150.0 | | | | - | | | | - | | | | - | | | | - | | | | 225.0 | | | | 150.0 | | | | - | | | | - | | | | 225.0 | | | | 150.0 | |
Andrea Brentan5 | | | - | | | | 56.3 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 56.3 | | | | - | | | | - | | | | - | | | | 56.3 | |
Robert Dove5 | | | - | | | | 60.0 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 60.0 | | | | - | | | | - | | | | - | | | | 60.0 | |
Francisco J. Martinez5 | | | - | | | | 61.9 | | | | - | | | | - | | | | | | | | | | | | | | | | 61.9 | | | | | | | | | | | | | | | | 61.9 | |
Jackson Robinson5 | | | - | | | | 60.0 | | | | - | | | | - | | | | | | | | | | | | | | | | 60.0 | | | | | | | | | | | | | | | | 60.0 | |
Daniel Villalba5 | | | - | | | | 84.4. | | | | - | | | | - | | | | | | | | | | | | | | | | 84.4 | | | | | | | | | | | | | | | | 84.4 | |
Total | | | 1,676.6 | | | | 1,652.8 | | | | 1,056.3 | | | | 996.4 | | | | 1,879.8 | | | | 770.9 | | | | 1,676.6 | | | | 1,652.8 | | | | 2,936.1 | | | | 1,767.3 | | | | 4,612.7 | | | | 3,420.1 | |
In thousands of U.S. Dollars | | Salary and Fees in Cash | | | Salary and Fees in DRSUs2 | | | Annual Bonuses | | | Long-Term Incentive Awards3 (Vested) | | | Deferred Restricted Share Units Dividend Equivalents 3 | | | Total Fixed Remuneration | | | Total Variable Remuneration | | | Total | |
Name1 | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | |
William Aziz | | | 160.0 | | | | 160.0 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 160.0 | | | | 160.0 | | | | - | | | | - | | | | 160.0 | | | | 160.0 | |
Debora Del Favero | | | 112.0 | | | | 128.5 | | | | 48.0 | | | | 31.5 | | | | - | | | | - | | | | - | | | | - | | | | 2.5 | | | | 0.3 | | | | 162.5 | | | | 160.3 | | | | - | | | | - | | | | 162.5 | | | | 160.3 | |
Brenda Eprile | | | 165.0 | | | | 165.0 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 165.0 | | | | 165.0 | | | | - | | | | - | | | | 165.0 | | | | 165.0 | |
Michael Forsayeth | | | 75.0 | | | | 100.8 | | | | 75.0 | | | | 49.2 | | | | - | | | | - | | | | - | | | | - | | | | 4.0 | | | | 0.5 | | | | 154.0 | | | | 150.5 | | | | - | | | | - | | | | 154.0 | | | | 150.5 | |
Edward C Hall5 | | | 62.5 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 62.5 | | | | - | | | | - | | | | - | | | | 62.5 | | | | - | |
Santiago Seage6 | | | 727.2 | | | | 816.6 | | | | - | | | | - | | | | 931.3
| | | | 1,056.3
| | | | 2,992.4 | | | | 1,879.8 | | | | - | | | | - | | | | 727.2 | | | | 816.6 | | | | 3,923.7 | | | | 2,936.1 | | | | 4,651.0 | | | | 3,752.7 | |
George Trisic7 | | | - | | | | - | | | | 110.0 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 1.6 | | | | - | | | | 111.6 | | | | - | | | | - | | | | - | | | | 111.6 | | | | - | |
Michael Woollcombe | | | - | | | | 77.5 | | | | 225.0 | | | | 147.5 | | | | - | | | | - | | | | - | | | | - | | | | 11.9 | | | | 1.5 | | | | 236.9 | | | | 226.5 | | | | - | | | | - | | | | 236.9 | | | | 226.5 | |
Total | | | 1,301.7 | | | | 1,448.5 | | | | 458.0 | | | | 228.1 | | | | 931.3
| | | | 1,056.3 | | | | 2,992.4 | | | | 1,879.8 | | | | 20.0 | | | | 2.3 | | | | 1,779.7 | | | | 1,679.0 | | | | 3,923.7 | | | | 2,936.1 | | | | 5,703.5 | | | | 4,615.1 | |
Notes:1 None of the Directors received any pension entitlement and/or taxable benefits in 2022 or 2021.
(1) | All directors served only part of 2020 (see Directors’ Report), except for Santiago Seage. |
(2) | Long-term Incentive Awards includes Long-term Incentive Plan (LTIP) and One-Off Plan vested in the year and calculating amounts with the share price at vesting date. In 2021, from the $1,879.8 thousand vested, $1,549.1 corresponded to share appreciation. In 2020, from the $770.9 vested, $464.7 thousand corresponded to share appreciation. |
(3) | Mr. Aziz, Mrs. Del Favero, Mrs. Eprile, Mr. Forsayeth and Mr. Woollcombe joined the Board of Directors on May 5, 2020 as independent non-executive Directors and were appointed as Chair of the Compensation Committee, Chair of the Nominating and Corporate Governance Committee, Chair of the Audit Committee, Chair of the Related Parties Transactions Committee and Interim Chair of the Board, respectively. |
(4) | The Chief Executive Officer’s compensation is approved in euros. It has been converted to U.S. dollars for reporting purposes, at the average exchange rate of each year, which is 1.18 $/€ in 2021 and 1.14 $/€ in 2020. |
2 Non-executive directors receive salary and fees via a mix of cash and Deferred Restricted Share Units (DRSUs). Following the Annual General Meeting held in May 2021, the Company determined, and Ms. Del Favero, Mr. Forsayeth, and Mr. Woollcombe agreed that 30%, 50% and 100% respectively of the annual fee payable to the director by the Company from May 31, 2021 shall be irrevocably substituted for the grant of DRSUs.
3 Long-term Incentive Awards includes awards under both the Long-term Incentive Plan (LTIP) and the One-Off Plan which vested in the year, calculating amounts using the share price at vesting date. In 2022, from the $2,992.4 thousand vested, $1,490.1 corresponded to share appreciation. In 2021, from the $1,879.8 thousand vested, $1,549.1 corresponded to share appreciation.
4 Dividend equivalent rights accumulated on the DRSUs corresponding to the amount of dividends paid for one share in the period between the DRSU effective date and December 31, 2022 and 2021, respectively, multiplied by the number of DRSUs held on that date. Such rights are only payable on vesting of the DRSUs.
5 Mr. Hall was appointed to the Board on August 2, 2022 as an independent non-executive Director. Mr. Hall’s 2022 fee was prorated for the year based on the annual directors’ retainer.
6 The CEO’s compensation is approved in Euros. It has been converted to U.S. dollars for reporting purposes, at the average exchange rate of each year, which is 1.05 $/€ in 2022 and 1.18 $/€ in 2021.
- In 2022, the CEO’s total pay amounted to €4,401.7 thousand ($4,651.0 thousand). Fixed salary amounted to €690.0 thousand ($727.2 thousand), annual bonus to €870.0 thousand ($931.3 thousand) and long-term incentive awards to €2,841.7 thousand ($2,992.4 thousand).
- In 2021, the Chief Executive Officer’sCEO’s total pay amounted to €3,148.6 thousand ($3,752.7 thousand). Fixed salary amounted to €690.0 thousand ($816.6 thousand), annual bonus to €892.5 thousand ($1,056.3 thousand) and long-term incentive awards to €1,566.1 thousand ($1,879.8 thousand).
In 2020,7 Mr. Trisic, non-independent non-executive director, has received compensation since April 6, 2022. Mr. Trisic’s 2022 fee was prorated for the Chief Executive Officer’s total pay amounted to €2,222.2 thousand ($2,524.1 thousand). Fixed salary amounted to €663.0 thousand ($756.8 thousand),year based on the annual bonus to €873.0 thousand ($996.4 thousand)directors’ retainer.The Company determined and long-term incentive awards to €686.3 thousand ($770.9 thousand).Mr. Trisic agreed that 100% of his fee shall be irrevocably substituted for the grant of DRSUs.
(5) | Mr. Villalba, Mr. Dove, Mr. Martinez and Mr. Robinson were directors until May 5, 2020, and were Chair of the Board of Directors, Chair of the Nominating and Corporate Governance Committee, Chair of the Audit Committee, and Chair of the Compensation Committee, respectively, until such date. Mr. Brentan was a director until May 5, 2020. |
This compensation reportThe Compensation Report is presented in U.S. dollars since remuneration of all directors except the CEO is defined in U.S. dollars and the functional currency of the Company is also the U.S. dollar. None of the directors received any pension entitlement and/or taxable benefits in 20212022 or 2020.2021. Each member of our boardBoard of directorsDirectors will be indemnified for his or her actions associated with being a director to the extent permitted by law.
The increase in the remuneration of the CEO in 2022 corresponds mainly to the vesting of restricted share units granted under the LTIP in 2019, as we explain below.
| - | Chief Executive Officer Long-Term Incentives awards vested |
1) One-off plan
An award in the form of restricted stock units (RSUs) was granted under a One-off plan to the CEO in 2019. In June 2022 and 2021, one-third of the Chief Executive Officer’s (the “CEO”) one-off plan stock unitssecond and third tranches vested, and shares were transferred to the CEO in accordance with the terms of the plan. The One-off plan using the share price at the date of vesting (June 20, 2021).RSUs are now fully vested.
The value of the shares transferred have been included in the Single Total Figure of Remuneration table above in their vesting period.
One-Off Plan1 | One-Off Plan Vesting | | Number of Restricted Stock Units (RSUs) | | | Share Price on Vesting Date (US$) | | | RSUs Value at Vesting Date ($ thousand)2 | |
2019 | June 20223 | | | 14,535 | | | | 31.30 | | | | 528.6 | |
June 2021 | | | 14,535 | | | | 36.50 | | | | 578.8 | |
1 Additional information on the One-off plan is disclosed in the Remuneration Policy section.
2 On each vesting date, one third of the RSUs vest (14,535 RSUs) plus dividend equivalent rights corresponding to the amount of dividends paid on one share in the period between the One-off plan effective date and the date on which the RSU vests ($5.07 per RSU for 2022 and $3.32 per RSU for 2021), multiplied by the number of RSUs vesting on that date.
3 In June 2020, one-third2022 the final tranche of RSUs vested. As a result, there are no other awards outstanding under this plan.
2) Options vested under the LTIP
One-third of each of the CEO’s one-off plan stock unitsshare options awarded in 2019, 2020 and 2021 under the LTIP vested during 2022. The 2019 and 2020 share options were paid in cashexercised, and shares were transferred to the CEO in accordance with the terms of the plan usingplan. The 2021 share options vested, but they were not exercised. The 2021 share options were underwater on the share price at the date of vesting (June 20, 2020).date.
The share options value of the shares transferred and cash payments have been included in the Single Total Figure of Remuneration table above in their vesting period.
One-Off Plan | One-Off Plan Vesting | | One-Third of Restricted Stock Units (RSUs) | | | Price on Vesting Date (US$) | | | Remuneration in Cash ($ thousand)* | | | RSUs Value at Vesting Date ($ thousand)* | |
2019 | June 2021 | | | 14,535 | | | | 36.50 | | | | - | | | | 578.8 | |
June 2020 | | | 14,535 | | | | 27.97 | | | | 430.3 | | | | - | |
LTIP Share Option Grant Date1 | Share Option Vesting Date | | Number of Share Options Vesting (#) | | | Share Price on Vesting Date (USD) | | | Exercise Price per Share Option (USD) | | | Share Options Value at Vesting Date (000’s USD)2 | |
2021 | 2022 | | | 24,948 | | | | 32.53 | | | | 37.98 | | | | - | |
2020 | 2022 | | | 34,494 | | | | 34.48 | | | | 26.39 | | | | 279.1 | |
2021 | | | 34,494 | | | | 44.17 | | | | 26.39 | | | | 613.3 | |
2019 | 2022 | | | 40,693 | | | | 31.30 | | | | 19.60 | | | | 476.1 | |
2021 | | | 40,693 | | | | 36.50 | | | | 19.60 | | | | 687.7 | |
* One-off plan1 Additional information on the LTIP is disclosed in the Remuneration Policy section.
2 The value of the share options on the vesting date is calculated using the number of share options multiplied by (the share price on the vesting date minus the exercise price per share option).
3) Restricted Stock Units vested under the LTIP
In June 2022 restricted stock units (RSUs) awarded in 2019 under the LTIP vested and shares were transferred to the CEO in accordance with the terms of the plan. In 2021 no units vested under the LTIP. The value of the vested RSUs have been included in the Single Total Figure of Remuneration table above in their vesting period.
RSU Grant Date | RSU Vesting Date | | Number of Restricted Stock Units Vesting (#) | | | Share Price on Vesting Date (USD) | | | RSUs Value at Vesting Date (000’s USD)1 | |
2019 | 2022 | | | 46,987 | | | | 31.10 | | | | 1,708.7 | |
1 RSU vesting under the LTIP in 2019 includes one third of RSUs (14,535(46,987 RSUs) plus dividend equivalent rights corresponding to the amount of dividends paid on one share RSU between the One-off planLTIP 2019 effective date and the date on which the RSU vests.vests ($5.07 per RSU).
In addition, one-third of the CEO’s share options awarded in 2019 and 2020 under the LTIP vested in June and January 2021, respectively. These share options were exercised, and shares were transferred to the CEO in accordance with the terms of the plan.
In 2020, one-third of the CEO’s share options awarded in 2019 under the LTIP vested. They were exercised in 2021 and the shares were transferred to the CEO in accordance with the terms of the plan.
The share options have been included in the table above in their vesting period.
LTIP | LTIP Vesting | | One-Third of Share Options | | | Share Price on Vesting Date (US$) | | | LTIP Vesting Price per Option (US$) | | | Share Options Value at Vesting Date (thousand US$)* | |
2020 | 2021 | | | 34,494 | | | | 44.17 | | | | 26.39 | | | | 613.3 | |
2019 | 2021 | | | 40,693 | | | | 36.50 | | | | 19.60 | | | | 687.7 | |
2020 | | | 40,693 | | | | 27.97 | | | | 19.60 | | | | 340.6 | |
* The value of the share options on vesting date is calculated using the number of share options multiplied by (the share price on vesting date minus the LTIP vesting price per option).
In 2021, the majority2022, most of the objectives setdefined for the CEO’sChief Executive Officer’s variable bonus were met or exceeded and the Compensation Committee decided to approve a bonus corresponding to 105.0%102.35% of the target variable compensation, which will be payable in 2022.2023.
| Percentage weight | Achievement |
CAFD (cash available for distribution) – Equal or higher than the CAFD budgeted in the 2021 budget | 40% | 99% |
EBITDA– Equal or Higher than the EBITDA budgeted in the 2021 budget | 15% | 99% |
Close accretive acquisitions for the Company | 20% | 120% |
Achieve health and safety targets – (Frequency with Leave / Lost Time Index below 3.5 and General frequency index below 11.0) based on reliable targets and consistent measure metrics | 10% | 116% |
Implement the succession plan | 15% | 100% |
| | Percentage weight | | Achievement |
CAFD (cash available for distribution) – Equal or higher than the CAFD budgeted in the 2022 budget | | | 35 | % | 99%
|
Adjusted EBITDA– Equal or Higher than the Adjusted EBITDA budgeted in the 2022 budget | | | 15 | % | 98%
|
Close sustainable value accretive investments | | | 15 | % | 85%
|
Achieve health and safety targets – (Frequency with Leave / Lost Time Index below 3.9 and General frequency index below 10.1) based on reliable targets and consistent measure metrics | | | 10 | % | 120%
|
Management of relationships with key shareholders and partners | | | 10 | % | 120%
|
Continued executive talent development | | | 10 | % | 120%
|
Disclosure best standards | | | 5 | % | 85%
|
1 Cash Available for Distribution (CAFD) refers to the cash distributions received by the Company from its subsidiaries, minus cash expenses of the Company, including debt service and general and administrative expenses.
In 2020,2021, most of the objectives defined for the CEO’sChief Executive Officer’s variable bonus were met or exceeded and the Compensation Committee decided to approve a bonus corresponding to 102.7%105.0% of the target variable compensation, which was paid in 2021.2022.
The CEO’sChief Executive Officer’s maximum potential bonus could beis 120% of such bonus, which is approximately $1,150$1,092 thousand (approximately €1,020 thousand).
No element of the CEO’sChief Executive Officer’s annual bonus is deferred.
Deferred Restricted Shares Units (“DRSU”) Plan
In 2021The following table sets out the Board of Directors established a DRSU Plan fortotal compensation received by non-executive directors to promotevia a greater alignmentmix of interests between directorscash and shareholders, which was approved atDRSUs in 2022:
Name | | Total Remuneration (000’s USD) | | Total Remuneration in Cash and/or Deferred Restricted Stock Units (DRSU) | |
Remuneration in Cash (000’s USD) | Remuneration in DRSUs |
DRSUs (000’s USD) | Number of DRSUs (#)4 |
| | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | | | 2022 | | | 2021 | |
William Aziz | | | 160.0 | | | | 160.0 | | | | 160.0 | | | | 160.0 | | | | - | | | | - | | | | - | | | | - | |
Debora Del Favero1 | | | 160.0 | | | | 160.0 | | | | 112.0 | | | | 128.5 | | | | 48.0 | | | | 31.5 | | | | 1,619 | | | | 878 | |
Brenda Eprile | | | 165.0 | | | | 165.0 | | | | 165.0 | | | | 165.0 | | | | - | | | | - | | | | - | | | | - | |
Michael Forsayeth1 | | | 150.0 | | | | 150.0 | | | | 75.0 | | | | 100.8 | | | | 75.0 | | | | 49.2 | | | | 2,530 | | | | 1,372 | |
Edward C. Hall2 | | | 62.5 | | | | - | | | | 62.5 | | | | - | | | | - | | | | - | | | | - | | | | - | |
George Trisic3 | | | 110.0 | | | | - | | | | - | | | | - | | | | 110.0 | | | | - | | | | 3,901 | | | | - | |
Michael Woollcombe1 | | | 225.0 | | | | 225.0 | | | | - | | | | 77.5 | | | | 225.0 | | | | 147.5 | | | | 7,589 | | | | 4,117 | |
Total | | | 1,032.5 | | | | 860.0 | | | | 574.5 | | | | 631.9 | | | | 458.0 | | | | 228.1 | | | | 15,638 | | | | 6,367 | |
1 Following the Annual General Meeting held in May 2021. The plan provides a means for directors to accumulate a financial interest in2021, the Company determined, and to enhance Atlantica’s ability to attractMs. Del Favero, Mr. Forsayeth, and retain qualified individuals withMr. Woollcombe agreed that 30%, 50% and 100% respectively of the experience and ability to serve as directors. Pursuantannual fee payable to the DRSU Plan,director by the Company shall determine, and the directors shall agree, the percentage of their fees, starting onfrom May 31, 2021 that shall be irrevocably substituted for the grant of Restricted Stock Units.DRSUs.
2 Mr. Hall was appointed to the Board on August 2, 2022 as an independent non-executive Director. Mr. Hall’s 2022 fee was prorated based on the annual director’s retainer.
3 Mr. Trisic, non-independent non-executive director, has received compensation since April 6, 2022. Mr. Trisic’s 2022 fee was prorated based on the annual directors’ retainer. The Company determined and Mr. Trisic agreed that 100% of his fee shall be irrevocably substituted for the grant of DRSUs.
4 The number of DRSUs credited to a participant’s accountgranted is determined by dividing the amount of the annual compensation to be received insubstituted for DRSUs by the market value of an ordinary share at the time of the grant. Upon a participant ceasing to be a member of the Board, for any reason whether voluntary or involuntary, the DRSUs will vest. The Company shall transfer to the director a number of shares equal to the number of vested DRSUs and a number of shares equal in value to any dividends which would have been paid or payable, on such number of ordinary shares equal to the vested DRSUs, from the grant date until the vesting date. The director shall not have any shareholders’ rights other than the dividend equivalent rights until the DRSUs vest and are settled by the issuance of shares.
The following table sets out the total compensation received by independent, non-executive directors via a mix144
ITEM 7. | MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS |
The following table sets forth information with respect to beneficial ownership of our ordinary shares as of the date of this annual report by:
each of our directors and executive officers;
our directors and executive officers as a group; and
each person known to us to beneficially own 5% and more of our ordinary shares.
Beneficial ownership is determined in accordance with the rules and regulations of the SEC. It includes the sole or shared power to direct the voting or the disposition of the securities or to receive the economic benefit of the ownership of the securities. In computing the number of shares beneficially owned by a person and the percentage ownership of that person, we have included shares that the person has the right to acquire within 60 days of this annual report, including through the exercise of any option or other right and the vesting of restricted shares. These shares, however, are not included in the computation of the percentage ownership of any other person. The calculations of percentage ownership in the table below is based on 112,451,438116,153,273 ordinary shares outstanding as of the date of this annual report.
Name | | Ordinary Shares Beneficially Owned | | | Deferred Restricted Share Units | | | Shares Units | | | Percentage | | | Ordinary Shares Beneficially Owned | | | Deferred Restricted Share Units (2)
| | | Shares Units (3)
| | | Percentage | |
Directors and Officers | | | | | | | | | | | | | | | | | | | | | | | | |
Santiago Seage | | 55,666 | | | | | | 120,880 | | | - | | |
William Aziz | | 2,500 | | | | | | | | | - | | | 2,500 | | | - | | | - | | | - | |
Debora Del Favero | | | - | | | 2,608 | | | - | | | - | |
Brenda Eprile | | 5,500 | | | | | | | | | - | | | 13,000 | | | - | | | - | | | - | |
Michael Forsayeth | | 2,500 | | | 1,372 | | | | | | - | | | 2,500 | | | 4,075
| | | - | | | - | |
Edward C. Hall | | | 1,500 | | | - | | | - | | | - | |
Santiago Seage | | | 117,491 | | | - | | | 105,868 | | | - | |
George Trisic | | | 1,000 | | | 3,962 | | | - | | | - | |
Michael Woollcombe | | 5,000 | | | 4,117 | | | | | | - | | | 5,000 | | | 12,225 | | | - | | | - | |
Debora Del Favero | | - | | | 878 | | | | | | - | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
5% Beneficial Owners | | | | | | | | | | | | | |
5% Beneficial Owner | | | | | | | | | | | | | |
Algonquin (AY Holdco) B.V. (1) | | 48,962,925 | | | | | | | | | 43.5 | % | | 48,962,925 | | | - | | | - | | | 42.2 | % |
Morgan Stanley (2) | | 5,677,200 | | | | | | | | | 5.1 | % | |
(1) | This information is based solely on the Schedule 13D filed on August 4, 2021May 10, 2022 by Algonquin Power & Utilities Corp., a corporation incorporated under the laws of Canada, Algonquin (AY Holdco) B.V., a corporation incorporated under the laws of the Netherlands, and Liberty (AY Holdings) B.V., a corporation incorporated under the laws of the Netherlands.Netherlands and our outstanding shares as of December 31, 2022. |
(2) | The number of DRSUs includes accumulated cash dividend equivalent rights, corresponding to the amount of dividends paid for one share in the period between the DRSU effective date and December 31, 2022 and 2021, respectively, multiplied by the number of DRSU on that date and divided by the share price of $25.90 as of December 31, 2022. The director shall not have any rights of a shareholder unless and until the DRSUs vest and are settled by the issuance of shares and dividend equivalent rights will not be payable until the DRSUs vest. |
(3) | Non-vested Share Units as of December 31, 2022. LTIP share units subject to 5% minimum Total Shareholder Return. |
(2) | This information is based solely on the Schedule 13G filed on February 10, 2022 by Morgan Stanley, corporation incorporated under the laws of Delaware. The registered address of Morgan Stanley is 1585 Broadway New York, NY 10036 |
As of December 31, 2021, the CEO holds 120,880 units convertible into shares in the future and 184,524 options under the LTIP and the one-off plan.
We have one class of ordinary shares, and each holder of our ordinary shares is entitled to one vote per share.
As of the date of this annual report, 112,451,438116,153,273 of our ordinary shares were outstanding. Because some of our ordinary shares are held by brokers and other nominees, the number of shares held by and the number of beneficial holders with addresses in the United States is not fully ascertainable. As of the date of this annual report, to the best of our knowledge, one of our shareholders of record was located in the United States and held in the aggregate 105,046,131108,649,817 ordinary shares representing approximately 93.4%93.5% of our outstanding shares. However, the United States shareholders of record include Cede & Co., which, as nominee for The Depositary Trust Company, is the record holder of all such ordinary shares. Accordingly, we believe that the shares held by Cede & Co. include ordinary shares beneficially owned by both United States and non-United States beneficial owners. As a result, these numbers may not accurately represent the number of beneficial owners in the United States.
144We are not aware of any arrangement that may, at a subsequent date, result in a change of control of our company.
B. | Related Party Transactions |
Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest
Our policy for the review, approval and ratification of related party transactions was updated and approved by the Board of Directors on February 28, 2018. Our policy requires that all transactions with related parties are subject to approval or ratification in accordance with the procedures set forth in the policy by the non-conflicted directors at the Board of Directors. With respect of any transaction with Liberty GES and Algonquin or its affiliates (other than our subsidiaries), including transactions pursuant to the ROFO agreements,Agreements, the Related Party Transactions Committee is required to review all of the relevant facts and circumstances and report its conclusions to the board. A majority of non-conflicted directors are required to either approve or disapprove of the entry into the transaction. In determining whether to approve or ratify a transaction with Liberty GES Algonquin or Abengoa,Algonquin, the directors unaffiliated with such entity are to consider, among other factors they may deem appropriate, whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and the extent of Liberty GES’, or Algonquin’s or Abengoa’s interest in the transaction. Our Related Party Transactions Policy is available on our website atwww.atlantica.com. www.atlantica.com.
Arrangements for Change in Control of the Company
On May 9, 2019, Algonquin, Liberty GES and the Company entered into the Enhanced Cooperation Agreement, and on May 17, 2019, Algonquin and the Company entered into a subscription agreement pursuant to which, among other things, the Company agreed to permit Algonquin to acquire, and Algonquin agreed to purchase, 1,384,402 ordinary shares, which were fully subscribed and paid by Algonquin. After giving effect to such purchase, Algonquin was the beneficial owner of 42,942,065 ordinary shares, representing approximately 42.3% of the issued and outstanding ordinary shares. Additionally, Algonquin purchased 4,020,860 ordinary shares of the Company in a private placement, which closed on January 7, 2021, which represents the pro-rata number of shares required to maintain their previous equity ownership in the Company. On August 3, 2021, we established an “at-the-market program” (the “ATM”) and on the same date we entered into the ATM Plan Letter Agreement with Algonquin, pursuant to which we will offer Algonquin the right but not the obligation, on a quarterly basis, to purchase a number of ordinary shares to maintain its percentage interest in Atlantica (see —ATM Plan Letter Agreement below). As of the date of this annual report Algonquin is the beneficial owner of 48,962,925 ordinary shares, representing 43.5%42.2% of the issued and outstanding ordinary shares.
Agreements with Current Shareholders
We entered into the ROFO Agreements with Liberty GES and Algonquin, respectively. In addition, Algonquin, Liberty GES and the Company entered into the Enhanced Cooperation Agreement, and Algonquin and the Company entered into a subscription agreement.
ROFO agreementsAgreements
Pursuant to the ROFO Agreements, Algonquin and Liberty GES granted us a right of first offer on any proposed sale, transfer or other disposition of the assets described thereunder, subject to the conditions and procedures set out in such agreement. Specifically, the Algonquin ROFO Agreements is applicable with respect to any assets located outside of the United States or Canada.
If either Algonquin or Liberty GES transfers interests in any asset under the ROFO Agreements, then either Algonquin or Liberty GES must require such transferee to acquire any asset under the ROFO Agreements subject to our right of first offer except under certain circumstances. The ROFO Agreements have each an initial term of ten years.
Under the ROFO Agreement, Algonquin and Liberty GES are not obligated to sell any asset and, therefore, we do not know when, if ever, these assets will be offered to us. In addition, in some of the assets under the ROFO Agreements, Algonquin and Liberty GES may have equity partners with rights regulating divestitures by either of them of their stake such as drag-along and tag-along clauses, and rights of first refusal, among others. We will consider and take into account all the clauses thereunder when deciding whether to present an offer.
Any material transaction between Algonquin or Liberty GES and us (including the proposed acquisition of any asset under the ROFO Agreements) will be subject to our related party transactions policy, which will require prior approval of such transaction by the related party transactions committee, which is composed of independent directors. See “—Procedures for Review, Approval and Ratification of Related Party Transactions; Conflicts of Interest,” “Item 3.D—Risk Factors—V. Risks Related to Our Growth Strategy— Our ability to grow organically is limited to some assets which have inflation indexation mechanisms in their revenues, to our transmission lines and to some renewable assets. We may not be able to deliver organic growth.”
Furthermore, with respect to the Liberty GES ROFO Agreement, Liberty GES may enter into agreements with other companies with the objective of jointly developing the construction of new projects consisting of concessional assets which are included in Liberty GES current or future portfolio. Pursuant to the terms of such agreement, Liberty GES may sell equity in these assets to third parties without being subject to the Liberty GES ROFO Agreement under certain circumstances in order to enhance the likelihood of success or financial prospects of such asset.
Acquisition and investment in Colombia
In December 2020 we reached an agreement with Algonquin to acquire La Sierpe, a 20 MW solar PV plant in Colombia for a total equity investment of approximately $23.5 million. The acquisition closed in November 2021.
Additionally, in December 2020, we agreed to potentially co-invest with Algonquin in two additional solar projects in Colombia with a combined capacity of approximately 30 MW. In July 2021 we acquired from Algonquin the two solar projects which arewere under development at that time, La Tolua and Tierra Linda, where we recently ended construction.
Given the fact that in the last five years we have only closed these acquisitions under the ROFO Agreements and given that to the best of our knowledge Algonquin’s pipeline outside Canada and the U.S. is limited, we do not currently under construction.expect these ROFO Agreements to be a material source of growth for us going forward.
ATM Plan Letter Agreement
On August 3, 2021, we established an ATM program and entered into the Distribution Agreement with J.P. Morgan Securities LLC, as sales agent. On that same date, we entered into an agreement with Algonquin, pursuant to which we will offer Algonquin the right but not the obligation, on a quarterly basis, to purchase a number of ordinary shares to maintain its percentage interest in Atlantica at the average price of the shares sold under the Distribution Agreement in the previous quarter, adjusted for any dividends, distributions, reorganizations or business combinations or similar transactions as if the portion of such shares equivalent to the portion of the shares issued under the ATM prior to the record date had also been issued to Algonquin prior to the record date with respect to such event. In the event that Algonquin exercises such right, subject to certain conditions further described in the ATM Plan Letter Agreement, including that a material adverse effect in relation to the Company shall not have occurred, we and Algonquin will enter into a subscription agreement with a settlement date no earlier than three business days and no later than one hundred and eighty days from Algonquin’s notice that it is subscribing for the ordinary shares.
Algonquin Shareholders Agreement
We entered into a Shareholders Agreement with Algonquin and Liberty GES. The Shareholders Agreement, among other things, sets forth certain corporate governance matters and rights and restrictions with respect to our ordinary shares, the main terms of which are summarized below.
On May 9, 2019, we signed a new enhanced collaboration agreement with Algonquin. Under this agreement, Atlantica had a right to acquire stakes or make investments in two Algonquin assets in the U.S., subject to the parties acting reasonably and in good faith agreeing price and terms of such transfers. Additionally, we agreed with Algonquin to analyze jointly during the next six months Algonquin’s contracted assets portfolio in the U.S. and Canada to identify assets where a drop down could add value for both parties, according to each company’s key metrics. After the analysis, the parties did not reach an agreement and therefore there was no consummation of any asset acquisition or investment in any asset.
Director Appointment Rights
The Shareholders Agreement provides that, if and to the extent provided in our articles, Liberty GES or Algonquin will have the right to appoint to our board the maximum number of directors that corresponds to Liberty GES’ and Algonquin’s holding of voting rights, as per articles of association but in any event no more than (i) such number of directors as corresponds to 41.5% of our voting securities; and (ii) 50% of our board less one, and if the resulting number is not a whole number, it shall be rounded up to the next whole number.
Furthermore, the Shareholders Agreement has been amended to allow Algonquin to increase its shareholding in Atlantica up to a 48.5% without any change in corporate governance. Algonquin’s voting rights and rights to appoint directors are still limited to a 41.5% and the additional shares (the difference between the actual shares beneficially owned by Algonquin and shares representing a 41.5% voting rights) will vote replicating non-Algonquin’s shareholder’s vote.
One of the directors appointed by Liberty GES and Algonquin holding in the aggregate at least 25.0% of our voting securities will have the right to be elected to any committee of our directors (except for the Audit Committee and Related Party Transactions Committee, and in those in which they are conflicted, or it is against the applicable law). In addition, so long as Liberty GES and Algonquin have the right to appoint a director and no such director is then serving on our Board of Directors, Liberty GES and Algonquin may appoint an observer to our Board of Directors and any committee thereof (except for the Audit Committee and Related Party Transactions Committee, and in those in which they are conflicted, or it is against the applicable law).
Dividends DistributionDividend Distributions
We agreed that each of Liberty GES and Algonquin may terminate the Shareholders Agreement with respect to itself and its affiliates if, among others, our Board of Directors confirms a dividend payment objective that is lower than 80% of the cash available for distribution or our Board of Directors does not confirm any dividend payment objective at least once during any period of more than 14 consecutive months.
As of December 31, 2021,2022, our dividend payout objective was 80%. This objective can be modified by our Board of Directors in the future.
Pre-emption rightsright
Liberty GES and Algonquin may subscribe in cash for (i) up to 100% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under the Liberty GES ROFO Agreement and Algonquin ROFO Agreement;Agreements; and (ii) up to 66% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under the Liberty GES ROFO Agreement. If we issue ordinary shares for any other purpose, Liberty GES and Algonquin may subscribe in cash for ordinary shares in the amount pro rata to such Liberty GES’ and Algonquin’s aggregate holding of voting rights.
In addition, if Liberty GES and Algonquin elect to subscribe for at least 50% of an offering of our ordinary shares that will be listed, the price per ordinary share for all persons that participate in such offering will be equal to 97% of the USD volume-weighted average closing price per ordinary share on NASDAQ (or other applicable stock exchange) over the 20 trading days immediately preceding the date of Liberty GES’ and Algonquin’s receipt of notice of such proposed offering from us.
Standstill
Algonquin will not acquire any of our voting securities which may result in Liberty GES and Algonquin holding in the aggregate more than 48.5% of the total voting rights or otherwise acquire control over us.
Also, Liberty GES and Algonquin will not be in breach of the standstill restriction if the shareholding of Liberty GES and Algonquin has increased in connection with our action to reduce the number of our outstanding shares.
Termination
Among others, theThe Shareholders Agreement will terminate if, among others, Liberty GES and Algonquin and/or their affiliates cease to hold in the aggregate at least 10% of the total voting rights attached to our voting securities.
As described under “—Dividend Distributions” above, each of Liberty GES and Algonquin may terminate the Shareholders Agreement with respect to itself and its affiliates if, among others, our Board of Directors confirms a dividend payment objective that is lower than 80% of the cash available for distribution.
AYES Shareholder Agreement
On May 24, 2019, Atlantica and Algonquin formed AYES Canada, a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. AYES Canada’s first investment was in Amherst Island, a 75 MW wind plant in Canada owned by the project company Windlectric, Inc. (“Windlectric”). Atlantica invested $4.9 million and Algonquin invested $92.3 million, both through AYES Canada, which in turn invested those funds in Amherst Island Partnership, the holding company of Windlectric. Since Atlantica has control over AYES Canada under IFRS 10 “Consolidated Financial Statements”, its consolidated financial statements show a total investment in the Amherst Island project of $97.2 million, accounted for as “Investments carried under the equity method” (Note 7 of the 2020 Consolidated Financial Statements) and Algonquin’s portion of that investment of $92.3 million as “Non-controlling interest”. In addition, and under certain circumstances considered remote by both companies, Atlantica and Algonquin have options to convert shares of AYES Canada currently owned by Algonquin into Atlantica ordinary shares in exchange for a higher stake in the plant, subject to the provisions of the standstill and enhanced collaboration agreements with Algonquin.
Code of Conduct
We have adopted a code of conduct applicable to all directors, officers and employees of Atlantica and our subsidiaries. The Code of Conduct is available on our website at www.atlantica.com, is communicated to all employees and is reviewed at least annually. All employees acknowledge and sign the Code of Conduct annually.
C.U. | Interests of Experts and Counsel |
Not applicable.
ITEM 8. | FINANCIAL INFORMATION |
A.U. | Consolidated Statements and Other Financial Information. |
We have included the Annual Consolidated Financial Statements as part of this annual report. See “Item 18—Financial Statements.”
Dividend Policy
Our Cash Dividend Policy
We expect to pay a quarterly dividend on or about the 75th75th day following the expiration of the first, second and third fiscal quarters to our shareholders of record on or about the 60th60th day following the last day of such fiscal quarters. A quarterly dividend corresponding to the fourth quarter is usually declared in the first quarter of the following year. We expect to pay this dividend on or about the 82nd82nd day following the expiration of the corresponding fourth fiscal quarter to our shareholders of record in general on or about the 72nd72nd day following the last day of such fiscal quarter. However, there might be exceptions to these dates. Additionally, our Board of Directors may change our dividend policy at any point in time or modify the dividend for specific quarters following prevailing conditions.
The table below included our historical quarterly dividends since the beginning of 2019:2020:
Declared | Record | Payable | Amount ($) per share |
-FebruaryFebruary 28, 2023 | March 14, 2023 | March 25, 2023 | 0.445
|
November 8, 2022 | November 30, 2022 | December 15, 2022 | 0.445 |
August 2, 2022 | August 31, 2022 | September 15, 2022 | 0.445 |
May 5, 2022 | May 31, 2022 | June 15, 2022 | 0.44 |
February 25, 2022 | March 14, 2022 | March 25, 2022 | 0.44
|
November 9, 2021 | November 30, 2021 | December 15, 2021 | 0.435 |
July 30, 2021 | August 31, 2021 | September 15, 2021 | 0.43 |
May 4, 2021 | May 31, 2021 | June 15, 2021 | 0.43 |
February 26, 2021 | March 12, 2021 | March 22, 2021 | 0.42 |
November 4, 2020 | November 30, 2020 | December 15, 2020 | 0.42 |
July 31, 2020 | August 31, 2020 | September 15, 2020 | 0.42 |
May 6, 2020 | June 1, 2020 | June 15, 2020 | 0.41 |
February 26, 2020 | March 12, 2020 | March 23, 2020 | 0.41 |
November 5, 2019 | November 29, 2019 | December 13, 2019 | 0.41 |
August 2, 2019 | August 30, 2019 | September 13, 2019 | 0.40 |
May 7, 2019 | June 3, 2019 | June 14, 2019 | 0.39 |
February 26, 2019 | March 12, 2019 | March 22, 2019 | 0.37 |
We declared our first quarterly dividend in November 2014 and paid it on December 15, 2014. Recently, on February 25, 2022,28, 2023, our Board of Directors approved a dividend of $0.44$0.445 per share corresponding to the fourth quarter of 2021,2022, which is expected to be paid on March 25, 2022.2023.
We intend to distribute a significant portion of our cash available for distribution as dividend, after considering the cash available for distribution that we expect our assets will be able to generate, less reserves for the prudent conduct of our business, (including reserves for, among other things, dividend shortfalls as a result of fluctuations in our cash flows), on an annual basis. We intend to distribute a quarterly dividend to shareholders. Our Board of Directors may, by resolution, amend the cash dividend policy at any time. We intend to grow our business via organic growth through the optimization of the existing portfolio and expansionthrough investments, development and construction of our currentnew assets and through investments in and acquisitions of new assets.acquisitions. We believe this will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share over time. However, the determination of the amount of cash dividends to be paid to holders of our shares will be made by our Board of Directors and will depend upon our financial condition, results of operations, cash flow, long-term prospects and any other matters that our Board of Directors deem relevant. Our Board of Directors may, by resolution, amend the cash dividend policy at any time.
Our cash available for distribution is likely to fluctuate from quarter to quarter, in some cases significantly, as a result of the seasonality of our assets, the terms of our financing arrangements and maintenance and outage schedules, among other factors. Accordingly, during quarters in which our assets generate cash available for distribution in excess of the amount necessary for us to pay our stated quarterly dividend, we may reserve a portion of the excess to fund cash distributions in future quarters. In quarters in which we do not generate sufficient cash available for distribution to fund our stated quarterly cash dividend, if our Board of Directors so determines, we may use retained cash flow from other quarters, as well as other sources of cash, to pay dividends to our shareholders.
Risks Regarding Our Cash Dividend Policy
There is no guarantee that we will pay quarterly cash dividends to our shareholders. We do not have a legal obligation to pay any dividend. While we currently intend to grow our business and increase our dividend per share over time, our cash dividend policy is subject to all the risks inherent in our business and may be changed at any time as a result of certain restrictions and uncertainties, including the following:
The amount of our quarterly cash available for distribution could be impacted by restrictions on cash distributions contained in our project-level financing arrangements, which require that our project-level subsidiaries comply with certain financial tests and covenants in order to make such cash distributions. Generally, these restrictions limit the frequency of permitted cash distributions to semi-annual or annual payments, and prohibit distributions unless specified debt service coverage ratios, historical and/or projected, are met. See the sub-sections entitled “Item 4.B—Business Overview—Our Operations—Project Level Financing” under the individual project descriptions. When forecasting cash available for distribution and dividend payments we have aimed to take these restrictions into consideration, but we cannot guarantee future dividends. In addition, restrictions or delays on cash distributions could also happen if our project finance arrangements are under an event of default.
Additionally, indebtedness we have incurred under the Green Senior Notes, the Note Issuance Facility 2020, the 2020 Green Private Placement and the Revolving Credit Facility contain, among other covenants, certain financial incurrence and maintenance covenants, as applicable. See “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources—Corporate debt agreements.”
We and our Board of Directors have the authority to establish cash reserves for the prudent conduct of our business and for future cash dividends to our shareholders, and the establishment of or increase in those reserves could result in a reduction in cash dividends from levels we currently anticipate pursuant to our stated cash dividend policy. These reserves may account for the fact that our project-level cash flows may vary from year to year based on, among other things, changes in the operating performance of our assets, operational costs, capital expenditures required in the assets, collections from our off-takers, electricity market prices, compliance with the terms of project debt including debt repayment schedules and cash reserve accounts requirements, compliance with the terms of corporate debt, compliance with all the applicable laws and regulations and working capital requirements. Our Board of Directors may increase reserves to account for the seasonality that has historically existed in our assets’ cash flows and the variances in the pattern and frequency of distributions to us from our assets during the year.
We may lack sufficient cash to pay dividends to our shareholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors, including low availability, low production, low electricity prices in our assets with exposure to merchant revenues, unexpected operating interruptions, legal liabilities, costs associated with governmental regulation, changes in governmental subsidies, delays in collections from our off-takers, changes in regulation, as well as increases in our operating and/or general and administrative expenses, maintenance capital expenditures, principal and interest payments on our and our subsidiaries’ outstanding debt, income tax expenses, failure of Abengoainability to comply with its obligations under the agreementsupstream cash from subsidiaries or to do it in place,an efficient manner, working capital requirements or anticipated cash needs at our project-level subsidiaries. See “Item 3.D—Risk Factors” for more information on the risks to which our business is subject.
We may pay cash to our shareholders via capital reduction in lieu of dividends in some years.
Our project companies’ cash distributions to us (in the form of dividends or other forms of cash distributions such as shareholder loan repayments) and, as a result, our ability to pay or grow our dividends, are dependent upon the performance of our subsidiaries and their ability to distribute cash to us. The ability of our project-level subsidiaries to make cash distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable corporation laws and other laws and regulations.
regulations
Our Board of Directors may, by resolution, amend the cash dividend policy at any time. Our Board of Directors may elect to change the amount of dividends, suspend any dividend or decide to pay no dividends even if there is ample cash available for distribution.
Our Ability to Grow our Business and Dividend
We intend to grow our business via organic growth through the optimization of the existing portfolio, repowering, hybridization with other technologies, and expansion of our current assets and through investments in development and construction of new assets, as well as and acquisitions of new assets. We believe this will facilitate the growth of our cash available for distribution and enable us to increase our dividend per share over time.
Our policy is to distribute a significant portion of our cash available for distribution as a dividend. We expect we will rely primarily upon external financing sources, including commercial bank borrowings and issuances of debt and equity securities in capital markets, to fund any future growth capital expenditures. To the extent we are unable to finance growth externally, our cash dividend policy could significantly impair our ability to grow because we do not currently intend to reserve a substantial amount of cash generated from operations to fund growth opportunities. If external financing is not available to us on acceptable terms, our Board of Directors may decide to finance investments with cash from operations, which would reduce or impair our ability to pay dividends to our shareholders. Our Board of Directors may also decide to finance our investments with cash generated from operations to increase the capital dedicated to finance development, construction and acquisition of new assets and foster our growth.
To the extent we issue additional shares to fund our business, our growth or for any other reason, the payment of dividends on those additional shares may increase the risk that we will be unable to maintain or increase our per share dividend level. Additionally, the incurrence of additional commercial bank borrowings or other debt to finance our growth would result in increased interest expense, which in turn may impact our cash available for distribution and, in turn, our ability to pay dividends to our shareholders.
There have been no significant changes since the date of the Annual Consolidated Financial Statements included in this annual report.
ITEM 9. | THE OFFER AND LISTING |
A. | Offering and Listing Details |
Our ordinary shares trade on the NASDAQ Global Select Market under the symbol “AY.”
Not applicable.
Our ordinary shares are traded on the NASDAQ Global Select Market under the symbol “AY.”
Not applicable.
Not applicable.
Not applicable.
ITEM 10. | ADDITIONAL INFORMATION |
Not applicable.applicable
B. | Memorandum and Articles of Association |
The information called for by this item has been reported previously in our Articles of Association on Form 6-K (File No. 001-36487), filed with the SEC on May 21, 2018 as exhibit 3.1 and is incorporated by reference into this annual report.
See “Item 4.B—Business Overview,” “Item 5.B— Operating and Financial Review and Prospects—Liquidity and Capital Resources—Corporate debt agreements”
See “Item 5.A—Operating and Financial Review and Prospects—Operating Results—Factors Affecting the Comparability of Our Results of Operations—Regulation.”
Material UK Tax Considerations
The following is a general summary of material UK tax considerations relating to the ownership and disposal of our shares. The comments set out below are based on current UK tax law as applied in England and Wales and HM Revenue & Customs, or HMRC, published practice (which may not be binding on HMRC) as at the date of this summary, both of which are subject to change, possibly with retrospective effect. They are intended as a general guide and, save where expressly stated otherwise apply to you only if you are a “U.S. Holder” (as defined in the section below entitled “—U.S. Federal Income Tax Considerations”) and if:
you hold Atlantica Sustainable Infrastructure shares as an investment for tax purposes, as capital assets and you are the absolute beneficial owner thereof for UK tax purposes; and
you are an individual, you are not resident in the United Kingdom for UK tax purposes and do not hold Atlantica Sustainable Infrastructure shares for the purposes of a trade, profession, or vocation that you carry on in the United Kingdom through a branch or agency, or if you are a corporation, you are not resident in the UK for United Kingdom tax purposes and do not hold the securities for the purpose of a trade carried on in the United Kingdom through a permanent establishment in the United Kingdom.
This summary does not address all possible tax consequences relating to an investment in the shares.shares and is written on the basis that we do not (and will not) directly or indirectly derive 75% or more of our qualifying asset value from U.K. land. Certain categories of shareholders, including those falling outside the category described above, those carrying on certain financial activities, those subject to specific tax regimes or benefitting from certain reliefs or exemptions, those connected with us and those for whom the shares are employment-related securities may be subject to special rules and this summary does not apply to such shareholders and any general statements made in this disclosure do not take them into account.
This summary is for general information only and is not intended to be, nor should it be considered to be, legal or tax advice to any particular investor. It does not address all of the tax considerations that may be relevant to specific investors in light of their particular circumstances or to investors subject to special treatment under UK tax law.
Potential investors should satisfy themselves prior to investing as to the overall tax consequences, including, specifically, the consequences under UK tax law and HMRC practice of the acquisition, ownership and disposal of the shares in their own particular circumstances by consulting their own tax advisors.
UK Taxation of Dividends
We will not be required to withhold amounts on account of UK tax at source when paying a dividend in respect of our shares to a U.S. Holder.
U.S. Holders who hold their shares as an investment and not in connection with any trade carried on by them will not be subject to U.K. tax in respect of any dividends. There are certain exceptions from U.K. tax in respect of dividends on shares held in connection with a trade carried on in the United Kingdom for trades conducted in the United Kingdom through independent agents, such as some brokers and investment managers.
UK Taxation of Capital Gains
An individual holder who is a U.S. Holder will generally not be liable to UK capital gains tax on capital gains realized on the disposal of his or her Atlantica Sustainable Infrastructure shares unless such holder carries on (whether solely or in partnership) a trade, profession or vocation in the United Kingdom through a branch or agency in the United Kingdom to which the shares are attributable.
A corporate holder of shares that is a U.S. Holder will generally not be liable for UK corporation tax on chargeable gains realized on the disposal of its Atlantica Sustainable Infrastructure shares unless it carries on a trade in the United Kingdom through a permanent establishment to which the shares are attributable.
An individual holder of shares who is temporarily a non-UK resident for UK tax purposes will, in certain circumstances, become liable to UK tax on capital gains in respect of gains realized while he or she was not resident in the United Kingdom.
Stamp Duty and Stamp Duty Reserve Tax
The stamp duty and stamp duty reserve tax, or SDRT, treatment of the issue and transfer of, and the agreement to transfer, Atlantica Sustainable Infrastructure shares outside a depositary receipt system or a clearance service are discussed in the paragraphs under ‘—General’ below. The stamp duty and SDRT treatment of such transactions in relation to such systems are discussed in the paragraphs under “Depositary Receipt Systems and Clearance Services” below. The discussion under the headings below applies to transactions undertaken by any holder of our shares.
General
No stamp duty, or SDRT, will arise on the issue of shares in registered form by Atlantica Sustainable Infrastructure.
An agreement to transfer our shares will normally give rise to a charge to SDRT at the rate of 0.5% of the amount or value of the consideration payable for the transfer (or, in certain circumstances and if it is higher, the market value of our shares to be transferred in accordance with the relevant agreement). SDRT is, in general, payable by the purchaser.
Transfers ofInstruments transferring our shares will generally be subject to stamp duty at the rate of 0.5% of the consideration given for the transfer (or, in certain circumstances and if it is higher, the market value of our shares to be transferred by the relevant instrument) rounded up to the next £5. The purchaser normally pays the stamp duty.
If a duly stamped transfer completing an agreement to transfer is produced within six years of the date on which the agreement is made (or, if the agreement is conditional, the date on which the agreement becomes unconditional) any SDRT already paid is generally repayable, normally with interest, and any SDRT charge yet to be paid is cancelled.
Depositary Receipt Systems and Clearance Services
Following the Court of Justice of the European Union’s decision in C-569/07 HSBC Holdings Plc, Vidacos Nominees Limited v The Commissioners of HerHis Majesty’s Revenue & Customs and the First-tier Tax Tribunal decision in HSBC Holdings Plc and The Bank of New York Mellon Corporation v. The Commissioners of HerHis Majesty’s Revenue & Customs, HMRC has published guidance stating that 1.5% SDRT is no longer payable when new shares are issued to a clearance service or depositary receipt system. HMRC'sHMRC’s published guidance confirms that this remains HMRC’s position following the transition period which expired on December 31, 2020 after the withdrawal of the United Kingdom from the EU.
Where our shares are transferred (i) to, or to a nominee or an agent for, a person whose business is or includes the provision of clearance services or (ii) to, or to a nominee or an agent for, a person whose business is or includes issuing depositary receipts, stamp duty or SDRT will generally be payable at the higher rate of 1.5% of the amount or value of the consideration given or, in certain circumstances, the value of the shares. In certain circumstances, there may be no charge to stamp duty or SDRT, and holders of our shares should accordingly seek their own advice before paying or accepting such charge.
Except in relation to clearance services that have made and maintained an election under Section 97A(1) of the Finance Act of 1986 (to which the special rules outlined below apply), no stamp duty or SDRT is payable in respect of transfers or agreements to transfer within clearance services or depositary receipt systems. Accordingly, no stamp duty or SDRT should, in practice, be required to be paid in respect of transfers or agreements to transfer our shares within the facilities of The Depository Trust Company, or DTC.
There is an exception from the 1.5% charge on the transfer to, or to a nominee or agent for, a clearance service where the clearance service has made and maintained an election under section 97A(1) of the Finance Act 1986, which has been approved by HMRC. In these circumstances, SDRT at the rate of 0.5% of the amount or value of the consideration payable for the transfer will arise on any transfer of our shares into such an account and on subsequent agreements to transfer such shares within such account. It is our understanding that DTC has not made an election under section 97A(1) of the Finance Act of 1986.
Any liability for stamp duty or SDRT in respect of any transfer into a clearance service or depositary receipt system, or in respect of a transfer within any clearance service or depositary receipt system, which does arise will strictly be accountable by the clearance service or depositary receipt system operator or their nominee, as the case may be, but will, in practice, be payable by the participants in the clearance service or depositary receipt system.
U.S. Federal Income Tax Considerations
The following is a summary of the U.S. federal income tax considerations generally applicable to the ownership and disposition of shares by U.S. Holders (as defined below). Unless otherwise noted, this summary addresses only U.S. Holders that hold shares as capital assets (generally, property held for investment) for U.S. federal income tax purposes. This summary is based upon the U.S. Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations promulgated thereunder (“Regulations”), judicial decisions, administrative pronouncements, and other relevant applicable authorities, all as of the date hereof and all of which are subject to change or differing interpretations, possibly with retroactive effect.
As used herein, the term “U.S. Holder” means a beneficial owner of shares that is, for U.S. federal income tax purposes:
an individual who is a citizen or resident of the United States;
a corporation (or other entity subject to tax as a corporation for U.S. federal income tax purposes) created in or organized under the laws of the United States or any political subdivision thereof;
an estate the income of which is subject to U.S. federal income taxation regardless of its source; or
a trust (i) if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust, or (ii) the trust has validly elected to be treated as a domestic trust for U.S. federal income tax purposes;
This summary does not address all aspects of U.S. federal income taxation that may be relevant to a particular investor in light of that holder’s particular circumstances or that may be relevant to certain types of holders subject to special treatment under U.S. federal income tax law, such as: insurance companies; tax-exempt organizations; banks and other financial institutions; pension plans; cooperatives; real estate investment trusts; dealers in securities or currencies; traders that elect to use a mark-to-market method of accounting; certain former U.S. citizens or long-term residents; persons holding shares as part of a straddle, hedge, conversion, constructive sale or other integrated transaction for U.S. federal income tax purposes; persons who acquire shares pursuant to any employee share option or otherwise as compensation; persons holding shares through an individual retirement account or other tax-deferred account; persons who actually or constructively own 10% or more of our stock (by vote or value); persons whose functional currency is not the U.S. dollar; partnerships or other entities or arrangements subject to tax as partnerships for U.S. federal income tax purposes or persons holding shares through such entities; or persons that carry on a trade, business or vocation in the United Kingdom through a branch, agency or permanent establishment to which the shares are attributable.
If a partnership (or other entity or arrangement subject to tax as a partnership for U.S. federal income tax purposes) is a beneficial owner of shares, the U.S. federal income tax treatment of a partner in such partnership will generally depend upon the status of the partner and the activities of the partnership. A partnership for U.S. federal income tax purposes that holds shares and its partners are urged to consult their tax advisors regarding an investment in the shares.
In addition, this summary does not address any U.S. state or local or non-U.S. tax considerations or any U.S. federal estate, gift, or alternative minimum tax considerations, or the Medicare tax on certain net investment income.
Taxation of distributions on the shares
The gross amount of any distributions received by a U.S. Holder on shares will generally be subject to tax as dividends to the extent paid out of Atlantica Sustainable Infrastructure’sour current or accumulated earnings and profits (as determined for U.S. federal income tax purposes),and will be includible in the gross income of a U.S. HoldersHolder on the day actually or constructively received. Such dividends will not be eligible for the dividends received deduction generally allowed to U.S. corporations under the Code. The following discussion assumes that any dividends will be paid in U.S. dollars. Atlantica Sustainable Infrastructure intendsWe intend to annually calculate itsour earnings and profits in accordance with U.S. federal income tax principles. If distributions exceed Atlantica Sustainable Infrastructure’sour current and accumulated earnings and profits, such excess distributions will generally constitute a non-taxable return of capital to the extent of thea U.S. Holder’s tax basis in its shares and will result in a reduction of such tax basis. To the extent such excess exceeds a U.S. Holder’s tax basis in its shares, such excess will generally be subject to tax as capital gain.
Individuals and other non-corporate U.S. Holders of shares may be eligible for reduced rates of taxation if the dividends are “qualified dividend income.” Distributions received by a U.S. Holder on shares will generally be qualified dividend income if: (i) the shares on which the distribution are paid are readily tradable on an established securities market in the United States (such as NASDAQ Global Select Market, where our shares are listed), (ii) certain holding period requirements are satisfied, and (iii) Atlantica Sustainable Infrastructure iswe are not classified as a PFIC for the taxable year in which the dividend is paid or the preceding taxable year. As discussed below under “—Passive foreign investment company rules,” although there can be no assurance that Atlantica Sustainable Infrastructurewe were not and will not be considered a PFIC for any taxable year, Atlantica Sustainable Infrastructure doeswe do not believe that it waswe were a PFIC, for its 2020U.S. federal income tax purposes, for the taxable year ended December 31, 2022, and doesdo not expect to beanticipate becoming a PFIC for itsthe current taxable year or in the foreseeable future.any future taxable year. There can be no assurance, moreover, that the shares will be considered readily tradable on an established securities market in the current year or in future years. Individuals and other non-corporate U.S. Holders should consult their tax advisors to determine whether they are subject to any special rules that limit their ability to be taxed at these favorable rates.
Dividends on the shares will generally be treated as income from sources outside the United States and will generally constitute passive category income for U.S. foreign tax credit purposes. Depending on the individual facts and circumstances, a U.S. Holder may be eligible, subject to a number of complex limitations, to claim a foreign tax credit not in excess of any applicable treaty rate in respect of any foreign withholding taxes imposed on dividends received on our common shares. A U.S. Holder who does not elect to claim a foreign tax credit for foreign taxes withheld may instead claim a deduction, for U.S. federal income tax purposes, in respect of such withholding, but only for a year in which such U.S. Holderholder elects to do so for all creditable foreign income taxes. The rules governing the U.S. foreign tax credit are complex and the application thereof depends in large part on the U.S. Holder’s individual facts and circumstances. Accordingly, U.S. Holders should consult their tax advisors regarding the availability of the U.S. foreign tax credit in their particular circumstances.
Taxation upon sale or other disposition of shares
A U.S. Holder will generally recognize U.S. source capital gain or loss on the sale or other disposition of the shares, which will generally be long-term capital gain or loss if the U.S. Holder’s holding period for the shares is more than one year at the time of disposition. The amount of the U.S. Holder’s gain or loss will generally be equal to the difference between the amount realized on the disposition and the U.S. Holder’s adjusted tax basis in the shares. Individuals and certain other non-corporate U.S. Holders will generally be subject to U.S. federal income tax on net long-term capital gains at a lower rate than the rate applicable to ordinary income. The deductibility of a capital loss may be subject to limitations.
Passive foreign investment company rules
A non-U.S. corporation, such as our company, will be classified as a PFIC for U.S. federal income tax purposes for any taxable year, if either (i) 75% or more of its gross income for such year consists of certain types of “passive” income or (ii) 50% or more of the value of its assets (determined on the basis of a quarterly average) during such year produce or are held for the production of passive income. Passive income generally includes dividends, interest, royalties, rents, annuities, net gains from the sale or exchange of property producing such income and net foreign currency gains. For this purpose, cash is categorized as a passive asset and the company’s unbooked intangibles associated with active business activity are taken into account as a non-passive asset. We will be treated as owning our proportionate share of the assets and earning our proportionate share of the income of any other corporation in which we own, directly, indirectly or constructively, 25% or more (by value) of the stock.
Based on our income and assets, and the value of our shares, we do not believe that we were a PFIC, for U.S. federal income tax purposes, for the taxable year ended December 31, 2021,2022, and do not anticipate becoming a PFIC for the current taxable year or for the foreseeable future.in any future taxable year. Nevertheless, because PFIC status is a factual determination made annually after the close of each taxable year on the basis of the composition of our income and assets, there can be no assurance that we were not a PFIC for the taxable year ended December 31, 2022, or will not be a PFIC for the current taxable year or in any future taxable year. Under circumstances where revenues from activities that produce passive income significantly increase relative to our revenues from activities that produce non-passive income, or where we determine not to deploy significant amounts of cash, our risk of becoming classified as a PFIC may substantially increase. In addition, because we have valued our goodwill based on the market value of our shares, a decrease in the market value of our shares may also result in our becoming a PFIC.
If we are a PFIC for any taxable year during which a U.S. Holder holds our shares, such holder will be subject to special tax rules with respect to any “excess distribution” that such holder receives on the shares and any gain such holder realizes from a sale or other disposition (including a pledge) of the shares, unless such holder makes a “mark-to-market” election as discussed below. Distributions received by a U.S. Holder in a taxable year that are greater than 125% of the average annual distributions such holder received during the shorter of the three preceding taxable years or such holder’s holding period for the shares will be treated as an excess distribution. Under these special tax rules:
the excess distribution or gain will be allocated ratably over the U.S. Holder’s holding period for the shares;
amounts allocated to the current taxable year and any taxable years in the U.S. Holder’s holding period prior to the first taxable year in which we are classified as a PFIC (a(each, a “pre-PFIC year”) will be subject to tax as ordinary income; and
amounts allocated to each prior taxable year, other than the current taxable year or a pre-PFIC year, will be subject to tax at the highest tax rate in effect applicable to the U.S. Holder for that year, and such amounts will be increased by an additional tax equal to interest on the resulting tax deemed deferred with respect to such years.
If we are a PFIC for any taxable year during which a U.S. Holder holds shares and any of our non-U.S. affiliated entities are also PFICs, such holder will be treated as owning a proportionate amount (by value) of the shares of each such non-U.S. affiliate classified as a PFIC for purposes of the application of these rules.
Alternatively, a U.S. Holder of “marketable stock” (as defined below) in a PFIC may make a mark-to-market election for such stock of a PFIC to elect out of the tax treatment discussed in the second preceding paragraph. If a U.S. Holder makes a valid mark-to-market election for the shares, the U.S. Holder will include in income each year an amount equal to the excess, if any, of the fair market value of the shares as of the close of such holder’s taxable year over such holder’s adjusted basis in such shares. The U.S. Holder is allowed a deduction for the excess, if any, of such holder’s adjusted basis in the shares over their fair market value as of the close of the taxable year. Deductions are allowable, however, only to the extent of any net mark-to-market gains on the shares included in the U.S. Holder’s income for prior taxable years. Amounts included in the U.S. Holder’s income under a mark-to-market election, as well as gain on the actual sale or other disposition of the shares, are treated as ordinary income. Ordinary loss treatment also applies to the deductible portion of any mark-to-market loss on the shares, as well as to any loss realized on the actual sale or disposition of the shares, to the extent that the amount of such loss does not exceed the net mark-to-market gains previously included in income with respect to such shares. The U.S. Holder’s basis in the shares will be adjusted to reflect any such income or loss amounts. If a U.S. Holder makes such a mark-to-market election, tax rules that apply to distributions by corporations which are not PFICs would apply to distributions by us (except that the lower applicable capital gains rate for qualified dividend income would not apply). If a U.S. Holder makes a valid mark-to-market election, and we subsequently cease to be classified as a PFIC, such U.S. Holderholder will not be required to take into account the mark-to-market income or loss described above during any period that we are not classified as a PFIC.
The mark-to-market election is available only for “marketable stock” which is stock that is traded in other than de minimis quantities on at least 15 days during each calendar quarter (“regularly traded”) on a qualified exchange or other market, as defined in applicable Regulations. We expect that the shares will continue to be listed on the NASDAQ Global Select Market, which is a qualified exchange for these purposes, and, consequently, assuming that the shares are regularly traded, if a U.S. Holder holds the shares, it is expected that the mark-to-market election would be available to such holder were we to become a PFIC.
In addition, because, as a technical matter, a mark-to-market election cannot be made for any lower-tier PFICs that we may own, a U.S. Holder may continue to be subject to the PFIC rules with respect to such holder’s indirect interest in any investments held by us that are treated as an equity interest in a PFIC for U.S. federal income tax purposes.
We do not intend to provide information necessary for U.S. Holders to make qualified electing fund elections, which, if available, would result in tax treatment different from the general tax treatment for PFICs described above.
If a U.S. Holder owns the shares during any taxable year that we are a PFIC, such holder must generally file an annual report with the IRS regarding their ownership of shares. U.S. Holders should consult their tax advisors concerning the U.S. federal income tax considerations of holding and disposing of the shares if we are or become a PFIC, including the availability and possibility of making a mark-to-market election.
Foreign financial asset reporting
A U.S. Holder may be required to report information relating to an interest in the shares, generally by filing IRS Form 8938 (Statement of Specified Foreign Financial Assets) with the U.S. Holder’s federal income tax return. A U.S. Holder may also be subject to significant penalties if the U.S. Holder is required to report such information and fails to do so. U.S. Holders should consult their tax advisors regarding information reporting obligations, if any, with respect to ownership and disposition of the shares.
THE PRECEDING DISCUSSION OF U.S. FEDERAL INCOME TAX CONSIDERATIONS IS INTENDED FOR GENERAL INFORMATION ONLY AND DOES NOT CONSTITUTE TAX ADVICE. U.S. HOLDERS SHOULD CONSULT THEIR TAX ADVISORS AS TO THE U.S. FEDERAL, STATE, LOCAL AND NON-U.S. TAX CONSIDERATIONS TO THEM OF THE OWNERSHIP AND DISPOSITION OF THE SHARES IN THEIR PARTICULAR CIRCUMSTANCES.
F. | Dividends and Paying Agent |
Not applicable.
Not applicable.
Our SEC filings are available to you on the SEC’s website at http://www.sec.gov. This site contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The information on that website is not part of this report. We also make available on our website free of charge, our annual reports on Form 20-F and the text of our reports on Form 6-K, including any amendments to these reports , as well as certain other SEC filings, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Our website address is www.atlantica.com. The information on that website is not part of this report.
As a foreign private issuer, we will be exempt from the rules under the Exchange Act related to the furnishing and content of proxy statements, and our officers, directors and principal shareholders will be exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act. In addition, we will not be required under the Exchange Act to file annual, quarterly and current reports and financial statements with the SEC as frequently or as promptly as United States companies whose securities are registered under the Exchange Act. However, for so long as we are listed on the NASDAQ, or any other U.S. exchange, and are registered with the SEC, we will file with the SEC, within 120 days after the end of each fiscal year, or such applicable time as required by the SEC, an annual report on Form 20-F containing financial statements audited by an independent registered public accounting firm. We also submit to the SEC on Form 6-K the interim financial information that we publish.
I. | Subsidiaries Information |
Not applicable.
ITEM 11. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Quantitative and Qualitative Disclosure about Market Risk
Our activities are undertaken through our segments and are exposed to market risks that include foreign exchange risk, interest rate risk, credit risk, liquidity risk, electricity price risk and liquiditycountry risk. Our objective is to protect Atlantica against material economic exposures and variability of results from those risks. Risk is managed by our Risk Management and Finance Departments in accordance with mandatory internal management rules. The internal management rules provide written policies for the management of overall risk, as well as for specific areas, such as foreign exchange rate risk, interest rate risk, credit risk and liquidity risk, among others. Our internal management policies also define the use of hedging instruments and derivatives and the investment of excess cash.
Market risk
We are exposed to market risk, such as movement in foreign exchange rates and interest rates. All of these market risks arise in the normal course of business and we do not carry out speculative operations. For the purpose of managing these risks, we use swaps and options on interest rates and foreign exchange rates.rates to manage certain of our risks. None of the derivative contracts signed has an unlimited loss exposure.
Foreign exchange risk
The main cash flows from our subsidiaries are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Given that financing of the projects is generally denominated in the same currency in which the contract with the client is signed, a natural hedge exists for our main operations.
Our functional currency is the U.S. dollar, as most of our revenue and expenses are denominated or linked to U.S. dollars. All our companies located in North America and most of our companies in South America have their revenue and financing contracts signed in, or indexed totally or partially to, U.S. dollars, with the exception of Calgary, with revenue in Canadian dollars. Our solar power plants in Europe have their revenue and expenses denominated in euros, Kaxu, our solar plant in South Africa, has its revenue and expenses denominated in South African rand and La Sierpe, our solar plant in Colombia, has its revenue and expenses denominated in Colombian pesos. Project financing is typically denominated in the same currency as that of the contracted revenue agreement. This policy seeks to ensure that the main revenue and expenses streams in foreign companies are denominated in the same currency, limiting our risk of foreign exchange differences in our financial results.
Our strategy is to hedge cash distributions from our assets in Europe. We hedge the exchange rate for the distributions in euros after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, we have hedged 100% of our euro-denominated net exposure for the next 12 months and 75% of our euro-denominated net exposure for the following 12 months. We expect to continue with this hedging strategy on a rolling basis.
Although we hedge cash-flows in euros, fluctuations in the value of the euro in relation to the U.S. dollar may affect our operating results. For example, revenue in euro-denominated companies could decrease when translated to U.S. dollars at the average foreign exchange rate solely due to a decrease in the average foreign exchange rate, in spite of revenue in the original currency being stable. Fluctuations in the value of the South African rand and the Colombian peso with respect to the U.S. dollar may also affect our operating results. Apart from the impact of these translation differences, the exposure of our income statement to fluctuations of foreign currencies is limited, as the financing of projects is typically denominated in the same currency as that of the contracted revenue agreement.
Interest rate risk
Interest rate risk arises mainly from our financial liabilities at variable interest rate (less than 10% of our total project debt financing). We use interest rate swaps and interest rate options (caps) to mitigate interest rate risk.
As a result, the notional amounts hedged as of December 31, 2021, contracted strikes and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, are very diverse, including the following:
Project debt in euro: between 75% and 100% of the notional amount, with hedged maturing until 2038 at an average guaranteed strike interest rates of between 0.00% and 4.87%.
Project debt in U.S. dollars: between 75% and 100% of the notional amount, with hedges maturing until 2038 and average strike interest rates of between 0.86% and 5.89%.
The most significant impact on our Annual Consolidated Financial Statements related to interest rates corresponds to the potential impact of changes in EURIBOR or LIBOR on the debt with interest rates based on EURIBOR or LIBOR and on derivative positions.
In relation to our interest rate swaps positions, an increase in EURIBOR or LIBOR above the contracted fixed interest rate would create an increase in our financial expense which would be positively mitigated by our hedges, reducing our financial expense to our contracted fixed interest rate. However, an increase in EURIBOR or LIBOR that does not exceed the contracted fixed interest rate would not be offset by our derivative position and would result in a net financial loss recognized in our consolidated income statement. Conversely, a decrease in EURIBOR or LIBOR below the contracted fixed interest rate would result in lower interest expense on our variable rate debt, which would be offset by a negative impact from our hedges, increasing our financial expense up to our contracted fixed interest rate, thus likely resulting in a neutral effect.
In relation to our interest rate options positions, an increase in EURIBOR or LIBOR above the strike price would result in higher interest expenses, which would be positively mitigated by our hedges, reducing our financial expense to our capped interest rate, whereas a decrease of EURIBOR or LIBOR below the strike price would result in lower interest expenses.
In addition to the above, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates.
In the event that EURIBOR and LIBOR had risen by 25 basis points as of December 31, 2021, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $2.5 million (a loss of $2.9 million in 2020 and a loss of $2.7 million in 2019) and an increase in hedging reserves of $22.4 million ($22.1 million in 2020 and $27.6 million in 2019). The increase in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.
Credit risk
The credit rating of Eskom is currently CCC+ from S&P , Caa1 from Moody’sfollowing table outlines Atlantica´s market risks and B from Fitch. Eskom is the off-taker of our Kaxu solar plant, a state-owned, limited liability company, wholly owned by the government of the Republic of South Africa. Eskom’s payment guarantees to our Kaxu solar planthow they are underwritten by the South African Department of Energy, under the terms of an implementation agreement. The credit ratings of the Republic of South Africa as of the date of this report are BB-/Ba2/BB- by S&P, Moody’s and Fitch, respectively.managed:
In addition, Pemex’s credit rating is currently BBB from S&P, Ba3 from Moody’s and BB- from Fitch. We have been experiencing delays from Pemex in collections since the second half of 2019 which have been significant in certain quarters.
In 2019, we also entered into a political risk insurance agreement with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $78.0 million in the event the South African Department of Energy does not comply with its obligations as guarantor. We also have a political risk insurance in place for our assets in Algeria up to $38.2 million, including two years dividend coverage. These insurance policies do not cover credit risk.
Market Risk | Description of Risk | Management of Risk |
Foreign exchange risk | We are exposed to foreign currency risk – including Euro, Canadian dollar, South African rand, Colombian peso and Uraguayan peso – related to operations and certain foreign currency debt.
Our presentation currency and the functional currency of most of our subsidiaries is the U.S. dollar, as most of our revenue and expenses are denominated or linked to U.S. dollars.
All our companies located in North America, with the exception of Calgary, whose revenue is in Canadian dollars, and most of our companies in South America have their revenue and financing contracts signed in or indexed totally or partially to U.S. dollars. Our solar power plants in Europe have their revenue and expenses denominated in euros; Kaxu, our solar plant in South Africa, has its revenue and expenses denominated in South African rand, La Sierpe, La Tolua and Tierra Linda, our solar plants in Colombia, have their revenue and expenses denominated in Colombian pesos and Albisu, our solar plant in Uruguay, has its revenue denominated in Uruguayan pesos, with a maximum and a minimum price in US dollars in the case of Uruguayan peso. | The main cash flows in our subsidiaries are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Project financing is typically denominated in the same currency as that of the contracted revenue agreement, which limits our exposure to foreign exchange risk. In addition, we maintain part of our corporate general and administrative expenses and part of our corporate debt in euros which creates a natural hedge for the distributions we receive from our assets in Europe.
To further mitigate this exposure, our strategy is to hedge cash distributions from our assets in Europe. We hedge the exchange rate for the net distributions in euros (after deducting interest payments and general and administrative expenses in euros). Through currency options, we have hedged 100% of our euro-denominated net exposure for the next 12 months and 75% of our euro-denominated net exposure for the following 12 months. We expect to continue with this hedging strategy on a rolling basis. The difference between the euro/U.S. dollar hedged rate for the year 2023 and the current rate reduced by 5% would create a negative impact on cash available for distribution of approximately $5.5 million. This amount has been calculated as the average net euro exposure expected for the years 2023 to 2026 multiplied by the difference between the average hedged euro /U.S. dollar rate for 2023 and the euro/U.S. dollar rate as of the date of this annual report reduced by 5%.
Although we hedge cash-flows in euros, fluctuations in the value of the euro in relation to the U.S. dollar may affect our operating results. For example, revenue in euro-denominated companies could decrease when translated to U.S. dollars at the average foreign exchange rate solely due to a decrease in the average foreign exchange rate, in spite of revenue in the original currency being stable. Fluctuations in the value of the South African rand, the Colombian peso and the Uruguayan Peso with respect to the U.S. dollar may also affect our operating results. Apart from the impact of these translation differences, the exposure of our income statement to fluctuations of foreign currencies is limited, as the financing of projects is typically denominated in the same currency as that of the contracted revenue agreement. |
Interest rate risk | We are exposed to interest rate risk on our variable-rate debt.
Interest rate risk arises mainly from our financial liabilities at variable interest rate (less than 10% of our consolidated debt).
The most significant impact on our Annual Consolidated Financial Statements related to interest rates corresponds to the potential impact of changes in EURIBOR, SOFR or LIBOR on the debt with interest rates based on these reference rates and on derivative positions.
In relation to our interest rate swaps positions, an increase in EURIBOR, SOFR or LIBOR above the contracted fixed interest rate would create an increase in our financial expense which would be positively mitigated by our hedges, reducing our financial expense to our contracted fixed interest rate. However, an increase in EURIBOR, SOFR or LIBOR that does not exceed the contracted fixed interest rate would not be offset by our derivative position and would result in a stable net expense recognized in our consolidated income statement. In relation to our interest rate options positions, an increase in EURIBOR, SOFR or LIBOR above the strike price would result in higher interest expenses, which would be positively mitigated by our hedges, reducing our financial expense to our capped interest rate. However, an increase in these rates of reference below the strike price would result in higher interest expenses. | Our assets largely consist of long duration physical assets, and financial liabilities consist primarily of long-term fixed-rate debt or floating-rate debt that has been swapped to fixed rates with interest rate financial instruments to minimize the exposure to interest rate fluctuations.
We use interest rate swaps and interest rate options (caps) to mitigate interest rate risk. As of December 31, 2022, approximately 92% of our project debt and approximately 96% of our corporate debt either has fixed interest rates or has been hedged with swaps or caps. Our revolving credit facility has variable interest rates and is not hedged as further described in “Item 5.B— Operating and Financial Review and Prospects— Liquidity and Capital Resources— Corporate debt agreements —Revolving Credit Facility”;
In the event that EURIBOR, SOFR and LIBOR had risen by 25 basis points as of December 31, 2022, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $1.3 million (a loss of $2.5 million in 2021 and a loss of $2.9 million in 2020) and an increase in hedging reserves of $18.4 million ($22.4 million increase in 2021 and $22.1 million increase in 2020). The increase in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges. |
Credit Risk | We are exposed to credit risk mainly from operating activities, the maximum exposure of which is represented by the carrying amounts reported in the statements of financial position. We are exposed to credit risk if counterparties to our contracts, trade receivables, interest rate swaps, foreign exchange hedge contracts are unable to meet their obligations.
The credit rating of Eskom is currently CCC+ from S&P , Caa1 from Moody’s and B from Fitch. Eskom is the off-taker of our Kaxu solar plant, a state-owned, limited liability company, wholly owned by the Republic of South Africa.
In addition, Pemex’s credit rating is currently BBB from S&P, B1 from Moody’s and BB- from Fitch. We have experienced delays in collections in the past, especially since the second half of 2019, which have been significant in certain quarters. As of December 31, 2022 these delays were shorter than in previous quarters. | The diversification by geography and business sector helps to diversify credit risk exposure by diluting our exposure to a single client.
In the case of Kaxu, Eskom’s payment guarantees to our Kaxu solar plant are underwritten by the South African Department of Mineral Resources and Energy, under the terms of an implementation agreement. The credit ratings of the Republic of South Africa as of the date of this annual report are BB-/Ba2/BB- by S&P, Moody’s and Fitch, respectively.
In the case of Pemex, during 2022 we have maintained a pro-active approach including fluent dialogue with our client. |
Liquidity risk | We are exposed to liquidity risk for financial liabilities.
Our liquidity at the corporate level depends on distribution from the project level entities, most of which have project debt in place. Distributions are generally subject to the compliance with covenants and other conditions under our project finance agreements. | The objective of our financing and liquidity policy is to ensure that we maintain sufficient funds to meet our financial obligations as they fall due.
Project finance borrowing permits us to finance projects through project debt and thereby insulate the rest of our assets from such credit exposure. We incur project finance debt on a project-by-project basis or by groups of projects. The repayment profile of each project is established based on the projected cash flow generation of the business. This ensures that sufficient financing is available to meet deadlines and maturities, which mitigates the liquidity risk. In addition, we maintain a periodic communication with our lenders and regular monitoring of debt covenants and minimum ratios.
As of December 31, 2022, we had $445.9 million liquidity at the corporate level, comprised of $60.8 million of cash on hand at the corporate level and $385.1 million available under our Revolving Credit Facility.
We believe that the Company’s liquidity position, cash flows from operations and availability under our revolving credit facility will be adequate to meet the Company’s financial commitments and debt obligations; growth, operating and maintenance capital expenditures; and dividend distributions to shareholders. Management continues to regularly monitor the Company’s ability to finance the needs of its operating, financing and investing activities within the guidelines of prudent balance sheet management. |
Electricity price risk | We currently have three assets with merchant revenues (Chile PV 1 and Chile PV 3, where we have a 35% ownership, and Lone Star II, where we have a 49% ownership) and one asset with partially contracted revenues (Chile PV 2, where we have a 35% ownership). In addition, in several of the jurisdictions in which we operate including Spain, Chile and Italy we are exposed to remuneration schemes which contain both regulated incentives and market price components. In such jurisdictions, the regulated incentive or the contracted component may not fully compensate for fluctuations in the market price component, and, consequently, total remuneration may be volatile.
In addition, operating costs in certain of our existing or future projects depend to some extent on market prices of electricity used for self-consumption and, to a lower extent, on market prices of natural gas. In Spain, for example, operating costs have increased during 2021 and 2022 as a result of the increase in the price of electricity and natural gas. | We manage our exposure to electricity price risk by ensuring that most of our revenues are not exposed to fluctuations in electricity prices. As of December 31, 2022, assets with merchant exposure represent less than a 2%9 of our portfolio in terms of Adjusted EBITDA. Regarding regulated assets with exposure to electricity market prices, these assets have the right to receive a “reasonable rate of return” (see “Item 4—Information on the Company— Regulation”). As a result, fluctuations in market prices may cause volatility in results of operations and cash flows, but it should not affect the net value of these assets. |
9 Calculated as a percentage of our Adjusted EBITDA in 2022.
ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC
INDEX TO FINANCIAL STATEMENTS
Annual Consolidated Financial Statements as of December 31, 20212022 and 20202021 and for the years ended December 31, 2022, 2021 2020 and 20192020
Report of Ernst and Young, S.L. (PCAOB ID 1461)
| F-1 |
Consolidated statements of financial position as of December 31, 20212022 and 20202021 | F-3F-4 |
Consolidated income statements for the years ended December 31, 2022, 2021 2020 and 20192020 | F-5 |
Consolidated financial statements of comprehensive income for the years ended December 31, 2022, 2021 2020 and 20192020 | F-6 |
Consolidated statements of changes in equity for the years ended December 31, 2022, 2021 2020 and 20192020 | F-7 |
Consolidated cash flow statements for the years ended December 31, 2022, 2021 2020 and 20192020 | F-10F-11 |
Notes to the annual consolidated financial statements | F-11F-12 |
Appendix I: Entities included in the Group as subsidiaries as of December 31, 20212022 and 20202021 | F-62F-60 |
Appendix II: Investments recorded under the equity method as of December 31, 20212022 and 2020
2021 | F-66F-65 |
Appendix III-1 and Appendix III-2: Assets subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 20212022 and 20202021 | F-68F-67 |
Appendix IV: Additional Information of Subsidiaries including material Non-controlling interest as of December 31, 20212022 and 2020
2021 | F-83F-82 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atlantica Sustainable Infrastructure plc
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of Atlantica Sustainable Infrastructure plc (the “Company”) as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, changes in equity and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with International Financial Reporting Standards as issued by International Accounting Standards Board.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 28, 2023, expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Recoverability assessment of contracted concessional, PP&E and other intangible assets
Description of the Matter | As described in Note 6 to the consolidated financial statements, the Company has recorded “contracted concessional, PP&E and other intangible assets” of $7,483 million at December 31, 2022. Revenue derived from the Company’s contracted concessional, PP&E and other intangible assets are primarily governed by power purchase agreements (“PPAs”) with the Company’s customers or by the applicable energy regulations of each country.
As described in Note 2 to the consolidated financial statements, the Company reviews its contracted concessional assets, PP&E and other intangible assets for impairment indicators whenever events or changes in circumstances indicate that the carrying amounts of the assets or group of assets may not be recoverable, or previous impairment losses are no longer adequate. As discussed in Note 6, management identified triggering events at the US Solana asset and at two Chilean assets (Chile PV1 and Chile PV2) and as a result, a $61 million impairment charge was recorded in 2022.
Auditing the Company’s recoverability assessment of contracted concessional, PP&E and other intangible assets involves significant judgment in determining whether impairment indicator existed and, if an indicator exists, in the assumptions used by management in the determination of whether an impairment should be recorded or reversed. The main inputs considered when evaluating for impairment indicators include the performance of the assets versus budget, changes in applicable regulations and estimates of future electricity prices. The significant assumptions which required substantial judgement or estimation used in management’s impairment calculation are discount rates and projections considering real data based on contract terms and projected changes in both selling prices and costs. |
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over the Company’s contracted concessional, PP&E and other intangible assets recoverability assessment process. Among others, we tested controls over management’s identification of potential impairment indicators, as well as controls over the determination of significant assumptions used in the impairment calculation, including, the discount rates and underlying projections used in the Company’s impairment assessment.
To test the Company’s impairment indicators assessment for contracted concessional, PP&E and other intangible assets, our audit procedures included, among others, comparing actual energy production versus budget for each asset, assessing the estimated future electricity prices versus prior year future estimates and determining whether identified changes in applicable regulation would negatively impact the Company’s assets’ future cash flows.
As part of our audit procedures, we assessed the appropriateness of the main inputs used in the cash flow projections, by, for example, comparing estimated future performance of the asset versus historical results and comparing future price estimates versus prior year future estimates. For the discount rate, we involved our valuation specialists to assist us in calculating and developing a range of discount rates, which we compared to those used by the Company.
We assessed the adequacy of the related disclosures in the Company’s consolidated financial statements, including the sensitivity analyses on the energy production, electricity prices and discount rate assumptions. |
/s/ ERNST & YOUNG, S.L.
We have served as the Company’s auditor since 2019
Madrid, Spain
February 28, 2023
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and the Board of Directors of Atlantica Sustainable Infrastructure plc:
Opinion on Internal Control Over Financial Reporting
We have audited Atlantica Sustainable Infrastructure plc plc’s’s internal control over financial reporting as of December 31, 2021,2022, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Atlantica Sustainable Infrastructure plc (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021,2022, based on the COSO criteria.
As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Coso,Chile TL 4, Chile PV 3, Italy PV 4, Rioglass Calgary District Heating, Chile PV2, Italy PV1, PV2Servicios and PV3 and La Sierpe,Atlantica South Africa Operations, which are included in the 20212022 consolidated financial statements of the Company and collectively constituted 6%1% of total assets, as of December 31, 20212022 and 13,5%0.6% of consolidated revenues, for the year then ended.
Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Coso,Chile TL 4, Chile PV 3, Italy PV 4, Rioglass Calgary District Heating, Chile PV2, Italy PV1, PV2Servicios and PV3 and La Sierpe.Atlantica South Africa Operations.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 20212022 consolidated financial statements of the Company and our report dated February 27, 202228, 2023, expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ ERNST & YOUNG, S.L. |
We have served as the Company’s auditor since 2019
|
Madrid, Spain
| |
February 27, 2022 | 28, 2023 |
Consolidated statements of financial position as of December 31, 20212022 and 20202021
Amounts in thousands of U.S. dollars
| | | | | As of December 31, | | | | | | As of December 31, | |
| | Note (1) | | | 2021
| | | 2020
| | | Note (1) | | | 2022
| | | 2021
| |
Assets | | | | | | | | | | | | | | | | | | |
Non-current assets | | | | | | | | | | | | | | | | | | |
Contracted concessional assets | | | 6 | | | | 8,021,568 | | | | 8,155,418 | | |
Contracted concessional, PP&E and other intangible assets | | | | 6 | | | | 7,483,259 | | | | 8,021,568 | |
Investments carried under the equity method | | | 7 | | | | 294,581 | | | | 116,614 | | | | 7 | | | | 260,031 | | | | 294,581 | |
Other accounts receivable
| | | 8 | | | | 85,801 | | | | 88,655 | | | | 8 | | | | 86,431 | | | | 85,801 | |
Derivative assets | | | 9 | | | | 10,807 | | | | 1,099 | | | | 9 | | | | 89,806 | | | | 10,807 | |
Financial investments | | | 8 | | | | 96,608 | | | | 89,754 | | |
Other financial assets | | | | 8 | | | | 176,237 | | | | 96,608 | |
Deferred tax assets | | | 18 | | | | 172,268 | | | | 152,290 | | | | 18 | | | | 149,656 | | | | 172,268 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total non-current assets | | | | | | | 8,585,025
| | | | 8,514,076
| | | | | | | | 8,069,183
| | | | 8,585,025
| |
| | | | | | | | | | | | | | | | | | | | | | | | |
Current assets | | | | | | | | | | | | | | | | | | | | | | | | |
Inventories | | | | | | | 29,694 | | | | 23,958 | | | | | | | | 34,511 | | | | 29,694 | |
Trade receivables | | | 11 | | | | 227,343 | | | | 258,087 | | | | 11 | | | | 125,437 | | | | 227,343 | |
Credits and other receivables | | | 11 | | | | 79,800 | | | | 73,648 | | | | 11 | | | | 74,897 | | | | 79,800 | |
Trade and other receivables | | | 11 | | | | 307,143 | | | | 331,735 | | | | 11 | | | | 200,334 | | | | 307,143 | |
Financial investments | | | 8 | | | | 207,379 | | | | 200,084 | | |
Other financial assets | | | | 8 | | | | 195,893 | | | | 207,379 | |
Cash and cash equivalents | | | 12 | | | | 622,689 | | | | 868,501 | | | | 12 | | | | 600,990 | | | | 622,689 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total current assets | | | | | | | 1,166,905
| | | | 1,424,278
| | | | | | | | 1,031,728
| | | | 1,166,905
| |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total assets | | | | | | | 9,751,930
| | | | 9,938,354
| | | | | | | | 9,100,911
| | | | 9,751,930
| |
(1) | Notes 1 to 23 are an integral part of the Consolidated Financial Statements |
Consolidated statements of financial position as of December 31, 20212022 and 20202021
Amounts in thousands of U.S. dollars
| | | | | As of December 31, | | | | | | As of December 31, | |
| | Note (1) | | | 2021
| | | 2020
| | | Note (1) | | | 2022
| | | 2021
| |
Equity and liabilities | | | | | | | | | | | | | | | | | | |
Equity attributable to the Company | | | | | | | | | | | | | | | | | | |
Share capital | | | 13 | | | | 11,240 | | | | 10,667 | | | | 13 | | | | 11,606 | | | | 11,240 | |
Share premium | | | 13 | | | | 872,011 | | | | 1,011,743 | | | | 13 | | | | 986,594 | | | | 872,011 | |
Capital reserves | | | 13 | | | | 1,020,027 | | | | 881,745 | | | | 13 | | | | 814,951 | | | | 1,020,027 | |
Other reserves | | | 9 | | | | 171,272 | | | | 96,641 | | | | 9 | | | | 345,567 | | | | 171,272 | |
Accumulated currency translation differences | | | 13
| | | | (133,450 | ) | | | (99,925 | ) | | | 13
| | | | (161,307 | ) | | | (133,450 | ) |
Accumulated deficit | | | 13 | | | | (398,701 | ) | | | (373,489 | ) | | | 13 | | | | (397,540 | ) | | | (398,701 | ) |
Non-controlling interest | | | 13 | | | | 206,206 | | | | 213,499 | | | | 13 | | | | 189,176 | | | | 206,206 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total equity | | | | | | | 1,748,605 | | | | 1,740,881 | | | | | | | | 1,789,047 | | | | 1,748,605 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Non-current liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Long-term corporate debt | | | 14 | | | | 995,190 | | | | 970,077 | | | | 14 | | | | 1,000,503 | | | | 995,190 | |
Borrowings | | | | | | | 3,407,956 | | | | 3,862,068 | | | | | | | | 3,322,115 | | | | 3,407,956 | |
Notes and bonds | | | | | | | 979,718 | | | | 1,063,200 | | | | | | | | 904,403 | | | | 979,718 | |
Long-term project debt | | | 15 | | | | 4,387,674 | | | | 4,925,268 | | | | 15 | | | | 4,226,518 | | | | 4,387,674 | |
Grants and other liabilities | | | 16 | | | | 1,263,744 | | | | 1,229,767 | | | | 16 | | | | 1,252,513 | | | | 1,263,744 | |
Derivative liabilities | | | 9 | | | | 223,453 | | | | 328,184 | | | | 9 | | | | 16,847 | | | | 223,453 | |
Deferred tax liabilities | | | 18 | | | | 308,859 | | | | 260,923 | | | | 18 | | | | 296,481 | | | | 308,859 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total non-current liabilities | | | | | | | 7,178,920
| | | | 7,714,219
| | | | | | | | 6,792,862
| | | | 7,178,920
| |
| | | | | | | | | | | | | | | | | | | | | | | | |
Current liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Short-term corporate debt | | | 14 | | | | 27,881 | | | | 23,648 | | | | 14 | | | | 16,697 | | | | 27,881 | |
Borrowings | | | | | | | 597,680 | | | | 261,788 | | | | | | | | 273,556 | | | | 597,680 | |
Notes and bonds | | | | | | | 50,839 | | | | 50,558 | | | | | | | | 52,978 | | | | 50,839 | |
Short-term project debt | | | 15 | | | | 648,519 | | | | 312,346 | | | | 15 | | | | 326,534 | | | | 648,519 | |
Trade payables and other current liabilities | | | 17 | | | | 113,907 | | | | 92,557 | | | | 17 | | | | 140,230 | | | | 113,907 | |
Income and other tax payables | | | | | | | 34,098 | | | | 54,703 | | | | | | | | 35,541 | | | | 34,098 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total current liabilities | | | | | | | 824,405
| | | | 483,254
| | | | | | | | 519,002
| | | | 824,405
| |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total equity and liabilities | | | | | | | 9,751,930
| | | | 9,938,354
| | | | | | | | 9,100,911
| | | | 9,751,930
| |
(1) | Notes 1 to 23 are an integral part of the Consolidated Financial Statements |
Consolidated income statements for the years ended December 31,
2022, 2021
2020 and
20192020
Amounts in thousands of U.S. dollars
| | Note (1) | | | For the year ended December 31, | | | Note (1) | | | For the year ended December 31, | |
| | | | | 2021
| | | 2020
| | | 2019
| | | | | | 2022
| | | 2021
| | | 2020
| |
Revenue | | | 4 | | | | 1,211,749 | | | | 1,013,260 | | | | 1,011,452 | | | | 4 | | | | 1,102,029 | | | | 1,211,749 | | | | 1,013,260 | |
Other operating income | | | 20 | | | | 74,670 | | | | 99,525 | | | | 93,774 | | | | 20 | | | | 80,782 | | | | 74,670 | | | | 99,525 | |
Employee benefit expenses | | | 20 | | | | (78,758 | ) | | | (54,464 | ) | | | (32,246 | ) | | | 20 | | | | (80,232 | ) | | | (78,758 | ) | | | (54,464 | ) |
Depreciation, amortization, and impairment charges | | | 6 | | | | (439,441 | ) | | | (408,604 | ) | | | (310,755 | ) | | | 6 | | | | (473,638 | ) | | | (439,441 | ) | | | (408,604 | ) |
Other operating expenses | | | 20 | | | | (414,330 | ) | | | (276,666 | ) | | | (261,776 | ) | | | 20 | | | | (351,248 | ) | | | (414,330 | ) | | | (276,666 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating profit | | | | | | | 353,890
| | | | 373,051 | | | | 500,449 | | | | | | | | 277,693
| | | | 353,890 | | | | 373,051 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Financial income | | | 21 | | | | 2,755 | | | | 7,052 | | | | 4,121 | | | | 21 | | | | 5,569 | | | | 2,755 | | | | 7,052 | |
Financial expense | | | 21 | | | | (361,270 | ) | | | (378,386 | ) | | | (407,990 | ) | | | 21 | | | | (333,263 | ) | | | (361,270 | ) | | | (378,386 | ) |
Net exchange differences | | | 21 | | | | 1,873 | | | | (1,351 | ) | | | 2,674 | | | | 21 | | | | 10,257 | | | | 1,873 | | | | (1,351 | ) |
Other financial income/(expense), net | | | 21 | | | | 15,750 | | | | 40,875 | | | | (1,153 | ) | |
Other financial income, net | | | | 21 | | | | 6,503 | | | | 15,750 | | | | 40,875 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Financial expense, net | | | | | | | (340,892 | ) | | | (331,810 | ) | | | (402,348 | ) | | | | | | | (310,934 | ) | | | (340,892 | ) | | | (331,810 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Share of profit of associates carried under the equity method | | | 7 | | | | 12,304 | | | | 510 | | | | 7,457 | | |
Share of profit of entities carried under the equity method | | | | 7 | | | | 21,465 | | | | 12,304 | | | | 510 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Profit before income tax | | | | | | | 25,302 | | | | 41,751 | | | | 105,558 | | |
Profit /(loss) before income tax | | | | | | | | (11,776 | ) | | | 25,302 | | | | 41,751 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Income tax expense | | | 18 | | | | (36,220 | ) | | | (24,877 | ) | | | (30,950 | ) | |
Income tax (expense)/income | | | | 18 | | | | 9,689 | | | | (36,220 | ) | | | (24,877 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Profit/(loss) for the year | | | | | | | (10,918 | ) | | | 16,874 | | | | 74,608 | | | | | | | | (2,087 | ) | | | (10,918 | ) | | | 16,874 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Profit attributable to non-controlling interests | | | | | | | (19,162 | ) | | | (4,906 | ) | | | (12,473 | ) | | | | | | | (3,356 | ) | | | (19,162 | ) | | | (4,906 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Profit/(loss) for the year attributable to the Company | | | | | | | (30,080 | ) | | | 11,968 | | | | 62,135 | | | | | | | | (5,443 | ) | | | (30,080 | ) | | | 11,968 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted average number of ordinary shares outstanding (thousands) - basic | | | 22 | | | | 111,008 | | | | 101,879 | | | | 101,063 | | |
Weighted average number of ordinary shares outstanding (thousands) – basic | | | | 22 | | | | 114,695 | | | | 111,008 | | | | 101,879 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Weighted average number of ordinary shares outstanding (thousands) - diluted | | | 22 | | | | 114,523 | | | | 103,392 | | | | 101,063 | | |
Weighted average number of ordinary shares outstanding (thousands) – diluted | | | | 22 | | | | 118,501 | | | | 114,523 | | | | 103,392 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic earnings per share (U.S. dollar per share) | | | 22 | | | | (0.27 | ) | | | 0.12 | | | | 0.61 | | | | 22 | | | | (0.05 | ) | | | (0.27 | ) | | | 0.12 | |
Diluted earnings per share (U.S. dollar per share) | | | 22 | | | | (0.26 | ) | | | 0.12 | | | | 0.61 | | | | 22 | | | | (0.05 | ) | | | (0.27 | ) | | | 0.12 | |
(1) | Notes 1 to 23 are an integral part of the Consolidated Financial Statements |
Consolidated statements of comprehensive income for the years ended December 31,
2022, 2021
2020 and
20192020
Amounts in thousands of U.S. dollars
| | | | | For the year ended December 31, | | | | | | For the year ended December 31, | |
| | Note (1) | | | 2021
| | | 2020
| | | 2019
| | | Note (1) | | | 2022
| | | 2021
| | | 2020
| |
Profit/(loss) for the year | | | | | | (10,918 | ) | | | 16,874 | | | | 74,608 | | | | | | | (2,087 | ) | | | (10,918 | ) | | | 16,874 | |
Items that may be subject to transfer to income statement | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Change in fair value of cash flow hedges | | | | | | 33,846 | | | | (26,272 | ) | | | (81,713 | ) | | | | | | 218,737 | | | | 33,846 | | | | (26,272 | ) |
Currency translation differences | | | | | | (41,956 | ) | | | (9,947 | ) | | | (22,284 | ) | | | | | | (33,704 | ) | | | (41,956 | ) | | | (9,947 | ) |
Tax effect | | | | | | (9,139 | ) | | | 5,897 | | | | 20,088 | | | | | | | (54,405 | ) | | | (9,139 | ) | | | 5,897 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net expenses recognized directly in equity | | | | | | (17,249 | ) | | | (30,322 | ) | | | (83,909 | ) | |
Net income/(expense) recognized directly in equity | | | | | | | 130,628 | | | | (17,249 | ) | | | (30,322 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash flow hedges | | | 9
| | | | 58,292 | | | | 58,381 | | | | 55,765 | | | | 9
| | | | 38,187 | | | | 58,292 | | | | 58,381 | |
Tax effect | | | | | | | (14,573 | ) | | | (14,595 | ) | | | (13,941 | ) | | | | | | | (9,547 | ) | | | (14,573 | ) | | | (14,595 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Transfers to income statement | | | | | | | 43,719 | | | | 43,786 | | | | 41,824 | | | | | | | | 28,640 | | | | 43,719 | | | | 43,786 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other comprehensive income/(loss) | | | | | | | 26,470 | | | | 13,464 | | | | (42,085 | ) | | | | | | | 159,268 | | | | 26,470 | | | | 13,464 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income for the year | | | | | | | 15,552 | | | | 30,338 | | | | 32,523 | | | | | | | | 157,181 | | | | 15,552 | | | | 30,338 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income attributable to non-controlling interest | | | | | | | (14,586 | ) | | | (4,627 | ) | | | (12,429 | ) | | | | | | | (14,613 | ) | | | (14,586 | ) | | | (4,627 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income attributable to the Company | | | | | | | 966 | | | | 25,711 | | | | 20,094 | | | | | | | | 142,568 | | | | 966 | | | | 25,711 | |
(1) | Notes 1 to 23 are an integral part of the Consolidated Financial Statements |
Consolidated statements of changes in equity for the years ended December 31,
2022, 2021
2020 and
20192020
Amounts in thousands of U.S. dollars
| | Share capital | | | Share premium | | | Capital reserves | | | Other reserves | | | Accumulated currency translation differences | | | Accumulated deficit
| | | Total equity attributable to the Company | | | Non- controlling interest | | | Total equity | |
Balance as of January 1, 2019 | | | 10,022
| | | | 1,981,881
| | | | 48,059 | | | | 95,011 | | | | (68,315 | ) | | | (449,274 | ) | | | 1,617,384 | | | | 138,728 | | | | 1,756,112 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Profit for the year after taxes | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 62,135 | | | | 62,135 | | | | 12,473 | | | | 74,608 | |
Change in fair value of cash flow hedges | | | 0 | | | | 0 | | | | 0 | | | | (27,947 | ) | | | 0 | | | | 1,682 | | | | (26,265 | ) | | | 317 | | | | (25,948 | ) |
Currency translation differences | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (22,509 | ) | | | 0 | | | | (22,509 | ) | | | 225 | | | | (22,284 | ) |
Tax effect | | | 0 | | | | 0 | | | | 0 | | | | 6,733 | | | | 0 | | | | 0 | | | | 6,733 | | | | (586 | ) | | | 6,147 | |
Other comprehensive income | | | 0 | | | | 0 | | | | 0 | | | | (21,214 | ) | | | (22,509 | ) | | | 1,682 | | | | (42,041 | ) | | | (44 | ) | | | (42,085 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | 0 | | | | 0 | | | | 0 | | | | (21,214 | ) | | | (22,509 | ) | | | 63,817 | | | | 20,094 | | | | 12,429 | | | | 32,523 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital increase (Note 13) | | | 138 | | | | 29,862 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 30,000 | | | | 0 | | | | 30,000 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amherst Island (Note 7) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 92,303 | | | | 92,303 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Reduction of Share Premium (Note 13) | | | 0 | | | | (1,000,000 | ) | | | 1,000,000 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Distributions (Note 13) | | | 0 | | | | 0 | | | | (159,002 | ) | | | 0 | | | | 0 | | | | 0 | | | | (159,002 | ) | | | (37,080 | ) | | | (196,082 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of December 31, 2019 | | | 10,160 | | | | 1,011,743 | | | | 889,057 | | | | 73,797 | | | | (90,824 | ) | | | (385,457 | ) | | | 1,508,476 | | | | 206,380 | | | | 1,714,856 | |
| | Share capital | | | Share premium | | | Capital reserves | | | Other reserves | | | Accumulated currency translation differences | | | Accumulated deficit
| | | Total equity attributable to the Company | | | Non- controlling interest | | | Total equity | |
Balance as of January 1, 2020 | | | 10,160
| | | | 1,011,743
| | | | 889,057 | | | | 73,797 | | | | (90,824 | ) | | | (385,457 | ) | | | 1,508,476 | | | | 206,380 | | | | 1,714,856 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Profit for the year after taxes | | | - | | | | - | | | | - | | | | - | | | | - | | | | 11,968 | | | | 11,968 | | | | 4,906 | | | | 16,874 | |
Change in fair value of cash flow hedges net of transfer to income statement
| | | - | | | | - | | | | - | | | | 31,353 | | | | - | | | | - | | | | 31,353 | | | | 756 | | | | 32,109 | |
Currency translation differences | | | - | | | | - | | | | - | | | | - | | | | (9,101 | ) | | | - | | | | (9,101 | ) | | | (846 | ) | | | (9,947 | ) |
Tax effect | | | - | | | | - | | | | - | | | | (8,509 | ) | | | - | | | | - | | | | (8,509 | ) | | | (189 | ) | | | (8,698 | ) |
Other comprehensive income | | | - | | | | - | | | | - | | | | 22,844 | | | | (9,101 | ) | | | - | | | | 13,743 | | | | (279 | ) | | | 13,464 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | - | | | | - | | | | - | | | | 22,844 | | | | (9,101 | ) | | | 11,968 | | | | 25,711 | | | | 4,627 | | | | 30,338 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital increase
| | | 507 | | | | - | | | | 161,347 | | | | - | | | | - | | | | - | | | | 161,854 | | | | - | | | | 161,854 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Business combinations
| | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 25,308 | | | | 25,308 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Distributions
| | | - | | | | - | | | | (168,659 | ) | | | - | | | | - | | | | - | | | | (168,659 | ) | | | (22,816 | ) | | | (191,475 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of December 31, 2020 | | | 10,667 | | | | 1,011,743 | | | | 881,745 | | | | 96,641 | | | | (99,925 | ) | | | (373,489 | ) | | | 1,527,382 | | | | 213,499 | | | | 1,740,881 | |
Notes 1 to 23 are an integral part of the Consolidated Financial Statements
| | Share capital | | | Share premium | | | Capital reserves | | | Other reserves | | | Accumulated currency translation differences | | | Accumulated deficit
| | | Total equity attributable to the Company | | | Non- controlling interest | | | Total equity | | | Share capital | | | Share premium | | | Capital reserves | | | Other reserves | | | Accumulated currency translation differences | | | Accumulated deficit
| | | Total equity attributable to the Company | | | Non- controlling interest | | | Total equity | |
Balance as of January 1, 2020 | | | 10,160 | | | | 1,011,743 | | | | 889,057 | | | | 73,797 | | | | (90,824 | ) | | | (385,457 | ) | | | 1,508,476 | | | | 206,380 | | | | 1,714,856 | | |
Balance as of January 1, 2021 | | | | 10,667 | | | | 1,011,743 | | | | 881,745 | | | | 96,641 | | | | (99,925 | ) | | | (373,489 | ) | | | 1,527,382 | | | | 213,499 | | | | 1,740,881 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Profit for the year after taxes | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 11,968 | | | | 11,968 | | | | 4,906 | | | | 16,874 | | |
Change in fair value of cash flow hedges | | | 0 | | | | 0 | | | | 0 | | | | 31,353 | | | | 0 | | | | 0 | | | | 31,353 | | | | 756 | | | | 32,109 | | |
Profit/(Loss) for the year after taxes | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (30,080 | ) | | | (30,080 | ) | | | 19,162 | | | | (10,918 | ) |
Change in fair value of cash flow hedges net of transfer to income statement
| | | | - | | | | - | | | | - | | | | 97,421 | | | | - | | | | (10,060 | ) | | | 87,361 | | | | 4,777 | | | | 92,138 | |
Currency translation differences | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (9,101 | ) | | | 0 | | | | (9,101 | ) | | | (846 | ) | | | (9,947 | ) | | | - | | | | - | | | | - | | | | - | | | | (33,525 | ) | | | - | | | | (33,525 | ) | | | (8,431 | ) | | | (41,956 | ) |
Tax effect | | | 0 | | | | 0 | | | | 0 | | | | (8,509 | ) | | | 0 | | | | 0 | | | | (8,509 | ) | | | (189 | ) | | | (8,698 | ) | | | - | | | | - | | | | - | | | | (22,790 | ) | | | - | | | | - | | | | (22,790 | ) | | | (922 | ) | | | (23,712 | ) |
Other comprehensive income | | | 0 | | | | 0 | | | | 0 | | | | 22,844 | | | | (9,101 | ) | | | 0 | | | | 13,743 | | | | (279 | ) | | | 13,464 | | | | - | | | | - | | | | - | | | | 74,631 | | | | (33,525 | ) | | | (10,060 | ) | | | 31,046 | | | | (4,576 | ) | | | 26,470 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | 0 | | | | 0 | | | | 0 | | | | 22,844 | | | | (9,101 | ) | | | 11,968 | | | | 25,711 | | | | 4,627 | | | | 30,338 | | | | - | | | | - | | | | - | | | | 74,631 | | | | (33,525 | ) | | | (40,140 | ) | | | 966 | | | | 14,586 | | | | 15,552 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital increase (Note 13) | | | 507 | | | | 0 | | | | 161,347 | | | | 0 | | | | 0 | | | | 0 | | | | 161,854 | | | | 0 | | | | 161,854 | | | | 573 | | | | 60,268 | | | | 128,920 | | | | - | | | | - | | | | - | | | | 189,761 | | | | - | | | | 189,761 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Reduction of Share Premium (Note 13)
| | | | - | | | | (200,000 | ) | | | 200,000 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Business combinations (Note 5) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 25,308 | | | | 25,308 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 8,287 | | | | 8,287 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Share-based compensation (Note 13) | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 14,928 | | | | 14,928 | | | | - | | | | 14,928 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Distributions (Note 13) | | | 0 | | | | 0 | | | | (168,659 | ) | | | 0 | | | | 0 | | | | 0 | | | | (168,659 | ) | | | (22,816 | ) | | | (191,475 | ) | | | - | | | | - | | | | (190,638 | ) | | | - | | | | - | | | | - | | | | (190,638 | ) | | | (30,166 | ) | | | (220,804 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of December 31, 2020 | | | 10,667 | | | | 1,011,743 | | | | 881,745 | | | | 96,641 | | | | (99,925 | ) | | | (373,489 | ) | | | 1,527,382 | | | | 213,499
| | | | 1,740,881 | | |
Balance as of December 31, 2021 | | | | 11,240 | | | | 872,011 | | | | 1,020,027 | | | | 171,272 | | | | (133,450 | ) | | | (398,701 | ) | | | 1,542,399 | | | | 206,206
| | | | 1,748,605 | |
Notes 1 to 23 are an integral part of the Consolidated Financial Statements
| | Share capital | | | Share premium | | | Capital reserves | | | Other reserves | | | Accumulated currency translation differences | | | Accumulated deficit
| | | Total equity attributable to the Company | | | Non- controlling interest | | | Total equity | | | Share capital | | | Share premium | | | Capital reserves | | | Other reserves | | | Accumulated currency translation differences | | | Accumulated deficit
| | | Total equity attributable to the Company | | | Non- controlling interest | | | Total equity | |
Balance as of January 1, 2021 | | | 10,667 | | | | 1,011,743 | | | | 881,745 | | | | 96,641 | | | | (99,925 | ) | | | (373,489 | ) | | | 1,527,382 | | | | 213,499 | | | | 1,740,881 | | |
Balance as of January 1, 2022 | | | | 11,240 | | | | 872,011 | | | | 1,020,027 | | | | 171,272 | | | | (133,450 | ) | | | (398,701 | ) | | | 1,542,399 | | | | 206,206 | | | | 1,748,605 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Profit/(Loss) for the year after taxes | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (30,080 | ) | | | (30,080 | ) | | | 19,162 | | | | (10,918 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (5,443 | ) | | | (5,443 | ) | | | 3,356 | | | | (2,087 | ) |
Change in fair value of cash flow hedges | | | 0 | | | | 0 | | | | 0 | | | | 97,421 | | | | 0 | | | | (10,060 | ) | | | 87,361 | | | | 4,777 | | | | 92,138 | | |
Change in fair value of cash flow hedges net of transfer to income statement
| | | | - | | | | - | | | | - | | | | 235,732 | | | | - | | | | 1,573 | | | | 237,305 | | | | 19,619 | | | | 256,924 | |
Currency translation differences | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (33,525 | ) | | | 0 | | | | (33,525 | ) | | | (8,431 | ) | | | (41,956 | ) | | | - | | | | - | | | | - | | | | - | | | | (27,857 | ) | | | - | | | | (27,857 | ) | | | (5,847 | ) | | | (33,704 | ) |
Tax effect | | | 0 | | | | 0 | | | | 0 | | | | (22,790 | ) | | | 0 | | | | 0 | | | | (22,790 | ) | | | (922 | ) | | | (23,712 | ) | | | - | | | | - | | | | - | | | | (61,437 | ) | | | - | | | | - | | | | (61,437 | ) | | | (2,515 | ) | | | (63,952 | ) |
Other comprehensive income | | | 0 | | | | 0 | | | | 0 | | | | 74,631 | | | | (33,525 | ) | | | (10,060 | ) | | | 31,046 | | | | (4,576 | ) | | | 26,470 | | | | - | | | | - | | | | - | | | | 174,295 | | | | (27,857 | ) | | | 1,573 | | | | 148,011 | | | | 11,257 | | | | 159,268 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total comprehensive income | | | 0 | | | | 0 | | | | 0 | | | | 74,631 | | | | (33,525 | ) | | | (40,140 | ) | | | 966 | | | | 14,586 | | | | 15,552 | | | | - | | | | - | | | | - | | | | 174,295 | | | | (27,857 | ) | | | (3,870 | ) | | | 142,568 | | | | 14,613 | | | | 157,181 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital increase (Note 13) | | | 573 | | | | 60,268 | | | | 128,920 | | | | 0 | | | | 0 | | | | 0 | | | | 189,761 | | | | 0 | | | | 189,761 | | | | 366 | | | | 114,583 | | | | (1,970 | ) | | | - | | | | - | | | | - | | | | 112,979 | | | | - | | | | 112,979 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Reduction of Share Premium (Note 13) | | | 0 | | | | (200,000 | ) | | | 200,000 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Business combinations (Note 5) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 8,287 | | | | 8,287 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 14,300 | | | | 14,300 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Share-based compensation (Note 13) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 14,928 | | | | 14,928 | | | | 0 | | | | 14,928 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 5,031 | | | | 5,031 | | | | - | | | | 5,031 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Distributions (Note 13) | | | 0 | | | | 0 | | | | (190,638 | ) | | | 0 | | | | 0 | | | | 0 | | | | (190,638 | ) | | | (30,166 | ) | | | (220,804 | ) | | | - | | | | - | | | | (203,106 | ) | | | - | | | | - | | | | - | | | | (203,106 | ) | | | (45,943 | ) | | | (249,049 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of December 31, 2021 | | | 11,240 | | | | 872,011 | | | | 1,020,027 | | | | 171,272 | | | | (133,450 | ) | | | (398,701 | ) | | | 1,542,399 | | | | 206,206 | | | | 1,748,605 | | |
Balance as of December 31, 2022 | | | | 11,606 | | | | 986,594 | | | | 814,951 | | | | 345,567 | | | | (161,307 | ) | | | (397,540 | ) | | | 1,599,871 | | | | 189,176 | | | | 1,789,047 | |
Notes 1 to 23 are an integral part of the Consolidated Financial Statements
Consolidated cash flow statements for the years ended December 31,
2022, 2021
2020 and
20192020
Amounts in thousands of U.S. dollars
| | | | | For the year ended | | | | | | For the year
| |
| | Note (1) | | | 2021
| | | 2020
| | | 2019 | | | Note (1) | | | 2022
| | | 2021
| | | 2020 | |
I. Profit/(loss) for the year | | | | | | (10,918 | ) | | | 16,874 | | | | 74,608 | | | | | | | (2,087 | ) | | | (10,918 | ) | | | 16,874 | |
Non-monetary adjustments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Depreciation, amortization and impairment charges | | | 6 | | | | 439,441 | | | | 408,604 | | | | 310,755 | | | | 6 | | | | 473,638 | | | | 439,441 | | | | 408,604 | |
Financial (income)/expenses | | | 21 | | | | 359,550 | | | | 315,151 | | | | 405,634 | | |
Financial expense | | | | 21 | | | | 335,546 | | | | 359,550 | | | | 315,151 | |
Fair value (gains)/losses on derivative financial instruments | | | 21 | | | | (16,785 | ) | | | 15,308 | | | | (613 | ) | | | 21 | | | | (19,138 | ) | | | (16,785 | ) | | | 15,308 | |
Shares of (profits)/losses from associates | | | 7 | | | | (12,304 | ) | | | (510 | ) | | | (7,457 | ) | |
Shares of profits from entities carried under the equity method | | | | 7 | | | | (21,465 | ) | | | (12,304 | ) | | | (510 | ) |
Income tax | | | 18 | | | | 36,220 | | | | 24,877 | | | | 30,950 | | | | 18 | | | | (9,689 | ) | | | 36,220 | | | | 24,877 | |
Other non-monetary items | | | | | | | 55,809 | | | | (43,943 | ) | | | (25,800 | ) | | | | | | | 27,996 | | | | 55,809 | | | | (43,943 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
II. Profit/(loss) for the year adjusted by non-monetary items | | | | | | | 851,013 | | | | 736,361 | | | | 788,077 | | | | | | | | 784,801 | | | | 851,013 | | | | 736,361 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Changes in working capital | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Inventories | | | | | | | 5,215 | | | | (4,590 | ) | | | (1,343 | ) | | | | | | | (6,955 | ) | | | 5,215 | | | | (4,590 | ) |
Trade and other receivables | | | 11 | | | | 48,521 | | | | (790 | ) | | | (71,505 | ) | | | 11 | | | | 99,249 | | | | 48,521 | | | | (790 | ) |
Trade payables and other current liabilities | | | 17 | | | | (25,782 | ) | | | (9,771 | ) | | | (36,533 | ) | | | 17 | | | | (6,158 | ) | | | (25,782 | ) | | | (9,771 | ) |
Financial investments and other current assets/liabilities | | | | | | | (31,081 | ) | | | 4,249 | | | | (15,602 | ) | |
Other current assets/liabilities | | | | | | | | (7,331 | ) | | | (31,081 | ) | | | 4,249 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
III. Changes in working capital | | | | | | | (3,127 | ) | | | (10,902 | ) | | | (124,983 | ) | | | | | | | 78,805 | | | | (3,127 | ) | | | (10,902 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Income tax received/(paid) | | | | | | | (51,684 | ) | | | (16,425 | ) | | | (23 | ) | |
Income tax paid | | | | | | | | (14,730 | ) | | | (51,684 | ) | | | (16,425 | ) |
Interest received | | | | | | | 2,519 | | | | 5,148 | | | | 10,135 | | | | | | | | 9,178 | | | | 2,519 | | | | 5,148 | |
Interest paid | | | | | | | (293,098 | ) | | | (275,961 | ) | | | (309,625 | ) | | | | | | | (271,732 | ) | | | (293,098 | ) | | | (275,961 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
A. Net cash provided by operating activities | | | | | | | 505,623 | | | | 438,221 | | | | 363,581 | | | | | | | | 586,322 | | | | 505,623 | | | | 438,221 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Acquisitions of subsidiaries and entities under the equity method | | | 5&7 | | | | (362,449 | ) | | | 2,453 | | | | (173,366 | ) | | | 5&7 | | | | (50,507 | ) | | | (362,449 | ) | | | 2,453 | |
Investments in contracted concessional assets* | | | 6 | | | | (24,682 | ) | | | (1,361 | ) | | | 22,009 | | |
Investments in operating concessional assets | | | | 6 | | | | (39,107 | ) | | | (19,216 | ) | | | (1,361 | ) |
Investments in assets under development or construction | | | | 6
| | | | (36,784 | ) | | | (7,028 | ) | | | (3,023 | ) |
Distributions from entities under the equity method | | | 7 | | | | 34,883 | | | | 22,246 | | | | 30,443 | | | | 7 | | | | 67,695 | | | | 34,883 | | | | 22,246 | |
Other non-current assets/liabilities | | | | | | | 1,093 | | | | (29,198 | ) | | | 2,703 | | |
Other non-current assets | | | | | | | | 1,265 | | | | 2,655 | | | | (26,175 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
B. Net cash used in investing activities | | | | | | | (351,155 | ) | | | (5,860 | ) | | | (118,211 | ) | | | | | | | (57,438 | ) | | | (351,155 | ) | | | (5,860 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Proceeds from project debt | | | 15 | | | | 14,560 | | | | 603,949 | | | | 5,860 | | | | 15 | | | | - | | | | 14,560 | | | | 603,949 | |
Proceeds from corporate debt | | | 14 | | | | 429,014 | | | | 678,651 | �� | | | 352,966 | | | | 14 | | | | 101,140 | | | | 429,014 | | | | 678,651 | |
Repayment of project debt | | | 15 | | | | (418,265 | ) | | | (621,691 | ) | | | (282,255 | ) | | | 15 | | | | (426,396 | ) | | | (418,265 | ) | | | (621,691 | ) |
Repayment of corporate debt | | | 14 | | | | (376,154 | ) | | | (502,042 | ) | | | (320,815 | ) | | | 14 | | | | (80,519 | ) | | | (376,154 | ) | | | (502,042 | ) |
Dividends paid to Company´s shareholders | | | 13 | | | | (190,638 | ) | | | (168,659 | ) | | | (159,002 | ) | | | 13 | | | | (203,106 | ) | | | (190,638 | ) | | | (168,659 | ) |
Dividends paid to non-controlling interest | | | 13 | | | | (28,134 | ) | | | (22,944 | ) | | | (29,239 | ) | | | 13 | | | | (39,209 | ) | | | (28,134 | ) | | | (22,944 | ) |
Purchase of Liberty´s Interactive's equity interests in Solana | | | 1 | | | | 0 | | | | (266,850 | ) | | | 0 | | |
Non-controlling interest capital contribution | | |
| | | | 0 | | | | 0 | | | | 92,303 | | |
Purchase of Liberty´s Interactive’s equity interests in Solana | | | | 21 | | | | - | | | | - | | | | (266,850 | ) |
Capital increase | | | 13 | | | | 189,454 | | | | 162,246 | | | | 30,000 | | | | 13 | | | | 113,072 | | | | 189,454 | | | | 162,246 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
C. Net cash used in financing activities | | | | | | | (380,163 | ) | | | (137,340 | ) | | | (310,182 | ) | | | | | | | (535,018 | ) | | | (380,163 | ) | | | (137,340 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net increase/(decrease) in cash and cash equivalents | | | | | | | (225,695 | ) | | | 295,021 | | | | (64,812 | ) | | | | | | | (6,134 | ) | | | (225,695 | ) | | | 295,021 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents at beginning of the year | | | 12 | | | | 868,501 | | | | 562,795 | | | | 631,542 | | | | 12 | | | | 622,689 | | | | 868,501 | | | | 562,795 | |
Translation differences in cash and cash equivalents | | | | | | | (20,117 | ) | | | 10,685 | | | | (3,935 | ) | | | | | | | (15,565 | ) | | | (20,117 | ) | | | 10,685 | |
Cash and cash equivalents at the end of the year | | | 12 | | | | 622,689
| | | | 868,501
| | | | 562,795
| | | | 12 | | | | 600,990
| | | | 622,689
| | | | 868,501
| |
* | Includes proceeds for $20.5 million, $7.4 million, and $22.2 million in 2021, 2020 and 2019 respectively (Note 6).
|
(1)
| Notes 1 to 23 are an integral part of the Consolidated Financial StatementsStatements. Reference to such notes is indicated here to provide with additional information on the nature of some of the lines of the Consolidated cash flow statement. |
Note 1.- Nature of the business | F-12F-13 |
| |
Note 2.- Significant accounting policies | F-16 |
| |
Note 3.- Financial risk management | F-28F-27
|
| |
Note 4.- Financial information by segment | F-29F-28 |
| |
Note 5.- Business combinations | F-34F-33 |
| |
Note 6.- Contracted concessional, PP&E and other intangible assets | F-36F-35 |
| |
Note 7.- Investments carried under the equity method | F-40F-38 |
| |
Note 8.- Financial instruments by category | F-42F-40 |
| |
Note 9.- Derivative financial instruments | F-43F-41 |
| |
Note 10.- Related parties | F-45F-43 |
| |
Note 11.- Trade and other receivables | F-46F-44 |
| |
Note 12.- Cash and cash equivalents | F-46F-44 |
| |
Note 13.- Equity | F-47F-45 |
| |
Note 14.- Corporate debt | F-48F-46 |
| |
Note 15.- Project debt | F-50F-48 |
| |
Note 16.- Grants and other liabilities | F-53F-51 |
| |
Note 17.-Trade payables and other current liabilities | F-54F-52 |
| |
Note 18.- Income tax | F-54F-52 |
| |
Note 19.- Commitments, third-party guarantees, contingent assets and liabilities | F-57F-55 |
| |
Note 20.- Employee benefit expenses and other operating income and expenses | F-58F-56 |
| |
Note 21.- Financial expense, net | F-59F-57 |
| |
Note 22.- Earnings per share | F-60F-58 |
| |
Note 23.- Other information | F-61F-59 |
| |
Appendices(1) | F-62F-60 |
(1) The Appendices are an integral part of the notes to the consolidated financial statements
Note 1.- Nature of the business
Atlantica Sustainable Infrastructure plc (“Atlantica” or the “Company”) is a sustainable infrastructure company with a majority of its business in renewable energy assets. Atlantica currently owns, manages and invests in renewable energy, storage, efficient natural gas and heat, electric transmission lines and water assets focused on North America (the United States, Canada and Mexico), South America (Peru, Chile, Colombia and Uruguay) and EMEA (Spain, Italy, Algeria and South Africa).
Atlantica’s shares trade on the NASDAQ Global Select Market under the symbol “AY”.
Algonquin Power & Utilities Corp.On January 17, 2022, the Company closed the acquisition of Chile TL4, a 63-mile transmission line and 2 substations in Chile for a total equity investment of $38.4 million (Note 5). The Company expects to expand the transmission line in 2023-2024, which would represent an additional investment of approximately $8 million. The asset has fully contracted revenues in US dollars, with annual inflation adjustments and a 50-year remaining contract life. The off-takers are several mini-hydro plants that receive contracted or regulated payments.
On April 4, 2022, the Company closed the acquisition of Italy PV 4, a 3.6 MW solar portfolio in Italy for a total equity investment of $3.7 million (Note 5). The asset has regulated revenues under a feed in tariff until 2031.
On September 2, 2022, the Company completed its third investment through its Chilean renewable energy platform in a 73 MW solar PV plant, Chile PV 3, located in Chile, for $7.7 million corresponding to a 35% of equity interest (Note 5). The Company expects to install batteries with a capacity of approximately 100 MWh in 2023-2024. Total investment including batteries is expected to be in the range of $15 million to $25 million depending on the capital structure. Part of the asset’s revenue is currently based on capacity payments. Adding storage would increase the portion of capacity payments.
On November 16, 2022, the Company closed the acquisition of a 49% interest, with joint control, in an 80 MW portfolio of solar PV projects in Chile, Chile PMGD, which is currently starting construction. Atlantica´s economic rights are expected to be approximately 70%. Total investment in equity and preferred equity is expected to be approximately $30 million and Commercial Operation Date (“Algonquin”COD”) is expected to be progressive in 2023 and 2024. Revenue for these assets is regulated under the largest shareholder of the Company and ownsSmall Distributed Generation Means Regulation Regime (“PMGD”) for projects with a 43.6%stake in Atlantica as of December 31, 2021. Algonquin’s voting rights and rightscapacity equal or lower than 9MW, which allows to appoint directors are limited to 41.5% and the difference between Algonquin´s ownership and 41.5% will vote replicating non-Algonquin’s shareholderssell electricity through a stabilized price’. vote.
During the year 2020,2021, the Company completed the following investments:
- | In 2021, the Company closed the acquisition in two stages of the 85% equity interest in Rioglass Solar Holding S.A. (“Rioglass”) that it did not previously own for a total investment of $17.1 million, resulting in a 100% ownership (Note 5). Rioglass is a supplier of spare parts and services in the solar industry and the Company gained control over the asset in January 2021. |
- | On April 3, 2020, the Company made an initial investment in the creation of a renewable energy platform in Chile, together with financial partners, where it owns an approximately 35% stake and has a strategic investor role. The first investment was the acquisition of a 55 MW solar PV plant (“Chile PV 1”). The Company’s initial contribution was approximately $4 million. In addition, on January 6, 2021, the Company closed its second investment through theits Chilean renewable energy platform with the acquisition ofin a 40 MW solar PV plant, (“Chile PV 2”). The total equity investment for this new asset was approximately $5.0 million. The platform intends to make further investments in renewable energy2, located in Chile, and sign Power Purchase Agreements (“PPAs” ) with credit worthy off-takers.for $5.0 million corresponding to a 35% of equity interest. |
- | In January 2019, the Company entered into an agreement with Abengoa (references to “Abengoa” refer to Abengoa, S.A., together with its subsidiaries, or Abenewco1, S.A. together with its subsidiaries, unless the context otherwise requires) for the acquisition of a 51% stake in Tenes, a water desalination plant in Algeria. Closing of the acquisition was subject to certain conditions precedent, which were not fulfilled. On May 31, 2020, the Company entered into a new agreement, which provided the Company with certain additional decision rights, including the right to appoint the majority of directors of the board of Befesa Agua Tenes, and therefore controls the asset. |
- | On August 17, 2020,April 7, 2021, the Company closed the acquisition of Liberty Interactive’s equity interest in Solana. Liberty Interactive was the tax equity investorCoso, a 135 MW geothermal plant in the Solana project.United States with 18-year average contract life Power Purchase Agreements (“PPAs”) in place. The total equity investment is expected to be up to $285 million of which $272 million has already been paid. |
In January 2021 the Company closed the acquisition of 42.5% of the equity of Rioglass Solar Holding S.A. (“Rioglass”) a supplier of spare parts and services to the solar industry, increasing its stake to 57.5%. In addition, on July 22, 2021 the Company exercised the option to acquire the remaining stake of 42.5%. The investment made in 2021 to acquire the additional 85% equity, resulting in a 100% ownership, was approximately $17.1was $130 million (Note 5). In addition, on July 15, 2021, the Company repaid $40 million to reduce project debt.
On April 7, 2021, the Company closed the acquisition of Coso, a 135 MW renewable asset in California. Coso is the third largest geothermal plant in the United States and provides base load renewable energy to the California Independent System Operator (California ISO). It has PPAs signed with an 18-year average contract life. The total equity investment was approximately $130 million (Note 5). In addition, on July 15, 2021, the Company repaid $40 million of project debt.- | On May 14, 2021, the Company closed the acquisition of Calgary District Heating, a district heating asset in Canada for a total equity investment of $22.9 million (Note 5). The asset has availability-based revenue with inflation indexation and 20 years of weighted average contract life at the time of the acquisition. |
On May 14, 2021, the Company closed the acquisition of Calgary District Heating, a district heating asset of approximately 55 MWt in Canada for a total equity investment of approximately $22.7 million (Note 5). Calgary District Heating has been in operation since 2010 and provides heating services to a diverse range of government, institutional and commercial customers in the city of Calgary.- | On June 16, 2021, the Company acquired a 49% interest in Vento II, a 596 MW wind portfolio in the United States for a total equity investment net of cash consolidated at the transaction date of approximately $180.7 million (Note 7). EDP Renewables owns the remaining 51%. The assets have PPAs with investment grade off-takers with a five-year average remaining contract life at the time of the investment. |
- | On August 6, 2021, the Company closed the acquisition of Italy PV 1 and Italy PV 2, two solar PV plants in Italy with a combined capacity of 3.7 MW for a total equity investment of $9 million (Note 5). On December 14, 2021, the Company closed the acquisition of Italy PV 3, a 2.5 MW solar PV portfolio in Italy for a total equity investment of $4 million (Note 5). These assets have regulated revenues under a feed in tariff until 2030, 2031 and 2032, respectively. |
- | On November 25, 2021, the Company closed the acquisition of La Sierpe, a 20 MW solar PV plant in Colombia for a total equity investment of $23.5 million (Note 5). The asset was acquired under a Right of First Offer (“ROFO”) agreement with Liberty GES. |
On June 16, 2021,In addition, the following three assets that the Company acquired a 49% interest in a 596 MW portfolio of wind assets in the United States (Vento II) for a total equity investment net of cash consolidated at the transaction date of approximately $180.7 million (Note 7). EDP Renewables owns the remaining 51%. The assets have PPAs with investment grade off-takers with five-year average remaining contract life at the time of the investment.had under construction during 2022, finished construction and reached or are about to reach COD:
On August 6, 2021, the Company closed the acquisition of Italy PV 1 and Italy PV 2, two solar PV plants in Italy with a combined capacity of 3.7 MW for a total equity investment of $9 million (Note 5). Italy PV 1 and Italy PV 2 have regulated revenues under a feed in tariff until 2030 and 2031, respectively.- | Albisu, a 10 MW PV asset wholly owned by the Company reached COD in January 2023. Albisu is located in the city of Salto (Uruguay). The asset has a 15-year PPA with Montevideo Refrescos, S.R.L, a subsidiary of Coca-Cola Femsa., S.A.B. de C.V. The PPA is denominated in local currency with a maximum and minimum price in U.S. dollars and is adjusted monthly based on a formula referring to U.S. Producer Price Index (PPI), Uruguay’s Consumer Price Index (CPI) and the applicable UYU/U.S. dollar exchange rate. |
On November 25, 2021, the Company closed the acquisition of La Sierpe, a 20 MW solar PV plant in Colombia for a total equity investment of approximately $23.5 million. The asset was acquired under a Right of First Offer (“ROFO”) agreement with Liberty GES. The Company also acquired 2 additional solar projects in Colombia which are currently in construction with a combined capacity of approximately 30 MW, La Tolua and Tierra Linda.
On December 14, 2021, the Company closed the acquisition of Italy PV 3, a 2.5 MW solar PV portfolio in Italy for a total equity investment of approximately $4 million. Italy PV 3 has regulated revenues under a feed in tariff until 2032.- | La Tolua and Tierra Linda, two solar PV assets in Colombia with a combined capacity of 30 MW. Each plant has a 10-year PPA in local currency indexed to local inflation with Coenersa, the largest independent electricity wholesaler in Colombia. Additionally, the Company has recently started the construction of three additional PV plants with a total capacity of 30 MW. |
The following table provides an overview of the main contracted concessionaloperating assets the Company owned or had an interest in as of December 31, 2021:2022:
Assets | Type | Ownership | Location | Currency(9) | Capacity (Gross) | Counterparty Credit Ratings(10) | COD* | Contract Years Remaining(16) | 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 | 22 | Renewable (Solar) | 100% | Arizona (USA) | USD | 280 MW | BBB+/A3/BBB+ | 2013 | 21 |
| | | | | | | | | |
Mojave | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB-/ -- /BB | 2014 | 18 | Renewable (Solar) | 100% | California (USA) | USD | 280 MW | BB-/ -- /BB | 2014 | 17 |
| | | | | | | | | |
Coso | Renewable (Geothermal) | 100% | California (USA) | USD | 135 MW | Investment Grade(11) | 1987-1989 | 17 | Renewable (Geothermal) | 100% | California (USA) | USD | 135 MW | Investment Grade(11) | 1987-1989 | 16 |
| | | | | | | | | |
Elkhorn Valley | Renewable (Wind) | 49% | Oregon (USA) | USD | 101 MW | BBB/A3/-- | 2007 | 6 | |
| | | | | | | | | |
Prairie Star | Renewable (Wind) | 49% | Minnesota (USA) | USD | 101 MW | --/A3/A- | 2007 | 6 | |
| | | | | | | | | |
Twin Groves II | Renewable (Wind) | 49% | Illinois (USA) | USD | 198 MW | BBB-/Baa2/-- | 2008 | 4 | |
| | | | | | | | | |
Lone Star II | Renewable (Wind) | 49% | Texas (USA) | USD | 196 MW | Not rated | 2008 | 1 | |
| | | | | | | | | |
Elkhorn Valley(16) | | Renewable (Wind) | 49% | Oregon (USA) | USD | 101 MW | BBB/Baa1/-- | 2007 | 5 |
Prairie Star(16) | | Renewable (Wind) | 49% | Minnesota (USA) | USD | 101 MW | --/A3/A- | 2007 | 5 |
Twin Groves II(16) | | Renewable (Wind) | 49% | Illinois (USA) | USD | 198 MW | BBB/Baa2/-- | 2008 | 3 |
Lone Star II(16) | | Renewable (Wind) | 49% | Texas (USA) | USD | 196 MW | N/A | 2008 | N/A |
Chile PV 1
| Renewable (Solar) | 35%(1) | Chile | USD | 55 MW | N/A | 2016 | N/A | 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 | 9 | Renewable (Solar) | 35%(1) | Chile | USD | 40 MW | Not rated | 2017 | 8 |
| | | | | | | | | |
Chile PV 3 | | Renewable (Solar) | 35%(1) | Chile | USD | 73 MW | N/A | 2014 | N/A |
La Sierpe | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2021
| 14 | Renewable (Solar) | 100% | Colombia | COP | 20 MW | Not rated | 2021 | 13 |
| | | | | | | | | |
Palmatir | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014
| 12
| Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 11 |
| | | | | | | | | |
Cadonal | Renewable (Wind)
| 100%
| Uruguay
| USD
| 50 MW
| BBB/Baa2/BBB-(12) | 2014 | 13 | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB-(12) | 2014 | 12 |
| | | | | | | | | |
Melowind | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB- | 2015 | 14 | Renewable (Wind) | 100% | Uruguay | USD | 50 MW | BBB/Baa2/BBB- | 2015 | 13 |
| | | | | | | | | |
Mini-Hydro | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB+/Baa1/BBB | 2012 | 11 | Renewable (Hydraulic) | 100% | Peru | USD | 4 MW | BBB/Baa1/BBB | 2012 | 10 |
| | | | | | | | | |
Solaben 2 & 3 | Renewable (Solar) | 70%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 16/16 | Renewable (Solar) | 70%(2) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 15/15 |
| | | | | | | | | |
Solacor 1 & 2 | Renewable (Solar) | 87%(3) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 15/15 | Renewable (Solar) | 87%(3) | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 14/14 |
| | | | | | | | | |
PS10 & PS20 | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007&2009 | 10/12 | Renewable (Solar) | 100% | Spain | Euro | 31 MW | A/Baa1/A- | 2007&2009 | 9/11 |
Helioenergy 1 & 2 | | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 14/14 |
Helios 1 & 2 | | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 14/15 |
Solnova 1, 3 & 4 | | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 12/12/13 |
Solaben 1 & 6 | | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 16/16 |
Seville PV | | Renewable (Solar) | 80%(4) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 13 |
Italy PV 1 | | Renewable (Solar) | 100% | Italy | Euro | 1.6 MW | BBB/Baa3/BBB | 2010 | 8 |
Italy PV 2 | | Renewable (Solar) | 100% | Italy | Euro | 2.1 MW | BBB/Baa3/BBB | 2011 | 8 |
Italy PV 3 | | Renewable (Solar) | 100% | Italy | Euro | 2.5 MW | BBB/Baa3/BBB | 2012 | 9 |
Italy PV 4 | | Renewable (Solar) | 100% | Italy | Euro | 3.6 MW | BBB/Baa3/BBB | 2011 | 9 |
Kaxu | | Renewable (Solar) | 51%(5) | South Africa | Rand | 100 MW | BB-/Ba2/BB-(13) | 2015 | 12 |
Calgary | | Efficient natural gas &heat | 100% | Canada | CAD | 55 MWt | ~41% A+ or higher(14) | 2010 | 18 |
ACT | | Efficient natural gas & heat | 100% | Mexico | USD | 300 MW | BBB/B1/BB- | 2013 | 10 |
Monterrey | | Efficient natural gas &heat | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 23 |
ATN (15) | | Transmission line | 100% | Peru | USD | 379 miles | BBB/Baa1/BBB | 2011 | 18 |
ATS | | Transmission line | 100% | Peru | USD | 569 miles | BBB/Baa1/BBB | 2014 | 21 |
ATN 2 | | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 10 |
Quadra 1 & 2 | | Transmission line | 100% | Chile | USD | 49 miles/32 miles | Not rated | 2014 | 12/12 |
Palmucho | | Transmission line | 100% | Chile | USD | 6 miles | BBB/ -- /BBB+ | 2007 | 15 |
Chile TL3 | | Transmission line | 100% | Chile | USD | 50 miles | A/A2/A- | 1993 | N/A |
Chile TL4 | | Transmission line | 100% | Chile | USD | 63 miles | Not rated | 2016 | 49 |
Skikda | | Water | 34.20%(6) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 11 |
Honaine | | Water | 25.50%(7) | Algeria | USD | 7 M ft3/day | Not rated | 2012 | 15 |
Tenes | | Water | 51%(8) | Algeria | USD | 7 M ft3/day | Not rated | 2015 | 17 |
Helioenergy 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2011 | 15/15 |
| | | | | | | | |
Helios 1 & 2 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2012 | 15/16 |
Solnova 1, 3 & 4 | Renewable (Solar) | 100% | Spain | Euro | 3x50 MW | A/Baa1/A- | 2010 | 13/13/14 |
| | | | | | | | |
Solaben 1 & 6 | Renewable (Solar) | 100% | Spain | Euro | 2x50 MW | A/Baa1/A- | 2013 | 17/17 |
| | | | | | | | |
Seville PV | Renewable (Solar) | 80%(4) | Spain | Euro | 1 MW | A/Baa1/A- | 2006 | 14 |
| | | | | | | | |
Italy PV 1 | Renewable (Solar) | 100% | Italy | Euro | 1.6 MW | BBB/Baa3/BBB | 2010 | 9 |
| | | | | | | | |
Italy PV 2 | Renewable (Solar) | 100% | Italy | Euro | 2.1 MW | BBB/Baa3/BBB | 2011 | 9 |
| | | | | | | | |
Italy PV 3 | Renewable (Solar) | 100% | Italy | Euro | 2.5 MW | BBB/Baa3/BBB | 2012 | 10 |
| | | | | | | | |
Kaxu | Renewable (Solar) | 51%(5) | South Africa | Rand | 100 MW | BB-/Ba2/BB-(13) | 2015 | 13 |
| | | | | | | | |
Calgary
| Efficient natural gas &heat | 100% | Canada | CAD | 55 MWt | ~41% A+ or higher(14) | 2010 | 19 |
| | | | | | | | |
ACT | Efficient natural gas & heat | 100% | Mexico | USD | 300 MW | BBB/ Ba3/BB- | 2013 | 11 |
| | | | | | | | |
Monterrey | Efficient natural gas &heat | 30% | Mexico | USD | 142 MW | Not rated | 2018 | 17 |
| | | | | | | | |
ATN (15) | Transmission line | 100% | Peru | USD | 379 miles | BBB+/Baa1/BBB | 2011 | 19 |
| | | | | | | | |
ATS | Transmission line | 100% | Peru | USD | 569 miles | BBB+/Baa1/BBB | 2014 | 22 |
| | | | | | | | |
ATN 2 | Transmission line | 100% | Peru | USD | 81 miles | Not rated | 2015 | 11 |
| | | | | | | | |
Quadra 1 & 2 | Transmission line | 100% | Chile | USD | 49 miles/32 miles | Not rated | 2014 | 13/13 |
| | | | | | | | |
Palmucho | Transmission line | 100% | Chile | USD | 6 miles | BBB/ -- /A- | 2007 | 16 |
| | | | | | | | |
Chile TL3 | Transmission line | 100% | Chile | USD | 50 miles | A/A1/A- | 1993 | Regulated |
| | | | | | | | |
Skikda | Water | 34.2%(6) | Algeria | USD | 3.5 M ft3/day | Not rated | 2009 | 12 |
| | | | | | | | |
Honaine | Water | 25.5%(7) | Algeria | USD | 7 M ft3/day | Not rated | 2012 | 16 |
| | | | | | | | |
Tenes | Water | 51%(8) | Algeria | USD | 7 M ft3/day | Not rated | 2015 | 18 |
(1) | 65% of the shares in Chile PV 1, Chile PV 2 and Chile PV 23 are indirectly held by financial partners through the renewable energy platform of the Company in Chile. |
(2) | Itochu Corporation holds 30% of the shares in each of Solaben 2 and Solaben 3. |
(3) | JGC holds 13% of the shares in each of Solacor 1 and Solacor 2. |
(4) | Instituto para la Diversificación y Ahorro de la Energía (“Idae”) holds 20% of the shares in Seville PV. |
(5) | Kaxu is owned by the Company (51%), Industrial Development Corporation of South Africa (29%(“IDC”, 29%) and Kaxu Community Trust (20%). |
(6) | Algerian Energy Company, SPA owns 49% of Skikda and Sacyr Agua, S.L. owns the remaining 16.8%. |
(7) | Algerian Energy Company, SPA owns 49% of Honaine and Sacyr Agua, S.L. owns the remaining 25.5%. |
(8) | Algerian Energy Company, SPA owns 49% of Tenes. The Company has an investment in Tenes through a secured loan to Befesa Agua Tenes (the holding company of Tenes) and the right to appoint a majority at the board of directors of the project company. Therefore, the Company controls Tenes since May 31, 2020, and fully consolidates the asset from that date. |
(9) | Certain contracts denominated in U.S. dollars are payable in local currency. |
(10) | Reflects the counterparty’s credit ratings issued by Standard & Poor’s Ratings Services, or S&P, Moody’s Investors Service Inc., or Moody’s, and Fitch Ratings Ltd, or Fitch. Not applicable (“N/A”) when the asset has no PPA. |
(11) | Refers to the credit rating of two Community Choice Aggregators: Silicon Valley Clean Energy and Monterrey Bar Community Power, both with A Rating from S&P and Southern California Public Power Authority. The third off-taker is not rated. |
(12) | Refers to the credit rating of Uruguay, as UTE (Administración Nacional de Usinas y Transmisoras Eléctricas) is unrated. |
(13) | Refers to the credit rating of the Republic of South Africa. The off-taker is Eskom, which is a state-owned utility company in South Africa. |
(14) | Refers to the credit rating of a diversified mix of 22 high credit quality clients (~41% A+ rating or higher, the rest is unrated). |
(15) | Including ATN Expansion 1 & 2. |
(16) | Part of Vento II Portfolio. |
(17) | As of December 31, 2021.2022.
|
(*) | Commercial Operation Date. |
The Kaxu project financing arrangement containsfor Kaxu contained a cross-default provisionsprovision related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. TheS.A.’s insolvency filing by the individual company Abengoa S.A. in February 2021 represents a theoretical event of default under the Kaxu project finance agreement.filing. In September 2021, the Company obtained a waiver for such theoretical eventcross-default which became effective on March 31, 2022, following the transfer of default which was conditional upon the replacement of the operation and maintenance supplier of the plant. On February 1, 2022, the Company transferred the employees performing the operation and maintenance servicesO&M in Kaxu from an Abengoa subsidiary to an Atlantica subsidiary. The waiver has been extended until April 30,subsidiary and other conditions. As a result, as of March 31, 2022, and is subject to the lenders receiving certain documentation from the Company including formal evidence of the approval by the client and the department of energy of South Africa of the operation and maintenance internalization and the Company is currently working on obtaining such documentation. Although the Company does not expect the acceleration of debt to be declared by the credit entities, as of December 31, 2021 Kaxu did not have what International Accounting Standards define ashad again an unconditional right to defer the settlement of the debt for at least twelve months, asand therefore the cross-default provisions make that right conditional. Therefore, Kaxu total debt (Note 15) has beenpreviously presented as current (as of December 31, 2021) had been reclassified as non-current at that date in accordance with the financing agreements in these Consolidated Financial Statements (Note 15).
As expected in 2022, the Administration in Spain approved, measures to adjust the regulated revenue component for renewable energy plants, following the increase since mid-2021 in the billings of these plants for the sale of electricity in the market. On March 30, 2022, 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 gas and electricity prices. It includes temporary changes to the detailed regulated components of revenue received by the solar assets of the Company in Spain, which are applicable from January 1, 2022. Specifically, prior to the entry into force of this new regulation, 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. Now, under article 5 of Royal Decree Law 6/2022, an extraordinary measure has been taken to subdivide the current regulatory semi-period, so as ofto create a new semi-period between January 1, 2022 and December 31, 20212022 and the remuneration will be reviewed taking into account the future prices of OMIP (Regulated market operator in Spain), too. On May 14, 2022, the Royal Decree Law 10/2022 was published, including the so-called “Iberian mechanism”, which is the temporary production cost adjustment mechanism for an amountreducing the price of $315 million,electricity in accordance with International Accounting Standards 1 (“IAS 1”), “Presentation of Financial Statements”.
Outbreak of COVID-19
the wholesale market. The outbreak of the COVID-19 coronavirus disease (“COVID-19”) was declared a pandemicmain changes included by the World Health Organization in March 2020 and continues to spread in key markets of the Company.
these regulations are:
Main risks and uncertainties identified by the Company, which may affect its business, financial condition, results of operations and cash flows, are:
| - | COVID-19 can affect the operation and maintenance activities of the Company. The Company may experience delays in certain operation and maintenance activities, or certain activities may take longer than usual.
|
| - | The rapid increase in demand instatutory 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 afterand (2) calendar year 2022. As a result, the slowdown in 2020 caused tensionsfixed monthly payment based on installed capacity (Remuneration on Investment or Rinv) for calendar year 2022 has been revised in the supply chains, including delays to obtain some components and increased prices. If the Company was to experience a shortage of or inability to acquire critical spare parts, it could incur significant delays in returning facilities to full operation. Supply chain tensions may also affect its projects in development and construction where the Company can experience delays or an increase in prices of equipment and materials required for the construction of new assets.Order TED/1232/2022. |
| - | The Company couldelectricity market price assumed by the regulation for calendar year 2022 was changed from €48.82 per MWh to an expected price of €121.9 per MWh, i.e., the remuneration parameters of 2022 have been updated with real prices of 2020 (33.94 €/MWh) and 2021 (111.90 €/MWh) and the future prices of OMIP for 2022 (value of second semester 2021: 121.9 €/MWh). As a result, the variable payment based on net electricity produced (Remuneration on Operation or Ro), is also experience commercial disputes with its clients, suppliers and partners related to implications of COVID-19 in contractual relations. Allbeing adjusted. The proposed Ro for the risks referred to can cause delays in distributions from its assets toyear 2022 is zero €/MWh reflecting the holding company. |
| - | Many governments have implemented and may continue to implement stimulus measures to reducefact that market prices for the negative impact of COVID-19power sold in the economy. In many cases, these measures may increase government spending which may translate into increased tax pressure on companies in the countries where the Company operates.market are significantly higher.
|
Measures takenFollowing the mandate contained in Royal Decree Law 6/2022 and Royal Decree Law 10/2022, whose main measures have been exposed above, the remuneration parameters have been updated for the year 2022 by the Company so far have focusedrecent Order TED/1232/2022, of December 2, 2022, that was published in final form on reinforcing safety measures in all its assets while it continues to provide a reliable service to its clients. For example, the Company has implemented the use of additional protection equipment, reinforced access control to its plants, reduced contact between employees, changed shifts, tested employees, identified and isolated potential cases together with their close contacts and taken additional measures to increase safety measures for its employees and operation and maintenance suppliers’ employees working at its assets. The Company has also reinforced its physical and cyber-security measures. The Company has implemented protocols to decide which offices to keep open and under what limitations, depending on health and safety indicators in each specific region.December 14, 2022.
COVID-19 didFor the three-year semi period starting on January 1, 2023, and ending on December 31, 2025, the adjustment for electricity price deviations in the preceding statutory half period will be progressively modified to take into account a mix of actual market prices and future market prices. On December 28, 2022 the proposed parameters for the year 2023 were published. They are still subject to review.
All the adjustments to the regulated revenue of the solar assets of the Company in Spain stated above do not have any materialaffect the reasonable return on investment previously set by the Spanish government, and therefore do not impact on the business disclosedvalue of these assets in these Consolidated Financial Statements.the long term.
The Consolidated Financial Statements were approved by the Board of Directors of the Company on February 25, 2022.28, 2023.
Note 2.- Significant accounting policies
2.1 Basis of preparation
These Consolidated Financial Statements are presented in accordance with the International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).
The Consolidated Financial Statements are presented in U.S. dollars, which is the Company’s functional and presentation currency. Amounts included in these Consolidated Financial Statements are all expressed in thousands of U.S. dollars, unless otherwise indicated.
The Company presents assets and liabilities in the statement of financial position based on current/non-current classification. An asset or liability is current when it is expected or due to be realized within twelve months after the reporting period.
The Company recognises that there may be potential financial implications in the future from changes in legislation and regulation implemented to address climate change risk. Over time these changes may have an impact across a number of areas of accounting. However, as at the reporting sheet date, the Company believes there is no material impact on the balance sheet carrying values of assets or liabilities.
Application of new accounting standards
| a) | Standards, interpretations and amendments effective from January 1, 20212022 under IFRS-IASB, applied by the Company in the preparation of these Consolidated Financial Statements: |
The applications of these amendments have not had any impact on these financial statements.
Interest Rate Benchmark Reform – Phase 2: Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16.
These amendments are mandatory for annual periods beginning on or after January 1, 2021 under IFRS-IASB. The amendments provide temporary reliefs which address the financial reporting effects when an interbank offered rate (“IBOR”) is replaced with an alternative risk-free interest rate (“RFR”). The amendments include the following practical expedients:
| - | A practical expedient to require contractual changes, or changes to cash flows that are directly required by the reform, to be treated as changes to a floating interest rate, equivalent to a movement in a market rate of interest. |
| - | Permit changes required by IBOR reform to be made to hedge designations and hedge documentation without the hedging relationship being discontinued. |
The Company intends to use the practical expedients in future periods if they become applicable.
| b) | Standards, interpretations and amendments published by the IASB that will be effective for periods beginning on or after January 1, 2022:2023: |
The Company does not anticipate any significant impact on the Consolidated Financial Statements derived from the application of the new standards and amendments that will be effective for annual periods beginning on or after January 1, 2021,2023, although it is currently still in the process of evaluating such application.
The Company has not early adopted any standard, interpretation or amendment that has been issued but is not yet effective.
Effect of IBOR reform
Following the financial crisis, the reform and replacement of benchmark interest rates such as LIBOR and IBORs has become a priority for global regulators. There remains some uncertainty around the timing and precise nature of these changes. The Company currently has several contracts which reference LIBOR and extend beyond 2021. These contracts are disclosed within the tables below.
It is currently expected that alternative RFRs will replace LIBOR. There remain key differences between LIBOR and RFRs. LIBOR is a ‘term rate’, which means that it is published for a borrowing period (such as three months or six months) and is ‘forward looking’, because it is published at the beginning of the borrowing period. RFRs may be based on overnight rates from actual transactions and published at the end of the overnight borrowing period. Furthermore, LIBOR includes a credit spread over the risk-free rate, which RFRs currently may not. To transition existing contracts and agreements that reference LIBOR to RFRs, adjustments for term differences and credit differences might need to be applied to RFRs, to enable the two benchmark rates to be economically equivalent on transition. At the time of reporting, industry working groups are reviewing methodologies for calculating adjustments between LIBOR and RFRs.
Risks arising from the transition relate principally to the potential impact of rate differences if the debt and related hedging instruments do not transition to the new benchmark interest rate at the same time and/or the rates move by different amounts. This could result in hedge ineffectiveness and a net cash expense to the Company as a result of the IBOR transition.
The following table contains details of the financial instruments that the Company holds as of December 31, 2021 which reference LIBOR and have not yet transitioned to RFRs:
| | Carrying amount as of December 31, 2021 | |
| | Assets
| | | Liabilities | |
Non-derivative assets and liabilities referenced to LIBOR | | | | | | |
Measured at amortized cost | | | | | | |
Project debt | |
| - | | | | 1,068,501 | |
Total non-derivatives items | | | 0 | | | | 1,068,501 | |
Derivatives | | | 0 | | | | 62,571 | |
Total assets and liabilities referenced to LIBOR | |
| 0 | | | | 1,131,072 | |
The following table contains details of only the hedging instruments used in the Company's hedging strategies which reference LIBOR and have not yet transitioned to RFRs, such that relief(s) of phase 1 and phase 2 amendments to IFRS 9 and IFRS 7 for IBOR reform, effective January 1st, 2020 and January 1st, 2021, respectively, have been applied to the hedging relationship:
| | Carrying amount as of December 31, 2021
| | | | | |
| | Notional | | | Assets | | | Liabilities | | Balance sheet line item(s) | | 2021 changes in fair value used for calculating hedge ineffectiveness | |
Cash flow hedge | | | | | | | | | | | | | |
Interest rate swaps | | | 939,670 | | | | 0 | | | | 62,571 | | Derivative liabilities | | | 30,013 | |
Total cash flow hedges | | | 939,670 | | | | 0 | | | | 62,571 | | | | | 30,013 | |
In calculating the change in fair value attributable to the hedged risk of floating-rate debt, the Company has made the following assumptions that reflect its current expectations:
| - | The floating-rate debt will move to RFRs during 2022, and the spread will be similar to the spread included in the interest rate swap used as the hedging instrument; |
| - | No other changes to the terms of the floating-rate debt are anticipated; |
2.2. Principles to include and record companies in the consolidated financial statements
Companies included in these Consolidated Financial Statements are accounted for as subsidiaries as long as Atlantica has control over them and are accounted for as investments under the equity method as long as Atlantica has significant influence over them, in the periods presented.
Control is achieved when the Company:
Has power over the investee;
| ● | Has power over the investee; |
| ● | Is exposed, or has rights, to variable returns from its involvement with the investee; and |
| ● | Has the ability to use its power to affect its returns. |
Has the ability to use its power to affect its returns.
The Company reassesses whether or not it controls an investee when facts and circumstances indicate that there are changes to one or more of the three elements of control listed above.
The Company uses the acquisition method to account for business combinations of companies previously controlled by a third party. According to this method, identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Any contingent consideration is recognized at fair value at the acquisition date and subsequent changes in its fair value are recognized in accordance with IFRS 9 in profit or loss. Acquisition related costs are expensed as incurred. The Company recognizes any non-controlling interest in the acquiree either at fair value or at the non-controlling interest’s proportionate share of the acquirer’s net assets on an acquisition by acquisition basis.
All assets and liabilities between entities of the group, equity, income, expenses, and cash flows relating to transactions between entities of the group are eliminated in full.
b) | Investments accounted for under the equity method |
An associate is an entity over which the Company has significant influence. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.
A joint venture is a type of joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the joint venture. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
F-18
The results and assets and liabilities of associates and joint ventures are incorporated in these financial statements using the equity method of accounting. Under the equity method, an investment in an associate or joint venture is initially recognized in the statement of financial position at costfair value and adjusted thereafter to recognize changes in Atlantica´s share of net assets of the associate or joint venture since the acquisition date. Any goodwill relating to the associate or joint venture is included in the carrying amount of the investment and is not tested for impairment separately.
Controlled entities, associates and associatesjoint ventures included in these financial statements as of December 31, 20212022 and 20202021 are set out in appendices.
2.3. Contracted concessional, Property, Plant and Equipment (PP&E) and other intangible assets
Contracted concessional assets correspond to the assets of the Company recorded as intangible or financial assets in accordance with IFRIC 12, property plant and equipment in accordance with IAS 16 and financial asset in accordance with IFRS 16.
The assets accounted for by the Company as concessionscontracted concessional assets under IFRIC 12 (either intangible model or financial model), as PP&E under IAS 16 or as other intangible assets under IAS 38 or under IFRS 16 (as “Lessee” or “Lessor”), include renewable energy assets, transmission lines, efficient natural gas assets and water plants. The useful life of these assets is approximately the same as the length of the concession arrangement.
| a) | Contracted concessional assets under IFRIC 12 |
The infrastructure used in a concession accounted for under IFRIC 12 can be classified as an intangible asset or a financial asset, depending on the nature of the payment entitlements established in the agreement.
The application of IFRIC 12 requires extensive judgement in relation to, among other factors, (i) the identification of certain infrastructures and contractual agreements in the scope of IFRIC 12, (ii) an understanding of the nature of the payments in order to determine the classification of the infrastructure as a financial asset or as an intangible asset and (iii) the timing and recognition of revenue from construction and concessionary activity.
Under the terms of contractual arrangements within the scope of this interpretation, the operator shall recognize and measure revenue in accordance with IFRS 15 for the services it performs.
The useful life of these assets is approximately the same as the length of the concession arrangement.
Intangible assets
The Company recognizes an intangible asset to the extent that it receives a right to charge final customers for the use of the infrastructure. This intangible asset is subject to the provisions of IAS 38 and is amortized linearly, taking into account the estimated period of commercial operation of the infrastructure which coincides with the concession period.
Once the infrastructure is in operation, the treatment of income and expense is as follows:
- | Revenues from the updated annual revenue for the contracted concession, as well as revenues from operations and maintenance services are recognized in each period according to IFRS 15 “Revenue from contracts with Customers”. |
- | Operating and maintenance costs and general overheads and administrative costs are recorded in accordance with the nature of the cost incurred (amount due) in each period. |
Financial asset
The Company recognizes a financial asset when demand risk is assumed by the grantor, to the extent that the concession holder has an unconditional right to receive payments for the asset. This asset is recognized at the fair value of the construction services provided, considering upgrade services in accordance with IFRS 15, if any.
The financial asset is subsequently recorded at amortized cost calculated according to the effective interest method, using a theoretical internal return rate specific to the asset. Revenue from operations and maintenance services is recognized in each period according to IFRS 15 “Revenue from contracts with Customers”.
Allowance for expected credit losses
(financial assets)
According to IFRS 9, Atlantica recognizes an allowance for expected credit losses (ECLs) for all debt instruments not held at fair value through profit or loss. ECLs are based on the difference between the contractual cash flows due in accordance with the contract and all the cash flows that the Company expects to receive.
There are two main approaches to applying the ECL model according to IFRS 9: the general approach which involves a three stage approach, and the simplified approach, which can be applied to trade receivables, contract assets and lease receivables. Atlantica applies the simplified approach. Under this approach, there is no need to monitor for significant increases in credit risk and entities will be required to measure lifetime expected credit losses at the end of each reporting period.
The key elements of the ECL calculations, based on external sources of information, are the following:
- | the Probability of Default (“PD”) is an estimate of the likelihood of default over a given time horizon. Atlantica calculates PD based on Credit Default Swaps spreads (“CDS”); |
- | the Exposure at Default (“EAD”) is an estimate of the exposure at a future default date; |
- | the Loss Given Default (“LGD”) is an estimate of the loss arising in the case where a default occurs at a given time. It is based on the difference between the contractual cash flows due and those that the Company would expect to receive. It is expressed as a percentage of the EAD. |
c) | b) | Property, plant and equipment under IAS 16
|
Property, plant and equipment is measured at historical cost, including all expenses directly attributable to the acquisition, less depreciation and impairment losses, with the exception of land, which is presented net of any impairment losses. Such cost includes the cost of replacing part of the plant and equipment and borrowing costs for long-term installation projects if the recognition criteria are met. Repair and maintenance costs are recognized in profit or loss as incurred.
OnceDepreciation is calculated on a straight-line basis over the infrastructureestimated useful lives of the assets.
The Company reviews the estimated residual values and expected useful lives of assets at least annually. In particular, the Company considers the impact of health, safety and environmental legislation in its assessment of expected useful lives and estimated residual values.
An item of property, plant and equipment and any significant part initially recognized is in operation,derecognized upon disposal (i.e., at the treatmentdate the recipient obtains control) or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition of income and expenses is the sameasset (calculated as the one described above for intangible asset.difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss when the asset is derecognized.
d) | Right-of-use assetsc) | Rights of use under IFRS 16
|
The Company assesses at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.
Company as a lessee:
The Company applies a single recognition and measurement approach for all leases, except for short-term leases and leases of low-value assets. The Company recognizes lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets.
Main right of use agreements correspond to land rights. The Company recognizes right-of-use assets under IFRS 16, at the commencement date of the lease (i.e. the date the underlying asset is available for use). Right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities (Note 2.11). The cost of right-of-use assets includes the amount of lease liabilities recognised, initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets.
e) | Revenue Recognition d) | Other intangible assets |
Other intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and accumulated impairment losses. Intangible assets are amortized over the useful economic life and assessed for impairment whenever there is an indication that the intangible asset may be impaired.
An intangible asset is derecognised upon disposal (i.e., at the date the recipient obtains control) or when no future economic benefits are expected from its use or disposal. Any gain or loss arising upon derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the statement of profit or loss.
Research and development costs:
Research costs are expensed as incurred. Development expenditures on an individual project are recognised as an intangible asset when the Company can demonstrate:
- | the technical feasibility of completing the intangible asset so that the asset will be available for use or sale |
- | its intention to complete and its ability and intention to use or sell the asset |
- | how the asset will generate future economic benefits |
- | the availability of resources to complete the asset |
- | the ability to measure reliably the expenditure during development. |
Following initial recognition of the development expenditure as an asset, the asset is carried at cost less any accumulated amortization and accumulated impairment losses. Amortization of the asset begins when development is complete, and the asset is available for use. It is amortized over the period of expected future benefit. During the period of development, the asset is tested for impairment annually.
Atlantica reviews its contracted concessional assets to identify any indicators of impairment at least annually, except for ECL assessment for financial assets which is discussed above. When impairment indicators exist, the Company calculates the recoverable amount of the asset.
The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, the Company calculates the recoverable amount of the Cash Generating Unit (‘CGU’) to which the asset belongs.
When the carrying amount of the CGU to which these assets belong is higher than its recoverable amount, the assets are impaired.
Assumptions used to calculate value in use include a discount rate and projections considering real data based in the contracts terms and projected changes in both selling prices and costs. The discount rate is estimated by Management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.
For contracted concessional assets, with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no relevant terminal value is assumed.
Contracted concessional assets have a contractual structure that permits the Company to estimate quite accurately the costs of the project and revenue during the life of the project.
Projections take into account real data based on the contract terms and fundamental assumptions based on specific reports prepared internally and third-party reports, assumptions on demand and assumptions on production. Additionally, assumptions on macro-economic conditions are taken into account, such as inflation rates, future interest rates, etc. and sensitivity analyses are performed over all major assumptions which can have a significant impact in the value of the asset.
Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.
Taking into account that in most CGUs the specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash-flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is performed.
In any case, sensitivity analyses are performed, especially in relation to the discount rate used and fair value changes in the main business variables, in order to ensure that possible changes in the estimates of these items do not impact the recovery of recognized assets.
In the event that the recoverable amount of an asset is lower than its carrying amount, an impairment charge for the difference would be recorded in the income statement under the item “Depreciation, amortization and impairment charges”.
An assessment is made at each reporting date to determine whether there is an indication that previously recognized impairment losses no longer exist or have decreased. If such indication exists, the Company estimates the CGU’s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the income statement.
2.4. Revenue recognition
According to IFRS 15, Revenue from Contracts with Customers, the Company assesses the goods and services promised in the contracts with the customers and identifies as a performance obligation each promise to transfer to the customer a good or service (or a bundle of goods or services).
In the case of contracts related to intangible or financial assets under IFRIC 12, the performance obligation of the Company is the operation of the asset. The contracts between the parties set the price of the service in an orderly transaction and therefore corresponds to the fair value of the service provided. The service is satisfied over time. The same conclusion applies to concessional assets that are classified as tangible assets under IAS 16 or leases under IFRS 16. All of the transaction prices of assets under IFRIC 12 are fixed and included as part of the long-term PPAs of the Company as disclosed in Appendix III-2.
In the case of financial asset under IFRIC 12, the financial asset accounts for the payments to be received from the client over the residual life of the contract, discounted at a theoretical internal rate of return for the project. In each period, the financial asset is reduced by the amounts received from the client and increased by any capital expenditure that the project may incur and by the effect of unwinding the discount of the financial asset at the theoretical internal rate of return. The increase of the financial asset deriving from the unwinding of the discount of the financial asset is recorded as revenue in each period. Revenue will therefore differ from the actual billings made by the asset to the client in each period.
In the case of Spain, according to Royal Decree 413/2014, solar electricity producers receive: (i) the market price for the power they produce, (ii) a payment based on the standard investment cost for each type of plant (without any relation whatsoever to the amount of power they generate) and (iii) an “operating payment” (in €/MWh produced). The principle driving this economic regime is that the payments received by a renewable energy producer should be equivalent to the costs that they are unable to recover on the electricity pool market where they compete with non-renewable technologies. This economic regime seeks to allow a “well-run and efficient enterprise” to recover the costs of building and running a plant, plus a reasonable return on investment (project investment rate of return). Some of the Company´s assets in Spain are receiving a remuneration based on a 7.09% reasonable rate of return until December 31, 2025 while others are receiving a remuneration based on a 7.398% reasonable rate of return until December 31, 2031.
2.4. Asset impairment
Atlantica reviews its contracted concessional assets to identify any indicators of impairment at least annually, except for ECL assessment for financial assets which is discussed in note 2.3. When impairment indicators exist, the company calculates the recoverable amount of the asset.
The recoverable amount of an asset is the higher of its fair value less costs to sell and its value in use, defined as the present value of the estimated future cash flows to be generated by the asset. In the event that the asset does not generate cash flows independently of other assets, the Company calculates the recoverable amount of the Cash Generating Unit (‘CGU’) to which the asset belongs.
When the carrying amount of the CGU to which these assets belong is higher than its recoverable amount, the assets are impaired.
Assumptions used to calculate value in use include a discount rate and projections considering real data based in the contracts terms and projected changes in both selling prices and costs. The discount rate is estimated by Management, to reflect both changes in the value of money over time and the risks associated with the specific CGU.
For contracted concessional assets, with a defined useful life and with a specific financial structure, cash flow projections until the end of the project are considered and no relevant terminal value is assumed.
Contracted concessional assets have a contractual structure that permits the Company to estimate quite accurately the costs of the project and revenue during the life of the project.
Projections take into account real data based on the contract terms and fundamental assumptions based on specific reports prepared internally and third-party reports, assumptions on demand and assumptions on production. Additionally, assumptions on macro-economic conditions are taken into account, such as inflation rates, future interest rates, etc. and sensitivity analyses are performed over all major assumptions which can have a significant impact in the value of the asset.
Cash flow projections of CGUs are calculated in the functional currency of those CGUs and are discounted using rates that take into consideration the risk corresponding to each specific country and currency.
Taking into account that in most CGUs the specific financial structure is linked to the financial structure of the projects that are part of those CGUs, the discount rate used to calculate the present value of cash-flow projections is based on the weighted average cost of capital (WACC) for the type of asset, adjusted, if necessary, in accordance with the business of the specific activity and with the risk associated with the country where the project is performed.
In any case, sensitivity analyses are performed, especially in relation to the discount rate used and fair value changes in the main business variables, in order to ensure that possible changes in the estimates of these items do not impact the recovery of recognized assets.
In the event that the recoverable amount of an asset is lower than its carrying amount, an impairment charge for the difference would be recorded in the income statement under the item “Depreciation, amortization and impairment charges”.
An assessment is made at each reporting date to determine whether there is an indication that previously recognized impairment losses no longer exist or have decreased. If such indication exists, the Company estimates the CGU’s recoverable amount. A previously recognized impairment loss is reversed only if there has been a change in the assumptions used to determine the asset’s recoverable amount since the last impairment loss was recognized. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in the income statement.
2.5. Loans and accounts receivable
Loans and accounts receivable are non-derivative financial assets with fixed or determinable payments, not listed on an active market.
In accordance with IFRIC 12, certain assets under concessions qualify as financial assets and are recorded as is described in Note 2.3.
Pursuant to IFRS 9, an impairment loss is recognized if the carrying amount of these assets exceeds the present value of future cash flows discounted at the initial effective interest rate.
Loans and accounts receivable are initially recognized at fair value plus transaction costs and are subsequently measured at amortized cost in accordance with the effective interest rate method. Interest calculated using the effective interest rate method is recognized under other financial income within financial income.
2.6. Derivative financial instruments and hedging activities
Derivatives are recognized at fair value in the statement of financial position. The Company maintains both derivatives designated as hedging instruments in hedging relationships, and derivatives to which hedge accounting is not applied.
When hedge accounting is applied, hedging strategy and risk management objectives are documented at inception, as well as the relationship between hedging instruments and hedged items. Effectiveness of the hedging relationship needs to be assessed on an ongoing basis. Effectiveness tests are performed prospectively at inception and at each reporting date. The Company analyses on each date if all these requirements are met:
- | there is an economic relationship between the hedged item and the hedging instrument; |
- | the effect of credit risk does not dominate the value changes that result from that economic relationship; and |
- | the hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Company actually hedges and the quantity of the hedging instrument that the Company uses to hedge that quantity of hedged item. |
Ineffectiveness is measured following the accumulated dollar offset method.
In all cases, current Company´s hedging relationships are considered cash flow hedges. Under this model, the effective portion of changes in fair value of derivatives designated as cash flow hedges are recorded temporarily in equity and are subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffective portion of the hedged transaction is recorded in the consolidated income statement as it occurs.
When interest rate options are designated as hedging instruments, the time value is excluded from the hedging instrument as permitted by IFRS 9. Changes in the effective portion of the intrinsic are recorded in equity and subsequently reclassified from equity to profit or loss in the same period or periods during which the hedged item affects profit or loss. Any ineffectiveness is recorded as financial income or expense as it occurs. Changes in options time value is recorded as cost of hedging. More precisely, considering that the hedged items are, in all cases, time period hedged item, changes in time value is recognized in other comprehensive income to the extent that it relates to the hedged item. The time value at the date of designation of the option as a hedging instrument, to the extent that it relates to the hedged item, is amortized on a systematic and rational basis over the period during which the hedge adjustment for the option’s intrinsic value could affect profit or loss.
When the hedging instrument matures or is sold, or when it no longer meets the requirements to apply hedge accounting, accumulated gains and losses recorded in equity remain as such until the forecast transaction is ultimately recognized in the income statement. However, if it becomes unlikely that the forecast transaction will actually take place, the accumulated gains and losses in equity are recognized immediately in the income statement.
Any change in fair value of derivatives instruments to which hedge accounting is not applied is directly recorded in the income statement.
2.7. Fair value estimates
Financial instruments measured at fair value are presented in accordance with the following level classification based on the nature of the inputs used for the calculation of fair value:
- | Level 1: Inputs are quoted prices in active markets for identical assets or liabilities. |
- | Level 2: Fair value is measured based on inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices). |
- | Level 3: Fair value is measured based on unobservable inputs for the asset or liability. |
In the event that prices cannot be observed, management shall make its best estimate of the price that the market would otherwise establish based on proprietary internal models which, in the majority of cases, use data based on observable market parameters as significant inputs (Level 2) but occasionally use market data that is not observed as significant inputs (Level 3). Different techniques can be used to make this estimate, including extrapolation of observable market data. The best indication of the initial fair value of a financial instrument is the price of the transaction, except when the value of the instrument can be obtained from other transactions carried out in the market with the same or similar instruments, or valued using a valuation technique in which the variables used only include observable market data, mainly interest rates. Differences between the transaction price and the fair value based on valuation techniques that use data that is not observed in the market, are not initially recognized in the income statement.
Atlantica derivatives correspond primarily to the interest rate swaps designated as cash flow hedges, which are classified as Level 2.
Description of the valuation method
Interest rate swap valuations consist in valuing separately the swap part of the contract and the credit risk. The methodology used by the market and applied by Atlantica to value interest rate swaps is to discount the expected future cash flows according to the parameters of the contract. Variable interest rates, which are needed to estimate future cash flows, are calculated using the curve for the corresponding currency and extracting the implicit rates for each of the reference dates in the contract. These estimated flows are discounted with the swap zero curve for the reference period of the contract.
The effect of the credit risk on the valuation of the interest rate swaps depends on the future settlement. If the settlement is favorable for the Company, the counterparty credit spread will be incorporated to quantify the probability of default at maturity. If the expected settlement is negative for the Company, its own credit risk will be applied to the final settlement.
Classic models for valuing interest rate swaps use deterministic valuation of the future of variable rates, based on future outlooks. When quantifying credit risk, this model is limited by considering only the risk for the current paying party, ignoring the fact that the derivative could change sign at maturity. A payer and receiver swaption model is proposed for these cases. This enables the associated risk in each swap position to be reflected. Thus, the model shows each agent’s exposure, on each payment date, as the value of entering into the ‘tail’ of the swap, i.e. the live part of the swap.
Variables (Inputs)
Interest rate derivative valuation models use the corresponding interest rate curves for the relevant currency and underlying reference in order to estimate the future cash flows and to discount them. Market prices for deposits, futures contracts and interest rate swaps are used to construct these curves. Interest rate options (caps and floors) also use the volatility of the reference interest rate curve.
To estimate the credit risk of the counterparty, the credit default swap (CDS) spreads curve is obtained in the market for important individual issuers. For less liquid issuers, the spreads curve is estimated using comparable CDSs or based on the country curve. To estimate proprietary credit risk, prices of debt issues in the market and CDSs for the sector and geographic location are used.
The fair value of the financial instruments that results from the aforementioned internal models takes into account, among other factors, the terms and conditions of the contracts and observable market data, such as interest rates, credit risk and volatility. The valuation models do not include significant levels of subjectivity, since these methodologies can be adjusted and calibrated, as appropriate, using the internal calculation of fair value and subsequently compared to the corresponding actively traded price. However, valuation adjustments may be necessary when the listed market prices are not available for comparison purposes.
2.8. Trade and other receivables
Trade and other receivables are amounts due from customers for sales in the normal course of business. They are recognized initially at fair value and subsequently measured at amortized cost using the effective interest rate method, less allowance for doubtful accounts. Trade receivables due in less than one year are carried at their face value at both initial recognition and subsequent measurement, provided that the effect of not discounting flows is not significant.
An allowance for doubtful accounts is recorded when there is objective evidence that the Company will not be able to recover all amounts due as per the original terms of the receivables. The Company has established a provision matrix that is based on its historical credit loss experience, adjusted for forward-looking factors specific to the debtors and the economic environment.
2.9. Cash and cash equivalents
Cash and cash equivalents include cash in hand, cash in bank and other highly-liquid current investments with an original maturity of three months or less which are held for the purpose of meeting short-term cash commitments.
2.10. Grants
Grants are recognized at fair value when it is considered that there is a reasonable assurance that the grant will be received and that the necessary qualifying conditions, as agreed with the entity assigning the grant, will be adequately complied with.
Grants are recorded as liabilities in the consolidated statement of financial position and are recognized in “Other operating income” in the consolidated income statement based on the period necessary to match them with the costs they intend to compensate.
In addition, as described in Note 2.11 below, grants correspond also to loans with interest rates below market rates, for the initial difference between the fair value of the loan and the proceeds received.
2.11. Loans and borrowings
Loans and borrowings are initially recognized at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortized cost and any difference between the proceeds initially received (net of transaction costs incurred in obtaining such proceeds) and the repayment value is recognized in the consolidated income statement over the duration of the borrowing using the effective interest rate method.
In the case of modification of terms of loans and borrowings, the Company determines whether the modification constitutes an exchange or an extinguishment of the debt instrument. In determining whether there is an exchange, the Company evaluates whether the redemption of the old debt and the issuance of new debt were negotiated in contemplation of one another (qualitative assessment) and performs the 10 per cent test to determine if the terms of the modified debt are substantially different (the net present value of the modified cash flows, including any fees paid net of any fees received, is higher than 10% different from the net present value of the remaining cash flows of the liability prior to the modification, both discounted at the original effective interest rate). When the terms of the modified liability are substantially different, the modification is accounted for as an extinguishment of the original liability and recognition of a new liability.
Loans with interest rates below market rates are initially recognized at fair value in liabilities and the difference between proceeds received from the loan and its fair value is initially recorded within “Grants and Other liabilities” in the consolidated statement of financial position, and subsequently recorded in “Other operating income” in the consolidated income statement when the costs financed with the loan are expensed.
Lease liabilities are recognized by the Company at the commencement date of the lease at the present value of lease payments to be made over the lease term. The lease payments include the exercise price of a purchase option reasonably certain to be exercised by the Company and payments of penalties for terminating the lease, if the lease term reflects the Company exercising the option to terminate. In calculating the present value of lease payments, the Company uses its incremental borrowing rate at the lease commencement date considering that the interest rate implicit in the lease is not readily determinable.
2.12. Bonds and notes
The Company initially recognizes ordinary notes at fair value, net of issuance costs incurred. Subsequently, notes are measured at amortized cost until settlement upon maturity. Any other difference between the proceeds obtained (net of transaction costs) and the redemption value is recognized in the consolidated income statement over the term of the debt using the effective interest rate method.
Convertible bonds or notes or debt issued with conversion features must be separated into liability and equity components if the feature meets the equity classification conditions in IAS 32. The issuer separates the instrument into its components by determining the fair value of the liability component and then deducting that amount from the fair value of the instrument as a whole; the residual amount is allocated to the equity component. If the equity conversion feature does not satisfy the equity classification conditions in IAS 32, it is bifurcated as an embedded derivative unless the issuer elects to apply the fair value option to the convertible debt. The embedded derivative is initially recognized at fair value and classified as derivatives in the statement of financial position. Changes in the fair value of the embedded derivatives are subsequently accounted for directly through the income statement. The debt element of the bond or note (the host contract), will be initially valued as the difference between the consideration received from the holders for the instrument and the value of the embedded derivative, and thereafter at amortized cost using the effective interest method.
2.13. Income taxes
Current income tax expense is calculated on the basis of the tax laws in force as of the date of the consolidated statement of financial position in the countries in which the subsidiaries and associates operate and generate taxable income.
Deferred income tax is calculated in accordance with the liability method, based upon the temporary differences arising between the carrying amount of assets and liabilities and their tax base. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the year when the asset is realized or the liability is settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the reporting date.
Deferred tax assets are recognized to the extent that it is probable that taxable profit will be available against which the deductible temporary differences, and the carry forward of unused tax credits and unused tax losses can be utilized.
2.14. Trade payables and other liabilities
Trade payables are obligations arising from purchases of goods and services in the ordinary course of business and are recognized initially at fair value and are subsequently measured at their amortized cost using the effective interest method. Other liabilities are obligations not arising in the normal course of business and which are not treated as financing transactions. Advances received from customers are recognized as “Trade payables and other current liabilities”.
2.15. Foreign currency transactions
The Consolidated Financial Statements are presented in U.S. dollars, which is Atlantica’s functional and presentation currency. Financial statements of each subsidiary within the Company are measured in the currency of the principal economic environment in which the subsidiary operates, which is the subsidiary’s functional currency.
Transactions denominated in a currency different from the subsidiary’sentity’s functional currency are translated into the subsidiary’sentity’s functional currency applying the exchange rates in force at the time of the transactions. Foreign currency gains and losses that result from the settlement of these transactions and the translation of monetary assets and liabilities denominated in foreign currency at the year-end rates are recognized in the consolidated income statement, unless they are deferred in equity, as occurs with cash flow hedges and net investment in foreign operations hedges.
Assets and liabilities of subsidiaries with a functional currency different from the Company’s reporting currency are translated to U.S. dollars at the exchange rate in force at the closing date of the financial statements. Income and expenses are translated into U.S. dollars using the average annual exchange rate, which does not differ significantly from using the exchange rates of the dates of each transaction. The difference between equity translated at the historical exchange rate and the net financial position that results from translating the assets and liabilities at the closing rate is recorded in equity under the heading “Accumulated currency translation differences”.
Results of companies carried under the equity method are translated at the average annual exchange rate.
2.16. Equity
The Company has recyclable balances in its equity, corresponding mainly to hedge reserves and translation differences arising from currency conversion in the preparation of these Consolidated Financial Statements. These balances have been presented separately in Equity.equity.
Ordinary shares are classified as equity. Any excess above the par value of shares received upon issuance of those shares is classified as share premium. Capital reserves is mainly the result of reductions of the share premium account which have increased distributable reserves.
Non-controlling interest represents interest of other partners in entitiessubsidiaries included in these Consolidated Financial Statements which are not fully owned by Atlantica as of the dates presented.
Share Capital, Share Premium and Capital Reserves represent the Parent’s net investment in the entities included in these Consolidated Financial Statements.
The costs of issuing equity instruments are accounted for as a deduction from equity.
2.17. Provisions and contingencies
Provisions are recognized when:
- | there is a present obligation, either legal or constructive, as a result of past events; |
- | it is more likely than not that there will be a future outflow of resources to settle the obligation; and the amount has been reliably estimated. |
Provisions are measured at the present value of the expected outflows required to settle the obligation. The discount rate used is a current pre-tax rate that reflects, when appropriate, the risks specific to the liability. The increase in the provision due to the passage of time is then recognized as a financial expense. The balance of provisions disclosed in the Notes reflects management’s best estimate of the potential exposure as of the date of preparation of the Consolidated Financial Statements.
Contingent liabilities are possible obligations, existing obligations with low probability of a future outflow of economic resources and existing obligations where the future outflow cannot be reliably estimated. Contingences are not recognized in the consolidated statements of financial position unless they have been acquired in a business combination.
Some companies of Atlantica have dismantling provisions, which are intended to cover future expenditure related to the dismantlement of the plants in situations where it is likely to be settled with an outflow of resources in the long term (over 5 years).
Such provisions are accruedrecognised when the obligation for dismantling, removing and restoring the site on which the plant is located, is incurred, which is usually during the construction period. The provision is measured in accordance with IAS 37, “Provisions, Contingent Liabilities and Contingent Assets” and is recorded as a liability under the heading “Grants and other liabilities” of the Financial Statements, and the corresponding entry as part of the cost of the plant under the heading “Contracted concessional assets.” The estimated future costs of dismantling are reviewed annually if conditions have changed and adjusted appropriately. The impact of changes in the estimate of future costs or in the timing of when such costs will be incurred, on the dismantling provision, is recorded against an increase or decrease of the cost of the plant.
2.18. Earnings per share
Basic earnings per share is calculated by dividing the profit for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the period.
Diluted earnings per share is calculated by dividing the profit for the period attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the period plus the weighted average number of ordinary shares that would be issued on conversion of all the dilutive potential ordinary shares into ordinary shares.
2.19. Significant judgements and estimates
Some of the accounting policies applied require the application of significant judgement by management to select the appropriate assumptions to determine these estimates. These assumptions and estimates are based on the historical experience, advice from experienced consultants, forecasts and other circumstances and expectations as of the close of the financial period. The assessment is considered in relation to the global economic situation of the industries and regions where the Company operates, taking into account future development of the businesses of the Company. By their nature, these judgements are subject to an inherent degree of uncertainty; therefore, actual results could materially differ from the estimates and assumptions used. In such cases, the carrying values of assets and liabilities are adjusted.
The most critical accounting policies, which reflect significant management estimates and judgement to determine amounts in these Consolidated Financial Statements, are as follows:
- | Impairment of contracted concessional, PP&E and other intangible assets. |
Impairment exists when the carrying value of an asset or cash generating unit exceeds its recoverable amount, which is the higher of its fair value less costs of disposal and its value in use. The value in use calculation is based on a discounted cash flow model, which is sensitive to the discount rate used as well as projected cash-flows (Note 6).
The significant assumptions which required substantial estimates used in management’s impairment calculation are discount rates and projections considering real data based on contract terms and projected changes in selling prices, energy generation and costs.
- | Recoverability of deferred tax assets. |
Deferred tax assets are recognised for unused tax losses to the extent that it is probable that taxable profit will be available against which the losses can be utilised. Significant management estimates are required to determine the amount of deferred tax assets that can be recognised, based upon the likely timing and the level of future taxable profits together with future tax planning strategies (Note 18).
- | Fair value of derivative financial instruments |
When the fair values of financial assets and financial liabilities recorded in the statement of financial position cannot be measured based on quoted prices in active markets, their fair value is measured using valuation techniques including the discounted cash flow model. The inputs to these models are taken from observable markets where possible, but where this is not feasible, a degree of estimate is required in establishing fair values. Estimates include considerations of inputs such as liquidity risk, credit risk and volatility. Changes in assumptions relating to these factors could affect the reported fair value of financial instruments.
- | Fair value of identifiable assets and liabilities arising from a business combination |
The assets acquired and liabilities assumed on a business combination are recognised at the fair values of the underlying items. The estimates that have a significant risk of causing a material adjustment to the carrying amounts of the assets and liabilities are the ones considered when performing impairment review of operating assets (see above).
- | Assessment of contracted concessionalassets agreements. |
- | Impairment of intangible assets and property, plant and equipment. |
By evaluating the terms and conditions of each assets agreement, the Company determines the accounting category to which the asset belongs, e.g. IAS 16, IFRIC 12 or IFRS 16 (Note 2.3.).
- | Derivative financial instruments and fair value estimates. |
- | Income taxes and recoverable amount of deferred tax assets. |
Judgement is required in determining the nature of Atlantica´s interest in another entity and in determining if it has control, joint control or significant influence over it (Note 2.2.).
As of the date of preparation of these Consolidated Financial Statements, no relevant changes in the estimates made are anticipated and, therefore, no significant changes in the value of the assets and liabilities recognized at December 31, 2021,2022, are expected.
Although these estimates and assumptions are being made using all available facts and circumstances, it is possible that future events may require management to amend such estimates and assumptions in future periods. Changes in accounting estimates are recognized prospectively, in accordance with IAS 8, in the consolidated income statement of the year in which the change occurs.
Note 3.- Financial risk management
Atlantica’s activities are exposed to various financial risks: market risk (including currency risk and interest rate risk), credit risk and liquidity risk. Risk is managed by the Company’s Risk FinanceManagement and ComplianceFinance Departments, which are responsible for identifying and evaluating financial risks quantifying them by project, region and company, in accordance with mandatory internal management rules. WrittenThe internal management rules provide written policies exist for globalthe management of overall risk, management, as well as for specific areasareas. The internal management policies of risk. In addition, there are official written management regulations regarding key controlsthe Company also define the use of hedging instruments and control procedures for each companyderivatives and the implementationinvestment of these controls is monitored through internal audit procedures.excess cash.
The Company is exposed to market risk, such as movement in foreign exchange rates and interest rates. All of these market risks arise in the normal course of business and the Company does not carry out speculative operations. For the purpose of managing these risks, the Company uses a series of interest rate swaps and options, and currency options. None of the derivative contracts signed has an unlimited loss exposure.
Interest rate risk arises when the Company’s activities are exposed to changes in interest rates, which arises from financial liabilities at variable interest rates. The main interest rate exposure for the Company relates to the variable interest rate with reference to the Libor, Euribor and RFRs.SOFR. To minimize the interest rate risk, the Company primarily uses interest rate swaps and interest rate options (caps), which, in exchange for a fee, offer protection against an increase in interest rates. The Company does not use derivatives for speculative purposes.
As a result, the notional amounts hedged, strikes contracted and maturities, depending on the characteristicsof December 31, 2022, approximately 92% of the Project debt on whichof the Company and approximately 96% of the Corporate debt either has fixed interest rate riskrates or has been hedged with swaps or caps. The Revolving Credit Facility of the Company has variable interest rates and is beingnot hedged are very diverse, including the following:(Note 14).
| o | Project debt in Euros: the Company hedges between 75% and 100% of the notional amount with headges maturing up to 2038 and average guaranteed strike interest rates of between 0.00% and 4.87%. |
| o | Project debt in U.S. dollars: the Company hedges between 75% and 100% of the notional amount with headges maturing up to 2038 and average guaranteed strike interest rates of between 0.86% and 5.89%. |
In connection with the interest rate derivative positions of the Company, the most significant impacts on these Consolidated Financial Statements are derived from the changes in EURIBOR, orSOFR and LIBOR, which represent the reference interest rate for most of the debt of the Company. In the event that EuriborEURIBOR, SOFR and LiborLIBOR had risen by 25 basis points as of December 31, 2021,2022, with the rest of the variables remaining constant, the effect in the consolidated income statement would have been a loss of $2,495 thousand$1.3 million (a loss of $2,897 thousand$2.5 million in 20202021 and a loss of $2,745 thousand$2.9 million in 2019)2020) and an increasea gain in hedging reserves of $22,440 thousand$18.4 million ($22,130 thousand22.4 million in 20202021 and $27,570 thousand$22.1 million in 2019)2020). The increasegain in hedging reserves would be mainly due to an increase in the fair value of interest rate swaps designated as hedges.
A breakdown of the interest rates derivatives as of December 31, 20212022 and 2020,2021, is provided in Note 9.
The main cash flows in the entities included in these Consolidated Financial Statements are cash collections arising from long-term contracts with clients and debt payments arising from project finance repayment. Given that financing of the projects is alwaystypically closed in the same currency in which the contract with client is signed, a natural hedge exists for the main operations of the Company.
In addition, to further mitigate this exposure, the Company policy is to contract currency options with leading financial institutions, which guarantee a minimum Euro-U.S. dollar exchange rate on the net distributions expected from solar assets in Spain.Europe. The net Euro exposure is 100% hedged for the coming 12 months and 75% for the following 12 months on a rolling basis.
Although the Company hedges cash-flows in euros, fluctuations in the value of the euro in relation to the U.S. dollar may affect its operating results. For example, revenue in euro-denominated companies could decrease when translated to U.S. dollars at the average foreign exchange rate solely due to a decrease in the average foreign exchange rate, in spite of revenue in the original currency being stable. Fluctuations in the value of the South African rand, the Colombian peso and the Uruguayan peso with respect to the U.S. dollar may also affect the operating results of the Company. Apart from the impact of these translation differences, the exposure of the income statement of the Company to fluctuations of foreign currencies is limited, as the financing of projects is typically denominated in the same currency as that of the contracted revenue agreement.
The Company considers that it has a limited credit risk with clients as revenues primarily derive from power purchase agreements with electric utilities and state-owned entities. In addition, the diversification by geography and business sector helps to diversify credit risk exposure by diluting the exposure of the Company to a single client.
Atlantica’s liquidity and financing policy is intended to ensure that the Company maintains sufficient funds to meet its financial obligations as they fall due.
Project finance borrowing permits the Company to finance the project through project debt and thereby insulate the rest of its assets from such credit exposure. The Company incurs in project-finance debt on a project-by-project basis.
The repayment profile of each project is established on the basis of the projected cash flow generation of the business. This ensures that sufficient financing is available to meet deadlines and maturities, which mitigates the liquidity risk significantly. In addition, the Company maintains a periodic communication with its lenders and regular monitoring of debt covenants and minimum ratios.
Corporate and Project debt repayment schedules are disclosed in Note 14 and 15, respectively.
Note 4.- Financial information by segment
Atlantica’s segment structure reflects how management currently makes financial decisions and allocates resources. Its operating and reportable segments are based on the following geographies where the contracted concessional assets are located: North America, South America and EMEA. In addition, based on the type of business, as of December 31, 2021,2022, the Company had the following business sectors: Renewable energy, Efficient natural gas and Heat, Transmission lines and Water. The business sector “Efficient natural gas” has been renamed “Efficient natural gas and Heat” in these Consolidated Financial Statements as it includes the Calgary District Heating asset acquired in May 2021 (Note 5).
Atlantica’s Chief Operating Decision Maker (CODM), which is the CEO, assesses the performance and assignment of resources according to the identified operating segments. The CODM considers the revenue as a measure of the business activity and the Adjusted EBITDA as a measure of the performance of each segment. Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest, income tax expense, financial expense (net), depreciation, amortization and impairment charges of entities included in the these Consolidated Financial Statements and depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of Atlantica's equity ownership). Adjusted EBITDA previously excluded share of profit/(loss) of associates carried under the equity method and did not include depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro-rata of Atlantica’s equity ownership). Prior periods have been presented accordingly.
In order to assess performance of the business, the CODM receives reports of each reportable segment using revenue and Adjusted EBITDA. Net interest expense evolution is assessed on a consolidated basis. Financial expense and amortization are not taken into consideration by the CODM for the allocation of resources.
In the year ended December 31, 2021,2022, Atlantica had 1 customerthree customers with revenues representing more than 10% of total revenue, two in the renewable energy and one in the efficient natural gas and heat business sector. sectors. In the year ended December 31, 2020, 2021, Atlantica had 4 customersone customer with revenues representing more than 10% of the total revenue, 3 in the renewable energy and 1 in the efficient natural gas and heat business sectors.sector.
a) | The following tables show Revenues and Adjusted EBITDA by operating segments and business sectors for the years 2022, 2021 2020 and 2019:2020: |
| | Revenue | | Adjusted EBITDA | | | Revenue | | Adjusted EBITDA | |
| | For the year ended December 31, | | For the year ended December 31, | | | For the year ended December 31, | | For the year ended December 31, | |
Geography | | 2021 | | 2020 | | 2019 | | 2021 | | 2020 | | 2019 | | | 2022 | | 2021 | | 2020 | | 2022 | | 2021 | | 2020 | |
North America | | 395,775 | | | 330,921 | | | 332,965 | | | 311,803 | | | 279,365 | | | 307,242 | | | 405,047 | | | 395,775 | | | 330,921 | | | 309,988 | | | 311,803 | | | 279,365 | |
South America | | 154,985 | | | 151,460 | | | 142,207 | | | 119,547 | | | 120,023 | | | 115,346 | | | 166,441 | | | 154,985 | | | 151,460 | | | 126,551 | | | 119,547 | | | 120,023 | |
EMEA | | | 660,989 | | | | 530,879 | | | | 536,280 | | | | 393,038 | | | | 396,735 | | | | 398,967 | | | | 530,541 | | | | 660,989 | | | | 530,879 | | | | 360,561 | | | | 393,038 | | | | 396,735 | |
Total | | | 1,211,749 | | | | 1,013,260 | | | | 1,011,452 | | | | 824,388 | | | | 796,123 | | | | 821,555 | | | | 1,102,029 | | | | 1,211,749 | | | | 1,013,260 | | | | 797,100 | | | | 824,388 | | | | 796,123 | |
| | Revenue | | Adjusted EBITDA | | | Revenue | | Adjusted EBITDA | |
| | For the year ended December 31, | | For the year ended December 31, | | | For the year ended December 31, | | For the year ended December 31, | |
Business sectors | | 2021
| | 2020 | | 2019 | | 2021
| | 2020 | | 2019 | | | 2022
| | 2021 | | 2020 | | 2022
| | 2021 | | 2020 | |
Renewable energy | | 928,525 | | | 753,089 | | | 761,090 | | | 602,583 | | | 576,285 | | | 604,080 | | | 821,377 | | | 928,525 | | | 753,089 | | | 588,016 | | | 602,583 | | | 576,285 | |
Efficient natural gas & Heat
| | 123,692 | | | 111,030 | | | 122,281 | | | 99,935 | | | 101,006 | | | 109,200 | | | 113,591 | | | 123,692 | | | 111,030 | | | 84,560 | | | 99,935 | | | 101,006 | |
Transmission lines | | 105,680 | | | 106,042 | | | 103,453 | | | 83,635 | | | 87,272 | | | 85,657 | | | 113,273 | | | 105,680 | | | 106,042 | | | 88,010 | | | 83,635 | | | 87,272 | |
Water | | | 53,852 | | | | 43,099 | | | | 24,629 | | | | 38,235 | | | | 31,560 | | | | 22,618 | | | | 53,788 | | | | 53,852 | | | | 43,099 | | | | 36,514 | | | | 38,235 | | | | 31,560 | |
Total | | | 1,211,749 | | | | 1,013,260 | | | | 1,011,452 | | | | 824,388 | | | | 796,123 | | | | 821,555 | | | | 1,102,029 | | | | 1,211,749 | | | | 1,013,260 | | | | 797,100 | | | | 824,388 | | | | 796,123 | |
The reconciliation of segment Adjusted EBITDA with the profit/(loss) attributable to the parent company is as follows:
| | For the year ended December 31, | | | For the year ended December 31, | |
| | 2021 | | | 2020 | | | 2019 | | | 2022 | | | 2021 | | | 2020 | |
Profit/(loss) attributable to the Company
| | | (30,080 | ) | | | 11,968 | | | | 62,135 | | | | (5,443 | ) | | | (30,080 | ) | | | 11,968 | |
Profit attributable to non-controlling interests | | | 19,162 | | | | 4,906 | | | | 12,473 | | | | 3,356 | | | | 19,162 | | | | 4,906 | |
Income tax expense
| | | 36,220 | | | | 24,877 | | | | 30,950 | | |
Income tax expense/(income)
| | | | (9,689 | ) | | | 36,220 | | | | 24,877 | |
Financial expense, net | | | 340,892 | | | | 331,810 | | | | 402,348 | | | | 310,934 | | | | 340,892 | | | | 331,810 | |
Depreciation, amortization, and impairment charges | | | 439,441 | | | | 408,604 | | | | 310,755 | | | | 473,638 | | | | 439,441 | | | | 408,604 | |
Depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of Atlantica's equity ownership) | | | 18,753
| | | | 13,958
| | | | 2,894
| | |
Depreciation and amortization, financial expense and income tax expense of unconsolidated affiliates (pro rata of Atlantica’s equity ownership) | | | | 24,304
| | | | 18,753
| | | | 13,958
| |
Total segment Adjusted EBITDA | | | 824,388 | | | | 796,123 | | | | 821,555 | | | | 797,100 | | | | 824,388 | | | | 796,123 | |
b) | The assets and liabilities by geography and business sector at the end of 20212022 and 20202021 are as follows: |
Assets and liabilities by geography as of December 31, 2021:2022:
| | North America | | South America | | EMEA | | Balance as of December 31, 2021
| | | North America | | South America | | EMEA | | Balance as of December 31, 2022
| |
Assets allocated | | | | | | | | | | | | | | | | | | |
Contracted concessional assets | | 3,355,669 | | | 1,231,276 | | | 3,434,623 | | | 8,021,568 | | |
Contracted concessional, PP&E and other intangible assets | | | 3,167,490 | | | 1,241,879 | | | 3,073,889 | | | 7,483,259 | |
Investments carried under the equity method | | 253,221 | | | 0 | | | 41,360 | | | 294,581 | | | 210,704 | | | 4,450 | | | 44,878 | | | 260,031 | |
Current financial investments | | 135,224 | | | 28,155 | | | 44,000 | | | 207,379 | | |
Other current financial assets | | | 118,385 | | | 31,136 | | | 46,373 | | | 195,893 | |
Cash and cash equivalents (project companies) | | | 171,744 | | | | 74,149 | | | | 287,655 | | | | 533,548 | | | | 187,568 | | | | 85,697 | | | | 266,557 | | | | 539,822 | |
Subtotal allocated | | | 3,915,858 | | | | 1,333,580 | | | | 3,807,638 | | | | 9,057,076 | | | | 3,684,147 | | | | 1,363,162 | | | | 3,431,697 | | | | 8,479,005 | |
Unallocated assets | | | | | | | | | | | | | | | | | | | | | | | | |
Other non-current assets | | | | | | | | | | | 268,876 | | | | | | | | | | | | 325,893 | |
Other current assets (including cash and cash equivalents at holding company level) | | | | | | | | | | | | 425,978 | | | | | | | | | | | | | 296,013 | |
Subtotal unallocated | | | | | | | | | | | | 694,854 | | | | | | | | | | | | | 621,906 | |
Total assets | | | | | | | | | | | | 9,751,930 | | | | | | | | | | | | | 9,100,911 | |
| | North America | | South America | | EMEA | | Balance as of December 31, 2021
| | | North America | | South America | | EMEA | | Balance as of December 31, 2022
| |
Liabilities allocated | | | | | | | | | | | | | | | | | | |
Long-term and short-term project debt | | 1,792,739 | | | 887,497 | | | 2,355,957 | | | 5,036,193 | | | 1,713,125 | | | 841,906 | | | 1,998,021 | | | 4,553,052 | |
Grants and other liabilities | | | 1,051,679 | | | | 14,445 | | | | 197,620 | | | | 1,263,744 | | | | 994,874 | | | | 25,031 | | | | 232,608 | | | | 1,252,513 | |
Subtotal allocated | | | 2,844,418 | | | | 901,942 | | | | 2,553,577 | | | | 6,299,937 | | | | 2,707,999 | | | | 866,937 | | | | 2,230,629 | | | | 5,805,565 | |
Unallocated liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Long-term and short-term corporate debt | | | | | | | | | | | 1,023,071 | | | | | | | | | | | | 1,017,200 | |
Other non-current liabilities | | | | | | | | | | | 532,312 | | | | | | | | | | | | 313,328 | |
Other current liabilities | | | | | | | | | | | | 148,005 | | | | | | | | | | | | | 175,771 | |
Subtotal unallocated | | | | | | | | | | | | 1,703,388 | | | | | | | | | | | | | 1,506,299 | |
Total liabilities | | | | | | | | | | | | 8,003,325 | | | | | | | | | | | | | 7,311,864 | |
Equity unallocated | | | | | | | | | | | | 1,748,605 | | | | | | | | | | | | | 1,789,047 | |
Total liabilities and equity unallocated | | | | | | | | | | | | 3,451,993 | | | | | | | | | | | | | 3,295,346 | |
Total liabilities and equity | | | | | | | | | | | | 9,751,930 | | | | | | | | | | | | | 9,100,911 | |
Assets and liabilities by geography as of December 31, 2020:2021:
| | North America | | South America | | EMEA | | Balance as of December 31, 2020
| | | North America | | South America | | EMEA | | Balance as of December 31, 2021
| |
Assets allocated | | | | | | | | | | | | | | | | | | |
Contracted concessional assets | | 3,073,785 | | | 1,211,952 | | | 3,869,681 | | | 8,155,418 | | |
Contracted concessional, PP&E and other intangible assets | | | 3,355,669 | | | 1,231,276 | | | 3,434,623 | | | 8,021,568 | |
Investments carried under the equity method | | 74,660 | | | 0 | | | 41,954 | | | 116,614 | | | 253,221 | | | - | | | 41,360 | | | 294,581 | |
Current financial investments | | 129,264 | | | 27,836 | | | 42,984 | | | 200,084 | | |
Other current financial assets | | | 135,224 | | | 28,155 | | | 44,000 | | | 207,379 | |
Cash and cash equivalents (project companies) | | | 206,344 | | | | 70,861 | | | | 255,530 | | | | 532,735 | | | | 171,744 | | | | 74,149 | | | | 287,655 | | | | 533,548 | |
Subtotal allocated | | | 3,484,053 | | | | 1,310,649 | | | | 4,210,149 | | | | 9,004,851 | | | | 3,915,858 | | | | 1,333,580 | | | | 3,807,638 | | | | 9,057,076 | |
Unallocated assets | | | | | | | | | | | | | | | | | | | | | | | | |
Other non-current assets | | | | | | | | | | | 242,044 | | | | | | | | | | | | 268,876 | |
Other current assets (including cash and cash equivalents at holding company level) | | | | | | | | | | | | 691,459 | | | | | | | | | | | | | 425,978 | |
Subtotal unallocated | | | | | | | | | | | | 933,503 | | | | | | | | | | | | | 694,854 | |
Total assets | | | | | | | | | | | | 9,938,354 | | | | | | | | | | | | | 9,751,930 | |
| | North America | | South America | | EMEA | | Balance as of December 31, 2020
| | | North America | | South America | | EMEA | | Balance as of December 31, 2021
| |
Liabilities allocated | | | | | | | | | | | | | | | | | | |
Long-term and short-term project debt | | 1,623,284 | | | 902,500 | | | 2,711,830 | | | 5,237,614 | | | 1,792,739 | | | 887,497 | | | 2,355,957 | | | 5,036,193 | |
Grants and other liabilities | | | 1,078,974 | | | | 11,355 | | | | 139,438 | | | | 1,229,767 | | | | 1,051,679 | | | | 14,445 | | | | 197,620 | | | | 1,263,744 | |
Subtotal allocated | | | 2,702,258 | | | | 913,855 | | | | 2,851,268 | | | | 6,467,381 | | | | 2,844,418 | | | | 901,942 | | | | 2,553,577 | | | | 6,299,937 | |
Unallocated liabilities | | | | | | | | | | | | | | | | | | | | | | | | |
Long-term and short-term corporate debt | | | | | | | | | | | 993,725 | | | | | | | | | | | | 1,023,071 | |
Other non-current liabilities | | | | | | | | | | | 589,107 | | | | | | | | | | | | 532,312 | |
Other current liabilities | | | | | | | | | | | | 147,260 | | | | | | | | | | | | | 148,005 | |
Subtotal unallocated | | | | | | | | | | | | 1,730,092 | | | | | | | | | | | | | 1,703,388 | |
Total liabilities | | | | | | | | | | | | 8,197,473 | | | | | | | | | | | | | 8,003,325 | |
Equity unallocated | | | | | | | | | | | | 1,740,881 | | | | | | | | | | | | | 1,748,605 | |
Total liabilities and equity unallocated | | | | | | | | | | | | 3,470,973 | | | | | | | | | | | | | 3,451,993 | |
Total liabilities and equity | | | | | | | | | | | | 9,938,354 | | | | | | | | | | | | | 9,751,930 | |
Assets and liabilities by business sectors as of December 31, 2022:
| | Renewable energy | | | Efficient natural gas & Heat
| | | Transmission lines | | | Water | | | Balance as of December 31, 2022
| |
Assets allocated | | | | | | | | | | | | | | | |
Contracted concessional, PP&E and other intangible assets | | | 6,035,091 | | | | 485,431 | | | | 800,067 | | | | 162,670 | | | | 7,483,259 | |
Investments carried under the equity method | | | 203,420 | | | | 10,034 | | | | 4,450 | | | | 42,128 | | | | 260,031 | |
Other current financial assets | | | 6,706
| | | | 116,366
| | | | 30,582
| | | | 42,240
| | | | 195,893
| |
Cash and cash equivalents (project companies) | | | 392,577 | | | | 73,673 | | | | 48,073 | | | | 25,498 | | | | 539,822 | |
Subtotal allocated | | | 6,637,794 | | | | 685,504 | | | | 883,172 | | | | 272,536 | | | | 8,479,005 | |
Unallocated assets | | | | | | | | | | | | | | | | | | | | |
Other non-current assets | | | | | | | | | | | | | | | | | | | 325,893 | |
Other current assets (including cash and cash equivalents at holding company level) | | | | | | | | | | | | | | | | | | | 296,013 | |
Subtotal unallocated | | | | | | | | | | | | | | | | | | | 621,906 | |
Total assets | | | | | | | | | | | | | | | | | | | 9,100,911 | |
| | Renewable energy | | | Efficient natural gas & Heat
| | | Transmission lines | | | Water | | | Balance as of December 31, 2022
| |
Liabilities allocated | | | | | | | | | | | | | | | |
Long-term and short-term project debt | | | 3,442,625 | | | | 440,999 | | | | 582,689 | | | | 86,739 | | | | 4,553,052 | |
Grants and other liabilities | | | 1,211,878 | | | | 32,138 | | | | 6,040 | | | | 2,457 | | | | 1,252,513 | |
Subtotal allocated | | | 4,654,503 | | | | 473,137 | | | | 588,729 | | | | 89,196 | | | | 5,805,565 | |
Unallocated liabilities | | | | | | | | | | | | | | | | | | | | |
Long-term and short-term corporate debt | | | | | | | | | | | | | | | | | | | 1,017,200 | |
Other non-current liabilities | | | | | | | | | | | | | | | | | | | 313,328 | |
Other current liabilities | | | | | | | | | | | | | | | | | | | 175,771 | |
Subtotal unallocated | | | | | | | | | | | | | | | | | | | 1,506,299 | |
Total liabilities | | | | | | | | | | | | | | | | | | | 7,311,864 | |
Equity unallocated | | | | | | | | | | | | | | | | | | | 1,789,047 | |
Total liabilities and equity unallocated | | | | | | | | | | | | | | | | | | | 3,295,346 | |
Total liabilities and equity | | | | | | | | | | | | | | | | | | | 9,100,911 | |
Assets and liabilities by business sectors as of December 31, 2021:
| | Renewable energy | | Efficient natural gas & Heat
| | Transmission lines | | Water | | Balance as of December 31, 2021
| | | Renewable energy | | Efficient natural gas & Heat
| | | | Water | | Balance as of December 31, 2021
| |
Assets allocated | | | | | | | | | | | | | | | | | | | | | | |
Contracted concessional assets | | 6,533,408 | | | 517,247 | | | 805,987 | | | 164,926 | | | 8,021,568 | | |
Contracted concessional, PP&E and other intangible assets | | | 6,533,408 | | | 517,247 | | | 805,987 | | | 164,926 | | | 8,021,568 | |
Investments carried under the equity method | | 240,302 | | | 15,358 | | | 0 | | | 38,921 | | | 294,581 | | | 240,302 | | | 15,358 | | | - | | | 38,921 | | | 294,581 | |
Current financial investments | | 10,761 | | | 128,461 | | | 27,813 | | | 40,344 | | | 207,379 | | |
Other current financial assets | | | 10,761
| | | 128,461
| | | 27,813
| | | 40,344
| | | 207,379
| |
Cash and cash equivalents (project companies) | | | 442,213 | | | | 25,392 | | | | 44,574 | | | | 21,369 | | | | 533,548 | | | | 442,213 | | | | 25,392 | | | | 44,574 | | | | 21,369 | | | | 533,548 | |
Subtotal allocated | | | 7,226,684 | | | | 686,458 | | | | 878,374 | | | | 265,560 | | | | 9,057,076 | | | | 7,226,684 | | | | 686,458 | | | | 878,374 | | | | 265,560 | | | | 9,057,076 | |
Unallocated assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other non-current assets | | | | | | | | | | | | | | 268,876 | | | | | | | | | | | | | | | 268,876 | |
Other current assets (including cash and cash equivalents at holding company level) | | | | | | | | | | | | | | | 425,978 | | | | | | | | | | | | | | | | 425,978 | |
Subtotal unallocated | | | | | | | | | | | | | | | 694,854 | | | | | | | | | | | | | | | | 694,854 | |
Total assets | | | | | | | | | | | | | | | 9,751,930 | | | | | | | | | | | | | | | | 9,751,930 | |
| | Renewable energy | | | Efficient natural gas & Heat
| | | Transmission lines | | | Water | | | Balance as of December 31, 2021
| |
Liabilities allocated | | | | | | | | | | | | | | | |
Long-term and short-term project debt | | | 3,857,313 | | | | 478,724 | | | | 602,278 | | | | 97,878 | | | | 5,036,193 | |
Grants and other liabilities | | | 1,244,346 | | | | 11,212 | | | | 5,795 | | | | 2,391 | | | | 1,263,744 | |
Subtotal allocated | | | 5,101,659 | | | | 489,936 | | | | 608,073 | | | | 100,269 | | | | 6,299,937 | |
Unallocated liabilities | | | | | | | | | | | | | | | | | | | | |
Long-term and short-term corporate debt | | | | | | | | | | | | | | | | | | | 1,023,071 | |
Other non-current liabilities | | | | | | | | | | | | | | | | | | | 532,312 | |
Other current liabilities | | | | | | | | | | | | | | | | | | | 148,005 | |
Subtotal unallocated | | | | | | | | | | | | | | | | | | | 1,703,388 | |
Total liabilities | | | | | | | | | | | | | | | | | | | 8,003,325 | |
Equity unallocated | | | | | | | | | | | | | | | | | | | 1,748,605 | |
Total liabilities and equity unallocated | | | | | | | | | | | | | | | | | | | 3,451,993 | |
Total liabilities and equity | | | | | | | | | | | | | | | | | | | 9,751,930 | |
Assets and liabilities by business sectors as of December 31, 2020:
| | Renewable energy | | | Efficient natural gas & Heat
| | | | | | Water | | | Balance as of December 31, 2020
| |
Assets allocated | | | | | | | | | | | | | | | |
Contracted concessional assets | | | 6,632,611 | | | | 502,285 | | | | 842,595 | | | | 177,927 | | | | 8,155,418 | |
Investments carried under the equity method | | | 61,866 | | | | 15,514 | | | | 30 | | | | 39,204 | | | | 116,614 | |
Current financial investments | | | 6,530 | | | | 124,872 | | | | 27,796 | | | | 40,886 | | | | 200,084 | |
Cash and cash equivalents (project companies) | | | 397,465 | | | | 67,955 | | | | 46,045 | | | | 21,270 | | | | 532,735 | |
Subtotal allocated | | | 7,098,472 | | | | 710,626 | | | | 916,466 | | | | 279,287 | | | | 9,004,851 | |
Unallocated assets | | | | | | | | | | | | | | | | | | | | |
Other non-current assets | | | | | | | | | | | | | | | | | | | 242,044 | |
Other current assets (including cash and cash equivalents at holding company level) | | | | | | | | | | | | | | | | | | | 691,459 | |
Subtotal unallocated | | | | | | | | | | | | | | | | | | | 933,503 | |
Total assets | | | | | | | | | | | | | | | | | | | 9,938,354 | |
| | Renewable energy | | | Efficient natural gas & Heat
| | | Transmission lines | | | Water | | | Balance as of December 31, 2020
| |
Liabilities allocated | | | | | | | | | | | | | | | |
Long-term and short-term project debt | | | 3,992,512 | | | | 504,293 | | | | 625,203 | | | | 115,606 | | | | 5,237,614 | |
Grants and other liabilities | | | 1,221,176 | | | | 108 | | | | 6,040 | | | | 2,443 | | | | 1,229,767 | |
Subtotal allocated | | | 5,213,688 | | | | 504,401 | | | | 631,243 | | | | 118,049 | | | | 6,467,381 | |
Unallocated liabilities | | | | | | | | | | | | | | | | | | | | |
Long-term and short-term corporate debt | | | | | | | | | | | | | | | | | | | 993,725 | |
Other non-current liabilities | | | | | | | | | | | | | | | | | | | 589,107 | |
Other current liabilities | | | | | | | | | | | | | | | | | | | 147,260 | |
Subtotal unallocated | | | | | | | | | | | | | | | | | | | 1,730,092 | |
Total liabilities | | | | | | | | | | | | | | | | | | | 8,197,473 | |
Equity unallocated | | | | | | | | | | | | | | | | | | | 1,740,881 | |
Total liabilities and equity unallocated | | | | | | | | | | | | | | | | | | | 3,470,973 | |
Total liabilities and equity | | | | | | | | | | | | | | | | | | | 9,938,354 | |
c) | The amount of depreciation, amortization and impairment charges recognized for the years ended December 31, 2022, 2021 2020 and 20192020 are as follows: |
| | For the year ended December 31, | | | For the year ended December 31, | |
Depreciation, amortization and impairment by geography | | 2021 | | | 2020 | | | 2019 | | | 2022 | | | 2021 | | | 2020 | |
North America | | | (152,946 | ) | | | (197,643 | ) | | | (116,232 | ) | | | (182,159 | ) | | | (152,946 | ) | | | (197,643 | ) |
South America | | | (57,214 | ) | | | (39,191 | ) | | | (47,844 | ) | | | (80,039 | ) | | | (57,214 | ) | | | (39,191 | ) |
EMEA | | | (229,281 | ) | | | (171,770 | ) | | | (146,679 | ) | | | (211,440 | ) | | | (229,281 | ) | | | (171,770 | ) |
Total | | | (439,441 | ) | | | (408,604 | ) | | | (310,755 | ) | | | (473,638 | ) | | | (439,441 | ) | | | (408,604 | ) |
| | For the year ended December 31, | | | For the year ended December 31, | |
Depreciation, amortization and impairment by business sectors | | 2021 | | | 2020 | | | 2019 | | | 2022 | | | 2021 | | | 2020 | |
Renewable energy | | | (432,138 | ) | | | (350,785 | ) | | | (286,907 | ) | | | (434,042 | ) | | | (432,138 | ) | | | (350,785 | ) |
Efficient natural gas & Heat
| | | 23,910 | | | | (26,563 | ) | | | 3,102 | | | | (5,430 | ) | | | 23,910 | | | | (26,563 | ) |
Transmission lines
| | | (31,286 | ) | | | (30,889 | ) | | | (27,490 | ) | | | (32,466 | ) | | | (31,286 | ) | | | (30,889 | ) |
Water | | | 73 | | | | (367 | ) | | | 541 | | | | (1,700 | ) | | | 73 | | | | (367 | ) |
Total | | | (439,441 | ) | | | (408,604 | ) | | | (310,755 | ) | | | (473,638 | ) | | | (439,441 | ) | | | (408,604 | ) |
Note 5.- Business combinations
For the year ended December 31, 2022
On January 17, 2022, the Company closed the acquisition of Chile TL4, a 63-mile transmission line and 2 substations in Chile for a total equity investment of $38.4 million. Atlantica has control over Chile TL4 under IFRS 10, Consolidated Financial Statements. The acquisition of Chile TL4 has been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. Chile TL4 is included within the Transmission Lines sector and the South America geography.
On April 4, 2022, the Company closed the acquisition of Italy PV 4, a 3.6 MW solar portfolio in Italy for a total equity investment of $3.7 million. Atlantica has control over Italy PV 4 under IFRS 10, Consolidated Financial Statements. The acquisition of Italy PV 4 has been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. Italy PV4 is included within the Renewable energy sector and the EMEA geography.
On September 2, 2022 the Company closed the acquisition of Chile PV 3, a 73 MW solar PV plant through its renewable energy platform in Chile for a total equity investment of $7.7 million. Atlantica has control over Chile PV 3 under IFRS 10, Consolidated Financial Statements. The acquisition of Chile PV 3 has been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations, showing 65% of non-controlling interests. Chile PV 3 is included within the Renewable energy sector and the South America geography.
The fair value of assets and liabilities consolidated at the effective acquisition date is shown in aggregate on the basis that they are individually not significant in the following table:
| | Business combinations for the year ended December 31, 2022 | |
| | | |
Property, plant and equipment under IAS 16 (Note 6) | | | 58,002 | |
Rights of use under IFRS 16 (Lessee) or intangible assets under IAS 38 (Note 6) | | | 16,993 | |
Cash & cash equivalents | | | 1,057 | |
Other current assets | | | 8,283 | |
Non-current Project debt (Note 15) | | | (1,301 | ) |
Current Project debt (Note 15) | | | (148 | ) |
Other current and non-current liabilities | | | (18,919 | ) |
Non-controlling interests | | | (14,300 | ) |
Total net assets acquired at fair value | | | 49,667 | |
Asset acquisition – purchase price paid | | | (49,667 | ) |
Net result of business combinations | | | - | |
The purchase price equals the fair value of the net assets acquired.
The allocation of the purchase price is provisional as of December 31, 2022 and amounts indicated above may be adjusted during the measurement period to reflect new information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the amounts recognized as of December 31, 2022. The measurement period will not exceed one year from the acquisition dates.
The amount of revenue contributed by the acquisitions performed during 2022 to the Consolidated Financial Statements of the Company for the year 2022 is $6.2 million, and the amount of profit after tax is $1.7 million. Had the acquisitions been consolidated from January 1, 2022, the consolidated statement of comprehensive income would have included additional revenue of $4.8 million and additional profit after tax of $1.7 million.
For the year ended December 31, 2021
On January 6, 2021, the Company completed its second investment through its Chilean renewable energy platform in a 40 MW solar PV plant, Chile PV 2, located in Chile, for approximately $5 million. Atlantica has control over Chile PV 2 under IFRS 10, Consolidated Financial Statements. The acquisition of Chile PV 2 hashad been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations, showing 65% of non-controlling interests. Chile PV 2 is included within the Renewable energy sector and the South America geography.
On January 8, 2021, the Company completed the purchase of an additional 42.5% stake in Rioglass, a supplier of spare parts and services to the solar industry, increasing its stake from 15% to 57.5% and gaining control over the business under IFRS 10, Consolidated Financial Statements. The purchase price paid was $8.6 million, and the Company paid an additional $3.7 million (deductible from the final payment) for an option to acquire the remaining 42.5% under the same conditions until September 2021. On July 22, 2021, the Company exercised the option paying an additional $4.8 million, becoming the sole shareholder of the entity. Rioglass is included within the Renewable energy sector and the EMEA geography. The acquisition of Rioglass hashad been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations.
On April 7, 2021, the Company closed the acquisition of Coso, a 135 MW renewable asset in California. The purchase price paid was $130 million. Atlantica has control over Coso under IFRS 10, Consolidated Financial Statements and its acquisition hashad been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. Coso is included within the Renewable energy sector and the North America geography.
On May 14, 2021, the Company closed the acquisition of Calgary District Heating, a district heating asset of approximately 55 MWt in Canada. The purchase price paid was approximately $22.7$22.9 million. The acquisition hashad been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. Calgary District Heating is included within the Efficient natural gas and Heat sector and the North America geography.
On August 6, 2021, the Company closed the acquisition of Italy PV 1 and Italy PV 2, 2two solar PV plants in Italy with a combined capacity of 3.7 MW for a total equity investment of $9 million. The acquisition hashad been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. These assets are included within the Renewable energy sector and the EMEA geography.
On November 25, 2021, the Company closed the acquisition of La Sierpe, a 20 MW solar PV plant in Colombia for a total equity investment of approximately $23.5 million. The acquisition hashad been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. La Sierpe is included within the Renewable energy sector and the South America geography.
On December 14, 2021, the Company closed the acquisition of Italy PV 3, a 2.5 MW solar asset in Italy for a total equity investment of approximately $4.0 million. The acquisition hashad been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations. Italy PV 3 is included within the Renewable Energy sector and the EMEA geography.
The fair value of assets and liabilities consolidated at the effective acquisition date is shown in aggregate under Other on the basis that they are individually not significant in the following table:
| | Business combinations for the year ended December 31, 2021 | |
| | Coso | | | Other | | | Total | |
Contracted concessional assets (Note 6) | | | 383,153 | | | | 158,927 | | | | 542,080 | |
Deferred tax asset (Note 18) | | | 0 | | | | 4,410 | | | | 4,410 | |
Other non-current assets | | | 11,024 | | | | 1,943 | | | | 12,967 | |
Cash & cash equivalents | | | 6,363 | | | | 14,649 | | | | 21,012 | |
Other current assets | | | 14,378 | | | | 46,679 | | | | 61,057 | |
Non-current Project debt (Note 15) | | | (248,544 | ) | | | (39,808 | ) | | | (288,352 | ) |
Current Project debt (Note 15) | | | (13,415 | ) | | | (25,366 | ) | | | (38,781 | ) |
Deferred tax liabilities (Note 18) | | | 0 | | | | (4,910 | ) | | | (4,910 | ) |
Other current and non-current liabilities | | | (22,959 | ) | | | (64,825 | ) | | | (87,784 | ) |
Non-controlling interests | | | 0 | | | | (8,287 | ) | | | (8,287 | ) |
Total net assets acquired at fair value | | | 130,000 | | | | 83,412 | | | | 213,412 | |
Asset acquisition – purchase price paid | | | (130,000 | ) | | | (80,364 | ) | | | (210,364 | ) |
Fair value of previously held 15% stake in Rioglass | | | 0 | | | | (3,048 | ) | | | (3,048 | ) |
Net result of business combinations | | | 0 | | | | 0 | | | | 0 | |
| | Business combinations for the year ended December 31, 2021 | |
| | Coso | | | Other | | | Total | |
Property, plant and equipment under IAS 16 (Note 6) | | | 383,153 | | | | 137,426
|
| | | 520,579 | |
Rights of use under IFRS 16 (Lessee) or intangible assets under IAS 38 (Note 6) | | | - | | | | 22,149 | | | | 22,149 | |
Deferred tax asset (Note 18) | | | - | | | | 4,410 | | | | 4,410 | |
Other non-current assets | | | 11,024 | | | | 1,943 | | | | 12,967 | |
Cash & cash equivalents | | | 6,363 | | | | 14,649 | | | | 21,012 | |
Other current assets | | | 14,378 | | | | 46,632 | | | | 61,010 | |
Non-current Project debt (Note 15) | | | (248,544 | ) | | | (39,808 | ) | | | (288,352 | ) |
Current Project debt (Note 15) | | | (13,415 | ) | | | (25,366 | ) | | | (38,781 | ) |
Deferred tax liabilities (Note 18) | | | - | | | | (4,910 | ) | | | (4,910 | ) |
Other current and non-current liabilities | | | (22,959 | ) | | | (64,922 | ) | | | (87,881 | ) |
Non-controlling interests | | | - | | | | (8,287 | ) | | | (8,287 | ) |
Total net assets acquired at fair value | | | 130,000 | | | | 83,916 | | | | 213,916 | |
Asset acquisition – purchase price paid | | | (130,000 | ) | | | (80,868 | ) | | | (210,868 | ) |
Fair value of previously held 15% stake in Rioglass | | | - | | | | (3,048 | ) | | | (3,048 | ) |
Net result of business combinations | | | - | | | | - | | | | - | |
The purchase price equalsequalled the fair value of the net assets acquired.
The allocation of the purchase price is provisional as of December 31, 2021 and amounts indicated above may be adjusted during the measurement period to reflect new information obtained about facts and circumstances that existed at the acquisition date that, if known, would have affected the amounts recognized as of December 31, 2021. The measurement period will not exceed one year from the acquisition dates.
The amount of revenue contributed by the acquisitions performed during 2021 to the Consolidated Financial Statements of the Company for the year 2021 iswas $163.5 million, and the amount of profit after tax iswas $0.8 million. Had the acquisitions been consolidated from January 1, 2021, the consolidated statement of comprehensive income would have included additional revenue of $17.7 million and additional profit after tax of $3.3 million.
For the year ended December 31, 2020
On April 3, 2020, the Company completed the investment in a 35% stake in a renewable energy platform in Chile for approximately $4 million and the acquisition of Chile PV 1, a 55 MW solar PV plant, through the platform. Atlantica has control over Chile PV 1 under IFRS 10, Consolidated Financial Statements. The acquisition of Chile PV 1 had been accounted for in these Consolidated Financial Statements in accordance with IFRS 3, Business Combinations, showing 65% of non-controlling interest.Chile PV 1 is included within the Renewable energy sector and the South America geography.
On May 31, 2020, the Company obtained the right to appoint the majority of directors of the board of Befesa Agua Tenes, which owns a 51% stake in Tenes, and therefore controls the asset, a water desalination plant in Algeria. The total investment amounted to approximately $19 million as of May 31, 2020. The acquisition had been accounted for in the Consolidated Financial Statements of Atlantica, in accordance with IFRS 3, Business Combinations, showing 49% of non-controlling interest.Tenes is included within the Water sector and the EMEA geography.
The fair value of assets and liabilities consolidated at the effective acquisition date is shown in the following table:
Business combinations for the year ended December 31, 2020 | |
Contracted concessional assets (Note 6) | | | 172,321 | |
Other non-current assets | | | 356 | |
Cash & cash equivalents | | | 17,646 | |
Other current assets | | | 31,421 | |
Non-current Project debt (Note 15) | | | (149,585 | ) |
Current Project debt (Note 15) | | | (8,680 | ) |
Other current and non-current liabilities | | | (15,561 | ) |
Non-controlling interests | | | (25,308 | ) |
Total net assets acquired at fair value | | | 22,610 | |
Asset acquisition - purchase price | | | (22,610 | ) |
Net result of business combinations | | | 0 | |
The purchase price equalled the fair value of the net assets acquired.
The amount of revenue contributed by the acquisitions performed during 2020 to the Consolidated Financial Statements of the Company for the year 2020 was $22.5 million, and the amount of profit after tax was $6.3 million. Had the acquisitions been consolidated from January 1, 2020, the consolidated statement of comprehensive income would have included additional revenue of $14.7 million and additional profit after tax of $3.7 million.
In April and May 2021, the provisional period for the purchase price allocation of Chile PV 1 and Tenes, respectively,all the businesses acquired in 2021 closed during the year 2022 and did not result in significant adjustments to the initial amounts recognized.
Note 6.- Contracted concessional, PP&E and other intangible assets
Contracted concessionalThe Company has assets correspond to the assets of the Company recorded as intangible or financial assets in accordance with IFRIC 12, property plant and equipment in accordance with IAS 16 and financial asset in accordance withright of use assets under IFRS 16.
16 or intangible assets under IAS 38.For further details on the application of IFRIC 12 to assets of the Company, see Appendix III.
a) | The following table shows the movements of assets included in the heading “Contracted Concessional assets” for 2021: |
The following table shows the movements of assets included in the heading “Contracted Concessional, PP&E and other intangible assets” for 2022:
Cost | | Financial assets under IFRIC 12 | | | Financial assets under IFRS 16 (Lessor) | | | Intangible assets under IFRIC 12 | | | Intangible assets under IFRS 16 (Lessee) | | | Property, plant and equipment under IAS
16 and other intangible assets under IAS 38
| | | Total assets | | | Financial assets under IFRIC 12 | | | Financial assets under IFRS 16 (Lessor) | | | Intangible assets under IFRIC 12 | | | Right of use assets under IFRS 16 (Lessee) and intangible assets under IAS 38 | | | Property, plant and equipment under IAS 16 | | | Total assets | |
Total as of January 1, 2021 | | | 936,837 | | | | 2,941 | | | | 9,467,309 | | | | 66,230 | | | | 350,720 | | | | 10,824,037 | | |
Total as of January 1, 2022 | | | | 874,525 | | | | 2,843 | | | | 9,202,539 | | | | 100,109 | | | | 839,119 | | | | 11,019,135 | |
Additions | | | 922 | | | | 442 | | | | 40,383 | | | | 2,459 | | | | 14,204 | | | | 58,410 | | | | - | | | | - | | | | 32,941 | | | | 4,155 | | | | 80,196 | | | | 117,292 | |
Subtractions | | | 0 | | | | 0 | | | | (348 | ) | | | 0 | | | | (21,282 | ) | | | (21,630 | ) | | | - | | | | (57 | ) | | | (499 | ) | | | (1,350 | ) | | | (8,655 | ) | | | (10,561 | ) |
Business combinations (Note 5) | | | 0 | | | | 0 | | | | 0 | | | | 19,148 | | | | 522,932 | | | | 542,080 | | | | - | | | | - | | | | - | | | | 16,993 | | | | 58,002 | | | | 74,995 | |
Currency translation differences | | | (9,519 | ) | | | (540 | ) | | | (334,497 | ) | | | (5,019 | ) | | | (20,703 | ) | | | (370,278 | ) | | | 1,760 | | | | 1 | | | | (261,536 | ) | | | (4,531 | ) | | | (21,006 | ) | | | (285,312 | ) |
Reclassification and other movements | | | (53,715 | ) | | | 0 | | | | 29,692 | | | | 0 | | | | 10,539 | | | | (13,484 | ) | | | (58,115 | ) | | | - | | | | 2,798 | | | | (6,200 | ) | | | 8,950 | | | | (52,567 | ) |
Total cost | | | 874,525 | | | | 2,843 | | | | 9,202,539 | | | | 82,818 | | | | 856,410 | | | | 11,019,135 | | |
Total cost, as of December 31, 2022
| | | | 818,170 | | | | 2,787 | | | | 8,976,243 | | | | 109,176 | | | | 956,606 | | | | 10,862,982 | |
Depreciation, amortization and impairment | | Financial assets under IFRIC 12 | | | Financial assets under IFRS 16 (Lessor) | | | Intangible assets under IFRIC 12 | | | Intangible assets under IFRS 16 (Lessee) | | | Property, plant and equipment under IAS
16 and other intangible assets under IAS 38 | | | Total assets | | | Financial assets under IFRIC 12 | | | Financial assets under IFRS 16 (Lessor) | | | Intangible assets under IFRIC 12 | | | Right of use assets under IFRS 16 (Lessee) and intangible assets under IAS 38 | | | Property, plant and equipment under IAS 16
| | | Total assets | |
Total as of January 1, 2021 | | | (87,689 | ) | | | 0 | | | | (2,442,520 | ) | | | (10,060 | ) | | | (128,350 | ) | | | (2,668,619 | ) | |
Total as of January 1, 2022 | | |
| (62,889 | ) | | | - | | | | (2,769,345 | ) | | | (21,578 | ) | | | (143,755 | ) | | | (2,997,567 | ) |
Additions | | | (418 | ) | | | 0 | | | | (424,181 | ) | | | (4,759 | ) | | | (31,003 | ) | | | (460,361 | ) | | | (6,560 | ) | | | - | | | | (398,639 | ) | | | (6,419 | ) | | | (64,306 | ) | | | (475,924 | ) |
Reversal of impairment | | | 24,929 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 24,929 | | |
Subtractions | | | | -
| | | | -
| | | | -
| | | | 859 | | | | 7,643 | | | | 8,502
| |
Currency translation differences | | | 289 | | | | 0 | | | | 97,356 | | | | 714 | | | | 8,125 | | | | 106,484 | | | | (108 | ) | | | - | | | | 79,206 | | | | 822 | | | | 5,346 | | | | 85,266 | |
Total depreciation, amortization and impairment | | | (62,889 | ) | | | 0 | | | | (2,769,345 | ) | | | (14,105 | ) | | | (151,228 | ) | | | (2,997,567 | ) | |
Total depreciation, amortization and impairment, as of December 31, 2022
| | | | (69,557 | ) | | | - | | | | (3,088,778 | ) | | | (26,316 | ) | | | (195,072 | ) | | | (3,379,723 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total net book value, as of December 31, 2022
| | | | 748,613 | | | | 2,787 | | | | 5,887,465 | | | | 82,860 | | | | 761,534 | | | | 7,483,259 | |
The decrease in the contracted concessional assets cost is primarily due to the lower value of the Euro denominated assets since the exchange rate of the Euro decreased against the U.S. dollar since December 31, 2021, that more than offsets the increase resulting from business combinations and the additions for the year that primarily correspond to investments in operating concessional assets and assets under development or construction. The increase in accumulated depreciation, amortization and impairment is primarily due to the amortization charge for the year and the impairment registered in Solana, Chile PV1 and Chile PV2 (see further explanation below).
The decrease included in “Reclassification and other movement” is mainly due to the reclassification from the long to the short term of the current portion of the contracted concessional financial assets.
The following table shows the movements of assets included in the heading “Contracted Concessional, PP&E and other intangible assets” for 2021:
Cost | | Financial assets under IFRIC 12 | | | Financial assets under IFRS 16 (Lessor) | | | Intangible assets under IFRIC 12 | | | Right of use assets under IFRS 16 (Lessee) and intangible assets under IAS 38 | | | Property, plant and equipment under IAS 16
| | | Total assets | |
Total as of January 1, 2021 | | | 936,837 | | | | 2,941 | | | | 9,467,309 | | | | 80,030 | | | | 336,920 | | | | 10,824,037 | |
Additions | | | 922 | | | | 442 | | | | 40,383 | | | | 3,639 | | | | 13,024 | | | | 58,410 | |
Subtractions | | | - | | | | - | | | | (348 | ) | | | (16 | ) | | | (21,266 | ) | | | (21,630 | ) |
Business combinations (Note 5) | | | - | | | | - | | | | - | | | | 22,149 | | | | 519,931 | | | | 542,080 | |
Currency translation differences | | | (9,519 | ) | | | (540 | ) | | | (334,497 | ) | | | (5,693 | ) | | | (20,029 | ) | | | (370,278 | ) |
Reclassification and other movements | | | (53,715 | ) | | | - | | | | 29,692 | | | | - | | | | 10,539 | | | | (13,484 | ) |
Total cost, as of December 31, 2021
| | | 874,525 | | | | 2,843 | | | | 9,202,539 | | | | 100,109 | | | | 839,119 | | | | 11,019,135 | |
Depreciation, amortization and impairment | | Financial assets under IFRIC 12 | | | Financial assets under IFRS 16 (Lessor) | | | Intangible assets under IFRIC 12 | | | Right of use assets under IFRS 16 (Lessee) and intangible assets under IAS 38 | | | Property, plant and equipment under IAS 16
| | | Total assets | |
Total as of January 1, 2021 | | | (87,689 | ) | | | - | | | | (2,442,520 | ) | | | (16,171 | ) | | | (122,239 | ) | | | (2,668,619 | ) |
Additions | | | (418 | ) | | | - | | | | (424,181 | ) | | | (6,370 | ) | | | (29,392 | ) | | | (460,361 | ) |
Reversal of impairment
| | | 24,929 | | | | - | | | | - | | | | - | | | | - | | | | 24,929 | |
Currency translation differences | | | 289 | | | | - | | | | 97,356 | | | | 963 | | | | 7,876 | | | | 106,484 | |
Total depreciation, amortization and impairment, as of December 31, 2021 | | | (62,889 | ) | | | - | | | | (2,769,345 | ) | | | (21,578 | ) | | | (143,755 | ) | | | (2,997,567 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total net book value, as of December 31, 2021 | | | 811,636 | | | | 2,843 | | | | 6,433,194 | | | | 78,531 | | | | 695,364 | | | | 8,021,568 | |
The increase in the contracted concessional assets cost iswas primarily due to business combinations for a total amount of $542 million (Note 5), partially offset by the lower value of the Euro denominated assets since the exchange rate of the Euro decreased against the U.S. dollar since December 31, 2020.
This increase iswas mainly offset by the depreciation and amortization charge for the year and the impairment registered in Solana (see further explanation below).
The decrease included in “Reclassification and other movement” iswas mainly due to the reclassification from the long to the short term of the current portion of the contracted concessional financial assets.
Solana triggering event of impairment
Considering the continued delays in the improvementsworks and replacements that the Company is carrying out in the storage system inat Solana and their impact on production in 2021,2022, as well as an increase in the discount rate, the Company identified an impairment triggering event, in accordance with IAS 36, Impairment of assets. As a result, an impairment test has been performed using historical level of output (generation), which resulted in the recording of an impairment loss of $43$41 million as of December 31, 2021.in 2022 ($43 million in 2021).
The impairment has been recorded within the line “Depreciation, amortization and impairment charges” of the consolidated income statement, decreasing the amount of “Contracted concessional assets”intangible assets under IFRIC 12 pertaining to the Renewable energy sector and the North America geography. The recoverable amount considered is the value in use and amounts to $943$881 million for Solana, as of December 31, 2021.2022 ($943 million as of December 31, 2021). A specific discount rate has been used in each year considering changes in the debt/equity leverage ratio over the useful life of this project, resulting in the use of a range of pre-tax discount rates between 4.5%5.9% and 5.0%6.3% in 2022 (between 4.9% and 5.9% in 2021).
An adverse change in the key assumptions which are individually used for the valuation could lead to future impairment recognition; specifically, a 5% decrease in generation over the entire remaining useful life (PPA) of the project would generate an additional impairment of approximately $69$59 million. An increase of 50 basis points in the discount rate would lead to an additional impairment of approximately $41$33 million.
Chile PV1 and Chile PV2 triggering event of impairment
Considering that expected electricity prices in Chile over the remaining useful life of Chile PV1 and Chile PV2 have recently decreased and are currently lower than the prices assumed at the time of the acquisition, the Company identified an impairment triggering event, in accordance with IAS 36, Impairment of assets. As a result, an impairment test has been performed which resulted in the recording of an impairment loss of $8 million for Chile PV1 and $12 million for Chile PV2 in 2022.
The impairment has been recorded within the line “Depreciation, amortization and impairment charges” of the consolidated income statement, decreasing the amount of Property, plant and equipment under IAS 16 pertaining to the Renewable energy sector and the South America geography. The recoverable amount considered is the value in use and amounts to $58 million for Chile PV1 and $22 million for Chile PV2, as of December 31, 2022. A specific discount rate has been used in each year considering changes in the debt/equity leverage ratio over the useful life of these projects, resulting in the use of a range of pre-tax discount rates between 7.5% and 8.4% for Chile PV1 and 7.5% and 8.3% for Chile PV2.
An adverse change in the key assumptions which are individually used for the valuation could lead to future impairment recognition; specifically, a 5% decrease in electricity prices over the entire remaining useful life of these projects would generate an additional total impairment of approximately $5 million. An increase of 50 basis points in the discount rate would lead to an additional total impairment of approximately $3 million.
The Company did not identify any other triggering event of impairment of its contracted concessional assets as of December 31, 2022 and 2021.
Expected credit losses
The impairment provision based on the expected credit losses on contracted concessional financial assets, calculated in accordance with IFRS 9, Financial instruments, decreasedincreased by $7 million in the year ended December 31, 2022, (decreased by $25 million in the year ended December 31, 2021, primarily in ACT, following an improvement of its client’s credit risk metrics.
b) | The following table shows the movements of assets included in the heading “Contracted Concessional assets” for 2020: |
Cost | | Financial assets under IFRIC 12 | | | Financial assets under IFRS 16 (Lessor) | | | Intangible assets under IFRIC 12 | | | Intangible assets under IFRS 16 (Lessee) | | | Property, plant and equipment under IAS
16 and other intangible assets under IAS 38 | | | Total assets | |
Total as of January 1, 2020 | | | 872,945 | | | | 3,459 | | | | 9,183,011 | | | | 60,618 | | | | 264,564 | | | | 10,384,597 | |
Additions | | | 0 | | | | 0 | | | | 29,213 | | | | 1,832 | | | | 4,310 | | | | 35,355 | |
Subtractions | | | 0 | | | | 0 | | | | (71,706 | ) | | | (954 | ) | | | (223 | ) | | | (72,883 | ) |
Business combinations (Note 5) | | | 102,560 | | | | 0 | | | | 0 | | | | 385 | | | | 63,916 | | | | 166,861 | |
Currency translation differences | | | (8,166 | ) | | | (163 | ) | | | 326,791 | | | | 4,349 | | | | 18,153 | | | | 340,964 | |
Reclassification and other movements | | | (30,502 | ) | | | (355 | ) | | | 0 | | | | 0 | | | | 0 | | | | (30,857 | ) |
Total cost | | | 936,837 | | | | 2,941 | | | | 9,467,309 | | | | 66,230 | | | | 350,720 | | | | 10,824,037 | |
Depreciation, amortization and impairment | | Financial assets under IFRIC 12 | | | Financial assets under IFRS 16 (Lessor) | | | Intangible assets under IFRIC 12 | | | Intangible assets under IFRS 16 (Lessee) | | | Property, plant and equipment under IAS
16 and other intangible assets under IAS 38 | | | Total assets | |
Total as of January 1, 2020 | | | (57,258 | ) | | | 0 | | | | (2,055,946 | ) | | | (6,585 | ) | | | (103,679 | ) | | | (2,223,468 | ) |
Additions | | | (27,111 | ) | | | 0 | | | | (338,393 | ) | | | (3,527 | ) | | | (15,958 | ) | | | (384,989 | ) |
Subtractions | | | 0 | | | | 0 | | | | 17,571 | | | | 634 | | | | 49 | | | | 18,253 | |
Reversal of impairment
| | | 0 | | | | 0 | | | | 18,787 | | | | 0 | | | | 0 | | | | 18,787 | |
Business combinations (Note 5)
| | | (3,797 | ) | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | (3,797 | ) |
Currency translation differences | | | 476 | | | | 0 | | | | (84,538 | ) | | | (581 | ) | | | (8,762 | ) | | | (93,405 | ) |
Total depreciation, amortization and impairment | | | (87,689 | ) | | | 0 | | | | (2,442,520 | ) | | | (10,060 | ) | | | (128,350 | ) | | | (2,668,619 | ) |
metrics), primarily in ACT.
During 2020, the cost of contracted concessional assets increased primarily due to the effect of the appreciation of the Euro against the U.S. dollar for the year ended December 31,2020, compared to the year ended December 31, 2019, and to the acquisition of new concessional assets (Note 5).
This increase was mainly offset by the amortization charge for the year and the write-off registered in Solana (see below).
The decrease included in “Reclassification and other movements” was mainly due to the reclassification from the long to the short term of the current portion of the contracted concessional financial assets.
Solana storage system partial write-off
The availability in the storage system of Solana was lower than expected in 2020 due to certain leaks identified in the storage system in the first quarter. The Company identified some elements of the storage system to be replaced, which were written off in these Consolidated Financial Statements through profit and loss in the line “Depreciation, amortization, and impairment charges” for an estimated net book value of approximately $48 million.
Solana triggering event of impairment
The Company identified in 2020 a triggering event of impairment for Solana as a result of the underperformance of the plant in terms of production. The Company therefore performed an impairment test as of December 31, 2020, which resulted in the recoverable amount (value in use) exceeding the carrying amount of the asset by 10%. To determine the value in use of the asset, a specific discount rate had been used in each year considering changes in the debt/equity leverage ratio over the useful life of this project, resulting in the use of a range of discount rates between 3.8% and 4.3%.
An adverse change in the key assumptions which are individually used for the valuation would not have led to future impairment recognition; neither in case of a 5% decrease in generation over the entire remaining useful life (PPA) of the project nor in case of an increase of 50 basis points in the discount rate.
Change in the useful life of the solar plants in Spain
Further to the recent developments in the Energy and Climate Policy Framework adopted by Spain in 2020, the Company concluded that the expected deep transformation of the electricity sector in Spain would probably significantly reduce the market price at which the electricity is sold in the mid- to long-term. In particular, the Company believed this may impact the price captured by the Company’s solar plants in Spain after the end of the regulation in place (2035 to 2038 onwards). As a result, the price captured by the plants after 2035 to 2038 (the end of the 25 years regulatory period) would likely not be sufficient to cover operating costs. In this case, the plants would stop operating and be dismantled at that point in time.
The Company believed that it was possible that long-term price evolution and technology changes could result in scenarios where the plants may continue to operate after the end of the regulatory period. Nevertheless, given the information currently available, the Company decided to reduce the useful life of the CSP plants in Spain from 35 years to 25 years after COD. This change of estimate of the useful life, effective September 1st, 2020, was accounted for as a change in accounting estimate in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors.
The main impacts recorded prospectively in these Consolidated Financial Statements were:
- | an increased amortization charge from September 1st, 2020, considering the reduction in the residual useful life of the plants. The impact was approximately $23 million as of December 31, 2020, recorded within the line “Depreciation, amortization and impairment charges” in the profit and loss statement.
|
- | an increase in the discounted value of the dismantling provision, as the dismantling of the plants would occur earlier. The provision increased by approximately $13 million as of December 31, 2020 (Note 16). |
In addition, reducing the useful life of the solar plants in Spain was a triggering event of impairment, given that the recoverable amount of the asset is negatively impacted if the plants stop operating in year 25 after COD.
The Company therefore performed an impairment test as of December 31, 2020, which resulted in the recoverable amount (value in use) exceeding the carrying amount of the assets by 6%. To determine the value in use of the assets, a specific discount rate had been used in each year considering changes in the debt/equity leverage ratio over the useful life of these projects, resulting in the use of a range of discount rates between 3.3% and 3.8%.
An adverse change in the key assumptions which were individually used for the valuation would not have led to future impairment recognition; neither in case of a 5% decrease in generation over the entire remaining useful life of the projects nor in case of an increase of 50 basis points in the discount rate.
Palmatir and Cadonal impairment reversals
As part of the triggering event analysis performed for Palmatir and Cadonal assets in 2020, the Company identified factors, such as a reduced discount rate according to favorable market conditions, increasing their recoverable amount (value in use). The Company therefore performed an impairment test as of December 31, 2020, which resulted in the reversal of impairments previously recorded, for an amount of $15.6 million and $3.1 million in Cadonal and Palmatir, respectively, recorded within the line “Depreciation, amortization and impairment charges” of the profit and loss statement.
No losses from impairment of contracted concessional assets, excluding any change in the provision for expected credit losses under IFRS 9, Financial instruments, were recorded during the year ended December 31, 2020. The impairment provision based on the expected credit losses on contracted concessional financial assets increased by $29 million in the year ended December 31, 2020, primarily in ACT.
Note 7.- Investments carried under the equity method
The table below shows the breakdown and the movement of the investments held in associates and joint ventures for 20212022 and 2020:2021:
Investments in associates | | 2021
| | | 2020
| | |
Investments in associates and joint ventures
| | | 2022
| | | 2021
| |
Initial balance | | | 116,614 | | | | 139,925 | | | | 294,581 | | | | 116,614 | |
Share of profit | | | 12,304 | | | | 510 | | | | 21,465 | | | | 12,304 | |
Distributions | | | (36,877 | ) | | | (23,703 | ) | | | (57,537 | ) | | | (36,877 | ) |
Acquisitions | | | 202,345 | | | | 0 | | | | 4,901 | | | | 202,345 | |
Others (incl. currency translation differences) | | | 195 | | | | (118 | ) | | | (3,379 | ) | | | 195 | |
Final balance | | | 294,581 | | | | 116,614 | | | | 260,031 | | | | 294,581 | |
In November 2022, Atlantica closed the acquisition of a 49% interest, with joint control, in Chile PMGD, an 80 MW portfolio of solar PV assets in Chile, which is currently starting construction (Note 1). Chile PMGD is accounted for in these Consolidated Financial Statements using the equity method as per IAS 28 – Investments in Associates.
The increasedecrease in investments carried under the equity method in 2021,2022, is primarily due to the distributions received by AYES Canada from Amherst Island Partnership for $20.9 million ($17.7 million in 2021), distributions from Vento II for $32.6 million ($14.8 million in 2021) and from Honaine for $4.0 million ($4.4 million in 2021), partially offset by the share of profit of associates for $21.5 million ($12.3 million in 2021) and the investment made in Vento IIChile PMGD in June 2021, partially offset by the distributions received from this portfolio since thenNovember, 2022 for $14.8$4.5 million from Honaine for $4.4 million ($4.5 million in 2020) and from Amherst for $17.7 million ($16.1 million in 2020). A significant portion of the distributions received from Amherst Island Partnership are distributed by the Company to Algonquin Power Co. (Note 13).
The tables below showsshow a breakdown of stand-alone amounts of assets, revenues and profit and loss as well as other information of interest for the years 20212022 and 20202021 for the associated companies:entities carried under the equity method:
Company | | % Shares | | | Non- current assets | | | Current assets | | | Project debt
| | | Other non- current liabilities | | | Other current liabilities | | | Revenue | | | Operating profit/ (loss) | | | Net profit/ (loss) | | | Investment under the equity method | |
2007 Vento II, LLC (*) | |
| 49.00 | | | | 459,037 | | | | 13,511 | | |
| 0 | | | | 62,387 | | | | 10,259 | | | | 104,461 | | | | 34,216 | | | | 32,806 | | | | 195,952 | |
Windlectric Inc (**) | | | 30.00 | | | | 310,751 | | | | 11,036 | | | | 0 | | | | 207,404 | | | | 38,126 | | | | 24,008 | | | | 10,442 | | | | 152 | | | | 41,911 | |
Myah Bahr Honaine, S.P.A.(***) | | | 25.50 | | | | 151,830 | | | | 59,020 | | | | 51,721 | | | | 18,142 | | | | 3,293 | | | | 53,450 | | | | 33,935 | | | | 24,899 | | | | 38,922 | |
Pemcorp SAPI de CV (****) | | | 30.00 | | | | 127,892 | | | | 117,083 | | | | 146,931 | | | | 101,439 | | | | 2,925 | | | | 40,166 | | | | 6,561 | | | | (6,522 | ) | | | 15,358 | |
Pectonex, R.F. Proprietary Limited | | | 50.00 | | | | 2,356 | | | | 0 | | | | 0 | | | | 0 | | | | 1 | | | | 0 | | | | (186 | ) | | | (186 | ) | | | 1,495 | |
Evacuación Valdecaballeros, S.L. | | | 57.16 | | | | 17,185 | | | | 976 | | | | 0 | | | | 15,022 | | | | 156 | | | | 938 | | | | (63 | ) | | | (93 | ) | | | 923 | |
Evacuación Villanueva del Rey, S.L | | | 40.02 | | | | 2,637 | | | | 63 | | | | 0 | | | | 1,601 | | | | 172 | | | | 0 | | | | 59 | | | | 0 | | | | 0 | |
ABY Infraestructuras S.L.U. | | | 20.00 | | | | 238 | | | | 46 | | | | 0 | | | | 0 | | | | 5 | | | | 0 | | | | (54 | ) | | | (54 | ) | | | 21 | |
As of December 31, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 294,581 | |
Company | | % Shares of the Company | | | Non- current assets | | | Current assets | | | Project debt
| | | Other non- current liabilities | | | Other current liabilities | | | Revenue | | | Operating profit/ (loss) | | | Net profit/ (loss) | | | Investment under the equity method | |
2007 Vento II, LLC (1) | | | 49.00 | | | | 435,029 | | | | 14,198 | | | | - | | | | 57,596 | | | | 11,515 | | | | 103,362 | | | | 42,662 | | | | 40,992 | | | | 181,735 | |
Windlectric Inc (2) | | | 30.00 | | | | 278,504 | | | | 3,338 | | | | - | | | | 167,519 | | | | 43,227 | | | | 24,996 | | | | 10,560 | | | | (15 | ) | | | 18,935 | |
Myah Bahr Honaine, S.P.A.(3) | | | 25.50 | | | | 150,623 | | | | 66,246 | | | | 43,579 | | | | 18,902 | | | | 4,257 | | | | 55,267 | | | | 33,374 | | | | 26,768 | | | | 42,128 | |
Pemcorp SAPI de CV (4) | | | 30.00 | | | | 138,931 | | | | 112,352 | | | | 159,382 | | | | 90,474 | | | | 4,328 | | | | 45,625 | | | | 1,680 | | | | (17,747 | ) | | | 10,034 | |
Pectonex, R.F. Proprietary Limited | | | 50.00 | | | | 2,045 | | | | - | | | | - | | | | - | | | | 1 | | | | - | | | | (168 | ) | | | (168 | ) | | | 1,411 | |
Evacuación Valdecaballeros, S.L. | | | 57.16 | | | | 15,551 | | | | 1,020 | | | | - | | | | 13,635 | | | | 232 | | | | 860 | | | | (60 | ) | | | (89 | ) | | | 858 | |
Evacuación Villanueva del Rey, S.L. | | | 40.02 | | | | 2,317 | | | | 12 | | | | - | | | | 1,386 | | | | 111 | | | | - | | | | 57 | | | | - | | | | - | |
Liberty Infraestructuras S.L. | | | 20.00 | | | | 93 | | | | 283 | | | | - | | | | - | | | | 37 | | | | - | | | | - | | | | (22 | ) | | | 29 | |
Akuo Atlantica PMGD Holding S.P.A. (5) | | | 49.00 | | | | 14,814 | | | | 2,828 | | | | - | | | | 8,755 | | | | 326 | | | | - | | | | - | | | | (348 | ) | | | 4,450 | |
Fontanil Solar, S.L.U. | | | 25.00 | | | | 117 | | | | 7 | | | | - | | | | 99 | | | | 24 | | | | - | | | | (1 | ) | | | (2 | ) | | | 229 | |
Murum Solar, S.L.U. | | | 25.00 | | | | 228 | | | | 8 | | | | - | | | | 180 | | | | 59 | | | | - | | | | (1 | ) | | | (5 | ) | | | 222 | |
As of December 31, 2022 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 260,031 | |
Company | | % Shares | | | Non- current assets | | | Current assets | | | Project
Debt
| | | Other non- current liabilities | | | Other current liabilities | | | Revenue | | | Operating profit/loss | | | Net profit/ (loss) | | | Investment under the equity method | |
Windlectric Inc (**) | |
| 30.00 | | | | 316,251 | | | | 7,299 | | |
| 0 | | | | 216,765 | | | | 31,403 | | | | 23,663 | | | | 10,451 | | | | (493 | ) | | | 59,116 | |
Myah Bahr Honaine, S.P.A.(***) | | | 25.50 | | | | 165,688 | | | | 57,808 | | | | 63,356 | | | | 17,617 | | | | 3,636 | | | | 50,739 | | | | 30,519 | | | | 12,402 | | | | 39,204 | |
Pemcorp SAPI de CV (****) | | | 30.00 | | | | 127,429 | | | | 121,468 | | | | 154,937 | | | | 104,893 | | | | 3,190 | | | | 28,832 | | | | 3,068 | | | | (6,237 | ) | | | 15,514 | |
Pectonex, R.F. Proprietary Limited | | | 50.00 | | | | 2,743 | | | | 0 | | | | 0 | | | | 0 | | | | 1 | | | | 0 | | | | (168 | ) | | | (168 | ) | | | 1,587 | |
Evacuación Valdecaballeros, S.L. | | | 57.16 | | | | 19,531 | | | | 1,130 | | | | 0 | | | | 16,721 | | | | 646 | | | | 853 | | | | (167 | ) | | | (194 | ) | | | 976 | |
Evacuación Villanueva del Rey, S.L | | | 40.02 | | | | 3,201 | | | | 134 | | | | 0 | | | | 1,861 | | | | 257 | | | | 0 | | | | 52 | | | | 0 | | | | 0 | |
Ca Ku A1, S.A.P.I de CV (PTS) | | | 5.00 | | | | 468,131 | | | | 156,528 | | | | 0 | | | | 604,986 | | | | 25,773 | | | | 80,240 | | | | 17,415 | | | | 1,615 | | | | 30 | |
ABY Infraestructuras S.L.U. | | | 20.00 | | | | 135 | | | | 84 | | | | 0 | | | | 0 | | | | 63 | | | | 0 | | | | (53 | ) | | | (53 | ) | | | 17 | |
Other renewable energy joint ventures (*****) | | | 50.00 | | | | 323 | | | | 210 | | | | 0 | | | | 0 | | | | 19 | | | | | | | | (66 | ) | | | (66 | ) | | | 169 | |
As of December 31, 2020 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 116,614 | |
Company | | % Shares of the Company | | | Non- current assets | | | Current assets | | | Project
Debt
| | | Other non- current liabilities | | | Other current liabilities | | | Revenue | | | Operating profit/ (loss) | | | Net profit/ (loss) | | | Investment under the equity method | |
2007 Vento II, LLC (1) | | | 49.00 | | | | 459,037 | | | | 13,511 | | | | - | | | | 62,387 | | | | 10,259 | | | | 104,461 | | | | 34,216 | | | | 32,806 | | | | 195,952 | |
Windlectric Inc (2) | | | 30.00 | | | | 310,751 | | | | 11,036 | | | | - | | | | 207,404 | | | | 38,126 | | | | 24,008 | | | | 10,442 | | | | 152 | | | | 41,911 | |
Myah Bahr Honaine, S.P.A.(3) | | | 25.50 | | | | 151,830 | | | | 59,020 | | | | 51,721 | | | | 18,142 | | | | 3,293 | | | | 53,450 | | | | 33,935 | | | | 24,899 | | | | 38,922 | |
Pemcorp SAPI de CV (4) | | | 30.00 | | | | 127,892 | | | | 117,083 | | | | 146,931 | | | | 101,439 | | | | 2,925 | | | | 40,166 | | | | 6,561 | | | | (6,522 | ) | | | 15,358 | |
Pectonex, R.F. Proprietary Limited | | | 50.00 | | | | 2,356 | | | | - | | | | - | | | | - | | | | 1 | | | | - | | | | (186 | ) | | | (186 | ) | | | 1,495 | |
Evacuación Valdecaballeros, S.L. | | | 57.16 | | | | 17,185 | | | | 976 | | | | - | | | | 15,022 | | | | 156 | | | | 938 | | | | (63 | ) | | | (93 | ) | | | 923 | |
Evacuación Villanueva del Rey, S.L. | | | 40.02 | | | | 2,637 | | | | 63 | | | | - | | | | 1,601 | | | | 172 | | | | - | | | | 59 | | | | - | | | | - | |
Liberty Infraestructuras S.L. | | | 20.00 | | | | 238 | | | | 46 | | | | - | | | | - | | | | 5 | | | | - | | | | (54 | ) | | | (54 | ) | | | 21 | |
As of December 31, 2021 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 294,581 | |
The Company has no control over Evacuación Valdecaballeros, S.L. as all relevant decisions of this company require the approval of a minimum of shareholders accounting for more than 75% of the shares.
None of the associated companies referred to above is a listed company.
(*)
(1) 2007 Vento II, LLC, is the holding company of a 596 MW portfolio of wind assets in the U.S., 0.49%49% owned by Atlantica since June 16, 2021, and accounted for under the equity method in these Consolidated Financial Statements (Note 1). Share of profit of 2007 Vento II, LLC. included in these Consolidated Financial Statements amounts to $20.1 million in 2022 and $8.4 million in 20212021..
(**)
(2) Windlectric Inc., the project entity, is 100% owned by Amherst Island Partnership which is accounted for under the equity method in these Consolidated Financial Statements.
(***)(3) Myah Bahr Honaine, S.P.A., the project entity, is 51% owned by Geida Tlemcen, S.L. which is accounted for using the equity method in these Consolidated Financial Statements. Geida Tlemcen, S.L. is 50% owned by Atlantica. Share of profit of Myah Bahr Honaine S.P.A. included in these Consolidated Financial Statements amounts to $6.8 million in 2022 and $6.4 million in 2021 and $3.1 million in 2020.2021.
(****)
(4) Pemcorp SAPI de CV, Monterrey´s project entity, is 100% owned by Arroyo Netherlands II B.V. which is accounted for under the equity method in these Consolidated Financial Statements. Arroyo Netherlands II B.V. is 30% owned by Atlantica. Share of profit of Pemcorp SAPI de CV included in these Consolidated Financial Statements amounts to a loss of $2.0$5.3 million in 20212022 and a loss of $1.9$2.0 million in 2020.2021.
(*****) Other renewable energy
(5) Akuo Atlantica PMGD Holding S.P.A. is the holding company of a 80 MW portfolio of solar PV assets in Chile, which is currently starting construction, 49% owned by Atlantica, with joint venturescontrol since November 2022 and accounted for under the equity method in 2020 corresponded to investments made in the following entities: AC Renovables Sol 1 SAS Esp, PA Renovables Sol 1 SAS Esp, SJ Renovables Sun 1 SAS Esp and SJ Renovables Wind 1 SAS Esp. As of December 31, 2021, these entities have been fully consolidated as the Company has gained control over these entities under IFRS 10, Consolidated Financial Statements.
Note 8.- Financial instruments by category
Financial instruments, in addition to financial assets included within Contracted concessional, PP&E and other intangible assets disclosed in Note 6, are primarily deposits, derivatives, trade and other receivables and loans. Financial instruments by category (current and non-current), reconciled with the statement of financial position as of December 31, 20212022 and 20202021 are as follows:
| | Notes | | Amortized cost | | Fair value through other comprehensive income | | Fair value through profit or loss | | Balance as of December 31, 2021 | | | Notes | | | Amortized cost | | | Fair value through other comprehensive income | | | Fair value through profit or loss | | | Balance as of December 31, 2022 | |
Derivative assets | | 9 | | | 0 | | | 0 | | | 12,960 | | | 12,960 | | | | 9 | | |
| - | | | | - | | | | 97,381 | | | | 97,381 | |
Investment in Ten West Link | | | | | 0 | | | 14,459 | | | 0 | | | 14,459 | | | | | | | | - | | | | 15,959 | | | | - | | | | 15,959 | |
Financial assets under IFRIC 12 (short-term portion) | | | | | 188,912 | | | 0 | | | 0 | | | 188,912 | | |
Financial assets under IFRIC 12 (short-term portion) (*) | | | | | | | | 186,841 | | | | - | | | | - | | | | 186,841 | |
Trade and other receivables | | 11 | | | 307,143 | | | 0 | | | 0 | | | 307,143 | | | | 11 | | | | 200,334 | | | | - | | | | - | | | | 200,334 | |
Cash and cash equivalents | | 12 | | | 622,689 | | | 0 | | | 0 | | | 622,689 | | | | 12 | | | | 600,990 | | | | - | | | | - | | | | 600,990 | |
Other financial investments | | | | | | 87,657 | | | 0 | | | 0 | | | 87,657 | | |
Other financial assets | | | | | | | | 71,949 | | | | - | | | | - | | | | 71,949 | |
Total financial assets | | | | | | 1,206,401 | | | 14,459 | | | 12,960 | | | 1,233,820 | | | | | | | | 1,060,114 | | | | 15,959 | | | | 97,381 | | | | 1,173,454 | |
| | | | | | | | | | | | | | | | | | | | | |
Corporate debt (**) | | | | 14 | | | | 1,017,200 | | | | - | | | | - | | | | 1,017,200 | |
Project debt (**) | | | | 15 | | | | 4,553,052 | | | | - | | | | - | | | | 4,553,052 | |
Trade and other current liabilities | | | | 17 | | | | 140,230 | | | | - | | | | - | | | | 140,230 | |
Derivative liabilities | | | | 9 | | | | - | | | | - | | | | 16,847 | | | | 16,847 | |
Total financial liabilities | | | | | | | | 5,710,482 | | | | - | | | | 16,847 | | | | 5,727,329 | |
Corporate debt | | | 14 | | | | 1,023,071 | | | | - | | | | 0 | | | | 1,023,071 | |
Project debt | | | 15 | | | | 5,036,193 | | | | - | | | | 0 | | | | 5,036,193 | |
Trade and other current liabilities | | | 17 | | | | 113,907 | | | | - | | | | 0 | | | | 113,907 | |
Derivative liabilities | | | 9 | | | | 0 | | | | - | | | | 223,453 | | | | 223,453 | |
Total financial liabilities | | | | | | | 6,173,171 | | | | - | | | | 223,453 | | | | 6,396,624 | |
| | Notes | | | Amortized cost | | | Fair value through other comprehensive income | | | Fair value through profit or loss | | | Balance as of December 31, 2020 | |
Derivative assets | | | 9 | | | | 0 | | | | 0 | | | | 1,559 | | | | 1,559 | |
Investment in Ten West Link | | | | | | | 0 | | | | 12,896 | | | | 0 | | | | 12,896 | |
Investment in Rioglass | | | | | | | 0 | | | | 0 | | | | 2,687 | | | | 2,687 | |
Financial assets under IFRIC 12 (short-term portion) | | | | | | | 178,198 | | | | 0 | | | | 0 | | | | 178,198 | |
Trade and other receivables | | | 11 | | | | 331,735 | | | | 0 | | | | 0 | | | | 331,735 | |
Cash and cash equivalents | | | 12 | | | | 868,501 | | | | 0 | | | | 0 | | | | 868,501 | |
Other financial investments | | | | | | | 94,497 | | | | 0 | | | | 0 | | | | 94,497 | |
Total financial assets | | | | | | | 1,472,931 | | | | 12,896 | | | | 4,246 | | | | 1,490,073 | |
Corporate debt | | 14 | | | 993,725 | | | - | | | 0 | | | 993,725 | | |
Project debt | | 15 | | | 5,237,614 | | | - | | | 0 | | | 5,237,614 | | |
Related parties – non-current | | 10 | | | 6,810 | | | - | | | 0 | | | 6,810 | | |
| | | Notes | | | Amortized cost | | | Fair value through other comprehensive income | | | Fair value through profit or loss | | | Balance as of December 31, 2021 | |
Derivative assets | | | | 9 | | |
| - | | | | - | | | | 12,960 | | | | 12,960 | |
Investment in Ten West Link | | | | | | | | - | | | | 14,459 | | | | - | | | | 14,459 | |
Financial assets under IFRIC 12 (short-term portion) (*) | | | | | | | | 188,912 | | | | - | | | | - | | | | 188,912 | |
Trade and other receivables | | | | 11 | | | | 307,143 | | | | - | | | | - | | | | 307,143 | |
Cash and cash equivalents | | | | 12 | | | | 622,689 | | | | - | | | | - | | | | 622,689 | |
Other financial assets | | | | | | | | 87,657 | | | | - | | | | - | | | | 87,657 | |
Total financial assets | | | | | | | | 1,206,401 | | | | 14,459 | | | | 12,960 | | | | 1,233,820 | |
| | | | | | | | | | | | | | | | | | | | | |
Corporate debt (**) | | | | 14 | | | | 1,023,071 | | | | - | | | | - | | | | 1,023,071 | |
Project debt (**) | | | | 15 | | | | 5,036,193 | | | | - | | | | - | | | | 5,036,193 | |
Trade and other current liabilities | | 17 | | | 92,557 | | | - | | | 0 | | | 92,557 | | | | 17 | | | | 113,907 | | | | - | | | | - | | | | 113,907 | |
Derivative liabilities | | 9 | | | | 0 | | | - | | | 328,184 | | | 328,184 | | | | 9 | | | | - | | | | - | | | | 223,453 | | | | 223,453 | |
Total financial liabilities | | | | | | 6,330,707 | | | - | | | 328,184 | | | 6,658,891 | | | | | | | | 6,173,171 | | | | - | | | | 223,453 | | | | 6,396,624 | |
Other financial investments(*) The long-term portion of Financial assets under IFRIC 12 is included within the line Contracted concessional, PP&E and other intangible assets (Note 6).
(**) The percentage of Corporate and Project debt at fixed interest or hedged is 96% and 92% respectively as of December 31, 20212022 (99% and 92% respectively as of December 31, 2021).
Other financial assets as of December 31, 2022 and as of December 31, 20202021 include among others, a loan to Monterrey (Note 7) and restricted cash for repairs or scheduled major maintenance work.
Investment in Ten West Link is a 12.5% interest in a 114-mile transmission line in the U.S., currently under development.
The investment in Rioglass corresponded to a 15.12% equity interest as of December 31, 2020. The Company gained control over the business in January 2021, which is fully consolidated since then in these Consolidated Financial Statements as of December 31, 2021 (Note 5).construction.
Note 9.- Derivative financial instruments
The breakdowns of the fair value amount of the derivative financial instruments as of December 31, 20212022 and 20202021 are as follows:
| | Balance as of December 31, 2021 | | Balance as of December 31, 2020 | | | Balance as of December 31, 2022 | | Balance as of December 31, 2021 | |
| | Assets | | Liabilities | | Assets | | Liabilities | | | Assets | | Liabilities | | Assets | | Liabilities | |
Interest rate cash flow hedge | | 9,550 | | | 206,763 | | | 898 | | | 302,302 | | | 94,192 | | | 12,159 | | | 9,550 | | | 206,763 | |
Foreign exchange derivatives instruments | | 3,410 | | | 0 | | | 661 | | | 0 | | | 3,189 | | | - | | | 3,410 | | | - | |
Notes conversion option (Note 14) | | | 0 | | | | 16,690 | | | | 0 | | | | 25,882 | | | | - | | | | 4,688 | | | | - | | | | 16,690 | |
Total | | | 12,960 | | | | 223,453 | | | | 1,559 | | | | 328,184 | | | | 97,381 | | | | 16,847 | | | | 12,960 | | | | 223,453 | |
The derivatives are primarily interest rate cash-flow hedges. All are classified as non-current assets or non-current liabilities, as they hedge long-term financing agreements.
As stated in Note 3 to these Consolidated Financial Statements, the general policy is to hedge variable interest rates of financing agreements using two types of hedging derivatives:
- | Interest rate swaps under which the Company receives the floating leg and pays the fixed leg; and |
- | Purchased call options (cap), in exchange of a premium to fix the maximum interest rate cost. |
The notional amounts hedged, strikes contracted and maturities, depending on the characteristics of the debt on which the interest rate risk is being hedged, can be diverse:diverse. As of December 31, 2022, approximately 92% of the Project debt and 96% of the Corporate debt of the Company either has fixed interest rates or has been hedged with swaps or caps (92% and 99%, respectively, as of December 31, 2021).
- | Project debt in Euros: the Company hedges between 75% and 100% of the notional amount, with hedges maturing up to 2038 and average guaranteed interest rate of between 0.00% and 4.87%. |
- | Project debt in U.S. dollars: the Company hedges between 75% and 100% of the notional amount, with hedges maturing up to 2038 and average guaranteed interest rate of between 0.86% and 5.89%. |
The table below shows a breakdown of the maturities of notional amounts of interest rate cash flow hedge derivatives as of December 31, 20212022 and 2020.2021.
Notionals | | Balance as of December 31, 2021 | | | Balance as of December 31, 2020 | | | Balance as of December 31, 2022 | | | Balance as of December 31, 2021 | |
| | Assets | | | Liabilities | | | Assets | | | Liabilities | | | Assets | | | Liabilities | | | Assets | | | Liabilities | |
Up to 1 year | | | 71,386 | | | | 106,191 | | | | 61,364 | | | | 120,874 | | | | 245,147 | | | | 47,029 | | | | 71,386 | | | | 106,191 | |
Between 1 and 2 years | | | 304,930 | | | | 240,197 | | | | 296,828 | | | | 249,785 | | | | 310,393 | | | | 102,476 | | | | 304,930 | | | | 240,197 | |
Between 2 and 3 years | | | 262,973 | | | | 271,350 | | | | 257,548 | | | | 276,111 | | | | 217,498 | | | | 112,855 | | | | 262,973 | | | | 271,350 | |
Subsequent years | | | 217,989 | | | | 860,777 | | | | 292,011 | | | | 852,696 | | | | 659,186 | | | | 280,016 | | | | 217,989 | | | | 860,777 | |
Total | | | 857,278 | | | | 1,478,515 | | | | 907,752 | | | | 1,499,466 | | | | 1,432,224 | | | | 542,376 | | | | 857,278 | | | | 1,478,515 | |
The table below shows a breakdown of the maturity of the fair values of interest rate cash flow hedge derivatives as of December 31, 20212022 and 2020:2021:
Fair value | | Balance as of December 31, 2021 | | | Balance as of December 31, 2020 | | | Balance as of December 31, 2022 | | | Balance as of December 31, 2021 | |
| | Assets | | | Liabilities | | | Assets | | | Liabilities | | | Assets | | | Liabilities | | | Assets | | | Liabilities | |
Up to 1 year | | | 678 | | | | (15,039 | ) | | | 59 | | | | (21,042 | ) | | | 10,868 | | | | (991 | ) | | | 678 | | | | (15,039 | ) |
Between 1 and 2 years | | | 1,810 | | | | (33,670 | ) | | | 255 | | | | (48,276 | ) | | | 17,860 | | | | (2,189 | ) | | | 1,810 | | | | (33,670 | ) |
Between 2 and 3 years | | | 2,268 | | | | (39,834 | ) | | | 305 | | | | (55,220 | ) | | | 12,257 | | | | (2,851 | ) | | | 2,268 | | | | (39,834 | ) |
Subsequent years | | | 4,794 | | | | (118,220 | ) | | | 280 | | | | (177,764 | ) | | | 53,208 | | | | (6,128 | ) | | | 4,794 | | | | (118,220 | ) |
Total | | | 9,550 | | |
| (206,763 | ) | | | 898 | | | | (302,302 | ) | | | 94,192 | | |
| (12,159 | ) | | | 9,550 | | | | (206,763 | ) |
The net amount of the fair value of interest rate derivatives designated as cash flow hedges transferred to the consolidated income statement in 20212022 is a loss of $38,187 thousand (loss of $58,292 thousand (lossin 2021 and a loss of $58,381 thousand in 2020 and a loss of $55,765 thousand in 2019)2020).
The after-tax result accumulated in equity in connection with derivatives designated as cash flow hedges at the years ended December 31, 20212022 and 2020,2021, amount to a $171,272$345,567 thousand gain and a $96,641$171,272 thousand gain, respectively.
Additionally, the Company has currency options with leading international financial institutions, which guarantee minimum Euro-U.S. dollar exchange rates. The strategy of the Company is to hedge the exchange rate for the net distributions from its European assets after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, the strategy of the Company is to hedge 100% of its euro-denominated net exposure for the next 12 months and 75% of its euro denominated net exposure for the following 12 months, on a rolling basis. Change in fair value of these foreign exchange derivatives instruments are directly recorded in the consolidated income statement.
Finally, the conversion option of the Green Exchangeable Notes issued in July 2020 (Note 14) is recorded as a derivative with a negative fair value (liability) of $17$5 million as of December 31, 20212022 ($2617 million as of December 31, 2020)2021).
Note 10.- Related parties
The related parties of the Company are primarily Algonquin and its subsidiaries, non-controlling interests (Note 13), entities accounted for under the equity method (Note 7) and Directors and the Senior Management of the Company.
Details of balances with related parties as of December 31, 20212022 and 20202021 are as follows:
| | Balance as of December 31, | |
| | 2021
| | | 2020
| |
| | | | | | |
Credit receivables (current) | | | 19,387 | | | | 23,067 | |
Credit receivables (non-current) | | | 15,768 | | | | 10,082 | |
Total receivables from related parties | | | 35,155 | | | | 33,149 | |
| | | | | | | | |
Credit payables (current) | | | 9,494 | | | | 18,477 | |
Credit payables (non-current) | | | 5 | | | | 6,810 | |
Total payables to related parties | | | 9,499 | | | | 25,287 | |
| As of December 31, | | | Receivables (current) | | | | Receivables (non- current) | | | | Payables (current)
| | | | Payables (non- current)
| |
Entities accounted for under the equity method: | | |
| $000 | | |
| $000 | | |
| $000 | | |
| $000 | |
Arroyo Netherland II B.V | 2022 | | | 1,097 | | | | 17,006 | | | | - | | | | - | |
2021 | | | 10,000 | | | | 15,768 | | | | - | | | | - | |
Amherst Island Partnership | 2022 | | | - | | | | - | | | | - | | | | - | |
2021 | | | 6,279 | | | | - | | | | - | | | | - | |
Other | 2022 | | | 127 | | | | - | | | | - | | | | - | |
2021 | | | - | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | |
Non controlling interest: | | | | | | | | | | | | | | | | | |
Algonquin | 2022 | | | - | | | | - | | | | 4,762 | | | | - | |
2021 | | | 198 | | | | - | | | | 6,144 | | | | - | |
JGC Corporation | 2022 | | | - | | | | - | | | | - | | | | 6,088 | |
2021 | | | 2,910 | | | | - | | | | - | | | | - | |
Industrial Development Corporation of South Africa and Community Trust | 2022 | | | - | | | | - | | | | - | | | | - | |
2021 | | | - | | | | - | | | | 3,309 | | | | - | |
Other | 2022 | | | - | | | | - | | | | 21 | | | | - | |
2021 | | | - | | | | - | | | | 41 | | | | 5 | |
Total | 2022 | | | 1,224 | | | | 17,006 | | | | 4,783 | | | | 6,088 | |
2021 | | | 19,387 | | | | 15,768 | | | | 9,494 | | | | 5 |
|
Current credit receivables as of December 31, 2021 mainly correspond to the short-term portion of the loan toReceivables with Arroyo Netherland II B.V.,B.V, the holding company of Pemcorp SAPI de CV.,CV, Monterrey´s project companyentity (Note 7) for $10.0 million ($15.5 million as, correspond to the short and long term portion of the loan that was granted at acquisition date of the project and accrues an interest of Libor plus 6.31%.
As of December 31, 2020) and to2021, Current receivable included a dividend to be collected from Amherst Island Partnership for $6.3 million ($4.3 million as of December 31, 2020).and a credit from Solacor 1 and 2 to JGC Corporation that was cancelled in 2022.
Non-current credit receivables as of December 31, 2021 and December 31, 2020 correspond to the long-term portion of the loan to Arroyo Netherland II B.V.
CreditCurrent payables relate to debts with non-controlling partners in Kaxu, Solaben 2 & 3 and Solacor 1 & 2 for an amount of $3.4 million as of December 31, 2021 ($21.1 million as of December 31, 2020). The decrease is primarily due to debt repayment at Kaxu. Current credit payables also include the dividend to be paid by AYES Canada to Algonquin for $6.1 millionAlgonquin. The Current payable as of December 31, 2021 ($4.2 millionwith Industrial Development Corporation of South Africa and Community Trust corresponded to the residual amount of the loan granted by the non-controlling interests to Kaxu during the construction period which has been repaid during 2022.
Non-current payables with JGC Corporation as of December 31, 2020).2022 include a subordinated debt with Solacor 1 and Solacor 2 that accrues an interest of Euribor plus 2.5% and with maturity date in 2037.
The transactions carried out by entities included in these Consolidated Financial Statements with related parties not included in the consolidation perimeter of Atlantica, for the years ended December 31, 2022, 2021 2020 and 20192020 have been as follows:
| | For the year ended December 31, | |
| | 2021
| | | 2020
| | | 2019
| |
Financial income | | | 2,069 | | | | 2,017 | | | | 978 | |
Financial expense | | | (97 | ) | | | (155 | ) | | | (195 | ) |
| | | | | Financial income | | | Financial expense | |
Entities accounted for under the equity method: | |
| | | |
| $000 | | |
| $000 | |
Arroyo Netherland II B.V | | | 2022 | | | | 1,275 | | | | - | |
| | 2021 | | | | 2,061 | | | | - | |
| | 2020 | | | | 2,001 | | | | - | |
Non controlling interest: | | | | | | | | | | | | |
| | | | | | | | | | | | |
Other | | | 2022 | | | | 23 | | | | (65 | ) |
| | 2021 | | | | 8 | | | | (97 | ) |
| | 2020 | | | | 16 | | | | (155 | ) |
Total | | | 2022 | | | | 1,298 | | | | (65 | ) |
| | | 2021
| | | | 2,069
| | | | (97 | ) |
| | | 2020
| | | | 2,017
| | | | (155 | ) |
The total amount of the remuneration received by the Board of Directors of the Company, including the CEO, amounts to $4.6$5.7 million in 20212022 ($3.44.6 million in 2020)2021), including $1.0$0.9 million of annual bonus ($1.01.1 million in 2020)2021) and $1.9$3.0 million of long-term award vested in 20212022 ($0.81.9 million in 2020)2021). The increase of the total remuneration in 20212022 is mainly due to the increase of the long-term award,awards, as a result of the vesting in 20212022 of one-thirda portion of the share options awarded in 2020from 2019 to 2022 and the increase of Atlantica’s share price.price from the date of such awards being granted. None of the directors received any pension remuneration in 20212022 nor 2020.2021.
Note 11.- Trade and other receivables
Trade and other receivable as of December 31, 20212022 and 2020,2021, consist of the following:
| | Balance as of December 31, | | | Balance as of December 31, | |
| | 2021
| | | 2020
| | | 2022
| | | 2021
| |
Trade receivables | | | 227,343 | | | | 258,087 | | | | 125,437 | | | | 227,343 | |
Tax receivables | | | 59,350 | | | | 50,663 | | | | 45,680 | | | | 59,350 | |
Prepayments | | | 9,342 | | | | 12,074 | | | | 11,827 | | | | 9,342 | |
Other accounts receivable | | | 11,108 | | | | 10,911 | | | | 17,390 | | | | 11,108 | |
Total | | | 307,143 | | | | 331,735 | | | | 200,334 | | | | 307,143 | |
The decrease in trade receivables is primarily due to payments received from the Spanish state-owned regulator, Comision Nacional de los Mercados y de la Competencia or “CNMC”, in the solar assets of the Company in Spain and from Pemex in ACT. In Spain, the assets of the Company have collected revenue in 2022 in line with the parameters corresponding to the regulation in place at the beginning of the year, as the new parameters became final on December 14, 2022, while revenue was recorded in accordance with these new parameters (Note 1). The amounts collected “in excess” in 2022 have started to be regularized in 2023.
As of December 31, 2021,2022, and 2020,2021, the fair value of trade and other accounts receivable does not differ significantly from its carrying value.
Trade receivables in foreign currency as of December 31, 20212022 and 2020,2021, are as follows:
| | Balance as of December 31, | | | Balance as of December 31, | |
| | 2021
| | | 2020
| | | 2022
| | | 2021
| |
Euro | | | 65,854 | | | | 105,826 | | | | 4,088 | | | | 65,854 | |
South African Rand | | | 24,513 | | | | 24,121 | | | | 23,416 | | | | 24,513 | |
Chilean peso
| | | | 5,037 | | | | 3,386 | |
Other | | | 13,330 | | | | 6,929 | | | | 3,974 | | | | 9,944 | |
Total | | | 103,697 | | | | 136,876 | | | | 36,515 | | | | 103,697 | |
The decrease in trade receivables in Euro as of December 31, 20212022 is primarily due to the improvement in the collection of receivables from the Spanish state-owned regulator Comision Nacional de los Mercados y de la Competencia or “CNMC” (solar assets in Spain).CNMC.
Note 12.- Cash and cash equivalents
The following table shows the detail of Cash and cash equivalents as of December 31, 20212022 and 2020:2021:
| | Balance as of December 31, | | | Balance as of December 31, | |
| | 2021
| | | 2020
| | | 2022
| | | 2021
| |
Cash at bank and on hand - non restricted | | | 368,381 | | | | 588,690 | | | | 393,430 | | | | 368,381 | |
Cash at bank and on hand - restricted | | | 254,308 | | | | 279,811 | | | | 207,560 | | | | 254,308 | |
Total | | | 622,689 | | | | 868,501 | | | | 600,990 | | | | 622,689 | |
Cash includes funds held to satisfy the customary requirements of certain non-recourse debt agreements within the Company´s projects (Note 15) amounting to $254$208 million as of December 31, 20212022 ($280254 million as of December 31, 2020)2021).
The following breakdown shows the main currencies in which cash and cash equivalent balances are denominated:
| | Balance as of December 31, | | | Balance as of December 31, | |
Currency | | 2021
| | | 2020
| | | 2022
| | | 2021
| |
U.S. dollar | | | 318,071 | | | | 575,567 | | | | 309,756 | | | | 318,071 | |
Euro | | | 230,136 | | | | 196,431 | | | | 217,675 | | | | 230,136 | |
South African Rand | | | 38,268 | | | | 40,561 | | | | 36,137 | | | | 38,268 | |
Mexican Peso | | | 4,926 | | | | 23,570 | | | | 4,010 | | | | 4,926 | |
Algerian Dinar | | | 21,156 | | | | 21,114 | | | | 24,727 | | | | 21,156 | |
Others | | | 10,132 | | | | 11,258 | | | | 8,685 | | | | 10,132 | |
Total | | | 622,689 | | | | 868,501 | | | | 600,990 | | | | 622,689 | |
Note 13.- Equity
As of December 31, 2021,2022, the share capital of the Company amounts to $11,240,297$11,605,513 ($10,667,08711,240,297 as of December 31, 2020)2021) represented by 112,402,973116,055,126 ordinary shares (106,670,866(112,402,973 shares as of December 31, 2020)2021) fully subscribed and disbursed with a nominal value of $0.10 each, all in the same class and series. Each share grants 1one voting right.
Algonquin owns 43.6%42.2% of the shares of the Company and is its largest shareholder as of December 31,2021.31, 2022. Algonquin’s voting rights and rights to appoint directors are limited to 41.5% and the difference between Algonquin´s ownership and 41.5% will vote replicating non-Algonquin’s shareholders’ vote.
On December 11, 2020, the Company closed an underwritten public offering of 5,069,200 ordinary shares, including 661,200 ordinary shares sold pursuant to the full exercise of the underwriters’ over-allotment option, at a price of $33 per new share. Gross proceeds were approximately $167 million. Given that the offering was issued through a subsidiary in Jersey, which became wholly owned by the Company at closing, and subsequently liquidated, the premium on issuance was credited to a merger reserve account (Capital reserves), net of issuance costs, for $161 million. Additionally, Algonquin committed to purchase 4,020,860 ordinary shares in a private placement in order to maintain its previous equity ownership of 44.2% in the Company. The private placement closed on January 7, 2021. Gross proceeds were approximately $133 million ($131 million net of issuance costs).
During the first quarter of 2021, the Company changed the accounting treatment applied to its existing long-term incentive plans granted to employees from cash-settled to equity-settled in accordance with IFRS 2, Share-based Payment, as a result of incentives being settled in shares. The liability recognized for the rights vested by the employees under such plans at the date of this change, was reclassified to equity within the line “Accumulated deficit” for approximately $9 million. The settlement in shares was approved by the Board of Directors on February 26, 2021, and the Company issued 141,482 new shares to its employees up to December 31, 2021, to settle a portion of these plans. During the year 2022, the Company issued 228,560 new shares under such incentive plans.
On August 3, 2021, the Company established an “at-the-market program” (the “ATM”) and entered into thea distribution agreement with J.P. Morgan Securities LLC, as sales agent, (the “Distribution Agreement”) under which the Company may offer and sell from time to time up to $150 million of its ordinary shares. The Company also entered into an agreement with Algonquin pursuant to which the Company has offered 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 Agreementdistribution agreement in the previous quarter (the “ATM Plan Letter Agreement”). On February 28, 2022, the Company established a new “at-the-market program” and entered into a distribution agreement with BofA Securities, MUFG and RBC Capital Markets, as its sales agents, under which the Company may offer and sell from time to time up to $150 million of its ordinary shares. Upon entry into the distribution agreement, the Company terminated its prior “at-the-market program” established on August 3, 2021 and the related distribution agreement dated such date, entered into with J.P. Morgan Securities LLC. During the year 2021,2022, the Company sold 1,613,0793,423,593 shares (1,613,079 shares during the year 2021) at an average market price of $38.43$33.57 ($38.43 in 2021) pursuant to its Distribution Agreement,distribution agreement, representing net proceeds of $61 million.$114 million ($61 million in 2021). Pursuant to the ATM Plan Letter Agreement, the Company delivers a notice to Algonquin quarterly in order for them to exercise their rights thereunder.
Atlantica´s reserves as of December 31, 20212022 are made up of share premium account and capital reserves. The share premium account reduction by $200 million during the year 2021, increasing capital reserves by the same amount, was made effective upon the confirmation received from the High Court in the UK, pursuant to the Companies Act 2006.
Other reserves primarily include the change in fair value of cash flow hedges and its tax effect.
Accumulated currency translation differences primarily include the result of translating the financial statements of subsidiaries prepared in a foreign currency into the presentation currency of the Company, the U.S. dollar.
Accumulated deficit primarily includes results attributable to Atlantica.
Non-controlling interests fully relate to interests held by JGC in Solacor 1 and Solacor 2, by Idae in Seville PV, by Itochu Corporation in Solaben 2 and Solaben 3, by Algerian Energy Company, SPA and Sacyr Agua S.L. in Skikda, , by Algerian Energy Company, SPA in Tenes, by Industrial Development Corporation of South Africa (IDC) and Kaxu Community Trust in Kaxu, by Algonquin Power Co. in AYES Canada, and by partners of the Company in the Chilean renewable energy platform in Chile PV 1, Chile PV 2 and Chile PV 2.3.
Additional information of subsidiaries including material non-controlling interests as of December 31, 20212022 and 2020,2021, is disclosed in Appendix IV.
Dividends declared during the year 2022 by the Board of Directors of the Company were as follows:
Declared | Payable | | Amount ($) per share | |
February 28, 2023 | March 25, 2023 | | 0.445
|
|
November 8, 2022 | December 15, 2022 | | | 0.445 | |
August 2, 2022 | September 15, 2022 | | | 0.445 | |
May 5, 2022 | June 15, 2022 | | | 0.44 | |
February 25, 2022 | March 25, 2022 | | | 0.44 | |
Dividends declared during the year 2021 by the Board of Directors of the Company were:were as follows:
Declared | -Payable | On | Amount ($) per share | |
November 9, 2021 | December 15, 2021 | | | 0.435 | |
July 30, 2021 | September 15, 2021 | | | 0.43 | |
May 4, 2021 | June 15, 2021 | | | 0.43 | |
February 26, 2021 the Board of Directors declared a dividend of $0.42 per share corresponding to the fourth quarter of 2020. The dividend was paid on | March 22, 2021 for a total amount of $46.5 million | | | 0.42 | |
| - | On May 4, 2021, the Board of Directors declared a dividend of $0.43 per share corresponding to the first quarter of 2021. The dividend was paid on June 15, 2021 for a total amount of $47.7 million. |
| - | On July 30, 2021, the Board of Directors declared a dividend of $0.43 per share corresponding to the second quarter of 2021. The dividend was paid on September 15, 2021 for a total amount of $47.8 million. |
| - | On November 9, 2021, the Board of Directors declared a dividend of $0.435 per share corresponding to the third quarter of 2021. The dividend was paid on December 15, 2021 for a total amount of $48.6 million. |
In addition, the Company declared dividends and distributions to non-controlling interests, primarily to Algonquin (interests in Amherst through AYES Canada, see Note 7) for $17.3$20.4 million in 20212022 ($14.717.3 million in 2020)2021), JGC for $10.4 million in 2022 ($0.5 million in 2021), Algerian Energy Company for $6.6$5.4 million in 20212022 ($3.76.6 million in 2020)2021), IDC and Kaxu Community Trust for $5.8 million in 2022 (nill in 2021) and Itochu for $5.7$3.5 million in 20212022 ($1.45.7 million in 2020)2021).
As of December 31, 2022 and December 31, 2021, there was 0no treasury stock and there have been 0no transactions with treasury stock during the periodyears then ended.
Note 14.- Corporate debt
The breakdown of the corporate debt as of December 31, 20212022 and 20202021 is as follows:
| | Balance as of December 31, | |
| | 2021
| | | 2020
| |
Non-current
| | | 995,190 | | | | 970,077 | |
Current
| | | 27,881 | | | | 23,648 | |
Total Corporate debt | | | 1,023,071 | | | | 993,725 | |
| | Balance as of December 31, | |
| | 2022
| | | 2021
| |
Non-current
| | | 1,000,503 | | | | 995,190 | |
Current
| | | 16,697 | | | | 27,881 | |
Total Corporate debt | | | 1,017,200 | | | | 1,023,071 | |
On July 20, 2017, the Company signed a credit facility (the “2017 Credit Facility”) for up to €10 million approximately $11.4 million,($10.7 million), which is available in euros or U.S. dollars. Amounts drawn down accrue interest at a rate per year equal to EURIBOR plus 2% or LIBOR plus 2%, depending on the currency, with a floor of 0% on the LIBOR and EURIBOR. As of December 31, 2021, $8.22022, $6.4 million werehas been drawn down. down ($8.2 million as of December 31, 2021). As of December 31, 2020,2021, the 2017 Credit Facility was fully available. The credit facility maturity iswas July 1, 2023. On July 1, 2022, the maturity has been extended to July 1, 2024.
On May 10, 2018, the Company entered into the Revolving Credit Facility for $215 million with a syndicate of banks. Amounts drawn down accrue interest at a rate per year equal to (A) for Eurodollar rate loans, LIBORTerm SOFR, plus a Term SOFR Adjustment equal to 0.10% per annum, plus a percentage determined by reference to the leverage ratio of the Company, ranging between 1.60% and 2.25% and (B) for base rate loans, the highest of (i) the rate per annum equal to the weighted average of the rates on overnight U.S. Federal funds transactions with members of the U.S. Federal Reserve System arranged by U.S. Federal funds brokers on such day plus ½ of 1.00%, (ii) the U.S. prime rate and (iii) LIBORTerm SOFR plus 1.00%, in any case, plus a percentage determined by reference to the leverage ratio of the Company, ranging between 0.60% and 1.00%. Letters of credit may be issued using up to $100 million of the Revolving Credit Facility. During 2019, the amount of the Revolving Credit Facility increased from $215 million to $425 million and the maturity was extended to December 31, 2022.million. In the first quarter of 2021, the Company increased the amount of the Revolving Credit Facility from $425 million to $450 millionmillion. On May 5, 2022, and the maturity was extended to December 31, 20232024. On December 31, 2022, $30 million were drawn down (nill as of December 31,2021, 2021). On December 31, 2022, the Company had issued letters of credit for $$35 million ($10 million, as of December 31, 2021). As of December 31, 2022, therefore, $440$385 million of the Revolving Credit Facility arewere available ($415($440 million as of December 31,2020) 2021).
On April 30, 2019, the Company entered into the Note Issuance Facility 2019, a senior unsecured note facility with a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of €268 million approximately $305 million,($287 million), with maturity date on April 30, 2025. Interest accruesaccrued at a rate per annum equalequaled to the sum of 3-month EURIBOR plus 4.50%. The interest rate on the Note Issuance Facility 2019 iswas fully hedged by an interest rate swap resulting in the Company paying a net fixed interest rate of 4.24%. The Note Issuance Facility 2019 provided that the Company may capitalize interest on the notes issued thereunder for a period of up to two years from closing at the Company´s discretion, subject to certain conditions,and the Company elected to capitalize such interest until the end of 2020.The Note Issuance Facility 2019 has beenwas fully repaid on June 4, 2021, and subsequently delisted from the Official List of The International Stock Exchange.
On October 8, 2019, the Company filed a euro commercial paper program (the “Commercial Paper”) with the Alternative Fixed Income Market (MARF) in Spain. The program had an original maturity of twelve months and washas been extended for another twelve-month period onannual periods until October 8, 2020.2023. The program allowedallows Atlantica to issue short term notes over the next twelve months for up to €50 million (approximately $57($54 million), with such notes having a tenor of up to two years. As of December 31, 2021,2022, the Company had €21.5€9.3 million (approximately ($24.49.9 million) issued and outstanding under the program at an average cost of 0.36%2.21% (€17.421.5 million, approximatelyor $19.824.4 million, as of December 31, 20202021).
On April 1, 2020, the Company closed the secured 2020 Green Private Placement for €290 million (approximately $330($310 million). The private placement accrues interest at an annual 1.96% interest rate, payable quarterly and has a June 2026 maturity.
On July 8, 2020, the Company entered into the Note Issuance Facility 2020, a senior unsecured financing with a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of approximately $159$150 million which is denominated in euros (€140 million). The Note Issuance Facility 2020 was issued on August 12, 2020, interest accrues annual interestat a rate per annum equal to the sum of the 3-month EURIBOR plus a margin of5.25%with a floor of 0% for the EURIBOR, payable quarterly and has a maturity of seven years from the closing date.The Company have entered into a cap at 0% for the EURIBOR with 3.5 years maturity to hedge the variable interest rate risk.
On July 17, 2020, ASI Jersey Ltd, a subsidiary of the Company issued the Green Exchangeable Notes for $100 million in aggregate principal amount of 4.00% convertible bonds due in 2025. On July 29, 2020, the Company closed an additional $15 million aggregate principal amount of the Green Exchangeable Notes. The notes mature on July 15, 2025 and bear interest at a rate of 4.00% per annum. The initial exchange rate of the notes is 29.1070 ordinary shares per $1,000 principal amount of notes, which is equivalent to an initial exchange price of $34.36 per ordinary share. Noteholders may exchange their notes at their option at any time prior to the close of business on the scheduled trading day immediately preceding April 15, 2025, only during certain periods and upon satisfaction of certain conditions. On or after April 15, 2025, noteholders may exchange their notes at any time. Upon exchange, the notes may be settled, at the election of the Company, into Atlantica ordinary shares, cash or a combination thereof. The exchange rate is subject to adjustment upon the occurrence of certain events.
As per IAS 32, “Financial Instruments: Presentation”, the conversion option of the Green Exchangeable Notes is an embedded derivative classified within the line “Derivative liabilities” of these Consolidated Financial Statements (Note 9). It was initially valued at the transaction date for $10 million, and prospective changes to its fair value are accounted for directly through the profit and loss statement. The principal element of the Green Exchangeable Notes, classified within the line “Corporate debt” of these Consolidated Financial Statements, is initially valued as the difference between the consideration received from the holders of the instrument and the value of the embedded derivative, and thereafter, at amortized cost using the effective interest method as per IFRS 9, “Financial Instruments”.Financial Instruments.
On December 4, 2020, the Company entered into a loan with a bank for €5 million approximately $5.7 million.($5.4 million). This loan accrues interest at a rate per year equal to 2.50%. The maturity date is December 4, 2025.
On May 18, 2021, the Company issued the Green Senior Notes due in 2028 in an aggregate principal amount of $400 million. The notes mature on May 15, 2028 and bear interest at a rate of 4.125% per annum payable on June 15 and December 15 of each year, commencing December 15, 2021.
On January 31, 2022, the Company entered into a loan with a bank for €5 million ($5.4 million). This loan accrues interest at a rate per year equal to 1.90%. The maturity date is January 31, 2026.
The repayment schedule for the corporate debt as of December 31, 20212022 is as follows:
| | 2022
| | | 2023
| | | 2024
| | | 2025
| | | 2026
| | | Subsequent years | | | Total | | | 2023
| | | 2024
| | | 2025
| | | 2026
| | | 2027
| | | Subsequent years | | | Total | |
2017 Credit Facility | | | 5 | | | | 8,199 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 8,204 | | | | 8 | | | | 6,423 | | | | - | | | | - | | | | - | | | | - | | | | 6,431 | |
Revolving Credit Facility | | | | 112 | | | | 29,387 | | | | | | | | | | | | | | | | | | | | 29,499 | |
Commercial Paper | | | 24,422 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 24,422 | | | | 9,937 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 9,937 | |
2020 Green Private Placement | | | 359 | | | | 0 | | | | 0 | | | | 0 | | | | 327,081 | | | | 0 | | | | 327,440 | | | | 423 | | | | - | | | | - | | | | 308,389 | | | | - | | | | - | | | | 308,812 | |
Note Issuance Facility 2020 | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 155,814 | | | | 155,814 | | |
2020 Note Issuance Facility | | | | - | | | | - | | | | - | | | | - | | | | 147,257 | | | | - | | | | 147,257 | |
Green Exchangeable Notes | | | 2,121 | | | | 0 | | | | 0 | | | | 104,289 | | | | 0 | | | | 0 | | | | 106,410 | | | | 2,107 | | | | - | | | | 107,055 | | | | - | | | | - | | | | - | | | | 109,162 | |
Bank Loan | | | 11 | | | | 1,895 | | | | 1,895 | | | | 1,862 | | | | 0 | | | | 0 | | | | 5,663 | | |
Green Senior Note | | | 963 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 394,155 | | | | 395,118 | | | | 964 | | | | - | | | | - | | | | - | | | | - | | | | 395,060 | | | | 396,024 | |
Other bank Loans | | | | 3,146 | | | | 3,122 | | | | 3,124 | | | | 686 | | | | - | | | | - | | | | 10,078 | |
Total | | | 27,881 | | | | 10,094 | | | | 1,895 | | | | 106,151 | | | | 327,081 | | | | 549,969 | | | | 1,023,071 | | | | 16,697 | | | | 38,932 | | | | 110,179 | | | | 309,075 | | | | 147,257 | | | | 395,060 | | | | 1,017,200 | |
The repayment schedule for the corporate debt as of December 31, 2020 is2021 was as follows:
| | 2021
| | | 2022
| | | 2023
| | | 2024
| | | 2025
| | | Subsequent years | | | Total | | | 2022
| | | 2023
| | | 2024
| | | 2025
| | | 2026
| | | Subsequent years | | | Total | |
2017 Credit Facility | | | 41 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 41 | | | | 5 | | | | 8,199 | | | | - | | | | - | | | | - | | | | - | | | | 8,204 | |
Notes Issuance Facility 2019 | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 343,999 | | | | 0 | | | | 343,999 | | |
Commercial Paper | | | 21,224 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 21,224 | | | | 24,422 | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 24,422 | |
2020 Green Private Placement | | | 289 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 351,026 | | | | 351,315 | | | | 359 | | | | - | | | | - | | | | - | | | | 327,081 | | | | - | | | | 327,440 | |
Note Issuance Facility 2020
| | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 0 | | | | 166,846 | | | | 166,846 | | |
2020 Note Issuance Facility | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 155,814 | | | | 155,814 | |
Green Exchangeable Notes
| | | 2,083 | | | | 0 | | | | 0 | | | | 0 | | | | 102,144 | | | | 0 | | | | 104,227 | | | | 2,121 | | | | - | | | | - | | | | 104,289 | | | | - | | | | - | | | | 106,410 | |
Green Senior Note | | | | 963 | | | | - | | | | - | | | | - | | | | - | | | | 394,155 | | | | 395,118 | |
Bank Loan
| | | 11 | | | | 0 | | | | 2,036 | | | | 2,036 | | | | 1,990 | | | | 0 | | | | 6,073 | | | | 11 | | | | 1,895 | | | | 1,895 | | | | 1,862 | | | | - | | | | - | | | | 5,663 | |
Total | | | 23,648 | | | | 0 | | | | 2,036 | | | | 2,036 | | | | 448,133 | | | | 517,872 | | | | 993,725 | | | | 27,881 | | | | 10,094 | | | | 1,895 | | | | 106,151 | | | | 327,081 | | | | 549,969 | | | | 1,023,071 | |
The following table details the movement in corporate debt for the years 20212022 and 2020,2021, split between cash and non-cash items:
Corporate Debt | | 2021
| | | 2020
| |
Initial balance | | | 993,725 | | | | 723,791 | |
Cash changes
| | | 14,754 | | | | 171,182 | |
Non-cash changes | | | 14,592 | | | | 98,752 | |
Final balance | | | 1,023,071 | | | | 993,725 | |
Corporate Debt | | 2022
| | | 2021
| |
Initial balance | | | 1,023,071 | | | | 993,725 | |
Cash changes
| | | (17,945) | | | | 14,754 | |
Non-cash changes | | | 12,074 | | | | 14,592 | |
Final balance | | | 1,017,200 | | | | 1,023,071 | |
The non-cash changes primarily relate to interests accrued and to currency translation differences.
Note 15.- Project debt
This note shows the project debt linked to the contracted concessional assets included in Note 6 of these Consolidated Financial Statements.
Project debt is generally used to finance contracted assets, exclusively using as a guarantee the assets and cash flows of the company or group of companies carrying out the activities financed. In most of the cases, the assets and/or contracts are set up as a guarantee to ensure the repayment of the related financing. In addition, the cash of the Company´s projects includes funds held to satisfy the customary requirements of certain non-recourse debt agreements and other restricted cash for an amount of $254$208 million as of December 31, 20212022 ($280254 million as of December 31, 2020)2021).
The variations in 20212022 of project debt hashave been the following:
| | Project debt - long term | | | Project debt - short term | | | Total | | | Project debt - long term | | | Project debt - short term | | | Total | |
Balance as of December 31, 2020 | | | 4,925,268 | | | | 312,346 | | | | 5,237,614 | | |
Balance as of December 31, 2021 | | | | 4,387,674 | | | | 648,519 | | | | 5,036,193 | |
Increases | | | 54,908 | | | | 256,581 | | | | 311,489 | | | | 39,161 | | | | 230,320 | | | | 269,481 | |
Decreases | | | (85,259 | ) | | | (564,603 | ) | | | (649,862 | ) | |
Payments | | | | (73,478 | ) | | | (543,484 | ) | | | (616,962 | ) |
Business combinations (Note 5) | | | 288,352 | | | | 38,781 | | | | 327,133 | | | | 1,301 | | | | 148 | | | | 1,449 | |
Currency translation differences | | | (140,502 | ) | | | (49,679 | ) | | | (190,181 | ) | | | (119,068 | ) | | | (18,041 | ) | | | (137,109 | ) |
Reclassifications | | | (655,093 | ) | | | 655,093 | | | | 0 | | | | (9,072 | ) | | | 9,072 | | | | - | |
Balance as of December 31, 2021 | | | 4,387,674 | | | | 648,519 | | | | 5,036,193 | | |
Balance as of December 31, 2022 | | | | 4,226,518 | | | | 326,534 | | | | 4,553,052 | |
The decrease in total project debt as of December 31, 20212022 is primarily due to:
| - | the repayment of project debt for the period in accordance with the financing arrangements; and |
| - | the lower value of debt denominated in Euros given the depreciation of the Euro against the U.S. dollar since December 31, 2020.2021. |
Interest accrued, which are included in Increases, were offset by a similar amount of interest paid during the year, included in Payments in the table above.
As of December 31, 2021, Kaxu total debt was presented as current in the Consolidated Financial Statements of the Company, for an amount of $314 million, in accordance with International Accounting Standards 1 (“IAS 1”), “Presentation of Financial Statements”, as a result of the existence of a theoretical event of default under the Kaxu project finance agreement. Since March 31, 2022, the Company has again an unconditional right to defer the settlement of the debt for at least more than twelve months, and therefore the debt previously presented as current in these Consolidated Financial Statements has been reclassified as non-current in accordance with the financing agreements (Note 1).
The variations in 2021 of project debt were the following:
| | Project debt - long term | | | Project debt - short term | | | Total | |
Balance as of December 31, 2020 | | | 4,925,268 | | | | 312,346 | | | | 5,237,614 | |
Increases | | | 54,908 | | | | 256,581 | | | | 311,489 | |
Payments
| | | (85,259 | ) | | | (564,603 | ) | | | (649,862 | ) |
Business combinations (Note 5) | | | 288,352 | | | | 38,781 | | | | 327,133 | |
Currency translation differences | | | (140,502 | ) | | | (49,679 | ) | | | (190,181 | ) |
Reclassifications | | | (655,093 | ) | | | 655,093 | | | | - | |
Balance as of December 31, 2021 | | | 4,387,674 | | | | 648,519 | | | | 5,036,193 | |
The decrease in total project debt as of December 31, 2021 were primarily due to:
| - | the repayment of project debt for the period in accordance with the financing arrangements; and |
| - | the lower value of debt denominated in Euros given the depreciation of the Euro against the U.S. dollar since December 31, 2020. |
The decrease of project debt during the year 2021 has beenwas partially offset by the business combinations, being the acquisitions of Rioglass, Coso, Chile PV 2, Italy PV 1 and Italy PV 3 for a total amount of $327 million (Note 5).
Interest accrued, which are included in Increases, were offset by a similar amount of interest paid during the year.year, included in Payments in the table above.
The Kaxu project financing arrangement contains cross-default provisions related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. The insolvency filing by the individual company Abengoa S.A. in February 2021 representsrepresented a theoretical event of default under the Kaxu project finance agreement. In September 2021, the Company obtained a waiver for such theoretical event of default whichand it was conditional upon the replacement of the operation and maintenance supplier of the plant. On February 1, 2022, the Company transferred the employees performing the operation and maintenance services to an Atlantica subsidiary. The waiver has been extended until April 30, 2022 and iswas subject to the lenders receiving certain documentation from the Company, including formal evidence of the approval by the client and the department of energy of South Africa of the operation and maintenance internalization and the Company is currently working on obtaining such documentation.Company. Although the Company doesdid not expect the acceleration of debt to be declared by the credit entities, as of December 31, 2021 Kaxu did not have what International Accounting Standards define as an unconditional right to defer the settlement of the debt for at least twelve months, as the cross-default provisions make that right conditional. Therefore, Kaxu total debt, previously presented as non-current as of December 31, 2020, has beenwas presented as current in the Consolidated Financial Statements of the Company as of December 31, 2021 for an amount of $315$314 million (Note 1).
The variations in 2020 ofrepayment schedule for project debt were the following:
| | Project debt - long term | | | Project debt - short term | | | Total | |
Balance as of December 31, 2019 | | | 4,069,909 | | | | 782,439 | | | | 4,852,348 | |
Increases | | | 613,604 | | | | 268,339 | | | | 881,943 | |
Decreases | | | (272,548 | ) | | | (552,770 | ) | | | (825,318 | ) |
Business combinations (Note 5) | | | 149,585 | | | | 8,680 | | | | 158,265 | |
Currency translation differences | | | 150,506 | | | | 19,869 | | | | 170,375 | |
Reclassifications | | | 214,211 | | | | (214,211 | ) | | | 0 | |
Balance as of December 31, 2020 | | | 4,925,268 | | | | 312,346 | | | | 5,237,614 | |
The increase in total project debt as of December 31, 2020 was primarily due to:
| - | business combinations, being the acquisition of Chile PV 1 and Tenes for a total amount of $158 million (Note 5). |
| - | a green project financing agreement entered into by Logrosán Solar Inversiones, S.A.U., the holding company of assets Solaben 1, 2, 3 and 6 in Spain, closed on April 8, 2020 for a €140 million nominal amount, (approximately $159 million).
|
| - | a non-recourse project debt refinancing of Helioenergy assets by adding a new long dated tranche of debt from an institutional investor closed on July 10, 2020, providing with a net refinancing proceeds (net “recap”) of approximately $43 million. |
| - | a non-recourse, project debt financing closed on July 14, 2020 for approximately €326 million (approximately $371 million) in relation to Helios, with institutional investors, which refinanced the previous bank project debt with approximately €250 million outstanding and canceled legacy interest rate swaps. After transaction costs and cancelation of legacy swaps, net refinancing proceeds (net “recap”) were approximately $30 million. The accumulated impact of the change in fair value of the interest rate swaps recorded in Other reserves and any difference between the nominal amount of the debt repaid and the amortized cost of the debt were transferred to the profit and loss in line “Other financial income/(expense), net” on transaction date for a total amount of $73 million (Note 21). |
| - | the higher value of debt denominated in Euro given the increase in the exchange rate of the Euro against the U.S. dollar since December 31, 2019. |
The increase of project debt during the year 2020 was partially offset by the contractual payments of debt for the year. Interest accrued were offset by a similar amount of interest paid during the year.
Additionally, on June 12, 2020 the Company refinanced the debt of Cadonal (Uruguay). The terms of the new debts were not substantially different from the original debts refinanced and therefore the exchange of debts instruments did not qualify for an extinguishment of the original debts under IFRS 9, ´Financial instruments´. When there is a refinancing with a non-substantial modification of the original debt, there is a gain or loss recorded in the income statement. This gain or loss is equal to the difference between the present value of the cash flows under the original terms of the former financing and the present value of the cash flows under the new financing, discounted both at the original effective interest rate. In this respect, the Company recorded a $3.8 million financial income in the profit and loss statement of the Consolidated Financial Statements (Note 21).
Due to the PG&E Corporation and its regulated utility subsidiary, Pacific Gas and Electric Company (“PG&E”), Chapter 11 filings in January 2019, a default of the PPA agreement with PG&E occurred. On July 1, 2020, PG&E emerged from Chapter 11 and the technical event of default was cured. As a result, as of December 31, 2020 the debt previously presented as current (during the year 2019) was reclassified as non-current in accordance with the financing agreements in these Consolidated Financial Statements.arrangements as of December 31, 2022, is as follows and is consistent with the projected cash flows of the related projects:
2023
| | | 2024
| | | 2025
| | | 2026
| | | 2027
| | | Subsequent years | | | Total | |
Interest payment | | | Nominal repayment | | | | | | | | | | | | | | | | | | | |
| 15,053
| | | | 311,481
| | | | 323,731
| | | | 442,920
| | | | 358,444
| | | | 504,954
| | | | 2,596,469
| | | | 4,553,052
| |
The repayment schedule for project debt in accordance with the financing arrangements and assuming there willwould be no acceleration at the Kaxu debt as of December 31, 2021, iswas as follows and iswas consistent with the projected cash flows of the related projects:
2022
| | | 2023
| | | 2024
| | | 2025
| | | 2026
| | | Subsequent years | | | Total | |
Interest payment | | | Nominal repayment | | | | | | | | | | | | | | | | | | | |
| 18,017
| | | | 317,388
| | | | 355,956
| | | | 369,528
| | | | 498,712
| | | | 411,514
| | | | 3,065,078
| | | | 5,036,193
| |
The repayment schedule for project debt in accordance with the financing arrangements as of December 31, 2020, is as follows and is consistent with the projected cash flows of the related projects:
2021
| | | 2022
| | | 2023
| | | 2024
| | | 2025
| | | Subsequent years | | | Total | |
Interest payment | | | Nominal repayment | | | | | | | | | | | | | | | | | | | |
| 19,287
| | | | 293,059
| | | | 328,364
| | | | 355,806
| | | | 371,548
| | | | 508,843
| | | | 3,360,707
| | | | 5,237,614
| |
The following table details the movement in project debt for the years 20212022 and 2020,2021, split between cash and non-cash items:
Project Debt | | 2021
| | | 2020
| | | 2022
| | | 2021
| |
Initial balance | | | 5,237,614 | | | | 4,852,348 | | | | 5,036,193 | | | | 5,237,614 | |
Cash changes
| | | (636,831 | ) | | | (254,495 | ) | | | (636,343 | ) | | | (636,831 | ) |
Non-cash changes | | | 435,410 | | | | 639,761 | | | | 153,202 | | | | 435,410 | |
Final balance | | | 5,036,193 | | | | 5,237,614 | | | | 4,553,052 | | | | 5,036,193 | |
The non-cash changes primarily relate to interest accrued, currency translation differences and the business combinations for the year.
The equivalent in U.S. dollars of the foreign currency-denominated project debts held by the Company is as follows:
| | Balance as of December 31, | | | Balance as of December 31, | |
Currency | | 2021
| | | 2020
| | | 2022
| | | 2021
| |
Euro | | | 1,942,903 | | | | 2,240,811 | | | | 1,633,790 | | | | 1,942,903 | |
South African Rand | | | 314,471 | | | | 355,414 | | | | 277,492 | | | | 314,471 | |
Algerian Dinar | | | 97,877 | | | | 115,606 | | | | 86,739 | | | | 97,877 | |
Total | | | 2,355,251 | | | | 2,711,830 | | | | 1,998,021 | | | | 2,355,251 | |
All of the Company’s financing agreements have a carrying amount close to its fair value.
Note 16.- Grants and other liabilities
Grants and other liabilities as of December 31, 20212022 and December 31, 20202021 are as follows:
| | Balance as of December 31, | | | Balance as of December 31, | |
| | 2021
| | | 2020
| | | 2022
| | | 2021
| |
Grants | | | 970,557 | | | | 1,028,765 | | | | 911,593 | | | | 970,557 | |
Other liabilities | | | 293,187 | | | | 201,002 | | |
Other liabilities and provisions | | | | 340,920 | | | | 293,187 | |
Dismantling provision | | | | 140,595 | | | | 124,593 | |
Lease liabilities | | | | 63,076 | | | | 59,219 | |
Accruals on Spanish market prices differences | | | | 91,884 | | | | 74,795 | |
Other | | | | 45,365 | | | | 34,580 | |
Grant and other non-current liabilities | | | 1,263,744 | | | | 1,229,767 | | | | 1,252,513 | | | | 1,263,744 | |
As of December 31, 2021,2022, the amount recorded in Grants corresponds primarily to the ITC Grant awarded by the U.S. Department of the Treasury to Solana and Mojave for a total amount of $642$610 million ($674642 million as of December 31, 2020)2021), which was primarily used to fully repay the Solana and Mojave short-term tranche of the loan with the Federal Financing Bank. The amount recorded in Grants as a liability is progressively recorded as other income over the useful life of the asset.
The remaining balance of the “Grants” account corresponds to loans with interest rates below market rates for Solana and Mojave for a total amount of $326$299 million ($352326 million as of December 31, 2020)2021). Loans with the Federal Financing Bank guaranteed by the Department of Energy for these projects bear interest at a rate below market rates for these types of projects and terms. The difference between proceeds received from these loans and its fair value, is initially recorded as “Grants” in the consolidated statement of financial position, and subsequently recorded in “Other operating income” starting at the entry into operation of the plants.
Total amount of income for these 2two types of grants for Solana and Mojave is $58.7$58.5 million and $58.9$58.7 million for the years ended December 31, 20212022 and 2020,2021, respectively (Note 20).
Other liabilities mainly include:
The “Accruals on Spanish market prices differences” corresponds to the payables related to the current high market prices in Spain at which the solar assets in Spain invoiced electricity up to December 31, 2022,as a result of a negative adjustment to the regulated revenues for the deviation from the estimated market prices used by the Administration in Spain, which is expected to be compensated over the remaining regulatory life of the solar assets of the Company.
- | $59 million of lease liabilities ($52 million as of December 31, 2020); |
- | $125 million of dismantling provision as of December 31, 2021 ($88 million as of December 31, 2020); and |
- | $75 million of provision related to the current high market prices in Spain at which the solar assets in Spain invoiced electricity up to December 31, 2021 ($0.6 million as of December 31, 2020), as a result of a negative adjustment to the regulated revenues expected to be recorded progressively over the remaining regulatory life of the solar assets of the Company, as a compensation. |
The maturity of Other liabilities and provisions as of December 31, 2022 and 2021 is as follows:
| Total | | 2023
| | 2024 and 2025 | | 2026 and 2027 | | Subsequent years
| |
Other liabilities and provisions | | | 340,920 | | | | - | | | | 46,489 | | | | 41,428 | | | | 253,003 | |
Total | | | 340,920 | | | | - | | | | 46,489 | | | | 41,428 | | | | 253,003 | |
As of December 31, 2021
| Total | | 2022
| | 2023 and 2024 | | 2025 and 2026 | | Subsequent years | |
Other liabilities and provisions | | | 293,187 | | | | - | | | | 51,490 | | | | 33,656 | | | | 208,041 | |
Total | | | 293,187 | | | | - | | | | 51,490 | | | | 33,656 | | | | 208,041 | |
Note 17.- Trade payables and other current liabilities
Trade payables and other current liabilities as of December 31, 20212022 and 20202021 are as follows:
| | Balance as of December 31, | | | Balance as of December 31, | |
Item | | 2021
| | | 2020
| | | 2022
| | | 2021
| |
Trade accounts payables | | | 79,052 | | | | 51,421 | | | | 84,465 | | | | 79,052 | |
Down payments from clients | | | 542 | | | | 416 | | | | 11,169 | | | | 542 | |
Other accounts payables | | | 34,313 | | | | 40,720 | | | | 44,596 | | | | 34,313 | |
Total | | | 113,907 | | | | 92,557 | | | | 140,230 | | | | 113,907 | |
Trade accounts payables mainly relate to the operation and maintenance of the plants.
Down payments from clients in 2022 primarily include the collections from the CNMC (Spanish solar assets), which have been in line with the parameters corresponding to the regulation in place at the beginning of the year, as the new parameters became final on December 14, 2022, while revenue was recorded in accordance with the new parameters (Note 1).
Nominal values of trade payables and other current liabilities are considered to approximately equal to fair values and the effect of discounting them is not significant.
Note 18.- Income Tax
All the companies of Atlantica file income taxes according to the tax regulations in force in each country on an individual basis or under consolidation tax regulations.
The consolidated income tax has been calculated as an aggregation of income tax expenses/income of each individual company. In order to calculate the taxable income of the consolidated entities individually, the accounting result is adjusted for temporary and permanent differences, recording the corresponding deferred tax assets and liabilities. At each consolidated income statement date, a current tax asset or liability is recorded, representing income taxes currently refundable or payable. Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount of assets and liabilities for financial statement and income tax purposes, as determined under enacted tax laws and rates.
Income tax payable is the result of applying the applicable tax rate in force to each tax-paying entity, in accordance with the tax laws in force in the country in which the entity is registered. Additionally, tax deductions and credits are available to certain entities, primarily relating to inter-company trades and tax treaties between various countries to prevent double taxation.
The Company offsets deferred tax assets and deferred tax liabilities in each entity where the latter has a legally enforceable right to set off current tax assets against current tax liabilities, and the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority.
As of December 31, 2021,2022, and 2020,2021, the analysis of deferred tax assets and deferred tax liabilities is as follows:
Deferred tax assets | | Balance as of December 31, | | | Balance as of December 31, | |
from | | 2021
| | | 2020
| | |
From | | | 2022
| | | 2021
| |
Net operating loss carryforwards (“NOL´s”) | | | 323,115 | | | | 497,184 | | | | 442,415 | | | | 323,115 | |
Temporary tax non-deductible expenses | | | 128,186 | | | | 115,063 | | | | 134,328 | | | | 128,186 | |
Derivatives financial instruments | | | 55,217 | | | | 83,847 | | | | 3,461 | | | | 55,217 | |
Other | | | 4,225 | | | | 3,021 | | | | 5,895 | | | | 4,225 | |
Total deferred tax assets | | | 510,743 | | | | 699,115 | | | | 586,099 | | | | 510,743 | |
Deferred tax liabilities | | Balance as of December 31, | | | Balance as of December 31, | |
from | | 2021
| | | 2020
| | |
From | | | 2022
| | | 2021
| |
Accelerated tax amortization | | | 465,219 | | | | 652,600 | | | | 524,363 | | | | 465,219 | |
Other difference between tax and book value of assets | | | 180,218 | | | | 154,969 | | | | 186,536 | | | | 180,218 | |
Derivatives financial instruments
| | | | 19,034 | | | | - | |
Other | | | 1,897 | | | | 179 | | | | 2,991 | | | | 1,897 | |
Total deferred tax liabilities | | | 647,334 | | | | 807,748 | | | | 732,924 | | | | 647,334 | |
After offsetting deferred tax assets and deferred tax liabilities, where applicable, the resulting net amounts presented on the consolidated balance sheet are as follows:
Consolidated balance sheets classifications | | Balance as of December 31, | | | Balance as of December 31, | |
| | 2021
| | | 2020
| | | 2022
| | | 2021
| |
Deferred tax assets | | | 172,268 | | | | 152,290 | | | | 149,656 | | | | 172,268 | |
Deferred tax liabilities | | | 308,859 | | | | 260,923 | | | | 296,481 | | | | 308,859 | |
Net deferred tax liabilities | | | 136,591 | | | | 108,633 | | | | 146,825 | | | | 136,591 | |
Most of the NOL´s recognized as deferred tax assets corresponds to the entities in the U.S., South Africa, Peru, Chile and Spain as of December 31, 20212022 and 2020.2021.
As of December 31, 2021,2022, deferred tax assets for non-deductible expenses are primarily due to the temporary limitation of financial expenses deductibles for tax purposes in the solar plants in Spain for $97$94 million ($11097 million as of December 31, 2020).
Deferred tax assets for derivatives financial instruments as of December 31, 2021 mainly relate to ACT for $14 million and to solar plants in Spain for $33 million ($22 million and $51 million as of December 31, 2020, respectively)2021).
As of December 31, 2021,2022, deferred tax liabilities for accelerated tax amortization are primarily in the U.S. assets for $274 million, the solar plants in Spain for $186 million, Solana and Mojave for $184$173 million and Kaxu for $76$63 million ($202184 million, $361$186 million and $90$76 million as of December 31, 2020,2021, respectively).
Deferred tax liabilities for other temporary differences between the tax and book value of contracted concessional assets relate primarily to ACT for $72$56 million, the U.S. entities for $51 million, the Peruvian entities for $34 million, U.S. entities for $28$37 million and the Chilean entities for $27 million as of December 31, 20212022 ($7572 million, $32$28 million, $2$34 million and $29$27 million as of December 31, 2020,2021, respectively).
In relation to tax losses carryforwards and deductions pending to be used recorded as deferred tax assets, the entities evaluate their recoverability projecting forecasted taxable result for the upcoming years and taking into account their tax planning strategy. Deferred tax liabilities reversals are also considered in these projections, as well as any limitation established by tax regulations in force in each tax jurisdiction. Therefore, the carrying amount of deferred tax assets is reviewed at each annual closing date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred tax asset to be utilised. Unrecognised deferred tax assets are re-assessed at each annual closing date and are recognised to the extent that it has become probable that future taxable profits will allow the deferred tax asset to be recovered. In assessing the recoverability of deferred tax assets, Atlantica relies on projections of results over the useful life of the contracted concessional assets.
In addition, the Company has $259$361 million unrecognized net operating loss carryforwards as of December 31, 20212022 ($290346 million as of December 31, 2020)2021), as it considers it is not probable that future taxable profits will be available against which these unused tax losses can be utilized.
The movements in deferred tax assets and liabilities during the years ended December 31, 20212022 and 20202021 were as follows:
Deferred tax assets | | Amount | |
As of December 31, 2019 | | | 147,966 | |
Increase/(decrease) through the consolidated income statement | | | 6,003 | |
Increase/(decrease) through other consolidated comprehensive income (equity) | | | (8,698) | |
Currency translation differences and other | | | 7,019 | |
As of December 31, 2020
| | | 152,290
| |
| | | | |
Increase/(decrease) through the consolidated income statement | | | 46,855 | |
Increase/(decrease) through other consolidated comprehensive income (equity) | | | (23,712 | ) |
Business combinations (Note 5)
| | | 4,410 | |
Currency translation differences and other | | | (7,575)(7,575 | ) |
As of December 31, 2021 | | | 172,268 | |
Deferred tax liabilities | | Amount | |
As of December 31, 2019
| | | 248,996 | |
Increase/(decrease) through the consolidated income statement | | | 9,675 | |
Currency translation differences and other | | | 2,252 | |
As of December 31, 2020
| | | 260,923 | |
| | | | |
Increase/(decrease) through the consolidated income statement | | | 29,197 | |
Increase/(decrease) through other consolidated comprehensive income (equity) | | | (46,344 | ) |
Currency translation differences and other | | | (5,465 | ) |
As of December 31, 2022 | | | 149,656 | |
Deferred tax liabilities | | Amount | |
As of December 31, 2020 | | | 260,923 | |
Increase/(decrease) through the consolidated income statement | | | 32,059 | |
Business combinations (Note 5)
| | | 4,910 | |
Currency translation differences and other | | | 10,967 | |
As of December 31, 2021 | | | 308,859 | |
| | | | |
Increase/(decrease) through the consolidated income statement | | | (19,864 | ) |
Increase/(decrease) through other consolidated comprehensive income (equity)
| | | 17,608 | |
Currency translation differences and other | | | (10,122 | ) |
As of December 31, 2022 | | | 296,481 | |
Details of income tax for the years ended December 31, 2022, 2021 2020 and 20192020 are as follows:
| | For the year ended December 31, | | | For the year ended December 31, | |
| | 2021
| | | 2020
| | | 2019
| | | 2022
| | | 2021
| | | 2020
| |
Current tax | | | (51,016 | ) | | | (21,205 | ) | | | (5,081 | ) | | | (39,372 | ) | | | (51,016 | ) | | | (21,205 | ) |
Deferred tax | | | 14,796 | | | | (3,672 | ) | | | (25,869 | ) | | | 49,061 | | | | 14,796 | | | | (3,672 | ) |
- relating to the origination and reversal of temporary differences | | | 14,796 | | | | (3,672 | ) | | | (25,869 | ) | | | 49,061 | | | | 14,796 | | | | (3,672 | ) |
Total income tax expense | | | (36,220 | ) | | | (24,877 | ) | | | (30,950 | ) | |
Total income tax (expense)/income | | | | 9,689 | | | | (36,220 | ) | | | (24,877 | ) |
The reconciliation between the theoretical income tax resulting from applying an average statutory tax rate to profit before income tax and the actual income tax expense recognized in the consolidated income statements for the years ended December 31, 2022, 2021, 2020, and 2019,2020, is as follows:
| | For the year ended December 31, | | | For the year ended December 31, | |
| | 2021
| | | 2020
| | | 2019
| | | 2022
| | | 2021
| | | 2020
| |
Consolidated income before taxes | | | 25,302 | | | | 41,751 | | | | 105,558 | | |
Consolidated profit/(loss) before taxes | | | | (11,776 | ) | | | 25,302 | | | | 41,751 | |
Average statutory tax rate | | | 25 | % | | | 25 | % | | | 25 | % | | | 25 | % | | | 25 | % | | | 25 | % |
Corporate income tax at average statutory tax rate | | | (6,326 | ) | | | (10,438 | ) | | | (26,390 | ) | | | 2,944 | | | | (6,326 | ) | | | (10,438 | ) |
Income tax of associates, net | | | 3,076 | | | | 128 | | | | 1,808 | | | | 5,366 | | | | 3,076 | | | | 128 | |
Differences in statutory tax rates | | | (3,359 | ) | | | (94 | ) | | | (7,076 | ) | | | (4,296 | ) | | | (3,359 | ) | | | (94 | ) |
Unrecognized NOLs and deferred tax assets | | | (11,232 | ) | | | (37,183 | ) | | | (14,161 | ) | | | (10,944 | ) | | | (11,232 | ) | | | (37,183 | ) |
Purchase of Liberty Interactive’s equity interest in Solana | | | 0 | | | | 36,352 | | | | 0 | | | | - | | | | - | | | | 36,352 | |
Other permanent differences | | | (4,052 | ) | | | (8,895 | ) | | | 11,220 | | | | 3,957 | | | | (4,052 | ) | | | (8,895 | ) |
Other non-taxable income/(expense) | | | (14,327 | ) | | | (4,747 | ) | | | 3,649 | | | | 12,662 | | | | (14,327 | ) | | | (4,747 | ) |
Corporate income tax | | | (36,220 | ) | | | (24,877 | ) | | | (30,950 | ) | | | 9,689 | | | | (36,220 | ) | | | (24,877 | ) |
For the year ended December 31, 2021, the overall effective tax rate was different than the average statutory rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in the UK entities and to provisions recorded for potential tax contingencies in some jurisdictions.
For the year ended December 31, 2020, the overall effective tax rate was different than the average statutory rate of 25% primarily due to unrecognized tax losses carryforwards, mainly in the UK entities, partially offset by the non-taxable gain recorded in the Consolidated Financial Statements on the purchase of Liberty Interactive’s equity interest in Solana (Note 21).
For the year ended December 31, 2019, the overall effectiveUncertain tax rate was different than the average statutory rate of 25%, primarily due to unrecognized tax losses carryforwards, mainly in the UK and US entities.
Any uncertain tax positions identified by the Company as of December 31, 2022, 2021 2020 and 20192020 has been provided for in these Consolidated Financial Statementsanalysed by the Company in accordance with IFRIC 23 uncertainty(uncertainty over income tax treatments.treatments). As a result of this analysis, the Company concluded that the risk of the uncertainties is remote and accordingly, the expectation is that these uncertainties would have an insignificant effect on the Consolidated Financial Statements.
Note 19.- Commitments, third-party guarantees, contingent assets and liabilities
Contractual obligations
The following tables show the breakdown of the third-party commitments and contractual obligations as of December 31, 20212022 and 2020:2021:
2021
| | Total | | | 2022
| | | 2023 and 2024 | | | 2025 and 2026 | | | Subsequent | | |
2022
| | | Total | | | 2023
| | | 2024 and 2025 | | | 2026 and 2027 | | | Subsequent | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Corporate debt (Note 14) | | | 1,023,071 | | | | 27,881 | | | | 11,989 | | | | 433,232 | | | | 549,969 | | | | 1,017,200 | | | | 16,697 | | | | 149,111 | | | | 456,332 | | | | 395,060 | |
Loans with credit institutions (project debt) (Note 15) | | | 4,010,825 | | | | 289,755 | | | | 624,633 | | | | 801,713 | | | | 2,294,724 | | | | 3,595,671 | | | | 273,556 | | | | 666,875 | | | | 755,269 | | | | 1,899,972 | |
Notes and bonds (project debt) (Note 15) | | | 1,025,368 | | | | 45,650 | | | | 100,850 | | | | 108,512 | | | | 770,355 | | | | 957,381 | | | | 52,978 | | | | 99,776 | | | | 108,129 | | | | 696,497 | |
Purchase commitments* | | | 1,570,831 | | | | 79,261 | | | | 191,171 | | | | 159,297 | | | | 1,141,102 | | | | 823,856 | | | | 96,847 | | | | 154,344 | | | | 107,909 | | | | 464,755 | |
Accrued interest estimate during the useful life of loans | | | 2,029,376 | | | | 267,645 | | | | 497,587 | | | | 427,159 | | | | 836,985 | | | | 1,821,915 | | | | 264,626 | | | | 477,936 | | | | 383,347 | | | | 696,006 | |
2020
| | Total | | | 2021
| | | 2022 and 2023 | | | 2024 and 2025 | | | Subsequent | | |
2021
| | | Total | | | 2022
| | | 2023 and 2024 | | | 2025 and 2026 | | | Subsequent | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Corporate debt (Note 14) | | | 993,725 | | | | 23,648 | | | | 2,036 | | | | 450,169 | | | | 517,872 | | | | 1,023,071 | | | | 27,881 | | | | 11,989 | | | | 433,232 | | | | 549,969 | |
Loans with credit institutions (project debt) (Note 15) | | | 4,123,856 | | | | 261,800 | | | | 583,259 | | | | 770,507 | | | | 2,508,290 | | | | 4,010,825 | | | | 289,755 | | | | 624,633 | | | | 801,713 | | | | 2,294,724 | |
Notes and bonds (project debt) (Note 15) | | | 1,113,758 | | | | 50,558 | | | | 100,911 | | | | 109,884 | | | | 852,405 | | | | 1,025,368 | | | | 45,650 | | | | 100,850 | | | | 108,512 | | | | 770,355 | |
Purchase commitments* | | | 1,709,660 | | | | 93,791 | | | | 160,211 | | | | 172,776 | | | | 1,282,881 | | | | 1,570,831 | | | | 79,261 | | | | 191,171 | | | | 159,297 | | | | 1,141,102 | |
Accrued interest estimate during the useful life of loans | | | 2,309,597 | | | | 286,724 | | | | 541,652 | | | | 468,060 | | | | 1,013,161 | | | | 2,029,376 | | | | 267,645 | | | | 497,587 | | | | 427,159 | | | | 836,985 | |
* Purchase commitments include lease commitments for lease arrangements accounted for under IFRS 16 for $107.6$112.0 million as of December 31, 20212022 ($94.6107.6 million as of December 31, 2020)2021), of which $7.3$7.9 million is due within one year and $104.1 million thereafter as of December 31, 2022 ($7.3 million due within one year and $100.3 million thereafter as of December 31, 2021 ($5.3 million due within one year and $89.3 million thereafter as of December 31, 2020)2021).
Third-party guarantees
As of December 31, 2021,2022, the sum of bank guarantees and surety bonds deposited by the subsidiaries of the Company as a guarantee to third parties (clients, financial entities and other third parties) amounted to $92.7$88.0 million ($36.292.7 million as of December 31, 2020)2021).The increase primarily relates to Coso and Rioglass, which are businesses acquired by the Company in 2021 (Note 5). In addition, Atlantica Sustainable Infrastructure plc or other holding entities on its behalf had outstanding guarantees amounting to $174.2$216.9 million as of December 31, 20212022 ($159.8174.2 million as of December 31, 2020). Guarantees issued by Atlantica Sustainable Infrastructure plc2021), which correspond mainly to guarantees provided to off-takers in PPAs, guarantees for debt service reserve accounts and guarantees for points of access for renewable energy projects.
Corporate debt guarantees
The payment obligations under the Green Senior Notes, the Revolving Credit Facility, the Note Issuance Facility 2020 and the 2020 Green Private Placement are guaranteed on a senior unsecured basis by following subsidiaries of the Company: Atlantica Infraestructura Sostenible, S.L.U., Atlantica Peru, S.A., ACT Holding, S.A. de C.V., Atlantica Investments Limited, Atlantica Newco Limited and Atlantica North America LLC. The Revolving Credit Facility and the 2020 Green Private Placement are also secured with a pledge over the shares of the subsidiary guarantors.
Legal Proceedings
In 2018, an insurance company covering certain Abengoa obligations in Mexico claimed certain amounts related to a potential loss. Atlantica reached an agreement under which Atlantica´s maximum theoretical exposure would in any case be limited to approximately $35 million, including $2.5 million to be held in an escrow account. In January 2019, the insurance company called on this $2.5 million from the escrow account and Abengoa reimbursed this amount. The insurance company could claim additional amounts if they faced new losses after following a process agreed between the parties and, in any case, Atlantica would only make payments if and when the actual loss has been confirmed and after arbitration if the Company initiates it. The Company used to have indemnities from Abengoa for certain potential losses, but such indemnities are no longer valid following the insolvency filing by Abengoa S.A. in February 2021.
In addition, during 2021 and 2022, several lawsuits were filed related to the February 2021 winter storm Uri in Texas against among others Electric Reliability Council of Texas (ERCOT), 2two utilities in Texas and more than 230 individual power generators, including Post Oak Wind, LLC, the project company owner of Lone Star I, one of the wind assets in Vento II where the Company currently has a 49% equity interest. The basis for the lawsuit is that the defendants failed to properly prepare for cold weather, including failure to implement measures and equipment to protect against cold weather, and failed to properly conduct their operations before and during the storm.
Atlantica is not a party to any other significant legal proceedings other than legal proceedings arising in the ordinary course of its business. Atlantica is party to various administrative and regulatory proceedings that have arisen in the ordinary course of business.
While Atlantica does not expect these proceedings, either individually or in combination, to have a material adverse effect on its financial position or results of operations, because of the nature of these proceedings Atlantica is not able to predict their ultimate outcomes, some of which may be unfavorable to Atlantica.
Note 20.- Employee benefit expenses and other operating income and expenses
Employee benefit expenses
The table below shows the employee benefit expenses and the average monthly number of employees for the years ended December 31, 2022, 2021 2020 and 2019:2020:
| | For the year ended December 31, | | | For the year ended December 31, | |
| | 2021
| | | 2020
| | | 2019
| | | 2022
| | | 2021
| | | 2020
| |
| | | | | | | | | | | | | | | | | | |
Employee benefit expenses | | | 78,758 | | | | 54,464 | | | | 32,246 | | | | 80,232 | | | | 78,758 | | | | 54,464 | |
Average monthly number of employees | | | 655 | | | | 441 | | | | 306 | | | | 874 | | | | 655 | | | | 441 | |
The increase in employee benefit expenses in 20212022 compared to 2021 is primarily due to the internalization of operation and maintenance services in some of the solar assets in Spain since June 2022 and of Kaxu since February 2022. The increase in 2021 compared to 2020 is was primarily due to the acquisition of Rioglass and Coso made effective in January 2021 and April 2021, respectively. The increase in 2020 compared to 2019 was primarily due to the internalization of operation and maintenance services in the U.S. solar assets of the Company, following the acquisition of ASI Operations in July 2019.
Other operating income and expenses
The table below shows the detail of Other operating income and expenses for the years ended December 31, 2022, 2021 2020 and 2019:2020:
| | For the year ended December 31, | | | For the year ended December 31, | |
Other operating income | | 2021
| | | 2020
| | | 2019
| | | 2022
| | | 2021
| | | 2020
| |
| | | | | | | | | | | | | | | | | | |
Grants | | | 60,746 | | | | 59,010 | | | | 59,142 | | | | 59,056 | | | | 60,746 | | | | 59,010 | |
Insurance proceeds and other
| | | 13,925 | | | | 40,515 | | | | 34,632 | | | | 21,726 | | | | 13,925 | | | | 40,515 | |
Total | | | 74,670 | | | | 99,525 | | | | 93,774 | | | | 80,782 | | | | 74,670 | | | | 99,525 | |
| | For the year ended December 31, | | | For the year ended December 31, | |
Other operating expenses | | 2021
| | | 2020
| | | 2019
| | | 2022
| | | 2021
| | | 2020
| |
Raw materials and consumables used | | | (70,690 | ) | | | (7,792 | ) | | | (9,719 | ) | | | (19,639 | ) | | | (70,690 | ) | | | (7,792 | ) |
Leases and fees | | | (9,332 | ) | | | (2,531 | ) | | | (1,850 | ) | | | (11,512 | ) | | | (9,332 | ) | | | (2,531 | ) |
Operation and maintenance | | | (154,007 | ) | | | (110,873 | ) | | | (116,018 | ) | | | (140,382 | ) | | | (154,007 | ) | | | (110,873 | ) |
Independent professional services | | | (39,177 | ) | | | (40,193 | ) | | | (41,579 | ) | | | (38,894 | ) | | | (39,177 | ) | | | (40,193 | ) |
Supplies | | | (40,790 | ) | | | (27,926 | ) | | | (25,823 | ) | | | (59,336 | ) | | | (40,790 | ) | | | (27,926 | ) |
Insurance | | | (45,429 | ) | | | (37,638 | ) | | | (23,971 | ) | | | (45,756 | ) | | | (45,429 | ) | | | (37,638 | ) |
Levies and duties | | | (29,949 | ) | | | (39,820 | ) | | | (34,844 | ) | | | (19,764 | ) | | | (29,949 | ) | | | (39,820 | ) |
Other expenses | | | (24,957 | ) | | | (9,891 | ) | | | (7,971 | ) | | | (15,965 | ) | | | (24,957 | ) | | | (9,891 | ) |
Total | | | (414,330 | ) | | | (276,666 | ) | | | (261,776 | ) | | | (351,248 | ) | | | (414,330 | ) | | | (276,666 | ) |
Grants income mainly relate to ITC cash grants and implicit grants recorded for accounting purposes in relation to the FFB loans with interest rates below market rates in Solana and Mojave projects (Note 16).
The increasedecrease in other operating expenses in 20212022, and specifically Raw materials and consumables used, is primarily due to the business combinations made effectivea specific non-recurrent solar project of Rioglass which ended in 2021 (Note 5).October 2021.
Note 21.- Financial expense, net
The following table sets forth financial income and expenses for the years ended December 31, 2022, 2021 2020 and 2019:2020:
| | For the year ended December 31, | | | For the year ended December 31, | |
Financial income | | 2021
| | | 2020
| | | 2019
| | | 2022
| | | 2021
| | | 2020
| |
Interest income from loans and credits | | | 2,066 | | | | 6,651 | | | | 3,665 | | | | 1,641 | | | | 2,066 | | | | 6,651 | |
Interest rates benefits derivatives: cash flow hedges | | | 689 | | | | 401 | | | | 456 | | | | 3,928 | | | | 689 | | | | 401 | |
Total | | | 2,755 | | | | 7,052 | | | | 4,121 | | | | 5,569 | | | | 2,755 | | | | 7,052 | |
| | For the year ended December 31, | | | For the year ended December 31, | |
Financial expenses | | 2021
| | | 2020
| | | 2019
| | | 2022
| | | 2021
| | | 2020
| |
Interest on loans and notes
| | | (302,558 | ) | | | (316,237 | ) | | | (348,672 | ) | | | (292,043 | ) | | | (302,558 | ) | | | (316,237 | ) |
Interest rates losses derivatives: cash flow hedges | | | (58,712 | ) | | | (62,149 | ) | | | (59,318 | ) | | | (41,220 | ) | | | (58,712 | ) | | | (62,149 | ) |
Total | | | (361,270 | ) | | | (378,386 | ) | | | (407,990 | ) | | | (333,263 | ) | | | (361,270 | ) | | | (378,386 | ) |
Financial interest income from loans and credits included in 2020 a non-monetary financial income of $3.8 million resulting from the refinancing of the debt of Cadonal in the second quarter of 2020 (Note 15).Cadonal.
Interest on loans and notes primarily include interest on corporate and project debt. Thedebt, which decrease in 20202022 and 2021 compared to 2019 isthe previous year, primarily due to the acquisitionrepayment of Liberty Interactive’s equity interest in Solana in August 2020, which was accounted for as a liability in these Consolidated Financial Statements,project and corporate debt in accordance with IAS 32.the financing arrangements.
Losses from interest rate derivatives designated as cash flow hedges primarily correspond to transfers from equity to financial expense when the hedged item impacts the consolidated income statement. The decrease in 2022 compared to 2021 is due to an increase in the spot interest rates in 2022 compared to 2021, which implies lower interest payments on the derivatives instruments contracted.
Net exchange differences
Net exchange differences primarily correspond to realized and unrealized exchange gains and losses on transactions in foreign currencies as part of the normal course of the business of the Company. The increase in profit in 2022 is mainly due to the impact of foreign exchange caps instruments hedging the net cash flows of the Company in Euros, resulting from the appreciation of the U.S. dollar against the Euro.
Other financial income/(expense), net
The following table sets out Other financial income/(expense), net for the years 2022, 2021 2020 and 2019:2020:
| | For the year ended December 31, | |
Other financial income/(expense), net | | 2021
| | | 2020
| | | 2019
| |
Other financial income | | | 32,321 | | | | 162,290 | | | | 14,152 | |
Other financial losses | | | (16,571 | ) | | | (121,415 | ) | | | (15,305 | ) |
Total | | | 15,750 | | | | 40,875 | | | | (1,153 | ) |
| | For the year ended December 31, | |
Other financial income/(expense), net | | 2022
| | | 2021
| | | 2020
| |
Other financial income | | | 27,938 | | | | 32,321 | | | | 162,290 | |
Other financial losses | | | (21,435 | ) | | | (16,571 | ) | | | (121,415 | ) |
Total | | | 6,503 | | | | 15,750 | | | | 40,875 | |
Other financial income in 20212022 include $7.6$6.2 million of income for non-monetary change to the fair value of derivatives of Kaxu for which hedge accounting is not applied, and $9.2$12.0 million income further to the change in the fair value of the conversion option of the Green Exchangeable Notes since December 20202021 (Note 14). Residual items primarily relate to interest on deposits and loans, including non-monetary changes to the amortized cost of such loans. The decrease of other financial income in 2021 compared to the year 2020 is primarily due to the gain of $145 million further to the purchase of Liberty Interactive´s equity interest in Solana accounted for in the third quarter of 2020.
Other financial losses primarily include guarantees and letters of credit, other bank fees, non-monetary changes to the fair value of derivatives which hedge accounting is not applied and of financial instruments recorded at fair value through profit and loss, and non-monetary changes to the present value of provision and other minor financial expenses. long-term liabilities.
The decrease of other financial losses in 2021 compared to the year 2020 iswas primarily due to $73 million of financial expenses further to the refinancing of the Helios 1&2 debts accounted for in the third quarter of 2020 (Note 15) and a $16 million expense further to the change in the fair value of the conversion option of the Green Exchangeable Notes in 2020 (Note 14).2020.
Note 22.- Earnings per share
Basic earnings per share have been calculated by dividing the profit/(loss) attributable to equity holders of the Company by the average number of outstanding shares.
Diluted earnings per shareAverage number of outstanding diluted shares for the year 2021 have2022 has been calculated considering the potential issuance of 3,347,305 shares (3,347,305 shares as of December 31, 2021 and December 31, 2020) on the settlement of the Green Exchangeable Notes (Note 14) and the potential issuance of 596,681 shares (725,041 shares as of December 31, 2021) to Algonquin under the agreement signed on August 3, 2021, according to which Algonquin has the option, on a quarterly basis, to subscribe such number of shares to maintain its percentage in Atlantica in relation to the use of the ATM program (Note 13).
| | For the year ended December 31, | |
Item | | 2022
| | | 2021
| | | 2020
| |
Profit/(loss) attributable to Atlantica | | | (5,443 | ) | | | (30,080 | ) | | | 11,968 | |
Average number of ordinary shares outstanding (thousands) - basic | | | 114,695 | | | | 111,008 | | | | 101,879 | |
Average number of ordinary shares outstanding (thousands) - diluted | | | 118,501 | | | | 114,523 | | | | 103,392 | |
Earnings per share for the year (US dollar per share) - basic
| | | (0.05 | ) | | | (0.27 | ) | | | 0.12 | |
Earnings per share for the year (US dollar per share) - diluted (*)
| | | (0.05 | ) | | | (0.27 | ) | | | 0.12
| |
Diluted
(*) The potential ordinary shares related to the Green Exchangeable Notes and the ATM program have not been considered in the calculation of diluted earnings per share for the year 2020 was calculated considering the potential issuance of 3,347,305 shares on settlement of the Green Exchangeable Notes. Diluted earnings per share equal basic earnings per share for the year 2019.years 2022 and 2021 as they have an antidilutive effect.
| | For the year ended December 31, | |
Item | | 2021
| | | 2020
| | | 2019
| |
Profit/(loss) from continuing operations attributable to Atlantica | | | (30,080 | ) | | | 11,968 | | | | 62,135 | |
Average number of ordinary shares outstanding (thousands) - basic | | | 111,008 | | | | 101,879 | | | | 101,063 | |
Average number of ordinary shares outstanding (thousands) - diluted | | | 114,523 | | | | 103,392 | | | | 101,063 | |
Earnings per share for the year (US dollar per share) - basic
| | | (0.27 | ) | | | 0.12 | | | | 0.61 | |
Earnings per share for the year (US dollar per share) - diluted
| | | (0.26 | ) | | | 0.12
| | | | 0.61
| |
Note 23.- Other information
23.1 Restricted Net assets
Certain of the consolidated entities are restricted from remitting certain funds to Atlantica Sustainable Infrastructure plc. as a result of a number of regulatory, contractual or statutory requirements. These restrictions are mainly related to standard requirements to maintain debt service coverage ratios and other requirements from the financing arrangements. At December 31, 2021,2022, the accumulated amount of the temporary restrictions for the entire restricted term of these affiliates was $326$286 million.
The Company performed a test on the restricted net assets of consolidated subsidiaries in accordance with Securities and Exchange Commission Regulation S-X Rule 12-04 and concluded the restricted net assets did not exceed 25% of the consolidated net assets of the Company as of December 31, 2021.2022. Therefore, separate financial statements of Atlantica Sustainable Infrastructure, plc. do not have to be presented.
23.2 Subsequent events
On January 17, 2022,February 22, 2023, the Company closedsigned an agreement to terminate the acquisitionoperation and maintenance services performed by Abengoa to some of Chile TL4,its solar assets in Spain. The transfer of employees from an Abengoa subsidiary to a 63-mile transmission line and 2 substations in Chile for a total equity investment of $39 million. The Company expectsCompany’s subsidiary is expected to make an expansion of the line in 2022, which would represent an additional investment of approximately $8 million. The asset has fully contracted revenues in US dollars, with inflation escalation and 50-year contract life. The off-takers are several mini-hydro plants that receive contracted or regulated payments.be effective on March 1, 2023.
On February 25, 2022,28, 2023, the Board of Directors of the Company approved a dividend of $0.44$0.445 per share, which is expected to be paid on March 25, 2022.2023.
Entities included in the Group as subsidiaries as of December 31, 20212022
Company name | Project name | Registered address | % of | Business |
ACT Energy México, S. de R.L. de C.V. | ACT | Santa Barbara (Mexico) | 100.00 | (2) |
AC Renovables Sol 1 S.A.S. | | Bogota D.C. (Colombia) | 70.00 | (3) |
Agrisun, Srl. | Italy PV 1 | Rome (Italy) | 100.00 | (3) |
Alcala Sviluppo Solare S.r.l | | Rovereto (Italy) | 99.00 | (3) |
Atlantica North America, LLC | | Delaware (United States) | 100.00 | (5) |
Atlantica Infraestructura Sostenible, S.L.U | | Seville (Spain) | 100.00 | (5) |
Atlantica Perú, S.A. | | Lima (Peru) | 100.00 | (5) |
Atlantica Renewable Power Mexico de R.L. de C.V | | Mexico D.F. (Mexico) | 100.00 | (5) |
Atlantica Sustainable Infrastructure Jersey, Ltd | | Jersey (United Kingdom) | 100.00 | (5) |
Atlantica Newco Limited | | Brentford (United Kingdom) | 100.00 | (5) |
Atlantica DCR, LLC | | Delaware (United States) | 100.00 | (5) |
ASHUSA Inc. | | Delaware (United States) | 100.00 | (5) |
Atlantica South Africa (Pty) Ltd | | Pretoria (South Africa) | 100.00 | (5) |
Atlantica South Africa Operations Proprietary Limited Ltd | | Upington (South Africa) | 92.00 | (3) |
ASUSHI, Inc. | | Delaware (United States) | 100.00 | (5) |
Atlantica Hidro Colombia SPA | | Bogota D.C. (Colombia) | 15.00* | (4) |
Atlantica Holdings USA LLC | | Tempe (United States) | 100.00 | (5) |
Atlantica Energia Sostenibile Italia, Srl. | | Rome (Italy) | 100.00 | (5) |
Atlantica Colombia S.A.S. | | Bogota D.C. (Colombia) | 100.00 | (5) |
Atlantica Chile SpA | | Santiago de Chile (Chile) | 100.00 | (5) |
Atlantica y Quartux Almacenamiento de Energía S.A.P.I. de C.V. | | Mexico D.F. (Mexico) | 60.00 | (3) |
Atlantica Solutions LLC | | Tempe (United States) | 100.00 | (3) |
ATN, S.A. | ATN | Lima (Peru) | 100.00 | (1) |
ATN 4, S.A | | Lima (Peru) | 100.00 | (1) |
Atlantica Transmisión Sur, S.A. | ATS | Lima (Peru) | 100.00 | (1) |
ACT Holdings, S.A. de C.V. | | Mexico D.F. (Mexico) | 100.00 | (5) |
Aguas de Skikda S.P.A. | Skikda | Dely Ibrahim (Algeria) | 51.00 | (4) |
Arizona Solar One, LLC. | Solana | Delaware (United States) | 100.00 | (3) |
ASI Operations LLC | | Delaware (United States) | 100.00 | (3) |
ASI Vento LLC | | Tempe (United States) | 100.00 | (5) |
ASO Holdings Company, LLC. | | Delaware (United States) | 100.00 | (5) |
Atlantica Investment Ltd. | | Brentford (United Kingdom) | 100.00 | (5) |
AYES International UK Ltd | | Brentford (United Kingdom) | 100.00 | (5) |
Atlantica Energia Sostenible España, S.L. | | Seville (Spain) | 100.00 | (5) |
ATN 2, S.A. | ATN 2 | Lima (Peru) | 100.00 | (1) |
AY Holding Uruguay, S.A. | | Montevideo (Uruguay) | 100.00 | (5) |
Atlantica Yield Energy Solutions Canada Inc. | | Vancouver (Canada) | 10.00* | (5) |
Banitod, S.A. | | Montevideo (Uruguay) | 100.00 | (5) |
Befesa Agua Tenes | | Seville (Spain) | 100.00 | (5) |
Company name | | Project name | | Registered address | | % of nominal share | | Business |
ACT Energy México, S. de R.L. de C.V. | | ACT | | Santa Barbara (Mexico) | | 100.00 | | (2) |
AC Renovables Sol 1 S.A.S. E.S | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
Agrisun, Srl. | | Italy PV 1 | | Rome (Italy) | | 100.00 | | (3) |
Atlantica Corporate Resources, S.L | | | | Seville (Spain) | | 100.00 | | (5) |
Atlantica North America, LLC | | | | Delaware (United States) | | 100.00 | | (5) |
Atlantica Infraestructura Sostenible, S.L.U | | | | Seville (Spain) | | 100.00 | | (5) |
Atlantica Perú, S.A. | | | | Lima (Peru) | | 100.00 | | (5) |
Atlantica Sustainable Infrastructure Jersey, Ltd | | | | Jersey (United Kingdom) | | 100.00 | | (5) |
Atlantica Newco Limited | | | | Brentford (United Kingdom) | | 100.00 | | (5) |
Atlantica DCR, LLC | | | | Delaware (United States) | | 100.00 | | (5) |
ASHUSA Inc. | | | | Delaware (United States) | | 100.00 | | (5) |
Atlantica South Africa (Pty) Ltd | | | | Pretoria (South Africa) | | 100.00 | | (5) |
ASUSHI, Inc. | | | | Delaware (United States) | | 100.00 | | (5) |
Atlantica Chile SpA | | | | Santiago de Chile (Chile) | | 100.00 | | (5) |
Atlantica Holdings USA LLC | | | | Tempe (United States) | | 100.00 | | (5) |
Atlantica Energia Sostenibile Italia, Srl. | | | | Rome (Italy) | | 100.00 | | (5) |
Atlantica Colombia S.A.S. E.S.P. | | | | Bogota D.C. (Colombia) | | 100.00 | | (5) |
ATN, S.A. | | ATN | | Lima (Peru) | | 100.00 | | (1) |
ATN 4, S.A | | | | Lima (Peru) | | 100.00 | | (1) |
Atlantica Transmisión Sur, S.A. | | ATS | | Lima (Peru) | | 100.00 | | (1) |
ACT Holdings, S.A. de C.V. | | | | Mexico D.F. (Mexico) | | 100.00 | | (5) |
Aguas de Skikda S.P.A. | | Skikda | | Dely Ibrahim (Algeria) | | 51.00 | | (4) |
Arizona Solar One, LLC. | | Solana | | Delaware (United States) | | 100.00 | | (3) |
ASI Operations LLC | | | | Delaware (United States) | | 100.00 | | (3) |
ASO Holdings Company, LLC. | | | | Delaware (United States) | | 100.00 | | (5) |
Atlantica Investment Ltd. | | | | Brentford (United Kingdom) | | 100.00 | | (5) |
AYES International UK Ltd | | | | Brentford (United Kingdom) | | 100.00 | | (5) |
Atlantica España O&M, S.L. | | | | Seville (Spain) | | 100.00 | | (5) |
ATN 2, S.A. | | ATN 2 | | Lima (Peru) | | 100.00 | | (1) |
AY Holding Uruguay, S.A. | | | | Montevideo (Uruguay) | | 100.00 | | (5) |
Atlantica Yield Energy Solutions Canada Inc. | | | | Vancouver (Canada) | | 10.00* | | (5) |
Banitod, S.A. | | | | Montevideo (Uruguay) | | 100.00 | | (5) |
Befesa Agua Tenes | | | | Seville (Spain) | | 100.00 | | (5) |
BPC US Wind Corporation, Inc. | | | | Tempe (United States) | | 100.00 | | (5) |
Cadonal, S.A. | | Cadonal | | Montevideo (Uruguay) | | 100.00 | | (3) |
Calgary District Heating, Inc | | Calgary | | Vancouver (Canada) | | 100.00 | | (2) |
Carpio Solar Inversiones, S.A. | | | | Seville (Spain) | | 100.00 | | (5) |
Chile PV 1 | | Chile PV 1 | | Santiago de Chile (Chile) | | 35.00 | | (3) |
CGP Holding Finance, LLC | | Coso | | Delaware (United States) | | 100.00 | | (3) |
Coropuna Transmisión, S.A | | | | Lima (Peru) | | 100.00 | | (1) |
Ecija Solar Inversiones, S.A. | | | | Seville (Spain) | | 100.00 | | (5) |
Estrellada, S.A. | | Melowind | | Montevideo (Uruguay) | | 100.00 | | (3) |
Extremadura Equity Investments Sárl. | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) |
Fotovoltaica Solar Sevilla, S.A. | | Seville PV | | Seville (Spain) | | 80.00 | | (3) |
Geida Skikda, S.L. | | | | Madrid (Spain) | | 67.00 | | (5) |
Helioenergy Electricidad Uno, S.A. | | Helioenergy 1 | | Seville (Spain) | | 100.00 | | (3) |
Helioenergy Electricidad Dos, S.A. | | Helioenergy 2 | | Seville (Spain) | | 100.00 | | (3) |
Helios I Hyperion Energy Investments, S.A. | | Helios 1 | | Seville (Spain) | | 100.00 | | (3) |
Helios II Hyperion Energy Investments, S.A. | | Helios 2 | | Seville (Spain) | | 100.00 | | (3) |
Hidrocañete S.A. | | Mini-Hydro | | Lima (Peru) | | 100.00 | | (3) |
Hypesol Energy Holding, S.L. | | | | Seville (Spain) | | 100.00 | | (5) |
Hypesol Solar Inversiones, S.A | | | | Seville (Spain) | | 100.00 | | (5) |
Kaxu Solar One (Pty) Ltd. | | Kaxu | | Gauteng (South Africa) | | 51.00 | | (3) |
Logrosán Equity Investments Sárl. | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) |
Logrosán Solar Inversiones, S.A. | | | | Seville (Spain) | | 100.00 | | (5) |
Logrosán Solar Inversiones Dos, S.L. | | | | Seville (Spain) | | 100.00 | | (5) |
Mojave Solar Holdings, LLC. | | | | Delaware (United States) | | 100.00 | | (5) |
Mojave Solar LLC. | | Mojave | | Delaware (United States) | | 100.00 | | (3) |
Montesejo Piano, Srl. | | Italy PV 3 | | Rome (Italy) | | 100.00 | | (3) |
Nesyla, S.A | | | | Montevideo (Uruguay) | | 100.00 | | (3) |
Overnight Solar LLC | | | | Arizona (United States) | | 100.00 | | (3) |
Palmatir S.A. | | Palmatir | | Montevideo (Uruguay) | | 100.00 | | (3) |
Palmucho, S.A. | | Palmucho | | Santiago de Chile (Chile) | | 100.00 | | (1) |
PA Renovables Sol 1 S.A.S. E.S | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
Parque Fotovoltaico La Tolua S.A.S | | | | Bogota D.C. (Colombia) | | 100.00 | | (3) |
Parque Solar Tierra Linda, S.A.S | | | | Bogota D.C. (Colombia) | | 100.00 | | (3) |
Parque Fotovoltaico La Sierpe S.A.S | | La Sierpe | | Bogota D.C. (Colombia) | | 100.00 | | (3) |
Re Sole, Srl. | | Italy PV 2 | | Rome (Italy) | | 100.00 | | (3) |
Rioglass Solar Holding, S.A. | | Rioglass | | Asturias (Spain) | | 100.00 | | (3) |
RRHH Servicios Corporativos, S. de R.L. de C.V. | | | | Santa Barbara. (Mexico) | | 100.00 | | (5) |
Sanlucar Solar, S.A. | | PS-10 | | Seville (Spain) | | 100.00 | | (3) |
SJ Renovables Sun 1 S.A.S. E.S | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
SJ Renovables Wind 1 S.A.S. E. | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
Solaben Electricidad Uno S.A. | | Solaben 1 | | Caceres (Spain) | | 100.00 | | (3) |
Solaben Electricidad Dos S.A. | | Solaben 2 | | Caceres (Spain) | | 70.00 | | (3) |
Solaben Electricidad Tres S.A. | | Solaben 3 | | Caceres (Spain) | | 70.00 | | (3) |
Solaben Electricidad Seis S.A. | | Solaben 6 | | Caceres (Spain) | | 100.00 | | (3) |
Solaben Luxembourg S.A. | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) |
Solacor Electricidad Uno, S.A. | | Solacor 1 | | Seville (Spain) | | 87.00 | | (3) |
Solacor Electricidad Dos, S.A. | | Solacor 2 | | Seville (Spain) | | 87.00 | | (3) |
Solar Processes, S.A. | | PS-20 | | Seville (Spain) | | 100.00 | | (3) |
Solnova Solar Inversiones, S.A. | | | | Seville (Spain) | | 100.00 | | (5) |
Solnova Electricidad, S.A. | | Solnova 1 | | Seville (Spain) | | 100.00 | | (3) |
Solnova Electricidad Tres, S.A. | | Solnova 3 | | Seville (Spain) | | 100.00 | | (3) |
Solnova Electricidad Cuatro, S.A. | | Solnova 4 | | Seville (Spain) | | 100.00 | | (3) |
Tenes Lilmiyah, S.P.A | | Tenes | | Dely Ibrahim (Algeria) | | 51.00 | | (4) |
Transmisora Mejillones, S.A. | | Quadra 1 | | Santiago de Chile (Chile) | | 100.00 | | (1) |
Transmisora Baquedano, S.A. | | Quadra 2 | | Santiago de Chile (Chile) | | 100.00 | | (1) |
VO Renovables SOL 1 S.A.S. E.S.P. | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
White Rock Insurance (Europe) PCC Limited | | | | Birkirkara (Malta) | | 100.00 | | (3) |
BPC US Wind Corporation, Inc. | | Tempe (United States) | 100.00 | (5) |
Cadonal, S.A. | Cadonal | Montevideo (Uruguay) | 100.00 | (3) |
Calgary District Heating, Inc | Calgary | Vancouver (Canada) | 100.00 | (2) |
Carpio Solar Inversiones, S.A. | | Seville (Spain) | 100.00 | (5) |
CGP Holding Finance, LLC | Coso | Delaware (United States) | 100.00 | (3) |
Chile PV I | Chile PV I | Santiago de Chile (Chile) | 35.00* | (3) |
Chile PV II | Chile PV II | Santiago de Chile (Chile) | 35.00* | (3) |
Chile PV III | Chile PV III | Santiago de Chile (Chile) | 35.00* | (3) |
Coropuna Transmisión, S.A. | | Lima (Peru) | 100.00 | (1) |
Day Ahead Solar LLC | | Tempe (United States) | 100.00 | (3) |
Ecija Solar Inversiones, S.A. | | Seville (Spain) | 100.00 | (5) |
Energía Renovable Dalia 1 SA de CV | | San Luis Potosi (Mexico) | 51.00 | (3) |
Energía Renovable Dalia 2 SA de CV | | San Luis Potosi (Mexico) | 51.00 | (3) |
Energía Renovable Dalia 3 SA de CV | | San Luis Potosi (Mexico) | 51.00 | (3) |
Estrellada, S.A. | Melowind | Montevideo (Uruguay) | 100.00 | (3) |
Extremadura Equity Investments Sárl. | | Luxembourg (Luxembourg) | 100.00 | (5) |
Fotovoltaica Solar Sevilla, S.A. | Seville PV | Seville (Spain) | 80.00 | (3) |
Geida Skikda, S.L. | | Madrid (Spain) | 67.00 | (5) |
Global Solar Participations Sarl | | Luxembourg (Luxembourg) | 100.00 | (5) |
Helioenergy Electricidad Uno, S.A. | Helioenergy 1 | Seville (Spain) | 100.00 | (3) |
Helioenergy Electricidad Dos, S.A. | Helioenergy 2 | Seville (Spain) | 100.00 | (3) |
Helios I Hyperion Energy Investments, S.A. | Helios 1 | Seville (Spain) | 100.00 | (3) |
Helios II Hyperion Energy Investments, S.A. | Helios 2 | Seville (Spain) | 100.00 | (3) |
Helios 2, S.R.L | Italy PV 4 | Rome (Italy) | 100.00 | (3) |
Hidrocañete S.A. | Mini-Hydro | Lima (Peru) | 100.00 | (3) |
Hunucma Wind Power S.A. de C.V | | Mexico D.F. (Mexico) | 100.00 | (3) |
Hypesol Energy Holding, S.L. | | Seville (Spain) | 100.00 | (5) |
Hypesol Solar Inversiones, S.A | | Seville (Spain) | 100.00 | (5) |
Kaxu Solar One (Pty) Ltd. | Kaxu | Gauteng (South Africa) | 51.00 | (3) |
Logrosán Equity Investments Sárl. | | Luxembourg (Luxembourg) | 100.00 | (5) |
Logrosán Solar Inversiones, S.A. | | Seville (Spain) | 100.00 | (5) |
Logrosán Solar Inversiones Dos, S.L. | | Seville (Spain) | 100.00 | (5) |
Mojave Solar Holdings, LLC. | | Delaware (United States) | 100.00 | (5) |
Mojave Solar LLC. | Mojave | Delaware (United States) | 100.00 | (3) |
Montesejo Pianno, S.R.L. | Italy PV 3 | Rome (Italy) | 100.00 | (3) |
Mordor ES1 LLC | | Tempe (United States) | 100.00 | (3) |
Mordor ES2 LLC | | Tempe (United States) | 100.00 | (3) |
Nesyla, S.A | Albisu | Montevideo (Uruguay) | 100.00 | (3) |
Overnight Solar LLC | | Arizona (United States) | 100.00 | (3) |
Palmatir S.A. | Palmatir | Montevideo (Uruguay) | 100.00 | (3) |
Palmucho, S.A. | Palmucho | Santiago de Chile (Chile) | 100.00 | (1) |
PA Renovables Sol 1 S.A.S. | | Bogota D.C. (Colombia) | 70.00 | (3) |
Parque Fotovoltaico La Tolua S.A.S | La Tolua | Bogota D.C. (Colombia) | 100.00 | (3) |
Parque Solar Tierra Linda, S.A.S | Tierra Linda | Bogota D.C. (Colombia) | 100.00 | (3) |
Parque Fotovoltaico La Sierpe S.A.S | La Sierpe | Bogota D.C. (Colombia) | 100.00 | (3) |
Re Sole, Srl. | Italy PV 2 | Rome (Italy) | 100.00 | (3) |
Rilados S.A | | Montevideo (Uruguay) | 100.00 | (3) |
Rioglass Solar Holding, S.A. | | Asturias (Spain) | 100.00 | (3) |
RRHH Servicios Corporativos, S. de R.L. de C.V. | | Santa Barbara (Mexico) | 100.00 | (5) |
Sanlucar Solar, S.A. | PS-10 | Seville (Spain) | 100.00 | (3) |
SJ Renovables Sun 1 S.A.S. | | Bogota D.C. (Colombia) | 70.00 | (3) |
SJ Renovables Wind 1 S.A.S. | | Bogota D.C. (Colombia) | 70.00 | (3) |
Solaben Electricidad Uno S.A. | Solaben 1 | Caceres (Spain) | 100.00 | (3) |
Solaben Electricidad Dos S.A. | Solaben 2 | Caceres (Spain) | 70.00 | (3) |
Solaben Electricidad Tres S.A. | Solaben 3 | Caceres (Spain) | 70.00 | (3) |
Solaben Electricidad Seis S.A. | Solaben 6 | Caceres (Spain) | 100.00 | (3) |
Solaben Luxembourg S.A. | | Luxembourg (Luxembourg) | 100.00 | (5) |
Solacor Electricidad Uno, S.A. | Solacor 1 | Seville (Spain) | 87.00 | (3) |
Solacor Electricidad Dos, S.A. | Solacor 2 | Seville (Spain) | 87.00 | (3) |
Atlantica Corporate Resources, S.L | | Seville (Spain) | 100.00 | (5) |
Solar Processes, S.A. | PS-20 | Seville (Spain) | 100.00 | (3) |
Solnova Solar Inversiones, S.A. | | Seville (Spain) | 100.00 | (5) |
Solnova Electricidad, S.A. | Solnova 1 | Seville (Spain) | 100.00 | (3) |
Solnova Electricidad Tres, S.A. | Solnova 3 | Seville (Spain) | 100.00 | (3) |
Solnova Electricidad Cuatro, S.A. | Solnova 4 | Seville (Spain) | 100.00 | (3) |
Tenes Lilmiyah, S.P.A | Tenes | Dely Ibrahim (Algeria) | 51.00 | (4) |
Transmisora Mejillones, S.A. | Quadra 1 | Santiago de Chile (Chile) | 100.00 | (1) |
Transmisora Melipeuco S.A. | Melipeuco | Santiago de Chile (Chile) | 100.00 | (1) |
Transmisora Baquedano, S.A. | Quadra 2 | Santiago de Chile (Chile) | 100.00 | (1) |
VO Renovables SOL 1 S.A.S. | | Bogota D.C. (Colombia) | 70.00 | (3) |
White Rock Insurance (Europe) PCC Limited | | Birkirkara (Malta) | 100.00 | (5) |
| (1) | Business sector: Transmission lines |
| (2) | Business sector: Efficient natural gas and Heat |
| (3) | Business sector: Renewable energy |
| (4) | Business sector: Water |
| * | Atlantica has control over AYES Canada Inc.these entities under IFRS 10, Consolidated Financial Statements. |
The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
Entities included in the Group as subsidiaries as of December 31, 20202021
Company name | | Project name | | Registered address | | % of nominal share | | Business | | Project name | | Registered address | | % of nominal share | | Business |
ACT Energy México, S. de R.L. de C.V. | | ACT | | Santa Barbara (Mexico) | | 100.00 | | (2) | | ACT | | Santa Barbara (Mexico) | | 100.00 | | (2) |
AC Renovables Sol 1 S.A.S. | | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
Agrisun, Srl. | | | Italy PV 1 | | Rome (Italy) | | 100.00 | | (3) |
Atlantica Corporate Resources, S.L | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
Atlantica North America, LLC | | | | Delaware (United States) | | 100.00 | | (5) | | | | Delaware (United States) | | 100.00 | | (5) |
Atlantica Infraestructura Sostenible, S.L.U | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
Atlantica Perú, S.A. | | | | Lima (Peru) | | 100.00 | | (5) | | | | Lima (Peru) | | 100.00 | | (5) |
Atlantica Sustainable Infrastructure Jersey, Ltd | | | | Jersey (United Kingdom) | | 100.00 | | (5) | | | | Jersey (United Kingdom) | | 100.00 | | (5) |
Atlantica Newco Limited | | | | Brentford (United Kingdom) | | 100.00 | | (5) | | | | Brentford (United Kingdom) | | 100.00 | | (5) |
Atlantica DCR, LLC | | | | Delaware (United States) | | 100.00 | | (5) | | | | Delaware (United States) | | 100.00 | | (5) |
ASHUSA Inc. | | | | Delaware (United States) | | 100.00 | | (5) | | | | Delaware (United States) | | 100.00 | | (5) |
Atlantica South Africa (Pty) Ltd | | | | Pretoria (South Africa) | | 100.00 | | (5) | | | | Pretoria (South Africa) | | 100.00 | | (5) |
ASUSHI, Inc. | | | | Delaware (United States) | | 100.00 | | (5) | | | | Delaware (United States) | | 100.00 | | (5) |
Atlantica Chile SpA | | | | Santiago de Chile (Chile) | | 100.00 | | (5) | | | | Santiago de Chile (Chile) | | 100.00 | | (5) |
Atlantica Holdings USA LLC | | | | | Tempe (United States) | | 100.00 | | (5) |
Atlantica Energia Sostenibile Italia, Srl. | | | | | Rome (Italy) | | 100.00 | | (5) |
Atlantica Colombia S.A.S. | | | | | Bogota D.C. (Colombia) | | 100.00 | | (5) |
ATN, S.A. | | ATN | | Lima (Peru) | | 100.00 | | (1) | | ATN | | Lima (Peru) | | 100.00 | | (1) |
ATN 4, S.A | | | | Lima (Peru) | | 100.00 | | (1) | | | | Lima (Peru) | | 100.00 | | (1) |
Atlantica Transmisión Sur, S.A. | | ATS | | Lima (Peru) | | 100.00 | | (1) | | ATS | | Lima (Peru) | | 100.00 | | (1) |
ACT Holdings, S.A. de C.V. | | | | Mexico D.F. (Mexico) | | 100.00 | | (5) | | | | Mexico D.F. (Mexico) | | 100.00 | | (5) |
Aguas de Skikda S.P.A. | | Skikda | | Dely Ibrahim (Algeria) | | 51.00 | | (4) | | Skikda | | Dely Ibrahim (Algeria) | | 51.00 | | (4) |
Arizona Solar One, LLC. | | Solana | | Delaware (United States) | | 100.00 | | (3) | | Solana | | Delaware (United States) | | 100.00 | | (3) |
ASI Operations LLC | | | | Delaware (United States) | | 100.00 | | (3) | | | | Delaware (United States) | | 100.00 | | (3) |
ASO Holdings Company, LLC. | | | | Delaware (United States) | | 100.00 | | (5) | | | | Delaware (United States) | | 100.00 | | (5) |
Atlantica Investment Ltd. | | | | Brentford (United Kingdom) | | 100.00 | | (5) | | | | Brentford (United Kingdom) | | 100.00 | | (5) |
AYES International UK Ltd | | | | Brentford (United Kingdom) | | 100.00 | | (5) | | | | Brentford (United Kingdom) | | 100.00 | | (5) |
Atlantica España O&M, S.L. | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
ATN 2, S.A. | | ATN 2 | | Lima (Peru) | | 100.00 | | (1) | | ATN 2 | | Lima (Peru) | | 100.00 | | (1) |
AY Holding Uruguay, S.A. | | | | Montevideo (Uruguay) | | 100.00 | | (5) | | | | Montevideo (Uruguay) | | 100.00 | | (5) |
Atlantica Yield Energy Solutions Canada Inc. | | | | Vancouver (Canada) | | 10.00* | | (5) | | | | Vancouver (Canada) | | 10.00* | | (5) |
Banitod, S.A. | | | | Montevideo (Uruguay) | | 100.00 | | (5) | | | | Montevideo (Uruguay) | | 100.00 | | (5) |
Befesa Agua Tenes | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
BPC US Wind Corporation, Inc. | | | | | Tempe (United States) | | 100.00 | | (5) |
Cadonal, S.A. | | Cadonal | | Montevideo (Uruguay) | | 100.00 | | (3) | | Cadonal | | Montevideo (Uruguay) | | 100.00 | | (3) |
Calgary District Heating, Inc | | Calgary | | Vancouver (Canada) | | 100.00 | | (2) | | Calgary | | Vancouver (Canada) | | 100.00 | | (2) |
Carpio Solar Inversiones, S.A. | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
Chile PV 1 | | Chile PV 1 | | Santiago de Chile (Chile) | | 35.00 | | (3) | | Chile PV 1 | | Santiago de Chile (Chile) | | 35.00* | | (3) |
Coropuna Transmisión, S.A | | | | Lima (Peru) | | 100.00 | | (1) | |
Chile PV 2
| | | Chile PV 2
| | Santiago de Chile (Chile) | | 35.00* | | (3)
|
CGP Holding Finance, LLC | | | Coso | | Delaware (United States) | | 100.00 | | (3) |
Coropuna Transmisión, S.A. | | | | | Lima (Peru) | | 100.00 | | (1) |
Ecija Solar Inversiones, S.A. | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
CKA1 Holding S. de R.L. de C.V. | | | | Mexico D.F. (Mexico) | | 100.00 | | (5) | |
Estrellada, S.A. | | Melowind | | Montevideo (Uruguay) | | 100.00 | | (3) | | Melowind | | Montevideo (Uruguay) | | 100.00 | | (3) |
Extremadura Equity Investments Sárl. | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) |
Fotovoltaica Solar Sevilla, S.A. | | Seville PV | | Seville (Spain) | | 80.00 | | (3) | | Seville PV | | Seville (Spain) | | 80.00 | | (3) |
Geida Skikda, S.L. | | | | Madrid (Spain) | | 67.00 | | (5) | | | | Madrid (Spain) | | 67.00 | | (5) |
Helioenergy Electricidad Uno, S.A. | | Helioenergy 1 | | Seville (Spain) | | 100.00 | | (3) | | Helioenergy 1 | | Seville (Spain) | | 100.00 | | (3) |
Helioenergy Electricidad Dos, S.A. | | Helioenergy 2 | | Seville (Spain) | | 100.00 | | (3) | | Helioenergy 2 | | Seville (Spain) | | 100.00 | | (3) |
Helios I Hyperion Energy Investments, S.A. | | | Helios 1 | | Seville (Spain) | | 100.00 | | (3) |
Helios II Hyperion Energy Investments, S.A. | | | Helios 2 | | Seville (Spain) | | 100.00 | | (3) |
Helios I Hyperion Energy Investments, S.A. | | Helios 1 | | Seville (Spain) | | 100.00 | | (3) | |
Helios II Hyperion Energy Investments, S.A. | | Helios 2 | | Seville (Spain) | | 100.00 | | (3) | |
Hidrocañete S.A. | | Mini-Hydro | | Lima (Peru) | | 100.00 | | (3) | | Mini-Hydro | | Lima (Peru) | | 100.00 | | (3) |
Hypesol Energy Holding, S.L. | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
Hypesol Solar Inversiones, S.A | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
Kaxu Solar One (Pty) Ltd. | | Kaxu | | Gauteng (South Africa) | | 51.00 | | (3) | | Kaxu | | Gauteng (South Africa) | | 51.00 | | (3) |
Logrosán Equity Investments Sárl. | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) |
Logrosán Solar Inversiones, S.A. | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
Logrosán Solar Inversiones Dos, S.L. | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
Mojave Solar Holdings, LLC. | | | | Delaware (United States) | | 100.00 | | (5) | | | | Delaware (United States) | | 100.00 | | (5) |
Mojave Solar LLC. | | Mojave | | Delaware (United States) | | 100.00 | | (3) | | Mojave | | Delaware (United States) | | 100.00 | | (3) |
Montesejo Piano, Srl. | | | Italy PV 3 | | Rome (Italy) | | 100.00 | | (3) |
Nesyla, S.A | | | | Montevideo (Uruguay) | | 100.00 | | (3) | | | | Montevideo (Uruguay) | | 100.00 | | (3) |
Overnight Solar LLC | | | | Arizona (United States) | | 100.00 | | (3) | | | | Arizona (United States) | | 100.00 | | (3) |
Palmatir S.A. | | Palmatir | | Montevideo (Uruguay) | | 100.00 | | (3) | | Palmatir | | Montevideo (Uruguay) | | 100.00 | | (3) |
Palmucho, S.A. | | Palmucho | | Santiago de Chile (Chile) | | 100.00 | | (1) | | Palmucho | | Santiago de Chile (Chile) | | 100.00 | | (1) |
PA Renovables Sol 1 S.A.S. | | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
Parque Fotovoltaico La Tolua S.A.S | | | | | Bogota D.C. (Colombia) | | 100.00 | | (3) |
Parque Solar Tierra Linda, S.A.S | | | | | Bogota D.C. (Colombia) | | 100.00 | | (3) |
Parque Fotovoltaico La Sierpe S.A.S | | | La Sierpe | | Bogota D.C. (Colombia) | | 100.00 | | (3) |
Re Sole, Srl. | | | Italy PV 2 | | Rome (Italy) | | 100.00 | | (3) |
Rioglass Solar Holding, S.A. | | | Rioglass | | Asturias (Spain) | | 100.00 | | (3) |
RRHH Servicios Corporativos, S. de R.L. de C.V. | | | | Santa Barbara. (Mexico) | | 100.00 | | (5) | | | | Santa Barbara (Mexico) | | 100.00 | | (5) |
Sanlucar Solar, S.A. | | PS-10 | | Seville (Spain) | | 100.00 | | (3) | | PS-10 | | Seville (Spain) | | 100.00 | | (3) |
SJ Renovables Sun 1 S.A.S. | | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
SJ Renovables Wind 1 S.A.S. | | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
Solaben Electricidad Uno S.A. | | Solaben 1 | | Caceres (Spain) | | 100.00 | | (3) | | Solaben 1 | | Caceres (Spain) | | 100.00 | | (3) |
Solaben Electricidad Dos S.A. | | Solaben 2 | | Caceres (Spain) | | 70.00 | | (3) | | Solaben 2 | | Caceres (Spain) | | 70.00 | | (3) |
Solaben Electricidad Tres S.A. | | Solaben 3 | | Caceres (Spain) | | 70.00 | | (3) | | Solaben 3 | | Caceres (Spain) | | 70.00 | | (3) |
Solaben Electricidad Seis S.A. | | Solaben 6 | | Caceres (Spain) | | 100.00 | | (3) | | Solaben 6 | | Caceres (Spain) | | 100.00 | | (3) |
Solaben Luxembourg S.A. | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) | | | | Luxembourg (Luxembourg) | | 100.00 | | (5) |
Solacor Electricidad Uno, S.A. | | Solacor 1 | | Seville (Spain) | | 87.00 | | (3) | | Solacor 1 | | Seville (Spain) | | 87.00 | | (3) |
Solacor Electricidad Dos, S.A. | | Solacor 2 | | Seville (Spain) | | 87.00 | | (3) | | Solacor 2 | | Seville (Spain) | | 87.00 | | (3) |
Solar Processes, S.A. | | PS-20 | | Seville (Spain) | | 100.00 | | (3) | | PS-20 | | Seville (Spain) | | 100.00 | | (3) |
Solnova Solar Inversiones, S.A. | | | | Seville (Spain) | | 100.00 | | (5) | | | | Seville (Spain) | | 100.00 | | (5) |
Solnova Electricidad, S.A. | | Solnova 1 | | Seville (Spain) | | 100.00 | | (3) | | Solnova 1 | | Seville (Spain) | | 100.00 | | (3) |
Solnova Electricidad Tres, S.A. | | Solnova 3 | | Seville (Spain) | | 100.00 | | (3) | | Solnova 3 | | Seville (Spain) | | 100.00 | | (3) |
Solnova Electricidad Cuatro, S.A. | | Solnova 4 | | Seville (Spain) | | 100.00 | | (3) | | Solnova 4 | | Seville (Spain) | | 100.00 | | (3) |
Tenes Lilmiyah, S.P.A | | Tenes | | Dely Ibrahim (Algeria) | | 51.00 | | (4) | | Tenes | | Dely Ibrahim (Algeria) | | 51.00 | | (4) |
Sunshine Finance Jersey, Ltd | | | | Jersey (United Kigdom) | | 100.00 | | (5) | |
Transmisora Mejillones, S.A. | | Quadra 1 | | Santiago de Chile (Chile) | | 100.00 | | (1) | | Quadra 1 | | Santiago de Chile (Chile) | | 100.00 | | (1) |
Transmisora Baquedano, S.A. | | Quadra 2 | | Santiago de Chile (Chile) | | 100.00 | | (1) | | Quadra 2 | | Santiago de Chile (Chile) | | 100.00 | | (1) |
VO Renovables SOL 1 S.A.S. | | | | | Bogota D.C. (Colombia) | | 70.00 | | (3) |
White Rock Insurance (Europe) PCC Limited | | | | | Birkirkara (Malta) | | 100.00 | | (3) |
(1) | Business sector: Transmission lines |
(2) | Business sector: Efficient natural gas and Heat |
(3) | Business sector: Renewable energy |
(4) | Business sector: Water |
* | Atlantica has control over AYES Canada Inc. under IFRS 10, Consolidated Financial Statements. |
The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
Investments recorded under the equity method as of December 31, 20212022
Company name | | Project name | | Registered address | | | % of nominal share | | | Business | | | Project name | | Registered address | | % of nominal share | | Business | |
ABY Infraestructuras, S.L. | | | | Seville (Spain) | | | | 20.0 | | | | (3 | ) | |
Akuo Atlantica PMGD Holding | | | Chile PMGD | | Santiago de Chile (Chile) | | 49.0 | | (3 | ) |
Amherst Island Partnership | | Windlectric | | Ontario (Canada) | | | | 30.0 | | | | (3 | ) | | Windlectric | | Ontario (Canada) | | 30.0 | | (3 | ) |
Arroyo Energy Netherlands II B.V. | | Monterrey | | Amsterdam (Netherlands) | | | | 30.0 | | | | (2 | ) | | Monterrey | | Amsterdam (Netherlands) | | 30.0 | | (2 | ) |
Evacuacion Valdecaballeros, S.L. | | | | Caceres (Spain) | | | | 57.2 | | | | (3 | ) | | | | Caceres (Spain) | | 57.2 | | (3 | ) |
Evacuación Villanueva del Rey, S.L. | | | | Seville (Spain) | | | | 40.0 | | | | (3 | ) | | | | Seville (Spain) | | 40.0 | | (3 | ) |
Fontanil Solar S.L. | | | | | Albacete (Spain) | | 25.0 | | (3 | ) |
Geida Tlemcen S.L. | | Honaine | | Madrid (Spain) | | | | 50.0 | | | | (4 | ) | | Honaine | | Madrid (Spain) | | 50.0 | | (4 | ) |
Liberty Infraestructuras, S.L. | | | | | Seville (Spain) | | 20.0 | | (3 | ) |
Murum Solar, S.L. | | | | | Murcia (Spain) | | 25,0 | | (3 | ) |
Pectonex R.F. | | | | Pretoria (South Africa) | | | | 50.0 | | | | (3 | ) | | | | Pretoria (South Africa) | | 50.0 | | (3 | ) |
2007 Vento II, LLC. | | Vento II | | Delaware (United States) | | | | 49.0 | | | | (3 | ) | | Vento II | | Delaware (United States) | | 49.0 | | (3 | ) |
(1) | Business sector: Transmission lines |
(2) | Business sector: Efficient natural gas and Heat |
(3) | Business sector: Renewable energy |
(4) | Business sector: Water |
The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
Investments recorded under the equity method as of December 31, 20202021
Company name | | Project name | | Registered address | | | % of nominal share | | | Business | | | Project name | | Registered address | | % of nominal share | | Business | |
ABY Infraestructuras, S.L. | | | | Seville (Spain) | | | | 20.0 | | | | (3 | ) | |
AC Renovables Sol 1 S.A.S. E.S.P. | | | | Bogota D.C. (Colombia) | | | | 50.0 | | | | (3 | ) | |
Amherst Island Partnership | | Windlectric | | Ontario (Canada) | | | | 30.0 | | | | (3 | ) | | Windlectric | | Ontario (Canada) | | 30.0 | | (3 | ) |
Arroyo Energy Netherlands II B.V. | | Monterrey | | Amsterdam (Netherlands) | | | | 30.0 | | | | (2 | ) | | Monterrey | | Amsterdam (Netherlands) | | 30.0 | | (2 | ) |
Ca Ku A1, S.A.P.I de CV | | | | Mexico D.F. (Mexico) | | | | 5.0 | | | | (2 | ) | |
Evacuacion Valdecaballeros, S.L. | | | | Caceres (Spain) | | | | 57.2 | | | | (3 | ) | | | | Caceres (Spain) | | 57.2 | | (3 | ) |
Evacuación Villanueva del Rey, S.L. | | | | Seville (Spain) | | | | 40.0 | | | | (3 | ) | | | | Seville (Spain) | | 40.0 | | (3 | ) |
Geida Tlemcen S.L. | | Honaine | | Madrid (Spain) | | | | 50.0 | | | | (4 | ) | | Honaine | | Madrid (Spain) | | 50.0 | | (4 | ) |
PA Renovables Sol 1 S.A.S. E.S.P. | | | | Bogota D.C. (Colombia) | | | | 50.0 | | | | (3 | ) | |
Liberty Infraestructuras, S.L. | | | | | Seville (Spain) | | 20.0 | | (3 | ) |
Pectonex R.F. | | | | Pretoria (South Africa) | | | | 50.0 | | | | (3 | ) | | | | Pretoria (South Africa) | | 50.0 | | (3 | ) |
SJ Renovables Sun 1 S.A.S. E.S.P. | | | | Bogota D.C. (Colombia) | | | | 50.0 | | | | (3 | ) | |
SJ Renovables Wind 1 S.A.S. E.S.P. | | | | Bogota D.C. (Colombia) | | | | 50.0 | | | | (3 | ) | |
2007 Vento II, LLC. | | | Vento II | | Delaware (United States) | | 49.0 | | (3 | ) |
(1) | Business sector: Transmission lines |
(2) | Business sector: Efficient natural gas and Heat |
(3) | Business sector: Renewable energy |
(4) | Business sector: Water |
The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
Assets subject to the application of IFRIC 12 interpretation based on the concession of
services as of December 31, 20212022 and 20202021
Description of the Arrangements
Solana
Solana is a 250 MW net (280 MW gross) solar electric generation facility located in Maricopa County, Arizona, approximately 70 miles southwest of Phoenix. Arizona Solar One LLC, or Arizona Solar, owns the Solana project. Solana includes a 22-mile 230kV transmission line and a molten salt thermal energy storage system. Solana reached COD on October 9, 2013.
Solana has a 30-year, PPA with Arizona Public Service, or APS, approved by the Arizona Corporation Commission (ACC). The PPA provides for the sale of electricity at a fixed price per MWh with annual increases of 1.84% per year. The PPA includes limitations on the amount and condition of the energy that is received by APS with minimum and maximum thresholds for delivery capacity that must not be breached.
Mojave
Mojave is a 250 MW net (280 MW gross) solar electric generation facility located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Mojave reached COD on December 1, 2014.
Mojave has a 25-year, PPA with Pacific Gas & Electric Company, or PG&E, approved by the California Public Utilities Commission (CPUC). The PPA began on COD. The PPA provides for the sale of electricity at a fixed base price per MWh without any indexation mechanism, including limitations on the amount and condition of the energy that is received by PG&E with minimum and maximum thresholds for delivery capacity that must not be breached.
Palmatir
Palmatir is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Palmatir has 25 wind turbines and each turbine has a nominal capacity of 2 MW. UTE, Uruguay’s state-owned electricity company, has agreed to purchase all energy produced by Palmatir pursuant to a 20-year PPA. UTE will pay a fixed-price tariff per MWh under the PPA, which is denominated in U.S. dollars and will be partially adjusted in January of each year according to a formula based on inflation.
Palmatir reached COD in May 2014.
Cadonal
Cadonal is an on-shore wind farm facility in Uruguay with nominal installed capacity of 50 MW. Cadonal has 25 wind turbines and each turbine has a nominal capacity of 2 MW each. UTE, Uruguay´s state-owned electricity company, has agreed to purchase all energy produced by Cadonal pursuant to a 20-year PPA.
Cadonal reached COD in December 2014.
Melowind
Melowind is an on-shore wind farm facility wholly owned by the Company, located in Uruguay with a capacity of 50 MW. Melowind has 20 wind turbines of 2.5 MW each. The asset reached COD in November 2015.
Melowind signed a 20-year PPA with UTE in 2015, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted every year based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollars exchange rate.
Solaben 2 & Solaben 3
The Solaben 2 and Solaben 3 are two 50 MW Solar Power facilities and reached COD in 2012. Itochu Corporation holds 30% of Solaben 2 & Solaben 3.
Renewable energy plants in Spain, like Solaben 2 and Solaben 3, are regulated through a series of laws and rulings which guarantee the owners of the plants a reasonable return for their investments. Solaben 2 and Solaben 3 sell the power they produce into the wholesale electricity market, where offer and demand are matched and the pool price is determined, and also receive additional payments from the CNMC, the Spanish state-owned regulator.
Solacor 1 & Solacor 2
The Solacor 1 and Solacor 2 are two 50 MW Solar Power facilities and reached COD in 2012. JGC Corporation holds 13% of Solacor 1 & Solacor 2.
Solnova 1, 3 & 4
The Solnova 1, 3 and 4 solar plants are located in the municipality of Sanlucar la Mayor, Spain. The plants have 50 MW each and reached COD in 2010.
Helios 1 & 2
The Helios 1 and 2 solar plants are located in Ciudad Real, Spain, and reached COD in 2012. The plants have 50 MW each.
Helioenergy 1 & 2
The Helioenergy 1 and 2 solar plants are located in Ecija, Spain, and reached COD in 2011. The plants have 50 MW each.
Solaben 1 & 6
The Solaben 1&6 are two 50 MW solar plants are located in the municipality of Logrosán, Spain and reached COD in 2013.
Kaxu
Kaxu Solar One, or Kaxu, is a 100 MW solar Conventional Parabolic Trough Project located in Paulputs in the Northern Cape Province of South Africa. Atlantica owns 51% of the Kaxu Project, while Industrial Development Corporation of South Africa owns 29% and Kaxu Community Trust owns 20%.
The project reached COD in February 2015.
Kaxu has a 20-year PPA with Eskom SOC Ltd., or Eskom, under a take or pay contract for the purchase of electricity up to the contracted capacity from the facility. Eskom purchases all the output of the Kaxu Plantplant under a fixed price formula in local currency subject to indexation to local inflation. The PPA expires in February 2035.
ACT
The ACT plant is a gas-fired cogeneration facility with a rated capacity of approximately 300 MW and between 550 and 800 metric tons per hour of steam. The plant includes a substation and an approximately 52 mile and 115-kilowatt transmission line.
On September 18, 2009, ACT entered into the Pemex Conversion Services Agreement, or the Pemex CSA, with Pemex. Pemex is a state-owned oil and gas company supervised by the (CRE), the Mexican state agency that regulates the energy industry. The Pemex CSA has a term of 20 years from the in-service date and will expire on March 31, 2033.
According to the Pemex CSA, ACT must provide, in exchange for a fixed price with escalation adjustments, services including the supply and transformation of natural gas and water into thermal energy and electricity. Part of the electricity is to be supplied directly to a Pemex facility nearby, allowing the (CFE) to supply less electricity to that facility. Approximately 90% of the electricity must be injected into the Mexican electricity network to be used by retail and industrial end customers of CFE in the region. Pemex is then entitled to receive an equivalent amount of energy in more than 1,000 of their facilities in other parts of the country from CFE, following an adjustment mechanism under the supervision of CFE.
The Pemex CSA is denominated in U.S. dollars. The price is a fixed tariff and will be adjusted annually, part of it according to inflation and part according to a mechanism agreed in the contract that on average over the life of the contract reflects expected inflation. The components of the price structure and yearly adjustment mechanisms were prepared by Pemex and provided to bidders as part of the request for proposal documents.
ATS
ATS is a 569 miles transmission line located in Peru wholly owned by the Company. ATS is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATS reached COD in 2014.
Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATS a concession to construct, develop, own, operate and maintain the ATS Project. The initial concession agreement became effective on July 22, 2010 and will expire 30 years after COD, which took place in January 2014. ATS is obliged to provide the service of transmission of electric energy through the operation and maintenance of the electric transmission line, according to the terms of the contract and the applicable law.
The laws and regulations of Peru establish the key parameters of the concession contract, the price indexation mechanism, the rights and obligations of the operator and the procedure that hashave to be followed in order to fix the applicable tariff, which occurs through a regulated bidding process. Once the bidding process is complete and the operator is granted the concession, the pricing of the power transmission service is established in the concession agreement. ATS has a 30-year concession agreement with fixed-price tariff base denominated in U.S. dollars that is adjusted annually after COD of each line, in accordance with the U.S. Finished Goods Less Food and Energy Index published by the U.S. Department of Labor.
ATN
ATN is a 365 miles transmission line located in Peru wholly owned by the Company, which is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATN reached COD in 2011. On December 28, 2018, ATN S.A. completed the acquisition of a power substation and two small transmission lines to connect its line to the Shahuindo (ATN expansion 1) mine located nearby. In October 2019, the Company also closed the acquisition of ATN Expansion 2.
Pursuant to the initial concession agreement, the Ministry of Energy, on behalf of the Peruvian Government, granted ATN a concession to construct, develop, own, operate and maintain the ATN Project. The initial concession agreement became effective on May 22, 2008 and will expire 30 years after COD of the first tranche of the line, which took place in January 2011. ATN is obliged to provide the service of transmission of electric energy through the operation and maintenance of the electric transmission line, according to the terms of the contract and the applicable law.
The laws and regulations of Peru establish the key parameters of the concession contract, the price indexation mechanism, the rights and obligations of the operator and the procedures that have to be followed in order to fix the applicable tariff, which occurs through a regulated bidding process. Once the bidding process is complete and the operator is granted the concession, the pricing of the power transmission service is established in the concession agreement. ATN has a 30-year concession agreement with a fixed-price tariff base denominated in U.S. dollars that is adjusted annually after COD of each line, in accordance with the U.S. Finished Goods Less Food and Energy Index published by the U.S. Department of Labor. In addition, both ATN Expansion 1 and ATN Expansion 2 have 20-year PPAs denominated in U.S. dollars.
ATN 2
ATN2, is an 81 miles transmission line located in Peru wholly owned by the Company, which is part of the Complementary Transmission System. ATN2 reached COD in June 2015.
The Client is Las Bambas Mining Company.
The ATN2 Project has a 18-year contract period, after that, ATN2 assets will remain as property of the SPV allowing ATN2 to potentially sign a new contract. The ATN2 Project has a fixed-price tariff base denominated in U.S. dollars, partially adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. The receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to the ATN2 Project. The tariff base is intended to provide the ATN2 Project with consistent and predictable monthly revenues sufficient to cover the ATN2 Project’s operating costs and debt service and to earn an equity return. Peruvian law requires the existence of a definitive concession agreement to perform electricity transmission activities where the transmission facilities cross public land or land owned by third parties. On May 31, 2014, the Ministry of Energy granted the project a definitive concession agreement to the transmission lines of the ATN2 Project.
Quadra 1 & Quadra 2
Quadra 1 is a 49-miles transmission line project and Quadra 2 is a 32-miles transmission line project, each connected to the Sierra Gorda substations.
Both projects have concession agreements with Sierra Gorda SCM. The agreements are denominated in U.S. dollars and are indexed mainly to CPI. The concession agreements each have a 21-year term that began on COD, which took place in April 2014 and March 2014 for Quadra 1 and Quadra 2, respectively.
Quadra 1 and Quadra 2 belong to the Northern Interconnected System (SING), one of the two interconnected systems into which the Chilean electricity market is divided and structured for both technical and regulatory purposes.
As part of the SING, Quadra 1 and Quadra 2 and the service they provide are regulated by several regulatory bodies, in particular: the Superintendent’s office of Electricity and Fuels (SEC), the Economic Local Dispatch Center (CDEC), the National Board of Energy CNE) and the National Environmental Board (CONAMA) and other environmental regulatory bodies.
In all these concession arrangements, the operator has all the rights necessary to manage, operate and maintain the assets and the obligation to provide the services defined above, which are clearly defined in each concession contract and in the applicable regulations in each country.
Skikda
The Skikda project is a water desalination plant located in Skikda, Algeria. AEC owns 49% and Sacyr Agua S.L. owns indirectly the remaining 16.83% of the Skikda project.
Skikda has a capacity of 3.5 M ft3 per day of desalinated water and is in operation since February 2009. The project serves a population of 0.5 million.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach / ADE.Algerienne des Eaux (“ADE”). The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
Honaine
The Honaine project is a water desalination plant located in Taffsout, Algeria. Myah Bahr Honaine Spa, or MBH, is the vehicle incorporated in Algeria for the purposes of owning the Honaine project. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua S.L., a subsidiary of Sacyr, S.A., owns indirectly the remaining 25.5% of the Honaine project.
Honaine has a capacity of seven M ft3 per day of desalinated water and it is under operation since July 2012.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach / ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.
Tenes
Tenes is a water desalination plant located in Algeria. Befesa Agua Tenes has a 51.0% stake in Ténès Lilmiyah SpA. The remaining 49% is owned by AEC.
The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/ADE. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the exchange rate between the U.S. dollar and local currency and yearly based on indexation mechanisms that include local inflation and U.S. inflation.
Assets subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 20212022
Project name | | Country | | Status(1) | | % of Nominal Share(2) | | Period of Concession (4)(5) | off-taker(7) | Financial/ Intangible(3) | | Assets/ Investment | | | Accumulated Amortization | | | Operating Profit/ (Loss)(8) | | Arrangement Terms (price) | | Description of the Arrangement | | Country | | Status(1) | | % of Nominal Share(2) | | Period of Concession (4)(5) | off-taker(7) | Financial/ Intangible(3) | | Assets/ Investment | | | Accumulated Amortization | | | Operating Profit/ (Loss)(8) | | Arrangement Terms (price) | Description of the Arrangement |
Renewable energy: | Renewable energy: | | | | | | | | | | | | | | | | | Renewable energy: | | | | | | | | | | | | | |
|
|
Solana | | USA | | (O) | | | 100.0 | | 30 Years | APS | (I) | | 1,865,770 | | | | (568,911 | ) | | | (11,377 | ) | Fixed price per MWh with annual increases of 1.84% per year | | 30-year PPA with APS regulated by ACC | | USA | | (O) | | 100.0 | | 30 Years | APS | (I) | | | 1,887,669 | | | | (664,681 | ) | | | (25,082 | ) | Fixed price per MWh with annual increases of 1.84% per year | 30-year PPA with APS regulated by ACC |
Mojave | | USA | | (O) | | | 100.0 | | 25 Years | PG&E | (I) | | 1,578,530 | | | | (435,937 | ) | | | 49,086 | | Fixed price per MWh without any indexation mechanism | | 25-year PPA with PG&E regulated by CPUC and CAEC | | USA | | (O) | | 100.0 | | 25 Years | PG&E | (I) | | | 1,573,621 | | | | (497,072 | ) | | | 45,193 | | Fixed price per MWh without any indexation mechanism | 25-year PPA with PG&E regulated by CPUC and CAEC |
Palmatir | | Uruguay | | (O) | | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | 147,925 | | | | (56,267 | ) | | | 4,278 | | Fixed price per MWh in USD with annual increases based on inflation | | 20-year PPA with UTE, Uruguay state-owned utility | | Uruguay | | (O) | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | | 147,937 | | | | (63,692 | ) | | | 4,021 | | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility |
Cadonal | | Uruguay | | (O) | | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | 122,002 | | | | (43,465 | ) | | | 1,220 | | Fixed price per MWh in USD with annual increases based on inflation | | 20-year PPA with UTE, Uruguay state-owned utility | | Uruguay | | (O) | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | | 122,012 | | | | (49,616 | ) | | | 3,680 | | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility |
Melowind | | Uruguay | | (O) | | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | 135,988 | | | | (36,794 | ) | | | 3,476 | | Fixed price per MWh in USD with annual increases based on inflation | | 20-year PPA with UTE, Uruguay state-owned utility | | Uruguay | | (O) | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | | 136,053 | | | | (43,988 | ) | | | 3,567 | | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility |
Solaben 2 | Spain | (O) | | 70.0 | | 25 Years | Kingdom of Spain | (I) | | 315,137 | | | (89,176 | ) | | 7,111 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 70.0 | | 25 Years | Kingdom of Spain | (I) | | 298,791 | | | (97,618 | ) | | 6,163 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solaben 3 | Spain | (O) | | 70.0 | | 25 Years | Kingdom of Spain | (I) | | 314,084 | | | (90,477 | ) | | 6,704 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 70.0 | | 25 Years | Kingdom of Spain | (I) | | 297,865 | | | (98,526 | ) | | 6,319 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solacor 1 | Spain | (O) | | 87.0 | | 25 Years | Kingdom of Spain | (I) | | 318,557 | | | (96,911 | ) | | 5,593 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 87.0 | | 25 Years | Kingdom of Spain | (I) | | 299,306 | | | (105,031 | ) | | 5,275 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solacor 2 | Spain | (O) | | 87.0 | | 25 Years | Kingdom of Spain | (I) | | 331,588 | | | (99,801 | ) | | 4,689 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 87.0 | | 25 Years | Kingdom of Spain | (I) | | 311,671 | | | (108,306 | ) | | 5,698 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solnova 1 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 317,624 | | | (116,464 | ) | | 7,112 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 301,041 | | | (123,894 | ) | | 7,509 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solnova 3 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 297,046 | | | (105,517 | ) | | 8,749 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 281,557 | | | (112,213 | ) | | 7,027 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solnova 4 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 277,953 | | | (97,828 | ) | | 8,720 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 263,079 | | | (104,282 | ) | | 7,694 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Helios 1 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 321,479 | | | (92,943 | ) | | 5,917 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 304,015 | | | (101,255 | ) | | 5,201 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Helios 2 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 313,182 | | | (89,008 | ) | | 5,930 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 296,267 | | | (97,167 | ) | | 4,508 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Helioenergy 1 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 307,727 | | | (94,563 | ) | | 8,510 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 291,454 | | | (101,428 | ) | | 8,032 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Helioenergy 2 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 308,472 | | | (91,879 | ) | | 8,472 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 292,225 | | | (99,126 | ) | | 8,149 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solaben 1 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 310,257 | | | (79,468 | ) | | 7,342 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 293,721 | | | (87,873 | ) | | 6,453 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solaben 6 | Spain | (O) | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 307,047 | | | (78,529 | ) | | 6,884 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | 290,745 | | | (86,822 | ) | | 7,110 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Kaxu | South Africa | (O) | | 51.0 | | 20 Years | Eskom | (I) | | 481,776 | | | (167,171 | ) | | 45,779 | | Take or pay contract for the purchase of electricity up to the contracted capacity from the facility. | | 20-year PPA with Eskom SOC Ltd. With a fixed price formula in local currency subject to indexation to local inflation | South Africa | (O) | | | 51.0 | | 20 Years | Eskom | (I) | | 455,517 | | | (179,417 | ) | | 44,487 | | Take or pay contract for the purchase of electricity up to the contracted capacity from the facility. | 20-year PPA with Eskom SOC Ltd. With a fixed price formula in local currency subject to indexation to local inflation |
| | | | | | | | | | | | | | | |
Efficient natural gas &Heat: | Efficient natural gas &Heat: | | | | | | | | | | | | | | | | | | Efficient natural gas &Heat: | | | | | | | | | | | | | | | | |
ACT | Mexico | (O) | | 100.0 | | 20 Years | Pemex | (F) | | 537,579 | | - | | | 124,799 | | Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract | | 20-year Services
Agreement with Pemex, Mexican oil & gas state-owned company | Mexico | (O) | | | 100.0 | | 20 Years | Pemex | (F) | | 512,796 | | | - | | | 80,731 | | Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract | | 20-year Services Agreement with Pemex, Mexican oil & gas state-owned company |
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| |
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Transmission lines: | Transmission lines: | | | | | | | | | | | | | | | | | | | Transmission lines: | | | | | | | | | | | | | | | | |
| |
|
ATS | Peru | (O) | | 100.0 | | 30 Years | Republic of Peru | (I) | | 532,675 | | (139,789 | ) | | 28,451 | | Tariff fixed by contract and adjusted annually in accordancewith the US Finished Goods Less Food and Energy inflation index | | 30-year Concession Agreement with the Peruvian Government | Peru | (O) | | | 100.0 | | 30 Years | Republic of Peru | (I) | | 532,859 | | | (157,573 | ) | | 31,351 | | Tariff fixed by contract and adjusted annually in accordancewith the US Finished Goods Less Food and Energy inflation index | | 30-year Concession Agreement with the Peruvian Government |
ATN | Peru | (O) | | 100.0 | | 30 Years | Republic of Peru | (I) | | 360,271 | | (118,116 | ) | | 7,413 | | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | | 30-year Concession Agreement with the Peruvian Government | Peru | (O) | | | 100.0 | | 30 Years | Republic of Peru | (I) | | 360,412 | | | (130,364 | ) | | 10,988 | | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | | 30-year Concession Agreement with the Peruvian Government |
ATN 2 | Peru | (O) | | 100.0 | | 18 Years | Las Bambas Mining | (F) | | 76,210 | | - | | | 11,428 | | Fixed-price tariff base denominated in U.S. dollars with Las Bambas | | 18 years purchase agreement | Peru | (O) | | | 100.0 | | 18 Years | Las Bambas Mining | (F) | | 71,966 | | | - | | | 10,673 | | Fixed-price tariff base denominated in U.S. dollars with Las Bambas | | 18 years purchase agreement |
Quadra I | Chile | (O) | | 100.0 | | 21 Years | Sierra Gorda | (F) | | 38,993 | | - | | | 5,358 | | Fixed price in USD with annual adjustments indexed mainly to US CPI | | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others | Chile | (O) | | | 100.0 | | 21 Years | Sierra Gorda | (F) | | 37,423 | | | - | | | 5,847 | | Fixed price in USD with annual adjustments indexed mainly to US CPI | | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others |
Quadra II | | Chile
| (O) | | | 100.0 | | 21 Years | Sierra Gorda | (F) | | 51,552 | | | - | | | 4,845 | | Fixed price in USD with annual adjustments indexed mainly to US CPI | | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others |
Quadra II | Chile | (O) | | 100.0 | | 21 Years | Sierra Gorda | (F) | | 55,561 | | | - | | | 4,711 | | Fixed price in USD with annual adjustments indexed mainly to US CPI | | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others | |
Water: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Skikda | Argelia | (O) | | 34.2 | | 25 Years | Sonatrach & ADE | (F) | | 70,969 | | | - | | | 14,654 | | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | | 25 years purchase agreement | | Algeria | (O) | | | 34.2 | | 25 Years | Sonatrach & ADE | (F) | | 71,007 | | - | | | | 13,121 | | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | 25 years purchase agreement |
Honaine | Argelia | (O) | | 25.5 | | 25 Years | Sonatrach & ADE | (F) | | N/A | (9) | | N/A | (9) | | N/A | (9) | U.S. dollar indexed take- or-pay contract with Sonatrach / ADE | | 25 years purchase agreement | | Algeria | (O) | | | 25.5 | | 25 Years | Sonatrach & ADE | (F) | | N/A | (9)
| |
| N/A | (9) | | | N/A | (9) | U.S. dollar indexed take- or-pay contract with Sonatrach / ADE | 25 years purchase agreement |
Tenes | Algeria | (O) | | 51.0 | | 25 Years | Sonatrach & ADE | (F) | | 99,438 | | | - | | | 16,671 | | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | | 25 years purchase agreement | | Algeria | (O) | | | 51.0 | | 25 Years | Sonatrach & ADE | (F) | | 98,962 | | | | - | | | | 14,637 | | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | 25 years purchase agreement |
| (1) | In operation (O), Construction (C) as of December 31, 2021.2022. |
| (2) | Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3. JGC Corporation holds 13% of the economic rights to each Solacor 1 and Solacor 2. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua, S.L., a subsidiary of Sacyr, S.A., owns the remaining 25.5% of the Honaine project. AEC owns 49% and Sacyr Agua S.L. owns the remaining 16.83% of the Skikda project. Industrial Development Corporation of South Africa (29%) & Kaxu Community Trust (20%) for the Kaxu Project. AEC owns 49% of the Tenes project. |
| (3) | Classified as concessional financial asset (F) or as intangible assets (I). |
| (4) | The infrastructure is used for its entire useful life. There are no obligations to deliver assets at the end of the concession periods, except for ATN and ATS. |
| (5) | Generally, there are no termination provisions other than customary clauses for situations such as bankruptcy or fraud from the operator, for example. |
| (6) | Sales to wholesale markets and additional fixed payments established by the Spanish government. |
| (7) | In each case the off-taker is the grantor. |
| (8) | Figures reflect the contribution to the Consolidated Financial Statements of Atlantica Sustainable Infrastructure plc. as of December 31, 2021.2022. |
| (9) | Recorded under the equity method. |
The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
Assets subject to the application of IFRIC 12 interpretation based on the concession of services as of December 31, 20202021
Project name | | Country | | Status(1) | | % of Nominal Share(2) | | Period of Concession (4)(5) | off-taker(7) | Financial/ Intangible(3) | | Assets/ Investment | | | Accumulated Amortization | | | Operating Profit/ (Loss)(8) | | Arrangem ent Terms (price) | | Description of the Arrangement | Country | Status(1) | | % of Nominal Share(2) | | Period of Concession (4)(5) | off-taker(7) | Financial/ Intangible(3) | | Assets/ Investment | | | Accumulated Amortization | | | Operating Profit/ (Loss)(8) | | Arrangement Terms (price) | Description of the Arrangement |
Renewable energy: | Renewable energy: | | | | | | | | | | | | | | | | �� | Renewable energy: | | | | | | | | | | | | | |
|
Solana | | USA | | (O) | | | 100.0 | | 30 Years | APS | (I) | | | 1,830,148 | | | | (468,323 | ) | | | (5,722 | ) | Fixed price per MWh with annual increases of 1.84% per year | | 30-year PPA with APS regulated by ACC | USA | (O) | | 100.0 | | 30 Years | APS | (I) | | 1,865,770 | | | (568,911 | ) | | (26,886 | ) | Fixed price per MWh with annual increases of 1.84% per year | 30-year PPA with APS regulated by ACC |
Mojave | | USA | | (O) | | | 100.0 | | 25 Years | PG&E | (I) | | | 1,557,559 | | | | (374,193 | ) | | | 48,436 | | Fixed price per MWh without any indexation mechanism | | 25-year PPA with PG&E regulated by CPUC and CAEC | USA | (O) | | 100.0 | | 25 Years | PG&E | (I) | | 1,578,530 | | | (435,937 | ) | | 38,239 | | Fixed price per MWh without any indexation mechanism | 25-year PPA with PG&E regulated by CPUC and CAEC |
Palmatir | | Uruguay | | (O) | | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | | 147,911 | | | | (48,843 | ) | | | 7,971 | | Fixed price per MWh in USD with annual increases based on inflation | | 20-year PPA with UTE, Uruguay state-owned utility | Uruguay | (O) | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | 147,925 | | | (56,267 | ) | | 4,278 | | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility |
Cadonal | | Uruguay | | (O) | | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | | 121,986 | | | | (37,315 | ) | | | 15,293 | | Fixed price per MWh in USD with annual increases based on inflation | | 20-year PPA with UTE, Uruguay state-owned utility | Uruguay | (O) | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | 122,002 | | | (43,465 | ) | | 1,220 | | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility |
Melowind | | Uruguay | | (O) | | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | | 135,977 | | | | (29,598 | ) | | | 4,673 | | Fixed price per MWh in USD with annual increases based on inflation | | 20-year PPA with UTE, Uruguay state-owned utility | Uruguay | (O) | | 100.0 | | 20 Years | UTE, Uruguay Administration | (I) | | 135,988 | | | (36,794 | ) | | 3,476 | | Fixed price per MWh in USD with annual increases based on inflation | 20-year PPA with UTE, Uruguay state-owned utility |
Solaben 2 | Spain | (O) | | | 70.0 | | 25 Years | Kingdom of Spain | (I) | | | 337,506 | | | | (80,255 | ) | | | 10,222 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solaben 3 | Spain | (O) | | | 70.0 | | 25 Years | Kingdom of Spain | (I) | | | 336,556 | | | | (81,998 | ) | | | 10,802 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solacor 1 | Spain | (O) | | | 87.0 | | 25 Years | Kingdom of Spain | (I) | | | 341,674 | | | | (88,382 | ) | | | 9,359 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solacor 2 | Spain | (O) | | | 87.0 | | 25 Years | Kingdom of Spain | (I) | | | 355,614 | | | | (90,861 | ) | | | 9,248 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solnova 1 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 340,713 | | | | (108,908 | ) | | | 14,090 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solnova 3 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 318,415 | | | | (98,755 | ) | | | 14,331 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solnova 4 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 297,118 | | | | (91,251 | ) | | | 13,865 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solaben 2 | Spain | (O) | | | 70.0 | | 25 Years | Kingdom of Spain | (I) | | | 315,137 | | | | (89,176 | ) | | | 7,111 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solaben 3 | Spain | (O) | | | 70.0 | | 25 Years | Kingdom of Spain | (I) | | | 314,084 | | | | (90,477 | ) | | | 6,704 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solacor 1 | Spain | (O) | | | 87.0 | | 25 Years | Kingdom of Spain | (I) | | | 318,557 | | | | (96,911 | ) | | | 5,593 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solacor 2 | Spain | (O) | | | 87.0 | | 25 Years | Kingdom of Spain | (I) | | | 331,588 | | | | (99,801 | ) | | | 4,689 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solnova 1 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 317,624 | | | | (116,464 | ) | | | 7,112 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solnova 3 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 297,046 | | | | (105,517 | ) | | | 8,749 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solnova 4 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 277,953 | | | | (97,828 | ) | | | 8,720 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Helios 1 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 344,533 | | | | (84,144 | ) | | | 11,285 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Helios 2 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 335,550 | | | | (80,361 | ) | | | 11,677 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Helioenergy 1 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 330,497 | | | | (87,496 | ) | | | 11,149 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Helioenergy 2 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 331,206 | | | | (84,360 | ) | | | 11,560 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solaben 1 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 332,537 | | | | (70,486 | ) | | | 11,542 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Solaben 6 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 329,203 | | | | (69,659 | ) | | | 12,161 | | Regulated revenue base(6) | | Regulated revenue established by different laws and rulings in Spain |
Kaxu | South Africa | (O) | | | 51.0 | | 20 Years | Eskom | (I) | | | 521,523 | | | | (154,962 | ) | | | 41,483 | | Take or pay contract for the purchase of electricity up to the contracted capacity from the facility. | | 20-year PPA with Eskom SOC Ltd. With a fixed price formula in local currency subject to indexation to local inflation |
Helios 1 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 321,479 | | | | (92,943 | ) | | | 5,917 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Helios 2 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 313,182 | | | | (89,008 | ) | | | 5,930 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Helioenergy 1 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 307,727 | | | | (94,563 | ) | | | 8,510 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Helioenergy 2 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 308,472 | | | | (91,879 | ) | | | 8,472 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solaben 1 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 310,257 | | | | (79,468 | ) | | | 7,342 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Solaben 6 | Spain | (O) | | | 100.0 | | 25 Years | Kingdom of Spain | (I) | | | 307,047 | | | | (78,529 | ) | | | 6,884 | | Regulated revenue base(6) | Regulated revenue established by different laws and rulings in Spain |
Kaxu | South Africa | (O) | | | 51.0 | | 20 Years | Eskom | (I) | | | 481,776 | | | | (167,171 | ) | | | 45,779 | | Take or pay contract for the purchase of electricity up to the contracted capacity from the facility. | 20-year PPA with Eskom SOC Ltd. With a fixed price formula in local currency subject to indexation to local inflation |
Efficient natural gas & Heat: | | | | | | | | | | | | | |
Efficient natural gas &Heat: | | Efficient natural gas &Heat: | | | | | | | | | | | | | | | | | | |
ACT | Mexico | (O) | | 100.0 | | 20 Years | Pemex | (F) | | 580,141 | | | - | | | | 75,349 | | Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract | | 20-year Services Agreement with Pemex, Mexican oil & gas state-owned company | Mexico | (O) | | 100.0 | | 20 Years | Pemex | (F) | | 537,579 | | | - | | | 124,799 | | Fixed price to compensate both investment and O&M costs, established in USD and adjusted annually partially according to inflation and partially according to a mechanism agreed in contract | | 20-year Services Agreement with Pemex, Mexican oil & gas state-owned company |
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Transmission lines: | Transmission lines: | | | | | | | | | | | | | | | | | Transmission lines: | | | | | | | | | | | | | | | | | | | |
ATS | Peru | (O) | | 100.0 | | 30 Years | Republic of Peru | (I) | | 531,887 | | | (122,005 | ) | | | 29,339 | | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | | 30-year Concession Agreement with the Peruvian Government | Peru | (O) | | 100.0 | | 30 Years | Republic of Peru | (I) | | 532,675 | | | (139,789 | ) | | 28,451 | | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | | 30-year Concession Agreement with the Peruvian Government |
ATN | Peru | (O) | | 100.0 | | 30 Years | Republic of Peru | (I) | | 359,912 | | | (105,618 | ) | | | 6,474 | | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | | 30-year Concession Agreement with the Peruvian Government | Peru | (O) | | 100.0 | | 30 Years | Republic of Peru | (I) | | 360,271 | | | (118,116 | ) | | 7,413 | | Tariff fixed by contract and adjusted annually in accordance with the US Finished Goods Less Food and Energy inflation index | | 30-year Concession Agreement with the Peruvian Government |
ATN 2 | Peru | (O) | | 100.0 | | 18 Years | Las Bambas Mining | (F) | | 78,743 | | | - | | | | 12,332 | | Fixed-price tariff base denominated in U.S. dollars with Las Bambas | | 18 years purchase agreement | Peru | (O) | | 100.0 | | 18 Years | Las Bambas Mining | (F) | | 76,210 | | | - | | | 11,428 | | Fixed-price tariff base denominated in U.S. dollars with Las Bambas | | 18 years purchase agreement |
Quadra I | Chile | (O) | | 100.0 | | 21 Years | Sierra Gorda | (F) | | 40,381 | | | - | | | | 5,362 | | Fixed price in USD with annual adjustments indexed mainly to US CPI | | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others | Chile | (O) | | 100.0 | | 21 Years | Sierra Gorda | (F) | | 38,993 | | | - | | | 5,358 | | Fixed price in USD with annual adjustments indexed mainly to US CPI | | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others |
Quadra II | Chile | (O) | | 100.0 | | 21 Years | Sierra Gorda | (F) | | 55,417 | | | - | | | 4,922 | | Fixed price in USD with annual adjustments indexed mainly to US CPI | | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others | Chile | (O) | | 100.0 | | 21 Years | Sierra Gorda | (F) | | 55,561 | |
| - | |
| 4,711 | | Fixed price in USD with annual adjustments indexed mainly to US CPI | 21-year Concession Contract with Sierra Gorda regulated by CDEC and the Superentendencia de Electricidad, among others |
Water: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Skikda | Argelia | (O) | | 34.2 | | 25 Years | Sonatrach & ADE | (F) | | 77,702 | | | - | | | 13,909 | | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | | 25 years purchase agreement | Algeria | (O) | | 34.2 | | 25 Years | Sonatrach & ADE | (F) | | 70,969 | |
| - | |
| 14,654 | | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | 25 years purchase agreement |
Honaine | Argelia | (O) | | 25.5 | | 25 Years | Sonatrach & ADE | (F) | | N/A | (9) | | N/A | (9) | | N/A | (9) | U.S. dollar indexed take- or-pay contract with Sonatrach / ADE | | 25 years purchase agreement | Algeria | (O) | | 25.5 | | 25 Years | Sonatrach & ADE | (F) | | N/A | (9)
| |
| | (9) | |
| N/A | (9)
| U.S. dollar indexed take- or-pay contract with Sonatrach / ADE | 25 years purchase agreement |
Tenes | Algeria | (O) | | 51.0 | | 25 Years | Sonatrach & ADE | (F) | | 106,071 | | | - | | | 10,610 | | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | | 25 years purchase agreement | Algeria | (O) | | 51.0 | | 25 Years | Sonatrach & ADE | (F) | | 99,438 | |
| - | | |
| 16,671 | | U.S. dollar indexed take-or-pay contract with Sonatrach / ADE | 25 years purchase agreement |
| (1) | In operation (O), Construction (C) as of December 31, 2020.2021. |
| (2) | Itochu Corporation holds 30% of the economic rights to each of Solaben 2 and Solaben 3. JGC Corporation holds 13% of the economic rights to each Solacor 1 and Solacor 2. Algerian Energy Company, SPA, or AEC, owns 49% and Sacyr Agua, S.L., a subsidiary of Sacyr, S.A., owns the remaining 25.5% of the Honaine project. AEC owns 49% and Sacyr Agua S.L. owns the remaining 16.83% of the Skikda project. Industrial Development Corporation of South Africa (29%) & Kaxu Community Trust (20%) for the Kaxu Project. AEC owns 49% of the Tenes project. |
| (3) | Classified as concessional financial asset (F) or as intangible assets (I). |
| (4) | The infrastructure is used for its entire useful life. There are no obligations to deliver assets at the end of the concession periods, except for ATN and ATS. |
| (5) | Generally, there are no termination provisions other than customary clauses for situations such as bankruptcy or fraud from the operator, for example. |
| (6) | Sales to wholesale markets and additional fixed payments established by the Spanish government. |
| (7) | In each case the off-taker is the grantor. |
| (8) | Figures reflect the contribution to the Consolidated Financial Statements of Atlantica Sustainable Infrastructure plc. as of December 31, 2020.2021. |
| (9) | Recorded under the equity method. |
The Appendices are an integral part of the Notes to the Consolidated Financial Statements.
Additional information of subsidiaries including material non-controlling interest as of December 31, 2022
Subsidiary name | | Non- controlling interest name | | % of non- controlling interest held | | | Distributions paid to non- controlling interest | | | Profit/(Loss) of non- controlling interest in Atlantica consolidated net result 2022 | | | Non- controlling interest in Atlantica consolidated equity as of December 31, 2022 | | | Non- current assets* | | | Current Assets* | | | Non- current liabilities* | | | Current liabilities* | | | Net Profit /(Loss)* | | | Total Comprehensive income* | |
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Aguas de Skikda S.P.A. | | Algerian Energy Company S.P.A. | | | 49 | %** | | | 2,849 | | | | 7,060 | | | | 47,509 | | | | 68,655 | | | | 29,293 | | | | 12,470 | | | | 6,788 | | | | 10,725 | | | | - | |
Atlantica Yield Energy Solutions Canada Inc. | | Algonquin Power Co. | | | 90 | % | | | 21,333 | | | | (5 | ) | | | 15,996 | | | | 18,657 | | | | 4,910 | | | | - | | | | 4,904 | | | | (6 | ) | | | - | |
Solaben Electricidad Dos S.A. | | Itochu Europe Plc | | | 30 | % | | | 1,913 | | | | 402 | | | | 25,271 | | | | 201,060 | | | | 12,730 | | | | 115,109 | | | | 14,857 | | | | 1,158 | | | | (1,428 | ) |
Solaben Electricidad Tres S.A. | | Itochu Europe Plc | | | 30 | % | | | 1,397 | | | | 370 | | | | 24,522 | | | | 201,088 | | | | 13,814 | | | | 117,948 | | | | 15,495 | | | | 1,051 | | | | (1,642 | ) |
Ténès Lilmiyah SPA | | Algerian Energy Company S.P.A. | | | 49 | % | | | 2,260 | | | | 5,675 | | | | 25,592 | | | | 94,989 | | | | 40,884 | | | | 72,279 | | | | 11,365 | | | | 11,581 | | | | - | |
* Stand-alone figures as of December 31, 2022.
** Atlantica Sustainable Infrastructure plc. owns 67% of the shares in Geida Skikda, S.L., which in its turn owns 51% of Aguas de Skikda S.P.A., so that indirectly Atlantica Sustainable Infrastructure plc. owns 34.17% of Aguas de Skikda S.P.A. The table only shows information related to the non-controlling interest of the SPV, Aguas de Skikda S.P.A.
Additional information of subsidiaries including material non-controlling interest as of December 31, 2021
Subsidiary name | Non- controlling interest name | | % of non- controlling interest held | | Dividends paid to non- controlling interest | | | Profit/(Loss) of non- controlling interest in Atlantica consolidated net result 2021 | | | Non- controlling interest in Atlantica consolidated equity as of December 31, 2021 | | Non- current assets* | | Current Assets* | | Non- current liabilities* | | Current liabilities* | | Net Profit /(Loss)* | | | Total Comprehensive income* | | | Non- controlling interest name | | % of non- controlling interest held | | | Distributions paid to non- controlling interest | | | Profit/(Loss) of non- controlling interest in Atlantica consolidated net result 2021 | | | Non- controlling interest in Atlantica consolidated equity as of December 31, 2021 | | | Non- current assets* | | | Current Assets* | | | Non- current liabilities* | | | Current liabilities* | | | Net Profit /(Loss)* | | | Total Comprehensive income* | |
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Aguas de Skikda S.P.A. | Algerian Energy Company S.P.A. | | | 49%** | | | | 3,753 | | | | 7,166 | | | | 43,985 | | | | 69,057 | | | | 27,863 | | | | 17,030 | | | | 6,552 | | | | 10,886 | | | - | | | Algerian Energy Company S.P.A. | | 49 | %** | | 3,753 | | | 7,166 | | | 43,985 | | | 69,057 | | | 27,863 | | | 17,030 | | | 6,552 | | | 10,886 | | | - | |
Atlantica Yield Energy Solutions Canada Inc. | Algonquin Power Co. | | | 90% | | | | 17,282 | | | | (8 | ) | | | 38,200 | | | | 38,507 | | | | 6,291 | | | | - | | | | 6,279 | | | | (8 | ) | | - | | | Algonquin Power Co. | | 90 | % | | 17,282 | | | (8 | ) | | 38,200 | | | 38,507 | | | 6,291 | | | - | | | 6,279 | | | (8 | ) | | - | |
Solaben Electricidad Dos S.A. | | | Itochu Europe Plc | | 30 | % | | 2,375 | | | 406 | | | 25,864 | | | 224,412 | | | 12,798 | | | 138,026 | | | 13,910 | | | 1,354 | | | (9,726 | ) |
Solaben Electricidad Tres S.A. | | | Itochu Europe Plc | | 30 | % | | 2,382 | | | 246 | | | 24,605 | | | 223,976 | | | 12,201 | | | 141,077 | | | 13,825 | | | 820 | | | (9,713 | ) |
Ténès Lilmiyah SPA | | | Algerian Energy Company S.P.A. | | 49 | % | | 2,813 | | | 6,409 | | | 21,795 | | | 96,444 | | | 36,283 | | | 79,129 | | | 9,120 | | | 12,950 | | | - | |
* Stand-alone figures as of December 31, 2021.
** Atlantica Sustainable Infrastructure plc. owns 67% of the shares in Geida Skikda, S.L., which in its turn owns 51% of Aguas de Skikda S.P.A., so that indirectly Atlantica Sustainable Infrastructure plc. owns 34.17% of Aguas de Skikda S.P.A. The table only shows information related to the non-controlling interest of the SPV, Aguas de Skikda S.P.A.
Additional information of subsidiaries including material non-controlling interest as of December 31, 2020
Subsidiary name | Non- controlling interest name | | % of non- controlling interest held | | | Dividends paid to non- controlling interest | | | Profit/(Loss) of non- controlling interest in Atlantica consolidated net result 2020 | | | Non- controlling interest in Atlantica consolidated equity as of December 31, 2020 | | | Non- current assets* | | | Current Assets* | | | Non- current liabilities* | | | Current liabilities* | | | Net Profit /(Loss)* | | | Total Comprehensive income* | |
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Aguas de Skikda S.P.A. | Algerian Energy Company S.P.A. | | | 49 | %** | | | 3,584 | | | | 1,563 | | | | 44,486 | | | | 75,893 | | | | 28,343 | | | | 22,336 | | | | 7,801 | | | | 2,374 | | | | - | |
Atlantica Yield Energy Solutions Canada Inc. | Algonquin Power Co. | | | 90 | % | | | 15,709 | | | | (6) | | | | 54,924 | | | | 56,308 | | | | 4,312 | | | | - | | | | 4,292 | | | | (6) | | | | - | |
* Stand-alone figures as of December 31, 2020.
** Atlantica Sustainable Infrastructure plc. owns 67% of the shares in Geida Skikda, S.L., which in its turn owns 51% of Aguas de Skikda S.P.A., so that indirectly Atlantica Sustainable Infrastructure plc. owns 34.17% of Aguas de Skikda S.P.A. The table only shows information related to the non-controlling interest of the SPV, Aguas de Skikda S.P.A.
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